Building for the Future Through Electric Regional Transmission Planning and Cost Allocation, 49280-49586 [2024-10872]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 89, Number 113 (Tuesday, June 11, 2024)]
[Rules and Regulations]
[Pages 49280-49586]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-10872]



[[Page 49279]]

Vol. 89

Tuesday,

No. 113

June 11, 2024

Part II





Department of Energy





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Federal Energy Regulatory Commission





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18 CFR Part 35





Building for the Future Through Electric Regional Transmission Planning 
and Cost Allocation; Final Rule

Federal Register / Vol. 89, No. 113 / Tuesday, June 11, 2024 / Rules 
and Regulations

[[Page 49280]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM21-17-000; Order No. 1920]


Building for the Future Through Electric Regional Transmission 
Planning and Cost Allocation

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Final order.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) revises 
the pro forma Open Access Transmission Tariff (OATT) to remedy 
deficiencies in the Commission's existing regional and local 
transmission planning and cost allocation requirements. In this final 
order, the Commission requires transmission providers to conduct Long-
Term Regional Transmission Planning that will ensure the 
identification, evaluation, and selection, as well as the allocation of 
the costs, of more efficient or cost-effective regional transmission 
solutions to address Long-Term Transmission Needs. The Commission also 
directs other reforms to improve coordination of regional transmission 
planning and generator interconnection processes, require consideration 
of certain alternative transmission technologies in regional 
transmission planning processes, and improve transparency of local 
transmission planning processes and coordination between regional and 
local transmission planning processes. These reforms are intended to 
ensure that existing regional and local transmission planning and cost 
allocation requirements are just, reasonable, and not unduly 
discriminatory or preferential.

DATES: This final order is effective August 12, 2024.

FOR FURTHER INFORMATION CONTACT: 
    David Borden (Technical Information), Office of Energy Policy and 
Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-8734, 
[email protected].
    Noah Lichtenstein (Technical Information), Office of Energy Market 
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8696, 
[email protected].
    Michael Kellermann (Legal Information), Office of the General 
Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8491, 
[email protected].

SUPPLEMENTARY INFORMATION: 

Table of Contents

 
                                                          Paragraph Nos.
 
I. Introduction and Background..........................               1
    A. Historical Framework: Order Nos. 888, 890, and                 14
     1000...............................................
    B. ANOPR and Technical Conference...................              20
    C. Joint Federal-State Task Force on Electric                     22
     Transmission.......................................
    D. Notice of Proposed Rulemaking....................              26
    E. High-Level Overview of NOPR Comments.............              36
    F. Use of Terms.....................................              37
II. The Overall Need for Reform.........................              47
    A. NOPR Proposal....................................              47
    B. Comments.........................................              49
    C. Commission Determination.........................              85
        1. The Transmission Investment Landscape Today..              90
        2. Unjust, Unreasonable, and Unduly                          112
         Discriminatory or Preferential Commission-
         Jurisdictional Transmission Planning and Cost
         Allocation Processes...........................
        3. Benefits of Long-Term Regional Transmission               134
         Planning and Cost Allocation To Identify and
         Plan for Long-Term Transmission Needs..........
        4. Conclusion...................................             139
III. Long-Term Regional Transmission Planning...........             140
    A. Requirement To Participate in Long-Term Regional              140
     Transmission Planning..............................
        1. NOPR Proposal................................             140
        2. Comments.....................................             145
            a. General Comments.........................             145
            b. Requests for Flexibility in Transmission              151
             Planning...................................
            c. Comments Regarding More Comprehensive                 163
             Transmission Planning......................
            d. Concerns Regarding Favoring Renewable                 172
             Resources..................................
            e. Concerns Regarding Uncertainty, Over-                 176
             Building, and Costs........................
            f. Concerns Regarding Incentives for                     187
             Resource Development.......................
            g. Comments Regarding Definition of Long-                189
             Term Regional Transmission Facility........
            h. Challenges to Commission Jurisdiction or              190
             Authority..................................
            i. Other Issues.............................             215
            j. Miscellaneous Concerns...................             217
        3. Commission Determination.....................             224
            a. Participation in Long-Term Regional                   224
             Transmission Planning......................
            b. Definition of Long-Term Regional                      250
             Transmission Facility......................
            c. Legal Authority To Adopt Reforms for Long-            253
             Term Regional Transmission Planning........
    B. Development of Long-Term Scenarios...............             284
        1. NOPR Proposal................................             284
        2. Comments.....................................             286
            a. General Comments.........................             286
            b. Applying Scenario Planning to Reliability             296
             and Economic Planning......................
        3. Commission Determination.....................             298
    C. Long-Term Scenarios Requirements.................             307
        1. Transmission Planning Horizon................             307
            a. NOPR Proposal............................             307
            b. Comments.................................             309
            c. Commission Determination.................             344
        2. Frequency of Long-Term Scenario Revisions....             352

[[Page 49281]]

 
            a. NOPR Proposal............................             352
            b. Comments.................................             354
            c. Commission Determination.................             377
        3. Categories of Factors........................             387
            a. Requirement To Incorporate Categories of              387
             Factors....................................
            b. Specific Categories of Factors...........             422
            c. Treatment of Specific Categories of                   495
             Factors....................................
            d. Stakeholder Process and Transparency.....             519
        4. Number and Development of Long-Term Scenarios             538
            a. NOPR Proposal............................             538
            b. Comments.................................             541
            c. Commission Determination.................             559
        5. Types of Long-Term Scenarios.................             564
            a. NOPR Proposal............................             564
            b. Comments.................................             566
            c. Commission Determination.................             575
        6. Sensitivities for High-Impact, Low-Frequency              578
         Events.........................................
            a. NOPR Proposal............................             578
            b. Comments.................................             580
            c. Commission Determination.................             593
        7. Specificity of Data Inputs...................             602
            a. NOPR Proposal............................             602
            b. Comments.................................             606
            c. Commission Determination.................             633
        8. Identification of Geographic Zones...........             645
            a. NOPR Proposal............................             645
            b. Comments.................................             650
            c. Commission Determination.................             665
    D. Evaluation of the Benefits of Regional                        667
     Transmission Facilities............................
        1. Requirement for Transmission Providers To Use             669
         a Set of Seven Required Benefits...............
            a. NOPR Proposal............................             669
            b. Comments.................................             673
            c. Commission Determination.................             719
        2. Required Benefits............................             740
            a. The Seven Required Benefits..............             740
        3. Identification, Measurement, and Evaluation               823
         of the Benefits of Long-Term Regional
         Transmission Facilities........................
            a. NOPR Proposal............................             823
            b. Comments.................................             824
            c. Commission Determination.................             837
        4. Evaluation of Transmission Benefits Over a                843
         Longer Time Horizon............................
            a. NOPR Proposal............................             843
            b. Comments.................................             845
            c. Commission Determination.................             859
        5. Evaluation of the Benefits of Portfolios of               871
         Transmission Facilities........................
            a. NOPR Proposal............................             871
            b. Comments.................................             872
            c. Commission Determination.................             889
        6. Issues Related to Use of Benefits............             891
            a. NOPR Proposal............................             891
            b. Comments.................................             892
            c. Commission Determination.................             902
    E. Evaluation and Selection of Long-Term Regional                904
     Transmission Facilities............................
        1. Requirement To Adopt an Evaluation Process                904
         and Selection Criteria.........................
            a. NOPR Proposal............................             904
            b. Comments.................................             906
            c. Commission Determination.................             911
        2. Flexibility..................................             919
            a. NOPR Proposal............................             919
            b. Comments.................................             920
            c. Commission Determination.................             924
        3. Minimum Requirements.........................             927
            a. NOPR Proposal............................             927
            b. Comments.................................             930
            c. Commission Determination.................             954
        4. Role of Relevant State Entities..............             972
            a. NOPR Proposal............................             972
            b. Comments.................................             973
            c. Commission Determination.................             994
        5. Voluntary Funding Opportunities..............            1003
            a. NOPR Proposal............................            1003
            b. Comments.................................            1004
            c. Commission Determination.................            1012
        6. No Selection Requirement.....................            1019

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            a. NOPR Proposal............................            1019
            b. Comments.................................            1020
            c. Commission Determination.................            1026
        7. Other Issues.................................            1029
            a. Comments.................................            1029
            b. Commission Determination.................            1031
        8. Reevaluation.................................            1033
            a. NOPR Proposal............................            1033
            b. Comments.................................            1035
            c. Commission Determination.................            1048
    F. Implementation of Long-Term Regional Transmission            1062
     Planning...........................................
        1. NOPR Proposal................................            1062
        2. Comments.....................................            1064
            a. Comments on the Initial Timing Sequence..            1064
            b. Comments on Periodic Forums..............            1067
        3. Commission Determination.....................            1071
            a. Initial Timing Sequence Implementation...            1071
            b. Periodic Forums..........................            1075
IV. Coordination of Regional Transmission Planning and              1076
 Generator Interconnection Processes....................
    A. Need for Reform and Overall Reform...............            1076
        1. NOPR Proposal................................            1076
        2. Comments.....................................            1079
            a. On the Overall Reform....................            1079
            b. Requesting Additional Reform.............            1081
            c. Concerns With the Overall Reform.........            1085
            d. Cost Allocation..........................            1093
            e. Interconnection Queue Gaming                         1095
             Considerations.............................
            f. Miscellaneous............................            1098
        3. Need for Reform..............................            1100
        4. Commission Determination.....................            1106
    B. Transmission Planning Process Evaluation.........            1122
        1. NOPR Proposal................................            1122
        2. Comments.....................................            1123
        3. Commission Determination.....................            1126
    C. Qualifying Criteria..............................            1130
        1. NOPR Proposal................................            1130
        2. Comments.....................................            1134
        3. Commission Determination.....................            1145
V. Consideration of Dynamic Line Ratings and Advanced               1163
 Power Flow Control Devices.............................
    A. General Proposal.................................            1163
        1. NOPR Proposal................................            1163
        2. Comments on General Proposal.................            1167
        3. Need for Reform..............................            1194
        4. Commission Determination.....................            1198
    B. Specific Alternative Transmission Technologies...            1217
        1. NOPR Proposal................................            1217
        2. Comments on Specific Technologies............            1218
        3. Commission Determination.....................            1239
VI. Regional Transmission Cost Allocation...............            1248
    A. Cost Allocation for Long-Term Regional                       1248
     Transmission Facilities............................
        1. Cost Allocation Methods for Long-Term                    1248
         Regional Transmission Facilities...............
            a. NOPR Proposal............................            1248
            b. Comments.................................            1252
            c. Commission Determination.................            1291
        2. Requirement that Transmission Providers Seek             1308
         the Agreement of Relevant State Entities
         Regarding the Cost Allocation Method or Methods
         for Long-Term Regional Transmission Facilities.
            a. NOPR Proposal............................            1308
            b. Comments.................................            1313
            c. Commission Determination.................            1354
        3. Proposals Relating to the Design and                     1369
         Operation of State Agreement Processes.........
            a. NOPR Proposal............................            1369
            b. Comments.................................            1371
            c. Commission Determination.................            1402
        4. Filing Rights Under the FPA..................            1422
            a. Comments.................................            1422
            b. Commission Determination.................            1428
        5. Time Period and Related Issues in the Long-              1432
         Term Regional Transmission Planning Cost
         Allocation Processes for State-Negotiated
         Alternate Cost Allocation Method...............
            a. NOPR Proposal............................            1432
            b. Comments.................................            1436
            c. Commission Determination.................            1456
    B. Long-Term Regional Transmission Facility Cost                1458
     Allocation Compliance With the Existing Six Order
     No. 1000 Regional Cost Allocation Principles.......

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        1. NOPR Proposal................................            1458
        2. Comments.....................................            1459
            a. General Proposal.........................            1459
            b. Comments Specific to a State Agreement               1467
             Process....................................
            3. Commission Determination.................            1469
    C. Identification of Benefits Considered in Cost                1480
     Allocation for Long-Term Regional Transmission
     Facilities.........................................
        1. NOPR Proposal................................            1480
        2. Comments.....................................            1482
            a. Agree With Proposal......................            1482
            b. Requests To Reflect the Full Breadth of              1491
             Benefits in Cost Allocation Methods While
             Maintaining Flexibility....................
            c. Disagree With Proposal, Mostly Require               1492
             Benefits...................................
            d. Alignment of Benefits Between                        1497
             Transmission Planning and Cost Allocation..
            e. Additional Benefits or Suggestions for               1502
             Refinement.................................
        3. Commission Determination.....................            1505
    D. Miscellaneous Cost Allocation Comments and                   1516
     Proposals..........................................
        1. Comments.....................................            1516
        2. Commission Determination.....................            1521
VII. Construction Work in Progress Incentive............            1524
    A. NOPR Proposal....................................            1524
    B. Comments.........................................            1525
        1. Interest in the NOPR Proposal................            1525
        2. Concerns With the NOPR Proposal..............            1532
        3. Interaction of the CWIP Incentive With the               1545
         Abandoned Plant Incentive......................
    C. Commission Determination.........................            1547
VIII. Exercise of a Federal Right of First Refusal in               1548
 Commission-Jurisdictional Tariffs and Agreements.......
    A. NOPR Proposal....................................            1548
    B. Comments.........................................            1553
        1. General Perspectives and Approach to Reform..            1553
        2. Comments on the NOPR's Joint Ownership                   1560
         Proposal.......................................
    C. Commission Determination.........................            1563
IX. Local Transmission Planning Inputs in the Regional              1565
 Transmission Planning Process..........................
    A. Need for Reform..................................            1565
        1. NOPR.........................................            1565
        2. Comments.....................................            1567
        3. Commission Determination.....................            1569
    B. Enhanced Transparency of Local Transmission                  1578
     Planning Inputs in the Regional Transmission
     Planning Process...................................
        1. NOPR Proposal................................            1578
        2. Comments.....................................            1581
            a. Interest in Enhanced Transparency of                 1581
             Local Transmission Planning Inputs.........
            b. Suggested Modifications to the NOPR                  1586
             Proposal...................................
            c. Concern With the NOPR Proposal...........            1591
            d. Specific Stakeholder Meeting Requirements            1601
            e. Additional Issues........................            1613
        3. Commission Determination.....................            1625
            a. Specific Stakeholder Meeting Requirements            1638
            b. Additional Issues........................            1647
    C. Identifying Potential Opportunities to Right-Size            1649
     Replacement Transmission Facilities................
        1. Eligibility..................................            1649
            a. NOPR Proposal............................            1649
            b. Comments.................................            1652
            c. Commission Determination.................            1677
        2. Right of First Refusal.......................            1693
            a. NOPR Proposal............................            1693
            b. Comments.................................            1694
            c. Commission Determination.................            1702
        3. Cost Allocation..............................            1710
            a. NOPR Proposal............................            1710
            b. Comments.................................            1712
            c. Commission Determination.................            1716
        4. Miscellaneous................................            1723
            a. Comments.................................            1723
            b. Commission Determination.................            1735
X. Interregional Transmission Coordination..............            1740
    A. NOPR Proposal....................................            1740
    B. Comments.........................................            1744
    C. Commission Determination.........................            1751
XI. Compliance Procedures...............................            1759
    A. NOPR Proposal....................................            1759
    B. Comments.........................................            1761
    C. Commission Determination.........................            1768
XII. Information Collection Statement...................            1775
XIII. Environmental Analysis............................            1784
XIV. Regulatory Flexibility Act.........................            1785

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XV. Document Availability...............................            1789
XVI. Effective Date and Congressional Notification......            1792
 

I. Introduction and Background

    1. In this final order, the Commission acts under section 206 of 
the Federal Power Act (FPA) to adopt reforms to its electric 
transmission planning and cost allocation requirements.\1\ The reforms 
herein will remedy deficiencies in the Commission's existing regional 
and local transmission planning and cost allocation requirements to 
ensure that the rates, terms, and conditions for transmission service 
provided by public utility transmission providers (transmission 
providers) \2\ remain just and reasonable and not unduly discriminatory 
or preferential. This final order builds upon Order No. 888, Order No. 
890,\3\ and Order No. 1000,\4\ in which the Commission incrementally 
developed the requirements that govern regional transmission planning 
and cost allocation processes to ensure that Commission-jurisdictional 
rates remain just and reasonable and not unduly discriminatory or 
preferential. Specifically, in this final order, we find that there is 
substantial evidence to support the conclusion that the existing 
regional transmission planning and cost allocation processes are 
unjust, unreasonable, and unduly discriminatory or preferential because 
the Commission's existing transmission planning and cost allocation 
requirements do not require transmission providers to: (1) perform a 
sufficiently long-term assessment of transmission needs that identifies 
Long-Term Transmission Needs; \5\ (2) adequately account on a forward-
looking basis for known determinants of Long-Term Transmission Needs; 
and (3) consider the broader set of benefits of regional transmission 
facilities planned to meet those Long-Term Transmission Needs. 
Accordingly, we believe that it is necessary to revisit existing 
transmission planning and cost allocation requirements. We conclude 
that adopting the reforms of this final order, as previously 
contemplated in the notice of proposed rulemaking (NOPR),\6\ will 
remedy the identified deficiencies in existing regional and local 
transmission planning and cost allocation requirements, as discussed 
below, and will ensure the identification, evaluation, and selection, 
as well as the allocation of the costs, of more efficient or cost-
effective regional transmission solutions to address Long-Term 
Transmission Needs.
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    \1\ 16 U.S.C. 824e.
    \2\ Section 201(e) of the FPA, 16 U.S.C. 824(e), defines 
``public utility'' to mean ``any person who owns or operates 
facilities subject to the jurisdiction of the Commission under this 
subchapter.'' As stated in the Order No. 888 pro forma Open Access 
Transmission Tariff (OATT), ``transmission provider'' is a ``public 
utility (or its Designated Agent) that owns, controls, or operates 
facilities used for the transmission of electric energy in 
interstate commerce and provides transmission service under the 
Tariff.'' Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Servs. by Pub. Utils.; Recovery of 
Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888, 
61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 31,036 (1996) 
(cross-referenced at 75 FERC ] 61,080), order on reh'g, Order No. 
888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ] 31,048 
(cross-referenced at 78 FERC ] 61,220), order on reh'g, Order No. 
888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C, 82 
FERC ] 61,046 (1998), aff'd in relevant part sub nom. Transmission 
Access Pol'y Study Grp. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), 
aff'd sub nom. N.Y. v. FERC, 535 U.S. 1 (2002); Pro forma OATT 
section I.1 (Definitions). The term ``transmission provider'' 
includes a public utility transmission owner when the transmission 
owner is separate from the transmission provider, as is the case in 
regional transmission organizations (RTO) and independent system 
operators (ISO).
    \3\ Preventing Undue Discrimination & Preference in Transmission 
Serv., Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & 
Regs. ] 31,241, 118 FERC ] 61,119 (2007), order on reh'g, Order No. 
890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ] 31,261 
(2007) (cross-referenced at 118 FERC ] 61,119), order on reh'g and 
clarification, Order No. 890-B, 73 FR 39092 (July 8, 2008), 123 FERC 
] 61,299 (2008), order on reh'g, Order No. 890-C, 74 FR 12540 (Mar. 
25, 2009), 126 FERC ] 61,228 (2009), order on clarification, Order 
No. 890-D, 74 FR 61511 (Nov. 25, 2009), 129 FERC ] 61,126 (2009).
    \4\ Transmission Plan. & Cost Allocation by Transmission Owning 
& Operating Pub. Utils., Order No. 1000, 76 FR 49842 (Aug. 11, 
2011), 136 FERC ] 61,051 (2011), Order No. 1000-A, 77 FR 32184 (May 
31, 2012), 139 FERC ] 61,132 (2012), order on reh'g & clarification, 
Order No. 1000-B, 141 FERC ] 61,044 (2012), aff'd sub nom. S.C. Pub. 
Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014).
    \5\ All capitalized terms are defined below. Infra Use of Terms 
section.
    \6\ Bldg. for the Future Through Elec. Reg'l Transmission 
Planning & Cost Allocation & Generator Interconnection, 87 FR 26504 
(May 4, 2022), 179 FERC ] 61,028 (2022) (NOPR); see also Bldg. for 
the Future Through Elec. Reg'l Transmission Planning & Cost 
Allocation & Generator Interconnection, 86 FR 40266 (July 27, 2021), 
176 FERC ] 61,024 (2021) (advanced notice of proposed rulemaking 
(ANOPR)).
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    2. Specifically, the reforms adopted in this final order require 
transmission providers in each transmission planning region to 
participate in a regional transmission planning process that includes 
Long-Term Regional Transmission Planning.\7\ This final order adopts 
specific requirements regarding how transmission providers must conduct 
Long-Term Regional Transmission Planning, including, among other 
things, the use of scenarios to identify Long-Term Transmission Needs 
and Long-Term Regional Transmission Facilities to meet those needs.
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    \7\ For purposes of this final order, and consistent with Order 
No. 1000, a transmission planning region is one in which 
transmission providers, in consultation with stakeholders and 
affected states, have agreed to participate for purposes of regional 
transmission planning and development of a single regional 
transmission plan. See Order No. 1000, 136 FERC ] 61,051 at P 160.
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    3. This final order also requires transmission providers to measure 
and use at least the seven specified benefits to evaluate Long-Term 
Regional Transmission Facilities as part of Long-Term Regional 
Transmission Planning. In addition, this final order requires 
transmission providers to calculate the benefits of Long-Term Regional 
Transmission Facilities over a time horizon that covers, at a minimum, 
20 years starting from the estimated in-service date of the 
transmission facilities and requires that this minimum 20-year benefit 
horizon be used both for the evaluation and selection of Long-Term 
Regional Transmission Facilities in the regional transmission plan for 
purposes of cost allocation.\8\
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    \8\ We recognize that some transmission planning regions may 
include Long-Term Regional Transmission Facilities, or a portfolio 
of such Facilities, in a regional transmission plan, but may not 
necessarily include these Facilities for purposes of cost 
allocation. See Order No. 1000, 136 FERC ] 61,051 at P 63. For 
purposes of this final order, unless otherwise noted, when 
referencing Long-Term Regional Transmission Facilities (or a 
portfolio of such Facilities) that are selected, we intend 
``selected'' to mean that those Facilities are selected in the 
regional transmission plan for purposes of cost allocation.
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    4. This final order requires transmission providers to include in 
their OATTs an evaluation process, including selection criteria, that 
they will use to identify and evaluate Long-Term Regional Transmission 
Facilities for potential selection to address Long-Term Transmission 
Needs.
    5. Further, this final order requires transmission providers to 
file one or more ex ante Long-Term Regional Transmission Cost 
Allocation Methods to allocate the costs of Long-Term Regional 
Transmission Facilities (or a portfolio of such Facilities) that are 
selected. This final order further permits, but does not require,

[[Page 49285]]

transmission providers to adopt a State Agreement Process, wherein 
Relevant State Entities agree to such a State Agreement Process that 
would provide up to six months after selection for its participants to 
determine, and transmission providers to file, a cost allocation method 
for specific Long-Term Regional Transmission Facilities. This final 
order establishes a six-month time period (Engagement Period), during 
which transmission providers must: (1) provide notice of the starting 
and end dates for the six-month time period; (2) post contact 
information that Relevant State Entities may use to communicate with 
transmission providers about any agreement among Relevant State 
Entities on a Long-Term Regional Transmission Cost Allocation Method(s) 
and/or a State Agreement Process, as well as a deadline for 
communicating such agreement; and (3) provide a forum for negotiation 
of a Long-Term Regional Transmission Cost Allocation Method(s) and/or a 
State Agreement Process that enables robust participation by Relevant 
State Entities.
    6. This final order also requires transmission providers to include 
in their OATTs a process to provide Relevant State Entities and 
interconnection customers the opportunity to voluntarily fund the cost 
of, or a portion of the cost of, a Long-Term Regional Transmission 
Facility that otherwise would not meet the transmission providers' 
selection criteria. This final order requires transmission providers to 
include in their OATTs provisions that require transmission providers--
in certain circumstances--to reevaluate Long-Term Regional Transmission 
Facilities that previously were selected.
    7. In addition, this final order requires that transmission 
providers evaluate for potential selection in their existing Order No. 
1000 regional transmission planning processes regional transmission 
facilities that will address certain identified interconnection-related 
transmission needs associated with certain interconnection-related 
network upgrades \9\ originally identified through the generator 
interconnection process.
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    \9\ The Commission's pro forma Large Generator Interconnection 
Procedures (LGIP) and pro forma Large Generator Interconnection 
Agreement (LGIA) provide that, ``Network Upgrades shall mean the 
additions, modifications, and upgrades to the Transmission 
Provider's Transmission System required at or beyond the point at 
which the Interconnection Facilities connect to the Transmission 
Provider's Transmission System to accommodate the interconnection of 
the Large Generating Facility to the Transmission Provider's 
Transmission System.'' See Improvements to Generator Interconnection 
Procedures & Agreements, Order No. 2023, 88 FR 61014 (Sept. 6, 
2023), 184 FERC ] 61,054, at P 13 n.23, order on reh'g, 185 FERC ] 
61,063 (2023), order on reh'g, Order No. 2023-A, 89 FR 27006 (Apr. 
16, 2024), 186 FERC ] 61,199 (2024). In this final order, we refer 
to network upgrades developed through the generator interconnection 
process as interconnection-related network upgrades.
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    8. This final order requires transmission providers in each 
transmission planning region to consider more fully the alternative 
transmission technologies of dynamic line ratings, advanced power flow 
control devices, advanced conductors, and transmission switching in 
Long-Term Regional Transmission Planning and existing Order No. 1000 
regional transmission planning and cost allocation processes.
    9. This final order does not finalize the NOPR proposal to not 
permit transmission providers to take advantage of the recovery of 100% 
of construction work in progress for Long-Term Regional Transmission 
Facilities, and the Commission will instead continue to consider 
transmission incentives issues in other proceedings. This final order 
similarly does not finalize the NOPR proposal with respect to 
permitting the exercise of Federal rights of first refusal for selected 
transmission facilities, conditioned on the incumbent transmission 
provider with the Federal right of first refusal establishing joint 
ownership of the transmission facilities, and the Commission will 
instead continue considering the NOPR proposal and potential Federal 
right of first refusal issues in other proceedings.
    10. This final order adopts the NOPR proposal to require 
transmission providers to adopt enhanced transparency requirements for 
local transmission planning processes and improve coordination between 
regional and local transmission planning with the aim of identifying 
potential opportunities to ``right-size'' replacement transmission 
facilities.
    11. This final order requires transmission providers to revise 
their interregional transmission coordination processes to reflect the 
Long-Term Regional Transmission Planning reforms adopted in this final 
order. This final order also requires that transmission providers meet 
additional information sharing and transparency requirements with 
respect to their interregional transmission coordination processes.
    12. This final order requires that each transmission provider 
submit a compliance filing within ten months of the effective date of 
this final order revising its OATT and other document(s) subject to the 
Commission's jurisdiction to demonstrate that it meets the requirements 
of this final order, with the exception of those requirements adopted 
in the Interregional Transmission Coordination section in this final 
order. This final order requires that each transmission provider submit 
a compliance filing within 12 months of the effective date of this 
final order revising its OATT and other document(s) subject to the 
Commission's jurisdiction as necessary to demonstrate that it meets the 
interregional transmission coordination requirements adopted in this 
final order.
    13. We recognize that transmission providers have ongoing efforts 
to address transmission planning and cost allocation. This final order 
is not intended to interfere with the potential progress represented by 
those efforts, and we encourage transmission providers to continue to 
innovate to improve their transmission planning and cost allocation 
processes.

A. Historical Framework: Order Nos. 888, 890, and 1000

    14. Over the last several decades, the Commission has taken 
multiple significant actions on transmission planning and cost 
allocation, including issuing Order Nos. 888, 890, and 1000. In 1996, 
the Commission issued Order No. 888, which implemented open access to 
transmission facilities owned, operated, or controlled by a public 
utility and included certain minimum requirements for transmission 
planning. In 2007, the Commission issued Order No. 890 to address 
identified deficiencies in the pro forma OATT after more than 10 years 
of experience since Order No. 888. Among other OATT reforms, the 
Commission required all public utility transmission providers' local 
transmission planning processes to satisfy nine transmission planning 
principles: (1) coordination; (2) openness; (3) transparency; (4) 
information exchange; (5) comparability; (6) dispute resolution; (7) 
regional participation; (8) economic planning studies; and (9) cost 
allocation for new projects.\10\
---------------------------------------------------------------------------

    \10\ Order No. 890, 118 FERC ] 61,119 at PP 418-601.
---------------------------------------------------------------------------

    15. In 2011, the Commission recognized the need for further 
transmission planning reforms with its issuance of Order No. 1000. The 
Commission based the reforms it adopted in Order No. 1000 on changes in 
the energy industry, its experience implementing Order No. 890, and a 
robust record developed through technical conferences and comments

[[Page 49286]]

from a diverse range of stakeholders.\11\ The Commission stated in 
Order No. 1000 that ``the electric industry is currently facing the 
possibility of substantial investment in future transmission facilities 
to meet the challenge of maintaining reliable service at a reasonable 
cost.'' \12\ In establishing the requirements of Order No. 1000, the 
Commission found that the existing requirements of Order No. 890 were 
not adequate, noting that Order No. 1000 ``expands upon the reforms 
begun in Order No. 890 by addressing new concerns that have become 
apparent in the Commission's ongoing monitoring of these matters.'' 
\13\ The Commission then enumerated multiple concerns that it had 
regarding existing transmission planning practices, including concerns 
about: (1) the lack of an affirmative obligation to develop a 
transmission plan evaluating if a regional transmission facility ``may 
be more efficient or cost-effective than solutions identified in local 
transmission planning processes''; (2) the lack of a requirement to 
address Public Policy Requirements; \14\ (3) the Federal right of first 
refusal for incumbent transmission developers to build upgrades to 
their existing transmission facilities; (4) the lack of procedures to 
identify and evaluate the benefits of interregional transmission 
facilities; and (5) cost allocation for regional and interregional 
transmission facilities.\15\
---------------------------------------------------------------------------

    \11\ For purposes of this final order, and consistent with Order 
No. 1000, a stakeholder includes any party interested in the 
transmission planning processes. See Order No. 1000, 136 FERC ] 
61,051 at P 151 n.143.
    \12\ Id. P 2.
    \13\ Id. P 21.
    \14\ Public Policy Requirements are requirements established by 
local, state, or Federal laws or regulations (i.e., enacted statutes 
passed by the legislature and signed by the executive and 
regulations promulgated by a relevant jurisdiction, whether within a 
state or at the Federal level). Id. P 2. Order No. 1000-A clarified 
that Public Policy Requirements include local laws or regulations 
passed by a local governmental entity, such as a municipal or county 
government. Order No. 1000-A, 139 FERC ] 61,132 at P 319.
    \15\ Order No. 1000, 136 FERC ] 61,051 at P 3.
---------------------------------------------------------------------------

    16. Order No. 1000 included reforms intended to ensure that the 
transmission planning and cost allocation requirements embodied in the 
pro forma OATT could support the development of more efficient or cost-
effective transmission facilities.\16\ The reforms in Order No. 1000 
included: (1) regional transmission planning; (2) transmission needs 
driven by Public Policy Requirements; (3) nonincumbent transmission 
developer reforms; (4) regional and interregional cost allocation, 
including a set of principles for each category of cost allocation; and 
(5) interregional transmission coordination. The reforms focused on the 
process by which transmission providers engage in regional transmission 
planning and the associated cost allocation rather than on the outcomes 
of the process.\17\
---------------------------------------------------------------------------

    \16\ Id. PP 11-12, 42-44; Order No. 1000-A, 139 FERC ] 61,132 at 
PP 3, 4-6.
    \17\ Order No. 1000, 136 FERC ] 61,051 at P 12.
---------------------------------------------------------------------------

    17. Among other regional transmission planning reforms in Order No. 
1000, the Commission required that the following Order No. 890 
transmission planning principles apply to regional transmission 
planning processes: (1) coordination; (2) openness; (3) transparency; 
(4) information exchange; (5) comparability; (6) dispute resolution; 
and (7) economic planning studies.\18\
---------------------------------------------------------------------------

    \18\ The Commission did not include the regional participation 
or cost allocation transmission planning principles with respect to 
regional transmission planning processes because those issues were 
addressed by other reforms in Order No. 1000. Id. P 151.
---------------------------------------------------------------------------

    18. In addition, with respect to the Order No. 1000 reforms, the 
Commission made a distinction between a transmission facility 
``included'' in a regional transmission plan and a transmission 
facility ``selected.'' A transmission facility selected in a regional 
transmission plan for purposes of cost allocation is a transmission 
facility that has been selected pursuant to a transmission planning 
region's Commission-approved regional transmission planning process for 
inclusion in a regional transmission plan for purposes of cost 
allocation because it is a more efficient or cost-effective 
transmission facility needed to meet regional transmission needs. Both 
regional transmission facilities and interregional transmission 
facilities are eligible for potential ``selection'' in a regional 
transmission plan for purposes of cost allocation.\19\
---------------------------------------------------------------------------

    \19\ Id. P 63. A regional transmission facility and an 
interregional transmission facility are defined below. Infra Use of 
Terms section.
---------------------------------------------------------------------------

    19. Selected transmission facilities often will not comprise all of 
the transmission facilities that are included in a regional 
transmission plan.\20\ Some transmission facilities are merely ``rolled 
up'' and listed in a regional transmission plan without going through 
an analysis at the regional level, and/or are merely considered for 
reliability implications upon a transmission system, and therefore, are 
not eligible for selection and regional cost allocation.\21\ For 
example, a local transmission facility is a transmission facility 
located solely within a transmission provider's retail distribution 
service territory or footprint that is not selected.\22\ Thus, a local 
transmission facility may be rolled up and ``included'' in a regional 
transmission plan for informational purposes, but it is not 
``selected.''
---------------------------------------------------------------------------

    \20\ Order No. 1000, 136 FERC ] 61,051 at P 63.
    \21\ Id. PP 7, 226, 318.
    \22\ Id. P 63. The Commission clarified in Order No. 1000-A that 
a local transmission facility is one that is located within the 
geographical boundaries of a public utility transmission provider's 
retail distribution service territory, if it has one; otherwise, the 
area is defined by the public utility transmission provider's 
footprint. In the case of an RTO/ISO whose footprint covers the 
entire region, a local transmission facility is defined by reference 
to the retail distribution service territories or footprints of its 
underlying transmission owing members. Order No. 1000-A, 139 FERC ] 
61,132 at P 429.
---------------------------------------------------------------------------

B. ANOPR and Technical Conference

    20. In July 2021, the Commission issued the ANOPR \23\ presenting 
potential reforms to improve the regional transmission planning and 
cost allocation and generator interconnection processes. In issuing the 
ANOPR, the Commission noted that, in part because more than a decade 
had passed since Order No. 1000, it was now an appropriate time to 
review its regulations governing regional transmission planning and 
cost allocation to determine whether reforms are needed to ensure 
Commission-jurisdictional rates remain just and reasonable and not 
unduly discriminatory or preferential.\24\ The Commission noted that 
the electricity sector is transforming as the generation fleet shifts 
from resources located close to population centers toward resources 
that may often be located far from load centers. The Commission also 
highlighted the growth of new resources seeking to interconnect to the 
transmission system and that the differing characteristics of those 
resources are creating new demands on the transmission system. The 
Commission explained that ensuring just and reasonable Commission-
jurisdictional rates during these changes, while maintaining grid 
reliability, remains the Commission's priority in adopting requirements 
for the regional transmission planning and cost allocation and 
generator interconnection processes. As a result, the Commission issued 
the ANOPR to consider whether there should be changes in the regional 
transmission planning and cost allocation and generator interconnection 
processes and, if so, which changes are necessary to ensure that 
Commission-jurisdictional rates remain just and reasonable and not 
unduly

[[Page 49287]]

discriminatory or preferential and that reliability is maintained.
---------------------------------------------------------------------------

    \23\ ANOPR, 176 FERC ] 61,024.
    \24\ Id. P 3.
---------------------------------------------------------------------------

    21. On November 15, 2021, the Commission convened a staff-led 
technical conference (November 2021 Technical Conference or Technical 
Conference) to examine in detail issues and potential reforms related 
to regional transmission planning as described in the ANOPR. 
Specifically, the Technical Conference included three panels covering 
issues to consider in long-term scenarios, consideration of long-term 
scenarios in regional transmission planning processes, and identifying 
geographic zones with high renewable resource potential for use in 
regional transmission planning processes.\25\ Following the Technical 
Conference, the Commission invited all interested persons to file 
comments to address issues raised during the Technical Conference.
---------------------------------------------------------------------------

    \25\ Bldg. for the Future Through Elec. Reg'l Transmission 
Planning & Cost Allocation & Generator Interconnection, Further 
Supplemental Notice of Technical Conference, Docket No. RM21-17-000 
(issued Nov. 12, 2021) (attaching agenda).
---------------------------------------------------------------------------

C. Joint Federal-State Task Force on Electric Transmission

    22. On June 17, 2021, the Commission established a Joint Federal-
State Task Force on Electric Transmission (Task Force) to formally 
explore broad categories of transmission-related topics.\26\ The 
Commission explained that the development of new transmission 
infrastructure implicates a host of different issues, including how to 
plan and pay for these facilities. Given that Federal and state 
regulators each have authority over transmission-related issues and 
given the impact of transmission infrastructure development on numerous 
different priorities of Federal and state regulators, the Commission 
determined that the topic was ripe for greater Federal-state 
coordination and cooperation.\27\ The Task Force was composed of all 
sitting FERC Commissioners as well as representatives from 10 state 
commissions nominated by the National Association of Regulatory Utility 
Commissioners (NARUC), with two originating from each NARUC region.\28\
---------------------------------------------------------------------------

    \26\ Joint Fed.-State Task Force on Elec. Transmission, 175 FERC 
] 61,224, at PP 1, 6 (2021).
    \27\ Id. P 2.
    \28\ An up-to-date list of Task Force members, as well as 
additional information on the Task Force, is available on the 
Commission's website at: https://www.ferc.gov/TFSOET. Public 
materials related to the Task Force, including transcripts from 
public meetings, are available in the Commission's eLibrary in 
Docket No. AD21-15-000.
---------------------------------------------------------------------------

    23. The Task Force has convened multiple formal meetings with eight 
meetings held thus far to discuss regional transmission planning and 
cost allocation issues, convening on November 10, 2021, February 16, 
2022, May 6, 2022, July 20, 2022, November 15, 2022, February 15, 2023, 
July 16, 2023, and February 28, 2024.
    24. The discussion at the November 2021 meeting was focused on 
incorporating state perspectives into regional transmission 
planning.\29\ The February 2022 meeting included discussion of specific 
categories and types of transmission benefits that transmission 
providers should consider for the purposes of transmission planning and 
cost allocation.\30\ The May 2022 meeting focused on barriers to the 
efficient, expeditious, and reliable interconnection of new 
resources.\31\ The July 2022 meeting focused on interregional 
transmission planning and transmission project development and the 
NOPR.\32\ The November 2022 meeting focused on regulatory gaps and 
challenges in oversight of transmission development.\33\ The February 
2023 meeting focused on the physical security of the Nation's 
transmission system, and featured guest speakers from the North 
American Electric Reliability Corporation and US DOE.\34\ The July 2023 
meeting focused on grid enhancing technologies, featuring a guest 
speaker from the Electric Power Research Institute.\35\ The February 
2024 meeting focused on transmission siting, featuring guest speakers 
from US DOE.\36\
---------------------------------------------------------------------------

    \29\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued Oct. 27, 2021) (attaching 
agenda).
    \30\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued Feb. 2, 2022) (attaching 
agenda).
    \31\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued Apr. 22, 2022) (attaching 
agenda).
    \32\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued June 30, 2022) (attaching 
agenda).
    \33\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued Nov. 1, 2022) (attaching 
agenda).
    \34\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued Feb. 1, 2023) (attaching 
agenda).
    \35\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued June 30, 2023) (attaching 
agenda).
    \36\ Joint Fed.-State Task Force on Elec. Transmission, Notice 
of Meeting, Docket No. AD21-15-000 (issued Feb. 13, 2024) (attaching 
agenda).
---------------------------------------------------------------------------

    25. In light of the Task Force expiring three years from its first 
public meeting, i.e., on November 10, 2024,\37\ on March 21, 2024, the 
Commission established the Federal and State Current Issues 
Collaborative (Collaborative).\38\ The Collaborative will be comprised 
of all Commissioners, as well as representative from 10 state 
commissions. The Collaborative will provide a venue for Federal and 
state regulators to share perspectives, increase understanding, and 
where appropriate, identify potential solutions regarding challenges 
and coordination on matters that impact specific state and Federal 
regulatory jurisdiction.\39\
---------------------------------------------------------------------------

    \37\ Joint Fed.-State Task Force on Elec. Transmission, 175 FERC 
] 61,224 at P 4.
    \38\ Joint Fed.-State Task Force on Elec. Transmission, 186 FERC 
] 61,189 (2024).
    \39\ Id. PP 5-6.
---------------------------------------------------------------------------

D. Notice of Proposed Rulemaking

    26. On April 21, 2022, the Commission issued the NOPR, proposing 
reforms focused on long-term regional transmission planning and cost 
allocation processes. In particular, the Commission proposed in the 
NOPR that transmission providers in each transmission planning region 
participate in a regional transmission planning process that includes 
Long-Term Regional Transmission Planning.\40\ The Commission also 
proposed to require that transmission providers develop Long-Term 
Scenarios as part of Long-Term Regional Transmission Planning.\41\
---------------------------------------------------------------------------

    \40\ NOPR, 179 FERC ] 61,028 at PP 64, 68.
    \41\ Id. P 84.
---------------------------------------------------------------------------

    27. The Commission proposed that transmission providers consider, 
as part of their Long-Term Regional Transmission Planning, regional 
transmission facilities that address certain interconnection-related 
transmission needs that the transmission provider has identified 
multiple times in the generator interconnection process but that have 
never been constructed due to the withdrawal of the relevant 
interconnection request(s).\42\
---------------------------------------------------------------------------

    \42\ Id. P 166.
---------------------------------------------------------------------------

    28. The Commission proposed 12 benefits that transmission providers 
may consider in Long-Term Regional Transmission Planning and cost 
allocation processes.\43\ The Commission stated that the list of 
potential benefits was neither mandatory nor exhaustive, and that 
pursuant to the proposal, transmission providers would have flexibility 
to propose which benefits to use as part of their Long-Term Regional 
Transmission Planning.\44\
---------------------------------------------------------------------------

    \43\ Id. P 185.
    \44\ Id. P 184.
---------------------------------------------------------------------------

    29. The Commission proposed, with regard to the selection of Long-
Term Regional Transmission Facilities in the regional transmission plan 
for purposes of cost allocation, to require that transmission 
providers, as part of their Long-Term Regional Transmission Planning, 
include in their OATTs: (1) transparent and not unduly

[[Page 49288]]

discriminatory criteria, which seek to maximize benefits to consumers 
over time without over-building transmission facilities, to identify 
and evaluate transmission facilities for potential selection that 
address transmission needs driven by changes in the resource mix and 
demand; and (2) a process to coordinate with the Relevant State 
Entities in developing such criteria.\45\
---------------------------------------------------------------------------

    \45\ Id. P 241.
---------------------------------------------------------------------------

    30. The Commission proposed to require transmission providers to 
more fully consider the incorporation into transmission facilities of 
dynamic line ratings and advanced power flow control devices in 
regional transmission planning and cost allocation processes.\46\
---------------------------------------------------------------------------

    \46\ Id. P 272.
---------------------------------------------------------------------------

    31. The Commission proposed to require, with regard to allocating 
the costs of Long-Term Regional Transmission Facilities, transmission 
providers to revise their OATTs to include: (1) a Long-Term Regional 
Transmission Cost Allocation Method to allocate the costs of Long-Term 
Regional Transmission Facilities; (2) a State Agreement Process by 
which one or more Relevant State Entities may voluntarily agree to a 
cost allocation method; or (3) a combination thereof.\47\ The 
Commission proposed to require transmission providers to seek the 
agreement of Relevant State Entities within the transmission planning 
region regarding the Long-Term Regional Transmission Cost Allocation 
Method, State Agreement Process, or combination thereof.\48\ The 
Commission proposed to require transmission providers to identify on 
compliance the benefits they will use in ex ante Long-Term Regional 
Transmission Cost Allocation Methods associated with Long-Term Regional 
Transmission Planning, how they will calculate those benefits, and how 
the benefits will reasonably reflect the benefits of regional 
transmission facilities to meet identified transmission needs driven by 
changes in the resource mix and demand.\49\
---------------------------------------------------------------------------

    \47\ Id. P 302.
    \48\ Id. P 303.
    \49\ Id. P 326.
---------------------------------------------------------------------------

    32. The Commission further proposed to not permit transmission 
providers to take advantage of the allowance for inclusion of 100% of 
construction work in progress costs in rate base in certain 
circumstances for Long-Term Regional Transmission Facilities.\50\
---------------------------------------------------------------------------

    \50\ Id. P 333.
---------------------------------------------------------------------------

    33. Finally, the Commission proposed to permit the exercise of 
Federal rights of first refusal for selected transmission facilities, 
conditioned on the incumbent transmission provider with the Federal 
right of first refusal for such regional transmission facilities 
establishing joint ownership of the transmission facilities consistent 
with certain proposed requirements described in the NOPR.\51\
---------------------------------------------------------------------------

    \51\ Id. P 351.
---------------------------------------------------------------------------

    34. The Commission also proposed to require transmission providers 
to revise the regional transmission planning process in their OATTs 
with additional provisions to enhance transparency of: (1) the 
criteria, models, and assumptions that they use in their local 
transmission planning process; (2) the local transmission needs that 
they identify through that process; and (3) the potential local or 
regional transmission facilities that they will evaluate to address 
those local transmission needs.\52\ The Commission proposed to require 
transmission providers to evaluate whether transmission facilities 
operating at or above 230 kV that an individual transmission provider 
that owns the transmission facility anticipates replacing in-kind with 
a new transmission facility during the next 10 years can be ``right-
sized'' to more efficiently or cost-effectively address regional 
transmission needs identified in Long-Term Regional Transmission 
Planning.\53\
---------------------------------------------------------------------------

    \52\ Id. P 400.
    \53\ Id. P 403.
---------------------------------------------------------------------------

    35. The Commission further proposed to require transmission 
providers in neighboring transmission planning regions to revise their 
existing interregional transmission coordination procedures (and 
regional transmission planning processes as needed) to provide for: (1) 
the sharing of information regarding their respective transmission 
needs identified in Long-Term Regional Transmission Planning, as well 
as potential transmission facilities to meet those needs; and (2) the 
identification and joint evaluation of interregional transmission 
facilities that may be more efficient or cost-effective transmission 
facilities to address transmission needs identified through Long-Term 
Regional Transmission Planning.\54\ Finally, the Commission proposed to 
require transmission providers in neighboring transmission planning 
regions to revise their interregional transmission coordination 
procedures (and regional transmission planning processes as needed) to 
allow an entity to propose an interregional transmission facility in 
the regional transmission planning process as a potential solution to 
transmission needs identified through Long-Term Regional Transmission 
Planning.\55\
---------------------------------------------------------------------------

    \54\ Id. P 427.
    \55\ Id. P 428.
---------------------------------------------------------------------------

E. High-Level Overview of NOPR Comments

    36. The Commission received a great many comments from a diverse 
set of parties in response to the NOPR.\56\ One hundred and ninety-six 
parties, including Federal agencies, state regulatory commissions, 
state policy makers and other state representatives, ratepayer 
advocates, municipalities, RTOs/ISOs, RTO/ISO market monitors, 
transmission providers, transmission-dependent utilities, electric 
cooperatives, municipal power providers, independent power producers, 
transmission developers, generation trade associations, transmission 
trade associations, industry interest groups, consumer interest groups, 
energy policy and law interest groups, individual businesses, 
landowners, and individuals, filed initial comments that totaled over 
15,000 pages with attachments. A similarly diverse set of 92 parties 
filed reply comments that totaled nearly 1,900 pages.
---------------------------------------------------------------------------

    \56\ See appendix A for a list of commenters and the abbreviated 
names of commenters that are used in this final order.
---------------------------------------------------------------------------

F. Use of Terms

    37. Before turning to the detailed requirements of this final 
order, we note several of the key terms used herein. We further address 
the definitions of these terms, including any modifications to 
definitions proposed in the NOPR, in the relevant later sections of 
this final order.
    38. For purposes of this final order, Long-Term Regional 
Transmission Planning means regional transmission planning on a 
sufficiently long-term, forward-looking, and comprehensive basis to 
identify Long-Term Transmission Needs, identify transmission facilities 
that meet such needs, measure the benefits of those transmission 
facilities, and evaluate those transmission facilities for potential 
selection in the regional transmission plan for purposes of cost 
allocation as the more efficient or cost-effective regional 
transmission facilities to meet Long-Term Transmission Needs.
    39. For purposes of this final order, Long-Term Transmission Needs 
are transmission needs identified through Long-Term Regional 
Transmission Planning by, among other things and as discussed in this 
final order, running

[[Page 49289]]

scenarios and considering the enumerated categories of factors.\57\
---------------------------------------------------------------------------

    \57\ Further discussion on Long-Term Transmission Needs can be 
found below. Infra Development of Long-Term Scenarios subsection 
under the Long-Term Regional Transmission Planning section.
---------------------------------------------------------------------------

    40. For purposes of this final order, Long-Term Scenarios are 
scenarios that incorporate various assumptions using best available 
data inputs about the future electric power system over a sufficiently 
long-term, forward-looking transmission planning horizon to identify 
Long-Term Transmission Needs and enable the identification and 
evaluation of transmission facilities to meet such transmission needs.
    41. For purposes of this final order, a Long-Term Regional 
Transmission Facility is a regional transmission facility \58\ that is 
identified as part of Long-Term Regional Transmission Planning to 
address Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \58\ For purposes of this final order, and consistent with Order 
No. 1000, a regional transmission facility is a transmission 
facility located entirely in one transmission planning region. An 
interregional transmission facility is a transmission facility that 
is located in two or more transmission planning regions. A local 
transmission facility is a transmission facility located solely 
within a transmission provider's retail distribution service 
territory or footprint that is not selected in the regional 
transmission plan for purposes of cost allocation. Order No. 1000, 
136 FERC ] 61,051 at PP 63, 482 n.374.
---------------------------------------------------------------------------

    42. For purposes of this final order, best available data inputs 
are data inputs that are timely, developed using best practices and 
diverse and expert perspectives, and adopted via a process that 
satisfies the transmission planning principles of Order Nos. 890 and 
1000, and reflect the list of factors that transmission providers 
account for in their Long-Term Scenarios.
    43. For purposes of this final order, a Long-Term Regional 
Transmission Cost Allocation Method is an ex ante regional cost 
allocation method for one or more selected Long-Term Regional 
Transmission Facilities (or a portfolio of such Facilities) that are 
selected in the regional transmission plan for purposes of cost 
allocation.
    44. For purposes of this final order, a Relevant State Entity is 
any state entity responsible for electric utility regulation or siting 
electric transmission facilities within the state or portion of a state 
located in the transmission planning region, including any state entity 
as may be designated for that purpose by the law of such state.
    45. For purposes of this final order, a State Agreement Process is 
a process by which one or more Relevant State Entities may voluntarily 
agree to a cost allocation method for Long-Term Regional Transmission 
Facilities (or a portfolio of such Facilities) before or no later than 
six months after they are selected.
    46. For purposes of this final order, federally-recognized Tribes 
are those Tribes listed in the most recent notice provided by the 
Bureau of Indian Affairs and published in the Federal Register.\59\
---------------------------------------------------------------------------

    \59\ See, e.g., Indian Entities Recognized by and Eligible to 
Receive Servs. from the U.S. Bureau of Indian Affairs, Federal 
Register, 89 FR 944 (Jan. 8, 2024).
---------------------------------------------------------------------------

II. The Overall Need for Reform

A. NOPR Proposal

    47. The Commission issued the NOPR on April 21, 2022, proposing to 
reform the pro forma OATT and the pro forma LGIA to remedy deficiencies 
in the Commission's existing regional transmission planning and cost 
allocation requirements. The Commission stated that, over the last 25 
years, it has undertaken a series of significant reforms to ensure that 
transmission planning and cost allocation processes result in 
Commission-jurisdictional rates that are just and reasonable and not 
unduly discriminatory or preferential.\60\ The Commission noted that it 
has now been more than a decade since Order No. 1000--its last 
significant regional transmission planning and cost allocation rule--
and that there is mounting evidence that its regional transmission 
planning and cost allocation requirements may be inadequate to ensure 
that Commission-jurisdictional rates remain just and reasonable and not 
unduly discriminatory or preferential.\61\
---------------------------------------------------------------------------

    \60\ NOPR, 179 FERC ] 61,028 at P 24.
    \61\ Id.
---------------------------------------------------------------------------

    48. The Commission found that, in particular, although transmission 
providers are required to participate in regional transmission planning 
and cost allocation processes under Order No. 1000, it was concerned 
that those processes may not be planning transmission on a sufficiently 
long-term, forward-looking basis to meet transmission needs driven by 
changes in the resource mix and demand. The Commission stated that, as 
a result, the regional transmission planning and cost allocation 
processes that transmission providers adopted to comply with Order No. 
1000 may not be identifying the more efficient or cost-effective 
transmission facilities.\62\ The Commission stated that it was 
concerned that the absence of sufficiently long-term, forward-looking, 
comprehensive transmission planning processes appears to be resulting 
in piecemeal transmission expansion to address relatively near-term 
transmission needs, and that continuing with the status quo approach 
may cause transmission providers to undertake relatively inefficient 
investments in transmission infrastructure, the costs of which are 
ultimately recovered through Commission-jurisdictional rates. The 
Commission stated that this dynamic may result in transmission 
customers paying more than necessary to meet their transmission needs, 
customers forgoing benefits that outweigh their costs, or some 
combination thereof--either or both of which could potentially render 
Commission-jurisdictional rates unjust and unreasonable or unduly 
discriminatory or preferential. Based on the evidence, the Commission 
preliminarily concluded that revisions to its existing transmission 
planning and cost allocation requirements established in Order Nos. 890 
and 1000 are necessary to ensure that Commission-jurisdictional 
services are provided at rates, terms, and conditions that are just and 
reasonable and not unduly discriminatory and preferential.\63\
---------------------------------------------------------------------------

    \62\ Id. PP 24-25.
    \63\ Id. PP 25, 27, 34-35.
---------------------------------------------------------------------------

B. Comments

    49. A significant majority of commenters, including transmission 
providers, transmission developers, transmission customers, members of 
Congress, states, state commissions, consumer advocates, trade 
associations, and public interest organizations, among others, agree 
that existing regional transmission planning and cost allocation 
processes need to be reformed.\64\ Advanced Energy Buyers

[[Page 49290]]

note that the electric system is presently undergoing one of the most 
significant transformations in a century.\65\ Other commenters agree 
that electric energy supply and demand is evolving quickly.\66\ Clean 
Energy Buyers agree with the Commission that there is a need for reform 
to meet these drastic changes in the resource mix and load and to 
ensure continued reliability and cost-effective transmission 
service.\67\
---------------------------------------------------------------------------

    \64\ See, e.g., Acadia Center and CLF Initial Comments at 1-2; 
ACEG Initial Comments at 11-12, 21-22; ACORE Initial Comments at 2-
5; ACORE Supplemental Comments at 1; Advanced Energy Buyers Initial 
Comments at 2-3; AEE Initial Comments at 7-8; AEP Initial Comments 
at 1-3; Amazon Initial Comments at 1-2; Ameren Initial Comments at 
1-2; American Municipal Power Initial Comments at 4; Anbaric Initial 
Comments at 1; Arizona Commission Initial Comments at 3-4; Avangrid 
Initial Comments at 5-6; BP Initial Comments at 3; Breakthrough 
Energy Initial Comments at 5-6; Breakthrough Energy Supplemental 
Comments at 1; Business Council for Sustainable Energy Initial 
Comments at 2-3; California Commission Initial Comments at 1-2; 
California Energy Commission Initial Comments at 1; CAISO Initial 
Comments at 1; City of New Orleans Council Initial Comments at 4, 7-
9; Cross Sector Representatives Supplemental Comments at 1; DC and 
MD Offices of People's Counsel Initial Comments at 4-5; US Senators 
Supplemental Comments at 1; EEI Initial Comments at 4-5; ELCON 
Initial Comments at 4; Enel Initial Comments at 2, 7; ENGIE Initial 
Comments at 1-2; Entergy Initial Comments at 2-3; Environmental 
Legislators Caucus Supplemental Comments at 1; Evergreen Action 
Initial Comments at 1-3; Eversource Initial Comments at 1-2, 5-9; 
Exelon Initial Comments at 1-2; Grid United Initial Comments at 1-2; 
Handy Law Initial Comments at 1-7; Harvard ELI Initial Comments at 
1; Illinois Commission Initial Comments at 3; Indicted PJM TOs 
Initial Comments at 1-2; Indicated US Senators and Representatives 
Initial Comments at 1; Interwest Initial Comments at 2-3; Invenergy 
Initial Comments at 2, 5; ISO-NE Initial Comments at 2, 8-9; ISO/RTO 
Council Initial Comments at 2; Kansas Commission Initial Comments at 
10-11; Massachusetts Attorney General Initial Comments at 3-6; 
Michigan Commission Initial Comments at 2, 4; Michigan State 
Entities Initial Comments at 3-4; Minnesota State Entities Initial 
Comments at 2-3; National Grid Initial Comments at 1, 6; National 
and State Conservation Organizations Initial Comments at 1; NESCOE 
Initial Comments at 2, 7, 14-15; New Jersey Commission Initial 
Comments at 1-2; New York Commission and NYSERDA Initial Comments at 
1-3; NextEra Reply Comments at 1; Non-RTO NASUCA Initial Comments at 
4-5; NYISO Initial Comments at 2-3; Onward Energy Initial Comments 
at 1-2; [Oslash]rsted Initial Comments at 2-3; Pattern Energy 
Initial Comments at 1; PacifiCorp and NV Energy Initial Comments at 
2, 7-8; Pacific Northwest State Agencies Initial Comments at 1, 8; 
PG&E Initial Comments at 1; PIOs Initial Comments at 6-7; Policy 
Integrity Initial Comments at 1-2; Renewable Northwest Initial 
Comments at 3-4; RMI Supplemental Comments at 1-2; SPP Market 
Monitor Initial Comments at 3-4; SEIA Initial Comments at 2; Shell 
Initial Comments at 1, 9; US Senator Barrasso Supplemental Comments 
at 2; Senator Whitehouse Supplemental Comments at 2; Southeast PIOs 
Initial Comments at 1; SREA Initial Comments at 1; State Officials 
Supplemental Comments at 1; TAPS Initial Comments at 1-2; US DOE 
Initial Comments at 1-4; US DOJ and FTC Initial Comments 1, 5; 
Vermont State Entities Initial Comments at 2; Western State 
Representatives Initial Comments at 3-4; WIRES Initial Comments at 
2, 5.
    \65\ Advanced Energy Buyers Initial Comments at 2.
    \66\ See, e.g., AEE Initial Comments at 1; Cross Sector 
Representatives Supplemental Comments at 1; Eversource Initial 
Comments at 5-8 (citing ISO-NE, 2020 Regional Electricity Outlook, 
at 35 (2020)); Indicated PJM TOs Initial Comments at 1-2; Kansas 
Commission Initial Comments at 2; Pattern Energy Initial Comments at 
1; PG&E Initial Comments at 1; Policy Integrity Initial Comments at 
2; Renewable Northwest Initial Comments at 5; State Agencies Initial 
Comments at 12-13; WIRES Initial Comments at 3.
    \67\ Clean Energy Buyers Initial Comments at 7.
---------------------------------------------------------------------------

    50. Many commenters argue that current regional transmission 
planning and cost allocation processes across the country are not 
ensuring efficient and cost-effective transmission development, are not 
satisfying the purposes of Order Nos. 890 and 1000, and are not meeting 
transmission needs at a reasonable cost. For example, several 
commenters assert that Order Nos. 890 and 1000 have not solved 
longstanding problems with regional transmission planning and cost 
allocation.\68\ Northwest and Intermountain claim that Order No. 1000 
has been inadequate to meet transmission needs, particularly in the 
non-RTO/ISO West.\69\ Michigan State Entities assert that the current 
lack of long-term transmission planning has led to significantly higher 
costs for residential ratepayers, costs that will increase without 
reforms.\70\ SREA argues that reform is needed to correct the 
unintended consequences of Order No. 1000 in the Southeast, where 
transmission planning ``has grown into an enormously elaborate and 
extremely expensive black box,'' without any meaningful review by state 
regulatory bodies.\71\
---------------------------------------------------------------------------

    \68\ See, e.g., Acadia Center and CLF Initial Comments at 1; 
ACEG Initial Comments at 17-18, 20 (citing Order No. 1000, 136 FERC 
] 61,051 at P 3; NOPR, 179 FERC ] 61,028 at PP 24-25); AEE Initial 
Comments at 1-2; CARE Coalition Initial Comments at 3; NERC Initial 
Comments at 5; Massachusetts Attorney General Initial Comments at 5-
6; Northwest and Intermountain Initial Comments at 6-7; Pine Gate 
Initial Comments at 8-10; PIOs Initial Comments at 2-3; Southeast 
PIOs Initial Comments at 7-9, 11, 16-17, 43-44; SPP Market Monitor 
Initial Comments at 3-4; SREA Reply Comments at 4; US DOE Initial 
Comments at 3-4, 7-8.
    \69\ Northwest and Intermountain Initial Comments at 6-7.
    \70\ Michigan State Entities Initial Comments at 1-2.
    \71\ SREA Reply Comments at 4.
---------------------------------------------------------------------------

    51. PIOs assert that transmission owners can evade Order No. 1000 
requirements through investments in local transmission projects, which 
has led to billions of dollars in excessive costs.\72\ PIOs explain 
that financial incentives drive utilities to upgrade their own systems 
at the expense of building a more integrated and robust transmission 
system to meet the needs and demands of the future.\73\ PIOs observe 
that, between 2013 and 2017, about one-half of the approximately $70 
billion in aggregate transmission investments by Commission-
jurisdictional transmission owners in RTO/ISO regions were approved 
outside of regional transmission planning processes or with limited 
stakeholder engagement.\74\ Ohio Consumers add that since 2017, less 
than 25% of new transmission investments in Ohio have been associated 
with large regional transmission projects needed for reliability or 
economic efficiency.\75\ Competition Coalition argues that incumbent 
transmission owners have used reliability designations to justify 
projects with higher costs.\76\
---------------------------------------------------------------------------

    \72\ PIOs Initial Comments at 8 (citing Johannes P. 
Pfeifenberger et al., The Brattle Group, Cost Savings Offered by 
Competition in Electric Transmission: Experience to Date and the 
Potential for Additional Customer Value, at 19-20, and Section I 
(Apr. 2019) (Brattle Apr. 2019 Competition Report), https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf).
    \73\ Id. at 6-7.
    \74\ Id. at 9 (citing Brattle Apr. 2019 Competition Report at 
4).
    \75\ Ohio Consumers Initial Comments at 5.
    \76\ Competition Coalition Initial Comments at 15-16.
---------------------------------------------------------------------------

    52. Citing to a report from Lawrence Berkeley National Laboratory, 
US DOE concludes that many existing regional transmission planning 
approaches are likely understating the economic value of new 
transmission. US DOE suggests that the need for increased transmission 
capacity to address persistent and worsening transmission congestion 
demonstrates that these processes may not fully anticipate present and 
future transmission needs.\77\ In addition, US DOE notes the unfair 
burden on interconnection customers that must bear increasing costs, 
especially for interconnection-related network upgrades that provide 
system-wide benefits.\78\ US DOJ and FTC agree that reforms are 
necessary to encourage needed regional and interregional transmission 
investment and that a larger, more integrated transmission system would 
improve resilience, promote competition, and lower costs for 
consumers.\79\
---------------------------------------------------------------------------

    \77\ US DOE Initial Comments at 3-4.
    \78\ Id. at 7-8.
    \79\ US DOJ and FTC Initial Comments at 1, 5 (citing NOPR, 179 
FERC ] 61,028 at P 6; P. R. Brown & A. Botterud, The Value of Inter-
Regional Coordination and Transmission in Decarbonizing the US 
Electricity System, 5 Joule 115, 115-134 (2021); Eric Larson et al., 
Princeton Univ., Net-Zero America: Potential Pathways, 
Infrastructure, and Impacts, at 108 (Oct. 2021), https://netzeroamerica.princeton.edu/the-report).
---------------------------------------------------------------------------

    53. Many commenters contend that inadequate regional transmission 
planning and cost allocation processes have resulted in, or are 
threatening to cause, unjust, unreasonable, and unduly discriminatory 
or preferential rates.\80\ Michigan State Entities cite renewable 
energy curtailments, which limit the supply of energy that customers 
can access, and the lack of regional and interregional transmission 
lines, which limit the transfer of lower-priced power.\81\ New Jersey 
Commission asserts that better transmission planning

[[Page 49291]]

can reduce overall system costs by billions of dollars.\82\ Certain 
TDUs add that Commission action is essential now to ensure that 
necessary transmission expansion occurs in a way that protects 
customers from excessive costs and that results in just and reasonable 
transmission rates.\83\ CARE Coalition argues that the Commission's 
current failure to require transmission planners to internalize siting-
related costs and risks results in unjust, unreasonable, and unduly 
discriminatory or preferential rates.\84\ In a similar vein, 
[Oslash]rsted and Massachusetts Attorney General claim that failure to 
proactively plan for offshore wind generation buildout could lead to 
transmission rates that are unjust, unreasonable, and unduly 
discriminatory or preferential.\85\
---------------------------------------------------------------------------

    \80\ See, e.g., ACORE Initial Comments at 3, AEE Initial 
Comments at 27 (citing NOPR, 179 FERC ] 61,028 at PP 47, 55, 78; 
S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 56); CARE Coalition 
Initial Comments at 17; Certain TDUs Initial Comments at 2; Clean 
Energy Associations Initial Comments at 3, 7; Clean Energy Buyers 
Initial Comments at 10; Harvard ELI Initial Comments at 1; 
Massachusetts Attorney General Initial Comments at 5-6; New Jersey 
Commission Initial Comments at 1-2; PIOs Initial Comments at 6; SEIA 
Initial Comments at 2-3; Southeast PIOs Reply Comments at 2; US DOE 
Initial Comments at 2, 6-7.
    \81\ Michigan State Entities Initial Comments at 3.
    \82\ New Jersey Commission Initial Comments at 3-9.
    \83\ Certain TDUs Initial Comments at 2.
    \84\ CARE Coalition Initial Comments at 17.
    \85\ Massachusetts Attorney General Initial Comments at 5; 
[Oslash]rsted Initial Comments at 3-5.
---------------------------------------------------------------------------

    54. Several commenters agree with the Commission's concerns that 
the expansion of the high-voltage transmission system is increasingly 
occurring outside of the regional transmission planning process through 
other mechanisms such as the generator interconnection process, which 
results in piecemeal transmission development.\86\ AEE agrees that 
limited development of regional transmission facilities, increased 
spending on local transmission projects, and backlogged interconnection 
queues all show that the existing regional transmission planning 
requirements are not sufficient to meet customers' transmission 
needs.\87\ Likewise, Exelon argues that relying on interconnection 
studies as the primary transmission planning method results in 
piecemeal and inefficient transmission investment.\88\ PIOs add that 
many generation developers have to bear the full costs of transmission 
upgrades, which leads to interconnection request withdrawals, 
inefficiencies, and higher system-wide costs.\89\ In addition, Clean 
Energy States note that interconnection queues are extremely large and 
that the current one-plant-at-a-time approach to transmission upgrades 
drives up costs and misses opportunities for improvements to the system 
as a whole.\90\
---------------------------------------------------------------------------

    \86\ See, e.g., Acadia Center and CLF Initial Comments at 3-4; 
Anbaric Initial Comments at 5; Clean Energy Associations Initial 
Comments at 4-7; Exelon Initial Comments at 1-2, 5; Joint Consumer 
Advocates Initial Comments at 5; Non-RTO NASUCA Initial Comments at 
4; [Oslash]rsted Initial Comments at 4-5; Pine Gate Initial Comments 
at 8-10; SEIA Initial Comments at 2; see also AEP Initial Comments 
at 8.
    \87\ AEE Initial Comments at 1-2 (citing NOPR, 179 FERC ] 61,028 
at PP 47-55).
    \88\ Exelon Initial Comments at 5.
    \89\ PIOs Initial Comments at 9-10.
    \90\ Clean Energy States Initial Comments at 2.
---------------------------------------------------------------------------

    55. Non-RTO NASUCA agrees with the Commission that Long-Term 
Regional Transmission Planning is necessary to help alleviate 
generation interconnection issues.\91\ According to Harvard ELI, 
current transmission planning processes have failed to address 
backlogged interconnection queues and operational challenges that are 
best addressed at the regional level, as well as to include inexpensive 
technologies that can increase transmission capacity.\92\
---------------------------------------------------------------------------

    \91\ Non-RTO NASUCA Initial Comments at 4.
    \92\ Harvard ELI Initial Comments at 1.
---------------------------------------------------------------------------

    56. ACEG argues that there is no evidence that any regional 
reliability or economic transmission planning performed in non-RTO/ISO 
regions, like the Southeastern Regional Transmission Planning region 
(SERTP), is equal to or superior to the techniques or outcomes in the 
NOPR.\93\ ACEG further contends that, instead, most new transmission 
facilities built since Order No. 1000 have been built for local 
transmission needs, thereby resulting in less efficient and cost-
effective transmission development that does not address the larger 
needs of the transmission system for reliability and resilience.\94\ 
Relatedly, SREA states that no state fully participates in SERTP, and 
that instead, each state in the Southeast uses its own state planning 
process, with no platform for states to collaborate. As a result, SREA 
argues that ``transmission planning in the Southeast has many holes and 
is threadbare.'' \95\ SREA catalogs deficiencies in many Southeastern 
states' planning processes, including a lack of transparency.\96\
---------------------------------------------------------------------------

    \93\ ACEG Reply Comments at 9 (citing Alabama Commission Initial 
Comments at 2-3; Southern Initial Comments at 5-6, Ex. 2 at 2-3).
    \94\ Id. at 9-10 (citing PIOs Initial Comments at 7).
    \95\ SREA Reply Comments at 4.
    \96\ Id. at 5-18.
---------------------------------------------------------------------------

    57. Western PIOs argue that, outside of CAISO, transmission 
planning in the West is ineffective.\97\ Specifically, Western PIOs 
assert that Western transmission planning groups have not developed new 
transmission projects using their Order No. 1000 transmission planning 
processes, but have instead built transmission projects that their 
utility members have already proposed.\98\ Relatedly, SEIA argues that 
``non-RTO areas do not engage in sufficient or transparent transmission 
planning,'' and that transmission planning in non-RTO/ISO regions is 
exclusionary, based on inconsistent and inaccurate data, and 
disjointed.\99\ More broadly, NRECA contends that incumbent investor-
owned utilities control transmission planning, and that some incumbent 
investor-owned utilities develop transmission without transparency, 
leading to disparities in transmission rates in different RTO/ISO local 
zones.\100\
---------------------------------------------------------------------------

    \97\ Western PIOs Initial Comments at 4-28.
    \98\ Id. at 28.
    \99\ SEIA Reply Comments at 5-6 (citing Southern Initial 
Comments at 13-14).
    \100\ NRECA Initial Comments at 15-16.
---------------------------------------------------------------------------

    58. Several commenters specify other reasons that transmission 
planning reforms are needed.\101\ Americans for Fair Energy Prices 
agree with PIOs that there is a need for regional transmission planning 
instead of the balkanized process that currently exists.\102\ DC and MD 
Offices of People's Counsel assert that the NOPR provides a once-in-a-
generation opportunity to meet the energy transition in a just, 
equitable, efficient, reliable, and resilient fashion by recognizing 
the benefits of long-term transmission planning and developing rules 
that incorporate those broad benefits. DC and MD Offices of People's 
Counsel state that current transmission planning processes do not fully 
consider all of the benefits of transmission development, including 
enhanced reliability and resilience that will serve as a necessary 
bulwark against disruptions caused by extreme weather.\103\ ACEG argues 
that current transmission planning processes have not led to investment 
in interregional transmission capacity, and that more interregional 
transmission capacity could have avoided some of the $25 billion to $70 
billion in yearly costs caused by severe weather events.\104\ EEI 
states that robust transmission development will provide a host of 
benefits for customers, including greater resilience, enhanced system 
reliability, and cost-savings from greater access to low-cost 
resources.\105\ Some commenters emphasize the importance of the 
Commission taking prudent action to remedy deficiencies in the 
Commission's existing regional transmission planning and cost

[[Page 49292]]

allocation requirements,\106\ and to strengthen electric reliability 
and resilience, while controlling costs.\107\
---------------------------------------------------------------------------

    \101\ See, e.g., Americans for Fair Energy Prices Reply Comments 
at 5; SREA Reply Comments at 4.
    \102\ Americans for Fair Energy Prices Reply Comments at 5 
(citing PIOs Initial Comments at 34).
    \103\ DC and MD Offices of People's Counsel Reply Comments at 1-
2.
    \104\ ACEG Initial Comments at 21-22 (citing Grid Strategies, 
LLC, Transmission Makes the Power System Resilient to Extreme 
Weather, at 1-3, 12 (July 2021) (Grid Strategies July 2021 Extreme 
Weather Report)).
    \105\ EEI Supplemental Comments at 1.
    \106\ US Senators Supplemental Comments at 1; Senator Whitehouse 
Supplemental Comments at 2.
    \107\ US Senator Barrasso Supplemental Comments at 1-2.
---------------------------------------------------------------------------

    59. Several commenters argue that the need to reform transmission 
planning includes addressing environmental justice and equity 
issues.\108\ Center for Biological Diversity states that energy justice 
and environmental justice considerations are appropriately included in 
transmission planning.\109\ Center for Biological Diversity further 
asserts that it is within the Commission's authority to consider these 
costs and benefits, as the benefits of decarbonization and related 
energy justice objectives will be far greater than the costs.\110\ 
Grand Rapids NAACP, CARE Coalition, and PIOs argue that to ensure just, 
reasonable, and nondiscriminatory rates, transmission planning must 
consider energy equity and environmental justice.\111\ Grand Rapids 
NAACP further argues that high energy burdens can be unjust, 
unreasonable, and unduly discriminatory or preferential.\112\ Grand 
Rapids NAACP argues that the Commission's duty under the FPA to promote 
the public interest requires it to ensure that energy justice and 
equity considerations are included in transmission planning 
processes.\113\ WE ACT relatedly argues that, due to under-investment, 
the transmission system is unreliable and vulnerable to extreme weather 
events, which is both a reliability and environmental justice issue 
because communities of color and low-income communities are more 
susceptible to power outages during extreme weather.\114\
---------------------------------------------------------------------------

    \108\ See, e.g., CARE Coalition Initial Comments at 2; Center 
for Biological Diversity Initial Comments at 20-24; Environmental 
Groups Supplemental Comments at 2; Environmental Legislators Caucus 
Supplemental Comments at 1; Grand Rapids NAACP Initial Comments at 
20-21; Massachusetts Attorney General Initial Comments at 53-54 
(citing Massachusetts Attorney General ANOPR Initial Comments at 32-
34); Montclair Congregation Supplemental Comments at 1; NESCOE Reply 
Comments at 8-9; New England for Offshore Wind Initial Comments at 
5; PIOs Reply Comments at 11-17; US DOE Initial Comments at 9; WE 
ACT Initial Comments at 1-2.
    \109\ Center for Biological Diversity Initial Comments at 20-24 
(citing Pacific Northwest National Laboratory & Sandia National 
Laboratories, Advancing Energy Equity in Grid Planning (Apr. 2022), 
https://netl.doe.gov/sites/default/files/netl-file/Advancing%20Energy%20Equity%20in%20Grid%20Planning.pdf; Office of 
Energy Justice and Equity, US DOE, Justice40 Initiative, https://www.energy.gov/diversity/justice40-initiative).
    \110\ Id. at 23 (citing Neb. Pub. Power Dist. v. FERC, 957 F.3d 
932, 942 (8th Cir. 2020)).
    \111\ Grand Rapids NAACP Reply Comments at 4 (citing 16 U.S.C. 
824(a); Re Nat'l Ass'n for the Advancement of Colored People, Inc., 
95 P.U.R.3d 357 (F.P.C. 1972), vacated and remanded sub nom. NAACP 
v. FPC, 520 F.2d 432 (D.C. Cir. 1975), aff'd, 425 U.S. 662 (1976)); 
CARE Coalition Initial Comments at 2; PIOs Reply Comments at 14.
    \112\ Id. at 20-21.
    \113\ Id. at 17-19.
    \114\ WE ACT Initial Comments at 1-2.
---------------------------------------------------------------------------

    60. Advanced Energy Buyers state that failure to prepare the grid 
for the energy transition would be problematic for three primary 
reasons: (1) insufficient transmission investment will leave customer 
cost savings on the table; (2) lack of available transmission capacity 
will constrain its members' ability to meet decarbonization and clean 
energy goals; and (3) failure to plan and build adequate transmission 
will hamper the transition to a cleaner and more reliable electric 
grid.\115\ New Jersey Commission contends that the lack of holistic 
multi-driver transmission planning is inflating consumers' electricity 
costs by billions of dollars every year.\116\ Northwest and 
Intermountain explain that due to insufficient transmission capacity 
from renewable rich zones, utilities must attempt to meet their 
renewable energy policy targets with new resources that are close to 
load but more expensive, less reliable, and less efficient than more 
distant alternatives, even considering the potential costs of 
transmission expansion.\117\ Clean Energy Associations add that the 
lack of transmission capacity imposes real and demonstrable costs 
today, as evidenced by geographic differences in real-time power 
prices, and that the lack of robust and proactive transmission planning 
rules renders current rates unjust, unreasonable, and unduly 
discriminatory or preferential.\118\
---------------------------------------------------------------------------

    \115\ Advanced Energy Buyers Initial Comments at 3.
    \116\ New Jersey Commission Initial Comments at 2-9.
    \117\ Northwest and Intermountain Initial Comments at 6.
    \118\ Clean Energy Associations Initial Comments at 5 (citing 
Dev Millstein et al., Lawrence Berkeley National Laboratory, 
Empirical Estimates of Transmission Value Using Locational Marginal 
Prices, at 3 (Aug. 2022), https://eta-publications.lbl.gov/sites/default/files/lbnlempirical_transmission_value_study-august_2022.pdf 
(LBNL Aug. 2022 Transmission Value Study)).
---------------------------------------------------------------------------

    61. Southeast PIOs contend that the ``snowballing'' inefficiencies 
created by numerous small-scale transmission ``band-aids'' result in 
unjust, unreasonable, and unduly discriminatory or preferential rates, 
and that reforms are particularly needed in the Southeast, where there 
is minimal utility coordination and a balkanized transmission 
system.\119\ According to ACEG, short-term, piecemeal transmission 
planning is unlikely to identify the more efficient or cost-effective 
solutions to transmission needs and thus will result in unjust, 
unreasonable, and unduly discriminatory or preferential rates.\120\
---------------------------------------------------------------------------

    \119\ Southeast PIOs Reply Comments at 1-2.
    \120\ ACEG Initial Comments at 21.
---------------------------------------------------------------------------

    62. Many commenters argue that reforms are necessary to meet state 
policy goals \121\ and that greater state involvement or consideration 
of state policies is needed to avoid transmission planning 
inefficiencies.\122\ For example, ACORE cites a recent National 
Renewable Energy Laboratory (NREL) report highlighting the need for new 
transmission to aid in achieving zero carbon goals.\123\ NextEra opines 
that the passage of the Inflation Reduction Act of 2022 will increase 
the demand for renewables and drive corresponding demands on the 
transmission system.\124\ Pacific Northwest State Agencies argue that 
reforms are critical to successfully achieving their respective state 
clean energy laws and policies and to ensuring that there is sufficient 
clean, safe, reliable, and affordable energy.\125\ Michigan State 
Entities note that some states may pursue aggressive renewable energy 
portfolio standards, and others may have no such requirements, but 
these policy choices will inevitably affect the price and reliability 
of energy for all customers across the states in question and that not 
planning for that reality imposes costs on unwilling customers.\126\
---------------------------------------------------------------------------

    \121\ See, e.g., Acadia Center and CLF Initial Comments at 1; 
ACORE Reply Comments at 1; Breakthrough Energy Initial Comments at 
5-6; Business Council for Sustainable Energy Initial Comments 2-3; 
Illinois Commission Initial Comments at 3-4; ISO-NE Initial Comments 
at 2; Michigan State Entities Initial Comments at 2-3; National Grid 
Initial Comments at 6-7; NESCOE Initial Comments at 9-10, 15-16; 
NextEra Reply Comments at 5, 25; Northwest and Intermountain Initial 
Comments at 5-6; [Oslash]rsted Initial Comments at 1-3; Pacific 
Northwest State Agencies Initial Comments at 1; PacifiCorp and NV 
Energy Initial Comments at 10-11; State Agencies Initial Comments at 
16-17; Vermont Electric and Vermont Transco Initial Comments at 2; 
Western State Representatives Initial Comments at 3.
    \122\ See, e.g., AEE Reply Comments at 3-4; California 
Democratic Representatives Supplemental Comments at 1-2; US Senators 
Supplemental Comments at 1 (citing to National Academies of 
Sciences, Engineering, and Medicine, Accelerating Decarbonization in 
the United States: Technology, Policy, and Societal Dimensions 
(2023)); Maryland Energy Admin Initial Comments at 1; North Carolina 
Commission and Staff Initial Comments at 2, 4; PJM States Initial 
Comments at 1; SREA Reply Comments at 4.
    \123\ ACORE Reply Comments at 1 (citing Paul Denholm, et al., 
NREL, Examining Supply-Side Options to Achieve 100% Clean 
Electricity by 2035 (Sept. 2022), https://www.nrel.gov/docs/fy22osti/81644.pdf).
    \124\ NextEra Reply Comments at 5, 25.
    \125\ Pacific Northwest State Agencies at 1.
    \126\ Michigan State Entities Initial Comments at 2-3.

---------------------------------------------------------------------------

[[Page 49293]]

    63. PacifiCorp and NV Energy similarly assert that the need for 
reform in the West is driven by the diverse policy priorities in its 
six-state transmission system, and they note that decisions are subject 
to state oversight and the participation of disparately situated 
transmission providers without inclination or authority to accept any 
cost allocation.\127\ National Grid asserts that ISO New England's 
(ISO-NE) 2050 Transmission Study demonstrates a direct connection 
between state laws and requirements to meet clean energy goals and the 
need for new and expanded transmission facilities.\128\ Indicated PJM 
TOs add that maintaining a reliable and resilient transmission system 
requires forward-looking assessments informed by evolving public 
policy, changing generation mix and demand patterns, and stakeholder 
input.\129\
---------------------------------------------------------------------------

    \127\ PacifiCorp and NV Energy Initial Comments at 10-11.
    \128\ National Grid Initial Comments at 6-7 (citing the then-
preliminary findings from the ISO-NE 2050 Transmission Study).
    \129\ Indicated PJM TOs Initial Comments at 1.
---------------------------------------------------------------------------

    64. Maryland Energy Administration contends that Maryland has 
experienced unfair and costly consequences of inadequate consultation 
with state authorities in regional transmission planning 
processes.\130\ AEE argues that if current transmission planning 
processes fail to incorporate factors such as state laws, corporate 
targets, and retail demand, then transmission needs will be unmet, 
risking unjust, unreasonable, and unduly discriminatory or preferential 
rates.\131\
---------------------------------------------------------------------------

    \130\ Maryland Energy Administration Initial Comments at 1 
(citing Maryland Energy Administration ANOPR Initial Comments at 2).
    \131\ AEE Reply Comments at 3-4.
---------------------------------------------------------------------------

    65. Many commenters argue that, based on the record, the Commission 
has an obligation under the FPA to take action to ensure that 
transmission planning and cost allocation results in rates that are 
just and reasonable and not unduly discriminatory.\132\ ACEG states 
that the Commission's broad authority to remedy unduly discriminatory 
behavior pursuant to FPA section 206 applies to transmission planning 
and cost allocation, as the U.S. Court of Appeals for the District of 
Columbia Circuit held in South Carolina Public Service Authority v. 
FERC.\133\ PIOs contend that the Commission is required by the FPA to 
use its authority to address market abuses and undue discrimination 
that have led to unjust, unreasonable, and unduly discriminatory or 
preferential rates for consumers, who bear the costs of inefficiencies 
in the current transmission planning process.\134\
---------------------------------------------------------------------------

    \132\ See, e.g., ACEG Initial Comments at 11; Clean Energy 
Associations Initial Comments at 7-10; Grand Rapids NAACP Initial 
Comments at 17; Massachusetts Attorney General Initial Comments at 
3-4; Pine Gate Initial Comments at 10-14; PIOs Initial Comments at 
8.
    \133\ 762 F.3d at 57. See also ACEG Initial Comments at 13-14; 
Harvard ELI Initial Comments at 1-2; SEIA Initial Comments at 3.
    \134\ PIOs Initial Comments at 8.
---------------------------------------------------------------------------

    66. Southeast PIOs assert that the NOPR adequately demonstrated 
that existing regional transmission planning processes have intrinsic 
flaws, making the integrated resource planning and request for proposal 
processes ill-equipped to efficiently address changes in the resource 
mix and demand.\135\ Specifically, Southeast PIOs cite the following 
preliminary findings from the NOPR: (1) existing transmission planning 
processes utilize a limited planning horizon; (2) many transmission 
planning processes provide an inaccurate portrayal of the comparative 
benefits of different transmission facilities; and (3) rapid changes to 
the generation fleet and demand are creating increasingly urgent 
transmission needs.\136\
---------------------------------------------------------------------------

    \135\ Southeast PIOs Reply Comments at 4 (citing Duke Initial 
Comments at 6-9; SERTP Sponsors Initial Comments at 31-36; Southern 
Initial Comments at 36-40).
    \136\ Id. at 5-6 (citing NOPR, 179 FERC ] 61,028 at PP 45, 47, 
49, 53).
---------------------------------------------------------------------------

    67. Southeast PIOs cite the finding in South Carolina Public 
Service Authority v. FERC that the threshold of substantial evidence 
could be met without ``empirical evidence'' as long as the Commission 
provides evidence based on ``reasonable economic propositions.'' \137\ 
Southeast PIOs also note that South Carolina Public Service Authority 
v. FERC upheld the Commission's findings in Order No. 1000, which were 
based on (1) a threat to just and reasonable rates from existing 
regional transmission planning and cost allocation practices, (2) 
significant changes in the industry driven by increases in renewable 
energy resources, and (3) recent increases in transmission 
investment.\138\ Moreover, Southeast PIOs note that findings need not 
be region-specific, as the ``Commission may rely on generic or general 
findings of a systemic problem to support imposition of an industry-
wide solution.'' \139\
---------------------------------------------------------------------------

    \137\ Id. at 6-7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 
at 65).
    \138\ Id. at 6-7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 
at 65-66).
    \139\ Id. at 7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 
at 67).
---------------------------------------------------------------------------

    68. ACEG similarly asserts that the Commission has shown the need 
for transmission planning reform based on findings that existing 
transmission planning requirements do not adequately identify 
transmission needs driven by changes in the resource mix and demand, 
and that failure to identify such needs causes customers to pay for 
less efficient or cost-effective transmission investments.\140\ 
Relatedly, ACEG argues that pursuing region-specific solutions will 
lead to siloed and disjunctive transmission planning policies that will 
not solve the problems facing the Nation's electric transmission 
system.\141\
---------------------------------------------------------------------------

    \140\ ACEG Reply Comments at 7-8 (citing Alabama Commission 
Initial Comments at 2-3; Duke Initial Comments at 6-9; Idaho Power 
Initial Comments at 2-3; NRECA Initial Comments at 11; North 
Carolina Commission and Staff Initial Comments at 14; Pacific 
Northwest Utilities Initial Comments at 9-10; Utah Commission 
Initial Comments at 9-12).
    \141\ Id. at 17.
---------------------------------------------------------------------------

    69. Colorado Consumer Advocate and Joint Consumer Advocates aver 
that the Commission has a statutory duty under the FPA to reform 
current regional transmission planning processes because they lack 
transparency, coordination, and openness, and because they create 
opportunities for monopoly transmission developers to exert dominant 
influence and promote their own economic self-interest at customers' 
and other stakeholders' expense.\142\ According to New Jersey 
Commission, current transmission planning processes are inefficient and 
unnecessarily burden ratepayers with excessive costs without providing 
additional benefits. New Jersey Commission contends that those 
processes are therefore per se unjust and unreasonable, and that the 
Commission thus has FPA section 206 authority to require that 
transmission providers employ practices like long-term, holistic, 
multi-driver transmission planning.\143\
---------------------------------------------------------------------------

    \142\ Colorado Consumer Advocate Initial Comments at 21-23; 
Joint Consumer Advocates Initial Comments at 18-20.
    \143\ New Jersey Commission Initial Comments at 3-4.
---------------------------------------------------------------------------

    70. Similarly, Harvard ELI states that deficient transmission 
planning threatens the justness and reasonableness of transmission 
rates, and therefore the Commission has legal authority and 
jurisdiction to order changes to transmission planning to remedy that 
deficiency.\144\ Harvard ELI further asserts that the Commission must 
remedy undue discrimination due to incumbent transmission owners' 
unduly discriminatory influence in regional transmission planning.\145\ 
Massachusetts Attorney General also

[[Page 49294]]

argues that the Commission's proposed reforms are necessary to fulfill 
the Commission's statutory obligation to ensure that transmission rates 
are just and reasonable.\146\
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    \144\ Harvard ELI Initial Comments at 1-2 (citing S.C. Pub. 
Serv. Auth. v. FERC, 762 F.3d 41; Order No.1000-A, 139 FERC ] 61,132 
at PP 56-75).
    \145\ Id. at 3.
    \146\ Massachusetts Attorney General Initial Comments at 3-6.
---------------------------------------------------------------------------

    71. Some commenters argue that there is insufficient evidence for 
the Commission to find that existing jurisdictional rates are unjust, 
unreasonable, and unduly discriminatory or preferential.\147\ For 
example, while Idaho Commission recognizes that there are deficiencies 
in existing transmission planning and cost allocation processes, Idaho 
Commission disagrees with the NOPR's claim that their failure to 
identify and plan for transmission needs driven by changes in the 
resource mix and demand is resulting in unjust, unreasonable, and 
unduly discriminatory or preferential Commission-jurisdictional 
rates.\148\ Mississippi Commission also disagrees that the lack of 
long-term regional transmission planning will result in unjust, 
unreasonable, and unduly discriminatory or preferential rates.\149\ 
ELCON questions a finding of unjust, unreasonable, and unduly 
discriminatory or preferential rates, and it states that the NOPR's 
focus on Long-Term Regional Transmission Planning solely to address 
changes in resource mix and demand, if adopted, could fail to produce 
better outcomes for customers and may exceed the Commission's authority 
under the FPA.\150\
---------------------------------------------------------------------------

    \147\ See, e.g., ELCON Initial Comments at 7; Idaho Commission 
Initial Comments at 2; Mississippi Commission Initial Comments at 2, 
9; NRECA Initial Comments at 14-16; Undersigned States Reply 
Comments at 6-7.
    \148\ Idaho Commission Initial Comments at 2 (citing NOPR, 179 
FERC ] 61,028 at P 34).
    \149\ Mississippi Commission Initial Comments at 2.
    \150\ ELCON Initial Comments at 7.
---------------------------------------------------------------------------

    72. Louisiana Commission states that the Commission's finding that, 
absent reforms, transmission rates universally are not just and 
reasonable and are discriminatory is not based on individual analysis 
of each RTO or region, is not supported, and should be retracted.\151\ 
Mississippi Commission also states that the Commission should, instead, 
initiate region-specific investigations pursuant to FPA section 
206.\152\ Southern argues that the Commission has failed to satisfy the 
first prong of its FPA section 206 burden of proof, noting that the 
NOPR's preliminary conclusion, that existing regional transmission 
planning processes are not sufficient to address changes in the 
resource mix and demand, cannot reasonably be made of Southern or 
SERTP.\153\
---------------------------------------------------------------------------

    \151\ Louisiana Commission Reply Comments at 5-6.
    \152\ Mississippi Commission Reply Comments at 7-9.
    \153\ Southern Initial Comments at 40; Southern Reply Comments 
at 1-3.
---------------------------------------------------------------------------

    73. Similarly, Industrial Customers argue that the Commission has 
not satisfied the first prong of FPA section 206, which requires the 
Commission to find, and provide substantial evidence supporting its 
finding, that existing rates are unjust, unreasonable, and unduly 
discriminatory or preferential.\154\ Industrial Customers claim that 
demand growth should be the primary factor in identifying transmission 
needs, and that demand is growing more slowly than in previous periods. 
Industrial Customers add that, in contrast, investment in transmission 
is rising relative to demand, which is the opposite of the 
circumstances that prevailed in 2007 when the Commission issued Order 
No. 890.\155\ According to Industrial Customers, changes in demand are 
not significant enough in historical terms to warrant major changes in 
transmission planning. Moreover, Industrial Customers state that 
changes in demand are unpredictable because technological changes are 
inherently difficult to forecast and the risks to consumers of making 
mistakes are too high. Industrial Customers argue that, if anything, 
the rapid growth of renewables indicates that current processes are 
already facilitating changes in the resource mix.\156\ Similarly, NRG 
argues that long-term forecasts of important factors are often wrong, 
which has real-world impacts on customers.\157\
---------------------------------------------------------------------------

    \154\ Industrial Customers Initial Comments at 6-7.
    \155\ Id. at 8-10.
    \156\ Id. at 10-11.
    \157\ NRG Initial Comments at 10-12 (noting, for example, that 
``[p]redictions for the future price of natural gas and thus the 
economics of gas generation in long-term forecasts have been 
notoriously inaccurate.'' (citing Lawrence Berkeley National 
Laboratory, Comparison of AEO 2008 Natural Gas Price Forecast to 
NYMEX Futures Prices (Jan. 2008)).
---------------------------------------------------------------------------

    74. Further, Industrial Customers contend that the NOPR does not 
clearly define the term ``changes in the resource mix and demand,'' 
despite using such changes as the justification for the proposals. 
Industrial Customers argue that transmission should only be planned in 
order to maintain reliability and should not be based on the demand for 
certain fuel sources or the fuel type of the generation fleet.\158\ 
Industrial Customers argue that current transmission planning is based 
on known and measurable factors, and that any attempt to plan for 
potential future changes in the resource mix without determining 
precisely what these changes will be would result in the overbuilding 
of the system for generation that may not be built. Industrial 
Customers argue that this outcome would be unjust and unreasonable and 
would force transmission customers to pay for generation that is non-
existent.\159\
---------------------------------------------------------------------------

    \158\ Industrial Customers Initial Comments at 7-8.
    \159\ Id. at 15.
---------------------------------------------------------------------------

    75. Other commenters agree that the Commission lacks a specific 
record to support the need for reform.\160\ For example, former Kansas 
Commission Chair Keen avers that there is no analytical or evidentiary 
basis in the NOPR for a complete and thorough overhaul or revision of 
transmission planning processes.\161\
---------------------------------------------------------------------------

    \160\ See, e.g., Alabama Commission Initial Comments at 4-5; 
Duke Initial Comments 6-9; Idaho Commission Initial Comments at 2; 
Industrial Customers Initial Comments at 1, 6-11, 15; Kansas 
Commission Chair Keen Initial Comments at 1-2; Nebraska Commission 
Initial Comments at 1-2; NRECA Initial Comments at 14-16; NRG 
Initial Comments at 3; Ohio Commission Federal Advocate Initial 
Comments at 5-6; Potomac Economics Initial Comments at 3-4; Southern 
Initial Comments at 40.
    \161\ Kansas Commission Chair Keen Initial Comments at 2.
---------------------------------------------------------------------------

    76. Duke asserts that the NOPR does not provide robust and specific 
support as to how and why current regional transmission planning 
processes are failing to plan for transmission needs driven by changes 
in the resource mix and demand, leading to inefficient investment.\162\ 
Duke asserts that the NOPR does not support the presumption that the 
absence of significant regional transmission investment is evidence of 
inefficient transmission planning.\163\ Duke also asserts that, to 
ensure legal durability, the Commission should identify evidence that 
justifies a nationwide finding that current transmission planning 
processes are failing to plan for transmission needs driven by changes 
in the resource mix and demand, leading to inefficient investment and 
unjust, unreasonable, and unduly discriminatory or preferential 
rates.\164\
---------------------------------------------------------------------------

    \162\ Duke Initial Comments at 6-7.
    \163\ Id. at 7-8.
    \164\ Id. at 9 (citing Emera Me. v. FERC, 854 F.3d 9, 24 (D.C. 
Cir. 2017)).
---------------------------------------------------------------------------

    77. Undersigned States argue that the Commission does not have 
evidence in the record that current rates are unjust, unreasonable, or 
unduly discriminatory or preferential, which FPA section 206 
requires.\165\ Undersigned States argue

[[Page 49295]]

that, contrary to the preliminary findings in the NOPR, the Southeast 
has developed significant and sufficient transmission infrastructure 
and renewable energy from 2015-2020. Undersigned States further argue 
that the Commission is supposed to enhance reliability, and that, 
because renewables are intermittent and inherently less reliable, 
forcing ratepayers to subsidize their use through financing the 
construction of additional transmission infrastructure is not 
consistent with the Commission's mission. Undersigned States also argue 
that the Commission has not justified replacing existing transmission 
planning processes with a new approach, so the NOPR is arbitrary and 
capricious.\166\ Further, Undersigned States argue that the Commission 
has not offered a detailed justification for countering prior precedent 
in Order No. 1000 that ``the regional transmission planning process is 
not the vehicle by which integrated resource planning is conducted.'' 
\167\
---------------------------------------------------------------------------

    \165\ Undersigned States Reply Comments at 6-7. The Undersigned 
States that submitted reply comments include the States of Texas, 
Utah, Alabama, Alaska, Arkansas, Florida, Georgia, Kansas, Kentucky, 
Louisiana, Mississippi, Montana, Nebraska, Ohio, Oklahoma, South 
Carolina, and West Virginia. Id. at 1. The Undersigned States that 
submitted initial comments include the States of Utah, Alaska, 
Georgia, Idaho, Indiana, Kansas, Kentucky, Louisiana, Mississippi, 
Montana, Nebraska, North Dakota, Ohio, Oklahoma, South Carolina, 
Texas, West Virginia, and Wyoming. Undersigned States Initial 
Comments at 5-6.
    \166\ Undersigned States Reply Comments at 6-8.
    \167\ Id. at 8 (citing Order No. 1000, 136 FERC ] 61,051 at P 
154).
---------------------------------------------------------------------------

    78. Some commenters assert that the intention of the NOPR is to 
improperly favor certain energy resources.\168\ Consumer Organizations 
argue that solutions that allow for an equitable transition and make 
space for advancing technology and smaller energy systems are 
preferrable to a rushed plan that favors certain resources, such as 
wind, solar, and battery storage, that have already proven to be 
inadequate.\169\ ELCON adds that Congress did not give the Commission 
express authority to balance the FPA's just and reasonable rates 
requirement with the policy goal of connecting renewable resources to 
the transmission system.\170\ SERTP Sponsors argue that Congress has 
not clearly provided the Commission with jurisdiction to presuppose 
generation decisions and thereby effect particular, substantive 
transmission outcomes; rather, SERTP Sponsors continue, Congress has 
expressly and unequivocally reserved generation authority to the 
states.\171\ Louisiana Commission argues that the FPA does not confer 
on the Commission authority to engage in wide-scale public policymaking 
by enacting sweeping energy policy changes with far-reaching, 
nationwide effects.\172\
---------------------------------------------------------------------------

    \168\ See, e.g., Consumers Organizations Initial Comments at 1-
3; ELCON Initial Comments at 9-10.
    \169\ Consumers Organizations Initial Comments at 1-3.
    \170\ ELCON Initial Comments at 9-10 (citing 16 U.S.C. 
824q(b)(4)).
    \171\ SERTP Sponsors Initial Comments at 18.
    \172\ Louisiana Commission Initial Comments at 6 (citing West 
Virginia v. EPA, 597 U.S. 697 (2022)).
---------------------------------------------------------------------------

    79. Ohio Commission Federal Advocate states that the NOPR may be 
intended ``to establish policies designed to encourage the massive 
transmission build-out that will doubtless be required to transition to 
an aspirational renewable future'' and ``to achieve narrow 
environmental policy objectives, not to address legitimate requirements 
under the Federal Power Act like ensuring just and reasonable rates or 
reliability.'' \173\ Former Kansas Commission Chair Keen claims that 
the NOPR encourages an extensive and expensive transmission build-out 
without considering the impact on state-jurisdictional generation 
mixes. He also claims that some of the NOPR proposals impose an 
accelerated pace for the transition from dispatchable to renewable 
resources, which could hasten the premature retirement of dispatchable 
generation and compromise regional and state power reliability. He also 
expresses concern that the NOPR proposals would force ratepayers in 
some states to pay for neighboring states' transmission projects to 
advance public policy goals that they do not share.\174\
---------------------------------------------------------------------------

    \173\ Ohio Commission Federal Advocate Initial Comments at 4-5 
(citing NOPR, 179 FERC ] 61,028, Danly, Comm'r, dissenting, at PP 2-
3).
    \174\ Kansas Commission Chair Keen Initial Comments at 3.
---------------------------------------------------------------------------

    80. Some commenters challenge aspects of the need for reform. For 
example, Nebraska Commission believes that the established structures 
in RTO/ISO regions are generally working and that many aspects of the 
NOPR are thus unnecessary there.\175\ Potomac Economics disagrees with 
some of the Commission's arguments for requiring Long-Term Regional 
Transmission Planning, contending that the Commission's proposals are 
based on anticipated future generation and other speculative factors 
and seem to be incorrectly premised on a presumption that congestion 
should not exist or may limit investment in economic generation. 
Potomac Economics states that investment should occur only to the 
extent that the savings of reducing congestion are larger than the 
investment costs. According to Potomac Economics, congestion that is 
caused by generators' siting decisions should be borne by the 
generation developers, as it will incent them to propose the lowest-
cost projects taking transmission costs into account. Potomac Economics 
argues that, if transmission is expanded preemptively to facilitate 
generation investment in a particular location, such costs are 
equivalent to subsidies for the developer.\176\
---------------------------------------------------------------------------

    \175\ Nebraska Commission Initial Comments at 1-2.
    \176\ Potomac Economics Initial Comments at 3-4.
---------------------------------------------------------------------------

    81. Mississippi Commission disagrees that too much expansion of 
high-voltage transmission has occurred through the generator 
interconnection process instead of through regional transmission 
planning.\177\ Similarly, North Carolina Commission and Staff disagree 
with the Commission's conclusion that the growth in interconnection-
related network upgrades demonstrates a failure of regional 
transmission planning as it relates to North Carolina.\178\ Southern 
adds that, contrary to statements in the NOPR, it is not significantly 
expanding its transmission system through the generator interconnection 
process.\179\
---------------------------------------------------------------------------

    \177\ Mississippi Commission Initial Comments at 9.
    \178\ North Carolina Commission and Staff Initial Comments at 5.
    \179\ Southern Initial Comments at 38-40.
---------------------------------------------------------------------------

    82. Alabama Commission asserts that Alabama has a resource planning 
process that accounts for needed transmission buildout to maintain 
reliable service, and thus, Alabama Power plans its transmission system 
proactively both to maintain deliveries from existing resources and to 
accommodate Alabama Commission-certified generation additions. Alabama 
Commission claims that the SERTP process builds on the integrated 
resource planning efforts of its sponsor states, ensuring that there 
are no regional transmission solutions that are more efficient or cost-
effective than solutions identified through the underlying state-
jurisdictional processes.\180\
---------------------------------------------------------------------------

    \180\ Alabama Commission Initial Comments at 4.
---------------------------------------------------------------------------

    83. Duke argues that, for certain transmission providers, the local 
transmission planning process may more effectively meet transmission 
needs, especially when combined with state-regulated integrated 
resource planning and a bottom-up regional transmission planning 
process. Duke contends that a regional transmission facility may not 
fully address local transmission needs such that a local transmission 
facility would still be needed, and thus, the regional transmission 
facility is not necessarily more efficient or cost-effective than the 
local transmission facility.\181\
---------------------------------------------------------------------------

    \181\ Duke Initial Comments at 7-9.

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[[Page 49296]]

    84. NRECA states that certain of its members in RTOs/ISOs believe 
that regional transmission planning is working well to meet long-term 
needs (e.g., those in MISO) and that the NOPR proposals would burden 
transmission providers' limited resources. NRECA states that other 
NRECA members in RTOs/ISOs believe that existing RTO/ISO transmission 
planning processes contain discrete deficiencies that the NOPR 
proposals will not remedy. According to NRECA, these electric 
cooperatives believe that some incumbent investor-owned transmission 
owners develop local transmission projects without transparency 
concerning need or costs, leading to disparities in transmission rates 
across RTO/ISO transmission zones, and that incumbent transmission 
owners control the transmission planning process such that no regional 
transmission planning occurs. NRECA states that, in these cooperatives' 
view, the criteria to determine the eligibility of a regional 
transmission project is the barrier, and that requiring Long-Term 
Regional Transmission Planning, by itself, will not solve the 
problem.\182\
---------------------------------------------------------------------------

    \182\ NRECA Initial Comments at 14-16.
---------------------------------------------------------------------------

C. Commission Determination

    85. Based on the record, we find that there is substantial evidence 
to support the conclusion that the Commission's existing regional 
transmission planning and cost allocation requirements are unjust, 
unreasonable, and unduly discriminatory or preferential. We therefore 
adopt the preliminary findings in the NOPR concerning the need for 
reform. Specifically, we find that the absence of sufficiently long-
term, forward-looking, and comprehensive transmission planning 
requirements is causing transmission providers to fail to adequately 
anticipate and plan for future system conditions. It causes 
transmission providers to fail to appropriately evaluate the benefits 
of transmission infrastructure, and results in piecemeal transmission 
expansion to address relatively near-term transmission needs. We find 
that this status quo causes transmission providers to undertake 
relatively inefficient investments in transmission infrastructure, the 
costs of which are ultimately recovered through Commission-
jurisdictional rates. This dynamic results in, among other things, 
transmission customers paying more than necessary or appropriate to 
meet their transmission needs and forgoing benefits that outweigh their 
costs, which results in less efficient or cost-effective transmission 
investments. As explained below, we find that these deficiencies render 
Commission-jurisdictional regional transmission planning and cost 
allocation processes unjust, unreasonable, and unduly discriminatory or 
preferential.
    86. The Commission has authority under FPA section 206 to issue 
this final order. Specifically, FPA section 206 ``instructs the 
Commission to remedy `any . . . practice' that `affect[s]' a rate for 
interstate electricity service `demanded' or `charged' by `any public 
utility' if such practice is `unjust, unreasonable, unduly 
discriminatory or preferential.''' \183\ As the D.C. Circuit has 
recognized, regional transmission planning and cost allocation 
processes are practices affecting rates subject to the Commission's 
exclusive jurisdiction.\184\ As the Court explained in South Carolina 
Public Service Authority v. FERC, transmission providers use those 
processes to ``determine which transmission facilities will more 
efficiently or cost-effectively meet'' transmission needs, the 
development of which directly impacts the rates, terms, and conditions 
of Commission-jurisdictional service.\185\ In particular, because these 
processes identify, evaluate, and select the regional transmission 
facilities whose costs will be recovered through transmission rates, we 
find that they directly affect those rates.\186\ In addition, as 
discussed below, such transmission facilities contribute to the 
development of a more robust transmission system, supporting continuity 
of service in the face of growing reliability challenges and providing 
wholesale electric customers greater access to lower-cost generation 
supplied by a wider range of resources. Accordingly, regional 
transmission planning and cost allocation processes, as well as ``the 
rules and practices that determine how those [processes] 
operate,''\187\ have a direct effect on the rates that customers pay 
for both the transmission and sale of electric energy in interstate 
commerce.\188\ The Commission may act pursuant to FPA section 206 if 
the Commission first establishes, through substantial evidence,\189\ 
that the existing practices are unjust, unreasonable, or unduly 
discriminatory or preferential and, second, establishes that the 
replacement practices are just and reasonable.\190\
---------------------------------------------------------------------------

    \183\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55 (quoting 16 
U.S.C. 824e(a)).
    \184\ Id. at 55-59, 84 (affirming the Commission's authority to 
regulate transmission planning and cost allocation as practices 
affecting rates); see also Order No. 1000-A, 139 FERC ] 61,132 at P 
577 (holding that ``requirements regarding transmission planning and 
cost allocation . . . are practices affecting rates.'').
    \185\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 56 (citing 
Order No. 1000, 136 FERC ] 61,051 at PP 112, 116); see also Emera 
Me. v. FERC, 854 F.3d at 674.
    \186\ That is true even if regional transmission planning and 
cost allocation processes do not result in the development, siting, 
and construction of every regional transmission facility that 
transmission providers select to more efficiently or cost-
effectively meet transmission needs. See, e.g., Conn. Dep't of Pub. 
Util. Control v. FERC, 569 F.3d 477, 485 (D.C. Cir. 2009) (holding 
that ``even if all [that] the I[nstalled] C[apacity] R[equirement] 
did was help to find the right [capacity] price,'' rather than 
result in the construction or procurement of any new capacity, ``it 
would still amount to a `practice . . . affecting' rates.'' (citing 
16 U.S.C. 824e(a) (omission in original))).
    \187\ FERC v. Elec. Power Supply Ass'n, 577 U.S. 260, 279 (2016) 
(EPSA).
    \188\ 16 U.S.C. 824e(a).
    \189\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 54 (``The 
Commission's factual findings are conclusive if supported by 
substantial evidence.''). Courts have held that substantial evidence 
in this context does not necessarily require the Commission to 
provide empirical evidence for every proposition. Rather, FPA 
section 206 empowers the Commission to address a mere threat of 
unjust and unreasonable rates. See S.C. Pub. Serv. Auth. v. FERC, 
762 F.3d at 64-65, 85.
    \190\ 16 U.S.C. 824e(a); see also EPSA, 577 U.S. at 277 
(affirming the Commission ``has the authority--and indeed, the 
duty--to ensure that rules or practices `affecting' wholesale rates 
are just and reasonable'').
---------------------------------------------------------------------------

    87. With regard to the first showing under FPA section 206, we find 
that, while Order No. 890 requires transmission providers to satisfy 
certain principles in their local transmission planning processes and 
Order No. 1000 requires transmission providers to participate in 
regional transmission planning and cost allocation processes that 
satisfy the requirements set forth therein, these existing transmission 
planning and cost allocation requirements do not result in regional 
transmission planning that is conducted on a sufficiently long-term, 
forward-looking, and comprehensive basis to plan for Long-Term 
Transmission Needs. As a result, we find that transmission providers 
are often not identifying, evaluating, or selecting more efficient or 
cost-effective regional transmission solutions to meet Long-Term 
Transmission Needs. This gap in existing regional transmission planning 
processes results in piecemeal, inefficient, and less cost-effective 
transmission planning that imposes real costs on customers, who pay 
Commission-jurisdictional transmission rates for less efficient or 
cost-effective transmission facilities and do not realize the benefits 
that would result from long-term, forward-looking, and more 
comprehensive regional transmission planning and cost allocation 
processes that identify, evaluate, and select more efficient or cost-
effective transmission

[[Page 49297]]

solutions to Long-Term Transmission Needs.
    88. We find that these deficiencies in the Commission's existing 
transmission planning and cost allocation requirements render those 
requirements unjust, unreasonable, and unduly discriminatory or 
preferential in violation of FPA section 206.
    89. We also find that the Commission's existing transmission 
planning and cost allocation requirements are insufficient to ensure 
just and reasonable and not unduly discriminatory or preferential 
rates. Given these findings, we are now requiring, pursuant to FPA 
section 206, that transmission providers engage in and conduct 
sufficiently long-term, forward-looking, and comprehensive transmission 
planning and cost allocation processes to identify and plan for Long-
Term Transmission Needs. We find that these reforms will facilitate a 
process by which transmission providers can better identify, evaluate, 
and select more efficient or cost-effective transmission solutions to 
meet Long-Term Transmission Needs, which will ensure that Commission-
jurisdictional rates are just and reasonable and not unduly 
discriminatory or preferential.
1. The Transmission Investment Landscape Today
    90. As the Commission explained in the NOPR, a robust, well-planned 
transmission system is foundational to ensuring an affordable, reliable 
supply of electricity.\191\ Due to continuing changes in the industry, 
ongoing investment in transmission facilities is necessary to ensure 
the transmission system continues to serve load in a reliable,\192\ 
affordable, and economically efficient fashion. Such investments 
support enhanced reliability, as larger, more integrated transmission 
systems result in a diversity of supply and demand conditions and a 
certain degree of redundancy that allows the system to better withstand 
failures during extreme events.\193\ Proactive, forward-looking 
transmission planning that considers both evolving reliability needs 
and other drivers of transmission needs more comprehensively can enable 
transmission providers to identify potential reliability problems and 
economic constraints, as well as to evaluate potential transmission 
solutions, well in advance of these issues affecting the transmission 
system,\194\ which can facilitate the selection of more efficient or 
cost-effective transmission facilities to meet Long-Term Transmission 
Needs.
---------------------------------------------------------------------------

    \191\ NOPR, 179 FERC ] 61,028 at P 28 (citing 16 U.S.C. 824, 
824d, 824e); see also US DOE ANOPR Initial Comments at 2 (stating 
that ``strengthening and expanding existing transmission 
infrastructure, particularly the development of regional and inter-
regional transmission projects, is key to continued access to 
reliable, resilient, lower-cost, and clean electricity for all'').
    \192\ See, e.g., MISO ANOPR Initial Comments at 40; Testimony of 
James B. Robb Before the U.S. Senate Energy and Natural Resources 
Committee, Reliability, Resiliency, and Affordability of Electric 
Service in the United States Amid the Changing Energy Mix and 
Extreme Weather Events, at 8-9 (Mar. 11, 2021), https://www.energy.senate.gov/services/files/D47C2B83-A0A7-4E0B-ABF2-9574D9990C11 (testifying that more transmission infrastructure is 
required to ensure the reliability and resilience of the bulk power 
system in light of changing conditions).
    \193\ ACORE ANOPR Initial Comments Ex. 4, Grid Strategies July 
2021 Extreme Weather Report; Mark Chupka & Pearl Donohoo-Vallett, 
Recognizing the Role of Transmission in Electric System Resilience 
(May 2018), https://wiresgroup.com/wp-content/uploads/2020/06/2018-05-09-Brattle-Group-Recognizing-the-Role-of-Transmission-in-Electric-System-Resilience-.pdf; NERC ANOPR Initial Comments at 17-
18; US DOE ANOPR Initial Comments at 18.
    \194\ MISO's Multi-Value Project (MVP) regional transmission 
planning process, for example, eliminated the need for approximately 
$300 million in reliability transmission facilities, resolving 
reliability violations and mitigating system instability conditions, 
through a forward-looking approach. Midcontinent Independent System 
Operator, MTEP17 MVP Triennial Review: A 2017 review of the public 
policy, economic, and qualitative benefits of the Multi-Value 
Project Portfolio, at 11, 33 (Sept. 2017) (MTEP2017 Review).
---------------------------------------------------------------------------

    91. In addition, transmission infrastructure can unlock the forces 
of competition, changing who can sell to whom, eliminating barriers to 
entry, and mitigating market power.\195\ Increased competition, in 
turn, can provide a host of benefits for customers, including cost-
savings from greater access to low-cost power and a wider range of 
resources.\196\ Transmission infrastructure can also serve as a form of 
insurance against future uncertainties because a more robust, 
integrated transmission system has the potential to provide consumers 
with the benefits of competition and enhanced reliability even if 
supply and demand fundamentals change over time.\197\
---------------------------------------------------------------------------

    \195\ Policy Integrity ANOPR Initial Comments at 13 n.40 (``A 
new transmission project can enhance competition by both increasing 
the total supply that can be delivered to consumers and the number 
of suppliers that are available to serve load.'' (citing Mohamed 
Awad et al., The California ISO Transmission Economic Assessment 
Methodology (TEAM): Principles and Applications to Path 26, at 3 
(2006)); PIOs ANOPR Initial Comments Ex. A, Johannes Pfeifenberger 
et al., The Brattle Group and Grid Strategies, Transmission Planning 
for the 21st Century: Proven Practices that Increase Value and 
Reduce Costs, at 48-49 (Oct. 2021) (Brattle-Grid Strategies Oct. 
2021 Report), https://www.brattle.com/wp-content/uploads/2021/10/2021-10-12-Brattle-GridStrategies-Transmission-Planning-Report_v2.pdf (``Expansion of the transmission network typically 
increases the number of independent wholesale electricity suppliers 
that are able to compete to supply electricity at locations in the 
transmission network served by the upgrade . . . .'' (quoting F.A. 
Wolak, World Bank, Managing Unilateral Market Power in Electricity, 
Policy Research Working Paper No. 3691, at 8 (2005))).
    \196\ See, e.g., PJM Interconnection, L.L.C., PJM Value 
Proposition, at 1-2 (2019), https://www.pjm.com/about-pjm/~/media/
about-pjm/pjm-value-proposition.ashx (PJM's planning of resource 
adequacy over a large region is estimated to result in savings of 
$1.2-1.8 billion.); Midcontinent Independent System Operator, MISO 
Value Proposition (2020), https://www.misoenergy.org/meet-miso/MISO_Strategy/miso-value-proposition/ (MISO estimated $517-572 
million in savings from more efficient use of existing assets and 
$2.5-3.2 billion from reduced need for additional assets.); SPP 
Transmission Planning, Southwest Power Pool, SPP's Value of 
Transmission: 2021 Report and Update (Mar. 31, 2022) (SPP estimated 
$382.7 million in adjusted product costs savings in 2020 due to 
transmission investment.); see also ACEG Initial Comments at 3-4 
(``The benefits generated by MISO's MVPs and SPP's Priority Projects 
exceeded the costs by 2.2 to 3.5 times and means that every dollar 
spent on transmission will enable access to generation that is $3 to 
$4 cheaper than would otherwise be available.'').
    \197\ US DOE, National Electric Transmission Congestion Study, 
at 11 (Sept. 2015), https://www.energy.gov/sites/prod/files/2015/09/f26/2015%20National%20Electric%20Transmission%20Congestion%20Study_0.pdf 
(stating transmission expansion can strengthen and increase the 
flexibility of the overall network and ``create real options to use 
the transmission system in ways that were not originally 
envisioned''); Vikram S. Budhraja et al., Improving Electricity 
Resource Planning Processes by Considering the Strategic Benefits of 
Transmission, 22 ELEC. J. 54 (Mar. 2009) (high voltage transmission 
affords ``mitigation of risks as a form of insurance against extreme 
events'').
---------------------------------------------------------------------------

    92. With that overview, we again begin with the key facts on the 
ground.\198\ Since the issuance of Order No. 1000, transmission 
spending has continued to increase nationwide. A study by US DOE found 
that ``annual investment [in transmission] first exceeded $5 billion 
per year in 2006 . . . and has increased consistently since that time. 
Annual investment [] doubled to more than $10 billion per year by 2010 
and then [] doubled again by 2016. Annual investment has been between 
$18 billion and $22 billion annually since 2014.'' \199\ A separate 
study, noted by the Commission in the NOPR, estimated that transmission 
developers in the United States invested $20 to $25 billion annually in 
transmission facilities from 2013 to 2020.\200\ Unsurprisingly, in 
regions that saw a significant increase in transmission expenditures, 
transmission costs have also become an increasing

[[Page 49298]]

share of customers' overall electricity bills, underscoring the 
importance of ensuring that transmission investments are efficient and 
cost-effective.\201\
---------------------------------------------------------------------------

    \198\ NOPR, 179 FERC ] 61,028 at P 36.
    \199\ California Commission Reply Comments at 9 n.27 (quoting US 
DOE, National Electric Transmission Congestion Study, at 9-10 (Sept. 
2020), https://www.energy.gov/sites/default/files/2020/10/f79/2020%20Congestion%20Study%20FINAL%2022Sept2020.pdf).
    \200\ NOPR, 179 FERC ] 61,028 at P 39 (citing Brattle-Grid 
Strategies Oct. 2021 Report at 2); Brattle Apr. 2019 Competition 
Report at 2-3 & fig.1.
    \201\ Resale Iowa Initial Comments at 3 (``[T]ransmission costs 
have comprised an increasing percentage of [] total wholesale 
electric costs [for Resale Iowa's members]. Currently, transmission 
and ancillary services constitute approximately 43% of such costs, 
as compared to 18.1% in 2009.''); Industrial Customers Initial 
Comments at 5 (showing that transmission costs made up just 7% of 
the total PJM electricity bill in 2011 but 27% by 2020); Rob 
Gramlich and Jay Caspary, Americans for a Clean Energy Grid, 
Planning for the Future: FERC's Opportunity to Spur More Cost-
Effective Transmission Infrastructure, at 26-28 (Jan. 2021), https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf (ACEG Jan. 2021 Planning Report) (stating that the 
current approach to transmission planning ``results in higher total 
energy bills for customers than would result from more forward-
looking, holistic transmission planning''); see also California 
Municipal Utilities Initial Comments at 10 (projecting that between 
2022 and 2040, total high and low-voltage transmission access 
charges will nearly double and noting that ``[g]one are the days 
when transmission was a de minimis portion of the overall bill and 
increases had little impact on the end consumer''); Public Systems 
Initial Comments at 5 (noting that ``New England's Regional Network 
Service transmission rate has grown nine-fold, from $15.60 per kW-
year (in 2003) to $140.98 per kW-year (in 2021)'').
---------------------------------------------------------------------------

    93. Furthermore, the record demonstrates that transmission 
investment is likely to substantially increase in coming years. A 
number of studies project significant and sustained transmission 
spending through at least 2050. For example, one projection cited by 
the US DOJ and FTC states that ``high voltage transmission capacity 
must expand by 60 percent by 2030 at a capital cost of $330 billion, 
and must triple by 2050 at a capital cost of $2.2 trillion.'' \202\ 
TAPS cites a separate study projecting $750 billion of new transmission 
investment between 2023 and 2050.\203\ SoCal Edison ``estimates that 
grid investments of up to $75 billion, including transmission upgrades, 
will be required from 2030 to 2045 in California alone to integrate 
bulk renewable generation and storage and serve load growth associated 
with electrification.'' \204\ And ISO-NE's recently-completed 2050 
Transmission Study estimates that transmission investment in New 
England will range from $16 billion to $26 billion between 2024 and 
2050, depending on the amount of load growth realized in the 
region.\205\
---------------------------------------------------------------------------

    \202\ US DOJ and FTC Initial Comments at 3 (citing Eric Larson 
et al., Net-Zero America: Potential Pathways, Infrastructure, and 
Impacts, Princeton Univ., 108 (Oct. 2021), https://netzeroamerica.princeton.edu/the-report).
    \203\ TAPS Initial Comments at 46 & n.133 (citing J[uuml]rgen 
Weiss et al., The Brattle Group, The Coming Electrification of the 
North American Economy, at iii (2019), https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf)).
    \204\ SoCal Edison Initial Comments at 2 (citing Southern 
California Edison, Pathway 2045: Update to the Clean Power and 
Electrification Pathway (2019), https://download.newsroom.edison.com/create_memory_file/?f_id=5dc0be0b2cfac24b300fe4ca&content_verified=True) (emphasis 
added)).
    \205\ ISO-NE, 2050 Transmission Study, at 55-56 (Feb. 12, 2024), 
https://www.iso-ne.com/static-assets/documents/100008/2024_02_14_pac_2050_transmission_study_final.pdf.
---------------------------------------------------------------------------

    94. The growing need for new transmission infrastructure, 
particularly over a longer time horizon, is being driven by a number of 
factors. First, longer-term reliability needs are changing. The NOPR 
explained that transmission system operators are increasing their 
reliance on regional transmission facilities to ensure operational 
stability, particularly because of the growing frequency of extreme 
weather events and increasing share of variable resources entering the 
resource mix.\206\ The comments submitted in response to the NOPR 
support that preliminary finding. The record shows that changing 
reliability needs are driving a significant shift in demands placed on 
the transmission system,\207\ and that because extreme weather events 
are occurring with greater frequency, transmission is increasingly 
critical to ensuring system reliability.\208\ For example, Winter Storm 
Uri demonstrated that transmission infrastructure can make critical 
contributions to system reliability during extreme weather events,\209\ 
as well as how transmission constraints can prevent operational 
generation resources from being able to serve load during tight supply 
conditions.\210\ Consistent with experience from Winter Storm Uri, US 
DOE's Lawrence Berkeley National Laboratory provides further evidence 
of the significant value of transmission during unanticipated events, 
with research suggesting that 50% of the value created by alleviating 
transmission system congestion occurs during only 5% of the hours 
during which the transmission system is used.\211\ Thus, transmission 
investment is likely to be more critical, and produce more reliability 
benefits, for customers as extreme weather and other system 
contingencies become more frequent.\212\ For some communities who can 
be more susceptible to the impacts of extreme weather, like communities 
of color and

[[Page 49299]]

low-income communities, transmission investment has the potential to be 
even more critical.\213\ Conversely, failure to adequately plan the 
transmission system to meet such changing reliability needs will forgo 
many of those potential benefits, jeopardize system reliability, and 
force customers to pay for transmission facilities that may not 
efficiently or cost-effectively address urgent reliability needs.
---------------------------------------------------------------------------

    \206\ NOPR, 179 FERC ] 61,028 at P 45.
    \207\ ACEG Initial Comments at 5 (noting that weather-related 
power outages cost Americans $25-70 billion annually (citing Grid 
Strategies July 2021 Extreme Weather Report at 1)); id. at 52 
(explaining that ``[c]hanges to the transmission planning processes 
that would allow for certain transmission upgrades identified in the 
interconnection process to be addressed and ultimately constructed 
through the transmission planning process will only serve to 
increase the resiliency and reliability of the transmission 
system.''); ACEG Reply Comments at 5-6 (``[R]eliability requires 
long term transmission planning that incorporates known and knowable 
information about the future resource mix.''); NERC Initial Comments 
at 6 (``Transmission will be the key to support the resource 
transformation enabling delivery of energy from areas that have 
surplus energy to areas which are deficient. The frequency of such 
occurrences are increasing as extreme weather conditions resulting 
from climate change impact the fuel sources for variable energy 
resources. Regional transmission planning can ensure that sufficient 
amounts of transmission capacity will be needed to address these 
more frequent extreme weather conditions.'').
    \208\ See DC and Maryland Offices of People's Counsel Reply 
Comments at 2 (noting that new transmission development has benefits 
including enhanced reliability and resilience that will serve as a 
necessary bulwark against disruptions caused by extreme weather); 
Indicated PJM TOs Initial Comments at 1 (explaining that maintaining 
a ``reliable and resilient'' transmission system requires holistic 
planning); NESCOE Initial Comments at 32-33 (``ISO-NE explains that 
energy-security risks in New England are well documented, 
highlighting the importance of conducting comprehensive energy 
security assessments covering a wide range of operating conditions, 
including low-probability, high-impact reliability risks (tail 
risks) related to extreme weather'' (internal quotations omitted)); 
NYISO Initial Comments at 16 (expressing a desire to engage in 
actionable scenario planning to plan for future reliability 
challenges that may arise due to extreme weather, including the loss 
of all generation connected to a pipeline or other fuel sources, 
loss of an entire transmission line, and impacts from weather events 
like hurricanes or wildfires).
    \209\ ACEG Initial Comments at 22 n.63 (During Winter Storm Uri, 
``[a]n additional 1 gigawatt (GW) of transmission ties between ERCOT 
and the Southeastern U.S. could have saved nearly $1 billion and 
kept power flowing to hundreds of thousands of Texans.'' (citing 
Grid Strategies July 2021 Extreme Weather Report at 1-3, 12)); Grid 
Strategies July 2021 Extreme Weather Report at 7-8 (``The value of 
transmission for resilience can be seen in the drastically different 
outcomes of MISO and SPP relative to ERCOT during [Winter Storm 
Uri]. . . . In contrast to the 13,000 MW MISO was importing during 
the peak of [the] event, ERCOT was only able to import about 800 MW 
of power throughout the event.''); NARUC Initial Comments at 67 
n.192 (During Winter Storm Uri, SPP's `` `relationships and 
interconnections with neighboring systems were critical. Usually a 
net exporter of energy, SPP relied significantly on imported energy 
to serve load during the winter event, with net amounts exceeding 
6,000 megawatts (MW) at times. This emphasizes the value these 
relationships and robust transmission interconnections provide 
during emergency events and the opportunity to further strengthen 
them.' '' (quoting Southwest Power Pool, A Comprehensive Review of 
Southwest Power Pool's Response to the February 2021 Winter Storm: 
Analysis and Recommendations, at 9 (July 2021), https://spp.org/documents/65037/comprehensive%20review%20of%20spp%27s%20response%20to%20the%20feb.%202021%20winter%20storm%202021%2007%2019.pdf (brackets omitted))).
    \210\ See Advanced Energy Buyers Initial Comments at 3.
    \211\ ACORE Initial Comments at 10-11 (citing LBNL Aug. 2022 
Transmission Value Study at 33); US DOE Initial Comments at 5-6 & 
n.13.
    \212\ ACORE Initial Comments at 11 (citing LBNL Aug. 2022 
Transmission Value Study at 33; see also Clean Energy Associations 
Initial Comments at 5.
    \213\ See, e.g., WE ACT Initial Comments at 1-2 & n.3 (citing 
Jeff Turrentine, NRDC, A Roadmap for Frontline Communities (Dec. 
2019)); see also Grand Rapids NAACP Initial Comments at 8 n.20 
(``[P]ower outages uniquely burden low-income communities of color 
`given that they are unable to `bounce back' as quickly from events 
that damage food and medicine supplies' '' (citing Shalanda Baker et 
al., The Energy Justice Workbook 20 (2019), https://iejusa.org/wp-content/uploads/2019/12/The-Energy-Justice-Workbook-2019-web.pdf)).
---------------------------------------------------------------------------

    95. Second, demand is changing. After many years of flat or minimal 
load growth in regions across the country, demand, on both a national 
and a regional basis, is projected to significantly increase in the 
coming decades, and it will require an increasingly robust transmission 
system to reliably serve this load growth. As stated in the NOPR, 
changes in electric demand and associated load profiles are occurring 
as load-serving entities work to meet increasing needs due to 
electrification trends, as well as new large loads associated with 
evolving industrial and commercial needs, such as growth in data 
centers.\214\ The comments submitted in this record demonstrate that, 
in regions across the country, customers are electrifying everything 
from household appliances to vehicles.\215\ Comments also substantiate 
the fact that, in many regions, large loads associated with new and 
emerging industrial needs, like data centers, are driving rapid load 
growth.\216\ Estimates quantifying the magnitude of this shift show 
that it is significant, with nationwide demand for electricity 
projected to increase by 5% to 15% (200 to 600 TWh) by 2030.\217\ That 
trend is projected not just to continue but to accelerate, with 
nationwide demand for electricity projected to increase by 25% to 85% 
(1,100 to 3,700 TWh) by 2050.\218\ Industrial customers in many regions 
are driving much of this increase; industry executives have reported 
that electrification initiatives, through which many of the Nation's 
largest companies plan to electrify their manufacturing processes, 
transportation, and heating operations, are well underway or soon to 
begin.\219\ Importantly, the record shows that these increases in 
aggregate demand for electricity will have significant consequences for 
the transmission system. To serve more load, the capacity of the 
already-oversubscribed transmission system will need to increase.\220\ 
Moreover, load growth driven primarily by electrification can create a 
load profile that has a higher load factor and that is thus more 
challenging to serve.\221\
---------------------------------------------------------------------------

    \214\ NOPR, 179 FERC ] 61,028 at PP 45, 51. The continuation 
and, in some instances, acceleration of these trends identified in 
the ANOPR and NOPR counters certain commenters' concerns that 
changes in demand are inherently unpredictable or that existing 
regional transmission planning processes are adequately identifying 
and addressing transmission needs. Compare infra notes 21515-2188 
and accompanying discussion, with Potomac Economics Initial Comments 
at 3-4 (arguing that Long-Term Regional Transmission Planning that 
requires speculating about future uncertainty is not advisable), and 
Industrial Customers Initial Comments at 10-11 (arguing that changes 
in demand are unpredictable).
    \215\ AEE Initial Comments at 1, 14 (noting that, as of 2022, 
``[n]ine states have also taken steps directly to promote 
electrification of transportation and buildings. Individuals and 
governments are also adopting electric vehicles; for example, light-
duty electric vehicle sales have increased from 10,092 vehicles in 
2011 to 459,426 vehicles in 2021, over a 4400% increase.''); 
Renewable Northwest Initial Comments at 20 (explaining that heat 
pumps installed as part of building electrification could add large 
new weather-dependent loads, estimated at 20,000 to 40,000 MW of 
incremental peak capacity by 2050 across the Pacific Northwest); see 
also AMP Initial Comments at 4; ISO-NE, Operational Impact of 
Extreme Weather Events: Final Report on the Probabilistic Energy 
Adequacy Tool (PEAT) Framework and 2027/2032 Study Results, at 190-
94 (Nov. 2023) (providing sensitivity that included 15% and 10% 
increases in peak load and average hourly loads, respectively, 
driven by heating and vehicle electrification); U.S. Energy Info. 
Admin. (EIA), Incentives and Lower Costs Drive Electric Vehicle 
Adoption in Our Annual Energy Outlook, (May 15, 2023) (noting that, 
per 2023 Annual Energy Outlook Projections, electric vehicles will 
account for between 13% and 29% of new light-duty vehicle sales in 
the United States, and between 11% and 26% of then on-road light 
duty vehicle stocks, by 2050).
    \216\ See, e.g., Transmission Dependent Utilities Initial 
Comments at 4-5 (``For example, the PJM Interconnection, L.L.C. 
Transmission Expansion Advisory Committee recently posted that 
Dominion Energy Virginia will need over $603 million in transmission 
upgrades through 2025--just three years from now--to accommodate 
significant data center load growth in Northern Virginia.'' (citing 
PJM Transmission Advisory Committee, Reliability Analysis Update, at 
3, 5 (Aug. 9, 2022))). These trends are continuing and even 
accelerating. See PJM Interconnection, L.L.C., PJM Load Forecast 
Report, at 1 (Jan. 2024), https://www.pjm.com/-/media/library/reports-notices/load-forecast/2024-load-report.ashx (noting upward 
adjustments in 2024 load forecasts for certain zones to account for 
large, unanticipated load growth driven by data centers, a chip 
processing plant, and port electrification, among other factors); 
id. at 78 (projecting increase from 2,333 GWh in 2024 to 130,489 GWh 
in 2039 due to plug-in electric vehicles); id. at 30 (showing 1.0% 
higher load growth projection for 2024, 6% higher load growth 
projection for 2029, and 10.4% higher load growth projection for 
2034, as compared to 2023 Load Forecast Report).
    \217\ National Grid Initial Comments at 8 (citing J[uuml]rgen 
Weiss et al., The Brattle Group, The Coming Electrification of the 
North American Economy (Mar. 2019), https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf).
    \218\ Id.; see also John D. Wilson and Zach Zimmerman, Grid 
Strategies, The Era of Flat Power Demand is Over, at 3 (Dec. 2023), 
https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf (``Over [2023], grid planners nearly 
doubled the 5-year load growth forecast. The nationwide forecast of 
electricity demand shot up from 2.6% to 4.7% growth over the next 
five years, as reflected in 2023 FERC [Form 714] filings. Grid 
planners forecast peak demand growth of 38 gigawatts (GW) through 
2028.''); N. Amer. Elec. Reliability Corp., 2023 Long-Term 
Reliability Assessment, at 33 (Dec. 2023), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf 
(``Electricity peak demand and energy growth forecasts over the 10-
year assessment period are higher than at any point in the past 
decade. The aggregated assessment area summer peak demand forecast 
is expected to rise by 79 GW, and aggregated winter peak demand 
forecasts are increasing by nearly 91 GW. Furthermore, the growth 
rates of forecasted peak demand and energy have risen sharply since 
the 2022 [Long-Term Reliability Assessment], reversing a decades-
long trend of falling or flat growth rates.'').
    \219\ Renewable Northwest Initial Comments at 20 (``A recent 
study done by Deloitte showed that 70 percent of executives in 
industrial manufacturing industries have plans for the 
electrification of industrial processes, and 50 percent of the 
executives who responded have goals to electrify vehicle fleets and 
space and water heating within their companies by 2030.'' (citing 
Stanley Porter et al., Deloitte, Electrification in Industrials 
(Aug. 2020), https://www2.deloitte.com/us/en/insights/industry/power-and-utilities/electrification-in-industrials.html)).
    \220\ See, e.g., National Grid Initial Comments at 6 (discussing 
preliminary findings of the ISO-NE 2050 Transmission Study, which 
show ``significant new transmission will be needed to reliably 
serve'' increased future loads assumed in the study (citing ISO-NE, 
2050 Transmission Study (2023), https://www.iso-ne.com/static-assets/documents/2023/08/2050_study_ma_cetwg_2023_aug_final.pdf)); 
Northwest and Intermountain Initial Comments at 5 n.12 (``For 
example, Bonneville Power Administration (`BPA') owns about 75 
percent of the transmission lines in the Pacific Northwest. In BPA's 
2022 Transmission Service Expansion Plan cluster study, customers 
submitted 153 separate transmission service requests totaling 11,831 
MW of transmission capacity. BPA was able to offer service (without 
requiring detailed studies and transmission upgrades) to only 275 
MWs of those service requests.'' (citing BPA, TSR Study and 
Expansion Process, at 12 (Dec. 2021), https://www.bpa.gov/-/media/Aep/transmission/atc-methodology/2021-22tsep-overview.pdf.)).
    \221\ MISO Initial Comments at 54 (``In addition, a return to 
load growth driven primarily by the electrification of 
transportation, space heating and water heating is creating a load 
profile that has a higher load factor and is more challenging to 
serve.''). Load factor refers to ``[t]he ratio of the average load 
to peak load during a specified time interval.'' U.S. Energy Info. 
Admin. (EIA), Glossary (last visited Mar. 2024), https://www.eia.gov/tools/glossary/index.php?id=L.
---------------------------------------------------------------------------

    96. Third, supply is changing. As the NOPR explained, Federal, 
state, and local policies are incentivizing various forms of generation 
resources and other technologies,\222\ resulting in changes to the 
Nation's resource mix. The comments in this record show that these 
policies are widespread and now span

[[Page 49300]]

many regions of the country. States and cities in the Northeast,\223\ 
Mid-Atlantic,\224\ Midwest,\225\ West,\226\ and Southeast \227\ have 
adopted binding state laws requiring emissions reductions. Moreover, 
with the passage of the Inflation Reduction Act in 2022, Congress has 
enacted legislation that will further spur investment nationwide in 
renewable and non-emitting resources.\228\
---------------------------------------------------------------------------

    \222\ NOPR, 179 FERC ] 61,028 at P 45.
    \223\ National Grid Initial Comments at 6-7 (explaining how all 
six states in New England have renewable energy standards and how 
ISO-NE's 2050 Transmission Study demonstrates the demands that 
meeting those standards will place on New England's transmission 
system); id. at 7 (explaining how the Climate Leadership and 
Community Protection Act enacted in New York State requires 70% 
renewable generation by 2030, zero-emissions by 2040, and 85% 
economy-wide emissions reductions by 2050, and that transmission 
infrastructure will be critical in meeting those goals); NESCOE 
Initial Comments at 15 (``Achieving a decarbonized system is 
required by laws and mandates in Connecticut, Maine, Massachusetts, 
Rhode Island, and Vermont.'').
    \224\ DC and MD Offices of People's Counsel Initial Comments at 
18 (noting that ``both Maryland and the District have adopted 
ambitious jurisdiction-wide decarbonization policies applicable to 
the [electric distribution companies] regulated by their respective 
public service commissions.'').
    \225\ Illinois Commission Initial Comments at 5 (explaining that 
``[i]n Illinois, the Climate and Equitable Jobs Act of 2021 . . . 
will affect the future resource mix and demand and lead to 
decarbonization and electrification. For example, [it] requires 
Illinois to completely transition to clean energy by 2050 and 
facilitates electrification through the promotion of electric 
vehicles.'').
    \226\ Renewable Northwest Initial Comments at 6 (explaining 
that, ``[c]urrently, 80 percent of NorthernGrid's load is subject to 
state clean energy laws, and by 2040 NorthernGrid will have 65 
percent carbon-free energy.''); id. at 21 (explaining that 
Washington state's ``SB 5974 sets a goal of all vehicles sold in 
2030 and beyond to be [electric vehicles], with that goal becoming a 
mandate in 2035[.]'').
    \227\ SREA Initial Comments at 25 (noting that North Carolina 
has adopted Renewable Energy and Energy Efficiency Portfolio 
Standards and enacted the North Carolina Carbon Plan).
    \228\ ACORE Initial Comments at 1-2 & n.2 (projecting that 
``annual additions increasing from 15 GW of wind and 10 GW of 
utility-scale solar PV in 2020 to an average of 39 GW/year of wind 
additions in 2025-2026 (~2x the 2020 pace) and 49 GW/year of solar 
(~5x the 2020 pace), with solar growth rates increasing 
thereafter.'' (citing REPEAT Project, Preliminary Report: The 
Climate and Energy Impacts of the Inflation Reduction Act of 2022, 
at 15 (2022), https://repeatproject.org/docs/REPEAT_IRA_Prelminary_Report_2022-08-12.pdf)); CARE Coalition 
Initial Comments at 17 (``Analysis suggests that the [Inflation 
Reduction Act] could more than triple clean energy production in the 
U.S. and lead to $600 billion in capital investment in clean energy 
infrastructure.'' (citing American Clean Power Ass'n, It's a Big 
Deal for Job Growth and for a Clean Energy Future (2022), https://cleanpower.org/blog/its-a-big-deal-for-job-growth-and-for-a-clean-energy-future)); Evergreen Action Initial Comments at 3-4 
(discussing model showing that clean energy could comprise up to 81% 
of all U.S. generation as a result of increased incentives in the 
Inflation Reduction Act (citing John Larsen et al., Rhodium Group, A 
Turning Point for US Climate Progress: Assessing the Climate and 
Clean Energy Provisions in the Inflation Reduction Act (2022), 
https://rhg.com/research/climate-clean-energy-inflation-reduction-act)); NextEra Reply Comments at 5 (``The signing of the Inflation 
Reduction Act of 2022 . . . will only increase the demand for 
renewables in the coming years and accelerate corresponding demands 
on the transmission system.'').
---------------------------------------------------------------------------

    97. Customers are also driving changes in the resource mix. In 
addition to increasing their aggregate demand for electricity, the NOPR 
explained that customers, including major corporations, in many regions 
are increasingly demanding that load be served by renewable or non-
emitting resources.\229\ Substantial evidence in the record supports 
the existence of this trend. Since 2014, for example, ``commercial and 
industrial customers have contracted for more than 52 GW of clean 
energy[.]'' \230\ Furthermore, this trend is accelerating. In 2021 
alone, energy customers voluntarily contracted for ``11.06 GW of clean 
energy.'' \231\ The record demonstrates that, going forward, this shift 
is projected to continue, as forecasts show that Fortune 1000 companies 
will have up to 85 GW of new demand for renewable energy to meet their 
public sustainability commitments for 2030.\232\ As also noted in the 
NOPR, utilities in many regions have made commitments to procure most 
or all of their electricity from renewable or non-emitting resources. 
For example, Exelon,\233\ Dominion,\234\ AEP,\235\ and Southern \236\ 
have all committed to achieve net-zero emissions by 2050, and each has 
set an interim goal to significantly reduce emissions by 2030. And, 
although utility commitments vary by utility and by region, the record 
shows that many utilities have announced some future emissions 
target.\237\
---------------------------------------------------------------------------

    \229\ NOPR, 179 FERC ] 61,028 at P 45.
    \230\ Advanced Energy Buyers Initial Comments at 5 (citing Clean 
Energy Buyers Alliance, State of the Market 2022, https://cebuyers.org/state-of-the-market/).
    \231\ Clean Energy Buyers Initial Comments at 7.
    \232\ Clean Energy Buyers Initial Comments at 7 n.13 (citing 
Clean Energy Buyers ANOPR Initial Comments at 21-22).
    \233\ Exelon Initial Comments at 2 (``Exelon has established 
ambitious targets and aims to be a leader in clean energy by 
continuing to reduce its own greenhouse gas emissions, including 
reducing operations-driven emissions 50 percent by 2030, relative to 
a 2015 baseline, and achieving net-zero operations by 2050.'' 
(citing Calvin Butler, Exelon Corporation, We're on the Path to 
Clean (Apr. 2021), https://www.exeloncorp.com/grid/were-on-the-path-to-clean)).
    \234\ Dominion Initial Comments at 3-4 (``Dominion Energy has 
committed to achieve net zero greenhouse gas emissions by 2050 and 
is investing in clean energy resources such as solar and wind.'').
    \235\ AEP Initial Comments at 4 n.12 (``AEP's goal is to reduce 
carbon emissions from directly owned generation by 80% by 2030 
compared to 2000 levels and to achieve net-zero emissions by 2050.'' 
(citing AEP, 2022 Corporate Sustainability Report, at 48 (2022), 
https://www.aep.com/news/releases/read/8520/AEP-Releases-2022-Corporate-Sustainability-Report)).
    \236\ Southern Initial Comments at 14 (``By 2019, Southern 
Companies had already achieved a 44% reduction in greenhouse gas 
emissions in pursuit of its goals of a 50% reduction by 2030 and net 
zero by 2050.'').
    \237\ See, e.g., SREA Initial Comments at 41-42 (``Major 
utilities in the South, including Entergy, Dominion Energy, Duke 
Energy, NextEra, Tennessee Valley Authority, and Southern Company 
have all announced some version of a net zero carbon emission plan 
or commitment.'').
---------------------------------------------------------------------------

    98. Furthermore, as noted in the NOPR,\238\ the resource mix is 
also being affected by the changing economics of the resources that 
comprise the resource mix.\239\
---------------------------------------------------------------------------

    \238\ NOPR, 179 FERC ] 61,028 at P 45 & n.72 (noting the average 
levelized cost of wind energy for commercial wind generation has 
decreased from $90 per MWh in 2009, to $35 per MWh in 2019 (citing 
Lawrence Berkeley National Laboratory, Wind Energy Technology Date 
Update: 2020 Edition, at 66 (Nov. 2020))); id. (noting that the 
average levelized power purchase agreement price for utility-scale 
solar generation has decreased from approximately $160 per MWh in 
2009, to approximately $40 MWh in 2020 (citing Lawrence Berkeley 
National Laboratory, Utility-Scale Solar Data Update: 2020 Edition, 
at 32 (Nov. 2020))).
    \239\ See ACORE ANOPR Initial Comments at app. 1, p. 22 (ACEG 
Jan. 2021 Planning Report) (``Wind and solar energy costs have 
fallen 70 and 89 percent, respectively, in the last ten years, from 
2009 through 2019.''); Dominion Initial Comments at 19 (noting how, 
during the 2010s, the fracking revolution and advanced technology 
for natural gas combined cycle generation lead to a shift away from 
coal and nuclear as ``baseload'' fuels and how, today, renewable 
energy resources are likewise undergoing a similar expansion); 
Evergreen Action Initial Comments at 3 (``Rapid innovation has made 
wind and solar power the lowest-cost resource in many areas of the 
country[.]'' (citing Univ. of Tex. at Austin Energy Inst., Levelized 
Cost of Electricity in the United States by County (2022), https://calculators.energy.utexas.edu/lcoe_map/#/county/tech); see also 
ACORE Reply Comments at 2 (``In all scenarios, building transmission 
that enables low-cost wind and other energy resources is often 
cheaper than the alternatives, such as use of higher-cost but local 
resources (and potentially additional storage).'' (citing Paul 
Denholm, et al., National Renewable Energy Laboratory, Examining 
Supply-Side Options to Achieve 100% Clean Electricity by 2035, at 
47-78 (Sept. 2022))).
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    99. Together, trends in economics, growing demand, and Federal, 
federally-recognized Tribal, state, and local policies are already 
resulting in significant changes in the resource mix. The record shows 
that as of 2021, nearly 70% of capacity additions across the country 
were from new, utility-scale wind and solar resources.\240\ Meanwhile, 
most of the capacity retirements are, and are projected to continue to 
be, coal resources.\241\ Based

[[Page 49301]]

on the record, those trends are projected to continue, with over 1,300 
GW of wind, solar, and storage resources in interconnection queues 
across the country as of 2021.\242\ With the passage of the Inflation 
Reduction Act in 2022, many analysts are predicting that the shift 
toward renewable resources will accelerate.\243\
---------------------------------------------------------------------------

    \240\ SREA Initial Comments at 1-2 (citing US Energy Info. 
Admin., Today in Energy (2021), https://www.eia.gov/todayinenergy/detail.php?id=46416#); see also AEE Initial Comments at 13 (noting 
that between 2011 and 2021, ``renewable generation nearly doubled, 
from 12.5% to more than 20%.'').
    \241\ AEE Initial Comments at 12-13 (``From 2011 to 2021, the 
proportion of U.S. electricity generated by coal plants dropped by 
almost half, from 42% to under 22%'' (citing U.S. Energy Info. 
Admin., U.S. Electricity Generation by Major Energy Source, 1950-
2021 (2022), https://www.eia.gov/energyexplained//electricity/charts/generation-major-source.csv)); California Commission Initial 
Comments at 65 (citing FERC, State of the Markets 2020 (Mar. 2021); 
Renewable Northwest Initial Comments at 36 (using IRP data to show 
that utilities in NorthernGrid plan to retire 6,573 MW of coal, 
1,476 MW of natural gas, 10 MW of wind, and 18 MW of solar, by 
2040). FERC's State of the Markets 2020 report stated that 9.6 GW of 
coal capacity retired in 2020, which had a noticeable effect on 
coal's operating capacity share in most RTOs/ISOs. FERC, State of 
the Markets 2020, at 10, 12 (Mar. 2021). FERC's State of the Markets 
2023 indicates that this trend is continuing, with coal generation 
declining 18.8% in 2023. FERC, State of the Markets 2023, at 4 (Mar. 
2024). See also US DOE Initial Comments at App. B, pp. 8-9 (Rand et 
al., Lawrence Berkeley National Laboratory, Queued Up: 
Characteristics of Power Plants Seeking Transmission Interconnection 
as of the End of 2021 (Apr. 2021)).
    \242\ See US DOE Initial Comments app. B, at p. 26 (Lawrence 
Berkeley National Laboratory, Queued Up: Characteristics of Power 
Plants Seeking Transmission Interconnection As of the End of 2021 
(Apr. 2022)) (noting that 676 GW of solar, 246 GW of wind, 213 GW of 
standalone battery capacity, and ~208 GW of hybrid battery capacity 
wait in interconnection queues across the U.S.). On the other hand, 
the number of coal and, relatedly, natural gas resources waiting to 
interconnect is limited. See id.; Colorado Consumer Advocates 
Initial Comments attach. 7, at p. 21 (``No new coal plants have been 
built for domestic utility electricity production since 2014[.]''); 
NESCOE Initial Comments at 15-16 (noting that new natural gas 
generation represented nearly 48% of the queue in 2017, but just 3% 
by March of 2022). Moreover, the updated version of the report to 
which US DOE cites indicates that the capacity of wind, solar, and 
storage in interconnection queues is still increasing. Lawrence 
Berkeley National Laboratory, Queued Up: Characteristics of Power 
Plants Seeking Transmission Interconnection As of the End of 2022 
(Apr. 2023) (noting that 947 GW of solar, 300 GW of wind, 325 GW of 
standalone battery capacity, and ~358 GW of hybrid storage capacity, 
totaling over 1900 GW, wait in interconnection queues across the 
country).
    \243\ ACORE Initial Comments at 1-2 & n.2 (``[P]rojecting annual 
additions increasing from 15 GW of wind and 10 GW of utility-scale 
solar PV in 2020 to an average of 39 GW/year of wind additions in 
2025-2026 (~2x the 2020 pace) and 49 GW/year of solar (~5x the 2020 
pace), with solar growth rates increasing thereafter.'' (quoting 
REPEAT Project, Preliminary Report: The Climate and Energy Impacts 
of the Inflation Reduction Act of 2022, at 15 (2022), https://repeatproject.org/docs/REPEAT_IRA_Prelminary_Report_2022-08-12.pdf)).
---------------------------------------------------------------------------

    100. In light of these changing demands on the transmission system, 
the record also affirms what the Commission has long recognized: 
regional transmission planning that identifies more efficient or cost-
effective transmission solutions to needs helps to ensure cost-
effective transmission development for customers and can yield better 
returns for every dollar spent than localized or piecemeal transmission 
solutions.\244\ Conversely, inadequate or poorly designed transmission 
planning processes can lead to relatively inefficient or less cost-
effective transmission investment, with customers footing the bill for 
piecemeal, inefficient, and less cost-effective transmission solutions 
designed to meet short-term or small-scale transmission needs. Given 
the magnitude of transmission investment needed to meet customers' 
changing needs, it is essential that regional transmission planning be 
of sufficient scope and duration to help to ensure customers' money is 
well-spent on transmission infrastructure that can efficiently and 
cost-effectively meet those needs. Unfortunately, we conclude that this 
is not the case today and that existing regional transmission planning 
processes are inadequate to address the emerging Long-Term Transmission 
Needs that are expected to increasingly drive transmission investment 
in the coming decades.
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    \244\ Order No. 1000, 136 FERC ] 61,051 at P 55 (``[T]he narrow 
focus of current planning requirements and shortcomings of current 
cost allocation practices create an environment that fails to 
promote the more efficient and cost-effective development of new 
transmission facilities.''); id. P 68 (concluding that reforms that 
require transmission providers to engage in regional transmission 
planning and evaluate proposed alternatives that ``may resolve the 
region's needs more efficiently or cost-effectively than solutions 
identified in the local transmission plans . . . will provide 
assurance that rates for transmission services on these systems will 
reflect more efficient or cost-effective solutions for the 
region.''); Order No. 890, 118 FERC ] 61,119 at P 524 
(``[C]oordination of planning on a regional basis will also increase 
efficiency through the coordination of transmission upgrades that 
have region-wide benefits, as opposed to pursuing transmission 
expansion on a piecemeal basis.''); see also ACORE Initial Comments 
at 6 (demonstrating that effective regional transmission planning 
could significantly reduce total electric system costs compared to 
electric system costs that result from intrastate planning (citing 
Brattle-Grid Strategies Oct. 2021 Report at 12)); R Street Initial 
Comments at 8 (``[H]olistic transmission planning could improve 
economic efficiencies and save billions of dollars . . . . For 
example, MISO's 2022 long-range transmission plan results include 
$10 billion in transmission projects that support interconnection of 
53,000 megawatts of new renewable generation and reduces other costs 
by $37-$68 billion. PJM similarly identified $3 billion in 
transmission upgrades that would save billions compared to the 
current practice of incremental upgrades through the interconnection 
process.'' (citing Johannes Pfeifenberger, Brattle Group, Planning 
for Generation Interconnection, at 5 (May 31, 2022), https://www.esig.energy/event/special-topic-webinar-interconnection-study-criteria (citation omitted))).
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    101. Experience with the implementation of Order No. 1000 over the 
last decade has highlighted a critical gap in the Commission's existing 
transmission planning and cost allocation requirements. Notwithstanding 
the broad recognition that additional transmission infrastructure is 
needed to address the drivers noted above, regional transmission 
planning processes across the country have yielded only limited 
investments in regional transmission projects. As the Commission 
observed in the NOPR, investment in regional transmission facilities in 
some regions has declined compared to prior to Order No. 1000.\245\ 
Moreover, across all the non-RTO/ISO regions, there has not yet been a 
single transmission facility selected since implementation of Order No. 
1000.\246\ The record also demonstrates that within some RTO/ISO 
regional transmission planning processes, even where investments 
through the regional transmission planning process do occur, much of 
that investment has been in transmission projects that only address 
immediate reliability needs.\247\ We find that this evidence supports 
our conclusion that existing regional transmission planning processes 
are not of sufficient scope and duration to adequately or consistently 
identify transmission needs and associated opportunities to more 
comprehensively evaluate and select more efficient or cost-effective 
transmission solutions to those needs.
---------------------------------------------------------------------------

    \245\ NOPR, 179 FERC ] 61,028 at P 39 (citing ACEG Jan. 2021 
Planning Report at 25 & fig. 8); see also ACORE ANOPR Initial 
Comments at 4 (``Despite the potential benefits, regional 
transmission investment has not increased and in some regions even 
has declined over the past decade.'') (citing ACEG Jan. 2021 
Planning Report at 25)); State Agencies Initial Comments at 23 
(``Regionally planned projects have [ ] declined in RTOs/ISOs . . . 
.'' (citing John C. Gravan and Rob Gramlich, NRRI Insights, A New 
State-Federal Cooperation Agenda for Regional and Interregional 
Transmission, at 2 (Sept. 2021), https://pubs.naruc.org/pub/FF5D0E68-1866-DAAC-99FB-A31B360DC685)).
    \246\ NOPR, 179 FERC ] 61,028 at P 39 (citing LS Power ANOPR 
Initial Comments App. I at 18 & n.57); FERC, Staff Report, 2017 
Transmission Metrics, at 19 (Oct. 6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf); 
see also Western PIOs Initial Comments at 28 (``The Western Regional 
Planning Groups, with the exception of the CAISO, have not developed 
new projects from their current Order 1000 transmission planning 
process.'').
    \247\ Southwestern Power Group Initial Comments at 15; PIOs 
ANOPR Initial Comments at 93 & n.276; see also Ari Peskoe, Is the 
Utility Syndicate Forever?, 42 Energy L.J. 1, 56-57 (2021) 
(explaining, for example, that in ISO-NE, all but one of the 
transmission projects approved through the regional transmission 
planning process were immediate-need reliability projects).
---------------------------------------------------------------------------

    102. Indeed, in the limited instances in which transmission 
providers have followed processes that share many of the elements of 
the long-term, forward-looking, and more comprehensive regional 
transmission planning this

[[Page 49302]]

order requires, customers have seen clear and quantifiable benefits. 
For example, as the Commission observed in the NOPR,\248\ MISO's Multi-
Value Project (MVP) transmission planning process proactively planned 
over a 20-year period for two key drivers of transmission needs: the 
impacts of changing state laws on the resource mix, and a large 
increase in the number of generator interconnection requests. To 
mitigate the uncertainties associated with such long-term projections 
of transmission needs, MISO relied on scenarios to consider a range of 
potential future conditions \249\ and disclosed the assumptions and 
inputs underlying each scenario.\250\ The MVP process then identified a 
portfolio of transmission projects that were projected to provide 
multiple kinds of reliability and economic benefits under all the 
alternate future scenarios studied.\251\ This process resulted in MISO 
identifying, evaluating, and selecting transmission facilities that are 
estimated to generate $2.20 to $3.40 of benefit per dollar 
invested.\252\
---------------------------------------------------------------------------

    \248\ NOPR, 179 FERC ] 61,028 at PP 30-31 (citing Midcontinent 
Indep. Sys. Operator, RGOS: Regional Generation Outlet Study, at 2 
(Nov. 2020)).
    \249\ Id. P 31 (citing MTEP2017 Review at 26-29).
    \250\ Id. (citing MTEP2017 Review at 16).
    \251\ Id. (citing MTEP2017 Review at 13).
    \252\ Id. P 30 (citing MTEP2017 Review at 4).
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    103. The benefits to transmission customers of long-term, forward-
looking, and more comprehensive regional transmission planning, which 
we discuss further below, are thus well-documented but realized all too 
infrequently under existing regional transmission planning processes. 
Relatedly, the record demonstrates that a substantial amount of new 
transmission investment is occurring outside of regional transmission 
planning processes. Because these other processes--specifically, 
generator interconnection processes and local transmission planning 
processes--are generally designed to address discrete, shorter-term 
needs, and do not comprehensively assess either broader transmission 
needs or solutions to those needs, overreliance on those processes can 
result in relatively inefficient or less cost-effective transmission 
development for customers,\253\ which contributes to rates for 
transmission that are unjust and unreasonable.
---------------------------------------------------------------------------

    \253\ ACORE Initial Comments at 4-5 (citing Brattle-Grid 
Strategies Oct. 2021 Report at 3); Clean Energy Associations Initial 
Comments at 5 (explaining that proactive, forward-looking 
transmission planning processes can reduces costs by nearly half as 
compared to incremental and reactive transmission planning 
processes); [Oslash]rsted Initial Comments at 5 (explaining that 
failure to proactively plan for offshore wind results in suboptimal 
transmission development, which can increase costs to ratepayers); 
Southeast PIOs Reply Comments at 2 (explaining that in the 
Southeast, ``snowballing inefficiencies created by numerous small-
scale transmission band-aids, unfit to address broader generation 
trends, translate into excessive, unjust, and unreasonable rates 
borne by an already overburdened populace.'').
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    104. The record demonstrates that significant expansion of the 
transmission system is occurring through one-off, piecemeal, 
interconnection-related network upgrades constructed in response to 
individual generator interconnection requests.\254\ As the Commission 
observed in the NOPR, the evidence shows a sharp growth in both the 
total cost of interconnection-related network upgrades and in the cost 
of such upgrades relative to generation project costs.\255\ The record 
indicates that the average cost of interconnection-related network 
upgrades is increasing over time as the transmission system is fully 
subscribed and demand for interconnection service outpaces transmission 
investment. As highlighted in the NOPR,\256\ in 2020, MISO identified 
the need for nearly $2.5 billion in interconnection-related network 
upgrades to interconnect just 9.2 GW of generation in MISO South, and 
MISO expects to need over $3 billion in interconnection-related network 
upgrades for interconnection in MISO West.\257\ Similarly, SPP 
identified the need for $4.6 billion in interconnection-related network 
upgrades to interconnect just 10.4 GW of new generation.\258\
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    \254\ Pine Gate Initial Comments at 6, 8-10; PIOs Initial 
Comments at 9 (noting how most transmission planning is done through 
the generator interconnection process or local transmission 
planning).
    \255\ NOPR, 179 FERC ] 61,028 at P 37.
    \256\ Id. PP 37-38.
    \257\ ACORE ANOPR Initial Comments at 10 (citing ICF Sept. 2021 
Interconnection Report at 2).
    \258\ Id. (citing ICF Sept. 2021 Interconnection Report at 3-4).
---------------------------------------------------------------------------

    105. Record evidence also shows that increases in interconnection 
costs are being driven, in many cases, by an expansion in the scope and 
complexity of interconnection-related network upgrades.\259\ The 
Commission noted in the NOPR, for example, that interconnection-related 
network upgrade costs in MISO West went from approximately $300/kW in 
2016 to nearly $1,000/kW in 2017.\260\ The trend is evident in other 
parts of the country as well.\261\ The costs of interconnection-related 
network upgrades are, in many cases, an ever-growing percentage of the 
total capital costs of new generation projects. According to one 
report, interconnection costs for new renewable resources were less 
than 10% of total generation project costs until a few years ago, but 
recently these costs have risen to as much as 50%-100% of the total 
generation project costs.\262\ At the

[[Page 49303]]

same time, interconnection-related network upgrades have frequently 
transitioned from primarily small transmission facilities that serve 
the needs of a limited number of interconnection customers to the size 
and scope of what have traditionally been considered high voltage 
transmission facilities. For example, interconnection-related network 
upgrades have recently included demolishing and rebuilding multiple 500 
kV transmission lines \263\ and constructing long, double-circuit, 765 
kV transmission lines,\264\ all at significant cost to the 
interconnection customer initially--and ultimately to consumers.
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    \259\ See, e.g., US DOE Initial Comments at 8 & n.20 (citing Jay 
Caspary et al., ACEG, Disconnected: The Need for a New Generator 
Interconnection Policy, at 13-16 (2021), https://cleanenergygrid.org/wp-content/uploads/2021/01/Disconnected-The-Need-for-a-New-Generator-Interconnection-Policy-1.pdf) (ACEG 2021 
Interconnection Report); Will Gorman et al., Improving estimates of 
transmission capital costs for utility-scale wind and solar projects 
to inform renewable energy policy, 135 Energy Policy 110994 (2019), 
https://www.sciencedirect.com/science/article/pii/S0301421519305816)); ACEG 2021 Interconnection Report at 13 (``[T]he 
costs for integrating new resources in MISO are rising substantially 
relative to previous years, indicating that the large-scale network 
has reached its capacity and needs to expand to connect more 
generation. In other words, much more than `driveway' type 
facilities are need; larger roads and highways are required to 
alleviate the traffic . . . . [H]istorically, interconnecting wind 
projects have incurred interconnection costs of $0.85 per megawatt 
hour (MWh) or $66 per kilowatt (kW). However, newly proposed wind 
projects now face interconnection costs that are nearly five times 
higher, at $4.05/MWh or $317/kW.''); id. at 14 (``New solar projects 
in MISO South have much higher upgrade costs. The most recent 2019 
system impact study for solar projects in MISO South estimated 
upgrade costs to total $307/kW, with upgrade costs for individual 
interconnection requests as high as $677/kW.''); id. (``The same 
trend of rising network upgrade cost assignments is occurring in 
PJM. Historically, the levelized costs for constructed wind and 
solar projects were $0.25/MWh and $1.72/MWh, respectively, or $19.07 
kW and $61.83/kW, respectively . . . costs for newly proposed wind 
and solar projects, however, have now risen to $0.69/MWh and $3.66/
MWh, respectively or $0.54/kW and $131.90/kW, respectively--more 
than a 100 percent increase.'').
    \260\ NOPR, 179 FERC ] 61,028 at P 38 (citing ACEG Jan. 2021 
Interconnection Report at 14; NextEra ANOPR Initial Comments at 16 
(citing Midcontinent Indep. Sys. Operator, MISO 2020 Queue Outlook, 
at 9 (2020), https://cdn.misoenergy.org/MISO2020InterconnectionQueueOutlook445829.pdf)).
    \261\ NOPR, 179 FERC ] 61,028 at P 38 (showing that, as of 2019, 
interconnection costs in PJM for constructed wind and solar projects 
were $19.07/kW and 61.83/kW, respectively, as compared to a greater 
than 100% increase to $54/kW and $131.90/kW, respectively, for 
projects newly proposed today) (citing e.g., ACEG Jan. 2021 
Interconnection Report at 14 & tbl.2)); NextEra ANOPR Initial 
Comments at 16-17 (stating that interconnection-related network 
upgrade cost estimates have nearly tripled for newly proposed wind 
projects, and more than doubled for solar projects in PJM); see also 
ACEG Jan. 2021 Interconnection Report at 16 (illustrating an 
increase in average interconnection-related network upgrade costs in 
NYISO from $67/kW in 2013 to $124/kW in 2019). Compare ACEG Jan. 
2021 Interconnection Report at 15 (identifying interconnection-
related network upgrade costs in 2013 in SPP as $89/kW), with ICF 
Sept. 2021 Interconnection Report at 2 (citing interconnection-
related network upgrade costs of $448/kW for interconnection 
customers studied in SPP's system impact study published in April 
2021)).
    \262\ NOPR, 179 FERC ] 61,028 at P 38 (citing ACEG Jan. 2021 
Interconnection Report at 6); id. (stating that the rising 
interconnection costs of wind projects in MISO recently reached 
approximately 23% of the capital cost of the project) (citing ACEG 
Jan. 2021 Interconnection Report at 13)); id. (identifying the 
increase in interconnection-related network upgrade costs in SPP 
between 2013 and 2017 as representing an increase from around 8% to 
over 43% of the capital cost of wind generation (citing ACEG Jan. 
2021 Interconnection Report. at 15)); NextEra ANOPR Initial Comments 
at 17 (similar)).
    \263\ NOPR, 179 FERC ] 61,028 at P 38 (describing 
interconnection-related network upgrades for a 120 MW solar plus 
storage project in southern Virginia to interconnect to PJM that 
cost as much as $12,086/kW (citing ACEG Jan. 2021 Interconnection 
Report at 15)).
    \264\ NOPR, 179 FERC ] 61,028 at P 38 (describing one 
interconnection-related network upgrade in SPP identified in the 
system impact study published in April 2021) (citing ACEG Jan. 2021 
Interconnection Report at 15)); ICF Sept. 2021 Interconnection 
Report at 3 (same); NextEra ANOPR Initial Comments at 17 (same). In 
2017, for example, SPP included a 165-mile, $1.34 billion double 
circuit 765 kV line in its Definitive Interconnection System Impact 
Study. See ACORE ANOPR Initial Comments Ex. 5, ICF Sept. 2021 
Interconnection Report at 4.
---------------------------------------------------------------------------

    106. Unlike regional transmission planning processes, however, the 
generator interconnection process is not designed to consider how to 
address transmission needs more efficiently or cost-effectively beyond 
the discrete interconnection request (or requests) being studied. 
Therefore, the generator interconnection process does not look at time 
horizons beyond the specific interconnection request(s) being studied, 
comprehensively assess any transmission needs beyond those created by 
the specific interconnection request(s), or achieve the economies of 
scale in transmission investment that long-term, forward-looking, and 
more comprehensive regional transmission planning processes can 
provide.\265\
---------------------------------------------------------------------------

    \265\ Anbaric Initial Comments at 5; Clean Energy Associations 
Initial Comments at 15 (noting the reactive nature of generator 
interconnection processes); Exelon Initial Comments at 5 (explaining 
that the ``project-by-project approach of developing 
[interconnection-related] network upgrades'' using the generator 
interconnection processes will likely not result in efficient or 
cost-effective outcomes given the ongoing changes in the resource 
mix and demand); Pine Gate Initial Comments at 9 (explaining how 
piecemeal approaches to transmission planning, like the generator 
interconnection process, result in inefficiently small upgrades 
(citing ACEG Jan. 2021 Interconnection Report at 7)); PIOs Initial 
Comments at 10; SEIA Initial Comments at 2; Southeast PIOs Initial 
Comments at 37 (``The lack of any regular, formal proceeding to 
consider Alabama Power's comprehensive facility investment plan is 
troubling and ensures that both generation and transmission are 
considered on a project-by-project basis. This piecemeal approach to 
addressing transmission needs for individual generation resource 
decisions will cause sticker-shock every time and an institutional 
aversion to broader transmission investment, especially when 
transmission benefits are expressly ignored.'').
---------------------------------------------------------------------------

    107. We acknowledge that the Commission recently issued Order No. 
2023, which requires transmission providers to reform their generator 
interconnection processes. But while Order No. 2023 aims to improve the 
efficient processing of interconnection queues, it does not attempt to 
remedy the discrete deficiency addressed in this final order: that 
existing regional transmission planning and cost allocation 
requirements do not require transmission providers to plan on a 
sufficiently long-term, forward-looking, and comprehensive basis. 
Instead, Order No. 2023 seeks to ameliorate the fact that existing 
generator interconnection procedures and agreements were ``insufficient 
to ensure that interconnection customers are able to interconnect to 
the transmission system in a reliable, efficient, transparent, and 
timely manner[.]'' \266\ The interconnection queue backlogs and delays 
that were the Commission's focus in Order No. 2023 have arisen, in 
part, due to deficiencies in the existing transmission planning 
requirements. But the Commission found issues regarding the 
coordination between transmission planning and generator 
interconnection processes were beyond the scope of Order No. 2023 and, 
therefore, the Commission addressed only interconnection queue 
processes rather than also addressing transmission planning 
requirements.\267\ Consequently, this final order addresses a root 
cause of interconnection backlogs and delays that Order No. 2023 did 
not--the failure of transmission providers to plan on a sufficiently 
long-term, forward-looking, and comprehensive basis. Accordingly, the 
need to reform this deficiency persists despite the Commission's 
reforms required by Order No. 2023.
---------------------------------------------------------------------------

    \266\ Order No. 2023, 184 FERC ] 61,054 at P 36.
    \267\ Order No. 2023, 184 FERC ] 61,054 at PP 1741, 1743 
(finding that, although ``several commenters argue in favor of 
greater coordination between generator interconnection and 
transmission planning or identify interconnection as a matter 
requiring interregional planning,'' those comments were beyond the 
scope of that rulemaking proceeding and noting that ``the Commission 
proposed reforms related to coordination between regional 
transmission planning and cost allocation and generator 
interconnection in'' the docket for this final order).
---------------------------------------------------------------------------

    108. While some commenters argue that transmission providers do not 
rely too heavily on the generator interconnection process to build 
transmission facilities,\268\ we find that the record indicates 
otherwise. Specifically, as discussed above, the increase in both the 
total and average cost of interconnection demonstrates how much 
transmission investment is occurring on a one-off, incremental basis 
through generator interconnection processes.\269\ The Commission has 
consistently and repeatedly found that interconnection-related network 
upgrades provide systemwide benefits,\270\ a finding which courts have 
upheld.\271\ In turn, we find that increasingly relying on 
interconnection customers' interconnection-related network upgrades to 
expand the capacity of the transmission system is inefficient and leads 
to less cost-effective transmission development than would result from 
long-term, forward-looking, and more comprehensive regional 
transmission planning, to the detriment of customers.
---------------------------------------------------------------------------

    \268\ Mississippi Commission Initial Comments at 9; North 
Carolina Commission and Staff Initial Comments at 5; Southern 
Initial Comments at 38-40.
    \269\ New Jersey Commission Initial Comments at 6-7 (noting that 
interconnecting 87.1 GW of capacity, which is needed to meet the PJM 
states' offshore wind and renewable portfolio standards goals, 
through the interconnection queue process alone is projected to cost 
$36 billion); US DOE Initial Comments at 8 (citing ACEG 2021 
Interconnection Report at 13-16 (2021)).
    \270\ See, e.g., Duke Energy Progress, LLC, 181 FERC ] 61,229, 
at P 17 (2022) (rejecting Duke's claim that ``its customers reap no 
benefits from network upgrades that must be constructed on Duke's 
affected system'' because ``Duke's characterization disregards the 
existence of any benefits to its customers from the network 
upgrades''); ISO New England Inc., 150 FERC ] 61,209, at P 386 
(2015) (noting that there ``is a presumption that transmission 
system enhancements benefit all members of an integrated 
transmission system''); Pac. Gas & Elec. Co., 106 FERC ] 61,144, at 
P 22 (2004) (explaining that ``the integrated grid is a single 
interconnected system serving and benefitting all transmission 
customers''); Pub. Serv. Co. of Colo., 62 FERC ] 61,013, at 61,061 
(1993) (``The Commission has reasoned that, even if a customer can 
be said to have caused the addition of a grid facility, the addition 
represents a system expansion used by and benefitting all users due 
to the integrated nature of the grid.'' (emphasis in original)).
    \271\ See, e.g., Nat'l. Ass'n of Regul. Util. Comm'rs v. FERC, 
475 F.3d 1277, 1285 (D.C. Cir. 2007) (``We have endorsed the 
approach of `assign[ing] the costs of system-wide benefits to all 
customers on an integrated transmission grid.''); W. Mass. Elec. Co. 
v. FERC, 165 F.3d 922, 927 (D.C. Cir. 1999) (``When a system is 
integrated, any system enhancements are presumed to benefit the 
entire system.''); City of Holyoke Gas & Elec. Dep't v. FERC, 954 
F.2d 740, 742-43 (D.C. Cir. 1992); Me. Pub. Serv. Co. v. FERC, 964 
F.2d 5, 8-9 (D.C. Cir. 1992).
---------------------------------------------------------------------------

    109. Separately, the record here also substantiates the NOPR's 
preliminary

[[Page 49304]]

finding that the majority of investment in transmission facilities 
since the issuance of Order No. 1000 has been in local transmission 
facilities.\272\ Commenters explain that, in RTO/ISO regions, one half 
of the nearly $70 billion in aggregate transmission investments by 
Commission-jurisdictional transmission providers between 2013 and 2017 
was approved outside of regional transmission planning processes.\273\ 
This investment trend is continuing and accelerating. For example, in 
2019, PJM approved 383 transmission-owner planned supplemental projects 
at a total cost of $3.75 billion, compared to only 80 regionally 
planned baseline projects at a total cost of $1.27 billion. Then, in 
2020, PJM approved 236 supplemental projects at a total cost of $4.7 
billion, compared to only 43 regionally planned baseline projects at a 
total cost of $413 million.\274\ In MISO, baseline reliability projects 
and other local transmission projects have grown dramatically since 
2010 and constituted 100% of approved transmission between 2018 and 
2020 and 80% since 2010.\275\ From 2019 to 2021, 63% of transmission 
investment by the three largest transmission owners in CAISO was in 
local transmission projects, and Pacific Gas and Electric forecasts 
that of the $13 billion it will spend on capital additions between 2022 
and 2027, approximately 84% will be on local transmission 
projects.\276\ In ISO-NE, spending on in-kind transmission 
replacements, which are not part of the regional transmission planning 
process, has been significant. Between 2016 and 2022, over $2.5 billion 
has been spent on in-kind replacement projects that have entered 
service and, as of 2022, an additional $3.122 billion of in-kind 
replacement projects had been proposed, planned, or were under 
construction.\277\
---------------------------------------------------------------------------

    \272\ NOPR, 179 FERC ] 61,028 at PP 39-40.
    \273\ PIOs Initial Comments at 9.
    \274\ PIOs ANOPR Initial Comments at 31-44; see also Ohio 
Consumers Initial Comments at 5 (``Since 2017, in Ohio, less than 
25% of the new investment in transmission has been associated with 
large regional transmission projects needed for reliability or 
economic efficiency.'').
    \275\ See PIOs Initial Comments at 10 n.31 (citing PIOs ANOPR 
Initial Comments at 49 (citing Brattle-Grid Strategies Oct. 2021 
Report at iii, 2)).
    \276\ See California Commission Initial Comments at 109-110.
    \277\ NESCOE Reply Comments at 6.
---------------------------------------------------------------------------

    110. As with the growing reliance on the generator interconnection 
process to identify needed transmission system improvements, local 
transmission planning, with its focus on the needs of individual 
utility footprints, does not necessarily provide sufficient, 
comprehensive analysis of broader regional transmission needs. 
Similarly, local transmission planning processes and in-kind 
replacement processes do not generally assess transmission needs based 
on a forward-looking multi-scenario assessment that more 
comprehensively accounts for the benefits of transmission 
infrastructure.\278\ Therefore, transmission expansion in this 
incremental manner also misses the potential for transmission providers 
to identify, evaluate, and select more efficient or cost-effective 
transmission facilities to solve transmission needs, as well as to 
afford system-wide benefits that may not be achieved through piecemeal, 
one-off local transmission facilities. As stated above, the result is 
relatively inefficient or less cost-effective transmission development 
for customers, which contributes to rates for transmission that are 
unjust and unreasonable.
---------------------------------------------------------------------------

    \278\ PIOs ANOPR Initial Comments at 33-34 (citing ACEG Jan. 
2021 Planning Report); ACEG Jan. 2021 Planning Report at 98-99.
---------------------------------------------------------------------------

    111. To be clear, our findings here are not intended to call into 
question the justness and reasonableness of either generator 
interconnection processes or local transmission planning processes, 
which each serve important roles in ensuring reliability and 
integrating new resources onto the transmission system.\279\ Rather, 
the trends regarding use of these processes, as well as in-kind 
replacement processes, provide additional evidence to support our 
finding that existing regional transmission planning and cost 
allocation requirements are inadequate without reform. As discussed 
further in the next section, we conclude that the record regarding the 
current and projected transmission landscape--including the investment 
trends and changing drivers of that investment detailed above--
highlights critical deficiencies in the Commission's current regional 
transmission planning and cost allocation requirements. In this final 
order, we address those deficiencies to help to ensure that customers 
receive the benefits of long-term, forward-looking, and more 
comprehensive regional transmission planning.
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    \279\ As discussed below, we separately find that specific 
existing requirements governing transparency in local transmission 
planning processes and coordination between local and regional 
transmission planning processes are unjust, unreasonable, and unduly 
discriminatory or preferential. See infra Local Transmission 
Planning Inputs in the Regional Transmission Planning Process 
section.
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2. Unjust, Unreasonable, and Unduly Discriminatory or Preferential 
Commission-Jurisdictional Transmission Planning and Cost Allocation 
Processes
    112. Based on the record, including comments submitted in response 
to the NOPR, as discussed below, we find that there is substantial 
evidence to support the determination that sufficiently long-term, 
forward-looking, and comprehensive regional transmission planning and 
cost allocation to meet Long-Term Transmission Needs is not occurring 
on a consistent and sufficient basis. We find that the absence of 
sufficiently long-term, forward-looking, and comprehensive regional 
transmission planning processes is resulting in piecemeal transmission 
expansion to address relatively near-term transmission needs. We find 
that the status quo approach results in transmission providers 
undertaking investments in relatively inefficient or less cost-
effective transmission infrastructure, the costs of which are 
ultimately recovered through Commission-jurisdictional rates. This 
dynamic results in, among other things, transmission customers paying 
more than is necessary or appropriate to meet their transmission needs, 
customers forgoing benefits that outweigh their costs, or some 
combination thereof, which results in less efficient or cost-effective 
transmission investments and, in turn, renders Commission-
jurisdictional regional transmission planning and cost allocation 
processes unjust and unreasonable.
    113. We therefore adopt, as modified by the discussion herein, the 
preliminary findings of the NOPR concerning the need for reform \280\ 
and, pursuant to FPA section 206, conclude that revisions to the 
Commission's regional transmission planning and cost allocation 
requirements are necessary to ensure that Commission-jurisdictional 
rates, terms, and conditions are just, reasonable, and not unduly 
discriminatory or preferential. We find that, as stated in the 
NOPR,\281\ absent the reforms instituted by this final order, regional 
transmission planning processes will continue to fail to identify, 
evaluate, and select regional transmission facilities that can more 
efficiently or cost-effectively meet Long-Term Transmission Needs, 
requiring customers to pay for relatively inefficient or less cost-
effective transmission development.
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    \280\ NOPR, 179 FERC ] 61,028 at PP 28-55.
    \281\ NOPR, 179 FERC ] 61,028 at P 33.

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[[Page 49305]]

    114. Based on the record, including the comments submitted in 
response to the NOPR, we find that there is substantial evidence to 
support the conclusion that deficiencies in the Commission's existing 
regional transmission planning and cost allocation requirements are 
resulting in Commission-jurisdictional rates that are unjust, 
unreasonable, and unduly discriminatory or preferential. Specifically, 
we find that the Commission's regional transmission planning and cost 
allocation requirements fail to require transmission providers to: (1) 
perform a sufficiently long-term assessment of transmission needs that 
identifies Long-Term Transmission Needs; (2) adequately account on a 
forward-looking basis for known determinants of Long-Term Transmission 
Needs; and (3) consider the broader set of benefits of regional 
transmission facilities planned to meet those Long-Term Transmission 
Needs. We find that these deficiencies render Commission-jurisdictional 
regional transmission planning and cost allocation processes unjust and 
unreasonable because they result in transmission providers failing to 
identify Long-Term Transmission Needs, to evaluate and select more 
efficient or cost-effective transmission solutions to meet those 
transmission needs, and to allocate the costs of transmission 
facilities selected to meet those transmission needs in a manner that 
is at least roughly commensurate with benefits. Below, we address each 
deficiency in turn.
    115. The first deficiency is that the Commission's regional 
transmission planning and cost allocation requirements fail to require 
transmission providers to perform a sufficiently long-term assessment 
of transmission needs. This deficiency is present in multiple aspects 
of existing regional transmission planning processes, from the degree 
to which planning studies that identify transmission needs are 
sufficiently forward looking, to whether forward-looking assessments 
actually inform the evaluation, selection, and eventual cost allocation 
of regional transmission facilities. The record demonstrates that, 
under existing regional transmission planning and cost allocation 
processes, transmission providers typically identify and plan for 
transmission needs using a relatively near-term transmission planning 
horizon. Specifically, commenters have noted that most transmission 
planning regions do not plan beyond a 10-year transmission planning 
horizon. For example, commenters point out that ISO-NE, SERTP, and 
NorthernGrid plan using a 10-year transmission planning horizon,\282\ 
while PJM notes that it plans using two different transmission planning 
horizons: a 5-year transmission planning horizon for what it refers to 
as its short-term transmission planning process and a 6-to-15-year 
transmission planning horizon for what it refers to as its 
intermediate-term transmission planning process.\283\ While it is 
reasonable and necessary for regional transmission planning and cost 
allocation processes to include a near-term study of the transmission 
system, the absence of any consistent and sufficient longer-term 
assessment of transmission needs prevents transmission providers from 
identifying Long-Term Transmission Needs and considering regional 
transmission facilities that may be more efficient or cost-effective 
solutions to address those needs.\284\
---------------------------------------------------------------------------

    \282\ Massachusetts Attorney General Initial Comments at 25 
(``For example, the Commission's proposal to increase the required 
long-term transmission planning horizon to at least 20 years with 3-
year reassessments would double the current long-term planning 
horizon for ISO-NE.''); Renewable Northwest Initial Comments at 12 
(citing Brattle-Grid Strategies Oct. 2021 Report at 15); Southeast 
PIOs Initial Comments at 12 (``The `independent reliability planning 
studies . . . start with the combined local transmission plans of 
participating utilities,' and the results comprise the ten-year 
regional transmission plan.'' (citation omitted)); Western PIOs 
Initial Comments at 8-9 (``NorthernGrid conducts transmission 
reliability plans on a two-year cycle, with each plan covering a 10-
year time horizon.''); see also ITC Initial Comments at 9 (referring 
to the ``broad use of a 10-year planning horizon in the existing 
transmission planning processes of many major planning 
regions[.]'').
    \283\ PJM Initial Comments at 2 n.4.
    \284\ See, e.g., MISO ANOPR Reply Comments at 5 (``[G]iven long-
term needs of an evolving system, additional transmission is 
necessary to reliably serve customers now and into the future. These 
challenges require immediate action and further delay only increases 
the risk that system enhancements may not be in place in the 
timeframe needed.''); PIOs Initial Comments at 13 (``[A] short-term 
outlook under-forecasts longer-term transmission needs, preventing 
the development of more cost-effective transmission facilities, and 
fails to consider how the needs of the transmission system are 
shifting[.]''); US DOE ANOPR Initial Comments at 10 (stating that 
failure to plan transmission far enough ahead results in ``adverse 
implications for system reliability, resilience, consumers' 
electricity rates, and the achievement of clean energy goals.'').
---------------------------------------------------------------------------

    116. This lack of a longer-term assessment of transmission needs is 
particularly problematic for a few reasons. First, shorter-term 
transmission planning fails to take advantage of the potential for 
efficiencies or economies of scale that regional transmission 
facilities can provide by allowing fewer or better designed 
transmission facilities to meet multiple transmission needs. For 
example, shorter-term transmission planning fails to provide the 
opportunity for transmission providers to identify, evaluate, and 
select regional transmission facilities that could address multiple 
transmission needs over various time horizons.\285\ Moreover, shorter-
term transmission planning fails to create opportunities to ``right 
size'' the replacement of aging transmission facilities to address 
multiple transmission needs over the longer term.\286\ Second, 
constructing large (e.g., high voltage or long distance) transmission 
facilities comes with long lead times: planning, permitting, and 
building regional transmission facilities can often take more than ten 
years.\287\ As an example, the MVP initiative in the MISO region took a 
decade to move from approval by the MISO Board of Directors in 2011 to 
completion of most of the projects by 2021, and this period of 10 years 
does not even account for the significant transmission facility 
development efforts that occurred prior to the MISO Board of Directors' 
approval.\288\ Finally, the useful life of

[[Page 49306]]

transmission assets generally far exceeds even 20 years, so a 10-year 
transmission planning horizon is much too short to capture all of the 
benefits that regional transmission facilities can provide.\289\
---------------------------------------------------------------------------

    \285\ ACORE Initial Comments at 4 (``The narrowly focused 
current approaches [to transmission planning] do not identify 
opportunities to take advantage of the large economies of scale in 
transmission that come from `up-sizing' reliability projects to 
capture additional benefits, such as congestion relief, reduced 
transmission losses, and facilitating the more cost-effective 
interconnection of the renewable and storage resources needed to 
meet public policy goals.'' (quoting Brattle-Grid Strategies Oct. 
2021 Report at 3)); PIOs ANOPR Initial Comments at 10-11; SEIA ANOPR 
Initial Comments at 14.
    \286\ ACORE Initial Comments at 4 (``[I]n-kind replacement of 
aging existing facilities misses opportunities to better utilize 
scarce rights-of-way for upsized projects that can meet multiple 
other needs and provide additional benefits, thus driving up costs 
and inefficiencies.'' (quoting Brattle-Grid Strategies Oct. 2021 
Report at 3)). PJM's long-term assessment of the transmission system 
ostensibly uses a 15-year transmission planning horizon, for 
example, but does not account for changes to the generation mix 
beyond a 5-year period. See Concerned Scientists ANOPR Initial 
Comments at 10 & n.11 (``Generation additions are unchanged in the 
15-year study period, as the input assumption has no additional 
information that would expand the set of generators included in the 
forecast.''); PSEG ANOPR Initial Comments at 11 (stating that ``in 
practice only new resources that are near the end of the 
interconnection queue process and have signed an Interconnection 
Service Agreement are considered in the RTEP base case.'').
    \287\ AEP Initial Comments at 11; Nevada Commission Initial 
Comments at 7 n.24 (noting that it took over seven years between the 
request to include a transmission line in an Integrated Resource 
Plan (IRP) and the in-service date, which did not include the lead 
time for developing the underlying application) PIOs Initial 
Comments at 14 (``[A] 20-year planning horizon was necessary given 
the time needed to site, permit, and construct transmission 
facilities or because states have longer-term public policy 
goals.''); Renewable Northwest Initial Comments at 5; SEIA Initial 
Comments at 6.
    \288\ AESL Consulting, A Transmission Success Story: The MISO 
MVP Transmission Portfolio, at 39 (2021).
    \289\ SEIA Initial Comments at 6; US DOE Initial Comments at 33 
(noting that transmission assets can have a useful life of at least 
40 years).
---------------------------------------------------------------------------

    117. Thus, relying solely on shorter-term transmission planning and 
studies fails to identify Long-Term Transmission Needs and, 
consequently, undervalues or entirely ignores the benefits of 
transmission investments to meet those needs. Moreover, the likelihood 
that near-term assessments will fail to identify Long-Term Transmission 
Needs and more efficient or cost-effective regional transmission 
facilities to meet those needs is higher during periods of rapid 
change, as the electric sector is now experiencing, during which the 
need for transmission infrastructure is expected to grow 
considerably.\290\ We find that continuing with the status quo approach 
is resulting in transmission providers undertaking investments in 
relatively inefficient or less cost-effective transmission 
infrastructure, the costs of which are ultimately recovered through 
Commission-jurisdictional rates.\291\ As a result, among other things, 
customers are paying more than necessary or appropriate to meet their 
transmission needs, forgoing benefits that outweigh their costs, or 
some combination thereof, which results in less efficient or cost-
effective transmission investments and, in turn, renders Commission-
jurisdictional regional transmission planning and cost allocation 
processes unjust and unreasonable.
---------------------------------------------------------------------------

    \290\ US DOE ANOPR Initial Comments at 10 (``Relying on 
successive small transmission expansion projects to meet foreseeable 
long-term needs may lead to the need for expensive retrofits (at 
customers' expense) at a later date. Economies of scale and network 
economies suggest that an initial larger-scale buildout will often 
represent a lower-cost solution.''); Midcontinent Independent System 
Operator, MTEP21 Report Addendum: Long Range Transmission Planning 
Tranche 1 Portfolio Report, at 6 (July 28, 2022), https://cdn.misoenergy.org/MTEP21%20Addendum-LRTP%20Tranche%201%20Report%20with%20Executive%20Summary625790.pdf 
(``While the Tranche 1 Portfolio is the result of MISO's long-range 
planning process being executed for only the second time, the rapid 
change within the industry will require that it become a more 
routine aspect of the MISO planning process going forward.'').
    \291\ See, e.g., S.C. Pub. Serv. Auth., 762 F.3d at 56-59 
(explaining that transmission planning processes are practices 
affecting rates pursuant to Section 206 of the FPA).
---------------------------------------------------------------------------

    118. The second deficiency is that the Commission's existing 
regional transmission planning and cost allocation requirements fail to 
require transmission providers to account adequately on a forward-
looking basis for known determinants of Long-Term Transmission Needs. 
This deficiency is related to the first deficiency in the sense that 
both relate to the failure of the existing transmission planning 
requirements to require transmission providers to adequately plan for 
the foreseeable future. We find that, even following Order Nos. 890 and 
1000, transmission providers have adopted widely divergent approaches 
to determining the factors that are relevant to identifying 
transmission needs within regional transmission planning.\292\ 
Specifically, as commenters note, some existing regional transmission 
planning processes ignore trends in future generation and the impact of 
extreme weather.\293\ Other commenters note that certain regional 
transmission planning processes ignore state laws or utility 
goals.\294\ In addition to failing to adequately account for factors 
that shape the resource mix, commenters also assert that current 
regional transmission planning processes fail to account for factors 
that will shape future load, particularly new loads associated with 
electrification trends like, for example, electric vehicles \295\ and 
data centers.\296\ Although transmission providers in some transmission 
planning regions account for a wider range of the factors that drive 
Long-Term Transmission Needs when performing regional transmission 
planning studies than do others,\297\ we find that transmission 
providers are not consistently or sufficiently accounting on a forward-
looking basis for the known determinants of Long-Term Transmission 
Needs or accounting for such known determinants in a manner that 
ensures the identification and evaluation of more efficient or cost-
effective regional transmission facilities to meet Long-Term 
Transmission Needs.
---------------------------------------------------------------------------

    \292\ ELCON Initial Comments at 3 (``While regional differences 
are important to consider, too much flexibility was provided to 
transmission providers in Order No. 1000 that . . . created a 
patchwork of planning processes further complicating planning and 
fostering additional balkanization of the grid[.]''); NOPR, 179 FERC 
] 61,028 at P 50.
    \293\ GridLab Initial Comments at 4-5 (noting that SPP does not 
consider extreme weather events in its transmission plan); Grid 
Strategies July 2021 Extreme Weather Report at 5 (``[T]ransmission's 
value for making the grid more resilient against severe weather and 
other unexpected threats is not typically accounted for in 
transmission planning and cost allocation analyses. Grid operator 
transmission planning processes typically assume normal electricity 
supply and demand patterns, and in most cases do not account for the 
value of transmission for increasing resilience.''); Renewable 
Northwest Initial Comments at 4, 8 (explaining that regional 
transmission planning in the Pacific Northwest does not model 
extreme weather events and generally does not reflect publicly 
available data such as utility IRPs or carbon reduction goals); see 
also Brattle-Grid Strategies Oct. 2021 Report at 36 (stating that 
production cost simulations that are typically used to estimate the 
economic benefit of regional transmission facilities assume no 
extreme weather events); SPP Market Monitor ANOPR Initial Comments 
at 3 & n.5 (describing that even SPP's more forward-looking scenario 
analysis of an emerging technology case in its Integrated 
Transmission Plan presently underestimates the actual growth of 
renewables so much that ``[w]ind capacity in service today (29.8 GW) 
already exceeds wind levels projected in both 2019 ITP futures that 
go out to 2029'').
    \294\ Acadia Center and CLF Initial Comments at 1 (``Order No. 
1000 has failed to require public utility transmission providers to 
align their transmission planning and funding processes with state 
policies and objectives.'' (citing Regulatory Assistance Project, 
FERC Transmission: The Highest-Yield Reforms, at 4 (July 2022), 
https://www.raponline.org/wp-content/uploads/2023/09/rap-littell-prause-weston-FERC-transmission-highest-yield-reforms-2022-july.pdf)); Renewable Northwest Initial Comments at 12 (citing 
Brattle-Grid Strategies Oct. 2021 Report at 15, which states that 
WestConnect, for example, does not include planning inputs that 
extend beyond generic, baseline projects nor ``knowable information 
about enacted public policy mandates, publicly stated utility plans, 
and/or consumer procurement targets[.]''); SREA Initial Comments at 
25 (stating that ``SERTP relies entirely on member utilities to 
self-nominate transmission study requests regarding public policy, 
meaning if utilities do not provide recommendations or requests, no 
SERTP study is completed. For instance, in 2021, SERTP stated, 
`[t]he SERTP did not receive any input or proposals for possible 
transmission needs driven by Public Policy Requirements for the 2021 
planning cycle. Therefore, no possible transmission needs driven by 
Public Policy Requirements have been identified for further 
evaluation of potential transmission solutions in the 2021 SERTP 
planning cycle.' '' (emphasis in original)).
    \295\ See, e.g., Clean Energy Buyers Initial Comments at 7-8; 
National Grid Initial Comments at 8; see also AEE ANOPR Initial 
Comments at 18 (stating that MISO projects electrification effects 
on load in its long-term regional transmission planning, but how 
other transmission providers account for electrification trends is 
not consistent or transparent).
    \296\ See supra note 2166; Rocky Mountain Institute Supplemental 
Comments at 1 (``Technology companies have begun requesting large 
interconnections for data centers that require increased electricity 
supply to power generative artificial intelligence.''); WIRES 
Supplemental Comments at attach. 1, p. 36 (Rob Gramlich, et al., 
Fostering Collaboration Would Help Build Needed Transmission (Feb. 
2024)) (``Load growth is rising in much of the country, and it is 
happening in a way that is hard for any single entity to assess on 
their own. It varies by local area due to factors such as 
manufacturing plant and data center additions, plus expectations for 
end-use electrification and penetration of electric vehicles.'').
    \297\ See, e.g., Renewable Northwest Initial Comments at 11, 14-
15 (discussing how the MISO transmission planning process accounts 
for the future resource mix); Western PIOs Initial Comments at 23-
24, 26-27 (explaining forward-looking aspects of the CAISO 
transmission planning process).
---------------------------------------------------------------------------

    119. We recognize there is inherent uncertainty in 
forecasting,\298\ and we

[[Page 49307]]

agree with Industrial Customers that current transmission planning is 
based on known and measurable factors.\299\ However, we find, based on 
this record, that the universe of known and measurable factors that 
drive regional transmission needs extends beyond those that 
transmission providers currently consider as part of their regional 
transmission planning processes. Specifically, the record demonstrates 
that a multitude of factors like reliability needs driven by the impact 
of extreme weather, trends in future generation additions and 
retirements, load growth, Federal, federally-recognized Tribal, state, 
and local laws, and utility goals increasingly shape Long-Term 
Transmission Needs, are known and identifiable, and have reasonably 
predictable effects, especially in the aggregate.
---------------------------------------------------------------------------

    \298\ We acknowledge NRG's comment that forecasting is 
inherently uncertain. NRG Initial Comments at 10-12. Sufficiently 
long-term, forward-looking, and comprehensive regional transmission 
planning and cost allocation, however, is better than a lack of 
planning. The Commission may, by applying its expertise and 
experience to the record, determine what type and amount of 
transmission planning results in a just and reasonable rate. S.C. 
Pub. Serv. Auth. v. FERC, 762 F.3d at 55 (``[I]n rate-related 
matters, the court's review of the Commission's determination is 
particularly deferential because such matters are either fairly 
technical or `involve policy judgements that lie at the core of the 
regulatory mission.' '' (citing Alcoa Inc. v. FERC, 564 F.3d 1342, 
1347 (D.C. Cir. 2009))). ``The court owes the Commission `great 
deference' in this realm because `[t]he statutory requirement that 
rates be `just and reasonable' is obviously incapable of precise 
judicial definition' and `the Commission must have considerable 
latitude in developing a methodology responsive to its regulatory 
challenge[.]' '' Id. (citing Morgan Stanley Cap. Grp. v. Pub. Util. 
Dist. No. 1, 554 U.S. 527, 532 (2008); Am. Pub. Gas Ass'n v. FPC, 
567 F.2d 1016, 1037 (D.C. Cir. 1977)).
    \299\ Industrial Customers Initial Comments at 11.
---------------------------------------------------------------------------

    120. As noted above, the record shows that the increasing 
frequency, duration, and intensity of extreme weather events are 
driving changes in Long-Term Transmission Needs to maintain system 
reliability.\300\ Additionally, demand growth is a major driver of 
Long-Term Transmission Needs, and contrary to commenter 
assertions,\301\ the record shows that evolving trends in load growth 
due to data centers, electrification, and industrial growth are driving 
Long-Term Transmission Needs.\302\ Similarly, state laws, utility 
integrated resource plans and resource procurements, and other 
regulatory actions necessarily affect Long-Term Transmission Needs for 
Commission-jurisdictional transmission services.\303\ Several 
commenters also support the broader consideration of anticipated 
generation retirements and interconnection requests in regional 
transmission planning processes because those factors shape the future 
resource mix and, therefore, Long-Term Transmission Needs.\304\ 
Relatedly, many commenters highlight the impact of utility goals on the 
resource mix because such goals will impact transmission needs.\305\ 
Yet, as described above, existing regional transmission planning 
processes frequently undervalue or entirely omit consideration of some 
or all of these factors. And while some existing regional transmission 
planning processes do a better job than others of incorporating 
different components of long-term, forward-looking, and more 
comprehensive regional transmission planning, the Commission's existing 
regional transmission planning requirements do not ensure that factors 
influencing future transmission will be sufficiently accounted for in 
that planning.
---------------------------------------------------------------------------

    \300\ ACEG Initial Comments at 63 (``[T]he need to improve 
regional and interregional planning arises from the transformative 
changes occurring with respect to resource diversity, energy market 
efficiencies, technological changes, operational innovations and 
resiliency to withstand severe weather events. If transmission 
facilities are not constructed, these are all benefits that would 
otherwise be forfeited.''); NERC Initial Comments at 6; Evergreen 
Action Initial Comments at 2 (``[A]dditional transmission built 
under improved planning procedures would [ ] create large 
reliability benefits. With increasing extreme weather events due to 
climate change--including wildfires, winter storms, hurricanes, and 
more--additional transmission infrastructure and grid improvements 
are increasingly necessary for resilience purposes.''); WE ACT 
Initial Comments at 2 (``Requiring public utility transmission 
providers to consider extreme weather events in Long-Term Regional 
Transmission Planning is a positive step towards addressing grid 
reliability in the face of more frequent and intensifying weather 
events.'').
    \301\ See, e.g., Industrial Customers Initial Comments at 8-10 
(arguing that demand is growing more slowly than in previous 
periods).
    \302\ See, e.g., Northwest and Intermountain Initial Comments at 
5 n.12 (``For example, Bonneville Power Administration (`BPA') owns 
about 75 percent of the transmission lines in the Pacific Northwest. 
In BPA's 2022 Transmission Service Expansion Plan cluster study, 
customers submitted 153 separate transmission service requests 
totaling 11,831 MW of transmission capacity. BPA was able to offer 
service (without requiring detailed studies and transmission 
upgrades) to only 275 MWs of those service requests.'' (citing BPA, 
TSR Study and Expansion Process, at 12 (Dec. 7, 2021), https://www.bpa.gov/-/media/Aep/transmission/atc-methodology/2021-22tsep-overview.pdf.)); John Wilson and Zach Zimmerman, The Era of Flat 
Demand is Over, Grid Strategies, at 3, 6 (Dec. 2023), https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf (noting the 5-year load growth forecast has 
nearly doubled from 2.6% to 4.7% and ``transmission investments need 
to increase just to keep up with demand'').
    \303\ See, e.g., Acadia Center and CLF Initial Comments at 8 
(``State laws are . . . essential considerations in planning 
transmission . . . as state laws drive substantial procurements of 
energy resources along with the concomitant need for additional 
transmission, as well as repurposed transmission and non-
transmission grid solutions.''); AEE Initial Comments at 10 (noting 
that ``[a]s of September 2020, 38 states and the District of 
Columbia had adopted renewable portfolio standards, and 21 states 
(plus the District of Columbia and Puerto Rico)--representing more 
than half of the U.S. population--include a target of 100% renewable 
energy by 2050 or sooner. Many of these requirements have been 
enacted in statute and are binding on utilities and retail energy 
providers.'').
    \304\ See, e.g., Pattern Energy Initial Comments at 26 (``[T]he 
generation interconnection queues are indicative of the market and 
should also be a major source for generation assumptions in scenario 
planning (both near-term and long-term).''); SEIA Initial Comments 
at 9.
    \305\ See, e.g., Renewable Northwest Initial Comments at 6; SREA 
Initial Comments at 41-46 (``The major utility announcements of 
achieving net zero or some approximation affects the marketplace, 
especially in the [S]outheast.'').
---------------------------------------------------------------------------

    121. The failure to adequately consider such factors delays 
planning for the transmission system's changing operational needs until 
shortly before those transmission needs manifest. As a result, existing 
transmission planning processes are piecemeal and fail to take 
advantage of economies of scale in transmission investment or 
opportunities to address multiple transmission needs over multiple time 
horizons.\306\ We find that engaging in regional transmission planning 
without adequate consideration of such factors leads to transmission 
investment that is not more efficient or cost-effective and renders 
Commission-jurisdictional regional transmission planning and cost 
allocation processes unjust and unreasonable.\307\
---------------------------------------------------------------------------

    \306\ PIOs Initial Comments at 10-11; Renewable Northwest 
Initial Comments at 8 (citing Brattle-Grid Strategies Oct. 2021 
Report at iii, iv).
    \307\ See, e.g., AEE Initial Comments at 10 (``Failing to take 
any of [the Commission-proposed factors] into consideration in 
developing long-term scenarios would risk under investment in needed 
regional transmission projects to meet transmission needs and 
potential[ly] result in unjust and unreasonable rates for 
transmission service.''); New Jersey Commission Initial Comments at 
3-9 (arguing that ``[e]nsuring just and reasonable rates requires 
mandating long-term, multi-value, and portfolio based transmission 
planning.'').
---------------------------------------------------------------------------

    122. Third, the record demonstrates that the Commission's regional 
transmission planning and cost allocation requirements fail to require 
transmission providers to adequately consider the broader set of 
benefits of regional transmission facilities planned to meet Long-Term 
Transmission Needs.\308\ For example, commenters note that many 
regional transmission planning processes focus too narrowly only on 
some benefits.\309\ For instance,

[[Page 49308]]

the Brattle-Grid Strategies Report concludes that ``most of [the 
Nation's recent transmission] investment addresses individual local 
asset replacement needs, near-term reliability compliance, and 
generation-interconnection-related reliability needs without 
considering a comprehensive set of multiple regional needs and system-
wide benefits.'' \310\ As PIOs argue, the Commission's existing 
regional transmission planning and cost allocation requirements do not 
require that transmission providers assess ``opportunities to benefit 
from economies of scale that come from `right-sizing' and strategic, 
comprehensive planning of transmission portfolios and projects to 
capture additional benefits . . . .'' \311\ Other regional transmission 
planning processes fail entirely to consider cost savings associated 
with certain transmission facilities.\312\
---------------------------------------------------------------------------

    \308\ See Order No. 1000, 136 FERC ] 61,051 at P 624 (declining 
to prescribe ``a particular definition of `benefits' '').
    \309\ Massachusetts Attorney General ANOPR Initial Comments at 
22 (``New England's siloed approach to transmission planning 
inhibits identification of multi-value solutions.'' As part of ISO-
NE's Boston 2028 Request for Proposals, ``[i]n focusing on cost-
effectively solving reliability needs alone, ISO-NE rejected all but 
one of thirty-six proposals. While ISO-NE rejected some of these 
proposals for technical reasons, it eliminated several due to cost 
considerations alone.''); PIOs Initial Comments at 10 (``[T]he vast 
majority of current transmission projects are focused solely either 
on network reliability or connecting the next generator in the 
interconnection queue and ignore any other potential benefits, 
possible economies of scale or other efficiencies that might occur 
by considering multiple future needs . . . . [M]ultiple quantifiable 
benefits to transmission . . . are being ignored in the transmission 
planning process.'').
    \310\ Brattle-Grid Strategies Oct. 2021 Report at 2.
    \311\ PIOs Initial Comments at 10-11. The benefits cited by PIOs 
``include congestion relief, reduced transmission losses, resiliency 
to extreme weather events, increased flexibility to respond to 
changing market or system conditions, and facilitating larger 
regional or interregional solutions for cost effective 
interconnection of the renewable and storage resources needed to 
meet public policy goals.'' Id. at 11.
    \312\ SREA Initial Comments at 24 (``SERTP participants 
explained that SERTP is unable to conduct adjusted production cost 
savings, because none of the utilities involved in SERTP have the 
software capable of doing so. In effect, the `Economic Planning 
Studies' only evaluate the costs of potential upgrades to the 
system, but none of the benefits.'').
---------------------------------------------------------------------------

    123. Based on the record, we find that, as with the universe of 
known and measurable factors driving transmission needs, the benefits 
that regional transmission facilities provide extend beyond those 
benefits that transmission providers currently consider as part of 
their regional transmission planning and cost allocation 
processes.\313\ Failing to adequately identify and consider the 
benefits of such transmission facilities may lead to relatively 
inefficient or less cost-effective transmission development. In 
particular, the cost-benefit analyses that transmission providers often 
use as part of the evaluation process may fail to identify more 
efficient or cost-effective regional transmission facilities for 
selection because they provide an inaccurate portrayal of the 
comparative benefits of different transmission facilities. Thus, the 
failure to adequately consider the benefits of regional transmission 
facilities results in, among other things, transmission customers 
forgoing benefits that may significantly outweigh their costs, which 
results in less efficient or cost-effective transmission investments 
and, in turn, contributes to Commission-jurisdictional rates that are 
unjust and unreasonable.
---------------------------------------------------------------------------

    \313\ We disagree with Potomac Economics' arguments that the 
sole benefit of transmission is alleviating congestion and that 
congestion is primarily an economic issue, so investment in 
alleviating congestion should not exceed the benefit of doing so. 
See Potomac Economics Initial Comments at 3-4. As discussed infra in 
the Evaluation of the Benefits of Regional Transmission Facilities 
section alleviating congestion is just one of many potential 
benefits that transmission infrastructure provides, and transmission 
benefits beyond solving congestion are considered by transmission 
providers in regional transmission planning processes today.
---------------------------------------------------------------------------

    124. Given our findings above concerning the deficiencies in 
existing transmission planning requirements, and our conclusion that 
long-term, forward-looking, and more comprehensive regional 
transmission planning is needed, we also conclude that existing cost 
allocation requirements are deficient and must be modified to properly 
account for Long-Term Regional Transmission Planning. The Commission 
has long recognized the ``close relationship between transmission 
planning, which identifies needed transmission facilities, and the 
allocation of costs of the transmission facilities in the plan,'' \314\ 
and that cost allocation issues will often determine whether 
transmission providers and customers support the construction of new 
facilities.\315\ Furthermore, experience with Order No. 1000 has 
reinforced the critical role that states play in the development of new 
transmission infrastructure, particularly at the regional level, where 
transmission projects may physically span, and their costs may be 
allocated across, multiple states. As the Commission discussed in the 
NOPR and we continue to find in this final order, facilitating state 
regulatory involvement in the cost allocation process could minimize 
delays and additional costs associated with state and local siting 
proceedings.\316\
---------------------------------------------------------------------------

    \314\ Order No. 1000, 136 FERC ] 61,051 at P 496.
    \315\ Order No. 890, 118 FERC ] 61,119 at P 557; see also Order 
No. 1000, 136 FERC ] 61,051 at P 496.
    \316\ NOPR, 179 FERC ] 61,028 at P 301; infra Regional 
Transmission Cost Allocation section.
---------------------------------------------------------------------------

    125. Given the link between cost allocation and transmission 
planning, it is essential that cost allocation requirements for Long-
Term Regional Transmission Facilities are appropriately tailored to the 
new Long-Term Regional Transmission Planning requirements of this 
order, particularly given the anticipated long-lead time for any 
regional transmission facilities developed and regionally cost 
allocated through this final order. Without proper alignment of the 
regional transmission planning and cost allocation requirements, it is 
less likely that transmission facilities selected in Long-Term Regional 
Transmission Planning will be developed, which would undermine the 
essential purpose of the regional transmission planning process, 
namely, the development of more efficient or cost-effective regional 
transmission facilities.
    126. We find that the Commission's current cost allocation 
requirements, which were designed and established in the context of 
existing Order No. 1000 regional transmission planning processes, are 
insufficient to appropriately allocate costs associated with regional 
transmission facilities that are selected in accordance with the new 
Long-Term Regional Transmission Planning requirements that we establish 
in this final order. The Commission's existing Order No. 1000 cost 
allocation requirements contemplate the application of differing cost 
allocation methods to different types of transmission facilities. But 
we find that Long-Term Regional Transmission Planning, which accounts 
for multiple drivers of Long-Term Transmission Needs and results in 
Long-Term Regional Transmission Facilities that produce a broader set 
of benefits, warrants a different approach to cost allocation for such 
transmission facilities. Likewise, existing Order No. 1000 regional 
transmission planning processes do not mandate the consideration of 
specific benefits that we believe are appropriately considered as part 
of Long-Term Regional Transmission Planning. New information concerning 
these benefits uncovered through the transmission planning process may 
be relevant when allocating the costs of Long-Term Regional 
Transmission Facilities in a manner that is at least roughly 
commensurate with their benefits.\317\ Importantly, existing cost 
allocation requirements do not provide a dedicated process through 
which states have an opportunity to participate in the development of 
regional cost allocation methods. We conclude such a role is 
particularly relevant to Long-Term Regional Transmission Planning, 
given: (1) the lengthy planning horizon over

[[Page 49309]]

which transmission projects might be identified, selected, and 
ultimately constructed; (2) the resultant increased uncertainty for 
Long-Term Regional Transmission Facilities; and (3) accordingly, the 
increased importance for state engagement regarding cost allocation to 
increase the likelihood such facilities obtain needed siting approvals 
from the states and are thus timely and cost-effectively developed. We 
therefore believe that it is both necessary and appropriate to 
establish specific cost allocation requirements that are tailored to 
the Long-Term Regional Transmission Planning reforms in this final 
order.
---------------------------------------------------------------------------

    \317\ Ill. Commerce Comm'n v. FERC, 576 F.3d 470, 477 (7th Cir. 
2009) (ICC v. FERC I); Order No. 1000, 136 FERC ] 61,051 at PP 622, 
639 (requiring costs of regional transmission facilities to be 
allocated in a manner that is at least roughly commensurate with 
estimated benefits).
---------------------------------------------------------------------------

    127. Based on the record, including comments submitted in response 
to the NOPR, we find that there is substantial evidence demonstrating 
that Long-Term Regional Transmission Planning and cost allocation to 
identify and plan for Long-Term Transmission Needs does not occur on a 
consistent and sufficient basis.\318\ We find, in large part, that this 
is because of the deficiencies that we have identified above in the 
Commission's existing regional transmission planning and cost 
allocation requirements. In addition, we find that, in the absence of 
sufficiently long-term, forward-looking, and comprehensive regional 
transmission planning and cost allocation processes, transmission 
providers are meeting many transmission needs by identifying 
transmission solutions and developing transmission facilities through 
other processes, i.e., outside of the regional transmission planning 
and cost allocation processes,\319\ or, as discussed above, in response 
to near-term reliability needs,\320\ which may not identify the more-
efficient or cost-effective solution.
---------------------------------------------------------------------------

    \318\ See New Jersey Commission Initial Comments at 8 
(explaining that, outside of limited circumstances, PJM, Florida, 
ISO-NE, Southeastern Regional, South Carolina Regional, WestConnect, 
NorthernGrid, NYISO, SPP, and CAISO do not conduct multi-driver or 
portfolio transmission planning, which has required ratepayers to 
pay for tens of billions of dollars in unnecessary transmission 
projects); NextEra ANOPR Initial Comments at 71 (``While there are 
examples of longer-term planning currently being utilized by some 
regions, such as MISO's annual 15-year Futures assessment or SPP's 
20-year Integrated Transmission Plan run every five years, there is 
no standard as to what time horizon long-term planning must study, 
nor how often this planning should be done. Further, no standards or 
guidelines exist as to what should be included in such long-term 
planning to ensure that customers are charged just and reasonable 
rates for the most efficient and cost-effective investments given 
the most comprehensive and up-to-date information available.''); 
Western PIOs Initial Comments at 4-28 (arguing that in the Western 
United States transmission planning outside of CAISO is not 
developed and is ineffective); Brattle-Grid Strategies Oct. 2021 
Report at 13-15 & tbl. 2 (documenting inconsistent ``use of 
proactive, scenario-based, multi-value processes'' across various 
planning authorities, including NYISO, CAISO, MISO, PJM, ISO-NE, 
Florida, Southeast Regional, and South Carolina'').
    \319\ See, e.g., LS Power Initial Comments at 46-50; PIOs 
Initial Comments at 9-10 (explaining that about half of the 
approximately $70 billion in aggregate transmission investment by 
Commission-jurisdictional transmission owners in RTO/ISO regions was 
approved outside of regional transmission planning processes).
    \320\ Supra note 309.
---------------------------------------------------------------------------

    128. To reiterate, the fact that transmission facilities are being 
identified and built outside of regional transmission planning 
processes and in response to near-term reliability needs is not 
inherently problematic. In many instances, as some commenters point 
out,\321\ those processes may be well equipped to identify necessary 
and appropriate transmission solutions. Rather, the problem is that 
incremental and piecemeal expansion of the transmission system outside 
of regional transmission planning process misses the potential for 
transmission providers to identify, evaluate, and select more efficient 
or cost-effective transmission solutions to solve Long-Term 
Transmission Needs, as well as to afford system-wide benefits that may 
not be achieved through one-off transmission system upgrades.\322\ To 
the extent that transmission providers may not be identifying and 
evaluating the more efficient or cost-effective transmission solutions 
needed to meet underlying transmission needs, including Long-Term 
Transmission Needs, over time, consumers will bear the costs of 
relatively inefficient or less cost-effective piecemeal transmission 
investment and expansion.\323\
---------------------------------------------------------------------------

    \321\ E.g., Duke Initial Comments at 7.
    \322\ See, e.g., ACORE Initial Comments at 8 ((``For example, 
two solutions to address a particular reliability need may offer 
vastly different total system-wide benefits. Thus, the higher-cost 
transmission solutions can actually result in significantly lower 
net cost from a system-wide perspective.'') (quoting Brattle-Grid 
Strategies Oct. 2021 Report at 30)); Clean Energy States Initial 
Comments at 2 (``[T]he one-plant-at-a-time approach to transmission 
upgrades results in a patchwork approach that drives up costs and 
misses opportunities for improvements to the system as a whole.''); 
Exelon Initial Comments at 5.
    \323\ Michigan State Entities Initial Comments at 1-2 
(explaining concerns that the lack of long-term transmission 
planning has led to significantly higher residential rates and how 
the problem will worsen if transmission investment does not reflect 
changes in the resource mix and demand); New Jersey Commission 
Initial Comments at 6-7 (noting PJM analysis showing transmission 
upgrades to interconnect 87.1 GW of a variety of resources, 
including offshore wind, would cost $3.2 billion if done through 
holistic transmission planning whereas connecting only 15.4 GW of 
offshore wind would cost $6.4 billion if done through the 
interconnection queue process, and estimating that the 
interconnection of 87.1 GW through the interconnection queue would 
increase the cost to consumers by over $30 billion compared to 
holistic transmission planning); PIOs Initial Comments at 8 (noting 
how deficiencies in the Commission's regional transmission planning 
processes have ``led to billions of dollars in excessive costs for 
consumers.'' (citing Brattle-Grid Strategies Oct. 2021 Report at 1-
13 (Section 1)).
---------------------------------------------------------------------------

    129. We find that the concerns arising from the absence of 
sufficiently long-term, forward-looking, and comprehensive regional 
transmission planning and cost allocation processes and the 
corresponding failure by transmission providers to identify and 
evaluate more efficient or cost-effective transmission solutions to 
Long-Term Transmission Needs are exacerbated by the fact that 
transmission needs in most transmission planning regions are 
drastically changing. Contrary to the claims of some commenters, we are 
not promulgating this order in an attempt to steer the resource mix and 
demand \324\ based on a preference for certain resources over 
others.\325\ Instead, the Commission is reacting to well-documented 
factors, which the record demonstrates are driven by exogenous forces 
beyond the Commission's jurisdiction or control, including, but not 
limited to, the increasing frequency of extreme weather events, 
customer preferences, demand growth, economic and technological trends, 
and Federal, federally-recognized Tribal, state, and local 
policies.\326\
---------------------------------------------------------------------------

    \324\ Consumer Organizations Initial Comments at 1-2; ELCON 
Initial Comments at 9; SERTP Sponsors Initial Comments at 16-20. But 
see SEIA Reply Comments at 2-3 (``The NOPR does make `repeated 
references' to the changing resource mix. But that is not because 
the NOPR will `promote a transition to a more renewables-heavy 
electric system.' The NOPR makes these references because the 
resource mix is, in fact, changing. The question before the 
Commission is not whether to promote or impede that change, but how 
to address the needs of the grid as a result of that inevitable 
change.'' (internal quotations omitted)); New Jersey Commission 
Reply Comments at 2 (``The Commission is . . . trying to ensure the 
electricity system can reliably and efficiently achieve the 
generation mix that state policymakers and voluntary consumers--not 
the Commission--have chosen. Ensuring that these customers are 
served at the lowest possible cost while maintaining reliability is 
entirely consistent with and indeed required in order to meet the 
dictates of the FPA. In other words, the Commission is acting to 
ensure transmission planning processes account for current realities 
and meet evolving consumer needs at a total cost that is just and 
reasonable.'' (internal citations omitted)).
    \325\ See, e.g., Ohio Commission Federal Advocate Initial 
Comments at 4-6 (arguing that the Commission's purpose in issuing 
the NOPR was to promote an aspirational renewable future and achieve 
narrow environmental objectives); Undersigned States Reply Comments 
at 7 (arguing that the Commission is forcing ratepayers to subsidize 
forms of energy by socializing the cost of a transmission build 
out).
    \326\ See New Jersey Commission Initial Comments at 3 (``The 
Commission is not proposing to unduly favor, mandate, or subsidize 
forms of generation but is rather seeking to ensure that the bulk 
electricity system maintains reliability and satisfies evolving 
consumer demand . . .'').

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[[Page 49310]]

    130. In response to commenters, we acknowledge that integrated 
resource planning processes, where they exist, shape the resource mix 
and can often include forms of proactive transmission planning. As 
stated in Order No. 1000, we reiterate that ``the regional transmission 
planning process is not the vehicle by which integrated resource 
planning is conducted.'' \327\ Indeed, this final order does not aim to 
affect--either facilitate or hinder--any changes or decisions that 
occur outside of the Commission's jurisdiction. Instead, because 
practices directly affecting Commission-jurisdictional rates, terms, 
and conditions of service for interstate transmission and wholesale 
electricity are the exclusive jurisdiction of the Commission, we must 
ensure that Commission-jurisdictional processes associated with 
regional transmission planning and cost allocation result in rates that 
are just and reasonable and not unduly discriminatory or preferential. 
To this end, this final order is focused on ensuring that regional 
transmission planning processes are adequately accounting for the 
changes occurring outside of the Commission's jurisdiction, including 
the resource decisions that are the exclusive jurisdiction of 
states.\328\ Additionally, to the extent that integrated resource 
planning processes include forms of transmission planning, such 
planning can be complementary to Commission-jurisdictional regional 
transmission planning processes but cannot take the place of such 
processes. This is not to diminish the importance of integrated 
resource planning processes, which serve a critical role in shaping the 
generation mix and transmission infrastructure. In recognition of this 
role, this final order requires transmission providers to consider 
integrated resource planning as a factor when conducting Long-Term 
Regional Transmission Planning. But, as discussed below, we conclude 
that integrated resource planning is appropriately considered as one of 
several categories of factors used to develop Long-Term Scenarios and 
identify Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \327\ Order No. 1000, 136 FERC ] 61,051 at P 154.
    \328\ See PJM Power Providers Grp. v. FERC, 88 F.4th 250, 275 
(3d Cir. 2023) (holding that the Commission is ``unambiguously 
authorize[d] . . . to take state policies into account to the extent 
that such policies affect [the Commission's] statutorily prescribed 
area of focus . . . .''); see also Elec. Power Supply Ass'n v. Star, 
904 F.3d 518, 524 (7th Cir. 2018) (approving of the Commission's 
decision to take state zero-emissions credit systems like that in 
Illinois ``as givens and set out to make the best of the situation 
[these systems] produce'').
---------------------------------------------------------------------------

    131. In response to commenters that argue regional transmission 
facilities may not address local transmission needs such that a local 
transmission facility would still be needed,\329\ we acknowledge that 
regional transmission facilities are not necessarily always a more 
efficient or cost-effective solution to address local transmission 
needs, and nothing in this final order requires transmission providers 
to rely on regional transmission facilities to address exclusively 
local transmission needs. Instead, this final order identifies 
deficiencies in existing Commission-jurisdictional regional 
transmission planning processes that lead transmission providers to 
fail to identify Long-Term Transmission Needs and fail to identify, 
evaluate, or select more efficient or cost-effective transmission 
solutions to meet those transmission needs. As a result of these 
deficiencies, transmission providers may undertake relatively 
inefficient investments in transmission infrastructure by missing 
opportunities to identify regional transmission facilities that bring 
economies of scale or address multiple transmission needs over 
different time horizons, including local transmission needs.
---------------------------------------------------------------------------

    \329\ See, e.g., Duke Initial Comments at 9 (arguing that there 
are instances in which larger regional transmission projects may not 
resolve localized transmission needs).
---------------------------------------------------------------------------

    132. We disagree with arguments that the Commission cannot 
promulgate this final order because we rely on general findings, rather 
than individualized analyses of each, specific transmission planning 
region.\330\ Relevant precedent, including regarding the Commission's 
comparable action in Order No. 1000, is clear that the Commission has 
discretion as to the procedural means through which it will apply its 
substantive expertise, and we need not make findings that are region 
specific in every case; rather, we are empowered to ``rely on `generic' 
or `general' findings of a systemic problem to support imposition of an 
industry-wide solution,'' \331\ and we do so here. The fact that 
individual transmission planning regions may have different forms of 
transmission planning processes, and may experience varying levels of 
transmission investment, would be ``as unastonishing as it is 
irrelevant.'' \332\ Moreover, although transmission planning practices 
vary considerably between transmission planning regions and some 
regions may engage in transmission planning that shares many of the 
elements of the more long-term, forward-looking, comprehensive regional 
transmission planning required in this order, the record demonstrates 
that this final order identifies deficiencies that reach well beyond 
``isolated pockets[.]'' \333\ Rather, the record demonstrates that 
these deficiencies pervade large swaths of the country, which include 
RTO/ISO and non-RTO/ISO transmission planning regions.\334\ 
Accordingly, this final order's remedy does not present an ``extreme 
`disproportion of remedy to ailment[.]' '' \335\ The Commission may 
reasonably rely on a rulemaking procedure to address the industry-wide 
changes to the transmission landscape, notwithstanding regional 
variation among regional transmission planning processes. As the 
Commission stated in Order No. 1000, ``[i]t is well established that 
the choice between rulemaking and case-by-case adjudication `lies 
primarily in the informed discretion of the administrative agency.' '' 
\336\ The Commission also stated that ``[i]t is within our discretion 
to conclude that a generic rulemaking, not case-by-case adjudications, 
is the most efficient approach to take to resolve the industry wide 
problems facing us.'' \337\ Moreover, we agree with ACEG that pursuing 
region-specific solutions will lead to ``siloed and disjunctive 
transmission planning policies [that] will not solve the problems 
facing the nation's electric grid.'' \338\
---------------------------------------------------------------------------

    \330\ See, e.g., Louisiana Commission Reply Comments at 5-6; 
NRECA Initial Comments at 14-16.
    \331\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67 (quoting 
Interstate Nat. Gas v. FERC, 285 F.3d 18, 37 (D.C. Cir. 2002)).
    \332\ Id. (quoting Wis. Gas v. FERC, 770 F.2d 1144, 1157 (D.C. 
Cir. 1985)).
    \333\ Id.
    \334\ See, e.g., supra notes 283 and 284 (explaining that ISO-
NE, SERTP, Northern Grid, and PJM undergo transmission planning 
using time horizons shorter than 20 years).
    \335\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67.
    \336\ Order No. 1000, 136 FERC ] 61,051 at P 60.
    \337\ Id.
    \338\ ACEG Reply Comments at 17.
---------------------------------------------------------------------------

    133. Furthermore, although not every transmission planning region 
is experiencing these changes in equal measure, the record shows that 
significant changes are well underway nationwide, and that failing to 
adequately account for Long-Term Transmission Needs poses a risk to 
just and reasonable rates throughout the country.\339\ In fact, the 
record raises a wide range of concerns, and the Commission need not, 
and should not, wait for systemic problems to undermine regional 
transmission

[[Page 49311]]

planning in every region before it acts.\340\ The record in this 
proceeding confirms that significant investments in new transmission 
facilities are expected to occur, with substantial impacts on the 
Commission-jurisdictional rates that customers pay.\341\ It is 
therefore critical, and it is the Commission's responsibility, to act 
now to address deficiencies in its regional transmission planning and 
cost allocation requirements to ensure that more efficient or cost-
effective transmission investments are made as the industry addresses 
the changing landscape.\342\
---------------------------------------------------------------------------

    \339\ AEE Reply Comments at 3-4.
    \340\ See Order No. 1000, 136 FERC ] 61,051 at P 50.
    \341\ See supra P 93.
    \342\ See Order No. 1000, 136 FERC ] 61,051 at P 46.
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3. Benefits of Long-Term Regional Transmission Planning and Cost 
Allocation To Identify and Plan for Long-Term Transmission Needs
    134. Upon consideration of the record, we find that the 
requirements set forth in this final order will address deficiencies in 
the existing regional transmission planning and cost allocation 
requirements and will promote enhanced reliability and more efficient 
or cost-effective transmission solutions, which will help to ensure 
just and reasonable Commission-jurisdictional rates.
    135. The record demonstrates that long-term, forward-looking, and 
more comprehensive regional transmission planning that identifies Long-
Term Transmission Needs will help transmission providers to identify, 
evaluate, and select more efficient or cost-effective transmission 
solutions to those needs. For example, like the Commission in the 
NOPR,\343\ commenters cite to the success of MISO's Long-Range 
Transmission Plan in delivering more efficient or cost-effective 
transmission solutions. By addressing public policy, economic, and 
reliability transmission planning needs simultaneously through its MVP 
category, MISO `` `eliminate[d] the need for $300 million in future 
baseline reliability upgrades,' and provided production cost savings 
that exceeded the entire cost of the portfolio by $10 billion.'' \344\ 
Brattle Group and Grid Strategies also found that ``building out 
piecemeal network upgrades through the interconnection queue process to 
integrate the same amount of generation would have cost over 80% more 
than the cost of the MVP portfolio.'' \345\ Similarly, the New Jersey 
Commission asserts that, by planning transmission facilities to address 
a specific set of known and identified transmission needs through a 
holistic portfolio, rather than piecemeal through the generator 
interconnection process, PJM could save customers more than $30 
billion.\346\
---------------------------------------------------------------------------

    \343\ See, e.g., NOPR, 179 FERC ] 61,028 at PP 31-32.
    \344\ New Jersey Commission Initial Comments at 4 (citing 
MTEP2017 Review at 6, 8) (emphasis in original).
    \345\ Id. at 4-5 (citing Brattle-Grid Strategies Oct. 2021 
Report at 7 & nn.13-14); see id. at 5 n.9 (noting that the cost of 
the MVP portfolio divided by the amount of wind capacity it 
interconnected came to $412 per kilowatt, while interconnection-
related network upgrades for new generation in MISO planned through 
the interconnection queue cost $756 per kilowatt).
    \346\ Id. at 6-7 (citing Brattle-Grid Strategies Oct. 2021 
Report at 7); id. (explaining that the onshore network upgrades 
required to interconnect 87.1 GW of resources meeting all of PJM 
states' current offshore wind goals and total renewable portfolio 
standards through ``piecemeal interconnection queue projects would 
cost nearly $36 billion in total--more than eleven times the $3.2 
billion cost of the integrated portfolio approach,'' or ``[p]ut 
another way, proactive, portfolio-based planning in PJM could 
ultimately save ratepayers over $30 billion compared to the status 
quo.'').
---------------------------------------------------------------------------

    136. We note that the cost-saving results that MISO experienced 
were the direct product of more comprehensive, longer-term regional 
transmission planning. By expanding the transmission planning horizon 
and considering factors affecting Long-Term Transmission Needs, as well 
as considering a broader list of benefits, transmission providers will 
be able to identify, evaluate, and select more efficient or cost-
effective transmission solutions to address Long-Term Transmission 
Needs.\347\ Such Long-Term Regional Transmission Planning will: (1) 
reduce reliance on transmission solutions that are relatively 
inefficient or less cost-effective because they address only short-term 
transmission needs; (2) unlock the benefits of economies of scale in 
transmission investment; \348\ (3) enable opportunities to ``right 
size'' replacement transmission facilities; \349\ (4) facilitate the 
selection of regional transmission facilities that could address 
multiple transmission needs over different time horizons; and (5) 
provide states, utilities, customers, and other stakeholders with 
greater insight and transparency into the costs and benefits of 
particular transmission solutions to address Long-Term Transmission 
Needs. We conclude that these regional transmission planning and cost 
allocation reforms will benefit customers by leading to more efficient 
or cost-effective transmission investment, thereby helping to ensure 
just and reasonable rates.\350\
---------------------------------------------------------------------------

    \347\ PIOs Initial Comments at 35.
    \348\ Id. at 10 (``[T]he vast majority of current transmission 
projects are focused solely either on network reliability or 
connecting the next generator in the interconnection queue and 
ignore any other potential benefits, possible economies of scale or 
other efficiencies that might occur by considering multiple future 
needs.'').
    \349\ ACEG Initial Comments at 53-56; Clean Energy Associations 
Initial Comments at 25-27; SEIA Initial Comments at 25-26.
    \350\ See, e.g., Exelon Initial Comments at 5 (``The project-by-
project approach of developing [interconnection-related] network 
upgrades in response to generator interconnection requests does not 
take into account broader, longer-term planning needs and 
furthermore raises questions about whether it will lead to efficient 
and cost-effective outcomes as the resource mix rapidly evolves.''); 
PIOs Initial Comments at 8 (``[O]verwhelming evidence indicates that 
transmission owners are largely able to evade the requirements of 
Order No. 1000 and . . . have primarily invested in local projects. 
This has led to . . . billions of dollars in excessive costs for 
consumers.'' (citing Brattle-Grid Strategies Oct. 2021 Report at 
Section 1)); Southeast PIOs Reply Comments at 2 (``All the while, 
snowballing inefficiencies created by numerous small-scale 
transmission band-aids, unfit to address broader generation trends, 
translate into excessive, unjust, and unreasonable rates borne by an 
already overburdened populace.'').
---------------------------------------------------------------------------

    137. In addition to potentially enhancing the efficiency and cost-
effectiveness of transmission investment, we find that sufficiently 
long-term, forward-looking, and comprehensive regional transmission 
planning and cost allocation processes will enhance reliability. In the 
NOPR, the Commission found that a robust, well-planned transmission 
system is foundational to ensuring an affordable, reliable supply of 
electricity. The record supports this conclusion. Many commenters agree 
that, especially in light of continuing changes in both supply and 
demand, ongoing investment in regional transmission facilities is 
necessary to ensure that the transmission system continues to serve 
load in a reliable manner at reasonable cost.\351\ Commenters also 
agree that regional transmission investments support enhanced 
reliability because larger, more integrated transmission systems are 
better equipped to accommodate a diversity of supply and demand 
conditions and provide redundancy that allow the system to better 
withstand unpredictable and extreme weather events, which are

[[Page 49312]]

occurring with increased frequency and severity.\352\
---------------------------------------------------------------------------

    \351\ ACORE ANOPR Initial Comments at 21-22 (explaining how 
additional transmission investments can alleviate billions of 
dollars in costs caused by extreme weather); EEI Initial Comments at 
4 (``Transmission plays and will continue to play a vital role in 
enabling the energy transition and in ensuring a reliable and 
resilient energy grid. A robust transmission system will not only 
enable electric utilities to integrate more renewable energy 
resources and deliver more clean energy to customers but will also 
enhance the reliability and resiliency of the grid and enable the 
deployment of new technologies.'' (citing EEI, Planning and 
Developing Electric Transmission Projects: The Path to the Grid of 
the Future (2022)); NERC Initial Comments at 6 (explaining that 
transmission will be key to managing a reliable transformation in 
the resource mix).
    \352\ NERC Initial Comments at 6 (explaining that regional 
transmission planning is necessary to ensure sufficient transmission 
capacity to move energy from areas with a surplus to areas that are 
deficient).
---------------------------------------------------------------------------

    138. Moreover, commenters provide examples of how long-term, 
forward-looking, and more comprehensive regional transmission planning 
can better identify reliability needs and resolve these needs with more 
efficient or cost-effective transmission solutions.\353\ For example, 
as noted above, MISO's MVP Portfolio 4 eliminated the need for $300 
million in future baseline reliability upgrades.\354\ By comparison, 
the Reliability Must-Run Agreement for Indian River Unit 4, a 410 MW 
coal-fired generation unit, highlights the costs of inadequate regional 
transmission planning. As NARUC explains, the Indian River Unit 4 was 
scheduled to retire, but PJM found that retirement would cause 
reliability issues and would necessitate upgrades to transmission 
facilities that, due to their age, were already due to be upgraded, and 
that the Reliability Must-Run Agreement was needed because those 
upgrades would take five years to complete.\355\ A long-term, forward-
looking, and more comprehensive regional transmission planning process 
may have obviated the need for the Reliability Must-Run Agreement, the 
individual transmission facility upgrades, or both.
---------------------------------------------------------------------------

    \353\ ITC Initial Comments at 44 (``While local transmission 
planning continues to serve a critically necessary, valuable 
function in maintaining the reliability and efficiency of 
transmission systems, it is nonetheless clear that holistic, long 
range transmission planning is far more capable of identifying 
optimal transmission solutions that serve the most needs and deliver 
the most benefits.''); MISO Initial Comments at 88 (explaining that 
in its Tranche 1 Long Range Transmission Plan, MISO recognizes 
Avoided Transmission Investment benefits provided by Long Range 
Transmission Plan facilities in addressing both avoided reliability 
projects and avoided age and condition replacement projects with the 
results being avoided costs in local transmission that would have 
otherwise been incurred to replace existing facilities).
    \354\ New Jersey Commission Initial Comments at 4.
    \355\ NARUC Initial Comments at 14-15.
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4. Conclusion
    139. In consideration of the record provided in this proceeding, as 
well as the related conclusions stated above, we find that the 
Commission's existing regional transmission planning and cost 
allocation requirements are unjust, unreasonable, and unduly 
discriminatory or preferential because they fail to require 
transmission providers to adequately plan on a sufficiently long-term, 
forward-looking, and comprehensive basis. Specifically, as discussed, 
we find that the Commission's regional transmission planning and cost 
allocation requirements fail to require transmission providers to: (1) 
perform a sufficiently long-term assessment of transmission needs that 
identifies Long-Term Transmission Needs; (2) adequately account on a 
forward-looking basis for known determinants of Long-Term Transmission 
Needs; and (3) consider the broader set of benefits of regional 
transmission facilities planned to meet those Long-Term Transmission 
Needs. We find that reforms to those requirements are thus necessary to 
ensure that Commission-jurisdictional rates are just, reasonable, and 
not unduly discriminatory or preferential. The failure to plan on a 
sufficiently long-term, forward-looking, and comprehensive basis 
results in the potential for relatively inefficient or less cost-
effective transmission development for which customers must pay. The 
requirements set forth in this final order will help to ensure that 
transmission providers plan to address Long-Term Transmission Needs, in 
turn helping to ensure more efficient or cost-effective transmission 
development and thus just and reasonable Commission-jurisdictional 
rates.

III. Long-Term Regional Transmission Planning

A. Requirement To Participate in Long-Term Regional Transmission 
Planning

1. NOPR Proposal
    140. In the NOPR, the Commission proposed to require each 
transmission provider to participate in a regional transmission 
planning process that includes Long-Term Regional Transmission 
Planning,\356\ meaning regional transmission planning on a sufficiently 
long-term, forward-looking, and comprehensive basis to identify 
transmission needs driven by changes in the resource mix and demand and 
to identify and evaluate transmission facilities for potential 
selection as the more efficient or cost-effective transmission 
facilities to meet such needs.\357\
---------------------------------------------------------------------------

    \356\ The two features of Long-Term Regional Transmission 
Planning that the Commission included in the proposed reforms were 
the development of scenarios with a 20-year transmission planning 
horizon to be reassessed and revised every three years, with each 
such re-assessment providing the basis for identification and 
evaluation of transmission facilities for potential selection. NOPR, 
179 FERC ] 61,028 at P 68 n.128.
    \357\ See id. PP 54, 64, 68.
---------------------------------------------------------------------------

    141. The Commission proposed that transmission providers may 
continue to rely on their existing regional transmission planning and 
cost allocation processes to comply with Order No. 1000's requirements 
related to transmission needs driven by reliability concerns or 
economic considerations.\358\
---------------------------------------------------------------------------

    \358\ Id. P 72.
---------------------------------------------------------------------------

    142. The Commission proposed that transmission providers that 
comply with the Long-Term Regional Transmission Planning requirements 
will comply with the requirement in Order No. 1000 that they 
participate in a regional transmission planning process that considers, 
and has associated cost allocation provisions related to, transmission 
needs driven by Public Policy Requirements.\359\ The Commission further 
proposed to allow transmission providers to propose to continue using 
some or all aspects of the existing regional transmission planning and 
cost allocation processes they use to consider transmission needs 
driven by Public Policy Requirements.\360\ The Commission stated, 
however, that such continued use of existing regional transmission 
planning and cost allocation processes would not supplant transmission 
providers' obligations to comply with the Long-Term Regional 
Transmission Planning requirements established in any final order in 
this proceeding. Moreover, the Commission proposed that transmission 
providers seeking to retain existing regional transmission planning and 
cost allocation processes to consider transmission needs driven by 
Public Policy Requirements would have to demonstrate that continued use 
of any such processes does not interfere or otherwise undermine the 
Long-Term Regional Transmission Planning proposed in the NOPR by 
demonstrating that continued use of such processes is consistent with 
or superior to any final order issued in this proceeding.\361\
---------------------------------------------------------------------------

    \359\ Id. P 73.
    \360\ Id. P 74.
    \361\ Id.
---------------------------------------------------------------------------

    143. The Commission preliminarily found that transmission providers 
could propose a regional transmission planning process that plans for 
reliability needs, economic needs, transmission needs driven by Public 
Policy Requirements, and transmission needs driven by changes in the 
resource mix and demand simultaneously through a combined approach. The 
Commission stated that transmission providers proposing to address all 
such transmission needs in a single regional transmission planning 
process would bear the burden of demonstrating continued compliance 
with Order No.

[[Page 49313]]

1000 in addition to compliance with the requirements of any final order 
in this proceeding.\362\
---------------------------------------------------------------------------

    \362\ Id. P 75.
---------------------------------------------------------------------------

    144. Finally, the Commission proposed to require that Long-Term 
Regional Transmission Planning comply with the following existing Order 
Nos. 890 and 1000 transmission planning principles: (1) coordination; 
(2) openness; (3) transparency; (4) information exchange; (5) 
comparability; and (6) dispute resolution.\363\
---------------------------------------------------------------------------

    \363\ Id. P 76.
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2. Comments
a. General Comments
    145. The majority of commenters support the Commission's 
proposal,\364\ with multiple commenters claiming that Long-Term 
Regional Transmission Planning is crucial to ensure that regional 
transmission planning appropriately identifies transmission needs to 
meet the changing resource mix and demand.\365\
---------------------------------------------------------------------------

    \364\ Acadia Center and CLF Initial Comments at 2; ACEG Initial 
Comments at 6, 22-23; ACORE Initial Comments at 2, 17; Advanced 
Energy Buyers Initial Comments at 4; AEP Initial Comments at 5-7; 
Amazon Initial Comments at 2; BP Initial Comments at 4-7; 
Breakthrough Energy Initial Comments at 3; Breakthrough Energy 
Supplemental Comments at 1; Business Council for Sustainable Energy 
Initial Comments at 2-4; California Energy Commission Initial 
Comments at 1; City of New Orleans Council Initial Comments at 4; 
City of New York Initial Comments at 1, 3; Clean Energy Associations 
Initial Comments at 10; Conservative Energy Network Supplemental 
Comments at 1; Conservatives for Clean Energy--Florida Supplemental 
Comments at 1; Conservatives for Clean Energy--South Carolina; CTC 
Global Initial Comments at 1; US Senators Supplemental Comments at 
1-2; EEI Initial Comments at 10; ELCON Initial Comments at 6-7; NERC 
Initial Comments at 6-7; ENGIE Initial Comments at 2; Entergy 
Initial Comments at 7; Environmental Groups Supplement Comments at 
2; Evergreen Action Initial Comments at 3; Eversource Initial 
Comments at 2; Exelon Initial Comments at 4-7; Form Energy Initial 
Comments at 2-3; Governor of Kansas Laura Kelly Supplemental 
Comments at 1; Handy Law Initial Comments at 7-8; US House 
Republicans Supplemental Comments at 1; Indicated PJM TOs Initial 
Comments at 7-8; Indicated US Senators and Representatives Initial 
Comments at 1; Michigan Conservative Energy Forum Supplemental 
Comments at 1; ISO-NE Initial Comments at 2, 8; ITC Initial Comments 
at 5-9; Joint Consumer Advocates Initial Comments at 5-6; Minnesota 
State Entities Initial Comments at 4; NARUC Initial Comments at 4; 
National Grid Initial Comments at 9-11; NEMA Initial Comments at 1-
2; NESCOE Initial Comments at 14-16; New England for Offshore Wind 
Initial Comments at 2; New York Commission and NYSERDA Initial 
Comments at 8; New York TOs Initial Comments at 1; New York Transco 
Initial Comments at 1; NextEra Initial Comments at 62; Northwest and 
Intermountain Initial Comments at 7; Ohio Conservative Energy Forum 
Supplemental Comments at 1; Pine Gate Initial Comments at 18-19; 
PIOs Initial Comments at 12-14; Policy Integrity Initial Comments at 
5; RMI Supplemental Comments at 2; Senator Schumer Supplemental 
Comments at 1-2; Senator Whitehouse Supplemental Comments at 1-3; 
SDG&E Initial Comments at 2; Southeast PIOs Initial Comments at 42-
49; State Officials Supplemental Comments at 1 (citing US Climate 
Alliance Initial Comments); US Climate Alliance Initial Comments at 
1-2; Vermont Electric and Vermont Transco Initial Comments at 3; 
Virginia Commission Staff Initial Comments at 2-3; Western PIOs 
Initial Comments at 28-30, 36; Western Way Colorado Supplemental 
Comments at 1; Western Way Nevada Supplemental Comments at 1; 
Western Way Utah Supplemental Comments at 1; Wisconsin Conservative 
Energy Forum Supplemental Comments at 1.
    \365\ Breakthrough Energy Initial Comments at 12; EEI 
Supplemental Comments at 1; Exelon Initial Comments at 5; US House 
Republicans Supplemental Comments at 1; ITC Initial Comments at 5.
---------------------------------------------------------------------------

    146. AEP and [Oslash]rsted argue that the Commission's proposal 
will address deficiencies in the current transmission planning 
process.\366\ National Grid claims that existing long-term transmission 
planning processes are sufficient for addressing reliability and 
economic transmission needs in the near-term but are inadequate for 
addressing the changing resource mix and demand, as well as for 
addressing resilience challenges driven by climate change.\367\ ACEG 
claims that Long-Term Regional Transmission Planning will allow right-
sizing of transmission facilities.\368\
---------------------------------------------------------------------------

    \366\ AEP Initial Comments at 8; [Oslash]rsted Initial Comments 
at 4-5.
    \367\ National Grid Initial Comments at 10.
    \368\ ACEG Initial Comments at 6.
---------------------------------------------------------------------------

    147. Some commenters observe that this proposal may result in cost-
savings for consumers. For example, DC and MD Offices of People's 
Counsel claim that this proposal could result in significant cost 
savings to consumers by helping address severe weather events and 
reduce the relative cost of decarbonizing the country's resource 
fleet.\369\ AEP argues that the NOPR proposal will benefit consumers by 
establishing a process that will identify more efficient or cost-
effective transmission facilities, capturing currently missed 
opportunities and achieving economies of scale.\370\ North Carolina 
Commission and Staff argue that Long-Term Regional Transmission 
Planning can provide state utility commissions and consumer advocates 
with useful information to promote a cost-effective and reliable 
transmission grid.\371\
---------------------------------------------------------------------------

    \369\ DC and MD Offices of People's Counsel Initial Comments at 
8-10 (citing Patrick Brown & Audun Botterud, The Value of Inter-
Regional Coordination and Transmission in Decarbonizing the US 
Electricity System, 5 Joule 115, 115-134 (2020), https://www.sciencedirect.com/science/article/pii/S2542435120305572?dgcid=author%20_blank); see also EEI Supplemental 
Comments at 1 (arguing that robust transmission development will 
provide cost savings from greater access to low-cost resources).
    \370\ See AEP Initial Comments at 8-12.
    \371\ North Carolina Commission and Staff Initial Comments at 4.
---------------------------------------------------------------------------

    148. NextEra states that Long-Term Regional Transmission Planning 
can minimize overall costs to consumers by enabling the lowest-cost 
generation.\372\ Relatedly, Tabors Caramanis Rudkevich states that the 
NOPR proposal would establish a transmission planning process that 
coordinates across franchises, states, and regions, which will reduce 
the production cost of delivery of energy to consumers.\373\
---------------------------------------------------------------------------

    \372\ NextEra Initial Comments at 62.
    \373\ Tabors Caramanis Rudkevich Initial Comments at 4-5.
---------------------------------------------------------------------------

    149. PPL notes that Long-Term Regional Transmission Planning may 
improve some of the limitations of criteria-based transmission 
planning, which is currently employed in RTOs/ISOs.\374\ [Oslash]rsted 
supports the proposed requirements regarding Long-Term Regional 
Transmission Planning and argues that existing regional transmission 
plans fail to anticipate the size and scale of future offshore wind 
generation development, leading to inaccurate plans and insufficient 
investment in infrastructure needed to integrate known future offshore 
wind generation.\375\
---------------------------------------------------------------------------

    \374\ PPL Initial Comments at 4. PPL claims that, while PJM may 
perform long-term transmission planning on a 15-year time frame on 
paper, its long-term transmission planning is effectively undertaken 
over only 7 to 10 years. Id.
    \375\ [Oslash]rsted Initial Comments at 4-5.
---------------------------------------------------------------------------

    150. State Agencies assert that the Commission's various proposed 
reforms in the NOPR collectively would enhance transparency, prevent 
unnecessary investment in local transmission projects, and improve the 
competitive landscape.\376\ US DOJ and FTC support reforms that address 
obstacles to transmission development and that are implemented 
consistent with principles for competition.\377\
---------------------------------------------------------------------------

    \376\ State Agencies Reply Comments at 6.
    \377\ US DOJ and FTC Initial Comments at 19.
---------------------------------------------------------------------------

b. Requests for Flexibility in Transmission Planning
    151. A number of commenters support the Commission's proposal to 
require Long-Term Regional Transmission Planning, but also express 
reservations or objections regarding what they perceive as an overly 
prescriptive approach that may disrupt existing processes that are 
already working.\378\ For example, multiple

[[Page 49314]]

commenters express concerns that the NOPR's allegedly prescriptive 
requirements for Long-Term Regional Transmission Planning will 
significantly limit needed discretion to conduct such planning, and 
that, without discretion to adjust the scenario modeling and 
assumptions to regional circumstances, the final order could lead to 
more delay and conflict.\379\ MISO TOs contend that the NOPR proposals 
vary sufficiently from MISO's current approach that MISO and its 
stakeholders will need to engage in complex and time-intensive 
revisions in order to comply.\380\ Similarly, City of New Orleans 
Council asks that the final order not hinder existing MISO 
processes.\381\
---------------------------------------------------------------------------

    \378\ See, e.g., Avangrid Initial Comments at 6, 9; CAISO 
Initial Comments at 1-2, 7-10, 13; California Commission Initial 
Comments at 6; Duke Initial Comments at 1-2; Indiana Commission 
Initial Comments at 1, 3; ISO-NE Initial Comments at 20; ISO/RTO 
Council Initial Comments at 4-5 (citing NOPR, 179 FERC ] 61,028 at 
PP 66, 104); Massachusetts Attorney General Initial Comments at 10-
12; Michigan Commission Initial Comments at 4-5; MISO Initial 
Comments at 23; NEPOOL Initial Comments at 7; NYISO Initial Comments 
at 11; PG&E Initial Comments at 2; PJM Initial Comments at 54-55; US 
Chamber of Commerce at 4-5.
    \379\ Ameren Initial Comments at 8; ISO-NE Initial Comments at 
20; ISO/RTO Council Initial Comments at 8-9; MISO TOs Reply Comments 
at 10-12.
    \380\ MISO TOs Reply Comments at 10-11.
    \381\ City of New Orleans Initial Comments at 5-6.
---------------------------------------------------------------------------

    152. Multiple commenters recommend that the Commission's final 
order establish principles and objectives for long-term transmission 
planning that address the Commission's concerns and provide 
transmission providers with the flexibility to develop tailored long-
term transmission planning approaches and implementation details 
accordingly.\382\ MISO recommends that each transmission provider 
should give the Commission a report outlining the actions and processes 
that support the Commission's principles and guidance, and then the 
Commission could direct specific changes within each transmission 
planning region as it deems necessary.\383\
---------------------------------------------------------------------------

    \382\ ISO-NE Initial Comments at 20; ISO/RTO Council Initial 
Comments at 4-5, 8-9; MISO Initial Comments at 22-23.
    \383\ MISO Initial Comments at 22.
---------------------------------------------------------------------------

    153. Multiple commenters argue for flexibility to accommodate local 
and regional differences, including differences in public policy goals 
that affect transmission planning.\384\ NYISO asks that the final order 
give each transmission planning region discretion to determine, in 
coordination with state entities and stakeholders, how best to 
incorporate the Long-Term Regional Transmission Planning requirements 
within its transmission planning framework.\385\ California Municipal 
Utilities add that a significant amount of demand in the West is served 
by publicly-owned utilities and electric cooperatives, which fall 
outside of state commission regulation, highlighting the need for 
flexibility in planning.\386\
---------------------------------------------------------------------------

    \384\ APPA Reply Comments at 9-10; California Commission Initial 
Comments at 5; California Municipal Utilities Reply Comments at 2-4; 
Industrial Customers Reply Comments at 4; Louisiana Commission Reply 
Comments at 4-5; Georgia Commission Initial Comments at 2; NARUC 
Initial Comments at 3; New York Transco Initial Comments at 5; North 
Dakota Commission Initial Comments at 3; New York Commission and 
NYSERDA Initial Comments at 3; OMS Initial Comments at 3; PJM States 
Initial Comments at 2.
    \385\ NYISO Initial Comments at 13.
    \386\ California Municipal Utilities Reply Comments at 2.
---------------------------------------------------------------------------

    154. Dominion asserts that any reforms adopted in this proceeding 
should align with the purpose of the transmission system, which is to 
provide reliable, affordable electric service to customers rather than 
to benefit generators.\387\
---------------------------------------------------------------------------

    \387\ Dominion Initial Comments at 5.
---------------------------------------------------------------------------

    155. APPA agrees with concerns expressed by Commissioner Christie 
and former Commissioner Danly that overly prescriptive transmission 
planning requirements have the potential to interfere with existing 
regional transmission planning processes, and hence argues that 
adequate flexibility is needed.\388\ Mississippi Commission states that 
where an RTO/ISO or non-RTO/ISO transmission provider is already 
engaged in long-term regional transmission planning, the Commission 
should accept flexibility and regional variations on compliance to 
address region-specific issues, including the delineation of regional 
and local transmission facilities through, for example, a voltage 
threshold (e.g., 100 kV).\389\
---------------------------------------------------------------------------

    \388\ APPA Initial Comments at 23.
    \389\ Mississippi Commission Reply Comments at 7-8 (citing 
Entergy Initial Comments at 2-4; Louisiana Commission Initial 
Comments at 35-36; Michigan State Entities Initial Comments at 2; 
MISO Initial Comments at 2-3, 19; MISO TOs Initial Comments at 2, 4, 
13-15).
---------------------------------------------------------------------------

    156. CAISO maintains that the Commission should allow it to 
continue evaluating transmission needs driven by Public Policy 
Requirements in its transmission planning process, in addition to any 
Long-Term Regional Transmission Planning process, and give CAISO the 
flexibility to continue using resource portfolios and geographic zones 
identified by state agencies and local regulatory authorities.\390\ 
Although ACORE urges the Commission not to grant requests for less 
stringent transmission planning requirements in the final order, ACORE 
agrees that there may be cases where an individual RTO's/ISO's existing 
processes may be superior to the proposed reforms, such as in the case 
of CAISO's treatment of public policy projects within its annual 
transmission planning process.\391\ California Municipal Utilities note 
that CAISO has already begun to implement some of the key reforms that 
the Commission proposed in the NOPR, specifically by adopting a 20-year 
outlook for transmission planning.\392\
---------------------------------------------------------------------------

    \390\ CAISO Reply Comments at 17-18.
    \391\ ACORE Reply Comments at 4.
    \392\ California Municipal Utilities Initial Comments at 5.
---------------------------------------------------------------------------

    157. MISO requests that a final order support, rather than detract 
from, its demonstrated success in long-term transmission planning.\393\ 
MISO TOs request that the Commission revise the NOPR's required 
parameters for Long-Term Regional Transmission Planning to accommodate 
the robust long-term regional transmission planning that some 
transmission planning regions, like MISO, have already developed.\394\ 
Similarly, Ameren contends that the Commission should find that MISO's 
approved Long Range Transmission Planning process substantially 
complies with the proposed reforms.\395\
---------------------------------------------------------------------------

    \393\ MISO Reply Comments at 2-3.
    \394\ MISO TOs Reply Comments at 11-12.
    \395\ Ameren Initial Comments at 8.
---------------------------------------------------------------------------

    158. New York TOs support allowing transmission planning regions 
with already successful transmission planning processes to retain those 
processes while making incremental enhancements and to demonstrate on 
compliance that they meet the NOPR's objectives.\396\ New York Transco 
asserts that the current NYISO public policy transmission planning 
processes already address, at least in part, the proposed reforms and 
believes that the Commission should permit regional flexibility.\397\
---------------------------------------------------------------------------

    \396\ New York TOs Initial Comments at 8-9.
    \397\ New York Transco Initial Comments at 5.
---------------------------------------------------------------------------

    159. SPP states that its current transmission planning processes 
are sufficient to meet the intent of the Commission's proposed Long-
Term Regional Transmission Planning reforms.\398\ Omaha Public Power 
states that SPP and other RTOs/ISOs have already developed long-term 
planning scenarios and suggests that transmission providers that 
already have long-term planning scenarios should be provided with the 
flexibility to continue using their previously established 
processes.\399\
---------------------------------------------------------------------------

    \398\ SPP Initial Comments at 3 (citing NOPR, 179 FERC ] 61,028 
at P 3).
    \399\ Omaha Public Power Initial Comments at 4.
---------------------------------------------------------------------------

    160. In contrast, some commenters argue that the final order should 
not provide too much flexibility to transmission providers because that 
flexibility will undermine Long-Term

[[Page 49315]]

Regional Transmission Planning.\400\ Many commenters opposing greater 
flexibility argue that the Commission should establish minimum 
requirements for Long-Term Regional Transmission Planning.\401\
---------------------------------------------------------------------------

    \400\ See, e.g., ACORE Reply Comments at 2-4 (citing New Jersey 
Commission Initial Comments at 7); AEP Reply Comments at 2-5; Clean 
Energy Associations Reply Comments at 4-6; DC and MD Offices of 
People's Counsel Reply Comments at 2-3; Hannon Armstrong Reply 
Comments at 1; Interwest Reply Comments at 3-4; Invenergy Reply 
Comments at 8-10; PIOs Reply Comments at 5-6.
    \401\ See, e.g., AEE Reply Comments at 9-13, 16-18, 21-22; AEP 
Reply Comments at 2-5; Cypress Creek Reply Comments at 4-9; 
Interwest Reply Comments at 3-4; Invenergy Initial Comments at 2; 
Kentucky Commission Chair Chandler Reply Comments at 2; PIOs Reply 
Comments at 2-3; SEIA Reply Comments at 1-3; Southeast PIOs Reply 
Comments at 21-22; SREA Reply Comments at 26-27.
---------------------------------------------------------------------------

    161. AEP argues that the Commission must resist requests for 
excessive regional flexibility that could threaten the development of 
long-term regional transmission and only permit it in limited instances 
that exceed minimum requirements.\402\ Onward Energy states that, while 
flexibility is reasonable, the Commission must clearly identify who 
will drive regional transmission planning processes and how 
transmission planners will coordinate, study, and implement Long-Term 
Scenarios that represent realistic future resource portfolios.\403\ 
Clean Energy Associations state that without robust and proactive 
transmission planning rules, the Commission cannot determine that rates 
remain just and reasonable.\404\ DC and MD Offices of People's Counsel 
state that, while regional flexibility is critical, long-term 
transmission planning rules that provide carve-outs and opt-outs will 
result in balkanized transmission development.\405\
---------------------------------------------------------------------------

    \402\ AEP Reply Comments at 3.
    \403\ Onward Energy Initial Comments at 4.
    \404\ Clean Energy Associations Reply Comments at 4-5 (citing 
CAISO Initial Comments at 3; California Commission Initial Comments 
at 11; ISO-New England Initial Comments at 4; ISO/RTO Council 
Initial Comments at 8; NYISO Initial Comments at 3; PG&E Initial 
Comments at 4; PJM States Initial Comments at 4).
    \405\ DC and MD Offices of People's Counsel Reply Comments at 2.
---------------------------------------------------------------------------

    162. Hannon Armstrong states that by diluting the proposed 
requirements or granting flexibility as some commenters request, the 
Commission would allow existing deficiencies to persist, enabling the 
continued reliance on either the generator interconnection process or 
operational planning to resolve or mitigate constraints.\406\ Invenergy 
rebuts commenters' claims that the NOPR is too prescriptive or that 
some of the NOPR requirements should be optional, stating that optional 
processes and deference to regional flexibility will not ensure needed 
transmission is built and that a flexible approach has already been 
tried and has failed to produce sufficient results.\407\
---------------------------------------------------------------------------

    \406\ Hannon Armstrong Reply Comments at 1.
    \407\ Invenergy Reply Comments at 9-10.
---------------------------------------------------------------------------

c. Comments Regarding More Comprehensive Transmission Planning
    163. Several commenters contend that Long-Term Regional 
Transmission Planning should not interfere with and should not supplant 
existing shorter-term transmission planning processes.\408\ PJM asks 
the Commission to confirm that it did not mean for the NOPR proposals 
on Long-Term Regional Transmission Planning to modify the existing 
reliability and market efficiency transmission planning processes.\409\ 
Transmission Dependent Utilities encourage the Commission to ensure 
that transmission providers do not focus on long-term objectives to 
satisfy state renewable energy portfolio requirements to the detriment 
of near-term reliability needs, such as end-of-life transmission 
planning.\410\ Large Public Power and NEPOOL state that any final order 
should clearly state that the current near-term transmission planning 
rules and processes, especially cost allocation, are not changed by the 
final order's reforms, except where expressly indicated.\411\ Ameren 
argues that the Commission was clear that changes to existing 
reliability and economic transmission planning requirements are beyond 
the scope of the NOPR and that the comments filed supporting holistic 
planning have provided no compelling basis for the Commission to 
address them.\412\
---------------------------------------------------------------------------

    \408\ Ameren Reply Comments at 17; CAISO Initial Comments at 2-
3, 17-20; Chemistry Council Initial Comments at 5; Dominion Initial 
Comments at 23; Exelon Initial Comments at 6-7; Indicated PJM TOs 
Initial Comments at 12; ITC Initial Comments at 8-9; Large Public 
Power Initial Comments at 14-16; NEPOOL Initial Comments at 8; 
NESCOE Initial Comments at 21-23; PJM Initial Comments at 55-57; PPL 
Initial Comments at 4-5; Transmission Dependent Utilities Initial 
Comments at 4-6; WIRES Initial Comments at 6-7; Xcel Initial 
Comments at 16.
    \409\ PJM Initial Comments at 55-57.
    \410\ Transmission Dependent Utilities Initial Comments at 4-6.
    \411\ Large Public Power Initial Comments at 16-18; NEPOOL 
Initial Comments at 7-8.
    \412\ Ameren Reply Comments at 17.
---------------------------------------------------------------------------

    164. Several commenters contend that Long-Term Regional 
Transmission Planning should not interfere with and must not supplant 
existing shorter-term transmission planning processes for transmission 
needs driven by Public Policy Requirements.\413\ CAISO states that the 
NOPR provides no guidance or criteria regarding how a transmission 
provider can demonstrate that its existing process for addressing 
transmission needs driven by Public Policy Requirements does not 
interfere with or undermine Long-Term Regional Transmission Planning. 
CAISO contends that it should not have to re-justify its existing 
process or demonstrate that its existing process is consistent with or 
superior to Long-Term Regional Transmission Planning.\414\
---------------------------------------------------------------------------

    \413\ Anbaric Initial Comments at 22-27; CAISO Initial Comments 
at 2-3, 9-20; Large Public Power Initial Comments at 14-16.
    \414\ CAISO Initial Comments at 19.
---------------------------------------------------------------------------

    165. AEP asserts that transmission providers should look at nearer-
term reliability and economic transmission planning processes to 
determine whether there are needs that can be incorporated into Long-
Term Regional Transmission Planning and addressed by a Long-Term 
Regional Transmission Facility.\415\ SEIA recommends that the 
Commission require transmission providers to engage in portfolio-based 
transmission planning that integrates all relevant factors, including 
near-term needs, into Long-Term Regional Transmission Planning.\416\ 
Policy Integrity argues that inclusion of specific requirements for 
transmission modeling are needed to fulfill the mandate of ensuring 
wholesale electric rates are just and reasonable.\417\ Xcel recommends 
that the Commission require that known or expected generation be 
included in short-term regional transmission planning assumptions.\418\
---------------------------------------------------------------------------

    \415\ AEP Initial Comments at 10.
    \416\ SEIA Initial Comments at 20-21.
    \417\ Policy Integrity Supplemental Comments at 3.
    \418\ Xcel Initial Comments at 16.
---------------------------------------------------------------------------

    166. PIOs state that, if the two processes continue to exist, the 
Commission should mandate that the base cases used in Order No. 1000 
regional transmission planning processes and Long-Term Scenarios in 
Long-Term Regional Transmission Planning be defined in the same 
process. Otherwise, PIOs contend, inconsistent assumptions between the 
two processes could lead to redundant transmission projects and failure 
to identify more efficient solutions. In particular, PIOs argue, if an 
Order No. 1000 transmission planning process base case identifies 
transmission needs that are not anticipated in the Long-Term Scenarios, 
the opportunities for more efficient planning created by the long-term 
process will be lost. In addition, PIOs suggest that there may be 
opportunities for stakeholders to undermine Long-Term Regional 
Transmission Planning if they believe Order No. 1000 transmission 
planning

[[Page 49316]]

would produce more favorable results for them. PIOs further argue that 
because uncertainty grows the further one looks into the future, there 
should not be significant differences in the short-term results of 
Long-Term Regional Transmission Planning and Order No. 1000 regional 
transmission planning processes.\419\
---------------------------------------------------------------------------

    \419\ PIOs Initial Comments at 44-46.
---------------------------------------------------------------------------

    167. Several commenters support forward-looking, Long-Term Regional 
Transmission Planning but argue for holistic planning using multiple 
drivers of transmission needs.\420\ They argue that a holistic approach 
is more efficient, better accounts for long-term benefits of new 
transmission, addresses the needs of more stakeholders, and is more 
likely to support development of regional transmission facilities, 
among other benefits. Competition Advocates support a final order that 
reflects the benefits of holistic modeling,\421\ while New Jersey 
Commission contends that holistic transmission planning using a 
competitive process provides significant benefits, including reducing 
costs.\422\
---------------------------------------------------------------------------

    \420\ See, e.g., Acadia Center and CLF Initial Comments at 4-7; 
ACEG Initial Comments at 6-7, 30-31; ACORE Initial Comments at 5-7; 
Anbaric Initial Comments at 5-10; AEE Reply Comments at 2; Business 
Council for Sustainable Energy Initial Comments at 2; City of New 
York Initial Comments at 4-6; Competition Coalition Initial Comments 
at 15-16; Cypress Creek Reply Comments at 4-5; Enel Initial Comments 
at 3; Pine Gate Initial Comments at 18-19; PIOs Reply Comments at 
11; SEIA Reply Comments at 2, 7-8; see also Pattern Energy Initial 
Comments at 16.
    \421\ Competition Advocates Supplemental Comments at 1; see also 
Policy Integrity Supplemental Comments at 2-3 (citing Jennifer Danis 
et al., Inst. for Policy Integrity, Transmission Planning for the 
Energy Transition: Rethinking Modeling Approaches (Dec. 2023), 
https://policyintegrity.org/files/publications/Transmission_Report_2023.pdf).
    \422\ New Jersey Commission Motion to Lodge at 4-5 (citing In re 
Declaring Transmission to Support Offshore Wind a Pub. Policy of the 
State of N.J., Order on the State Agreement Approach SAA Proposals, 
N.J. BPU Docket No. QO20100630 (Oct. 26, 2022), https://publicaccess.bpu.state.nj.us/DocumentHandler.ashx?document_id=1279919; Johannes P. Pfeifenberger, 
et al., Brattle Grp., New Jersey State Agreement Approach for 
Offshore Wind Transmission: Evaluation Report, (Oct. 26, 2022), 
https://publicaccess.bpu.state.nj.us/DocumentHandler.ashx?document_id=1279916; PJM, Economic Analysis 
Report: 2021 SAA Proposal Window to Support NJ OSW (Nov. 4, 2022), 
https://www.pjm.com/-/media/committees-groups/committees/teac/2022/
20221104-special/informationalonly_-njosw-economic-analysis-
report.ashx).
---------------------------------------------------------------------------

    168. To ensure that reforms are not undermined by existing 
processes, Clean Energy Buyers recommend that the Commission extend to 
all existing regional transmission planning processes--not just 
transmission planning processes to address transmission needs driven by 
Public Policy Requirements, as proposed in the NOPR--the requirement 
that, on compliance with any final order, transmission providers who 
seek to retain existing regional transmission planning and cost 
allocation processes must demonstrate that continued use of those 
processes does not interfere with or undermine Long-Term Regional 
Transmission Planning.\423\
---------------------------------------------------------------------------

    \423\ Clean Energy Buyers Initial Comments at 9-10.
---------------------------------------------------------------------------

    169. However, other commenters support the Commission's proposal in 
the NOPR to not apply the proposed reforms to existing Order No. 1000 
reliability and near-term economic regional transmission planning 
processes.\424\ Ohio Consumers support the NOPR's proposal to mostly 
retain the regional transmission planning processes outlined in Order 
No. 1000, explaining that PJM stakeholders have reached an effective 
settlement under that framework in which costs are allocated in a 
manner that is roughly commensurate with the benefits received.\425\
---------------------------------------------------------------------------

    \424\ Ameren Reply Comments at 17; Exelon Initial Comments at 6-
7; ITC Initial Comments at 8-9; WIRES Initial Comments at 6-7.
    \425\ Ohio Consumers Initial Comments at 7 (citing NOPR, 179 
FERC ] 61,028 at P 72).
---------------------------------------------------------------------------

    170. Some commenters argue that the Commission should require that 
local transmission projects be evaluated and approved as part of a 
holistic planning approach.\426\ AEE asserts that, to ensure that 
transmission providers consider the full range of needs in developing 
long-term regional transmission plans, the final order should require 
them to consider local transmission plans and to determine whether a 
regional solution would be more efficient or cost-effective.\427\ OMS 
suggests that the Commission require that all local transmission 
projects be evaluated and approved as part of regional transmission 
planning processes with the opportunity for meaningful input from 
retail regulators, which it argues will enable participation by state 
regulators while respecting transmission owners' abilities to maintain 
their systems.\428\
---------------------------------------------------------------------------

    \426\ AEE Initial Comments at 3, 38; OMS Initial Comments at 16-
17; LS Power and NRG Supplemental Comments at 34-37.
    \427\ AEE Initial Comments at 3, 38.
    \428\ OMS Initial Comments at 16-17.
---------------------------------------------------------------------------

    171. By contrast, WIRES argues that the Commission should maintain 
the distinction between regional transmission planning and local 
transmission planning. WIRES argues that, while the regional 
transmission planning process is directed toward addressing certain 
reliability concerns, economic criteria, and public policy initiatives, 
it is not geared toward addressing additional system needs related to 
resilience, asset management, customer needs, customer impact, and 
aging infrastructure replacement that is typically the focus of local 
transmission planning.\429\ Similarly, AEP states that if an RTO/ISO 
were to make all decisions regarding local transmission projects, they 
would also need to assume the accompanying responsibility--and the 
liability--for such decisions, which would entail physical inspection 
and condition assessment of assets, as well as a determination of when 
transmission facilities have reached their end of useful life.\430\ AEP 
points out that both CAISO and PJM have expressly stated that they do 
not wish to undertake these types of activities and assume such 
obligations.\431\
---------------------------------------------------------------------------

    \429\ WIRES Initial Comments at 9.
    \430\ AEP Reply Comments at 7.
    \431\ Id. (citing S. Cal. Edison Co., 164 FERC ] 61,160, at P 18 
(2018); PJM Interconnection, L.L.C., Comments of PJM, Docket No. 
ER20-2308-000, at attach. A (July 2, 2020) (citation omitted)).
---------------------------------------------------------------------------

d. Concerns Regarding Favoring Renewable Resources
    172. ELCON argues that the Commission's proposal could require 
customers to pay higher costs to connect distant renewables when a 
lower-cost transmission project would provide the same reliability or 
economic benefits.\432\ Utah Division of Public Utilities states that 
Long-Term Scenario requirements favoring renewable generation burden 
transmission providers while providing little to no benefit and that 
developers and generation utilities should determine which renewable 
generation should be developed at their respective zones or sites.\433\ 
Utah Commission further contends that nationwide mandates for 
transmission planning add costs, produce confusion, and create 
conflicts that could lead to higher utility prices for consumers.\434\ 
Kansas Ratepayer Advocates contend that Long-Term Regional Transmission 
Planning would presume material additions of renewable energy to serve 
consumers within a state, coupled with material additions of 
transmission to interconnect those renewables to the electric 
transmission grid, which do not reflect the unique circumstances of 
Kansas.\435\
---------------------------------------------------------------------------

    \432\ ELCON Initial Comments at 9-10.
    \433\ Utah Division of Public Utilities Initial Comments at 7-8.
    \434\ Utah Commission Initial Comments at 11, 13.
    \435\ Kansas Ratepayers Advocates Reply Comments at 2.
---------------------------------------------------------------------------

    173. Vistra asserts that the proposed reforms could devolve into 
the subsidization of resources chosen to

[[Page 49317]]

achieve state policy goals, masking the true costs of those remotely 
located resources that require extensive transmission development to 
interconnect to the grid and leading to market distortions that 
undermine the objectives of these reforms.\436\
---------------------------------------------------------------------------

    \436\ Vistra Initial Comments at 11.
---------------------------------------------------------------------------

    174. Louisiana Commission states that the NOPR would result in 
subsidization of the costs of transmitting remote renewable energy, 
spreading the costs out broadly based on an expanded ``nebulous concept 
of `benefits' and perceived `public policy,' '' thus ensuring that 
those transmission projects will pass any economic test.\437\ According 
to Louisiana Commission, this subsidization would interfere with price 
signals, thereby distorting the efficient functioning of the wholesale 
market.\438\ Louisiana Commission states that any Commission policy 
should be resource and technology neutral and should not impose costs 
on states that do not benefit from distant renewable power.\439\
---------------------------------------------------------------------------

    \437\ Louisiana Commission Reply Comments at 12 (citing NOPR, 
179 FERC ] 61,028 (Christie, Comm'r, concurring at P 2)).
    \438\ Louisiana Commission Initial Comments at 19-21.
    \439\ Id. at 21-24.
---------------------------------------------------------------------------

    175. Finally, Louisiana Commission contends that the NOPR's long-
term transmission planning requirements could threaten the reliability 
of the transmission grid because the intermittent renewable resources 
that the NOPR favors do not provide stable output and are not 
dispatchable.\440\ Similarly, former Kansas Commission Chair Keen 
argues that the NOPR fails to acknowledge the reliability concerns 
associated with a generation mix that is too heavily weighted to 
intermittent renewable generation resources.\441\
---------------------------------------------------------------------------

    \440\ Id. at 21-23. But see Cypress Creek Reply Comments at 2-4 
(disagreeing with Louisiana Commission and claiming that regionally 
coordinated transmission planning should provide demonstrable system 
reliability benefits).
    \441\ Kansas Commission Chair Keen Initial Comments at 1.
---------------------------------------------------------------------------

e. Concerns Regarding Uncertainty, Over-Building, and Costs
    176. A few commenters argue that long-term transmission planning 
introduces uncertainty or incentivizes speculative transmission 
development.\442\ While EPSA acknowledges that long-term forecasts can 
provide valuable information about the potential scale of construction 
necessary to achieve decarbonization, it argues that using such 
forecasts to justify investment shifts the risks to consumers from 
developers and facility owners.\443\ California Municipal Utilities 
state that, as transmission planning horizons are extended, the changes 
in resource mix, technology types, the location of resources, and 
demand will likely change congestion patterns and therefore the need 
for transmission upgrades needed to address them.\444\
---------------------------------------------------------------------------

    \442\ EPSA Initial Comments at 7; New England Systems Initial 
Comments at 22; see also NRECA Initial Comments at 28-29.
    \443\ EPSA Initial Comments at 7.
    \444\ California Municipal Utilities Initial Comments at 7.
---------------------------------------------------------------------------

    177. Louisiana Commission states that it opposes the NOPR proposal 
because it would lead to an inefficient and expensive build-out of the 
transmission system and could be used to justify shifting the costs of 
this build-out to load.\445\ ELCON states that it is concerned that the 
Commission's proposal to prioritize Long-Term Regional Transmission 
Planning to connect renewable generation over Long-Term Regional 
Transmission Planning for economically necessary transmission may 
exceed the Commission's authority if it increases transmission rates 
for the benefit of a few stakeholders.\446\ Southern states that 
transmission expansion predicated on hypothetical resources that might 
not materialize would not satisfy the fundamental legal requirements of 
being used and useful, prudent, and/or otherwise needed for the public 
use, could harm reliability, and would violate the Commission's duty 
under the FPA to facilitate transmission planning to meet load-serving 
entities' obligations.\447\
---------------------------------------------------------------------------

    \445\ Louisiana Commission Initial Comments at 4-5.
    \446\ ELCON Initial Comments at 9 (citing NOPR, 179 FERC ] 
61,028 (Danly, Comm'r, dissenting, at P 2 n.3); NOPR, 179 FERC ] 
61,028 at P 47).
    \447\ Southern Initial Comments at 32, 34.
---------------------------------------------------------------------------

    178. Industrial Customers argue that the NOPR does not provide 
evidence that extending the transmission planning horizon would exclude 
modeling of speculative projects, which would likely result in the 
over-building of transmission and unnecessary increases in rates.\448\ 
Industrial Customers cite the D.C. Circuit's finding in Old Dominion 
Electric Cooperative v. FERC that ``[w]e are sensitive to the concern . 
. . that individual utilities should not have free rein to impose 
unjustified costs on an entire region by unilaterally adopting overly 
ambitious planning criteria,'' and argue that the current NOPR proposal 
would result in the same issues.\449\
---------------------------------------------------------------------------

    \448\ Industrial Customers Initial Comments at 6, 15-16, 19-21.
    \449\ Id. at 16 (citing Old Dominion Elec. Coop. v. FERC, 898 
F.3d 1254, 1263 (D.C. Cir. 2018)).
---------------------------------------------------------------------------

    179. NRG urges caution on over-reliance on any 20-year planning 
study for making transmission investments due to the inherent 
uncertainty of a study with such a long planning horizon.\450\ NRG 
argues that the NOPR will increase delivery costs by reducing the value 
of private investments and replacing such investments with a centrally 
planned, cost-socialized approach that is founded on at least some 
incorrect assumptions.\451\ NRG provides several examples of how 
forecast errors have caused adverse consequences, including forecasts 
of natural gas prices, load forecasts, and canceled planned 
transmission facilities.\452\
---------------------------------------------------------------------------

    \450\ NRG Initial Comments at 8.
    \451\ Id. at 3.
    \452\ Id. at 10-11.
---------------------------------------------------------------------------

    180. Likewise, Ohio Consumers urge the Commission to avoid adopting 
proposals based on long-term projections that justify massive charges 
to consumers based on hypothetical scenarios.\453\ Ohio Consumers state 
that Ohio customers have recently been saddled with rate increases in 
part due to transmission investments and that long-term transmission 
planning requirements would increase ratepayer burden, which is 
especially troublesome if projections turn out to be inaccurate.\454\
---------------------------------------------------------------------------

    \453\ Ohio Consumers Initial Comments at 5.
    \454\ Id.
---------------------------------------------------------------------------

    181. As an alternative to Long-Term Regional Transmission Planning, 
Potomac Economics states that the Commission could require the 
transmission planning process to incorporate a broader array of near-
term emerging trends that are less uncertain than the proposed longer-
term factors.\455\ Louisiana Commission states that it shares Potomac 
Economics' concerns. Louisiana Commission urges the Commission to heed 
testimony submitted by Potomac Economics arguing that: (1) there is 
significant uncertainty about future technology and a significant risk 
of investing in transmission projects that will not ultimately provide 
value; (2) large transmission projects are often not the most economic, 
whereas smaller, targeted projects are more beneficial; and (3) there 
can and likely would be stranded transmission if transmission planning 
processes attempt to identify and meet transmission needs 20 to 30 
years in the future.\456\
---------------------------------------------------------------------------

    \455\ Potomac Economics Initial Comments at 4.
    \456\ Louisiana Commission Reply Comments at 13-14.
---------------------------------------------------------------------------

    182. US Chamber of Commerce argues that the Commission should 
ensure that any Long-Term Regional Transmission

[[Page 49318]]

Planning reforms do not perpetuate an irrational transmission buildout 
that undermines competitive advantages of domestic electricity rates. 
US Chamber of Commerce asserts that the loss of competitive advantage 
would lead to lost jobs, lost economic growth, decreased electricity 
use, and fixed system costs assessed to fewer customers.\457\
---------------------------------------------------------------------------

    \457\ US Chamber of Commerce Initial Comments at 8.
---------------------------------------------------------------------------

    183. Vistra states that the proposed reforms lean toward accounting 
for regulatory and public policy initiatives that may shape changes in 
the generation mix without sufficiently incorporating the commercial 
and markets-related aspects of generation development.\458\ Vistra 
states that, without a process to assess commercial interest and 
financial commitment from generation developers, long-term regional 
transmission plans may under- or over-build transmission facilities or 
build them in the wrong locations.\459\ Relatedly, NRECA states that 
planning a regional transmission network for generation resources or 
changes in demand not identified by load-serving entities' forecasts, 
and instead through unsupported top-down assumptions, may produce 
uneconomic results from over-building and increase reliability 
risks.\460\
---------------------------------------------------------------------------

    \458\ Vistra Initial Comments at 7.
    \459\ Id.
    \460\ NRECA Initial Comments at 18-19.
---------------------------------------------------------------------------

    184. NRG states that, in light of the uncertainty of variables such 
as the amount of electrification and resulting load requirements, 
technology costs for new resources, and viability and repurposing of 
existing resources, it is not clear whether a ``no regrets'' option 
genuinely exists. NRG also asserts that the centralized planning 
envisioned in the NOPR sacrifices the ability of market participants to 
use available information to assess whether their investments will be 
viable in the future, which is a critical feature of competition. NRG 
asserts that the Commission has not contemplated that trade-off or 
quantified its costs, noting that past long-term transmission planning 
studies have done a questionable job at forecasting future needs.\461\
---------------------------------------------------------------------------

    \461\ NRG Initial Comments at 8.
---------------------------------------------------------------------------

    185. Other commenters, however, note that the NOPR proposal 
includes measures that mitigate the uncertainty inherent in longer-term 
regional transmission planning.\462\ For example, New Jersey Commission 
states that the proposed requirements to develop multiple scenarios and 
perform reassessments mitigates the uncertainty inherently present in a 
20-year transmission planning horizon.\463\ Additionally, several 
commenters rebut opposition to Long-Term Regional Transmission Planning 
based on concerns that it presents unreasonable levels of 
uncertainty.\464\ For example, SREA and Clean Energy Buyers assert that 
periodic updates of forecasts and scenarios will help to mitigate 
uncertainty.\465\
---------------------------------------------------------------------------

    \462\ New Jersey Commission Initial Comments at 10-11; PIOs 
Initial Comments at 15-16.
    \463\ New Jersey Commission Initial Comments at 10-11.
    \464\ Clean Energy Buyers Reply Comments at 8; Policy Integrity 
Reply Comments at 2; SREA Reply Comments at 21-24.
    \465\ Clean Energy Buyers Reply Comments at 8; SREA Reply 
Comments at 23.
---------------------------------------------------------------------------

    186. Policy Integrity further explains that future uncertainty is 
exactly why long-term scenario planning is necessary to ensure just and 
reasonable rates. Policy Integrity states that the current transmission 
planning process uses deterministic modeling that does not account for 
the changing world, which will not lead to the development of efficient 
or cost-effective transmission solutions. Policy Integrity asserts 
that, in contrast, long-term scenario planning will allow transmission 
planners to be prepared for changes.\466\ Policy Integrity argues that 
any forward-looking decision will have a degree of uncertainty, but 
that the risk posed by uncertainty can be mitigated and managed by 
using a portfolio evaluation of costs and benefits.\467\ Policy 
Integrity further argues that ignoring the uncertainty surrounding the 
energy transition runs its own risk of failing to build transmission 
that can be useful to meet needs in the short, medium, and long 
term.\468\
---------------------------------------------------------------------------

    \466\ Policy Integrity Reply Comments at 2.
    \467\ Id. at 3-4.
    \468\ Id. at 4.
---------------------------------------------------------------------------

f. Concerns Regarding Incentives for Resource Development
    187. Vistra asserts that it is critical for Commission policy to 
maintain interconnection cost signals to drive cost-effective 
generation siting choices.\469\ Vistra also argues that a policy that 
assigns all interconnection-related network upgrade costs, or even a 
disproportionately high share, to load undermines the incentive that 
generation developers currently have to site new projects in locations 
that minimize the related transmission upgrade costs.\470\
---------------------------------------------------------------------------

    \469\ Vistra Initial Comments at 7.
    \470\ Id. at 7-8.
---------------------------------------------------------------------------

    188. In contrast, New Jersey Commission argues that requiring 
individual interconnecting generators to pay for piecemeal 
interconnection-related network upgrades does not necessarily encourage 
developers to make siting decisions that minimize the overall cost of 
integrating large amounts of new generation.\471\ Likewise, Clean 
Energy Associations state that robust, proactive regional transmission 
planning will better incent efficient siting decisions, because 
generators will evaluate the likely costs of interconnection facilities 
that ensure deliverability to the grid, rather than more broadly 
beneficial transmission facilities.\472\
---------------------------------------------------------------------------

    \471\ New Jersey Commission Reply Comments at 7.
    \472\ Clean Energy Associations Reply Comments at 9 (citing ACEG 
2021 Interconnection Report at 15).
---------------------------------------------------------------------------

g. Comments Regarding Definition of Long-Term Regional Transmission 
Facility
    189. PJM states that the Commission should clarify certain details 
of the NOPR proposal, including the meaning of the word ``identified'' 
in the proposed definition of Long-Term Regional Transmission 
Facility.\473\ In addition, PJM requests that the Commission clarify 
that if a transmission project shows up in several Long-Term Scenarios 
but is not selected until it reaches one of the shorter-term 
reliability and market efficiency transmission planning processes, that 
project would not be considered a Long-Term Regional Transmission 
Facility for selection and cost allocation purposes.\474\ Otherwise, 
PJM contends, the rules for selection and cost allocation for 
transmission projects selected in the shorter-term and intermediate-
term reliability and market efficiency transmission planning processes 
will be unclear, leading to re-litigation.\475\
---------------------------------------------------------------------------

    \473\ PJM Initial Comments at 8, 98.
    \474\ Id. at 99.
    \475\ Id. at 99, 101.
---------------------------------------------------------------------------

h. Challenges to Commission Jurisdiction or Authority
i. FPA Section 201
    190. Some commenters argue that the NOPR proposals exceed the 
Commission's jurisdiction or that the Commission otherwise lacks the 
authority to adopt a final order in this proceeding. Of these 
commenters, most contend that the NOPR proposal interferes with 
authority reserved to the states under FPA section 201.\476\
---------------------------------------------------------------------------

    \476\ Alabama Commission Initial Comments at 3-4, 7-8; Kansas 
Ratepayer Advocates Reply Comments at 2-3; Louisiana Commission 
Initial Comments at 5, 8-9, 27-28; Louisiana Commission Reply 
Comments at 14-15; Mississippi Commission Initial Comments at 3, 5-
6; Mississippi Commission Reply Comments at 2; Nevada Commission 
Initial Comments at 2-3, 6; SERTP Sponsors Initial Comments at 5, 
15-19 & n.20; SERTP Sponsors Reply Comments at 12-13; Southern 
Initial Comments at 3-8, 12-13, 15-24; Southern Reply Comments at 3, 
6-7; Utah Commission Initial Comments at 7-9; Undersigned States 
Reply Comments at 2, 4-5.

---------------------------------------------------------------------------

[[Page 49319]]

    191. Some commenters argue that the NOPR proposal intrudes on the 
authority reserved to the states under FPA section 201 over integrated 
resource planning processes or resource mix decision making.\477\ For 
example, Alabama Commission states that the NOPR proposal for Long-Term 
Regional Transmission Planning would intrude on state integrated 
resource planning to the extent that it dictates the construction of 
facilities through a top-down regional process or seeks to influence or 
mandate a substantive change to the generation resource mix.\478\ 
Similarly, Nevada Commission argues that the NOPR may impact states' 
authority to determine their own mix of generating resources. Nevada 
Commission contends that the NOPR may cross the line from regulating 
interstate transmission to regulating intrastate processes--
particularly because the Commission has not asserted jurisdiction over 
bundled retail transmission.\479\ Louisiana Commission argues that the 
Commission should not override state jurisdiction on resource planning, 
fuel type, and siting decisions, along with the regulation of retail 
rates.\480\
---------------------------------------------------------------------------

    \477\ Alabama Commission Initial Comments at 3-4, 7-8; Kansas 
Ratepayer Advocates Reply Comments at 2; Louisiana Commission 
Initial Comments at 8-9, 27-28; Louisiana Commission Reply Comments 
at 14-15; Mississippi Commission Initial Comments at 3 (citing NOPR, 
179 FERC ] 61,028 (Christie, Comm'r, concurring, at P 2)); Nevada 
Commission Initial Comments at 2-3; SERTP Sponsors Initial Comments 
at 5, 15-19 & n.20; SERTP Sponsors Reply Comments at 12-13; Southern 
Initial Comments at 3-8, 12-13, 15-24; Southern Reply Comments at 3, 
6-7; Utah Commission Initial Comments at 7-9; Undersigned States 
Reply Comments at 2, 4-5.
    \478\ Alabama Commission Initial Comments at 3-4, 7-8.
    \479\ Nevada Commission Initial Comments at 2-3.
    \480\ Louisiana Commission Initial Comments at 27-28; Louisiana 
Commission Reply Comments at 14-15.
---------------------------------------------------------------------------

    192. Mississippi Commission requests that the Commission 
acknowledge that it cannot force regional planning entities to 
indirectly act as a national integrated resource planner.\481\ SERTP 
Sponsors and Southern argue that the NOPR essentially constitutes a 
Commission-regulated integrated resource plan/request for proposal 
process and that, to be workable, Long-Term Regional Transmission 
Planning instead must be based on state commission-regulated integrated 
resource planning/request for proposal decisions.\482\ SERTP Sponsors 
and Southern contend that the NOPR proposed to require transmission 
providers to make independent resource and load decisions because: (1) 
state integrated resource plans are just one of many factors to be 
considered in developing Long-Term Scenarios; and (2) state integrated 
resource planning or request for proposal processes generally use a 10-
year planning horizon such that there are no state-approved resources 
for the second half of the NOPR's proposed 20-year transmission 
planning horizon.\483\ SERTP Sponsors and Southern further argue that, 
in upholding Order No. 1000, the D.C. Circuit emphasized that the 
Commission was regulating the transmission planning process and not 
mandating any particular outcome, and that, if the Commission 
prescribes a process that supplants state decision making, it will have 
crossed the line into prescribing substantive outcomes and thus 
exceeded its jurisdiction.\484\
---------------------------------------------------------------------------

    \481\ Mississippi Commission Initial Comments at 3 (citing NOPR, 
179 FERC ] 61,028 (Christie, Comm'r, concurring, at P 2)).
    \482\ SERTP Sponsors Initial Comments at 15-16; SERTP Sponsors 
Reply Comments at 12-13; Southern Initial Comments at 4-5, 7, 15-16; 
Southern Reply Comments at 6-7.
    \483\ SERTP Sponsors Initial Comments at 16; Southern Initial 
Comments at 12-13.
    \484\ SERTP Sponsors Initial Comments at 19; Southern Initial 
Comments at 23-24 (citing Order No. 1000, 136 FERC ] 61,051 at P 
154).
---------------------------------------------------------------------------

    193. Ohio Commission Federal Advocate contends that the NOPR 
appears designed to target the achievement of narrow environmental 
policy objectives or the socialization of transmission costs, not to 
ensure reliability or foster just and reasonable rates.\485\ Southern 
and Utah Commission state that the Commission has consistently 
recognized that the FPA does not allow the Commission to pick winners 
and losers when it comes to generation and argue that the Commission 
has no authority to favor one generation mix over another.\486\ 
Similarly, Louisiana Commission, Kansas Ratepayer Advocates, and 
Undersigned States contend that the Commission lacks the statutory 
authority to dictate states' generation resource decisions. They argue 
instead that each state possesses such authority and is uniquely 
qualified to choose the generation resources that are needed to 
economically meet ratepayers' electric service needs within their 
states.\487\
---------------------------------------------------------------------------

    \485\ Ohio Commission Federal Advocate Initial Comments at 4-6.
    \486\ Southern Initial Comments at 23 (citing ISO New England 
Inc., 162 FERC ] 61,205, at P 26 (2018)); Utah Commission Initial 
Comments at 7-9.
    \487\ Louisiana Commission Initial Comments at 8-10 (citing 
Monongahela Power Co., 40 FERC ] 61,256, at 61,861 (1987); Pac. Gas 
& Elec. Co. v. State Energy Res. Conservation & Dev. Comm'n, 461 
U.S. 190, 212 (1983)); Kansas Ratepayer Advocates Reply Comments at 
2; Undersigned States Reply Comments at 2, 4-5 (citing Pac. Gas & 
Elec. Co. v. State Energy Res. Conservation & Dev. Comm'n, 461 U.S. 
at 205).
---------------------------------------------------------------------------

    194. SERTP Sponsors and Southern argue that, even if assumptions 
about the resource mix included in Long-Term Scenarios do not bind 
states, requiring transmission providers to develop Long-Term Scenarios 
that are predicated on particular resource assumptions effectively 
makes a substantive resource decision because it favors the assumed 
resource mix over others.\488\ SERTP Sponsors and Southern contend that 
this is akin to the Commission attempting to accomplish indirectly what 
it could not directly.\489\ SERTP Sponsors argue that the Commission 
should support the exercise of traditional state resource and 
infrastructure planning authority rather than supplant it.\490\ North 
Carolina Commission and Staff argue that the use of the production cost 
savings benefit in Long-Term Regional Transmission Planning ``could 
conflict with state-jurisdictional resource decisions.'' \491\
---------------------------------------------------------------------------

    \488\ SERTP Sponsors Initial Comments at 17 n.20; Southern 
Initial Comments at 19.
    \489\ SERTP Sponsors Initial Comments at 17 n.20; Southern 
Initial Comments at 18.
    \490\ SERTP Sponsors Initial Comments at 17, 19; see also 
Undersigned States Reply Comments at 5, 8 (citing Am. Gas Ass'n v. 
FERC, 912 F.2d 1496, 1510 (D.C. Cir. 1990)).
    \491\ North Carolina Commission and Staff Initial Comments at 7.
---------------------------------------------------------------------------

    195. Other commenters disagree with these contentions and argue 
that the NOPR proposal would not intrude on states' reserved authority 
over resource mix decision making or integrated resource plan 
processes.\492\ Kentucky Commission Chair Chandler and SEIA argue that 
the NOPR's stated aim of reforming regional and interregional 
transmission planning processes does not foreclose states' decision 
making on generation.\493\ ACEG contends that the NOPR does not propose 
or purport to regulate the electric supply mix and that the Commission 
is acting squarely within its authority under the FPA's cooperative 
federalism structure.\494\ AEE notes that the Commission included 
integrated resource planning and utility load-serving planning as a 
factor driving transmission needs and argues that none of the 
requirements proposed by the Commission directly conflict with

[[Page 49320]]

integrated resource planning processes, require that integrated 
resource planning be conducted on a different timeline, or override 
resource planning efforts.\495\ Likewise, Kentucky Commission Chair 
Chandler reiterates that Kentucky's integrated resource plans are not 
driving transmission planning processes in the state. He explains that 
integrated resource plans/requests for proposals are not the basis for 
generation investment decisions, but the state's requests for proposals 
seek generation proposals after the integrated resource planning 
process is complete and a need for generation is identified.\496\ In 
response to Alabama Commission's arguments that the NOPR's proposed 
rules have the potential to encroach on state-jurisdictional integrated 
resource planning and resource procurement processes overseen by 
Alabama Commission, SREA contends that Alabama Commission in fact does 
not have a formal integrated resource planning process upon which the 
Commission could encroach.\497\
---------------------------------------------------------------------------

    \492\ ACEG Reply Comments at 15; AEE Reply Comments at 23; New 
Jersey Commission Reply Comments at 2; Kentucky Commission Chair 
Chandler Reply Comments at 3; SEIA Reply Comments at 2-3.
    \493\ Kentucky Commission Chair Chandler Reply Comments at 3; 
SEIA Reply Comments at 2-3.
    \494\ ACEG Reply Comments at 15.
    \495\ AEE Reply Comments at 23.
    \496\ Kentucky Commission Chair Chandler Reply Comments at 6.
    \497\ SREA Reply Comments at 2-3.
---------------------------------------------------------------------------

    196. New Jersey Commission disagrees with commenters who argue that 
the Commission intends to impose a preferred resource mix on the Nation 
by overriding state choices and contends that such arguments are 
``profoundly misconstruing'' the nature of the NOPR proposal and what 
the Commission aims to achieve.\498\ Instead, New Jersey Commission 
argues that Long-Term Regional Transmission Planning would address 
transmission needs that are being driven by state policies, market 
decisions, and technological changes, all of which reflect consumer-
driven demand for cleaner electricity.\499\ New Jersey Commission 
contends that the NOPR proposal would ensure that transmission needs 
are reliably met at a total cost that is just and reasonable, which New 
Jersey Commission argues is required--not precluded--by the FPA.\500\
---------------------------------------------------------------------------

    \498\ New Jersey Commission Reply Comments at 1-2.
    \499\ Id. at 2.
    \500\ Id.
---------------------------------------------------------------------------

    197. Some commenters argue that the NOPR proposal would intrude on 
authority over siting and construction of transmission facilities that 
is reserved to the states under FPA section 201.\501\ For example, 
Southern argues that the FPA reserves transmission siting authority to 
the states and that the final order should not directly or indirectly 
interfere with this authority.\502\ Alabama Commission argues that 
Long-Term Regional Transmission Planning would interfere with state 
authority to the extent it dictates the construction of facilities 
through a top-down regional process.\503\ Kansas Ratepayer Advocates 
state that the Commission would exceed its authority and violate 
states' constitutional rights by ordering states to construct 
interregional transmission facilities with construction costs paid by 
retail ratepayers in Kansas.\504\
---------------------------------------------------------------------------

    \501\ Alabama Commission Initial Comments at 7; Kansas Ratepayer 
Advocates Reply Comments at 3; NARUC Initial Comments at 29; Nevada 
Commission Initial Comments at 2-3; Southern Initial Comments at 21-
22.
    \502\ Southern Initial Comments at 21-22.
    \503\ Alabama Commission Initial Comments at 7.
    \504\ Kansas Ratepayer Advocates Reply Comments at 3.
---------------------------------------------------------------------------

    198. Nevada Commission explains that Nevada law governs the 
issuance of permits to construct transmission facilities, and that such 
facilities--even where their costs are not intended to be recovered 
through retail rates--must go through and may not bypass that process 
in favor of regional transmission planning processes.\505\ NARUC 
contends that state participation in cost allocation for a portfolio of 
Long-Term Regional Transmission Facilities does not require a state, in 
its role as a transmission siting authority, to approve any projects 
within the portfolio.\506\
---------------------------------------------------------------------------

    \505\ Nevada Commission Initial Comments at 2-3.
    \506\ NARUC Initial Comments at 29.
---------------------------------------------------------------------------

    199. A few commenters argue that the NOPR proposal would intrude on 
the authority over certain transmission planning allegedly reserved to 
the states under FPA section 201. For example, Mississippi Commission 
states that the final order must respect state jurisdictional authority 
over planning and approval of transmission facilities used to serve 
state load.\507\ Nevada Commission states that Nevada will continue to 
plan for transmission through its integrated resource planning process 
and that the Commission should allow ``bottom up'' transmission 
planning, particularly in non-RTO/ISO transmission planning 
regions.\508\
---------------------------------------------------------------------------

    \507\ Mississippi Commission Initial Comments at 5 (citing 
Mississippi Commission ANOPR Comments at 2, 17; NOPR, 179 FERC ] 
61,028 (Christie, Comm'r, concurring at PP 2, 11-14)).
    \508\ Nevada Commission Initial Comments at 6.
---------------------------------------------------------------------------

    200. In contrast, other commenters express support for the 
Commission's role in transmission planning. Ohio Consumers argue that 
the Commission has authority over transmission planning, even in states 
like Ohio that allow for retail consumer choice.\509\ SREA explains 
that states and other jurisdictional regulators will continue to have 
ultimate control over generation resource planning and transmission 
planning, regardless of what a regional transmission body proposes. 
SREA states that, even within RTO/ISO regions, ``transmission or 
generation resource plans are subject to review, update or even 
cancellation, and those decisions are always determined by the relevant 
regulatory bodies.'' \510\ Vistra states that any final order should 
recognize the legal and practical boundaries on the Commission's role 
in transmission development and in shaping the generation sector. 
According to Vistra, the Commission has successfully relied on its 
general authority under FPA sections 205 and 206 to oversee rates, 
terms, and conditions of jurisdictional service as the basis for its 
policies on transmission planning.\511\
---------------------------------------------------------------------------

    \509\ Ohio Consumers Initial Comments at 26 (citing New York v. 
FERC, 535 U.S. at 23-24, 26-28).
    \510\ SREA Reply Comments at 1-2.
    \511\ Vistra Initial Comments at 4 & n.6.
---------------------------------------------------------------------------

    201. Finally, Mississippi Commission argues that the NOPR proposal 
may infringe upon states' reserved authority under FPA section 201 to 
make resource adequacy decisions. Mississippi Commission explains that, 
when an RTO/ISO approves construction to deliver generation output to 
remote utilities that have failed to agree to purchase the energy, that 
RTO/ISO infringes on the state's resource adequacy jurisdiction.\512\ 
Mississippi Commission contends that requiring State A to pay for 
transmission upgrades to rely on energy generated in State B, despite 
State A having constructed its own generation facilities, would usurp 
State A's resource adequacy jurisdiction.\513\
---------------------------------------------------------------------------

    \512\ Mississippi Commission Initial Comments at 5-6.
    \513\ Id. at 13.
---------------------------------------------------------------------------

ii. ``Major Questions Doctrine''
    202. Some commenters argue that the NOPR proposal would not 
withstand judicial review under the major questions doctrine.\514\
---------------------------------------------------------------------------

    \514\ Louisiana Commission Initial Comments at 6, 12-13; Ohio 
Consumers Reply Comments at 14; SERTP Sponsors Initial Comments at 
17-18; Southern Initial Comments at 20-21; Utah Commission Initial 
Comments at 8-9; Undersigned States Reply Comments at 3-4.
---------------------------------------------------------------------------

    203. Louisiana Commission claims that the NOPR proposal violates 
principles of ``agency law'' and the separation of powers doctrine 
because Congress has not clearly delegated to the Commission the 
authority to enact far-reaching, nationwide policy changes favoring one 
form of generation over another.\515\ Louisiana Commission

[[Page 49321]]

contends that the NOPR proposals exceed the limits of the FPA, which 
does not provide clear delegated authority for the Commission to decide 
types of generating resources. Louisiana Commission argues that the 
Commission therefore lacks the authority to determine whether the 
country should undergo a clean energy transition. Drawing parallels 
between the NOPR proposal and the U.S. Supreme Court's decision in West 
Virginia v. EPA, Louisiana Commission avers that the determination of 
what type of generating resources should be transmitted from where in 
the United States qualifies as a ``major question'' of public policy 
that Congress should order.\516\
---------------------------------------------------------------------------

    \515\ Louisiana Commission Initial Comments at 6.
    \516\ Id. at 12 (citing 597 U.S. 697, 729-30, 735).
---------------------------------------------------------------------------

    204. SERTP Sponsors argue that West Virginia v. EPA reinforces the 
need for the Commission to exercise restraint in expanding its 
jurisdiction without a clear Congressional delegation of 
authority.\517\ According to SERTP Sponsors, West Virginia v. EPA makes 
clear that the Nation's energy policy and generation mix is a ``major 
question'' for which the Commission must have direct authorization from 
Congress to assert jurisdiction.\518\ SERTP Sponsors contend that 
Congress has not clearly provided the Commission with jurisdiction to 
presuppose generation decisions and thereby effect particular 
substantive transmission outcomes.\519\ Rather, SERTP Sponsors argue 
that Congress instead expressly and unequivocally reserved generation 
authority to the states.\520\
---------------------------------------------------------------------------

    \517\ SERTP Sponsors Initial Comments at 17 (citing West 
Virginia v. EPA, 597 U.S. at 723); see also EEI Initial Comments at 
8 (urging the Commission to consider the overlap of the Commission's 
and state commissions' respective jurisdictions).
    \518\ SERTP Sponsors Initial Comments at 17-18.
    \519\ Id. at 18.
    \520\ Id.
---------------------------------------------------------------------------

    205. Southern similarly argues that West Virginia v. EPA makes 
clear that the Nation's energy policy and generation mix is a ``major 
question'' that requires more than a ``merely plausible textual basis'' 
for a Federal agency to assert jurisdiction.\521\ Southern contends 
that, as applied to the NOPR proposal's ``contemplated foray into 
[integrated resource planning] and generation/resource matters,'' the 
Commission does not rely upon a specific and clear grant of 
congressional authorization but instead relies upon its ``general, gap-
filling authorization in FPA Section 206 to regulate a `practice' 
affecting a rate or charge for transmission.'' \522\ Southern contends 
that rather than provide clear congressional authorization, Congress 
instead reserved authority over integrated resource plans and 
generation to the states.\523\
---------------------------------------------------------------------------

    \521\ Southern Initial Comments at 20-21 (citing West Virginia 
v. EPA, 597 U.S. at 723).
    \522\ Id.
    \523\ Id. at 21.
---------------------------------------------------------------------------

    206. Utah Commission argues that the Commission has no authority to 
enact any rule for the purpose of influencing the resource generation 
mix or expanding development of any type of generation. Utah Commission 
states that the increased development and integration of renewable 
generation is a ``highly charged political question and a matter of 
significant political interest about which state legislatures have made 
very different policy choices.'' As such, Utah Commission argues that, 
although courts have given the Commission ``some latitude under FPA 
Section 206,'' the U.S. Supreme Court will not uphold a final order 
premised upon the Commission's ``claimed authority to prescribe a 
single, onerous national regime for transmission planning specifically 
intended to pressure transmission providers to select costly expansions 
into remote areas for the purpose of realizing [the Commission's] 
preferred generation mix, a matter specifically reserved to the 
states.'' \524\ Utah Commission explains that the Supreme Court's 
reasoning in West Virginia v. EPA is applicable to the Commission. Utah 
Commission argues that ``imposing a single set of federally mandated, 
highly prescriptive transmission planning and cost allocation 
requirements for the purpose of privileging the selection of costly 
transmission projects to serve remote and speculative renewable 
generation is not a lawful exercise of [the Commission's] authority 
under FPA Section 206.'' \525\
---------------------------------------------------------------------------

    \524\ Utah Commission Initial Comments at 8.
    \525\ Id. at 8-9 (citing West Virginia v. EPA, 597 U.S. at 729-
30).
---------------------------------------------------------------------------

    207. Undersigned States argue that ``[n]ational-scale energy grid 
regulation'' is a ``major question'' because of the ``massive economic 
consequences'' involved and the implication of a ``unique and complex 
jurisdictional divide between [s]tate and federal regulatory 
authority.'' \526\ According to Undersigned States, the Commission 
``has no statutory authority at all--much less `clear congressional 
authorization'--to revamp the energy grid's mix of generation resources 
writ large.'' \527\
---------------------------------------------------------------------------

    \526\ Undersigned States Reply Comments at 3 (citing West 
Virginia v. EPA, 597 U.S. 697; Ala. Ass'n of Realtors v. HHS, 594 
U.S. 758, 764 (2021)).
    \527\ Id. at 4 (quoting West Virginia v. EPA, 597 U.S. at 723).
---------------------------------------------------------------------------

    208. Harvard ELI and Policy Integrity disagree with Undersigned 
States. They argue that Undersigned States ``mischaracterize the NOPR'' 
because the NOPR would not revamp the energy grid's mix of generation 
resources. Rather, according to Harvard ELI and Policy Integrity, the 
NOPR would require utilities to amend their existing regional 
transmission planning processes in response to changes in the resource 
mix and demand that are occurring because of factors unrelated to the 
NOPR.\528\
---------------------------------------------------------------------------

    \528\ Harvard ELI and Policy Integrity Supplemental Comments at 
2.
---------------------------------------------------------------------------

    209. Harvard ELI and Policy Integrity also contend that Undersigned 
States overlook the major questions doctrine's key requirements. They 
assert that application of the major questions doctrine does not turn 
on whether a regulation will have significant economic effects or 
intrudes on areas traditionally regulated by states. Instead, Harvard 
ELI and Policy Integrity assert that the major questions doctrine is 
triggered only when an agency's action is both unheralded and 
transformative.\529\
---------------------------------------------------------------------------

    \529\ Id. at 2-3.
---------------------------------------------------------------------------

    210. Harvard ELI and Policy Integrity argue that the NOPR is not 
unheralded. They explain that Order No. 1000 similarly regulated 
transmission planning and cost allocation in response to concerns about 
the generation mix, and that the D.C. Circuit upheld Order No. 1000 
while rejecting arguments similar to those that Undersigned States make 
here.\530\ Moreover, Harvard ELI and Policy Integrity identify 
provisions in existing tariffs that are similar to those that the NOPR 
proposes and point to other antecedents for Commission regulation of 
regional transmission planning.\531\
---------------------------------------------------------------------------

    \530\ Id. at 4 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 
at 48-49; Order No. 1000, 136 FERC ] 61,051 at PP 45, 47).
    \531\ Id. at 4-5; id. app. A.
---------------------------------------------------------------------------

    211. Likewise, Harvard ELI and Policy Integrity argue that the NOPR 
does not represent a transformative expansion in the Commission's 
authority nor a ``fundamental change to the statutory scheme.'' \532\ 
Instead, they assert that the NOPR merely builds on existing regional 
transmission planning processes to ensure that Commission-
jurisdictional rates remain just and reasonable, as the FPA 
requires.\533\
---------------------------------------------------------------------------

    \532\ Id. at 6-7 (quoting West Virginia v. EPA, 597 U.S. at 723 
(internal quotations omitted)).
    \533\ Id.

---------------------------------------------------------------------------

[[Page 49322]]

iii. ``Equal Sovereignty Doctrine''/Cross-Subsidization
    212. Some commenters argue that the NOPR's cost allocation proposal 
impermissibly requires states to subsidize other states' public 
policies.\534\ Undersigned States argue that the NOPR would exceed the 
Commission's jurisdiction because it violates the Constitution's equal 
sovereignty doctrine, which provides constitutional equality among the 
states.\535\ According to Undersigned States, the NOPR ``sets up a 
scheme where one [s]tate can effectively require other [s]tates to 
subsidize their own vision of what resources should be used in 
electricity generation--a core, sovereign [s]tate function,'' which 
risks ``undue discrimination'' among states.\536\ Mississippi 
Commission argues that unanimous agreement, rather than majority 
agreement, would be required for any ex ante default cost allocation 
method, as each state has sole jurisdiction within its boundaries.\537\
---------------------------------------------------------------------------

    \534\ Alabama Commission Initial Comments at 9; Louisiana 
Commission Initial Comments at 29; Mississippi Commission Reply 
Comments at 3; Ohio Commission Federal Advocate Initial Comments at 
4-5; Ohio Consumers Reply Comments at 14.
    \535\ Undersigned States Reply Comments at 5-6 (citing Coyle v. 
Smith, 221 U.S. 559, 567 (1911)).
    \536\ Id. at 6 (citing NOPR, 179 FERC ] 61,018, Danly, Comm'r, 
dissenting, at PP 4-5).
    \537\ Mississippi Commission Reply Comments at 2-3.
---------------------------------------------------------------------------

    213. Louisiana Commission asserts that ``group state oversight'' is 
not equivalent to ``state oversight,'' and that the Commission should 
not adopt a rule that subjects one state's will to majority override. 
Louisiana Commission further argues that the Commission should not 
enact rules that would ``impose costs for projects selected under the 
proposed long-term planning criteria on unwilling states that do not 
benefit from those projects, even if those states are in the 
minority.'' Louisiana Commission contends that the Commission should 
not attempt to override state jurisdiction simply because a majority of 
states in a region may support imposing costs on unwilling states that 
do not benefit from transmission projects favored by the majority.\538\ 
Louisiana Commission argues that states should not be required to cede 
their jurisdiction by engaging in any ``consulting'' committee 
structure required with respect to Long-Term Regional Transmission 
Planning,\539\ because granting each state one vote in a multi-state 
body cannot replace the meaningful exercise of state jurisdiction 
within a state's borders.\540\
---------------------------------------------------------------------------

    \538\ Louisiana Commission Initial Comments at 27-28; Louisiana 
Commission Reply Comments at 14-16.
    \539\ Louisiana Commission Initial Comments at 28-29.
    \540\ Louisiana Commission Reply Comments at 16.
---------------------------------------------------------------------------

    214. Conversely, ACEG disputes these claims, which ACEG states are 
``incorrect and misconstrue the NOPR.'' \541\ ACEG highlights the fact 
that the NOPR does not include resource preferences in its proposed 
planning criteria, factors, or benefits, nor does the NOPR exclude 
consideration of non-renewable resources from transmission 
planning.\542\ ACEG further notes that the NOPR proposes to direct 
transmission planners to plan the system to ``meet transmission needs 
driven by changes in the resource mix and demand,'' requiring 
transmission planners to consider the resource mix as a whole, which 
necessarily requires considering all types of resources.\543\ New 
Jersey Commission agrees, stating that the Commission did not propose 
in the NOPR ``to unduly favor, mandate, or subsidize forms of 
generation,'' but rather ``to ensure that the bulk electricity system 
maintains reliability and satisfies evolving consumer demands, whether 
driven by public policy requirements or voluntary goals, at the lowest 
reasonable cost.'' \544\ Moreover, New Jersey Commission argues, 
allocating the cost of Long-Term Regional Transmission Facilities only 
to those states with relevant public policy goals ``would allow the 
remaining states to free ride, and effectively force the states with 
public policy goals to subsidize the provision of normal electricity 
service in other states in order to pursue their own policies.'' \545\
---------------------------------------------------------------------------

    \541\ ACEG Reply Comments at 18.
    \542\ Id. at 18-19.
    \543\ Id. at 19.
    \544\ New Jersey Commission Initial Comments at 3.
    \545\ Id. at 20.
---------------------------------------------------------------------------

i. Other Issues
    215. NRECA requests that the Commission clarify that the final 
order, consistent with the Commission's obligation under FPA section 
217(b)(4), ``is intended to facilitate and support `bottom-up' 
transmission planning to meet the transmission needs of [load-serving 
entities] to provide reliable and economical service to consumers.'' 
\546\
---------------------------------------------------------------------------

    \546\ NRECA Initial Comments at 17-21.
---------------------------------------------------------------------------

    216. Some commenters argue that the final order will not withstand 
judicial scrutiny if it does not permit regional flexibility.\547\ For 
example, US Chamber of Commerce explains that the interstate power grid 
includes investor-owned utilities, publicly-owned utilities, and 
electric cooperatives, which can be members of RTOs/ISOs, power pooling 
arrangements, joint-ownership agreements, or subject to traditional 
vertically-integrated structures.\548\ According to US Chamber of 
Commerce, imposing a new regional transmission planning regime on all 
these various entities would ignore the compromises and benefits that 
led to the status quo.\549\ Relatedly, Southern and SERTP Sponsors 
argue that the legal viability of the final order will be threatened if 
the Commission fails to respect the FPA's fundamental jurisdictional 
roles by not providing states and transmission providers with the 
opportunity and flexibility to adapt their planning processes.\550\
---------------------------------------------------------------------------

    \547\ SERTP Sponsors Initial Comments at 1; SERTP Sponsors Reply 
Comments at 1-2; Southern Initial Comments at 1; Southern Reply 
Comments at 3; US Chamber of Commerce Initial Comments at 4.
    \548\ US Chamber of Commerce Initial Comments at 4.
    \549\ Id.
    \550\ Southern Initial Comments at 1; Southern Reply Comments at 
3; SERTP Sponsors Initial Comments at 1; SERTP Sponsors Reply 
Comments at 1-2.
---------------------------------------------------------------------------

j. Miscellaneous Concerns
    217. MISO seeks clarification from the Commission that the term 
``transmission planning region'' has the same meaning as in Order No. 
1000, where MISO may comprise a single transmission planning region 
despite including multiple transmission zones or local balancing 
authorities.\551\
---------------------------------------------------------------------------

    \551\ MISO Initial Comments at 24.
---------------------------------------------------------------------------

    218. California Municipal Utilities state that transmission 
planning should not be a vehicle to centralize resource choices, but 
instead should reflect the choices made by state and local 
authorities.\552\ Similarly, Mississippi Commission argues that Long-
Term Regional Transmission Planning should be driven by state-specific 
concerns and needs and that regional priorities should be subordinated 
to state priorities.\553\ Mississippi Commission asks that the 
Commission not issue a final order but instead establish proceedings to 
address specific concerns with certain regional transmission planning 
processes on a more limited basis.\554\ Southern argues that Long-Term 
Regional Transmission Facilities in non-RTO/ISO transmission planning 
regions must have the support of affected states, as these facilities 
stem from resource and load assumptions that are not the result of 
those states' planning and procurement processes.\555\ Southern urges 
the Commission to maintain the appropriate transmission

[[Page 49323]]

planning and state-driven supply- and demand-side relationships, which 
Order No. 1000 preserved.\556\ SERTP Sponsors argue that the Commission 
should avoid mandates that could largely result in transmission 
expansion or infrastructure decisions that lead to investments borne, 
largely, by retail electricity consumers that lack the consent and 
support of the state authorities vested with the responsibility to 
protect those consumers.\557\
---------------------------------------------------------------------------

    \552\ California Municipal Utilities Reply Comments at 2.
    \553\ Mississippi Commission Initial Comments at 3.
    \554\ Id. at 9.
    \555\ Southern Initial Comments at 8.
    \556\ Id. at 12.
    \557\ SERTP Sponsors Initial Comments at 6-7.
---------------------------------------------------------------------------

    219. Several commenters agree with the Commission that any final 
order should apply to transmission providers in both RTO/ISO and non-
RTO/ISO transmission planning regions.\558\ However, several commenters 
disagree and argue that the final order, or certain specified 
requirements in the final order, should apply only to RTO/ISO 
transmission planning regions.\559\ Nevada Commission argues that the 
RTOs/ISOs ``may be better suited'' than other regions for the 
transmission planning that the NOPR proposes.\560\ Utah Division of 
Public Utilities stresses the need for regional flexibility, noting 
that transmission providers located outside of RTOs/ISOs already 
coordinate on transmission planning with many non-Commission-
jurisdictional entities.\561\
---------------------------------------------------------------------------

    \558\ See, e.g., AEE Reply Comments at 11; MISO Reply Comments 
at 3; PIOs Reply Comments at 2-3; SEIA Reply Comments at 5; SREA 
Initial Comments at 47; TAPS Initial Comments at 70.
    \559\ See, e.g., Mississippi Commission Initial Comments at 16; 
Utah Division of Public Utilities Reply Comments at 1-2.
    \560\ Nevada Commission Initial Comments at 2-4.
    \561\ Utah Division of Public Utilities Reply Comments at 1-2.
---------------------------------------------------------------------------

    220. SEIA rebuts the claims of Southern and Louisiana, Utah, 
Mississippi, and Alabama Commissions that state planning processes 
already interact well with transmission planning and support customers' 
transmission needs.\562\ SEIA and SREA assert that non-RTO/ISO 
transmission planning regions do not engage in sufficient or 
transparent transmission planning.\563\ Specifically, SEIA states, the 
transmission planning processes in non-RTO/ISO regions are rife with 
issues, including the use of inconsistent and inaccurate data and an 
exclusionary and insufficiently transparent process.\564\ Further, SEIA 
states that the end result of an integrated resource planning process 
may be based on inconsistent and inaccurate data,\565\ the process is 
``sometimes disjointed,'' \566\ and the process is a voluntary process 
in which the planning authority must accept, and not verify, the 
information provided.\567\
---------------------------------------------------------------------------

    \562\ SEIA Reply Comments at 5.
    \563\ Id.; SREA Reply Comments at 15-17.
    \564\ SEIA Reply Comments at 5-6.
    \565\ Id. at 5 (citing Western PIOs Initial Comments at 10).
    \566\ Id. (citing PacifiCorp and NV Energy Initial Comments at 
10).
    \567\ Id. (citing PacifiCorp and NV Energy Initial Comments at 
13; Western PIOs Initial Comments at 11).
---------------------------------------------------------------------------

    221. SREA rebuts Southern's contention that Southern's transmission 
planning processes are adequate, noting that Southern itself has 
presented testimony to the Georgia Commission conceding that it is 
unable to perform more robust transmission planning due to limitations 
in its software and models.\568\ SREA argues that throughout the 
Southeast, transmission planning is not a priority and that integrated 
resource planning is not a substitute for robust transmission 
planning.\569\ SREA explains that the NOPR borrows many of the 
qualities of integrated resource planning and applies them to 
transmission planning, including scenario-based evaluation and use of 
20-year planning horizons, and that many states have integrated 
resource planning rules and guidelines that recognize the value of 
long-term planning.\570\
---------------------------------------------------------------------------

    \568\ SREA Reply Comments at 7 (citing SREA Initial Comments, 
attach. B (Testimony of Georgia Power Witness Robinson) at 282-283).
    \569\ Id. at 5.
    \570\ Id.
---------------------------------------------------------------------------

    222. EPSA states that the Commission should focus not on 
socializing transmission costs but on reducing transaction costs, 
accelerating lagging processes, and adopting market-based solutions 
like open seasons.\571\
---------------------------------------------------------------------------

    \571\ EPSA Initial Comments at 7-8.
---------------------------------------------------------------------------

    223. GridLab states that there is evidence to suggest that changes 
in resource mix, demand, and weather will lead to significant changes 
in the value of regional transmission facilities in the 2030s, though 
GridLab asserts that these changes may increase or decrease the value 
of regional transmission facilities. Accordingly, GridLab recommends 
that the Commission and stakeholders resist evaluating the success of 
this rulemaking based on arbitrary metrics related to each transmission 
provider's expansion of regional transmission facilities.\572\
---------------------------------------------------------------------------

    \572\ GridLab Initial Comments at 9-10.
---------------------------------------------------------------------------

3. Commission Determination
a. Participation in Long-Term Regional Transmission Planning
    224. We adopt the NOPR proposal to require transmission providers 
in each transmission planning region to participate in a regional 
transmission planning process that includes Long-Term Regional 
Transmission Planning, meaning regional transmission planning on a 
sufficiently long-term, forward-looking, and comprehensive basis to 
identify Long-Term Transmission Needs, identify transmission facilities 
that meet such needs, measure the benefits of those transmission 
facilities, and evaluate those transmission facilities for potential 
selection in the regional transmission plan for purposes of cost 
allocation as the more efficient or cost-effective transmission 
facilities to meet Long-Term Transmission Needs.\573\ We also adopt the 
NOPR proposal to require that Long-Term Regional Transmission Planning 
comply with the following existing Order Nos. 890 and 1000 transmission 
planning principles: (1) coordination; (2) openness; (3) transparency; 
(4) information exchange; (5) comparability; and (6) dispute 
resolution.\574\ In developing their compliance filings, transmission 
providers and stakeholders should review the requirements set forth in 
Order No. 890 and Order No. 1000, and the Commission's orders on 
compliance filings submitted by transmission providers, for guidance as 
to what each of these transmission planning principles requires. For 
example, as a starting point, a transmission provider should review the 
orders addressing its own Order Nos. 890 and 1000 compliance filings 
and the compliance filings for transmission providers in its 
transmission planning region.
---------------------------------------------------------------------------

    \573\ We note that, while we have modified this definition of 
Long-Term Regional Transmission Planning from the NOPR proposal, the 
modified definition does not substantively change the steps involved 
in Long-Term Regional Transmission Planning from those proposed in 
the NOPR. Rather, the revised definition merely clariies the steps 
that transmission providers must take in conducting Long-Term 
Regional Transmission Planning.
    \574\ Order No. 1000, 136 FERC ] 61,051 at PP 146, 151. We do 
not address these principles in detail here.
---------------------------------------------------------------------------

    225. We also adopt specific requirements regarding how transmission 
providers must conduct Long-Term Regional Transmission Planning. 
Specifically, and as discussed further below, we require transmission 
providers in each transmission planning region \575\ to: (1) identify 
Long-Term

[[Page 49324]]

Transmission Needs and Long-Term Regional Transmission Facilities to 
meet those needs through the development of Long-Term Scenarios \576\ 
that satisfy the requirements set forth in this final order; (2) use 
and measure, at a minimum, a set of seven required benefits \577\ to 
evaluate Long-Term Regional Transmission Facilities over a time horizon 
that covers, at a minimum, 20 years starting from the estimated in-
service date of each transmission facility; and (3) evaluate Long-Term 
Regional Transmission Facilities to determine whether they are more 
efficient or cost-effective transmission solutions to meet Long-Term 
Transmission Needs and use selection criteria (in collaboration with 
states and other stakeholders) that provide the opportunity for 
transmission providers to select such Long-Term Regional Transmission 
Facilities.
---------------------------------------------------------------------------

    \575\ In response to MISO's request, MISO Initial Comments at 
24, we clarify that this final order does not alter the meaning of 
``transmission planning region'' as used in Order No. 1000. A 
transmission planning region is one in which transmission providers, 
in consultation with stakeholders and affected states, have agreed 
to participate for purposes of regional transmission planning and 
development of a single regional transmission plan. Order No. 1000-
A, 139 FERC ] 61,132 at P 272; Order No. 1000, 136 FERC ] 61,051 at 
P 160.
    \576\ The requirements related to Long-Term Scenarios are 
discussed below.
    \577\ As discussed further below in the Evaluation of the 
Benefits of Regional Transmission Facilities section, these seven 
benefits are: (1) Benefit 1, Avoided or Deferred Reliability 
Transmission Facilities and Aging Transmission Infrastructure 
Replacement; (2) Benefit 2(a), Reduced Loss of Load Probability, or 
Benefit 2(b), Reduced Planning Reserve Margin; (3) Benefit 3, 
Production Cost Savings; (4) Benefit 4, Reduced Transmission Energy 
Losses; (5) Benefit 5, Reduced Congestion Due to Transmission 
Outages; (6) Mitigation of Extreme Weather Events and Unexpected 
System Conditions; and (7) Capacity Cost Benefits from Reduced Peak 
Energy Losses.
---------------------------------------------------------------------------

    226. These requirements together establish a long-term, forward-
looking, and more comprehensive approach to regional transmission 
planning, which will ensure that transmission providers identify, 
evaluate, and select more efficient or cost-effective transmission 
solutions to address Long-Term Transmission Needs. Long-Term Regional 
Transmission Planning, as set forth in this final order, requires 
regional transmission planning based on a multitude of drivers of Long-
Term Transmission Needs and provides the opportunity for transmission 
providers to meet those needs by selecting more efficient or cost-
effective Long-Term Regional Transmission Facilities.
    227. In considering the comments received on this proposal, we 
strike a careful balance. On the one hand, we believe that there is an 
inherent risk in transmission providers waiting for the near-term 
certainty that some commenters appear to believe is necessary \578\ 
before planning to address transmission needs. As explained in the 
Overall Need for Reform section above, doing so may result in 
transmission providers relying on relatively inefficient and less cost-
effective piecemeal transmission solutions to address these needs 
shortly before they manifest, to the detriment of customers. On the 
other hand, we acknowledge the inherent uncertainty involved in 
planning to meet Long-Term Transmission Needs and that this uncertainty 
means that forward-looking regional transmission planning entails 
certain risks, including the risk that transmission needs may change 
over time. In this final order, we balance these risks, requiring 
planning to meet Long-Term Transmission Needs, while imposing 
requirements on how Long-Term Regional Transmission Planning is 
conducted, as discussed further herein, to mitigate uncertainty. To 
adequately prepare for the future, transmission providers need to make 
decisions in the present that are grounded in a thorough, informed 
analysis of the factors that drive Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \578\ See, e.g., NRG Initial Comments at 8 (arguing that there 
are unliekly to be any ``no regrets'' options).
---------------------------------------------------------------------------

    228. As discussed in the Overall Need for Reform section, these 
factors are together driving rapid changes in the Long-Term 
Transmission Needs that transmission providers must plan to meet to 
continue to provide an affordable, reliable supply of electricity to 
customers, but neither transmission infrastructure nor regional 
transmission planning processes are keeping pace. Consequently, the 
Commission's existing regional transmission planning requirements are 
no longer just and reasonable, as they increasingly result in 
transmission investment decisions occurring outside of regional 
transmission planning processes and instead through generator 
interconnection processes and local transmission planning processes 
that typically plan to meet discrete, nearer-term transmission needs. 
In addition, the record demonstrates that transmission providers have 
made substantial investments in in-kind replacement transmission 
facilities, which generally are not identified through more long-term, 
forward-looking, or comprehensive transmission planning. This final 
order aims to ensure that transmission providers, through their 
regional transmission planning processes, identify, evaluate, and 
select Long-Term Regional Transmission Facilities that more efficiently 
or cost-effectively address Long-Term Transmission Needs, helping to 
ensure just and reasonable rates.
    229. We disagree with arguments that the Commission should not 
require Long-Term Regional Transmission Planning because, certain 
commenters claim, doing so will introduce excessive uncertainty into 
regional transmission planning, transmission providers will make 
forecasting errors, or the final order will result in regional 
transmission planning that is speculative.\579\ To the contrary, we 
believe that the reforms adopted in this final order account for and 
seek to reduce the inherent uncertainty in forward-looking regional 
transmission planning, while ensuring that transmission providers, 
through their regional transmission planning processes, identify, 
evaluate, and select Long-Term Regional Transmission Facilities that 
more efficiently or cost-effectively address Long-Term Transmission 
Needs, thus helping to ensure just and reasonable rates.\580\ In fact, 
by requiring transmission providers to use Long-Term Scenarios in Long-
Term Regional Transmission Planning, this final order provides 
transmission providers with a critical tool for managing uncertainty, 
facilitating regional transmission planning that accounts for a range 
of potential futures, as well as an assessment of the likelihood of 
each scenario manifesting, when identifying, evaluating, and selecting 
Long-Term Regional Transmission Facilities. Further, as discussed in 
the Evaluation and Selection of Long-Term Regional Transmission 
Facilities section below, we require transmission providers to 
reevaluate Long-Term Regional Transmission Facilities in certain 
circumstances, which will provide transmission providers with yet 
another such tool.
---------------------------------------------------------------------------

    \579\ Louisiana Commission Initial Comments at 4-5; NRG Initial 
Comments at 3-4; Ohio Consumers Initial Comments at 5.
    \580\ See Policy Integrity Initial Comments at 6 (arguing that 
future uncertainty requires scenario planning).
---------------------------------------------------------------------------

    230. Moreover, notwithstanding allegations to the contrary, we 
believe that Long-Term Regional Transmission Planning is a logical and 
reasonable extension of current regional transmission planning 
processes, which also manage uncertainty and plan for future regional 
transmission needs. The key difference, which we address through this 
final order, is that these existing regional transmission planning 
processes are conducted in a manner that is not sufficiently long-term, 
forward-looking, or comprehensive such that transmission providers are 
not identifying Long-Term Transmission Needs. As a result, transmission 
providers are failing to identify or evaluate regional transmission 
facilities that would more efficiently or cost-effectively address 
those Long-Term Transmission Needs, and consequently,

[[Page 49325]]

are missing the opportunity to select such regional transmission 
facilities. Our reforms in this final order remedy these deficiencies.
    231. Further, we believe that Long-Term Regional Transmission 
Planning as set forth in this final order provides adequate safeguards 
against excessive transmission development in response to speculative 
transmission needs. For example, this final order requires transmission 
providers to develop multiple plausible and diverse Long-Term Scenarios 
based upon best available data, which will allow transmission providers 
to better understand how certain categories of factors will give rise 
to Long-Term Transmission Needs, and requires transmission providers to 
update their assumptions periodically, as discussed further below.\581\ 
In developing these Long-Term Scenarios, transmission providers are 
required to treat more certain drivers of Long-Term Transmission Needs 
differently than less certain drivers, and must provide opportunities 
for stakeholder engagement. Further, the final order grants substantial 
flexibility to transmission providers to develop an evaluation process 
and selection criteria that will provide them with the opportunity to 
select Long-Term Regional Transmission Facilities in a way that 
maximizes benefits accounting for costs over time without over-building 
transmission facilities. Consistent with the existing Order No. 1000 
regional transmission planning processes, the final order does not 
require transmission providers to select any regional transmission 
facilities as part of Long-Term Regional Transmission Planning. 
Finally, we require transmission providers to reevaluate previously 
selected Long-Term Regional Transmission Facilities in certain 
circumstances, as discussed further below in the Reevaluation section.
---------------------------------------------------------------------------

    \581\ See New Jersey Commission Initial Comments at 10-11.
---------------------------------------------------------------------------

    232. The regional transmission planning and cost allocation 
requirements in this final order, like those of Order Nos. 890 and 
1000, are focused on the transmission planning process, and do not 
require any substantive outcomes from this process.\582\ We disagree 
with certain commenters' assertions that this final order favors, 
promotes, or subsidizes particular types of generation resources over 
others, or otherwise engages in generation planning.\583\ Instead, this 
final order requires transmission providers to participate in Long-Term 
Regional Transmission Planning through their regional transmission 
planning process that identifies Long-Term Transmission Needs, 
evaluates the benefits of Long-Term Regional Transmission Facilities to 
meet those needs, and provides the opportunity for transmission 
providers to select Long-Term Regional Transmission Facilities that are 
more efficient or cost-effective transmission solutions to those needs. 
We reiterate that, as discussed below in the Evaluation and Selection 
of Long-Term Regional Transmission Facilities section, any selected 
Long-Term Regional Transmission Facilities must satisfy transmission 
provider-developed selection criteria that maximize benefits accounting 
for costs over time without over-building transmission facilities, 
which ensures that the costs of such transmission facilities are 
outweighed by the benefits they deliver to customers.
---------------------------------------------------------------------------

    \582\ See, e.g., Order No. 1000, 136 FERC ] 61,051 at P 12.
    \583\ Alabama Commission Initial Comments at 7-8; Louisiana 
Commission Initial Comments at 12, 19-21; Potomac Economics Initial 
Comments at 3-4; Utah Division of Public Utilities Initial Comments 
at 2; Vistra Initial Comments at 11.
---------------------------------------------------------------------------

    233. We disagree with commenters that argue that the factors giving 
rise to Long-Term Transmission Needs, such as state laws dictating 
specific generation resource mixes, are irreconcilable with effective 
transmission planning.\584\ These changes are occurring independent of 
any action that we take in this final order, and they are being driven 
by a wide variety of factors. This final order provides transmission 
providers with the tools that they need to respond to these factors, 
requiring that they conduct Long-Term Regional Transmission Planning to 
identify, evaluate, and select Long-Term Regional Transmission 
Facilities that are more efficient or cost-effective regional 
transmission solutions to the Long-Term Transmission Needs that these 
factors drive.
---------------------------------------------------------------------------

    \584\ See ELCON Initial Comments at 9 (``ELCON has always 
believed that planning for disparate state energy priorities is at 
odds with market-driven, efficient, and cost-effective transmission 
planning.'').
---------------------------------------------------------------------------

    234. We disagree with Louisiana Commission and former Kansas 
Commission Chairman Keen's claims that Long-Term Regional Transmission 
Planning will threaten the reliability of the transmission system. We 
acknowledge that reliability needs are evolving; for example, the 
increasing frequency and severity of high-impact extreme weather events 
threatens grid reliability. We believe that Long-Term Regional 
Transmission Planning--in addition to existing Order No. 1000 regional 
transmission planning and cost allocation requirements--is needed to 
support the reliable operation of transmission systems, given these 
changes. As the Commission and the North American Electric Reliability 
Corporation have noted, the transmission system may not be adequately 
prepared for extreme weather events and the increasing frequency of 
these events must be planned for to ensure system reliability.\585\ We 
thus view our action in this final order as complementary to other 
steps that the Commission has taken in recent years to bolster system 
reliability.\586\
---------------------------------------------------------------------------

    \585\ FERC, North American Electric Reliability Corporation, 
Winter Storm Elliot Report: Inquiry into Bulk-Power System 
Operations During December 2022 (Nov. 2023), https://www.ferc.gov/media/winter-storm-elliott-report-inquiry-bulk-power-system-operations-during-december-2022; FERC, North American Electric 
Reliability Corporation, The February 2021 Cold Weather Outages in 
Texas and the South Central United States (Nov. 2021), https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and.
    \586\ See, e.g., Transmission Sys. Planning Performance 
Requirements for Extreme Weather, Order No. 896, 88 FR 41262 (June 
23, 2023), 183 FERC ] 61,191 (2023); One-Time Info. Reports on 
Extreme Weather Vulnerability Assessments, Order No. 897, 88 FR 
41447 (June 27, 2023), 183 FERC ] 61,192 (2023).
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    235. Further, we disagree with the contention of Louisiana 
Commission and Vistra that Long-Term Regional Transmission Planning 
will distort the efficient functioning of Commission-jurisdictional 
wholesale markets by subsidizing uneconomic generation or by distorting 
price signals. As discussed further below, we require transmission 
providers, as part of Long-Term Regional Transmission Planning, to 
assess the costs and measure the benefits of regional transmission 
facilities that address Long-Term Transmission Needs and to develop 
evaluation processes and selection criteria that provide the 
opportunity to select those transmission facilities as more efficient 
or cost-effective regional transmission solutions to those Needs. While 
the addition of any new transmission facility necessarily affects 
Commission-jurisdictional wholesale markets, the requirements set forth 
in this final order ensure that transmission providers will have the 
opportunity to select more efficient or cost-effective Long-Term 
Regional Transmission Facilities that provide value to transmission 
customers and support the efficient functioning of wholesale markets by 
addressing Long-Term Transmission Needs.

[[Page 49326]]

    236. We also disagree with Vistra's contention that Long-Term 
Regional Transmission Planning somehow will assign all, or a 
disproportionately high share, of interconnection-related network 
upgrade costs to load or undermine the incentives for generation 
developers to site new generation resources in ways that minimize 
transmission system upgrade costs. Rather, because transmission 
providers will now engage in Long-Term Regional Transmission Planning 
to identify, evaluate, and select more efficient or cost-effective 
regional transmission facilities to address Long-Term Transmission 
Needs, Long-Term Regional Transmission Facilities will be planned in a 
more efficient and cost-effective manner than if transmission 
facilities meeting a narrower set of transmission needs were left to be 
identified through the generator interconnection process. Indeed, 
numerous commenters explain that the piecemeal expansion of the 
transmission system is highly inefficient and results in higher costs 
for transmission customers,\587\ in part because the costs of 
interconnection-related network upgrades ultimately are passed on to 
consumers.
---------------------------------------------------------------------------

    \587\ See, e.g., NYISO Initial Comments at 30; PIOs Initial 
Comments at 9-10.
---------------------------------------------------------------------------

    237. We strike another careful balance in this final order. On the 
one hand, we recognize transmission providers' need for sufficient 
flexibility to implement Long-Term Regional Transmission Planning in 
their transmission planning regions to reflect regional differences, 
such as different market structures.\588\ On the other hand, we must 
ensure that transmission providers' regional transmission planning 
processes result in just and reasonable rates, which, as discussed 
above in the Overall Need for Reform section, necessitates that they 
plan on a sufficiently long-term, forward-looking, and comprehensive 
basis such that transmission providers are identifying, evaluating, and 
selecting more efficient or cost-effective regional transmission 
facilities to address Long-Term Transmission Needs. We believe that the 
balance struck in the final order will ensure that Commission-
jurisdictional rates are just and reasonable and not unduly 
discriminatory or preferential and, thus, we reject requests for 
flexibility that exceeds that provided in this final order.
---------------------------------------------------------------------------

    \588\ The Commission also recognized the need for sufficient 
flexibility in regional transmission planning to reflect regional 
differences in Order No. 1000. See Order No. 1000, 136 FERC ] 61,051 
at P 61.
---------------------------------------------------------------------------

    238. In particular, we reject requests that, instead of requiring 
transmission providers to implement Long-Term Regional Transmission 
Planning in accordance with the requirements adopted in this final 
order, we set forth principles and objectives articulating our concerns 
with existing regional transmission planning processes and give 
transmission providers the flexibility to propose revisions to their 
processes to address those concerns.\589\ Having found existing 
regional transmission planning and cost allocation requirements to be 
unjust and unreasonable, we have an obligation under FPA section 206 to 
adopt reforms that remedy the deficiencies identified in this final 
order. We also believe that such an approach would fail to adequately 
address the deficiencies described above in the Overall Need for Reform 
section, namely that transmission providers are not currently required 
to: (1) perform a sufficiently long-term assessment of transmission 
needs that identifies Long-Term Transmission Needs; (2) adequately 
account on a forward-looking basis for known determinants of Long-Term 
Transmission Needs; and (3) consider the broader set of benefits of 
regional transmission facilities planned to meet those Long-Term 
Transmission Needs. We further believe that establishing requirements 
rather than principles will ensure a sufficiently robust process for 
Long-Term Regional Transmission Planning while providing sufficient 
clarity about that process to avert conflict among stakeholders, as 
noted by AEP.\590\
---------------------------------------------------------------------------

    \589\ ISO-NE Initial Comments at 20; ISO RTO Council Initial 
Comments at 4-5, 8-9; MISO Initial Comments at 22-23.
    \590\ AEP Reply Comments at 2-4.
---------------------------------------------------------------------------

    239. We also disagree with commenters that argue that this final 
order should apply to only RTO/ISO transmission planning regions. The 
Commission's existing regional transmission planning requirements, 
which, as described above in the Overall Need for Reform section, we 
find to be deficient, apply in RTO/ISO and non-RTO/ISO transmission 
planning regions alike; without the Long-Term Regional Transmission 
Planning Requirements adopted herein, transmission providers in both 
RTO/ISO and non-RTO/ISO transmission planning regions will continue to 
be at risk of undertaking investments in relatively inefficient or less 
cost-effective transmission infrastructure, the costs of which are 
ultimately recovered through Commission-jurisdictional rates. 
Accordingly, while we acknowledge differences between RTO/ISO and non-
RTO/ISO transmission planning regions, we find that transmission 
providers in all transmission planning regions must implement Long-Term 
Regional Transmission Planning as required in this final order to 
ensure that Commission-jurisdictional rates are just and reasonable and 
not unduly discriminatory or preferential. Additionally, we note that 
many of the requirements established in this final order provide for 
regional flexibility, including, but not limited to, the requirements 
to develop Long-Term Scenarios, determine which factors in each 
required category of factors do not affect Long-Term Transmission Needs 
and need not be considered, develop methods to measure the benefits of 
Long-Term Regional Transmission Facilities, design an evaluation 
process and selection criteria, and establish a Long-Term Regional 
Transmission Cost Allocation Method.
    240. We acknowledge that certain transmission planning regions 
already conduct some regional transmission planning on a relatively 
forward-looking, proactive basis. We do not intend to undermine 
progress made in these transmission planning regions, and our goal is 
to set a floor, not a ceiling. We decline to prejudge whether any 
existing regional transmission planning process meets the requirements 
set forth in this final order and accordingly reject requests that we 
do so.\591\ We note that, if a transmission provider believes that it 
participates in a regional transmission planning process that fulfills 
the requirements adopted in this final order, it may describe in its 
compliance filing how its process meets these requirements.
---------------------------------------------------------------------------

    \591\ See, e.g., Ameren Initial Comments at 8.
---------------------------------------------------------------------------

    241. We expect Long-Term Regional Transmission Planning to enhance 
the existing regional transmission planning and cost allocation 
processes required by Order No. 1000. Except as set forth in this final 
order, we do not require that any transmission provider replace or 
otherwise make changes to its existing Order No. 1000-compliant 
regional transmission planning processes that plan for reliability or 
economic transmission needs, or the associated Order No. 1000-compliant 
regional cost allocation method(s). Transmission providers may continue 
to rely on their existing regional transmission planning and cost 
allocation processes to comply with Order No. 1000's requirements 
related to transmission needs driven by reliability concerns or 
economic considerations.

[[Page 49327]]

    242. We also do not alter the existing Order No. 1000 requirement 
to consider transmission needs driven by Public Policy Requirements in 
the regional transmission planning process. Instead, we clarify that we 
will deem transmission providers to be in compliance with this existing 
requirement by conducting Long-Term Regional Transmission Planning in 
accordance with the requirements set forth in this final order. As 
discussed below, we require transmission providers to incorporate a 
variety of factors into the development of Long-Term Scenarios, which 
include, among others, certain Federal, state, and local laws and 
regulations. Therefore, we find that transmission providers that 
implement Long-Term Regional Transmission Planning and satisfy the 
requirements set forth in this final order will comply with the 
requirement in Order No. 1000 to participate in a regional transmission 
planning process that considers, and has associated cost allocation 
provisions related to, transmission needs driven by Public Policy 
Requirements.
    243. We understand--and acknowledge comments submitted in this 
proceeding explaining--that transmission providers in some transmission 
planning regions have developed processes to consider transmission 
needs driven by Public Policy Requirements through their regional 
transmission planning processes that they wish to retain.\592\ In their 
filings made to comply with this final order, transmission providers 
may propose to continue using some or all aspects of the existing 
regional transmission planning and cost allocation processes that they 
use to consider transmission needs driven by Public Policy 
Requirements. Transmission providers must nevertheless comply with the 
Long-Term Regional Transmission Planning requirements set forth in this 
final order, such that continued use of existing regional transmission 
planning and cost allocation processes related to transmission needs 
driven by Public Policy Requirements will not supplant transmission 
providers' obligation to comply with this final order. In their filing 
to comply with this final order, transmission providers that wish to 
continue to use some or all of their existing regional transmission 
planning and cost allocation processes to consider transmission needs 
driven by Public Policy Requirements must demonstrate that continued 
use of any such processes does not interfere with or otherwise 
undermine Long-Term Regional Transmission Planning as set forth in this 
final order.
---------------------------------------------------------------------------

    \592\ CAISO Reply Comments at 17-18; New York Transco Initial 
Comments at 5.
---------------------------------------------------------------------------

    244. Similarly, we allow transmission providers to propose a 
regional transmission planning process that simultaneously plans for 
shorter-term reliability and economic transmission needs, as well as 
Long-Term Transmission Needs, as outlined in this final order, through 
a combined process. Transmission providers proposing to address all of 
these transmission needs in a single regional transmission planning 
process must demonstrate that the unified regional transmission 
planning process continues to comply with Order No. 1000, as well as 
with the Long-Term Regional Transmission Planning requirements set 
forth in this final order, by demonstrating that such a combined 
process is consistent with or superior to the requirements of both 
Order No. 1000 and this final order. However, in the case that the 
requirements of Order No. 1000 and this final order conflict, the 
requirements of this final order prevail, and transmission providers 
must demonstrate that their proposed regional transmission planning 
process is consistent with or superior to the applicable requirements 
in this final order.
    245. We reject requests to require transmission providers to 
simultaneously plan for all such transmission needs through a single 
regional transmission planning process, however.\593\ We recognize that 
such a combined process has potential benefits and do not prohibit such 
an approach, but at this time we believe that the benefits of requiring 
such a combined process on a generic basis may be outweighed by the 
difficulty of transitioning to such a process from existing regional 
transmission planning processes. Therefore, we do not require in this 
final order that transmission providers plan for all reliability and 
economic transmission needs and Long-Term Transmission Needs through a 
single regional transmission planning process. Further, we believe that 
Long-Term Regional Transmission Planning, as set forth in this final 
order, meets many of the same objectives as would such a combined 
regional transmission planning process because, by identifying Long-
Term Transmission Needs and considering a broad set of benefits when 
evaluating Long-Term Regional Transmission Facilities, the existing 
regional transmission planning processes for economic and reliability 
needs may ultimately come to address only residual needs not already 
addressed through Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------

    \593\ See, e.g., ACEG Initial Comments at 30-31.
---------------------------------------------------------------------------

    246. With respect to the request by PIOs to mandate that the base 
cases used in Order No. 1000 regional transmission planning processes 
and Long-Term Scenarios in Long-Term Regional Transmission Planning be 
defined in the same process,\594\ we decline to adopt this proposal. 
The record is inadequate to assess the impact that such a requirement 
would have on existing Order No. 1000 regional transmission planning 
processes, and whether this proposal would work across the differing 
transmission planning processes in each transmission planning region. 
With respect to the proposals by Clean Energy Buyers, Cypress Creek, 
and Policy Integrity,\595\ these proposals were not among the proposals 
included in the NOPR and are beyond the scope of this proceeding, and 
therefore we decline to adopt them.
---------------------------------------------------------------------------

    \594\ PIOs Initial Comments at 44-46.
    \595\ Clean Energy Buyers Initial Comments at 9-10; Cypress 
Creek Reply Comments at 10-12; Policy Integrity Supplemental 
Comments at 3.
---------------------------------------------------------------------------

    247. We also reject requests to incorporate local transmission 
planning into Long-Term Regional Transmission Planning specifically or 
regional transmission planning more generally,\596\ as well as requests 
to require transmission providers to evaluate and approve local 
transmission facilities in regional transmission planning.\597\ This 
final order sets forth requirements that will enhance the transparency 
of local transmission planning and examine opportunities for right-
sizing in-kind replacements of existing transmission facilities, 
including local transmission facilities, but the Commission in the NOPR 
did not propose other changes to local transmission planning processes 
and therefore these requests are beyond the scope of this final order.
---------------------------------------------------------------------------

    \596\ AEE Initial Comments at 3, 38.
    \597\ OMS Initial Comments at 16-17.
---------------------------------------------------------------------------

    248. As discussed in detail below, we require transmission 
providers to satisfy specific requirements in implementing Long-Term 
Regional Transmission Planning, including requirements to: (1) use a 
transmission planning horizon of no less than 20 years into the future 
in developing Long-Term Scenarios; (2) reassess and revise those 
scenarios at least once every five years; (3) incorporate into the 
Long-Term Scenarios a set of Commission-identified categories of 
factors that give rise to Long-Term Transmission Needs;

[[Page 49328]]

(4) develop a plausible and diverse set of at least three Long-Term 
Scenarios; (5) perform sensitivity analyses of uncertain operational 
outcomes during multiple concurrent and sustained generation and/or 
transmission outages due to an extreme weather event across a wide 
area; and (6) use ``best available data'' in developing Long-Term 
Scenarios.
    249. Before turning to these topics, however, we address two 
preliminary matters: the definition of Long-Term Regional Transmission 
Facility; and our jurisdiction to adopt these reforms.
b. Definition of Long-Term Regional Transmission Facility
    250. We modify the NOPR proposal and define Long-Term Regional 
Transmission Facility for purposes of this final order as a regional 
transmission facility, as defined in Order No. 1000, that is identified 
as part of Long-Term Regional Transmission Planning to address Long-
Term Transmission Needs.\598\ In so doing, we clarify that some Long-
Term Regional Transmission Facilities may be selected in a regional 
transmission plan for purposes of cost allocation, while others may be 
considered for selection but not be selected.
---------------------------------------------------------------------------

    \598\ In the NOPR, the Commission proposed to define a Long-Term 
Regional Transmission Facility as a transmission facility identified 
as part of Long-Term Regional Transmission Planning and selected in 
the regional transmission plan for purposes of cost allocation to 
address transmission needs driven by changes in the resource mix and 
demand. NOPR, 179 FERC ] 61,028 at P 252 n.398.
---------------------------------------------------------------------------

    251. This modification also clarifies that Long-Term Regional 
Transmission Facilities are a subset of regional transmission 
facilities as defined in Order No. 1000. Further, consistent with Order 
No. 1000,\599\ a selected Long-Term Regional Transmission Facility is a 
regional transmission facility that has been selected pursuant to a 
Commission-approved Long-Term Regional Transmission Planning process in 
a regional transmission plan for purposes of cost allocation because it 
is a more efficient or cost-effective solution to Long-Term 
Transmission Needs.
---------------------------------------------------------------------------

    \599\ Order No. 1000, 136 FERC ] 61,051 at P 63.
---------------------------------------------------------------------------

    252. We disagree with PJM that Order No. 1000's requirements 
related to regional transmission planning processes addressing 
transmission needs driven by reliability concerns or economic 
considerations will be unclear given the definition of Long-Term 
Regional Transmission Facility, and we find unpersuasive PJM's 
contention that Long-Term Regional Transmission Planning will 
inadvertently cause the re-litigation of aspects of those existing 
processes. If a regional transmission facility is selected in an 
existing Order No. 1000 regional transmission planning process, the 
rules of, as well as the regional cost allocation method for, that 
existing process apply to the selected regional transmission facility. 
If a Long-Term Regional Transmission Facility is selected in Long-Term 
Regional Transmission Planning, then the rules of, and the Long-Term 
Regional Cost Allocation Method for, Long-Term Regional Transmission 
Planning apply to that Long-Term Regional Transmission Facility.
c. Legal Authority To Adopt Reforms for Long-Term Regional Transmission 
Planning
    253. We reaffirm our conclusion in the NOPR that we are acting 
within the Commission's legal authority under FPA section 206 by 
requiring transmission providers to participate in a regional 
transmission planning process that includes Long-Term Regional 
Transmission Planning. The FPA grants the Commission authority over the 
transmission of electric energy in interstate commerce, which includes 
transmission on the interconnected national grids.\600\ FPA section 205 
requires that the rates charged by any public utility in connection 
with such transmission--as well as the rules and regulations affecting 
such rates--be just and reasonable, and further requires that public 
utilities file with the Commission the practices affecting such 
rates.\601\ Under FPA section 206, when the Commission determines that 
any rate or any practice affecting such rate is unjust, unreasonable, 
or unduly discriminatory or preferential--as we find above with respect 
to transmission planning practices--the Commission must determine the 
just and reasonable rate or practice to be followed.\602\ Transmission 
planning and cost allocation processes are practices affecting the 
rates charged by public utilities in connection with the Commission-
jurisdictional transmission of electric energy in interstate 
commerce.\603\ No commenter has claimed otherwise.
---------------------------------------------------------------------------

    \600\ New York v. FERC, 535 U.S. at 16-17 (citing 16 U.S.C. 
824(b)).
    \601\ 16 U.S.C. 824d.
    \602\ 16 U.S.C. 824e.
    \603\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55-59; 
accord Emera Me. v. FERC, 854 F.3d at 673-74.
---------------------------------------------------------------------------

    254. Despite this, a number of commenters claim that the specific 
transmission planning requirements we adopt in this final order 
infringe on the authority reserved to the states by FPA section 201 or 
are otherwise barred by certain prudential or constitutional 
principles. As a threshold matter, we believe that commenters' concerns 
with respect to our jurisdiction or authority to adopt this final order 
mainly arise from factual misunderstandings or mischaracterizations 
about what Long-Term Regional Transmission Planning will and will not 
require transmission providers to do. As explained above, this final 
order requires transmission providers in each transmission planning 
region to participate in a regional transmission planning process that 
includes Long-Term Regional Transmission Planning and to conduct Long-
Term Regional Transmission Planning in accordance with the requirements 
set forth in this final order. Transmission providers are required to 
identify Long-Term Transmission Needs, identify Long-Term Regional 
Transmission Facilities that meet such needs, measure the benefits of 
these Long-Term Regional Transmission Facilities, and evaluate these 
Long-Term Regional Transmission Facilities for potential selection. As 
such, this final order does not regulate, aim at, or otherwise attempt 
to influence integrated resource planning, the generation mix, 
decisions related to the siting and construction of transmission 
facilities or generation resources, or any other matters reserved to 
states under FPA section 201.
    255. As discussed in the Introduction and Background section above, 
the requirements of this final order build upon more than a quarter 
century of significant actions taken by the Commission on transmission 
planning and cost allocation, beginning with the Commission's initial 
open access reforms in Order No. 888. In 2007, the Commission issued 
Order No. 890 to address identified deficiencies in the pro forma OATT 
based on more than 10 years of experience since the issuance of Order 
No. 888. Most recently, in 2011, the Commission issued Order No. 1000, 
which required transmission providers to develop a regional 
transmission plan after evaluating whether regional transmission 
facilities may be more efficient or cost-effective than transmission 
facilities identified in local transmission planning processes and to 
consider transmission needs driven by Public Policy Requirements. These 
practices serve as the foundation for regional transmission planning, 
and this final order leaves them in place.
    256. As described above, however, we have identified specific gaps 
in the Order No. 1000 framework--namely, that regional transmission 
planning practices do not perform a sufficiently

[[Page 49329]]

long-term assessment of transmission needs, adequately account on a 
forward-looking basis for known determinants of Long-Term Transmission 
Needs, or consider the broader set of benefits of regional transmission 
facilities. In this final order, we direct reforms to close these gaps 
without otherwise disturbing the regional transmission planning 
structure required by Order No. 1000, which was fully affirmed on 
appeal in the face of similar objections to those raised here.\604\
---------------------------------------------------------------------------

    \604\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55-64 
(rejecting arguments that the requirement to engage in regional 
transmission planning, as prescribed in Order No. 1000, exceeded the 
Commission's jurisdiction under FPA section 206, interfered with 
traditional state authority reserved under FPA section 201, or 
improperly interpreted and applied FPA section 202(a)).
---------------------------------------------------------------------------

    257. Critically, as in Order No. 1000, our focus continues to be on 
ensuring that Commission-jurisdictional regional transmission planning 
processes are just and reasonable and that, as a result of improvements 
to the regional transmission planning and cost allocation processes, 
Commission-jurisdictional rates remain just and reasonable.\605\ And, 
as in Order No. 1000, while the improvements to the regional 
transmission planning and cost allocation processes will ensure that 
potentially more efficient or cost-effective regional transmission 
facilities are evaluated for potential selection and have a cost 
allocation method available if they are selected, this order does not 
mandate development of any particular transmission facility.
---------------------------------------------------------------------------

    \605\ See id. at 63-64 (affirming that the Commission was acting 
within its jurisdiction because its planning mandate ``relates 
wholly to electricity transmission, as opposed to electricity 
sales'' and ``is directed at ensuring the proper functioning of the 
interconnected grid spanning state lines'').
---------------------------------------------------------------------------

    258. Consistent with the regional transmission planning and cost 
allocation reforms adopted in Order No. 1000, and in response to 
commenters arguing otherwise,\606\ we affirm that this final order does 
not authorize or require any entity to adopt a particular siting plan 
for Long-Term Regional Transmission Facilities that transmission 
providers select; or to forego state-jurisdictional siting proceedings 
where they are necessary; or to begin construction on such Long-Term 
Regional Transmission Facilities. Even where transmission providers 
select a Long-Term Regional Transmission Facility, the relevant 
transmission developer typically must secure a variety of other permits 
and authorizations before beginning to construct the facility, 
including those that are subject to state jurisdiction. Nothing in this 
final order changes otherwise applicable siting laws or requirements.
---------------------------------------------------------------------------

    \606\ Alabama Commission Initial Comments at 7; Kansas Ratepayer 
Advocates Reply Comments at 3; NARUC Initial Comments at 29; Nevada 
Commission Initial Comments at 2-3; Southern Initial Comments at 3-
4, 7, 15-17; Southern Reply Comments at 6-7.
---------------------------------------------------------------------------

    259. Similarly, this final order does not change existing 
mechanisms for cost-recovery through retail rates; authorize or require 
states or state commissions to change the laws or regulations that 
govern the conduct of integrated resource planning or request for 
proposal processes; authorize or require transmission providers or 
transmission developers to bypass any applicable state-regulated 
integrated resource planning or request for proposal processes; or 
authorize or require states or public utilities to adopt a different 
mix of generation resources than would otherwise be the case. Comments 
suggesting otherwise do not accurately represent the Commission's 
proposed requirements in the NOPR or the requirements adopted in this 
final order,\607\ which seeks to ensure that transmission providers 
plan for Long-Term Transmission Needs, however those needs arise.\608\
---------------------------------------------------------------------------

    \607\ Alabama Commission Initial Comments at 3-4, 7-9; Kansas 
Ratepayer Advocates Reply Comments at 2; Louisiana Commission 
Initial Comments at 8-10, 27-28; Louisiana Commission Reply Comments 
at 14-15; Mississippi Commission Initial Comments at 3 (citing NOPR, 
179 FERC ] 61,028 (Christie, Comm'r, concurring, at P 2); Nevada 
Commission Initial Comments at 2-3; SERTP Sponsors Initial Comments 
at 5, 16, 17 n.20, 19-20; SERTP Sponsors Reply Comments at 12-13; 
Southern Initial Comments at 3-4, 7-8, 12-13, 15-17, 23-24; Southern 
Reply Comments at 3, 6-7; Undersigned States Reply Comments at 2, 4-
5, 8; Utah Commission Initial Comments at 7-9.
    \608\ New Jersey Commission Reply Comments at 1-2.
---------------------------------------------------------------------------

    260. We disagree with Southern and SERTP Sponsors' characterization 
of Long-Term Regional Transmission Planning as a Commission-regulated 
integrated resource planning/request for proposal process.\609\ 
Similarly, comments that suggest that this final order intends to 
``revamp the energy grid's mix of generation resources writ large'' 
\610\ are incorrect. We understand these comments to argue that the 
Commission seeks reforms to regional transmission planning and cost 
allocation processes so that it can direct or influence investments 
toward particular resources, as would an entity engaged in integrated 
resource planning. In this final order, the Commission neither aims to 
influence the resource mix, nor, as a practical matter, could the final 
order achieve such an outcome.
---------------------------------------------------------------------------

    \609\ SERTP Sponsors Initial Comments at 16-17; Southern Initial 
Comments at 3-4, 7, 15-17.
    \610\ Undersigned States Reply Comments at 4; see also Louisiana 
Commission Initial Comments at 6, 12-13 (arguing that the FPA does 
not allow the Commission to ``enact[ ] sweeping energy policy 
changes that would have far-reaching, nation-wide effects'' or to 
favor one form of generation over another).
---------------------------------------------------------------------------

    261. Instead, the final order merely requires transmission 
providers to account for observable changes affecting the transmission 
system. The final order neither directs those changes, nor does it 
require any entity, including a state, to approve changes to any 
subject within its jurisdiction. As with Order Nos. 890 and 1000, which 
built on the Commission's open access reforms in Order No. 888, this 
final order responds to changes in the electric industry that have 
arisen in the years since the Commission's last regulatory action 
related to transmission planning. As discussed above in the Overall 
Need for Reform section, this final order responds to evolving 
reliability concerns, including the increasing frequency of high-impact 
extreme weather events; changes in electricity demand, including 
significant load growth that is projected to increase in coming years; 
changes in supply, including Federal, federally-recognized Tribal, 
state, and local laws and policies that affect the future resource mix; 
changes in the economics of generation, transmission, and storage 
technologies; corporate, governmental, and utility commitments to rely 
on certain generation resources; and other factors as discussed in this 
final order.
    262. We emphasize that these changes, which are affecting and will 
continue to drive transmission needs, are not within the Commission's 
control and, in many cases, are beyond the Commission's jurisdiction. 
We do not aim to influence these drivers of transmission needs through 
the requirements in this final order.\611\ However, the Commission has 
an obligation under the FPA to ensure that Commission-jurisdictional 
transmission rates remain just and reasonable, and we affirm--
consistent with the Commission's actions in Order Nos. 890 and 1000--
that the Commission has the requisite authority to account for the 
effects of these changes driving transmission needs in Commission-
jurisdictional transmission planning processes.\612\
---------------------------------------------------------------------------

    \611\ See EPSA, 577 U.S. 260 at 282 (citing Oneok, Inc. v. 
Learjet, Inc., 575 U.S. 373, 385 (2015)).
    \612\ Cf. EPSA, 577 U.S. at 281-82 (``When FERC regulates what 
takes place on the wholesale market, as part of carrying out its 
charge to improve how that market runs, then no matter the effect on 
retail rates, 824(b) imposes no bar.'').
---------------------------------------------------------------------------

    263. We also emphasize, and no commenter contests, that this final 
order directly regulates transmission planning

[[Page 49330]]

and cost allocation processes, which are practices that affect the 
rates for the transmission of electric energy in interstate commerce. 
Importantly, it directly regulates only those practices, and it does 
not directly regulate any matter reserved to the states by FPA section 
201. Moreover, in doing so, this final order is not aiming to 
indirectly regulate any matter reserved to the states by FPA section 
201. Instead, our aim here is to improve on the Commission's existing 
transmission planning and cost allocation processes for the express 
purpose of addressing identified deficiencies with those processes.
    264. As the U.S. Supreme Court has recognized, it is true that 
almost any action that the Commission takes with respect to regulating 
the practices affecting the rates for the transmission of or the 
wholesale sale of electric energy in interstate commerce will have 
``some effect, in either the short or long term'' on matters reserved 
to the states' jurisdiction.\613\ But those effects, inevitable as they 
may be, are ``of no legal consequence'' to determining whether this 
final order infringes on the states' authority under FPA section 
201.\614\ Instead, such effects are a ``fact of economic life'' for the 
electric industry, given Congress's decision in the FPA to divide 
jurisdiction over the industry, including both generation and 
transmission, into spheres of Commission and state jurisdiction that 
are not ``hermetically sealed'' from one another.\615\ Accordingly, 
Commission regulation of Commission-jurisdictional practices affecting 
transmission may ``have natural consequences'' for generation.\616\ 
But, even where that happens, that does not defeat Federal 
jurisdiction.
---------------------------------------------------------------------------

    \613\ Id. at 281 (emphasis added).
    \614\ Id.
    \615\ Id.
    \616\ Id.
---------------------------------------------------------------------------

    265. Rather, as in EPSA, what matters is that this final order aims 
to regulate and, in fact, does regulate only practices that affect the 
transmission of electric energy in interstate commerce, which are 
squarely within the Commission's jurisdiction under the FPA. As in 
Order Nos. 890 \617\ and 1000,\618\ this final order aims to improve 
Commission-regulated transmission planning processes, in this instance 
by ensuring that they are sufficiently long-term, forward-looking, and 
comprehensive such that they are capable of identifying and meeting 
Long-Term Transmission Needs.\619\ Thus, this final order ensures just 
and reasonable Commission-jurisdictional rates and practices by 
ensuring that transmission providers have adequate processes to 
identify Long-Term Transmission Needs and to identify, evaluate, and 
select Long-Term Regional Transmission Facilities that more efficiently 
or cost-effectively address those needs.
---------------------------------------------------------------------------

    \617\ Order No. 890, 118 FERC ] 61,119 at P 3.
    \618\ Order No. 1000, 136 FERC ] 61,051 at P 12.
    \619\ EPSA, 577 U.S. at 281-83.
---------------------------------------------------------------------------

    266. Moreover, as in EPSA, what also matters is that ``every aspect 
of the [final order] happens exclusively'' as part of a process that is 
subject to the Commission's jurisdiction and governs exclusively how 
those processes work.\620\ In aiming to improve transmission planning 
processes, this final order does not require that transmission 
providers achieve any particular substantive outcome of those 
processes, including either the selection or construction of any 
specific transmission facilities. The final order patently does not aim 
to alter states' or the Nation's generation mix or otherwise regulate 
matters that are within state jurisdiction. Indeed, to the contrary, 
our rationale in this final order is ``all about, and only about, 
improving'' the relevant matters under the Commission's 
jurisdiction.\621\ Nor is it clear how, under commenters' theory, the 
final order could be argued to regulate matters under states' 
jurisdiction, given that the final order does not require investment in 
any particular transmission facilities, and could not, even indirectly, 
ensure investments in any particular set of generating facilities that 
may rely on such transmission facilities.
---------------------------------------------------------------------------

    \620\ Id. at 282.
    \621\ Id. (citing Oneok, Inc. v. Learjet, Inc., 575 U.S. at 
385).
---------------------------------------------------------------------------

    267. Despite some commenters' claims,\622\ nothing in this final 
order requires states to subsidize other states' public policies and, 
indeed, this final order requires, consistent with long-established 
Commission and court precedent, that transmission customers within a 
transmission planning region need only pay costs that are ``roughly 
commensurate'' with the benefits that transmission providers estimate 
they will receive from a regional transmission facility.\623\ Thus, the 
final order ensures that transmission customers nationwide are not 
required to pay for Long-Term Regional Transmission Facilities from 
which they do not benefit.
---------------------------------------------------------------------------

    \622\ Alabama Commission Initial Comments at 8-9; Louisiana 
Commission Initial Comments at 6, 9-10; Mississippi Commission Reply 
Comments at 2-3; Ohio Commission Federal Advocate Initial Comments 
at 4-6; Ohio Consumers Reply Comments at 14.
    \623\ See Ill. Com. Comm'n v. FERC, 756 F.3d 556, 562 (7th Cir. 
2014) (ICC v. FERC III); ICC v. FERC I, 576 F.3d at 477; Sw. Power 
Pool, Inc., 182 FERC ] 61,141, at P 12 (2023).
---------------------------------------------------------------------------

    268. The reforms in the final order require greater transparency 
regarding the benefits that would result from the development of Long-
Term Regional Transmission Facilities, but these reforms also continue 
to allow flexibility, as under Order No. 1000, for the transmission 
providers in each transmission planning region to determine the 
appropriate method for allocating to transmission customers the costs 
of any selected Long-Term Regional Transmission Facility. Rather than 
force transmission providers to adopt a particular cost allocation 
method that would necessarily result in customers in one state 
subsidizing the costs of customers in another state, as these 
commenters allege, the final order affords significant new 
opportunities for Relevant State Entities to inform the evaluation 
process, selection criteria, and cost allocation method adopted by the 
transmission providers in a transmission planning region. We believe 
that the requirements for greater transparency regarding the benefits 
of proposed transmission facilities, the increased opportunities for 
state engagement in evaluation, selection, and cost allocation, the 
flexibility for transmission providers in each transmission planning 
region to determine their own cost allocation methods, and the 
requirement that any cost allocation method must ensure costs are 
allocated in a manner that is at least roughly commensurate with 
estimated benefits provide robust assurance that the cost allocation 
methods ultimately proposed under the final order will not result in 
improper cost subsidization. Ultimately, the Commission must review and 
accept each cost allocation method proposed under the final order to 
ensure that it is just and reasonable and consistent with the final 
order's requirements.
    269. As discussed in the Evaluation of the Benefits of Regional 
Transmission Facilities section below, this final order requires 
transmission providers to use and measure a set of seven required 
benefits to evaluate Long-Term Regional Transmission Facilities. The 
measurement of these benefits represents the value that the 
transmission providers expect a particular Long-Term Regional 
Transmission Facility to provide to transmission customers in the 
transmission planning region. As further discussed in the Regional 
Transmission Planning Cost Allocation section below, this final order 
requires transmission providers to provide a forum for

[[Page 49331]]

Relevant State Entities to negotiate a cost allocation method and/or a 
process for determining future cost allocation methods for Long-Term 
Regional Transmission Facilities, which enables robust participation by 
those entities. Moreover, the cost allocation methods required by this 
final order are intended to ensure that costs are allocated in a manner 
that is at least roughly commensurate with the estimated benefits that 
a Long-Term Regional Transmission Facility provides to transmission 
customers.
    270. The benefits this order requires to be used and measured--
which provide an important source of transparency regarding any 
resulting allocation of costs to transmission customers--reflect 
objective, measurable changes in transmission system conditions, rather 
than achievement of state public policies. For example, even if a 
state's public policy is one driver of a Long-Term Transmission Need, 
these benefits of a Long-Term Regional Transmission Facility resolving 
that need are well understood and measurable, including, for example, 
reducing the cost of generating electricity by allowing for the 
increased dispatch of suppliers that have lower incremental costs of 
production, minimizing energy losses incurred in transmitting 
electricity, and lowering the number or duration of loss of load 
events. Transmission providers will evaluate Long-Term Regional 
Transmission Facilities for selection considering these benefits that 
these facilities would provide, and these benefits accrue to the 
transmission customers that fund their construction. In other words, 
under this final order, customers pay for a more reliable and economic 
transmission system as identified through open and transparent Long-
Term Regional Transmission Planning, and any state's ratepayers only 
fund the construction of Long-Term Regional Transmission Facilities 
that provide them with such benefits that are at least roughly 
commensurate with the costs of those facilities.
    271. We turn now to commenters' specific jurisdiction arguments. As 
an initial matter, we acknowledge that, in addition to granting 
authority to the Commission over the transmission of electric energy in 
interstate commerce, FPA section 201 also reserves certain authority to 
the states.\624\ As such, we agree with Southern that Congress sought 
in enacting the FPA to ensure the ``continued exercise of state power'' 
\625\ over certain matters. However, the requirements in this final 
order respect and do not unlawfully infringe on state authority. 
Rather, as discussed above, the Commission is acting in an area 
squarely within its jurisdiction--transmission planning and cost 
allocation--by requiring transmission providers to engage in Long-Term 
Regional Transmission Planning to remedy deficiencies in the current 
transmission planning and cost allocation processes, which we conclude 
are unjust and unreasonable.
---------------------------------------------------------------------------

    \624\ See 16 U.S.C. 824(a)-(b)(1); New York v. FERC, 535 U.S. at 
20-21 (``It is, however, perfectly clear that the original FPA did a 
good deal more than close the gap in state power identified in [Pub. 
Utils. Comm'n of R.I. v. Attleboro Steam & Elec. Co., 273 U.S. 83 
(1927) (Attleboro)]. The FPA authorized Federal regulation not only 
of wholesale sales that had been beyond the reach of state power, 
but also the regulation of wholesale sales that had been previously 
subject to state regulation. More importantly, as discussed above, 
the FPA authorized Federal regulation of interstate transmissions as 
well as of interstate wholesale sales, and such transmissions were 
not of concern in Attleboro.'' (emphasis in original) (internal 
citations omitted)).
    \625\ Southern Initial Comments at 16 (quoting Oneok, Inc. v. 
Learjet, Inc., 575 U.S. at 385).
---------------------------------------------------------------------------

    272. We acknowledge that Long-Term Regional Transmission Planning 
will affect matters that are within the states' jurisdiction. As 
stated, this is inevitable. Effective transmission planning necessarily 
involves taking into account assumptions about the generation resources 
that will be available, because transmission needs arise from the 
relative amounts, locations, and timing of supply (i.e., generation) 
and of demand (i.e., load); indeed, existing transmission planning 
processes also take into account these assumptions.\626\ Our action in 
this final order simply modifies the scope and duration of these 
assumptions to ensure that regional transmission planning processes are 
conducted on a sufficiently long-term, forward-looking, and 
comprehensive basis by requiring transmission providers to evaluate 
factors that give rise to Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \626\ See, e.g., Xcel Initial Comments at 13, 16 & n.26 
(discussing generation resource assumptions made in existing Order 
No. 1000 regional transmission planning and cost allocation 
processes).
---------------------------------------------------------------------------

    273. Southern and SERTP Sponsors acknowledge that the NOPR proposed 
to require transmission providers to incorporate the results of state-
sanctioned integrated resource planning as factors in developing Long-
Term Scenarios, but they insist that Long-Term Regional Transmission 
Planning will intrude upon state authority if we do not require Long-
Term Scenarios to be limited to those state-sanctioned resources.\627\ 
This assertion is incorrect for at least three reasons. First, the 
public utilities whose integrated resource plans are approved by state 
commissions are not the only entities whose decisions may influence the 
development of generation resources within a particular transmission 
planning region. For example, a wide variety of private enterprises, 
publicly-owned utilities, and electric cooperatives have made 
commitments to fund the development of certain generation resources, 
and transmission providers may reasonably determine that these 
procurement decisions give rise to Long-Term Transmission Needs. 
Second, making generation resource assumptions for the purpose of 
performing transmission planning does not result in any legally-binding 
determination on a matter within a state's jurisdiction, let alone 
undermine a state's ability to ultimately decide what generation 
resources to build, and on what timetable.\628\ Third, as Southern and 
SERTP Sponsors concede,\629\ many existing integrated resource planning 
processes do not identify specific generation resources beyond a 
particular point in time. Other integrated resource planning processes 
may not result in a set of state-sanctioned generation resources and 
may instead serve merely as a guide for the relevant public 
utility.\630\ As a result, relying on such integrated resource planning 
processes exclusively to identify Long-Term Transmission Needs would 
fail to ensure that regional transmission planning processes are 
conducted on a sufficiently long-term, forward-looking, and 
comprehensive basis and therefore would fail to ensure just and 
reasonable Commission

[[Page 49332]]

jurisdictional-rates. To be clear, we are not in this final order 
attempting to denigrate or diminish the importance of integrated 
resource planning. Rather, in the context of Long-Term Regional 
Transmission Planning, integrated resource planning is reasonably 
considered one of several categories of factors used to develop Long-
Term Scenarios and identify Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \627\ SERTP Sponsors Initial Comments at 15-17; Southern Initial 
Comments at 18-19.
    \628\ We disagree with Southern's and SERTP Sponsors' contention 
that the inclusion of such non-binding assumptions about generation 
resources in transmission planning will ``bias'' subsequent state 
resource decisions. See Southern Initial Comments at 19; SERTP 
Sponsors Initial Comments at 17 n.20. As Kentucky Commission Chair 
Chandler argues, the NOPR's reforms do not foreclose states' 
decision making on generation. Kentucky Commission Chair Chandler 
Reply Comments at 3. We also disagree with North Carolina Commission 
and Staff's contention that merely requiring transmission providers 
to use and measure production cost savings in evaluating Long-Term 
Regional Transmission Facilities ``could conflict with state-
jurisdictional resource decisions.'' North Carolina Commission and 
Staff Initial Comments at 7. If nothing else, Long-Term Regional 
Transmission Planning will provide public utilities and state 
commissions the opportunity to develop longer-term, forward-looking, 
robust assessments that can inform future decision making.
    \629\ SERTP Sponsors Initial Comments at 16; Southern Initial 
Comments at 19.
    \630\ See, e.g., SREA Reply Comments at 2-3 (arguing, in 
response to Alabama Commission, that Alabama has no formal 
integrated resource plan process upon which the Commission could 
encroach).
---------------------------------------------------------------------------

    274. In that light, Southern's and SERTP Sponsors' argument--that 
we should limit transmission providers to state-approved resources and 
prohibit non-binding assumptions about the resource mix and demand--
does not safeguard but in fact subverts the FPA's division between 
Federal and state authority. As stated above, were we to require that 
transmission providers limit their assumptions to only state-sanctioned 
generation resources, we would be requiring transmission providers to 
ignore many of the factors that, as demonstrated by this record, 
transmission providers must reasonably consider to plan on a 
sufficiently long-term, forward-looking, and comprehensive basis. 
Instead, it is within our jurisdiction to determine the factors that 
transmission providers must incorporate in order to identify Long-Term 
Transmission Needs.
    275. Commenters' arguments that the final order would not withstand 
judicial scrutiny under the ``major questions doctrine'' are similarly 
unfounded. For example, some commenters appear to misinterpret West 
Virginia v. EPA as standing for the proposition that ``the nation's 
energy policy and generation mix is a `major question' and that an 
agency must have direct authorization from Congress to assert 
jurisdiction'' over these matters.\631\ As an initial matter, as noted 
above, the aim of this final order is not to influence the generation 
mix or energy policy more broadly, but to ensure that Commission-
jurisdictional transmission providers are planning for Long-Term 
Transmission Needs in a manner that is just and reasonable and results 
in just and reasonable Commission-jurisdictional rates.
---------------------------------------------------------------------------

    \631\ SERTP Sponsors Initial Comments at 17-18; Southern Initial 
Comments at 20; see also Undersigned States Reply Comments at 3 
(``National-scale energy grid regulation is a `major question' 
because of the massive economic consequences involved in such 
regulation.'').
---------------------------------------------------------------------------

    276. In any case, the Court did not determine that energy policy 
and the mix of generation resources are in every instance a major 
question. Instead, in West Virginia v. EPA, the U.S. Supreme Court 
considered a specific agency action in light of a specific statutory 
provision and concluded that the Environmental Protection Agency's 
(EPA) exercise of authority was a ``major question'' based on a variety 
of factors specific to that context--including whether the EPA's 
administrative action was a ``transformative'' expansion of its power, 
whether the EPA had relevant technical and policy expertise, whether 
the relevant statutory provision was ``ancillary'' to the broader 
statutory construct, and whether the EPA's administrative action 
implicated significant economic and political questions.\632\
---------------------------------------------------------------------------

    \632\ West Virginia v. EPA, 597 U.S. at 710, 724-725, 729, 731-
32; see also Biden v. Nebraska, 143 S. Ct. 2355, 2372-2374 (2023) 
(applying West Virginia v. EPA's mode of analysis).
---------------------------------------------------------------------------

    277. Commenters have not attempted a similar analysis of whether 
courts should construe this final order as a ``major question,'' \633\ 
and we find that their contentions that courts ought to do so are based 
on the factual mischaracterizations discussed above. In any event, this 
final order neither transforms nor expands the Commission's authority; 
it merely applies existing authority, based on the Commission's 
expertise and experience, to identify and remedy deficiencies in 
existing regional transmission planning and cost allocation 
processes.\634\ As with Order Nos. 890 and 1000, the Commission is 
promulgating a final order pursuant to FPA section 206 to address those 
deficiencies in order to ensure that transmission planning practices, a 
subject long-regulated by the Commission and well within its area of 
expertise, remain just and reasonable and not unduly discriminatory or 
preferential. To that end, this final order requires further reforms to 
regional transmission planning and cost allocation processes so that 
they are sufficiently long-term, forward-looking, and comprehensive. 
And while the transmission planning required in this final order may be 
more forward-looking, long-term, and comprehensive than the status quo, 
as a matter of the Commission's jurisdiction, it is fundamentally no 
different than the regional transmission planning already required by 
the Commission and upheld by appellate courts.\635\ In short, the 
differences in transmission planning required by this final order 
represent differences in degree, not kind, from the Commission's 
longstanding regulations. As such, they are a far cry from the 
``transformative expansion'' of the EPA's authority on which the Court 
relied in West Virginia v. EPA to find that the issue presented therein 
represented a major question not delegated to the agency to decide.
---------------------------------------------------------------------------

    \633\ See Harvard ELI and Policy Integrity Supplemental Comments 
at 2 (arguing that Undersigned States, for example, ``overlook key 
requirements of the major questions doctrine'').
    \634\ See, e.g., S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 68-
69. Cf. PJM Power Providers Grp. v. FERC, 88 F.4th at 274.
    \635\ See, e.g., S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 48-
49; see also Harvard ELI and Policy Integrity Supplemental Comments 
at 4-7.
---------------------------------------------------------------------------

    278. Just as it is clear that incremental improvements to practices 
that the courts have already determined fall squarely within the 
Commission's jurisdiction do not constitute a ``transformative 
expansion'' or ``extraordinary grant'' of regulatory authority to which 
the major questions doctrine may apply, so too is it clear that the 
other ancillary factors cited by the Court are similarly inapplicable. 
The final order's incremental process improvements, while necessary to 
ensure just and reasonable Commission-jurisdictional rates, do not have 
the ``vast economic and political significance'' that would implicate 
the major questions doctrine.\636\ The Commission's regulation of 
interstate transmission rates will have an effect on billions of 
dollars in customer charges and, in that generic sense, is of political 
interest to many. The incremental process improvements required by the 
final order, however, do not fundamentally change the economic or 
political stakes of ensuring that Commission-jurisdictional rates 
remain just and reasonable.
---------------------------------------------------------------------------

    \636\ West Virginia v. EPA, 597 U.S. at 735 (J. Gorsuch, 
concurring).
---------------------------------------------------------------------------

    279. Likewise, the Commission's continued assertion of authority 
over regional transmission planning and cost allocation processes does 
not resemble the EPA's assertion of authority related to the electric 
system that the Court found to be beyond that agency's expertise.\637\ 
Here, the Commission undisputedly bears the relevant expertise over the 
interstate transmission system.\638\ Nor does the Commission rely on a 
``backwater'' statutory provision to achieve its reforms.\639\ The 
Commission relies on FPA sections 205 and 206, which the Court has held 
``unambiguously authorize[ ]'' the Commission to assert jurisdiction 
over interstate

[[Page 49333]]

transmission\640\ and extends an authority--indeed, a duty--to ensure 
that the practices directly affecting such rates are just and 
reasonable.\641\ This provision was not ancillary to the statutory 
scheme but, rather, central to Congress' aim to ensure that the 
Commission possessed adequate authority to regulate interstate 
transmission beyond the reach of state power.\642\ Finally, commenters 
do not point to Congress's ``conspicuous[ ] and repeated[ ]'' rejection 
of legislation that would enact reforms similar to those adopted in the 
final order.\643\
---------------------------------------------------------------------------

    \637\ West Virginia v. EPA, 597 U.S. at 729 (finding relevant 
that EPA itself admitted it lacked expertise to project ``system-
wide trends in areas such as electricity transmission, distribution, 
and storage'').
    \638\ Cf. Amerada Hess Pipeline Corp. v. FERC, 117 F.3d 596, 
600-01 (D.C. Cir. 1997) (``[The Federal Energy Regulatory 
Commission] is entrusted with administering the regulations relating 
to oil pipelines and has an expertise in the field based on that 
jurisdiction.'' (emphasis added)).
    \639\ West Virginia v. EPA, 597 U.S. at 729.
    \640\ New York v. FERC, 535 U.S. at 19.
    \641\ EPSA, 577 U.S. at 277.
    \642\ New York v. FERC, 535 U.S. at 20-21 (discussing enactment 
of FPA in 1935 as a response to Attleboro).
    \643\ West Virginia v. EPA, 597 U.S. at 745 (J. Gorsuch, 
concurring).
---------------------------------------------------------------------------

    280. We also disagree with Undersigned States' legal claim that 
allowing ``one [s]tate [to] effectively require other [s]tates to 
subsidize their own vision of what resources should be used in 
electricity generation'' would violate the Constitution's ``equal 
sovereignty doctrine.'' \644\ As discussed above, the final order 
categorically does not require states to subsidize other states' public 
policies or generation decisions. To the contrary, consistent with the 
cost causation principle, this final order requires customers to pay 
for a share of the costs of new Long-Term Regional Transmission 
Facilities only to the extent that they benefit from those facilities 
and, even then, any share they pay for must be roughly commensurate 
with the benefits they receive.\645\
---------------------------------------------------------------------------

    \644\ Undersigned States Reply Comments at 5-6.
    \645\ See supra note 623 and accompanying discussion.
---------------------------------------------------------------------------

    281. Moreover, according to Undersigned States, the equal 
sovereignty doctrine dictates that the Nation ``is a union of [s]tates, 
equal in power, dignity and authority, each competent to exert that 
residuum of sovereignty not delegated to the United States by the 
Constitution itself.'' \646\ But, ``neither the Supreme Court nor any 
other court has ever applied that principle as a limit on the Commerce 
Clause or other Article I powers.'' \647\ Instead, Courts have found 
that ``the Constitution does not contain any textual provision 
suggesting an equal sovereignty limit on Congress's Article I powers 
generally or on the Commerce Clause in particular.'' \648\ As relevant 
here, pursuant to the Constitution's Commerce Clause,\649\ Congress 
duly enacted the FPA, which in turn empowers the Commission to regulate 
the rates and practices affecting rates for the transmission of 
electricity in interstate commerce.\650\ Under the FPA, the Commission 
is ``unambiguously authorize[d] . . . to take state policies into 
account to the extent that such policies affect [the Commission's] 
statutorily prescribed area of focus . . . .'' \651\
---------------------------------------------------------------------------

    \646\ Undersigned States Reply Comments at 5 (citing Coyle v. 
Smith, 221 U.S. at 567). But see Ohio v. EPA, 2024 WL 1515001, at 
*15 (D.C. Cir. Apr. 9, 2024) (holding that ``[t]he equal footing 
cases,'' like Coyle v. Smith, ``do not directly apply either outside 
of the admission context or to Article I powers like the Commerce 
Clause.'').
    \647\ Ohio v. EPA, 2024 WL 1515001 at *13.
    \648\ Id. at *16.
    \649\ U.S. Const. art. 1, 8.
    \650\ 16 U.S.C. 824d.
    \651\ PJM Power Providers Grp. v. FERC, 88 F.4th at 275; see 
also Elec. Power Supply Ass'n v. Star, 904 F.3d at 524 (approving of 
the Commission's decision to take state zero-emissions credit 
systems like that in Illinois ``as givens and set out to make the 
best of the situation [these systems] produce'').
---------------------------------------------------------------------------

    282. The nature of the interconnected transmission system is such 
that states naturally affect one another in pursuing policies available 
to them while exercising the authority reserved to them under FPA 
section 201.\652\ For the reasons explained in this final order, we 
conclude that transmission providers must participate in a regional 
transmission planning process that includes Long-Term Regional 
Transmission Planning, and we find that transmission providers must 
have the opportunity to select Long-Term Regional Transmission 
Facilities that more efficiently or cost-effectively address Long-Term 
Transmission Needs. Our role within our Federal system is not to 
``unreasonably interfere with'' nor to ``pass judgement on state and 
local policies and objectives,'' \653\ including where such policies 
and objectives have incidental interstate effects.\654\ Nor need we, 
because even if one state's public policy is a driver of a Long-Term 
Transmission Need, the costs of a Long-Term Regional Transmission 
Facility that transmission providers select will be allocated to 
transmission customers only to the extent that they benefit from that 
facility and only to a degree that is at least roughly commensurate 
with the benefits that facility provides to them. That approach is 
consistent with Commission precedent and commenters have not 
demonstrated that this framework results in impermissible cross-
subsidization among states.\655\
---------------------------------------------------------------------------

    \652\ See Elec. Power Supply Ass'n v. Star, 904 F.3d at 524 
(describing the effects on interstate sales resulting from states' 
exercise of powers reserved to them under FPA section 201 as ``an 
inevitable consequence of a system in which power is shared between 
state and national governments'' (citing Hughes v. Talen Energy 
Mktg., LLC, 578 U.S. 150, 164 (2016)).
    \653\ N.J. Bd. Pub. Utils. v. FERC, 744 F.3d 74, 98 n.24 (3rd 
Cir. 2014) (quoting PJM Interconnection, L.L.C., 137 FERC ] 61,145, 
at P 3 (2011)); see also PJM Interconnection, L.L.C., 186 FERC ] 
61,080, at P 186 (2024) (rejecting an argument that the Commission 
was required to determine whether state-sponsored resources were 
providing disproportionate benefits to other states in the form of 
lower capacity market prices).
    \654\ See Coal. for Competitive Elec. v. Zibelman, 906 F.3d 41, 
56 (2d Cir. 2018) (collecting Commission orders sanctioning state-
jurisdictional programs incidentally affecting wholesale markets).
    \655\ For example, PJM incorporates transmission needs driven by 
Public Policy Requirements into the assumptions stage of its 
regional transmission planning process to identify needed 
reliability and economic regional transmission facilities for 
potential selection and cost allocation, rather than through a 
separate and distinct process to identify and allocate the costs of 
transmission facilities selected to address transmission needs 
driven by Public Policy Requirements. The Commission found PJM's 
approach complied with the requirement in Order No. 1000 to consider 
transmission needs driven by Public Policy Requirements in regional 
transmission planning and cost allocation processes. PJM 
Interconnection, L.L.C., 142 FERC ] 61,214, at PP 109-120 (2013), 
order on reh'g and compliance, 147 FERC ] 61,128, at PP 66-71 
(2014).
---------------------------------------------------------------------------

    283. Finally, in response to NRECA's request, we confirm that the 
final order is consistent with the Commission's obligation under FPA 
section 217(b)(4). As articulated in South Carolina Public Service 
Authority v. FERC, FPA section 217(b)(4) requires the Commission to 
``facilitate the planning of a reliable grid,'' and we do so by 
``seek[ing] to ensure that adequate transmission capacity is built to 
allow load-serving entities to meet their service obligations.'' \656\ 
This final order seeks to ensure precisely the same goal, and it 
therefore satisfies the Commission's obligation under FPA section 
217(b)(4).
---------------------------------------------------------------------------

    \656\ 762 F.3d at 90.
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B. Development of Long-Term Scenarios

1. NOPR Proposal
    284. In the NOPR, the Commission proposed to require transmission 
providers to develop Long-Term Scenarios as part of Long-Term Regional 
Transmission Planning. The Commission proposed to define Long-Term 
Scenarios as a tool to identify the transmission planning region's 
needs driven by changes in the resource mix and demand--and enable the 
evaluation of transmission facilities to meet such transmission needs--
across multiple scenarios that incorporate different assumptions about 
the future electric power system over a sufficiently long-term, 
forward-looking transmission planning horizon. The Commission explained 
that a scenario is a hypothetical sequence of events that includes 
assumptions used to forecast transmission needs. The Commission also 
stated that assumptions used to forecast transmission needs driven by

[[Page 49334]]

changes in the resource mix and demand include: forecasts of the level 
and pattern (i.e., hourly and seasonal variability) of future 
electricity demand; the quantity, location, and type of resource 
additions and retirements; and other relevant forecasts about the 
electric power system that are used as inputs to the transmission model 
and determine the need for new transmission facilities over the 
transmission planning horizon. In addition, the Commission noted that 
other relevant assumptions might include forecasts for natural gas 
prices, increasing outage trends due to extreme weather and climatic 
trends, and other future events.
    285. The Commission also proposed in the NOPR to require that 
transmission providers use Long-Term Scenarios to evaluate potential 
regional transmission facilities needed to meet transmission needs 
driven by changes in the resource mix and demand to identify the more 
efficient or cost-effective regional transmission facilities.\657\
---------------------------------------------------------------------------

    \657\ NOPR, 179 FERC ] 61,028 at P 84.
---------------------------------------------------------------------------

2. Comments
a. General Comments
    286. Of the commenters specifically addressing the proposal to 
require Long-Term Scenarios in Long-Term Regional Transmission 
Planning, the majority support scenario-based planning.\658\ Clean 
Energy Buyers state that Long-Term Scenarios are critical to Long-Term 
Regional Transmission Planning because its success will depend on the 
quality of forecasting.\659\ Form Energy states that long-term scenario 
review will ensure that transmission upgrades address future needs in a 
cost-effective and environmentally friendly manner.\660\ LADWP asserts 
that Long-Term Scenarios are critical to developing an effective 
transmission system that ensures reliability, while also providing 
flexibility to support the delivery of renewable energy.\661\ NARUC 
states that Long-Term Scenarios are a flexible planning tool for 
addressing the uncertainty involved in identifying transmission needs 
driven by changes in the resource mix and demand and that using them 
will ensure that transmission providers adequately assess the potential 
benefits of regional transmission facilities.\662\
---------------------------------------------------------------------------

    \658\ See ACEG Initial Comments at 6; AEP Initial Comments at 7-
8; Amazon Initial Comments at 2-3; BP Initial Comments at 4; 
California Commission Initial Comments at 1-2, 5-6, 21; California 
Energy Commission Initial Comments at 1-2; City of New York Initial 
Comments at 7; Clean Energy Associations Initial Comments at 10; 
Clean Energy Buyers Initial Comments at 11; Duke Initial Comments at 
10; Eversource Initial Comments at 10; Exelon Initial Comments at 5; 
Form Energy Initial Comments at 2-3; GridLab Initial Comments at 10; 
Handy Law Initial Comments at 9-10; Indicated PJM TOs Initial 
Comments at 7-8; LADWP Initial Comments at 2; NARUC Initial Comments 
at 4; National Grid Initial Comments at 10-11; PIOs Initial Comments 
at 14; PPL Initial Comments at 4; SEIA Initial Comments at 4-5; 
Southeast PIOs Initial Comments at 42; SREA Initial Comments at 39; 
State Agencies Initial Comments at 14; State Officials Supplemental 
Comments at 1 (citing US Climate Alliance Initial Comments); US 
Climate Alliance Initial Comments at 2; WE ACT Initial Comments at 
3; WIRES Initial Comments at 6.
    \659\ Clean Energy Buyers Initial Comments at 11.
    \660\ Form Energy Initial Comments at 3.
    \661\ LADWP Initial Comments at 2.
    \662\ NARUC Initial Comments at 4.
---------------------------------------------------------------------------

    287. Southeast PIOs claim that Long-Term Scenarios are essential to 
improving current transmission planning processes in the 
Southeast.\663\ SREA argues that Long-Term Regional Transmission 
Planning is not occurring in MISO South and states that scenario 
planning is contentious but necessary.\664\
---------------------------------------------------------------------------

    \663\ Southeast PIOs Initial Comments at 42, 46.
    \664\ SREA Initial Comments at 39-41.
---------------------------------------------------------------------------

    288. California Energy Commission requests that the Commission 
clarify that transmission providers may rely on scenarios developed by 
other agencies, as currently CAISO relies on analyses conducted by 
California Energy Commission and California Commission.\665\ Relatedly, 
New York Commission and NYSERDA and ISO-NE highlight the importance of 
state-led identification of public policy needs and their impact on 
scenario assumptions.\666\ New York Commission and NYSERDA state that, 
especially in a single-state RTO/ISO like NYISO, the state should be 
afforded a central role in determining the scenarios to be 
studied.\667\ ISO-NE also believes that reliance on states is 
consistent with prior Commission orders permitting transmission 
providers to rely on a committee of state regulators to identify 
transmission needs driven by Public Policy Requirements.\668\
---------------------------------------------------------------------------

    \665\ California Energy Commission Initial Comments at 2.
    \666\ New York Commission and NYSERDA Initial Comments at 7; 
ISO-NE Initial Comments at 25-26.
    \667\ New York Commission and NYSERDA Initial Comments at 8.
    \668\ ISO-NE Initial Comments at 25 (citing ISO New England 
Inc., 143 FERC ] 61,150, at P 108 (2013)).
---------------------------------------------------------------------------

    289. PJM States suggest that the Commission's proposal for state 
involvement in the development of Long-Term Scenarios could be 
interpreted as more limited than its proposal for state involvement 
with respect to Long-Term Regional Cost Allocation and ask that the 
Commission clarify that retail regulators have a primary role in both. 
PJM States warn that, if a retail regulator disagrees with the 
scenarios or benefits metrics used to select a transmission project, it 
is unlikely to receive regulatory approval.\669\
---------------------------------------------------------------------------

    \669\ PJM States Initial Comments at 3-4 (citing NOPR, 179 FERC 
] 61,028 at P 245).
---------------------------------------------------------------------------

    290. Cypress Creek asserts that the Commission should require the 
use of a defined and standardized set of baseline assumptions to ensure 
that scenario projections are realistic, and that deviation should only 
be allowed if the proposal is consistent with or superior to the pro 
forma.\670\
---------------------------------------------------------------------------

    \670\ Cypress Creek Reply Comments at 5-8.
---------------------------------------------------------------------------

    291. Concerned Scientists state that the Commission should reject 
comments arguing that uncertainty prohibits scenario-based planning, 
and instead endeavor to create a transmission planning process that 
properly acknowledges and addresses that uncertainty. Concerned 
Scientists state that uncertainty does not prohibit long-term 
transmission planning but rather necessitates the evaluation of 
multiple plausible scenarios to identify investments that will perform 
well over a variety of possible future conditions. Concerned Scientists 
explain that, just as utilities and generator developers do not shy 
away from an uncertain future when building new generation resources, 
transmission investments should also be informed by, but not avoided 
due to, future uncertainty. Concerned Scientists state that the 
Commission's proposed Long-Term Scenarios requirements are a reasonable 
minimum for responsible transmission planning.\671\
---------------------------------------------------------------------------

    \671\ Concerned Scientists Reply Comments at 18-19.
---------------------------------------------------------------------------

    292. Other commenters support the NOPR proposal to require Long-
Term Scenarios in transmission planning but have reservations.\672\ 
Many of these commenters argue that the NOPR is too prescriptive and 
ask for greater flexibility so that the Long-Term Scenario planning 
already occurring in their respective transmission planning region will 
comply with any final order.\673\ For example, OMS points to such 
flexibility as key to the success of MISO's long-term transmission 
planning

[[Page 49335]]

processes.\674\ SERTP Sponsors argue that the Commission should not 
make Long-Term Scenarios even more prescriptive because such an 
approach would likely result in litigation and delay.\675\
---------------------------------------------------------------------------

    \672\ Ameren Initial Comments at 7-8; American Municipal Power 
Initial Comments at 7; APPA Initial Comments at 25; CAISO Initial 
Comments at 21; Chemistry Council Initial Comments at 5; Michigan 
Commission Initial Comments at 4-5; MISO TOs Initial Comments at 15-
17; Omaha Public Power Initial Comments at 3-4; OMS Initial Comments 
at 3-5; PJM Initial Comments at 54.
    \673\ CAISO Initial Comments at 21; Michigan Commission Initial 
Comments at 4-5; MISO TOs Initial Comments at 15-16; OMS Initial 
Comments at 3-4.
    \674\ OMS Initial Comments at 4-5.
    \675\ SERTP Sponsors Reply Comments at 13-14.
---------------------------------------------------------------------------

    293. American Municipal Power believes that transmission providers 
should conduct Long-Term Scenarios in a highly collaborative way with 
the full and active participation of all stakeholders.\676\ Similarly, 
Six Cities recommend that Long-Term Scenarios be coordinated between 
state and local regulatory authorities to reflect varying policies. Six 
Cities recommend that, in CAISO, Long-Term Scenarios should consider 
the procurement choices of non-jurisdictional utilities, such as Six 
Cities, as well as policy portfolios provided by California 
Commission.\677\
---------------------------------------------------------------------------

    \676\ American Municipal Power Initial Comments at 7.
    \677\ Six Cities Initial Comments at 4.
---------------------------------------------------------------------------

    294. Some commenters oppose the NOPR proposal to require Long-Term 
Scenarios in Long-Term Regional Transmission Planning.\678\ Dominion 
argues for maximum flexibility for planning assumptions to support 
reliable and affordable transmission service for customers.\679\ Idaho 
Commission states that any prescription for scenario analysis should be 
supported by clear evidence of a deficiency.\680\ Instead of specific 
scenario planning requirements, Nebraska Commission states that the 
Commission should provide general guidelines and as much flexibility as 
possible to transmission providers, who--along with state regulatory 
officials--are best situated to evaluate the needs of each transmission 
planning region.\681\
---------------------------------------------------------------------------

    \678\ Dominion Initial Comments at 10; Idaho Commission Initial 
Comments at 3; Nebraska Commission Initial Comments at 3; Ohio 
Consumers Initial Comments at 2, 5; Potomac Economics Initial 
Comments at 2.
    \679\ Dominion Initial Comments at 10-12.
    \680\ Idaho Commission Initial Comments at 3.
    \681\ Nebraska Commission Initial Comments at 3.
---------------------------------------------------------------------------

    295. Potomac Economics questions the NOPR's proposal to require 
Long-Term Scenarios, stating that it will force RTOs/ISOs to plan and 
commit to sizable transmission investment costs based on uncertain 
factors and unreasonable speculation on factors such as the location of 
future generation, retirements, grid enhancing technologies, and 
transmission reconfiguration options.\682\ Potomac Economics also 
questions the usefulness of Long-Term Scenarios, asserting that future 
congestion patterns will be increasingly uncertain given that the 
higher penetration of intermittent resources will cause larger 
fluctuations in transmission flows, making it more difficult to 
accurately estimate the benefits of transmission upgrades.\683\ Potomac 
Economics argues that many of the most beneficial transmission upgrades 
address very specific constraints, are smaller in size, can be 
difficult to identify in advance, and can be very sensitive to modest 
changes in generation and load.\684\
---------------------------------------------------------------------------

    \682\ Potomac Economics Initial Comments at 2, 4.
    \683\ Id. at 2.
    \684\ Id. at 3.
---------------------------------------------------------------------------

b. Applying Scenario Planning to Reliability and Economic Planning
    296. California Commission and City of New York assert that the 
Commission should require the use of Long-Term Scenarios in all 
transmission planning processes--not just Long-Term Regional 
Transmission Planning.\685\ City of New York argues that such a 
requirement would enable consideration of a broad range of potential 
future system conditions across multiple planning categories.\686\ 
Similarly, NYISO states that the final order should authorize, but not 
require, the use of multiple alternative scenarios in existing 
transmission planning processes. NYISO states that doing so would 
enhance its ability to anticipate and solicit more efficient, holistic 
transmission solutions, which would support system reliability and 
resilience.\687\
---------------------------------------------------------------------------

    \685\ California Commission Initial Comments at 22-24; City of 
New York Initial Comments at 7.
    \686\ City of New York Initial Comments at 7.
    \687\ NYISO Initial Comments at 14-15.
---------------------------------------------------------------------------

    297. In contrast, certain commenters oppose requiring transmission 
providers to incorporate some form of scenario analysis into their 
existing reliability and economic regional transmission planning 
processes.\688\ Duke contends that the Commission should avoid 
disrupting existing regional transmission planning processes that work 
well.\689\ MISO notes that, while this type of scenario-based planning 
has been applied to economic transmission planning processes and could 
be applied to existing reliability transmission planning processes, 
such application should be flexible and tailored to the unique needs of 
each transmission provider, adding that scenario-based planning 
requires considerable time and resources.\690\
---------------------------------------------------------------------------

    \688\ Duke Initial Comments at 2, 10-11; Eversource Initial 
Comments at 19; MISO Initial Comments at 32; NESCOE Initial Comments 
at 23; PJM Initial Comments at 54-56.
    \689\ Duke Initial Comments at 2, 10-11.
    \690\ MISO Initial Comments at 32.
---------------------------------------------------------------------------

3. Commission Determination
    298. We adopt, with modification, the NOPR proposals to require 
transmission providers in each transmission planning region to (1) 
develop and use Long-Term Scenarios as part of Long-Term Regional 
Transmission Planning and (2) use those Long-Term Scenarios to identify 
and evaluate Long-Term Regional Transmission Facilities needed to meet 
Long-Term Transmission Needs. As further explained in subsequent 
sections of this final order, we find that these requirements regarding 
the development and use of Long-Term Scenarios in Long-Term Regional 
Transmission Planning strike a reasonable balance between ensuring that 
Long-Term Regional Transmission Planning reasonably identifies Long-
Term Transmission Needs over a sufficiently long-term, forward-looking 
transmission planning horizon and providing sufficient flexibility for 
transmission providers to develop and use Long-Term Scenarios in a way 
that reflects the unique characteristics of their respective 
transmission planning regions.
    299. We first address the definition of Long-Term Transmission 
Needs. For purposes of this final order, Long-Term Transmission Needs 
are transmission needs identified through Long-Term Regional 
Transmission Planning by, among other things and as discussed in this 
final order, running scenarios and considering the enumerated 
categories of factors. As explained in the NOPR, the drivers of 
transmission needs are diverse and include, but are not limited to, 
evolving reliability concerns, changes in the resource mix, and changes 
in demand. For example, as identified in the NOPR, reliability concerns 
giving rise to Long-Term Transmission Needs include, among other 
things, the increasing frequency of high-impact extreme weather events, 
the increasing reliance by transmission system operators on regional 
integration and coordination to reliably serve load, the operational 
challenges created by the increasing share of variable resources 
entering the resource mix, and changes in electric demand patterns such 
as shifts in load profiles caused by, for example, the emergence of 
large loads associated with evolving industrial and commercial needs 
such as the growth in data centers, and increased electrification of 
energy end uses.\691\
---------------------------------------------------------------------------

    \691\ See NOPR, 179 FERC ] 61,028 at PP 45, 51.
---------------------------------------------------------------------------

    300. In the NOPR, the Commission referred to transmission needs 
identified through Long-Term Regional Transmission Planning largely as 
needs

[[Page 49336]]

driven by changes in the resource mix and demand.\692\ Nevertheless, we 
agree with commenters who correctly note that there are additional 
drivers of Long-Term Transmission Needs,\693\ and, as noted above, the 
Commission itself contemplated in the NOPR that Long-Term Regional 
Transmission Planning would consider drivers beyond those tied directly 
to changes in supply and demand. We therefore clarify that, although 
changes in the resource mix and demand are important drivers of Long-
Term Transmission Needs, they represent only a subset of such drivers. 
In addition, we note that Long-Term Transmission Needs are similar in 
kind to transmission needs identified through existing regional 
transmission planning processes established under Order No. 1000. Where 
Long-Term Transmission Needs differ is their identification through the 
long-term, forward-looking, and more comprehensive regional 
transmission planning and cost allocation processes established in this 
final order. Accordingly, in this final order, we refer to the 
transmission needs that are identified through Long-Term Regional 
Transmission Planning as Long-Term Transmission Needs. The 
identification of Long-Term Transmission Needs and Long-Term Regional 
Transmission Facilities to potentially meet those needs is accomplished 
through the use of Long-Term Scenarios in Long-Term Regional 
Transmission Planning.
---------------------------------------------------------------------------

    \692\ Id.
    \693\ See, e.g., AEE Initial Comments at 7-8 (noting that 
reforms are needed to meet transmission needs driven by ``market 
forces, state policies, and new reliability and resilience 
imperatives''); ELCON Initial Comments at 4 (``[L]ong term scenario 
planning should not be limited to anticipated resource mix but also 
take into consideration impacts on reliability and congestion 
management.''); New Jersey Commission Initial Comments at 2 (``[T]he 
Board stresses that most of the reforms the Commission is proposing 
would be necessary even in the absence of `changes in the resource 
mix and demand.' '') (citing NOPR, 179 FERC ] 61,028 at P 24); 
Renewable Northwest Initial Comments at 8 (noting how current 
transmission planning processes ignore both ``trends in future 
generation and the impact of extreme weather events'') (citing NOPR, 
179 FERC ] 61,028 at P 51); Southeast PIOs Initial Comments at 7-8 
(noting that both intensifying ``changes in the generation mix'' and 
``increasingly common extreme weather and high-intensity, low 
frequency events'' burden the existing transmission system).
---------------------------------------------------------------------------

    301. As discussed in the Requirement for Transmission Providers to 
Use a Set of Seven Required Benefits section of this final order, we 
require transmission providers to measure and use a set of seven 
required benefits in Long-Term Regional Transmission Planning. 
Transmission providers must use this same set of benefits to help to 
inform their identification of Long-Term Transmission Needs. For 
example, in this final order we require transmission providers to 
measure and use production cost savings in Long-Term Regional 
Transmission Planning. As such, when transmission providers are working 
to identify Long-Term Transmission Needs, areas of significant 
congestion on the transmission system--where Long-Term Regional 
Transmission Facilities could reduce congestion and in turn facilitate 
production cost savings--may indicate a Long-Term Transmission Need.
    302. We adopt the definition of Long-Term Scenarios proposed in the 
NOPR,\694\ with modification. We define Long-Term Scenarios as 
scenarios that incorporate various assumptions using best available 
data inputs about the future electric power system over a sufficiently 
long-term, forward-looking transmission planning horizon to identify 
Long-Term Transmission Needs and enable the identification and 
evaluation of transmission facilities to meet such transmission needs. 
We make this modification to clarify the intent of the definition 
proposed in the NOPR, rather than modify the definition in substance.
---------------------------------------------------------------------------

    \694\ In the NOPR, the Commission proposed to define Long-Term 
Scenarios as a tool to identify transmission needs driven by changes 
in the resource mix and demand--and enable the evaluation of 
transmission facilities to meet such transmission needs--across 
multiple scenarios that incorporate different assumptions about the 
future electric power system over a sufficiently long-term, forward-
looking transmission planning horizon. NOPR, 179 FERC ] 61,028 at P 
84.
---------------------------------------------------------------------------

    303. Certain commenters assert that the Commission should not 
require transmission providers to develop Long-Term Scenarios due to 
the inherent uncertainty of forecasting future transmission needs over 
a long transmission planning horizon. We acknowledge the inherent 
uncertainty involved in planning to meet Long-Term Transmission Needs. 
However, we believe that such uncertainty is mitigated by using Long-
Term Scenarios themselves, as noted by Concerned Scientists and 
NARUC.\695\ Scenario planning allows transmission providers to evaluate 
whether Long-Term Regional Transmission Facilities are beneficial in 
more than one scenario. Transmission providers may also examine whether 
Long-Term Transmission Needs appear in one or more scenarios. Scenario 
planning also allows transmission providers to consider a broader range 
of future circumstances and be better prepared for changes in the 
electric power system.\696\ Finally, transmission providers may use 
scenario planning to determine whether identified Long-Term Regional 
Transmission Facilities provide sufficient benefits across more than 
one scenario when considering whether to select such facilities, as 
also noted by NARUC.\697\ Moreover, we adopt requirements for Long-Term 
Scenarios, as discussed further below, to ensure they are based on 
reasonable assumptions and better reflect future transmission system 
conditions and uncertainties in those future circumstances. In sum, 
incorporating Long-Term Scenarios into Long-Term Regional Transmission 
Planning provides an appropriate approach to ensure just and reasonable 
rates by accounting for the increasing uncertainty in the accuracy of 
assumptions over longer (i.e., over 10 years) transmission planning 
horizons and mitigating the risks of under-building or over-building 
Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------

    \695\ Concerned Scientists Reply Comments at 18-19; NARUC 
Initial Comments at 4 (citing NOPR, 179 FERC ] 61,028 at PP 86, 88).
    \696\ See Policy Integrity Reply Comments at 2.
    \697\ NARUC Initial Comments at 4.
---------------------------------------------------------------------------

    304. Further, we disagree with commenters that suggest that the 
Commission should not establish specific Long-Term Scenario 
requirements and that imposing general principles is sufficient to 
ensure just and reasonable rates. We find that Long-Term Regional 
Transmission Planning that does not incorporate Long-Term Scenarios 
that meet the requirements of this final order would fail to ensure 
that transmission providers identify Long-Term Transmission Needs, as 
well as identify and evaluate Long-Term Regional Transmission 
Facilities to address those needs. For example, relying on a single 
forecast of future transmission system conditions may limit 
transmission providers' and stakeholders' confidence in identified 
Long-Term Transmission Needs, and accordingly the evaluation of Long-
Term Regional Transmission Facilities to address those needs. Further, 
failure to incorporate Long-Term Scenarios would increase the 
likelihood of piecemeal and relatively inefficient or less cost-
effective transmission development. Accordingly, we find that requiring 
transmission providers to develop and use Long-Term Scenarios that meet 
the requirements established in this final order as part of Long-Term 
Regional Transmission Planning will ensure that Commission-
jurisdictional rates are just and reasonable and not unduly 
discriminatory or preferential.
    305. Additionally, as stated above and in response to commenters 
that emphasize the importance of

[[Page 49337]]

collaboration in developing Long-Term Scenarios, this final order 
retains the requirements for an open, coordinated, and transparent 
local transmission planning process established in Order No. 890 and 
further required for regional transmission planning in Order No. 
1000.\698\ For example, consistent with the transparency transmission 
planning principle,\699\ transmission providers must make transparent 
the methodology, criteria, assumptions, and data used to develop each 
Long-Term Scenario. Moreover, as described below, this final order 
requires that transmission providers provide meaningful opportunity for 
stakeholder input, including from state and local regulators, as well 
as non-jurisdictional entities, into the factors used to develop Long-
Term Scenarios.
---------------------------------------------------------------------------

    \698\ Order No. 1000, 136 FERC ] 61,051 at PP 150-152; Order No. 
890, 118 FERC ] 61,119 at P 435.
    \699\ Order No. 890, 118 FERC ] 61,119 at P 471.
---------------------------------------------------------------------------

    306. In response to PJM's request that the Commission clarify that 
the role of the state regulator is primary in developing Long-Term 
Scenarios, we note that, as described in the Stakeholder Process and 
Transparency determination within the Categories of Factors section, 
transmission providers retain the ultimate responsibility for 
transmission planning.\700\ As such, transmission providers have 
discretion, subject to the limits imposed in this final order, to weigh 
more heavily one source of information over another, such as weighing 
information related to a factor provided by a state regulator more 
heavily than information provided by other stakeholders. In response to 
California Energy Commission, we find that the final order does not 
preclude transmission providers from relying on scenarios developed by 
state agencies, provided that the Commission finds that the OATT 
provisions governing those Long-Term Scenarios' development comply with 
the Long-Term Scenarios requirements of this final order (e.g., 
transmission planning horizon and stakeholder input requirements). We 
decline to require the use of Long-Term Scenarios in all transmission 
planning processes, as requested by California Commission and City of 
New York. The record in this proceeding does not demonstrate that the 
incorporation of Long-Term Scenarios in existing Order No. 1000 
regional transmission planning processes is necessary to ensure that 
Long-Term Regional Transmission Planning is just and reasonable. In 
response to NYISO's request that transmission providers be allowed to 
use scenario planning in their existing Order No. 1000 regional 
transmission planning processes, while we agree that such a practice 
may offer benefits, we find that any such request amending existing 
transmission planning processes must be submitted in an FPA section 205 
filing separate from their compliance filings to this final order.\701\
---------------------------------------------------------------------------

    \700\ Id. P 454. There, we stated in response to the suggestion 
by some commenters that we require transmission providers to allow 
customers to collaboratively develop transmission plans with 
transmission providers on a co-equal basis that transmission 
planning is the tariff obligation of each transmission provider, and 
the pro forma OATT planning process adopted in the final rule is the 
means to see that it is carried out in a coordinated, open, and 
transparent manner, in order to ensure that customers are treated 
comparably. Therefore, the ultimate responsibility for planning 
remains with transmission providers.
    \701\ We note that an exception to the requirement to file a 
separate FPA section 205 filing applies if transmission providers 
were to propose a unified transmission planning process, as 
discussed above. See supra Participation in Long-Term Regional 
Transmission Planning section.
---------------------------------------------------------------------------

C. Long-Term Scenarios Requirements

1. Transmission Planning Horizon
a. NOPR Proposal
    307. In the NOPR, the Commission proposed to require transmission 
providers to develop Long-Term Scenarios as part of Long-Term Regional 
Transmission Planning using no less than a 20-year transmission 
planning horizon.\702\
---------------------------------------------------------------------------

    \702\ NOPR, 179 FERC ] 61,028 at PP 97-100.
---------------------------------------------------------------------------

    308. The Commission preliminarily found that a 20-year transmission 
planning horizon requirement strikes a reasonable balance between the 
current transmission planning horizons used in many transmission 
planning regions and the 30-year or longer transmission planning 
horizon proposed by some ANOPR commenters. The Commission noted that 
the 30-year or longer transmission planning horizon was criticized by 
other commenters as speculative or too uncertain. The Commission also 
stated that a 20-year transmission planning horizon requirement may be 
reasonable because some transmission providers use a 20-year 
transmission planning horizon in existing regional transmission 
planning processes. In addition, the Commission stated that a 20-year 
transmission planning horizon would allow for sufficient time to 
identify, plan, and obtain siting and permitting approval for and to 
construct regional transmission facilities to meet long-term regional 
transmission needs, including those that may take longer than the 
average amount of time to go from the planning stage to in-service. 
Finally, the Commission stated that a 20-year transmission planning 
horizon would allow transmission providers to better leverage economies 
of scale by sizing transmission facilities to meet not only nearer-term 
transmission needs, but also longer-term transmission needs driven by 
changes in the resource mix and demand over time. The Commission 
preliminarily found that by assessing transmission needs over a longer 
time horizon--for example, starting in year six \703\ through year 20 
of the transmission planning horizon--Long-Term Regional Transmission 
Planning should be able to identify more efficient or cost-effective 
regional transmission facilities to address these needs.\704\
---------------------------------------------------------------------------

    \703\ The Commission noted that the North American Electric 
Reliability Corporation defines the long-term transmission planning 
horizon as covering year six through year 10 and beyond. Id. P 94 
n.160.
    \704\ Id. PP 97-99 (footnotes omitted).
---------------------------------------------------------------------------

b. Comments
i. Support for 20-Year Transmission Planning Horizon
    309. Many commenters support the Commission's proposal to require 
transmission providers to develop Long-Term Scenarios as part of Long-
Term Regional Transmission Planning using no less than a 20-year 
transmission planning horizon.\705\ Several

[[Page 49338]]

commenters generally consider a 20-year transmission planning horizon 
to be reasonable, acceptable, or appropriate.\706\ Some commenters 
argue that a 20-year transmission planning horizon provides a 
reasonable balance between shorter- and longer-term transmission 
planning horizons.\707\ National Grid states that a 20-year 
transmission planning horizon balances the benefits of prospective 
transmission planning with the greater uncertainty that comes with 
forecasting system needs over a longer period.\708\ Numerous commenters 
argue that a 20-year transmission planning horizon will help to improve 
the efficiency and cost of developing transmission and to assess future 
transmission needs.\709\
---------------------------------------------------------------------------

    \705\ ACORE Initial Comments at 1; Advanced Energy Buyers 
Initial Comments at 7; AEE Initial Comments at 8; AEP Initial 
Comments at 5, 8-12; Amazon Initial Comments at 2-3; BP Initial 
Comments at 4-5; Breakthrough Energy Initial Comments at 12-13; 
Breakthrough Energy Supplemental Comments at 1; California Water 
Initial Comments at 14-15; Certain TDUs Initial Comments at 3, 19; 
Clean Energy Associations Initial Comments at 10; Clean Energy 
Buyers Initial Comments at 12; Clean Energy States Initial Comments 
at 2; Concerned Scientists Reply Comments at 18-19; Cypress Creek 
Reply Comments at 4; DC and MD Offices of People's Counsel Initial 
Comments at 8; Environmental Groups Supplemental Comments at 2; 
Eversource Initial Comments at 14; Form Energy Initial Comments at 
2; Georgia Commission Initial Comments at 2-3; GridLab Initial 
Comments at 5; Idaho Power Initial Comments at 4; Illinois 
Commission Initial Comments at 6; Indicated US Senators and 
Representatives Initial Comments at 1; Interwest Initial Comments at 
4-5; ITC Initial Comments at 9-11; LADWP Initial Comments at 2; 
Minnesota State Entities Initial Comments at 4; National and State 
Conservation Organizations Initial Comments at 1; National Grid 
Initial Comments at 12-13; Nevada Commission Initial Comments at 7; 
New England for Offshore Wind Initial Comments at 2; New Jersey 
Commission Initial Comments at 9-10; NextEra Initial Comments at 62; 
NYISO Initial Comments at 2; Pacific Northwest State Agencies 
Initial Comments at 2; PG&E Initial Comments at 2; Policy Integrity 
Initial Comments at 10; PIOs Initial Comments at 15; R Street 
Initial Comments at 6; SEIA Initial Comments at 6; SoCal Edison 
Initial Comments at 11-12; Southeast PIOs Initial Comments at 43; 
SPP Initial Comments at 5-6; SPP Market Monitor Initial Comments at 
4-5; State Officials Supplemental Comments at 1 (citing US Climate 
Alliance Initial Comments at 2); US Climate Alliance Initial 
Comments at 2; US DOE Initial Comments at 10; Vermont Electric and 
Vermont Transco Initial Comments at 2; Vermont State Entities 
Initial Comments at 5; WE ACT Initial Comments at 3.
    \706\ CAISO Initial Comments at 21; EEI Initial Comments at 11; 
Entergy Initial Comments at 9; NARUC Initial Comments at 5; New York 
TOs Initial Comments at 10; Pine Gate Initial Comments at 19-20; PPL 
Initial Comments at 6; WIRES Initial Comments at 7.
    \707\ DC and MD Offices of People's Counsel Initial Comments at 
8-9; LADWP Initial Comments at 2-3; National Grid Initial Comments 
at 12-13.
    \708\ National Grid Initial Comments at 12-13.
    \709\ AEP Reply Comments at 4-5 (citing MTEP2017 Review at 33-
34); Amazon Initial Comments at 2-3; BP Initial Comments at 5; 
Certain TDUs Reply Comments at 5; PIOs Initial Comments at 15.
---------------------------------------------------------------------------

    310. New Jersey Commission argues that a 20-year transmission 
planning horizon should help to make long-term multi-driver 
transmission projects viable by identifying needs and opportunities in 
a timeframe that allows states to have a meaningful conversation about 
voluntarily funding such projects.\710\ Policy Integrity argues that it 
is crucial to model what is going to be needed over the next 20 years 
to ensure that short- and medium-term transmission projects are built 
efficiently, stating that a longer transmission planning horizon is 
reasonable in the context of long-lived transmission assets with long 
lead times.\711\
---------------------------------------------------------------------------

    \710\ New Jersey Commission Initial Comments at 9-10, 28.
    \711\ Policy Integrity Initial Comments at 10.
---------------------------------------------------------------------------

    311. US DOE asserts that there is sufficient evidence to extend the 
transmission planning horizon to a minimum of 20 years for Long-Term 
Regional Transmission Planning to capture power sector changes that 
occur during transmission development.\712\ PIOs note that panelists at 
the November 2021 Technical Conference suggested a 20-year transmission 
planning horizon is necessary, in part, due to long-term public policy 
goals.\713\ Acadia Center and CLF similarly argue that transmission 
planners should plan over long-term horizons to factor in predictable 
trends, such as timelines required under state laws and policies.\714\
---------------------------------------------------------------------------

    \712\ US DOE Initial Comments at 10.
    \713\ PIOs Initial Comments at 15 (citing Tr. 129-137 (multiple 
witnesses)).
    \714\ Acadia Center and CLF Initial Comments at 4.
---------------------------------------------------------------------------

    312. Several commenters emphasize that a transmission planning 
horizon of 20 years is sufficient to account for the amount of time 
needed to develop transmission projects, considering the complexity and 
challenges of major transmission development.\715\ Eversource states 
that a long-term perspective is necessary to take advantage of the 
economies of scale that large transmission projects can enable, as well 
as to incorporate anticipated changes in generation and load beyond the 
traditional transmission planning horizon.\716\ Illinois Commission 
states that a 20-year transmission planning horizon is necessary to 
properly plan and build transmission and generation resources.\717\ 
LADWP states that a 20-year transmission planning horizon provides 
enough time for transmission projects to be developed and placed in 
service when such projects require new rights-of-way without becoming 
too speculative.\718\ NextEra contends that a 20-year transmission 
planning horizon will ensure that transmission planners anticipate and 
plan transmission facilities for needs driven by changes in the 
resource mix and demand.\719\
---------------------------------------------------------------------------

    \715\ Eversource Initial Comments at 14; Illinois Commission 
Initial Comments at 6; LADWP Initial Comments at 2; NextEra Initial 
Comments at 62-63; PG&E Initial Comments at 2; PIOs Initial Comments 
at 15.
    \716\ Eversource Initial Comments at 14.
    \717\ Illinois Commission Initial Comments at 6.
    \718\ LADWP Initial Comments at 2.
    \719\ NextEra Initial Comments at 62-63.
---------------------------------------------------------------------------

    313. PIOs state that a 20-year transmission planning horizon should 
be the minimum timeframe, explaining that because transmission 
facilities can take 15 years to plan, permit, and construct, a 20-year 
transmission planning horizon can result in just-in-time planning, 
where the transmission plan is developed shortly before the process for 
siting and permitting must begin.\720\ GridLab asserts that a 20-year 
transmission planning horizon might identify regional transmission 
needs that occur after year 10, as well as transmission projects that 
would be selected and approved in later transmission planning 
cycles.\721\
---------------------------------------------------------------------------

    \720\ PIOs Initial Comments at 15.
    \721\ GridLab Initial Comments at 8-9.
---------------------------------------------------------------------------

    314. Clean Energy States support quick adoption of at least a 20-
year planning horizon because many of their member states have 
established 100% clean energy power sector or zero-carbon goals for 
their state economies by 2040 or 2050.\722\ California Municipal 
Utilities, on the other hand, support a 20-year transmission planning 
horizon, but caution that transmission costs identified can be 
significant and could rely upon speculative resources that may not come 
to fruition, namely off-shore wind development.\723\
---------------------------------------------------------------------------

    \722\ Clean Energy States Initial Comments at 2.
    \723\ California Municipal Utilities Initial Comments at 6-7.
---------------------------------------------------------------------------

    315. Many commenters highlight transmission planning regions with 
existing long-term transmission planning that either does or will 
conform to the 20-year transmission planning horizon proposed in the 
NOPR.\724\ MISO commits to continue using its 20-year forecast period 
under this proposed reform.\725\ SPP states that it currently performs 
a 20-year assessment that incorporates Long-Term Scenarios at least 
once every five years.\726\ New York Transco notes that NYISO's 
transmission planning process utilizes multiple cases and scenarios 
over a 20-year evaluation horizon.\727\ Acadia Center and CLF note that 
ISO-NE recently gained Commission approval for longer-term transmission 
studies to undertake long-term transmission planning to 2050.\728\
---------------------------------------------------------------------------

    \724\ Acadia and CLF Initial Comments at 3; CAISO Initial 
Comments at 15; California Municipal Utilities Initial Comments at 
5-6; Clean Energy States Initial Comments at 2; ISO/RTO Council 
Initial Comments at 3-4; MISO Initial Comments at 33; MISO TOs 
Initial Comments at 17; New York TOs Initial Comments at 2; New York 
Transco Initial Comments at 5; NextEra Initial Comments at 63-64 
(discussing efforts at CAISO, SPP, and MISO); Omaha Public Power 
Initial Comments at 4; PIOs Initial Comments at 14 (pointing to 
NYISO and MISO as examples of transmission planning regions already 
successfully using a 20-year transmission planning horizon); SPP 
Initial Comments at 5-6.
    \725\ MISO Initial Comments at 33.
    \726\ SPP Initial Comments at 5-6.
    \727\ New York Transco Initial Comments at 5 (citing NYISO, 
NYISO Tariffs, NYISO OATT, attach. Y section 31.4a (Public Policy 
Requirements Planning Process) (23.0.0), section 31.4.6.1).
    \728\ Acadia Center and CLF Initial Comments at 3.
---------------------------------------------------------------------------

    316. CAISO states that it currently approves transmission projects 
in its annual transmission planning process based on a 10-year outlook, 
although the CAISO OATT allows for a longer 20-year transmission 
horizon outlook to reliably and cost-effectively account for 
California's greenhouse gas and renewable energy objectives.\729\ CAISO 
explains that its 20-year outlook does not include a process for 
approving specific transmission projects, but rather allows 
considerations beyond 10 years to inform decisions in its annual

[[Page 49339]]

transmission planning process.\730\ California Municipal Utilities also 
highlight CAISO's existing transmission planning processes, noting that 
its 20-year transmission outlook calls for an estimated combined 
capital cost of $30.5 billion.\731\ NextEra notes that, while many 
transmission planning regions use or will use a 20-year transmission 
planning horizon, no requirements exist to ensure that these practices 
persist.\732\
---------------------------------------------------------------------------

    \729\ CAISO Initial Comments at 15.
    \730\ Id. at 15-16.
    \731\ California Municipal Utilities Initial Comments at 5-6 
(citing CAISO, 20-Year Transmission Outlook, Table ES-1: Cost 
estimate of transmission development to integrate resources of SB100 
Starting Point scenario (Jan. 31, 2022), https://www.caiso.com/InitiativeDocuments/Draft20-YearTransmissionOutlook.pdf).
    \732\ NextEra Initial Comments at 64-65.
---------------------------------------------------------------------------

    317. Several commenters reference existing long-term planning 
processes as support for the Commission's proposed 20-year transmission 
planning horizon.\733\ NextEra and ACEG explain that longer time 
horizons are embedded into existing integrated resource plans, through 
law or common practice, and extend into and beyond 2040 to meet 
ambitious resource goals.\734\ R Street argues that, for benchmarking 
purposes, 20- to 25-year planning horizons have been a best practice 
for integrated resource planning for decades.\735\
---------------------------------------------------------------------------

    \733\ BP Initial Comments at 5 (citing CAISO's transmission 
planning process); Idaho Power Initial Comments at 4 (noting 
NorthernGrid's 20-year transmission planning horizon); Interwest 
Initial Comments at 5 (noting existing state resource planning 
processes); Nevada Commission Initial Comments at 7 (noting its 
integrated resource planning process requiring a minimum of eight 
years); PIOs Initial Comments at 14 (noting 20-year horizons used by 
NYISO, MISO, and other transmission planning regions); SPP Market 
Monitor Initial Comments at 4-5 (noting SPP's existing transmission 
planning process); Western PIOs Initial Comments at 28-29 (noting 
Western Electricity Coordinating Council's planning scenarios and 
the integrated resource planning timelines of western vertically-
integrated utilities).
    \734\ ACEG Reply Comments at 4-5; NextEra Initial Comments at 
62-63.
    \735\ R Street Initial Comments at 6.
---------------------------------------------------------------------------

    318. LADWP asserts that the proposed 20-year transmission planning 
horizon is likely the least disruptive horizon because of its current 
use by many transmission providers. LADWP further argues that a 
consistent transmission planning horizon will optimize asset investment 
and minimize public impacts; facilitate planning, coordination, and 
development of large-scale regional transmission projects; and ensure 
that transmission providers consider the same end point assessments of 
the evolving resource mix, environmental requirements that develop 
beyond a typical 10-year period, and significant maintenance and 
retirement issues.\736\
---------------------------------------------------------------------------

    \736\ LADWP Initial Comments at 2.
---------------------------------------------------------------------------

ii. Requests for Flexibility
    319. Several commenters recommend that the Commission provide 
transmission providers in each transmission planning region with the 
flexibility to propose other transmission planning horizons that may be 
appropriate and beneficial based on their planning processes.\737\ APS 
states that it is not convinced that a prescriptive approach will yield 
the benefits that the Commission seeks.\738\
---------------------------------------------------------------------------

    \737\ Ameren Initial Comments at 13; APPA Initial Comments at 5; 
California Water Initial Comments at 14-15; EEI Initial Comments at 
11; Indicated PJM TOs Initial Comments at 10; ISO-NE Initial 
Comments at 22-23; MISO TOs Initial Comments at 17; NARUC Initial 
Comments at 5-6; NESCOE Initial Comments at 25; New York State 
Department Initial Comments at 3; New York TOs Initial Comments at 
10; Pennsylvania Commission Initial Comments at 5; TANC Initial 
Comments at 10; WIRES Initial Comments at 7; Xcel Initial Comments 
at 9.
    \738\ APS Initial Comments at 3.
---------------------------------------------------------------------------

    320. NESCOE states that there is not one ``right'' transmission 
planning horizon and that it does not support a one-size-fits-all 
transmission planning horizon requirement.\739\ NESCOE requests that 
the Commission allow transmission providers in each transmission 
planning region to demonstrate that existing tariff provisions are 
consistent with or superior to a final order mandating a minimum 
transmission planning horizon, explaining--along with ISO-NE--that ISO-
NE's Tariff does not provide a prescribed timeframe to request 
transmission analyses based on state-provided scenarios.\740\ 
Relatedly, California Commission suggests that, instead of mandating a 
20-year transmission planning horizon, the Commission should adopt 
NYISO's recommendation to provide transmission providers with the 
discretion, up to 20 years, to plan for their needs.\741\
---------------------------------------------------------------------------

    \739\ NESCOE Initial Comments at 23-24.
    \740\ ISO-NE Initial Comments at 22-23; NESCOE Initial Comments 
at 24-25.
    \741\ California Commission Initial Comments at 11-12 (citing 
NYISO ANOPR Initial Comments at 37).
---------------------------------------------------------------------------

    321. PG&E understands that not every transmission need identified 
in the latter years of a 20-year transmission planning horizon will 
require immediate selection resolution, and it therefore asks the 
Commission to give individual transmission planning regions the 
flexibility to determine how to allow for monitoring and updating 
planning assumptions for transmission projects that meet transmission 
needs beyond 10 years.\742\ ISO-NE argues that the Commission should 
permit an approach that allows (but does not require) a transmission 
planning horizon beyond 10 years because the 20-year transmission 
planning horizon could potentially limit the identification of system 
issues during interim years, inhibit adaptation to evolving policies, 
and preclude the transmission planning process from considering public 
policies that may include shorter timeframes, which may limit the 
ability to adapt to emerging needs or changing laws.\743\ NESCOE 
contends that a rigid 20-year transmission planning horizon may be 
counterproductive and could divert resources focused on meeting 
requests under ISO-NE's longer-term transmission planning process to 
study a time horizon that states, stakeholders, and ISO-NE may not find 
useful.\744\
---------------------------------------------------------------------------

    \742\ PG&E Initial Comments at 4-6.
    \743\ ISO-NE Initial Comments at 22-23.
    \744\ NESCOE Initial Comments at 24-25.
---------------------------------------------------------------------------

    322. OMS argues that the final order should permit flexibility in 
transmission planning horizons and enable transmission planning regions 
to meet objectives through routine scenario-based planning within an 
appropriate study window.\745\ Industrial Customers assert that 
transmission planning horizons should consider the time to identify, 
plan, and obtain siting and permitting approval to construct regional 
transmission facilities, and that timing can vary dramatically by 
region. Industrial Customers believe a stringent 20-year transmission 
planning horizon could create more uncertainty, resulting in stranded 
transmission investments and increased transmission rates because it is 
difficult, if not impossible, to forecast transmission needs and 
requirements 20 years into the future.\746\
---------------------------------------------------------------------------

    \745\ OMS Initial Comments at 4-5.
    \746\ Industrial Customers Reply Comments at 4-5.
---------------------------------------------------------------------------

    323. PJM States recommend, and Clean Energy Associations agree, 
that instead of requiring a transmission planning horizon of a 
particular length, the Commission should require each transmission 
provider to demonstrate that the transmission planning horizon it 
chooses is adequate to achieve the goals of Long-Term Regional 
Transmission Planning.\747\
---------------------------------------------------------------------------

    \747\ Clean Energy Associations Reply Comments at 5-6; PJM 
States Initial Comments at 4.
---------------------------------------------------------------------------

    324. New York State Department recommends that the final order 
allow states to determine the appropriate transmission planning horizon 
since New York Public Service Commission has already issued orders 
directing long-term transmission and distribution

[[Page 49340]]

planning with undefined terms.\748\ EEI and US Chamber of Commerce 
explain that state regulators may not appreciate a rigid 20-year 
transmission planning horizon requirement given that some state 
resource procurement processes use a 10-year outlook, and the proposed 
transmission planning process may thus make resource decisions that are 
not state-sanctioned.\749\ Consistent with their Coordinated Grid 
Planning Process, New York Commission and NYSERDA assert that the 
Commission should allow state regulators to help determine the 
appropriate transmission planning horizon, especially in a single-state 
RTO/ISO such as NYISO.\750\
---------------------------------------------------------------------------

    \748\ New York State Department Initial Comments at 3.
    \749\ EEI Initial Comments at 11; US Chamber of Commerce Initial 
Comments at 6.
    \750\ New York Commission and NYSERDA Initial Comments at 10-12.
---------------------------------------------------------------------------

    325. Louisiana Commission states that a 20-year transmission 
planning horizon may be longer than the planning horizon utilized in 
state integrated resource planning, explaining that its integrated 
resource planning rules allow for a 20-year default planning period, 
but also for alternative periods, and more importantly, require 5-year 
action plans.\751\
---------------------------------------------------------------------------

    \751\ Louisiana Commission Reply Comments at 8 (citing Corrected 
General Order Docket No R-30021 (LPSC 3/12/2012)).
---------------------------------------------------------------------------

    326. APPA argues, and TANC concurs, that the Commission should 
allow transmission planning regions to incorporate cost and benefit-
tracking mechanisms to reduce the risk of speculative transmission 
projects.\752\
---------------------------------------------------------------------------

    \752\ APPA Initial Comments at 26, 36; TANC Initial Comments at 
10.
---------------------------------------------------------------------------

iii. Requests for a Different Transmission Planning Horizon
    327. Several commenters argue that a 20-year transmission planning 
horizon is too long.\753\ Indicated PJM TOs contend that the Commission 
should ensure that transmission planning horizons result in the 
identification of transmission facilities that can be realistically 
planned and developed, and that 20 years may be too long given rapidly 
changing technology, generation mix, and demand patterns.\754\ 
Mississippi Commission also favors a shorter transmission planning 
horizon, arguing that there is too much uncertainty to plan 20 to 40 
years into the future.\755\ NRECA argues that a 20-year transmission 
planning horizon may allow more alternatives to be considered, but cost 
efficacy is not guaranteed. Further, NRECA argues that planning beyond 
10 years will by necessity devolve into a top-down process that would, 
at best, relegate actual load-serving entity resource plans and demand 
forecasts to a secondary status or, at worst, ignore them altogether, 
violating FPA section 217(b)(4).\756\
---------------------------------------------------------------------------

    \753\ Exelon Initial Comments at 4, 7-8; Indicated PJM TOs 
Initial Comments at 10; Industrial Customers Initial Comments at 18; 
Louisiana Commission Reply Comments at 13; Mississippi Commission 
Initial Comments at 12; Nebraska Commission Initial Comments at 3-4; 
NRECA Initial Comments at 27-28; NRG Initial Comments at 6-9, 14; 
Ohio Consumers Initial Comments at 20; Omaha Public Power Initial 
Comments at 3-4; PJM Initial Comments at 5, 58-62; US Chamber of 
Commerce Initial Comments at 5-6; Utah Commission Initial Comments 
at 13.
    \754\ Indicated PJM TOs Initial Comments at 10.
    \755\ Mississippi Commission Initial Comments at 12; see also 
Louisiana Commission Reply Comments at 13 (citing Mississippi 
Commission Initial Comments at 12).
    \756\ NRECA Initial Comments at 27-28.
---------------------------------------------------------------------------

    328. PJM Market Monitor states that uncertainty increases 
significantly as the transmission planning horizon is extended, and the 
transmission planning process should be both long-term and flexible, 
allowing transmission planners to change plans as reality changes.\757\ 
Similarly, US Chamber of Commerce asserts that, as the length of the 
transmission planning horizon increases, the number of assumptions 
increases and the quality of assumptions decreases, rendering costs and 
benefits less certain. US Chamber of Commerce states that today's 
transmission grid was not forecasted at the turn of the century, and, 
thus, forecasts made today for a similar period are likely to under or 
over-shoot transmission needs due to new and advancing generation 
technologies with commercial operation timeframes not yet known.\758\ 
Nebraska Commission states that a 20-year transmission planning horizon 
may reduce the transmission planning process to an academic exercise 
due to the amount of speculation necessarily involved.\759\
---------------------------------------------------------------------------

    \757\ PJM Market Monitor Initial Comments at 3.
    \758\ US Chamber of Commerce Initial Comments at 6.
    \759\ Nebraska Commission Initial Comments at 3.
---------------------------------------------------------------------------

    329. Industrial Customers state that the Commission has not ruled 
against transmission planning horizons under 15 years and has 
acknowledged that the average time needed to develop and build a 
transmission project is 10 years.\760\ Industrial Customers assert 
that, contrary to the Commission's view, most transmission planners use 
10-year transmission planning horizons, and transmission investment 
should be driven by shorter timeframes to plan for economic and 
reliability needs.\761\ Ohio Consumers note that the 5-year timeframe 
used by PJM's DFAX method is characterized by high uncertainty, so a 
longer timeframe would exacerbate inaccuracies.\762\
---------------------------------------------------------------------------

    \760\ Industrial Customers Initial Comments at 18.
    \761\ Industrial Customers Initial Comments at 16-19 
(referencing NYISO and the Eastern Interconnection Planning 
Collaborative planning processes).
    \762\ Ohio Consumers Initial Comments at 20.
---------------------------------------------------------------------------

    330. Several commenters argue that a 10-year transmission planning 
horizon could reduce speculation, such as with respect to the changing 
resource mix.\763\ NRG states that a shorter, 10-year transmission 
planning horizon would fit within the time horizon necessary to make 
transmission investment decisions and still reflect regional policy 
goals.\764\ Utah Commission notes that NorthernGrid's members in 2020 
adopted a 10-year transmission planning horizon and objects to being 
compelled to abandon that planning horizon in favor of a one-size-fits-
all mandate.\765\
---------------------------------------------------------------------------

    \763\ Nebraska Commission Initial Comments at 3-4; NRG Initial 
Comments at 6-9, 14; Omaha Public Power Initial Comments at 3-4.
    \764\ NRG Initial Comments at 6-9, 14.
    \765\ Utah Commission Initial Comments at 13.
---------------------------------------------------------------------------

    331. PJM and Exelon advocate for a 15-year transmission planning 
horizon to reduce uncertainty and enhance reliability.\766\ Exelon 
argues that a 15-year transmission planning horizon may yield less 
uncertain forecasts that are more likely to be actionable and better 
align with target dates in public policies.\767\ PJM argues that its 
current 15-year transmission planning horizon is sufficient to plan and 
develop needed transmission, and that forecasts of fuel prices, load 
trends, generation retirement, and other relevant parameters become 
more uncertain the further one looks out. Moreover, PJM asserts, a 
longer transmission planning horizon leads to a greater probability 
that a transmission provider will commit to a transmission project that 
will look unfortunate in hindsight.\768\
---------------------------------------------------------------------------

    \766\ Exelon Initial Comments at 4, 7-8; PJM Initial Comments at 
5, 58-62.
    \767\ Exelon Initial Comments at 4, 7-8.
    \768\ PJM Initial Comments at 59-62 (citing Promoting Regional 
Transmission Planning and Expansion to Facilitate Fuel Diversity 
Including Expanded Uses of Coal-fired Resources, Notice of Technical 
Conference, Docket No. AD05-3-000, at 1 (issued Feb. 16, 2005)).
---------------------------------------------------------------------------

    332. Some commenters argue that a transmission planning horizon 
longer than 20 years may be warranted to capture the longer-term 
benefits of transmission facilities.\769\ ACEG recommends that the 
Commission

[[Page 49341]]

consider up to a 40-year transmission planning horizon to match the 
expected life of most transmission assets.\770\ CARE Coalition argues 
that a 40-year transmission planning horizon would be consistent with 
standard practice in economics and public policy of evaluating benefits 
over the life of the asset, and that the long lead time to develop 
transmission facilities justifies a longer planning horizon.\771\
---------------------------------------------------------------------------

    \769\ ACEG Initial Comments at 6-7, 24; CARE Coalition Initial 
Comments at 40-41; Interwest Initial Comments at 5; National and 
State Conservation Organizations Initial Comments at 1; Pine Gate 
Initial Comments at 19-20; PIOs Initial Comments at 15; SEIA Initial 
Comments at 6.
    \770\ ACEG Initial Comments at 6, 24.
    \771\ CARE Coalition Initial Comments at 40-41.
---------------------------------------------------------------------------

iv. Opposition to Requests for a Different Transmission Planning 
Horizon
    333. Several commenters dispute claims that a 20-year transmission 
planning horizon introduces risks from uncertainty and that a shorter 
planning horizon is more appropriate.\772\ Southeast PIOs claim that 
the risk of unaddressed transmission needs grows over time because of 
long lead times needed for transmission development, and that SERTP's 
10-year transmission planning horizon prevented Georgia Power from 
using that process to plan for its long-term North Georgia Reliability 
& Resilience Plan and its goal to integrate 6,000 MW of renewable 
resources by 2035.\773\ Southeast PIOs assert that a longer 
transmission planning horizon will put future transmission needs on the 
radar for transmission planners and, if updated frequently, allow 
transmission providers to select transmission facilities conditional on 
subsequent transmission planning cycles, which affords planners 
flexibility to determine the need for the facility and whether there 
are more cost-effective alternatives.\774\ ACORE notes that the NOPR 
addresses the uncertainty about the future by requiring the use of 
multiple Long-Term Scenarios that are revised every three years.\775\
---------------------------------------------------------------------------

    \772\ ACORE Reply Comments at 5 (citing EPSA Initial Comments at 
7; ITC Initial Comments at 9; Mississippi Commission Initial 
Comments at 12; PJM Initial Comments at 58-62); Concerned Scientists 
Reply Comments at 18-19; PJM Initial Comments at 58-62; Southeast 
PIOs Reply Comments at 23-25 (citing Dominion Initial Comments at 
19; Southern Initial Comments at 19, 32-33).
    \773\ Southeast PIOs Reply Comments at 24 (citing Southeast PIOs 
Initial Comments at 27-28).
    \774\ Id. at 23-25.
    \775\ ACORE Reply Comments at 5.
---------------------------------------------------------------------------

    334. Several commenters state that the transmission planning 
horizon should not extend beyond 20 years to avoid overly speculative 
long-term forecasts.\776\ Entergy asserts that looking beyond 20 years 
would increase the likelihood of errors, risk billions of dollars in 
investments that may prove to be misguided, and amplify the risk of 
planning a transmission system that poorly aligns with actual future 
needs.\777\ Illinois Commission states that a transmission planning 
horizon longer than 20 years would make it difficult to accurately 
predict the factors relevant to transmission planning.\778\ Clean 
Energy Buyers propose that transmission providers seeking to adopt a 
transmission planning horizon beyond 20 years should be required to 
demonstrate the justness and reasonableness of that transmission 
planning horizon.\779\
---------------------------------------------------------------------------

    \776\ Arizona Commission Initial Comments at 3-4; California 
Commission Initial Comments at 11-13; Entergy Initial Comments at 9-
11; Georgia Commission Initial Comments at 2-3; Pennsylvania 
Commission Initial Comments at 5; US Chamber of Commerce Initial 
Comments at 4, 6.
    \777\ Entergy Initial Comments at 9-11.
    \778\ Illinois Commission Initial Comments at 6.
    \779\ Clean Energy Buyers Initial Comments at 12-13.
---------------------------------------------------------------------------

    335. Certain TDUs and Louisiana Commission oppose a 40-year 
transmission planning horizon.\780\ Certain TDUs emphasize that, as 
evidenced by the Michigan Thumb Loop transmission project, assumptions 
such as the resource mix can change in as few as seven years.\781\ 
Louisiana Commission argues that longer periods, such as the 40-year 
transmission planning horizon proposed by some commenters, will greatly 
increase the risk for errors and wasted investments. According to 
Louisiana Commission, transmission planning horizons should neither 
exceed the availability of reasonable data and assumptions nor create 
unnecessary risks that ratepayers will be required to fund transmission 
facilities that do not deliver expected benefits.\782\
---------------------------------------------------------------------------

    \780\ Certain TDUs Reply Comments at 3-6 (citing ACEG Initial 
Comments at 24); Louisiana Commission Reply Comments at 8.
    \781\ Certain TDUs Reply Comments at 3-6.
    \782\ Louisiana Commission Reply Comments at 8.
---------------------------------------------------------------------------

v. Meaning and Scope of Transmission Planning Horizon
    336. Several commenters request that the Commission define the 20-
year transmission planning horizon as a simple 20-year period, and not 
a 20-year period starting from the estimated in-service date of the 
transmission facilities, which would result in forecasting transmission 
needs beyond 20 years.\783\ Kentucky Commission Chair Chandler states 
that the usefulness of Long-Term Regional Transmission Planning and 
measuring benefits 20 years after a transmission project's in-service 
date will decrease if each project's relative benefits cannot be 
adequately measured and identified.\784\ PPL argues that tying the 
transmission planning horizon to the study date rather than the 
solution in-service date will facilitate a more realistic, certain, and 
simple transmission planning process and reduce the need for additional 
analysis.\785\ US Chamber of Commerce adds that beginning at the in-
service date of the transmission facilities would extend the effective 
transmission planning horizon to 25-30 years, thereby further 
increasing the uncertainty of Long-Term Regional Transmission Planning; 
thus, US Chamber of Commerce argues the Commission should use the 20-
year transmission planning horizon as a ceiling, rather than a floor, 
consistent with the far end of most state planning horizons, which 
would protect transmission planners from being forced to plan beyond 
the requirements of applicable state law.\786\
---------------------------------------------------------------------------

    \783\ Kentucky Commission Chair Chandler Reply Comments at 2; 
National Grid Initial Comments at 12-13; PJM States Initial Comments 
at 3; PPL Initial Comments at 6; US Chamber of Commerce Initial 
Comments at 6.
    \784\ Kentucky Commission Chair Chandler Reply Comments at 2.
    \785\ PPL Initial Comments at 6.
    \786\ US Chamber of Commerce Initial Comments at 6.
---------------------------------------------------------------------------

    337. Policy Integrity requests that the Commission clarify the 
details of the 20-year time horizon, stating that it is unclear whether 
the Commission intended the 20-year time horizon for Long-Term Regional 
Transmission Planning to be tied to construction commencing in year 
20.\787\ ISO-NE and Policy Integrity seek clarification that, if the 
Commission requires that transmission providers must study what is 
needed over the next 20 years, transmission providers are not precluded 
from evaluating what needs to be built in the short and medium 
terms.\788\ Industrial Customers assert that the proposed 20-year 
transmission planning horizon is unclear because some commenters 
interpret the Commission's proposal as requiring a 20-year transmission 
planning horizon for Long-Term Regional Transmission Planning,\789\ 
while others argue it requires a 20-year transmission planning horizon 
in existing regional transmission planning processes.\790\
---------------------------------------------------------------------------

    \787\ Policy Integrity Initial Comments at 5.
    \788\ ISO-NE Initial Comments at 23; Policy Integrity Initial 
Comments at 5.
    \789\ Industrial Customers Reply Comments at 5-6 (citing NARUC 
Initial Comments at 5).
    \790\ Industrial Customers Reply Comments at 5-6 (citing 
California Commission Initial Comments at 11).
---------------------------------------------------------------------------

    338. Several commenters support a 20-year transmission planning 
horizon if Long-Term Scenarios are used to inform the development of 
transmission

[[Page 49342]]

facilities but not used to select transmission facilities or to dictate 
construction.\791\ TANC does not believe that a 20-year transmission 
planning horizon should be used for local transmission planning 
processes or selection.\792\ Nebraska Commission states that using a 
20-year transmission planning horizon for only research, study, and 
projections will avoid speculation, increased costs, and unjust and 
unreasonable rates.\793\ NRECA asserts that using a 20-year 
transmission planning horizon in Long-Term Regional Transmission 
Planning to select transmission projects will not produce the 
granularity and certainty needed to assign costs to beneficiaries.\794\ 
Similarly, Ohio Consumers argue that too little is known about the 
location of future loads and resources and the direction of power flows 
over 20 years to use a 20-year transmission planning horizon for cost 
allocation purposes.\795\ NRG argues that use of a 20-year transmission 
planning horizon to allocate costs will lead to unjust and unreasonable 
outcomes, and instead, a 10-year transmission planning horizon is 
appropriate.\796\ New England Systems state that the Commission should 
adjust the NOPR's focus on transmission planning horizons toward an 
evolutionary and evidence-based transmission planning process aimed at 
mitigating avoidable costs for operating generation out of economic 
merit order and at improving the utilization of renewable resources 
that experience curtailment due to congestion.\797\
---------------------------------------------------------------------------

    \791\ NARUC Initial Comments at 5; Nebraska Commission Initial 
Comments at 3; Northwest and Intermountain Initial Comments at 7, 
13; NRECA Initial Comments at 23, 29; NRG Initial Comments at 6-9, 
14; Ohio Consumers Initial Comments at 20; see also Dominion Reply 
Comments at 4-5 (citing NARUC Initial Comments at 5); PJM States 
Reply Comments at 9 (citing NARUC Initial Comments at 5).
    \792\ TANC Initial Comments at 10.
    \793\ Nebraska Commission Initial Comments at 3.
    \794\ NRECA Initial Comments at 23-24 (citing GDS Assocs., Inc., 
Report, at 10 (Aug. 17, 2022)).
    \795\ Ohio Consumers Initial Comments at 1, 20.
    \796\ NRG Initial Comments at 6-9, 14.
    \797\ New England Systems Initial Comments at 21-22.
---------------------------------------------------------------------------

    339. Some commenters support a 20-year transmission planning 
horizon only if the latter portion of the planning horizon is not used 
to direct the development of transmission facilities.\798\ SERTP 
Sponsors state that the Commission should not require that regional 
transmission expansion be based on transmission planning horizons that 
are incompatible with the planning horizons used for integrated 
resource planning or supply-side resource plan development, or that 
involve a degree of speculation that the states comprising a 
transmission planning region are not willing to accept.\799\ SPP Market 
Monitor contends that if the Commission requires all RTOs/ISOs to 
perform a 20-year study, the final order should also provide guidance 
on how information determined in that long-term study will be used. SPP 
Market Monitor supports a secondary, shorter-term transmission planning 
horizon of 10 years that could be based on the results of the longer-
term 20-year studies.\800\
---------------------------------------------------------------------------

    \798\ APS Initial Comments at 3-4; Kansas Commission Initial 
Comments at 13-14; Maryland Energy Administration Initial Comments 
at 3; SERTP Sponsors Initial Comments at 20; Shell Initial Comments 
at 21; SPP Market Monitor Initial Comments at 5-6.
    \799\ SERTP Sponsors Initial Comments at 20.
    \800\ SPP Market Monitor Initial Comments at 5-6.
---------------------------------------------------------------------------

    340. Shell suggests that the 20-year transmission planning horizon 
include a developmental ``Actionable Period'' for the first 10 years, 
during which developers may be willing to invest in generation 
projects, or the RTOs/ISOs or utilities may be willing to commit to and 
authorize the construction of new transmission. Shell proposes that 
there would be an ``Indicative Period'' for the following 10 years, 
which would be used to drive the Actionable Period so that the 
Commission establishes a process that converges and integrates short, 
medium, and long-term planning. Shell asserts that its proposal could 
foster more comprehensive and efficient Long-Term Regional Transmission 
Planning and inform existing regional transmission planning 
processes.\801\ To remove speculative assumptions from Long-Term 
Regional Transmission Planning, Arizona Commission similarly suggests 
that the Commission divide the 20-year transmission planning horizon 
into two equal parts: a ``more certain'' forecast and a ``flexible'' 
forecast.\802\ Likewise, APS recommends that the Commission adopt a 20-
year transmission planning horizon for ``potential projects'' and a 10-
year planning horizon for ``planned projects'' to provide greater 
regional flexibility.\803\
---------------------------------------------------------------------------

    \801\ Shell Initial Comments at 19-23.
    \802\ Arizona Commission Initial Comments at 3-4.
    \803\ APS Initial Comments at 3-4.
---------------------------------------------------------------------------

    341. Kansas Commission, Mississippi Commission, and NRECA state 
that the results of Long-Term Regional Transmission Planning should be 
considered informational only.\804\ Kansas Commission requests that the 
Commission establish solid evidentiary and policy bases to support a 
20-year transmission planning horizon before imposing such a 
requirement.\805\ Mississippi Commission believes that transmission 
construction decisions should use a 10-year transmission planning 
horizon.\806\
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    \804\ Kansas Commission Initial Comments at 13-14; Mississippi 
Commission Reply Comments at 6; NRECA Initial Comments at 23.
    \805\ Kansas Commission Initial Comments at 13.
    \806\ Mississippi Commission Reply Comments at 6.
---------------------------------------------------------------------------

    342. Some commenters rebut arguments that Long-Term Regional 
Transmission Planning should be performed for informational purposes 
only.\807\ ACEG contends that adopting the proposed transmission 
planning methods is essential to accomplishing the Commission's 
responsibilities and that less stringent requirements have not led to 
much-needed development of high-capacity transmission throughout the 
country. ACEG further states that providing informational reports will 
do little to remedy undue discrimination and achieve actual 
transmission plans.\808\ DC and MD Offices of People's Counsel state 
that the potential benefits to ratepayers and other stakeholders of a 
20-year transmission planning horizon is significantly diminished if 
transmission planning is simply an academic exercise, without actual 
impact on future transmission development.\809\ SEIA argues that the 
Commission should mandate that scenarios developed under the final 
order be used in transmission planning rather than for informational 
purposes only or contingent on the approval of state regulators.\810\
---------------------------------------------------------------------------

    \807\ ACEG Reply Comments at 10; DC and MD Offices of People's 
Counsel Reply Comments at 5; SEIA Reply Comments at 2.
    \808\ ACEG Reply Comments at 10.
    \809\ DC and MD Offices of People's Counsel Reply Comments at 5.
    \810\ SEIA Reply Comments at 2.
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    343. Business Council for Sustainable Energy states that 
transmission planning should consider the length of time that it takes 
for transmission assets to be built and the estimated useful life of 
those facilities.\811\ California Municipal Utilities argue, and TANC 
concurs, that any lengthening of the transmission planning horizon must 
be accompanied by consumer protections that guard against speculative 
siting of generation and a rigorous re-evaluation of planning 
assumptions and other relevant factors, such as commercial viability of 
transmission projects and the associated resources.\812\
---------------------------------------------------------------------------

    \811\ Business Council for Sustainable Energy Initial Comments 
at 4.
    \812\ California Municipal Utilities Initial Comments at 3; TANC 
Initial Comments at 10.
---------------------------------------------------------------------------

c. Commission Determination
    344. We adopt the NOPR proposal to require transmission providers 
in each transmission planning region to develop

[[Page 49343]]

Long-Term Scenarios as part of Long-Term Regional Transmission Planning 
using no less than a 20-year transmission planning horizon. We further 
clarify that using a transmission planning horizon of no less than 20 
years means that transmission providers must develop Long-Term 
Scenarios to identify Long-Term Transmission Needs that will 
materialize in the 20 years or more following the commencement of the 
Long-Term Regional Transmission Planning cycle.
    345. In requiring a transmission planning horizon of not less than 
20 years, we strike a balance. On the one hand, a 20-year transmission 
planning horizon extends far enough into the future that transmission 
providers can proactively identify Long-Term Transmission Needs that 
could be met with more efficient or cost-effective Long-Term Regional 
Transmission Facilities; in contrast, as discussed below, a 
transmission planning horizon less than 20 years may limit transmission 
providers' ability to adequately plan for Long-Term Transmission Needs. 
Specifically, as described in the NOPR, a 20-year transmission planning 
horizon allows for more time between when a transmission facility is 
identified to meet a future transmission need, and when the 
transmission need materializes, allowing for sufficient time to 
identify, plan, obtain siting and permitting approval for, and 
construct Long-Term Regional Transmission Facilities. Moreover, as some 
commenters observe, several transmission providers, including MISO, 
SPP, and NYISO, already use a 20-year transmission planning horizon. On 
the other hand, based on the record before us, we find that there may 
be sufficient uncertainty with regard to system conditions and 
transmission needs beyond a 20-year horizon such that it may be 
challenging for transmission providers to forecast Long-Term 
Transmission Needs across that time period, especially for those 
transmission providers that do not presently conduct, and thus do not 
have experience with, long-term regional transmission planning. 
Accordingly, we decline to adopt a requirement to use a transmission 
planning horizon that exceeds 20 years. However, this does not preclude 
transmission providers from proposing to use a transmission planning 
horizon of more than 20 years.
    346. We clarify that transmission providers must plan for the 
entire duration of the 20-year transmission planning horizon. 
Specifically, transmission providers must, among other requirements 
established in this final order, develop and use Long-Term Scenarios to 
identify Long-Term Transmission Needs occurring in any period of the 
20-year transmission planning horizon and to evaluate potential 
transmission solutions to those needs.
    347. Certain commenters either misstate aspects of the proposed 20-
year transmission planning horizon or request clarification regarding 
the horizon.\813\ We specify that the transmission planning horizon 
starts at the beginning of the Long-Term Regional Transmission Planning 
cycle and ends 20 years from that date. The transmission planning 
horizon is not tied to the in-service date of any identified 
transmission solution; rather, potential transmission solutions are 
identified after identifying Long-Term Transmission Needs that manifest 
during the 20-year transmission planning horizon.
---------------------------------------------------------------------------

    \813\ Kentucky Commission Chair Chandler Reply Comments at 2; 
National Grid Initial Comments at 12-13; PJM States Initial Comments 
at 3; PPL Initial Comments at 6; US Chamber of Commerce Initial 
Comments at 6.
---------------------------------------------------------------------------

    348. We disagree with commenters that assert that a 20-year 
transmission planning horizon could result in Long-Term Regional 
Transmission Planning based on speculative transmission needs \814\ or, 
relatedly, that a 20-year transmission planning horizon is only 
appropriate if Long-Term Scenarios are not used to select Long-Term 
Regional Transmission Facilities.\815\ We find these assertions to be 
unfounded. In fact, the Long-Term Regional Transmission Planning 
requirements adopted in this final order are designed to avoid over-
building transmission in response to speculative transmission needs 
through a series of tools and safeguards, discussed at length 
above.\816\ To highlight just one of these safeguards, as discussed in 
the Evaluation and Selection of Long-Term Regional Transmission 
Facilities section of this final order, we require transmission 
providers to reevaluate certain previously selected Long-Term Regional 
Transmission Facilities in some circumstances to confirm that the Long-
Term Regional Transmission Facility continues to meet the transmission 
providers' selection criteria. This reevaluation process will help 
ensure that the continued selection of Long-Term Regional Transmission 
Facilities is based on the use of updated information regarding the 
existence of a Long-Term Transmission Need and the benefits that 
transmission providers expect a Long-Term Regional Transmission 
Facility to provide.
---------------------------------------------------------------------------

    \814\ E.g., TANC Initial Comments at 10.
    \815\ NARUC Initial Comments at 5; Nebraska Commission Initial 
Comments at 3; Northwest and Intermountain Initial Comments at 7, 
13; NRECA Initial Comments at 23, 29; NRG Initial Comments at 6-9, 
14; Ohio Consumers Initial Comments at 20; see also PJM States Reply 
Comments at 9 (citing NARUC Initial Comments at 5).
    \816\ See supra Participation in Long-Term Regional Transmission 
Planning section.
---------------------------------------------------------------------------

    349. We disagree with commenters that assert that the Commission 
should adopt a shorter transmission planning horizon.\817\ A 
transmission planning horizon of less than 20 years would fail to 
sufficiently capture Long-Term Transmission Needs given that at least 
some of the drivers of such needs extend up to 20 years into the future 
(e.g., many state laws include requirements to be met 15 to 20 years in 
the future). Additionally, a shorter minimum transmission planning 
horizon may not allow for sufficient time to develop Long-Term Regional 
Transmission Facilities with long lead-time requirements or to compare 
alternative transmission solutions to identify more efficient or cost-
effective transmission solutions to meet Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \817\ Exelon Initial Comments at 4, 7-8; Industrial Customers 
Initial Comments at 18; Mississippi Commission Initial Comments at 
34; Nebraska Commission Initial Comments at 3-4; NRECA Initial 
Comments at 27-28; NRG Initial Comments at 6-9, 14; Omaha Public 
Power Initial Comments at 3-4; PJM Initial Comments at 5, 58-62; US 
Chamber of Commerce Initial Comments at 6; Utah Commission Initial 
Comments at 13.
---------------------------------------------------------------------------

    350. We disagree with commenters that assert requiring a 20-year 
transmission planning horizon is incompatible with planning horizons 
used with state integrated resource planning.\818\ In addition to the 
discussions in the Overall Need for Reform and Legal Authority to Adopt 
Reforms for Long-Term Regional Transmission Planning sections regarding 
state integrated resource planning, we note that regardless of the 
planning horizon used in a state integrated resource planning process, 
the results of that process can be incorporated into Long-Term Regional 
Transmission Planning to identify Long-Term Transmission Needs. In 
fact, as explained in State-Approved Utility Integrated Resource Plans 
and Expected Supply Obligations for Load-Serving Entities (Factor 
Category Three) section below, integrated resource plans are part of 
the Categories of Factors and thus, transmission providers must 
incorporate information on the load-serving entities' projected loads 
and resources over the planning horizon. The fact that a state 
integrated resource plan does not extend out a full 20 years--or 
extends further

[[Page 49344]]

into the future--does not change the obligation for transmission 
providers to incorporate the information that is available over the 20-
year transmission planning horizon.
---------------------------------------------------------------------------

    \818\ SERTP Sponsors Initial Comments at 21.
---------------------------------------------------------------------------

    351. In response to ISO-NE, and Policy Integrity,\819\ the 20-year 
transmission planning horizon is distinct from the requirement to 
calculate benefits of an identified Long-Term Regional Transmission 
Facility over a minimum of 20 years from the estimated in-service date, 
as discussed in the Required Benefits section.
---------------------------------------------------------------------------

    \819\ ISO-NE Initial Comments at 23; Policy Integrity Initial 
Comments at 5.
---------------------------------------------------------------------------

2. Frequency of Long-Term Scenario Revisions
a. NOPR Proposal
    352. In the NOPR, the Commission proposed to require each 
transmission provider to develop Long-Term Scenarios at least every 
three years, by reassessing whether the data inputs and factors 
incorporated in the previously developed Long-Term Scenarios need to be 
updated and then revising the Long-Term Scenarios as needed to reflect 
updated data inputs and factors. The Commission also proposed to 
require that the development of Long-Term Scenarios be completed within 
three years, before the next three-year assessment commences.\820\
---------------------------------------------------------------------------

    \820\ NOPR, 179 FERC ] 61,028 at P 97.
---------------------------------------------------------------------------

    353. The Commission preliminarily found that a three-year frequency 
requirement balances the need of transmission providers to reassess 
changes in the resource mix and demand, as technology, markets, and 
policies have the potential to rapidly change, against the burden of 
developing Long-Term Scenarios that can take a year or longer to 
produce. The Commission stated that this three-year frequency 
requirement would allow transmission providers to identify new 
transmission needs driven by changes in the resource mix and demand 
during the interim years of the transmission planning period, and 
update previously identified transmission needs, if warranted.\821\
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    \821\ NOPR, 179 FERC ] 61,208 at P 99.
---------------------------------------------------------------------------

b. Comments
i. Support for Frequency of Long-Term Scenario Revisions
    354. Many commenters support the Commission's proposal to require 
transmission providers in each transmission planning region to develop 
Long-Term Scenarios at least every three years, by reassessing whether 
the data inputs and factors incorporated in their previously developed 
Long-Term Scenarios need to be updated and then revising the Long-Term 
Scenarios as needed to reflect updated data inputs and factors.\822\ 
Arizona Commission and Interwest state that the proposed three-year 
process aligns with their existing regional transmission planning 
processes.\823\ Several commenters assert that this proposal allows for 
Long-Term Scenarios to remain accurate and account for material 
technological, political, environmental, and operational developments 
in the energy industry,\824\ with some commenters indicating that past 
experience demonstrates that the energy industry is rapidly 
changing.\825\ For example, PIOs share that MISO recently recognized 
assumptions in its MISO Transmission Expansion Plan did not capture the 
rate of change for the region's fuel mix.\826\
---------------------------------------------------------------------------

    \822\ ACORE Initial Comments at 10; Advanced Energy Buyers 
Initial Comments at 7; AEE Initial Comments at 8-9; AEP Initial 
Comments at 5, 8, 13-14; Amazon Initial Comments at 3; Arizona 
Commission Initial Comments at 4; BP Initial Comments at 4; 
Breakthrough Energy Supplemental Comments at 1; CAISO Initial 
Comments at 21; California Water Initial Comments at 15; Clean 
Energy Associations Initial Comments at 10; Clean Energy Buyers 
Initial Comments at 13; DC and MD Offices of People's Counsel 
Initial Comments at 8; Entergy Initial Comments at 11; Idaho Power 
Initial Comments at 4; Interwest Initial Comments at 6-8; Joint 
Consumer Advocates Initial Comments at 8; Nevada Commission Initial 
Comments at 7; New England Offshore Wind Initial Comments at 2; New 
Jersey Commission Initial Comments at 11; NYISO Initial Comments at 
18; Pacific Northwest State Agencies Initial Comments at 13-14; 
Pennsylvania Commission Initial Comments at 5; PG&E Initial Comments 
at 6; PIOs Initial Comments at 16; PJM Initial Comments at 5-6, 63; 
SEIA Initial Comments at 6; SPP Market Monitor Initial Comments at 
6; US DOE Initial Comments at 11; Vermont State Entities Initial 
Comments at 5; WE ACT Initial Comments at 3.
    \823\ Arizona Commission Initial Comments at 3; Interwest 
Initial Comments at 6-8.
    \824\ Advanced Energy Buyers Initial Comments at 7; California 
Water Initial Comments at 15; ELCON Initial Comments at 11; Joint 
Consumer Advocates at 8; PIOs Initial Comments at 17; SPP Market 
Monitor Initial Comments at 6; US DOE Initial Comments at 11.
    \825\ Advanced Energy Buyers Initial Comments at 7; ELCON 
Initial Comments at 11.
    \826\ PIOs Initial Comments at 16-17 (stating that MISO's 
prediction for changes in its fuel mix 15 years out in the MISO 
Transmission Expansion Plan 2020 Report had already materialized 
before that final report was published).
---------------------------------------------------------------------------

    355. Pennsylvania Commission states that routine reviews could 
update information and data, justify modifications to transmission 
plans, and reduce the risk of uneconomic transmission investments.\827\ 
ELCON notes that the proposed three-year reassessment provides the 
opportunity to consult recent data and update the probability of each 
scenario, which will produce better outcomes in the transmission 
planning process.\828\ Joint Consumer Advocates state that long-term 
transmission plans must be revisited regularly and with sufficient 
frequency to ensure that they remain accurate and account for material 
developments.\829\ AEE states that triennial updates will provide a 
suitable amount of time for stakeholders to complete comprehensive 
studies while also ensuring that scenarios do not become stale as 
advanced energy technology deployment scales more rapidly and policy 
changes disrupt existing assumptions.\830\
---------------------------------------------------------------------------

    \827\ Pennsylvania Commission Initial Comments at 5.
    \828\ ELCON Initial Comments at 11.
    \829\ Joint Consumer Advocates Initial Comments at 8.
    \830\ AEE Initial Comments at 8-9.
---------------------------------------------------------------------------

    356. Louisiana Commission avers that the proposed three-year 
reassessment will prevent transmission providers from ignoring changes 
that might better reflect future assumptions.\831\ PIOs state that a 
three-year update will also help address issues that could occur if a 
transmission provider is too aggressive or conservative when defining 
scenarios.\832\ DC and MD Offices of People's Counsel recommend that 
plans be updated every three years.\833\
---------------------------------------------------------------------------

    \831\ Louisiana Commission Reply Comments at 9.
    \832\ PIOs Initial Comments at 17.
    \833\ DC and MD Offices of People's Counsel Reply Comments at 2.
---------------------------------------------------------------------------

    357. Entergy and Interwest state that a three-year reassessment 
cycle balances the need for recent data and the time and resources 
needed to develop the updates.\834\ LADWP states that a rolling near-
term planning horizon provides the long-term transmission planning 
process with up-to-date information without being too frequent.\835\ 
New Jersey Commission notes that reassessments more frequent than every 
three years would be overly burdensome.\836\ Similarly, Nebraska 
Commission states that a frequency shorter than every three years would 
require almost constant updates from transmission providers, which 
would drive up costs, while a frequency longer than three to five years 
could risk the underlying information becoming stale between 
revisions.\837\
---------------------------------------------------------------------------

    \834\ Entergy Initial Comments at 11; Interwest Initial Comments 
at 6.
    \835\ LADWP Initial Comments at 3.
    \836\ New Jersey Commission Initial Comments at 11.
    \837\ Nebraska Commission Initial Comments at 4.
---------------------------------------------------------------------------

    358. Certain TDUs suggest that the Commission address concerns that 
a three-year review period would put significant strain on transmission 
provider resources by clarifying that three-year assessments would 
review the key drivers and assumptions behind

[[Page 49345]]

a transmission plan with updates as needed for material changes rather 
than a rerun of the full transmission planning process. In addition, 
Certain TDUs state that a three-year reassessment of initial 
transmission plans would result in more transparency and consideration 
of alternatives in the transmission planning process.\838\ In contrast, 
PJM requests that the Commission clarify that Long-Term Scenarios would 
be completely updated with new data, updated factors, and the best 
information available at least every three years, not merely partially 
reassessed. PJM also requests that the Commission clarify that scenario 
evaluations will not overlap, as re-runs are expensive, and a 
predictable three-year clock will make the process run smoothly.\839\
---------------------------------------------------------------------------

    \838\ Certain TDUs Reply Comments at 7.
    \839\ PJM Initial Comments at 6, 63-64.
---------------------------------------------------------------------------

    359. AEP requests that the Commission require all transmission 
planning regions to continuously follow the same, consistent three-year 
transmission planning cycles to align future efforts and ease burdens 
on transmission providers and developers operating in multiple 
transmission planning regions and to promote better coordination among 
regions concerning potential interregional transmission solutions.\840\
---------------------------------------------------------------------------

    \840\ AEP Initial Comments at 5, 8, 13-14; AEP Reply Comments at 
5.
---------------------------------------------------------------------------

    360. Southeast PIOs support the NOPR proposal to require 
transmission providers to reassess and revise Long-Term Scenarios every 
three years, arguing that it would synchronize with existing state 
processes and ensure that long-term regional transmission plans remain 
an up-to-date resource for state planning.\841\ Similarly, Certain TDUs 
argue that a five-year transmission planning cycle is too long and that 
a three-year transmission planning cycle would be more likely to 
account for unforeseen changes, helping to prevent inefficient 
transmission development and balance planning for future needs with the 
need to quickly identify material changes to planning assumptions.\842\
---------------------------------------------------------------------------

    \841\ Southeast PIOs Reply Comments at 25.
    \842\ Certain TDUs Reply Comments at 5-6.
---------------------------------------------------------------------------

ii. Concerns About Frequency of Long-Term Scenario Revisions
    361. Some commenters urge the Commission to provide flexibility for 
transmission providers to determine the frequency at which they must 
develop Long-Term Scenarios by reassessing whether the data inputs and 
factors incorporated in their previously developed Long-Term Scenarios 
need to be updated and then revising the Long-Term Scenarios as needed 
to reflect updated data inputs and factors.\843\ EEI requests that the 
Commission allow transmission providers in each transmission planning 
region to initiate a new Long-Term Scenario process in lieu of a 
refresh of old Long-Term Scenarios.\844\ California Commission and 
Omaha Public Power argue that requiring transmission providers to 
reassess and revise Long-Term Scenarios at least every three years will 
create a significant compliance burden without improving planning 
outcomes, such as forecast accuracy.\845\
---------------------------------------------------------------------------

    \843\ Ameren Initial Comments at 12-13; American Municipal Power 
Initial Comments at 33; California Commission Initial Comments at 
16; Duke Initial Comments at 11; ISO-NE Initial Comments at 24; MISO 
Initial Comments at 28-29; MISO TOs Initial Comments at 17; NARUC 
Initial Comments at 6-7; NESCOE Initial Comments at 25-26; OMS 
Initial Comments at 4-5; Pacific Northwest State Agencies Initial 
Comments at 15; Vermont State Entities Initial Comments at 5; WIRES 
Initial Comments at 7.
    \844\ EEI Initial Comments at 12.
    \845\ California Commission Initial Comments at 16; Omaha Public 
Power Initial Comments at 3.
---------------------------------------------------------------------------

    362. MISO TOs argue that flexibility is warranted because MISO is 
already implementing Long-Term Regional Transmission Planning, as well 
as reassessing its data as needed.\846\ MISO states that the NOPR 
proposal is overly prescriptive, may not reflect stakeholder and 
regional needs, and could result in a compliance exercise without the 
prospect of transmission expansion.\847\ NESCOE and OMS suggest that 
the Commission require transmission providers to reassess Long-Term 
Scenarios at regular intervals but leave the timing of that 
reassessment to the transmission planning region.\848\ MISO also 
recommends that the Commission allow transmission providers to reuse 
Long-Term Scenarios as long as they update the relevant input data to 
reflect the latest available information.\849\
---------------------------------------------------------------------------

    \846\ MISO TOs Initial Comments at 17.
    \847\ MISO Initial Comments at 28.
    \848\ NESCOE Initial Comments at 25-26; OMS Initial Comments at 
4-5.
    \849\ MISO Initial Comments at 29.
---------------------------------------------------------------------------

    363. Duke asserts that the Commission should allow transmission 
planning regions to propose their own cycles to reassess and revise 
Long-Term Scenarios to meet the needs of the region, keep pace with 
markets and policies across the country, and align their processes with 
state integrated resource planning processes.\850\ Similarly, WIRES 
requests a variance to the proposed three-year scenario reassessment 
requirement because three years may be too short and could potentially 
be disruptive or increase costs. WIRES further asks that the Commission 
clarify that transmission providers are not required to reassess 
previously approved transmission projects as part of their triennial 
review process.\851\
---------------------------------------------------------------------------

    \850\ Duke Initial Comments at 12.
    \851\ WIRES Initial Comments at 7.
---------------------------------------------------------------------------

    364. Pacific Northwest State Agencies state that the Commission 
should set three years as a minimum and provide transmission planning 
regions with the flexibility to work with states to determine the 
appropriate schedule for developing Long-Term Scenarios.\852\ 
Similarly, Vermont State Entities and Pennsylvania Commission argue 
that transmission planning regions should have the flexibility to 
conduct reassessments at intervals shorter than every three years.\853\
---------------------------------------------------------------------------

    \852\ Pacific Northwest State Agencies Initial Comments at 15.
    \853\ Pennsylvania Commission Initial Comments at 5; Vermont 
State Entities Initial Comments at 5.
---------------------------------------------------------------------------

    365. NYISO recommends that the final order should allow 
transmission planning regions to modify or add to their Long-Term 
Scenarios to account for changes that would significantly affect their 
analysis when they occur instead of waiting for the next transmission 
planning cycle. NYISO further requests that the Commission clarify 
that, if a transmission planning region requires more than three years 
to complete a given transmission planning cycle, it may extend the 
three-year time period. In addition, NYISO requests that the Commission 
permit transmission providers in each transmission planning region to 
commence the next Long-Term Regional Transmission Planning cycle using 
current information even if the prior transmission planning cycle is 
running in parallel. NYISO adds that the Commission should allow 
transmission planning regions to use their existing Long-Term Scenarios 
for the duration of a Long-Term Regional Transmission Planning cycle, 
even if it runs beyond three years, to avoid stopping and re-starting 
that cycle due to changes in circumstances.\854\
---------------------------------------------------------------------------

    \854\ NYISO Initial Comments at 19.
---------------------------------------------------------------------------

    366. Some commenters raise concerns that the proposal to require 
development of Long-Term Scenarios at least every three years may 
create overlapping planning assessments and suggest ways to avoid that 
situation.\855\ ISO-NE states that the timeframe for Long-Term Regional 
Transmission Planning should account for all the elements of the 
process, such as implementing the process for selecting

[[Page 49346]]

transmission solutions, before the next long-term study begins. ISO-NE 
indicates that this will allow subsequent Long-Term Regional 
Transmission Planning studies to account for the outcomes of the 
preceding transmission planning cycle and avoid unnecessary study 
overlap between cycles.\856\
---------------------------------------------------------------------------

    \855\ Eversource Initial Comments at 15; ISO-NE Initial Comments 
at 24; NESCOE Initial Comments at 26; PJM Initial Comments at 63.
    \856\ ISO-NE Initial Comments at 24.
---------------------------------------------------------------------------

    367. Eversource suggests that the Commission require completion of 
project selection before the development of the next set of Long-Term 
Scenarios, arguing that it would undermine the project selection 
process if the current three-year Long-Term Scenario cycle fails to 
include selected transmission facilities from the prior three-year 
cycle.\857\
---------------------------------------------------------------------------

    \857\ Eversource Initial Comments at 15.
---------------------------------------------------------------------------

    368. Similarly, NESCOE is concerned that the three-year Long-Term 
Scenario cycle requirement is inflexible and could interfere with 
existing procedures in New England. NESCOE states that ISO-NE's longer-
term transmission planning process requires that a planning process be 
concluded before a new one can begin, and that a request for a longer-
term transmission study may be submitted to ISO-NE no earlier than six 
months after the conclusion of the prior study.\858\
---------------------------------------------------------------------------

    \858\ NESCOE Initial Comments at 26.
---------------------------------------------------------------------------

    369. Some commenters argue that requiring transmission providers to 
reassess and revise their Long-Term Scenarios every three years may be 
too frequent and costly, asserting that between every three and five 
years may be more appropriate.\859\ ITC avers that a three-year 
transmission planning cycle for Long-Term Regional Transmission 
Planning would exceed the capabilities of the transmission providers 
administering the process.\860\ Likewise, NRECA asserts that developing 
multiple Long-Term Scenarios and updating them every three years will 
require significant time and resources, as well as substantial changes 
in transmission planning throughout the country. NRECA asserts that 
existing power supply and transmission planning models employ different 
assumptions that cannot be used to prepare 20-year Long-Term Scenarios, 
much less update them every three years.\861\
---------------------------------------------------------------------------

    \859\ ACEG Initial Comments at 7, 25; Breakthrough Energy 
Initial Comments at 12-13; EEI Initial Comments at 12; Indicated PJM 
TOs Initial Comments at 11-12; ITC Initial Comments at 5, 9-11; Pine 
Gate Initial Comments at 19-20.
    \860\ ITC Initial Comments at 10.
    \861\ NRECA Initial Comments at 23 (citing GDS Assocs., Report, 
at 8-10 (Aug. 17, 2022)).
---------------------------------------------------------------------------

iii. Support for Different Frequency of Long-Term Scenario Revisions
    370. Western PIOs support mandating a two-year timeframe for 
revision, as three years may be too long and therefore may miss 
important updated data inputs.\862\
---------------------------------------------------------------------------

    \862\ Western PIOs Initial Comments at 30.
---------------------------------------------------------------------------

    371. Shell argues that the Commission should require transmission 
providers to reassess and revise their Long-Term Scenarios every five 
years, asserting that the proposal to use three years could create too 
much uncertainty and delay the development of renewable generation 
being developed to comply with state climate objectives and resource 
adequacy requirements in forward-looking capacity markets.\863\ 
Indicated PJM TOs argue that three years may be insufficient to perform 
relevant studies and recommend that the Commission provide transmission 
providers with the flexibility to adopt four- or five-year transmission 
planning cycles.\864\
---------------------------------------------------------------------------

    \863\ Shell Initial Comments at 18-19.
    \864\ Indicated PJM TOs Initial Comments at 11-12.
---------------------------------------------------------------------------

    372. Exelon argues that a three-year transmission planning cycle is 
too short, as it is unlikely that transmission needs will surface 
within three years, and that conducting a study so soon could create 
uncertainty that recently selected transmission projects will be 
revisited. Exelon instead recommends that the final order adopt a five-
year transmission planning cycle requirement with a provision that 
requires transmission providers to initiate a new cycle sooner, with 
good reason, to better align with the time needed to permit and 
construct new transmission infrastructure.\865\
---------------------------------------------------------------------------

    \865\ Exelon Initial Comments at 9.
---------------------------------------------------------------------------

    373. Similarly, PPL argues that a five-year transmission planning 
cycle will allow sufficient time for one transmission planning cycle to 
be completed before the subsequent cycle commences.\866\ Pine Gate 
states that a five-year transmission planning cycle is warranted given 
the size and complexity of transmission planning regions and the time 
needed to receive and incorporate stakeholder feedback and to achieve 
consensus on cost allocation. Pine Gate further notes that a five-year 
transmission planning cycle would more closely align the results of 
Long-Term Regional Transmission Planning with the time horizons for 
reliability planning and other transmission planning processes.\867\
---------------------------------------------------------------------------

    \866\ PPL Initial Comments at 6.
    \867\ Pine Gate Initial Comments at 20-21.
---------------------------------------------------------------------------

    374. SPP argues in favor of the update procedures in its current 
transmission planning processes rather than the three-year schedule for 
updating Long-Term Scenarios proposed in the NOPR. SPP states that it 
performs a 20-year assessment that incorporates Long-Term Scenarios at 
least once every five years and that, on an annual basis, SPP assesses 
data inputs and factors incorporated into the assessment.\868\
---------------------------------------------------------------------------

    \868\ SPP Initial Comments at 5-6.
---------------------------------------------------------------------------

iv. Miscellaneous Comments
    375. Several commenters state that the Commission should regularly 
review transmission planning processes and assumptions to account for 
new developments.\869\ Pattern Energy states that the best way to make 
20-year transmission plans useful is for their outputs to be fed into 
near-term (i.e., five-to-seven-year horizon) transmission planning 
activities.\870\
---------------------------------------------------------------------------

    \869\ Clean Energy Buyers Initial Comments at 13; SREA Reply 
Comments at 26-27.
    \870\ Pattern Energy Initial Comments at 22.
---------------------------------------------------------------------------

    376. ELCON recommends that the Commission hold a technical 
conference after the first three-year reassessment period for Long-Term 
Scenarios to allow transmission providers to offer their experiences 
with and best practices for Long-Term Regional Transmission 
Planning.\871\
---------------------------------------------------------------------------

    \871\ ELCON Initial Comments at 11.
---------------------------------------------------------------------------

c. Commission Determination
    377. We modify the NOPR proposal to require transmission providers 
in each transmission planning region to reassess and revise the Long-
Term Scenarios that they use in Long-Term Regional Transmission 
Planning at least once every five years. In implementing this 
requirement, transmission providers in each transmission planning 
region must reassess whether the data inputs and factors incorporated 
in previously developed Long-Term Scenarios need to be updated and then 
revise those Long-Term Scenarios, as needed, to reflect updated data 
inputs and factors. At the outset of a Long-Term Regional Transmission 
Planning cycle, transmission providers may develop the new Long-Term 
Scenarios either by crafting entirely new Long-Term Scenarios, or by 
updating the data inputs and factors of previously developed Long-Term 
Scenarios.
    378. To assist transmission providers in implementing the 
requirement to reassess and revise Long-Term Scenarios used in Long-
Term Regional Transmission Planning at least once every five years, we 
clarify that the process, which begins with the development of Long-
Term Scenarios using best available data inputs, and

[[Page 49347]]

proceeds to identifying Long-Term Transmission Needs, measuring the 
benefits of Long-Term Regional Transmission Facilities to address those 
needs, and evaluating and deciding whether to select Long-Term Regional 
Transmission Facilities (collectively, the Long-Term Regional 
Transmission Planning cycle),\872\ must conclude at a date that is no 
later than five years after the date that it began.
---------------------------------------------------------------------------

    \872\ The Long-Term Regional Transmission Planning cycle 
encompasses all components of Long-Term Regional Transmission 
Planning, including each of these foundational steps.
---------------------------------------------------------------------------

    379. While we find that the record supports a five-year interval 
before new Long-Term Scenarios must be developed, we also conclude that 
transmission providers should not need the full five-year period to 
reach the point in Long-Term Regional Transmission Planning at which 
they decide whether to select Long-Term Regional Transmission 
Facilities that they have evaluated. Accordingly, we require 
transmission providers to complete the steps of the Long-Term Regional 
Transmission Planning cycle and determine whether to select Long-Term 
Regional Transmission Facilities no later than three years from the 
date when the Long-Term Regional Transmission Planning cycle 
began.\873\ Specifically, we find the record demonstrates that three 
years provides sufficient time for transmission providers to develop 
Long-Term Scenarios, identify Long-Term Transmission Needs, measure the 
benefits of Long-Term Regional Transmission Facilities to address those 
needs, and evaluate and decide whether to select Long-Term Regional 
Transmission Facilities.\874\ At the same time, we are persuaded by 
commenters' concerns that requiring the Long-Term Regional Transmission 
Planning cycle to repeat at three-year intervals could be 
administratively burdensome, and that the benefit of updating Long-Term 
Scenarios every three years may not outweigh those additional 
burdens.\875\ We therefore find that requiring selection decisions to 
occur within three years of commencing a Long-Term Regional 
Transmission Planning cycle, while allowing as long as five years 
between the commencement of each planning cycle, strikes an appropriate 
balance by ensuring timely identification, evaluation, and selection of 
more efficient or cost-effective Long-Term Regional Transmission 
Facilities, while balancing the administrative burden associated with 
updating the Long-Term Scenarios that form the basis for Long-Term 
Regional Transmission Planning during each planning cycle.\876\
---------------------------------------------------------------------------

    \873\ To be clear, nothing in this final order prevents 
transmission providers from evaluating and selecting additional 
Long-Term Regional Transmission Facilities after year three of the 
Long-Term Regional Transmission Planning cycle and before the next 
five-year Long-Term Regional Transmission Planning cycle begins. 
However, if Long-Term Regional Transmission Facilities are selected 
at year three of the Long-Term Regional Transmission Planning cycle, 
those same Long-Term Regional Transmission Facilities cannot be de-
selected during the remainder of the current five-year planning 
cycle.
    \874\ See ACORE Initial Comments at 10; Advanced Energy Buyers 
Initial Comments at 7; AEE Initial Comments at 8-9; AEP Initial 
Comments at 5, 8, 13-14; Amazon Initial Comments at 3; Arizona 
Commission Initial Comments at 4; BP Initial Comments at 4; 
Breakthrough Energy Supplemental Comments at 1; CAISO Initial 
Comments at 21; California Water Initial Comments at 15; Clean 
Energy Associations Initial Comments at 10; Clean Energy Buyers 
Initial Comments at 13; DC and MD Offices of People's Counsel 
Initial Comments at 8; Entergy Initial Comments at 11; Idaho Power 
Initial Comments at 4; Interwest Initial Comments at 6-8; Joint 
Consumer Advocates Initial Comments at 8; Nevada Commission Initial 
Comments at 7; New England Offshore Wind Initial Comments at 2; New 
Jersey Commission Initial Comments at 11; NYISO Initial Comments at 
18; Pacific Northwest State Agencies Initial Comments at 13-14; 
Pennsylvania Commission Initial Comments at 5; PG&E Initial Comments 
at 6; PIOs Initial Comments at 16; PJM Initial Comments at 5-6, 63; 
SEIA Initial Comments at 6; SPP Market Monitor Initial Comments at 
6; US DOE Initial Comments at 11; Vermont State Entities Initial 
Comments at 5; WE ACT Initial Comments at 3.
    \875\ See Ameren Initial Comments at 12-13; American Municipal 
Power Initial Comments at 33; California Commission Initial Comments 
at 16; Duke Initial Comments at 11; ISO-NE Initial Comments at 24; 
MISO Initial Comments at 28-29; MISO TOs Initial Comments at 17; 
NARUC Initial Comments at 6-7; NESCOE Initial Comments at 25-26; OMS 
Initial Comments at 4-5; Pacific Northwest State Agencies Initial 
Comments at 15; Vermont State Entities Initial Comments at 5; WIRES 
Initial Comments at 7.
    \876\ Accordingly, we decline NYISO's request to clarify that 
the transmission provider may extend the transmission planning 
cycle. As explained, we find that three years provides sufficient 
time to complete the actions necessary to make selection decisions.
---------------------------------------------------------------------------

    380. We find that requiring transmission providers to reassess and 
revise Long-Term Scenarios used in Long-Term Regional Transmission 
Planning at least once every five years is necessary to ensure that the 
Long-Term Scenarios accurately reflect factors that may change over the 
five-year time span, such as changes in technology, load forecasts, or 
Federal, federally-recognized Tribal, state, or local laws. 
Furthermore, regular scenario reassessment and revision may also 
address some of the uncertainty associated with Long-Term Regional 
Transmission Planning over a 20-year transmission planning horizon that 
some commenters assert may result in under-building or over-building 
transmission facilities.\877\ As discussed below in the Specificity of 
Data Inputs section, nothing in this final order prohibits transmission 
providers from updating the inputs used to inform Long-Term Scenarios 
during a Long-Term Regional Transmission Planning cycle.
---------------------------------------------------------------------------

    \877\ Industrial Customers Initial Comments at 15-16, 19-21; 
NRECA Initial Comments at 18-19, 28; Vistra Initial Comments at 7.
---------------------------------------------------------------------------

    381. As discussed in the Evaluation and Selection of Long-Term 
Regional Transmission Facilities section of this final order, 
transmission providers must designate a point in the evaluation process 
at which they will make a decision to either select or not select the 
relevant Long-Term Regional Transmission Facility (or portfolio of such 
Facilities). Further, we clarify that transmission providers must 
conclude a Long-Term Regional Transmission Planning cycle before 
developing Long-Term Scenarios at the beginning of the next Long-Term 
Regional Transmission Planning cycle. Given that, as we state directly 
above, nothing in this final order prevents transmission providers from 
evaluating and selecting additional Long-Term Regional Transmission 
Facilities after year three of the Long-Term Regional Transmission 
Planning cycle and before the next five-year Long-Term Regional 
Transmission Planning cycle begins, we further find that transmission 
providers must designate the point in time or action that concludes a 
Long-Term Regional Transmission Planning cycle. Such designation will 
ensure transparency regarding whether the transmission providers are 
engaging in the evaluation and selection of additional Long-Term 
Regional Transmission Facilities after year three of the Long-Term 
Regional Transmission Planning cycle.
    382. Some commenters express concern that the proposal to reassess 
Long-Term Scenarios in concurrent Long-Term Regional Transmission 
Planning cycles would create uncertainty as to which cycle produced the 
controlling outcome and would burden stakeholders (e.g., requiring them 
to provide input on the development of Long-Term Scenarios for the next 
Long-Term Regional Transmission Planning cycle while also requiring 
them to provide input on Long-Term Regional Transmission Facilities 
being considered for selection from the previous Long-Term Regional 
Transmission Planning cycle).\878\ By providing for a period of up to 
two years between the date by which transmission

[[Page 49348]]

providers are required to make a decision to select or not select Long-
Term Regional Transmission Facilities and the date by which the next 
Long-Term Regional Transmission Planning cycle must commence, and by 
clarifying that transmission providers must conclude one Long-Term 
Regional Transmission Planning cycle before another begins, this final 
order will appropriately minimize confusion regarding overlap between 
planning assessments. Specifically, this clarification will allow 
transmission providers to use in subsequent Long-Term Regional 
Transmission Planning cycles updated base or reference cases that 
include all Long-Term Regional Transmission Facilities that were 
selected in a previous Long-Term Regional Transmission Planning cycle, 
including those not yet in service. We find that including the selected 
Long-Term Regional Transmission Facilities in subsequent Long-Term 
Regional Transmission Planning cycles will improve the accuracy of 
Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------

    \878\ Eversource Initial Comments at 15; ISO-NE Initial Comments 
at 24; NESCOE Initial Comments at 26.
---------------------------------------------------------------------------

    383. In response to WIRES's request,\879\ we clarify that 
transmission providers need not routinely reevaluate selected Long-Term 
Regional Transmission Facilities. However, we note that, as discussed 
further in the Evaluation and Selection of Long-Term Regional 
Transmission Facilities section below, we require transmission 
providers to reevaluate previously selected Long-Term Regional 
Transmission Facilities in certain specified circumstances.
---------------------------------------------------------------------------

    \879\ WIRES Initial Comments at 7.
---------------------------------------------------------------------------

    384. Given that we are requiring transmission providers in each 
transmission planning region to reassess and revise Long-Term Scenarios 
used in Long-Term Regional Transmission Planning at least once every 
five years, thus establishing the maximum length of the Long-Term 
Regional Transmission Planning cycle, we affirm that to the extent that 
transmission providers believe that a shorter Long-Term Regional 
Transmission Planning cycle is appropriate for their transmission 
planning region and circumstances, they may propose on compliance to 
conduct Long-Term Regional Transmission Planning more frequently than 
every five years.
    385. We find AEP's request to require all transmission planning 
regions to follow the same-length transmission planning cycles is 
beyond the scope of this proceeding.\880\ In the NOPR, we proposed 
frequency requirements related to the Long-Term Regional Transmission 
Planning cycles but did not propose a requirement for transmission 
providers to align their regional transmission planning cycles with 
those of the transmission providers in neighboring transmission 
planning regions.
---------------------------------------------------------------------------

    \880\ AEP Initial Comments at 5, 8, 14; AEP Reply Comments at 5.
---------------------------------------------------------------------------

    386. While we do not establish a technical conference after the 
first Long-Term Regional Transmission Planning cycle, as ELCON 
requests,\881\ the Commission has discretion to conduct additional 
proceedings at a future date if it finds they are warranted.
---------------------------------------------------------------------------

    \881\ ELCON Initial Comments at 11.
---------------------------------------------------------------------------

3. Categories of Factors
a. Requirement To Incorporate Categories of Factors
i. NOPR Proposal
    387. In the NOPR, the Commission proposed to require transmission 
providers to incorporate specific categories of factors in the 
development of Long-Term Scenarios as part of Long-Term Regional 
Transmission Planning.\882\ Specifically, the Commission proposed to 
require transmission providers to incorporate, at a minimum, the 
following categories of factors in the development of Long-Term 
Scenarios: (1) Federal, state, and local laws and regulations that 
affect the future resource mix and demand; \883\ (2) Federal, state, 
and local laws and regulations on decarbonization and electrification; 
(3) state-approved utility integrated resource plans and expected 
supply obligations for load-serving entities; (4) trends in technology 
and fuel costs within and outside of the electricity supply industry, 
including shifts toward electrification of buildings and 
transportation; (5) resource retirements; (6) generator interconnection 
requests and withdrawals; and (7) utility and corporate commitments and 
Federal, state, and local goals \884\ that affect the future resource 
mix and demand.\885\
---------------------------------------------------------------------------

    \882\ NOPR, 179 FERC ] 61,028 at PP 104-112.
    \883\ Id. P 104 n.189. The Commission explained that ``state or 
federal laws or regulations'' meant ``enacted statutes (i.e., passed 
by the legislature and signed by the executive) and regulations 
promulgated by a relevant jurisdiction, whether within a state, 
municipality, or at the federal level.''
    \884\ Id. P 104 n.195. The Commission explained that ``goal'' 
meant ``any commitment or statement expressed in writing that is not 
a law or regulation.''
    \885\ Id. P 104.
---------------------------------------------------------------------------

    388. The Commission preliminarily found that incorporating, at a 
minimum, these categories of factors in the development of Long-Term 
Scenarios is appropriate because these categories of factors affect the 
future resource mix and demand, and their incorporation in Long-Term 
Scenarios is therefore essential to identifying transmission needs 
driven by changes in the resource mix and demand through Long-Term 
Regional Transmission Planning.\886\ To the extent that transmission 
providers in a transmission planning region would like to incorporate 
additional categories of factors in the development of Long-Term 
Scenarios, the Commission proposed to require that they demonstrate on 
compliance with any final order that the incorporation of more than the 
minimum categories is consistent with or superior to any final order in 
this proceeding.\887\
---------------------------------------------------------------------------

    \886\ Id. P 105.
    \887\ Id.
---------------------------------------------------------------------------

    389. Also, as discussed in the Coordination of Regional 
Transmission Planning and Generator Interconnection Processes section 
of the NOPR,\888\ the Commission proposed to require that transmission 
providers consider in their Long-Term Regional Transmission Planning 
regional transmission facilities that address interconnection-related 
transmission needs that the transmission provider has identified 
multiple times in the generator interconnection process but that have 
never been constructed due to the withdrawal of the underlying 
interconnection request(s). The Commission proposed to require that 
transmission providers incorporate the specific interconnection-related 
needs identified through that proposed reform, in addition to one or 
more factors that more generally characterize generator interconnection 
withdrawals, as a factor in the generator interconnection requests and 
withdrawals category of factors in their development of Long-Term 
Scenarios.\889\
---------------------------------------------------------------------------

    \888\ Id. PP 166-174.
    \889\ Id. P 107.
---------------------------------------------------------------------------

    390. The Commission explained that incorporation of the categories 
of factors set forth above in developing Long-Term Scenarios would help 
facilitate the identification of transmission needs driven by changes 
in the resource mix and demand, which the Commission preliminarily 
found was necessary to ensure just and reasonable and not unduly 
discriminatory or preferential Commission-jurisdictional rates. The 
Commission explained that absent a requirement to incorporate these 
categories of factors in the development of Long-Term Scenarios, 
transmission providers may not incorporate known inputs that likely 
will affect the future resource mix and demand. Additionally, the 
Commission explained that transmission providers may not adequately 
identify transmission needs

[[Page 49349]]

driven by changes in the resource mix and demand and evaluate the 
potential benefits of regional transmission facilities that may more 
efficiently or cost-effectively meet such needs. The Commission stated 
that, as an additional benefit, this requirement would provide clarity 
to transmission providers and stakeholders regarding which factors must 
be considered in scenario development.\890\
---------------------------------------------------------------------------

    \890\ Id. P 111.
---------------------------------------------------------------------------

ii. Comments
(a) Requirement To Incorporate Categories of Factors
    391. A number of commenters support the proposal to require 
transmission providers to incorporate in their development of Long-Term 
Scenarios the seven specific categories of factors identified in the 
NOPR.\891\ Georgia Commission asserts that these categories of factors 
adequately capture the factors expected to drive changes in the 
resource mix and demand,\892\ and APPA states that they reflect 
potential drivers of the need for new transmission.\893\
---------------------------------------------------------------------------

    \891\ ACEG Initial Comments at 7; Advanced Energy Buyers Initial 
Comments at 5; AEE Initial Comments at 9-10; Breakthrough Energy 
Initial Comments at 14; Breakthrough Energy Supplemental Comments at 
1; City of New York Initial Comments at 7; Clean Energy Associations 
Initial Comments at 10-11; Clean Energy Buyers Initial Comments at 
14-15; ELCON Initial Comments at 12; Eversource Initial Comments at 
16-17; Illinois Commission Initial Comments at 4-5; Kansas 
Commission Initial Comments at 14-15; Nevada Commission Initial 
Comments at 8; Northwest and Intermountain Initial Comments at 13; 
NRECA Initial Comments at 30; OMS Initial Comments at 6; 
[Oslash]rsted Initial Comments at 6; Pacific Northwest State 
Agencies Initial Comments at 14; PG&E Initial Comments at 6; Pine 
Gate Initial Comments at 22; PIOs Initial Comments at 17-18; PJM 
Initial Comments at 6, 64; SEIA Initial Comments at 7; Southeast 
PIOs Initial Comments at 44-45; US DOE Initial Comments at 11-12.
    \892\ Georgia Commission Initial Comments at 4.
    \893\ APPA Initial Comments at 27-28.
---------------------------------------------------------------------------

    392. AEE asks that the Commission clarify that consideration of 
each factor is mandatory, arguing that failing to take into account any 
of the seven listed categories of factors would risk under-investment 
in regional transmission facilities, which could result in unjust and 
unreasonable rates.\894\ Evergreen Action and Pine Gate assert that the 
Commission should require that the seven factors are ``incorporated'' 
instead of ``considered'' in order to make clear that incorporation is 
not optional.\895\ Otherwise, Pine Gate states, transmission providers 
may ignore certain categories relevant and critical to identifying 
needed transmission infrastructure.\896\
---------------------------------------------------------------------------

    \894\ AEE Initial Comments at 10.
    \895\ Evergreen Action Initial Comments at 4; Pine Gate Initial 
Comments at 22-23.
    \896\ Pine Gate Initial Comments at 22.
---------------------------------------------------------------------------

    393. DC and MD Offices of People's Counsel also urge the Commission 
to require that all seven factor categories listed in the NOPR be 
included in Long-Term Scenarios.\897\ DC and MD Offices of People's 
Counsel and ACEG state that the flexibility proposed in the NOPR could 
give transmission providers the option of not considering the last four 
factor categories.\898\ SEIA recommends that the Commission establish 
guidelines on the information used to determine factors in the last 
four factor categories to ensure some level of certainty in how they 
are reflected in Long-Term Scenarios.\899\
---------------------------------------------------------------------------

    \897\ DC and MD Offices of People's Counsel Initial Comments at 
11-12.
    \898\ ACEG Initial Comments at 28; DC and MD Offices of People's 
Counsel Initial Comments at 11.
    \899\ SEIA Initial Comments at 9-10.
---------------------------------------------------------------------------

    394. Clean Energy Buyers support the NOPR proposal, arguing that 
requiring uniform categories of factors across transmission planning 
regions could promote efficiency and interregional coordination.\900\ 
Southeast PIOs argue that broader consideration of resource trends and 
other transmission drivers through comprehensive scenarios will inform 
the decision-making of state authorities tasked with approving 
transmission facilities.\901\ Indicated US Senators and Representatives 
express general support for proactive transmission planning that 
considers a broad range of factors.\902\
---------------------------------------------------------------------------

    \900\ Clean Energy Buyers Initial Comments at 14-15.
    \901\ Southeast PIOs Reply Comments at 26.
    \902\ Indicated US Senators and Representatives Initial Comments 
at 1.
---------------------------------------------------------------------------

    395. MISO TOs, MISO, and OMS state that existing MISO processes 
already identify and consider the proposed categories of factors to 
develop scenarios for transmission planning.\903\ MISO TOs further 
claim that there is no need to require that MISO consider additional 
factors.\904\ OMS supports the NOPR's proposed requirements as to the 
minimum categories of factors and asserts that the categories of 
factors proposed in the NOPR are all included in MISO's existing 
transmission planning processes.\905\
---------------------------------------------------------------------------

    \903\ MISO Initial Comments at 34-35; MISO TOs Initial Comments 
at 18; OMS Initial Comments at 6.
    \904\ MISO TOs Initial Comments at 18.
    \905\ OMS Initial Comments at 6.
---------------------------------------------------------------------------

    396. Some commenters support the NOPR proposal because they note 
that it provides transmission providers with flexibility as to the 
specific factors they incorporate into their development of Long-Term 
Scenarios, as well as how they incorporate those factors.\906\
---------------------------------------------------------------------------

    \906\ Exelon Initial Comments at 10-11; Georgia Commission 
Initial Comments at 4; Illinois Commission Initial Comments at 7; 
NEPOOL Initial Comments at 7.
---------------------------------------------------------------------------

    397. A few commenters support the NOPR proposal to allow 
transmission providers to incorporate additional categories of factors 
if they can demonstrate that doing so is consistent with or superior to 
the final order.\907\ Specifically, AEE states that the Commission 
should clarify that transmission providers can propose to consider 
other categories of factors.\908\
---------------------------------------------------------------------------

    \907\ Acadia Center and CLF Initial Comments at 9; Clean Energy 
Buyers Initial Comments at 14-15; ELCON Initial Comments at 12; 
NESCOE Initial Comments at 27; US DOE Initial Comments at 11-12.
    \908\ AEE Initial Comments at 10.
---------------------------------------------------------------------------

    398. Pattern Energy states that the Commission should provide 
examples of how the categories of factors and their associated 
sensitivities may be modeled to ensure that each Long-Term Scenario is 
useful for Long-Term Regional Transmission Planning. For example, 
Pattern Energy asks whether the different scenarios alter the various 
assumptions for each (or some) of the factors. Alternatively, Pattern 
Energy asks whether the assumptions remained fixed across scenarios and 
different scenarios are designed to evaluate different transmission 
solutions.\909\
---------------------------------------------------------------------------

    \909\ Pattern Energy Initial Comments at 24.
---------------------------------------------------------------------------

(b) Requests for Flexibility
    399. Some commenters argue that the Commission should give 
transmission providers more flexibility to determine the appropriate 
categories of factors or individual factors to include in their 
development of Long-Term Scenarios.\910\ NESCOE contends that providing 
flexibility would be consistent with the Commission's approach in Order 
No. 1000, where it did not require the identification of transmission 
needs driven by any particular Public Policy Requirements.\911\ PG&E 
argues that the Commission should allow transmission providers to 
experiment with how they define scenarios and factors to best reflect 
the policy and planning environments of their transmission

[[Page 49350]]

planning regions.\912\ EEI notes that not all of the factors listed in 
the NOPR may be relevant for all transmission planning regions during 
every long-term assessment and explains that private sector, Federal, 
state, and local public policy goals may diverge or conflict, 
especially in multi-state regions.\913\
---------------------------------------------------------------------------

    \910\ Alabama Commission Initial Comments at 7; APPA Initial 
Comments at 27-28; Dominion Initial Comments at 25; Indicated PJM 
TOs Initial Comments at 8-9; MISO Initial Comments at 29; NARUC 
Initial Comments at 8-9; New York TOs Initial Comments at 11-12; 
NYISO Initial Comments at 8, 20; Pennsylvania Commission Initial 
Comments at 5-6; PG&E Initial Comments at 7.
    \911\ NESCOE Initial Comments at 27-28 (citing Order No. 1000, 
136 FERC ] 61,051 at P 207).
    \912\ PG&E Initial Comments at 7.
    \913\ EEI Initial Comments at 12-13.
---------------------------------------------------------------------------

    400. ISO-NE requests that the Commission provide transmission 
providers with flexibility in the consideration of factors for 
inclusion in each scenario, noting that the factors may vary from study 
to study depending on the study objectives. Specifically, ISO-NE argues 
that the Commission should not require that each Long-Term Scenario 
account for and consistently reflect the first three categories of 
factors: Federal, state, and local laws and regulations on the future 
resource mix, decarbonization and electrification, and state-approved 
integrated resource plans. ISO-NE emphasizes that the Commission should 
not require local laws to be consistently reflected in and accounted 
for in Long-Term Scenarios. ISO-NE argues that, in addition to being 
too prescriptive, such a requirement would introduce unnecessary and 
substantial administrative burdens and compliance risks with the 
possibility for inadvertent exclusion of a required law, regulation, or 
integrated resource plan. Moreover, ISO-NE contends, it would 
unnecessarily prevent testing of variations with these categories of 
factors, limiting the usefulness of scenario analysis.\914\
---------------------------------------------------------------------------

    \914\ ISO-NE Initial Comments at 26-27.
---------------------------------------------------------------------------

    401. Idaho Commission and Idaho Power argue that the NOPR proposal 
is too prescriptive.\915\ PJM advises the Commission not to include too 
many inflexible details in the implementation of the factors.\916\ 
However, PJM generally supports the NOPR proposal to create seven 
factors that should guide the development of scenarios with some 
additions and revisions.\917\
---------------------------------------------------------------------------

    \915\ Idaho Commission Initial Comments at 3; Idaho Power 
Initial Comments at 5.
    \916\ PJM Initial Comments at 67.
    \917\ Id. at 6, 64.
---------------------------------------------------------------------------

    402. NYISO states that the Commission should not prescribe specific 
categories of factors that transmission providers must use and instead 
should allow each transmission planning region, in coordination with 
state entities and stakeholders, to determine to what extent and how 
the seven categories of factors should be applied.\918\ SEIA disagrees, 
asserting that each proposed category of factors is broad enough to 
reflect regional differences within the category, but suggests that the 
Commission provide flexibility on implementation details. SEIA explains 
that the categories of factors do not set forth specific requirements 
on how much weight each factor should have in each Long-Term Scenario, 
what generation mix will result from the mix of factors, or what models 
to use. SEIA states that the Commission should allow transmission 
providers to include these implementation details in their 
manuals.\919\
---------------------------------------------------------------------------

    \918\ NYISO Initial Comments at 8, 20.
    \919\ SEIA Reply Comments at 3-4.
---------------------------------------------------------------------------

    403. Some commenters express support for some or all of the 
proposed categories of factors but request that the Commission provide 
transmission providers with flexibility in how they incorporate the 
factors into their development of Long-Term Scenarios.\920\ For 
example, TANC requests that the Commission allow transmission planning 
regions, in consultation with stakeholders, to exclude some of the 
proposed factors (i.e., regulatory and corporate goals or technology 
trends) from their development of Long-Term Scenarios.\921\ TANC also 
advocates that the Commission should allow transmission planning 
regions to determine the manner in which other factors, namely trends, 
resource requirements, generator interconnection requests, and 
withdrawals, are incorporated in regional transmission planning 
studies. Although SPP states that most of the categories of factors are 
appropriate, it contends that requiring the listed factors to be 
incorporated, rather than considered, in development of Long-Term 
Scenarios could overburden the process.\922\
---------------------------------------------------------------------------

    \920\ Ameren Initial Comments at 9-12; APPA Initial Comments at 
27-28; Arizona Commission Initial Comments at 5; Eversource Initial 
Comments at 16-17; ISO-NE Initial Comments at 26; LADWP Initial 
Comments at 3; TANC Initial Comments at 9-10.
    \921\ TANC Initial Comments at 9-10.
    \922\ SPP Initial Comments at 7-8.
---------------------------------------------------------------------------

    404. NEPOOL states that the categories of factors identified in the 
NOPR seem generic enough to allow implementation despite regional 
differences or changes in circumstances over time but contends that the 
Commission should carefully consider different market structures and 
potential changes to state policies to ensure that any requirement 
accommodates regional differences.\923\ Pine Gate further requests 
clarification as to the degree of flexibility that the Commission will 
grant to transmission providers in how they incorporate each factor 
into Long-Term Scenarios.\924\
---------------------------------------------------------------------------

    \923\ NEPOOL Initial Comments at 7.
    \924\ Pine Gate Initial Comments at 22-23.
---------------------------------------------------------------------------

(c) Concerns With the Requirement To Incorporate Categories of Factors
    405. Large Public Power argues that the NOPR proposal ignores the 
Commission's fundamental responsibility to facilitate planning to meet 
the needs of load-serving entities, as well as Congress' recognition 
that load-serving entities themselves have a fundamental obligation to 
build transmission to meet their load.\925\ Large Public Power asserts 
that the NOPR proposal to establish factors that look more broadly than 
the Commission's core obligations under the FPA threatens to undermine 
the needs of load-serving entities and their customers.\926\ Further, 
Large Public Power contends that the Commission has no authority to 
direct the development of transmission facilities.\927\ Similarly, some 
commenters voice concerns with the use of categories of factors to 
direct transmission investment.\928\ Louisiana Commission states that 
the incorporation of speculative factors would result in a large-scale 
transmission build-out to accommodate the policy preference of some, at 
the cost of all.\929\
---------------------------------------------------------------------------

    \925\ Large Public Power Initial Comments at 19-20 (citing 16 
U.S.C. 824q, (e)); see also NRECA Initial Comments at 17-18 (quoting 
16 U.S.C. 824q(b)(4)), 19-20).
    \926\ Large Public Power Initial Comments at 20-21.
    \927\ Id. at 11 (citing 16 U.S.C. 824o(i)(2)).
    \928\ Industrial Customers Initial Comments at 11; Louisiana 
Commission Initial Comments at 17-19
    \929\ Louisiana Commission Initial Comments at 17-19.
---------------------------------------------------------------------------

    406. Undersigned States claim that the proposed requirement that 
each Long-Term Scenario ``incorporate and be consistent'' with certain 
factors does not address potentially irresolvable conflicts over how 
certain factors affect the future resource mix and demand.\930\ PPL 
criticizes the NOPR for failing to explain how to translate the 
proposed factors into usable assumptions that can feed into 
transmission planning models, leading to increased uncertainty for 
transmission developers and greater difficultly in financing 
transmission projects or gaining siting approval.\931\
---------------------------------------------------------------------------

    \930\ Undersigned States Initial Comments at 3.
    \931\ PPL Initial Comments at 8.
---------------------------------------------------------------------------

(d) Alternative Frameworks
    407. Other commenters propose alternative frameworks for 
incorporating factors in the development of Long-Term Scenarios. PPL 
believes that the Commission's proposed categories of factors are 
largely overlapping and can

[[Page 49351]]

be summarized and replaced by a single factor: reasonable expectations 
regarding the future resource mix and demand.\932\ ENGIE suggests that, 
because the Commission's proposed factors may be too numerous for 
transmission providers to model, certain factors (i.e., laws, 
regulations, and announced retirements) should be fixed while others 
are varied or studied as sensitivities (i.e., costs, demand, and 
resource development trends).\933\ PIOs state that the Commission must 
set minimum requirements for some factors, asserting that there is 
broad support for minimum requirements.\934\
---------------------------------------------------------------------------

    \932\ Id. at 7.
    \933\ ENGIE Initial Comments at 3.
    \934\ PIOs Reply Comments at 10.
---------------------------------------------------------------------------

    408. GridLab contends that the Commission's proposal to require 
that transmission providers incorporate specific categories of factors 
in the development of Long-Term Scenarios cannot be enforced and that 
such broad factors will not change investment outcomes. GridLab states 
that the proposed list of factors are a helpful minimum standard and 
recommends that the Commission focus on whether transmission providers 
have meaningfully incorporated them into Long-Term Regional 
Transmission Planning.\935\ Further, GridLab avers that local laws and 
regulations and corporate commitments are difficult to incorporate into 
Long-Term Regional Transmission Planning in a bottom-up, meaningful 
way.\936\ As an alternative, GridLab suggests that transmission 
providers could use aggregate assumptions and indicative scenario 
design and allow state and local agencies, as well as other 
stakeholders, to provide inputs into scenario development, and then 
evaluate whether the resulting scenarios are consistent with state, 
local, and corporate commitments.\937\
---------------------------------------------------------------------------

    \935\ GridLab Initial Comments at 21-22.
    \936\ Id. at 22.
    \937\ Id.
---------------------------------------------------------------------------

iii. Commission Determination
    409. We adopt the NOPR proposal to require transmission providers 
in each transmission planning region to incorporate the seven specific 
categories of factors proposed in the NOPR, as modified in this final 
order, in the development of Long-Term Scenarios. Specifically, as 
discussed in more detail below, transmission providers must incorporate 
in the development of Long-Term Scenarios: (1) Federal, federally-
recognized Tribal,\938\ state, and local laws and regulations affecting 
the resource mix and demand; (2) Federal, federally-recognized Tribal, 
state, and local laws and regulations on decarbonization and 
electrification; (3) state-approved integrated resource plans and 
expected supply obligations for load-serving entities; (4) trends in 
fuel costs and in the cost, performance, and availability of 
generation, electric storage resources, and building and transportation 
electrification technologies; (5) resource retirements; (6) generator 
interconnection requests and withdrawals; and (7) utility and corporate 
commitments and Federal, federally-recognized Tribal, state, and local 
policy goals that affect Long-Term Transmission Needs.\939\ We address 
each of these categories of factors in the Specific Categories of 
Factors determination section below.
---------------------------------------------------------------------------

    \938\ We emphasize that we are requiring transmission providers 
to incorporate laws and regulations into Long-Term Scenario 
development. As noted earlier, while we are providing this 
opportunity for federally-recognized Tribes to voluntarily 
participate, we are not imposing any requirements on them to 
participate.
    \939\ Modifications to the title of Factor Categories One, Two, 
Four, and Seven are discussed in the Specific Categories of Factors 
determination section.
---------------------------------------------------------------------------

    410. We find that existing regional transmission planning 
requirements fail to ensure that transmission providers adequately 
account on a forward-looking basis for known determinants of Long-Term 
Transmission Needs.\940\ Many commenters in this proceeding, even some 
that may oppose the prescriptiveness of the requirement or otherwise 
request more flexibility in how transmission providers account for 
factors affecting Long-Term Transmission Needs,\941\ generally agree 
that the categories of factors outlined in the NOPR account for many of 
the known determinants of such needs. We find that incorporating the 
seven categories of factors in the development of Long-Term Scenarios 
is necessary because these categories of factors are essential to 
identifying Long-Term Transmission Needs. Further, we find that 
requiring transmission providers to incorporate the enumerated 
categories of factors in Long-Term Regional Transmission Planning will 
help to ensure that transmission providers are accounting for known and 
identifiable drivers of Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \940\ NOPR, 179 FERC ] 61,028 at PP 50-51.
    \941\ See, e.g., EEI Initial Comments at 12-13; PJM Initial 
Comments at 64-67.
---------------------------------------------------------------------------

    411. We are not persuaded by commenters' arguments that certain of 
the categories of factors may not be relevant in certain transmission 
planning regions and therefore that transmission providers should not 
be required to incorporate those categories of factors in the 
development of Long-Term Scenarios.\942\ We decline to allow 
transmission providers to exclude some of the proposed categories of 
factors from being incorporated in the development of Long-Term 
Scenarios, as certain commenters request, because we conclude that each 
category of factors includes important determinants of Long-Term 
Transmission Needs. We are concerned that not requiring incorporation 
of all of the proposed categories of factors in Long-Term Scenarios 
would increase the likelihood that transmission providers will continue 
to underestimate--or omit entirely--certain known determinants of Long-
Term Transmission Needs in their regional transmission planning 
processes.
---------------------------------------------------------------------------

    \942\ See, e.g., EEI Initial Comments at 12-13; SPP Initial 
Comments at 7-8.
---------------------------------------------------------------------------

    412. In response to AEE's request, we affirm that the seven 
categories of factors adopted in this final order are the minimum set 
of known determinants of Long-Term Transmission Needs that transmission 
providers must incorporate into the development of their Long-Term 
Scenarios, and we decline to adopt the NOPR proposal to require 
transmission providers to demonstrate on compliance that the 
incorporation of additional categories of factors is consistent with or 
superior to any final order in this proceeding.\943\ Transmission 
providers may be aware of additional categories of factors beyond those 
adopted in this final order that drive Long-Term Transmission Needs 
and, thus, should be incorporated into the development of Long-Term 
Scenarios. While transmission providers may incorporate additional 
categories of factors into the development of Long-Term Scenarios, we 
require in this final order that each Long-Term Scenario remains 
plausible, as discussed further below.
---------------------------------------------------------------------------

    \943\ AEE Initial Comments at 10.
---------------------------------------------------------------------------

    413. We clarify that incorporating each category of factors into 
the development of Long-Term Scenarios means more than merely 
considering each category of factors in the development of Long-Term 
Scenarios.\944\ Incorporating a category of factors in the development 
of Long-Term Scenarios means that transmission providers must use 
factors in the category, for each factor individually or collectively, 
to determine the assumptions that will be used in the development of 
Long-Term Scenarios. Incorporating a category of factors into the 
development of Long-Term

[[Page 49352]]

Scenarios does not require exacting precision; transmission providers 
may generalize how all of the discrete factors in a category of factors 
will, in the aggregate, affect the development of Long-Term 
Scenarios.\945\ However, we expect that similar factors (or groups of 
factors) affecting a single assumption used in the development of Long-
Term Scenarios will have an additive effect on that assumption.\946\ We 
also expect that incorporating a category of factors into the 
development of Long-Term Scenarios will result in scenarios that differ 
from scenarios lacking that specific category of factors; that is, the 
incorporation of a category of factors should have a measurable impact 
on the Long-Term Scenario, compared to that same Long-Term Scenario, 
all else equal, if it had not incorporated that category of factors.
---------------------------------------------------------------------------

    \944\ Evergreen Action Initial Comments at 4; Pine Gate Initial 
Comments at 22-23.
    \945\ For example, transmission providers could aggregate the 
effect of corporate goals by leveraging publicly available surveys 
of corporations' clean energy and electrification goals and then 
using those surveys to inform the assumptions used to develop Long-
Term Scenarios (e.g., 10% more clean energy resources and 10% higher 
load growth for a Long-Term Scenario that assumes full achievement 
of those goals than in a Long-Term Scenario that does not consider 
such goals).
    \946\ For example, two independent factors that increase the 
likelihood of future electric storage resource development (e.g., 
(1) a state law requiring the deployment of at least 5 gigawatts of 
electric storage resources by 2030 and (2) a Federal investment tax 
credit for the deployment of electric storage resources) would have 
a combined effect that exceeds the effect of either factor alone.
---------------------------------------------------------------------------

    414. We believe that the best-available data requirement, which we 
adopt and discuss further below, should mitigate concerns that 
transmission providers may undermine Long-Term Regional Transmission 
Planning by not incorporating categories of factors in a meaningful 
way.\947\ The best-available data requirement will ensure that the data 
inputs that transmission providers use to incorporate categories of 
factors are timely, developed using best practices, and diverse and 
expert perspectives. We also clarify that, as a consequence of the 
requirement that all Long-Term Scenarios must be plausible, as well as 
the requirement that all Long-Term Scenarios must be diverse, both of 
which we adopt and discuss below, transmission providers must 
incorporate the categories of factors in the development of Long-Term 
Scenarios in a way that results in plausible and diverse Long-Term 
Scenarios.
---------------------------------------------------------------------------

    \947\ E.g., ACEG Initial Comments at 28.
---------------------------------------------------------------------------

    415. As to the factors within each category that transmission 
providers must account for when they incorporate each category of 
factors in the development of Long-Term Scenarios, we require 
transmission providers to account for the factors that they have 
determined are likely to affect Long-Term Transmission Needs. As 
explained above, these Long-Term Transmission Needs include, but are 
not limited to, evolving reliability concerns and changes in the 
resource mix, and changes in demand. For each factor (or group of 
similar factors) within each category of factors that transmission 
providers identify, in coordination with stakeholders through an open 
and transparent process as described below, transmission providers must 
make a determination as to how that factor (or group of similar 
factors) is likely to affect Long-Term Transmission Needs. Transmission 
providers must then account for the factors that they have determined 
are likely to affect Long-Term Transmission Needs in the development of 
the Long-Term Scenarios used in Long-Term Regional Transmission 
Planning. We clarify, however, that transmission providers in a 
transmission planning region need not account for a factor, 
stakeholder-identified or otherwise, if they determine that factor is 
unlikely to affect Long-Term Transmission Needs.
    416. We also clarify that a category of factors (e.g., Factor 
Category Two: Federal, federally-recognized Tribal, state, and local 
laws and regulations on decarbonization and electrification) differs 
from a specific factor (e.g., a specific state law with a 
decarbonization requirement). We make this distinction because some 
commenters use only the word ``factors'' when describing the categories 
of factors proposed in the NOPR.\948\
---------------------------------------------------------------------------

    \948\ E.g., AEE Initial Comments at 9; Evergreen Action Initial 
Comments at 4.
---------------------------------------------------------------------------

    417. We disagree with commenters that the categories of factors 
requirements are too prescriptive,\949\ and we believe that the 
framework adopted in this final order requiring transmission providers 
to incorporate categories of factors into the development of Long-Term 
Scenarios strikes the right balance between prescriptive requirements 
and flexibility. Transmission providers have discretion to determine 
whether specific factors must be accounted for within each category 
(i.e., if the specific factor will likely affect Long-Term Transmission 
Needs), how to account for specific factors in the development of Long-
Term Scenarios (e.g., the method and data used to forecast resource 
retirements), and how to vary the treatment of each category of factors 
across Long-Term Scenarios (e.g., assume all forecasted resource 
retirements materialize in some but not all Long-Term Scenarios), so 
long as transmission providers assume that the laws, regulations, 
state-approved integrated resource plans, and expected supply 
obligations for load-serving entities identified in the first three 
categories of factors--that transmission providers have determined are 
likely to affect Long-Term Transmission Needs--are fully met (as 
discussed below). We believe that each proposed category of factors is 
broad enough to allow the transmission providers in each transmission 
planning region to reflect regional differences within the category, as 
noted by SEIA and NEPOOL.\950\ In response to PG&E's request that we 
allow flexibility for transmission providers to use Long-Term Scenarios 
that best reflect the individual policy and planning environments in 
their specific transmission planning regions, and to Pattern Energy's 
questions about how categories of factors may be modeled,\951\ we 
clarify that transmission providers have the flexibility to develop 
different Long-Term Scenarios specific to their transmission planning 
region and develop using assumptions based on the categories of 
factors.
---------------------------------------------------------------------------

    \949\ ISO-NE Initial Comments at 26; NYISO Initial Comments at 
8, 20; PJM Initial Comments at 67.
    \950\ NEPOOL Initial Comments at 7; SEIA Reply Comments at 3-4.
    \951\ Pattern Energy Initial Comments at 24; PG&E Initial 
Comments at 7.
---------------------------------------------------------------------------

    418. In response to NESCOE, we decline to give transmission 
providers the flexibility to choose which of the proposed categories of 
factors to incorporate into Long-Term Scenarios, which NESCOE states 
would be consistent with the flexibility that the Commission provided 
to transmission providers in Order No. 1000, where it did ``not . . . 
require the identification of any particular transmission need driven 
by any particular Public Policy Requirements.'' \952\ As noted in The 
Overall Need for Reform section, there are deficiencies in the 
Commission's existing regional transmission planning requirements, 
including that they fail to ensure that transmission providers 
adequately account on a forward-looking basis for known determinants of 
Long-Term Transmission Needs. We are concerned that, if transmission 
providers have flexibility to choose which of the proposed categories 
of factors to incorporate into the development of Long-Term Scenarios, 
they will continue to underestimate--or omit entirely--certain known 
determinants of Long-Term Transmission Needs in their regional

[[Page 49353]]

transmission planning processes. Additionally, we note that 
transmission needs are distinct from categories of factors: as 
explained above, categories of factors, and specific factors therein, 
form the basis for assumptions that will be used in the development of 
Long-Term Scenarios that transmission providers will then use to 
identify Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \952\ NESCOE Initial Comments at 27-28 (citing Order No. 1000, 
136 FERC ] 61,051 at P 207).
---------------------------------------------------------------------------

    419. We also disagree with arguments that we are directing the 
development of specific transmission facilities.\953\ As an initial 
matter, transmission providers retain discretion to determine how 
specific factors will affect Long-Term Transmission Needs. Moreover, 
the categories of factors requirements adopted in this final order do 
not create new transmission needs that did not previously exist, but 
rather, they improve regional transmission planning processes by 
requiring transmission providers to identify Long-Term Transmission 
Needs across a plausible and diverse range of future scenarios and to 
identify, evaluate, and select Long-Term Regional Transmission 
Facilities to address those needs. If transmission providers do not 
account in Long-Term Regional Transmission Planning for known 
determinants of Long-Term Transmission Needs, then those needs would 
still exist and would likely be resolved, if at all, in a relatively 
inefficient or less cost-effective manner (e.g., in a piecemeal fashion 
through local transmission planning processes and/or generator 
interconnection processes). We are not requiring that transmission 
providers select any particular Long-Term Regional Transmission 
Facility and therefore are not directing the development of any 
particular transmission facilities. Finally, we clarify that while the 
requirement for transmission providers to incorporate the seven 
categories of factors adopted in this final order into the development 
of Long-Term Scenarios is intended to ensure that Long-Term Regional 
Transmission Facilities are identified for selection to more 
efficiently or cost-effectively address Long-Term Transmission Needs, 
we do not believe that concerns over whether a transmission provider 
appropriately implemented this requirement represent an appropriate 
basis on which to challenge the cost allocation for one or more 
individual Long-Term Regional Transmission Facilities. Rather, whether 
the allocation of costs is just and reasonable and not unduly 
discriminatory is governed by the requirement that costs be roughly 
commensurate with benefits, as discussed in the Regional Transmission 
Cost Allocation section below.
---------------------------------------------------------------------------

    \953\ E.g., Large Public Power Initial Comments at 20-21; see 
also Alabama Commission Initial Comments at 4; Industrial Customers 
Initial Comments at 10; Louisiana Commission Initial Comments at 17-
19; Pennsylvania Commission Initial Comments at 6.
---------------------------------------------------------------------------

    420. We disagree with Large Public Power's argument that we are 
ignoring the Commission's fundamental responsibility to facilitate 
planning to meet the needs of load-serving entities.\954\ As described 
below, we are requiring all Long-Term Scenarios to be consistent with 
and fully account for factors in Factor Category Three, which includes 
state-approved integrated resource plans and the expected supply 
obligations of load-serving entities. Therefore, transmission providers 
are required to plan to meet the needs of load-serving entities.
---------------------------------------------------------------------------

    \954\ Large Public Power Initial Comments at 19-20 (citing 16 
U.S.C. 824q, (e)); see also NRECA Initial Comments at 17-18 (quoting 
16 U.S.C. 824q(b)(4)), 19-20.
---------------------------------------------------------------------------

    421. We decline to adopt more specific minimum requirements than 
those described herein for incorporating categories of factors in the 
development of Long-Term Scenarios, as requested by some 
commenters.\955\ We believe that the requirements adopted herein, 
coupled with the other Long-Term Scenarios requirements, including the 
plausible and diverse and best available data requirements, are 
sufficiently detailed to address the need for reform without limiting 
regional flexibility.
---------------------------------------------------------------------------

    \955\ E.g., PIOs Reply Comments at 10.
---------------------------------------------------------------------------

b. Specific Categories of Factors
i. NOPR Proposal
    422. In the NOPR, the Commission proposed to require transmission 
providers to incorporate, at a minimum, the following categories of 
factors in the development of Long-Term Scenarios: (1) Federal, state, 
and local laws and regulations that affect the future resource mix and 
demand; \956\ (2) Federal, state, and local laws and regulations on 
decarbonization and electrification; (3) state-approved utility 
integrated resource plans and expected supply obligations for load-
serving entities; (4) trends in technology and fuel costs within and 
outside of the electricity supply industry, including shifts toward 
electrification of buildings and transportation; (5) resource 
retirements; (6) generator interconnection requests and withdrawals; 
and (7) utility and corporate commitments and Federal, state, and local 
goals that affect the future resource mix and demand.\957\
---------------------------------------------------------------------------

    \956\ NOPR, 179 FERC ] 61,028 at P 104 n.189. The Commission 
explained that ``state or federal laws or regulations'' meant 
``enacted statutes (i.e., passed by the legislature and signed by 
the executive) and regulations promulgated by a relevant 
jurisdiction, whether within a state or municipality, or at the 
federal level.''
    \957\ Id. P 104.
---------------------------------------------------------------------------

(a) Federal, Federally-Recognized Tribal, State, and Local Laws and 
Regulations That Affect the Future Resource Mix and Demand (Factor 
Category One)
(1) Comments
    423. Many commenters support the proposed requirement that each 
Long-Term Scenario incorporate and be consistent with the Federal, 
state, and local laws and regulations that affect the future resource 
mix and demand.\958\ AEE, Clean Energy States, and Acadia Center and 
CLF argue that laws and regulations implementing clean energy and 
decarbonization policies will be key drivers in changes to the resource 
mix and demand.\959\ Moreover, AEE notes, 38 states and the District of 
Columbia have adopted renewable portfolio standards, many of which have 
been enacted in statute and constitute binding commitments on utilities 
and retail energy providers.\960\ Clean Energy States similarly assert 
that the 21 states (plus the District of Columbia and Puerto Rico) with 
100% clean energy policies account for 42.3% of United States power 
sales as of 2020, 49.4% of United States customer accounts, and 51% of 
United States population.\961\ Clean Energy States argue that 
altogether, these states could see an aggregated demand for 800 TWh of 
new energy generation to meet their targets.
---------------------------------------------------------------------------

    \958\ Acadia Center and CLF Initial Comments at 8; AEE Initial 
Comments at 9-10; Breakthrough Energy Initial Comments at 14; 
California Commission Initial Comments at 17; Clean Energy 
Associations Initial Comments at 10-11; Clean Energy States Initial 
Comments at 3; Environmental Groups Supplemental Comments at 2; 
Exelon Initial Comments at 10-11; New England for Offshore Wind 
Initial Comments at 2; OMS Initial Comments at 6; Pacific Northwest 
State Agencies at Initial Comments at 14; Pine Gate Initial Comments 
at 23; PIOs Initial Comments at 17-18; WE ACT Initial Comments at 4-
5.
    \959\ Acadia Center and CLF Initial Comments at 8; AEE Initial 
Comments at 10; Clean Energy States Initial Comments at 3.
    \960\ AEE Initial Comments at 10 (citing Energy Info. Admin., 
Renewable Energy Explained, Portfolio Standards (June 29, 2021), 
https://www.eia.gov/energyexplained/renewable-sources/portfolio-standards.php).
    \961\ Clean Energy States Initial Comments at 3 (citing Clean 
Energy States Alliance, 100% Energy Collaborative, https://www.cesa.org/projects/100-clean-energy-collaborative/).
---------------------------------------------------------------------------

    424. AEE, DC and MD Offices of People's Counsel, and SEIA agree 
that transmission providers should incorporate the effects of Federal, 
state, and local laws and regulations on

[[Page 49354]]

renewable energy development into development of Long-Term 
Scenarios.\962\ City of New York states that government action that 
bears the force of law should be reflected in baseline transmission 
planning studies and not considered as merely one of multiple factors 
used to develop Long-Term Scenarios.\963\
---------------------------------------------------------------------------

    \962\ AEE Initial Comments at 17-18, 22; DC and MD Offices of 
People's Counsel Reply Comments at 5-6; SEIA Initial Comments at 7-
8.
    \963\ City of New York Initial Comments at 7.
---------------------------------------------------------------------------

    425. Southeast PIOs argue that concerns that requiring the 
incorporation of local laws and regulations in the development of Long-
Term Scenarios is unduly burdensome are misplaced at this stage because 
the details of how it will be done will be established during 
compliance proceedings.\964\
---------------------------------------------------------------------------

    \964\ Southeast PIOs Reply Comments at 26.
---------------------------------------------------------------------------

    426. PIOs argue that the Commission should require the same level 
of engagement with Tribal governments as it does with states and that 
the Commission should clarify that Long-Term Scenarios must incorporate 
relevant aspects of Tribal policies.\965\
---------------------------------------------------------------------------

    \965\ PIOs Reply Comments at 15.
---------------------------------------------------------------------------

    427. Acadia Center and CLF claim that the Commission should clarify 
that state laws and regulations that affect the future resource mix and 
demand include state laws and regulations that affect demand 
management, such as energy efficiency, distributed generation, flexible 
load, and demand response because laws and initiatives in this area 
will also affect transmission needs while providing grid 
solutions.\966\
---------------------------------------------------------------------------

    \966\ Acadia Center and CLF Initial Comments at 9.
---------------------------------------------------------------------------

    428. Center for Biological Diversity states that the Commission 
must include all Executive Actions, not just laws and regulations, as 
factors in Long-Term Regional Transmission Planning. Center for 
Biological Diversity states that allowing transmission providers to 
decide whether to consider Executive Orders fails to provide 
stakeholders with the type of clarity that is a goal of the NOPR.\967\
---------------------------------------------------------------------------

    \967\ Center for Biological Diversity Initial Comments at 3, 9-
12.
---------------------------------------------------------------------------

    429. As noted above, some commenters oppose the overall categories 
of factors requirement in this final order and argue that requiring 
transmission providers to incorporate certain factors, such as laws and 
regulations that affect the resource mix, will force transmission 
providers to settle irresolvable conflicts among state policies and 
conduct transmission planning that accommodates the policy preferences 
of some, at the cost of all.\968\
---------------------------------------------------------------------------

    \968\ Louisiana Commission Initial Comments at 17-18; 
Undersigned States Initial Comments at 3.
---------------------------------------------------------------------------

    430. Some commenters acknowledge that state laws and regulations 
may affect the future resource mix and demand but argue against 
mandatory inclusion such that they cannot discount certain Federal, 
state, and local laws and regulations.\969\ Idaho Power states that the 
NOPR proposal does not provide transmission providers with the 
flexibility necessary to create transmission planning regions that span 
multiple states and could cause non-jurisdictional entities to opt out 
of regional transmission planning.\970\ NYISO states that the final 
order should not require transmission providers to assume across all 
scenarios the full achievement of all Federal, state, and local laws 
and regulations that could drive the need for transmission. NYISO also 
does not think that the final order should require the identification 
of all Federal, state, and local laws and regulations that may drive 
the need for transmission over the 20-year transmission planning 
horizon, but instead should provide each transmission planning region 
with flexibility.\971\
---------------------------------------------------------------------------

    \969\ Ameren Initial Comments at 9-10; NESCOE Initial Comments 
at 27-28; NYISO Initial Comments at 8, 20.
    \970\ Idaho Power Initial Comments at 7.
    \971\ NYISO Initial Comments at 8.
---------------------------------------------------------------------------

    431. Although Duke agrees that many of the categories of factors 
identified in the NOPR capture a minimum list of factors that are 
expected to drive changes in the resource mix and demand, it does not 
support the inclusion of local laws and regulations.\972\
---------------------------------------------------------------------------

    \972\ Duke Initial Comments at 13-14.
---------------------------------------------------------------------------

(2) Commission Determination
    432. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to 
incorporate Factor Category One: Federal, federally-recognized Tribal, 
state, and local laws and regulations affecting the resource mix and 
demand, in the development of Long-Term Scenarios. We find that the 
factors in this category have been, and will continue to be, key 
drivers of Long-Term Transmission Needs and therefore must be accounted 
for in Long-Term Regional Transmission Planning. Accordingly, we find 
that failing to account for factors in Factor Category One would hamper 
the identification, evaluation, and selection of Long-Term Regional 
Transmission Facilities that are potentially more efficient or cost-
effective solutions to Long-Term Transmission Needs.
    433. We clarify that factors in Factor Category One include, among 
other things, legally binding obligations, incentives (e.g., tax 
credits), and/or restrictions promulgated by policymakers that will 
affect new or existing generators, or demand. Further, as discussed in 
the Additional Categories of Factors section below, we recognize that 
energy equity and justice laws and regulations are also potential 
factors within Factor Category One to the extent that they are likely 
to affect Long-Term Transmission Needs.
    434. As discussed in further detail below in the Additional 
Categories of Factors section, we modify the NOPR proposal for Factor 
Category One to include federally-recognized Tribal laws and 
regulations affecting the resource mix and demand because we are 
persuaded by commenters that contend that such factors have a similar 
potential to affect Long-Term Transmission Needs as Federal, state, and 
local laws and regulations. Federally-recognized Tribal laws and 
regulations mean the legally binding obligations, incentives, and/or 
restrictions promulgated by federally-recognized Tribes that will 
affect new or existing generators, or demand. We make similar 
modifications to Factor Category Two and Factor Category Seven, as 
discussed in the Factor Category Two and Factor Category Seven sections 
below.
    435. We are not persuaded by Louisiana Commission's argument that 
requiring transmission providers to incorporate certain factors, such 
as Federal, federally-recognized Tribal, state, and local laws and 
regulations affecting the resource mix and demand, would result in a 
transmission buildout that only accommodates the policy preferences of 
some stakeholders, at the cost of all transmission customers.\973\ 
Similarly, we are not persuaded by Undersigned States' contention that 
policy differences among states may be irresolvable, and therefore the 
Commission should not require transmission providers to account for 
laws and regulations in their Long-Term Scenarios.\974\ First, every 
policy choice--from Federal tax incentives and state regulation of 
generation, down to local economic development policies--that changes 
the quantity and location of generation and load contributes to changes 
in transmission needs. Accordingly, all transmission buildout--whether 
it occurs through a

[[Page 49355]]

local or regional transmission plan, or through a near-term 
transmission planning process or a more forward-looking one--is a 
reflection, at least in part, of Federal, federally-recognized Tribal, 
state, and local laws and regulations that drive transmission needs. 
Rather than a unique feature of Long-Term Regional Transmission 
Planning, transmission planning of any kind will inherently reflect the 
policy choices of multiple decisionmakers, because the quantity and 
location of generation and load are shaped by multiple decisionmakers.
---------------------------------------------------------------------------

    \973\ Louisiana Commission Initial Comments at 17.
    \974\ Undersigned States Initial Comments at 3.
---------------------------------------------------------------------------

    436. Second, we find that requiring transmission providers to 
properly account for known determinants of Long-Term Transmission Needs 
is necessary to ensure just and reasonable rates. Specifically, 
because, as described above, Long-Term Transmission Needs driven by 
disparate policy decisions would continue to exist, regardless of 
whether they were identified in Long-Term Regional Transmission 
Planning, failing to identify, evaluate, and select Long-Term Regional 
Transmission Facilities to address those needs will result in unjust 
and unreasonable rates. We note that some policy decisions are 
reflected in laws and regulations, which can affect load-serving 
entities' supply obligations, and in transmission planning regions with 
vertically integrated utilities, some policy decisions are reflected in 
the integrated resource plans approved by retail regulators.
    437. We are not endorsing the merits of any specific Federal, 
federally-recognized Tribal, state, or local laws and regulations or of 
any specific state-approved integrated resource plans. We emphasize 
that the Commission's policies are technology neutral, and we are not 
establishing a preference for certain types of generation or energy end 
uses. We acknowledge that, in some instances, a policy choice in one 
jurisdiction may reduce or negate the effect of a policy choice in 
another jurisdiction. However, the fact that certain factors may have 
conflicting effects on Long-Term Transmission Needs is not a basis to 
conclude that the effects of laws and regulations or state-approved 
integrated resource plans should be ignored or discounted.
(b) Federal, Federally-Recognized Tribal, State, and Local Laws and 
Regulations on Decarbonization and Electrification (Factor Category 
Two)
(1) Comments
    438. Several commenters support the proposed requirement that Long-
Term Scenarios incorporate Federal, state, and local laws and 
regulations on decarbonization and electrification.\975\ Illinois 
Commission notes that, in Illinois, the Climate and Equitable Jobs Act 
of 2021 will affect future demand and the supply mix and that Long-Term 
Regional Transmission Planning will be critical to meeting Illinois' 
policy goals.\976\ New England for Offshore Wind states that 
electrification to meet New England states' greenhouse gas emissions 
mandates will dramatically increase electricity load and require 
massive amounts of clean energy.\977\ Pattern Energy states that 
Federal and state legislative efforts to promote decarbonization should 
be the basis of scenario modeling for generation and demand.\978\ 
Center for Biological Diversity states that the Commission should 
identify decarbonization as an objective in Long-Term Regional 
Transmission Planning because it has the authority and responsibility 
to prioritize decarbonization in the transmission planning process 
since these policies bear directly on the provision of transmission 
service.\979\
---------------------------------------------------------------------------

    \975\ Acadia and CLF Initial Comments at 9; Center for 
Biological Diversity Initial Comments at 7-9; Clean Energy 
Associations Initial Comments at 10-11; DC and MD Offices of 
People's Counsel Reply Comments at 6; Illinois Commission Initial 
Comments at 4-5; New England for Offshore Wind Initial Comments at 
2-3; Pacific Northwest State Agencies at Initial Comments at 14; 
Pattern Energy Initial Comments at 26; Pine Gate Initial Comments at 
23; PIOs Initial Comments at 17-18; Renewable Northwest Initial 
Comments at 19-22.
    \976\ Illinois Commission Initial Comments at 4-5.
    \977\ New England for Offshore Wind Initial Comments at 2-3.
    \978\ Pattern Energy Initial Comments at 26.
    \979\ Center for Biological Diversity Initial Comments at 7-9 
(citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 89-93).
---------------------------------------------------------------------------

    439. Nevada Commission acknowledges that other state policies and 
its own integrated resource planning process should be considered in 
Long-Term Regional Transmission Planning even though it does not 
support other state policies affecting Nevada ratepayers.\980\ Utah 
Division of Public Utilities states that the impact of state policies 
should be part of the Long-Term Regional Transmission Planning scenario 
analysis.\981\ Cypress Creek asserts that the Commission should include 
state policy requirements in a uniform set of assumptions that are 
applicable across all Long-Term Scenarios.\982\
---------------------------------------------------------------------------

    \980\ Nevada Commission Initial Comments at 8.
    \981\ Utah Division of Public Utilities Reply Comments at 4.
    \982\ Cypress Creek Reply Comments at 5-6.
---------------------------------------------------------------------------

(2) Commission Determination
    440. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to 
incorporate Factor Category Two: Federal, federally-recognized Tribal, 
state, and local laws and regulations on decarbonization and 
electrification, in the development of Long-Term Scenarios. Similar to 
Factor Category One, we find that the factors in this category have 
been, and will continue to be, key drivers of Long-Term Transmission 
Needs and therefore must be accounted for in Long-Term Regional 
Transmission Planning. We clarify that this category of factors 
includes legally binding obligations, incentives, and/or restrictions 
that affect Long-Term Transmission Needs in different ways than Factor 
Category One, for example, by limiting the carbon intensity of 
electricity generation or electrifying energy end uses and thereby 
significantly increasing electricity use in certain sectors of the 
economy, such as transportation and building heating and cooling. We 
acknowledge that there could be overlap between Factor Categories One 
and Two because a certain law or regulation could reasonably be 
considered to fit into both categories. In such a circumstance, 
transmission providers must account for the law or regulation in one of 
the two categories, not both, to avoid double-counting of that factor's 
anticipated effect on Long-Term Transmission Needs. Since transmission 
providers must account for and be consistent with, and not discount, 
factors in the first three categories of factors equally once the 
transmission providers have determined that such a factor is likely to 
affect Long-Term Transmission Needs, we do not believe it is necessary 
to ensure that a certain factor is considered as part of Factor 
Category One instead of Factor Category Two (or vice versa), but rather 
it is only necessary to ensure that these factors are accounted for in 
the development of Long-Term Scenarios.
    441. In addition, based on the record before us, we modify the NOPR 
proposal for Factor Category Two to include federally-recognized Tribal 
laws and regulations on decarbonization and electrification because we 
are persuaded by commenters that argue that such factors have the same 
potential to affect Long-Term Transmission Needs as Federal, state, and 
local laws and regulations on decarbonization and electrification.
    442. Similar to our response in the Factor Category One section to 
commenters arguing that categories of factors involving Federal, 
federally-recognized Tribal, state, and local laws and regulations 
would provide

[[Page 49356]]

preference to some at the cost of all or result in irresolvable 
conflict,\983\ we find that differences in if and how government 
entities promulgate laws and regulations concerning decarbonization and 
electrification (i.e., factors in Factor Category Two) do not diminish 
the effect of such laws and regulations. As such, Long-Term Scenarios 
must account for these key drivers of Long-Term Transmission Needs so 
that transmission providers can identify such needs through Long-Term 
Regional Transmission Planning and can identify, evaluate, and select 
Long-Term Regional Transmission Facilities to address those needs.
---------------------------------------------------------------------------

    \983\ Louisiana Commission Initial Comments at 17-19; 
Undersigned States Initial Comments at 3. Comments originally 
summarized in PP 404-405.
---------------------------------------------------------------------------

(c) State-Approved Utility Integrated Resource Plans and Expected 
Supply Obligations for Load-Serving Entities (Factor Category Three)
(1) Comments
    443. Several commenters support the proposed requirement that each 
Long-Term Scenario incorporate state-approved integrated resource plans 
and expected supply obligations for load-serving entities.\984\ NRECA 
and TAPS state that using Long-Term Scenarios that satisfy expected 
load-serving entity supply obligations is consistent with FPA section 
217(b)(4)'s directive to facilitate the planning and expansion of 
transmission to meet the reasonable needs of load-serving entities to 
satisfy their service obligations.\985\ NRECA asserts that this 
category should be moved to the top of the list of categories of 
factors because state-approved integrated resource plans and load-
serving entity supply obligations will incorporate state laws and 
regulations affecting resource mix, demand, decarbonization, and 
electrification. Additionally, NRECA contends that the changing 
characteristics of the distribution grid, such as distributed energy 
resources, storage, demand response, energy efficiency, and 
electrification of demand, will affect load-serving entity needs and 
should be incorporated in this category of factors.\986\ Clean Energy 
Associations and ACEG agree.\987\
---------------------------------------------------------------------------

    \984\ California Commission Initial Comments at 17; NRECA 
Initial Comments at 30; Pine Gate Initial Comments at 23; PIOs 
Initial Comments at 17-18; US Chamber of Commerce Initial Comments 
at 6-7.
    \985\ NRECA Initial Comments at 30-31; TAPS Initial Comments at 
2, 7-8 (citing NOPR, 179 FERC ] 61,028 at P 106); see also APPA 
Initial Comments at 28.
    \986\ NRECA Initial Comments at 30-31 n.85.
    \987\ ACEG Reply Comments at 22; Clean Energy Associations Reply 
Comments at 6-7.
---------------------------------------------------------------------------

    444. APPA and ACEG argue that the final order should focus on the 
resource plans of load-serving entities and include a requirement for 
transmission providers to include in their Long-Term Regional 
Transmission Planning process a requirement to coordinate with load-
serving entities.\988\ ACEG argues that such a requirement is necessary 
because not all load-serving entities either own generation or are 
overseen by a state regulator, meaning that they must rely on the 
Commission to ensure that transmission planning meets their needs.\989\
---------------------------------------------------------------------------

    \988\ ACEG Reply Comments at 22; APPA Initial Comments at 27-28.
    \989\ ACEG Reply Comments at 22-23.
---------------------------------------------------------------------------

    445. Several commenters clarify that they support the inclusion of 
load-serving entity demand as a factor in Long-Term Scenarios.\990\ In 
addition, some commenters support the inclusion of load-serving entity 
generation resource planning as a factor in Long-Term Scenarios.\991\ 
PIOs argue that the Commission should require load-serving entities to 
provide their generation and demand forecasts to transmission planning 
entities.\992\ ACEG agrees and argues that PIOs' recommendation will 
decrease the burden on transmission planning entities and provide them 
with the information they need to determine the future resource 
mix.\993\
---------------------------------------------------------------------------

    \990\ ACEG Reply Comments at 22-23; Clean Energy Associations 
Reply Comments at 7; DC and MD Offices of People's Counsel Reply 
Comments at 4; PIOs Initial Comments at 18; PIOs Reply Comments at 
10.
    \991\ ACEG Reply Comments at 22-23; Clean Energy Associations 
Reply Comments at 7; DC and MD Offices of People's Counsel Reply 
Comments at 4.
    \992\ PIOs Initial Comments at 19.
    \993\ ACEG Reply Comments at 23.
---------------------------------------------------------------------------

    446. Entergy asserts that the Commission has identified the 
appropriate factors but explains that not all states conduct commission 
proceedings related to integrated resource plans and, for those states 
that do, the timelines are not necessarily the same. Thus, Entergy 
requests that the Commission clarify that the term ``state-approved 
utility integrated resource plans'' will be construed broadly to 
include any resource plan developed and reviewed through a retail 
commission proceeding and submitted to the relevant transmission 
provider for use in Long-Term Regional Transmission Planning. Entergy 
asserts that such clarification would result in a range of benefits 
such as consistency of data with current local, state, and Federal laws 
and expected retirements, additions, and corporate goals.\994\
---------------------------------------------------------------------------

    \994\ Entergy Initial Comments at 15-16.
---------------------------------------------------------------------------

(2) Commission Determination
    447. We adopt the NOPR proposal to require transmission providers 
in each transmission planning region to incorporate Factor Category 
Three: state-approved integrated resource plans and expected supply 
obligations for load-serving entities, in the development of Long-Term 
Scenarios. We find it appropriate to require transmission providers to 
incorporate Factor Category Three because it reflects the outcomes of 
retail-level regulatory proceedings that will affect Long-Term 
Transmission Needs. Further, incorporation of Factor Category Three 
into Long-Term Scenarios will ensure that transmission providers 
properly account for resource planning and anticipated changes to 
demand, including increased integration of distributed energy 
resources. We note that the Commission shares concurrent jurisdiction 
over the bulk power system with retail regulators,\995\ and we agree 
with commenters that note that FPA section 217(b)(4) directs the 
Commission to facilitate the planning and expansion of transmission to 
meet the reasonable needs of load-serving entities to satisfy their 
service obligations.\996\
---------------------------------------------------------------------------

    \995\ Compare 16 U.S.C. 824d(a) (providing the Commission 
authority to regulate the rates charged by public utilities in 
connection with the transmission or wholesale sale of electric 
energy), with id. 824(a) (reserving certain state authorities).
    \996\ 16 U.S.C. 824q(b)(4) (``The Commission shall exercise the 
authority of the Commission under this chapter in a manner that 
facilitates the planning and expansion of transmission facilities to 
meet the reasonable needs of load-serving entities to satisfy the 
service obligations of the load-serving entities, and enables load-
serving entities to secure firm transmission rights (or equivalent 
tradable or financial rights) on a long-term basis for long-term 
power supply arrangements made, or planned, to meet such needs.'').
---------------------------------------------------------------------------

    448. In response to commenters that note some retail regulators may 
review but not formally approve integrated resource plans, we clarify 
that, for this category of factors, state-approved integrated resource 
plans includes resource plans that are developed and reviewed through a 
retail proceeding in jurisdictions where the retail regulator does not 
formally approve such plans.\997\ We grant Entergy's clarification 
request that the term ``state-approved utility integrated resource 
plans'' be construed broadly to include any resource plan developed and 
reviewed through a retail commission proceeding and submitted to the 
relevant transmission provider for use in Long-Term Regional 
Transmission Planning because it would enable a more complete 
consideration of state-approved integrated resource plans and

[[Page 49357]]

expected supply obligations for load-serving entities.
---------------------------------------------------------------------------

    \997\ Entergy Initial Comments at 15-16.
---------------------------------------------------------------------------

    449. In response to APPA and ACEG's request for the Commission to 
require transmission providers to coordinate with load-serving 
entities,\998\ we note that we require transmission providers, as 
described in further detail below, to provide an open and transparent 
process in their OATT that provides stakeholders, including load-
serving entities, with a meaningful opportunity to propose potential 
factors and to provide input on how to account for specific factors in 
the development of Long-Term Scenarios.\999\ However, in response to 
PIOs' request that the Commission require load-serving entities to 
provide their generation and demand forecast to transmission providers, 
we agree that such information will assist transmission providers in 
developing Long-Term Scenarios. Therefore, consistent with the 
information exchange transmission planning principle established in 
Order No. 890,\1000\ we require load-serving entities that are taking 
transmission service pursuant to an OATT to provide transmission 
providers with information on the load-serving entities' projected 
loads and resources over the planning horizon.
---------------------------------------------------------------------------

    \998\ ACEG Reply Comments at 22; APPA Initial Comments at 27-28.
    \999\ See infra Stakeholder Process and Transparency section.
    \1000\ The information exchange transmission planning principle 
requires network transmission customers to submit information on 
their projected loads and resources on a comparable basis (e.g., 
planning horizon and format) as used by transmission providers in 
planning for their native load. Point-to-point transmission 
customers are required to submit their projections for need of 
service over the planning horizon and at what receipt and delivery 
points. To the extent applicable, transmission customers should also 
provide information on existing and planned demand resources and 
their impact on demand and peak demand. Transmission providers, in 
consultation with their customers and other stakeholders, must 
develop guidelines and a schedule for the submittal of such customer 
information. Order No. 890, 118 FERC ] 61,119 at PP 486-487.
---------------------------------------------------------------------------

(d) Trends in Technology and Fuel Costs Within and Outside of the 
Electricity Supply Industry, Including Shifts Toward Electrification of 
Buildings and Transportation (Factor Category Four)
(1) Comments
    450. Several commenters emphasize the importance of incorporating 
assumptions regarding shifts towards electrification in Long-Term 
Scenarios.\1001\ Clean Energy Buyers assert that regional flexibility 
should not be used to diminish the representation in Long-Term 
Scenarios of significant load growth from the commercial and industrial 
sectors and electrification of transportation.\1002\ Likewise, DC and 
MD Offices of People's Counsel assert that regional flexibility should 
be reflected in the actual inputs for these factors, rather than their 
inclusion in or exclusion from Long-Term Scenarios, noting, for 
example, that electrification forecasts in some areas are increasing 
load growth estimates by 30%.\1003\ Clean Energy Associations argue 
that, to keep pace with changes in supply and demand, Long-Term 
Scenarios should incorporate aging infrastructure and planned 
replacements, along with load and generation trends informed by both 
historical data and applicable policy drivers.\1004\
---------------------------------------------------------------------------

    \1001\ Clean Energy Associations Initial Comments at 11; Clean 
Energy Buyers Initial Comments at 15-16; DC and MD Offices of 
People's Counsel Initial Comments at 11-12; ENGIE Initial Comments 
at 3; PJM Market Monitor Initial Comments at 3.
    \1002\ Clean Energy Buyers Initial Comments at 15-16.
    \1003\ DC and MD Offices of People's Counsel Initial Comments at 
11-12.
    \1004\ Clean Energy Associations Initial Comments at 12.
---------------------------------------------------------------------------

    451. Other commenters emphasize the trends in specific technology 
costs, such as long-duration storage. ENGIE states that advances in 
longer-duration storage and advancing photovoltaic technologies may 
affect the ability to develop resources in areas previously considered 
to be uneconomic, which could affect the resource and demand mix.\1005\ 
Form Energy argues that the inclusion of diverse, long-duration 
electric storage technologies would require significantly fewer new 
transmission needs.\1006\
---------------------------------------------------------------------------

    \1005\ ENGIE Initial Comments at 3.
    \1006\ Form Energy Initial Comments at 2-3.
---------------------------------------------------------------------------

    452. Pine Gate supports the inclusion of trends in technology and 
fuel costs in Long-Term Scenarios; however, Pine Gate requests that the 
Commission clarify what type of data would constitute a ``trend'' and 
how it expects transmission providers to assure that trend-related 
input is objective and representative of the ``best available data.'' 
\1007\ Similarly, US DOE recommends that the Commission clarify whether 
the term ``trends in technology and fuel costs'' refers to trends in 
fuel cost and trends in technology, or rather trends in the cost of 
fuel and trends in the cost of technology. If the Commission is 
referring to the former, US DOE recommends that the Commission consider 
the phrase ``trends in fuel costs and in the cost, performance, and 
availability of generation, storage, and transmission technologies.'' 
US DOE further recommends that the Commission provide a non-exhaustive 
list of examples of cost and technology trends that transmission 
planners could consider.\1008\
---------------------------------------------------------------------------

    \1007\ Pine Gate Initial Comments at 24.
    \1008\ US DOE Initial Comments at 12-13.
---------------------------------------------------------------------------

    453. SEIA recommends that the Commission direct transmission 
providers to use the data and models used in NREL's Electrification 
Futures Study, Solar Futures Study, Storage Futures Study, and 
Transportation Futures Study.\1009\ PIOs disagree with granting 
discretion to transmission providers to define trends in technology and 
fuel costs because PIOs state that it could empower them to distort the 
modeling process and create Long-Term Scenarios that are 
meaningless.\1010\
---------------------------------------------------------------------------

    \1009\ SEIA Initial Comments at 10.
    \1010\ PIOs Initial Comments at 19.
---------------------------------------------------------------------------

    454. PIOs argue that the Commission should require transmission 
providers to use certain values for trends in technology and fuel costs 
within and outside of the electricity supply industry.\1011\
---------------------------------------------------------------------------

    \1011\ Id. at 17-19.
---------------------------------------------------------------------------

    455. New York TOs argue that trends in technology costs are 
amorphous and therefore should not be prescribed as a required factor 
for transmission providers to consider.\1012\ Similarly, PPL criticizes 
the Commission's proposed requirement that transmission providers 
forecast trends in technology without providing concrete assumptions to 
use, or without a guarantee for cost recovery for investments that are 
based on those uncertain forecasts.\1013\
---------------------------------------------------------------------------

    \1012\ New York TOs Initial Comments at 11-12.
    \1013\ PPL Initial Comments at 8.
---------------------------------------------------------------------------

(2) Commission Determination
    456. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to 
incorporate Factor Category Four: trends in fuel costs and in the cost, 
performance, and availability of generation, electric storage 
resources, and building and transportation electrification 
technologies, in the development of Long-Term Scenarios. We find it 
appropriate to require transmission providers to incorporate Factor 
Category Four into the development of Long-Term Scenarios because the 
relative cost of constructing and operating different types of 
generation or storage resources and the relative cost of electrifying 
certain energy end uses will affect Long-Term Transmission Needs. We 
further find that this requirement is necessary to ensure that 
transmission providers

[[Page 49358]]

develop plausible Long-Term Scenarios that account for technological 
changes expected over the transmission planning horizon, facilitating 
transmission providers' identification of Long-Term Transmission Needs.
    457. As requested by commenters, including US DOE, we modify this 
category of factors in the final order to clarify that this category of 
factors is meant to capture changes in the cost, as well as the 
performance and availability, of certain technologies relevant to the 
electric industry.\1014\ In response to commenters arguing that trends 
in technology costs are amorphous and should not be included in the 
final order as a required category of factors, we disagree. However, as 
discussed above, we grant transmission providers discretion to 
determine whether specific trends identified in Factor Category Four 
are likely to affect Long-Term Transmission Needs and how to account 
for those specific trends in Long-Term Scenarios.\1015\ As discussed in 
further detail below, transmission providers also have some discretion 
to discount or place more weight on the anticipated effects on Long-
Term Transmission Needs due to factors in this category.
---------------------------------------------------------------------------

    \1014\ Pine Gate Initial Comments at 24; US DOE Initial Comments 
at 12.
    \1015\ See New York TOs Initial Comments at 11-12; PPL Initial 
Comments at 8.
---------------------------------------------------------------------------

    458. In response to comments from US DOE,\1016\ we clarify that 
trends in fuel costs and in the cost, performance, and availability of 
generation, storage, and building and transportation electrification 
technologies may include, but are not limited to, cost and technology 
trends for: utility-scale generation construction costs for different 
generating technologies; distributed energy resources; storage 
technologies with differing duration limitations; carbon capture and 
sequestration; small modular nuclear; light-, medium-, and heavy-duty 
electric vehicles and electric vehicle supply equipment; and ground- 
and air-source heat pumps. While we agree with US DOE that transmission 
providers should consider trends in the cost, performance, and 
availability of transmission technologies as part of their evaluation 
of potential solutions to Long-Term Transmission Needs, we do not 
believe that these trends should be included as factors in this 
category because trends in the cost, performance, and availability of 
transmission technologies do not drive Long-Term Transmission Needs. We 
also agree with commenters that note that the effects of the factors in 
this category may vary significantly, such as shifts towards 
electrification leading to significant load growth, or cost reductions 
for emerging technologies, like long-duration electric storage 
resources, mitigating some new transmission needs.
---------------------------------------------------------------------------

    \1016\ US DOE Initial Comments at 12-13.
---------------------------------------------------------------------------

(e) Resource Retirements (Factor Category Five)
(1) Comments
    459. Several commenters support the proposed requirement that each 
Long-Term Scenario incorporate resource retirements as a category of 
factors.\1017\ PJM Market Monitor states that PJM faces the potential 
for the retirement of large coal resources and that the PJM capacity 
market design and the transmission planning process need to identify 
these specific resources well in advance and ensure an efficient 
response to obviate the need for nonmarket cost-of-service contracts to 
retain generation while transmission is constructed.\1018\
---------------------------------------------------------------------------

    \1017\ Breakthrough Energy Initial Comments at 14; NRECA Initial 
Comments at 31; NYISO Initial Comments at 24; PIOs Initial Comments 
at 21; SPP Market Monitor Initial Comments at 9; see also PJM Market 
Monitor at 3 (``PJM faces the potential retirement . . . of a 
significant amount of coal resources in the next five years. Both 
the PJM capacity market and design and the transmission planning 
process need to identify these specific resources well in advance 
and plan for their retirement in order to ensure an efficient 
response and to obviate the need for nonmarket cost of service 
contracts to retain the generation while transmission is 
constructed.'').
    \1018\ PJM Market Monitor Initial Comments at 3.
---------------------------------------------------------------------------

    460. PIOs and NYISO both argue that the Commission should further 
specify that transmission providers must incorporate expected trends in 
resource retirements rather than just announced retirements into Long-
Term Scenarios.\1019\ PIOs state the Commission should require 
transmission providers to (1) specify how they will use generator age 
and condition data to predict retirements, (2) include announced 
retirements, and (3) specify how they will reflect trends and 
incentives for distributed energy resources, as well as how they will 
quantify these trends.\1020\
---------------------------------------------------------------------------

    \1019\ NYISO Initial Comments at 24; PIOs Initial Comments at 
21.
    \1020\ PIOs Initial Comments at 21.
---------------------------------------------------------------------------

    461. NYISO states that the final order should confirm that each 
transmission planning region has the authority and flexibility to 
account for likely resource retirements that have not been announced by 
the resource based on factors that include the facility's age, its 
emission profile, applicable laws and regulations, and other 
factors.\1021\ Similarly, Pine Gate asserts that resource retirements 
should be included at the earliest opportunity as there is often a 
significant gap of time between when a public announcement is made and 
when the official notice of deactivation is communicated to the 
transmission provider.\1022\
---------------------------------------------------------------------------

    \1021\ NYISO Initial Comments at 24.
    \1022\ Pine Gate Initial Comments at 24.
---------------------------------------------------------------------------

    462. SEIA states that transmission providers should only be 
required to include the retirement of resources that have provided 
notice of pending retirement pursuant to the applicable tariff 
provisions.\1023\ PJM supports engaging in transparent economic impact 
analyses of generation resource retirements but asserts that such 
analyses might disclose confidential information about specific 
generators. Therefore, PJM contends that the Commission will need to 
provide clear direction on how it wishes to address these issues, 
especially since masking of data is not a practical solution once the 
transmission case is released.\1024\
---------------------------------------------------------------------------

    \1023\ SEIA Initial Comments at 10.
    \1024\ PJM Initial Comments at 6, 69.
---------------------------------------------------------------------------

(2) Commission Determination
    463. We adopt the NOPR proposal to require transmission providers 
in each transmission planning region to incorporate Factor Category 
Five: resource retirements, in the development of Long-Term Scenarios. 
We find it appropriate to require transmission providers to incorporate 
Factor Category Five because resource retirements expected over the 
transmission planning horizon will affect Long-Term Transmission Needs. 
Commenters generally support requiring this category of factors, but 
commenters disagree as to how transmission providers should account for 
projected resource retirements that have not been publicly 
announced.\1025\
---------------------------------------------------------------------------

    \1025\ NYISO Initial Comments at 24; Pine Gate Initial Comments 
at 24; PIOs Initial Comments at 21.
---------------------------------------------------------------------------

    464. In response to those commenters, we clarify that, to develop 
plausible Long-Term Scenarios, transmission providers must, in 
incorporating Factor Category Five into the development of Long-Term 
Scenarios, account for likely resource retirements beyond those that 
have been publicly announced. The record indicates that resource 
retirements have significantly influenced the supply of electricity in 
the past and are expected to do so in the coming decades.\1026\ The 
North

[[Page 49359]]

American Electric Reliability Corporation's 2021 Long-Term Reliability 
Assessment reports nearly 50 GW of confirmed thermal generation 
resource retirements by 2026 and acknowledges that many more are yet to 
be announced.\1027\ In addition, the record reflects that publicly 
announced resource retirements are only a fraction of the resource 
retirements expected over the required 20-year transmission planning 
horizon.\1028\ Given the significance of resource retirements, and the 
limited scope of publicly announced resource retirements, we find that 
transmission providers must account for expected retirements that have 
not been publicly announced to meet this final order's requirement that 
transmission providers develop a plausible set of Long-Term 
Scenarios.\1029\
---------------------------------------------------------------------------

    \1026\ See supra note 241; Colorado Consumer Advocate Initial 
Comments, attach. 7 (US DOE, Staff Report to the Secretary on 
Electricity Markets and Reliability (Aug. 2017)) at 13-14 (stating 
that 132 GW of generation capacity retired between 2002 and 2016--
approximately 15% of the installed capacity in 2002--due to the 
advantaged economics of natural gas-fired generation, low 
electricity demand growth, the deployment of variable energy 
resources, and regulatory requirements); see also, e.g., AEP Initial 
Comments at 4 n.12.
    \1027\ SEIA Initial Comments at 9 (citing North American 
Electric Reliability Corporation, 2021 Long-Term Reliability 
Assessment, at 30, 35 (Dec. 2021)). The North American Electric 
Reliability Corporation states that long-range retirement projects 
based on confirmed retirements could be ``significantly 
understated'' because generator retirement announcements can be made 
as late as 90 days prior to planned deactivation in some areas. The 
North American Electric Reliability Corporation 's 2021 reported 
retirements through 2026 increased 126% compared to the North 
American Electric Reliability Corporation's 2020 estimates; and the 
North American Electric Reliability Corporation's 2022 reported 
retirements through 2026 increased compared to the North American 
Electric Reliability Corporation 's 2021 retirements. See North 
American Electric Reliability Corporation, 2021 Long-Term 
Reliability Assessment, at 35 (Dec. 2021); NERC, 2022 Long-Term 
Reliability Assessment, at 17 (Dec. 2022).
    \1028\ For example, announced retirements account for less than 
half of MISO's projected retirements over a 20-year transmission 
planning horizon. See MISO Initial Comments at 35 (citing MISO, MISO 
Futures Report, at 14-19, (Dec. 2021), https://cdn.misoenergy.org/MISO%20Futures%20Report538224.pdf).
    \1029\ See infra Types of Long-Term Scenarios section.
---------------------------------------------------------------------------

    465. We provide flexibility to transmission providers to propose on 
compliance with this final order how to account for resource 
retirements that might take place over the transmission planning 
horizon, in addition to those that have been publicly announced. We 
note, for example, that transmission providers could propose to account 
for expected retirements by considering factors such as a generating 
facility's age, its emissions profile, its projected costs and 
revenues, and any applicable laws and regulations that may affect a 
generating facility's continued operation over the transmission 
planning horizon.\1030\ To the extent that certain laws and regulations 
identified by stakeholders in Factor Categories One and Two will 
necessitate the retirement of certain resources, we reiterate that 
transmission providers must develop Long-Term Scenarios that are 
consistent with such laws and regulations.
---------------------------------------------------------------------------

    \1030\ For example, MISO assumes age-based resource retirements 
which vary by resource type and scenario, over a 20-year 
transmission planning horizon. In a 2021 study, MISO assumes coal-
fired resources will retire at age 46 in one scenario, and age 36 in 
another. MISO assumes utility-scale solar resources will retire at 
age 25 in every scenario. MISO also incorporates resource 
retirements announced by the resource owner, stated in an integrated 
resource plan, or filed in MISO's Attachment Y. See MISO Initial 
Comments at 35 (citing MISO, MISO Futures Report, at 14-19, (Dec. 
2021), https://cdn.misoenergy.org/MISO%20Futures%20Report538224.pdf).
---------------------------------------------------------------------------

    466. In response to PJM's concerns that conducting transparent 
economic impact analyses of generation resource retirements could lead 
to the disclosure of confidential information about specific 
generators, we note that the Commission has previously acknowledged 
that tension exists between ensuring transparency in transmission 
planning processes and protecting confidential information, including 
commercially sensitive information.\1031\ We note that we are not 
specifying how transmission providers must estimate resource 
retirements, and we clarify that transmission providers may include 
what they believe to be appropriate confidentiality protections in 
their proposals to account for resource retirements that might take 
place over the transmission planning horizon. The Commission will 
evaluate those proposals by using the established principles in Order 
No. 890,\1032\ as well as precedent on existing confidentiality 
protections with respect to transmission planning that the Commission 
has previously found comply with the Order No. 890 principles, to guide 
its findings on whether such protections are appropriate.
---------------------------------------------------------------------------

    \1031\ Sw. Power Pool, Inc., 137 FERC ] 61,227, at P 20 (2011).
    \1032\ Order No. 890, 118 FERC ] 61,119 at PP 471-476.
---------------------------------------------------------------------------

(f) Generator Interconnection Requests and Withdrawals (Factor Category 
Six)
(1) Comments
    467. Several commenters support the proposed requirement that each 
Long-Term Scenario incorporate generator interconnection requests and 
withdrawals.\1033\ Pattern Energy argues that generation 
interconnection queues are indicative of the market for generation 
capacity additions and should also be a major source for generation 
assumptions in both near-term and long-term scenario planning.\1034\ 
SEIA supports the proposed requirement with the caveat that 
transmission providers should only include interconnection customers 
that have signed a facilities study agreement, or other applicable 
study agreement.\1035\ Cypress Creek asserts that the Commission should 
require transmission providers to include the proposed generator 
interconnection requests in the queue that have completed a system 
impact study as part of a uniform set of assumptions applicable across 
all scenarios.\1036\
---------------------------------------------------------------------------

    \1033\ Breakthrough Energy Initial Comments at 14; Cypress Creek 
Reply Comments at 5-7.
    \1034\ Pattern Energy Initial Comments at 26.
    \1035\ SEIA Initial Comments at 10.
    \1036\ Cypress Creek Reply Comments at 5-7.
---------------------------------------------------------------------------

    468. CAISO and MISO state that their regional transmission planning 
processes already include projects in the generator interconnection 
queue.\1037\ MISO further explains that it considers the generator 
interconnection queue when determining the location where future 
generation will interconnect, but MISO also states that transmission 
providers and their stakeholders need to have flexibility, including 
how to consider trends in interconnection queue requests.\1038\ 
Further, MISO argues that ``generation interconnection requests and 
withdrawals'' as stated in the NOPR is unclear regarding how the 
transmission provider must weigh withdrawals differently than requests. 
Therefore, MISO requests that the Commission revise the NOPR proposal 
to require transmission providers to ``consider activity in the 
generation interconnection queue.'' \1039\
---------------------------------------------------------------------------

    \1037\ CAISO Initial Comments at 34; MISO Initial Comments at 
35.
    \1038\ MISO Initial Comments at 35-36.
    \1039\ Id. at 36.
---------------------------------------------------------------------------

    469. Nebraska Commission asserts that the Commission should not 
include interconnection request withdrawals as a factor because it does 
not follow the Commission's cost causation principles and would 
incentivize additional interconnection requests. For example, Nebraska 
Commission states, most interconnection requests in SPP are 
duplicative, and entities compare costs among their requests once they 
are analyzed. Nebraska Commission asserts that such requests could be 
used to game the transmission planning process, create additional 
backlogs in the interconnection queue, and shift costs from 
interconnection customers to transmission customers.\1040\
---------------------------------------------------------------------------

    \1040\ Nebraska Commission Initial Comments at 4-5.
---------------------------------------------------------------------------

    470. Likewise, Omaha Public Power claims that, until generator 
interconnection reform is enacted, the use of interconnection queues 
and withdrawals as factors will lead to

[[Page 49360]]

scenario inaccuracy due to the size of interconnection backlogs and 
speculative nature of many queued projects.\1041\ Dominion also opposes 
using the number and size of interconnection requests as a basis for 
transmission planning because speculative interconnection requests 
could stimulate transmission development in areas slated for 
development by private interests.\1042\
---------------------------------------------------------------------------

    \1041\ Omaha Public Power Initial Comments at 3.
    \1042\ Dominion Reply Comments at 7-8.
---------------------------------------------------------------------------

    471. PJM Market Monitor states that, while there are many comments 
on the significant renewable resources PJM will connect to its grid, 
based on historic completion rates and effective load carry capability 
derate factors, only 5.6% of renewable resources are expected to go 
into service.\1043\
---------------------------------------------------------------------------

    \1043\ PJM Market Monitor Initial Comments at 4.
---------------------------------------------------------------------------

(2) Commission Determination
    472. We adopt the NOPR proposal to require transmission providers 
in each transmission planning region to incorporate Factor Category 
Six: generator interconnection requests and withdrawals, in the 
development of Long-Term Scenarios. We find it appropriate to require 
transmission providers to incorporate Factor Category Six because 
generation interconnection queues provide important information about 
future generation development over the transmission planning horizon 
and therefore affect Long-Term Transmission Needs. Multiple RTOs/ISOs 
explain that their regional transmission planning processes already 
account for generation projects in the interconnection queue, but MISO 
notes that transmission providers need flexibility in how to 
incorporate that data into the development of Long-Term 
Scenarios.\1044\ In response to MISO's concerns, we reiterate that 
transmission providers have discretion to determine how to account for 
all factors, including interconnection requests and withdrawals, in 
Long-Term Scenarios.
---------------------------------------------------------------------------

    \1044\ MISO Initial Comments at 35-36.
---------------------------------------------------------------------------

    473. We disagree with commenters that argue that, because many 
interconnection requests are speculative and/or duplicative, requiring 
transmission providers to incorporate Factor Category Six into the 
development of Long-Term Scenarios will compromise the accuracy of 
Long-Term Scenarios, shift costs to transmission customers that should 
be borne by interconnection customers, or create an incentive for 
additional interconnection requests that could slow down 
interconnection queue processing.\1045\ We note that over the years, 
and recently with Order No. 2023, transmission providers and the 
Commission have adopted changes to generator interconnection procedures 
to reduce the submission of speculative interconnection requests in the 
interconnection queue. For example, interconnection requests require 
significant financial commitments from the interconnection customer 
(e.g., application fees, study deposits, and site control 
requirements), which the Commission made more stringent in Order No. 
2023.\1046\ Noting that, as discussed above, transmission providers 
will have discretion as to how they account for factors in Long-Term 
Scenarios and may determine whether certain generator interconnection 
requests are speculative and/or duplicative, such that the requests are 
unlikely to affect Long-Term Transmission Needs, and then make 
corresponding adjustments to their Long-Term Scenarios. As discussed in 
further detail below, transmission providers can also account for 
uncertainty by discounting or putting more weight on the anticipated 
effects on Long-Term Transmission Needs due to factors in this 
category. Additionally, we believe that the existence of a large number 
of interconnection requests in a certain area, even if some of those 
requests are speculative, indicates that generation developers have an 
interest in interconnecting resources in that area, which Long-Term 
Scenarios should take into account.
---------------------------------------------------------------------------

    \1045\ Dominion Reply Comments at 7-8; Nebraska Commission 
Initial Comments at 4-5; Omaha Public Power Initial Comments at 3.
    \1046\ Order No. 2023, 184 FERC ] 61,054 at P 490.
---------------------------------------------------------------------------

(g) Utility and Corporate Commitments and Federal, Federally-Recognized 
Tribal, State, and Local Policy Goals That Affect Long-Term 
Transmission Needs (Factor Category Seven)
(1) Comments
    474. Some commenters generally support the proposed requirement to 
incorporate in Long-Term Scenarios utility and corporate commitments 
and Federal, state, and local goals that affect the future resource mix 
and demand.\1047\ ACEG contends that FPA section 217(b)(4) supports the 
Commission's proposed requirement to include public policies and 
utility and corporate renewable procurement goals within Long-Term 
Scenarios because load-serving entities' service obligations will 
depend upon both public policies and the resource preferences of their 
customers.\1048\ AEE highlights the role of local goals by noting that 
29 of the 50 most populous cities in the United States have set clean 
or renewable energy targets.\1049\
---------------------------------------------------------------------------

    \1047\ ACEG Initial Comments at 26-29; AEE Initial Comments at 
10-11; Advanced Energy Buyers Initial Comments at 5-6; Amazon 
Initial Comments at 3-4; Center for Biological Diversity Initial 
Comments at 9-12; Environmental Groups Supplemental Comments at 2; 
[Oslash]rsted Initial Comments at 7; Pacific Northwest State 
Agencies at Initial Comments at 14; PIOs Initial Comments at 18-19; 
SEIA Initial Comments at 10; SREA Initial Comments at 41-46; see 
also Environmental Groups Supplemental Comments at 2 (``The electric 
industry is undergoing a major transformation driven by consumer, 
utility, and corporate preferences, state public policies, and the 
cost competitiveness of renewable energy. The Commission's 
transmission planning and cost allocation standards must be up to 
the challenge of enabling this transition while ensuring the 
continued provision of reliable and affordable electricity at just 
and reasonable rates.'').
    \1048\ ACEG Initial Comments at 26-29.
    \1049\ AEE Initial Comments at 10-11 (citing Third Way, 
Utilities, Cities, and States with Clean Energy Targets (July 30, 
2021), https://www.thirdway.org/graphic/utilities-cities-and-states-with-clean-energy-targets).
---------------------------------------------------------------------------

    475. Advanced Energy Buyers argue that private efforts to use more 
low- and zero-carbon electricity are significantly affecting the 
resource mix and in turn transmission needs, noting that since 2014, 
commercial and industrial customers have contracted for more than 52 GW 
of clean energy in the United States, with annual increases every year 
since 2016.\1050\ Moreover, Advanced Energy Buyers state, corporate and 
industrial customer demand for renewable energy in the United States is 
expected to reach about 85 GW by 2030.\1051\ Advanced Energy Buyers 
state that, in some markets, corporate demand is already a dominant 
driver of renewable energy deployment, as in Illinois, where corporate 
procurement accounted for roughly one-third of total renewable 
deployment.\1052\ SEIA states that, for corporate commitments, 
transmission providers should include data from the Clean Energy Buyers 
Association Deal Tracker, and for utility commitments, transmission 
providers should include

[[Page 49361]]

data from state resource plans and regulatory filings.\1053\
---------------------------------------------------------------------------

    \1050\ Advanced Energy Buyers Initial Comments at 5 (citing 
Clean Energy Buyers Alliance, State of the Market 2022, https://cebuyers.org/state-of-the-market/).
    \1051\ Id. at 5-6 (citing Wood Mackenzie, Corporates Usher in 
New Wave of US Wind and Solar Growth (Aug. 2019), https://www.woodmac.com/our-expertise/focus/Power--Renewables/corporates-usher-in-new-wave-of-u.s.-wind-and-solar-growth/).
    \1052\ Id. at 6 (citing Advanced Energy Economy, Adding it All 
Up for Voluntary Buyers of Renewable Energy (Jan. 2021), https://blog.advancedenergyunited.org/adding-it-all-up-for-voluntary-buyers-of-renewable-energy; Microsoft, Greener datacenters for a brighter 
future: Microsoft's commitment to renewable energy (May 2016), 
https://blogs.microsoft.com/on-the-issues/2016/05/19/greener-datacenters-brighter-future-microsofts-commitment-renewable-energy/
).
    \1053\ SEIA Initial Comments at 10 (citing Clean Energy Buyer 
Association, CEBA Deal Tracker, https://cebuyers.org/deal-tracker/; 
Sierra Club, Check Out Where We Are Ready For 100%, https://www.sierraclub.org/climate-and-energy/map).
---------------------------------------------------------------------------

    476. SREA and ACEG argue that the Commission should require 
transmission providers to incorporate utilities' generation planning 
announcements associated with net zero commitments and publicized 
utility resource plans, including SEC filings and public statements, 
into the development of Long-Term Scenarios.\1054\ SREA contends that 
such a requirement would protect the interests of customers and 
generation developers because these announcements affect the 
marketplace.\1055\ Breakthrough Energy suggests that utility targets 
and expected consumer demand should also be incorporated into the 
development of Long-Term Scenarios because actual demand is often 
higher than reflected in utility plans, which do not sufficiently 
incorporate corporate demand, including corporate buyer 
commitments.\1056\
---------------------------------------------------------------------------

    \1054\ ACEG Initial Comments at 28-29; SREA Initial Comments at 
41-46.
    \1055\ SREA Initial Comments at 41-46.
    \1056\ Breakthrough Energy Initial Comments at 14-15.
---------------------------------------------------------------------------

    477. LADWP, MISO, and NRECA support the inclusion of this category 
of factors as long as transmission providers are allowed to discount 
these factors in their analysis by assuming the goals or commitments 
may not be fully met.\1057\ NRECA is concerned that factor category 
seven (utility and corporate commitments) carries a distinct risk of 
stranded transmission costs and therefore supports it being 
discounted.\1058\ NRECA further states that it is concerned that 
stakeholders may try to use Long-Term Regional Transmission Planning to 
impose goals and commitments that lack the force of law.\1059\ LADWP 
argues that the Commission should allow transmission planners to use 
discretion when identifying utility commitments and local goals.\1060\ 
MISO is concerned about the inherent difficulty of modeling corporate 
commitments given the ambiguous nature of corporate footprints.\1061\
---------------------------------------------------------------------------

    \1057\ LADWP Initial Comments at 3; MISO Initial Comments at 36; 
NRECA Initial Comments at 32-33.
    \1058\ NRECA Initial Comments at 32 (citing GDS Assocs., Report, 
at 12 (Aug. 17, 2022)).
    \1059\ Id. at 32-33.
    \1060\ LADWP Initial Comments at 3.
    \1061\ MISO Initial Comments at 36.
---------------------------------------------------------------------------

    478. Several commenters oppose including utility and corporate 
commitments and/or Federal, state, and local goals as a category of 
factors in Long-Term Scenarios.\1062\ For example, California 
Commission states that it is not clear what purpose would be served by 
requiring transmission providers to incorporate these commitments or 
goals into Long-Term Scenarios yet, at the same time, allowing them to 
discount such commitments or goals to account for their inherent 
uncertainty.\1063\ New York TOs argue that corporate commitments are 
amorphous and therefore should not be prescribed as a required factor 
for transmission providers to consider. Moreover, New York TOs state 
that, if a goal is not codified as a law, it is not clear that it is 
sufficiently solidified and supported to be included as a factor.\1064\
---------------------------------------------------------------------------

    \1062\ Alabama Commission Initial Comments at 6; California 
Commission Initial Comments at 20; Duke Initial Comments at 13; New 
York TOs Initial Comments at 11-12; Pennsylvania Commission Initial 
Comments at 6.
    \1063\ California Commission Initial Comments at 20.
    \1064\ New York TOs Initial Comments at 11-12.
---------------------------------------------------------------------------

    479. PJM argues that the NOPR proposal to include corporate 
commitments as a factor in Long-Term Scenarios is vague, inappropriate, 
and impractical, because even if PJM is able to develop a record of 
information in the expansive PJM footprint, this information will 
likely be incomplete. PJM argues that the burden to ensure that a 
transmission provider is aware of corporate commitments and goals 
should be on the corporation or another interested party.\1065\
---------------------------------------------------------------------------

    \1065\ PJM Reply Comments at 37-38 (citing PJM Initial Comments 
at 68).
---------------------------------------------------------------------------

    480. Illinois Commission states that transmission planning criteria 
should not include vague terms such as ``corporate goals,'' which could 
mean multiple things and may already be accounted for.\1066\ Alabama 
Commission states that corporate commitments and goals are not a 
sufficient basis for planning decisions as they are not law and 
accountability for achieving them is limited.\1067\ Similarly, 
Pennsylvania Commission states that determinants for Long-Term 
Scenarios should not be based on speculative factors, arguing that 
factors that include Federal, state, and local laws and regulations 
that affect the future resource mix and demand are preferable to 
factors that include utility, corporate, Federal, state, and local 
goals or policies that have no enforcement mechanisms.\1068\ PPL states 
that utility and corporate commitments are unlikely to be sufficiently 
firm or definitive to pass state siting review.\1069\
---------------------------------------------------------------------------

    \1066\ Illinois Commission Initial Comments at 7.
    \1067\ Alabama Commission Initial Comments at 6.
    \1068\ Pennsylvania Commission Initial Comments at 5-6.
    \1069\ PPL Initial Comments at 8.
---------------------------------------------------------------------------

(2) Commission Determination
    481. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to 
incorporate Factor Category Seven: utility and corporate commitments 
and Federal, federally-recognized Tribal, state, and local policy goals 
that affect Long-Term Transmission Needs, in the development of Long-
Term Scenarios. We find it appropriate to require transmission 
providers to incorporate Factor Category Seven into the development of 
Long-Term Scenarios because the relevant commitments and goals 
represent known consumer preferences that have been, and will continue 
to be, key drivers of Long-Term Transmission Needs. We agree with 
commenters that argue that corporate demand for clean energy resources, 
as demonstrated by the volume of bilateral corporate contracts with 
renewable energy resources, is already a major driver of changes in the 
resource mix and demand and that corporate and industrial customer 
demand for clean energy is projected to increase. We believe that it is 
necessary for transmission providers to incorporate publicly announced 
utility commitments in the development of Long-Term Scenarios. Such 
commitments may be ignored or overlooked in retail-level regulatory 
proceedings, but they nevertheless may have an impact on future changes 
in the resource mix and demand that must be accounted for to ensure the 
development of plausible Long-Term Scenarios.
    482. We modify the NOPR proposal for Factor Category Seven to 
include federally-recognized Tribal goals that affect the resource mix 
and demand because we are persuaded by commenters that argue that such 
factors have the same potential to affect Long-Term Transmission Needs 
as Federal, state, and local goals. We believe that federally-
recognized Tribal goals should include publicly announced policy 
recommendations, such as energy vision reports.\1070\ Further, as 
discussed under Additional Categories of Factors below, we recognize 
that energy equity and justice goals are potential factors within 
Factor Category Seven.
---------------------------------------------------------------------------

    \1070\ See, e.g., Columbia River Inter-Tribal Fish Comm'n, 
Energy Vision for the Columbia River Basin (Sept. 2022), https://critfc.org/wp-content/uploads/2022/09/CRITFC-Energy-Vision-Full-Report.pdf.

---------------------------------------------------------------------------

[[Page 49362]]

    483. While Federal, federally-recognized Tribal, state, and local 
goals may not have the same durability and binding impact of laws and 
regulations, we believe that it is appropriate for transmission 
providers to account for such goals in Long-Term Scenarios because 
these goals represent known preferences of governmental entities that 
affect Long-Term Transmission Needs. Such goals may improve or diminish 
the prospects of deploying certain technologies. For example, as AEE 
explains, local governments representing some of the most populous 
cities in the United States have established goals to have their 
cities' loads served by clean or renewable energy.\1071\
---------------------------------------------------------------------------

    \1071\ AEE Initial Comments at 10-11 (citing Third Way, 
Utilities, Cities, and States with Clean Energy Targets (July 30, 
2021), https://www.thirdway.org/graphic/utilities-cities-and-states-with-clean-energy-targets).
---------------------------------------------------------------------------

    484. We disagree with commenters that argue that transmission 
providers should not be required to incorporate utility and corporate 
commitments into the development of Long-Term Scenarios because they 
may not be significant enough to drive Long-Term Transmission Needs or 
that accountability for achieving commitments and goals is too limited 
for these factors to be considered sufficiently firm.\1072\ We 
acknowledge that utility and corporate commitments and governmental 
goals may be more likely to change over the transmission planning 
horizon than factors in other required factor categories; however, we 
are not persuaded that these commitments and goals are so speculative, 
amorphous, or unreliable that they should not be incorporated into 
Long-Term Scenarios at all. We emphasize that transmission providers 
have discretion, as discussed above, in how to account for these 
factors in the development of Long-Term Scenarios, and we note, as 
discussed in further detail below, that transmission providers can 
account for the uncertainty associated with the achievement of these 
commitments and goals by using discounting or putting more weight on 
the effects of these factors on Long-Term Transmission Needs in each of 
the required Long-Term Scenarios. Similarly, transmission providers 
have discretion to determine how to account for commitments and goals 
in Long-Term Scenarios if the effects of particular commitments or 
goals conflict with, negate, or duplicate the effects of other factors.
---------------------------------------------------------------------------

    \1072\ Alabama Commission Initial Comments at 6; California 
Commission Initial Comments at 20; Illinois Commission Initial 
Comments at 7; New York TOs Initial Comments at 11-12; Pennsylvania 
Commission Initial Comments at 5-6; PJM Reply Comments at 37-38 
(citing PJM Initial Comments at 68); PPL Initial Comments at 8.
---------------------------------------------------------------------------

(h) Additional Categories of Factors
(1) Comments on Energy Equity and Justice
    485. Some commenters argue that the Commission should include 
equity and energy justice considerations in Long-Term Regional 
Transmission Planning.\1073\ Grand Rapids NAACP, agreeing with NASEO, 
urges the Commission to expand factors considered in Long-Term Regional 
Transmission Planning to include energy equity and justice.\1074\ Grand 
Rapids NAACP also states that transmission providers should be required 
to follow Federal, state, and local laws addressing the need for energy 
equity and justice.\1075\ In concordance with PIOs, Grand Rapids NAACP 
urges the Commission to address equity in the transmission planning 
process because doing so would encourage competition and lower consumer 
costs.\1076\ Finally, Grand Rapids NAACP urges the Commission to 
encourage transmission providers to develop metrics that advance 
economic equity and environmental justice by facilitating consideration 
of the impact of transmission infrastructure on disadvantaged 
communities.\1077\
---------------------------------------------------------------------------

    \1073\ See, e.g., California Energy Commission Initial Comments 
at 2; City of New York Initial Comments at 9; Clean Energy Buyers 
Initial Comments at 8-9; Grand Rapids NAACP Initial Comments at 12, 
15, 21, 23; Grand Rapids NAACP Reply Comments at 2-3, 5; Montclair 
Congregation Supplemental Comments at 1; NARUC Initial Comments at 
3-4; NASEO Initial Comments at 5; PIOs Initial Comments at 35-36; 
PIOs Reply Comments at 15; Policy Integrity Initial Comments at 28; 
WE ACT Initial Comments at 4-6.
    \1074\ Grand Rapids NAACP Reply Comments at 2 (citing NASEO 
Initial Comments at 5).
    \1075\ Id.
    \1076\ Id. (citing PIOs Initial Comments at 35, 36).
    \1077\ Id. at 2-3 (citing NARUC Initial Comments at 3-4).
---------------------------------------------------------------------------

    486. US DOE asserts that energy justice considerations will form an 
integral part of transmission planning. Specifically, US DOE states 
that transmission planning can identify potential sources, sinks, and 
locations of transmission expansion facilities and that identifying 
locations where frontline communities and historically underserved 
communities have faced long-standing impacts may affect the future 
resource mix.\1078\ NESCOE agrees with US DOE and argues that regional 
transmission planning processes should accommodate state efforts to 
advance equity and environmental justice concerns.\1079\ New England 
for Offshore Wind argues that without a transparent and inclusive 
transmission planning process, regional transmission planning efforts 
will be at odds with state policy on environmental justice.\1080\
---------------------------------------------------------------------------

    \1078\ US DOE Initial Comments at 9.
    \1079\ NESCOE Reply Comments at 8-9.
    \1080\ New England for Offshore Wind Initial Comments at 5.
---------------------------------------------------------------------------

    487. PIOs state that the Commission should be clear that Long-Term 
Regional Transmission Planning complies with and incorporates relevant 
aspects of applicable Federal, federally-recognized Tribal, state, and 
local environmental and energy justice policies--including future 
resource mix impacts, assignment of transmission benefits toward 
disadvantaged communities, and project selection.\1081\
---------------------------------------------------------------------------

    \1081\ PIOs Reply Comments at 15 (citing Grand Rapids NAACP 
Initial Comments at 12-15, 21-23 (listing notable Federal, state, 
and local public policies requiring that equity and energy justice 
inform decision making processes); WE ACT Initial Comments at 6).
---------------------------------------------------------------------------

    488. CARE Coalition states that the Commission should consider 
issues of siting and the granting of permits that cause significant 
delays in construction of new transmission facilities.\1082\ CARE 
Coalition emphasizes WE ACT's argument that a final order should ensure 
that transmission planners and states ``are cognizant about siting and 
the potential harms of transmission development to environmental 
justice communities.'' \1083\ Relatedly, CARE Coalition highlights 
NRECA's argument that rural and poorer areas are disproportionately 
burdened under the current regime because ``siting decisions are 
primarily driven by technical and economic factors.'' \1084\
---------------------------------------------------------------------------

    \1082\ CARE Coalition Reply Comments at 3.
    \1083\ Id. at 4 (citing WE ACT Initial Comments at 6).
    \1084\ Id. (citing NRECA Initial Comments at 39 n.111).
---------------------------------------------------------------------------

(2) Comments on Efficiency and Technology
    489. NASEO argues that the Commission should expand its list of 
factors that transmission providers should include in Long-Term 
Regional Transmission Planning and Long-Term Scenarios to include 
increased energy efficiency of existing transmission lines, and the 
efficient use of existing rights of way.\1085\ Invenergy suggests that 
the Commission expressly require consideration of advanced-stage 
merchant HVDC transmission as a factor in regional transmission 
planning scenarios.\1086\ Invenergy highlights US DOE's proposal that 
transmission providers consider trends in the development of HVDC 
network technology, arguing, however, that such

[[Page 49363]]

consideration should include incorporating and accounting for HVDC 
transmission facilities in transmission planning models and 
scenarios.\1087\
---------------------------------------------------------------------------

    \1085\ NASEO Initial Comments at 5.
    \1086\ Invenergy Initial Comments at 6-7.
    \1087\ Invenergy Reply Comments at 11 (citing US DOE Initial 
Comments at 13).
---------------------------------------------------------------------------

(3) Comments Regarding Enhanced Reliability and Interregional Transfer 
Capability
    490. PJM recommends that the Commission require enhanced 
reliability and Interregional Transfer Capability as two additional 
categories of factors that transmission providers must incorporate into 
the development of Long-Term Scenarios.\1088\ PJM envisions enhanced 
reliability to include, but not be limited to, storm hardening of 
critical facilities, reducing the number of critical CIP-014 facilities 
through transmission upgrades, coordination of infrastructure 
development with natural gas pipelines serving generation in the 
region, and ensuring redundancy of facilities, where appropriate, to 
address the threat of physical or cyber attacks.\1089\ PJM envisions 
Interregional Transfer Capability to be established in accordance with 
the methodology that the Commission adopts in a subsequent order.\1090\
---------------------------------------------------------------------------

    \1088\ PJM Initial Comments at 6, 13, 65-67.
    \1089\ Id. at 66.
    \1090\ Id. at 66-67.
---------------------------------------------------------------------------

    491. Invenergy agrees with the additional categories of factors 
that PJM proposes.\1091\ ELCON supports the consideration of transfer 
capability between seams, which it asserts would provide transmission 
providers with the ability to develop and consider solutions that may 
solve for multiple drivers and offer greater benefits to more 
consumers.\1092\ In contrast, AEE states that it disagrees with the 
additional categories of factors that PJM proposes, although it agrees 
with PJM that enhanced reliability planning is an important 
consideration.\1093\
---------------------------------------------------------------------------

    \1091\ Invenergy Reply Comments at 11.
    \1092\ ELCON Initial Comments at 8.
    \1093\ AEE Reply Comments at 20.
---------------------------------------------------------------------------

(4) Commission Determination
    492. We recognize that some commenters ask the Commission to 
require transmission providers to incorporate several categories of 
factors in addition to those proposed in the NOPR in the development of 
Long-Term Scenarios. We decline to include energy equity and justice as 
a distinct and additional category of factors because we believe that 
these important energy equity and justice laws and regulations, or 
goals, that are likely to affect Long-Term Transmission Needs, are 
accounted for in Factor Category One: Federal, federally-recognized 
Tribal, state, and local laws and regulations affecting the resource 
mix and demand, or Seven: utility and corporate commitments and 
Federal, federally-recognized Tribal, state, and local policy goals 
that affect Long-Term Transmission Needs.\1094\ Stakeholders will have 
a meaningful opportunity to identify any such factors as part of the 
open and transparent stakeholder process described below in the 
Stakeholder Process and Transparency section.
---------------------------------------------------------------------------

    \1094\ Grand Rapids NAACP Reply Comments at 2 (citing NASEO 
Initial Comments at 5).
---------------------------------------------------------------------------

    493. We decline to adopt Invenergy's recommendation that the 
Commission require transmission providers to include advanced-stage 
merchant HVDC transmission as an additional category of factors. The 
Commission did not propose specific requirements in the NOPR regarding 
merchant HVDC transmission facilities under development, and we are not 
persuaded by the evidence in the record that the Commission should 
include advanced-stage HVDC transmission facilities in the minimum set 
of known determinants of Long-Term Transmission Needs. We reiterate 
that transmission providers may be aware of additional categories of 
factors beyond those adopted in this final order that drive Long-Term 
Transmission Needs and may incorporate additional categories of factors 
in the development of Long-Term Scenarios provided that each Long-Term 
Scenario remains plausible.
    494. In response to PJM's request for the Commission to require 
enhanced reliability and Interregional Transfer Capability \1095\ as 
additional categories of factors,\1096\ we find that the record in this 
proceeding is insufficient to adequately consider whether to require 
transmission providers to adopt such categories of factors in this 
final order. As noted in our response to Invenergy just above, 
transmission providers may incorporate additional categories of factors 
in the development of Long-Term Scenarios provided that each Long-Term 
Scenario remains plausible. We note that, in this final order, we 
provide transmission providers with flexibility in how they develop 
Long-Term Scenarios to identify Long-Term Transmission Needs. We 
believe that other parts of this final order enable transmission 
providers to account for enhanced reliability and Interregional 
Transfer Capability by modeling sensitivities and using certain 
transmission benefits. As discussed below, we require transmission 
providers to develop at least one sensitivity analysis, applied to each 
Long-Term Scenario, to account for uncertain operational outcomes 
during multiple concurrent and sustained generation and/or transmission 
outages due to an extreme weather event across a wide area that 
determine the benefits of or need for Long-Term Regional Transmission 
Facilities. As discussed in the Evaluation of the Benefits of Regional 
Transmission Facilities section below, we require transmission 
providers to measure, and consider as part of Benefit 6, the benefits 
associated with any increase in Interregional Transfer Capability that 
a Long-Term Regional Transmission Facility would provide.
---------------------------------------------------------------------------

    \1095\ We define Interregional Transfer Capability for purposes 
of this final order consistent with the definition of total transfer 
capability in the Commission's regulations as: ``the amount of 
electric power that can be moved or transferred reliably from one 
area to another area of the interconnected transmission systems by 
way of all transmission lines (or paths) between those areas under 
specified system conditions, or such definition as contained in 
Commission-approved Reliability Standards.'' 18 CFR 37.6(b)(1)(vi). 
In the context of Interregional Transfer Capability, an ``area'' in 
the above definition would be a transmission planning region 
composed of transmission providers.
    \1096\ PJM Initial Comments at 6, 13, 65-67.
---------------------------------------------------------------------------

c. Treatment of Specific Categories of Factors
i. NOPR Proposal
    495. The Commission proposed to require that each Long-Term 
Scenario that transmission providers use in Long-Term Regional 
Transmission Planning incorporate and be consistent with Federal, 
state, and local laws and regulations that affect the future resource 
mix and demand; Federal, state, and local laws and regulations on 
decarbonization and electrification; and state-approved integrated 
resource plans and expected supply obligations for load-serving 
entities. The Commission preliminarily found that it is reasonable to 
require transmission providers to assume that legally binding 
obligations and state utility regulator-approved plans will be followed 
and that expected supply obligations for load-serving entities will be 
fully met. As a result, the Commission explained that, under the 
proposal, transmission providers cannot discount the factors included 
in the categories of Federal, state, and local laws and regulations 
that affect the future resource mix; Federal, state, and local laws and 
regulations on decarbonization and electrification; and state-approved 
integrated resource plans and expected

[[Page 49364]]

supply obligations for load-serving entities.\1097\
---------------------------------------------------------------------------

    \1097\ NOPR, 179 FERC ] 61,028 at P 106.
---------------------------------------------------------------------------

    496. In addition, the Commission proposed to require that each 
Long-Term Scenario that transmission providers use in Long-Term 
Regional Transmission Planning include trends in technology and fuel 
costs within and outside the electricity supply industry, including 
shifts toward electrification of buildings and transportation; resource 
retirements; and generator interconnection requests and withdrawals. 
For these particular categories of factors, the Commission proposed to 
provide transmission providers with flexibility in how they incorporate 
each factor into Long-Term Scenarios as long as transmission providers 
identify and publish specific factors for each of these categories, as 
further described below.\1098\
---------------------------------------------------------------------------

    \1098\ Id. P 107.
---------------------------------------------------------------------------

    497. Further, the Commission proposed to require that each Long-
Term Scenario incorporate utility and corporate goals and Federal, 
state, and local goals that affect the future resource mix and demand. 
However, the Commission acknowledged that these categories of factors 
are less binding and more likely to change over time, and therefore 
their impact on the future resource mix and demand are less certain, 
than other categories of factors. For this reason, the Commission 
preliminarily found that it may be appropriate for transmission 
providers to discount such goals to account for this uncertainty. The 
Commission explained that transmission providers would not be required 
to assume that utility and corporate goals and Federal, state, and 
local goals that affect the future resource mix will be fully 
met.\1099\
---------------------------------------------------------------------------

    \1099\ Id. P 108.
---------------------------------------------------------------------------

ii. Comments
    498. Several commenters, that generally support the NOPR proposal, 
support discounting and rebut arguments opposing discounting.\1100\ 
NRECA, Exelon, and TAPS argue that the NOPR proposal to allow 
transmission providers to discount some categories of factors while 
weighing factors in other categories more heavily strikes an 
appropriate balance.\1101\ Specifically, Exelon supports the NOPR 
proposal to allow for variation in the treatment of different 
categories of factors such as legislated energy policy, which it states 
should not vary by scenario, and non-binding targets, which it states 
may be discounted yet are important to consider.\1102\ TAPS also 
supports the proposed flexibility in how transmission providers 
incorporate factors that are not Federal, state, and local laws and 
regulations, state-approved integrated resource plans, and expected 
supply obligations for load-serving entities.\1103\
---------------------------------------------------------------------------

    \1100\ Exelon Initial Comments at 10-11; Georgia Commission 
Initial Comments at 4; Illinois Commission Initial Comments at 7; 
NEPOOL Initial Comments at 7; NRECA Initial Comments at 32; TAPS 
Initial Comments at 2-3, 8.
    \1101\ Exelon Initial Comments at 10-11; NRECA Initial Comments 
at 32; TAPS Initial Comments at 2-3, 8.
    \1102\ Exelon Initial Comments at 10-11.
    \1103\ TAPS Initial Comments at 2-3, 8.
---------------------------------------------------------------------------

    499. Some commenters express concerns that the NOPR proposal would 
allow transmission providers in each transmission planning region to 
discount, or not fully incorporate, some factors when developing Long-
Term Scenarios.\1104\ Clean Energy Associations state that certain 
factors (i.e., Federal, state, and local policies, utility integrated 
resource plans, generator retirements, interconnection requests, 
corporate commitments, and trends in technology and fuel costs) can be 
quantified and should be reflected in Long-Term Scenarios without 
discounting.\1105\ Clean Energy Buyers are concerned that the 
flexibility proposed in the NOPR for transmission providers to 
incorporate into their Long-Term Scenarios the categories of factors 
that include trends in fuel costs and technologies both inside and 
outside the electricity supply industry, including regarding shifts in 
electrification of transport and buildings, resource retirements, and 
generator interconnection requests and withdrawals, could delay the 
transmission build-out.\1106\ ACEG recommends that the Commission 
presume that all factors are required to be incorporated (and not 
discounted or only considered) unless the Commission approves a request 
from the transmission providers in a transmission planning region not 
to include a factor.\1107\ In response, California Municipal Utilities 
argue that mandating the use of specific factors would not account for 
the cost consequences of such mandates, which must be considered for 
any transmission planning requirements to be just and reasonable.\1108\
---------------------------------------------------------------------------

    \1104\ ACEG Initial Comments at 27-28; Amazon Initial Comments 
at 4; Clean Energy Associations Initial Comments at 10-11; Pine Gate 
Initial Comments at 23-25; PIOs Initial Comments at 18-19; SEIA 
Initial Comments at 8-10.
    \1105\ Clean Energy Associations Initial Comments at 10-11.
    \1106\ Clean Energy Buyers Initial Comments at 15-16.
    \1107\ ACEG Initial Comments at 27.
    \1108\ California Municipal Utilities Reply Comments at 5-6.
---------------------------------------------------------------------------

    500. Several commenters object to the Commission's proposal to 
provide transmission providers with the flexibility to discount utility 
and corporate and Federal, state, and local goals that affect the 
future resource mix and demand.\1109\ Amazon states that transmission 
providers should not be allowed to discount clean energy goals in their 
development of Long-Term Scenarios without proving such discounting is 
just and reasonable by showing evidence that such goals have been 
unfulfilled in the past, or that those goals have been altered or 
abandoned.\1110\
---------------------------------------------------------------------------

    \1109\ Amazon Initial Comments at 4; Clean Energy Associations 
Initial Comments at 10-11; Pine Gate Initial Comments at 24-25; PIOs 
Initial Comments at 18-19; SEIA Initial Comments at 8.
    \1110\ Amazon Initial Comments at 4.
---------------------------------------------------------------------------

    501. PIOs state that the NOPR proposal to discount Factor Category 
Seven would allow transmission providers to game the results if their 
incentives are contrary to consumers' goals.\1111\ SEIA urges the 
Commission to limit the flexibility given to transmission providers 
regarding this factor because SEIA believes that they would ignore 
certain factors if consideration is not mandatory.\1112\ Further, Clean 
Energy Associations argue that utility, corporate, and Federal, state, 
and local goals should be fully incorporated, without discounting 
targets not enshrined in law or regulation. If necessary, Clean Energy 
Associations contend, changes in non-binding obligations could be 
treated as a sensitivity or probabilistic change in one or more 
scenarios to determine how they might affect transmission 
development.\1113\
---------------------------------------------------------------------------

    \1111\ PIOs Initial Comments at 18-19.
    \1112\ SEIA Initial Comments at 8.
    \1113\ Clean Energy Associations Initial Comments at 10-11.
---------------------------------------------------------------------------

    502. PIOs state that, when utilities make commitments affecting the 
future resource mix and consumer demand, they should be held to them 
and that granting transmission providers complete discretion to 
discount such factors could undermine the goals of the NOPR proposal. 
Thus, PIOs state, the Commission should set minimum requirements for 
some factors, including for incorporating corporate commitments into 
future resource mix estimates.\1114\ PIOs assert that widespread 
support exists for these

[[Page 49365]]

recommendations, citing ELCON as an example.\1115\
---------------------------------------------------------------------------

    \1114\ PIOs Initial Comments at 17-18.
    \1115\ PIOs Reply Comments at 10-11 (citing ELCON Initial 
Comments at 4).
---------------------------------------------------------------------------

    503. Pine Gate argues that transmission providers should be 
required to assume that utility and corporate and Federal, state, and 
local goals that affect the future resource mix will be fully met in at 
least one of their Long-Term Scenarios.\1116\
---------------------------------------------------------------------------

    \1116\ Pine Gate Initial Comments at 25.
---------------------------------------------------------------------------

    504. In addition, Pattern Energy argues that the Commission should 
distinguish between generation assumptions and demand assumptions for 
purposes of 20-year transmission planning so that there is no 
ambiguity. For example, Pattern Energy states that transmission 
providers should not be permitted to utilize their planning for load 
growth to satisfy the requirement to plan for changing resources and 
demand. Pattern Energy asserts that transmission providers should be 
required to distinguish between modeling a changing resource mix and, 
separately, a changing demand profile, arguing that both are important 
and should be considerations in near-term and long-term transmission 
planning.\1117\
---------------------------------------------------------------------------

    \1117\ Pattern Energy Initial Comments at 26.
---------------------------------------------------------------------------

    505. NYISO argues that the final order should permit transmission 
providers to appropriately account for, in coordination with state and 
local entities and stakeholders, the likely effect of applicable laws 
and regulations on the need for transmission and to realistically 
appraise achievement of such laws and regulations.\1118\
---------------------------------------------------------------------------

    \1118\ NYISO Initial Comments at 23.
---------------------------------------------------------------------------

    506. Some commenters oppose the NOPR proposal to require that 
transmission providers incorporate applicable local laws and 
regulations in their development of Long-Term Scenarios.\1119\ Duke 
explains that although local laws and regulations for decarbonization 
and electrification may affect the resource mix and demand at the local 
level, it is unclear how such laws would have a material effect on 
regional transmission planning that warrants the additional burden of 
tracking and incorporating them into Long-Term Scenarios.\1120\ Alabama 
Commission argues that local laws, regulations, and goals might change 
or conflict with the policy perspectives of other states.\1121\ PPL 
claims that the NOPR proposal is impractical and will significantly 
increase uncertainty, which in turn will invite disagreement and 
litigation.\1122\ PJM recommends that the Commission require 
transmission providers to only consider local laws, local regulations, 
and local goals to the extent that such laws, regulations, and goals 
are brought to their attention by states, other local regulators, or 
stakeholders.\1123\
---------------------------------------------------------------------------

    \1119\ Alabama Commission Initial Comments at 5-6; Ameren 
Initial Comments at 9-10; Duke Initial Comments at 13-14, 16; ISO-NE 
Initial Comments at 26-27; ISO/RTO Council Initial Comments at 4-5; 
NYISO Initial Comments at 21-23.
    \1120\ Duke Initial Comments at 13.
    \1121\ Alabama Commission Initial Comments at 5-6.
    \1122\ PPL Initial Comments at 7-8.
    \1123\ PJM Reply Comments at 38 (citing PJM Initial Comments at 
68).
---------------------------------------------------------------------------

iii. Commission Determination
(a) Treatment of Factors in the First Three Categories
    507. With regard to the first three categories of factors,\1124\ we 
require transmission providers in each transmission planning region to 
assume that legally binding obligations (i.e., Federal, federally-
recognized Tribal, state, and local laws and regulations) are followed, 
state-approved integrated resource plans are followed, and expected 
supply obligations for load-serving entities are fully met. Therefore, 
we require that each Long-Term Scenario account for and be consistent 
with, and not discount, factors in the first three categories of 
factors once the transmission providers have determined that such a 
factor is likely to affect Long-Term Transmission Needs. We believe it 
is necessary to prohibit discounting of factors in the first three 
categories of factors because they are more certain drivers of Long-
Term Transmission Needs, relative to factors in other factor 
categories.
---------------------------------------------------------------------------

    \1124\ As explained above, the first three categories of factors 
are: (1) Federal, federally-recognized Tribal, state, and local laws 
and regulations affecting the resource mix and demand; (2) Federal, 
federally-recognized Tribal, state, and local laws and regulations 
on decarbonization and electrification; and (3) state-approved 
integrated resource plans and expected supply obligations for load-
serving entities.
---------------------------------------------------------------------------

    508. We clarify that transmission providers may rely on the open 
and transparent stakeholder process discussed below to identify the 
factors in the first three required categories of factors. More 
specifically, this final order does not obligate transmission providers 
to independently identify all of the factors in the first three 
categories of factors. We believe that it would be unduly burdensome 
and potentially impractical for transmission providers to independently 
identify all of the potential factors in the first three categories of 
factors, which will include numerous Federal, federally-recognized 
Tribal, state, and local laws and regulations, as well as integrated 
resource plans and expected supply obligations for load-serving 
entities.\1125\ However, transmission providers may, if they choose, 
independently identify factors in the first three categories of factors 
as part of the stakeholder process, discussed further in the 
Stakeholder Process and Transparency section below.
---------------------------------------------------------------------------

    \1125\ The Commission has previously found that transmission 
providers ``cannot later be faulted'' for failing to consider 
projections of a need for service from a point-to-point transmission 
customer if such projections are not provided by the transmission 
customer. Order No. 890, 118 FERC ] 61,119 at P 487; id. (``We also 
believe that it is appropriate to require point-to-point customers 
to submit any projections they have of a need for service over the 
planning horizon and at what receipt and delivery points . . . . If 
the point-to-point customers do not submit such projections, then 
the transmission provider cannot later be faulted for failing to 
consider planning scenarios that might have taken into account 
reasonable projections of future system uses that were not the 
subject of specific service requests.'').
---------------------------------------------------------------------------

    509. We believe that this clarification addresses PJM's request 
that we clarify that the burden of making the transmission provider 
aware of laws, regulations, and goals rests with stakeholders and not 
with the transmission provider itself.\1126\ We also believe that this 
clarification mitigates the potential administrative burdens and 
compliance risks identified by ISO-NE, as well as the burden of 
incorporating factors identified by SPP.\1127\
---------------------------------------------------------------------------

    \1126\ PJM Initial Comments at 68.
    \1127\ ISO-NE Initial Comments at 26-27; SPP Initial Comments at 
7-8.
---------------------------------------------------------------------------

    510. In addition, as clarified above, transmission providers retain 
the discretion to determine whether particular factors, including those 
in the first three categories of factors, that stakeholders identify 
are likely to affect Long-Term Transmission Needs. Thus, transmission 
providers may determine, for example, that some stakeholder-identified 
local laws and regulations that fall within Factor Categories One and 
Two are unlikely to affect Long-Term Transmission Needs and therefore 
need not be accounted for in the development of Long-Term Scenarios. We 
believe that this clarification addresses concerns about the additional 
burden some commenters identified of tracking and incorporating local 
laws and regulations into the development of Long-Term Scenarios, as 
well as concerns that the inclusion of local laws and regulations in 
the first two categories of factors creates a burden for transmission 
providers to account for factors that are unlikely to affect Long-Term 
Transmission Needs.\1128\
---------------------------------------------------------------------------

    \1128\ Duke Initial Comments at 13.
---------------------------------------------------------------------------

    511. We believe that the open and transparent stakeholder process

[[Page 49366]]

discussed below in the Stakeholder Process and Transparency section 
will help transmission providers to ensure that each Long-Term Scenario 
accounts for factors in the first three categories of factors without 
discounting the effects of those factors on Long-Term Transmission 
Needs. We expect that transmission providers will rely, at least in 
part, on information that relevant Federal, state, and local government 
entities, federally-recognized Tribes, utilities, and load-serving 
entities provide during the required open and transparent stakeholder 
process to determine if specific factors are likely to affect Long-Term 
Transmission Needs and how to account for those specific factors in 
Long-Term Scenarios. We agree with NYISO regarding the value of 
coordination and clarify that transmission providers may work in 
coordination with government entities and stakeholders to determine how 
applicable laws and regulations may affect Long-Term Transmission 
Needs.\1129\
---------------------------------------------------------------------------

    \1129\ NYISO Initial Comments at 23.
---------------------------------------------------------------------------

    512. We recognize that some commenters raise concerns as to whether 
factors in the first three categories of factors can be fully achieved 
(e.g., a legislative requirement is met) or may have various levels of 
impact on Long-Term Transmission Needs.\1130\ At the outset, we find it 
appropriate to assume legally binding obligations are met, unless and 
until there is a change in law. Government entities have an interest 
and ability to ensure that the requirements of laws and regulations are 
fully achieved. Similarly, utilities and load-serving entities, as well 
as the relevant retail regulator, have an interest in developing 
accurate integrated resource plans and expected supply obligations that 
can be fully achieved. Even in the limited circumstances in which these 
factors are not fully achieved, we expect the targets or requirements 
associated with these factors will be informative for purposes of 
identifying Long-Term Transmission Needs. We acknowledge that, for 
certain factors, there may be insufficient information for transmission 
providers to determine, or stakeholder disagreement about, how the 
factor will affect Long-Term Transmission Needs. In such instances, we 
clarify that transmission providers have discretion over how to account 
for a factor in the first three categories of factors in their Long-
Term Scenarios as long as the assumptions in each Long-Term Scenario 
are consistent with legally binding obligations, state-approved 
integrated resource plans, and expected supply obligations of load-
serving entities.
---------------------------------------------------------------------------

    \1130\ Id.
---------------------------------------------------------------------------

    513. For example, when a legally binding obligation sets a minimum 
requirement or threshold (e.g., a state law requiring the deployment of 
at least 5 gigawatts of electric storage resources by 2030), 
transmission providers may develop Long-Term Scenarios assuming either 
the minimum amount of the requirement or more than the minimum amount 
of the requirement (e.g., modeling 10 gigawatts of electric storage 
resources deployed by 2030 instead of the minimum 5 gigawatts) but may 
not develop any Long-Term Scenarios that are inconsistent with that 
minimum (e.g., modeling only 2 gigawatts of electric storage resources 
deployed by 2030). We believe that these clarifications sufficiently 
address PPL's concerns regarding the uncertainty associated with how 
transmission providers are expected to translate factors, including 
local laws and regulations, into Long-Term Scenarios.\1131\ We note 
that the requirement, discussed further below, that Long-Term Scenarios 
be plausible and diverse also clarifies how transmission providers must 
account for factors in the Long-Term Scenarios. That is, while 
transmission providers can model assumptions that exceed the minimum 
requirements of factors in the first three categories in developing 
Long-Term Scenarios, they can only exceed those minimum requirements 
such that each Long-Term Scenario remains plausible.\1132\ Similarly, 
the requirement that Long-Term Scenarios be diverse ensures that 
transmission providers will model the effect of factors on Long Term 
Transmission Needs in different ways, and thus that Long-Term Scenarios 
help to manage uncertainty over how factors will affect Long-Term 
Transmission Needs.
---------------------------------------------------------------------------

    \1131\ PPL Initial Comments at 8.
    \1132\ Likewise, as discussed in the Treatment of Factors in the 
Last Four Categories section, transmission providers may only 
discount the effect of factors in the last four categories on Long-
Term Transmission Needs such that each Long-Term Scenario remains 
plausible.
---------------------------------------------------------------------------

    514. We disagree with ISO-NE's claim that requiring that each Long-
Term Scenario account for and consistently reflect the first three 
categories of factors would unnecessarily prevent testing of variations 
with these categories of factors. Where a factor's effect is not clear 
on its face, transmission providers have discretion, within reason, to 
determine the likely effect of full achievement of the factor and 
reflect that into development of the Long-Term Scenarios. Transmission 
providers also are not limited to assuming only the minimum 
requirements of a factor are fully achieved in developing the Long-Term 
Scenarios.
    515. We also are unpersuaded by commenter claims that local laws 
and regulations might conflict with state laws and regulations and, 
therefore, we should not include local laws and regulations in the 
first two categories of factors.\1133\ However, we acknowledge that 
there may be limited circumstances when two legally binding factors 
have conflicting or opposite implications for Long-Term Transmission 
Needs. We clarify that, in such circumstances, transmission providers 
shall reconcile this information while giving full effect to the 
maximum extent possible to all legally binding factors. For example, 
where two laws have equal and opposite effect, transmission providers 
may need to incorporate them as negating each other, as necessary to 
comply with the requirement to produce plausible Long-Term Scenarios. 
In circumstances when that is not possible because the legally binding 
factors support alternatives to the same assumption used to develop 
Long-Term Scenarios, transmission providers could use two or more of 
the three required Long-Term Scenarios, or develop additional Long-Term 
Scenarios, to capture the differences implied by each of the 
conflicting factors.
---------------------------------------------------------------------------

    \1133\ Alabama Commission Initial Comments at 5-6; PJM Initial 
Comments at 68.
---------------------------------------------------------------------------

(b) Treatment of Factors in the Last Four Categories
    516. We affirm that transmission providers have additional 
discretion in how they account for each factor in the last four 
categories of factors compared to how they account for each factor in 
the first three categories.\1134\ After transmission providers have 
determined that a specific factor, stakeholder-identified or otherwise, 
is likely to affect Long-Term Transmission Needs over the transmission 
planning horizon, transmission providers must then assess the extent to 
which the anticipated effects on Long-Term Transmission Needs due to 
that factor are likely to be realized in full, in part, or exceeded, 
for purposes of developing a plausible and diverse set of Long-Term 
Scenarios. For example, for a corporate commitment

[[Page 49367]]

identified in Factor Category Seven, transmission providers can make a 
determination that only a fraction of that corporate commitment will 
actually be met, and the transmission providers can subsequently model 
more limited effects on Long-Term Transmission Needs due to that 
factor, in some or all Long-Term Scenarios. Likewise, transmission 
providers may put more weight on the factor by modeling more than the 
projected change in some or all Long-Term Scenarios to reflect the 
transmission providers' view regarding the likelihood that the 
anticipated effects on Long-Term Transmission Needs due to that factor 
will occur. Transmission providers may choose to discount or put more 
weight on the effects on Long-Term Transmission Needs due to factors in 
Factor Categories Four through Seven to account for uncertainty when 
developing plausible and diverse Long-Term Scenarios.
---------------------------------------------------------------------------

    \1134\ As explained above, the last four categories of factors 
are: (4) trends in fuel costs and in the cost, performance, and 
availability of generation, electric storage resources and building 
and transportation electrification technologies; (5) resource 
retirements; (6) generator interconnection requests and withdrawals; 
(7) utility and corporate commitments and Federal, federally-
recognized Tribal, state, and local policy goals that affect Long-
Term Transmission Needs.
---------------------------------------------------------------------------

    517. Several commenters generally support this flexibility to treat 
the last four categories of factors differently from the first 
three.\1135\ We believe that requiring transmission providers to 
incorporate the last four categories of factors, but allowing 
transmission providers to discount the effects of factors within these 
categories, strikes an appropriate balance between requiring factors in 
these categories be given full weight, and allowing them to be excluded 
entirely in developing Long-Term Scenarios. We believe that these 
categories of factors affect Long-Term Transmission Needs, and absent a 
requirement to incorporate them, transmission providers may fail to 
identify, evaluate, and select more efficient or cost-effective Long-
Term Regional Transmission Facilities to address those Long-Term 
Transmission Needs. On the other hand, these categories of factors are 
less certain than the first three categories and should not necessarily 
be given the same weight in developing Long-Term Scenarios as factors 
that are legally binding.
---------------------------------------------------------------------------

    \1135\ APPA Initial Comments at 27-28; Exelon Initial Comments 
at 10-11 (citing NOPR, 179 FERC ] 61,028 at P 121); NRECA Initial 
Comments at 29-32; TAPS Initial Comments at 2-3, 8.
---------------------------------------------------------------------------

    518. We disagree with the concern that this flexibility could allow 
transmission providers to ignore the last four factor categories \1136\ 
because the final order requires transmission providers to incorporate 
all categories of factors in each Long-Term Scenario, even if they 
discount specific factors within the category, and requires that all 
Long-Term Scenarios be plausible.\1137\ We reiterate that transmission 
providers may only discount the effects of factors in these categories 
on Long-Term Transmission Needs such that each Long-Term Scenario 
remains plausible.
---------------------------------------------------------------------------

    \1136\ E.g., ACEG Initial Comments at 27-28; Amazon Initial 
Comments at 4; Clean Energy Associations Initial Comments at 10-11; 
Pine Gate Initial Comments at 23-25; PIOs Initial Comments at 18-19; 
SEIA Initial Comments at 8-10.
    \1137\ ACEG Initial Comments at 28; DC and MD Offices of 
People's Counsel Initial Comments at 11.
---------------------------------------------------------------------------

d. Stakeholder Process and Transparency
i. NOPR Proposal
    519. The Commission proposed to require that transmission providers 
identify and publish on an Open Access Same-Time Information System 
(OASIS) or other public website a list of the factors that fall into 
each of the required categories of factors that they will incorporate 
in their development of Long-Term Scenarios. The Commission explained 
that transmission providers would be responsible for identifying all 
the factors they know of and are considering incorporating in the 
development of Long-Term Scenarios as part of Long-Term Regional 
Transmission Planning. The Commission also proposed to require 
transmission providers to revise the regional transmission planning 
processes in their OATTs to outline an open and transparent process 
that provides stakeholders, including states, with a meaningful 
opportunity to propose potential factors that transmission providers 
must incorporate in their development of Long-Term Scenarios, such as 
specific laws, regulations, goals, and commitments, and to provide 
input on how to appropriately discount factors that are less 
certain.\1138\
---------------------------------------------------------------------------

    \1138\ NOPR, 179 FERC ] 61,028 at P 109.
---------------------------------------------------------------------------

    520. The Commission noted that, under Order No. 1000, transmission 
providers must already have procedures in their OATTs that give 
stakeholders a meaningful opportunity to submit proposed transmission 
needs driven by Public Policy Requirements and that allow transmission 
providers to identify, out of the larger set of potential transmission 
needs driven by Public Policy Requirements that stakeholders propose, 
those needs for which transmission facilities will be evaluated.\1139\ 
Therefore, the Commission explained that transmission providers may be 
able to modify and expand these existing procedures for identifying 
transmission needs driven by Public Policy Requirements to meet these 
proposed requirements regarding the identification of factors for 
incorporation into Long-Term Scenarios.\1140\
---------------------------------------------------------------------------

    \1139\ Id. P 110 (citing Order No. 1000, 136 FERC ] 61,051 at PP 
206-207; Order No. 1000-A, 139 FERC ] 61,132 at P 335).
    \1140\ Id.
---------------------------------------------------------------------------

ii. Comments
(a) State Input
    521. Several commenters emphasize the important role of 
stakeholders, including states, in identifying or commenting on the 
factors to be included in the development of Long-Term Scenarios.\1141\ 
In addition, Southeast PIOs note that states do not currently engage in 
regional transmission planning processes to any meaningful degree, and 
therefore, the Commission should encourage their participation in 
shaping and conducting Long-Term Regional Transmission Planning.\1142\
---------------------------------------------------------------------------

    \1141\ APPA Initial Comments at 27-29; PIOs Initial Comments at 
22; PJM Initial Comments at 70; Southeast PIOs Initial Comments at 
45, 46-47.
    \1142\ Southeast PIOs Initial Comments at 45-46; State Officials 
Supplemental Comments at 1.
---------------------------------------------------------------------------

    522. Some commenters discuss the important role of states in 
identifying factors within specific category of factors.\1143\ DC and 
MD Offices of People's Counsel assert that the final order should 
explicitly require information on the factors to be provided by 
appropriate authorities, such as state agencies.\1144\ New Jersey 
Commission supports the Commission's proposal to require that states 
have a meaningful opportunity to propose potential factors to be 
incorporated into the development of Long-Term Scenarios and to provide 
input on appropriately discounting less certain factors.\1145\ NESCOE 
asserts that, if states do not play a central role in determining the 
factors, the proposed reforms will likely run into the problem that 
underlies the Order No. 1000 public policy transmission planning 
process in New England, where states do not have a decision-making role 
over project selection even though state laws or policies could be the 
driver for the project.\1146\
---------------------------------------------------------------------------

    \1143\ DC and MD Offices of People's Counsel Initial Comments at 
12; New Jersey Commission Initial Comments at 14-15.
    \1144\ DC and MD Offices of People's Counsel Initial Comments at 
12.
    \1145\ New Jersey Commission Initial Comments at 14-15.
    \1146\ NESCOE Initial Comments at 28-29.
---------------------------------------------------------------------------

    523. However, other commenters state that their existing processes 
are adequate for determining the relevant factors to include in Long-
Term

[[Page 49368]]

Regional Transmission Planning.\1147\ PJM states that it currently has 
processes and standing committees that allow states and stakeholders to 
participate in discussions of factors to use in its transmission 
planning processes. For example, PJM asserts that its Independent State 
Agencies Committee is set up to receive feedback on transmission 
planning from states, and it discusses, among other things, assumptions 
used in the models, relevant regulatory initiatives and their impact, 
and alternative sensitivities, as well as what was discussed at other 
committee meetings. In addition, PJM states, it vets all proposed 
transmission solutions with its Transmission Expansion Advisory 
Committee before submitting them to the PJM board for approval.\1148\
---------------------------------------------------------------------------

    \1147\ MISO Initial Comments at 34-35; MISO TOs Initial Comments 
at 18; OMS Initial Comments at 6; PJM Initial Comments at 6, 64, 70-
71.
    \1148\ PJM Initial Comments at 70-71.
---------------------------------------------------------------------------

(b) Transparency, Enforcement, and Accuracy
    524. Cross Sector Representatives state that Long-Term Regional 
Transmission Planning processes should provide transparency for 
impacted stakeholders.\1149\ SEIA argues that the Commission should 
adopt clear, uniform language that sets forth the specific goals and 
deliverables from the proposed Long-Term Regional Transmission Planning 
process for transmission providers to include in their tariffs, 
including language that mirrors the proposed list of categories of 
factors the Commission included in the NOPR.\1150\
---------------------------------------------------------------------------

    \1149\ Cross Sector Representatives Supplemental Comments at 1.
    \1150\ SEIA Reply Comments at 3-4 (citing PJM Initial Comments 
at 27-28).
---------------------------------------------------------------------------

    525. Several commenters support the NOPR proposal to require 
transmission providers to post the list of factors that they will 
incorporate into their Long-Term Scenarios on a public website for 
stakeholder comment.\1151\ Pine Gate recommends that the Commission 
further require that transmission providers identify and publish all 
factors that were considered but not incorporated.\1152\
---------------------------------------------------------------------------

    \1151\ Ameren Initial Comments at 11-12; APPA Initial Comments 
at 28; NESCOE Initial Comments at 28; Pine Gate Initial Comments at 
25; PIOs Initial Comments at 22.
    \1152\ Pine Gate Initial Comments at 25.
---------------------------------------------------------------------------

    526. Clean Energy Buyers state that, to ensure transparency and 
just and reasonable rates, the Commission should require that 
transmission providers post the details regarding any proposed or 
adopted discounting of factors on OASIS, including: (1) which factors 
are to be discounted; (2) the extent of the discounting; and (3) the 
justification for and derivation of the amount of discounting deemed 
appropriate.\1153\
---------------------------------------------------------------------------

    \1153\ Clean Energy Buyers Initial Comments at 16-17.
---------------------------------------------------------------------------

    527. GridLab and R Street propose modifications to the NOPR 
proposal regarding the role of stakeholders.\1154\ GridLab proposes 
that state agencies, other stakeholders, and independent experts could 
play a dominant role in enforcing the Commission's requirement to 
incorporate specific categories of factors, and that the Commission 
would provide a common framework establishing guidelines on the kinds 
of factors that transmission providers should consider, at a minimum, 
in developing Long-Term Scenarios.\1155\ In addition, R Street argues 
that governance mechanisms should drive the selection of data sets, 
methods, and assumptions behind these factors to promote objective 
accuracy.\1156\
---------------------------------------------------------------------------

    \1154\ GridLab Initial Comments at 20-21; R Street Initial 
Comments at 7.
    \1155\ GridLab Initial Comments at 21.
    \1156\ R Street Initial Comments at 7.
---------------------------------------------------------------------------

iii. Commission Determination
    528. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to revise 
the regional transmission planning processes in their OATTs to outline 
an open and transparent process that provides stakeholders, including 
federally-recognized Tribes and states, with a meaningful opportunity 
to propose potential factors and to provide timely input on how to 
account for specific factors in the development of Long-Term 
Scenarios.\1157\ As discussed below, we also adopt the NOPR proposal, 
with modification, to require transmission providers to publish on the 
public portion of an OASIS or other public website: (1) the list of the 
factors in each of the seven required categories of factors that they 
will account for in their Long-Term Scenarios; (2) a description of 
each factor that they will account for in their Long-Term Scenarios; 
(3) a general statement explaining how they will account for each of 
those factors in their Long-Term Scenarios; (4) a description of the 
extent to which they will discount any factors in Factor Categories 
Four through Seven in each Long-Term Scenario; and (5) a list of the 
factors that they considered but did not incorporate in their Long-Term 
Scenarios.
---------------------------------------------------------------------------

    \1157\ As an example, transmission providers would provide 
stakeholders with an opportunity to describe how a specific state 
law in the first category of factors will result in the development 
of new resources of a certain type, the retirement of existing 
resources, or changes in demand patterns due to increased 
electrification.
---------------------------------------------------------------------------

    529. We believe that a robust stakeholder process will ensure that 
transmission providers can identify which, and how, specific factors 
might influence Long-Term Transmission Needs over the transmission 
planning horizon. For this reason, consistent with Order No. 890's 
transmission planning principles,\1158\ we require transmission 
providers to give stakeholders a meaningful opportunity to provide 
timely input on how and what information to incorporate in Long-Term 
Scenarios, including how to account for a specific factor in terms of 
how the factor may affect Long-Term Transmission Needs. We clarify that 
this meaningful opportunity for stakeholders to provide timely input 
includes the opportunity to propose factors, provide information and 
identify sources of best available data, propose how a factor may 
affect Long-Term Transmission Needs, and explain how that factor could 
be reflected in the development of Long-Term Scenarios, including the 
extent to which it is appropriate to discount the effects of certain 
factors on Long-Term Transmission Needs. We note that some transmission 
providers have existing processes in place that allow states and 
stakeholders to participate in discussions of factors, which 
transmission providers can propose, with any necessary modifications, 
to comply with this final order.\1159\
---------------------------------------------------------------------------

    \1158\ See, e.g., Order No. 890, 118 FERC ] 61,119 at P 454.
    \1159\ MISO Initial Comments at 34-35; PJM Initial Comments at 
6, 64, 70-71.
---------------------------------------------------------------------------

    530. We believe that affording stakeholders a meaningful 
opportunity to propose potential factors and to provide input on how to 
account for specific factors in the development of Long-Term Scenarios 
will help transmission providers to develop more accurate assumptions 
to serve as the basis for their Long-Term Scenarios. Specifically, with 
stakeholder input, transmission providers will be in a better position 
to determine which specific factors within each category of factors 
they should account for in the development of Long-Term Scenarios, as 
well as how best to incorporate them. Stakeholder input is particularly 
important for factors in the first three categories of factors because 
Federal, state, and local government entities, federally-recognized 
Tribes, and utilities, load-serving entities, and their retail 
regulators that participate in the stakeholder process are distinctly

[[Page 49369]]

positioned to provide transmission providers with vital information on 
how the factors over which they have authority or govern are likely to 
influence Long-Term Transmission Needs over the transmission planning 
horizon. Similarly, utilities, corporations, and governments that 
participate in the stakeholder process are distinctly positioned to 
provide transmission providers with vital information regarding factors 
in Factor Category Seven: utility and corporate commitments and 
Federal, federally-recognized Tribal, state, and local policy goals 
that affect Long-Term Transmission Needs. The required stakeholder 
process ensures that all stakeholders, including states, can provide 
important and useful information concerning factors that they believe 
will affect Long-Term Transmission Needs.
    531. We recognize that different stakeholders may provide 
information about the same factor that is contradictory--an issue 
identified by some commenters.\1160\ Different stakeholders may also 
provide different analyses showing, for example, how a specific factor 
will affect resource additions and retirements. However, as we explain 
earlier, transmission providers have discretion regarding how to 
account for specific factors in their development of Long-Term 
Scenarios. In reviewing the information provided by stakeholders in the 
open and transparent stakeholder process, transmission providers may 
weigh more heavily one source of information over another. To maintain 
transparency for stakeholders, transmission providers must include a 
general statement explaining how they will account for each factor in 
their Long-Term Scenarios on the public portion of an OASIS or other 
public website, as further described below.
---------------------------------------------------------------------------

    \1160\ E.g., Undersigned States Initial Comments at 3 (citing 
NOPR, 179 FERC ] 61,028 at P 106).
---------------------------------------------------------------------------

    532. We also believe that the information provided in the open and 
transparent stakeholder process will reduce the burden placed on 
transmission providers to identify and assess the impact of relevant 
factors for each category. For example, transmission providers can rely 
on the open and transparent stakeholder process to identify the 
multiple relevant local laws and regulations that are likely to 
influence Long-Term Transmission Needs over the transmission planning 
horizon. The same is true for the utility and corporate commitments and 
Federal, federally-recognized Tribal, state, and local policy goals 
that affect Long-Term Transmission Needs in Factor Category Seven. 
During the stakeholder process, government entities, utilities, and 
corporate entities can identify their publicly announced goals and 
provide feedback on how the transmission providers can account for 
these publicly announced goals in Long-Term Scenarios. These entities 
will have an opportunity to provide information to help the 
transmission providers determine the likelihood that they will achieve 
their stated goals, which the transmission providers can then use to 
discount the specific factors in Factor Category Seven, if necessary.
    533. With regard to the information about factors and categories of 
factors that transmission providers must publish on the public portion 
of an OASIS or other public website, we modify the proposal in the 
NOPR. We require transmission providers to publish on the public 
portion of an OASIS or other public website: (1) the list of the 
factors in each of the seven required categories of factors that they 
will account for in their Long-Term Scenarios; (2) a description of 
each factor that they will account for in their Long-Term Scenarios; 
(3) a general statement explaining how they will account for each of 
these factors in their Long-Term Scenarios; (4) a description of the 
extent to which they will discount any factors in Factor Categories 
Four through Seven in each Long-Term Scenario; and (5) a list of the 
factors that they considered but did not incorporate in their Long-Term 
Scenarios.\1161\ Transmission providers must post this information 
after stakeholders, including states, have had the meaningful 
opportunity to propose potential factors and to provide input on how to 
account for specific factors in the development of Long-Term Scenarios.
---------------------------------------------------------------------------

    \1161\ As discussed above, transmission providers may not 
discount factors in Factor Categories One through Three.
---------------------------------------------------------------------------

    534. We believe that this transparency is necessary to make clear 
to stakeholders which specific factors transmission providers 
incorporate into Long-Term Scenarios and how they incorporate those 
factors. We believe the posting requirement will also provide greater 
transparency into how transmission providers develop Long-Term 
Scenarios (discussed below), as some commenters requested, while still 
providing transmission providers with flexibility regarding whether, 
and if so, how they choose to incorporate relevant factors.
    535. In response to commenters requesting additional 
transparency,\1162\ we require transmission providers to publish on the 
public portion of an OASIS or other public website the factors that 
were considered but not accounted for in the development of Long-Term 
Scenarios. We believe this requirement will help stakeholders 
understand which factors, either identified in the stakeholder process 
or independently identified by a transmission provider, the 
transmission providers in a transmission planning region have 
determined are unlikely to affect Long-Term Transmission Needs. This 
transparency also ensures that stakeholder-proposed factors are 
reviewed in a fair and non-discriminatory manner.
---------------------------------------------------------------------------

    \1162\ E.g., Pine Gate Initial Comments at 25.
---------------------------------------------------------------------------

    536. We decline to require transmission providers to publicly 
publish the justification for and derivation of the amount of 
discounting deemed appropriate, as requested by Clean Energy 
Buyers.\1163\ We believe such a requirement to detail the rationale for 
the treatment of each factor in Factor Categories Four through Seven, 
across all Long-Term Scenarios, would create a time-consuming 
administrative burden for transmission providers that is not justified 
by the value of the additional information provided to stakeholders.
---------------------------------------------------------------------------

    \1163\ Clean Energy Buyers Initial Comments at 16-17.
---------------------------------------------------------------------------

    537. We decline to adopt modifications to the NOPR proposal that 
would diminish the role of the transmission providers in developing 
Long-Term Scenarios.\1164\ Transmission providers must provide 
stakeholders with a meaningful opportunity to propose potential factors 
and to provide input on how to incorporate specific factors in the 
development of Long-Term Scenarios, as described above. However, we 
reiterate that transmission providers are not required to incorporate 
stakeholder-identified factors into their development of Long-Term 
Scenarios merely because stakeholders propose them, if transmission 
providers determine that the factor is unlikely to influence Long-Term 
Transmission Needs over the transmission planning horizon. Consistent 
with Order No. 890, the ultimate responsibility for transmission 
planning remains with the transmission provider.\1165\
---------------------------------------------------------------------------

    \1164\ E.g., GridLab Initial Comments at 20-21; R Street Initial 
Comments at 7.
    \1165\ Order No. 890, 118 FERC ] 61,119 at P 454. There, in 
response to the suggestion by some commenters that we require 
transmission providers to allow customers to collaboratively develop 
transmission plans with transmission providers on a co-equal basis, 
we clarified that transmission planning is the tariff obligation of 
each transmission provider, and the pro forma OATT planning process 
adopted in this final rule is the means to see that it is carried 
out in a coordinated, open, and transparent manner, in order to 
ensure that customers are treated comparably. Therefore, the 
ultimate responsibility for planning remains with transmission 
providers.

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[[Page 49370]]

4. Number and Development of Long-Term Scenarios
a. NOPR Proposal
    538. In the NOPR, the Commission proposed to require transmission 
providers to develop at least four distinct Long-Term Scenarios as part 
of Long-Term Regional Transmission Planning at least once during a 
transmission planning cycle.\1166\ The Commission explained that it 
preliminarily found that using at least four distinct Long-Term 
Scenarios is a reasonable lower bound for the number of Long-Term 
Scenarios that transmission providers must evaluate in Long-Term 
Regional Transmission Planning. The Commission explained that this 
minimum number of Long-Term Scenarios would help to ensure that 
transmission providers conduct Long-Term Regional Transmission Planning 
that identifies more efficient or cost-effective regional transmission 
facilities to meet transmission needs driven by changes in the resource 
mix and demand. The Commission explained that to satisfy this 
requirement, transmission providers could develop a base case and three 
alternatives, or a low-, medium-, and high-level assumption for the 
factors that transmission providers (and their stakeholders) believe to 
be important to conduct Long-Term Regional Transmission Planning to 
more efficiently or cost-effectively meet transmission needs driven by 
changes in the resource mix and demand, along with a scenario that 
accounts for a high-impact, low-frequency event (as discussed 
below).\1167\
---------------------------------------------------------------------------

    \1166\ NOPR, 179 FERC ] 61,028 at PP 121-126.
    \1167\ Id. P 122.
---------------------------------------------------------------------------

    539. Consistent with the Order No. 890 transparency transmission 
planning principle,\1168\ the Commission proposed to require 
transmission providers in each transmission planning region to publicly 
disclose (subject to any applicable confidentiality protections) 
information and data inputs they use to create each Long-Term Scenario. 
The Commission explained that this transparency requirement will allow 
stakeholders to understand how each scenario differs.
---------------------------------------------------------------------------

    \1168\ The transparency transmission planning principle requires 
transmission providers to reduce to writing and make available the 
basic methodology, criteria, and processes used to develop 
transmission plans. Transmission providers must make sufficient 
information available to enable customers and other stakeholders to 
replicate the results of transmission planning studies. Order No. 
890, 118 FERC ] 61,119 at P 471. Order No. 1000 applied this and 
other Order No. 890 transmission planning principles to regional 
transmission planning processes. Order No. 1000, 136 FERC ] 61,051 
at P 151.
---------------------------------------------------------------------------

    540. Similarly, consistent with the coordination transmission 
planning principle established in Order No. 890,\1169\ the Commission 
proposed to require that transmission providers in each transmission 
planning region give stakeholders the opportunity to provide timely and 
meaningful input into the identification of which Long-Term Scenarios 
are developed. The Commission proposed to require transmission 
providers to revise the regional transmission planning processes in 
their OATTs to outline an open and transparent process that provides 
stakeholders, including states, with a meaningful opportunity to 
propose which future outcomes are probable and can be captured through 
assumptions made in the development of Long-Term Scenarios. 
Furthermore, the Commission proposed to require transmission providers 
to explain on compliance how their process will identify a plausible 
and diverse set of Long-Term Scenarios.\1170\
---------------------------------------------------------------------------

    \1169\ The coordination transmission planning principle requires 
transmission providers to provide customers and other stakeholders 
with the opportunity to participate fully in the transmission 
planning process. The transmission planning process must provide for 
the timely and meaningful input and participation of customers and 
other stakeholders regarding the development of transmission plans, 
allowing customers and other stakeholders to participate in the 
early stages of development. Order No. 890, 118 FERC ] 61,119 at PP 
451-454.
    \1170\ NOPR, 179 FERC ] 61,028 at P 123.
---------------------------------------------------------------------------

b. Comments
    541. Many commenters support requiring transmission providers in 
each transmission planning region to develop at least four distinct 
Long-Term Scenarios as part of Long-Term Regional Transmission 
Planning.\1171\ GridLab and R Street state that this proposed 
requirement appropriately balances the need to address uncertainty and 
risk factors associated with long-term transmission planning while 
limiting the complexity of the transmission planning process.\1172\ PJM 
says that employing multiple scenarios will ensure that transmission 
providers' plans reflect changing needs while avoiding the risk of 
over-building.\1173\ SEIA states that requiring four distinct Long-Term 
Scenarios will allow transmission providers to reflect the uncertainty 
inherent in long-term planning.\1174\ AEE states that the Commission 
should establish a minimum number of scenarios as a baseline for 
compliance with any final order.\1175\ New York TOs support requiring 
the use of multiple scenarios for Long-Term Regional Transmission 
Planning, noting that NYISO already incorporates multiple scenarios 
into its transmission planning processes.\1176\ Nevada Commission notes 
that information from four scenarios could provide inputs into Nevada's 
integrated regional planning process and identify both local and 
regional needs.\1177\
---------------------------------------------------------------------------

    \1171\ ACORE Initial Comments at 10; Advanced Energy Buyers 
Initial Comments at 8; AEE Initial Comments at 8, 18; APPA Initial 
Comments at 29; Arizona Commission Initial Comments at 6; Concerned 
Scientists Reply Comments at 18-19; ELCON Initial Comments at 12; 
ENGIE Initial Comments at 4; Evergreen Action Initial Comments at 3; 
Georgia Commission Initial Comments at 4-5; GridLab Initial Comments 
at 12; ITC Initial Comments at 12; Nevada Commission Initial 
Comments at 8-9; New England for Offshore Wind Initial Comments at 
2; NextEra Initial Comments at 65; Northwest and Intermountain 
Initial Comments at 12; NYISO Initial Comments at 25; [Oslash]rsted 
Initial Comments at 7; Southeast PIOs Initial Comments at 46; SPP 
Market Monitor Initial Comments at 6-7; US Chamber of Commerce 
Initial Comments at 7; US DOE Initial Comments at 14; Vermont 
Electric and Vermont Transco Initial Comments at 2.
    \1172\ GridLab Initial Comments at 12; R Street Initial Comments 
at 6.
    \1173\ PJM Initial Comments at 74.
    \1174\ SEIA Initial Comments at 11.
    \1175\ AEE Reply Comments at 18.
    \1176\ New York TOs Initial Comments at 2.
    \1177\ Nevada Commission Initial Comments at 8-9.
---------------------------------------------------------------------------

    542. Policy Integrity argues that the Commission should require 
more than four Long-Term Scenarios.\1178\ Policy Integrity identifies 
planning efforts that have used more than four scenarios to illustrate 
that best practice counsels against reducing the number of required 
Long-Term Scenarios.\1179\ Northwest and Intermountain state that, 
depending upon the size and characteristics of the transmission 
planning region, additional scenarios may be necessary to identify the 
transmission facilities that are most likely to ensure just and

[[Page 49371]]

reasonable rates.\1180\ LADWP states that while developing more than 
four scenarios will likely be prudent in some instances such as special 
studies, four scenarios should be adequate for most Long-Term Regional 
Transmission Planning given the 20-year planning horizon and 
uncertainties.\1181\
---------------------------------------------------------------------------

    \1178\ Policy Integrity Initial Comments at 14-16.
    \1179\ Id. at 15 (citing US DOE et al., Presentation on National 
Transmission Planning Study at the Modeling Subcommittee Meeting, at 
slide 21 (June 7, 2022), https://perma.cc/MEJ5-9JE6 (study will use 
approximately 100 scenarios); ERCOT, Report On Existing and 
Potential Electric System Constrains and Needs 10 (Dec. 2020), 
https://perma.cc/JGS4-9VH7 (ERCOT has previously used five 
scenarios); Mohamed Labib Awad et al., Using Market Simulations for 
Economic Assessment of Transmission Upgrades: Application of the 
California ISO Approach, in Restructured Electric Power Systems: 
Analysis Of Electricity Markets With Equilibrium Models 241, 255 
(Xiao-Ping Zhang ed. 2010) (economists evaluating CAISO have used 
seventeen scenarios)).
    \1180\ Northwest and Intermountain Initial Comments at 12.
    \1181\ LADWP Initial Comments at 4.
---------------------------------------------------------------------------

    543. Some commenters stress the importance of considering multiple 
Long-Term Scenarios and the uncertainty associated with future 
conditions.\1182\ ACORE suggests that uncertainties in data can be 
addressed with multiple Long-Term Scenarios that are continuously 
revised instead of granting flexibility or encouraging discounting of 
certain factors.\1183\ ENGIE states that a single base-case scenario is 
not effective at capturing trends in the resource mix and demand.\1184\ 
New York Commission and NYSERDA state that Long-Term Scenarios should 
reflect a range of plausible long-term futures that are relevant to the 
state (or transmission planning region) and should account for the 
uncertainty associated with looking out over longer time 
horizons.\1185\ On the other hand, R Street posits that whether 
scenario planning sufficiently captures information on the resource mix 
and demand depends more on the quality of inputs and scenario 
construction elements than the total number of scenarios.\1186\
---------------------------------------------------------------------------

    \1182\ ACORE Initial Comments at 10; ENGIE Initial Comments at 
3-4; New York Commission and NYSERDA Initial Comments at 8; R Street 
Initial Comments at 6.
    \1183\ ACORE Initial Comments at 10.
    \1184\ ENGIE Initial Comments at 4.
    \1185\ New York Commission and NYSERDA Initial Comments at 8.
    \1186\ R Street Initial Comments at 6.
---------------------------------------------------------------------------

    544. Some commenters generally support requiring Long-Term 
Scenarios \1187\ including scenarios examining the effects of high 
energy demand,\1188\ and penetration of renewable resources.\1189\
---------------------------------------------------------------------------

    \1187\ Breakthrough Energy Supplemental Comments at 1; Clean 
Energy Associations Initial Comments at 11-12; Cross Sector 
Representatives Supplemental Comments at 1; PJM Initial Comments at 
6, 71-72; RMI Supplemental Comments at 2; US Climate Alliance 
Initial Comments at 2; Western PIOs Initial Comments at 29.
    \1188\ ACORE Supplemental Comments at 1; Environmental Groups 
Supplemental Comments at 2.
    \1189\ ACORE Supplemental Comments at 1; Environmental Groups 
Supplemental Comments at 2.
---------------------------------------------------------------------------

    545. Other commenters do not oppose this requirement.\1190\
---------------------------------------------------------------------------

    \1190\ Clean Energy Buyers Initial Comments at 17; Dominion 
Initial Comments at 25; Pine Gate Initial Comments at 26; Utah 
Division of Public Utilities Initial Comments at 5.
---------------------------------------------------------------------------

    546. Some commenters support requiring transmission providers to 
establish Long-Term Scenarios, but would modify the NOPR proposal to 
require a lower minimum number. AEP, Entergy, NRECA, Pine Gate, and 
Western PIOs support requiring at least three Long-Term 
Scenarios.\1191\ CAISO argues that the Commission should not require 
transmission providers to develop a minimum of four Long-Term Scenarios 
because there is no evidence, rationale, or justification for why four 
is the appropriate number of scenarios to develop.\1192\ Instead, CAISO 
asserts that the Commission should grant transmission planners the 
flexibility to determine the minimum number of Long-Term Scenarios that 
are appropriate given the specific circumstances in their region and 
planning cycle. However, CAISO states that if Commission were to adopt 
a minimum number of Long-Term Scenarios, three Long-Term Scenarios is 
appropriate because it allows for a base case scenario and two 
sensitivity scenarios.\1193\ Entergy and NRECA claim that three Long-
Term Scenarios would better balance the burden with the benefit of 
developing an additional scenario.\1194\ Pine Gate recommends that, 
instead of requiring a fourth scenario, the Commission should permit 
transmission providers in each transmission planning region to develop 
and use no less than three Long-Term Scenarios, and then to conduct 
either a fourth scenario or a sensitivity analysis on the most likely 
Long-Term Scenario to ``account for uncertain operational outcomes that 
determine the benefits of or need for transmission facilities during 
high-impact, low frequency events'' as proposed in the NOPR.\1195\
---------------------------------------------------------------------------

    \1191\ AEP Initial Comments at 5, 8, 12; Entergy Initial 
Comments at 13; NRECA Initial Comments 35; Pine Gate Initial 
Comments at 26-27; Western PIOs Initial Comments at 33.
    \1192\ CAISO Initial Comments at 23-24.
    \1193\ Id. at 25-26.
    \1194\ Entergy Initial Comments at 13; NRECA Initial Comments 
35.
    \1195\ Pine Gate Initial Comments at 26 (citing NOPR, 179 FERC ] 
61,028 at P 124).
---------------------------------------------------------------------------

    547. National Grid argues that there is an inherent trade-off 
between the number of Long-Term Scenarios, the quality of the data 
underpinning the assessment, and the frequency of reassessments. 
National Grid concludes that a transmission provider should not be 
required to plan for a scenario that is impossible or not supported by 
its stakeholders solely to meet the requirement that four distinct 
Long-Term Scenarios be developed and studied.\1196\ Xcel supports the 
use of scenarios but states that the proposed requirement to use at 
least four Long-Term Scenarios is too prescriptive.\1197\ Relatedly, 
LADWP states that developing more than four Long-Term Scenarios may be 
prudent in some instances but that it would be inefficient and a waste 
of resources to require all transmission providers in each transmission 
planning region to do so.\1198\
---------------------------------------------------------------------------

    \1196\ National Grid Initial Comments at 14-15.
    \1197\ Xcel Initial Comments at 10.
    \1198\ LADWP Initial Comments at 4.
---------------------------------------------------------------------------

    548. Some commenters broadly oppose the NOPR proposal to require 
transmission providers in each transmission planning region to develop 
at least a minimum number or specific number of Long-Term 
Scenarios.\1199\ California Commission argues that the NOPR's approach 
would interfere with regional transmission planning processes, such as 
CAISO's, that are closely coordinated with state resource planning and 
load forecasting and already effectively identify transmission 
necessary to accommodate changes in the resource mix and demand.\1200\ 
Duke argues that requiring a minimum number of Long-Term Scenarios, 
while also requiring one capture high-impact, low-frequency events, 
places greater importance on developing scenarios purely to satisfy the 
requirement than on gaining consensus about what scenarios are in fact 
plausible or most likely.\1201\ MISO states that a prescriptive number 
of Long-Term Scenarios with specific factors included may introduce a 
level of granularity and complexity into Long-Term Regional 
Transmission Planning that impedes progress.\1202\
---------------------------------------------------------------------------

    \1199\ California Commission Initial Comments at 21-24; Duke 
Initial Comments at 15; Indicated PJM TOs Initial Comments at 9-10; 
ISO-NE Initial Comments at 28; ISO/RTO Council Initial Comments at 
9; MISO Initial Comments at 20; NESCOE Initial Comments at 30; OMS 
Initial Comments at 5; PG&E Initial Comments at 6-7; SPP Initial 
Comments at 9-10; State Agencies Initial Comments at 14.
    \1200\ California Commission Initial Comments at 23.
    \1201\ Duke Initial Comments at 15.
    \1202\ MISO Initial Comments at 20.
---------------------------------------------------------------------------

    549. Some commenters request that the Commission provide 
transmission providers in each transmission planning region with the 
flexibility to determine how many Long-Term Scenarios to develop.\1203\ 
US DOE supports a

[[Page 49372]]

requirement to identify four scenarios as a reasonable lower bound, and 
supports the analysis of additional scenarios, including sensitivities, 
but asserts that the development of Long-Term Scenarios should not be 
prescriptive but, rather, the Commission should provide guidelines and 
give transmission planning regions flexibility to work within those 
guidelines to capture reasonable sets of scenarios.\1204\
---------------------------------------------------------------------------

    \1203\ Ameren Initial Comments at 13-14; Avangrid Initial 
Comments at 9-10; CAISO Initial Comments at 25; California Energy 
Commission Initial Comments at 2; Clean Energy Associations Initial 
Comments at 11-12; Dominion Initial Comments at 25; Entergy Initial 
Comments at 13; MISO Initial Comments at 16, 20; MISO TOs Initial 
Comments at 16-17; National Grid Initial Comments at 14; Nebraska 
Commission Initial Comments at 5; PG&E Initial Comments at 7; PJM 
Initial Comments at 72; SPP Initial Comments at 9; US DOE Initial 
Comments at 14; Xcel Initial Comments at 10.
    \1204\ US DOE Initial Comments at 14.
---------------------------------------------------------------------------

    550. Some commenters propose that, if the Commission does not 
require a minimum number of Long-Term Scenarios, the Commission should 
instead require that transmission providers in each transmission 
planning region demonstrate, on compliance, why their proposed number 
of Long-Term Scenarios is appropriate.\1205\ Duke asserts that the 
Commission should direct transmission providers to offer on compliance 
a process for Long-Term Scenario development that will capture enough 
sufficiently plausible scenarios with distinct sets of assumptions to 
adequately capture a consensus view of the most likely future state(s) 
to occur.\1206\
---------------------------------------------------------------------------

    \1205\ CAISO Initial Comments at 25; Duke Initial Comments at 
15; Eversource Initial Comments at 17-18; NESCOE Initial Comments at 
30-31.
    \1206\ Duke Initial Comments at 15.
---------------------------------------------------------------------------

    551. Other commenters call for the Commission to permit discretion 
on how transmission providers determine the number of Long-Term 
Scenarios to use.\1207\ ISO-NE and ISO/RTO Council argue that the 
number of Long-Term Scenarios is an implementation detail that each 
transmission planning region should decide.\1208\ NYISO states that the 
final order should permit each transmission planning region to conduct 
Long-Term Regional Transmission Planning using multiple Long-Term 
Scenarios that account for varying levels of achievement of local laws 
and regulations.\1209\
---------------------------------------------------------------------------

    \1207\ Indicated PJM TOs Initial Comments at 9-10; ISO-NE 
Initial Comments at 28; ISO/RTO Council Initial Comments at 9; MISO 
Initial Comments at 20; NESCOE Initial Comments at 30-31; OMS 
Initial Comments at 5.
    \1208\ ISO-NE Initial Comments at 28; ISO/RTO Council Initial 
Comments at 9.
    \1209\ NYISO Initial Comments at 23.
---------------------------------------------------------------------------

    552. MISO opposes requiring transmission providers to evaluate a 
specific number of Long-Term Scenarios and proposes, instead, that the 
Commission require that future scenarios be developed and implemented 
for purposes of long-term regional transmission planning, leaving each 
transmission planning region to determine what and how many scenarios 
are appropriate. According to MISO, this approach would ensure 
consistency across the transmission planning regions in what is 
required while allowing for any needed variation within each 
region.\1210\ Additionally, MISO notes that it developed the futures 
that it uses in its Long-Range Transmission Plan through extensive 
stakeholder processes and that these futures reflect the specific 
realities of its member utilities. MISO contends that allowing 
transmission providers to develop the number of Long-Term Scenarios 
they need, and at intervals appropriate for them, encourages 
stakeholder buy-in and more efficient allocation of planning 
resources.\1211\
---------------------------------------------------------------------------

    \1210\ MISO Initial Comments at 16, 20.
    \1211\ MISO Reply Comments at 9-10.
---------------------------------------------------------------------------

    553. California Municipal Utilities disagree with comments that 
urge prescriptive uniformity, arguing that uniformity involves high 
costs and lacks consumer protection measures against speculative 
transmission projects.\1212\ For example, California Municipal 
Utilities argue against the proposal from Western PIOs for the 
development of three common scenarios to be synchronized across the 
Western Interconnection because this proposal amounts to central 
resource planning, which is not consistent with the existing process in 
which state and local choices drive the planning process.\1213\
---------------------------------------------------------------------------

    \1212\ California Municipal Utilities Reply Comments at 5.
    \1213\ Id. (citing Western PIOs Initial Comments at 32-33).
---------------------------------------------------------------------------

    554. Louisiana Commission states that the Commission's proposal is 
overly prescriptive and that the Commission should provide for a more 
flexible approach that allows transmission providers, retail 
regulators, and other stakeholders to develop scenarios with 
appropriate, realistic, and reasonable assumptions. Louisiana 
Commission states that Long-Term Scenarios should be based on 
reasonable ranges of assumptions for load, and generation type and 
location. Louisiana Commission argues that the number of scenarios 
required is far less important than the quality of the data and 
assumptions used to develop them.\1214\ MISO TOs agree that the NOPR 
proposal is overly prescriptive, stating that the Commission should not 
create unnecessary obstacles, but rather create a rule broad enough to 
incorporate existing processes.\1215\
---------------------------------------------------------------------------

    \1214\ Louisiana Commission Reply Comments at 6-7.
    \1215\ MISO TOs Reply Comments at 13.
---------------------------------------------------------------------------

    555. Some commenters emphasize the need for an open and transparent 
process that provides stakeholders, including states, with a meaningful 
opportunity to provide timely and meaningful input into which Long-Term 
Scenarios are developed.\1216\ For example, California Commission, 
NRECA, Concerned Scientists, and US Climate Alliance support the NOPR 
proposal to require transmission providers to disclose--subject to any 
applicable confidentiality protections--information and data inputs 
that they use to create each Long-Term Scenario.\1217\ ELCON states 
that the Commission should require each transmission provider to post 
all methodologies and inputs used in determining Long-Term Scenarios 
and factors to its OASIS.\1218\ NRG claims that the NOPR proposes a 
central determination of particular actions based on collectively 
determined assumptions, which gives up a major advantage of 
competition--the requirement that market participants take an 
individual view based on available information of the future viability 
of any investment they might make.\1219\
---------------------------------------------------------------------------

    \1216\ California Commission Initial Comments at 25; Clean 
Energy Associations Initial Comments at 12; DC and MD Offices of 
People's Counsel Initial Comments at 14; ELCON Initial Comments at 
12; NRECA Initial Comments at 35; Pacific Northwest State Agencies 
at 14-15; US Climate Alliance Initial Comments at 2.
    \1217\ California Commission Initial Comments at 25; NRECA 
Initial Comments at 35; Concerned Scientists Reply Comments at 15-
16; US Climate Alliance Initial Comments at 2.
    \1218\ ELCON Initial Comments at 12.
    \1219\ NRG Initial Comments at 8.
---------------------------------------------------------------------------

    556. NESCOE argues that states must play a central role in Long-
Term Regional Transmission Planning. Specifically, NESCOE agrees with 
ISO-NE, which calls for the Commission to explicitly authorize states 
to have a central decision-making role at all aspects of Long-Term 
Regional Transmission Planning, including ``scenario analysis 
development,'' to ensure necessary additional investment for a 
reliable, clean energy future.\1220\ Similarly, Nebraska Commission 
adds that state regulatory commissions should have a significant role 
in defining Long-Term Scenarios.\1221\
---------------------------------------------------------------------------

    \1220\ NESCOE Reply Comments at 2 (citing ISO-NE Initial 
Comments at 2-4).
    \1221\ Nebraska Commission Initial Comments at 5-6.
---------------------------------------------------------------------------

    557. AEE requests that the Commission clarify the role of states in 
providing input to the development of Long-Term Scenarios.\1222\
---------------------------------------------------------------------------

    \1222\ AEE Initial Comments at 19.
---------------------------------------------------------------------------

    558. GridLab states that the Commission should be prepared to act

[[Page 49373]]

as the arbiter of stakeholder concerns about Long-Term Scenario design, 
similar to the role that state public utility commissions play in the 
integrated resource planning process, and that this may require new 
staff, resources, and the development of new expertise at the 
Commission.\1223\
---------------------------------------------------------------------------

    \1223\ GridLab Initial Comments at 11-12.
---------------------------------------------------------------------------

c. Commission Determination
    559. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to develop 
at least three distinct Long-Term Scenarios as part of Long-Term 
Regional Transmission Planning. In implementing this requirement, 
transmission providers must develop, at least once during the five-year 
Long-Term Regional Transmission Planning cycle, at least three distinct 
Long-Term Scenarios that, at a minimum, incorporate the seven 
categories of factors listed in the Categories of Factors section 
above. We find that requiring transmission providers to develop at 
least three distinct Long-Term Scenarios as part of Long-Term Regional 
Transmission Planning strikes the appropriate balance between 
establishing a sufficient number of Long-Term Scenarios and the 
associated burden of developing and using Long-Term Scenarios in Long-
Term Regional Transmission Planning. We also find that requiring 
transmission providers to develop at least three distinct Long-Term 
Scenarios instead of four, as proposed in the NOPR, is more consistent 
with the manner in which some transmission providers currently employ 
scenarios in their existing regional transmission planning 
process.\1224\ We also reiterate, as stated in the NOPR, that if 
transmission providers produce a base-case Long-Term Scenario in Long-
Term Regional Transmission Planning, that base case should be 
consistent with what the transmission provider determines is the most 
likely scenario to occur.\1225\
---------------------------------------------------------------------------

    \1224\ See, e.g., CAISO Initial Comments at 26 (explaining that 
``CAISO typically has utilized three scenarios in its public policy 
planning process, a base case scenario and two sensitivity 
scenarios''); Entergy Initial Comments at 13-14 (explaining that 
MISO currently uses three scenarios in its transmission planning 
process and arguing that the use of three scenarios enables 
``transmission providers to `bookend' plausible outcomes to plan no-
regrets additions to meet the grid, and then develop a scenario 
between those two to better inform the decision making''); NRECA 
Initial Comments at 35 n.100 (highlighting that MISO uses three 
scenarios in its transmission planning process).
    \1225\ NOPR, 179 FERC ] 61,028 at P 123.
---------------------------------------------------------------------------

    560. In addition, we adopt the NOPR proposal to require, consistent 
with Order No. 890's transparency transmission planning principle, 
transmission providers in each transmission planning region to publicly 
disclose (subject to any applicable confidentiality protections) 
information and data inputs that they use to create each Long-Term 
Scenario.\1226\ We also adopt the NOPR proposal to require transmission 
providers in each transmission planning region, consistent with Order 
No. 890's coordination transmission planning principle, to provide 
stakeholders an opportunity to provide timely and meaningful input into 
how Long-Term Scenarios are developed.\1227\ Consistent with Order No. 
890 and Order No. 1000's coordination transmission planning principle, 
we require transmission providers, with the input of their customers 
and other stakeholders, to craft coordination requirements that work 
for those transmission providers and their customers and other 
stakeholders. Furthermore, we adopt the NOPR proposal to require 
transmission providers to revise the regional transmission planning 
process in their OATTs to outline an open and transparent process that 
provides stakeholders, including states, with a meaningful opportunity 
to propose which future outcomes are probable and can be captured 
through assumptions made in the development of Long-Term Scenarios. We 
conclude that these requirements will help ensure that transmission 
providers will have the necessary information to identify Long-Term 
Transmission Needs and identify, evaluate, and select Long-Term 
Regional Transmission Facilities to address those needs. Furthermore, 
by requiring transmission providers to afford stakeholders a meaningful 
opportunity to propose future outcomes that are probable, we believe 
that this requirement helps to ensure that Long-Term Transmission Needs 
are being addressed in a more efficient or cost-effective manner.\1228\
---------------------------------------------------------------------------

    \1226\ The transparency transmission planning principle requires 
transmission providers to reduce to writing and make available the 
basic methodology, criteria, and processes used to develop 
transmission plans. Transmission providers must make sufficient 
information available to enable customers and other stakeholders to 
replicate the results of transmission planning studies. Order No. 
890, 118 FERC ] 61,119 at P 471. Order No. 1000 applied this and 
other Order No. 890 transmission planning principles to regional 
transmission planning processes. Order No. 1000, 136 FERC ] 61,051 
at P 151.
    \1227\ The coordination transmission planning principle requires 
transmission providers to provide customers and other stakeholders 
with the opportunity to participate fully in the transmission 
planning process. The transmission planning process must provide for 
the timely and meaningful input and participation of customers and 
other stakeholders regarding the development of transmission plans, 
allowing customers and other stakeholders to participate in the 
early stages of development. Order No. 890, 118 FERC ] 61,119 at P 
454.
    \1228\ Order No. 1000, 136 FERC ] 61,051 at P 150.
---------------------------------------------------------------------------

    561. We also note the important role of states in developing Long-
Term Scenarios. As the Commission stated in Order No. 890 and Order No. 
1000, and we reiterate here, our expectation is that ``all transmission 
providers will respect states' concerns'' when engaging in the regional 
transmission planning process.\1229\ We strongly encourage states to 
participate actively in the development of Long-Term Scenarios, as well 
as in all other aspects of Long-Term Regional Transmission Planning. In 
response to NESCOE's and AEE's concerns about the role of state 
regulators in the development of Long-Term Scenarios and their use in 
Long-Term Regional Transmission Planning,\1230\ we find that, 
consistent with Order No. 890,\1231\ transmission planning must be 
coordinated with interested stakeholders, including relevant state 
regulators that wish to participate in the Long-Term Regional 
Transmission Planning process. As reflected throughout this final 
order, we recognize that states have a particularly important role to 
play in the development of Long-Term Regional Transmission Facilities 
and encourage transmission providers to work with states in a way that 
reflects that role in addition to complying with the relevant 
requirements established herein.
---------------------------------------------------------------------------

    \1229\ Id. P 212; Order No. 890, 118 FERC ] 61,119 at P 574.
    \1230\ AEE Initial Comments at 8; NESCOE Reply Comments at 2 
(citing ISO-NE Initial Comments at 2-4).
    \1231\ Order No. 890, 118 FERC ] 61,119 at P 574.
---------------------------------------------------------------------------

    562. In response to commenters that argue that the Commission 
should require four or more Long-Term Scenarios,\1232\ we affirm that 
nothing in this final order precludes or prevents transmission 
providers from proposing

[[Page 49374]]

to use more than three Long-Term Scenarios in Long-Term Regional 
Transmission Planning. To the extent that transmission providers, in 
consultation with stakeholders, conclude that using more than three 
Long-Term Scenarios is appropriate for Long-Term Regional Transmission 
Planning in their transmission planning region, those transmission 
providers may propose to use more than three Long-Term Scenarios in 
their compliance filings.
---------------------------------------------------------------------------

    \1232\ ACORE Initial Comments at 10; Advanced Energy Buyers 
Initial Comments at 8; AEE Initial Comments at 8; APPA Initial 
Comments at 29; Arizona Commission Initial Comments at 6; Concerned 
Scientists Reply Comments at 18-19; ELCON Initial Comments at 12; 
ENGIE Initial Comments at 4; Evergreen Action Initial Comments at 3; 
Georgia Commission Initial Comments at 4-5; GridLab Initial Comments 
at 12; ITC Initial Comments at 12; Nevada Commission Initial 
Comments at 8-9; New England for Offshore Wind Initial Comments at 
2; NextEra Initial Comments at 65; Northwest and Intermountain 
Initial Comments at 12; NYISO Initial Comments at 25; [Oslash]rsted 
Initial Comments at 7; Southeast PIOs Initial Comments at 46; SPP 
Market Monitor Initial Comments at 7; US Chamber of Commerce Initial 
Comments at 7; US DOE Initial Comments at 14-15; Vermont Electric 
and Vermont Transco Initial Comments at 2.
---------------------------------------------------------------------------

    563. In response to California Commission's comments about the 
interaction between the development of Long-Term Scenarios and existing 
regional transmission planning processes,\1233\ we believe the final 
order, as modified from the NOPR proposal, addresses this concern and 
provides transmission providers with sufficient flexibility to tailor 
the development of Long-Term Scenarios to their transmission planning 
regions' specific needs or existing practices, as discussed elsewhere 
in this final order.\1234\
---------------------------------------------------------------------------

    \1233\ California Commission Initial Comments at 23.
    \1234\ See supra Categories of Factors, Requirement to 
Incorporate Categories of Factors section; Categories of Factors, 
Stakeholder Process and Transparency section.
---------------------------------------------------------------------------

5. Types of Long-Term Scenarios
a. NOPR Proposal
    564. In the NOPR, the Commission proposed to require that each 
Long-Term Scenario incorporate, at a minimum, the categories of factors 
listed in the requirement above. As discussed in the Factors section of 
the NOPR,\1235\ the Commission proposed that each Long-Term Scenario 
must be consistent with Federal, state, and local laws and regulations 
that affect the future resource mix; Federal, state, and local laws and 
regulations on decarbonization and electrification; and state-approved 
integrated resource plans. However, the Commission explained that each 
Long-Term Scenario may vary according to assumptions about the 
remaining categories of factors described in the NOPR, as well as with 
respect to other characteristics of the future electric power system. 
The Commission explained that it neither proposed to require the 
development of a specific Long-Term Scenario or specific set of Long-
Term Scenarios, nor did it propose to require that transmission 
providers identify the relative likelihood of different Long-Term 
Scenarios except where transmission providers develop a base case 
scenario, as described more fully below.\1236\
---------------------------------------------------------------------------

    \1235\ NOPR, 179 FERC ] 61,028 at PP 104-112.
    \1236\ Id. P 121.
---------------------------------------------------------------------------

    565. The Commission proposed to require transmission providers in 
each transmission planning region to develop a plausible and diverse 
set of Long-Term Scenarios.\1237\ The Commission explained that the set 
of at least four Long-Term Scenarios must be: (1) plausible, that is 
they must reasonably capture probable future outcomes, and (2) diverse 
in the sense that transmission providers must be able to distinguish 
distinct transmission facilities or distinct benefits of similar 
transmission facilities in each scenario. The Commission proposed to 
require that if the transmission providers in a transmission planning 
region use a base case scenario, that scenario should be consistent 
with the scenario that the transmission providers determine to be the 
most likely scenario to occur.
---------------------------------------------------------------------------

    \1237\ The Commission noted that different assumptions about the 
factors and data inputs used to develop Long-Term Scenarios and 
other characteristics of the future electric power system determine 
whether the set of Long-Term Scenarios are plausible and diverse.
---------------------------------------------------------------------------

b. Comments
    566. Some commenters support the Commission's proposal to require 
transmission providers in each transmission planning region to develop 
a plausible and diverse set of Long-Term Scenarios.\1238\ For example, 
GridLab agrees that the Commission should require that transmission 
providers demonstrate that their Long-Term Scenarios capture a 
reasonable range of possible futures. GridLab argues that scenarios 
that are too conservative will lead to similar load-resource and 
transmission portfolio scenarios, which limits the value of scenario 
planning in managing uncertainty and risk.\1239\ Illinois Commission 
argues that the NOPR's proposed requirement for diverse and plausible 
scenarios is important, and that Long-Term Scenarios must consider a 
wide array of conditions.\1240\
---------------------------------------------------------------------------

    \1238\ APPA Initial Comments at 29; Clean Energy Buyers Initial 
Comments at 17; DC and MD Offices of People's Counsel Initial 
Comments at 13; GridLab Initial Comments at 11 & n.12; Illinois 
Commission Initial Comments at 7; Mississippi Commission Reply 
Comments at 9; NARUC Initial Comments at 10; NESCOE Initial Comments 
at 32; New York Commission and NYSERDA Initial Comments at 8; SPP 
Market Monitor Initial Comments at 7.
    \1239\ GridLab Initial Comments at 11.
    \1240\ Illinois Commission Initial Comments at 7.
---------------------------------------------------------------------------

    567. Some commenters discuss the need for certain types of Long-
Term Scenarios.\1241\ Certain TDUs and PIOs argue that, although Long-
Term Scenarios should include anticipated levels of generation, they 
should also include ``book end'' scenarios of high- and low-load 
growth.\1242\ Clean Energy Associations argue that, because the 
Inflation Reduction Act provides for significant funding for 
electrification, at least some scenarios should evaluate transmission 
needs under higher-than-anticipated load growth.\1243\
---------------------------------------------------------------------------

    \1241\ ACORE Initial Comments at 10-11; AEE Initial Comments at 
8; APPA Initial Comments at 29; Certain TDUs Initial Comments at 18; 
Clean Energy Associations Initial Comments at 10-11; Evergreen 
Action Initial Comments at 3; Eversource Initial Comments at 18-19; 
Georgia Commission Initial Comments at 4-5; NESCOE Initial Comments 
at 32; NextEra Initial Comments at 65; PIOs Initial Comments at 22-
23; PJM Initial Comments at 73-74; US Climate Alliance Initial 
Comments at 2; US DOE Initial Comments at 15; Utah Division of 
Public Utilities Initial Comments at 5-6; Western PIOs Initial 
Comments at 33.
    \1242\ Certain TDUs Initial Comments at 18; PIOs Initial 
Comments at 22-23.
    \1243\ Clean Energy Associations Initial Comments at 11 (citing 
Inflation Reduction Act, Public Law 117-169 (2022)).
---------------------------------------------------------------------------

    568. PJM describes four scenarios that it might use: (1) a low 
uncertainty scenario with known inputs, such as legislative and 
regulatory laws and announced deactivations and load forecasts; (2) a 
medium uncertainty scenario that includes state and local goals and 
economic retirement analysis; (3) a higher uncertainty scenario that 
adds more speculative and aspirational goals; and (4) a high-impact-
low-frequency resilience evaluation scenario that includes low-
probability, high-impact events. PJM states that the scenarios should 
be: (1) based on a clearly defined, robust set of factor development 
criteria grounded in customer needs; (2) capable of adapting to an 
evolving set of future system conditions; and (3) crafted to produce 
the appropriate level of transmission.\1244\
---------------------------------------------------------------------------

    \1244\ PJM Initial Comments at 73-74.
---------------------------------------------------------------------------

    569. Western PIOs state that one scenario should be based on 
existing policy and assumptions about generation retirements and 
electrification that are likely to occur. Western PIOs state that a 
second scenario would build on that base case scenario by assuming 
Public Policy Requirements and utility and corporate goals are met or 
exceeded, as well as high levels of electrification and generation 
retirements. Western PIOs state that a third scenario should address 
high-impact, low-frequency extreme weather events. Western PIOs state 
that the fourth scenario could be reserved for a scenario unique to 
each of the non-RTO/ISO transmission planning regions.\1245\
---------------------------------------------------------------------------

    \1245\ Western PIOs Initial Comments at 33.
---------------------------------------------------------------------------

    570. ACORE argues that uncertainties in data do not require 
granting

[[Page 49375]]

flexibility or encouraging discounting, but instead can be addressed 
with multiple scenarios that are continuously revised as recommended in 
the NOPR. For example, one Long-Term Scenario can include a discounted 
set of goals, while another can add contingency factors for when demand 
exceeds those goals; and a range of scenarios could be incorporated for 
the extent of electrification of buildings and transportation. ACORE 
states that scenario analysis should incorporate a probabilistic-based 
range of future weather and extreme events which, ACORE asserts, will 
support the analyses of the benefits of mitigation of those extreme 
events and system contingencies and mitigation of weather and load 
uncertainty.\1246\
---------------------------------------------------------------------------

    \1246\ ACORE Initial Comments at 10-11.
---------------------------------------------------------------------------

    571. AEE recommends that the Commission require Long-Term Scenarios 
that consider anticipated distributed energy resource 
deployments.\1247\ Evergreen Action urges the Commission to require 
that at least one Long-Term Scenario contemplate a 100% clean-energy 
grid by 2035, to reflect the Biden Administration's target of 100% 
carbon-free electricity by 2035.\1248\ Similarly, NextEra argues that 
the Commission should require that one of the Long-Term Scenarios be 
based on an economy-wide, net-zero emissions scenario or at least a 
Federal net-zero emissions mandate limited to the power sector.\1249\ 
In contrast, Utah Division of Public Utilities states that one of the 
Long-Term Scenarios should consider little or no state renewable energy 
or decarbonization goals or requirements to assist in determining 
transmission costs for states that have less onerous goals.\1250\
---------------------------------------------------------------------------

    \1247\ AEE Initial Comments at 8.
    \1248\ Evergreen Action Initial Comments at 3.
    \1249\ NextEra Initial Comments at 65.
    \1250\ Utah Division of Public Utilities Initial Comments at 5-
6.
---------------------------------------------------------------------------

    572. APPA requests that one of the Long-Term Scenarios represent a 
base case of business as usual.\1251\ Eversource supports the NOPR 
proposal to use the ``most likely scenario to occur'' as the base case 
for analysis of Long-Term Scenarios.\1252\ Georgia Commission argues 
that a base case scenario should reflect the expected long-term mix of 
generating capacity, with additional scenarios reflecting alternative 
carbon emission constraints, fuel prices, and growth in distributed 
energy resources.\1253\ US Climate Alliance states that business-as-
usual cases should be consistent with state and Federal policy and used 
in addition to alternative scenarios that demonstrate a range of 
factors influencing the changing grid.\1254\
---------------------------------------------------------------------------

    \1251\ APPA Initial Comments at 29.
    \1252\ Eversource Initial Comments at 19.
    \1253\ Georgia Commission Initial Comments at 4-5.
    \1254\ US Climate Alliance Initial Comments at 2.
---------------------------------------------------------------------------

    573. However, PIOs state that the Commission should not use the 
phrase ``business as usual'' as it is misleading in a rapidly changing 
electric industry.\1255\ US DOE argues against identifying the 
likelihood of any one Long-Term Scenario, including a base case 
scenario, because identifying a single such scenario as most likely is 
challenging and discourages the analysis of more scenarios and 
sensitivities, undermining the value of scenario analysis. Instead, US 
DOE argues that transmission facilities that provide high value in 
multiple scenarios should be identified as more likely to provide value 
to the future transmission system, because expansion options that 
provide high value in many future scenarios are flexible, and that 
flexibility to accommodate multiple future scenarios is more important 
than trying to characterize the likelihood of any one scenario.\1256\
---------------------------------------------------------------------------

    \1255\ PIOs Initial Comments at 22.
    \1256\ US DOE Initial Comments at 15.
---------------------------------------------------------------------------

    574. Senator Schumer supports requiring a high variable energy 
resource penetration scenario.\1257\
---------------------------------------------------------------------------

    \1257\ Senator Schumer Supplemental Comments at 2.
---------------------------------------------------------------------------

c. Commission Determination
    575. We adopt the NOPR proposal to require transmission providers 
in each transmission planning region to develop a plausible and diverse 
set of at least three Long-Term Scenarios. Specifically, we find that 
the set of at least three Long-Term Scenarios must be: (1) plausible, 
meaning that each scenario must itself be reasonably probable, and 
collectively that the set of plausible scenarios must reasonably 
capture probable future outcomes, and (2) diverse, in the sense that 
transmission providers can distinguish distinct transmission facilities 
or distinct benefits of similar transmission facilities in each Long-
Term Scenario. We find that requiring Long-Term Scenarios to be both 
plausible and diverse prevents the development of Long-Term Scenarios 
that may otherwise be too conservative, speculative, or similar for 
transmission providers to identify Long-Term Transmission Needs and 
identify, evaluate, and select Long-Term Regional Transmission 
Facilities to more efficiently or cost-effectively address those needs. 
Absent a requirement that Long-Term Scenarios be both plausible and 
diverse, transmission providers could develop Long-Term Scenarios in a 
manner that undercuts one of the primary benefits of using scenario-
based planning practices, which is to help ensure that transmission 
providers can account for the uncertainty about future conditions when 
conducting Long-Term Regional Transmission Planning.
    576. Moreover, we also require that each individual Long-Term 
Scenario be plausible (i.e., individually the scenario must be 
reasonably probable) because, absent such a requirement, we are 
concerned that the set of Long-Term Scenarios may include a Long-Term 
Scenario that rests on assumptions about the factors and data inputs 
that do not reasonably capture possible future outcomes. Additionally, 
we also clarify the term ``diverse'' to mean that the set of Long-Term 
Scenarios must represent a reasonable range of probable future outcomes 
consistent with the requirement for plausibility, based on assumptions 
about the factors and data inputs.
    577. We disagree with commenters that argue that the Commission 
should modify the NOPR proposal and prescribe specific types of Long-
Term Scenarios for transmission providers to use in Long-Term Regional 
Transmission Planning.\1258\ We are not persuaded that we should 
require transmission providers to develop either a specific Long-Term 
Scenario or a specific set of Long-Term Scenarios because we believe 
that transmission providers, with an opportunity for timely and 
meaningful input from stakeholders, are in the best position to 
determine which plausible Long-Term Scenarios are applicable to their 
transmission planning region. Further, we do not find it necessary to 
require transmission providers to develop low-, medium-, and high-level 
assumptions for the factors that transmission providers believe to be 
important except where transmission providers develop a base case 
scenario, as discussed above.\1259\
---------------------------------------------------------------------------

    \1258\ ACORE Initial Comments at 10-11; AEE Initial Comments at 
8; APPA Initial Comments at 29; Certain TDUs Initial Comments at 18, 
22; Clean Energy Associations Initial Comments at 11; Evergreen 
Action Initial Comments at 3; Eversource Initial Comments at 19; 
Georgia Commission Initial Comments at 4-5; NESCOE Initial Comments 
at 32; NextEra Initial Comments at 65; PIOs Initial Comments at 22-
23; PJM Initial Comments at 73-74; US Climate Alliance Initial 
Comments at 2; US DOE Initial Comments at 15; Utah Division of 
Public Utilities Initial Comments at 5-6; Western PIOs Initial 
Comments at 33.
    \1259\ See supra Types of Long-Term Scenarios section.

---------------------------------------------------------------------------

[[Page 49376]]

6. Sensitivities for High-Impact, Low-Frequency Events
a. NOPR Proposal
    578. In the NOPR, the Commission proposed to require that at least 
one of the four distinct Long-Term Scenarios that transmission 
providers in each transmission planning region use in Long-Term 
Regional Transmission Planning account for uncertain operational 
outcomes that determine the benefits of or need for transmission 
facilities during high-impact, low-frequency events. The Commission 
proposed to allow transmission providers the flexibility to determine 
which high-impact, low-frequency event should be modeled in this Long-
Term Scenario as part of Long-Term Regional Transmission Planning based 
on the Commission's understanding that each transmission planning 
region may see a need to evaluate a different type of high-impact, low-
frequency event. The Commission stated that high-impact, low-frequency 
events may include extreme weather events or events associated with 
potential cyber-attacks. The Commission explained that this Long-Term 
Scenario accounting for a high-impact, low-frequency event can be 
developed, for example, by assuming greater-than-expected electricity 
demand and greater-than-expected generation or transmission outages. 
The Commission proposed that the use of either probabilistic 
transmission planning \1260\ or stochastic techniques would be 
sufficient to satisfy this requirement, but it did not propose to 
require either approach at this time.\1261\
---------------------------------------------------------------------------

    \1260\ NOPR, 179 FERC ] 61,028 at P 124. The Commission stated 
that it considers probabilistic transmission planning approaches to 
include any transmission planning approach that uses a probability 
distribution to assign probabilities to one or more inputs to the 
transmission model. The Commission stated that these inputs can 
include shorter-term operational inputs (like wind generation or 
generation outages). The Commission described stochastic techniques 
as including adaptive transmission planning techniques that identify 
transmission facilities that optimize transmission net-benefits over 
a time horizon under market and regulatory uncertainty about the 
future. Id. P 124 n.228.
    \1261\ Id. P 124.
---------------------------------------------------------------------------

    579. The Commission noted that transmission providers can develop 
sensitivities for every Long-Term Scenario to assess how outcomes 
modeled in Long-Term Scenarios may depend on an assumption about 
electric power system model inputs that does not vary across scenarios 
(e.g., higher natural gas prices). The Commission explained that such 
sensitivities can provide valuable information about the need for and 
benefits of potential transmission facilities, but also noted that they 
can be burdensome to develop if applied to every scenario.\1262\
---------------------------------------------------------------------------

    \1262\ Id. P 125.
---------------------------------------------------------------------------

b. Comments
    580. Some commenters support the NOPR proposal to require one Long-
Term Scenario to account for uncertain operational outcomes that 
determine the benefits of or need for transmission facilities during 
high-impact, low-frequency events as part of Long-Term Regional 
Transmission Planning.\1263\ Ameren states that the inclusion of such 
events in Long-Term Regional Transmission Planning would provide 
additional information for transmission providers, stakeholders, state 
regulators, and others to consider when determining the need for 
regional transmission facilities.\1264\ According to Arizona 
Commission, including such a scenario, and giving the transmission 
provider the discretion to determine what this should be for its 
region, may provide the added benefit of allowing state involvement in 
identifying the appropriate ``high-impact'' event to be analyzed. 
Arizona Commission additionally asserts that the Commission should 
require transmission providers to develop sensitivities for each Long-
Term Scenario to better understand the range of benefits under each 
scenario.\1265\
---------------------------------------------------------------------------

    \1263\ Ameren Initial Comments at 13; Arizona Commission Initial 
Comments at 6; California Commission Initial Comments at 24; 
Evergreen Action Initial Comments at 4; Eversource Initial Comments 
at 18; Grid United Initial Comments at 4; New England for Offshore 
Wind Initial Comments at 2; Pacific Northwest State Agencies Initial 
Comments at 14; US DOE Initial Comments at 15.
    \1264\ Ameren Initial Comments at 13-14.
    \1265\ Arizona Commission Initial Comments at 6-7.
---------------------------------------------------------------------------

    581. Eversource supports the NOPR proposal given the increasing 
threat of extreme weather events and potential cyber-attacks.\1266\ 
Similarly, Illinois Commission states that the inclusion of high-
impact, low-frequency events in the transmission planning process is 
reasonable and should include cyber-security attacks and extreme 
weather events to strengthen the system's resilience.\1267\ New England 
for Offshore Wind argues that it is prudent for the Commission to 
require transmission providers to develop at least one high-impact, 
low-frequency scenario due to the increased likelihood of extreme 
weather events due to climate change.\1268\ SoCal Edison states that 
incorporating probabilistic assumptions about extreme weather in Long-
Term Scenarios would be a reasonable, proactive approach to mitigate 
the impacts of extreme weather when it occurs.\1269\
---------------------------------------------------------------------------

    \1266\ Eversource Initial Comments at 18.
    \1267\ Illinois Commission Initial Comments at 6.
    \1268\ New England for Offshore Wind Initial Comments at 2.
    \1269\ SoCal Edison Initial Comments at 12.
---------------------------------------------------------------------------

    582. Likewise, Cypress Creek, City of New Orleans Council, DC and 
MD Offices of People's Counsel, and PIOs support the inclusion of 
extreme weather events in Long-Term Scenarios.\1270\ Business Council 
for Sustainable Energy contends that Long-Term Scenarios must account 
for the increase in significant climate events, acknowledging that the 
most salient events to assess may vary regionally.\1271\ US DOE asserts 
that regional transmission planning should consider the effects of 
extreme events, including extreme weather events, on the availability 
and reliability of the transmission system.\1272\ WE ACT comments that 
requiring transmission providers to consider extreme weather events in 
Long-Term Regional Transmission Planning is a positive step towards 
addressing grid reliability in the face of more frequent and 
intensifying weather events brought on by the climate crisis.\1273\
---------------------------------------------------------------------------

    \1270\ City of New Orleans Council Initial Comments at 8; 
Cypress Creek Reply Comments at 5-6; DC and MD Offices of People's 
Counsel Reply Comments at 6; PIOs Reply Comments at 10; see also RMI 
Supplemental Comments at 2; Senator Whitehouse Supplemental Comments 
at 2-3.
    \1271\ Business Council for Sustainable Energy Initial Comments 
at 4.
    \1272\ US DOE Initial Comments at 5.
    \1273\ WE ACT Initial Comments at 2.
---------------------------------------------------------------------------

    583. Other commenters express more general support for the study of 
high-impact, low-frequency events in Long-Term Regional Transmission 
Planning.\1274\ Clean Energy Associations emphasize that no scenario or 
sensitivity should assume that historical operating conditions will 
persist given the unpredictable and increasing impact of climate 
change.\1275\ Grid United states that high-impact, low-frequency 
scenarios should not be considered ``black swan'' events since they 
occur on a regular, but low-frequency, basis. Moreover, Grid United 
asks that the Commission define or provide examples of high-impact, 
low-frequency events that transmission providers could incorporate into 
Long-Term Scenarios to

[[Page 49377]]

provide clarity and consistency across transmission planning 
regions.\1276\
---------------------------------------------------------------------------

    \1274\ See Business Council for Sustainable Energy Initial 
Comments at 4; Clean Energy Associations Initial Comments at 12; 
Evergreen Action Initial Comments at 3-4; Grid United Initial 
Comments at 4-5; NARUC Initial Comments at 11-12; NASUCA Initial 
Comments at 4-5; NESCOE Initial Comments at 32-33; NRECA Initial 
Comments at 35-36; Pattern Energy Initial Comments at 25; SoCal 
Edison Initial Comments at 12.
    \1275\ Clean Energy Associations Initial Comments at 12.
    \1276\ Grid United Initial Comments at 5.
---------------------------------------------------------------------------

    584. NARUC does not oppose the requirement that one of the Long-
Term Scenarios account for high-impact, low-frequency events but notes 
that states' input is important when developing such scenarios.\1277\ 
Pattern Energy states that, with respect to low-probability, high-risk 
event scenarios, the Commission should: (1) require the North American 
Electric Reliability Corporation and the Regional Entities to develop 
the scope of low-probability, high-risk events for each region of the 
country and then (2) require transmission providers to model at least 
one of the events in a rotation of the three-year review of the 20-year 
plans to identify vulnerabilities that can be addressed through 
transmission solutions that increase resilience.\1278\ Vermont Electric 
and Vermont Transco request clarity on what scenarios the Commission 
would consider sufficiently high-impact to be analyzed but not so high-
impact as to be unable to be mitigated by effective Long-Term Regional 
Transmission Planning.\1279\
---------------------------------------------------------------------------

    \1277\ NARUC Initial Comments at 11-12.
    \1278\ Pattern Energy Initial Comments at 25.
    \1279\ Vermont Electric and Vermont Transco Initial Comments at 
3.
---------------------------------------------------------------------------

    585. Some commenters support the Commission's proposal to permit 
transmission providers to model high-impact, low-frequency events via 
probabilistic or stochastic methods.\1280\ PJM states that it will 
sometimes use probabilistically-derived parameters and sometimes use 
deterministically-derived parameters in its Long-Term Scenarios, 
depending on which is more appropriate.\1281\ Policy Integrity asserts 
that the Commission should ensure the use of modeling techniques that 
address uncertainty, such as stochastic programming and robust 
optimization models.\1282\ Policy Integrity argues that modeling that 
fails to consider uncertainties that arise from various factors could 
reduce the cost-efficacy and efficiency of results and, ultimately, 
result in unjust and unreasonable rates.\1283\ Policy Integrity cites 
the European Network of Transmission System Operators' consideration of 
the interactions between gas and electric systems as an example of best 
practices for choosing scenarios.\1284\
---------------------------------------------------------------------------

    \1280\ California Commission Initial Comments at 24-25; 
Eversource Initial Comments at 18; PJM Initial Comments at 74-75.
    \1281\ PJM Initial Comments at 75.
    \1282\ Policy Integrity Initial Comments at 7.
    \1283\ Id. at 6.
    \1284\ Id. at 9 (citing European Commission, Key Cross Border 
Infrastructure Projects, https://perma.cc/4U6X-Q2WN (last visited 
Aug. 9, 2022)).
---------------------------------------------------------------------------

    586. Some commenters provided views on the Commission's proposal to 
require transmission providers to develop sensitivities for each Long-
Term Scenario.\1285\ Business Council for Sustainable Energy states 
that it is important that scenario planning cover a range of 
sensitivities, and that the long-term needs of the transmission system 
as well as long-term policy goals should be incorporated.\1286\ NERC 
states that studies could more adequately study various sensitivities 
and extreme conditions (e.g., extreme weather) to ensure a reliable, 
resilient, and secure bulk power system on a longer time horizon, which 
could, in turn, help inform transmission expansion plans particularly 
related to the changing resource mix.\1287\
---------------------------------------------------------------------------

    \1285\ Business Council for Sustainable Energy Initial Comments 
at 4; NERC Initial Comments at 7; Exelon Initial Comments 7 & n.7; 
GridLab Initial Comments at 17-19; Idaho Power Initial Comments at 
5; Minnesota State Entities Initial Comments at 5; NYISO Initial 
Comments at 26; PIOs Initial Comments at 23-24; Policy Integrity 
Initial Comments at 14-16; PPL Initial Comments at 9; R Street 
Initial Comments at 6; US DOE Initial Comments at 15-16.
    \1286\ Business Council for Sustainable Energy Initial Comments 
at 4.
    \1287\ NERC Initial Comments at 7.
---------------------------------------------------------------------------

    587. GridLab recommends that the Commission provide a high-level 
requirement and guidance on what kinds of factors are more effectively 
considered in scenario versus sensitivity analysis and how sensitivity 
analysis might be used in tandem with scenario analysis.\1288\ Policy 
Integrity states that, instead of mandating only a minimum number of 
Long-Term Scenarios, the Commission should also require sensitivity 
analysis of critical drivers of transmission needs.\1289\ In addition, 
Policy Integrity recommends that the Commission require transmission 
providers to run a sensitivity for each Long-Term Scenario using a 30-
year transmission planning horizon and compare the results with those 
from the analysis of each Long-Term Scenario using a 20-year 
transmission planning horizon.\1290\ PIOs state that the Commission 
should specify that, if any critical variable (e.g., natural gas 
prices, capital costs of wind and solar, short and long duration 
storage, and carbon capture and sequestration) is the same in more than 
two Long-Term Scenarios, then transmission providers must conduct 
sensitivities that use different values for that variable.\1291\
---------------------------------------------------------------------------

    \1288\ GridLab Initial Comments at 17-18.
    \1289\ Policy Integrity Initial Comments at 15.
    \1290\ Id. at 10-11.
    \1291\ PIOs Initial Comments at 23-24.
---------------------------------------------------------------------------

    588. Although NRECA does not oppose the proposal that at least one 
Long-Term Scenario account for high-impact, low-frequency events from 
extreme weather, NRECA states that the Commission should not require 
any Long-Term Scenarios to account for possible cyber-attacks. NRECA 
asserts that modeling cyber-attacks and their effects would be 
extraordinarily complex and risk disclosure of non-public Critical 
Electric Infrastructure Information (CEII) and that such risks are 
better addressed in North American Electric Reliability Corporation 
standards development, noting that cyber-attacks may already be 
evaluated under North American Electric Reliability Corporation 
Transmission Planning Reliability Standard TPL-001-4.\1292\
---------------------------------------------------------------------------

    \1292\ NRECA Initial Comments at 35-36 (citing GDS Associates, 
Report, at 13 (Aug. 17, 2022); NERC Reliability Standard TPL-001-4, 
Table 1--Steady State, https://www.nerc.com/pa/Stand/Reliability%20Standards/TPL-001-4.pdf).
---------------------------------------------------------------------------

    589. Some commenters oppose requiring one Long-Term Scenario for 
uncertain operational outcomes that determine the benefits of or need 
for transmission facilities during high-impact, low-frequency 
events.\1293\ LADWP asserts that a more meaningful measure of benefits 
or needs associated with high-impact, low-frequency events may be a 
periodic examination of the impacts of large-scale single points of 
failures.\1294\ US Chamber of Commerce argues against requiring a Long-
Term Scenario for high-impact, low-frequency events because, it 
asserts, the scope and impacts of such events on the transmission 
system can be infinite in number.\1295\
---------------------------------------------------------------------------

    \1293\ LADWP Initial Comments at 3; MISO Initial Comments at 27-
28, 38-39; Mississippi Commission Reply Comments at 6; OMS Initial 
Comments at 6; US Chamber of Commerce Initial Comments at 7.
    \1294\ LADWP Initial Comments at 3.
    \1295\ US Chamber of Commerce Initial Comments at 7.
---------------------------------------------------------------------------

    590. MISO argues that, although the impacts of large-scale 
generation loss events associated with extreme weather events should be 
considered in Long-Term Regional Transmission Planning, the Commission 
should consider requiring analysis or sensitivities of extreme events 
that are focused on the times or snapshots when the system is 
potentially impacted by those events instead of requiring a separate 
extreme event scenario.\1296\ MISO further argues that the Commission 
should not require a specific number or type of sensitivities, which 
can vary over time, but instead transmission providers should have 
flexibility to assess the appropriate sensitivities needed to test 
scenarios and results at the time those

[[Page 49378]]

are being developed.\1297\ Similarly, OMS argues that analyzing system 
performance during extreme weather for all Long-Term Scenarios would 
result in a better understanding of the benefits of transmission and 
ensure reliability regardless of future changes in generation and/or 
load.\1298\ PIOs likewise recommend that the Commission require that 
transmission providers model extreme weather events as sensitivities in 
each Long-Term Scenario and, specifically, that they model at least 
extreme heat or cold over geographic areas that are experiencing these 
extremes.\1299\
---------------------------------------------------------------------------

    \1296\ MISO Initial Comments at 27-28.
    \1297\ Id. at 39.
    \1298\ OMS Initial Comments at 6.
    \1299\ PIOs Initial Comments at 21.
---------------------------------------------------------------------------

    591. NESCOE states that it supports the study of high-impact, low-
frequency events; however, NESCOE argues that the proposal raises 
questions about whether codifying such a requirement blurs the line 
between public policy planning and reliability planning, contrary to 
the NOPR's contention that none of the proposals seek to alter the 
reliability planning process. NESCOE contends that making the study of 
high-impact, low-frequency events discretionary instead of mandatory 
under Long-Term Regional Transmission Planning would avoid such 
tension.\1300\ Mississippi Commission states that the Commission should 
not mandate that transmission planning attempt to predict extreme 
weather events and over-build the system, because ``predicting where 
the next hurricane or tornado will land is speculative.'' Mississippi 
Commission argues that a better approach is to incorporate construction 
standards (e.g., North American Electric Reliability Corporation, IEEE, 
local reliability criteria) designed to withstand such events.\1301\
---------------------------------------------------------------------------

    \1300\ NESCOE Initial Comments at 32-33.
    \1301\ Mississippi Commission Reply Comments at 6.
---------------------------------------------------------------------------

    592. Idaho Power raises concerns that developing multiple 
sensitivities for multiple Long-Term Scenarios over a long-term 
transmission planning horizon introduces too many variables.\1302\ 
Minnesota State Entities state that defining specific methods in the 
final order--such as the difference between a ``sensitivity'' and what 
is included in a ``scenario''--can be unnecessarily confusing and 
complex.\1303\ US DOE encourages transmission providers to perform 
sensitivity analyses but states that the Commission should only require 
that one Long-Term Scenario analyze high-impact, low-frequency 
events.\1304\
---------------------------------------------------------------------------

    \1302\ Idaho Power Initial Comments at 5.
    \1303\ Minnesota State Entities Initial Comments at 5.
    \1304\ US DOE Initial Comments at 16.
---------------------------------------------------------------------------

c. Commission Determination
    593. We modify the NOPR proposal to require transmission providers 
in each transmission planning region to develop at least one 
sensitivity, applied to each Long-Term Scenario, to account for 
uncertain operational outcomes that determine the benefits of and/or 
need for transmission facilities during multiple concurrent and 
sustained generation and/or transmission outages due to an extreme 
weather event across a wide area.\1305\ As discussed below, we 
acknowledge support in the record for studying high-impact, low-
frequency events as proposed in the NOPR \1306\ but also recognize that 
requiring a fourth Long-Term Scenario might be a burdensome way to 
study such events as compared to a sensitivity.\1307\ We find that more 
clearly defining the type of system conditions that transmission 
providers must model to account for uncertain operational outcomes--in 
particular, multiple concurrent and sustained generation and/or 
transmission outages due to an extreme weather event across a wide 
area--compared to the NOPR proposal, will enable transmission providers 
to better account for periods when regional transmission facilities may 
have particularly high value by decreasing the risk of loss of load 
and/or decreasing the cost to reliably serve load.
---------------------------------------------------------------------------

    \1305\ The Commission proposed in the NOPR to require that at 
least one of four Long-Term Scenarios account for uncertain 
operational outcomes that determine the benefits of or need for 
transmission facilities during high-impact, low-frequency events. 
NOPR, 179 FERC ] 61,028 at P 124.
    \1306\ See, e.g., New England for Offshore Wind Initial Comments 
at 2; see also Arizona Commission Initial Comments at 6-7. We also 
note that the Commission has previously discussed that ``[e]xtreme 
heat and cold weather events have occurred with greater frequency in 
recent years, and are projected to occur with even greater frequency 
in the future.'' Order No. 896, 183 FERC ] 61,191 at P 2.
    \1307\ See, e.g., MISO Initial comments at 27.
---------------------------------------------------------------------------

    594. Therefore, we require that, after developing at least three 
Long-Term Scenarios, transmission providers develop a sensitivity for 
each of the Long-Term Scenarios.\1308\ We provide transmission 
providers with flexibility to conduct this sensitivity either before or 
after identifying potential regional transmission solutions to the 
Long-Term Transmission Needs identified using those Long-Term 
Scenarios. Conducting this sensitivity before identifying potential 
regional transmission solutions can be useful because it may help 
transmission providers to identify such solutions. On the other hand, 
conducting this sensitivity after identifying potential regional 
transmission solutions to Long-Term Transmission Needs would allow 
transmission providers to engage in efforts to develop additional or 
alternative regional transmission solutions to address such conditions.
---------------------------------------------------------------------------

    \1308\ See NOPR, 179 FERC ] 61,028 at P 125 n.229. A sensitivity 
represents a single assumption about a short-term input or factor 
(some input with a value that may change throughout a day or year). 
A scenario represents an assumption about a longer-term input or 
factor (e.g., resource retirements and additions or public 
policies).
---------------------------------------------------------------------------

    595. In conducting this sensitivity, transmission providers change 
the data inputs of the underlying Long-Term Scenarios--in terms of 
load, generation, generator outages, and transmission outages--to 
account for uncertain operational outcomes that determine the benefits 
of or need for regional transmission facilities during multiple 
concurrent and sustained generation and/or transmission outages due to 
an extreme weather event across a wide area, while maintaining the 
underlying longer-term determinants of the Long-Term Scenario (e.g., 
the installed capacity of each generation resource). The sensitivity 
can be thought of as a ``stress test'' for all Long-Term Scenarios.
    596. We find it necessary to require the consideration of a more 
narrowly defined set of conditions, as compared to the broader high-
impact, low-frequency event conditions described in the NOPR, to 
include multiple concurrent and sustained generation and/or 
transmission outages due to an extreme weather event across a wide 
area.\1309\ Extreme weather events have occurred more frequently in 
recent years,\1310\ are periods when regional transmission facilities 
have particularly high value,\1311\ and create system conditions that 
transmission providers can readily specify compared to contingencies 
with an unknown root cause.\1312\ During these extreme weather

[[Page 49379]]

events, generation and transmission outages can be widespread, occur at 
the same time, and persist due to a common cause like freezing 
temperatures or limited fuel availability. This more narrowly defined 
set of conditions also gives transmission providers more direct 
guidance on how to comply with the requirements of this final 
order.\1313\
---------------------------------------------------------------------------

    \1309\ See, e.g., Grid United Initial Comments at 4-5 (stating 
that ``the Commission should define or provide examples of the low-
frequency, high impact events that it would like to be considered 
for planning purposes'').
    \1310\ See supra The Overall Need for Reform section; see also 
NOPR, 179 FERC ] 61,028 at P 45; Breakthrough Energy Initial 
Comments at 8.
    \1311\ See ACEG Initial Comments at 5; PIOs Initial Comments at 
21; US DOE Initial Comments at 5-6.
    \1312\ In terms of specifying the system conditions during 
extreme weather events, transmission providers can, for example, 
look at previous severe cold weather events to identify how load 
might increase, how load and generation forecasts might be 
incorrect, and how generation and transmission outages might occur 
during a future extreme weather event.
    \1313\ See, e.g., Grid United Initial Comments at 4-5.
---------------------------------------------------------------------------

    597. Although we are only requiring that one sensitivity analysis 
specific to extreme weather events be applied to each Long-Term 
Scenario to comply with this final order, we do not preclude 
transmission providers from considering additional sensitivities. We 
recognize that transmission providers may consider several other 
sensitivities as important and helpful in evaluating the benefits of 
and need for Long-Term Regional Transmission Facilities. For example, 
transmission providers can develop sensitivities to account for a 
cyber-attack, significant forecast error, or fuel price volatility. We 
encourage transmission providers to assess the need to develop other 
sensitivities as part of Long-Term Regional Transmission Planning.
    598. We find that modeling extreme weather events as sensitivities 
is appropriate for Long-Term Regional Transmission Planning. We first 
note that extreme weather events can occur under any assumed future 
scenario but do not, by themselves, represent changes in the way that 
factors are used in Long-Term Scenarios to determine Long-Term 
Transmission Needs.\1314\ Therefore, we believe that applying a 
sensitivity to each Long-Term Scenario is a more accurate way to 
evaluate the effects of high-impact, low-frequency events than 
considering such events in a distinct Long-Term Scenario. Second, 
although there is a burden associated with conducting sensitivities, 
the overall burden of conducting a sensitivity analysis is 
comparatively lower than that of developing a new, separate Long-Term 
Scenario. This is because sensitivities will be conducted using the 
existing Long-Term Scenarios, where most inputs, and the factors and 
assumptions used to develop the scenarios, have already been 
established and mapped. Adjusting a set of existing inputs to test the 
impact of the changes on a Long-Term Scenario through a sensitivity 
analysis is therefore less burdensome than developing an entirely new 
Long-Term Scenario.
---------------------------------------------------------------------------

    \1314\ See MISO Initial Comments at 27-28; OMS Initial Comments 
at 6.
---------------------------------------------------------------------------

    599. In addition, we highlight that transmission providers can use 
the required sensitivity analyses to evaluate the need for, or benefits 
of, increased Interregional Transfer Capability provided by candidate 
Long-Term Regional Transmission Facilities. We recognize that certain 
Long-Term Regional Transmission Facilities could increase Interregional 
Transfer Capability by changing the topology of the transmission 
system, even if the specific transmission facility is not directly 
connected to a neighboring transmission planning region's transmission 
system. We believe that an increase in Interregional Transfer 
Capability could provide significant benefits during extreme weather 
events that result in multiple concurrent and sustained generation and/
or transmission outages.\1315\ We note that several commenters discuss 
the need for greater Interregional Transfer Capability because of 
extreme weather events\1316\ and the importance of modeling extreme 
weather event conditions to capture the benefits of regional 
transmission facilities.\1317\ As discussed in the Evaluation of the 
Benefits of Regional Transmission Facilities section below, we require 
transmission providers to consider increased Interregional Transfer 
Capability provided by a Long-Term Regional Transmission Facility when 
measuring Benefit 6.\1318\ We believe that transmission providers can 
evaluate Benefit 6, including reduced loss of load and reduced 
production costs during extreme weather events that result in multiple 
concurrent and sustained generation and/or transmission outages, using 
this required sensitivity, among other sensitivities that transmission 
providers may develop to capture extreme events and system 
contingencies.
---------------------------------------------------------------------------

    \1315\ See, e.g., Order No. 896, 183 FERC ] 61,191 at PP 85-88.
    \1316\ BP Initial Comments at 10; Breakthrough Energy Initial 
Comments at 2; Kansas Commission Initial Comments at 8-9; NARUC 
Initial Comments at 23; US DOE Initial Comments at 39-42; see also 
ELCON Initial Comments at 8 (arguing Interregional Transfer 
Capability should be a driver of transmission needs); PJM Initial 
Comments at 66-67.
    \1317\ See ACEG Initial Comments at 5; PIOs Initial Comments at 
21; US DOE Initial Comments at 5-6.
    \1318\ See infra Evaluation of the Benefits of Regional 
Transmission Facilities, Required Benefits, Benefit 6: Mitigation of 
Extreme Weather Events and Unexpected System Conditions section.
---------------------------------------------------------------------------

    600. We disagree with NESCOE's concern that a requirement to study 
the impact of high-impact, low-frequency events might ``blur[] the line 
between public policy planning and reliability planning.'' \1319\ 
Rather, as discussed below in the Evaluation of the Benefits of 
Regional Transmission Facilities section, we believe that the 
requirement complements Benefit 6 (Mitigation of Extreme Weather Events 
and Unexpected System Conditions) given the high probability that 
extreme weather events will cause unplanned transmission outages and 
the likelihood that such events will continue to occur at regular 
intervals.\1320\ Although this final order requires a more 
comprehensive consideration of benefits, it does not alter Order No. 
1000's requirements for transmission providers to create a regional 
transmission plan that will identify transmission facilities that more 
efficiently or cost-effectively meet the transmission planning region's 
reliability and economic requirements.
---------------------------------------------------------------------------

    \1319\ NESCOE Initial Comments at 33.
    \1320\ See infra Evaluation of the Benefits of Regional 
Transmission Facilities, Required Benefits, Benefit 6: Mitigation of 
Extreme Weather Events and Unexpected System Conditions section.
---------------------------------------------------------------------------

    601. We also acknowledge LADWP's concern that a more meaningful 
measure of benefits or needs associated with high-impact, low-frequency 
events may be a periodic examination of the impacts of large-scale 
single point failure.\1321\ Although we do not preclude transmission 
providers from conducting such a study, such a study would not meet the 
final order's requirement to conduct a sensitivity, applied to each 
Long-Term Scenario, to account for uncertain operational outcomes that 
determine the benefits of and/or need for transmission facilities 
during multiple concurrent and sustained generation and/or transmission 
outages due to an extreme weather event across a wide area.
---------------------------------------------------------------------------

    \1321\ LADWP Initial Comments at 3.
---------------------------------------------------------------------------

7. Specificity of Data Inputs
a. NOPR Proposal
    602. In the NOPR, the Commission proposed to require transmission 
providers in each transmission planning region to use ``best available 
data inputs'' when developing Long-Term Scenarios.\1322\ The Commission 
stated that, by ``best available,'' the Commission did not imply that 
there is a single ``best'' value for each data input that transmission 
providers must use, but rather that best practices are used to develop 
that data input.\1323\
---------------------------------------------------------------------------

    \1322\ NOPR, 179 FERC ] 61,028 at PP 130-134.
    \1323\ Id. P 130.
---------------------------------------------------------------------------

    603. The Commission proposed to define ``best available data 
inputs'' as data inputs that are timely and developed using diverse and 
expert perspectives, adopted via a process that satisfies the Order 
Nos. 890 and 1000 transparency transmission planning principles 
described above, and reflect

[[Page 49380]]

the list of factors that transmission providers must incorporate into 
Long-Term Scenarios.\1324\ The Commission explained that an example of 
data inputs that could meet this requirement are the long-term load 
forecasts of demand that RTOs/ISOs currently use for predicting long-
term resource adequacy. The Commission stated that another example of 
data inputs that could meet this requirement are the most recent data 
on renewable energy potential and distributed energy resources 
developed by national labs.\1325\
---------------------------------------------------------------------------

    \1324\ Id. P 131.
    \1325\ Id. P 131 n.247.
---------------------------------------------------------------------------

    604. The Commission proposed to require transmission providers in 
each transmission planning region to update all data inputs each time 
they reassess and revise, as necessary, their Long-Term Scenarios, 
which, as explained in the NOPR, the Commission proposed to require 
that they do at least every three years. As indicated in the Long-Term 
Regional Transmission Planning section of the NOPR,\1326\ the 
Commission also proposed to require that the Order Nos. 890 and 1000 
transmission planning principles apply to the process through which 
transmission providers determine which data inputs to use in their 
Long-Term Scenarios. For example, consistent with the coordination 
transmission planning principle established in Order No. 890, the 
Commission proposed to require that transmission providers in each 
transmission planning region give stakeholders the opportunity to 
provide timely and meaningful input concerning which data inputs to use 
in Long-Term Scenarios.\1327\
---------------------------------------------------------------------------

    \1326\ Id. PP 64-67.
    \1327\ Id. P 132.
---------------------------------------------------------------------------

    605. The Commission preliminarily found that a requirement to use 
the best available data inputs was necessary to ensure that 
transmission providers are regularly updating data inputs and then 
using timely and accurate data inputs to inform Long-Term Scenarios. 
The Commission stated that data inputs can drive the results of Long-
Term Regional Transmission Planning. As a result, the Commission 
explained that data inputs can directly affect which transmission 
facilities may be selected and, in turn, Commission-jurisdictional 
rates.\1328\
---------------------------------------------------------------------------

    \1328\ Id. P 133.
---------------------------------------------------------------------------

b. Comments
i. Interest in Best Available Data Requirement
    606. Many commenters generally support the NOPR proposal for ``best 
available data,'' but some recommend that the Commission monitor data 
inputs.\1329\ AEE states that it is not practical to make a more 
prescriptive requirement for data inputs than the NOPR proposal and 
recommends that the Commission be vigilant in monitoring data 
inputs.\1330\ Policy Integrity states that the NOPR proposal is crucial 
in protecting against strategic modeling behavior.\1331\ WATT Coalition 
adds that ``best available data'' on future generation must be used 
because demand and energy profiles are inherently uncertain.\1332\
---------------------------------------------------------------------------

    \1329\ AEE Initial Comments at 23; Certain TDUs Initial Comments 
at 16; Clean Energy Buyers Initial Comments at 17-18; DC and MD 
Offices of People's Counsel Initial Comments at 14; Duke Initial 
Comments at 16-17; Eversource Initial Comments at 20; Georgia 
Commission Initial Comments at 5; ITC Initial Comments at 12; NARUC 
Initial Comments at 13-15; NRECA Initial Comments at 35-36; OMS 
Initial Comments at 5; [Oslash]rsted Initial Comments at 7; Pacific 
Northwest State Agencies Initial Comments at 13-14; PJM Initial 
Comments at 7, 76; Policy Integrity Initial Comments at 6; US DOE 
Initial Comments at 16-17; WATT Coalition Initial Comments at 7.
    \1330\ AEE Initial Comments at 23.
    \1331\ Policy Integrity Initial Comments at 17.
    \1332\ WATT Coalition Initial Comments at 7.
---------------------------------------------------------------------------

    607. ACEG claims that the FPA supports the Commission's proposed 
requirement to plan based on the best available data, noting that 
section 217(b)(4) requires the Commission to exercise its authority 
``in a manner that facilitates the planning and expansion of 
transmission facilities to meet the reasonable needs of load-serving 
entities to satisfy the service obligation of load-serving entities.'' 
\1333\ ACEG argues that load-serving entities' service obligations will 
be more accurately predicted by the best available forecasting 
methodologies.\1334\
---------------------------------------------------------------------------

    \1333\ ACEG Initial Comments at 26-27 (citing 16 U.S.C. 
824q(b)(4)).
    \1334\ Id. at 27.
---------------------------------------------------------------------------

    608. Clean Energy Buyers state that it is important to get 
stakeholder input on data inputs, as has been done through MISO's Long-
Range Transmission Planning effort.\1335\ Breakthrough Energy states 
that Long-Term Scenarios should use ``best available data.'' \1336\
---------------------------------------------------------------------------

    \1335\ Clean Energy Buyers Initial Comments at 18.
    \1336\ Breakthrough Energy Supplemental Comments at 1.
---------------------------------------------------------------------------

ii. Reservations with the Best Available Data Requirement
    609. Several commenters support the NOPR proposal but nevertheless 
have suggestions about how to modify the proposal.\1337\ For example, 
several commenters request that the Commission create a common dataset, 
publish a database of best available sources of data, or otherwise 
standardize data inputs.\1338\ Southeast PIOs state that the Commission 
should publish a regularly updated database of best available data 
sources and require transmission providers to justify any decision not 
to use that database, arguing that flexibility in project selection can 
only work if the selection process utilizes reliable and standardized 
inputs.\1339\ SEIA urges the Commission to issue standards or 
guidelines that define what constitutes ``best available data inputs'' 
for each of the seven categories of factors.\1340\ R Street contends 
that intraregional standardization could support internal consistency 
and transparency and focus scarce stakeholder capital.\1341\
---------------------------------------------------------------------------

    \1337\ ACEG Initial Comments at 7; ACORE Initial Comments at 8-
9; Eversource Initial Comments at 20-21; GridLab Initial Comments at 
23; OMS Initial Comments at 5; Pine Gate Initial Comments at 27-29; 
PIOs Initial Comments at 19-20; Policy Integrity Initial Comments at 
6, 16-18; Southeast PIOs Initial Comments at 47-48.
    \1338\ ACEG Initial Comments at 7; ACORE Initial Comments at 8-
9; GridLab Initial Comments at 23; PIOs Initial Comments at 19-20; 
Southeast PIOs Initial Comments at 47-48.
    \1339\ Southeast PIOs Initial Comments at 47.
    \1340\ SEIA Initial Comments at 11; SEIA Reply Comments at 4.
    \1341\ R Street Initial Comments at 7.
---------------------------------------------------------------------------

    610. ELCON notes that, as part of the three-year reassessment of 
Long-Term Scenarios, the Commission may decide that identifying or 
standardizing data inputs and sources may help to ensure that 
transmission providers are consistently using timely and widely 
accepted data.\1342\ Interwest endorses US DOE's proposal in its 
comments to the ANOPR to standardize data inputs.\1343\ ACORE states 
that an identification of certain common data sets and modeling best 
practices will reduce uncertainty, improve transparency, and achieve 
greater consistency among transmission planning regions.\1344\
---------------------------------------------------------------------------

    \1342\ ELCON Initial Comments at 13.
    \1343\ Interwest Initial Comments at 8 (citing US DOE ANOPR 
Initial Comments at 12-15).
    \1344\ ACORE Reply Comments at 5.
---------------------------------------------------------------------------

    611. ENGIE states that data inputs should be sourced from Federal 
and state agencies whenever possible.\1345\ Renewable Northwest states 
that determining a future resource mix for NorthernGrid is possible 
with publicly available data.\1346\ GridLab states that the Commission 
should consider whether to require that transmission providers either 
use unadjusted, publicly available data in Long-Term Regional 
Transmission Planning or justify why using proprietary data would 
provide superior results.
---------------------------------------------------------------------------

    \1345\ ENGIE Initial Comments at 3.
    \1346\ Renewable Northwest Initial Comments at 17.
---------------------------------------------------------------------------

    612. Several commenters state that it is not necessary for the 
Commission to facilitate the development of data or

[[Page 49381]]

standardize inputs.\1347\ PPL, for example, asserts that the task of 
developing data inputs should be left to transmission providers, with 
the caveat that the entire process should avoid hindsight bias or an 
inappropriate shift in burden or responsibility to the transmission 
provider.\1348\ SPP states that the development of data inputs 
facilitated by the Commission could provide value if implemented in a 
way that does not create additional burden to the assessment. SPP 
suggests that allowing access to recommended data sources or standard 
information would provide an additional reference for transmission 
providers to validate their own data, incorporate portions of the data, 
or utilize all of the data, as appropriate.\1349\
---------------------------------------------------------------------------

    \1347\ Ameren Initial Comments at 14-15; Idaho Power Initial 
Comments at 5; NESCOE Initial Comments at 35-36; New York State 
Department Initial Comments at 8-9; PPL Initial Comments at 10.
    \1348\ PPL Initial Comments at 10.
    \1349\ SPP Initial Comments at 11-12.
---------------------------------------------------------------------------

    613. US Climate Alliance and US DOE support transparency 
requirements for data inputs.\1350\ Similarly, California Commission 
and NRECA support transparency requirements for data inputs, subject to 
appropriate confidentiality considerations.\1351\ Colorado Consumer 
Advocate contends that greater transparency and opportunities for 
meaningful stakeholder input regarding data inputs for Long-Term 
Regional Transmission Planning will improve the regional transmission 
planning process and help to ensure that Order No. 890 transmission 
planning principles are met.\1352\
---------------------------------------------------------------------------

    \1350\ US Climate Alliance Initial Comments at 2; US DOE Initial 
Comments at 17.
    \1351\ California Commission Initial Comments at 25; NRECA 
Initial Comments at 35-37 (citing GDS Associates, Report, at 13 
(Aug. 17, 2022)).
    \1352\ Colorado Consumer Advocate Initial Comments at 26.
---------------------------------------------------------------------------

    614. Concerned Scientists state that the final order should require 
transmission providers and load-serving entities to submit to the 
relevant transmission planner an account of planned investments and 
retirements over the transmission planning horizon because not doing so 
ensures a transmission planning process that is less informed than it 
can and should be. Concerned Scientists state that excluding these 
minimum requirements from the final order will inevitably lead to the 
exclusion of information needed by regulators, stakeholders, and the 
transmission providers themselves to make informed investment 
decisions.\1353\ PJM, which supports the NOPR proposal, states that, 
while it is important to consider resource retirements when developing 
planning assumptions, generation retirement forecasts may be 
interpreted by stakeholders as sending economic signals concerning the 
viability of existing generating units. Thus, PJM urges the Commission 
to provide clear direction on how to balance the heightened 
transparency and public processes proposed in the NOPR with appropriate 
safeguards against releasing data that could preempt unit owner 
economic decisions, as well as decisions by market participants.\1354\
---------------------------------------------------------------------------

    \1353\ Concerned Scientists Reply Comments at 17.
    \1354\ PJM Reply Comments at 22.
---------------------------------------------------------------------------

    615. ITC, PJM, and SEIA support the NOPR proposal, and ITC and SEIA 
agree with PJM's suggestion that the Commission hold regular forums, 
workshops, or technical conferences to determine best practices in 
developing best available data.\1355\
---------------------------------------------------------------------------

    \1355\ ITC Initial Comments at 12; PJM Initial Comments at 76-
77; SEIA Initial Comments at 11; SEIA Reply Comments at 4-5.
---------------------------------------------------------------------------

    616. SPP Market Monitor contends that the Commission should further 
provide guidance in the form of parameters by which transmission 
providers should define the phrase ``best available data,'' which SPP 
Market Monitor argues would aid in ensuring that the Long-Term 
Scenarios studied and transmission projects or facilities planned are 
consistent and reasonable.\1356\ Relatedly, Pine Gate states that the 
NOPR's failure to address source accuracy in the definition of best 
available date inputs may introduce subjectivity into Long-Term 
Regional Transmission Planning, obscure sources, and inhibit the 
ability of stakeholders to meaningfully engage in the Long-Term 
Regional Transmission Planning process. To remedy these concerns, Pine 
Gate suggests that the Commission define ``best available data inputs'' 
as data inputs that: (1) are current and developed using diverse and 
expert perspectives expressed during a stakeholder process; (2) have 
identified sources; (3) are adopted via a process that satisfies Order 
No. 890's transparency planning principle; and (4) reflect the list of 
factors that transmission providers must incorporate into Long-Term 
Scenarios.\1357\ Policy Integrity states that the Commission should 
require external vetting of data inputs used by a party without a stake 
in the outcomes.\1358\
---------------------------------------------------------------------------

    \1356\ SPP Market Monitor Initial Comments at 8.
    \1357\ Pine Gate Initial Comments at 28.
    \1358\ Policy Integrity Initial Comments at 17-18.
---------------------------------------------------------------------------

    617. Several commenters state that the final order should add a 
requirement that data must be accurate.\1359\ ELCON notes that 
utilities should consider whether a data source's historical 
projections ultimately proved to be accurate when identifying ``best 
available'' inputs, and Vermont Electric and Vermont Transco 
agree.\1360\ Arizona Commission supports the use of relevant, timely, 
and accurate data.\1361\
---------------------------------------------------------------------------

    \1359\ ELCON Initial Comments at 13; LADWP Initial Comments at 
4; Vermont Electric and Vermont Transco Initial Comments at 3.
    \1360\ ELCON Initial Comments at 13; Vermont Electric and 
Vermont Transco Initial Comments at 3.
    \1361\ Arizona Commission Initial Comments at 7.
---------------------------------------------------------------------------

    618. LADWP asserts that the determination of ``best available 
data'' should be changed to ``the most accurate data inputs available'' 
at the time of study because ``best'' is subjective but ``most 
accurate'' is clear and objective. LADWP states that, if data is 
interpreted differently, as may be the case under the ``best 
available'' standard, then results will be inconsistent. For example, 
LADWP states that the ``most accurate data inputs available'' for load 
inputs for near-term planning and for data for generation and energy 
storage capacities would be data derived from projections based on 
actual field measurements, and from in-service equipment (instead of 
from manufacturing brochures or articles), respectively. LADWP states 
that for new technologies, the projected availability and performance 
parameters should be based on actual data when possible. For example, 
LADWP states that data derived from field operating experience with 
prototypes should be considered ``most accurate'' as compared to lab 
test data. LADWP contends that transmission providers should be careful 
not to take ``expert perspectives'' at face value, but should seek to 
use data inputs that show a strong correlation to scientifically 
verifiable facts. Furthermore, LADWP states, projected data based on 
administrative law or executed interconnection agreements should be 
considered more certain, and hence more accurate, than data based on 
corporate or government goals.\1362\
---------------------------------------------------------------------------

    \1362\ LADWP Initial Comments at 4.
---------------------------------------------------------------------------

    619. GridLab recommends that the Commission request that the 
national laboratories and other public agencies work with transmission 
providers, resource developers, and others to evaluate the historical 
accuracy of publicly available data sources.\1363\ However, Ameren sees 
no reason to expand the definition of best available data inputs to 
include an evaluation of data source entities' historical accuracy 
identifying and projecting trends

[[Page 49382]]

because the open and transparent planning process of diverse 
stakeholders will identify any questionable or non-reliable data 
sources.\1364\
---------------------------------------------------------------------------

    \1363\ GridLab Initial Comments at 24.
    \1364\ Ameren Initial Comments at 15.
---------------------------------------------------------------------------

    620. ELCON states that the Commission may need to clarify what data 
is considered ``timely'' and argues, for example, that the Commission 
should not establish a mandate in favor of using historical data (e.g., 
actual data from the previous 12 months) because such data may not 
reflect current and future operational needs.\1365\ Pine Gate is 
concerned that the use of the term ``timely'' in the definition of 
``best available data inputs'' may lead to confusion and inconsistency 
amongst transmission providers.\1366\
---------------------------------------------------------------------------

    \1365\ ELCON Initial Comments at 13.
    \1366\ Pine Gate Initial Comments at 28.
---------------------------------------------------------------------------

    621. PJM Market Monitor states that both aggregate and very 
specific locational data on future demand and the future resource mix 
will be critical for efficient and cost-effective transmission 
planning.\1367\
---------------------------------------------------------------------------

    \1367\ PJM Market Monitor Initial Comments at 4.
---------------------------------------------------------------------------

iii. Concerns With Best Available Data
    622. Several commenters either oppose the NOPR proposal or object 
to specific aspects of the NOPR proposal.\1368\ Ameren, EEI, and PPL 
state that the NOPR proposal is unnecessary and too prescriptive.\1369\ 
Idaho Commission agrees that it is too prescriptive.\1370\ EEI states 
that, while using the best available data inputs when preparing the 
Long-Term Scenarios is appropriate, a pro forma definition may not be 
necessary.\1371\
---------------------------------------------------------------------------

    \1368\ Ameren Initial Comments at 14-15; Dominion Initial 
Comments at 26-28; EEI Initial Comments at 14; ELCON Initial 
Comments at 13; Idaho Power Initial Comments at 5; LADWP Initial 
Comments at 4; MISO Initial Comments at 40-41; MISO TOs Initial 
Comments at 18-19; National Grid Initial Comments at 14; Nebraska 
Commission Initial Comments at 6; NESCOE Initial Comments at 35-36; 
PPL Initial Comments at 9-10; R Street Initial Comments at 7; 
Vermont Electric and Vermont Transco Initial Comments at 3; Xcel 
Initial Comments at 10.
    \1369\ Ameren Initial Comments at 14-15; EEI Initial Comments at 
14; PPL Initial Comments at 9.
    \1370\ Idaho Commission Initial Comments at 3.
    \1371\ EEI Initial Comments at 14.
---------------------------------------------------------------------------

    623. PPL expresses concern that the proposed requirement for data 
inputs will unnecessarily burden transmission providers by effectively 
shifting a burden from data owners (who are in the best position to 
control and ensure data accuracy) to the transmission provider and 
instead recommends that the Commission strengthen the requirements 
applicable to the data owners or data source entities.\1372\ Dominion 
states that using best available data inputs should not be a 
requirement because transmission providers should be permitted to 
select the data inputs that are most appropriate for their own 
situation, as they know their transmission systems best. Dominion 
additionally does not support defining ``best available data inputs'' 
as proposed because it would limit transmission providers' flexibility 
to conduct transmission planning that is most appropriate to their 
unique system needs.\1373\
---------------------------------------------------------------------------

    \1372\ PPL Initial Comments at 9-10.
    \1373\ Dominion Initial Comments at 26-27.
---------------------------------------------------------------------------

    624. MISO, Utah Division of Public Utilities, and Xcel state that 
the NOPR proposal on data inputs is a potential source of 
conflict.\1374\ MISO is concerned that parties opposing particular 
long-range transmission planning outcomes could seize on the proposed 
language and argue that some other data was the best available data, 
thereby delaying the process; and the resulting disputes could 
potentially slow down the transmission planning process and ultimately 
delay much needed transmission.\1375\ Xcel agrees.\1376\ Utah Division 
of Public Utilities attests that requiring transmission providers to 
use the best data available is not based on evidence showing that data 
inputs currently used by transmission providers have led to unjust or 
discriminatory rates, and may produce unnecessary and time-consuming 
disagreements among stakeholders regarding which data inputs to 
use.\1377\ National Grid asserts that the term ``best available'' data 
is vague and subjective, which introduces development, regulatory and 
implementation inefficiencies.\1378\ Clean Energy Associations argue 
that transmission providers should be required to explain the number 
and the basis for including each input they choose to include.\1379\
---------------------------------------------------------------------------

    \1374\ MISO Initial Comments at 29; Utah Division of Public 
Utilities Initial Comments at 6; Xcel Initial Comments at 10.
    \1375\ MISO Initial Comments at 40.
    \1376\ Xcel Initial Comments at 10.
    \1377\ Utah Division of Public Utilities Initial Comments at 6.
    \1378\ National Grid Initial Comments at 14.
    \1379\ Clean Energy Associations Initial Comments at 13.
---------------------------------------------------------------------------

iv. Flexibility Issues
    625. Several commenters, some that support the NOPR proposal and 
some that do not, call for flexibility in allowing transmission 
providers to determine what constitutes best available data. ISO-NE and 
NYISO support the NOPR proposal but request that the Commission provide 
transmission providers with some flexibility about how to satisfy this 
requirement.\1380\ ISO-NE asserts that the Commission should allow 
flexibility for ISO-NE to rely on the states to determine the data 
inputs, with its technical support and stakeholder input, and NESCOE, 
which opposes the NOPR proposal, agrees.\1381\ NESCOE is concerned 
about the prescriptive nature of the NOPR proposal and contends that 
data inputs should be determined on a region-by-region basis by 
transmission providers with input from states and stakeholders.\1382\ 
MISO agrees on both points.\1383\ Duke, which generally supports the 
NOPR proposal to define best available data inputs and requirement to 
follow a transparent process to develop the data inputs, states that 
because there is not a single ``best'' value for each input, the 
emphasis should be on best practices to develop the data inputs, which 
should be left to the regions to develop with their specific 
stakeholders.\1384\
---------------------------------------------------------------------------

    \1380\ ISO-NE Initial Comments at 28; NYISO Initial Comments at 
28.
    \1381\ ISO-NE Initial Comments at 28; NESCOE Initial Comments at 
35-36.
    \1382\ NESCOE Initial Comments at 36.
    \1383\ MISO Initial Comments at 40.
    \1384\ Duke Initial Comments at 16-17.
---------------------------------------------------------------------------

    626. In addition, NYISO requests that the Commission revise the 
definition of best available data to permit flexibility on how it 
reflects factors considered in the scenarios. Specifically, NYISO 
requests that the language in the NOPR specifying that the data inputs 
must ``reflect the list of factors that transmission providers must 
incorporate into Long-Term Scenarios'' should be modified to ``reflect 
the factors that the transmission provider considers in the scenarios'' 
to reflect the authority of transmission planning regions to identify 
which factors should be used in Long-Term Scenarios. NYISO adds that 
transmission providers should have authority over how to interpolate 
and employ their data sets.\1385\
---------------------------------------------------------------------------

    \1385\ NYISO Initial Comments at 28.
---------------------------------------------------------------------------

    627. MISO, which opposes the NOPR proposal, contends that the 
Commission should allow transmission providers to determine, in 
consultation with its stakeholders, what data is most appropriate, but 
require transmission providers to use the most up-to-date data from the 
source that they select.\1386\ MISO recommends that, if the final order 
includes the NOPR proposal for best available data, then the Commission 
should clarify that transmission providers may satisfy the requirement 
by using the most up-to-date data that they have selected and that 
reflects practical limitations

[[Page 49383]]

regarding the precision and scope of the data.\1387\ MISO TOs suggest 
that the Commission consider articulating principles and guidelines and 
let transmission planning regions develop their own conception of 
``best available data'' in the interest of flexibility.\1388\ Nevada 
Commission states that the definition of ``best available data'' may 
need further comment and will likely evolve as the Long-Term Regional 
Transmission Planning process is implemented.\1389\
---------------------------------------------------------------------------

    \1386\ MISO Initial Comments at 40.
    \1387\ Id. at 29.
    \1388\ MISO TOs Initial Comments at 19.
    \1389\ Nevada Commission Initial Comments at 9.
---------------------------------------------------------------------------

    628. National Grid requests that the Commission clarify that 
transmission providers have final and sole responsibility and 
discretion to determine what is ``best available data'' as transmission 
providers are best situated to make these determinations in 
consultation with their stakeholders. National Grid also seeks clarity 
from the Commission as to what ``diverse'' means as it describes best 
available data inputs. National Grid further asserts that the 
Commission should distinguish between Long-Term Scenarios based on 
diverse inputs in each scenario.\1390\
---------------------------------------------------------------------------

    \1390\ National Grid Initial Comments at 14.
---------------------------------------------------------------------------

v. Best Sources of Data Issues
    629. Several commenters, some that support the NOPR proposal and 
some that do not, make suggestions about the best sources of data. 
Several commenters state that transmission providers already have the 
best available data.\1391\ Nebraska Commission further states that the 
current methods used by RTOs/ISOs would meet the NOPR's proposed 
requirements.\1392\ PPL states that transmission providers already use 
a ``best available data inputs'' standard in transmission planning but 
must rely on other entities' data.\1393\ EEI states that, if the 
Commission adopts a definition for best available data, it should 
acknowledge that transmission providers and load-serving entities often 
may possess this data.\1394\
---------------------------------------------------------------------------

    \1391\ EEI Initial Comments at 14; Nebraska Commission Initial 
Comments at 6; PJM Initial Comments at 76; PPL Initial Comments at 
9-10.
    \1392\ Nebraska Commission Initial Comments at 6.
    \1393\ PPL Initial Comments at 9-10.
    \1394\ EEI Initial Comments at 14.
---------------------------------------------------------------------------

    630. Several commenters state that load-serving entities have the 
best available data.\1395\ Eversource recommends that the Commission 
require the RTOs/ISOs to collaborate with the transmission owners 
regarding transmission owners' forecast of load localized peak 
times.\1396\ PIOs state that the Commission should require load-serving 
entities to provide their generation and load forecasts to transmission 
providers so that they have reasonable information to use and do not 
have to perform their own estimates.\1397\ ACEG and Clean Energy 
Associations agree.\1398\
---------------------------------------------------------------------------

    \1395\ Id.; Eversource Initial Comments at 20; Xcel Initial 
Comments at 10.
    \1396\ Eversource Initial Comments at 20.
    \1397\ PIOs Initial Comments at 19.
    \1398\ ACEG Reply Comments at 23; Clean Energy Associations 
Reply Comments at 7.
---------------------------------------------------------------------------

    631. Western PIOs state that the Western Electricity Coordinating 
Council databases on load and generation forecasts and the Western 
Electricity Coordinating Council Anchor dataset constitute best 
available data.\1399\ NARUC argues that any reasonable, credible source 
of data should be allowed to supplement more traditional sources like 
the national laboratories and RTO/ISO-generated data.\1400\ SREA 
recommends that, to the extent possible, the Commission should 
recognize the National Renewable Energy Lab's Annual Technology 
Baseline (NREL ATB) as the Nation's preferred data set.\1401\ Policy 
Integrity states that the Commission should urge transmission providers 
to engage independent researchers in the process to ensure inclusion of 
the latest modeling and computational developments.\1402\ PIOs state 
that the Commission could publish a regularly updated list of databases 
that meet the ``best available data requirement,'' such as the 
following current databases: NREL ATB data, US DOE's Annual Energy 
Outlook for fuel costs, and NREL's Electrification Futures Study for 
electrification trends. PIOs suggests that the Commission could 
additionally partner with the US DOE and National Laboratories to 
develop appropriate databases.\1403\
---------------------------------------------------------------------------

    \1399\ Western PIOs Initial Comments at 31.
    \1400\ NARUC Initial Comments at 13.
    \1401\ SREA Reply Comments at 26.
    \1402\ Policy Integrity Initial Comments at 17.
    \1403\ PIOs Initial Comments at 19.
---------------------------------------------------------------------------

    632. Entergy asserts that integrated resource plans approved by 
retail commissions should be considered the best available data, and 
Louisiana Commission and Mississippi Commission agree.\1404\ However, 
Kentucky Commission Chair Chandler disagrees with the propositions that 
local data provided by a utility in an integrated resource plan is 
superior to other data and that RTOs/ISOs should be required to rely on 
such data.\1405\
---------------------------------------------------------------------------

    \1404\ Entergy Initial Comments at 18; Louisiana Commission 
Reply Comments at 7; Mississippi Commission Reply Comments at 9.
    \1405\ Kentucky Commission Chair Chandler Reply Comments at 3.
---------------------------------------------------------------------------

c. Commission Determination
    633. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to use 
``best available data inputs'' when developing Long-Term Scenarios. As 
the Commission explained in the NOPR, by ``best available,'' we do not 
imply that there is a single ``best'' value for each data input that 
transmission providers must use, but rather that best practices will be 
used to develop each data input. We adopt, with modification, the NOPR 
proposal to define ``best available data inputs'' as data inputs that 
are timely, developed using best practices and diverse and expert 
perspectives,\1406\ and adopted via a process that satisfies the 
transmission planning principles of Order Nos. 890 and 1000.\1407\ We 
further adopt the NOPR proposal to require that best available data 
inputs also reflect the list of factors that transmission providers 
account for in their Long-Term Scenarios.\1408\ By ``reflect the list 
of factors,'' we mean the data inputs that correspond to the list of 
factors that transmission providers have determined might affect Long-
Term Transmission Needs.\1409\ We also adopt the NOPR proposal to 
require transmission providers to update, as necessary, all data inputs 
each time they reassess and revise their Long-Term Scenarios.
---------------------------------------------------------------------------

    \1406\ While we largely adopt the definition of ``best available 
data inputs'' proposed in the NOPR, we modify it to reflect the 
requirement that ``best available data inputs'' are developed using 
best practices.
    \1407\ For example, the transparency transmission planning 
principle requires transmission providers to reduce to writing and 
make available the basic methodology, criteria, and processes used 
to develop transmission plans. Transmission providers must make 
sufficient information available to enable customers and other 
stakeholders to replicate the results of transmission planning 
studies. Order No. 890, 118 FERC ] 61,119 at P 471. Order No. 1000 
applied this and other Order No. 890 transmission planning 
principles to regional transmission planning processes. Order No. 
1000, 136 FERC ] 61,051 at P 151.
    \1408\ One example of a data input dataset that would meet the 
requirement for best available data are the long-term load forecasts 
of demand that RTOs/ISOs currently use for predicting long-term 
resource adequacy. Another example of a data input dataset that 
would meet the requirement for best available data is the most 
recent data on renewable energy potential and distributed energy 
resources developed by national labs.
    \1409\ For example, a transmission provider might determine that 
corporate goals for corporations less than $20 million are too small 
to affect Long-Term Transmission Needs and not include these 
corporate goals in its Long-Term Scenarios. This transmission 
provider does not have any obligation to develop data inputs 
corresponding to these omitted corporate goals.
---------------------------------------------------------------------------

    634. Finally, in addition, we adopt the NOPR proposal to require 
that the Order Nos. 890 and 1000 transmission planning principles apply 
to the process

[[Page 49384]]

through which transmission providers determine which data inputs to use 
in their Long-Term Scenarios. Consistent with the coordination 
transmission planning principle established in Order No. 890, we also 
adopt the NOPR proposal to require transmission providers in each 
transmission planning region to give stakeholders an opportunity to 
provide timely and meaningful input during each Long-Term Regional 
Transmission Planning cycle concerning which data inputs to use in 
Long-Term Scenarios.\1410\ Also, we clarify that the right to challenge 
data inputs via dispute resolution as discussed in Order No. 890 is 
available for interested parties with respect to data inputs that 
transmission providers develop for Long-Term Regional Transmission 
Planning.\1411\
---------------------------------------------------------------------------

    \1410\ NOPR, 179 FERC ] 61,028 at P 132.
    \1411\ Order No. 890, 118 FERC ] 61,119 at PP 501-503.
---------------------------------------------------------------------------

    635. We agree, in part, with NYISO's suggestion to revise the 
wording of the NOPR proposal that required best available data to 
reflect ``the list of factors that transmission providers must 
incorporate into Long-Term Scenarios.'' \1412\ NYISO states that the 
NOPR language should be modified to ``reflect the factors that the 
public utility transmission provider considers in the scenarios.'' 
\1413\ As discussed in the Categories of Factors section of this final 
order, we explain that transmission providers need not account for a 
factor, stakeholder-identified or otherwise, if they determine that 
factor is unlikely to affect Long-Term Transmission Needs. We find that 
transmission providers must use best available data when determining 
whether each factor is likely to affect Long-Term Transmission Needs. 
Once transmission providers have determined that a factor is likely to 
affect Long-Term Transmission Needs, they must use the best available 
data when they then account for that factor in the development of Long-
Term Scenarios.
---------------------------------------------------------------------------

    \1412\ NYISO Initial Comments at 28 (citing NOPR, 179 FERC ] 
61,028 at P 131).
    \1413\ Id.
---------------------------------------------------------------------------

    636. We find that a requirement to use the best available data 
inputs is warranted to ensure that transmission providers are regularly 
updating data inputs and using timely and accurate data inputs to 
inform Long-Term Scenarios. We further find that data inputs can drive 
the results of Long-Term Regional Transmission Planning. As a result, 
we find that data inputs affect transmission providers' ability to 
identify Long-Term Transmission Needs and thus affect the ability to 
identify, evaluate, and select Long-Term Regional Transmission 
Facilities to more efficiently or cost-effectively address those needs. 
We note that many commenters share this view and support the NOPR 
proposal.\1414\
---------------------------------------------------------------------------

    \1414\ ACORE Initial Comments at 8; AEE Initial Comments at 22; 
Certain TDUs Initial Comments at 16; Clean Energy Buyers Initial 
Comments at 17-18; DC and MD Offices of People's Counsel Initial 
Comments at 14; Eversource Initial Comments at 20; Georgia 
Commission Initial Comments at 5; ISO-NE Initial Comments at 28; ITC 
Initial Comments at 12; Mississippi Commission Initial Comments at 
34-35; NARUC Initial Comments at 13-15; NRECA Initial Comments at 
36; OMS Initial Comments at 5; [Oslash]rsted Initial Comments at 7; 
Pacific Northwest State Agencies Initial Comments at 13-14; PJM 
Initial Comments at 7, 76; Policy Integrity Initial Comments at 16-
17; US DOE Initial Comments at 16-18; WATT Coalition Initial 
Comments at 7.
---------------------------------------------------------------------------

    637. We disagree with commenters asserting that the requirements 
for data inputs would be overly burdensome to transmission 
providers.\1415\ We believe that, because most transmission providers 
already endeavor to use best available data inputs to ensure credible 
results in regional transmission planning, this final order's 
requirements for data inputs will not impose an unreasonable burden 
beyond existing practices today. Further, as many commenters 
note,\1416\ any increase in transmission providers' burden from such 
requirements is outweighed by the benefits of establishing reasonable 
safeguards for accuracy and confidence in Long-Term Regional 
Transmission Planning.
---------------------------------------------------------------------------

    \1415\ Ameren Initial Comments at 14; MISO Initial Comments at 
29; PPL Initial Comments at 9-10; Utah Division of Public Utilities 
Initial Comments at 7; Xcel Initial Comments at 10.
    \1416\ See ACORE Initial Comments at 8; AEE Initial Comments at 
23; Certain TDUs Initial Comments at 16; Clean Energy Buyers Initial 
Comments at 17-18; DC and MD Offices of People's Counsel Initial 
Comments at 14; Eversource Initial Comments at 20; Georgia 
Commission Initial Comments at 5; ISO-NE Initial Comments at 28; ITC 
Initial Comments at 12; Mississippi Commission Initial Comments at 
34-35; NARUC Initial Comments at 13-15; NRECA Initial Comments at 
36; OMS Initial Comments at 5; [Oslash]rsted Initial Comments at 7; 
Pacific Northwest State Agencies Initial Comments at 13-14; PJM 
Initial Comments at 7, 76; Policy Integrity Initial Comments at 16-
17; US DOE Initial Comments at 16-18; WATT Coalition Initial 
Comments at 7.
---------------------------------------------------------------------------

    638. We disagree with commenters' arguments that the final order 
requirements for data inputs would lead to problems because 
stakeholders will delay Long-Term Regional Transmission Planning by 
contesting the data used by transmission providers.\1417\ Similarly, we 
disagree with commenters' arguments that the requirements for data 
inputs unnecessarily limit transmission providers' flexibility in 
producing data inputs.\1418\ As discussed above, this final order 
establishes requirements for data inputs used in Long-Term Scenarios 
and requires that stakeholders have an opportunity to provide timely 
and meaningful input during each Long-Term Regional Transmission 
Planning cycle concerning those data inputs. However, transmission 
providers have significant flexibility about which data inputs they use 
in Long-Term Scenarios, and no commenters have provided us with 
convincing or specific arguments that stakeholder input will undermine 
that flexibility or cause consequential delays to the Long-Term 
Regional Transmission Planning process.
---------------------------------------------------------------------------

    \1417\ MISO Initial Comments at 29; Utah Division of Public 
Utilities Initial Comments at 6; Xcel Initial Comments at 10.
    \1418\ Dominion Initial Comments at 26-27; Duke Initial Comments 
at 16-17; MISO Initial Comments at 40; MISO TOs Initial Comments at 
19; NESCOE Initial Comments at 35-36.
---------------------------------------------------------------------------

    639. We decline to adopt the suggestion of commenters to 
standardize data inputs used by transmission providers in Long-Term 
Regional Transmission Planning.\1419\ Imposing further requirements to 
enforce uniformity in data is challenging given regional variation in 
transmission planning approaches. Further, it might stifle innovation 
that would improve Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------

    \1419\ ACEG Initial Comments at 7; ACORE Initial Comments at 8-
9; GridLab Initial Comments at 23; PIOs Initial Comments at 19-20; 
Southeast PIOs Initial Comments at 47-48.
---------------------------------------------------------------------------

    640. We decline to adopt the modifications of the NOPR proposal 
suggested by certain commenters to establish specific accuracy 
standards in addition to requiring that transmission providers use best 
available data inputs.\1420\ While we agree that transmission providers 
should strive for data accuracy, including by assessing the historical 
accuracy of different data sources where appropriate, a specific 
accuracy standard would be difficult to develop and administer given 
the diversity of different data inputs.\1421\ As we explain above, 
transmission providers must use best available data inputs, which 
include forecasted data, and must develop such inputs using diverse and 
expert perspectives. They must use best practices to develop data 
inputs, and must do so in an open and transparent stakeholder process. 
Taken together, we believe that these

[[Page 49385]]

requirements will help ensure that data inputs are as accurate as 
possible, while also providing transmission providers with the 
flexibility to use best practices to develop data inputs that are 
appropriate for their transmission planning regions and to recognize 
the inherent uncertainty involved in planning transmission on a 
forward-looking basis.
---------------------------------------------------------------------------

    \1420\ ELCON Initial Comments at 13; LADWP Initial Comments at 
4; Pine Gate Initial Comments at 27-29; Vermont Electric and Vermont 
Transco Initial Comments at 3.
    \1421\ In addition, while we decline to adopt a specific 
accuracy standard that data must meet in order to be ``best 
available data,'' we note that a demonstration that a data source 
has historically proven to be relatively inaccurate would likely 
constitute evidence that such data is not best available data.
---------------------------------------------------------------------------

    641. With respect to the issue raised by PJM about revealing 
potentially confidential data to improve accuracy,\1422\ we reiterate, 
as discussed above, that consistent with Order No. 890's transparency 
transmission planning principle, transmission providers in each 
transmission planning region are required to disclose (subject to 
appropriate confidentiality protections) information and data inputs 
they use to create each Long-Term Scenario.\1423\ The Commission has 
recognized that tension exists between ensuring transparency in 
transmission planning processes and protecting confidential 
information, including commercially sensitive information.\1424\ The 
Commission has also noted that using resource-specific data that best 
reflect actual operations on the transmission system leads to more 
precise and effective transmission study results. In addition, the 
Commission has recognized that market participants who provide that 
information need to be assured that the confidential information they 
provide will be used for its intended purpose in planning the 
transmission system and will not be disclosed in a manner that harms 
them commercially. However, the Commission has found that, at the same 
time, the requirement in Order No. 890 for transmission providers to 
disclose to all customers and other stakeholders the basic methodology, 
criteria, assumptions, and data that underlie their transmission system 
plans to enable customers, other stakeholders, or an independent third-
party to replicate the results of planning studies is essential to an 
open and transparent transmission planning process.\1425\ Thus, the 
Commission has found that, without certain generator dispatch and 
economic information, for example, it becomes difficult or impossible 
to conduct meaningful load flow studies for some transmission planning 
purposes,\1426\ and the competitive playing field is tilted toward 
those who have this information and away from those who do not.\1427\
---------------------------------------------------------------------------

    \1422\ PJM Reply Comments at 22.
    \1423\ See supra Number and Development of Long-Term Scenarios 
section.
    \1424\ Sw. Power Pool, Inc., 137 FERC ] 61,227 at P 20.
    \1425\ Order No. 890, 118 FERC ] 61,119 at P 471.
    \1426\ Id. P 478.
    \1427\ Sw. Power Pool, Inc., 137 FERC ] 61,227 at P 20.
---------------------------------------------------------------------------

    642. The Commission therefore required in Order No. 890, and we 
apply that requirement to Long-Term Regional Transmission Planning in 
this final order, disclosure of the methodology, criteria, assumptions, 
data and other information that underlie transmission plans, including 
Long-Term Scenarios. We recognize that no bright line rule exists to 
determine the appropriate balance between ensuring transparency in the 
transmission planning processes and ensuring that confidential 
information is not disclosed inappropriately. Transmission providers 
may propose what they believe are appropriate confidentiality 
protections in their filings to comply with this final order, and the 
Commission will evaluate those proposals by using the established 
principles in Order No. 890, as well as precedent on existing 
confidentiality protections with respect to transmission planning that 
the Commission has previously found comply with the Order No. 890 
principles, to guide its findings on whether such protections are 
appropriate.
    643. With respect to the issue raised by ELCON and Pine Gate about 
timely data,\1428\ we decline to adopt their suggestion to define 
precisely what ``timely'' means with respect to best available data 
because we believe flexibility is warranted given the diverse regional 
transmission planning processes to which this reform will apply. That 
is, we believe that updating data inputs may require different 
timelines depending on the transmission planning region and the 
specific data input, where each input may change on a different 
timeline. However, given the five-year duration of the Long-Term 
Regional Transmission Planning cycle, and the risk of data becoming 
stale, we require transmission providers to update their data inputs at 
least once at the outset of each Long-Term Regional Transmission 
Planning cycle.
---------------------------------------------------------------------------

    \1428\ ELCON Initial Comments at 13; Pine Gate Initial Comments 
at 28-29.
---------------------------------------------------------------------------

    644. With respect to National Grid's request to clarify the 
definition of ``diverse'' in the context of the requirement that data 
inputs must be developed using diverse and expert perspectives,\1429\ 
we clarify that the term ``diverse'' specifically used in the context 
of data inputs indicates that the data inputs must represent a range of 
data within the bounds of plausibility. We believe that this 
requirement will ensure that the set of Long-Term Scenarios that are 
developed from these data inputs will represent a reasonable range of 
probable future outcomes consistent with the requirement for 
plausibility.
---------------------------------------------------------------------------

    \1429\ National Grid Initial Comments at 14.
---------------------------------------------------------------------------

8. Identification of Geographic Zones
a. NOPR Proposal
    645. In the NOPR, the Commission proposed to require that each 
transmission provider, as part of its regional transmission planning 
process, consider whether to establish geographic zones within the 
transmission planning region that have the potential for development of 
large amounts of new generation. If transmission providers within a 
transmission planning region choose to establish geographic zones, then 
the Commission proposed to require the transmission provider to: (1) 
identify, with stakeholder input, specific geographic zones within the 
transmission planning region that have the potential for development of 
large amounts of new generation; (2) assess generation developers' 
commercial interest in developing generation within the identified 
geographic zones; and (3) incorporate designated zones, and the 
identified commercial interest in each zone, into Long-Term 
Scenarios.\1430\
---------------------------------------------------------------------------

    \1430\ NOPR, 179 FERC ] 61,028 at P 145.
---------------------------------------------------------------------------

    646. The Commission preliminarily found that requiring the 
consideration and potential identification of geographic zones within 
Long-Term Scenarios assists transmission providers, transmission 
developers, and generation developers in coordinating their activities. 
The Commission stated that transmission providers would be able to 
better identify transmission needs driven by changes in the resource 
mix and demand by considering geographic zones that have the potential 
for the development of large amounts of new generation and where 
developers have already shown commercial interest. Further, the 
Commission stated that, using the information gained through the 
process described below to identify such geographic zones, transmission 
providers in each transmission planning region could then plan 
transmission facilities that would serve large concentrations of new 
generation in a more efficient or cost-effective manner.\1431\
---------------------------------------------------------------------------

    \1431\ Id. P 146.
---------------------------------------------------------------------------

    647. The Commission proposed to require, as step one of the three-
step geographic zone process, that transmission providers consider

[[Page 49386]]

whether to establish and include in the regional transmission planning 
process outlined in their OATTs the method that they will use to 
identify geographic zones within the transmission planning region. The 
Commission also proposed to require that transmission providers in each 
transmission planning region use this information to create a set of 
draft geographic zones, and that they post on their OASIS or other 
public website maps of the draft geographic zones, as well as the 
information used to create the draft geographic zones, for 
stakeholders' input.\1432\
---------------------------------------------------------------------------

    \1432\ Id. PP 147-148.
---------------------------------------------------------------------------

    648. In addition, the Commission proposed to require transmission 
providers in each transmission planning region to consider this 
stakeholder feedback and modify the draft geographic zones as 
appropriate to produce a final list of designated geographic zones 
within the transmission planning region.\1433\
---------------------------------------------------------------------------

    \1433\ The Commission noted that, while it referred to multiple 
``zones,'' subsequent to stakeholder feedback, the final list may 
contain only one designated geographic zone. Id. P 149.
---------------------------------------------------------------------------

    649. The Commission proposed to require, in step two of the three-
step geographic zone process, that transmission providers in each 
transmission planning region assess generation developers' commercial 
interest in developing generation within each designated geographic 
zone.\1434\ The Commission proposed to require, in the final step of 
the three-step geographic zone process, that transmission providers in 
each transmission planning region incorporate the information from step 
one and step two regarding the designated geographic zones into their 
Long-Term Scenarios.\1435\
---------------------------------------------------------------------------

    \1434\ Id. P 150.
    \1435\ Id. P 151.
---------------------------------------------------------------------------

b. Comments
    650. Many commenters support the Commission's proposal to require 
each transmission provider, as part of its regional transmission 
planning process, to consider whether to: (1) identify, with 
stakeholder input, specific geographic zones within the transmission 
planning region that have the potential for development of large 
amounts of new generation; (2) assess generation developers' commercial 
interest in developing generation within the identified geographic 
zones; and (3) incorporate designated zones, and the identified 
commercial interest in each zone, into Long-Term Scenarios.\1436\ 
Commenters assert that, compared to interconnection-related network 
upgrades identified on a case-by-case basis in the interconnection 
process, identifying and incorporating geographic zones into Long-Term 
Scenarios would save consumers money by identifying more efficient or 
cost-effective transmission facilities to connect areas with the 
potential for low cost generation to load centers and reduce congestion 
and generator curtailment.\1437\ Further, commenters note the success 
of previous planning efforts in ERCOT, MISO, CAISO, and ISO-NE to 
incorporate geographic zones into their transmission planning 
efforts.\1438\
---------------------------------------------------------------------------

    \1436\ Ameren Initial Comments at 15; American Municipal Power 
Initial Comments at 35; Clean Energy Associations Initial Comments 
at 13; EEI Initial Comments at 15; ENGIE Initial Comments at 4; 
Eversource Initial Comments at 21-22; Interwest Reply Comments at 4; 
ISO-NE Initial Comments at 30; ITC Initial Comments at 5, 13-17; 
Middle River Power Initial Comments at 3; MISO Initial Comments at 
30; NARUC Initial Comments at 16; Nebraska Commission Initial 
Comments at 6-7; NESCOE Initial Comments at 37; New Jersey 
Commission Initial Comments at 15; New York TOs Initial Comments at 
12; New York Transco Initial Comments at 5-6; Northwest and 
Intermountain Initial Comments at 5-6; NRECA Initial Comments at 37; 
New York Commission and NYSERDA Initial Comments at 14-15; NYISO 
Initial Comments at 29-30; [Oslash]rsted Initial Comments at 7; US 
DOE Initial Comments at 18; Western PIOs Initial Comments at 31-32.
    \1437\ See, e.g., ENGIE Initial Comments at 4; Eversource 
Initial Comments at 21-22; ITC Initial Comments at 13-17; Northwest 
and Intermountain Initial Comments at 5-6; NYISO Initial Comments at 
29-30.
    \1438\ See, e.g., ENGIE Initial Comments at 4; Eversource 
Initial Comments at 21-22.
---------------------------------------------------------------------------

    651. Some commenters highlight the importance of this proposed 
reform for remotely located renewable resources generally, and more 
specifically for offshore wind, which is constrained to lease areas 
auctioned by the Bureau of Ocean Energy Management.\1439\ For example, 
[Oslash]rsted argues that the location and approximate resource 
potential of offshore wind is well understood and the failure to 
proactively plan the necessary transmission would result in higher 
costs to ratepayers.\1440\ BP further contends that the geographic 
zones in which National Interest Electric Transmission Corridors are 
likely to be established also merit inclusion in transmission 
planning.\1441\
---------------------------------------------------------------------------

    \1439\ See, e.g., BP Initial Comments at 4, 7-8; Clean Energy 
Buyers Initial Comments at 18; New York Transco Initial Comments at 
5-6; [Oslash]rsted Initial Comments at 7-8.
    \1440\ See, e.g., [Oslash]rsted Initial Comments at 7-8.
    \1441\ BP Initial Comments at 7 (citing 16 U.S.C. 824p).
---------------------------------------------------------------------------

    652. Some commenters support the proposal but urge the Commission 
to require the identification of geographic zones and planning 
transmission to integrate generation in those zones rather than just 
requiring transmission providers to consider whether to identify 
geographic zones.\1442\ Acadia Center and CLF argue that the Commission 
should require the identification and creation of geographic zones in 
areas where the majority of states have binding greenhouse gas emission 
reduction or renewables mandates, which could result in fewer 
transmission corridors being built, thereby reducing costs, siting 
challenges, and benthic environmental impacts.\1443\ Acadia Center and 
CLF assert that, without mandatory identification and establishment of 
geographic zones, there is a significant risk that adequate 
transmission will not be built to accommodate state emission reduction 
and renewables mandates in a cost-effective or efficient way.\1444\
---------------------------------------------------------------------------

    \1442\ Acadia Center and CLF Initial Comments at 13-15; Amazon 
Initial Comments at 6-7; California Water Initial Comments at 16; 
Center for Biological Diversity Initial Comments at 13-15; City of 
New York Initial Comments at 7-8; Handy Law Initial Comments at 12; 
Invenergy Reply Comments at 9-10; SEIA Initial Comments at 11-12; 
Shell Initial Comments at 23.
    \1443\ Acadia Center and CLF Initial Comments at 13-14.
    \1444\ Id. at 13.
---------------------------------------------------------------------------

    653. In contrast, other commenters emphasize that they support the 
proposal to require transmission providers to consider identifying 
geographic zones rather than to actually identify such geographic 
zones.\1445\ Such commenters assert that providing the option to 
identify geographic zones would allow transmission providers to 
determine, with their stakeholders, what is right for their 
transmission planning region.\1446\
---------------------------------------------------------------------------

    \1445\ See, e.g., Ameren Initial Comments at 15-16; American 
Municipal Power Initial Comments at 34-35; Clean Energy Associations 
Initial Comments at 13; EEI Initial Comments at 15; ISO-NE Initial 
Comments at 30; ITC Initial Comments at 5, 13-17; MISO Initial 
Comments at 30; Nebraska Commission Initial Comments at 6-7; NESCOE 
Initial Comments at 37; NRECA Initial Comments at 37; New York 
Commission and NYSERDA Initial Comments at 14-15; NYISO Initial 
Comments at 32; PPL Initial Comments at 11; US Chamber of Commerce 
Initial Comments at 7.
    \1446\ See, e.g., EEI Initial Comments at 15; ISO-NE Initial 
Comments at 30; MISO Initial Comments at 30; New York Commission and 
NYSERDA Initial Comments at 14-15; NYISO Initial Comments at 32.
---------------------------------------------------------------------------

    654. Other commenters express concerns with the idea of 
incorporating geographic zones with the potential for large amounts of 
generation into regional transmission planning, but do not oppose the 
proposal so long as it is optional.\1447\ For example, NESCOE and

[[Page 49387]]

National Grid assert that the proposed requirements for each of the 
three steps is overly prescriptive and could be included in a final 
order as guidance, but not as a mandate.\1448\
---------------------------------------------------------------------------

    \1447\ APPA Initial Comments at 29-30; Dominion Initial Comments 
at 28-29; Georgia Commission Initial Comments at 6; Large Public 
Power Initial Comments at 22; National Grid Initial Comments at 16-
17; NESCOE Initial Comments at 38; SERTP Sponsors Initial Comments 
at 27; SPP Market Monitor Initial Comments at 11-12; TANC Initial 
Comments at 10.
    \1448\ NESCOE Initial Comments at 38; National Grid Initial 
Comments at 16.
---------------------------------------------------------------------------

    655. Several commenters urge the Commission to provide flexibility 
in any process for considering and potentially identifying geographic 
zones.\1449\ For example, Michigan Commission states that the proposed 
three-step process in the NOPR is highly prescriptive and overly 
burdensome, and instead the Commission should provide greater 
flexibility to ensure that generation siting assumptions included in 
Long-Term Scenarios are developed transparently in collaboration with 
state regulators, generation utilities, and resource planners.\1450\
---------------------------------------------------------------------------

    \1449\ See, e.g., APS Initial Comments at 5; ISO-NE Initial 
Comments at 30; Michigan Commission Initial Comments at 6; MISO 
Initial Comments at 42; MISO TOs Initial Comments at 32; NARUC 
Initial Comments at 17; New Jersey Commission Initial Comments at 
15; NYISO Initial Comments at 3-4.
    \1450\ Michigan Commission Initial Comments at 6.
---------------------------------------------------------------------------

    656. Several commenters suggest modifications to the NOPR 
proposal.\1451\ For example, Vistra contends that the NOPR proposal 
could be improved through the use of open seasons or other comparable 
tools to elicit concrete commitments from generator developers.\1452\ 
Other commenters argue that the NOPR proposal should be modified to 
involve a subscription model in which prospective generation resources 
within the zone indicate their willingness to pay for transmission to 
the zone.\1453\ Although PJM opposes the NOPR proposal, PJM argues that 
these alternative proposals offered by Vistra and New Jersey Commission 
have merit and are worthy of further dialogue.\1454\
---------------------------------------------------------------------------

    \1451\ Acadia Center and CLF Initial Comments at 15-16; 
California Energy Commission Initial Comments at 2-3; Center for 
Biological Diversity Initial Comments at 13-16; Clean Energy 
Associations Initial Comments at 24-25; Illinois Commission Initial 
Comments at 9-11; Large Public Power Initial Comments at 26; 
Microgrid Resources Coalition Initial Comments at 4-6; New Jersey 
Commission Initial Comments at 16-17; Vistra Initial Comments at 24.
    \1452\ Vistra Initial Comments at 24.
    \1453\ Clean Energy Associations Initial Comments at 24-25; 
Large Public Power Initial Comments at 26; New Jersey Commission 
Initial Comments at 16-17.
    \1454\ PJM Reply Comments at 29-30, 31-32.
---------------------------------------------------------------------------

    657. Regarding the specific steps in the NOPR proposal for 
identifying geographic zones, several commenters support the proposal 
to provide all stakeholders, including relevant Federal and state 
siting authorities, with a meaningful opportunity to provide input on 
the draft geographic zones.\1455\ Other commenters, however, assert 
that the Commission should provide a clearer role for states and other 
stakeholders to participate earlier in the process of identifying 
geographic zones.\1456\
---------------------------------------------------------------------------

    \1455\ ISO/RTO Council Initial Comments at 8; NARUC Initial 
Comments at 16-17; National Grid Initial Comments at 17; Nebraska 
Commission Initial Comments at 7; SEIA Initial Comments at 12-13; 
Shell Initial Comments at 25.
    \1456\ Acadia Center and CLF Initial Comments at 12-13; AEE 
Initial Comments at 24-25; Amazon Initial Comments at 7; CAISO 
Initial Comments at 4-5, 28-29, 31; DC and MD Offices of People's 
Counsel Initial Comments at 15-16; Interwest Initial Comments at 9; 
ISO-NE Initial Comments at 29; National Grid Initial Comments at 17-
18; NESCOE Initial Comments at 38-39; Nevada Commission Initial 
Comments at 9-10; SERTP Sponsors Initial Comments at 27.
---------------------------------------------------------------------------

    658. Some commenters argue that the NOPR proposal regarding what 
information transmission providers should use to gauge commercial 
interest in geographic zones is overly prescriptive and that the 
information would be too speculative to be an accurate indicator of 
commercial interest.\1457\ Several commenters urge the Commission to 
increase the transparency of the NOPR proposal.\1458\ For example, US 
DOE recommends that the Commission specify minimum standards for 
reporting the attributes of each geographic zone.\1459\
---------------------------------------------------------------------------

    \1457\ See, e.g., Middle River Power Initial Comments at 3; MISO 
Initial Comments at 43; PJM Initial Comments at 84.
    \1458\ Amazon Initial Comments at 8; Shell Initial Comments at 
23-24; US DOE Initial Comments at 24-25
    \1459\ US DOE Initial Comments at 20.
---------------------------------------------------------------------------

    659. Several commenters oppose the proposal to require transmission 
providers to consider whether to identify geographic zones with the 
potential for large amounts of generation.\1460\ For example, APS 
argues that the proposal may not be appropriate due to the speculative 
nature of the identification of geographic zones and the long-term 
nature of planning and building transmission infrastructure.\1461\ 
Idaho Power is concerned that the NOPR proposal will create a 
significant level of work for transmission providers that would 
outweigh the minor benefits developers would receive from the 
data.\1462\
---------------------------------------------------------------------------

    \1460\ APS Initial Comments at 5-7; Arizona Commission Initial 
Comments at 8; CAISO Initial Comments at 27-28; Consumer 
Organizations Initial Comments at 3-7; Duke Initial Comments at 4, 
18-19; Idaho Power Initial Comments at 5; Indicated PJM TOs Initial 
Comments at 3-4, 12-13; ISO/RTO Council Initial Comments at 7; LADWP 
Initial Comments at 4; Louisiana Commission Initial Comments at 24-
25; Michigan Commission Initial Comments at 5-6; Microgrid Resources 
Initial Comments at 5; North Carolina Commission and Staff Initial 
Comments at 8-10; North Dakota Commission Initial Comments at 4-5; 
Ohio Commission Federal Advocate Initial Comments at 7-8.
    \1461\ APS Initial Comments at 6-7.
    \1462\ Idaho Power Initial Comments at 5.
---------------------------------------------------------------------------

    660. PJM opposes the NOPR proposal, which it describes as an 
arbitrary and inflexible process that fails to account for regional 
differences and that will require transmission providers to draw lines 
on a map and commit to these areas for 20 years.\1463\ PJM states that 
the information from the geographic zones will be poor compared to 
information in the marketplace, including nearer term decisions of 
interconnection customers.\1464\ PJM states that an alternative, more 
case-specific flexible approach that builds on and is better 
synchronized with the transmission provider's interconnection queue 
process and market developments, and accommodates topologies as diverse 
as those in PJM, is a better solution.\1465\ For example, PJM suggests 
that the PJM State Agreement Approach is a better way to facilitate 
clusters of renewable energy interconnections by finding states that 
are willing to sponsor the new transmission to help fulfill a renewable 
energy policy.\1466\
---------------------------------------------------------------------------

    \1463\ PJM Initial Comments at 77-78.
    \1464\ Id. at 77.
    \1465\ Id. at 7.
    \1466\ Id. at 79-82 (citing PJM Operating Agreement, Schedule 6, 
section 1.5.9).
---------------------------------------------------------------------------

    661. Several state commissions express concerns that the NOPR 
proposal would give undue preference to certain kinds of 
resources.\1467\ For example, North Dakota Commission argues that the 
NOPR proposal would bias transmission planning towards one type of 
generation, encourage speculative build-out of transmission, and 
prevent visibility into the cost of other generation/transmission 
combinations, which will result in under-utilized transmission and 
additional costs to ratepayers with little benefit.\1468\
---------------------------------------------------------------------------

    \1467\ Arizona Commission Initial Comments at 8; Louisiana 
Commission Initial Comments at 24-25; Louisiana Commission Reply 
Comments at 11-12; Michigan Commission Initial Comments at 5-6; 
North Carolina Commission and Staff Initial Comments at 10-13; North 
Dakota Commission Initial Comments at 4; Ohio Commission Federal 
Advocate Initial Comments at 7-8; Pennsylvania Commission Initial 
Comments at 7-8.
    \1468\ North Dakota Commission Initial Comments at 4.
---------------------------------------------------------------------------

    662. North Carolina Commission and Staff assert that the NOPR 
proposal is an unwarranted intrusion into state jurisdiction over 
generation and fails to acknowledge state authority over utility 
generation, resource portfolios, and

[[Page 49388]]

integrated resource planning.\1469\ Similarly, Ohio Commission Federal 
Advocate asserts that the NOPR proposal exceeds the Commission's 
authority and interferes with Ohio's ability to maintain its 
competitive retail electric service law.\1470\ Mississippi Commission 
states that decisions to develop such zones within a state should be 
left to the state.\1471\ Pennsylvania Commission argues that the 
geographic zones used for Long-Term Scenarios could frustrate a state's 
legitimate policy choices in establishing, for example, economic 
development zones designed to encourage developers to site generation 
in specific areas, by favoring another state's policy choices.\1472\ 
TAPS opposes any requirement to undertake a process to consider and 
identify remote geographic zones where state or local laws require 
local generating resources rather than remote resources.\1473\
---------------------------------------------------------------------------

    \1469\ North Carolina Commission and Staff Initial Comments at 
8.
    \1470\ Ohio Commission Federal Advocate Initial Comments at 7 
(quoting Ohio Commission Federal Advocate ANOPR Comments at 8).
    \1471\ Mississippi Commission Reply Comments at 10.
    \1472\ Pennsylvania Commission Initial Comments at 7-8.
    \1473\ TAPS Initial Comments 9-10.
---------------------------------------------------------------------------

    663. Many commenters argue that the NOPR proposal would be 
duplicative of, or would interfere with, existing processes.\1474\ AEE 
states that the consideration of geography in developing long-term 
regional transmission plans should occur as a natural outgrowth of more 
effective regional transmission planning and that a specific 
requirement to identify geographic zones could have unintended 
consequences.\1475\ AEE further asserts that some of the factors that 
the NOPR proposes to require transmission providers to incorporate in 
their Long-Term Scenarios inherently require them to consider what 
geographic areas are ripe for low-cost generation development but are 
isolated or otherwise transmission constrained.\1476\ Similarly, 
Indicated PJM TOs argue that it is unnecessary to require the 
identification of geographic zones in Long-Term Regional Transmission 
Planning because transmission providers necessarily will rely on 
driving factors (e.g., public policy goals) that will determine where 
renewable resources will be developed.\1477\ According to Duke, the 
categories of factors proposed in the NOPR already capture generator 
interconnections, so it is unclear what this additional process will 
add.\1478\
---------------------------------------------------------------------------

    \1474\ AEE Initial Comments at 8; APS Initial Comments at 5; 
CAISO Initial Comments at 4-5; Duke Initial Comments at 18-19; 
Illinois Commission Initial Comments at 9-11; Indicated PJM TOs 
Initial Comments at 12; ISO-NE Initial Comments at 30; ISO/RTO 
Council Initial Comments at 7; MISO TOs Initial Comments at 32; 
Mississippi Commission Reply Comments at 10; Nebraska Commission 
Initial Comments at 6; NESCOE Initial Comments at 37; Nevada 
Commission Initial Comments at 10; New York TOs Initial Comments at 
12; NYISO Initial Comments at 33; SPP Initial Comments at 12-13; 
TAPS Initial Comments 8-10; Xcel Initial Comments at 10-11.
    \1475\ AEE Initial Comments at 8.
    \1476\ Id. at 23-24.
    \1477\ Indicated PJM TOs Initial Comments at 12.
    \1478\ Duke Initial Comments at 18.
---------------------------------------------------------------------------

    664. Several commenters argue that some transmission planning 
processes already incorporate the identification of geographic zones, 
and those existing processes should be allowed to continue.\1479\ ISO-
NE claims that transmission providers' planning constructs may already 
include rules that allow for assessing and identifying geographic zones 
with potential for high renewable development, rendering a separate 
process redundant or unnecessary.\1480\ SPP states that the NOPR 
proposal would duplicate SPP's current process to some extent and that 
it would not be practical to do both.\1481\ Similarly, CAISO argues 
that the NOPR proposal is overly prescriptive and would interfere with 
California's existing processes, which are working effectively.\1482\ 
New York TOs note that New York's transmission planning processes 
already include the evaluation of geographic zones expected to see 
significant growth in generation or changes in load and incorporate 
state involvement.\1483\ Mississippi Commission asserts that MISO 
already considers geographic zones for new generation.\1484\
---------------------------------------------------------------------------

    \1479\ See, e.g., CAISO Initial Comments at 27-33; ISO-NE 
Initial Comments at 30; MISO TOs Initial Comments at 32; Nebraska 
Commission Initial Comments at 6; NESCOE Initial Comments at 37; 
Nevada Commission Initial Comments at 10; New York TOs Initial 
Comments at 12; NYISO Initial Comments at 33; SPP Initial Comments 
at 12-13.
    \1480\ ISO-NE Initial Comments at 30.
    \1481\ SPP Initial Comments at 12-13.
    \1482\ CAISO Initial Comments at 4-5, 27-33.
    \1483\ New York TOs Initial Comments at 12.
    \1484\ Mississippi Commission Reply Comments at 10.
---------------------------------------------------------------------------

c. Commission Determination
    665. We decline to adopt the proposed requirement that each 
transmission provider, as part of its regional transmission planning 
process, consider whether to establish geographic zones within the 
transmission planning region that have the potential for development of 
large amounts of new generation. We are persuaded by commenters that 
finalizing and requiring the NOPR proposal is not warranted at this 
time. Further, given the other requirements in this final order, such 
as the requirement for transmission providers to plan for factors 
affecting supply and demand, we agree with commenters that adopting 
this proposed requirement is not necessary at this time to ensure that 
Long-Term Regional Transmission Planning ensures just and reasonable 
rates. We also agree with commenters that the prescriptive nature of 
the proposed three-step process could unintentionally impede existing 
efforts to incorporate geographic zones into regional transmission 
planning.
    666. Although we are not adopting the NOPR proposal, we encourage 
transmission providers to consider geographic zones that have the 
potential for development of large amounts of new generation as part of 
their regional transmission planning process. As such, transmission 
providers in a transmission planning region may propose to identify 
geographic zones as part of Long-Term Regional Transmission Planning on 
compliance with this final order, provided that they demonstrate that 
their process for identifying such geographic zones is consistent with 
or superior to the Long-Term Regional Transmission Planning 
requirements established herein.

D. Evaluation of the Benefits of Regional Transmission Facilities

    667. In this final order, we require transmission providers, as 
part of Long-Term Regional Transmission Planning, to measure seven 
specified benefits that were enumerated in the NOPR (``set of seven 
required benefits'' or ``required benefits'') in each Long-Term 
Scenario. We also allow transmission providers to propose on compliance 
to measure additional benefits as part of Long-Term Regional 
Transmission Planning. In addition, we require transmission providers 
to use those measured benefits when evaluating Long-Term Regional 
Transmission Facilities to determine whether they more efficiently or 
cost-effectively address Long-Term Transmission Needs.\1485\
---------------------------------------------------------------------------

    \1485\ As discussed in the Development of Long-Term Scenarios 
section supra, transmission providers must also use these benefits 
to inform their identification of Long-Term Transmission Needs.
---------------------------------------------------------------------------

    668. This section of the final order discusses the requirements 
that we adopt governing transmission providers' measurement and use of 
benefits in Long-Term Regional Transmission Planning. Specifically, we 
discuss: (1) the requirement to use a set of seven required benefits; 
(2) the required benefits, themselves; (3) the requirement

[[Page 49389]]

to include a general description of how transmission providers will 
measure each of the benefits that the final order requires, as well as 
any additional benefits that they may propose, in their OATTs; (4) the 
requirements related to the minimum time horizon over which 
transmission providers must calculate the benefits of Long-Term 
Regional Transmission Facilities; (5) the evaluation of the benefits of 
portfolios of Long-Term Regional Transmission Facilities; and (6) other 
issues related to benefits.
1. Requirement for Transmission Providers To Use a Set of Seven 
Required Benefits
a. NOPR Proposal
    669. In the NOPR, the Commission proposed a list of benefits that 
transmission providers in each transmission planning region may 
consider in Long-Term Regional Transmission Planning and cost 
allocation processes, which included: (1) avoided or deferred 
reliability transmission projects and aging infrastructure replacement; 
(2) either reduced loss of load probability or reduced planning reserve 
margin; (3) production cost savings; (4) reduced transmission energy 
losses; (5) reduced congestion due to transmission outages; (6) 
mitigation of extreme events and system contingencies; (7) mitigation 
of weather and load uncertainty; (8) capacity cost benefits from 
reduced peak energy losses; (9) deferred generation capacity 
investments; (10) access to lower-cost generation; (11) increased 
competition; and (12) increased market liquidity.\1486\ The NOPR 
provided a description of each of these benefits categories as well as 
a method to calculate benefits in each category.\1487\
---------------------------------------------------------------------------

    \1486\ NOPR, 179 FERC ] 61,028 at P 185. As more fully described 
below, the Commission is making modifications to the list of 
benefits in this final order. Therefore, we clarify for the reader 
how we refer to each of those benefits in this section. We refer to 
benefits 1-6 as ``Benefit 1,'' ``Benefit 2,'' etc. We refer to 
Benefit 7, ``mitigation of weather and load uncertainty'' as NOPR 
Benefit 7. We refer to ``(8) capacity cost benefits from reduced 
peak energy losses'' as ``NOPR Benefit 8'', ``Final Order Benefit 
7'', and ``Benefit 7''. We refer to benefits 9-12 as ``Benefit 9,'' 
Benefit 10,'' etc.
    \1487\ Id. PP 189-225.
---------------------------------------------------------------------------

    670. The Commission explained that it was not proposing to make the 
list of potential benefits mandatory or exhaustive and that 
transmission providers would have flexibility to propose which benefits 
to use as part of their Long-Term Regional Transmission Planning.\1488\
---------------------------------------------------------------------------

    \1488\ Id. P 184.
---------------------------------------------------------------------------

    671. The 12 potential benefits described in the NOPR are:

------------------------------------------------------------------------
      Number               Benefit                  Description
------------------------------------------------------------------------
1.................  Avoided or deferred   Reduced costs of avoided or
                     reliability           delayed transmission
                     transmission          investment otherwise required
                     facilities and        to address reliability needs
                     aging transmission    or replace aging transmission
                     infrastructure        facilities.
                     replacement.
2a................  Reduced loss of load  Reduced frequency of loss of
                     probability [OR       load events by providing
                     next benefit].        additional pathways for
                                           connecting generation
                                           resources with load (if
                                           planning reserve margin is
                                           constant), resulting in
                                           benefit of reduced expected
                                           unserved energy by customer
                                           value of lost load.
2b................  Reduced planning      While holding loss of load
                     reserve margin [OR    probabilities constant,
                     prior benefit].       system operators can reduce
                                           their resource adequacy
                                           requirements (i.e., planning
                                           reserve margins), resulting
                                           in a benefit of reduced
                                           capital cost of generation
                                           needed to meet resource
                                           adequacy requirements.
3.................  Production cost       Reduction in production costs,
                     savings.              including savings in fuel and
                                           other variable operating
                                           costs of power generation,
                                           that are realized when
                                           transmission facilities allow
                                           for the increased dispatch of
                                           suppliers that have lower
                                           incremental costs of
                                           production, displacing higher-
                                           cost supplies; also,
                                           reduction in market prices as
                                           lower-cost suppliers set
                                           market clearing prices; when
                                           adjusted to account for
                                           purchases and sales outside
                                           the region, called adjusted
                                           production cost savings.
4.................  Reduced transmission  Reduced energy losses incurred
                     energy losses.        in transmittal of power from
                                           generation to loads, thereby
                                           reducing total energy
                                           necessary to meet demand.
5.................  Reduced congestion    Reduced production costs
                     due to transmission   during transmission outages
                     outages.              that significantly increase
                                           transmission congestion.
6.................  Mitigation of         Reduced production costs
                     extreme events and    during extreme events, such
                     system                as unusual weather
                     contingencies.        conditions, fuel shortages,
                                           and multiple or sustained
                                           generation and transmission
                                           outages, through more robust
                                           transmission system reducing
                                           high-cost generation and
                                           emergency procurements
                                           necessary to support the
                                           system.
7.................  Mitigation of         Reduced production costs
                     weather and load      during higher than normal
                     uncertainty.          load conditions or
                                           significant shifts in
                                           regional weather patterns.
8.................  Capacity cost         Reduced energy losses during
                     benefits from         peak load reduces generation
                     reduced peak energy   capacity investment needed to
                     losses.               meet the peak load and
                                           transmission losses.
9.................  Deferred generation   Reduced costs of needed
                     capacity              generation capacity
                     investments.          investments through expanded
                                           import capability into
                                           resource-constrained areas.
10................  Access to lower-cost  Reduced total cost of
                     generation.           generation due to ability to
                                           locate units in a more
                                           economically efficient
                                           location (e.g., low
                                           permitting costs, low-cost
                                           sites on which plants can be
                                           built, access to existing
                                           infrastructure, low labor
                                           costs, low fuel costs, access
                                           to valuable natural
                                           resources, locations with
                                           high-quality renewable energy
                                           resources).
11................  Increased             Reduced bid prices in
                     competition.          wholesale electricity markets
                                           due to increased competition
                                           among generators and reduced
                                           overall market concentration/
                                           market power.
12................  Increased market      Reduced transaction costs
                     liquidity.            (e.g., bid-ask spreads) of
                                           bilateral transactions,
                                           increased price transparency,
                                           increased efficiency of risk
                                           management, improved
                                           contracting, and better
                                           clarity for Long-Term
                                           Regional Transmission
                                           Planning and investment
                                           decisions through increased
                                           number of buyers and sellers
                                           able to transact with each
                                           other as a result of
                                           transmission expansion.
------------------------------------------------------------------------


[[Page 49390]]

    672. While the Commission did not propose to require use of any 
specific benefits in the NOPR, it sought comment on whether 
transmission providers should be required to use some or all of the 
potential benefits described in the NOPR as a minimum set of benefits 
for their Long-Term Regional Transmission Planning process.\1489\
---------------------------------------------------------------------------

    \1489\ Id. P 188.
---------------------------------------------------------------------------

b. Comments
    673. Many commenters support the NOPR approach of providing 
illustrative benefits rather than mandating the use of certain 
benefits.\1490\ Indicated PJM TOs contend that the NOPR proposal would 
advance the Commission's goals better than a more prescriptive 
proposal.\1491\ SERTP Sponsors and Southern argue that the Commission 
should not impose a minimum set of benefits because existing state-
regulated integrated resource planning processes adequately examine 
some of the proposed benefits, and that some of the proposed benefits 
would harm existing integrated resource planning processes or are only 
appropriate for RTO/ISO regions.\1492\ LADWP asserts that some or all 
of the identified benefits will be considered as part of the normal 
transmission planning process without a requirement.\1493\ Dominion 
asserts that the question arises of who will judge whether a 
transmission project addresses the NOPR's proposed list of benefits and 
that such debates could be time-consuming and further delay projects 
and drive up costs.\1494\ Dominion states that transmission providers 
should be permitted to identify the benefits that they will consider in 
conducting Long-Term Regional Transmission Planning but retain 
flexibility to apply the specific benefits that are most appropriate 
given each transmission provider's individual circumstances.\1495\
---------------------------------------------------------------------------

    \1490\ Ameren Initial Comments at 19; APPA Initial Comments at 
31; APS Initial Comments at 9; Dominion Initial Comments at 34; Duke 
Initial Comments at 22-23; EEI Initial Comments at 19-20; Eversource 
Initial Comments at 25; Georgia Commission Initial Comments at 6-7; 
Idaho Commission Initial Comments at 4; Idaho Power Initial Comments 
at 7-8; Illinois Commission Initial Comments at 13-14; Indiana 
Commission Initial Comments at 6; Indicated PJM TOs Initial Comments 
at 17; ISO-NE Initial Comments at 5, 33-34; LADWP Initial Comments 
at 5; Louisiana Commission Reply Comments at 9-10; Michigan 
Commission Initial Comments at 6; MISO Initial Comments at 9, 51-52; 
Mississippi Commission Initial Comments at 36; NARUC Initial 
Comments at 20-21; National Grid Initial Comments at 26; North 
Carolina Commission and Staff Initial Comments at 7; Nebraska 
Commission Initial Comments at 7; New York TOs Initial Comments at 
15; NRECA Initial Comments at 43-45; NYISO Initial Comments at 9, 
37-38; OMS Initial Comments at 7-8; Pacific Northwest Utilities 
Initial Comments at 8; Pennsylvania Commission Initial Comments at 
9; SERTP Sponsors Initial Comments 29-30; Southern Initial Comments 
at 24; TANC Initial Comments at 16; TAPS Initial Comments at 3, 14; 
US Chamber of Commerce Initial Comments at 7; Vermont State Entities 
Initial Comments at 7; Virginia Commission Staff Initial Comments at 
5; Vistra Initial Comments at 15; Xcel Initial Comments at 12.
    \1491\ Indicated PJM TOs Initial Comments at 17.
    \1492\ SERTP Sponsors Initial Comments 29-30; Southern Initial 
Comments at 25-27.
    \1493\ LADWP Initial Comments at 5.
    \1494\ Dominion Initial Comments at 34.
    \1495\ Id.
---------------------------------------------------------------------------

    674. TAPS supports requiring transmission providers to evaluate 
production cost modeling but opposes requiring transmission providers 
to consider any other benefits in order to allow for regional 
flexibility.\1496\ Northwest and Intermountain and NYISO ask that the 
final order confirm that the 12 illustrative benefits are neither 
mandatory nor exhaustive.\1497\ California Municipal Utilities state 
that requiring the consideration of all 12 benefits proposed in the 
NOPR would misapprehend the state and local nature of resource 
portfolio planning and fail to account for the costs of such 
prescriptive measures and the need for consumer protection measures to 
guard against speculative transmission projects.\1498\
---------------------------------------------------------------------------

    \1496\ TAPS Initial Comments at 3, 14.
    \1497\ Northwest and Intermountain Initial Comments at 16; NYISO 
Initial Comments at 39.
    \1498\ California Municipal Utilities Reply Comments at 5-6.
---------------------------------------------------------------------------

    675. OMS urges the Commission to clarify that transmission 
providers will have sufficient flexibility to use different sets of 
benefit metrics in different transmission planning cycles.\1499\ 
Relatedly, Xcel states that for any specific study, portfolio, or 
transmission project, all benefits do not need to be calculated and, in 
some cases, calculating additional benefits may be costly, time 
consuming, and contentious and provide little added value.\1500\
---------------------------------------------------------------------------

    \1499\ OMS Initial Comments at 8.
    \1500\ Xcel Initial Comments at 12.
---------------------------------------------------------------------------

    676. Many of the commenters that support an illustrative approach 
emphasize the importance of regional flexibility.\1501\ US Chamber of 
Commerce states that flexibility will allow transmission planning 
regions to consider benefits that best align with their respective 
market structures.\1502\ MISO states that, without flexibility, it may 
not be able to move forward with the transmission projects of the 
greatest benefit and value to MISO and its stakeholders, noting that 
benefits used to meet criteria for its recent Long-Range Transmission 
Planning projects are not specified in its OATT.\1503\ MISO, NYISO, and 
SPP argue that transmission providers and their stakeholders ought to 
determine what the benefits evaluated for specific transmission 
projects or sets of projects should be.\1504\ NARUC, New York TOs, and 
Pennsylvania Commission agree, emphasizing consultation with 
states.\1505\
---------------------------------------------------------------------------

    \1501\ Ameren Reply Comments at 16-17 (citing MISO Initial 
Comments at 9); APS Initial Comments at 9; Dominion Initial Comments 
at 34; Duke Initial Comments at 22-23; EEI Initial Comments at 19-
20; Eversource Initial Comments at 25; Entergy Reply Comments at 3; 
Idaho Commission Initial Comments at 4; Idaho Power Initial Comments 
at 7-8; Illinois Commission Initial Comments at 13-14; Indiana 
Commission Initial Comments at 6-7; Large Public Power Initial 
Comments at 28; ISO-NE Initial Comments at 33-34; Massachusetts 
Attorney General Initial Comments at 12, 15; MISO Initial Comments 
at 9; Mississippi Commission Initial Comments at 35-36; NARUC 
Initial Comments at 20-21; National Grid Initial Comments at 26; 
Nebraska Commission Initial Comments at 7; New York TOs Initial 
Comments at 15; Pennsylvania Commission Initial Comments at 9; SPP 
Initial Comments at 18; US Chamber of Commerce Initial Comments at 
7; Vistra Initial Comments at 15; Xcel Initial Comments at 12.
    \1502\ US Chamber of Commerce Initial Comments at 7.
    \1503\ MISO Initial Comments at 9.
    \1504\ MISO Initial Comments at 9-10; NYISO Initial Comments at 
39; SPP Initial Comments at 18.
    \1505\ NARUC Initial Comments at 21-22; New York TOs Initial 
Comments at 15; Pennsylvania Commission Initial Comments at 9.
---------------------------------------------------------------------------

    677. Entergy urges the Commission to affirm its commitment to 
providing transmission planning regions with flexibility in terms of 
how they identify, consider, and calculate benefits. Entergy further 
urges the Commission to adopt guiding principles to aid transmission 
providers in identifying their own benefits.\1506\ Entergy argues that 
the Commission should recognize that not all benefits are appropriate 
in all jurisdictions and that some states will want to prioritize 
transmission projects that reduce customer bills.\1507\
---------------------------------------------------------------------------

    \1506\ Entergy Initial Comments at 21.
    \1507\ Id.
---------------------------------------------------------------------------

    678. SPP argues that how and when transmission benefits are 
calculated and incorporated in any regional transmission planning 
assessment should be at the discretion of each transmission provider 
and its stakeholders. Specifically, SPP argues that the effort required 
to incorporate additional benefit metrics into its current transmission 
planning process cannot be accommodated within its current process 
timeline.\1508\
---------------------------------------------------------------------------

    \1508\ SPP Initial Comments at 18.
---------------------------------------------------------------------------

    679. Mississippi Commission argues that any required benefits would 
be arbitrary and some metrics may not be applicable at times.\1509\ 
National Grid

[[Page 49391]]

argues that flexibility will allow transmission providers to adapt more 
readily to changes in state policy drivers, prevent the requirements of 
Long-Term Regional Transmission Planning from becoming dated, and allow 
benefits and cost allocation discussions to be synchronized.\1510\ Duke 
contends that allowing regional flexibility may help to mitigate some 
disputes within transmission planning regions over what benefits to 
measure and how to measure them. Moreover, Duke argues that regional 
flexibility is critical to ensuring that each benefit metric used is 
relevant and calculable for each transmission planning region, 
particularly given differences between RTO/ISO and non-RTO/ISO regions. 
Duke contends that regions must not be forced into accepting and 
implementing benefits metrics that they have not vetted or on which 
they do not have consensus.\1511\
---------------------------------------------------------------------------

    \1509\ Mississippi Commission Initial Comments at 35-36.
    \1510\ National Grid Initial Comments at 26-27.
    \1511\ Duke Initial Comments at 22-23.
---------------------------------------------------------------------------

    680. MISO, while stating its preference for flexibility in 
identifying benefits, also states that it would support identifying and 
using a general set of benefit metrics that capture key areas of 
transmission value, such as reliability and resilience, production cost 
savings, and avoided resource and/or transmission investment, assuming 
that each transmission planning region may determine how to calculate 
each metric and how each applies during a transmission assessment, as 
well as allowing for different benefit metrics not part of that 
``general set'' to be applied when warranted.\1512\
---------------------------------------------------------------------------

    \1512\ MISO Initial Comments at 9.
---------------------------------------------------------------------------

    681. Some commenters offer support for the illustrative benefits 
without suggesting that they be required.\1513\ PG&E states that 
CAISO's transmission planning process currently evaluates several of 
the same benefits, either routinely or on a case-specific basis, and 
that PG&E supports the continued flexibility the NOPR envisions for 
RTO/ISOs.\1514\
---------------------------------------------------------------------------

    \1513\ Nevada Commission Initial Comments at 10-11; Pattern 
Energy Initial Comments at 14; PG&E Initial Comments at 7.
    \1514\ PG&E Initial Comments at 7.
---------------------------------------------------------------------------

    682. In contrast, many commenters support the Commission requiring 
that transmission providers consider a minimum list of benefits for 
Long-Term Regional Transmission Planning.\1515\ PIOs argue that most of 
the benefits outlined in the NOPR have broad support, even among those 
commenters that do not support a Commission requirement to consider a 
minimum set of benefits.\1516\
---------------------------------------------------------------------------

    \1515\ ACORE Initial Comments at 12; ACORE Reply Comments at 6; 
ACORE Supplemental Comments at 1; AEE Initial Comments at 8, 25; AEP 
Initial Comments at 6, 23-25; Breakthrough Energy Initial Comments 
at 4, 21-22; Business Council for Sustainable Energy Initial 
Comments at 2, 5; Certain TDUs Initial Comments at 11-12; Clean 
Energy Buyers Reply Comments at 8-9; Concerned Scientists Reply 
Comments at 7-10; Cypress Creek Reply Comments at 7-8; DC and MD 
Offices of People's Counsels Reply Comments at 3, 7-8; ELCON Initial 
Comments at 15; Enel Initial Comments at 3; Environmental Groups 
Supplemental Comments at 2; Environmental Legislators Caucus 
Supplemental Comments at 1; Exelon Initial Comments at 16: Grid 
United Initial Comments at 2; Handy Law Initial Comments at 8; US 
House Republicans Supplemental Comments at 1; Indicated US Senators 
and Representatives Initial Comments at 2; ITC Initial Comments at 
5, 18-22; Interwest Initial Comments at 12; Interwest Reply Comments 
at 6-7; Joint Consumer Advocates Initial Comments at 11; Kentucky 
Commission Chair Chandler Reply Comments at 7; Minnesota State 
Entities Initial Comments at 6; New England for Offshore Wind 
Initial Comments at 5; New Jersey Commission Initial Comments at 11-
14; Pacific Northwest State Agencies Initial Comments at 16-17; PIOs 
Initial Comments at 27-28; PIOs Reply Comments at 7-8; Policy 
Integrity Initial Comments at 27; Policy Integrity Supplemental 
Comments at 4; R Street Initial Comments at 9; RMI Initial Comments 
at 1; RMI Supplemental Comments at 2; SEIA Initial Comments at 16-
17; Southeast PIOs Initial Comments at 50; Southeast PIOs Reply 
Comments at 27-28; US DOE Initial Comments at 30-33; US Senator 
Schumer Supplemental Comments at 1-2; US Senator Whitehouse 
Supplemental Comments at 2; US Senators Supplemental Comments at 2; 
WATT Coalition Initial Comments at 7.
    \1516\ PIOs Initial Comments at 26, 41; PIOs Reply Comments at 
7-8.
---------------------------------------------------------------------------

    683. Clean Energy Associations and US Senator Schumer assert that 
the failure to adopt a minimum list of benefits risks skewing benefit-
to-cost ratios against developing necessary transmission because all 
costs would be included in an evaluation but not all benefits would 
also be included.\1517\ Clean Energy Associations further state that 
failing to require the adoption of a minimum list of benefits could 
lead to higher costs in the long-term, as larger transmission projects 
with net benefits would not be selected.\1518\ Finally, Clean Energy 
Associations argue that, without a minimum list of benefits, 
significant disparities in regional identification of potential Long-
Term Regional Transmission Facilities could have harmful spillover 
effects on coordinated activities such as interregional transmission 
coordination and affected systems studies.\1519\
---------------------------------------------------------------------------

    \1517\ Clean Energy Associations Initial Comments at 19; US 
Senator Schumer Supplemental Comments at 1-2.
    \1518\ Clean Energy Associations Initial Comments at 19-20 
(citing The Brattle Group, Transmission Planning and Benefit-Cost 
Analyses, at 26 (Apr. 2021)).
    \1519\ Clean Energy Associations Initial Comments at 19.
---------------------------------------------------------------------------

    684. Michigan State Entities argue that there must be some 
prescribed list of benefits, asserting that it would not force 
differently situated transmission providers to implement any specific 
policy, but instead would ensure that they take a ``fair look'' at 
transmission planning policies, including those using storage, that 
could produce substantial savings for customers.\1520\ Interwest 
contends that a standard and comprehensive framework for evaluating 
benefits is necessary because an ad hoc approach could result in 
inconsistencies and an incomplete picture of a transmission project's 
potential benefits.\1521\
---------------------------------------------------------------------------

    \1520\ Michigan State Entities Reply Comments at 2.
    \1521\ Interwest Reply Comments at 7.
---------------------------------------------------------------------------

    685. Southeast PIOs urge the Commission to prescribe a set of 
benefits for use in benefit-cost analyses, starting with the entire 
list of benefits in the NOPR. Southeast PIOs argue that the 
transmission providers in the Southeast exploited the flexibility in 
establishing and assessing benefits that the Commission provided in 
Order No. 1000 to implement a straight cost comparison.\1522\ Southeast 
PIOs further state that minimum standards are necessary to produce 
actionable results; otherwise, Long-Term Regional Transmission Planning 
will devolve into a ``box-checking exercise.'' \1523\ SREA argues that 
the Commission needs to set clear guidelines around benefit metrics to 
avoid opponents to the NOPR finding easy work-arounds.\1524\
---------------------------------------------------------------------------

    \1522\ Southeast PIOs Initial Comments at 50.
    \1523\ Southeast PIOs Reply Comments at 23, 27.
    \1524\ SREA Reply Comments at 26 (citing Louisiana Commission 
Initial Comments at 17; Mississippi Commission Initial Comments at 
11; Southern Initial Comments at 12).
---------------------------------------------------------------------------

    686. Similarly, R Street states that transmission providers should 
be required to use a minimum set of benefits because they lack the 
incentive to account for all system-wide benefits. R Street argues that 
proposing a benefits list for transmission providers to consider is the 
status quo and the Commission should expect little change without a 
benefits requirement.\1525\ Concerned Scientists agree, claiming that 
the experience with Order No. 1000 implementation and the descriptions 
in the comments in response to the NOPR illustrate how transmission 
planning processes are resistant to changes when the Commission 
provides latitude for discretion.\1526\ Concerned Scientists further 
contend that the discretion provided in the NOPR will allow a pattern 
of undue discrimination and unjust and unreasonable rates to persist

[[Page 49392]]

that initially motivated the Commission to act.\1527\
---------------------------------------------------------------------------

    \1525\ R Street Initial Comments at 9.
    \1526\ Concerned Scientists Reply Comments at 7.
    \1527\ Id. at 8-9.
---------------------------------------------------------------------------

    687. Some commenters assert that requiring the same benefits in 
different transmission planning regions will help increase 
interregional transmission coordination.\1528\ Clean Energy 
Associations argue that it is important for transmission planning 
regions to have a common starting point in terms of which benefits they 
evaluate to facilitate greater interregional transmission 
coordination.\1529\ Breakthrough Energy notes that load diversity--and 
its effect on reducing very expensive generation capacity costs--is a 
major and under-appreciated benefit of large-scale interregional 
transmission facilities.\1530\ Grid United states that, without a 
minimum set of benefits criteria, disparate benefits in neighboring 
transmission planning regions could balkanize the grid and disrupt 
effective interregional transmission planning, emphasizing the need for 
a set of principles that outline benefits that are universal and 
necessary for effective long-term transmission planning.\1531\ Policy 
Integrity asserts that defining a uniform set of minimum benefits would 
facilitate better identification and selection of efficient and cost-
effective transmission solutions and would ensure comparability of 
transmission expansion projects across different RTOs/ISOs, which will 
be particularly useful given the need to improve Interregional Transfer 
Capability.\1532\
---------------------------------------------------------------------------

    \1528\ Breakthrough Energy Initial Comments at 22-23; California 
Commission Initial Comments at 33; Grid United Initial Comments at 
3; Policy Integrity Initial Comments at 27-28; US DOE Initial 
Comments at 31-32.
    \1529\ Clean Energy Associations Initial Comments at 19.
    \1530\ Breakthrough Energy Initial Comments at 22.
    \1531\ Grid United Initial Comments at 3.
    \1532\ Policy Integrity Initial Comments at 3, 27-28.
---------------------------------------------------------------------------

    688. Relatedly, PJM states that, while it agrees that transmission 
providers should have flexibility to propose which benefits make sense 
to consider for their own transmission planning regions, the Commission 
should adopt a core set of benefits to be considered nationwide to 
ensure consistency.\1533\ SREA notes that, in RTOs/ISOs, seams are 
perpetually a problem due to a lack of common national standards on 
benefits metrics and data inputs and asserts that the Commission should 
set minimum standards.\1534\
---------------------------------------------------------------------------

    \1533\ PJM Initial Comments at 93 (citing NOPR, 179 FERC ] 
61,028 at P 186).
    \1534\ SREA Reply Comments at 26-27.
---------------------------------------------------------------------------

    689. Some commenters assert that a failure to consider sufficient 
benefits could result in higher costs and/or unjust and unreasonable 
rates.\1535\ According to Enel, without considering a larger number of 
benefits, transmission projects that would have large net benefits will 
not be selected if no benefits or even only a small number of potential 
benefits were compared against the upfront costs.\1536\
---------------------------------------------------------------------------

    \1535\ Enel Initial Comments at 3; Clean Energy Association 
Initial Comments at 20; Conservative Energy Network Supplemental 
Comments at 1; Conservatives for Clean Energy--Florida Supplemental 
Comments at 1; Conservatives for Clean Energy--South Carolina 
Supplemental Comments at 1; Indicated US Senators and 
Representatives Initial Comments at 2; Michigan Conservative Energy 
Forum Supplemental Comments at 1; Ohio Conservative Energy Forum 
Supplemental Comments at 1; Western Way Colorado Supplemental 
Comments at 1; Western Way Nevada Supplemental Comments at 1; 
Western Way Utah Supplemental Comments at 1; Wisconsin Conservative 
Energy Forum Supplemental Comments at 1.
    \1536\ Enel Initial Comments at 3.
---------------------------------------------------------------------------

    690. Some commenters assert that a failure to require consideration 
of specific benefits will undermine other aspects of the NOPR's 
proposed reforms.\1537\ Anbaric, for instance, argues that the NOPR 
falls far short of requiring comprehensive transmission planning, 
because it does not propose to mandate the use of any specific set of 
benefits.\1538\ RMI contends that there is overwhelming evidence that 
transmission infrastructure provides multiple, diverse benefits, as 
well as established precedent that transmission costs should be 
allocated roughly commensurate with benefits. Therefore, RMI states, it 
would be illogical to allow transmission providers to ignore any 
benefits that transmission infrastructure offers, as it would lead to 
flawed investment decisions and defective cost allocation. RMI asserts 
that transmission providers should be required to quantify the full 
suite of known benefits of transmission infrastructure in Long-Term 
Regional Transmission Planning and that the list of 12 benefits in the 
NOPR is conservative and does not double-count benefits.\1539\
---------------------------------------------------------------------------

    \1537\ Anbaric Initial Comments at 6-7; RMI Initial Comments at 
2.
    \1538\ Anbaric Initial Comments at 6-7.
    \1539\ RMI Initial Comments at 2.
---------------------------------------------------------------------------

    691. AEE argues that several of the listed benefits are 
indisputably relevant to all transmission planners and that these 
benefits should form a core group of minimum considerations.\1540\ AEE 
states that the Commission may wish to conduct additional fact-finding 
in this docket to consider whether additional benefits cut across all 
markets and transmission planning regions or whether it is necessary to 
require each region to identify region-specific benefits for 
inclusion.\1541\ Hannon Armstrong states that the Commission indicated 
that each of the 12 benefits listed in the NOPR has the potential to 
provide a meaningful contribution to offset the cost of transmission 
and recommends that, absent any double-counting in this list, the 
Commission should require each of these benefits to be evaluated.\1542\ 
ITC argues that the Commission should adopt as minimum benefit criteria 
for project evaluation those used in the recently approved MISO Long-
Range Transmission Plan process.\1543\
---------------------------------------------------------------------------

    \1540\ AEE Initial Comments at 26.
    \1541\ Id.
    \1542\ Hannon Armstrong Initial Comments at 2-3.
    \1543\ ITC Initial Comments at 5, 18-22.
---------------------------------------------------------------------------

    692. Southeast PIOs claim that the Commission must establish a set 
of minimum benefits for transmission providers to incorporate in their 
assessment of regional transmission facilities to ensure that regional 
transmission facilities are accurately represented in the transmission 
planning process.\1544\ Southeast PIOs contend that a regional 
transmission planning process that quantifies and fully accounts for 
benefits of regional transmission alternatives would provide a measure 
of assurance to regulators and stakeholders that such alternatives were 
evaluated appropriately.\1545\ In response to Southern and SERTP, 
Southeast PIOs argue that quantifying the listed benefits does not 
itself make resource decisions; the benefits are meant to determine the 
value proposition of alternative regional transmission 
facilities.\1546\
---------------------------------------------------------------------------

    \1544\ Southeast PIOs Initial Comments at 50.
    \1545\ Id. at 53.
    \1546\ Southeast PIOs Reply Comments at 28 (citing Southern 
Initial Comments at 25-26; SERTP Sponsors Initial Comments at 30).
---------------------------------------------------------------------------

    693. GridLab states that the Commission should require transmission 
providers to justify why their transmission solution evaluation 
frameworks omit any categories of benefits in relation to a standard 
list of benefits like those proposed in the NOPR.\1547\ Pattern Energy 
agrees and notes that a ``common starting point'' would lower barriers 
to entry for market participants that do business in multiple 
transmission planning regions. Moreover, Pattern Energy argues that a 
required set of standardized benefits would facilitate a more 
transparent transmission planning process, as developers would have a 
baseline knowledge of any single transmission provider's transmission 
planning

[[Page 49393]]

process regardless of where they are located.\1548\
---------------------------------------------------------------------------

    \1547\ GridLab Initial Comments at 25.
    \1548\ Pattern Energy Reply Comments at 6-8 (citing ACEG Initial 
Comments at 32; Clean Energy Associations Initial Comments at 21).
---------------------------------------------------------------------------

    694. Tabors Caramanis Rudkevich states that when transmission 
planning analyses account for the benefits of capital cost savings, 
resource adequacy, and resilience, the total benefits of transmission 
infrastructure well exceed the cost.\1549\ Tabors Caramanis Rudkevich 
provides an example of multi-value benefit stacking for the 
transmission line connecting ERCOT and Southern Company and states that 
the results show total benefits of $390 million, compared to $33 
million when considering production cost savings alone.\1550\
---------------------------------------------------------------------------

    \1549\ Tabors Caramanis Rudkevich Initial Comments at 6.
    \1550\ Id.
---------------------------------------------------------------------------

    695. Certain TDUs and NESCOE support or are amenable to a 
requirement for minimum benefits that also allows for flexibility in 
determination of additional benefits.\1551\ Specifically, NESCOE 
recommends that the Commission establish a list of benefits that must 
be considered for a regional discussion on transmission cost allocation 
and that the benefits list in the NOPR is an appropriate starting 
point. However, NESCOE contends, after consulting with the states, 
transmission providers should have the flexibility to include 
additional benefits or remove benefits from the list, asserting that 
such an approach would help facilitate collaboration in determining the 
appropriate set of benefits for a transmission planning region.\1552\ 
NESCOE also argues that, because benefits and the methods of measuring 
them may change over time, the Commission should clarify in any final 
order that transmission providers may modify or add benefits in future 
FPA section 205 filings.\1553\
---------------------------------------------------------------------------

    \1551\ Certain TDUs Initial Comments at 2-3, 9-12; NESCOE 
Initial Comments at 43-44.
    \1552\ NESCOE Initial Comments at 44.
    \1553\ Id. at 43-44.
---------------------------------------------------------------------------

    696. Certain TDUs also urge the Commission to allow for regional 
flexibility and state involvement in determining other measurable and 
quantifiable benefits to use in evaluating Long-Term Regional 
Transmission Facilities.\1554\ While arguing for requiring certain 
benefits, Cypress Creek states that it agrees with Brattle Group that 
requiring evaluation of all 12 benefits in every scenario would detract 
from necessary regional flexibility.\1555\ Cypress Creek asserts that 
the Commission should require two additional project/region-specific 
benefits in evaluating multi-value projects but does not explain what 
they should be.\1556\
---------------------------------------------------------------------------

    \1554\ Certain TDUs Initial Comments at 9.
    \1555\ Cypress Creek Reply Comments at 7-8 (citing PIOs Initial 
Comments Ex. A, ]] 8-9).
    \1556\ Id. at 8.
---------------------------------------------------------------------------

    697. Exelon supports the Commission's proposal to provide 
flexibility to each transmission planning region to identify which 
benefits they will use in Long-Term Regional Transmission Planning. For 
instance, Exelon suggests that congestion reduction is more applicable 
to regions with Locational Marginal Price pricing, while it may be 
impossible to calculate the benefits of deferred generation capacity 
investments in a region like PJM where generation capacity is largely 
market-driven.\1557\ Similarly, the New Jersey Commission recommends 
providing regional flexibility to include additional benefits that may 
be harder to quantify and/or do not reduce customers' bills (e.g., 
resilience benefits and the value of meeting state public 
policies).\1558\
---------------------------------------------------------------------------

    \1557\ Exelon Initial Comments at 15.
    \1558\ New Jersey Commission Initial Comments at 14.
---------------------------------------------------------------------------

    698. Clean Energy Buyers state that the proposed set of benefits is 
generally appropriate and that a common set of benefits would allow for 
the proper identification of benefits in Long-Term Regional 
Transmission Planning, accounting for changes in the resource mix and 
demand, and facilitating stakeholder participation. Therefore, Clean 
Energy Buyers argue, the Commission should require transmission 
providers to adopt a set of Commission-identified benefits that are 
consistent with the just and reasonable standard or demonstrate on 
compliance why they should not have to do so. That said, Clean Energy 
Buyers state that the Commission should permit transmission providers 
to propose processes for weighing benefits in accordance with their 
relative importance in each specific transmission planning 
region.\1559\
---------------------------------------------------------------------------

    \1559\ Clean Energy Buyers Initial Comments at 19-21.
---------------------------------------------------------------------------

    699. Several commenters recognize that benefits analysis can be 
resource intensive and therefore recommend that the Commission allow 
transmission providers to use a screening approach that initially 
screens benefit categories for significance before investing staff 
resources and modeling work to provide a detailed quantification.\1560\ 
Clean Energy Buyers argue that, at a minimum, the Commission should 
require that transmission providers screen for all 12 benefits listed 
in the NOPR and quantify them accordingly.\1561\ Hannon Armstrong 
states that while certain benefits may have a zero or de minimis 
contribution for certain candidate transmission projects, the 
Commission should require transmission providers to document each 
potential benefit by using a high-level screening analysis or detailed 
modeling as applicable.\1562\ PIOs assert that screening tools can be 
used to reduce analytical burdens, allowing transmission providers to 
self-certify compliance and/or provide justifications for when benefits 
do not apply.\1563\
---------------------------------------------------------------------------

    \1560\ ACEG Initial Comments at 7, 33; ACORE Initial Comments at 
12; Breakthrough Energy Initial Comments at 22; CTC Global Initial 
Comments at 9; Interwest Initial Comments at 12-13; WATT Coalition 
Initial Comments at 7.
    \1561\ Clean Energy Buyers Initial Comments at 20-21.
    \1562\ Hannon Armstrong Initial Comments at 2-3.
    \1563\ PIOs Initial Comments at 41.
---------------------------------------------------------------------------

i. List of Benefits Proposed in the NOPR
    700. Some commenters support requiring transmission providers to 
consider all 12 illustrative benefits enumerated in the NOPR.\1564\ 
ACORE contends that these categories represent a best practice and 
track closely with recommended multi-benefit planning approaches.\1565\ 
Breakthrough Energy notes that some of the Commission-listed benefits 
can be very significant but are typically ignored in today's 
transmission planning processes.\1566\ SEIA and Fervo assert that the 
final order should account for the full range of transmission benefits 
and use multi-value planning to comprehensively identify investments 
that address all categories of needs and benefits.\1567\
---------------------------------------------------------------------------

    \1564\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25: Amazon Initial Comments at 5; Breakthrough Energy 
Initial Comments at 21-22; Clean Energy Associations Initial 
Comments at 19-20; DC and MD Offices of People's Counsel Initial 
Comments at 19-20; ENGIE Reply Comments at 3; Hannon Armstrong 
Initial Comments at 3; Interwest Initial Comments at 12-14; National 
and State Conservation Organizations Initial Comments at 1; Pine 
Gate Initial Comments at 34-37; PIOs Initial Comments at 38-41; RMI 
Initial Comments at 1; SEIA Initial Comments at 16; Southeast PIOs 
Initial Comments at 50.
    \1565\ ACORE Initial Comments at 12 (citing Rob Gramlich, Grid 
Strategies LLC, Enabling Low-Cost Clean Energy and Reliable Service 
Through Better Transmission Benefits Analysis, at 9 (Aug. 9, 2022)).
    \1566\ Breakthrough Energy Initial Comments at 22.
    \1567\ Fervo Reply Comments at 2; SEIA Initial Comments at 16.
---------------------------------------------------------------------------

    701. PIOs state that there is strong evidence in the record to 
support the proposed list of benefits, including extensive testimony 
provided by the Brattle Group and others. PIOs state that these 
benefits all correlate with needs

[[Page 49394]]

and goals associated with Long-Term Regional Transmission Planning and, 
as such, the Commission should require transmission providers to 
consider them for most, if not all, regional transmission projects. 
Finally, PIOs encourage the Commission to make clear that these 
benefits should be assessed as part of any transmission planning 
process--even those conducted for economic purposes.\1568\
---------------------------------------------------------------------------

    \1568\ PIOs Initial Comments at 37-38, 41.
---------------------------------------------------------------------------

    702. Amazon supports the list of benefits set forth in the NOPR and 
urges the Commission to make consideration of those benefits mandatory 
except insofar as a transmission provider files for waiver and 
overcomes a strong presumption of their relevance to transmission 
planning and cost allocation.\1569\ To facilitate the responsible 
construction of transmission facilities, ENGIE recommends that the 
Commission incorporate the 12 listed benefits as a minimum set of 
benefits for analysis but permit flexibility in how transmission 
providers conduct their analysis.\1570\
---------------------------------------------------------------------------

    \1569\ Amazon Initial Comments at 5.
    \1570\ ENGIE Reply Comments at 3.
---------------------------------------------------------------------------

ii. Application of the Benefits of Long-Term Regional Transmission 
Facilities in Non-RTO/ISO Regions
    703. Certain commenters state that all or most of the Commission's 
proposed benefits are applicable and appropriate in non-RTO/ISO 
transmission planning regions.\1571\ For example, ACEG states the 
minimum set of benefits should be implemented as universally as 
possible across RTOs/ISOs and non-RTO/ISO regions.\1572\ PIOs state 
that the Brattle-Grid Strategies Oct. 2021 Report shows the numerous 
benefits not currently quantified in RTO/ISO regions to consumers' 
detriment and that the problem is more dire in non-RTO/ISO 
regions.\1573\ Relatedly, MISO states that benefits could be applied in 
non-RTO/ISO regions but may be limited or not fully realized due to 
less coordinated congestion management and transmission planning.\1574\
---------------------------------------------------------------------------

    \1571\ ACEG Initial Comments at 32, 48, 61; PIOs Initial 
Comments at 42; SEIA Initial Comments at 17.
    \1572\ ACEG Initial Comments at 32.
    \1573\ PIOs Initial Comments at 42.
    \1574\ MISO Initial Comments at 51.
---------------------------------------------------------------------------

    704. SEIA comments that the Commission should mandate the 
consideration of benefits of Long-Term Regional Transmission Facilities 
in non-RTO/ISO transmission planning regions. Otherwise, SEIA states, 
transmission providers could rely on state integrated resource planning 
processes, which do not incorporate lower cost transmission 
alternatives to generation procurement, potentially leading to 
transmission expansion to accommodate higher-cost generation than is 
needed. According to SEIA, there is no basis to apply different 
benefits in non-RTO/ISO transmission planning regions, because many of 
the proposed benefits of Long-Term Regional Transmission Facilities 
have already been calculated in non-RTO/ISO regions.\1575\
---------------------------------------------------------------------------

    \1575\ SEIA Initial Comments at 17-18.
---------------------------------------------------------------------------

    705. Southeast PIOs claim that Southeastern transmission providers 
should not be exempt from quantifying benefits, even if some benefits 
do not apply in the same manner to non-RTO/ISO transmission planning 
regions as they do to RTO/ISO regions.\1576\ Southeast PIOs advocate 
for the Commission to establish standardized metrics for both RTO/ISO 
regions and non-RTO/ISO regions to capture similar benefits.\1577\ 
Otherwise, Southeast PIOs argue, transmission providers will continue 
to focus only on costs, thereby depriving states and stakeholders of a 
fuller picture of transmission planning options.\1578\ TAPS contends 
that no transmission facilities have been selected in a regional 
transmission plan for purposes of cost allocation since the 
implementation of Order No. 1000 in non-RTO/ISO transmission planning 
regions partly because of the narrow factors that most non-RTO/ISO 
regions consider in evaluating the benefits of potential transmission 
projects.\1579\
---------------------------------------------------------------------------

    \1576\ Southeast PIOs Initial Comments at 51.
    \1577\ Id. at 52.
    \1578\ Id. at 52-53.
    \1579\ TAPS Initial Comments at 15.
---------------------------------------------------------------------------

    706. Other commenters express concern that certain NOPR benefits 
would be inapplicable or problematic to apply to non-RTO/ISO 
transmission planning regions or argue that the same types of benefits 
should not be applied to both sets of regions.\1580\ California 
Municipal Utilities oppose applying the list of benefits to non-RTO/ISO 
transmission planning regions, stating that doing so would misapprehend 
the state and local nature of resource portfolio planning and would 
fail to account for the costs of such prescriptive measures and to 
provide consumer protection measures to guard against speculative 
transmission projects.\1581\ Dominion states that a one-size-fits-all 
approach to benefits may be inappropriate, for instance, in locations 
where some transmission providers operate outside of an RTO/ISO while 
others function within an RTO/ISO.\1582\
---------------------------------------------------------------------------

    \1580\ California Municipal Utilities Reply Comments at 5-6; 
Dominion Reply Comments at 2; Duke Initial Comments at 23; EEI 
Initial Comments at 19; Idaho Power Initial Comments at 8; North 
Carolina Commission and Staff Initial Comments at 7; Southern 
Initial Comments at 25-27.
    \1581\ California Municipal Utilities Reply Comments at 5-6.
    \1582\ Dominion Reply Comments at 2.
---------------------------------------------------------------------------

    707. EEI and Idaho Power state that non-RTO/ISO transmission 
planning regions may not be able to calculate reduced congestion or 
increased market liquidity.\1583\ Likewise, North Carolina Commission 
and Staff state that some of the benefits proposed for consideration 
are only applicable in RTOs/ISOs (e.g., increased market liquidity) and 
argue that some benefits could conflict with state-jurisdictional 
resource decisions (e.g., production cost savings, access to lower-cost 
generation).\1584\
---------------------------------------------------------------------------

    \1583\ EEI Initial Comments at 19; Idaho Power Initial Comments 
at 8.
    \1584\ North Carolina Commission and Staff Initial Comments at 
7.
---------------------------------------------------------------------------

    708. Southern states that, while certain benefits identified in the 
NOPR could work for Southern's non-RTO/ISO footprint, others could harm 
underlying state integrated resource planning/request for proposal 
processes or are suited only for RTO/ISO markets, such as increased 
market liquidity.\1585\ For example, Southern states that considering 
production cost savings effectively would make generation resource-
related decisions that would intrude into integrated resource plan/
request for proposal planning, which considers the total costs 
(including both generation and transmission costs) of available 
alternatives to customers.\1586\ Similarly, SERTP Sponsors state that, 
because SERTP Sponsors continue to use integrated resource plan/request 
for proposal planning to make their resource and load determinations, 
some of the benefits that are appropriate for consideration in RTOs/
ISOs are inapplicable for transmission planning or cost allocation 
purposes in the Southeast.\1587\ SERTP Sponsors further state that, as 
the states have exclusive jurisdiction over such integrated resource 
plan/generation matters, requiring consideration of ``[integrated 
resource plan/request for proposal]-related benefits,'' including 
production cost savings, capacity costs benefits, reduced planning 
reserve margins, and reduced peak energy losses, could exceed the 
Commission's jurisdiction by infringing on such state processes.\1588\
---------------------------------------------------------------------------

    \1585\ Southern Initial Comments at 25-27.
    \1586\ Id. at 26.
    \1587\ SERTP Sponsors Initial Comments at 30.
    \1588\ SERTP Sponsors Initial Comments at 30.
---------------------------------------------------------------------------

    709. Kentucky Commission Chair Chandler argues against SERTP 
Sponsors' comments that suggest that integrated resource plan/request 
for proposal processes already consider four of the proposed categories 
of

[[Page 49395]]

benefits included in the NOPR. Kentucky Commission Chair Chandler 
contends that the integrated resource planning/request for proposal 
process can only address these four categories on a utility-by-utility 
basis and, thus, is unable to plan for transmission facilities across 
utilities or transmission planning regions by nature.\1589\
---------------------------------------------------------------------------

    \1589\ Kentucky Commission Chair Chandler Reply Comments at 7.
---------------------------------------------------------------------------

    710. Some commenters advocate for or against requiring transmission 
providers to consider other specific lists, categories, or combinations 
of benefits, arguing that such approaches reduce possible duplication 
of benefits, increase flexibility, and/or focus on benefits they 
believe are most important.\1590\ PIOs, for example, assert that some 
commenters who are opposed to the list of benefits in the NOPR 
nonetheless agree that transmission planners should quantify broad 
categories of benefits to plan effectively.\1591\ AEP states that some 
benefits are more difficult to calculate than others and argues that 
the minimum set of benefits it recommends appropriately balances the 
significance of each type of benefit with the difficulty of quantifying 
that benefit.\1592\
---------------------------------------------------------------------------

    \1590\ ACEG Reply Comments at 6-7; AEE Reply Comments at 25-26; 
AEP Initial Comments at 6, 23-25; California Commission Initial 
Comments at 31-34; Certain TDUs Reply Comments at 1-2; Entergy 
Initial Comments at 21; GridLab Initial Comments at 27; Joint 
Consumer Advocates Initial Comments at 11; PIOs Reply Comments at 7-
9; PJM Initial Comments at 94-96; PPL Initial Comments at 14.
    \1591\ PIOs Reply Comments at 7-8 (citing Entergy Initial 
Comments at 21; Exelon Initial Comments at 15).
    \1592\ AEP Initial Comments at 23.
---------------------------------------------------------------------------

    711. AEP and GridLab argue that many of the benefits listed in the 
NOPR measure or identify the same type of benefit and therefore argue 
that the Commission should group similar benefits together into 
categories to avoid double-counting.\1593\ Specifically, AEP and 
GridLab propose that the production cost savings and access to lower-
cost generation benefits be grouped into a required category.\1594\ In 
addition, AEP states that the reduced loss of load probability, reduced 
planning reserve margin, capacity cost benefits from reduced peak 
energy losses, and deferred capacity investments benefits should be 
combined into one required category.\1595\
---------------------------------------------------------------------------

    \1593\ AEP Initial Comments at 23-24; GridLab Initial Comments 
at 27.
    \1594\ AEP Initial Comments at 25; GridLab Initial Comments at 
27.
    \1595\ AEP Initial Comments at 25.
---------------------------------------------------------------------------

    712. GridLab and PJM contend that the Commission should combine the 
benefits of reduced loss of load probability and deferred generation 
capacity investment into a single category of benefits.\1596\ PJM 
further argues that the Commission should combine the benefits of 
mitigation of extreme events and mitigation of weather and load 
uncertainty.\1597\
---------------------------------------------------------------------------

    \1596\ GridLab Initial Comments at 27; PJM Initial Comments at 
95.
    \1597\ PJM Initial Comments at 94.
---------------------------------------------------------------------------

    713. California Commission recommends that to capture the benefits 
of transmission infrastructure, the Commission should require 
transmission providers to assess benefits within the following six 
benefit categories: (1) production cost benefits; (2) emissions 
reductions benefits; (3) generation capital cost benefits; (4) risk 
mitigation benefits; (5) resource adequacy benefits; and (6) resilience 
benefits. California Commission states that such a requirement would 
promote greater uniformity in how the benefits of regional (and 
interregional) transmission projects are evaluated, reducing potential 
disputes over cost allocation.\1598\ However, California Commission 
argues, the Commission should allow transmission providers, in 
consultation with Relevant State Entities, to define each identified 
benefit and determine how to quantify it.\1599\ To ensure that 
customers are protected from speculative transmission development and 
unreasonably high costs, California Commission concludes that the 
Commission should require transmission providers to demonstrate on 
compliance that they identified and defined benefits within each of the 
required benefit categories and determined appropriate quantification 
methods through a transparent public process.\1600\
---------------------------------------------------------------------------

    \1598\ California Commission Initial Comments at 33.
    \1599\ Id. at 28-29.
    \1600\ Id. at 34-35.
---------------------------------------------------------------------------

    714. Joint Consumer Advocates state that the following categories 
of benefits should be included in Long-Term Regional Transmission 
Planning: (1) production cost savings; (2) avoided or deferred 
reliability transmission facilities; and (3) aging transmission 
infrastructure replacement.\1601\
---------------------------------------------------------------------------

    \1601\ Joint Consumer Advocates Initial Comments at 11.
---------------------------------------------------------------------------

    715. AEE notes that some commenters propose that the Commission 
adopt a smaller set of benefit categories.\1602\ AEE states that while 
there may be value in considering these proposals, they miss important 
benefits such as increased competition, market liquidity, and increased 
resilience from mitigation of extreme weather events effects and system 
contingencies.\1603\ Thus, AEE recommends that the Commission adopt as 
mandatory the full set of 12 benefits listed in the NOPR but allow a 
transmission provider to demonstrate that an alternative set of 
benefits captures all the benefits of transmission in its transmission 
planning region.
---------------------------------------------------------------------------

    \1602\ AEE Reply Comments at 25-26 (citing PJM Initial Comments 
at 93-96; California Commission Initial Comments at 32; New Jersey 
Commission Initial Comments at 13-14).
    \1603\ Id.
---------------------------------------------------------------------------

    716. A few commenters offer categories of benefits while noting the 
importance of regional flexibility.\1604\ ACEG notes widespread support 
for the Commission to require certain categories of minimum benefits 
and requests flexibility for transmission providers to address these 
categories in accordance with regional needs. ACEG states that 
considering categories of benefits will reduce the risk of double-
counting or miscalculating benefits and allow flexibility to apply 
specific benefits best suited to each transmission planning 
region.\1605\
---------------------------------------------------------------------------

    \1604\ ACEG Reply Comments at 6-7; Entergy Initial Comments at 
21.
    \1605\ ACEG Reply Comments at 6-7 (citing Entergy Initial 
Comments at 21; AEP Initial Comments at 23-27; Exelon Initial 
Comments at 15-16).
---------------------------------------------------------------------------

    717. In addition to concerns expressed by commenters in the context 
of the combinations of benefits proposed above, other commenters 
express concern regarding the potential for double-counting of benefits 
if transmission providers are required to consider certain 
benefits.\1606\ For example, NRECA asserts that accounting for 
increased competition and increased market liquidity would risk double-
counting benefits,\1607\ and Utah Division of Public Utilities argues 
that accounting for both reduction in loss of load probability and 
mitigation of extreme events and system contingencies would result in 
double-counting.\1608\ Clean Energy Buyers ask that the Commission 
require transmission providers to explain how they will avoid double-
counting issues,\1609\ while ISO-NE seeks more information from the 
Commission regarding which benefits the Commission believes are 
redundant.\1610\
---------------------------------------------------------------------------

    \1606\ See, e.g., APPA Initial Comments at 32; City of New 
Orleans Council Initial Comments at 10-11; Louisiana Commission 
Reply Comments at 10; Michigan Commission Initial Comments at 6; 
Nevada Commission Initial Comments at 10-11; Utah Division of Public 
Utilities Initial Comments at 8; Vistra Initial Comments at 16-17.
    \1607\ NRECA Initial Comments at 45 (citing NRECA Initial 
Comments, attach. at 16-17).
    \1608\ Utah Division of Public Utilities Initial Comments at 8.
    \1609\ Clean Energy Buyers Initial Comments at 20-21.
    \1610\ ISO-NE Initial Comments at 34.

---------------------------------------------------------------------------

[[Page 49396]]

    718. A few commenters state that the list of 12 benefits in the 
NOPR does not risk double-counting.\1611\ DC and MD Offices of People's 
Counsel concludes that each benefit in this list is mutually exclusive, 
noting that some transmission providers may wish to mix and match these 
benefits because their modeling tools may not disaggregate them in 
exactly the way described in the NOPR.\1612\ MISO notes that there are 
instances where one benefit can enable other benefits and that adopting 
a calculation method that recognizes that complementary behavior can 
yield incremental value.\1613\ For example, MISO states, a calculation 
approach that distinguishes between the benefit of enabling resource 
expansion and the benefit of increased transmission capability provided 
by regional transmission projects would produce unique benefits.\1614\
---------------------------------------------------------------------------

    \1611\ DC and MD Offices of People's Counsel Initial Comments at 
20; MISO Initial Comments at 50.
    \1612\ DC and MD Offices of People's Counsel Initial Comments at 
20.
    \1613\ MISO Initial Comments at 50.
    \1614\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    719. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to measure 
a set of seven required benefits (required benefits) for Long-Term 
Regional Transmission Facilities under each Long-Term Scenario as part 
of Long-Term Regional Transmission Planning. Furthermore, we adopt the 
NOPR proposal, with modification, to require transmission providers in 
each transmission planning region to use these measured benefits to 
evaluate Long-Term Regional Transmission Facilities, as discussed below 
in the Evaluation and Selection of Regional Transmission Facilities 
section. This Evaluation of the Benefits of Regional Transmission 
Facilities section discusses this final order's requirements with 
regard to transmission providers' measurement and use of benefits in 
evaluating Long-Term Regional Transmission Facilities; however, as 
discussed in the Development of Long-Term Scenarios section, these same 
benefits should help to inform transmission providers' identification 
of Long-Term Transmission Needs.\1615\
---------------------------------------------------------------------------

    \1615\ See supra Long-Term Regional Transmission Planning, 
Development of Long-Term Scenarios section.
---------------------------------------------------------------------------

    720. The seven required benefits that we require transmission 
providers to measure and use in Long-Term Regional Transmission 
Planning, which we describe in greater detail in the discussion of the 
individual benefits below, are: (1) avoided or deferred reliability 
transmission facilities and aging infrastructure replacement; (2) a 
benefit that can be characterized and measured as either reduced loss 
of load probability or reduced planning reserve margin; (3) production 
cost savings; (4) reduced transmission energy losses; (5) reduced 
congestion due to transmission outages; (6) mitigation of extreme 
weather events and unexpected system conditions; and (7) capacity cost 
benefits from reduced peak energy losses.\1616\
---------------------------------------------------------------------------

    \1616\ We discuss modifications to Benefit 6 from its 
description in the NOPR in the Benefit 6 determination section.
---------------------------------------------------------------------------

    721. We find that these requirements are necessary to ensure that 
transmission providers can evaluate Long-Term Regional Transmission 
Facilities to determine whether they more efficiently or cost-
effectively address Long-Term Transmission Needs. Specifically, we find 
that transmission providers must measure these seven required benefits 
in each Long-Term Scenario because, as discussed further in the 
Evaluation and Selection of Regional Transmission Facilities section, 
evaluating Long-Term Regional Transmission Facilities for potential 
selection necessarily involves the consideration of the benefits 
measured in each Long-Term Scenario and sensitivity to help address 
uncertainty over the 20-year transmission planning horizon and to 
maximize benefits accounting for costs over time. As such, we find 
that, to ensure just and reasonable Commission-jurisdictional rates, 
transmission providers must measure, at minimum, the set of seven 
required benefits in Long-Term Regional Transmission Planning and then 
use them to evaluate Long-Term Regional Transmission Facilities for 
selection.
    722. Although the Commission did not propose to require the use of 
any specific benefits in the NOPR, the Commission sought comment on 
whether it should require transmission providers to use some or all of 
the potential benefits described in the NOPR as a minimum set of 
benefits in Long-Term Regional Transmission Planning. The record in 
this proceeding shows that, in order to ensure just and reasonable 
Commission-jurisdictional transmission rates, it is necessary to 
require transmission providers to measure and use in Long-Term Regional 
Transmission Planning a set of particular benefits so that they may 
identify, evaluate, and select regional transmission facilities that 
are more efficient or cost-effective transmission solutions to Long-
Term Transmission Needs. We find that the benefits that Long-Term 
Regional Transmission Facilities generally provide extend beyond the 
benefits that transmission providers currently consider as part of 
their regional transmission planning and cost allocation processes, and 
without consideration of such benefits, Long-Term Regional Transmission 
Planning cannot be reasonably expected to identify, evaluate, and 
select more efficient or cost-effective regional transmission solutions 
to address Long-Term Transmission Needs.
    723. By requiring the measurement and use of the seven enumerated 
benefits in Long-Term Regional Transmission Planning, we ensure that 
transmission providers will consider a sufficiently broad range of 
benefits when determining whether to select a Long-Term Regional 
Transmission Facility as a more efficient or cost-effective regional 
transmission solution to Long-Term Transmission Needs. In contrast, 
adopting the more flexible approach proposed in the NOPR would not 
address the identified deficiencies in existing regional transmission 
planning and cost allocation processes because such an approach would 
fail to ensure that transmission providers consider the broader set of 
benefits provided by, and the beneficiaries receiving the benefits of, 
Long-Term Regional Transmission Facilities, and thus, may fail to 
identify the potentially more efficient or cost-effective regional 
transmission solution. We find that failing to use the set of benefits 
that we require in this final order to evaluate Long-Term Regional 
Transmission Facilities for potential selection could render resulting 
Commission-jurisdictional rates unjust and unreasonable. We find that 
not requiring transmission providers to use certain benefits to 
evaluate Long-Term Regional Transmission Facilities would be expected 
to lead to relatively inefficient and less cost-effective transmission 
development, as Long-Term Regional Transmission Facilities that provide 
significant net benefits may not be selected.\1617\ In addition, we 
find that the transparency provided by requiring consideration of a 
sufficiently broad and common set of benefits will help to ensure the 
costs of Long-Term Regional Transmission Facilities are allocated to 
beneficiaries in a manner that is at least

[[Page 49397]]

roughly commensurate with the benefits they derive from them.\1618\
---------------------------------------------------------------------------

    \1617\ See Clean Energy Associations Initial Comments at 20 
(citing The Brattle Group, Transmission Planning and Benefit-Cost 
Analyses, at 26 (Apr. 2021)).
    \1618\ ICC v. FERC I, 576 F.3d at 477; Order No. 1000, 136 FERC 
] 61,051 at PP 622, 639 (requiring costs of regional transmission 
facilities to be allocated in a manner that is at least roughly 
commensurate with estimated benefits).
---------------------------------------------------------------------------

    724. We appreciate arguments made by certain commenters that 
failure to incorporate identifiable benefits risks skewing the 
evaluation process against developing needed and beneficial Long-Term 
Regional Transmission Facilities because transmission providers would 
consider all of the costs of such transmission facilities without 
similarly considering many important benefits that they may 
provide.\1619\ However, we are also cognizant of concerns about 
duplication of benefits and difficulty of measuring certain benefits. 
In this final order, rather than requiring transmission providers to 
measure and use all 12 benefits enumerated in the NOPR, we only require 
transmission providers to measure and use seven specific benefits that 
have a proven track record, can be discretely measured, and are 
unlikely to cause duplication. We find that the modification to the 
NOPR proposal to require the measurement and use of these seven 
benefits to evaluate Long-Term Regional Transmission Facilities, as 
discussed above, resolves concerns about important benefits being 
omitted from Long-Term Regional Transmission Planning, as well as 
challenges raised concerning duplication and measurement of certain 
benefits.
---------------------------------------------------------------------------

    \1619\ See Enel Initial Comments at 3.
---------------------------------------------------------------------------

    725. We acknowledge that many commenters do not favor requiring the 
use of particular benefits. In response, we emphasize that a set of 
common benefits and a requirement to measure and use those benefits in 
Long-Term Regional Transmission Planning will ensure just and 
reasonable rates, as discussed above.\1620\ Specifically, unless 
transmission providers consider a sufficiently broad range of benefits 
when determining whether to select a Long-Term Regional Transmission 
Facility as a more efficient or cost-effective regional transmission 
solution to Long-Term Transmission Needs, they may fail to identify the 
more efficient or cost-effective regional transmission solution, 
resulting in relatively inefficient or less cost-effective transmission 
development.
---------------------------------------------------------------------------

    \1620\ See ACORE Initial Comments at 12; ACORE Reply Comments at 
6; ACORE Supplemental Comments at 1; AEE Initial Comments at 8, 25; 
AEP Initial Comments at 6, 23-25; Breakthrough Energy Initial 
Comments at 4, 21-22; Business Council for Sustainable Energy 
Initial Comments at 2, 5; Certain TDUs Initial Comments at 11-12; 
Clean Energy Buyers Reply Comments at 8-9; Concerned Scientists 
Reply Comments at 7-10; Cypress Creek Reply Comments at 7-8; DC and 
MD Offices of People's Counsels Reply Comments at 3, 7-8; ELCON 
Initial Comments at 15; Enel Initial Comments at 3; Environmental 
Groups Supplemental Comments at 2; Environmental Legislators Caucus 
Supplemental Comments at 1; Exelon Initial Comments at 16: Grid 
United Initial Comments at 2; Handy Law Initial Comments at 8; US 
House Republicans Supplemental Comments at 1; Indicated US Senators 
and Representatives Initial Comments at 2; ITC Initial Comments at 
5, 18-22; Interwest Initial Comments at 12; Interwest Reply Comments 
at 6-7; Joint Consumer Advocates Initial Comments at 11; Kentucky 
Commission Chair Chandler Reply Comments at 7; Minnesota State 
Entities Initial Comments at 6; New England for Offshore Wind 
Initial Comments at 5; New Jersey Commission Initial Comments at 11-
14; Pacific Northwest State Agencies Initial Comments at 16-17; PIOs 
Initial Comments at 27-28; PIOs Reply Comments at 7-8; Policy 
Integrity Initial Comments at 27; Policy Integrity Supplemental 
Comments at 4; R Street Initial Comments at 9; RMI Initial Comments 
at 1; RMI Supplemental Comments at 2; SEIA Initial Comments at 16-
17; Southeast PIOs Initial Comments at 50; Southeast PIOs Reply 
Comments at 27-28; ; US DOE Initial Comments at 30-33; US Senator 
Schumer Supplemental Comments at 1-2; US Senator Whitehouse 
Supplemental Comments at 2; US Senators Supplemental Comments at 2; 
WATT Coalition Initial Comments at 7.
---------------------------------------------------------------------------

    726. We note that some commenters request flexibility to use 
different benefits, such as SPP, which states that the effort required 
to incorporate additional benefit metrics into its current regional 
transmission planning process cannot be accommodated within its current 
process timeline.\1621\ As discussed in the Implementation and 
Compliance sections of this final order, we require transmission 
providers to propose on compliance a date, no later than one year from 
the date on which initial filings to comply with this final order are 
due, on which they will commence the first Long-Term Regional 
Transmission Planning cycle (unless additional time is needed to align 
the first Long-Term Regional Transmission Planning cycle with existing 
transmission planning cycles), and thus transmission providers will not 
be required to immediately implement this reform.
---------------------------------------------------------------------------

    \1621\ SPP Initial Comments at 18.
---------------------------------------------------------------------------

    727. Some commenters argue that the requirement to measure and use 
these benefits will increase costs and require additional effort, and 
that the Commission has presented insufficient evidence that this 
requirement will produce the desired benefits.\1622\ Commenters who 
express such concerns did not provide persuasive evidence to suggest 
that requiring the measurement and use of a required set of benefits 
would be unduly burdensome. While measuring these benefits may impose a 
degree of burden on some transmission providers, the requirement for 
transmission providers to measure and use the seven required benefits 
in Long-Term Regional Transmission Planning is necessary to ensure that 
rates are just and reasonable. Specifically, absent a requirement that 
transmission providers measure and use a sufficiently broad range of 
benefits of Long-Term Regional Transmission Facilities when evaluating 
them for potential selection, transmission providers may not identify, 
evaluate, and select more efficient or cost-effective regional 
transmission solutions to Long-Term Transmission Needs, which may lead 
to relatively inefficient or less cost-effective transmission 
development. Further, we believe that experience gained by transmission 
providers will over time allow them to perform the necessary 
measurements more efficiently. Moreover, in our discussion of each 
required benefit below, we provide a description, for several of the 
required benefits, of at least one manner in which transmission 
providers could measure each required benefit. Finally, commenters also 
did not provide persuasive evidence that the burdens of measuring and 
using a required set of benefits outweigh the benefits of using these 
benefits in Long-Term Regional Transmission Planning. We therefore find 
that any burdens of measuring and using the seven required benefits in 
Long-Term Regional Transmission Planning are outweighed by the 
identification, evaluation, and selection of more efficient or cost-
effective Long-Term Regional Transmission Facilities to address Long-
Term Transmission Needs.\1623\
---------------------------------------------------------------------------

    \1622\ E.g., Dominion Initial Comments at 34-35.
    \1623\ See Clean Energy Associations Initial Comments at 20 
(``Not requiring benefits to be evaluated could lead to higher costs 
in the long-term, and, thus, unjust and unreasonable rates.'').
---------------------------------------------------------------------------

    728. Another common concern expressed by some commenters is that 
requiring a minimum set of benefits would undermine regional 
flexibility.\1624\ We conclude that it would be inappropriate to 
provide flexibility not to consider this required set of benefits in 
Long-Term Regional Transmission Planning because, as described above, 
requiring the measurement and use of these benefits ensures that 
transmission providers are able to identify, evaluate, and select 
regional transmission solutions to more efficiently or cost-effectively 
address Long-Term Transmission Needs, and thereby ensures just and 
reasonable rates. We therefore disagree with Dominion that transmission 
providers should be permitted to identify initial benefits that they 
will consider in

[[Page 49398]]

conducting Long-Term Regional Transmission Planning but retain 
flexibility in applying such benefits to each transmission provider's 
individual circumstances.\1625\ However, as we discuss further below, 
we are providing flexibility to transmission providers regarding how 
they will measure each of the required benefits.
---------------------------------------------------------------------------

    \1624\ E.g., Entergy Initial Comments at 21.
    \1625\ Dominion Initial Comments at 34.
---------------------------------------------------------------------------

    729. Transmission providers may also propose to measure and use 
additional benefits in Long-Term Regional Transmission Planning, as 
discussed below in the Other Benefits section. This approach provides 
flexibility to transmission providers in how they implement the 
requirement to measure and use the required set of benefits in Long-
Term Regional Transmission Planning, while maintaining the baseline 
requirement that they measure and use all seven benefits included in 
that required set of benefits, in order to ensure that rates remain 
just and reasonable. Requiring all transmission providers to measure 
and use a required set of benefits will help to improve interregional 
transmission coordination among different transmission planning 
regions, as noted by commenters.\1626\
---------------------------------------------------------------------------

    \1626\ Breakthrough Energy Initial Comments at 22-23; California 
Commission Initial Comments at 33; Grid United Initial Comments at 
3; Policy Integrity Initial Comments at 27-28; US DOE Initial 
Comments at 31-32.
---------------------------------------------------------------------------

    730. In addition, as more fully described below, we also find that 
the seven benefits we require are not overly burdensome to calculate. 
We address such concerns for individual benefits in more detail within 
the determination section on each benefit below.
    731. Some commenters assert that some benefits are only appropriate 
for use in RTO/ISO transmission planning regions.\1627\ We believe that 
all seven required benefits can be calculated in both RTO/ISO and non-
RTO/ISO transmission planning regions, as noted by ACEG.\1628\ In 
particular, we note that all seven required benefits have either been 
approved for use in regional transmission planning in at least one non-
RTO/ISO transmission planning region or may be implemented by building 
upon the modeling or techniques used to measure benefits in RTO/ISO or 
non-RTO/ISO regions, or both.
---------------------------------------------------------------------------

    \1627\ Pacific Northwest Utilities Initial Comments at 8-10; 
SERTP Sponsors Initial Comments 29-30; Southern Initial Comments at 
25-27.
    \1628\ ACEG Initial Comments at 48.
---------------------------------------------------------------------------

    732. As described below, in the NOPR, the Commission noted that it 
approved the use of production cost savings (i.e., Benefit 3) to 
evaluate Order No. 1000 economic transmission projects in a non-RTO/ISO 
transmission planning region.\1629\ We note that, as measurements of 
reduced production costs outside of normal conditions, the measurement 
methods for Benefit 5, Reduced Congestion Due to Transmission Outages, 
and Benefit 6, Mitigation of Extreme Weather Events and Unexpected 
System Conditions, may be built upon the modeling used to measure 
Benefit 3. Separately, the Commission has accepted use of benefits in 
evaluating regional transmission facilities in Order No. 1000 regional 
transmission planning processes akin to Benefit 2(a), Reduced Loss of 
Load Probability,\1630\ and Benefit 4, Reduced Transmission Energy 
Losses, in non-RTO/ISO transmission planning regions.\1631\ In the 
NOPR, the Commission likewise noted that it has accepted accounting for 
the avoided costs (i.e., Benefit 1) as part of a method for identifying 
beneficiaries and allocating costs in almost all the regional cost 
allocation methods in non-RTO/ISO transmission planning regions.\1632\ 
With respect to Final Order Benefit 7 (i.e., capacity cost benefits 
from reduced peak energy losses), the avoided costs associated with 
this benefit are comparable across RTO/ISO and non-RTO/ISO transmission 
planning regions. Transmission providers in all transmission planning 
regions incur capital costs to meet installed generation requirements 
and to maintain reliable operations. Transmission expansions may help 
reduce peak energy losses, and under this benefit, result in capital 
cost savings associated with the reduction in installed generation 
requirements.
---------------------------------------------------------------------------

    \1629\ NOPR, 179 FERC ] 61,028 at P 201 (citing Pub. Serv. Co. 
of Colo., 142 FERC ] 61,206, at P 314 (2013)).
    \1630\ PacifiCorp, 147 FERC ] 61,057, at PP 133-134, 141-143 
(2014); Pub. Serv. Co. of Colo., 142 FERC ] 61,206 at P 314.
    \1631\ PacifiCorp, 147 FERC ] 61,057 at PP 132, 134, 141-143.
    \1632\ NOPR, 179 FERC ] 61,028 at PP 189-190 & n.326 (citing 
Order No. 1000, 136 FERC ] 61,051 at P 81).
---------------------------------------------------------------------------

    733. We disagree with commenters that express concerns that 
required benefits would conflict with state-regulated integrated 
resource planning processes.\1633\ As discussed in the Legal Authority 
to Adopt Reforms for Long-Term Regional Transmission Planning section, 
nothing in this final order infringes on the states' reserved authority 
under FPA section 201.
---------------------------------------------------------------------------

    \1633\ SERTP Sponsors Initial Comments at 30; Southern Initial 
Comments at 24-26.
---------------------------------------------------------------------------

    734. Entergy argues that the Commission should recognize that not 
all benefits are created equal for all jurisdictions and that some 
states will want transmission projects that actually reduce customer 
bills to have clear priority.\1634\ We believe that the required 
measurement and use of the required set of benefits can accommodate 
such preferences. Our requirements ensure that all benefits are 
measured transparently and considered in selection decisions. In 
addition, our required set of benefits captures considerations such as 
production cost savings that can flow through to customer bills. PJM, 
for example, notes that lower production costs will generally also 
reduce market prices for electricity as lower-cost suppliers will set 
market clearing prices more frequently than without the transmission 
project.\1635\ We note that while this final order requires the 
measurement and use of the required set of benefits, it is the 
evaluation process, including selection criteria, that transmission 
providers propose on compliance that will inform which Long-Term 
Regional Transmission Facilities are selected. Transmission providers 
may propose an evaluation process, including selection criteria, that 
reflect regional preferences as long as those criteria meet the 
requirements set forth below in the Evaluation and Selection of Long-
Term Regional Transmission Facilities section.
---------------------------------------------------------------------------

    \1634\ Entergy Initial Comments at 21.
    \1635\ PJM Initial Comments at 95.
---------------------------------------------------------------------------

    735. ISO-NE notes that the Commission sought information on 
potential double-counting of benefits and requests that the Commission 
clarify which benefits the Commission believes are redundant.\1636\ We 
believe that the seven benefits that we include in the required set of 
benefits that transmission providers must measure and use in Long-Term 
Regional Transmission Planning are distinct enough that they will not 
overlap in a way that results in double-counting. Nonetheless, to the 
extent that transmission providers are concerned that any possibility 
of double-counting remains, we provide transmission providers with 
flexibility on the measurement of such benefits and expect that 
transmission providers can use such flexibility to develop methods for 
measuring each required benefit that address those concerns.
---------------------------------------------------------------------------

    \1636\ ISO-NE Initial Comments at 34.
---------------------------------------------------------------------------

    736. Some commenters urge the Commission to adopt a combination or 
categorical approach toward benefits, under which required benefits 
would be grouped under certain categories or combinations.\1637\ We 
decline to adopt

[[Page 49399]]

this approach, largely because our analysis and review of the record 
suggests that such an approach could reduce transparency regarding the 
benefits that we are requiring. For example, in some cases adopting a 
combination or categories approach could obfuscate individual benefit 
calculations within a category, making it less clear to interested 
parties what specific benefits a Long-Term Regional Transmission 
Facility may provide. Additionally, we find that these seven benefits 
merit individual measurement and evaluation.
---------------------------------------------------------------------------

    \1637\ ACEG Reply Comments at 6-7; AEP Initial Comments at 23-
25; California Commission Initial Comments at 33; Entergy Initial 
Comments at 21; GridLab Initial Comments at 27; Joint Consumer 
Advocates Initial Comments at 11; PJM Initial Comments at 94-96.
---------------------------------------------------------------------------

    737. Northwest and Intermountain and NYISO ask that the final order 
confirm that the 12 illustrative benefits described in the NOPR are not 
exhaustive.\1638\ First, we confirm that the list of 12 illustrative 
benefits described in the NOPR is not an exhaustive list of the 
potential benefits of Long-Term Regional Transmission Facilities. 
Second, we reiterate that the required set of benefits adopted in this 
final order is a subset of the benefits listed in the NOPR, as modified 
in the discussions below. Transmission providers may be aware of 
additional benefits beyond those included in the required set of 
benefits, or the 12 illustrative benefits described in the NOPR, and we 
provide them with the flexibility to propose to measure and use 
additional benefits in Long-Term Regional Transmission Planning so long 
as they do so in a manner that is consistent with transmission 
providers' obligations under Order No. 890 and Order No. 1000 
transmission planning principles to be open and transparent as to their 
transmission planning processes. In particular, the evaluation process 
must result in a determination that is sufficiently detailed for 
stakeholders to understand why a particular Long-Term Regional 
Transmission Facility (or portfolio of such Facilities) was selected or 
not selected to address Long-Term Transmission Needs.\1639\ This 
necessarily means that stakeholders must understand which benefits 
transmission providers considered in the evaluation process, including 
any beyond the seven benefits that we require transmission providers to 
include in their OATTs. We find that this transparency strikes an 
appropriate balance between ensuring that transmission providers 
measure and use the seven required benefits in Long-Term Regional 
Transmission Planning and allowing flexibility for transmission 
providers to use additional benefits that they believe will reasonably 
reflect the benefits of a Long-Term Regional Transmission Facility or 
Facilities in their transmission planning regions.
---------------------------------------------------------------------------

    \1638\ Northwest and Intermountain Initial Comments at 16; NYISO 
Initial Comments at 39.
    \1639\ See infra Evaluation and Selection of Long-Term Regional 
Transmission Facilities section.
---------------------------------------------------------------------------

    738. OMS urges the Commission to clarify that transmission 
providers will have sufficient flexibility to use different sets of 
benefit metrics in different transmission planning cycles.\1640\ We 
clarify that transmission providers must use the required set of 
benefits to evaluate Long-Term Regional Transmission Facilities in 
every Long-Term Regional Transmission Planning cycle, and we discuss 
the use of other benefits to evaluate Long-Term Regional Transmission 
Facilities in the Other Benefits section of this final order.
---------------------------------------------------------------------------

    \1640\ OMS Initial Comments at 8.
---------------------------------------------------------------------------

    739. Some commenters suggest that the Commission allow transmission 
providers to use a screening approach that initially screens benefit 
categories for significance before investing staff resources and 
modeling work to provide a detailed quantification.\1641\ Clean Energy 
Buyers similarly argue that, at a minimum, the Commission should 
require that transmission providers screen for all 12 benefits 
described in the NOPR and quantify them accordingly.\1642\ We find such 
screening approaches, as advocated by some commenters, to be 
inconsistent with the approach we adopt in this final order, which 
requires measurement and use of each of the seven required benefits in 
Long-Term Regional Transmission Planning, and we are concerned that 
permitting the use of screens could undermine this requirement. We 
therefore do not allow transmission providers to use a screening 
approach when measuring the seven required benefits.
---------------------------------------------------------------------------

    \1641\ ACEG Initial Comments at 7, 33; ACORE Initial Comments at 
12; Breakthrough Energy Initial Comments at 22; CTC Global Initial 
Comments at 9; Interwest Initial Comments at 12-13; WATT Coalition 
Initial Comments at 7.
    \1642\ Clean Energy Buyers Initial Comments at 20-21.
---------------------------------------------------------------------------

2. Required Benefits
a. The Seven Required Benefits
i. Benefit 1: Avoided or Deferred Reliability Transmission Facilities 
and Aging Transmission Infrastructure Replacement
(a) NOPR Description
    740. The Commission described this benefit in the NOPR as the 
reduced costs of avoided or delayed transmission investment otherwise 
required to address reliability needs or replace aging transmission 
facilities. The Commission stated that, recognizing that regional 
transmission planning could lead to the development of transmission 
facilities that span the service territories of multiple transmission 
providers, which in turn would obviate the need for transmission 
facilities that would otherwise be identified in multiple local 
transmission plans, the Commission has accepted accounting for such 
``avoided costs'' as part of a method for identifying beneficiaries and 
allocating costs in almost all the regional cost allocation methods in 
non-RTO/ISO regions.\1643\ The Commission noted that, in using this 
method, transmission providers in a transmission planning region 
determine the beneficiaries of a regional transmission facility or 
portfolio of facilities by identifying the local and regional 
transmission facilities that a new proposed regional transmission 
facility or portfolio of facilities would displace. The Commission 
described the method as defining the benefits of the regional 
transmission facility or facilities as the costs that transmission 
providers in the transmission planning region ``avoid'' because they no 
longer need to build the displaced local and regional transmission 
facilities. Further, the Commission stated that the method allocates 
costs among transmission providers whose local or regional transmission 
facilities the new proposed regional transmission facility or 
facilities would displace in proportion to their share of the total 
benefits (i.e., the total avoided costs). If the new proposed regional 
transmission facility or facilities do not displace any local or 
regional transmission facilities in existing local or regional 
transmission plans, the Commission discussed that the avoided cost 
method determines the benefits of the applicable facilities by 
considering the costs of local or regional transmission facilities that 
would otherwise be needed to meet the same need that the new proposed 
regional transmission facility will meet.\1644\ The Commission noted 
that, in calculating this benefit, transmission providers in each 
transmission planning region could first identify transmission 
facilities that could defer or replace an identified reliability 
transmission solution. Avoided cost benefits could be calculated by 
comparing the cost of

[[Page 49400]]

transmission facilities required to address the reliability need 
without the proposed regional transmission facility to the cost of 
transmission facilities needed to address the reliability need assuming 
the regional transmission solution were in place.\1645\
---------------------------------------------------------------------------

    \1643\ NOPR, 179 FERC ] 61,028 at PP 189-190 (citing Order No. 
1000, 136 FERC ] 61,051 at P 81).
    \1644\ NOPR, 179 FERC ] 61,028 at P 190 (citing S.C. Elec. & Gas 
Co., 143 FERC ] 61,058, at P 232 (2013)).
    \1645\ Id. P 191 (citing Brattle-Grid Strategies Oct. 2021 
Report at 37).
---------------------------------------------------------------------------

    741. The Commission noted that Benefit 1 could also include the 
separate benefits stream caused by a deferral of replacement of other 
transmission facilities through identification and selection of a 
transmission facility or facilities. This could be measured through 
calculation of the present value savings for the period of deferral of 
additional replacement transmission facilities multiplied by their 
estimated capital cost.\1646\ The Commission also noted that a number 
of transmission providers already evaluate the avoided or deferred 
costs of reliability transmission projects. For example, SPP uses a 
power flow model to analyze the ability of potential economic and 
Public Policy Requirements transmission facilities to meet the same 
thermal reliability needs addressed by a potential reliability 
transmission facility. The costs of these avoided or delayed 
reliability transmission facilities are used to determine the 
reliability benefit of the potential economic or Public Policy 
Requirements transmission facilities.\1647\ The Commission stated that 
transmission providers could also use avoided costs to calculate the 
benefits of replacing aging transmission facilities. The Commission 
provided NYISO as an example, which estimates the benefits associated 
with the replacement of aging transmission facilities by quantifying 
the savings of not having to refurbish the facilities in the 
future.\1648\
---------------------------------------------------------------------------

    \1646\ Id. P 192.
    \1647\ Id. P 193 (citing SPP, SPP Benefit Metrics Manual, SPP 
Engineering, at 15 (Nov. 6, 2020)).
    \1648\ Id. P 193 (citing The Brattle Group, Benefit-Cost 
Analysis of Proposed New York AC Transmission Upgrades, at 114 
(Sept. 15, 2015)).
---------------------------------------------------------------------------

(b) Comments
    742. A number of commenters support mandating consideration of 
Benefit 1.\1649\ ACEG, for example, supports inclusion of this benefit, 
asserting that reliability considerations and replacing aging assets 
are responsible for almost all current transmission spending.\1650\ 
However, MISO states that, when capturing avoided transmission 
investment benefits, care must be exercised to avoid the counting of 
benefits associated with facility overloads that are identified in 
reliability studies and directly addressed by regional transmission 
projects. MISO indicates that this approach is necessary because the 
adjusted production cost savings benefits already reflect the 
congestion associated with these facility overloads.\1651\ Southern 
states that this benefit would likely prove workable under its non-RTO/
ISO construct because SERTP Sponsors' regional and interregional 
transmission planning and cost allocation processes already incorporate 
the benefit of ``avoided costs.'' \1652\
---------------------------------------------------------------------------

    \1649\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25; AEP Initial Comments at 25 (including Benefit 1 in 
its recommended minimum set of benefit categories); Amazon Initial 
Comments at 5; Breakthrough Energy Initial Comments at 21-22; 
Certain TDUs Reply Comments at 1-2; Clean Energy Associations 
Initial Comments at 19-20; DC and MD Offices of People's Counsel 
Initial Comments at 19-20; ENGIE Reply Comments at 3; Hannon 
Armstrong Initial Comments at 3; Interwest Initial Comments at 12-
14; National and State Conservation Organizations Initial Comments 
at 1; New Jersey Commission Initial Comments at 11-13; Pine Gate 
Initial Comments at 34-37; PIOs Initial Comments at 38-41; PJM 
Initial Comments at 96; RMI Initial Comments at 1; SEIA Initial 
Comments at 16; Southeast PIOs Initial Comments at 50; US DOE 
Initial Comments at 31-32.
    \1650\ ACEG Initial Comments at 34-35.
    \1651\ MISO Initial Comments at 50.
    \1652\ Southern Initial Comments at 25.
---------------------------------------------------------------------------

    743. Several commenters oppose or express concerns with mandating 
consideration of Benefit 1.\1653\ West Virginia Commission argues that 
calculation of this benefit requires evidence based on assumptions that 
are difficult, if not impossible, to quantify in advance.\1654\ Xcel 
states that benefit calculations can be different between the short-
term regional transmission planning process and Long-Term Regional 
Transmission Planning and that, for example, it would likely be 
unreasonable to determine reliability benefits in Long-Term Regional 
Transmission Planning using the avoided cost of local reliability 
solutions.\1655\
---------------------------------------------------------------------------

    \1653\ Joint Consumer Advocates Initial Comments at 11; NARUC 
Initial Comments at 22; West Virginia Commission Supplemental 
Comments at 4; Xcel Initial Comments at 13.
    \1654\ West Virginia Commission Supplemental Comments at 4.
    \1655\ Xcel Initial Comments at 13.
---------------------------------------------------------------------------

    744. NARUC states that, while Benefit 1 seems capable of 
calculation, it carries with it a degree of risk if aging transmission 
infrastructure continues to be operated. For instance, NARUC indicates 
that some wildfires have been linked to deferred transmission 
maintenance of aging infrastructure.\1656\ AEE responds by stating that 
the Commission should clarify: (1) its expectations regarding its 
calculation; and (2) that regional transmission built for inherently 
economic or public policy purposes has, when installed, avoided 
reliability cost benefits.\1657\ AEE argues that calculating the 
benefits of avoided investment in reliability or replacement facilities 
should not create an environment for continuously putting ``band aid'' 
fixes on aging systems that should instead be replaced to ensure 
reliability and resilience.\1658\
---------------------------------------------------------------------------

    \1656\ NARUC Initial Comments at 22.
    \1657\ AEE Reply Comments at 26 (citing NARUC Initial Comments 
at 22).
    \1658\ Id.
---------------------------------------------------------------------------

(c) Commission Determination
    745. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to measure 
and use Benefit 1, Avoided or Deferred Reliability Transmission 
Facilities and Aging Transmission Infrastructure Replacement, in Long-
Term Regional Transmission Planning. We adopt the NOPR's proposed 
description of Benefit 1 as the reduced costs due to avoided or delayed 
transmission investment otherwise required to address reliability needs 
or replace aging transmission facilities. We find that requiring the 
measurement and use of Benefit 1, as described, is necessary because 
Long-Term Regional Transmission Facilities may obviate or delay the 
need for reliability transmission facilities identified in the near 
term, or the need for later replacements of aging transmission 
infrastructure. Requiring transmission providers to measure and use the 
benefits associated with avoiding or delaying such transmission needs 
will help to ensure that, when conducting Long-Term Regional 
Transmission Planning, transmission providers identify, evaluate, and 
select Long-Term Regional Transmission Facilities that more efficiently 
or cost-effectively address Long-Term Transmission Needs.
    746. We note that a number of transmission providers already 
evaluate avoided or deferred costs of reliability transmission 
facilities. ACEG states that Benefit 1 reflects that reliability 
considerations and replacing aging assets drive significant investment 
in transmission and account for almost all current transmission 
spending.\1659\ SPP employs a power flow model to analyze the ability 
of potential economic and Public Policy Requirements transmission 
facilities to meet the same thermal reliability needs addressed by a

[[Page 49401]]

potential reliability transmission facility, using the costs of these 
avoided or delayed reliability transmission facilities to determine the 
reliability benefit of the potential economic or Public Policy 
Requirements transmission facilities.\1660\ Additionally, NYISO 
estimates the benefits associated with the replacement of aging 
transmission facilities by quantifying the savings of not having to 
refurbish the facilities in the future.\1661\ We find that widespread 
use of this benefit contradicts West Virginia Commission's assertion 
that calculation of this benefit requires evidence based on assumptions 
that are difficult, if not impossible, to quantify in advance, as well 
as similar assertions by Xcel.\1662\
---------------------------------------------------------------------------

    \1659\ ACEG Initial Comments at 34-35.
    \1660\ NOPR, 179 FERC ] 61,028 at P 193 (citing SPP, SPP Benefit 
Metrics Manual, SPP Engineering, at 15 (Nov. 6, 2020)).
    \1661\ Id. (citing The Brattle Group, Benefit-Cost Analysis of 
Proposed New York AC Transmission Upgrades, at 114 (Sept. 15, 
2015)).
    \1662\ West Virginia Commission Supplemental Comments at 4; Xcel 
Initial Comments at 13.
---------------------------------------------------------------------------

    747. We agree with NARUC and AEE that continued operation of aging 
infrastructure can carry risks if it is not properly maintained.\1663\ 
We note that nothing in this final order restricts an incumbent 
transmission provider from developing a local transmission facility to 
meet its reliability needs or service obligations in its own retail 
distribution service territory or footprint.\1664\ Such a solution 
would not be subject to approval at the regional or interregional level 
where the transmission provider does not seek to have it selected as a 
regional transmission facility for purposes of cost allocation.\1665\ 
Moreover, nothing in this final order requires transmission providers 
to keep transmission facilities in operation beyond their useful life. 
We emphasize that transmission providers can use Benefit 1 to calculate 
the costs that are avoided because replacements of local or regional 
transmission facilities are no longer needed, or may be deferred, when 
they are displaced by proposed new Long-Term Regional Transmission 
Facilities.
---------------------------------------------------------------------------

    \1663\ AEE Reply Comments at 26 (citing NARUC Initial Comments 
at 22); NARUC Initial Comments at 22.
    \1664\ Order No. 1000, 136 FERC ] 61,051 at PP 262, 329.
    \1665\ Id. P 384.
---------------------------------------------------------------------------

ii. Benefit 2(a): Reduced Loss of Load Probability or Benefit 2(b): 
Reduced Planning Reserve Margin
(a) NOPR Description
    748. The Commission described this benefit in the NOPR as being 
measured in one of two ways: (a) using reduced loss of load probability 
or (b) reduced planning reserve margin. The Commission noted that, 
because there is an overlap between reduced loss of load probability 
benefits and reduced planning reserve margin benefits, a single 
transmission facility can either reduce loss of load events if the 
planning reserve margin is unchanged or allow for the reduction in 
planning reserve margins if loss of load events remain constant, but 
not both simultaneously.\1666\
---------------------------------------------------------------------------

    \1666\ NOPR, 179 FERC ] 61,028 at P 194.
---------------------------------------------------------------------------

    749. The Commission described Benefit 2(a) in the NOPR as reduced 
frequency of loss of load events by providing additional pathways for 
connecting generation resources with load in regions that can be 
constrained by weather events and unplanned outages (if the planning 
reserve margin is not changed despite lower loss of load events), as 
well as improved physical reliability benefits by reducing the 
likelihood of load shed events.\1667\ The Commission noted that 
transmission investments, even those not made to satisfy a reliability 
need, generally enhance the reliability of the transmission system by 
increasing transfer capability, which, in turn, reduces the likelihood 
that a transmission provider will be unable to serve its load due to a 
shortage of generation over a given period. This enhancement in 
reliability can be measured as a reduction in loss of load probability, 
or the likelihood of system demand exceeding generation over a given 
period. The Commission noted that one example of how a reduction of 
loss of load probability benefit could be calculated can be found in a 
report by SPP's Metrics Task Force. The report proposes quantifying the 
incremental increase in system reliability by determining the reduction 
in expected unserved energy between the base case and the change case, 
obtaining the value of lost load, and multiplying these two values to 
obtain the monetary benefit of enhanced reliability associated with a 
transmission expansion.\1668\
---------------------------------------------------------------------------

    \1667\ Id.
    \1668\ Id. P 195 & n.331 (citing SPP, Benefits for the 2013 
Regional Cost Allocation Review, at 25 (Sept. 13, 2012)).
---------------------------------------------------------------------------

    750. The Commission described Benefit 2(b) in the NOPR as reduced 
planning reserve margin, or ``the reduction in capital costs of 
generation needed to meet resource adequacy requirements (i.e., 
planning reserve margins) while holding loss of load probability 
constant.'' \1669\ The Commission stated that investments in 
transmission capacity can reduce the system-wide planning reserve 
margin requirement or the reserve margin requirement within individual 
resource adequacy zones of a transmission planning region, which can 
reduce the need for generation capital expenditures.\1670\ The 
Commission also stated that it is important to note that, due to the 
overlap between the benefit obtained from a reduction in reserve margin 
requirements and the benefit associated with loss of load probability, 
only one of these benefits should be calculated for a transmission 
investment, but not both simultaneously.\1671\ The Commission noted 
that RTOs/ISOs have calculated the transmission benefits of reduced 
planning reserve margins. MISO, for example, calculated a reduction in 
planning reserves associated with its Multi-Value Projects portfolio, 
which reduced the need for future generation buildout to meet reserve 
requirements, by using loss of load expectation reliability 
simulations. MISO estimated that its Multi-Value Projects portfolio was 
expected to reduce the required planning reserve margin by up to one 
percentage point, which translated into a projected savings of $1.0 to 
$5.1 billion in benefits over 10 years.\1672\
---------------------------------------------------------------------------

    \1669\ Id. P 194.
    \1670\ Id. P 196.
    \1671\ Id.
    \1672\ Id. P 197 (citing Midcontinent Independent System 
Operator, Inc., Proposed Multi Value Project Portfolio: Business 
Case Workshop, at 36-38 (Sept. 19 & 29, 2011)).
---------------------------------------------------------------------------

(b) Comments
    751. A number of commenters support mandating consideration of 
Benefit 2(a).\1673\ Some commenters discuss the manner in which this 
benefit should be calculated.\1674\ ACEG and DC and MD Offices of 
People's Counsel note the importance of geographic diversity between 
transmission planning regions as an important consideration in 
evaluating this benefit.\1675\ Specifically, ACEG states that it can be 
estimated using the

[[Page 49402]]

value of lost load and generation capital cost savings due to lower 
needed planning reserve margins.\1676\
---------------------------------------------------------------------------

    \1673\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25: AEP Initial Comments at 25; Amazon Initial Comments 
at 5; Breakthrough Energy Initial Comments at 21-22; Clean Energy 
Associations Initial Comments at 19-20; DC and MD Offices of 
People's Counsel Initial Comments at 19-20; ENGIE Reply Comments at 
3; Hannon Armstrong Initial Comments at 3; Interwest Initial 
Comments at 12-14; National and State Conservation Organizations 
Initial Comments at 1; Pine Gate Initial Comments at 34-37; PIOs 
Initial Comments at 38-41; RMI Initial Comments at 1; SEIA Initial 
Comments at 16; Southeast PIOs Initial Comments at 50; US DOE 
Initial Comments at 31-32.
    \1674\ E.g., ACEG Initial Comments at 38-39.
    \1675\ ACEG Initial Comments at 35-38; DC and MD Offices of 
People's Counsel Initial Comments at 21-24.
    \1676\ ACEG Initial Comments at 38.
---------------------------------------------------------------------------

    752. However, some commenters oppose or express concerns regarding 
mandating consideration of Benefit 2(a).\1677\ NARUC states that 
transmission planners are likely already considering loss of load 
events in their evaluations of system expansions and that whether such 
benefit, in isolation, is sufficient to recommend construction of a 
particular transmission project is a question best left to them and 
their states.\1678\ West Virginia Commission argues that calculation of 
benefits from reduced loss of load probability requires evidence based 
on assumptions that are difficult, if not impossible, to quantify in 
advance.\1679\ R Street states that Benefit 2(a) should be refined to 
the avoided value of lost load so that it is compatible with an 
economic assessment, while Illinois Commission asserts that the 
Commission should consider a more expansive definition of reduced loss 
of load probability composed of more than one metric, such as value of 
lost load, expected unserved energy, or a hybrid measure, that can 
serve as a supplement to loss of load expectation.\1680\
---------------------------------------------------------------------------

    \1677\ NARUC Initial Comments at 23; Pacific Northwest Utilities 
Initial Comments at 9; West Virginia Commission Supplemental 
Comments at 4.
    \1678\ NARUC Initial Comments at 23.
    \1679\ West Virginia Commission Supplemental Comments at 4.
    \1680\ Illinois Commission Initial Comments at 14; R Street 
Initial Comments at 9.
---------------------------------------------------------------------------

    753. With respect to Benefit 2(b), a number of commenters support 
mandating consideration of this benefit.\1681\ AEP recommends including 
Benefit 2(b) as a part of a combination of benefits.\1682\ Pine Gate 
states that this proposed benefit is critical to address resource 
adequacy concerns, particularly where a transmission planning region 
relies heavily on a single generation type.\1683\
---------------------------------------------------------------------------

    \1681\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25; AEP Initial Comments at 25; Amazon Initial Comments 
at 5; Breakthrough Energy Initial Comments at 21-22; Clean Energy 
Associations Initial Comments at 19-20; DC and MD Offices of 
People's Counsel Initial Comments at 20; ENGIE Reply Comments at 3; 
Hannon Armstrong Initial Comments at 3; Interwest Initial Comments 
at 12-14; National and State Conservation Organizations Initial 
Comments at 1; Pine Gate Initial Comments at 34-37; PIOs Initial 
Comments at 38; RMI Initial Comments at 1; SEIA Initial Comments at 
16; Southeast PIOs Initial Comments at 50.
    \1682\ AEP Initial Comments at 25.
    \1683\ Pine Gate Initial Comments at 37.
---------------------------------------------------------------------------

    754. With respect to comments in opposition to Benefit 2(b), 
similar to its comments on Benefit 2(a) above, West Virginia Commission 
argues that calculation of benefits from reduced planning reserve 
margin requires evidence based on assumptions that are difficult, if 
not impossible, to quantify in advance.\1684\
---------------------------------------------------------------------------

    \1684\ West Virginia Commission Supplemental Comments at 4.
---------------------------------------------------------------------------

(c) Commission Determination
    755. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to measure 
and use Benefit 2, in Long-Term Regional Transmission Planning. This 
benefit can be characterized and measured as Benefit 2(a), Reduced Loss 
of Load Probability, or as Benefit 2(b), Reduced Planning Reserve 
Margin, and we clarify that these are different methods for measuring 
the same underlying benefit. We find that requiring the measurement and 
use of this benefit is necessary because it reflects an important 
category of reliability benefits of Long-Term Regional Transmission 
Facilities. Because there is an overlap between reduced loss of load 
probability benefits and reduced planning reserve margin benefits, for 
purposes of Long-Term Regional Transmission Planning, transmission 
providers must either measure reduced loss of load events by holding 
the planning reserve margin constant or measure the reduction in 
planning reserve margins by holding loss of load events constant but 
may not measure both simultaneously for purposes of using and measuring 
Benefit 2(a) or 2(b).
    756. We adopt the NOPR's proposed description of Benefit 2(a) that 
describes Benefit 2(a), Reduced Loss of Load Probability, as the 
reduced frequency of loss of load events by providing additional 
pathways for connecting generation resources with load in regions that 
can be constrained by weather events and unplanned outages (if the 
planning reserve margin is not changed despite lower loss of load 
events), as well as improved physical reliability benefits by reducing 
the likelihood of load shed events. Benefit 2(a) measures reduced loss 
of load probability for resource adequacy planning, which typically 
includes the consideration of normal system conditions. One method of 
measuring a reduction in loss of load probability benefit is to 
quantify the incremental increase in system reliability by determining 
the reduction in expected unserved energy between the base case and the 
change case, determining the value of lost load, and multiplying these 
two values to obtain the monetary benefit of enhanced reliability 
associated with a Long-Term Regional Transmission Facility or a 
portfolio of Long-Term Regional Transmission Facilities.\1685\
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    \1685\ NOPR, 179 FERC ] 61,028 at P 195 & n.331 (citing SPP, 
Benefits for the 2013 Regional Cost Allocation Review, at 25 (Sept. 
13, 2012)).
---------------------------------------------------------------------------

    757. Numerous commenters support mandating Benefit 2(a).\1686\ We 
recognize commenter suggestions regarding the method for calculating 
this benefit, with some recommending consideration of geographic 
diversity between transmission planning regions \1687\ and others 
recommending that the benefit be expressed in terms of the value of 
lost load.\1688\ We agree that geographic diversity is an important 
consideration in evaluating the reduced loss of load probability method 
of calculating this benefit and find that the flexibility in measuring 
benefits that we provide to transmission providers under this final 
order allows for this consideration. As to the suggestion by Illinois 
Commission and R Street that Benefit 2(a) should be expressed in terms 
of the value of lost load so that it can be expressed in terms of cost, 
we believe that either Benefit 2(a) or Benefit 2(b) are reasonable 
methods to calculate Benefit 2 and we reiterate that transmission 
providers can choose either method to calculate this benefit. We 
encourage transmission providers to consider whether Benefit 2(a) or 
Benefit 2(b) is the most effective way to accurately reflect the 
benefits of a proposed Long-Term Regional Transmission Facility in 
their individual regions. As to NARUC's contention that the benefit of 
reducing the probability of loss of load events, in isolation, may be 
insufficient to support the development of a particular

[[Page 49403]]

transmission project, while we are requiring transmission providers to 
use Benefit 2(a) or Benefit 2(b) to evaluate Long-Term Regional 
Transmission Facilities, we are not requiring transmission providers to 
base their evaluation on this single benefit--or any single benefit, 
for that matter--but rather on at least the range of benefits included 
in the required set of benefits that we adopt herein. Moreover, we are 
not requiring that transmission providers select any Long-Term Regional 
Transmission Facility.
---------------------------------------------------------------------------

    \1686\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25: AEP Initial Comments at 25; Amazon Initial Comments 
at 5; Breakthrough Energy Initial Comments at 21-22; Clean Energy 
Associations Initial Comments at 19-20; DC and MD Offices of 
People's Counsel Initial Comments at 19-20; ENGIE Reply Comments at 
3; Hannon Armstrong Initial Comments at 3; Interwest Initial 
Comments at 12-14; National and State Conservation Organizations 
Initial Comments at 1; Pine Gate Initial Comments at 34-37; PIOs 
Initial Comments at 38-41; RMI Initial Comments at 1; SEIA Initial 
Comments at 16; Southeast PIOs Initial Comments at 50; US DOE 
Initial Comments at 31-32.
    \1687\ ACEG Initial Comments at 35-38; DC and MD Offices of 
People's Counsel Initial Comments at 21-24.
    \1688\ Illinois Commission Initial Comments at 14 (suggesting 
alternatively that Benefit 2(a) be expressed in terms of expected 
unserved energy, or a hybrid measurement composed of more than one 
metric); R Street Initial Comments at 9 (stating that using value of 
lost load is compatible with an economic assessment).
---------------------------------------------------------------------------

    758. As noted above, the NOPR proposed the following description of 
Benefit 2(b), ``the reduction in capital costs of generation needed to 
meet resource adequacy requirements (i.e., planning reserve margins) 
while holding loss of load probability constant.'' \1689\ We adopt the 
NOPR description in this final order. We find that a lower planning 
reserve margin is another way to demonstrate a resource adequacy 
benefit. As we indicate above, due to the relationship between the 
benefit obtained from a reduction in reserve margin requirements and 
the benefit associated with reduced loss of load probability, only one 
of these methods for calculating the benefit for a transmission 
investment can be used, but not both simultaneously. We find that 
Benefit 2(b) is one of two ways to calculate reduced costs related to 
resource adequacy because Long-Term Regional Transmission Facilities 
can reduce the system-wide planning reserve margin requirements within 
individual resource adequacy zones of a transmission planning region 
and provide benefits by reducing the need for generation capital 
expenditures.
---------------------------------------------------------------------------

    \1689\ NOPR, 179 FERC ] 61,028 at P 194.
---------------------------------------------------------------------------

    759. Many commenters support mandating consideration of Benefit 
2(b). For example, DC and MD Offices of People's Counsel note that the 
benefit of a reduced reserve planning margin has been used in multiple 
cases.\1690\ We also find that it is feasible for transmission 
providers to calculate the benefit of reduced planning reserve margins. 
We reiterate here the example of MISO, which calculated a reduction in 
planning reserves associated with its Multi-Value Projects portfolio, 
reducing the need for future generation investments to meet reserve 
requirements by using loss of load expectation reliability simulations. 
MISO estimated that its Multi-Value Projects portfolio was expected to 
reduce the required planning reserve margin by up to one percentage 
point, which translated into a projected savings of $1.0 to $5.1 
billion in benefits over 10 years.\1691\ We also note that the 
Commission has accepted benefits for use in evaluating regional 
transmission facilities in Order No. 1000 regional transmission 
planning processes akin to Benefit 2(a), Reduced Loss of Load 
Probability,\1692\ in non-RTO/ISO transmission planning regions.\1693\
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    \1690\ DC and MD Offices of People's Counsel at 22-23 (citing 
Midcontinent Independent System Operator, Inc., Proposed Multi Value 
Project Portfolio: Business Case Workshop, at 36-38 (Sept. 19 & 29, 
2011); SPP, Benefits for the 2013 Regional Cost Allocation Review 
(Sept. 13, 2012); Investigation on Comm'n's Own Motion to Review 18 
Percent Planning Reserve Margin Requirement, Docket No. 5-EI-141 
(PSC REF# 102692), at 5 (Pub. Serv. Comm'n Wis. Oct. 9, 2008); SPP, 
The Value of Transmission, at 16 (Jan. 26, 2016); Midcontinent 
Independent System Operator, Inc., MISO Value Proposition 2020: 
Forward View, at 20-21 (June 2022); PJM Interconnection, L.L.C., PJM 
Value Proposition, at 2 (2019); Australian Energy Market Operator, 
2022 Integrated System Plan, at 64 (June 2022)).
    \1691\ NOPR, 179 FERC ] 61,028 at P 197 (citing Midcontinent 
Independent System Operator, Inc., Proposed Multi Value Project 
Portfolio: Business Case Workshop, at 36-38 (Sept. 19 & 29, 2011)).
    \1692\ PacifiCorp, 147 FERC ] 61,057 at PP 133-134, 141-143; 
Pub. Serv. Co. of Colo., 142 FERC ] 61,206 at P 314.
    \1693\ PacifiCorp, 147 FERC ] 61,057 at PP 132, 134, 141-143.
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    760. Finally, we disagree with West Virginia Commission's claim 
that calculation of this benefit requires evidence based on assumptions 
that are difficult, if not impossible, to quantify in advance.\1694\ As 
noted above, there are multiple examples in the record of transmission 
providers that currently calculate these benefits. Because we find that 
transmission providers will be able to calculate either Benefit 2(a) or 
2(b) and recognize the importance of accounting for Benefit 2 in Long-
Term Regional Transmission Planning, we require transmission providers 
to measure and use Benefit 2.
---------------------------------------------------------------------------

    \1694\ West Virginia Commission Supplemental Comments at 4.
---------------------------------------------------------------------------

iii. Benefit 3: Production Cost Savings
(a) NOPR Description
    761. The Commission described Benefit 3 in the NOPR as savings in 
fuel and other variable operating costs of power generation that are 
realized when transmission facilities allow for displacement of higher-
cost supplies through the increased dispatch of suppliers that have 
lower incremental costs of production, as well as a reduction in market 
prices as lower-cost suppliers set market clearing prices.\1695\ The 
Commission stated that most regional transmission planning processes 
currently estimate production cost savings. Generally, within RTOs/
ISOs, security-constrained production cost models simulate the hourly 
operations of the electric system and the wholesale electricity market 
by emulating how system operators would commit and dispatch generation 
resources to serve load at least cost, subject to transmission and 
operating constraints. The traditional method for estimating the 
changes in adjusted production costs associated with proposed 
transmission facilities (or portfolio of facilities) is to compare the 
adjusted production costs with and without those facilities. Analysts 
typically call the market simulations without the proposed transmission 
facilities the ``Base Case'' and the simulations with those facilities 
the ``Change Case.'' \1696\
---------------------------------------------------------------------------

    \1695\ NOPR, 179 FERC ] 61,028 at P 198 & n.333 (proposing to 
define this as adjusted production cost savings when the calculation 
is adjusted to account for purchases and sales outside the region).
    \1696\ NOPR, 179 FERC ] 61,028 at P 199.
---------------------------------------------------------------------------

    762. The Commission further explained that approaches used to 
calculate production cost savings vary. MISO uses production cost 
savings (adjusted for import costs and export revenues) to allocate the 
costs of its Market Efficiency Projects to cost allocation zones based 
on each zone's share of the total adjusted production cost 
savings.\1697\ The Commission also explained, in contrast, that NYISO 
and PJM use reductions to load energy payments (adjusted to reflect the 
reduced value of transmission congestion contracts) to allocate the 
costs of economic transmission facilities.\1698\
---------------------------------------------------------------------------

    \1697\ NOPR, 179 FERC ] 61,028 at P 200 (citing MISO, FERC 
Electric Tariff, attach. FF, Benefit Metrics section (I)(A)(1) 
(33.0.0)).
    \1698\ NOPR, 179 FERC ] 61,028 at P 200 & n.335 (citing PJM 
Interconnection L.L.C., 142 FERC ] 61,214 at P 416; N.Y. Indep. Sys. 
Operator Corp., 143 FERC ] 61,059, at PP 268, 269, n.516 (2013); 
NYISO, NYISO Tariffs, OATT, attach. Y, section 31.5 (Cost Allocation 
and Cost Recovery) (30.0.0), section 31.5.4.3.2.) (``For high 
voltage economic transmission facilities, PJM allocates 50% of the 
costs in accordance with its economic analysis and allocates the 
other 50% of the costs on a load-ratio share basis.'').
---------------------------------------------------------------------------

    763. The Commission stated that non-RTO/ISO regions, without 
centrally organized energy markets, rely on other tools to perform 
analyses of production cost savings. For example, WestConnect's 
regional cost allocation method for regional transmission facilities 
driven by economic considerations identifies the benefits and 
beneficiaries of a proposed regional transmission facility or 
facilities by modeling the potential of the transmission facilities to 
support more economic bilateral transactions between generators and 
loads in the region. Specifically, WestConnect considers the 
transactions between loads and lower-

[[Page 49404]]

cost generation that a proposed regional transmission facility could 
support and, accounting for the costs associated with transmission 
service, identifies the transactions that are likely to occur. 
WestConnect then estimates any resulting cost savings (in the form of 
reductions in production costs and reserve sharing requirements) and 
allocates the costs of the regional transmission facilities on that 
basis.\1699\
---------------------------------------------------------------------------

    \1699\ NOPR, 179 FERC ] 61,028 at P 201 (citing Pub. Serv. Co. 
of Colo., 142 FERC ] 61,206 at P 314).
---------------------------------------------------------------------------

(b) Comments
    764. A number of commenters support mandating consideration of this 
benefit.\1700\ AEP recommends including Benefit 3 as a part of a 
combination of benefits.\1701\ According to TAPS, all of the RTOs/ISOs 
already consider production cost savings; TAPS argues that the 
Commission should require transmission providers in non-RTO/ISO 
transmission planning regions to consider them as well.\1702\ Indicated 
PJM TOs state that this benefit is one of the main benefits that will 
drive the selection of transmission facilities in PJM.\1703\
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    \1700\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25; AEP Initial Comments at 25; Amazon Initial Comments 
at 5; Breakthrough Energy Initial Comments at 21-22; Certain TDUs 
Reply Comments at 1-2; Clean Energy Associations Initial Comments at 
19-20; DC and MD Offices of People's Counsel Initial Comments at 19-
20; ENGIE Reply Comments at 3; Hannon Armstrong Initial Comments at 
3; Interwest Initial Comments at 12-14; National and State 
Conservation Organizations Initial Comments at 1; Joint Consumer 
Advocates Initial Comments at 11; New Jersey Commission Initial 
Comments at 13-14 (including reduced production costs during 
transmission outages, extreme events, and higher than normal load 
conditions in Benefit 3); Pine Gate Initial Comments at 34-37; PIOs 
Initial Comments at 38-41; PJM Initial Comments at 96; RMI Initial 
Comments at 1; SEIA Initial Comments at 16; Southeast PIOs Initial 
Comments at 50; TAPS Initial Comments at 14; US DOE Initial Comments 
at 31-32.
    \1701\ AEP Initial Comments at 25.
    \1702\ TAPS Initial Comments at 14.
    \1703\ Indicated PJM TOs Initial Comments at 17.
---------------------------------------------------------------------------

    765. Some commenters opine on how to calculate this benefit.\1704\ 
ACEG states that production cost savings should include fuel and 
variable operating cost savings, adjustments for imports from 
neighboring transmission planning regions, reduced costs of cycling 
power plants, reduced amounts and costs of operating reserves and other 
ancillary services, and mitigation of reliability-must-run 
conditions.\1705\ Likewise, DC and MD Offices of People's Counsel state 
that production cost savings should include ancillary service cost 
savings.\1706\ MISO notes that, in addition to evaluating production 
cost savings under normal patterns of renewable dispatch and load, 
transmission providers can analyze production cost savings that accrue 
during transmission outages using historical sampling or statistical 
modeling of transmission outage patterns.\1707\ MISO TOs state that its 
process to evaluate Multi-Value Projects considers production cost 
savings that can be realized through reduced transmission congestion 
and transmission energy losses, capacity loss savings, capacity 
savings, long-term cost savings, and ``any other financially 
quantifiable benefit.''\1708\
---------------------------------------------------------------------------

    \1704\ ACEG Initial Comments at 40; DC and MD Offices of 
People's Counsel Initial Comments at 25; GridLab Initial Comments at 
26-27; MISO Initial Comments at 49-50.
    \1705\ ACEG Initial Comments at 40.
    \1706\ DC and MD Offices of People's Counsel Initial Comments at 
25.
    \1707\ MISO Initial Comments at 49-50.
    \1708\ MISO TOs Initial Comments at 21 (citing MISO Open Access 
Transmission, Energy and Operating Reserve Markets Tariff, attach. 
FF (90.0.0), section II.C.5).
---------------------------------------------------------------------------

    766. Some commenters oppose or express concerns regarding mandating 
consideration of production cost savings.\1709\ For example, Southern 
states that considering production cost savings could result in the 
double-counting of benefits in its footprint by, for example, making 
generation pricing/cost decisions that have already been made or will 
ultimately be made in integrated resource planning or request for 
proposal processes.\1710\ Relatedly, North Carolina Commission and 
Staff state that requiring consideration of production cost savings 
would conflict with state-jurisdictional resource decisions.\1711\ 
Mississippi Commission contends that this benefit may not always be 
applicable, such as where financial transmission rights fully hedge the 
cost of congestion.\1712\ PJM Market Monitor states that in PJM, 
comparing production cost savings across different gas prices and 
different generation resource capacity may not provide meaningful 
guidance as to the benefits of a transmission facility beyond that 
currently provided by satisfying reliability criteria because of 
potentially inaccurate forecasts for key values.\1713\ Pacific 
Northwest Utilities assert that this benefit is not easily 
quantifiable.\1714\
---------------------------------------------------------------------------

    \1709\ Mississippi Commission Initial Comments at 35-36; North 
Carolina Commission and Staff Initial Comments at 7; Pacific 
Northwest Utilities Initial Comments at 9; PJM Market Monitor 
Initial Comments at 5; Southern Initial Comments at 26.
    \1710\ Southern Initial Comments at 26 (citing Southern Initial 
Comments Ex. 1, ]] 8, 15).
    \1711\ North Carolina Commission and Staff Initial Comments at 
7.
    \1712\ Mississippi Commission Initial Comments at 36.
    \1713\ PJM Market Monitor Initial Comments at 5.
    \1714\ Pacific Northwest Utilities Initial Comments at 9.
---------------------------------------------------------------------------

(c) Commission Determination
    767. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to measure 
and use Benefit 3, Production Cost Savings, in Long-Term Regional 
Transmission Planning. We adopt the NOPR's proposed description of 
Benefit 3 as savings in fuel and other variable operating costs of 
power generation that are realized when transmission facilities allow 
for displacement of higher-cost supplies through the increased dispatch 
of suppliers that have lower incremental costs of production, as well 
as a reduction in market prices as lower-cost suppliers set market 
clearing prices. We find that requiring the use of Benefit 3 is 
necessary because Long-Term Regional Transmission Facilities could 
result in savings in fuel and other variable operating costs of power 
generation that are realized when transmission facilities allow for 
displacement of higher-cost supplies through the increased dispatch of 
suppliers that have lower incremental costs of production. We further 
find that, absent a requirement for transmission providers to measure 
and use Benefit 3 in Long-Term Regional Transmission Planning, 
transmission providers may not identify, evaluate, and select Long-Term 
Regional Transmission Facilities that more efficiently or cost-
effectively address Long-Term Transmission Needs.
    768. We do not require a standardized method for measuring 
production cost savings, and, consistent with this approach, we decline 
commenter requests to specify the exact types of cost savings for which 
transmission providers must account when measuring this benefit.\1715\ 
As the Commission stated in the NOPR,\1716\ different transmission 
planning regions have different approaches toward the calculation of 
this benefit, and this final order provides flexibility for 
transmission providers in developing the method that they use to 
measure production cost savings, consistent with the requirement to 
measure and use the required set of benefits in Long-Term Regional 
Transmission Planning described above.
---------------------------------------------------------------------------

    \1715\ See ACEG Initial Comments at 40; DC and MD Offices of 
People's Counsel Initial Comments at 25; GridLab Initial Comments at 
26-27; MISO Initial Comments at 49-50.
    \1716\ NOPR, 179 FERC ] 61,028 at PP 200-201.

---------------------------------------------------------------------------

[[Page 49405]]

    769. We note that Benefit 3 is distinct from other benefits that we 
require transmission providers to measure and use in Long-Term Regional 
Transmission Planning. Although Benefit 3 and Benefit 6, as described 
in this final order, both measure production cost savings (including 
savings that occur during generation outage contingencies), the system 
conditions used in calculating each benefit are distinct. For example, 
Benefit 6 can include higher electricity demand, forecast errors, 
volatile production costs, and a more expansive set of generation 
outages such as unplanned generation outages due to extreme weather. 
And as we discuss below in the context of Benefit 5, because Benefit 3, 
Production Cost Savings, as described in this order, does not capture 
production cost savings during transmission outages, we require 
transmission providers to measure and use Benefit 5 to ensure that they 
are accounting for reduced production costs during transmission outages 
as well.
    770. We also do not believe that requiring transmission providers 
to measure and use Benefit 3 in Long-Term Regional Transmission 
Planning will, as Southern suggests, result in double-counting of 
benefits because such benefits are also considered in state resource 
planning. While we acknowledge that integrated resource planning 
processes, where they exist, may consider similar benefits compared to 
those required by this final order, the consideration of benefits in a 
state-jurisdictional process does not result in the double-counting of 
benefits within any Commission-jurisdictional transmission planning 
process. Because practices affecting rates, terms, and conditions for 
interstate transmission service are the exclusive jurisdiction of the 
Commission, we must ensure that Commission-jurisdictional regional 
transmission planning processes result in rates that are just and 
reasonable and not unduly or discriminatory. To this end, this final 
order is focused on ensuring that, when conducting Long-Term Regional 
Transmission Planning, transmission providers consider the broader set 
of benefits provided by Long-Term Regional Transmission Facilities so 
that they may determine whether to select such facilities as the more 
efficient or cost-effective regional transmission solution to address 
Long-Term Transmission Needs.
    771. Pacific Northwest Utilities assert that production cost 
savings are not easily quantifiable.\1717\ We acknowledge that there 
are some challenges associated with measuring this benefit, but we 
conclude that it is nonetheless necessary to require such measurement 
in order to ensure that transmission rates are just, reasonable, and 
not unduly discriminatory or preferential. We also note that there is 
an abundance of examples of how transmission providers can measure this 
benefit. Production cost savings are used extensively in many 
transmission planning regions, including MISO, NYISO, PJM, SPP, CAISO, 
ISO-NE, NorthernGrid, and WestConnect.\1718\ We believe that 
transmission providers are capable of measuring production cost savings 
given that this benefit has been used as a metric in transmission 
planning for decades.
---------------------------------------------------------------------------

    \1717\ Pacific Northwest Utilities Initial Comments at 9.
    \1718\ See NOPR, 179 FERC ] 61,028 at PP 200-201; Brattle-Grid 
Strategies Oct. 2021 Report at 31; ISO New England, Inc., 
Transmission Planning: Maintaining Power System Reliability Amid 
Change, https://www.iso-ne.com/system-planning/transmission-planning 
(last visited Mar. 25, 2024); NorthernGrid, Study Scope for the 
2022-2023 NorthernGrid Planning Cycle, 2 (Sept. 21, 2022), https://www.northerngrid.net/private-media/documents/NG_Study_Scope_2022-2023_Approved.pdf; The Brattle Group, The Benefits of Electric 
Transmission: Identifying and Analyzing the Value of Investments, 31 
(July 2013), https://www.brattle.com/wp-content/uploads/2021/06/The-Benefits-of-Electric-Transmission-Identifying-and-Analyzing-the-Value-of-Investments.pdf (noting that in the Western Electricity 
Coordinating Council (WECC), whose service area includes one RTO 
(CAISO) and three non-RTO regions (ColumbiaGrid, Northern Tier 
Transmission Group (NTTG), and WestConnect) production costs 
simulations are used to calculate the energy costs savings of 
transmission projects in WECC's long-term transmission planning 
studies).
---------------------------------------------------------------------------

    772. In response to North Carolina Commission and Staff's 
contention that requiring consideration of production cost savings 
conflicts with state-jurisdictional resource decisions,\1719\ we find 
that North Carolina Commission and Staff have failed to explain why 
there may be a conflict. As noted in the Need for Reform, there are 
deficiencies in the Commission's existing transmission planning and 
cost allocation requirements, including that they fail to require 
transmission providers to adequately consider the broader set of 
benefits of regional transmission facilities planned to meet Long-Term 
Transmission Needs. We are concerned that failing to adequately 
identify and consider the benefits, including production cost benefits, 
of such transmission facilities may lead to relatively inefficient and 
less cost-effective transmission development. Additionally, as 
described above in the Categories of Factors section, transmission 
providers must incorporate, and not discount, state-jurisdictional 
resource decisions, such as integrated resource plans, into all Long-
Term Scenarios to identify Long-Term Transmission Needs. Therefore, we 
believe that requiring transmission providers to measure production 
cost savings will not conflict with state-jurisdictional resource 
decisions, because the effects of such resource decisions on Long-Term 
Transmission Needs must be fully accounted for in all Long-Term 
Scenarios, which are used to help identify more efficient or cost-
effective regional transmission solutions within the Commission-
jurisdictional regional transmission planning process. Moreover, as 
discussed in the Legal Authority to Adopt Reforms for Long-Term 
Regional Transmission Planning section of this final order, nothing in 
this final order conflicts with or infringes on the states' reserved 
authority under FPA section 201.
---------------------------------------------------------------------------

    \1719\ North Carolina Commission and Staff Initial Comments at 
7.
---------------------------------------------------------------------------

    773. We disagree with Mississippi Commission's assertion that 
production cost savings may not always be applicable, such as where 
financial transmission rights fully hedge the cost of congestion.\1720\ 
Financial transmission rights are required in RTO/ISO markets and allow 
the market participant that owns the right to mitigate the congestion 
charge along an existing transmission path for the capacity of that 
path.\1721\ A new transmission facility could reduce congestion and 
allow that market participant to purchase more electricity, exceeding 
the capacity of the transmission path for the financial transmission 
right, at a lower price. This reduced congestion allows for load to 
access lower cost resources, and results in more efficient dispatch of 
resources and, thus, provides avoided production cost benefits that are 
distinct from the avoided congestion charges associated with financial 
transmission rights.
---------------------------------------------------------------------------

    \1720\ Mississippi Commission Initial Comments at 36.
    \1721\ Long-Term Firm Transmission Rights in Organized Elec. 
Mkts., Order No. 681, 116 FERC ] 61,077, at PP 5, 19-21, reh'g 
denied, Order No. 681-A, 117 FERC ] 61,201 (2006), order on reh'g & 
clarification, Order No. 681-B, 126 FERC ] 61,254 (2009).
---------------------------------------------------------------------------

    774. We recognize the PJM Market Monitor's concern regarding the 
potential for inaccurate forecasts of key inputs to the calculation of 
production cost savings.\1722\ However, we conclude that this potential 
concern does not outweigh the value of measuring and using this 
benefit, as demonstrated by long-standing use of this benefit within 
PJM and other transmission planning regions, including all RTOs/ISOs 
and some non-RTO/ISO regions. Moreover,

[[Page 49406]]

as noted in the Long-Term Scenarios section of this final order, the 
use of Long-Term Scenarios in Long-Term Regional Transmission Planning 
mitigates such uncertainty in transmission planning outcomes. 
Specifically, comparing the production cost savings, as well as the 
other benefits that we require transmission providers to measure and 
use in Long-Term Regional Transmission Planning, provided by Long-Term 
Transmission Facilities across three distinct Long-Term Scenarios 
should help to address the uncertainty noted by the PJM Market Monitor.
---------------------------------------------------------------------------

    \1722\ PJM Market Monitor Initial Comments at 5.
---------------------------------------------------------------------------

iv. Benefit 4: Reduced Transmission Energy Losses
(a) NOPR Description
    775. The Commission described this benefit in the NOPR as reduced 
total energy necessary to meet demand stemming from reduced energy 
losses incurred in transmittal of power from generation to loads.\1723\
---------------------------------------------------------------------------

    \1723\ NOPR, 179 FERC ] 61,028 at P 202.
---------------------------------------------------------------------------

    776. The Commission explained that production cost savings metrics 
used today typically exclude reduced transmission energy losses and 
three other production cost savings-related benefits proposed in the 
NOPR. The Commission also stated that including those additional 
proposed benefits can produce a more robust set of congestion and 
production cost benefits that can be quantified and integrated into the 
method for calculating production cost savings and, therefore, help to 
ensure that more efficient or cost-effective transmission facilities 
are selected through Long-Term Regional Transmission Planning.\1724\
---------------------------------------------------------------------------

    \1724\ Id. P 203.
---------------------------------------------------------------------------

    777. The Commission noted that to measure reduced transmission 
energy losses, transmission providers could: (1) simulate losses in 
production cost models; (2) estimate changes in losses with power flow 
models for a range of hours; or (3) estimate how the cost of supplying 
losses will likely change with marginal loss charges. For example, ATC 
measured reduced transmission energy losses based on changes in 
marginal loss charges and loss refund estimates using the marginal loss 
component from the PROMOD \1725\ electric market simulation software 
simulations for the Paddock-Rockdale 345 kV Access Project,\1726\ which 
produced cost reduction benefits using adjusted production cost 
analysis. Also, SPP's analysis for its Regional Cost Allocation Review 
process estimated energy loss reductions through post-processing the 
marginal loss component of the locational marginal prices in PROMOD 
simulation results.\1727\
---------------------------------------------------------------------------

    \1725\ PROMOD is a generator and portfolio modeling system. 
Hitachi Energy: PROMOD, https://www.hitachienergy.com/us/en/products-and-solutions/energy-portfolio-management/enterprise/promod 
(last visited Apr. 2024).
    \1726\ NOPR, 179 FERC ] 61,028 at P 204 & n.338 (citing ATC, 
Planning Analysis of the Paddock-Rockdale Project, Docket No. 137-
CE-149, app. C, Ex. 1, at 34-38 (Wisc. Pub. Serv. Comm'n Apr. 5, 
2007)).
    \1727\ SPP, SPP Regional Cost Allocation Review Report for RCAR 
II, at 56, 64 (July 11, 2016), https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf.
---------------------------------------------------------------------------

(b) Comments
    778. A number of commenters support mandating consideration of 
Benefit 4.\1728\ While not favoring a benefits measurement requirement, 
Southern states that this benefit would likely prove workable under 
Southern's non-RTO/ISO construct because SERTP Sponsors' regional and 
interregional transmission planning and cost allocation processes 
already incorporate the benefit of reduced transmission energy 
losses.\1729\
---------------------------------------------------------------------------

    \1728\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy 
Initial Comments at 21-22; Clean Energy Associations Initial 
Comments at 19-20; DC and MD Offices of People's Counsel Initial 
Comments at 19-20; ENGIE Reply Comments at 3; Hannon Armstrong 
Initial Comments at 3; Interwest Initial Comments at 12-14; National 
and State Conservation Organizations Initial Comments at 1; New 
Jersey Commission Initial Comments at 13-14; Pine Gate Initial 
Comments at 34-37; PIOs Initial Comments at 38-41; RMI Initial 
Comments at 1; SEIA Initial Comments at 16; Southeast PIOs Initial 
Comments at 50; US DOE Initial Comments at 31-32.
    \1729\ Southern Initial Comments at 25.
---------------------------------------------------------------------------

    779. Several commenters comment on the manner in which Benefit 4 
should be calculated.\1730\ ACEG states that this benefit has been 
calculated in various studies.\1731\
---------------------------------------------------------------------------

    \1730\ ACEG Initial Comments at 41; NARUC Initial Comments at 23 
(noting that advanced technologies also provide this benefit and 
should be preferred over greenfield construction); Utah Division of 
Public Utilities Initial Comments at 8.
    \1731\ ACEG Initial Comments at 41 (citing ATC, Planning 
Analysis of the Paddock-Rockdale Project, app. C Ex. 1, at 34-38 
(Wisc. Pub. Serv. Docket No. 137-CE-149); SPP, Regional Cost 
Allocation Review Report for RCAR II, at 5 (July 11, 2016), https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf).
---------------------------------------------------------------------------

    780. West Virginia Commission opposes the use of Benefit 4, arguing 
that the calculation of benefits from reduced transmission losses 
requires significant evidence based on assumptions that are difficult, 
if not impossible, to quantify before the fact.\1732\
---------------------------------------------------------------------------

    \1732\ West Virginia Commission Supplemental Comments at 4.
---------------------------------------------------------------------------

(c) Commission Determination
    781. We adopt the NOPR proposal, with modification, to require 
transmission providers to measure and use Benefit 4, Reduced 
Transmission Energy Losses, in Long-Term Regional Transmission 
Planning. We adopt the NOPR's proposed description of Benefit 4, as 
modified, as the reduced total energy necessary to meet demand stemming 
from reduced energy losses incurred in transmittal of power from 
generation to loads. We find that requiring the measurement and use of 
Benefit 4 in Long-Term Regional Transmission Planning is necessary 
because reduced energy losses are widely understood to be a benefit of 
transmission facilities.\1733\ As such, we find that transmission 
providers must measure and use this benefit in Long-Term Regional 
Transmission Planning because it will help to ensure that they 
identify, evaluate, and select more efficient or cost-effective 
regional transmission solutions to address Long-Term Transmission 
Needs.
---------------------------------------------------------------------------

    \1733\ See Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy 
Initial Comments at 21-22; Clean Energy Associations Initial 
Comments at 19-20; DC and MD Offices of People's Counsel Initial 
Comments at 19-20; ENGIE Reply Comments at 3; Hannon Armstrong 
Initial Comments at 3; Interwest Initial Comments at 12-14; National 
and State Conservation Organizations Initial Comments at 1; New 
Jersey Commission Initial Comments at 11-14; Pine Gate Initial 
Comments at 34-37; PIOs Initial Comments at 38-41; RMI Initial 
Comments at 1; SEIA Initial Comments at 16; Southeast PIOs Initial 
Comments at 50; US DOE Initial Comments at 31-32.
---------------------------------------------------------------------------

    782. We recognize that there are multiple ways for transmission 
providers to measure reduced transmission energy losses.\1734\ We note 
that this final order does not require transmission providers to adopt 
any single method to measure reduced transmission energy losses. As 
described in the NOPR, transmission providers could: (1) simulate 
losses in production cost models; (2) estimate changes in losses with 
power flow models for a range of hours; or (3) estimate how the cost of 
supplying losses will likely change with marginal loss charges.\1735\ 
Transmission providers could also follow the example of ATC, which 
measured reduced transmission energy losses based on changes in 
marginal loss charges and loss refund estimates provided by the PROMOD 
electric market simulation software.\1736\

[[Page 49407]]

Similarly, SPP estimates energy loss reductions through its Regional 
Cost Allocation Review process by post-processing the marginal loss 
component of the locational marginal prices in PROMOD simulation 
results.\1737\
---------------------------------------------------------------------------

    \1734\ See, e.g., ACEG Initial Comments at 41 (citing studies in 
which Benefit 4 has been calculated).
    \1735\ NOPR, 179 FERC ] 61,028 at P 204.
    \1736\ ATC, Planning Analysis of the Paddock-Rockdale Project, 
Docket No. 137-CE-149, app. C Ex. 1, at 34-38 (Wisc. Pub. Serv. 
Comm'n Apr. 5, 2007).
    \1737\ SPP, Regional Cost Allocation Review Report for RCAR II, 
at 56, 64 (July 11, 2016), https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf.
---------------------------------------------------------------------------

    783. Because we find that transmission providers have multiple ways 
of calculating the benefit of reduced transmission energy losses, as 
well as record evidence demonstrating that the calculation of Benefit 4 
is either already considered or is feasible in multiple transmission 
planning regions, we disagree with West Virginia Commission's claim 
that calculation of this benefit requires evidence based on assumptions 
that are difficult, if not impossible, to quantify in advance.\1738\ We 
also note that the Commission has accepted benefits for use in 
evaluating regional transmission facilities in Order No. 1000 regional 
transmission planning processes akin to Benefit 4, Reduced Transmission 
Energy Losses, in non-RTO/ISO transmission planning regions.\1739\
---------------------------------------------------------------------------

    \1738\ West Virginia Commission Supplemental Comments at 4.
    \1739\ PacifiCorp, 147 FERC ] 61,057 at PP 132, 134, 141-143.
---------------------------------------------------------------------------

v. Benefit 5: Reduced Congestion Due to Transmission Outages
(a) NOPR Description
    784. The Commission described Benefit 5 in the NOPR as reduced 
production costs resulting from avoided congestion during transmission 
outages. Such benefits include reduced production costs during 
transmission outages that significantly increase transmission 
congestion. Production cost simulations typically consider planned 
generation outages and, in most cases, a random distribution of 
unplanned generation outages. In contrast, they do not generally 
reflect transmission outages, planned or unplanned.\1740\ The 
Commission noted that transmission providers could measure this 
benefit, for example, by either building a data set of a normalized 
outage schedule (not including extreme events) that can be introduced 
into simulations or by inducing system constraints more frequently. One 
application of this approach is SPP's Regional Cost Allocation Review 
process, which, inter alia, measured the benefits of reducing 
congestion resulting from transmission outages. In this process, SPP 
modeled outage events and new constraints based on these outages in 
PROMOD for a 2025 case year, and then conducted PROMOD simulations to 
calculate adjusted production cost savings for a base case and the 
change case including the transmission line.\1741\
---------------------------------------------------------------------------

    \1740\ NOPR, 179 FERC ] 61,028 at P 205 & n.340 (citing Brattle-
Grid Strategies Oct. 2021 Report at 79).
    \1741\ Id. P 205 & n.341 (citing SPP, Inc., Regional Cost 
Allocation Review Report for RCAR II, at 51-52 (July 11, 2016), 
https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf. 
To estimate incremental savings associated with mitigation of 
transmission outage costs, SPP analyzed outage cases in PROMOD for 
the 2025 study year. SPP developed cases based on 12 months of 
historical SPP transmission data. SPP said that because of the high 
volume of historical transmission outage data (approximately 7,000 
outage events) and based on the expectation that many outages would 
not lead to significant increases in congestion, SPP only modeled a 
subset of outage events. The events selected were those expected to 
create significant congestion and met at least one of three 
conditions. Id. at 51.)
---------------------------------------------------------------------------

(b) Comments
    785. A number of commenters support mandating consideration of 
Benefit 5.\1742\ While Southern does not support a requirement to use 
this or other benefits, it states that this benefit--which Southern 
understands as ``operational flexibility''--could be explored for 
potential adoption in its footprint.\1743\
---------------------------------------------------------------------------

    \1742\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy 
Initial Comments at 21-22; Clean Energy Associations Initial 
Comments at 18-20; DC and MD Offices of People's Counsel Initial 
Comments at 20; ENGIE Reply Comments at 2-3; Hannon Armstrong 
Initial Comments at 2-3; Interwest Initial Comments at 12-14; 
National and State Conservation Organizations Initial Comments at 1; 
Pine Gate Initial Comments at 34-37; PIOs Initial Comments at 37-38; 
RMI Initial Comments at 1; SEIA Initial Comments at 16; Southeast 
PIOs Initial Comments at 50.
    \1743\ Southern Initial Comments at 25.
---------------------------------------------------------------------------

    786. A few commenters opine on how to calculate the benefit of 
reduced congestion due to transmission outages.\1744\ ACEG states that 
most transmission planning models ignore unplanned transmission outages 
that are likely to occur during extreme weather events, which ACEG 
claims will underestimate the value of Benefit 5.\1745\ Similarly, DC 
and MD Offices of People's Counsel argue that, because unplanned 
transmission outages cause a significant portion of congestion costs, 
calculation of this benefit should account for such outages.\1746\
---------------------------------------------------------------------------

    \1744\ ACEG Initial Comments at 41-42; DC and MD Offices of 
People's Counsel Initial Comments at 25-26.
    \1745\ ACEG Initial Comments at 41.
    \1746\ DC and MD Offices of People's Counsel Initial Comments at 
25-26.
---------------------------------------------------------------------------

    787. Some commenters oppose mandating consideration of Benefit 
5.\1747\ AEP argues that reduced congestion due to transmission outages 
is of lesser importance and does not need to be in the required minimum 
set of benefits.\1748\ NARUC states that benefits associated with new 
construction to alleviate congestion is already a planning 
consideration.\1749\ Pacific Northwest Utilities and West Virginia 
Commission assert that this benefit is not easily quantifiable.\1750\ 
Idaho Power states that non-RTO/ISO transmission planning regions may 
not be able to calculate reduced congestion.\1751\
---------------------------------------------------------------------------

    \1747\ AEP Initial Comments at 27-28; NARUC Initial Comments at 
23; Pacific Northwest Utilities Initial Comments at 9; West Virginia 
Commission Supplemental Comments at 4.
    \1748\ AEP Initial Comments at 27.
    \1749\ NARUC Initial Comments at 23.
    \1750\ Pacific Northwest Utilities Initial Comments at 9; West 
Virginia Commission Supplemental Comments at 4.
    \1751\ Idaho Power Initial Comments at 8.
---------------------------------------------------------------------------

(c) Commission Determination
    788. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to measure 
and use Benefit 5, Reduced Congestion Due to Transmission Outages, in 
Long-Term Regional Transmission Planning. We adopt the NOPR's proposed 
description of Benefit 5 as reduced production costs resulting from 
avoided congestion during transmission outages. Such benefits include 
reduced production costs during transmission outages that significantly 
increase transmission congestion. We find that requiring the 
measurement and use of Benefit 5, as described, is necessary because 
reduced congestion due to transmission outages is widely understood to 
be a benefit of transmission facilities.\1752\ As such, we find that 
transmission providers must measure and use this benefit in Long-Term 
Regional Transmission Planning because it will help to ensure that they 
identify, evaluate, and select more efficient or cost-effective 
regional

[[Page 49408]]

transmission solutions to address Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \1752\ See Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy 
Initial Comments at 21-22; Clean Energy Associations Initial 
Comments at 18-20; DC and MD Offices of People's Counsel Initial 
Comments at 20; ENGIE Reply Comments at 2-3; Hannon Armstrong 
Initial Comments at 2-3; Interwest Initial Comments at 12-14; 
National and State Conservation Organizations Initial Comments at 1; 
Pine Gate Initial Comments at 34-37; PIOs Initial Comments at 37-38; 
RMI Initial Comments at 1; SEIA Initial Comments at 16; Southeast 
PIOs Initial Comments at 50.
---------------------------------------------------------------------------

    789. We also find that consideration of Benefit 5 is necessary 
because most current production cost simulations only consider 
generation outages--both planned generation outages and random 
distributions of unplanned generation outages; by contrast, production 
cost simulations do not typically address transmission outages, either 
planned or unplanned. Given that transmission facilities can provide 
benefits by reducing production costs during both generation outages 
and transmission outages, we find that it is necessary for transmission 
providers to measure and use production cost savings during both 
generation outages and transmission outages in Long-Term Regional 
Transmission Planning. Because Benefit 3, Production Cost Savings, as 
described in this order does not capture production cost savings during 
transmission outages, we require transmission providers to measure and 
use Benefit 5 to ensure that they are accounting for reduced production 
costs during transmission outages as well. We note that Benefit 6 is 
distinct from other benefits that we require transmission providers to 
measure and use in Long-Term Regional Transmission Planning. Although 
Benefit 5 and Benefit 6 both measure the benefit of reduced congestion 
due to transmission outages, the system conditions used to measure 
Benefit 6 include a more expansive set of transmission outages such as 
unplanned outages due to extreme weather.
    790. For the reasons stated above, we disagree with AEP's arguments 
that reduced congestion due to transmission outages is less important 
than other benefits and thus should not be required.\1753\ And while 
some commenters object to consideration of reduced congestion due to 
transmission outages as a benefit on the grounds that this benefit is 
not easily quantifiable,\1754\ we believe this benefit is merely 
another variant in production cost savings modeling that we already 
require for other benefits, such as Benefits 3 and 4.
---------------------------------------------------------------------------

    \1753\ AEP Initial Comments at 27.
    \1754\ See Pacific Northwest Utilities Initial Comments at 9; 
West Virginia Commission Supplemental Comments at 4.
---------------------------------------------------------------------------

vi. Benefit 6: Mitigation of Extreme Weather Events and Unexpected 
System Conditions
(a) NOPR Description
    791. The Commission described the benefit of mitigation of extreme 
events and system contingencies in the NOPR as reductions in production 
costs resulting from reduced high-cost generation and emergency 
procurements necessary to support the transmission system during 
extreme events (such as unusual weather conditions, fuel shortages, or 
multiple or sustained generation and transmission outages) and system 
contingencies.\1755\ These benefits include reduced production costs 
during extreme events facilitated by a more robust transmission system 
that reduces high-cost generation and emergency procurements necessary 
to support the system.\1756\ The Commission noted that transmission 
providers can measure benefits from the mitigation of extreme events 
and system contingencies by calculating the probability-weighted 
production cost savings through production cost simulation for a set of 
extreme historical market conditions. The Commission provided as one 
example CAISO's analysis of Devers-Palo Verde Line No. 2, where CAISO 
modeled several contingencies to determine the value of the line during 
high-impact, low-probability events and, as another example, ATC's 
production cost simulation analysis of insurance benefits for the ATC 
Paddock-Rockdale transmission line. ATC found that probability-weighted 
savings from reducing production and power purchase costs during a 
number of simulated extreme events offset 20% of total project 
costs.\1757\ The Commission also noted that a study found development 
of an additional 1,000 MW of transmission capacity into Texas would 
have fully paid for itself over four days during Winter Storm Uri and 
the same into MISO would have saved $100 million during the same time 
period.\1758\
---------------------------------------------------------------------------

    \1755\ NOPR, 179 FERC ] 61,028 at P 206.
    \1756\ Id.
    \1757\ Id. P 207 & n.342 (Opinion Granting Certificate of Public 
Convenience and Necessity, In the Matter of the Application of 
Southern California Edison Company (U 338-E) for a Certificate of 
Public Convenience and Necessity Concerning the Devers-Palo Verde 
No. 2 Transmission Line Project, Application 05-04-015 (Cal. Comm'n 
Jan. 27, 2007)) & n.343 (ATC, Planning Analysis of the Paddock-
Rockdale Project, Docket No. 137-CE-149, app. C, Ex. 1, at 4, 50-53 
(Wisc. Pub. Serv. Comm'n Apr. 5, 2007)).
    \1758\ Id. P 207 & n.344 (M. Goggin, Grid Strategies, LLC, 
Transmission Makes the Power System Resilient to Extreme Weather 
(July 2020)).
---------------------------------------------------------------------------

    792. Separately, the Commission described the benefit of mitigation 
of weather and load uncertainty in the NOPR as reduced production costs 
during higher than normal load conditions or significant shifts in 
regional weather patterns.\1759\ The Commission stated that this is 
beyond the effects of extreme weather described above and may account 
for, for example, regional and sub-regional load variances that will 
occur due to changing weather patterns.\1760\ The Commission provided, 
as one example, simulations that ERCOT performed for normal loads, 
higher-than-normal loads, and lower-than-normal loads for a Houston 
import project, which showed increased benefits with a probability-
weighted average for all three simulated load conditions.\1761\
---------------------------------------------------------------------------

    \1759\ Id. P 208.
    \1760\ Id.
    \1761\ Id. P 209 & n.345 (citing ERCOT, Economic Planning 
Criteria: Question 1: 1/7/2011 Joint CMWG/PLWG Meeting, at 10 (Mar. 
4, 2011). The $57.8 million probability-weighted estimate is 
calculated based on ERCOT's simulation results for three load 
scenarios and Luminant Energy estimated probabilities for the same 
scenarios).
---------------------------------------------------------------------------

(b) Comments
    793. A number of commenters support mandating consideration of the 
benefit of mitigation of extreme events and system contingencies.\1762\ 
For instance, Grid United states that extreme weather conditions 
significantly affect the electric grid and that requiring transmission 
providers to consider transmission projects based on their ability to 
mitigate extreme weather events will enhance resilience.\1763\ ACEG and 
DC and Maryland Offices of People's Counsel state that consideration of 
the benefit of mitigation of extreme events and system contingencies is 
merited given ``the hundreds of millions of dollars that would have 
been saved if transmission capacity had been greater during a number of 
actual severe weather episodes.'' \1764\ Clean Energy Associations 
assert that transmission providers should not calculate benefits

[[Page 49409]]

solely based on average system conditions, as transmission investments 
can provide significant benefits during abnormal or extreme conditions 
or events.\1765\
---------------------------------------------------------------------------

    \1762\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; ACORE 
Supplemental Comments at 1; AEE Reply Comments at 25; Amazon Initial 
Comments at 5; Breakthrough Energy Initial Comments at 21-22; Clean 
Energy Associations Initial Comments at 18-20; DC and MD Offices of 
People's Counsel Initial Comments at 20; ENGIE Reply Comments at 2-
3; Grid United Initial Comments at 3; Hannon Armstrong Initial 
Comments at 2-3; Interwest Initial Comments at 12-14; National and 
State Conservation Organizations Initial Comments at 1; Pine Gate 
Initial Comments at 34-37; PIOs Initial Comments at 37-38; PJM 
Initial Comments at 94 (in combination with Benefit 7, noting that 
significant stakeholder engagement is needed to implement); RMI 
Initial Comments at 1; SEIA Initial Comments at 16; Southeast PIOs 
Initial Comments at 50; US DOE Initial Comments at 31-32; US Senator 
Schumer Supplemental Comments at 2-3.
    \1763\ Grid United Initial Comments at 3.
    \1764\ ACEG Initial Comments at 43 & n.119; DC and Maryland 
Offices of People's Counsel Initial Comments at 26-27 & n.65 (both 
citing Grid Strategies, LLC, Transmission Makes the Power System 
Resilient to Extreme Weather (Jul. 2021), https://acore.org/wp-content/uploads/2021/07/GS_Resilient-Transmission_proof.pdf).
    \1765\ Clean Energy Associations Initial Comments at 21.
---------------------------------------------------------------------------

    794. Some commenters comment on the manner in which the benefit of 
mitigation of extreme events and system contingencies should be 
calculated.\1766\ ACEG states that the benefit of mitigation of extreme 
events and system contingencies can be calculated by retrospective 
analysis or probabilistically. Additionally, ACEG recommends that the 
Commission require transmission providers to include avoided scarcity 
pricing, storm hardening and wildfire resilience, grid strength, and 
increased fuel diversity and system flexibility in addition to 
production cost savings when calculating the benefit of mitigation of 
extreme events and system contingencies.\1767\ Similarly, DC and MD 
Offices of People's Counsel assert that the benefit of mitigation of 
extreme events and system contingencies should include resilience 
benefits such as storm and wildfire hardening, fuel diversity, and 
system flexibility, as well as reduced prices to consumers given that 
many regions set scarcity prices at values higher than generator 
production costs.\1768\
---------------------------------------------------------------------------

    \1766\ ACEG Initial Comments at 43; Clean Energy Associations 
Initial Comments at 21; DC and MD Offices of People's Counsel 
Initial Comments at 26-27; MISO Initial Comments at 51; NARUC 
Initial Comments at 23; Pacific Northwest Utilities Initial Comments 
at 9.
    \1767\ ACEG Initial Comments at 43-44.
    \1768\ DC and MD Offices of People's Counsel Initial Comments at 
26-27.
---------------------------------------------------------------------------

    795. A number of commenters also support mandating consideration of 
the benefit of mitigation of weather and load uncertainty.\1769\ Some 
commenters comment on the manner in which the benefit of mitigation of 
weather and load uncertainty should be calculated.\1770\ GridLab posits 
that mitigation of weather and load uncertainty should only be included 
in the context of planning and operating reserves because ``the cost to 
system operators of mitigating uncertainty is [the same as] the cost of 
holding additional reserves.'' \1771\
---------------------------------------------------------------------------

    \1769\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply 
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy 
Initial Comments at 21-22; Clean Energy Associations Initial 
Comments at 18-20; DC and MD Offices of People's Counsel Initial 
Comments at 20; ENGIE Reply Comments at 2-3; Grid United Initial 
Comments at 3; Hannon Armstrong Initial Comments at 2-3; Interwest 
Initial Comments at 12-14; National and State Conservation 
Organizations Initial Comments at 1; Pine Gate Initial Comments at 
34-37; PIOs Initial Comments at 37-38; PJM Initial Comments at 94 
(in combination with Benefit 6, noting that significant stakeholder 
engagement would be necessary to implement); RMI Initial Comments at 
1; SEIA Initial Comments at 16; Southeast PIOs Initial Comments at 
50; US DOE Initial Comments at 31-32.
    \1770\ ACEG Initial Comments at 44; GridLab Initial Comments at 
26; NARUC Initial Comments at 23.
    \1771\ GridLab Initial Comments at 26.
---------------------------------------------------------------------------

    796. Other commenters oppose mandating consideration of the benefit 
of mitigation of extreme events and system contingencies, arguing that 
it is challenging to quantify and that its calculation entails 
subjective judgment.\1772\ Louisiana Commission states that the value 
of mitigating extreme weather events can vary significantly across 
transmission planning regions and states. Louisiana Commission opposes 
any extreme weather benefit category that would result in the 
assignment of costs of transmission hardening projects to Louisiana 
ratepayers from which they do not benefit. Louisiana Commission further 
states that any analysis of this benefit should be limited to 
sensitivities.\1773\
---------------------------------------------------------------------------

    \1772\ NRECA Initial Comments at 45; Pacific Northwest Utilities 
Initial Comments at 9; West Virginia Commission Supplemental 
Comments at 4.
    \1773\ Louisiana Commission Initial Comments at 18-19.
---------------------------------------------------------------------------

    797. Some commenters oppose mandating consideration of the 
mitigation of weather and load uncertainty.\1774\ AEP states that this 
benefit should not be included in the minimum set of benefits because 
it is of lesser importance than other benefits described in the 
NOPR.\1775\ NRECA argues that quantifying this benefit requires 
subjective judgment.\1776\ According to Pacific Northwest Utilities, 
this benefit accrues to generation and load-serving entities, not to 
transmission providers.\1777\
---------------------------------------------------------------------------

    \1774\ AEP Initial Comments at 27; NARUC Initial Comments at 23; 
NRECA Initial Comments at 45; Pacific Northwest Utilities Initial 
Comments at 9.
    \1775\ AEP Initial Comments at 27.
    \1776\ NRECA Initial Comments at 45.
    \1777\ Pacific Northwest Utilities Initial Comments at 9.
---------------------------------------------------------------------------

    798. NARUC states that the benefits of mitigation of extreme 
events, system contingencies, weather, and load uncertainties may be 
more appropriate for consideration in interregional transmission 
planning, depending on the size of the transmission planning region. 
While NARUC states that mitigation of such contingencies is among the 
soundest reasons for Interregional Transfer Capability planning, it 
also notes that in regions with a large footprint (e.g., PJM, MISO) it 
may be possible to assess these resilience benefits in the regional 
transmission planning process.\1778\
---------------------------------------------------------------------------

    \1778\ NARUC Initial Comments at 21, 23.
---------------------------------------------------------------------------

    799. MISO states that the treatment of mitigation of extreme events 
and system contingencies and mitigation of weather and load uncertainty 
as economic benefits differ only to the degree at which production cost 
savings are realized. MISO also states that ``mitigation of extreme 
events'' may be represented as a reliability benefit where a value of 
outage costs can be used to monetize the benefits of mitigating the 
risk of load shedding.\1779\ PJM suggests that the Commission should 
consolidate the benefits of mitigation of extreme events and system 
contingencies and the benefits of mitigation of weather and load 
uncertainty into a single enhanced reliability benefit that would 
evaluate the ability of grid enhancements to serve load reliably under 
extreme events and vulnerabilities.\1780\ MISO and NARUC state that 
their comments regarding mitigation of extreme events and system 
contingencies are equally applicable to mitigation of weather and load 
uncertainty.\1781\
---------------------------------------------------------------------------

    \1779\ MISO Initial Comments at 51.
    \1780\ PJM Initial Comments at 94.
    \1781\ MISO Initial Comments at 51; NARUC Initial Comments at 
23.
---------------------------------------------------------------------------

(c) Commission Determination
    800. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to measure 
and use Final Order Benefit 6, mitigation of extreme weather events and 
unexpected system conditions, in Long-Term Regional Transmission 
Planning. The revised Final Order Benefit 6 modifies and combines two 
of the benefits proposed in the NOPR: (1) mitigation of extreme events 
and system contingencies (NOPR Benefit 6) and (2) mitigation of weather 
and load uncertainty (NOPR Benefit 7).\1782\ In combining these two 
proposed NOPR benefits, we modify the description of NOPR Benefit 6 and 
describe Final Order Benefit 6 as reduced production costs and reduced 
loss of load (or emergency procurements necessary to support the 
system), including due to increased Interregional Transfer Capability, 
during extreme weather events and unexpected system conditions, such as 
unusual weather conditions or fuel shortages that result in multiple 
concurrent and sustained generation and/or transmission outages. The 
description of Final Order Benefit 6 that we adopt in this final order

[[Page 49410]]

includes three additional modifications to the NOPR proposals 
describing NOPR Benefit 6 and NOPR Benefit 7. First, we require 
transmission providers to measure, as part of Benefit 6,\1783\ the 
benefits of reduced loss of load (not only reduced production costs). 
Second, we require transmission providers, as part of Benefit 6, to 
account for both extreme weather events and unexpected system 
conditions when transmission facilities have particularly high value. 
The unexpected system conditions can include, for example, system 
contingencies in the form of generator and/or transmission outages, 
extreme or volatile production costs, and generation and/or load 
forecast errors. Third, we require transmission providers to measure, 
as part of Benefit 6, the benefits associated with any increase in 
Interregional Transfer Capability provided by a Long-Term Regional 
Transmission Facility during an extreme weather event or unexpected 
system condition that results in multiple and concurrent sustained 
generation and/or transmission outages.
---------------------------------------------------------------------------

    \1782\ NOPR, 179 FERC ] 61,028 at PP 206-207 (NOPR Benefit 6), 
208-209 (NOPR Benefit 7).
    \1783\ Throughout this final order, ``Benefit 6'' refers to 
``Final Order Benefit 6'' unless preceded by ``NOPR.''
---------------------------------------------------------------------------

    801. We find that requiring the measurement and use of Benefit 6 in 
Long-Term Regional Transmission Planning is necessary because Long-Term 
Regional Transmission Facilities could result in reduced production 
costs and reduced loss of load (or reduced emergency procurements 
necessary to support the system), including reductions due to increased 
Interregional Transfer Capability, and improved performance during 
extreme weather events and unexpected system conditions. Further, the 
benefit of mitigation of high production costs resulting from extreme 
weather events and unexpected system conditions can be economically 
significant. A relatively few numbers of hours could represent a large 
share of the total benefit of reduced congestion costs that a Long-Term 
Regional Transmission Facility provides.\1784\ We also find that it is 
critical for transmission providers to measure and use Benefit 6 given 
that extreme weather events and unexpected system conditions have 
significantly and increasingly affected the reliable operation of the 
electric grid. As the Commission has previously noted, extreme weather 
events have occurred with greater frequency in recent years, leading to 
load shed events that present an unacceptable risk to life and have an 
extreme economic impact.\1785\ By requiring the use of Benefit 6, we 
ensure that transmission providers measure and use the benefit of Long-
Term Regional Transmission Facilities under these conditions when 
performing Long Term Regional Transmission Planning. Further, by 
requiring use of Benefit 6, we enable transmission providers to 
identify, evaluate, and select Long-Term Regional Transmission 
Facilities that more efficiently or cost-effectively address Long-Term 
Transmission Needs.
---------------------------------------------------------------------------

    \1784\ E.g., ACORE Initial Comments at 11 (citing LBNL Aug. 2022 
Transmission Value Study at 33).
    \1785\ See Order No. 896, 183 FERC ] 61,191 at P 2; Order No. 
897, 183 FERC ] 61,192 at PP 21-22.
---------------------------------------------------------------------------

    802. Regarding the first modification listed above, we require 
transmission providers to measure, as part of Benefit 6, reduced loss 
of load (or reduced emergency energy procurement to avoid loss of 
load), not only reduced production costs. We find it necessary to 
include reduced loss of load because Long-Term Regional Transmission 
Facilities can provide benefits by improving reliability during extreme 
weather events and unexpected system conditions,\1786\ which can be 
significant given the high cost and risk to life during periods with 
insufficient generation to meet system load. An example of how a 
reduction in loss of load could be measured is by quantifying the 
reduction in expected unserved energy but for the Long-Term Regional 
Transmission Facility during an extreme weather event or unexpected 
system conditions, determining the value of lost load, and multiplying 
these two values to obtain a monetary value.\1787\
---------------------------------------------------------------------------

    \1786\ PJM Initial Comments at 94; MISO Initial Comments at 12-
13; Order No. 897, 183 FERC ] 61,192 at PP 6-12.
    \1787\ E.g., MISO, LRTP Tranche 2 Business Case Benefit Metrics, 
6-7 (Aug. 31, 2023), https://cdn.misoenergy.org/20230831%20LRTP%20Workshop%20Item%2002%20Business%20Case%20Metrics%20Development630034.pdf.
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    803. We note that Benefit 6 is distinct from other benefits that we 
require transmission providers to measure and use, because transmission 
providers must model different system conditions (extreme weather 
events and unexpected system conditions) when measuring Benefit 6. 
Specifically, Benefit 2(a) measures reduced loss of load probability in 
the context of the system conditions used for resource adequacy 
planning, which typically includes consideration of normal system 
conditions and may vary by region. In contrast, Benefit 6 measures 
reduced loss of load for specific extreme weather events and unexpected 
system conditions identified by the transmission providers.\1788\ 
Additionally, while Benefit 3 and Benefit 6 both measure production 
cost savings, the system conditions used to measure Benefit 6 can 
include higher electricity demand, volatile production costs, and a 
more expansive set of generation outages, such as unplanned generation 
outages due to extreme weather. Similarly, Benefit 5 and Benefit 6 both 
measure the benefits of reduced congestion due to transmission outages; 
however, the system conditions used to measure Benefit 6 include a more 
expansive set of transmission outages, such as unplanned transmission 
outages due to extreme weather.
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    \1788\ Benefit 2(b), which measures the benefit of reduced 
planning reserve margin, is also used in the context of resource 
adequacy planning. We do not allow transmission providers to measure 
Benefit 6 in terms of reduced planning reserve margin because system 
planners do not always model extreme weather events or unexpected 
system conditions when establishing the planning reserve margin used 
for resource adequacy purposes. In contrast, reduced loss of load 
can be measured for any system condition, even those conditions that 
are not used for resource adequacy planning.
---------------------------------------------------------------------------

    804. Regarding the second modification listed above, we require 
transmission providers, as part of Benefit 6, to account for mitigation 
of unexpected system conditions during periods when transmission 
facilities have particularly high value, not only during extreme 
weather events. We recognize that unexpected system conditions can 
create periods when Long-Term Regional Transmission Facilities have 
particularly high value because of, for example, generator and/or 
transmission outages, extreme or volatile production costs, and 
generation and/or load forecast errors.\1789\ Limited resource 
availability, or limited system flexibility, can make

[[Page 49411]]

it challenging for system operators to immediately address these 
unexpected system conditions, and Long-Term Regional Transmission 
Facilities that provide benefits under Benefit 6 will equip system 
operators with more options to manage the worst-case outcomes. These 
high-value periods of unexpected system conditions, while infrequent 
and not necessarily during extreme weather events, may account for a 
large share of the potential value of a Long-Term Regional Transmission 
Facility.\1790\ We require transmission providers to account for 
circumstances that contribute to these infrequent and high-value 
periods specific to their transmission planning region when measuring 
Benefit 6. Transmission providers may, for example, identify historical 
periods when significant transmission congestion was due to certain 
conditions (e.g., generators being unavailable due to a forecast 
error), then model those conditions in each Long-Term Scenario.\1791\ 
Therefore, we require transmission providers to use not only 
information from modeling extreme weather events but also information 
from additional modeling that accounts for unexpected system 
conditions, as part of Benefit 6. To avoid double-counting of similar 
circumstances, transmission providers must account for extreme weather 
events and unexpected system conditions that are separate and distinct 
such that the benefits of mitigating each system condition can be 
combined into a single benefit measure.
---------------------------------------------------------------------------

    \1789\ See, e.g., ACEG Initial Comments at 42-45 (citing 
Pfeifenberger, Ruiz, Van Horn, The Value of Diversifying Uncertain 
Renewable Generation through the Transmission System (Oct. 14, 
2020), https://open.bu.edu/handle/2144/41451; The Brattle Group and 
Grid Strategies, Transmission Planning for the 21st Century: Proven 
Practices that Increase Value and Reduce Costs, 2, 34, 78, 85-86, 99 
(2021), https://www.brattle.com/wp-content/uploads/2021/10/2021-10-12-Brattle-GridStrategies-TransmissionPlanning-Report_v2.pdf); DC 
and MD Offices of People's Counsel Initial Comments at 28 (citing 
Pfeifenberger, Ruiz, Van Horn, The Value of Diversifying Uncertain 
Renewable Generation through the Transmission System, BU-ISE (Oct. 
14, 2020), https://open.bu.edu/handle/2144/41451); US Senator 
Schumer Supplemental Comments at 2-3 (citing Millstein et al., 
Lawrence Berkeley National Laboratory, The Latest Market Data Show 
that the Potential Savings of New Electric Transmission was Higher 
Last Year than at Any Point in the Last Decade, 3-6 (Feb. 2023), 
https://eta-publications.lbl.gov/sites/default/files/lbnl-transmissionvalue-fact_sheet-2022update-20230203.pdf); US Senator 
Whitehouse Supplemental Comments at 2 (referencing outages related 
to extreme events having costs, including economic costs of in the 
billions of dollars from elevated energy costs).
    \1790\ LBNL Aug. 2022 Transmission Value Study at 33 (stating 
that the majority of transmission value estimated occurs during 
``extreme'' conditions that fall outside of the 171 designated 
extreme weather event days between 2012 and 2021); Millstein et al., 
Lawrence Berkeley National Laboratory, The Latest Market Data Show 
that the Potential Savings of New Electric Transmission was Higher 
Last Year than at Any Point in the Last Decade, 3-6 (Feb. 2023), 
https://eta-publications.lbl.gov/sites/default/files/lbnl-transmissionvalue-fact_sheet-2022update-20230203.pdf.
    \1791\ Alternatively, transmission providers may, for example, 
use probabilistic transmission planning methods to account for 
infrequent and high-value periods.
---------------------------------------------------------------------------

    805. Finally, we require transmission providers to measure, as part 
of Benefit 6, the benefits associated with any increase in 
Interregional Transfer Capability that a Long-Term Regional 
Transmission Facility would provide during an extreme weather event and 
unexpected system conditions that results in multiple concurrent and 
sustained generation and/or transmission outages. As discussed above, 
we find that Long-Term Regional Transmission Facilities can increase 
Interregional Transfer Capability by changing the topology of the 
transmission system.\1792\ Further, we find that the benefits of 
mitigating extreme weather events and unexpected system conditions due 
to increased Interregional Transfer Capability provided by Long-Term 
Regional Transmission Facilities can be significant.\1793\ To comply 
with this requirement, transmission providers must include in the 
modeling they use to measure Benefit 6 any increase in Interregional 
Transfer Capability that a Long-Term Regional Transmission Facility 
would provide during an extreme weather event and unexpected system 
conditions that results in multiple concurrent and sustained generation 
and/or transmission outages.
---------------------------------------------------------------------------

    \1792\ Supra Long-Term Regional Transmission Planning, Long-Term 
Scenarios Requirements, Sensitivities for High-Impact, Low-Frequency 
Events section.
    \1793\ ACEG Initial Comments at 5; ACEG Reply Comments at 3-5; 
BP Initial Comments at 10; Breakthrough Energy Initial Comments at 
2; Clean Energy Associations Initial Comments at 5, 21; Kansas 
Corporation Commission Initial Comments at 8-9; NARUC Initial 
Comments at 23; US DOE Initial Comments at 39-42.
---------------------------------------------------------------------------

    806. To account for extreme weather events as part of Benefit 6, 
transmission providers may incorporate information from the sensitivity 
they must develop and apply to each Long-Term Scenario that includes 
multiple concurrent and sustained generation and/or transmission 
outages due to an extreme weather event across a wide area.\1794\ We 
reiterate that we require transmission providers to measure the 
required benefits under each Long-Term Scenario. However, in the case 
of Benefit 6, transmission providers may measure the benefit of 
mitigating extreme weather events using the required extreme weather 
event sensitivity applied to each Long-Term Scenario; we do not require 
them to separately measure the benefit of mitigating extreme weather 
events in each scenario without applying that sensitivity.\1795\
---------------------------------------------------------------------------

    \1794\ Supra Long-Term Regional Transmission Planning, Long-Term 
Scenarios Requirements, Sensitivities for High-Impact, Low-Frequency 
Events section (stating transmission providers must develop at least 
one sensitivity, applied to each Long-Term Scenario, to account for 
uncertain operational outcomes that determine the benefits of and/or 
need for transmission facilities during multiple concurrent and 
sustained generation and/or transmission outages due to an extreme 
weather event across a wide area). Transmission providers may also 
incorporate analyses from an Extreme Weather Vulnerability 
Assessment as generally described in Order No. 897.
    \1795\ We recognize that transmission providers may not use an 
extreme weather event sensitivity that includes system conditions 
that allow transmission providers to measure the benefit of 
mitigating unexpected system conditions in every Long-Term Scenario. 
In such cases, transmission providers must measure the benefit of 
mitigating unexpected system conditions in each Long-Term Scenario 
even without an extreme weather event sensitivity applied to those 
scenarios or must apply a separate sensitivity that allows for the 
measurement of Benefit 6 to each Long-Term Scenario.
---------------------------------------------------------------------------

    807. Consistent with all other benefits that we require 
transmission providers to measure, we do not require a standardized 
method for measuring Benefit 6 subject to measuring the components 
described above.\1796\ As the Commission stated in the NOPR, there are 
different approaches to calculating components of this benefit,\1797\ 
and this final order provides transmission providers with flexibility 
in developing the method that they will use to measure this benefit.
---------------------------------------------------------------------------

    \1796\ E.g., ACEG Initial Comments at 42-44; DC and MD Offices 
of People's Counsel Initial Comments at 26-27.
    \1797\ NOPR, 179 FERC ] 61,028 at P 207 (providing examples of 
CAISO's analysis of Devers-Palo Verde Line No. 2, ATC's production 
cost simulation analysis of insurance benefits for the ATC Paddock-
Rockdale transmission line, and a Grid Strategies study).
---------------------------------------------------------------------------

    808. We disagree with commenters who express general concerns 
regarding the difficulty of measuring this benefit.\1798\ In the NOPR, 
the Commission identified studies that measured benefits of a 
transmission facility in a manner similar to the requirements in 
Benefit 6.\1799\ Because we allow flexibility as far as the method 
transmission providers use to measure each benefit included in the 
required set of benefits, including Benefit 6, we believe that 
transmission providers should be able to tailor a method for measuring 
Benefit 6 that fits their circumstances. Further, transmission 
providers can build on methods that they use to measure the other 
benefits required by this final order to measure Benefit 6. For 
example, transmission providers can use the same method to measure 
reduced production costs in accordance with Benefit 6 as they do to 
measure Benefit 3, Production Costs Savings, but modify the model 
inputs to capture reduced production costs during extreme weather 
events and unexpected system conditions. Moreover, we recognize that 
there is a balance between requiring transmission providers to measure 
the benefits of Long-Term Regional Transmission Facilities that are 
most readily measured and ensuring that transmission providers are 
appropriately capturing the value of Long-Term Regional Transmission 
Facilities when evaluating them for selection. Even to the extent to 
which Benefit 6 may be more difficult to measure than the other 
benefits that

[[Page 49412]]

we require, we nonetheless find that requiring transmission providers 
to measure Benefit 6 is necessary because Benefit 6 is 
significant.\1800\
---------------------------------------------------------------------------

    \1798\ NRECA Initial Comments at 45; Pacific Northwest Utilities 
Initial Comments at 9; West Virginia Commission Supplemental 
Comments at 4.
    \1799\ NOPR, 179 FERC ] 61,028 at PP 207, 209.
    \1800\ Supra P 797.
---------------------------------------------------------------------------

    809. We are unpersuaded by general arguments that transmission 
providers should not consider this benefit because it varies by 
transmission planning region or it only accrues to certain 
entities.\1801\ We are not requiring transmission providers to model a 
specific extreme weather event or unexpected system condition; 
transmission providers may decide what extreme weather event and 
unexpected system conditions to model, allowing them to ensure that the 
conditions modeled are relevant to circumstances in their transmission 
planning region. In response to NRECA's argument that this benefit 
requires subjective judgement,\1802\ we conclude that transmission 
providers have sufficient expertise to identify and model extreme 
weather events and unexpected system conditions when evaluating Long-
Term Regional Transmission Facilities.\1803\ In response to AEP's 
argument that NOPR Benefit 7 (mitigation of weather and load 
uncertainty) is of lesser importance compared to other benefits 
described in the NOPR and should be optional for transmission providers 
to measure and use,\1804\ we disagree because the evidence in the 
record demonstrates that Final Order Benefit 6 (which includes NOPR 
Benefit 7) is significant.\1805\
---------------------------------------------------------------------------

    \1801\ Louisiana Commission Initial Comments at 18-19; Pacific 
Northwest Utilities Initial Comments at 9.
    \1802\ NRECA Initial Comments at 45.
    \1803\ NESCOE Initial Comments at 42.
    \1804\ AEP Initial Comments at 27.
    \1805\ Supra note 1769; see also ACORE Initial Comments at 11 
(citing LBNL Aug. 2022 Transmission Value Study at 33).
---------------------------------------------------------------------------

    810. NARUC states that the benefit of mitigation of extreme weather 
events may need to be more fully considered only in large transmission 
planning regions or in interregional transmission planning.\1806\ 
Although transmission providers could also consider the benefits of 
mitigation of extreme weather events as part of interregional 
transmission coordination, we believe transmission providers can 
measure and use the benefit of mitigation of extreme weather events in 
regional transmission planning processes regardless of the size of the 
transmission planning region, because extreme weather events can occur 
and affect the transmission system in any region. If the size of the 
extreme weather event is larger than the transmission planning region, 
transmission providers can consider the extent to which they can rely 
on interregional flows from other transmission planning regions during 
the extreme weather event. We note that transmission providers in each 
transmission planning region must coordinate and share information with 
the transmission providers in each neighboring transmission planning 
region and must identify and jointly evaluate interregional 
transmission facilities that may be more efficient or cost-effective 
transmission facilities to address Long-Term Transmission Needs, as 
described in more detail in the Interregional Transmission Coordination 
section of this final order. Better measurement of the benefits of 
mitigation of extreme weather events as part of regional transmission 
planning can only help facilitate such efforts. We encourage 
transmission providers in neighboring transmission planning regions to 
share information with one another that would be useful to measure 
Benefit 6 more accurately through their interregional transmission 
coordination procedures.
---------------------------------------------------------------------------

    \1806\ NARUC Initial Comments at 21, 23.
---------------------------------------------------------------------------

    811. Some commenters state that the benefits of mitigation of 
extreme events and system contingencies and mitigation of weather and 
load uncertainty overlap, or should be combined.\1807\ We note that 
Benefit 6, as described above, modifies and combines the benefits 
proposed in the NOPR of (1) mitigation of extreme events and system 
contingencies and (2) mitigation of weather and load uncertainty, which 
should address concerns of separately requiring transmission providers 
to use two similar benefits that some argue could overlap.
---------------------------------------------------------------------------

    \1807\ MISO Initial Comments at 51; PJM Initial Comments at 94.
---------------------------------------------------------------------------

vii. Final Order Benefit 7: Capacity Cost Benefits From Reduced Peak 
Energy Losses
(a) NOPR Description
    812. The Commission described this benefit, NOPR Benefit 8 
(renumbered in this final order as Final Order Benefit 7), in the NOPR 
as reduced generation capacity investment needed to meet peak 
load.\1808\ The Commission noted that capacity cost savings from 
reduced peak energy losses benefits refer to the ability of proposed 
transmission facilities to lessen the amount of transmission system 
energy losses during peak-load conditions which, over time, would 
decrease the need for new generation capacity installations or 
purchases. To the extent that new transmission facilities result in 
changes to generation dispatch and flows, transmission system energy 
losses will also change. If transmission system losses are reduced via 
the new transmission facilities, transmission providers will not have 
to construct or procure additional generation to satisfy installed 
capacity requirements for peak-load conditions. If there is a reduction 
in energy losses during peak conditions, this would result in, 
presumably, lowered investments for generation capacity resources to 
meet the peak load. For example, Entergy found that potential 
transmission facilities in its footprint could reduce peak-load 
transmission losses and associated needed generation investment by 2% 
of total transmission facility costs.\1809\ The Commission noted that 
capacity cost savings from reduced peak energy losses only attempt to 
evaluate benefits for peak-load conditions.
---------------------------------------------------------------------------

    \1808\ NOPR, 179 FERC ] 61,028 at P 210.
    \1809\ Id. P 211 & n.346 (citing ITC, Joint Application, Docket 
No. EC12-145-000, Ex. ITC-600 (Testimony of Pfeifenberger), at 77-78 
(filed Sept. 24, 2012)).
---------------------------------------------------------------------------

    813. The Commission stated that one potential way to calculate 
capacity cost savings from reduced peak energy losses is to calculate 
the present value of capital cost savings associated with the reduction 
in installed generation requirements.\1810\ To arrive at the value of 
associated capital cost savings, the estimated net cost of new entry 
(Net CONE) (i.e., the cost of new peaking generating capacity net of 
operating margins earned in energy and ancillary services markets when 
the region is resource constrained) would be multiplied by the 
reduction in installed generation capacity requirements. The resulting 
value would represent the avoided cost of procuring more generation to 
cover transmission system losses during peak-load conditions that would 
be passed on to consumers via lowered generation capacity costs.\1811\
---------------------------------------------------------------------------

    \1810\ Id. P 212.
    \1811\ Id.
---------------------------------------------------------------------------

(b) Comments
    814. A number of commenters support mandating consideration of NOPR 
Benefit 8.\1812\ ACEG and DC and

[[Page 49413]]

MD People's Counsel state that NOPR Benefit 8 is a distinct benefit 
category that has been measured before.\1813\ PIOs state that SPP 
quantified NOPR Benefit 8 in its 2016 Regional Cost Allocation Review 
and that ``leav[ing] these cost savings on the cutting room floor will 
ultimately raise costs for consumers and result in an inefficient 
transmission plan.'' \1814\
---------------------------------------------------------------------------

    \1812\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32, 45; ACORE Initial Comments at 12; AEE Reply 
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy 
Initial Comments at 21-22; Clean Energy Associations Initial 
Comments at 18-20; DC and MD Offices of People's Counsel Initial 
Comments at 20; ENGIE Reply Comments at 2-3; Hannon Armstrong 
Initial Comments at 2-3; Interwest Initial Comments at 12-14; 
National and State Conservation Organizations Initial Comments at 1; 
Pine Gate Initial Comments at 34-37; PIOs Initial Comments at 37-38; 
RMI Initial Comments at 1; SEIA Initial Comments at 16; Southeast 
PIOs Initial Comments at 50.
    \1813\ ACEG Initial Comments at 48; DC and MD People's Counsel 
Initial Comments at 28 (both citing ITC, Joint Application, Docket 
No. EC12-145-000, Ex. ITC-600 (Testimony of Pfeifenberger), at 77-78 
(filed Sept. 24, 2012); SPP, SPP Priority Projects Phase II Report, 
Rev. 1, April 27, 2010, at 26; ATC, Planning Analysis of the 
Paddock-Rockdale Project, April 5, 2007 (filed in PSCW Docket 137-
CE-149, PSC Reference # 75598), at 4, 63; and MISO, Proposed Multi 
Value Project Portfolio, Technical Study Task Force and Business 
Case Workshop, August 22, 2011, at 25, 27)).
    \1814\ PIOs Initial Comments at 42.
---------------------------------------------------------------------------

    815. Other commenters, such as NARUC, oppose mandating 
consideration of NOPR Benefit 8. NARUC contends that this benefit is a 
subset of the lowered system reserve margins benefit. NARUC states that 
NOPR Benefit 8 is unlikely to occur within organized, competitive 
generation markets because additional transmission will not deter the 
installation of new generation under current Federal open access 
policies. However, NARUC argues, this benefit may be attainable in 
transmission planning regions served by vertically integrated utilities 
where transmission can substitute for new generation construction. 
NARUC asserts that hundreds of thousands of megawatts of generation 
currently await interconnection studies in the various RTOs/ISOs and 
non-RTO/ISO transmission planning regions, and it is difficult to see 
how construction of new transmission facilities can remove any of this 
demand for additional generator interconnection.\1815\
---------------------------------------------------------------------------

    \1815\ NARUC Initial Comments at 24.
---------------------------------------------------------------------------

    816. West Virginia Commission also opposes a requirement to use 
NOPR Benefit 8, arguing that the calculation requires significant 
evidence based on assumptions that are difficult, if not impossible, to 
quantify before the fact.\1816\
---------------------------------------------------------------------------

    \1816\ West Virginia Commission Supplemental Comments at 4.
---------------------------------------------------------------------------

(c) Commission Determination
    817. As an initial matter, we renumber NOPR Benefit 8 and refer to 
it in this determination section as Final Order Benefit 7. We adopt the 
NOPR proposal, with modification, to require transmission providers in 
each transmission planning region to measure and use Final Order 
Benefit 7, Capacity Cost Benefits from Reduced Peak Energy Losses, in 
Long-Term Regional Transmission Planning. We adopt the NOPR's proposed 
description of Final Order Benefit 7 as reduced generation capacity 
investment needed to meet peak load.\1817\ We find that requiring the 
use and measurement of Final Order Benefit 7, as described, is 
necessary to ensure that capacity cost benefits from reduced peak 
energy losses are not excluded from Long-Term Regional Transmission 
Planning because standard production cost modeling and the other 
benefits that this final order requires transmission providers to 
measure and use will not capture this benefit. Absent a requirement for 
transmission providers to measure and use Final Order Benefit 7 in 
Long-Term Regional Transmission Planning, transmission providers may 
not identify, evaluate, and select Long-Term Regional Transmission 
Facilities that more efficiently or cost-effectively address Long-Term 
Transmission Needs.
---------------------------------------------------------------------------

    \1817\ We note that in the NOPR, this benefit was designated as 
Benefit 8. We have revised the ordering designation of this benefit 
in this final order.
---------------------------------------------------------------------------

    818. One potential way to measure capacity cost savings from 
reduced peak energy losses is to calculate the present value of capital 
cost savings associated with the reduction in installed generation 
requirements. To arrive at the value of capital cost savings, the 
estimated net cost of new entry (i.e., the cost of new peaking 
generating capacity net of operating margins earned in energy and 
ancillary services markets when the region is resource constrained) 
could be multiplied by the reduction in installed generation capacity 
requirements. The resulting value would represent the avoided cost of 
procuring more generation to cover transmission system losses during 
peak-load conditions, savings that would be passed on to customers via 
lowered generation capacity costs.
    819. We disagree with NARUC's contention that this benefit is a 
subset of the lowered system reserve margins benefit and that it is 
unlikely to occur within organized, competitive generation 
markets.\1818\ ACEG and DC and MD People's Counsel both indicate that 
Final Order Benefit 7 is a distinct benefit category that has been 
measured before, citing MISO's Multi-Value Project portfolio, among 
other examples of its use, which measures capacity cost savings from 
reduced peak energy losses as an independent benefit.\1819\ While we 
acknowledge that this benefit may have the effect of lowering system 
reserve margins, we agree with PIOs that these cost savings are 
distinct from Benefit 2 and that failing to specifically evaluate 
potential cost savings related to reduced peak energy losses may result 
in higher capacity costs and relatively inefficient or less cost-
effective transmission development. As discussed above, Benefit 2 
recognizes potential cost savings of providing additional pathways for 
connecting generation resources with load. Here, we are assessing the 
benefits of limiting transmission losses along those pathways. We also 
note that this approach is consistent with Benefits 3 and 4 above that 
separately recognize potential cost savings associated with lower 
production costs and reduced transmission energy losses in energy 
markets. In light of the evidence that multiple transmission providers 
have successfully measured this benefit, as well as the example that we 
provide above describing how a transmission provider may be able to 
calculate this benefit, we further disagree with West Virginia 
Commission's argument that calculation of this benefit is based on 
assumptions that are difficult to quantify in advance.
---------------------------------------------------------------------------

    \1818\ NARUC Initial Comments at 24.
    \1819\ ACEG Initial Comments at 48; DC and MD People's Counsel 
Initial Comments at 28 (both citing ITC, Joint Application, Docket 
No. EC12-145-000, Ex. ITC-600 (Testimony of Pfeifenberger), at 77-78 
(filed Sept. 24, 2012); SPP, SPP Priority Projects Phase II Report, 
Rev. 1, April 27, 2010, at 26; ATC, Planning Analysis of the 
Paddock-Rockdale Project, April 5, 2007 (filed in PSCW Docket 137-
CE-149, PSC Reference # 75598), at 4, 63; and MISO, Proposed Multi 
Value Project Portfolio, Technical Study Task Force and Business 
Case Workshop, August 22, 2011, at 25, 27)).
---------------------------------------------------------------------------

viii. Other Benefits
(a) Comments
    820. Numerous commenters address in various ways the other five 
benefits that the Commission described in the NOPR but that we do not 
require transmission providers to measure and use in Long-Term Regional 
Transmission Planning in this final order: mitigation of weather and 
load uncertainty,\1820\ deferred generation capacity investments, 
access to lower cost generation, increased competition, and increased 
market liquidity.\1821\

[[Page 49414]]

Other commenters address in various ways benefits not listed in the 
NOPR for transmission providers to consider for use in evaluating Long-
Term Regional Transmission Facilities.\1822\
---------------------------------------------------------------------------

    \1820\ We note that elements of this benefit are now contained 
in Benefit 6, the description of which has been revised from the 
NOPR.
    \1821\ Acadia Center and CLF Initial Comments at 21-22; ACEG 
Initial Comments at 32, 45-48; ACORE Initial Comments at 12; AEE 
Reply Comments at 25; AEP Initial Comments at 25-27; Amazon Initial 
Comments at 5; Breakthrough Energy Initial Comments at 21-22; Clean 
Energy Associations Initial Comments at 18-20; DC and MD Offices of 
People's Counsel Initial Comments at 20, 28-30; ENGIE Reply Comments 
at 2-3; Hannon Armstrong Initial Comments at 2-3; Idaho Power 
Initial Comments at 7-8; Interwest Initial Comments at 12-14; ISO-NE 
Initial Comments at 34; Joint Consumer Advocates Initial Comments at 
11-12; MISO Initial Comments at 50-51; NARUC Initial Comments at 21, 
24-25; National and State Conservation Organizations Initial 
Comments at 1; New Jersey Commission Initial Comments at 11-14; 
North Carolina Commission and Staff Initial Comments at 6-7; NRECA 
Initial Comments at 45; Pacific Northwest Utilities Initial Comments 
at 9; Pine Gate Initial Comments at 34-37; PIOs Initial Comments at 
37-38; PJM Initial Comments at 94; PJM Market Monitor Initial 
Comments at 5-6; PPL Initial Comments at 13-15; RMI Initial Comments 
at 1; SEIA Initial Comments at 16; Southeast PIOs Initial Comments 
at 50; Southeast PIOs Reply Comments at 27-28; Southern Initial 
Comments at 25-27; West Virginia Commission Supplemental Comments at 
4; US DOE Initial Comments at 31-32.
    \1822\ ACEG Initial Comments at 6-8; AEE Reply Comments at 25-
26; AEP Initial Comments at 6, 23-27; Amazon Initial Comments at 5; 
Breakthrough Energy Initial Comments at 21-23; California Commission 
Initial Comments at 31-34; California Energy Commission Initial 
Comments at 3; CARE Coalition Initial Comments at 32-33; Certain 
TDUs Reply Comments at 1-3; Clean Energy Associations Initial 
Comments at 19-20; Clean Energy Buyers Initial Comments at 20-21; 
Clean Energy States Initial Comments at 6-8; DC and MD Offices of 
People's Counsel Initial Comments at 18-19; Entergy Initial Comments 
at 21; Environmental Groups Supplemental Comments at 2-3; Grand 
Rapids NAACP Initial Comments at 21-23; GridLab Initial Comments at 
25-28; Interwest Initial Comments at 13-14; ITC Initial Comments at 
21-22; Joint Consumer Advocates Initial Comments at 11-12; Large 
Public Power Initial Comments at 28-29; Michigan Commission Initial 
Comments at 7; Nevada Commission Initial Comments at 10-11; 
Northwest and Intermountain Initial Comments at 15-16; NYISO Initial 
Comments at 39; Pattern Energy Reply Comments at 8-9; PIOs Initial 
Comments at 43-44; PIOs Reply Comments at 7-8; PJM Initial Comments 
at 94-96; Policy Integrity Initial Comments at 28; Policy Integrity 
Supplemental Comments at 4-8; PPL Initial Comments at 14-15; R 
Street Initial Comments at 9-10; Rail Electrification Initial 
Comments at 6-7; RMI Initial Comments at 2; SEIA Initial Comments at 
16-17; Shell Initial Comments at 14-16; Tabors Caramanis Rudkevich 
Initial Comments at 6; US DOE Initial Comments at 33-34; Vistra 
Initial Comments at 15-16; WE ACT Initial Comments at 2-3.
---------------------------------------------------------------------------

(b) Commission Determination
    821. We decline to require transmission providers to measure and 
use the remaining five benefits described in the NOPR in Long-Term 
Regional Transmission Planning (i.e., mitigation of weather and load 
uncertainty, generation capacity investments, access to lower-cost 
generation, increased competition, and increased market liquidity). We 
find that the required set of benefits that we adopt herein is a 
sufficiently broad range of benefits to ensure that transmission 
providers are identifying, evaluating, and selecting Long-Term Regional 
Transmission Facilities that more efficiently or cost-effectively 
address Long-Term Transmission Needs. As such, we find that the 
measurement and use of additional benefits in Long-Term Regional 
Transmission Planning is not necessary to ensure that rates remain just 
and reasonable.
    822. However, we recognize that Long-Term Regional Transmission 
Facilities may provide additional benefits that may merit consideration 
when transmission providers are identifying, evaluating, and selecting 
such facilities to address Long-Term Transmission Needs more 
efficiently or cost-effectively. Therefore, transmission providers may 
measure and use additional benefits beyond those included in the 
required set of benefits in Long-Term Regional Transmission Planning, 
including on a transmission facility or plan-specific basis, subject to 
the requirement that they do so in a manner that is consistent with 
their obligations under Order No. 890 and Order No. 1000 transmission 
planning principles to be open and transparent as to their transmission 
planning processes.
3. Identification, Measurement, and Evaluation of the Benefits of Long-
Term Regional Transmission Facilities
a. NOPR Proposal
    823. The Commission proposed to require transmission providers in 
each transmission planning region to identify on compliance the 
benefits that they will use in Long-Term Regional Transmission 
Planning, how they will calculate those benefits, and how the benefits 
will reasonably reflect the benefits of regional transmission 
facilities to meet identified transmission needs driven by changes in 
the resource mix and demand. The Commission proposed that as part of 
this compliance obligation, transmission providers would be required to 
explain the rationale for using the benefits identified.\1823\
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    \1823\ NOPR, 179 FERC ] 61,028 at P 183.
---------------------------------------------------------------------------

b. Comments
    824. Many commenters support requiring identification of, and 
transparency regarding, the benefits that transmission providers will 
use in Long-Term Regional Transmission Planning.\1824\ For example, 
Nebraska Commission states that the NOPR proposal will foster the 
necessary flexibility to accommodate varying needs and approaches of 
different transmission planning regions.\1825\
---------------------------------------------------------------------------

    \1824\ APPA Initial Comments at 5; Avangrid Initial Comments at 
7, 29; Business Council for Sustainable Energy Initial Comments at 
5; California Commission Initial Comments at 28-30; California 
Energy Commission Initial Comments at 3; ENGIE Reply Comments at 3; 
Handy Law Initial Comments at 8; Massachusetts Attorney General 
Initial Comments at 3; Michigan Commission Initial Comments at 6; 
Nebraska Commission Initial Comments at 7; NESCOE Initial Comments 
at 44 (citing NOPR, 179 FERC ] 61,028 at PP 183, 186); NRECA Initial 
Comments at 46; NYISO Initial Comments at 37-38; Pennsylvania 
Commission Initial Comments at 9; PJM Initial Comments at 7; Vermont 
State Entities Initial Comments at 6.
    \1825\ Nebraska Commission Initial Comments at 7.
---------------------------------------------------------------------------

    825. Certain TDUs and Michigan Commission state that transmission 
providers must clearly articulate their methods for calculating 
identified benefits.\1826\ Certain TDUs further state that benefits 
should be evaluated with consistent reference cases to ensure 
consistency across scenarios.\1827\ Certain TDUs and Entergy state that 
transmission providers should incorporate their benefit calculation 
methods, as well as, according to Entergy, their role in selection, 
into the OATT.\1828\ Entergy argues that the Commission should allow 
transmission providers to use different benefits on a regional or 
subregional level, but that benefits should not change from one 
transmission project or portfolio to the next without an OATT 
amendment.\1829\
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    \1826\ Certain TDUs Initial Comments at 13; Michigan Commission 
Initial Comments at 6.
    \1827\ Certain TDUs Initial Comments at 13-14.
    \1828\ Certain TDUs Initial Comments at 14-15; Entergy Reply 
Comments at 4-5 (citing City & Cnty. of San Francisco v. FERC, 24 
F.4th 652, 661 (D.C. Cir. 2022); Sw. Power Pool, Inc., 180 FERC ] 
61,074, at PP 24-31 (2022), order on reh'g and setting aside, 182 
FERC ] 61,100 (2023)).
    \1829\ Entergy Reply Comments at 5.
---------------------------------------------------------------------------

    826. MISO TOs state that MISO already meets the NOPR's proposed 
requirement to identify benefits used in Long-Term Regional 
Transmission Planning and explain how they will be calculated.\1830\
---------------------------------------------------------------------------

    \1830\ MISO TOs Initial Comments at 19-22 (citing MISO, Electric 
Tariff, attach. FF Sec. Sec.  II.C.2, II.C.5; MISO, LRTP Tranche 1 
Portfolio Detailed Business Case, at 15-49, 60 (June 25, 2022), 
https://cdn.misoenergy.org/LRTP%20Tranche%201%20Detailed%20Business%20Case625789.pdf).
---------------------------------------------------------------------------

    827. Some commenters express concerns with the Commission's 
proposed benefit identification requirement,\1831\ including concerns 
over perceived excessive quantification \1832\ or requirements to 
calculate benefits individually.\1833\ Duke asserts that the Commission 
should

[[Page 49415]]

clarify that it will not force transmission providers to assign dollar 
values for every benefit because some benefits' quantification is 
subjective.\1834\ EEI asserts that transmission providers should not 
have to calculate all of the benefits for a transmission project but 
states that those benefits used for cost allocation purposes should be 
quantifiable.\1835\ NYISO requests that the final order confirm that it 
does not prescribe how benefits must be calculated and, more 
specifically, that transmission providers are not required to calculate 
the listed benefits in the exact manner described in the NOPR.\1836\
---------------------------------------------------------------------------

    \1831\ DC and MD Offices of People's Counsel Initial Comments at 
19; Duke Initial Comments at 24; EEI Initial Comments at 20; Entergy 
Initial Comments at 22; Illinois Commission Initial Comments at 13-
14; Louisiana Commission Initial Comments at 18; Michigan Commission 
Initial Comments at 6; US Chamber of Commerce Initial Comments at 7-
8. Further detail on the basis for these commenters' concerns is 
provided infra.
    \1832\ See, e.g., Duke Initial Comments at 24.
    \1833\ See, e.g., EEI Initial Comments at 20.
    \1834\ Duke Initial Comments at 24.
    \1835\ EEI Initial Comments at 20.
    \1836\ NYISO Initial Comments at 36-40.
---------------------------------------------------------------------------

    828. MISO notes that the benefits it currently uses in regional 
transmission planning are not all specified in the Tariff itself but 
were developed as part of the review process with MISO stakeholders. 
MISO adds that the flexibility to look for relevant benefits and apply 
them in long-term planning scenarios is important in the process to 
identify long-term regional solutions that reflect the needs and value-
drivers of the MISO footprint.\1837\ MISO states that if limited to a 
prescriptive set of benefits, MISO may not be in the same position to 
move forward the transmission projects of the greatest benefit and 
value to MISO and its stakeholders.\1838\
---------------------------------------------------------------------------

    \1837\ MISO Initial Comments at 9-10.
    \1838\ Id. at 9.
---------------------------------------------------------------------------

    829. Some commenters opine on requirements or best practices for 
identifying, measuring, and combining benefits.\1839\ For example, some 
commenters comment on the measurement and/or calculation of 
benefits.\1840\ Entergy argues that the Commission should require all 
benefits to be reasonably achievable in real-time operations.\1841\ SPP 
Market Monitor states that assumptions into benefit calculations should 
be improved to ensure that they result in just and reasonable 
rates.\1842\ Large Public Power emphasizes that the Commission should 
clarify that benefits must reflect load-serving entities' actual use of 
proposed transmission facilities, measured by anticipated power 
flows.\1843\
---------------------------------------------------------------------------

    \1839\ Acadia Center and CLF Initial Comments at 23; ACORE Reply 
Comments at 3; ACEG Initial Comments at 32; AEP Initial Comments at 
21-24; APPA Initial Comments at 32; City of New Orleans Council 
Initial Comments at 11; Clean Energy Associations Initial Comments 
at 20-21; DC and MD Offices of People's Counsel Initial Comments at 
19; Duke Initial Comments at 24; EEI Initial Comments at 20; Entergy 
Initial Comments at 22; Illinois Commission Initial Comments at 13-
14; Large Public Power Initial Comments at 28; Louisiana Commission 
Initial Comments at 18; Michigan State Entities Initial Comments at 
5-7; NARUC Initial Comments at 20-26; NASUCA Initial Comments at 10; 
NRECA Initial Comments at 45; NYISO Initial Comments at 37; PJM 
Market Monitor Initial Comments at 4; SEIA Initial Comments at 18-
19; Six Cities Initial Comments at 2-3; Southern Initial Comments at 
31; SPP Market Monitor Initial Comments at 11; US Chamber of 
Commerce Initial Comments at 7-8; US DOE Initial Comments at 31; 
Vermont State Entities Initial Comments at 6.
    \1840\ AEP Initial Comments at 21-24; Clean Energy Associations 
Initial Comments at 21; Large Public Power Initial Comments at 28; 
SEIA Initial Comments at 18-19; SPP Market Monitor Initial Comments 
at 11.
    \1841\ Entergy Initial Comments at 22.
    \1842\ SPP Market Monitor Initial Comments at 11.
    \1843\ Large Public Power Initial Comments at 28.
---------------------------------------------------------------------------

    830. SEIA suggests that there are many resources to inform methods 
for the calculation of benefits, including MISO's Long Range 
Transmission Plan Tranche 1 portfolio.\1844\ Also referencing MISO's 
process, AEP contends that the benefits of regional transmission 
facilities should be evaluated collectively, through a multi-value 
analysis, and cites MISO's existing process as an example.\1845\
---------------------------------------------------------------------------

    \1844\ SEIA Initial Comments at 18-19 (citing Rob Gramlich, 
Enabling Low-Cost Clean Energy & Reliable Service Through Better 
Transmission Benefits Analysis, at 17, https://acore.org/wp-content/uploads/2022/08/ACORE-Enabling-Low-Cost-Clean-Energy-and-Reliable-Service-Through-Better-Transmission-Analysis.pdf).
    \1845\ AEP Initial Comments at 21-24.
---------------------------------------------------------------------------

    831. Some commenters opine on the need for quantification and/or 
specificity of benefits.\1846\ DC and MD Offices of People's Counsel 
assert that any benefit used should be pre-defined and its measurement 
accurate and transparent.\1847\ PIOs also state that the Brattle-Grid 
Strategies Oct. 2021 Report provides evidence that benefits from 
transmission facilities are not difficult to quantify despite claims to 
the contrary.\1848\ NASUCA asserts that the methods for calculating and 
assigning benefits should be based on objective, measurable, clear, and 
specific metrics.\1849\ Similarly, Illinois Commission, Pacific 
Northwest Utilities, and NARUC assert that transmission benefits must 
be verifiable and quantifiable.\1850\
---------------------------------------------------------------------------

    \1846\ ACORE Reply Comments at 3 (citing US DOE Initial Comments 
at 31); Concerned Scientists Reply Comments at 8-10; DC and MD 
Offices of People's Counsel Initial Comments at 19; Entergy Initial 
Comments at 22; NASUCA Initial Comments at 10; US DOE Initial 
Comments at 31.
    \1847\ DC and MD Offices of People's Counsel Initial Comments at 
19.
    \1848\ PIOs Initial Comments at 42-44.
    \1849\ NASUCA Initial Comments at 10.
    \1850\ Illinois Commission Initial Comments at 13-14; NARUC 
Initial Comments at 20-25; Pacific Northwest Utilities Initial 
Comments at 8-9.
---------------------------------------------------------------------------

    832. A few commenters address the ease of quantification of the 
benefits listed in the NOPR. NARUC states that NOPR Benefits 1-5 and 8-
10 seem somewhat capable of quantification.\1851\ NRECA asserts that 
the benefits at the top of the list in the NOPR are reasonably 
quantifiable, while those farther down the list require more subjective 
judgements.\1852\ APPA agrees that some of the benefits listed in the 
NOPR would be more challenging to quantify and therefore would be more 
difficult to justify as a just and reasonable way to allocate 
costs.\1853\
---------------------------------------------------------------------------

    \1851\ NARUC Initial Comments at 21.
    \1852\ NRECA Initial Comments at 45.
    \1853\ APPA Initial Comments at 32.
---------------------------------------------------------------------------

    833. Some commenters support the use of benefit-cost analysis 
frameworks.\1854\ Michigan State Entities express that having a 
prescribed benefit-cost analysis framework can help ensure appropriate 
quantification of benefits, adding that there is less transparency when 
individual transmission providers may determine how these benefits 
stack up against each other.\1855\ Therefore, Michigan State Entities 
recommend that the Commission adopt the cost-benefit analysis framework 
already used throughout the Federal Government. According to Michigan 
State Entities, the Commission's legal authority to do so is well-
established by court decisions and it would help to ensure sufficient 
regional transmission cooperation to achieve just and reasonable 
rates.\1856\
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    \1854\ Michigan State Entities Initial Comments at 5-7; Six 
Cities Initial Comments at 2-3; Southern Initial Comments at 31; 
Vermont State Entities Initial Comments at 6-7.
    \1855\ Michigan State Entities Initial Comments at 5.
    \1856\ Id. at 6-7.
---------------------------------------------------------------------------

    834. Six Cities argues that transmission planning should assess 
both project benefits and costs.\1857\ Vermont State Entities agree 
that a comprehensive benefit-cost analysis would lead to better and 
more cost-effective transmission planning.\1858\ Southern also states 
that the burdens associated with proposed transmission projects should 
be recognized, including not only immediate cost and rate impacts, but 
also effects on local communities and landowners and issues of equity 
and environmental justice.\1859\
---------------------------------------------------------------------------

    \1857\ Six Cities Initial Comments at 2-3.
    \1858\ Vermont State Entities Initial Comments at 6-7.
    \1859\ Southern Initial Comments at 31.
---------------------------------------------------------------------------

    835. Likewise, certain commenters state that they support the 
adoption of benefit-cost analysis using quantifiable, replicable, non-
duplicative, and forward-looking metrics.\1860\ US

[[Page 49416]]

Chamber of Commerce contends that the objective nature of such metrics 
should limit uncertainty otherwise present in projections spanning 
multiple decades and reduce the variability and error in benefit 
calculations.\1861\ Acadia Center and CLF and ACEG argue that an 
unbiased analysis of both benefits and costs is essential for ensuring 
just and reasonable rates and that the Commission should seek to ensure 
that a minimum set of benefits is applied consistently across RTO/ISO 
and non-RTO/ISO transmission planning regions.\1862\ ACORE agrees with 
US DOE that consistency in benefit quantification could facilitate 
improved interregional transmission planning.\1863\
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    \1860\ City of New Orleans Council Initial Comments at 11; 
Entergy Initial Comments at 22; Louisiana Commission Initial 
Comments at 18; US Chamber of Commerce Initial Comments at 7-8.
    \1861\ US Chamber of Commerce Initial Comments at 8.
    \1862\ Acadia Center and CLF Initial Comments at 23; ACEG 
Initial Comments at 32.
    \1863\ ACORE Reply Comments at 3 (citing US DOE Initial Comments 
at 31).
---------------------------------------------------------------------------

    836. Other commenters state that the NOPR's proposed reforms will 
help improve transmission providers' existing benefit-cost 
analyses.\1864\ GridLab states that the NOPR's approach balances 
regional flexibility with Federal standardization in benefit categories 
across transmission providers and more accountability by transmission 
providers in their benefit-cost analysis.\1865\ PJM Market Monitor 
states that PJM's current benefit-cost analysis does not accurately 
measure the costs and benefits of transmission projects because it does 
not account for the fact that benefits are uncertain and sensitive to 
modeling assumptions or that costs may exceed estimates.\1866\ Illinois 
Commission states that the use of too many metrics could lead to the 
evaluation of transmission projects based on the margins and 
inequitable cost allocation.\1867\ Illinois Commission further states 
that some metrics may be most relevant for interregional and regional 
transmission projects identified in the Long-Term Regional Transmission 
Planning process and that the Commission can aid transmission planning 
regions in putting together a shorter list of these metrics.\1868\
---------------------------------------------------------------------------

    \1864\ GridLab Initial Comments at 25; PJM Market Monitor 
Initial Comments at 4-5; Southeast PIOs Initial Comments at 49-50.
    \1865\ GridLab Initial Comments at 25.
    \1866\ PJM Market Monitor Initial Comments at 4-5.
    \1867\ Illinois Commission Initial Comments at 13.
    \1868\ Id. at 14.
---------------------------------------------------------------------------

c. Commission Determination
    837. We adopt the NOPR proposal, with modification, and require 
transmission providers in each transmission planning region to include 
in their OATTs a general description of how they will measure each of 
the seven benefits included in the required set of benefits that we 
require them to measure and use in Long-Term Regional Transmission 
Planning. As discussed above, we clarify that transmission providers 
may use and measure additional benefits, beyond the seven required by 
this final order.\1869\
---------------------------------------------------------------------------

    \1869\ While we conclude that it is important for transmission 
providers to at minimum use and measure the required seven benefits, 
we agree with MISO that the flexibility to look for relevant 
benefits and apply them in long-term planning scenarios can be 
important in the process to identify long-term regional solutions 
that reflect region-specific needs and value-drivers. MISO Initial 
Comments at 9. We therefore afford flexibility to transmission 
planners in identifying and measuring benefits that go beyond the 
core set of seven required here.
---------------------------------------------------------------------------

    838. We find that requiring such a description in transmission 
providers' OATTs for the seven required benefits is necessary to ensure 
that all stakeholders have transparency regarding the benefits that 
transmission providers use to identify, evaluate, and select Long-Term 
Regional Transmission Facilities that more efficiently or cost-
effectively address Long-Term Transmission Needs. We further conclude 
that requiring inclusion of this information in the OATT will better 
ensure transmission providers measure and use the set of benefits 
required in the final order in Long-Term Regional Transmission 
Planning.
    839. Some commenters express concerns regarding excessive 
quantification of benefits.\1870\ But the approach adopted in this 
final order--of requiring transmission providers to measure and use a 
required set of benefits in Long-Term Regional Transmission Planning 
and requiring transmission providers to include in their OATTs a 
general description of the method they will use to measure each of 
those benefits--represents a reasonable balance between specificity and 
flexibility. As discussed above, we provide flexibility to transmission 
providers to specify the method for measuring each of the seven 
required benefits. However, because our requirement that transmission 
providers measure and use these benefits in Long-Term Regional 
Transmission Planning is necessary to address the identified 
deficiencies in existing regional transmission planning and cost 
allocation processes, we find that it is also necessary for 
transmission providers to include in their OATTs a general description 
of how they will measure each of these benefits. Such a requirement 
will ensure that transmission providers consider a sufficiently broad 
range of benefits when determining whether to select a Long-Term 
Regional Transmission Facility as a more efficient or cost-effective 
regional transmission solution to Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \1870\ See, e.g., Duke Initial Comments at 24.
---------------------------------------------------------------------------

    840. In response to some commenters, such as MISO, that urge that 
requiring details on measurement of benefits to be incorporated into 
the OATT could impede development and use of new transmission metrics, 
we clarify that the description for each required benefit in the OATT 
must only be sufficient to enable stakeholders to understand the manner 
by which transmission providers will measure these benefits. We do not 
require further details on measurement of the benefits to be included 
in the OATT.
    841. Large Public Power asks that the Commission clarify that any 
acceptable list of benefits detailed in compliance filings must 
emphasize load-serving entities' actual use of the proposed 
transmission facilities, which should be measured by anticipated power 
flows that occur across these facilities.\1871\ We decline to adopt 
Large Public Power's suggested clarification as we are not mandating 
any particular method for measuring the seven benefits included in the 
required set of benefits.
---------------------------------------------------------------------------

    \1871\ Large Public Power Initial Comments at 28.
---------------------------------------------------------------------------

    842. We decline certain commenters' requests to require that 
transmission providers justify why they omit any categories of 
benefits.\1872\ Such a requirement is unnecessary because of our 
modifications to the NOPR proposal, which now require transmission 
providers to measure and use the required set of benefits in Long-Term 
Regional Transmission Planning.
---------------------------------------------------------------------------

    \1872\ GridLab Initial Comments at 25; NYISO Initial Comments at 
37-38; Vermont State Entities Initial Comments at 6-7.
---------------------------------------------------------------------------

4. Evaluation of Transmission Benefits Over a Longer Time Horizon
a. NOPR Proposal
    843. In the NOPR, the Commission proposed to require transmission 
providers in each transmission planning region to evaluate, as part of 
Long-Term Regional Transmission Planning, the benefits of regional 
transmission facilities over a time horizon that covers, at a minimum, 
20 years starting from the estimated in-service date of the regional 
transmission facilities.\1873\
---------------------------------------------------------------------------

    \1873\ NOPR, 179 FERC ] 61,028 at P 227.
---------------------------------------------------------------------------

    844. The Commission proposed to require transmission providers to 
evaluate benefits over this time horizon in all stages of Long-Term 
Regional Transmission Planning, which includes evaluating regional 
transmission

[[Page 49417]]

facilities, selecting more efficient or cost-effective regional 
transmission facilities in the regional transmission plan for purposes 
of cost allocation, and allocating the costs of such regional 
transmission facilities in a manner that is at least roughly 
commensurate with estimated benefits. The Commission proposed that for 
consistency and a matching comparison of benefits and costs over time, 
to the extent that transmission providers estimate the costs of 
transmission facilities beyond the in-service date of the transmission 
facilities, that transmission providers should estimate those future 
costs over the same time horizon as the estimated benefit.\1874\ The 
Commission proposed that approaches may exceed this minimum 
requirement, but transmission providers must demonstrate that their 
proposal is consistent with or superior to any final order in this 
proceeding.
---------------------------------------------------------------------------

    \1874\ Id. P 228.
---------------------------------------------------------------------------

b. Comments
i. Requirement for a Benefits Evaluation Time Horizon of a Minimum of 
20 Years From the In-Service Date
    845. Several commenters support the Commission's proposal to 
require that transmission providers in each transmission planning 
region evaluate, as part of Long-Term Regional Transmission Planning, 
the benefits of regional transmission facilities over a time horizon 
that covers, at a minimum, 20 years starting from the estimated in-
service date of the transmission facilities.\1875\ NARUC, for example, 
states that transmission planning must strike a reasonable balance 
between considering benefits only through the end of the transmission 
planning horizon regardless of the transmission facility's in-service 
date and considering benefits over its full expected life, which NARUC 
states that the NOPR proposal achieves.\1876\ Northwest and 
Intermountain state that they cautiously support the Commission's 
proposal to establish a minimum 20-year horizon for the calculation of 
benefits, noting that their concerns are mitigated by the NOPR proposal 
to allow flexibility within each transmission planning region to tailor 
cost allocation criteria to that region's needs.\1877\ Similarly, 
Vermont State Entities and NESCOE state that a rigid one-size-fits-all 
rule could be counterproductive and would not necessarily lead to just 
and reasonable transmission rates.\1878\ NARUC states that, while it 
supports the NOPR proposal, transmission providers should be allowed 
independent entity variations to deviate above or below the 20-year 
horizon after gaining experience with Long-Term Regional Transmission 
Planning.\1879\ NYISO contends that it already employs a 30-year study 
period in evaluating the benefits of transmission projects in its 
public policy transmission planning process.\1880\
---------------------------------------------------------------------------

    \1875\ ACEG Initial Comments at 24; California Commission 
Initial Comments at 36; Certain TDUs Reply Comments at 3; ITC 
Initial Comments at 22-23; NARUC Initial Comments at 26-27; NYISO 
Initial Comments at 40; OMS Initial Comments at 8-9; Pacific 
Northwest State Agencies Initial Comments at 16-19.
    \1876\ NARUC Initial Comments at 26.
    \1877\ Northwest and Intermountain Initial Comments at 8.
    \1878\ NESCOE Initial Comments at 45; Vermont State Entities 
Initial Comments at 6.
    \1879\ NARUC Initial Comments at 39-40.
    \1880\ NYISO Initial Comments at 40.
---------------------------------------------------------------------------

    846. MISO supports the Commission's proposal, stating that a 
minimum period of 20 years is adequate to assess the benefits of 
regional transmission facilities.\1881\ MISO cautions, however, that 
the benefits determined over this time horizon represent the minimum 
benefits that a regional transmission facility provides and that the 
analysis should recognize that additional benefits would be realized 
over the life of the investment even if changing system conditions 
create uncertainty as to the precise value of those benefits.\1882\
---------------------------------------------------------------------------

    \1881\ MISO Initial Comments at 52.
    \1882\ Id.
---------------------------------------------------------------------------

    847. Other commenters suggest that the time horizon for the 
evaluation of benefits in Long-Term Regional Transmission Planning 
should align with the useful life of the transmission asset.\1883\ 
Breakthrough Energy and CARE Coalition contend that the proper time 
horizon for evaluation of benefits in standard economics and public 
policy is the life of the transmission asset, noting that transmission 
assets can often last 40 years or longer.\1884\ ACEG agrees, noting 
that, while it supports use of a 20-year minimum horizon to evaluate 
benefits, standard regulatory practice for a benefit-cost analysis is 
typically the life of the asset.\1885\ Likewise, PIOs contend that, 
while they agree with the NOPR proposal, it would be preferable to 
align the time horizon for evaluating benefits with the useful life of 
the transmission project.\1886\ PIOs state that calculating the 
benefits and costs of a transmission project over a shorter timespan 
can understate the benefit-cost ratio because benefits tend to grow 
over time, while transmission revenue requirements will decline over 
time as the asset is depreciated.\1887\
---------------------------------------------------------------------------

    \1883\ ACEG Initial Comments at 24; Breakthrough Energy Initial 
Comments at 23; CARE Coalition Initial Comments at 40-41; Clean 
Energy Associations Initial Comments at 21; CTC Global Initial 
Comments at 16-17; ENGIE Initial Comments at 2; ENGIE Reply Comments 
at 2; Indicated PJM TOs Initial Comments at 17-18; Interwest Initial 
Comments at 14; Interwest Reply Comments at 6-7; Pine Gate Initial 
Comments at 35; PIOs Initial Comments at 40-41; US DOE Initial 
Comments at 33-34; WIRES Initial Comments at 7.
    \1884\ Breakthrough Energy Initial Comments at 23; CARE 
Coalition Initial Comments at 40-41.
    \1885\ ACEG Initial Comments at 24.
    \1886\ PIOs Initial Comments at 40 (citing PIOs Initial Comments 
Ex. A, ]] 24-29).
    \1887\ Id. (citing PIOs Initial Comments Ex. A, ] 28).
---------------------------------------------------------------------------

    848. CTC Global states that while it supports the NOPR proposal, it 
argues that it would be more appropriate to align the timeline for 
evaluating benefits with the asset life, because while advanced 
conductors are almost always more expensive than legacy conductors 
initially, their costs are offset by efficiency and resilience benefits 
decades into the future.\1888\ Indicated PJM TOs state that benefits 
``should be calculated on the same time horizon as the project that is 
being assessed to allow for the ability to properly compare projects.'' 
\1889\
---------------------------------------------------------------------------

    \1888\ CTC Global Initial Comments at 16-17.
    \1889\ Indicated PJM TOs Initial Comments at 18.
---------------------------------------------------------------------------

    849. Given that transmission assets often have a useful life of at 
least 40 years, US DOE encourages the Commission to require 
transmission providers to evaluate costs and benefits over a minimum of 
30 years after the in-service date of a transmission facility rather 
than the proposed 20 years. According to US DOE, doing so would better 
align with the useful life assumptions that generation developers 
make.\1890\
---------------------------------------------------------------------------

    \1890\ US DOE Initial Comments at 33-34.
---------------------------------------------------------------------------

    850. Clean Energy Buyers and PG&E suggest that benefits should be 
evaluated over the same 20-year horizon as the proposed Long-Term 
Regional Transmission Planning transmission planning horizon.\1891\ 
Similarly, PPL states that, while it supports the proposed 20-year 
minimum duration to evaluate benefits in Long-Term Regional 
Transmission Planning, the Commission should require transmission 
providers to measure benefits from the study date rather than the 
proposed in-service date of the Long-Term Regional Transmission 
Facility. PPL contends that the NOPR proposal would introduce 
significant variability that will make it challenging to align the 
outcome with the long-term need and would incentivize transmission 
developers to delay or adjust the timing

[[Page 49418]]

of transmission projects to maximize the demonstrated benefit.\1892\
---------------------------------------------------------------------------

    \1891\ Clean Energy Buyers Initial Comments at 20; PG&E Initial 
Comments at 7.
    \1892\ PPL Initial Comments at 15-17.
---------------------------------------------------------------------------

    851. In contrast, GridLab contends that the 20-year Long-Term 
Regional Transmission Planning transmission planning horizon need not 
correspond with the time horizon over which transmission providers 
evaluate the benefits and costs of potential transmission investments. 
GridLab recommends that the Commission clarify the distinction between 
the requirement for a 20-year transmission planning horizon and for a 
20-year period to evaluate benefits, while keeping both 
requirements.\1893\
---------------------------------------------------------------------------

    \1893\ GridLab Initial Comments at 6-8.
---------------------------------------------------------------------------

    852. Many commenters assert that evaluating benefits over a 20-year 
time horizon is difficult or speculative.\1894\ Ohio Consumers and 
Dominion argue that, since transmission providers would be required to 
plan for potential transmission needs in 20 years and evaluate benefits 
over a 20-year project life span, the requirement effectively amounts 
to a 40-year cost allocation process and will be particularly 
challenging.\1895\ APS agrees, stating that calculating benefits over a 
potential 40 years may lead to benefit calculations that are overstated 
or yield unreasonable or unrealistic results.\1896\
---------------------------------------------------------------------------

    \1894\ APPA Initial Comments at 32; Dominion Initial Comments at 
17; Louisiana Commission Initial Comments at 18; NRECA Initial 
Comments at 46; Ohio Consumers Initial Comments at 8; PJM Initial 
Comments at 97.
    \1895\ Ohio Consumers Initial Comments at 8.
    \1896\ APS Initial Comments at 8-9.
---------------------------------------------------------------------------

    853. Some commenters request certain clarifications or 
modifications to address that uncertainty.\1897\ For example, Exelon 
states that benefits should tie back to customer value and suggests 
that the Commission should give transmission providers flexibility to 
assign more weight to nearer-term benefits tied to specific savings 
that are more certain.\1898\ SERTP Sponsors and Duke agree, and Duke 
requests that the Commission clarify that transmission providers are 
permitted to discount benefits based on increased uncertainty in later 
years for purposes of evaluating, selecting, and allocating the costs 
of Long-Term Regional Transmission Facilities.\1899\
---------------------------------------------------------------------------

    \1897\ Duke Initial Comments at 23-24; Exelon Initial Comments 
at 16; SERTP Sponsors Initial Comments at 31.
    \1898\ Exelon Initial Comments at 16.
    \1899\ Duke Initial Comments at 23-24; SERTP Sponsors Initial 
Comments at 31.
---------------------------------------------------------------------------

    854. Several commenters oppose requiring a minimum 20-year horizon 
for evaluating benefits of Long-Term Regional Transmission 
Facilities.\1900\ For example, Idaho Commission argues that the NOPR 
proposal is founded on benefits that are not ``generally accepted or 
regionally flexible'' and may not be beneficial for regional 
transmission planning benefit evaluation.\1901\ Furthermore, Idaho 
Commission argues, it is difficult to accurately predict and quantify 
benefits over a 20-year period for purposes of cost allocation.\1902\
---------------------------------------------------------------------------

    \1900\ Dominion Reply Comments at 4-5; Idaho Commission Initial 
Comments at 4; NARUC Initial Comments at 5-6; NESCOE Initial 
Comments at 44-45; Pacific Northwest Utilities Initial Comments at 
6-7; Pennsylvania Commission Initial Comments at 4-5.
    \1901\ Idaho Commission Initial Comments at 4.
    \1902\ Id.
---------------------------------------------------------------------------

    855. Similarly, Dominion requests that the Commission decline to 
adopt the NOPR proposal or provide clarification that the Commission 
did not intend to propose that benefits would need to be evaluated over 
a potential 40-year period. Dominion states that it would be 
unreasonable for the Commission to require transmission providers to 
consider benefits over a 40-year period, because identifying benefits 
and beneficiaries that far into the future would involve too much 
speculation.
    856. Pennsylvania Commission requests that the Commission revise 
the NOPR proposal to set a long-term horizon of no longer than 20 years 
for planning and benefit-cost analysis. Pennsylvania Commission argues 
that as the planning and benefit-cost analysis horizons lengthen, 
uncertainty in predictions of load growth, costs, and benefits will 
increase, potentially leading to uneconomic transmission 
projects.\1903\ Pacific Northwest Utilities oppose the NOPR proposal 
because, they argue, beneficiaries and benefits cannot be identified or 
quantified with any reasonable certainty over a 20-year transmission 
planning horizon. Specifically, Pacific Northwest Utilities contend 
that there is no plausible reason to believe that such speculative 
benefits would be roughly commensurate with the costs that are 
allocated to identified beneficiaries.\1904\
---------------------------------------------------------------------------

    \1903\ Pennsylvania Commission Initial Comments at 4-5.
    \1904\ Pacific Northwest Utilities Initial Comments at 7 (citing 
ICC v. FERC I, 576 F.3d 470).
---------------------------------------------------------------------------

ii. Applicability of Benefits Evaluation Horizon to Long-Term Regional 
Transmission Planning Stages (Evaluation of Facilities, Selection, and 
Cost Allocation)
    857. Pacific Northwest State Agencies supports the Commission's 
proposal to require that transmission providers evaluate benefits over 
a consistent time horizon in all stages of Long-Term Regional 
Transmission Planning, which includes evaluating regional transmission 
facilities, selecting more efficient or cost-effective regional 
transmission facilities in the regional transmission plan for purposes 
of cost allocation, and allocating the costs of such transmission 
facilities in a manner that is roughly commensurate with estimated 
benefits.\1905\
---------------------------------------------------------------------------

    \1905\ Pacific Northwest State Agencies Initial Comments at 18.
---------------------------------------------------------------------------

    858. Several commenters also support the Commission's proposal 
that, to the extent that transmission providers estimate the costs of 
transmission facilities beyond the in-service date of the transmission 
facilities, they should estimate those future costs over the same time 
horizon as the estimated benefits.\1906\ For instance, MISO states that 
costs and benefits for regional transmission investments should be 
evaluated using the same time horizon to ensure there is consistency in 
accounting for the effects of time in the calculations.\1907\ MISO 
attests that since benefits are only realized once a transmission 
project or portfolio of projects is in service, transmission providers 
should assess the benefits over the period of time starting with the 
in-service date to align with costs.\1908\ Pacific Northwest State 
Agencies and Certain TDUs agree.\1909\
---------------------------------------------------------------------------

    \1906\ Certain TDUs Reply Comments at 3 (citing MISO Initial 
Comments at 53); MISO Initial Comments at 53; NARUC Initial Comments 
at 27; OMS Initial Comments at 8-9; Pacific Northwest State Agencies 
Initial Comments at 18.
    \1907\ MISO Initial Comments at 53.
    \1908\ Id.
    \1909\ Certain TDUs Reply Comments at 3 (citing MISO Initial 
Comments at 53); Pacific Northwest State Agencies Initial Comments 
at 18.
---------------------------------------------------------------------------

c. Commission Determination
    859. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region, as part of 
Long-Term Regional Transmission Planning, to calculate the benefits of 
Long-Term Regional Transmission Facilities over a time horizon that 
covers, at a minimum, 20 years starting from the estimated in-service 
date of the transmission facilities, and we require that this minimum 
20-year benefit horizon be used both for the evaluation and selection 
of Long-Term Regional Transmission Facilities.\1910\ However,

[[Page 49419]]

we do not adopt the NOPR proposal to require a minimum 20-year horizon 
to calculate benefits for purposes of cost allocation. As described in 
the Identification of Benefits Considered in Cost Allocation for Long-
Term Regional Transmission Facilities section of this final order, 
requiring transmission providers to adopt this provision for purposes 
of cost allocation would unduly complicate development and review of 
Long-Term Regional Transmission Cost Allocation Methods, with little 
incremental gain. Lastly, for consistency and a matching comparison of 
costs over time, we adopt the NOPR proposal to require that, to the 
extent that transmission providers estimate the costs of Long-Term 
Regional Transmission Facilities beyond the in-service date of the 
transmission facilities, they must estimate those future costs over the 
same time horizon as the estimated benefits.
---------------------------------------------------------------------------

    \1910\ In the NOPR, the Commission used the term ``regional 
transmission facilities''; however, as this reform only concerns 
Long-Term Regional Transmission Planning, we clarify that the 
Commission's intent was to refer only to Long-Term Regional 
Transmission Facilities. As discussed in the Development of Long-
Term Scenarios section, transmission providers also use these 
benefits to help to inform their identification of Long-Term 
Transmission Needs that manifest during the 20-year transmission 
planning horizon.
---------------------------------------------------------------------------

    860. We find that calculating benefits both for the evaluation and 
selection of Long-Term Regional Transmission Facilities over a timeline 
that covers, at a minimum, 20 years starting from the estimated in-
service date of the Long-Term Regional Transmission Facility, strikes 
an appropriate balance. This balance reasonably reflects the benefits 
that a Long-Term Regional Transmission Facility is likely to provide 
over its useful life, a time period that can exceed 40 years,\1911\ 
while recognizing the inherent difficulties in attempting to predict 
system conditions too far into the future. As described in the Long-
Term Regional Transmission Planning section of this final order, the 
uncertainty associated with forecasting future transmission needs over 
a long-term transmission planning horizon can be mitigated through the 
use of multiple Long-Term Scenarios and sensitivities.
---------------------------------------------------------------------------

    \1911\ ACEG Initial Comments at 24; Breakthrough Energy Initial 
Comments at 23; CARE Coalition Initial Comments at 40-41; Clean 
Energy Associations Initial Comments at 21; CTC Global Initial 
Comments at 16-17; ENGIE Initial Comments at 2; ENGIE Reply Comments 
at 2; Indicated PJM TOs Initial Comments at 18; Interwest Initial 
Comments at 14; Interwest Reply Comments at 7; Pine Gate Initial 
Comments at 35; PIOs Initial Comments at 40-41; US DOE Initial 
Comments at 33-34; WIRES Initial Comments at 7.
---------------------------------------------------------------------------

    861. Specifically, this final order requires transmission providers 
to develop multiple plausible and diverse Long-Term Scenarios, which 
will allow transmission providers to better understand how certain 
categories of factors will give rise to Long-Term Transmission Needs, 
and also requires transmission providers to update their assumptions 
periodically. Additionally, transmission providers are permitted to 
assess the extent to which the projected change to Long-Term 
Transmission Needs due to factors in Factor Categories Four through 
Seven is likely to be realized in full, in part, or exceeded, for 
purposes of developing a plausible and diverse set of Long-Term 
Scenarios.\1912\ Because of these reforms, we believe that transmission 
providers will be able to identify Long-Term Transmission Needs with a 
higher likelihood of occurrence, and, therefore, the benefits resulting 
from Long-Term Regional Transmission Facilities to more efficiently or 
cost-effectively address these Long-Term Transmission Needs will 
similarly be more certain.
---------------------------------------------------------------------------

    \1912\ Supra Long-Term Regional Transmission Planning, Long-Term 
Scenarios Requirements, Categories of Factors section.
---------------------------------------------------------------------------

    862. Moreover, as described in the Evaluation and Selection of 
Regional Transmission Facilities section of this final order, we 
provide transmission providers with considerable flexibility to develop 
an evaluation process and selection criteria that will provide them the 
opportunity to select Long-Term Regional Transmission Facilities in a 
way that maximizes benefits accounting for costs over time without 
over-building transmission facilities. In particular, transmission 
providers have the flexibility to evaluate Long-Term Regional 
Transmission Facilities and their measured benefits across the 
different Long-Term Scenarios and sensitivities in a manner that 
addresses the inherent uncertainty in Long-Term Regional Transmission 
Planning, for example through the use of a least-regrets or a weighted-
benefits approach. Lastly, as is the case under the existing Order No. 
1000 regional transmission planning processes, the final order does not 
require transmission providers to select any transmission facilities as 
part of Long-Term Regional Transmission Planning. Taken together, the 
aspects of the final order described above offer transmission providers 
meaningful tools to address uncertainty in Long-Term Regional 
Transmission Planning, including the calculation of benefits.
    863. We disagree with NESCOE and Vermont State Entities, who argue 
that a requirement to calculate benefits over a minimum of 20 years 
from the estimated in-service date is overly rigid and may not lead to 
transmission rates that are just and reasonable. As discussed above, 
this requirement strikes a reasonable balance between the benefits that 
a Long-Term Regional Transmission Facility is likely to provide over 
its useful life, while recognizing the inherent difficulties in 
attempting to forecast system conditions too far into the future. 
Further, allowing transmission providers to calculate benefits over a 
shorter period would more likely undervalue the total benefits that 
Long-Term Regional Transmission Facilities can provide and could 
therefore lead to relatively inefficient and less cost-effective 
transmission development, as Long-Term Regional Transmission Facilities 
that provide significant net benefits may not be selected to address 
Long-Term Transmission Needs. Lastly, and as stated above, we are not 
requiring transmission providers to use a minimum 20-year horizon to 
calculate benefits for purposes of cost allocation.
    864. Similarly, we also disagree with commenters that suggest that 
the results of the benefits evaluation would not be accurate or 
dependable enough for transmission providers to use in making the 
decision to select Long-Term Regional Transmission Facilities.\1913\ We 
further note that transmission providers in multiple transmission 
planning regions already evaluate the benefits of transmission 
facilities over a 20-year time horizon as part of their regional 
transmission planning processes.\1914\ For example, NYISO states that 
it employs a 30-year study period in evaluating the benefits of 
transmission projects in its public policy transmission planning 
process.\1915\
---------------------------------------------------------------------------

    \1913\ APPA Initial Comments at 32; APS Initial Comments at 8-9; 
Dominion Initial Comments at 17; Idaho Commission Initial Comments 
at 4; Louisiana Commission Initial Comments at 18; NRECA Initial 
Comments at 46; Ohio Consumers Initial Comments at 8; Pacific 
Northwest Utilities Initial Comments at 7; PJM Initial Comments at 
97.
    \1914\ MISO Initial Comments at 52; NYISO Initial Comments at 
40; see also MISO, LRTP Business Case, Long Range Transmission 
Planning Workshop, at 7 (Jan. 21, 2022, revised Feb. 2, 2022), 
https://cdn.misoenergy.org/20220121%20LRTP%20Workshop%20Item%2004%20Business%20Case%20Presentation619895.pdf; CAISO, 20-Year Transmission Outlook (Jan. 31, 2022), 
https://www.caiso.com/InitiativeDocuments/Draft20-YearTransmissionOutlook.pdf; SPP Engineering, 2021 SPP Transmission 
Expansion Plan Report (Jan. 11, 2021), https://spp.org/documents/56611/2021%20step%20report.pdf.
    \1915\ NYISO Initial Comments at 40.
---------------------------------------------------------------------------

    865. Some commenters suggest that the Commission should provide 
additional flexibility to account for uncertainty in calculating 
benefits over a minimum 20-year time horizon, including that the 
Commission make clear that transmission providers may discount or 
weight the calculated benefits based on the relative certainty 
throughout the benefits horizon.\1916\ As

[[Page 49420]]

we described above, this final order affords transmission providers 
considerable flexibility in how to address uncertainty in Long-Term 
Regional Transmission Planning, including by allowing transmission 
providers to assess the extent to which the projected change to Long-
Term Transmission Needs due to factors in factor Categories Four 
through Seven is likely to be realized in full, in part, or exceeded, 
for purposes of developing a plausible and diverse set of Long-Term 
Scenarios. Given these flexibilities, we find that while transmission 
providers may discount the benefits calculated for purposes of 
determining a present value of those benefits, they may not further 
discount those benefits to reflect uncertainty over the minimum 20-year 
time horizon for calculating benefits.
---------------------------------------------------------------------------

    \1916\ Duke Initial Comments at 23-24; Exelon Initial Comments 
at 16; SERTP Sponsors Initial Comments at 31.
---------------------------------------------------------------------------

    866. In response to Dominion's request for clarification that the 
Commission did not intend to propose that benefits would need to be 
evaluated over a potential 40-year period, we reiterate that 
transmission providers must calculate the benefits of Long-Term 
Regional Transmission Facilities over a minimum of 20 years from their 
estimated in-service date, even if the estimated in-service date is 20 
years into the future. The failure to take such an approach could 
result in transmission providers' consideration of a Long-Term Regional 
Transmission Facility's cost but not the facility's corresponding 
benefits.
    867. We also decline to modify the proposal, as requested by 
Pennsylvania Commission,\1917\ to require a benefits horizon of no 
longer than 20 years as a means of reducing speculation and uncertainty 
in calculating benefits of Long-Term Regional Transmission Facilities, 
as well as NARUC's request that the Commission permit transmission 
providers to deviate below the 20-year benefit evaluation horizon. As 
explained above, a minimum of 20 years strikes a reasonable balance for 
calculating the benefits of Long-Term Regional Transmission Facilities. 
In addition, as indicated by many commenters, calculating the benefits 
of a Long-Term Transmission Facility over a time horizon longer than 20 
years is consistent with the long life of transmission facilities--
which generally exceeds 20 years by a substantial margin--and also 
consistent with the fact that transmission facilities may provide 
significant benefits over their entire useful life. While we reiterate 
that transmission providers must calculate the benefits of Long-Term 
Regional Transmission Facilities over a time horizon that covers, at a 
minimum, 20 years starting from the estimated in-service date of the 
transmission facilities, to the extent that transmission providers 
would like to consider a longer time horizon for the evaluation of 
benefits, they may propose to do so on compliance.
---------------------------------------------------------------------------

    \1917\ Pennsylvania Commission Initial Comments at 4-5.
---------------------------------------------------------------------------

    868. In response to Pacific Northwest Utilities' argument that 
transmission providers will be unable to identify the beneficiaries of 
Long-Term Regional Transmission Facilities over a 20-year time horizon, 
and therefore that the costs of Long-Term Regional Transmission 
Facilities will not be allocated in a manner that is roughly 
commensurate with the benefits received,\1918\ we note that this final 
order modifies the NOPR proposal and transmission providers are not 
required to use a benefits time horizon of 20 years for purposes of 
cost allocation. We find this modification to the final order moots 
Pacific Northwest Utilities' argument.
---------------------------------------------------------------------------

    \1918\ Pacific Northwest Utilities Initial Comments at 7 (citing 
ICC v. FERC I, 576 F.3d 470).
---------------------------------------------------------------------------

    869. We disagree with PPL's comments arguing that calculating 
benefits from the estimated in-service date of a Long-Term Regional 
Transmission Facility will present challenges to align the outcome with 
the actual needs in Long-Term Regional Transmission Planning or 
otherwise create perverse incentives for transmission developers to 
delay or adjust the timing of certain transmission projects to maximize 
benefits.\1919\ To the contrary, establishing a minimum benefits 
horizon of 20 years starting from the estimated in-service date of 
Long-Term Regional Transmission Facilities will allow for a comparable 
evaluation of benefits that identified Long-Term Regional Transmission 
Facilities may provide, even when such facilities may be placed in 
service at different times during the transmission planning horizon. We 
therefore decline PPL's request that the Commission modify the proposal 
to require that transmission providers measure benefits for a minimum 
of 20 years starting from the study date, rather than the estimated in-
service date of the Long-Term Regional Transmission Facility.
---------------------------------------------------------------------------

    \1919\ PPL Initial Comments at 15-17.
---------------------------------------------------------------------------

    870. In response to GridLab's request that the Commission clarify 
the distinction between the requirements for a minimum 20-year 
transmission planning horizon and a minimum 20-year benefits evaluation 
period,\1920\ we reiterate the example provided in the NOPR whereby, if 
the Long-Term Regional Transmission Planning process identifies a Long-
Term Regional Transmission Facility that is estimated to be in service 
in year 10 of the 20-year Long-Term Regional Transmission Planning 
horizon, then the estimate of benefits for that same facility will 
commence at year 10 and cover an additional 20 years. Thus, the 
requirement to use a 20-year transmission planning horizon is separate 
and distinct from the requirement to calculate benefits of an 
identified Long-Term Regional Transmission Facility over a minimum of 
20 years from its estimated in-service date.
---------------------------------------------------------------------------

    \1920\ GridLab Initial Comments at 6-8.
---------------------------------------------------------------------------

5. Evaluation of the Benefits of Portfolios of Transmission Facilities
a. NOPR Proposal
    871. In the NOPR, the Commission proposed to provide transmission 
providers in each transmission planning region with the flexibility to 
propose to use a portfolio approach in the evaluation of benefits of 
regional transmission facilities through their Long-Term Regional 
Transmission Planning. Rather than mandating its use, the Commission 
encouraged the use of this approach by transmission providers.\1921\ 
The Commission proposed to require transmission providers that propose 
to use a portfolio approach to include in their OATTs provisions 
describing how they would analyze the benefits of regional transmission 
facilities under such an approach and whether the portfolio approach 
would be used for Long-Term Regional Transmission Planning universally 
or would be used only in certain specified instances.\1922\
---------------------------------------------------------------------------

    \1921\ NOPR, 179 FERC ] 61,028 at PP 233-234.
    \1922\ Id. P 234.
---------------------------------------------------------------------------

b. Comments
i. General Interest in the Use of Portfolios
    872. Most commenters who addressed the issue support the use of a 
portfolio approach to the evaluation of the benefits of regional 
transmission facilities in Long-Term Regional Transmission Planning, 
under which transmission providers would evaluate multiple transmission 
facilities in an aggregated, integrated fashion rather than doing so on 
a facility-by-facility basis.\1923\ Exelon states that benefits

[[Page 49421]]

assessments for portfolios are likely to be more robust and less 
sensitive to changes in study assumptions than project-by-project 
analyses, tend to have widely distributed benefits, which can help 
garner stakeholder support, and may provide for administrative 
efficiencies in transmission planning.\1924\ ACEG states that portfolio 
planning more accurately evaluates the benefits that new transmission 
provides to the system.\1925\ Georgia Commission states that evaluating 
transmission facilities collectively, rather than on a facility-by-
facility basis, may provide a better picture of the benefits to each 
state or transmission planning region and result in a more robust 
selection of transmission facilities.\1926\
---------------------------------------------------------------------------

    \1923\ See, e.g., Acadia Center and CLF Initial Comments at 10; 
ACEG Initial Comments at 49; ACORE Initial Comments at 2; AEP 
Initial Comments at 6, 27-28; Ameren Initial Comments at 19; Clean 
Energy Associations Initial Comments at 10; Eversource Initial 
Comments at 25; Exelon Initial Comments at 15-16; Joint Consumer 
Advocates Initial Comments at 11; Massachusetts Attorney General 
Initial Comments at 15-16; Pacific Northwest State Agencies Initial 
Comments at 7; PG&E Initial Comments at 8; PJM Reply Comments at 23; 
PIOs Initial Comments at 28; TANC Initial Comments at 16; US DOE 
Initial Comments at 34-35.
    \1924\ Exelon Initial Comments at 15-16, 18 (citing NOPR, 179 
FERC ] 61,028 at P 233).
    \1925\ ACEG Initial Comments at 49.
    \1926\ Georgia Commission Initial Comments at 7.
---------------------------------------------------------------------------

    873. Renewable Northwest states that using portfolios in 
transmission planning is a best practice because it more completely 
captures systems benefits and leads to cost efficiencies.\1927\ 
Renewable Northwest also comments that singularly focused planning 
processes often fail to identify the most cost-effective and efficient 
investments and instead have led to a bottom-up approach that has 
created a patchwork of transmission projects with high costs largely 
borne by ratepayers.\1928\ EEI explains that the portfolio approach 
comprehensively addresses a number of transmission needs while ensuring 
a ``no regrets'' set of beneficial regional transmission 
projects.\1929\ Eversource states that a portfolio approach can allow 
transmission providers to devise a set of transmission solutions that 
collectively create the most value compared to a piecemeal 
process.\1930\
---------------------------------------------------------------------------

    \1927\ Renewable Northwest Initial Comments at 9-10 (citing 
Brattle-Grid Strategies Oct. 2021 Report at 23).
    \1928\ Id. at 9.
    \1929\ EEI Initial Comments at 15.
    \1930\ Eversource Initial Comments at 25.
---------------------------------------------------------------------------

    874. AEP states that the portfolio approach offers three 
advantages: (1) it enables transmission planning regions to identify 
transmission projects with synergistic benefits across transmission 
planning regions because regions will be able to recognize the 
efficiencies of a collection of transmission projects that provide 
greater overall value to the grid together than they each provide on an 
individual basis; (2) there are administrative efficiencies; and (3) a 
portfolio approach best incorporates consideration of non-transmission 
alternatives and grid-enhancing technologies.\1931\
---------------------------------------------------------------------------

    \1931\ AEP Initial Comments at 27-28.
---------------------------------------------------------------------------

    875. Numerous commenters point to the MISO Multi-Value Project 
process as an example of the successful use of portfolios.\1932\ Clean 
Energy Associations state that the Multi-Value Project process has 
resulted in lower interconnection costs for generators as compared to 
transmission upgrades planned in response to interconnection 
requests.\1933\ US DOE suggests the Multi-Value Project process is an 
example of the use of portfolios to generate benefits that exceed 
costs.\1934\ MISO states that it has worked with stakeholders to apply 
broad benefit metrics in the evaluation of Multi-Value Projects to 
identify portfolios of projects with benefits spread broadly throughout 
the region.\1935\
---------------------------------------------------------------------------

    \1932\ See, e.g., EEI Initial Comments at 15; Clean Energy 
Associations Initial Comments at 10; MISO Initial Comments at 14; US 
DOE Initial Comments at 34-35 (citing Brattle-Grid Strategies Oct. 
2021 Report at 65-66).
    \1933\ Clean Energy Associations Initial Comments at 10.
    \1934\ US DOE Initial Comments at 35 (citing Brattle-Grid 
Strategies Oct. 2021 Report at 65-66).
    \1935\ MISO Initial Comments at 14.
---------------------------------------------------------------------------

    876. Some commenters believe that the Commission should require the 
use of portfolios in the evaluation of benefits of regional 
transmission facilities.\1936\ US DOE supports requiring transmission 
planners to evaluate the benefits of proposed transmission facilities 
as a portfolio, rather than as individual investments, to reduce the 
uncertainty of estimating system-level benefits, to simplify cost 
allocation, and to reduce administrative burden.\1937\ US DOE states 
that if the portfolio approach is inappropriate in a particular 
circumstance, the impacted entities could petition the Commission, on a 
case-by-case basis, to describe their proposed alternative 
approach.\1938\
---------------------------------------------------------------------------

    \1936\ Acadia Center and CLF Initial Comments at 4-5; ACEG 
Initial Comments at 31, 48-49; Cypress Creek Reply Comments at 8-9; 
ITC Initial Comments at 6, 23-24; Pattern Energy Initial Comments at 
15-17; Pine Gate Initial Comments at 38-39; PIOs Initial Comments at 
28; SEIA Initial Comments at 20-21; US DOE Initial Comments at 34-
35; WATT Initial Comments at 8-9.
    \1937\ US DOE Initial Comments at 34-35.
    \1938\ Id. at 35.
---------------------------------------------------------------------------

    877. New Jersey Commission states that the evidence from multiple 
studies of and experiences with long-term multi-driver and portfolio-
based transmission planning proves that these approaches save 
ratepayers billions of dollars and failure to use them is per se unjust 
and unreasonable.\1939\ Cypress Creek argues that a portfolio approach 
is essential to optimize benefits and reduce the likelihood of a state 
or agency derailing a transmission project with proven regional 
benefits.\1940\
---------------------------------------------------------------------------

    \1939\ New Jersey Commission Initial Comments at 7.
    \1940\ Cypress Creek Reply Comments at 9.
---------------------------------------------------------------------------

    878. PIOs state that the costs of a transmission project in a rural 
area that enhances access to renewable resources may exceed its 
benefits when evaluated alone, but, if evaluated with another project 
that relieves congestion, the two projects may support power flows that 
would not otherwise be possible.\1941\ PIOs further state that 
portfolio planning can reduce the risk that transmission projects are 
underutilized because they were built for a single resource that is no 
longer used or only a narrow set of users were considered.\1942\
---------------------------------------------------------------------------

    \1941\ PIOs Initial Comments at 31-32.
    \1942\ Id. at 36.
---------------------------------------------------------------------------

    879. ITC argues that the Commission should mandate the use of a 
portfolio approach in RTO/ISOs to ensure that the most efficient, cost-
effective, and broadly beneficial set of transmission projects are 
selected in each transmission planning cycle.\1943\ ITC states that the 
use of a portfolio approach ensures that the greatest number of 
subregions within a transmission planning region receive benefits from 
each transmission planning cycle and provides significant efficiency 
gains because transmission providers can examine the whole portfolio to 
ensure that benefits exceed costs.\1944\
---------------------------------------------------------------------------

    \1943\ ITC Initial Comments at 6, 23-24.
    \1944\ Id. at 23.
---------------------------------------------------------------------------

    880. Pattern Energy urges the Commission to require transmission 
providers to adopt portfolio approaches and explain why a portfolio 
approach was not (or could not be) identified in any Long-Term Regional 
Transmission Plan when an incremental transmission solution is 
proposed.\1945\ Pattern Energy suggests that, if the Commission does 
not require portfolios, it should set a voltage threshold to identify 
portfolio solutions and require that transmission providers must 
explain why a portfolio approach was not taken when proposing 
incremental transmission facilities at voltage levels above 100 
kV.\1946\ Similarly, Shell states that if the Commission does not 
require a portfolio approach, it should require transmission

[[Page 49422]]

providers to explain why portfolios are not being used.\1947\
---------------------------------------------------------------------------

    \1945\ Pattern Energy Initial Comments at 15-17.
    \1946\ Id. at 17.
    \1947\ Shell Initial Comments at 16.
---------------------------------------------------------------------------

ii. Interest in Flexibility in the Use of Portfolios
    881. Many other commenters assert that the Commission should only 
permit, not require, the use of portfolios in the evaluation of 
benefits.\1948\ For example, Duke states that a facility-by-facility 
approach may be better suited if Long-Term Scenarios reveal the same or 
nearly identical constraints in discrete and isolated areas of the 
transmission grid where upgrades would be beneficial, whereas if Long-
Term Scenarios reveal more disparate issues in different scenarios a 
portfolio approach may be better suited to gaining consensus and 
allowing for more even distribution of benefits.\1949\ Duke asks the 
Commission to provide that, on compliance, a transmission provider may 
document processes for switching between or using both a facility-by-
facility analysis and a portfolio approach.\1950\
---------------------------------------------------------------------------

    \1948\ APPA Initial Comments at 32; Arizona Commission Initial 
Comments at 8; California Commission Initial Comments at 36-37; 
Dominion Initial Comments at 36; Duke Initial Comments at 25; 
Georgia Commission Initial Comments at 25; Michigan Commission 
Initial Comments at 8; MISO Initial Comments at 54; NARUC Initial 
Comments at 27-29; Nebraska Commission Initial Comments at 7-8; 
NESCOE Initial Comments at 45; NYISO Initial Comments at 9, 41-42; 
PPL Initial Comments at 16-17; SDG&E Initial Comments at 3; SPP 
Initial Comments at 10; TANC Initial Comments at 16; TAPS Initial 
Comments at 14; Vermont State Entities Initial Comments at 7; Xcel 
Initial Comments at 12.
    \1949\ Duke Initial Comments at 25-26.
    \1950\ Id. at 25.
---------------------------------------------------------------------------

    882. Dominion Energy states that some transmission providers may 
not have a portfolio of transmission projects to examine. NYISO asserts 
that transmission providers should not be required to mix and match 
components of different transmission developers' proposed transmission 
solutions to develop a portfolio to address a single transmission 
need.\1951\ APPA and TANC urge the Commission to allow regional 
flexibility to use a portfolio approach to evaluate benefits.\1952\
---------------------------------------------------------------------------

    \1951\ NYISO Initial Comments at 41.
    \1952\ APPA Initial Comments at 32; TANC Initial Comments at 16.
---------------------------------------------------------------------------

    883. PPL argues that a portfolio approach should not be mandated 
because one-size-fits-all portfolio-based planning may have downsides 
and may not be applicable in all circumstances or transmission planning 
regions.\1953\ PPL further states that relying on portfolios could lead 
to complications in siting and cost allocation.\1954\ Relatedly, 
Michigan Commission argues that requiring portfolios could cause 
unnecessary delays for transmission projects that have strong 
stakeholder buy-in and incentivize including transmission projects less 
deserving of regional cost allocation purely to bolster assertions that 
all zones in multi-state RTOs/ISOs will benefit.\1955\
---------------------------------------------------------------------------

    \1953\ PPL Initial Comments at 16-17.
    \1954\ Id. at 17.
    \1955\ Michigan Commission Initial Comments at 8.
---------------------------------------------------------------------------

    884. CAISO states that portfolio planning should be optional, 
arguing that CAISO's sequential transmission planning approach achieves 
multi-benefit and holistic objectives without requiring a portfolio 
approach.\1956\ CAISO explains that a project-by-project review does 
not mean examining only one transmission need at a time or failing to 
consider transmission projects that meet multiple needs or deliver 
multiple benefits.\1957\
---------------------------------------------------------------------------

    \1956\ CAISO Reply Comments at 22.
    \1957\ Id. at 21-22.
---------------------------------------------------------------------------

iii. Interest in Including the Portfolio Approach in a Transmission 
Provider's OATT
    885. In response to the Commission's proposal that a transmission 
provider that proposes a portfolio approach must include in its OATT a 
description of when it would use the approach and how it would analyze 
benefits, some commenters agree that even if use of portfolios is 
flexible, the Commission should have such a requirement.\1958\ Vermont 
State Entities suggest that if a transmission provider elects to use a 
portfolio approach, it must include in its OATT a description of how it 
would use such an approach and whether that approach would be used 
universally or only in certain specified instances.\1959\
---------------------------------------------------------------------------

    \1958\ Clean Energy Associates Initial Comments at 14; NESCOE 
Initial Comments at 45; Vermont State Entities Initial Comments at 
7.
    \1959\ Vermont State Entities Initial Comments at 7.
---------------------------------------------------------------------------

iv. Integrating Economic and Reliability Planning With Long-Term 
Regional Transmission Planning
    886. PIOs state that portfolio planning is necessary and that the 
use of portfolios should incorporate long-term reliability and economic 
needs and benefits along with long-term Public Policy Requirements, 
because doing so allows transmission providers to select transmission 
projects with the higher benefit-to-cost ratios that resolve needs at 
least cost.\1960\ PIOs state that by assessing all transmission needs 
at once and evaluating potential solutions, stakeholders will be able 
to find more efficient solutions that address multiple transmission 
needs that affect different jurisdictions simultaneously.\1961\ PIOs 
ask that the final order allow transmission providers to continue to 
address unforeseen short-term local reliability needs but establish a 
rebuttable requirement that all long-term economic, public policy, and 
regional reliability needs and benefits will be assessed on a portfolio 
basis in Long-Term Regional Transmission Planning.\1962\
---------------------------------------------------------------------------

    \1960\ PIOs Initial Comments at 30-32.
    \1961\ Id. at 35.
    \1962\ PIOs Initial Comments at 32.
---------------------------------------------------------------------------

    887. SEPA states that the portfolio approach can be further 
enhanced by considering all categories of benefits: reliability, 
economic, public policy, and resilience.\1963\ Likewise, SEIA states 
that the Commission should require portfolio-based planning that 
integrates all relevant factors, reliability, economic, and public 
policy, into Long-Term Regional Transmission Planning.\1964\ Acadia 
Center and CLF discuss portfolio planning as integrating Long-Term 
Regional Transmission Planning with economic and reliability planning 
and state that the final order should require portfolio-based planning 
that assesses economic, reliability, and other needs at the same 
time.\1965\
---------------------------------------------------------------------------

    \1963\ SEPA Initial Comments at 1.
    \1964\ SEIA Initial Comments at 20-21.
    \1965\ Acadia Center and CLF Initial Comments at 4-5.
---------------------------------------------------------------------------

v. Concerns With the Portfolio Approach
    888. A few commenters express apprehension about the portfolio 
approach, including concerns that the use of portfolios may mask bad 
individual transmission projects in a portfolio or result in good 
transmission projects not being approved because of difficulties in 
obtaining multiple state approvals that may be necessary for a 
portfolio.\1966\ For example, Pennsylvania Commission states that a 
portfolio approach may cause siting concerns if a single transmission 
project in a portfolio is found by a state siting authority to be 
inconsistent with its state's public interest and siting 
regulations.\1967\ Idaho Commission opposes requiring the use of a 
portfolio under any circumstances, stating that flexibility is 
necessary in transmission planning. It further states that a Commission 
requirement to use a portfolio approach under certain circumstances 
without specifying what

[[Page 49423]]

these circumstances are could result in unjust and unreasonable 
rates.\1968\ Louisiana Commission also opposes any requirement to use a 
portfolio approach and disagrees with the NOPR's encouragement of such 
an approach.\1969\
---------------------------------------------------------------------------

    \1966\ CAISO Reply Comments at 24; Duke Initial Comments at 25-
26; Idaho Commission Initial Comments at 4; Louisiana Commission 
Initial Comments at 26; NARUC Initial Comments at 28; Pennsylvania 
Commission Initial Comments at 10; PPL Initial Comments at 17.
    \1967\ Pennsylvania Commission Initial Comments at 10.
    \1968\ Idaho Commission Initial Comments at 4.
    \1969\ Louisiana Commission Initial Comments at 26.
---------------------------------------------------------------------------

c. Commission Determination
    889. We adopt the NOPR proposal to allow, but not require, 
transmission providers in each transmission planning region to use a 
portfolio approach when evaluating the benefits of Long-Term Regional 
Transmission Facilities. Further, we adopt with modification the NOPR 
proposal to require transmission providers that propose to use a 
portfolio approach when evaluating the benefits of Long-Term Regional 
Transmission Facilities to include provisions in their OATTs regarding 
their use of the portfolio approach. While we adopt the NOPR proposal 
to require transmission providers to include provisions in their OATTs 
regarding their use of a portfolio approach, we do not adopt the other 
proposed requirements. Specifically, we decline to adopt the NOPR 
proposal to require transmission providers to indicate whether a 
portfolio approach will be used universally or only in certain 
specified instances or to describe how they will analyze the benefits 
of regional transmission facilities under a portfolio approach. These 
requirements could impede transmission provider consideration and 
development of portfolio approaches. In response to Duke's request that 
the final order provide transmission providers with the flexibility to 
switch between or use both facility-by-facility and portfolio 
approaches,\1970\ we clarify that transmission providers may use either 
or both facility-by-facility and portfolio approaches within the same 
Long-Term Regional Transmission Planning cycle.
---------------------------------------------------------------------------

    \1970\ Duke Initial Comments at 25-26.
---------------------------------------------------------------------------

    890. We find that there are numerous advantages to a portfolio 
approach to evaluating benefits, including administrative efficiencies 
related to economies of scale and a more stable or even distribution of 
benefits that may result from a portfolio evaluation, which is likely 
to facilitate agreement on regional cost allocation. However, these 
advantages must be balanced against other considerations, and we 
therefore find that providing transmission providers in each 
transmission planning region with flexibility as to whether to use a 
portfolio approach is appropriate. Accordingly, we decline the request 
of some commenters \1971\ to require transmission providers to use a 
portfolio approach.
---------------------------------------------------------------------------

    \1971\ Acadia Center and CLF Initial Comments at 4-5; ACEG 
Initial Comments at 31, 48-49; Cypress Creek Reply Comments at 8-9; 
ITC Initial Comments at 6, 23-24; Pattern Energy Initial Comments at 
16-18; Pine Gate Initial Comments at 38-39; PIOs Initial Comments at 
28; SEIA Initial Comments at 20-21; US DOE Initial Comments at 34-
35; WATT Initial Comments at 8-9.
---------------------------------------------------------------------------

6. Issues Related to Use of Benefits
a. NOPR Proposal
    891. The Commission in the NOPR declined, consistent with Order No. 
1000, to propose to prescribe any particular definition of ``benefits'' 
or ``beneficiaries.'' \1972\
---------------------------------------------------------------------------

    \1972\ NOPR, 179 FERC ] 61,028 at P 183 & n.324 (citing Order 
No. 1000, 136 FERC ] 61,051 at PP 624-625).
---------------------------------------------------------------------------

b. Comments
    892. Some commenters request specific definitions for the terms 
``benefits'' or ``beneficiaries'' or offer guidance on 
definitions.\1973\ NASUCA urges the Commission not to define benefits 
so broadly that every transmission project would qualify to be built, 
stating that overly broad benefit definitions reduce any rational 
relationship between cost allocation and identifiable 
beneficiaries.\1974\
---------------------------------------------------------------------------

    \1973\ ELCON Initial Comments at 14-15; NASUCA Initial Comments 
at 10.
    \1974\ NASUCA Initial Comments at 10.
---------------------------------------------------------------------------

    893. In contrast, other commenters agree with the Commission's 
proposal not to define ``benefits'' or ``beneficiaries.'' \1975\ For 
example, OMS and the Indiana Commission express support for the NOPR 
proposal to allow for flexibility in determining the definitions of 
benefits and beneficiaries for the purpose of selecting transmission 
facilities in Long-Term Regional Transmission Planning.\1976\
---------------------------------------------------------------------------

    \1975\ APPA Initial Comments at 31-33; Clean Energy Buyers Reply 
Comments at 9; Georgia Commission Initial Comments at 6-7; Indiana 
Commission Initial Comments at 6-7; Louisiana Commission Reply 
Comments at 9-10; Nebraska Commission Initial Comments at 7; TANC 
Initial Comments at 16; US Chamber of Commerce Initial Comments at 
7-8.
    \1976\ Indiana Commission Initial Comments at 6-7; OMS Initial 
Comments at 13.
---------------------------------------------------------------------------

    894. Some commenters call for a state role in identifying benefits 
or metrics for use in Long-Term Regional Transmission Planning.\1977\ 
California Commission states that the Commission should require 
transmission providers to demonstrate that they consulted with the 
Relevant State Entities in their transmission planning region regarding 
benefits metrics.\1978\ California Commission further states that the 
Commission should require transmission providers to indicate in their 
compliance filings whether their proposed benefits and metrics are 
supported by the Relevant State Entities, as well as to explain any 
points of disagreement.\1979\ Likewise, New York Commission and NYSERDA 
state that, especially in single-state RTOs/ISOs, the state should be 
afforded a central role in determining the benefits that transmission 
providers will consider and the metrics for quantifying them.\1980\
---------------------------------------------------------------------------

    \1977\ California Commission Initial Comments at 35; 
Massachusetts Attorney General Initial Comments at 14; Michigan 
Commission Initial Comments at 7-8; NESCOE Initial Comments at 41-
43; North Carolina Commission and Staff Initial Comments at 6; PJM 
Market Monitor Initial Comments at 4.
    \1978\ California Commission Initial Comments at 35.
    \1979\ Id.
    \1980\ New York Commission and NYSERDA Initial Comments at 8.
---------------------------------------------------------------------------

    895. North Carolina Commission and Staff state that, given the 
focus of the NOPR on transmission needs driven by changes in the 
generation mix and demand, which are areas of state jurisdiction, the 
Commission should require state agreement at every stage of the Long-
Term Regional Transmission Planning process from identification of 
transmission needs, to the evaluation of the benefits of regional 
transmission facilities to meet those needs, to establishment of 
selection criteria, and finally to establishment of a cost allocation 
method.\1981\ Similarly, NESCOE explains that, while transmission 
providers have the technical expertise to identify, calculate, and 
explain the benefits that a given transmission facility may provide, 
states must be involved where state laws and policies are the project 
drivers.\1982\ As such, NESCOE requests that the Commission require 
that transmission providers either elevate and codify the states' role 
in all four phases of Long-Term Regional Transmission Planning or 
explain how and why, following consultation with the Relevant State 
Entities, the transmission provider developed a different 
approach.\1983\ NESCOE asserts that this requirement would ensure that 
states, if they so elect, have a defined role in the evaluation phase 
of Long-Term Regional Transmission Planning.\1984\
---------------------------------------------------------------------------

    \1981\ North Carolina Commission and Staff Initial Comments at 
6.
    \1982\ NESCOE Initial Comments at 41-43.
    \1983\ Id. at 9-10, 41-43.
    \1984\ Id. at 41-43.
---------------------------------------------------------------------------

    896. Virginia Commission Staff contends that the NOPR-identified 
benefits should be used only if affected

[[Page 49424]]

states agree to their use.\1985\ PJM Market Monitor agrees that it 
makes sense to attempt an evaluation of a broad set of benefits and 
beneficiaries through increased state involvement.\1986\
---------------------------------------------------------------------------

    \1985\ Virginia Commission Staff Initial Comments at 5.
    \1986\ PJM Market Monitor Initial Comments at 4.
---------------------------------------------------------------------------

    897. Michigan Commission asserts that state regulators should be 
afforded substantial deference in identifying what benefit metrics and 
calculation methods should be used to justify long-term transmission 
plans, arguing that states with objections or concerns that an approved 
benefit metric is too speculative or otherwise inappropriate may find 
it more challenging to justify ratepayer investments and land 
condemnation in state siting proceedings.\1987\ Massachusetts Attorney 
General states that the Commission should require that transmission 
providers establish an open and transparent process that provides 
states and other stakeholders with a meaningful opportunity to 
participate in the process of identifying the benefits to be used in 
Long-Term Regional Transmission Planning and determining how such 
benefits will be calculated.\1988\ Several commenters state that 
decisions regarding benefit determination, metrics, and implementation 
of metrics should be made in coordination with all stakeholders.\1989\ 
NRECA and Vermont State Entities assert that transmission providers 
should be required to demonstrate that all stakeholders are provided an 
opportunity to become fully aware of the analytic framework for 
incorporating benefits that will be used in Long-Term Regional 
Transmission Planning.\1990\
---------------------------------------------------------------------------

    \1987\ Michigan Commission Initial Comments at 7-8.
    \1988\ Massachusetts Attorney General Initial Comments at 14.
    \1989\ NYISO Initial Comments at 37; NRECA Initial Comments at 
46; Vermont State Entities Initial Comments at 6.
    \1990\ NRECA Initial Comments at 46; Vermont State Entities 
Initial Comments at 6.
---------------------------------------------------------------------------

    898. PPL stresses the important role that states play in siting 
transmission facilities and the significance of benefits from 
transmission facilities in this process, cautioning that differences 
between states' and the Commission's delineation and evaluation of 
benefits will result in great uncertainty. PPL asserts that this 
uncertainty could lead to abandoned projects, costly litigation, and a 
largely underutilized planning tool, akin to transmission projects 
driven by public policy needs under Order No. 1000.\1991\
---------------------------------------------------------------------------

    \1991\ PPL Initial Comments at 14-15.
---------------------------------------------------------------------------

    899. In contrast, ACORE notes that the benefits of transmission 
facilities are often spread out among states regardless of the state 
policies contributing to the need for such transmission 
facilities.\1992\
---------------------------------------------------------------------------

    \1992\ ACORE Initial Comments at 12; ACORE Reply Comments at 6.
---------------------------------------------------------------------------

    900. SoCal Edison urges the Commission not to decouple policy 
projects from reliability and economic projects in transmission 
planning, so as to reduce barriers to regional coordination and ensure 
analysis of all potential benefits of a transmission project.\1993\
---------------------------------------------------------------------------

    \1993\ SoCal Edison Initial Comments at 12-13.
---------------------------------------------------------------------------

    901. Indiana Commission states that it supports the NOPR proposal 
as long as the final order provides for an equitable cost allocation 
method that allocates costs to the cost causer and beneficiaries of 
regional transmission development.\1994\
---------------------------------------------------------------------------

    \1994\ Indiana Commission Initial Comments at 6-7.
---------------------------------------------------------------------------

c. Commission Determination
    902. Consistent with the NOPR, we continue to decline to define 
``benefits'' or ``beneficiaries.'' We discuss above descriptions of the 
seven required benefits, and we further require transmission providers 
to propose a method to measure each of those benefits. These 
descriptions and requirements for these seven benefits will facilitate 
transparency regarding the use of benefits in Long-Term Regional 
Transmission Planning and represent an improvement in this respect over 
Order No. 1000, which lacked such descriptions.\1995\ However, we do 
not believe that establishing a definition of ``benefits'' or 
``beneficiaries'' would significantly improve upon these descriptions 
and we are concerned that any such definition could inadvertently 
exclude benefits and beneficiaries.
---------------------------------------------------------------------------

    \1995\ As noted above, we do not require transmission providers 
to include additional benefits that they use for purposes of 
evaluation and selection of Long-Term Regional Transmission 
Facilities in their OATTs.
---------------------------------------------------------------------------

    903. We acknowledge comments requesting greater clarity regarding 
states' roles in determining benefits in their transmission planning 
regions and regarding the benefits that will be used by transmission 
providers in Long-Term Regional Transmission Planning, including 
NRECA's and Vermont State Entities' assertions that transmission 
providers should be required to demonstrate that all stakeholders 
(including state entities and load-serving entities) are provided an 
opportunity to become fully aware of the analytic framework for 
incorporating benefits that will be used in Long-Term Regional 
Transmission Planning.\1996\ In response, we note this final order 
provides transmission providers with flexibility as to how they measure 
the seven required benefits, as well as flexibility to use additional 
benefits beyond the seven that we require. Consistent with other 
reforms in this final order incorporating an inclusive role for states 
in transmission planning, we encourage transmission providers to 
consult with states as they develop proposals to comply with the 
requirements of this final order and consider whether, and if so, how, 
to use additional benefits in Long-Term Regional Transmission 
Planning.\1997\
---------------------------------------------------------------------------

    \1996\ NRECA Initial Comments at 46; Vermont State Entities 
Initial Comments at 6.
    \1997\ See supra Other Benefits section.
---------------------------------------------------------------------------

E. Evaluation and Selection of Long-Term Regional Transmission 
Facilities

1. Requirement To Adopt an Evaluation Process and Selection Criteria
a. NOPR Proposal
    904. In the NOPR, the Commission proposed to require that 
transmission providers, as part of their Long-Term Regional 
Transmission Planning, include in their OATTs a transparent and not 
unduly discriminatory evaluation process and criteria to identify and 
evaluate transmission facilities (or portfolios of transmission 
facilities) for potential selection that address transmission needs 
driven by changes in the resource mix and demand.\1998\ The Commission 
preliminarily found that the development and analysis of Long-Term 
Scenarios cannot remedy the deficiencies in the Commission's existing 
regional transmission planning requirements without the inclusion of 
such an evaluation process and selection criteria because, without 
them, transmission providers' Commission-jurisdictional rates may be 
unjust and unreasonable and unduly discriminatory and 
preferential.\1999\
---------------------------------------------------------------------------

    \1998\ See NOPR, 179 FERC ] 61,028 at PP 241-242.
    \1999\ Id. P 250.
---------------------------------------------------------------------------

    905. The Commission further proposed in the NOPR that, consistent 
with Order No. 1000, the developer of a transmission facility selected 
through Long-Term Regional Transmission Planning to address 
transmission needs driven by changes in the resource mix and demand 
would be eligible to use the applicable cost allocation method for the 
Long-Term Regional Transmission Facility.
b. Comments
    906. Many commenters support the Commission's proposal to require

[[Page 49425]]

transmission providers to include in their OATTs provisions providing 
criteria that they will use to identify and evaluate transmission 
facilities for potential selection to address transmission needs driven 
by changes in the resource mix and demand.\2000\ For example, Pacific 
Northwest State Agencies argue that this reform is critical to ensuring 
that Long-Term Regional Transmission Planning results in appropriate 
modeling and evaluation of Long-Term Regional Transmission 
Facilities.\2001\ ACEG contends that transparent selection processes 
are key to reducing conflict (including costly litigation), developing 
legally sustainable long-term regional transmission plans, and 
maximizing benefits over time to consumers without over-building 
transmission facilities.\2002\
---------------------------------------------------------------------------

    \2000\ ACEG Initial Comments at 9; ACORE Initial Comments at 14; 
Amazon Initial Comments at 9; Ameren Initial Comments at 20; APPA 
Initial Comments at 33; CARE Coalition Initial Comments at 11-12; 
Clean Energy Buyers Initial Comments at 22; Exelon Initial Comments 
at 17; GridLab Initial Comments at 19; NRECA Initial Comments at 25; 
[Oslash]rsted Initial Comments at 5-6; Pacific Northwest State 
Agencies Initial Comments at 19; PPL Initial Comments at 18; Resale 
Iowa Initial Comments at 7-8.
    \2001\ Pacific Northwest State Agencies Initial Comments at 19.
    \2002\ ACEG Initial Comments at 9, 58.
---------------------------------------------------------------------------

    907. Other commenters oppose the Commission's proposal. Many of 
these commenters argue that Long-Term Regional Transmission Planning 
should be for informational purposes only and that the Commission 
should not require transmission providers to include selection criteria 
in their OATTs.\2003\ Alabama Commission contends that Long-Term 
Regional Transmission Planning should not involve selection or 
construction obligations unless the affected state regulators support 
such actions.\2004\ ELCON argues that selection should occur in 
``nearer-term planning (i.e., 10-15 years)'' when there is greater 
certainty that there is a specific transmission need.\2005\
---------------------------------------------------------------------------

    \2003\ Alabama Commission Initial Comments at 3; ELCON Initial 
Comments at 10; Kansas Commission Initial Comments at 14; NRECA 
Initial Comments at 23-24; NRG Initial Comments at 6, 14; Ohio 
Consumers Initial Comments at 20; see also NARUC Initial Comments at 
5 (``Long-Term Regional Transmission Planning [should] be used as a 
planning tool and not a construction requirement.''); TANC Initial 
Comments at 10 (commenting that TANC ``requests that the Commission 
clarify[ ] that the Commission is not proposing to require use of a 
20-year planning horizon for . . . selecting Long-Term Regional 
Transmission Facilities'').
    \2004\ Alabama Commission Initial Comments at 3. Relatedly, 
Avangrid argues that the Commission should more clearly articulate 
how selection affects the actual construction of the transmission 
facility. Avangrid Initial Comments at 17.
    \2005\ ELCON Initial Comments at 10-11.
---------------------------------------------------------------------------

    908. Some commenters argue that it is unnecessary for the 
Commission to require that transmission providers include additional 
selection criteria in their OATTs. For example, Dominion contends that 
Order No. 1000 already requires transmission providers to include 
selection criteria in their OATTs, and that the final order should 
allow, but not require, them to add to those existing selection 
criteria.\2006\ Idaho Commission also believes that Order No. 1000's 
requirements are adequate and argues that the Commission has not 
demonstrated that there is a need to modify them.\2007\ Similarly, 
Idaho Power argues that selection criteria specific to Long-Term 
Regional Transmission Planning are unnecessary in light of existing 
processes to identify and evaluate transmission facilities in the 
NorthernGrid transmission planning region.\2008\ NYISO requests that 
the Commission confirm that the final order will not require changes to 
or the replacement of existing selection criteria.\2009\ Chemistry 
Council argues that the Commission should affirm that transmission 
providers must continue addressing nearer-term regional transmission 
needs, giving significant weight to transmission facilities that meet 
customer and end-user needs, ensure grid reliability and energy 
security, and prevent abandonment of needed resources.\2010\
---------------------------------------------------------------------------

    \2006\ Dominion Initial Comments at 37 (citing NOPR, 179 FERC ] 
61,028 at P 236).
    \2007\ Idaho Commission Initial Comments at 4-5.
    \2008\ Idaho Power Initial Comments at 8.
    \2009\ NYISO Initial Comments at 43.
    \2010\ Chemistry Council Initial Comments at 6-7.
---------------------------------------------------------------------------

    909. Clean Energy Buyers state that they support the NOPR proposal 
to grant eligibility to use the applicable cost allocation method to 
the developer of a Long-Term Regional Transmission Facility selected, 
subject to applicable development schedules. Clean Energy Buyers argue 
that this proposal could provide a more stable source of revenue and 
help resolve the ``first-mover problem,'' which in turn could support 
additional transmission development.\2011\
---------------------------------------------------------------------------

    \2011\ Clean Energy Buyers Initial Comments at 21-22 (citing 
NOPR, 179 FERC ] 61,028 at P 247).
---------------------------------------------------------------------------

    910. Finally, SPP contends that allowing transmission providers to 
include selection criteria in business practice manuals rather than 
their OATTs would give them more flexibility if they need to adjust 
study approaches.\2012\
---------------------------------------------------------------------------

    \2012\ SPP Initial Comments at 21-22.
---------------------------------------------------------------------------

c. Commission Determination
    911. We adopt the NOPR proposal to require transmission providers 
in each transmission planning region to include in their OATTs an 
evaluation process, including selection criteria, that they will use to 
identify and evaluate Long-Term Regional Transmission Facilities for 
potential selection to address Long-Term Transmission Needs. We set 
forth requirements with respect to the evaluation process and selection 
criteria in the following sections.
    912. We also adopt the NOPR proposal that, consistent with Order 
No. 1000, the transmission developer of a Long-Term Regional 
Transmission Facility that is selected, whether incumbent or 
nonincumbent, will be eligible to use the applicable cost allocation 
method for the Long-Term Regional Transmission Facility.
    913. As explained above, transmission providers currently are not 
identifying or evaluating Long-Term Regional Transmission Facilities 
that might more efficiently or cost-effectively address Long-Term 
Transmission Needs and, therefore, do not have the opportunity to 
select such transmission facilities. We find that remedying these 
deficiencies in the Commission's existing regional transmission 
planning requirements requires the inclusion in transmission providers' 
OATTs of an evaluation process and selection criteria for Long-Term 
Regional Transmission Facilities, as outlined below, which, together 
with other aspects of this final order, will help to ensure that 
transmission providers' Commission-jurisdictional rates are just and 
reasonable and not unduly discriminatory or preferential.
    914. We find that the inclusion in transmission providers' OATTs of 
an evaluation process and selection criteria for Long-Term Regional 
Transmission Facilities is essential to the reforms that we adopt in 
this final order. Without these essential components, Long-Term 
Regional Transmission Planning would merely inform the existing 
regional transmission planning processes rather than solving the 
deficiencies in the Commission's existing regional transmission 
planning requirements that we identify in this final order. The 
complete set of reforms that we adopt here are fundamental to resolving 
these deficiencies and to ensuring that transmission providers have the 
opportunity to select more efficient or cost-effective Long-Term 
Regional Transmission Facilities to meet Long-Term Transmission Needs. 
Therefore, we disagree with commenters who suggest that an evaluation 
process or selection criteria are unnecessary or

[[Page 49426]]

inappropriate for the Long-Term Regional Transmission Planning \2013\ 
reforms that we adopt in this final order.
---------------------------------------------------------------------------

    \2013\ See, e.g., Alabama Commission Initial Comments at 3; 
Dominion Initial Comments at 37; ELCON Initial Comments at 10-11; 
Idaho Commission Initial Comments at 4-5; Idaho Power Initial 
Comments at 8; Kansas Commission Initial Comments at 14; NRECA 
Initial Comments at 23-24; NRG Initial Comments at 6, 14; TANC 
Initial Comments at 10; see also Ohio Consumers Initial Comments at 
20 (arguing that a 20-year transmission planning horizon is 
inappropriate for constructing or allocating the costs of 
transmission facilities).
---------------------------------------------------------------------------

    915. We understand that transmission providers might propose to re-
purpose existing evaluation processes or selection criteria (with or 
without modifications thereto) to use in Long-Term Regional 
Transmission Planning. In their compliance filings, transmission 
providers must propose the evaluation process and selection criteria 
that they will use in Long-Term Regional Transmission Planning, and 
they must demonstrate that they meet the final order requirements. In 
response to NYISO's request,\2014\ however, we clarify that nothing in 
this final order requires transmission providers to modify or replace 
selection criteria used in their existing reliability and economic 
Order No. 1000 regional transmission planning processes.
---------------------------------------------------------------------------

    \2014\ NYISO Initial Comments at 43. We reiterate that, as 
discussed above in the Participation in Long-Term Regional 
Transmission Planning section, transmission providers may propose to 
continue using some or all aspects of the existing regional 
transmission planning and cost allocation processes that they use to 
consider transmission needs driven by Public Policy Requirements, 
provided that transmission providers demonstrate that continued use 
of any such processes does not interfere with or otherwise undermine 
Long-Term Regional Transmission Planning as set forth in this final 
order.
---------------------------------------------------------------------------

    916. As discussed below, to meet the requirements of this final 
order, transmission providers in each transmission planning region must 
establish a Long-Term Regional Transmission Planning evaluation process 
that: (1) identifies Long-Term Regional Transmission Facilities that 
address Long-Term Transmission Needs; (2) measures the benefits of the 
identified Long-Term Regional Transmission Facilities consistent with 
the final order requirements; and (3) designates a point in the 
evaluation process at which transmission providers will determine 
whether to select or not select identified Long-Term Regional 
Transmission Facilities in the regional transmission plan for purposes 
of cost allocation.\2015\ We recognize the inherent uncertainty 
involved in identifying Long-Term Transmission Needs over the minimum 
transmission planning horizon adopted in this final order and in 
measuring the benefits that could be provided by Long-Term Regional 
Transmission Facilities. However, we continue to believe that there are 
selection criteria that transmission providers could adopt, following 
consultation with stakeholders and with Relevant State Entities in 
their transmission planning region's footprint, that minimize these 
risks while allowing for selection of Long-Term Regional Transmission 
Facilities that more efficiently or cost-effectively meet Long-Term 
Transmission Needs. We emphasize that we do not require transmission 
providers to select any particular Long-Term Regional Transmission 
Facilities but rather to adopt an evaluation process and selection 
criteria that meet the final order requirements. This evaluation 
process will ensure that Long-Term Regional Transmission Planning will 
provide transmission providers with a framework that allows for the 
selection of Long-Term Regional Transmission Facilities that more 
efficiently or cost-effectively address Long-Term Transmission 
Needs.\2016\
---------------------------------------------------------------------------

    \2015\ See, e.g., NOPR, 179 FERC ] 61,028 at P 56 (setting forth 
requirements for Long-Term Regional Transmission Planning).
    \2016\ For these reasons, in addition to those discussed above, 
we disagree with ELCON that transmission providers should only 
select transmission facilities in ``near-term planning (i.e., 10-15 
years).'' ELCON Initial Comments at 10-11.
---------------------------------------------------------------------------

    917. We reiterate that, consistent with Order No. 1000,\2017\ 
selection in the regional transmission plan does not entitle the 
transmission developer of a selected Long-Term Regional Transmission 
Facility to site or construct that transmission facility, nor does it 
obviate the need for the transmission developer to obtain other state, 
local, and/or Federal permits or authorizations. For this reason, we 
disagree with comments suggesting that the Commission proposed to do 
otherwise in the NOPR.\2018\
---------------------------------------------------------------------------

    \2017\ E.g., Order No. 1000-A, 139 FERC ] 61,132 at P 191.
    \2018\ See, e.g., Alabama Commission Initial Comments at 3; 
Dominion Reply Comments at 8 (citing PIOs Initial Comments at 28; 
NARUC Initial Comments at 5-6, 39); NARUC Initial Comments at 5, 39.
---------------------------------------------------------------------------

    918. Finally, we find that, consistent with the Commission's rule 
of reason,\2019\ transmission providers' evaluation processes and 
selection criteria significantly affect rates, are reasonably 
susceptible to specification, and are not otherwise so generally 
understood as to render their recitation superfluous and therefore must 
be included in their OATTs. As such, we reject SPP's request that we 
allow transmission providers to instead maintain evaluation processes 
and selection criteria in their business practice manuals.\2020\
---------------------------------------------------------------------------

    \2019\ See Cal. Indep. Sys. Operator Corp., 185 FERC ] 61,210, 
at P 183 (2023) (citing Hecate Energy Greene Cnty. 3 LLC v. FERC, 72 
F.4th 1307, 1314 (D.C. Cir. 2023); City of Cleveland v. FERC, 773 
F.2d 1368, 1376 (D.C. Cir. 1985)).
    \2020\ SPP Initial Comments at 21-22.
---------------------------------------------------------------------------

2. Flexibility
a. NOPR Proposal
    919. Subject to certain minimum requirements, the Commission 
proposed in the NOPR to provide transmission providers with the 
flexibility to propose the selection criteria that they, in 
consultation with their stakeholders, believe will ensure that more 
efficient or cost-effective regional transmission facilities to address 
the region's transmission needs driven by changes in the resource mix 
and demand ultimately are selected.\2021\ The Commission stated that 
this proposed flexibility would help accommodate regional differences, 
such as differences in transmission needs, factors driving those needs, 
and market structures.\2022\ The Commission stated that providing 
flexibility to propose evaluation processes and selection criteria 
would allow transmission providers, in consultation with their 
stakeholders, to determine criteria for assessing the efficiency or 
cost-effectiveness of various regional transmission facilities, whether 
by reference, for example, to a benefit-cost ratio or by aggregate net 
benefits.\2023\ The Commission stated that it further believed this 
proposed flexibility would allow transmission providers in each 
transmission planning region to develop selection criteria that could 
sufficiently balance individual state interests within each 
transmission planning region.\2024\
---------------------------------------------------------------------------

    \2021\ NOPR, 179 FERC ] 61,028 at P 242.
    \2022\ Id. P 243.
    \2023\ Id. P 243.
    \2024\ Id. P 244.
---------------------------------------------------------------------------

b. Comments
    920. Many commenters support the Commission's proposal to provide 
transmission providers with the flexibility to propose an evaluation 
process and selection criteria that they, in consultation with their 
stakeholders, believe will ensure that more efficient or cost-effective 
Long-Term Regional Transmission Facilities to address the transmission 
planning region's transmission needs driven by changes in the resource 
mix and demand ultimately are selected.\2025\
---------------------------------------------------------------------------

    \2025\ APPA Initial Comments at 33-34; Avangrid Initial Comments 
at 17; California Commission Initial Comments at 37; Chemistry 
Council Initial Comments at 6; Duke Initial Comments at 26; 
Eversource Initial Comments at 26; GridLab Initial Comments at 19; 
ISO-NE Initial Comments at 35; MISO Initial Comments at 54; Nebraska 
Commission Initial Comments at 8; TAPS Initial Comments at 16; US 
Chamber of Commerce Initial Comments at 8.

---------------------------------------------------------------------------

[[Page 49427]]

    921. For example, Nebraska Commission asserts that this flexibility 
will allow transmission providers to develop selection criteria that 
balance individual states' interests.\2026\ Eversource argues that 
flexibility will foster investments in cost-effective regional 
transmission facilities, accommodate differences in transmission needs 
between transmission planning regions, and encourage stakeholder 
engagement.\2027\ While NEPOOL supports flexibility as a general 
matter, it asserts that the Commission should articulate guiding 
principles for how selection decisions will be made and by whom, and 
guidelines regarding when transmission solutions should be selected to 
address long-term transmission needs.\2028\
---------------------------------------------------------------------------

    \2026\ Nebraska Commission Initial Comments at 8 (citing NOPR, 
179 FERC ] 61,028 at P 244).
    \2027\ Eversource Initial Comments at 26 (citing NOPR, 179 FERC 
] 61,028 at PP 242-243).
    \2028\ NEPOOL Initial Comments at 7-8.
---------------------------------------------------------------------------

    922. By contrast, some commenters argue that the Commission should 
establish pro forma selection criteria.\2029\ Clean Energy Associations 
argues that doing so would enhance transparency, minimize differences 
across seams, and enable state regulators, consumers, and other market 
participants to evaluate transmission projects that result from Long-
Term Regional Transmission Planning on an apples-to-apples basis.\2030\ 
Similarly, SEIA urges the Commission to establish a set of minimum 
requirements for selecting transmission facilities in Long-Term 
Regional Transmission Planning, arguing that transmission planning 
regions otherwise may fail to select transmission facilities that 
provide significant regional benefits.\2031\ For its part, Clean Energy 
Buyers contends that adopting pro forma selection criteria would 
provide greater transparency and consistency across transmission 
planning regions, hopefully help to avoid disputes, and allow for 
consultation with states and other stakeholders.\2032\
---------------------------------------------------------------------------

    \2029\ See, e.g., ACORE Reply Comments at 5-6 (citing Policy 
Integrity Initial Comments at 2-3); Policy Integrity Initial 
Comments at 2-3.
    \2030\ Clean Energy Associations Initial Comments at 22-23.
    \2031\ SEIA Initial Comments at 5, 19.
    \2032\ Clean Energy Buyers Initial Comments at 22-23.
---------------------------------------------------------------------------

    923. Acadia Center and CLF argue that requiring a minimum set of 
selection criteria will provide critical information to transmission 
providers who rely on the Commission to make clear what considerations 
they may weigh in Long-Term Regional Transmission Planning, 
facilitating more productive conversations at the regional level.\2033\
---------------------------------------------------------------------------

    \2033\ Acadia Center and CLF Initial Comments at 10-11.
---------------------------------------------------------------------------

c. Commission Determination
    924. Subject to the requirements described further below, we adopt 
the NOPR proposal to require transmission providers in each 
transmission planning region to propose, after consultation with 
Relevant State Entities and other stakeholders, evaluation processes, 
including selection criteria, that they believe will ensure that more 
efficient or cost-effective Long-Term Regional Transmission Facilities 
are selected to address the transmission planning region's Long-Term 
Transmission Needs. We believe that providing transmission providers 
with this flexibility will allow them to design evaluation processes 
and selection criteria that can accommodate regional differences.
    925. We reject requests that, instead of providing transmission 
providers with flexibility, we set forth standard evaluation processes 
and selection criteria in this final order that transmission providers 
would be required to adopt.\2034\ While we recognize that there may be 
some benefits to doing so, we also find that transmission planning 
regions have different transmission needs and market structures that 
make designing a standard evaluation process and selection criteria 
difficult.
---------------------------------------------------------------------------

    \2034\ Acadia Center and CLF Initial Comments at 10-11; Clean 
Energy Associations Initial Comments at 22-23; SEIA Initial Comments 
at 5, 19.
---------------------------------------------------------------------------

    926. In response to NEPOOL,\2035\ we clarify that transmission 
providers make the selection decisions in Long-Term Regional 
Transmission Planning. Although we do not require transmission 
providers to select any particular Long-Term Regional Transmission 
Facility to address Long-Term Transmission Needs, as discussed below in 
the No Selection Requirement section, we do set forth minimum 
requirements with respect to the evaluation process and selection 
criteria, which will help to ensure that transmission providers select 
Long-Term Regional Transmission Facilities to more efficiently or cost-
effectively address Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \2035\ NEPOOL Initial Comments at 8.
---------------------------------------------------------------------------

3. Minimum Requirements
a. NOPR Proposal
    927. In the NOPR, the Commission proposed certain minimum 
requirements such that transmission providers' selection criteria must 
(1) be transparent and not unduly discriminatory; (2) aim to ensure 
that more efficient or cost-effective transmission facilities are 
selected in the regional transmission plan for purposes of cost 
allocation; and (3) seek to maximize benefits to consumers over time 
without over-building transmission facilities.\2036\ The Commission 
noted that, to comply with the Order Nos. 890 and 1000 transmission 
planning principles, the evaluation process must result in a 
determination that is sufficiently detailed for stakeholders to 
understand why a particular transmission facility was selected or not 
selected in the regional transmission plan for purposes of cost 
allocation to address transmission needs driven by changes in the 
resource mix and demand.\2037\ The Commission stated that the 
evaluation process and, specifically, the selection criteria, must seek 
to maximize benefits to consumers over time without over-building 
transmission facilities.\2038\
---------------------------------------------------------------------------

    \2036\ NOPR, 179 FERC ] 61,028 at PP 241-242, 245.
    \2037\ Id. P 242 (citing Order No. 1000, 136 FERC ] 61,051 at P 
328).
    \2038\ Id.
---------------------------------------------------------------------------

    928. The Commission stated that providing flexibility to propose 
selection criteria would allow transmission providers, in consultation 
with their stakeholders, to determine criteria for assessing the 
efficiency or cost-effectiveness of various regional transmission 
facilities, whether by reference, for example, to a benefit-cost ratio 
or by aggregate net benefits.\2039\ The Commission also stated that 
transmission providers would have the flexibility to propose to use a 
portfolio approach in selecting regional transmission facilities that 
address transmission needs driven by changes in the resource mix and 
demand.\2040\ The Commission proposed to require transmission providers 
that propose such an approach to include in their OATTs provisions 
describing whether the selection criteria would apply to one proposed 
regional transmission facility or to a portfolio of regional 
transmission facilities, as well as whether the portfolio approach 
would be used for Long-Term Regional Transmission Planning universally 
to address transmission needs driven by changes in

[[Page 49428]]

the resource mix and demand or would be used only in certain specified 
instances.\2041\
---------------------------------------------------------------------------

    \2039\ Id. P 243.
    \2040\ Id. P 249.
    \2041\ Id.
---------------------------------------------------------------------------

    929. The Commission recognized the inherent uncertainty involved in 
predicting future transmission needs, including those driven by changes 
in the resource mix and demand, as well as the concerns that many 
commenters expressed in response to the ANOPR that imperfect 
information may lead to selecting transmission facilities that become 
stranded assets.\2042\ The Commission also stated that there are 
selection criteria that transmission providers could adopt, following 
consultation with stakeholders and with Relevant State Entities in 
their transmission planning region's footprint, that could minimize 
these risks while allowing for investment in transmission facilities 
that more efficiently or cost-effectively meet transmission needs 
driven by changes in the resource mix and demand.\2043\ The Commission 
noted that under a ``least-regrets'' approach, for example, 
transmission providers in a transmission planning region would select a 
transmission facility (or portfolio of transmission facilities) that is 
net-beneficial in most or all Long-Term Scenarios, even if other 
transmission facilities have more net benefits or a higher benefit-cost 
ratio in a single Long-Term Scenario. The Commission stated that 
another approach is a ``weighted-benefits approach,'' in accordance 
with which transmission providers in a transmission planning region 
would select a transmission facility (or portfolio of regional 
transmission facilities) based on its probability-weighted average 
benefits, where probabilities have been assigned to each Long-Term 
Scenario studied.\2044\
---------------------------------------------------------------------------

    \2042\ Id. P 251.
    \2043\ Id.
    \2044\ Id. (citing Brattle-Grid Strategies Oct. 2021 Report at 
59-60).
---------------------------------------------------------------------------

b. Comments
    930. Commenters make a wide variety of arguments with respect to 
the minimum requirements that the Commission should impose with respect 
to evaluation processes and selection criteria. Many commenters support 
the Commission's proposal to require that selection criteria: (1) be 
transparent and not unduly discriminatory; (2) aim to ensure that more 
efficient or cost-effective transmission facilities are selected in the 
regional transmission plan for purposes of cost allocation to address 
transmission needs driven by changes in the resource mix and demand; 
and (3) seek to maximize benefits to consumers over time without over-
building transmission facilities.\2045\
---------------------------------------------------------------------------

    \2045\ See ACEG Initial Comments at 58-59; ACORE Initial 
Comments at 14; Amazon Initial Comments at 9; APPA Initial Comments 
at 33-34; CARE Coalition Initial Comments at 11-12; NESCOE Initial 
Comments at 46; NRECA Initial Comments at 25; [Oslash]rsted Initial 
Comments at 5-6; Pacific Northwest State Agencies Initial Comments 
at 19; PPL Initial Comments at 17-18; TAPS Initial Comments at 16.
---------------------------------------------------------------------------

    931. Some commenters generally support the Commission's proposal 
with certain modifications. For example, Ameren argues that requiring 
selection criteria to maximize benefits to consumers over time without 
over-building transmission facilities is highly subjective, because 
such a requirement could refer to maximizing gross or net benefits and 
because certain interpretations could override the consideration of 
costs.\2046\ Vistra likewise argues that the directive to maximize 
benefits to consumers over time without over-building transmission 
facilities is unhelpfully vague and that maximizing benefits should not 
be understood to disregard costs.\2047\ WATT Coalition states that the 
Commission should require maximization of net benefits and cautions 
that it would be unjust and unreasonable to ignore benefits or costs in 
the assessment of options.\2048\
---------------------------------------------------------------------------

    \2046\ Ameren Initial Comments at 20 (citing NOPR, 179 FERC ] 
61,028 at P 243 n.390).
    \2047\ Vistra Initial Comments at 17-18.
    \2048\ WATT Coalition Initial Comments at 9.
---------------------------------------------------------------------------

    932. GridLab argues that selection criteria should seek to manage 
uncertainty and risk, stating that the Commission should clarify that 
the criteria must address not only the risk of over-building but also 
of under-building transmission.\2049\ In contrast, New York State 
Department argues that selection criteria should be designed to 
minimize the financial risk to ratepayers of over-building the 
transmission system.\2050\ NYISO requests clarification on the 
definition of over-building and argues that the final order should 
provide additional guidance on how transmission planning regions should 
address this risk. NYISO contends that the final order should treat the 
risk of over-building as an additional qualitative criterion that 
transmission planning regions should consider, as informed by open and 
transparent stakeholder review.\2051\
---------------------------------------------------------------------------

    \2049\ GridLab Initial Comments at 19.
    \2050\ New York State Department Initial Comments at 4.
    \2051\ NYISO Initial Comments at 43.
---------------------------------------------------------------------------

    933. EEI contends that it is appropriate for the Commission to 
provide guidance by providing non-mandatory factors for transmission 
planning regions to consider.\2052\ ELCON argues that transparency with 
respect to selection criteria requires that the criteria and their 
proper weighting must be clear and easily accessible to consumers 
through transmission providers' OASIS and OATT.\2053\
---------------------------------------------------------------------------

    \2052\ EEI Initial Comments at 45-46.
    \2053\ ELCON Initial Comments at 17.
---------------------------------------------------------------------------

    934. Commenters make several arguments with respect to the metrics 
that the Commission should allow or require transmission providers to 
use when evaluating whether to select Long-Term Regional Transmission 
Facilities. For example, some commenters argue that transmission 
providers should select transmission facilities by using metrics that 
seek to maximize net benefits instead of ones that rely on benefit-cost 
ratios.\2054\ ACEG argues that the Commission can require metrics that 
seek to maximize net benefits using the same authority it relied upon 
in promulgating Order No. 1000.\2055\
---------------------------------------------------------------------------

    \2054\ ACEG Initial Comments at 49-50; Breakthrough Energy 
Initial Comments at 23; Clean Energy Associations Initial Comments 
at 22; DC and MD Offices of People's Counsel Initial Comments at 33; 
Evergreen Action Initial Comments at 4; ITC Initial Comments at 25; 
WATT Coalition Initial Comments at 9.
    \2055\ See ACEG Initial Comments at 49-50 (citing S.C. Pub. 
Serv. Auth. v. FERC, 762 F.3d at 58).
---------------------------------------------------------------------------

    935. Breakthrough Energy states that, while metrics such as 
benefit-cost ratios are useful indicators, the efficient solution is 
the one that maximizes net benefits.\2056\ WATT Coalition contends 
that, in Australia, the transmission planner lists all transmission 
facility alternatives ranked by the net present value of the consumer 
benefits that the alternatives would provide, and selects the option 
that provides the most benefits in the absence of a compelling reason 
not to do so.\2057\
---------------------------------------------------------------------------

    \2056\ Breakthrough Energy Initial Comments at 23.
    \2057\ WATT Coalition Initial Comments at 9.
---------------------------------------------------------------------------

    936. MISO argues that selection criteria should maximize long-term 
transmission value, defined as the difference between total benefits 
and total costs on a present value basis over a pre-determined 
transmission planning horizon.\2058\ MISO contends that using such a 
metric is important when benefit-cost ratios are high and transmission 
expansion is substantial, as many of the benefits provided by new 
transmission facilities are difficult to quantify in terms of dollars 
despite providing significant qualitative benefits.\2059\ Relatedly, 
CTC Global argues that selecting transmission facilities with the 
lowest capital costs is no longer a best

[[Page 49429]]

practice, in light of increased debate in many RTOs/ISOs about issues 
such as mandated resource mixes, compensation in capacity markets, 
transmission planning criteria and cost allocation, and carbon 
taxes.\2060\ CTC Global asserts that, if a transmission project is 
selected with least capital cost as a selection criterion, consumers 
will pay higher energy costs and higher total costs than what they 
would pay if the Commission were to require transmission providers to 
evaluate the NOPR's proposed benefits as well as cost.\2061\
---------------------------------------------------------------------------

    \2058\ MISO Initial Comments at 55-56.
    \2059\ Id.
    \2060\ CTC Global Initial Comments at 6-7 (citing State 
Voluntary Agreements to Plan and Pay for Transmission Facilities, 
175 FERC ] 61,225 (2021) (Christie, Comm'r, concurring at PP 4-5)).
    \2061\ Id. at 9.
---------------------------------------------------------------------------

    937. Commenters also offer a variety of perspectives regarding 
benefit-cost ratios. Clean Energy Associations recommend that, if the 
Commission continues to allow benefit-cost ratios, such ratios not 
exceed Order No. 1000's maximum allowable benefit-cost ratio of 1.25-
to-1.00.\2062\ ITC argues that, if the Commission allows transmission 
providers to use benefit-cost ratios, it should require the use of a 
1.00-to-1.00 benefit-cost ratio for the evaluation of candidate 
portfolios.\2063\ Cypress Creek asserts that the Commission should 
retain the maximum permitted benefit-cost ratio of 1.25-to-1.00 and 
consider lowering that threshold to 1.00-to-1.00 because a transmission 
facility with a benefit-cost ratio of at least 1.00-to-1.00 is 
beneficial.\2064\
---------------------------------------------------------------------------

    \2062\ Clean Energy Associations Initial Comments at 22.
    \2063\ ITC Initial Comments at 25-26.
    \2064\ See Cypress Creek Reply Comments at 8 & n.14 (citing 
Order No. 1000, 136 FERC ] 61,051 at P 646).
---------------------------------------------------------------------------

    938. Pattern Energy argues that the existing maximum 1.25-to-1.00 
allowable benefit-cost ratio is too high for purposes of Long-Term 
Regional Transmission Planning. Pattern Energy explains that scenarios 
and sensitivities typically are created to bookend what the future may 
look like, and those bookends are often weighted lower than a 
``business as usual'' scenario. In this context, Pattern Energy argues 
that a lower benefit-to-cost ratio is necessary because the standard to 
approve transmission facilities is so high that transmission ratepayers 
are not receiving an appropriate opportunity to realize the value of 
new transmission infrastructure. Pattern Energy suggests that a more 
reasonable benefit-cost ratio would be 1.10-to-1.00 but notes that a 
higher benefit-to-cost ratio may be appropriate to evaluate a portfolio 
of transmission facilities (e.g., 1.15-1.25).\2065\
---------------------------------------------------------------------------

    \2065\ Pattern Energy Initial Comments at 14-15.
---------------------------------------------------------------------------

    939. By contrast, New York State Department asserts that 
transmission providers should not select a transmission facility unless 
benefits in the long term greatly exceed costs and that adopting a much 
higher benefit-cost ratio than the existing 1.25 standard may be 
required (e.g., 2.25-to-1.00).\2066\
---------------------------------------------------------------------------

    \2066\ New York State Department Initial Comments, Montalvo Aff. 
at 14-15.
---------------------------------------------------------------------------

    940. Some commenters express support for least-regrets \2067\ or 
weighted-benefits approaches \2068\ to selecting transmission 
facilities in Long-Term Regional Transmission Planning. For example, 
National Grid argues that identifying least-regrets transmission 
facilities should be the goal of Long-Term Regional Transmission 
Planning.\2069\
---------------------------------------------------------------------------

    \2067\ See Avangrid Initial Comments at 10-11; Eversource 
Initial Comments at 26-27; Exelon Initial Comments at 18; GridLab 
Initial Comments at 19-20; National Grid Initial Comments at 11-12; 
NRECA Initial Comments at 48; PG&E Initial Comments at 6.
    \2068\ See ACORE Initial Comments at 14 (citing Brattle-Grid 
Strategies Oct. 2021 Report at 59-60; Derek Stenclik and Ryan Deyoe, 
Multi-Value Transmission Planning for a Clean Energy Future: A 
Report of the Transmission Benefits Valuation Task Force, Energy 
Systems Integration Group, 37 (June 2022), https://www.esig.energy/wp-content/uploads/2022/07/ESIG-Multi-Value-Transmission-Planning-report-2022a.pdf) (Energy Systems Integration Group June 2022 
Report)); Clean Energy Associations Initial Comments at 22 (citing 
NOPR, 179 FERC ] 61,028 at P 251).
    \2069\ National Grid Initial Comments at 11-12 (citing National 
Grid ANOPR Initial Comments at 16).
---------------------------------------------------------------------------

    941. Avangrid explains that ``no regrets'' or ``low regrets'' 
transmission facilities are those that likely will be needed under 
multiple scenarios and a broad range of assumptions.\2070\ PG&E agrees 
and argues that these transmission facilities are most likely to 
realize projected benefits.\2071\ PG&E states that transmission 
facilities that provide more limited benefits or benefits under a 
limited number of scenarios may require additional study and should not 
be selected until there is more certainty that their benefits will be 
realized.\2072\
---------------------------------------------------------------------------

    \2070\ Avangrid Initial Comments at 10-11.
    \2071\ PG&E Initial Comments at 6.
    \2072\ Id.
---------------------------------------------------------------------------

    942. Exelon also advocates for a least-regrets approach, arguing 
that it minimizes risk and maximizes value for customers and 
transmission owners.\2073\ Eversource contends that a least-regrets 
approach is most likely to build the consensus among stakeholders that 
can support transmission facilities through planning, financing, 
siting, and cost allocation.\2074\ NRECA argues that a least-regrets 
approach will help mitigate the risk that consumers will pay for 
unnecessary transmission facilities.\2075\
---------------------------------------------------------------------------

    \2073\ Exelon Initial Comments at 18.
    \2074\ Eversource Initial Comments at 26-27.
    \2075\ NRECA Initial Comments at 48.
---------------------------------------------------------------------------

    943. ACORE recommends the use of a weighted-benefits approach, 
which ACORE argues has been endorsed in recent expert reports on 
transmission planning.\2076\ Dominion sees promise in both least-
regrets and weighted-benefits approaches but argues that requiring 
transmission providers to propose specific selection criteria may 
result in litigation, delay, and increased costs.\2077\
---------------------------------------------------------------------------

    \2076\ ACORE Initial Comments at 14 (citing Brattle-Grid 
Strategies Oct. 2021 Report at 59-60; Energy Systems Integration 
Group June 2022 Report at 37).
    \2077\ See Dominion Initial Comments at 38.
---------------------------------------------------------------------------

    944. New England for Offshore Wind argues that the Commission 
should require transmission providers to give preference to 
transmission facilities that perform well under a range of 
scenarios.\2078\ A number of commenters caution, however, that the 
Commission should allow transmission providers to select transmission 
facilities even where they are not net-beneficial in every Long-Term 
Scenario.\2079\
---------------------------------------------------------------------------

    \2078\ New England for Offshore Wind Initial Comments at 2; see 
also Clean Energy Associations Initial Comments at 22 (arguing for 
selecting transmission facilities that maximize net benefits across 
multiple scenarios).
    \2079\ ACEG Initial Comments at 7, 30; ACORE Initial Comments at 
14; Evergreen Action Initial Comments at 4; Pine Gate Initial 
Comments at 37-38.
---------------------------------------------------------------------------

    945. A number of commenters recommend accounting for siting 
considerations in various ways in the selection of transmission 
facilities. For example, CARE Coalition recommends that the Commission 
require transmission providers to work with state authorities and other 
stakeholders to develop environmental- and energy justice-based siting 
criteria to guide transmission project selection and cost 
allocation.\2080\ CARE Coalition also states that the Commission should 
allow RTOs/ISOs to take a flexible approach to identifying siting-based 
criteria that consider local and regional impacts, local and regional 
energy justice impacts (including use of existing transmission 
corridors and investment flow to disadvantaged communities as defined 
by the President's Justice40 Initiative), integration with plans for 
energy storage, and integration with major infrastructure development 
plans (e.g., highways, rail corridors).\2081\ CARE Coalition states 
that planners and stakeholders should consider the

[[Page 49430]]

economic, environmental, and other impacts associated with the full 
expected useful lives of proposed transmission and associated 
facilities.\2082\
---------------------------------------------------------------------------

    \2080\ CARE Coalition Initial Comments at 7-8.
    \2081\ Id. at 10.
    \2082\ Id.
---------------------------------------------------------------------------

    946. Similarly, ACEG recommends selection criteria that account for 
whether potential transmission facilities use existing rights-of-way, 
contribute to equitable energy service, alleviate environmental justice 
concerns, or impact employment and economic development.\2083\ Exelon 
also recommends giving preference to approaches that prioritize 
existing rights-of-way, given that they are more readily accomplished 
and have fewer environmental impacts than greenfield transmission 
projects.\2084\
---------------------------------------------------------------------------

    \2083\ ACEG Initial Comments at 59.
    \2084\ Exelon Initial Comments at 18.
---------------------------------------------------------------------------

    947. Acadia Center and CLF urge the Commission to provide 
transmission providers clear guidance, by adopting minimum selection 
criteria in the final order, on their ability to consider factors such 
as environmental justice, mitigating environmental impacts, use of 
existing transmission facilities, and non-transmission alternatives, 
which have community and environmental benefits. Acadia Center and CLF 
contend that the consideration of these issues is consistent with NEPA, 
the FPA, and state law, and that, in the absence of such guidance, 
transmission providers may continue to exclude consideration of these 
issues given concerns regarding their authority and jurisdiction to do 
so.\2085\ Grand Rapids NAACP also argues that the Commission has the 
authority to require that transmission providers explicitly incorporate 
energy equity and justice concerns into selection criteria, and that 
the Commission should do so in a final order.\2086\ WE ACT states that 
equity considerations and other non-energy benefits (e.g., pollution 
reduction, health, jobs, and local economic development) should be 
among the benefits that transmission providers could use in selecting 
transmission facilities.\2087\ PIOs assert that the Commission should 
require transmission providers to consider equity impacts when 
determining which transmission facilities to select, including whether 
construction of such facilities will impact environmental justice 
communities and what the cumulative impacts of the facilities will 
be.\2088\
---------------------------------------------------------------------------

    \2085\ Acadia Center and CLF Initial Comments at 11-12.
    \2086\ Grand Rapids NAACP Initial Comments at 17-23 (citations 
omitted).
    \2087\ WE ACT Initial Comments at 5.
    \2088\ PIOs Reply Comments at 17 (citations omitted).
---------------------------------------------------------------------------

    948. DC and MD Offices of People's Counsel suggest that 
transmission providers should select transmission facilities that 
optimize the interconnection of portfolios of generation resources, 
including those that deliver benefits arising from grid decarbonization 
and the benefits set forth in the NOPR.\2089\ Eversource argues that 
the Commission should consider requiring transmission providers to 
address needs identified in high-impact, low-frequency event scenarios, 
such that selection criteria would accommodate worst-case scenarios 
like Winter Storm Uri.\2090\ Exelon urges that selection criteria be 
tied to well-established and defined needs, like reliability and market 
economics, such as reduced production costs, congestion, or capacity 
costs.\2091\
---------------------------------------------------------------------------

    \2089\ DC and MD Offices of People's Counsel Initial Comments at 
38-39.
    \2090\ Eversource Initial Comments at 26-27 (citing FERC, North 
American Electric Reliability Corporation, Regional Entity Staff 
Report, The February 2021 Cold Weather Outages in Texas, and the 
South-Central United States (Nov. 2021), https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and).
    \2091\ Exelon Initial Comments at 18.
---------------------------------------------------------------------------

    949. Duke asserts that selection of a transmission facility in the 
absence of clear consensus from load-serving entities, states, and/or 
customers would be problematic and thwart the Commission's objectives, 
especially where certain transmission facilities will not be supported 
by state commissions in siting decisions or by consumer advocates in 
cost recovery proceedings.\2092\ As such, Duke argues that the 
Commission should allow transmission providers to include a qualitative 
selection criterion of whether there is state and consumer support for 
a particular Long-Term Regional Transmission Facility or portfolio of 
facilities.\2093\ New York TOs state that New York Commission should 
retain its flexibility under NYISO's public policy transmission 
planning process such that, when the New York Commission identifies a 
transmission need driven by Public Policy Requirements, it can also 
require certain selection criteria in addition to those in NYISO's 
OATT.\2094\
---------------------------------------------------------------------------

    \2092\ Duke Initial Comments at 26-27.
    \2093\ Id. at 4, 26-27.
    \2094\ New York TOs Initial Comments at 9, 11-12, 15.
---------------------------------------------------------------------------

    950. NYISO contends that the final order should continue to allow 
transmission providers to use a range of qualitative and quantitative 
criteria to rank and select transmission projects as the more efficient 
or cost-effective transmission facility.\2095\ ACEG encourages the 
Commission to provide guidance in the final order as to selection 
criteria that meet its requirements, arguing that doing so would 
facilitate efficient compliance proceedings.\2096\
---------------------------------------------------------------------------

    \2095\ NYISO Initial Comments at 39-40.
    \2096\ ACEG Initial Comments at 59.
---------------------------------------------------------------------------

    951. Maine Public Advocate also argues that the Commission should 
require transmission providers to select non-transmission alternatives 
when they meet an identified transmission need at the same or lower 
cost.\2097\
---------------------------------------------------------------------------

    \2097\ Maine Public Advocate Initial Comments at 1-2.
---------------------------------------------------------------------------

    952. TAPS asserts that the Commission should require transmission 
providers to explain how their selection criteria would account for the 
uncertainty involved in predicting future transmission needs and to 
report ``Affordability Metrics'' that disclose the impact that 
selection of a particular transmission facility would have on 
transmission rates.\2098\ TAPS argues that these ``Affordability 
Metrics'' would enhance the transparency of stakeholder processes in 
Long-Term Regional Transmission Planning and assist states in 
discussions about cost allocation and in considering whether to 
voluntarily fund a particular transmission facility or portfolio of 
transmission facilities.\2099\
---------------------------------------------------------------------------

    \2098\ TAPS Initial Comments at 16-17.
    \2099\ Id. at 19-20 (citing Alliant Energy, et al., ANOPR 
Initial Comments at 14; Alliant Energy, et al., ANOPR Reply Comments 
at 2-3).
---------------------------------------------------------------------------

    953. ELCON states that, given the potential for massive 
transmission investment in the next 10 to 25 years, it is vitally 
important that consumers be protected from any unnecessary costs.\2100\ 
As such, ELCON argues that selection criteria must incorporate metrics 
for reliability and economic efficiency, incorporate all potential 
drivers of transmission needs, and afford greater weight to those 
transmission facilities that produce benefits in more than one 
category.\2101\
---------------------------------------------------------------------------

    \2100\ ELCON Initial Comments at 16 (citing Eric Larson et al., 
Net-Zero America: Potential Pathways, Infrastructure, and Impacts, 
Net Zero America, 108 (Oct. 29, 2021), https://www.dropbox.com/s/ptp92f65lgds5n2/Princeton%20NZA%20FINAL%20REPORT%20%2829Oct2021%29.pdf?dl=0).
    \2101\ Id.

---------------------------------------------------------------------------

[[Page 49431]]

c. Commission Determination
i. Transparent and Not Unduly Discriminatory; More Efficient or Cost-
Effective Transmission Facilities
    954. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to propose 
evaluation processes, including selection criteria, that are 
transparent and not unduly discriminatory. Consistent with Order No. 
1000,\2102\ we adopt the NOPR proposal to establish a requirement that 
transmission providers' evaluation of transmission facilities must 
culminate in a determination that is sufficiently detailed for 
stakeholders to understand why a particular Long-Term Regional 
Transmission Facility (or portfolio of such Facilities) was selected or 
not selected. As discussed further below, we modify the NOPR proposal 
to include a requirement that the determination of why a particular 
Long-Term Regional Transmission Facility (or portfolio of such 
Facilities) was selected or not selected must include the measured 
benefits for each alternative Long-Term Regional Transmission Facility 
(or portfolio of such Facilities) considered in the Long-Term Regional 
Transmission Planning process.
---------------------------------------------------------------------------

    \2102\ Order No. 1000, 136 FERC ] 61,051 at P 328.
---------------------------------------------------------------------------

    955. We also adopt the NOPR proposal, with modification, to require 
transmission providers to propose on compliance evaluation processes, 
including selection criteria, that aim to ensure that more efficient or 
cost-effective Long-Term Regional Transmission Facilities are selected 
to address Long-Term Transmission Needs. We modify the NOPR proposal to 
provide additional clarity as to how transmission providers' evaluation 
processes must aim to ensure the selection of more efficient or cost-
effective Long-Term Regional Transmission Facilities to address Long-
Term Transmission Needs by adopting several requirements. First, 
transmission providers in a transmission planning region must identify 
one or more Long-Term Regional Transmission Facilities (or portfolio of 
such Facilities) that address the Long-Term Transmission Needs that the 
transmission providers have identified through Long-Term Regional 
Transmission Planning. As part of this identification, consistent with 
Order Nos. 890 and 1000,\2103\ nonincumbent transmission developers 
must be able to propose transmission facilities in Long-Term Regional 
Transmission Planning. Thus, we clarify that transmission providers in 
each transmission planning region must make clear in their OATTs the 
point in the Long-Term Regional Transmission Planning evaluation 
process at which they will accept Long-Term Regional Transmission 
Facility proposals from stakeholders, including nonincumbent 
transmission developers. Second, transmission providers' evaluation 
processes must estimate the costs and measure the benefits of the Long-
Term Regional Transmission Facilities (or portfolio of such Facilities) 
that are identified or proposed for potential selection, in addition to 
evaluating the identified Long-Term Regional Transmission Facilities 
(or portfolio of such Facilities) using any qualitative or other 
quantitative selection criteria that the transmission providers in a 
transmission planning region propose to apply. Third, transmission 
providers must designate a point in the evaluation process at which 
transmission providers will determine whether to select or not select 
identified Long-Term Regional Transmission Facilities (or portfolio of 
such Facilities).\2104\ This point must be no later than three years 
following the beginning of the Long-Term Regional Transmission Planning 
cycle.\2105\ Finally, the evaluation process must culminate in 
determinations that are sufficiently detailed for stakeholders to 
understand why a particular Long-Term Regional Transmission Facility 
(or portfolio of such Facilities) was selected or not selected. We 
reiterate, however, that, as discussed further below in the No 
Selection Requirement section, this final order does not require 
transmission providers to select any particular Long-Term Regional 
Transmission Facility (or portfolio of such Facilities) to address 
Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \2103\ See id. P 315 (citing Order No. 890, 118 FERC ] 61,119 at 
P 494; Order No. 890-A, 121 FERC ] 61,297 at PP 215-216).
    \2104\ As described further below in the Voluntary Funding 
Opportunities section, transmission providers must also provide 
Relevant State Entities with the opportunity to fund the cost of, or 
part of the cost of, the Long-Term Regional Transmission Facility 
(or portfolio of such Facilities) to ensure that it meets the 
transmission providers' selection criteria.
    \2105\ We note, however, consistent with the discussion above in 
the Frequency of Long-Term Scenario Revisions section, that 
transmission providers may evaluate and select additional Long-Term 
Regional Transmission Facilities during the period of the Long-Term 
Regional Transmission Planning cycle after this point and before the 
commencement of the next such cycle.
---------------------------------------------------------------------------

    956. As discussed earlier, this final order requires transmission 
providers to develop and use at least three Long-Term Scenarios, and 
one sensitivity analysis applied to each Long-Term Scenario, when 
conducting Long-Term Regional Transmission Planning. Each Long-Term 
Scenario or sensitivity analysis may suggest that different Long-Term 
Transmission Needs exist, that different Long-Term Regional 
Transmission Facilities would resolve those needs, or that such Long-
Term Regional Transmission Facilities would provide different benefits 
for transmission customers. We clarify that, in the context of Long-
Term Regional Transmission Planning, Order No. 890's requirements that 
transmission providers conduct coordinated, open, and transparent 
transmission planning on the regional level \2106\ requires that 
transmission providers make transparent the methods that they used to 
analyze each individual Long-Term Scenario and the sensitivity or 
sensitivities applied to each scenario to determine the Long-Term 
Transmission Needs that exist in the transmission planning region, the 
Long-Term Regional Transmission Facilities that would resolve those 
needs, and the benefits of those Long-Term Regional Transmission 
Facilities for purposes of selection.\2107\
---------------------------------------------------------------------------

    \2106\ Order No. 890, 118 FERC ] 61,119 at P 435.
    \2107\ For example, transmission providers might weigh specific 
Long-Term Scenarios and sensitivities based on the probability that 
the analyses reflect future system conditions (which the Commission 
referred to in the NOPR as a ``weighted-benefits approach''). NOPR, 
179 FERC ] 61,028 at P 251 (citing Brattle-Grid Strategies Oct. 2021 
Report at 59-60).
---------------------------------------------------------------------------

    957. Consistent with the Order No. 1000 regional transmission 
planning requirements,\2108\ the Long-Term Regional Transmission 
Planning process must result in a regional transmission plan that 
identifies the Long-Term Regional Transmission Facilities that more 
efficiently or cost-effectively meet the transmission planning region's 
Long-Term Transmission Needs. To effectuate this requirement, we 
clarify that transmission providers have an affirmative obligation to 
identify Long-Term Regional Transmission Facilities that more 
efficiently or cost-effectively address Long-Term Transmission Needs, 
regardless of whether any stakeholder proposes potential Long-Term 
Regional Transmission Facilities for consideration in Long-Term 
Regional Transmission Planning. In this section, we enumerate specific 
requirements for how transmission providers conduct their Long-Term 
Regional Transmission Planning with the aim to ensure that more 
efficient or cost-effective Long-Term Regional Transmission Facilities

[[Page 49432]]

are selected. By clearly enumerating their evaluation processes and 
selection criteria in their OATTs, transmission providers will provide 
significant transparency to stakeholders to understand how Long-Term 
Transmission Needs will be addressed, whether there are more efficient 
or cost-effective Long-Term Regional Transmission Facilities that may 
meet those needs, and their benefits.
---------------------------------------------------------------------------

    \2108\ Order No. 1000, 136 FERC ] 61,051 at PP 55, 146-148; see 
Louisville Gas & Elec. Co., 144 FERC ] 61,054, at PP 61-62 (2013), 
on reh'g sub nom., Duke Energy Carolinas LLC, 147 FERC ] 61,241, at 
PP 82-83 (2014).
---------------------------------------------------------------------------

    958. Provided that transmission providers' evaluation processes and 
selection criteria comply with the requirements that we adopt here, we 
provide transmission providers with flexibility to determine how they 
will evaluate whether Long-Term Regional Transmission Facilities more 
efficiently or cost-effectively address Long-Term Transmission Needs, 
including by using benefit-cost ratios, assessing their net benefits 
and selecting the Long-Term Regional Transmission Facilities that 
maximize those benefits, and/or using some other method.\2109\ 
Consistent with Order No. 1000 regional cost allocation principle (3), 
and as further discussed below in the Regional Transmission Cost 
Allocation section, transmission providers may not impose as a 
selection criterion a minimum benefit-cost ratio that is higher than 
1.25-to-1.00.\2110\ We decline to reduce or increase the maximum 
benefit-cost ratio that transmission providers may use as a selection 
criterion in Long-Term Regional Transmission Planning. As the 
Commission found in Order No. 1000,\2111\ requiring that a benefit-cost 
ratio, if adopted, not exceed 1.25-to-1.00 ensures that the ratio is 
not so high as to exclude Long-Term Regional Transmission Facilities 
with significant positive net benefits from selection.
---------------------------------------------------------------------------

    \2109\ Nothing in this final order requires the use of any 
particular approach, and we clarify that transmission providers may 
use more than one approach complementarily. Compare, e.g., MISO 
Initial Comments at 54-56 (explaining MISO's approach to selecting 
transmission facilities with the goal of maximizing ``long-term 
transmission value''), with MISO, FERC Electric Tariff, MISO OATT, 
attach. FF, Transmission Expansion Planning Protocol (90.0.0), 
sections II.B.1.c, II.C.2.b (setting forth as a minimum selection 
criterion a benefit-cost ratio of 1.25 or 1.00 for Market Efficiency 
Projects and Multi-Value Projects, respectively).
    \2110\ NOPR, 179 FERC ] 61,028 at P 243 n.390; Order No. 1000, 
136 FERC ] 61,051 at P 646.
    \2111\ Order No. 1000, 136 FERC ] 61,051 at P 648.
---------------------------------------------------------------------------

    959. We decline to require transmission providers to account for 
siting considerations in their evaluation process and selection 
criteria.\2112\ We acknowledge that siting considerations (e.g., use of 
existing rights-of-way) may affect the costs, timeline, or feasibility 
of developing a Long-Term Regional Transmission Facility. While such 
siting considerations may inform the evaluation process and selection 
criteria, we do not require transmission providers to account for such 
considerations in this final order. We note, however, that, as 
discussed below in the Role of Relevant State Entities section, this 
final order requires that transmission providers consult with and seek 
the support of Relevant State Entities \2113\ regarding the evaluation 
process and selection criteria that transmission providers propose to 
use to evaluate Long-Term Regional Transmission Facilities for 
selection.
---------------------------------------------------------------------------

    \2112\ CARE Coalition Initial Comments at 7-8; see also ACEG 
Initial Comments at 59; Exelon Initial Comments at 18.
    \2113\ Many Relevant State Entities exercise their state's 
authority over the siting of transmission facilities.
---------------------------------------------------------------------------

    960. We also do not require transmission providers to include 
environmental justice or equity considerations in their evaluation 
process or selection criteria. While several commenters recommend that 
we impose such requirements,\2114\ none provides any approach for how 
these concerns would be incorporated into transmission providers' 
evaluation process and selection criteria on a generic basis. We 
acknowledge that the selection of Long-Term Regional Transmission 
Facilities represents a substantial step in the development of new 
electric transmission infrastructure, which may impact environmental 
justice communities or raise equity concerns. We further recognize that 
such environmental justice or equity considerations may affect the 
costs, timeline, or feasibility of developing a Long-Term Regional 
Transmission Facility, particularly in regions where legal frameworks 
provide for consideration of environmental justice and equity. Nothing 
in this final order precludes transmission providers from proposing on 
compliance to include environmental justice considerations within their 
evaluation process and selection criteria.
---------------------------------------------------------------------------

    \2114\ See, e.g., Acadia Center and CLF Initial Comments at 11-
12; Grand Rapids NAACP Initial Comments at 17-23 (citations 
omitted); PIOs Reply Comments at 17 (citations omitted).
---------------------------------------------------------------------------

    961. NYISO requests that the Commission clarify that transmission 
providers may continue to use qualitative and quantitative measures in 
the Long-Term Regional Transmission Planning process.\2115\ We clarify 
that nothing in this final order prohibits transmission providers from 
proposing to use qualitative factors in their evaluation processes and/
or selection criteria. Accordingly, transmission providers may propose 
to use qualitative factors in their evaluation processes and/or 
qualitative selection criteria, provided that they demonstrate on 
compliance that their proposals comply with the evaluation process and 
selection criteria requirements of this final order.
---------------------------------------------------------------------------

    \2115\ NYISO Initial Comments at 39-40.
---------------------------------------------------------------------------

    962. In response to Duke's request to allow transmission providers 
to include a selection criterion that is a qualitative evaluation of 
whether there is state and consumer support for a particular Long-Term 
Regional Transmission Facility or portfolio of such Facilities,\2116\ 
we find that transmission providers may not include in their evaluation 
process or selection criteria any prohibition on the selection of a 
Long-Term Regional Transmission Facility based on the transmission 
providers' anticipated response of a state public utility commission or 
consumer advocates to particular Long-Term Regional Transmission 
Facilities. Rather than address this issue via selection criteria 
regarding a transmission provider's anticipation of such an entity's 
response, we conclude that the requirement discussed below to consult 
with and seek support from Relevant State Entities regarding the 
evaluation process and selection criteria is a more appropriate 
mechanism to account for the Relevant State Entity's views. We also 
note that beyond this consultative process, state public utility 
commissions and consumer advocates have numerous opportunities to 
express their views on transmission development, including through 
state- and Commission-jurisdictional proceedings. Further, allowing 
such features in evaluation processes or selection criteria could 
amount to a requirement that transmission providers obtain the consent 
of Relevant State Entities, which, as discussed below in the Role of 
Relevant State Entities section, we do not believe is necessary or 
appropriate to resolve the deficiencies identified in this final 
order.\2117\
---------------------------------------------------------------------------

    \2116\ Duke Initial Comments at 4, 26-27.
    \2117\ See New York v. FERC, 535 U.S. at 26-28 (upholding 
Commission's decision not to assert jurisdiction over bundled retail 
transmission).
---------------------------------------------------------------------------

    963. In response to New York TOs,\2118\ we decline to require that 
transmission providers include selection criteria requested by state 
public utility commissions. As discussed further below in the Role of 
Relevant State Entities section, transmission providers must propose on 
compliance an evaluation process and selection criteria that comply 
with the

[[Page 49433]]

requirements of this final order after consulting with and seeking the 
support of Relevant State Entities. To the extent that a transmission 
provider believes that a selection criterion proposed by a Relevant 
State Entity would comply with the final order requirements, they may 
propose to include that criterion in their compliance filings, and the 
Commission will determine if it complies with these requirements.
---------------------------------------------------------------------------

    \2118\ New York TOs Initial Comments at 9, 11-12, 15.
---------------------------------------------------------------------------

ii. Maximize Benefits
    964. We adopt the NOPR proposal, with modification, to require that 
transmission providers in each transmission planning region propose 
evaluation processes, including selection criteria, that seek to 
maximize benefits accounting for costs over time without over-building 
transmission facilities. In the NOPR, the Commission proposed that the 
evaluation processes and selection criteria seek to maximize benefits 
to consumers over time without over-building transmission facilities. 
However, we believe that it is appropriate to modify that proposal for 
clarity. We modify the requirement to require that transmission 
providers' evaluation processes and selection criteria seek to maximize 
benefits accounting for costs. Some commenters have interpreted the 
NOPR as proposing to allow transmission providers to disregard costs 
and simply maximize benefits.\2119\ We clarify that was not the 
Commission's intent, and we modify the NOPR proposal in this final 
order to make that clear. Further, we note that while we omit reference 
``to consumers'' in the requirement for brevity, we do not view this 
change as substantive. As discussed above, this requirement, together 
with other aspects of this final order, helps to ensure transmission 
providers identify, evaluate, and select Long-Term Regional 
Transmission Facilities that more efficiently or cost-effectively 
address Long-Term Transmission Needs in order to ensure just and 
reasonable Commission-jurisdictional rates, which ultimately benefits 
ratepayers.
---------------------------------------------------------------------------

    \2119\ See, e.g., Ameren Initial Comments at 20 (citing NOPR, 
179 FERC ] 61,028 at P 242); Vistra Initial Comments at 17-18; WATT 
Coalition Initial Comments at 9.
---------------------------------------------------------------------------

    965. As discussed in the Requirement for Transmission Providers to 
Use a Set of Seven Required Benefits section, transmission providers 
conducting Long-Term Regional Transmission Planning must use and 
measure a set of benefits to evaluate Long-Term Regional Transmission 
Facilities. In setting forth an evaluation process and selection 
criteria, we clarify, consistent with the directive to seek to maximize 
benefits accounting for costs over time without over-building 
transmission facilities, that transmission providers may not disregard 
benefits that we require them to use and measure when implementing 
their approved evaluation process and selection criteria.\2120\ We 
further clarify that transmission providers may not disregard benefits 
even where those benefits are only measured in certain transmission 
system conditions, such as may be the case with Benefit 6, Mitigation 
of Extreme Weather Events and Unexpected System Conditions, and 
therefore are captured only under certain Long-Term Scenarios or 
sensitivities thereto. While transmission providers may not disregard 
such benefits, transmission providers' evaluation processes and 
selection criteria may account for the fact that certain benefits are 
only measured under certain conditions by, for example, weighting how 
likely certain conditions expressed in specific Long-Term Scenarios or 
sensitivities are to occur.
    966. As discussed further below, transmission providers have the 
discretion to select or not select any Long-Term Regional Transmission 
Facility that they identify through Long-Term Regional Transmission 
Planning, even a facility that otherwise meets the selection criteria. 
However, as noted above, the evaluation process must culminate in a 
determination that is sufficiently detailed for stakeholders to 
understand why a particular Long-Term Regional Transmission Facility 
was selected or not selected to address Long-Term Transmission Needs. 
We clarify that this determination must include the estimated costs and 
measured benefits of each alternative Long-Term Regional Transmission 
Facility (or portfolio of such Facilities) evaluated by the 
transmission providers, whether or not the Long-Term Regional 
Transmission Facility (or portfolio of such Facilities) is 
selected.\2121\
---------------------------------------------------------------------------

    \2121\ Where transmission providers employ a portfolio approach 
to evaluating and selecting Long-Term Regional Transmission 
Facilities, we require only that they include in such a 
determination the measured benefits for the portfolio of Long-Term 
Regional Transmission Facilities on an aggregate basis.
---------------------------------------------------------------------------

    967. We acknowledge commenters' concerns that there is inherent 
uncertainty in Long-Term Regional Transmission Planning.\2122\ This 
final order adopts provisions that allow for significant flexibility 
for transmission providers to address that uncertainty. As stated above 
in the Participation in Long-Term Regional Transmission Planning 
section, we require transmission providers to develop and use Long-Term 
Scenarios, which are a critical tool for managing uncertainty and 
facilitating regional transmission planning that account for a range of 
potential futures, as well as an assessment of the likelihood of each 
scenario manifesting, when identifying, evaluating, and selecting Long-
Term Regional Transmission Facilities. Further, transmission providers 
could adopt evaluation processes and selection criteria that would 
allow transmission providers to make selection decisions while 
minimizing the future risk of developing a previously selected Long-
Term Regional Transmission Facility that is not the more efficient or 
cost-effective regional transmission solution to Long-Term Transmission 
Needs. For example, transmission providers might develop a least-
regrets approach under which they would select Long-Term Regional 
Transmission Facilities in the regional transmission plan for purposes 
of cost allocation if those Long-Term Regional Transmission Facilities 
are net beneficial in more than one Long-Term Scenario and sensitivity 
analyses even if other transmission facilities have a higher benefit-
cost ratio or provide more net benefits in a single Long-Term Scenario 
or particular sensitivity. Transmission providers might also adopt a 
weighted-benefits approach under which they would select a Long-Term 
Regional Transmission Facility based on its probability-weighted 
average benefits, where probabilities have been assigned to each Long-
Term Scenario or sensitivity thereof that is studied. Under either 
approach, to maximize benefits accounting for costs over time without 
over-building transmission facilities, transmission providers must 
consider not only the risk that changing conditions might produce fewer 
benefits than originally anticipated, but also that they might produce 
more benefits than originally anticipated. Finally, as discussed below 
in the Reevaluation section, we require transmission providers to 
reevaluate certain selected Long-Term Regional Transmission Facilities 
to determine whether they continue to meet the transmission providers' 
selection criteria.
---------------------------------------------------------------------------

    \2122\ See, e.g., GridLab Initial Comments at 19; TAPS Initial 
Comments at 16-17.
---------------------------------------------------------------------------

    968. While we acknowledge commenters' wide support for least-
regrets and weighted-benefits approaches to selecting Long-Term 
Regional Transmission Facilities in Long-Term Regional Transmission 
Planning, we decline to require

[[Page 49434]]

transmission providers to use either approach. However, we clarify that 
transmission providers may not adopt an approach under which they would 
not select a Long-Term Regional Transmission Facility unless it meets 
their selection criteria in every Long-Term Scenario and sensitivity. 
We are concerned that such an approach could impose a threshold for 
selection that is so onerous it limits selection of most or all Long-
Term Regional Transmission Facilities, and, as such, is inconsistent 
with the requirement that selection criteria seek to maximize benefits 
accounting for costs over time without over-building transmission 
facilities. We find that such an approach would not ensure that 
transmission providers have the opportunity to select Long-Term 
Regional Transmission Facilities to more efficiently or cost-
effectively address Long-Term Transmission Needs, an opportunity that 
we find, as described in the Transparent and Not Unduly Discriminatory; 
More Efficient or Cost-Effective Transmission Facilities section above, 
is necessary to ensure just and reasonable Commission-jurisdictional 
rates.
    969. Again, we emphasize that this final order does not require 
that transmission providers select any particular Long-Term Regional 
Transmission Facility (or portfolio of such Facilities). Rather, this 
final order simply requires transmission providers to adopt an 
evaluation process and selection criteria that meet the minimum 
requirements set forth in this final order, including that they aim to 
maximize benefits accounting for costs over time without over-building 
transmission facilities. In response to NYISO,\2123\ however, we 
decline to clarify the definition of ``over-building,'' because doing 
so would limit transmission providers' flexibility to assess what 
constitutes over-building in their transmission planning region. 
Transmission planning regions have a wide variety of market structures, 
and numerous factors drive transmission needs, which may require 
evaluation processes and selection criteria that maximize benefits 
accounting for costs or guard against over-building in different ways. 
We expect that evaluation processes and selection criteria that 
maximize benefits accounting for costs over time without over-building 
transmission facilities will include a variety of features, based on 
their regional circumstances, that combine to ensure that transmission 
providers give careful, informed consideration to Long-Term Regional 
Transmission Facilities that more efficiently or cost-effectively 
address Long-Term Transmission Needs. We also note that, in response to 
CTC Global's concerns about the selection criteria being limited to 
considering regional transmission facilities with the least capital 
costs,\2124\ we clarify that both estimated benefits and costs must be 
disclosed when evaluating a Long-Term Regional Transmission Facility 
for selection and that transmission providers must adopt selection 
criteria that seek to maximize benefits accounting for costs over time 
without over-building transmission facilities.
---------------------------------------------------------------------------

    \2123\ NYISO Initial Comments at 43.
    \2124\ CTC Global Initial Comments at 9.
---------------------------------------------------------------------------

    970. In response to Maine Public Advocate,\2125\ we decline to 
require transmission providers to select non-transmission alternatives 
where such non-transmission alternatives meet a Long-Term Transmission 
Need at a lower cost than an alternative Long-Term Regional 
Transmission Facility. The Commission did not propose to require 
transmission providers to consider non-transmission alternatives for 
potential selection in the NOPR, and we are not persuaded to do so in 
this final order. We note, however, that transmission providers already 
are required to consider non-transmission alternatives on a comparable 
basis in regional transmission planning.\2126\
---------------------------------------------------------------------------

    \2125\ Maine Public Advocate Initial Comments at 1-2.
    \2126\ Order No. 1000, 136 FERC ] 61,051 at P 148.
---------------------------------------------------------------------------

    971. Finally, in response to TAPS,\2127\ we decline to require 
transmission providers to develop affordability metrics to provide 
along with other information about a particular Long-Term Regional 
Transmission Facility. The Commission did not propose such a 
requirement in the NOPR, and we are not persuaded to adopt a 
requirement for such metrics in this final order.
---------------------------------------------------------------------------

    \2127\ TAPS Initial Comments at 16-17, 19-20 (citations 
omitted).
---------------------------------------------------------------------------

4. Role of Relevant State Entities
a. NOPR Proposal
    972. In the NOPR, the Commission proposed to require that 
transmission providers, as part of their Long-Term Regional 
Transmission Planning, include in their OATTs a process to coordinate 
with the Relevant State Entities in developing selection 
criteria.\2128\ Regarding this requirement, the Commission proposed to 
require transmission providers to demonstrate on compliance that they 
consulted with and sought support from the Relevant State Entities in 
their transmission planning region's footprint to develop their 
proposed selection criteria.\2129\
---------------------------------------------------------------------------

    \2128\ NOPR, 179 FERC ] 61,028 at P 241.
    \2129\ Id. P 246.
---------------------------------------------------------------------------

b. Comments
i. Support/Oppose
    973. Many commenters support the Commission's proposal to require 
transmission providers to consult with and seek support from Relevant 
State Entities \2130\ and include in their OATTs a process to 
coordinate with the Relevant State Entities \2131\ in developing 
selection criteria. For example, ELCON argues that coordination with 
Relevant State Entities in identifying selection criteria is critical 
because it will promote cooperation and could result in more efficient 
state siting and permitting processes.\2132\ Pennsylvania Commission 
asserts that requiring consultation will provide states the opportunity 
to influence regional transmission planning and cost allocation, 
thereby promoting the public interest and reducing conflicts and 
disputes on these matters.\2133\
---------------------------------------------------------------------------

    \2130\ See ACEG Initial Comments at 59-60; Ameren Initial 
Comments at 20; American Municipal Power Initial Comments at 12; 
California Commission Initial Comments at 37; ELCON Initial Comments 
at 17; Nebraska Commission Initial Comments at 8-9; North Carolina 
Commission and Staff Initial Comments at 4-5; Pennsylvania 
Commission Initial Comments at 10; PJM States Initial Comments at 3.
    \2131\ See NARUC Initial Comments at 44; NESCOE Initial Comments 
at 9-10, 46; Pacific Northwest State Agencies Initial Comments at 
19; PJM States Initial Comments at 3.
    \2132\ ELCON Initial Comments at 17.
    \2133\ Pennsylvania Commission Initial Comments at 10.
---------------------------------------------------------------------------

    974. ISO-NE supports the proposal to provide states with a greater 
role in the selection of transmission facilities.\2134\ Further, ISO-NE 
argues that, in the context of policy-based planning, states should be 
responsible for determining whether to select transmission facilities, 
with ISO-NE playing a supporting, technical role.\2135\ While NESCOE 
supports the proposal that transmission providers must consult with and 
seek support from Relevant State Entities within their transmission 
planning region's footprint to develop selection criteria, NESCOE 
requests that the Commission provide Relevant State Entities an 
expanded role in the selection of transmission projects where the 
project is identified as needed in response to state laws or policy 
goals and require transmission providers to include such a role in 
their OATTs.\2136\
---------------------------------------------------------------------------

    \2134\ ISO-NE Initial Comments at 35.
    \2135\ Id. NESCOE supports ISO-NE's position. NESCOE Reply 
Comments at 5 & n.16.
    \2136\ NESCOE Initial Comments at 9-10, 48-49.

---------------------------------------------------------------------------

[[Page 49435]]

    975. PJM states that it also supports providing additional 
opportunity for involvement by states and stakeholders in Long-Term 
Regional Transmission Planning; however, in response to ISO-NE, PJM 
urges the Commission to make clear that transmission providers retain 
authority to select transmission facilities and argues that such role 
is more than a ``technical supporting role.'' \2137\ PJM States contend 
that an upfront and transparent process, with substantive state 
involvement, will ensure that selection criteria are thoroughly 
discussed by stakeholders and are consistent with the rest of Long-Term 
Regional Transmission Planning.\2138\
---------------------------------------------------------------------------

    \2137\ PJM Reply Comments at 35-36 (citing ISO-NE Initial 
Comments at 16).
    \2138\ PJM States Reply Comments at 8.
---------------------------------------------------------------------------

    976. New York Commission and NYSERDA state that the Commission 
should allow Relevant State Entities to be part of the decision-making 
process regarding the appropriate timeframe for selecting a 
transmission facility.\2139\
---------------------------------------------------------------------------

    \2139\ New York Commission and NYSERDA Initial Comments at 12.
---------------------------------------------------------------------------

    977. California Commission urges the Commission to require that 
transmission providers indicate in their compliance filings whether the 
selection criteria they propose are supported by the Relevant State 
Entities and, if not, to explain any points of disagreement.\2140\ PJM 
States argue that the Commission should, without dictating any 
substantive outcomes, ``recognize the primacy of the role for retail 
regulators'' in the final order.\2141\ By contrast, ACEG cautions that 
transmission providers must balance all states' interests when 
developing selection criteria instead of maximizing one state's 
interest over another's.\2142\ NYISO states that each transmission 
planning region should have flexibility to determine how it will 
consult with and seek support from Relevant State Entities regarding 
selection criteria.\2143\
---------------------------------------------------------------------------

    \2140\ California Commission Initial Comments at 37-38.
    \2141\ PJM States Initial Comments at 3-4 (citing NOPR, 179 FERC 
] 61,028 at P 245).
    \2142\ ACEG Initial Comments at 59-60.
    \2143\ NYISO Initial Comments at 44.
---------------------------------------------------------------------------

    978. To ensure that consultation is successful, NARUC recommends 
that the Commission require transmission providers to take two steps: 
(1) communicate with the Relevant State Entities promptly following 
issuance of a final order in a manner that is reasonably calculated to 
be received by the Relevant State Entities; and (2) establish a forum 
for negotiation that enables full and robust participation by both 
transmission providers and Relevant State Entities during the period 
allotted for making compliance filings.\2144\
---------------------------------------------------------------------------

    \2144\ NARUC Initial Comments at 44.
---------------------------------------------------------------------------

    979. Some commenters oppose the Commission's NOPR proposal.\2145\ 
Dominion argues that mandating involvement by Relevant State Entities 
would unnecessarily burden transmission providers.\2146\ Louisiana 
Commission argues that the proposal would represent ``superficial state 
involvement'' and serve as ``window dressing'' for the erosion of state 
authority due to Long-Term Regional Transmission Planning. Louisiana 
Commission argues that collective oversight by the states within an 
RTO/ISO is not equivalent to state oversight of its own retail electric 
service companies, particularly in circumstances where states are 
subject to the decisions of the majority.\2147\
---------------------------------------------------------------------------

    \2145\ See, e.g., Clean Energy Associations Initial Comments at 
22-23 (arguing that, while state involvement should play a role, the 
Commission should set forth pro forma selection criteria).
    \2146\ Dominion Initial Comments at 37-38.
    \2147\ Louisiana Commission Initial Comments at 27.
---------------------------------------------------------------------------

    980. APPA opposes any requirement for transmission providers to 
consult with, and/or seek the support of, Relevant State Entities in 
identifying selection criteria.\2148\ APPA contends that Relevant State 
Entities should be considered in the same manner as other stakeholders 
under the requirements of Order Nos. 890 and 1000.\2149\ DC and MD 
Offices of People's Counsel disagree with APPA, arguing that the 
Commission should afford Relevant State Entities an expansive role in 
the selection of transmission facilities in Long-Term Regional 
Transmission Planning.\2150\ DC and MD Offices of People's Counsel 
contend that Relevant State Entities can reach agreement quickly and 
have access to the best available data used for baseline planning and 
scenario analysis of transmission facilities.\2151\
---------------------------------------------------------------------------

    \2148\ APPA Initial Comments at 34.
    \2149\ Id.
    \2150\ DC and MD Offices of People's Counsel Reply Comments at 9 
(citing APPA Initial Comments at 35).
    \2151\ Id.
---------------------------------------------------------------------------

    981. MISO takes no position but argues that its existing processes 
already entail extensive stakeholder engagement, including consulting 
with state regulatory commissions individually and through OMS, to 
determine the selection criteria that should be used to maximize long-
term transmission value and to ensure an adequate, reliable, and 
resilient transmission system.\2152\
---------------------------------------------------------------------------

    \2152\ MISO Initial Comments at 55.
---------------------------------------------------------------------------

ii. Obtaining/Not Obtaining Consent
    982. Several commenters discuss whether transmission providers need 
only consult with and seek support from Relevant State Entities in the 
development of selection criteria, or whether they also must obtain 
their consent.\2153\ For example, Indicated PJM TOs support the NOPR 
proposal but argue that the Commission should not require transmission 
providers to obtain the agreement of Relevant State Entities in 
determining selection criteria.\2154\ AEP agrees and argues that state 
input should be only one factor and that engineering considerations 
should drive the establishment of selection criteria. AEP also 
expresses skepticism that requiring transmission providers to consult 
with Relevant State Entities will increase the chances that states will 
site the transmission facilities that transmission providers select, 
because transmission line siting processes will occur years after the 
establishment of selection criteria, will likely be performed by 
different personnel, and will address considerations separate from 
those in establishing selection criteria.\2155\
---------------------------------------------------------------------------

    \2153\ See, e.g., Acadia Center and CLF Initial Comments at 27-
28 (arguing that states should have veto authority over transmission 
providers' selection criteria in certain circumstances).
    \2154\ Indicated PJM TOs Initial Comments at 18 (citing NOPR 
179, FERC ] 61,028 at PP 244, 246).
    \2155\ AEP Initial Comments at 29-30.
---------------------------------------------------------------------------

    983. Southeast PIOs argue that, while they do not oppose factoring 
state and consumer support into the selection of transmission 
facilities, the Commission should not require transmission providers to 
obtain the approval of Relevant State Entities prior to selection of 
transmission facilities, because doing so would risk indefinitely 
delaying Long-Term Regional Transmission Planning.\2156\
---------------------------------------------------------------------------

    \2156\ Southeast PIOs Reply Comments at 27.
---------------------------------------------------------------------------

    984. PJM argues that it should be able to develop selection 
criteria in the event that Relevant State Entities do not agree on the 
establishment of selection criteria. PJM recommends that the Commission 
clarify that any requirement to demonstrate that transmission providers 
have consulted with and sought support from Relevant State Entities 
could be satisfied even if the transmission provider is unable to 
secure the agreement of Relevant State Entities.\2157\
---------------------------------------------------------------------------

    \2157\ PJM Initial Comments at 104.
---------------------------------------------------------------------------

    985. By contrast, NARUC opposes a process in which transmission 
providers consult with and seek support from Relevant State Entities 
but are empowered to override or ignore selection criteria proposed and

[[Page 49436]]

supported by Relevant State Entities. NARUC seeks clarification as to 
what recourse will be available to Relevant State Entities in the event 
that there is not agreement on selection criteria.\2158\ Nebraska 
Commission argues that the Commission should require transmission 
providers to demonstrate to the greatest extent possible that they 
gained the support of Relevant State Entities, because otherwise the 
process of consulting with and seeking support from Relevant State 
Entities could become a mere exercise.\2159\
---------------------------------------------------------------------------

    \2158\ NARUC Initial Comments at 45.
    \2159\ Nebraska Commission Initial Comments at 8-9.
---------------------------------------------------------------------------

    986. Mississippi Commission suggests that the Commission require 
transmission providers to obtain the agreement of Relevant State 
Entities on selection criteria for Long-Term Regional Transmission 
Planning.\2160\ Southern goes further, arguing that the Commission 
should allow Relevant State Entities to use the State Agreement Process 
not only to allocate the costs of Long-Term Regional Transmission 
Facilities, but also to select such transmission facilities in the 
first instance. Southern contends that, if the Commission does not 
allow states to select transmission facilities, the Commission will 
unlawfully intrude into state jurisdiction over resource 
planning.\2161\
---------------------------------------------------------------------------

    \2160\ Mississippi Commission Initial Comments at 3-4 (citing 
NOPR, 179 FERC ] 61,028 (Christie, Comm'r, concurring at P 11)).
    \2161\ Southern Initial Comments at 6-10 & n.12 (citations 
omitted).
---------------------------------------------------------------------------

    987. Acadia Center and CLF assert that states should have the 
authority to propose selection criteria, arguing that this will ensure 
that transmission providers do not refuse to consider states' interests 
and goals regarding transmission needs. Acadia Center and CLF further 
contend that states should have veto authority over transmission 
providers' selection criteria in certain scenarios, such as ISO-NE, 
where a majority of states in a transmission planning region have 
decarbonization goals but the ISO/RTO continues to apply business-as-
usual selection criteria that prioritize reliability and economic 
considerations.\2162\
---------------------------------------------------------------------------

    \2162\ Acadia Center and CLF Initial Comments at 27-28.
---------------------------------------------------------------------------

    988. AEE argues that the final order should clearly provide an 
opportunity for states to suggest selection criteria and inputs for 
analyzing transmission projects, noting that such a process may need to 
be continually developed following issuance of a final order.\2163\
---------------------------------------------------------------------------

    \2163\ AEE Initial Comments at 30-32 (citations omitted).
---------------------------------------------------------------------------

iii. Consultation With Other Entities
    989. A number of commenters argue that transmission providers 
should consult with and seek support from other entities in addition to 
Relevant State Entities. Large Public Power does not object to the NOPR 
proposal but argues that it is essential that municipal utilities also 
be included as participants in the consultative process.\2164\ American 
Municipal Power urges the Commission to recognize that publicly-owned 
utilities play a role analogous to state commissions, in that they are 
publicly accountable, operate through open and transparent procedures, 
and adopt policies reflecting the consensus of communities that own and 
support them. American Municipal Power argues that FPA section 
217(b)(4) requires the Commission to revise the NOPR proposal such that 
load-serving entities, including publicly-owned utilities, are on a par 
with Relevant State Entities.\2165\ NRECA agrees, arguing that Relevant 
State Entities may not have regulatory authority over electric 
cooperatives, and therefore the Commission must modify its proposal to 
include consultation with load-serving entities to conform with FPA 
section 217(b)(4) and Order No. 1000's transmission planning 
principles.\2166\
---------------------------------------------------------------------------

    \2164\ Large Public Power Initial Comments at 30.
    \2165\ American Municipal Power Initial Comments at 12-13.
    \2166\ NRECA Initial Comments at 50.
---------------------------------------------------------------------------

    990. Relatedly, NARUC argues that nothing in the final order should 
inhibit states from permitting the participation of certain quasi-
public/private state and Federal entities or other state entities in 
addition to Relevant State Entities.\2167\ NEPOOL states that the 
selection of any transmission facilities should be made with 
substantial input from both market participant stakeholders and the 
transmission planning region's states.\2168\
---------------------------------------------------------------------------

    \2167\ NARUC Initial Comments at 29-30 (citation omitted).
    \2168\ NEPOOL Initial Comments at 8.
---------------------------------------------------------------------------

iv. Practical Implementation Issues
    991. Several commenters discuss practical issues with the 
requirement that transmission providers consult with and seek the 
support of Relevant State Entities in developing selection criteria. 
For example, PPL generally supports the Commission's proposal but 
contends that some states may find it difficult to fulfill the role 
described in the NOPR. PPL therefore argues that the Commission should 
allow transmission providers flexibility in developing consultative 
processes.\2169\ AEP argues that some states will be unable to 
participate effectively given a lack of resources or statutory 
limitations, such that the consultative process may result in selection 
criteria ``that unfairly or unreasonably emphasize certain values.'' 
\2170\ NESCOE states that the Commission should provide flexibility as 
to how states elect to engage in the transmission planning process, 
noting that a state official's role in siting electric infrastructure 
may make it preferable for a different state official to provide that 
state's view on certain aspects of Long-Term Regional Transmission 
Planning, such as transmission project selection.\2171\
---------------------------------------------------------------------------

    \2169\ PPL Initial Comments at 18-19.
    \2170\ AEP Initial Comments at 30 (quoting NOPR, 179 FERC ] 
61,028 at P 290).
    \2171\ NESCOE Initial Comments at 9 n.16.
---------------------------------------------------------------------------

    992. NEPOOL requests that the Commission articulate principles for 
who should make selection decisions when a Long-Term Regional 
Transmission Facility may address transmission needs driven by 
reliability, economics, and public policy.\2172\
---------------------------------------------------------------------------

    \2172\ NEPOOL Initial Comments at 8.
---------------------------------------------------------------------------

    993. Michigan State Entities argue that the success of the 
Commission's proposed reforms depends on transmission providers 
meaningfully engaging with stakeholders, which requires that 
stakeholders have the time and capability to participate in a 
stakeholder review process. Michigan State Entities further assert that 
stakeholders representing diffuse and broad interests (e.g., 
residential ratepayers), as opposed to concentrated interests, tend to 
have fewer resources with which to fund participation in these 
processes, noting that many states have created consumer advocacy 
agencies to correct this imbalance. Michigan State Entities assert that 
the Commission should require that transmission providers include RTO/
ISO-level, publicly funded consumer advocates in the stakeholder 
processes that are empowered to participate in approving selection 
criteria.\2173\
---------------------------------------------------------------------------

    \2173\ Michigan State Entities Initial Comments at 4-5.
---------------------------------------------------------------------------

c. Commission Determination
    994. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to consult 
with and seek support from Relevant State Entities regarding the 
evaluation process, including selection criteria, that transmission 
providers propose to use to identify and evaluate Long-Term Regional 
Transmission Facilities for selection. Specifically, we require 
transmission providers to demonstrate on compliance that they made good

[[Page 49437]]

faith efforts to consult with and seek support from Relevant State 
Entities in their transmission planning region's footprint when 
developing the evaluation process and selection criteria that they 
propose to include in their OATTs.\2174\
---------------------------------------------------------------------------

    \2174\ In response to New York Commission and NYSERDA, we note 
that such consultation may include discussion of the appropriate 
timeframe for selecting a Long-Term Regional Transmission Facility. 
New York Commission and NYSERDA Initial Comments at 12.
---------------------------------------------------------------------------

    995. We decline to adopt the NOPR proposal to require transmission 
providers to include in their OATTs a process for coordinating with 
Relevant State Entities. We believe that the requirement adopted in 
this final order will simplify compliance efforts without sacrificing 
the benefits of consulting with and seeking the support of Relevant 
State Entities. We disagree with Dominion that requiring transmission 
providers to consult with and seek support from Relevant State Entities 
will prove burdensome, and we believe that our decision not to require 
transmission providers to include a process for such consultation in 
their OATTs will further reduce any administrative burden of this 
requirement.\2175\
---------------------------------------------------------------------------

    \2175\ See Dominion Initial Comments at 37-38.
---------------------------------------------------------------------------

    996. We clarify that we require transmission providers to seek 
support from Relevant State Entities, but do not require transmission 
providers to obtain their support, before proposing an evaluation 
process and selection criteria on compliance.\2176\ In response to 
Acadia Center and CLF, we note that Relevant State Entities may propose 
selection criteria to transmission providers, but ultimately, it is 
transmission providers who must propose on compliance an evaluation 
process and selection criteria that comply with the requirements of 
this final order. We further note that providing states with veto 
authority over transmission providers' proposed selection criteria 
would be akin to requiring transmission providers to obtain the support 
of Relevant State Entities, and therefore we do not adopt Acadia Center 
and CLF's recommendation.\2177\ While we believe that Long-Term 
Regional Transmission Planning is more likely to be successful where 
transmission providers, Relevant State Entities, and other stakeholders 
collaborate to develop an evaluation process and selection criteria, we 
reiterate that transmission planning is the tariff obligation of each 
transmission provider and transmission providers retain ultimate 
responsibility for regional transmission planning, including Long-Term 
Regional Transmission Planning, as well as complying with the 
obligations of this final order.\2178\ Moreover, we acknowledge that 
achieving consensus may not be possible in every instance.
---------------------------------------------------------------------------

    \2176\ See, e.g., PJM Initial Comments at 104 (requesting 
clarification that transmission providers are permitted to submit an 
evaluation process and selection criteria on compliance in the 
absence of obtaining the support of Relevant State Entities).
    \2177\ See Acadia Center and CLF Initial Comments at 27-28.
    \2178\ See Order No. 1000, 136 FERC ] 61,051 at P 153 (``[T]he 
ultimate responsibility for transmission planning remains with 
public utility transmission providers.'' (citing Order No. 890, 118 
FERC ] 61,119 at P 454)).
---------------------------------------------------------------------------

    997. We disagree with NARUC that, in the absence of a requirement 
that transmission providers obtain the support of Relevant State 
Entities, transmission providers will be empowered to ignore the input 
of Relevant State Entities. In this final order, we require 
transmission providers to make good faith efforts to consult with and 
seek the support of Relevant State Entities. We do not agree that the 
failure to obtain the support of Relevant State Entities is necessarily 
evidence that transmission providers did not exercise good faith 
efforts to seek their support.
    998. For similar reasons, we also disagree with Louisiana 
Commission when it argues that requiring transmission providers to 
simply consult with and seek support from Relevant State Entities will 
amount to only superficial state involvement in the development of an 
evaluation process and selection criteria.\2179\ In response to 
Louisiana Commission's additional contention that collective oversight 
of regional transmission planning processes by the transmission 
planning region's states is not equivalent to state oversight of its 
own retail electric service companies, we reiterate that this final 
order requires transmission providers to engage in and conduct 
sufficiently long-term, forward-looking, and comprehensive transmission 
planning and cost allocation processes to identify and plan for Long-
Term Transmission Needs in order to ensure Commission-jurisdictional 
rates are just and reasonable. As discussed in the Legal Authority to 
Adopt Reforms for Long-Term Regional Transmission Planning section, the 
final order neither aims at nor conflicts with state authority over 
retail rates.
---------------------------------------------------------------------------

    \2179\ Louisiana Commission Initial Comments at 27.
---------------------------------------------------------------------------

    999. We do not believe that it is necessary to adopt California 
Commission's proposal to require transmission providers to indicate in 
their compliance filings whether Relevant State Entities support the 
proposal or explain any points of disagreement that they may have with 
Relevant State Entities. Relevant State Entities may intervene in 
compliance filing proceedings and provide this information for the 
Commission's consideration as it determines whether transmission 
providers have met the requirements that we adopt in this final order. 
Nor do we adopt NARUC's request that we impose specific requirements 
dictating how transmission providers should consult with and seek the 
support of Relevant State Entities beyond the requirement that they 
demonstrate good faith efforts to do so. We believe that it is 
appropriate to provide transmission providers with flexibility in how 
to consult with and seek support of Relevant State Entities based on 
the specific needs and makeup of their transmission planning region. 
Further, we acknowledge, as argued by some commenters,\2180\ that 
practical or legal limitations may limit the extent to which some 
Relevant State Entities may participate in such processes, reinforcing 
the need for flexibility.
---------------------------------------------------------------------------

    \2180\ See AEP Initial Comments at 30 (quoting NOPR, 179 FERC ] 
61,028 at P 290); NESCOE Initial Comments at 9 n.16; PPL Initial 
Comments at 18-19.
---------------------------------------------------------------------------

    1000. We clarify that nothing in this final order diminishes the 
role of stakeholders that are not Relevant State Entities, nor absolves 
transmission providers of any existing obligations that they may have 
to provide opportunities for stakeholder input.\2181\ That said, we 
decline to require transmission providers to consult with or seek 
support from entities in addition to Relevant State Entities, including 
load-serving entities.\2182\ This final order recognizes that Relevant 
State Entities play a unique role in representing the interests of 
states, which retain a variety of authorities, including those under 
FPA section 201, that are integral to the success of Long-Term Regional 
Transmission Planning.
---------------------------------------------------------------------------

    \2181\ In response to NARUC and NEPOOL, see NARUC Initial 
Comments at 29-30; NEPOOL Initial Comments at 9, we reiterate that 
this may include other state entities in addition to Relevant State 
Entities, such as Federal entities, market participants, and other 
stakeholders.
    \2182\ See, e.g., American Municipal Power Initial Comments at 
12-13; Large Public Power Initial Comments at 30.
---------------------------------------------------------------------------

    1001. Further, we disagree with American Municipal Power that FPA 
section 217(b)(4) requires that this final order treat load-serving 
entities on par with Relevant State Entities. Through the requirements 
of this final order, we seek to ensure that adequate

[[Page 49438]]

transmission capacity is built to allow load-serving entities to meet 
their service obligations and facilitate the planning of a reliable 
grid, consistent with FPA section 217(b)(4). Nothing in our 
determination to require transmission providers to consult with and 
seek support from Relevant State Entities (but not load-serving 
entities) changes that aim or undercuts the ability of Long-Term 
Regional Transmission Planning to achieve it. We continue to find that 
other requirements in the final order, including the requirement to 
incorporate state-approved integrated resource plans and expected 
supply obligations for load-serving entities in the development of 
Long-Term Scenarios, ensure load-serving entities' reasonable needs for 
transmission capacity to meet their service obligations are 
incorporated into Long-Term Regional Transmission Planning.
    1002. Finally, in response to commenters,\2183\ we clarify that 
transmission providers, not Relevant State Entities, must determine 
whether or not to select Long-Term Transmission Facilities to meet 
Long-Term Transmission Needs. Under the FPA, the Commission has 
jurisdiction over transmission providers, and those entities, not 
Relevant State Entities, are subject to the requirements of this final 
order. As discussed above in the Transparent and Not Unduly 
Discriminatory; More Efficient or Cost-Effective Transmission 
Facilities section, we require herein that transmission providers 
designate a point in the evaluation process at which they will 
determine whether to select or not select identified Long-Term Regional 
Transmission Facilities (or portfolio of such Facilities).
---------------------------------------------------------------------------

    \2183\ See, e.g., ISO-NE Initial Comments at 35 (arguing that 
states should be responsible for determining whether to select 
transmission facilities and that transmission providers should play 
a supportive, technical role); NEPOOL Initial Comments at 8 
(requesting that the Commission articulate principles for who should 
select multi-value transmission facilities); NESCOE Initial Comments 
at 9,48-49 (requesting that the Commission require transmission 
providers to include a role in their OATTs for Relevant State 
Entities in the selection of Long-Term Regional Transmission 
Facilities); PJM Reply Comments at 36 (requesting that the 
Commission clarify that transmission providers retain the authority 
to select transmission facilities).
---------------------------------------------------------------------------

5. Voluntary Funding Opportunities
a. NOPR Proposal
    1003. In the NOPR, the Commission sought comment on whether 
Relevant State Entities should have the opportunity to voluntarily fund 
the cost of, or a portion of the cost of, a Long-Term Regional 
Transmission Facility to enable such facility to meet transmission 
providers' selection criteria (e.g., any benefit-cost threshold), and 
if so, what mechanism would be appropriate to document such voluntary 
funding agreements, how transmission providers would be assured that 
commitments to provide funding would be sufficiently binding, and what 
the most appropriate point would be in the process for such voluntary 
commitments.\2184\ The Commission also sought comment on whether such a 
voluntary funding opportunity should be extended to other entities, 
such as interconnection customers.\2185\
---------------------------------------------------------------------------

    \2184\ NOPR, 179 FERC ] 61,028 at P 252. The Commission stated 
that, for Long-Term Regional Transmission Facilities, such an 
opportunity for the Relevant State Entities could enable them to 
assign a value to achieving their particular policy goals while 
ensuring that their customers bear the corresponding costs. Id. P 
252 n.399.
    \2185\ Id.
---------------------------------------------------------------------------

b. Comments
    1004. Of commenters that address the question posed in the NOPR 
regarding whether Relevant State Entities should have the opportunity 
to voluntarily fund the cost of, or a portion of the cost of, a Long-
Term Regional Transmission Facility, nearly all argue that the 
Commission should allow such an opportunity.\2186\ ISO-NE argues that 
the Commission should provide flexibility to transmission providers to 
determine the specific means for documenting the state's agreement to 
provide such funding.\2187\ APPA argues that the Commission should 
require the filing under FPA section 205 of agreements to fund the cost 
of, or a portion of the cost of, a transmission facility so that 
affected parties have an opportunity to comment.\2188\
---------------------------------------------------------------------------

    \2186\ See Ameren Initial Comments at 21; APPA Initial Comments 
at 34-35; Clean Energy Associations Initial Comments at 23; Duke 
Initial Comments at 28-29; Grid United Initial Comments at 6; Idaho 
Commission Initial Comments at 5; ISO-NE Initial Comments at 36; 
Louisiana Commission Initial Comments at 29; NARUC Initial Comments 
at 31-32 (citing MISO-SPP Joint Targeted Interconnection Queue Study 
(JTIQ), MISO, https://www.misoenergy.org/engage/committees/miso-spp-joint-targeted-interconnection-queue-study/); New Jersey Commission 
Initial Comments at 25; PPL Initial Comments at 19; SDG&E Initial 
Comments at 4; WATT Coalition Initial Comments at 11; Xcel Initial 
Comments at 14 (stating that neither the FPA nor the Commission's 
rules and regulations categorically preclude voluntary agreement to 
plan and pay for new transmission facilities (citing Order No. 1000, 
136 FERC ] 61,051 at PP 146, 561, 724; State Voluntary Agreements to 
Plan & Pay for Transmission Facilities, 175 FERC ] 61,225 at P 3)).
    \2187\ ISO-NE Initial Comments at 36.
    \2188\ APPA Initial Comments at 34-35 (citing PJM 
Interconnection, L.L.C., 179 FERC ] 61,024 (2022)).
---------------------------------------------------------------------------

    1005. Grid United argues that, while it supports ex ante cost 
allocation methods, the Commission also should continue to permit 
alternative cost recovery arrangements, including participant funding 
agreements and voluntary agreements entered into by generation 
developers and Relevant State Entities.\2189\ Duke asserts that the 
Commission should avoid prescriptive rules that discourage or 
undervalue voluntary funding from transmission providers, states, 
Relevant State Entities, or interconnection customers.\2190\ Xcel 
argues that the Commission should state in a final order that neither 
the FPA nor the Commission's rules and regulations forbid voluntary 
arrangements for planning and paying for transmission facilities.\2191\
---------------------------------------------------------------------------

    \2189\ Grid United Initial Comments at 6.
    \2190\ Duke Initial Comments at 28-29.
    \2191\ Xcel Initial Comments at 14.
---------------------------------------------------------------------------

    1006. NARUC argues that the final order should not inhibit the 
flexibility of Relevant State Entities in developing approaches to such 
voluntary funding commitments.\2192\ NARUC argues that the final order 
should be as flexible as possible in providing voluntary funding 
opportunities to account for the variety of state laws enabling such 
authority and to allow for the possibility of sharing the costs of such 
transmission facilities between load and generator developers.\2193\
---------------------------------------------------------------------------

    \2192\ NARUC Initial Comments at 31-32; accord Idaho Commission 
Initial Comments at 5.
    \2193\ NARUC Initial Comments at 32.
---------------------------------------------------------------------------

    1007. Louisiana Commission supports the NOPR proposal and argues 
that voluntary agreement is the only fair, reasonable, and just way to 
allocate the costs of transmission facilities selected in Long-Term 
Regional Transmission Planning.\2194\ Ameren believes that Relevant 
State Entities should have the opportunity to fund a portion of the 
cost of a transmission facility that otherwise would not meet the OATT 
selection criteria but requests that the Commission clarify that this 
decision ``is referring to cost allocation.'' \2195\ Ameren argues that 
without this clarification, Relevant State Entities could fund part of 
the transmission facility while imposing on a transmission owner the 
obligation to operate and maintain that facility and assure regulatory 
compliance without adequate compensation, in violation of the D.C. 
Circuit's determination in Ameren Services Co. v. FERC that 
transmission owners ``should not be forced to operate as a non-
profit.'' \2196\
---------------------------------------------------------------------------

    \2194\ Louisiana Commission Initial Comments at 29.
    \2195\ Ameren Initial Comments at 21-22 (citing NOPR, 179 FERC ] 
61,028 at P 252).
    \2196\ Id. (citing Ameren Servs. Co. v. FERC, 880 F.3d 571 (D.C. 
Cir. 2018)).

---------------------------------------------------------------------------

[[Page 49439]]

    1008. Clean Energy Associations suggest two mechanisms to provide 
opportunities for states and interconnection customers to ensure that 
necessary transmission facilities are built. First, Clean Energy 
Associations would provide a ``Transmission Alternative Right,'' 
through which states or interconnection customers could pay the 
difference between evaluated benefits and the level of benefits 
necessary to meet the applicable benefits threshold. Second, Clean 
Energy Associations would provide a ``Transmission Expansion Right,'' 
which would allow states or interconnection customers to provide 
funding to expand transmission facilities beyond those identified in 
Long-Term Regional Transmission Planning. With respect to this second 
right, Clean Energy Associations contend that the funding parties 
should receive time-limited priority usage of additional transmission 
expansion that they fund and retain incremental capacity attributes 
associated with the expanded capability.\2197\ Clean Energy 
Associations also suggest that the portion of the expanded Long-Term 
Regional Transmission Facility originally identified in the regional 
transmission plan would receive the applicable regional cost 
allocation.\2198\
---------------------------------------------------------------------------

    \2197\ Clean Energy Associations Initial Comments at 23-24 
(citing Clean Energy Associations ANOPR Initial Comments at 76). 
Clean Energy Associations assert this would be consistent with Order 
No. 807. Id. (citing Clean Energy Associations ANOPR Initial 
Comments at 76-78; Open Access & Priority Rights on Interconnection 
Customer's Interconnection Facilities, Order No. 807, 150 FERC ] 
61,211, at P 109, order on reh'g, Order No. 807-A, 153 FERC ] 61,047 
(2015)).
    \2198\ See id.
---------------------------------------------------------------------------

    1009. New Jersey Commission argues that allowing Relevant State 
Entities the opportunity to fund the cost of or part of the cost of 
transmission facilities would provide a way to value a transmission 
facility's public policy benefits and a mechanism for co-optimizing 
reliability and economic benefits while meeting public policy needs. 
However, New Jersey Commission states that, while the proposed 20-year 
transmission planning horizon should ensure that transmission providers 
identify opportunities for multi-driver transmission projects in 
sufficient time for states to provide funding, the Commission should 
mandate that transmission providers reach out to Relevant State 
Entities to inform them of such opportunities on a timely basis.\2199\
---------------------------------------------------------------------------

    \2199\ New Jersey Commission Initial Comments at 28.
---------------------------------------------------------------------------

    1010. SPP takes no position on the voluntary funding issue but 
states that its Regional State Committee developed a cost allocation 
framework that includes the option for entities to sponsor specific 
transmission projects, assuming cost responsibility without imposing 
burdens on others through the general rate structure. SPP states that 
this mechanism could be used by a state or states to fund projects that 
SPP otherwise would not select.\2200\
---------------------------------------------------------------------------

    \2200\ SPP Initial Comments at 22 (citing SPP, Governing 
Documents Tariff, Bylaws, First Revised Volume No. 4 (0.0.0), Sec.  
7.2).
---------------------------------------------------------------------------

    1011. While PPL supports the ability of states to fund the cost of, 
or a portion of the costs of, transmission facilities that otherwise 
would not meet selection criteria, PPL argues that the final order 
should not require transmission providers to facilitate such an 
opportunity with states.\2201\ APS contends that it is not appropriate 
for a Relevant State Entity to volunteer its ratepayers to fund, and 
APS to build, a transmission facility. APS explains that Arizona is a 
diverse state with several non-jurisdictional entities; as such, APS 
contends that the state would not have the authority to volunteer all 
the state's ratepayers to fund the transmission facility, which 
ultimately may burden transmission providers with additional costs and 
responsibilities.\2202\
---------------------------------------------------------------------------

    \2201\ PPL Initial Comments at 19.
    \2202\ APS Initial Comments at 10.
---------------------------------------------------------------------------

c. Commission Determination
    1012. We modify the NOPR proposal and require transmission 
providers in each transmission planning region to include in their 
OATTs a process to provide Relevant State Entities and interconnection 
customers with the opportunity to voluntarily fund the cost of, or a 
portion of the cost of, a Long-Term Regional Transmission Facility that 
otherwise would not meet the transmission providers' selection 
criteria. We provide transmission providers with the flexibility to 
propose certain features of such a voluntary funding process in their 
compliance filings.\2203\ However, this voluntary funding process must 
be transparent and not unduly discriminatory or preferential and 
provide for the four components discussed below. Further, as with other 
aspects of the evaluation process and selection criteria, transmission 
providers must consult with and seek support from Relevant State 
Entities when developing a process to provide Relevant State Entities 
and interconnection customers with the opportunity to voluntarily fund 
the cost of, or a portion of the cost of, a Long-Term Regional 
Transmission Facility that they propose to include in their OATTs.
---------------------------------------------------------------------------

    \2203\ See ISO-NE Initial Comments at 36; NARUC Initial Comments 
at 31-32 (requesting flexibility to design voluntary funding 
processes).
---------------------------------------------------------------------------

    1013. In setting forth the requirement that transmission providers 
include in their OATTs a process to provide Relevant State Entities and 
interconnection customers with the opportunity to voluntarily fund the 
cost of, or a portion of the cost of, a Long-Term Regional Transmission 
Facility that otherwise would not meet the transmission providers' 
selection criteria, we direct transmission providers to propose OATT 
provisions on compliance that describe: (1) the process by which the 
transmission providers will make voluntary funding opportunities 
available to Relevant State Entities and interconnection customers, 
which must ensure that Relevant State Entities and interconnection 
customers receive timely notice of such opportunities and provide a 
meaningful opportunity for Relevant State Entities and interconnection 
customers; (2) the period during which Relevant State Entities and 
interconnection customers may exercise the option to provide voluntary 
funding; (3) the method that transmission providers will use to 
determine the amount of voluntary funding required to ensure that the 
Long-Term Regional Transmission Facility meets the transmission 
providers' selection criteria; and (4) the mechanism through which 
transmission providers and Relevant State Entities or interconnection 
customers will memorialize any voluntary funding agreement, e.g., a pro 
forma agreement in the OATT. We clarify that, for any portion of the 
costs of a selected Long-Term Regional Transmission Facility that is 
not voluntarily funded by a Relevant State Entity (or Entities) or 
interconnection customers, those remaining costs must be allocated 
according to the applicable Long-Term Regional Transmission Cost 
Allocation Method (or cost allocation method resulting from a State 
Agreement Process, if such a process is adopted by the transmission 
providers in the associated transmission planning region).
    1014. We believe that requiring transmission providers to include a 
voluntary funding process in their OATTs ultimately may increase the 
number of Long-Term Regional Transmission Facilities that are selected. 
The voluntary funding processes that we are requiring transmission 
providers to include in their OATTs will allow Relevant State Entities 
and interconnection customers to voluntarily fund the cost of, or a 
portion of the cost of, a Long-Term

[[Page 49440]]

Regional Transmission Facility, with any remaining costs allocated to 
beneficiaries in a manner that is at least roughly commensurate with 
the estimated benefits that they will receive. As such, a voluntary 
funding process will allow the development of Long-Term Regional 
Transmission Facilities that Relevant State Entities or interconnection 
customers believe are beneficial but that might not otherwise be 
selected.\2204\ We also believe that such a voluntary funding process 
could help transmission providers to avoid, manage, or resolve 
otherwise difficult disputes among stakeholders in their transmission 
planning regions, such as those arising from situations in which 
Relevant State Entities or interconnection customers value the 
development of certain Long-Term Regional Transmission Facilities 
differently.
---------------------------------------------------------------------------

    \2204\ See, e.g., New Jersey Commission Initial Comments at 25-
26 (arguing that voluntary funding would provide a way to value a 
transmission facility's public policy benefits and a mechanism for 
co-optimizing reliability and economic benefits while meeting public 
policy needs).
---------------------------------------------------------------------------

    1015. We acknowledge, consistent with APS's comments, that in 
certain states Relevant State Entities may not have the necessary 
authority to require all of that state's ratepayers to provide the 
funding needed to take advantage of voluntary funding 
opportunities.\2205\ We do note, however, nothing in this final order 
is intended to limit, preempt, or otherwise affect state or local laws 
or regulations with respect to the ability of any Relevant State Entity 
to voluntarily fund any costs of a Long-Term Regional Transmission 
Facility. Whether and to what extent a Relevant State Entity chooses to 
take advantage of an opportunity to voluntarily fund the costs of a 
Long-Term Regional Transmission Facility is dependent on whether that 
entity has the requisite authority to do so.
---------------------------------------------------------------------------

    \2205\ APS Initial Comments at 10.
---------------------------------------------------------------------------

    1016. In response to Ameren,\2206\ we decline to determine at this 
point what effect Ameren Services Co. v. FERC may have on voluntary 
funding arrangements or the allocation of the costs of a transmission 
facility net of that voluntary funding, which may depend on how 
transmission providers propose to allow for voluntary funding 
opportunities.
---------------------------------------------------------------------------

    \2206\ Ameren Initial Comments at 21-22.
---------------------------------------------------------------------------

    1017. We decline Clean Energy Associations' request that we require 
transmission providers to allow voluntary funding opportunities to 
expand a Long-Term Regional Transmission Facility beyond what was 
identified through Long-Term Regional Transmission Planning (e.g., 
voluntarily funding the construction of a 500 kV transmission line 
where a 345 kV transmission line was identified through Long-Term 
Regional Transmission Planning).\2207\ While we recognize that there 
may be interest in providing additional opportunities for voluntary 
funding, we find that there is insufficient record evidence to support 
imposing this modification to the voluntary funding opportunity we 
require in this final order. We note, however, that nothing in this 
final order prohibits this type of voluntary funding approach and 
transmission providers may either seek to demonstrate that a proposal 
including such an approach is consistent with or superior to what is 
required by this order, or else submit a filing under FPA section 205 
to propose the inclusion in their OATTs of voluntary funding 
opportunities that go beyond those required in this final order.
---------------------------------------------------------------------------

    \2207\ Clean Energy Associations Initial Comments at 23-24 
(citations omitted).
---------------------------------------------------------------------------

    1018. Finally, in response to APPA,\2208\ we decline to impose any 
specific requirement for transmission providers to file agreements that 
memorialize voluntary funding arrangements under FPA section 205. The 
Commission will evaluate on compliance the mechanism that transmission 
providers propose for memorializing voluntary funding agreements 
between transmission providers and Relevant State Entities or 
interconnection customers, as applicable.
---------------------------------------------------------------------------

    \2208\ APPA Initial Comments at 34-35 (citing PJM 
Interconnection, L.L.C., 179 FERC ] 61,024).
---------------------------------------------------------------------------

6. No Selection Requirement
a. NOPR Proposal
    1019. The Commission did not propose in the NOPR to require that 
transmission providers select transmission facilities, even in the 
event that a transmission facility meets the selection criteria 
established by the transmission providers.\2209\
---------------------------------------------------------------------------

    \2209\ See NOPR, 179 FERC ] 61,028 at P 9 (noting that the 
proposed reforms related to regional transmission planning and cost 
allocation requirements, like those of Order Nos. 890 and 1000, are 
focused on the transmission planning process, and not on any 
substantive outcomes that may result from this process); see also 
id. P 241 (requiring transmission providers to propose selection 
criteria to identify and evaluate transmission facilities for 
potential selection).
---------------------------------------------------------------------------

b. Comments
    1020. Many commenters express opposition to any potential 
requirement under which the Commission would require transmission 
providers to select Long-Term Regional Transmission Facilities.\2210\ 
For example, ISO-NE states that the final order should be clear that 
transmission providers are not required to select any identified Long-
Term Regional Transmission Facilities for inclusion in system plans or 
cost allocation purposes, and NESCOE agrees.\2211\ Ameren contends that 
a mandate to select any transmission facility may result in over-
building the transmission system.\2212\ Xcel makes a similar point, 
arguing that it would result in a loss of confidence in the 
transmission planning process. Furthermore, Xcel argues, transmission 
planning is subjective and removing all discretion from transmission 
planners would result in bad outcomes.\2213\
---------------------------------------------------------------------------

    \2210\ See, e.g., California Water Initial Comments at 14-15; 
Dominion Initial Comments at 18; Dominion Reply Comments at 8 
(citing NARUC Initial Comments at 5-6, 39); ISO-NE Initial Comments 
at 35-36 (citing NOPR, 179 FERC ] 61,028 (Christie, Comm'r, 
concurring at P 10)); NESCOE Initial Comments at 46-47; NRECA 
Initial Comments at 48; NRECA Reply Comments at 4-8 (citations 
omitted); NYISO Initial Comments at 44 (citing N.Y. Indep. Sys. 
Operator, Inc., 148 FERC ] 61,044, at P 125 (2014)); TANC Initial 
Comments at 10.
    \2211\ ISO-NE Initial Comments at 35-36 (citing NOPR, 179 FERC ] 
61,028 (Christie, Comm'r, concurring at P 10)); NESCOE Reply 
Comments at 5 (citing ISO-NE Initial Comments at 35-36).
    \2212\ Ameren Initial Comments at 13 (citing Large Public Power 
Initial Comments at 10).
    \2213\ Xcel Initial Comments at 13-14.
---------------------------------------------------------------------------

    1021. SERTP Sponsors urge the Commission to make clear that there 
is no requirement for transmission providers to select Long-Term 
Regional Transmission Facilities based on long-term studies without 
specific express support and agreement of the relevant regulatory 
authorities and policy makers.\2214\ NRECA asserts that transmission 
planning using a 20-year transmission planning horizon is an exercise 
fraught with uncertainty, and requests that the Commission clarify that 
it is not mandating that transmission providers select Long-Term 
Regional Transmission Facilities 20 years in advance.\2215\ NRECA 
states that other commenters also expressed concerns about risks to 
consumers associated with selecting transmission projects in the 
regional transmission plan for purposes of cost allocation 20 years 
before they may be needed.\2216\
---------------------------------------------------------------------------

    \2214\ SERTP Sponsors Initial Comments at 5; see also Alabama 
Commission Initial Comments at 3 (contending that Long-Term Regional 
Transmission Planning should not involve selection or construction 
obligations unless the affected state regulators support such 
actions).
    \2215\ NRECA Initial Comments at 27, 48.
    \2216\ NRECA Reply Comments at 4-8 (citing APPA Initial Comments 
at 22, 24-36; California Municipal Utilities Initial Comments at 2-
3, 5-7, 15; ELCON Initial Comments at 10; Large Public Power Initial 
Comments at 6-8, 11-13; Nebraska Commission Initial Comments at 2; 
New York Commission and NYSERDA Initial Comments at 8, 11-12; 
Pennsylvania Commission Initial Comments at 4-5; PJM Initial 
Comments at 59-62; TANC Initial Comments at 10).

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[[Page 49441]]

    1022. Dominion claims that Long-Term Regional Transmission Planning 
should not be a mandated development and construction plan of 
transmission facilities and argues that it should instead merely be a 
tool to help transmission providers understand where transmission needs 
may exist now and in the future.\2217\
---------------------------------------------------------------------------

    \2217\ Dominion Reply Comments at 8 (citing PIOs Initial 
Comments at 13, 28; NARUC Initial Comments at 5-6, 39).
---------------------------------------------------------------------------

    1023. PJM requests that the Commission clarify that transmission 
providers can identify trends across multiple Long-Term Regional 
Transmission Planning cycles without needing to select specific 
transmission facilities, arguing that it should have the flexibility to 
open solicitations for transmission facilities as system needs 
arise.\2218\
---------------------------------------------------------------------------

    \2218\ PJM Reply Comments at 36-37.
---------------------------------------------------------------------------

    1024. A few commenters favor selection mandates in at least some 
circumstances. For example, Eversource argues that the Commission 
should consider requiring transmission providers to address 
transmission needs that are identified in multiple Long-Term Scenarios 
or in the ``high-impact, low-frequency event'' scenario. Eversource 
contends that transmission providers otherwise risk failing to select 
transmission facilities that will greatly increase reliability, 
resiliency, and affordability.\2219\
---------------------------------------------------------------------------

    \2219\ Eversource Initial Comments at 26 (citing NOPR, 179 FERC 
] 61,028 at P 124).
---------------------------------------------------------------------------

    1025. PIOs state that experience with Order No. 1000 demonstrates 
that some transmission providers may only do the bare minimum to comply 
and therefore may fail to select, allocate the costs of, or construct 
much needed transmission. As such, PIOs state, the Commission should 
require transmission providers to use good faith efforts to select 
recommended transmission facilities.\2220\
---------------------------------------------------------------------------

    \2220\ PIOs Initial Comments at 12-13.
---------------------------------------------------------------------------

c. Commission Determination
    1026. The Commission did not propose in the NOPR, and we will not 
require in this final order, that transmission providers select any 
particular Long-Term Regional Transmission Facility--even where a 
particular transmission facility meets the transmission providers' 
selection criteria in their OATTs.\2221\ This final order improves 
regional transmission planning processes by ensuring that transmission 
providers identify Long-Term Transmission Needs, identify Long-Term 
Regional Transmission Facilities that resolve those needs and assess 
the benefits thereof, and provide the opportunity for transmission 
providers to select such Long-Term Regional Transmission Facilities. In 
other words, as in Order No. 1000, our focus is on ensuring that 
regional transmission planning processes result in just and reasonable 
rates, and not on requiring that these processes achieve any particular 
substantive outcome.
---------------------------------------------------------------------------

    \2221\ See, e.g., ISO-NE Initial Comments at 35-36 (citing NOPR, 
179 FERC ] 61,028 (Christie, Comm'r, concurring at P 10)); NESCOE 
Reply Comments at 5 (citing ISO-NE Initial Comments at 35-36); SERTP 
Sponsors Initial Comments at 5.
---------------------------------------------------------------------------

    1027. We believe that transmission providers implementing Long-Term 
Regional Transmission Planning and developing regional transmission 
plans require the flexibility to balance competing interests in the 
transmission planning region and to exercise engineering judgment to 
ensure the reliable operation of the transmission system and compliance 
with a variety of regulatory requirements.
    1028. We clarify that nothing in this final order prohibits 
transmission providers from proposing to impose upon themselves a 
requirement to select a Long-Term Regional Transmission Facility in 
certain circumstances. For example, transmission providers might 
propose selection criteria that would require them to select a Long-
Term Regional Transmission Facility if it would meet a Long-Term 
Transmission Need that appears in multiple Long-Term Scenarios, or if 
it exceeded selection criteria by a pre-set margin.
7. Other Issues
a. Comments
    1029. Clean Energy Associations argue that any transmission 
projects that are approved at the end of a transmission planning cycle 
should be included in updated models in the next transmission planning 
cycle, as well as in generation interconnection studies.\2222\
---------------------------------------------------------------------------

    \2222\ Clean Energy Associations Initial Comments at 10.
---------------------------------------------------------------------------

    1030. R Street argues that the status quo selection process 
undermines the NOPR's objective of advancing efficient and cost-
effective transmission expansion and that many transmission projects, 
especially reliability projects, are not subject to economic scrutiny. 
Therefore, R Street argues that the Commission should require that all 
transmission projects pass a cost-benefit analysis under the purview of 
an independent transmission planner and/or monitor across all Order No. 
1000 transmission planning regions.\2223\
---------------------------------------------------------------------------

    \2223\ R Street Initial Comments at 10.
---------------------------------------------------------------------------

b. Commission Determination
    1031. In response to Clean Energy Associations, we clarify that we 
are not imposing specific requirements regarding the treatment of 
selected Long-Term Regional Transmission Facilities in subsequent Long-
Term Regional Transmission Planning cycles, beyond the overall 
requirements discussed in the Development of Long-Term Scenarios 
section of this final order. As we explain above, selection is only one 
of a number of steps in the transmission development process, and we 
believe that it is appropriate to provide transmission providers 
flexibility on how to update their planning models in a manner that 
most effectively addresses the specifics of their regional transmission 
planning processes, consistent with the requirements of this final 
order.
    1032. Finally, we note that this final order generally does not 
require transmission providers to replace or otherwise make changes to 
existing Order No. 1000 regional reliability and economic transmission 
planning and cost allocation processes. As such, we decline to adopt R 
Street's proposal to require that all transmission projects pass a 
cost-benefit analysis.
8. Reevaluation
a. NOPR Proposal
    1033. The Commission proposed in the NOPR that, consistent with 
Order No. 1000, the developer of a transmission facility selected 
through Long-Term Regional Transmission Planning to address 
transmission needs driven by changes in the resource mix and demand 
would be eligible to use the applicable cost allocation method for the 
Long-Term Regional Transmission Facility. The Commission proposed that 
the existing transmission developer requirements would apply, including 
that the developer of the selected regional transmission facility must 
submit a development schedule that indicates the required steps, such 
as the granting of state approvals necessary to develop and construct 
the transmission facility such that it meets the transmission needs of 
the transmission planning region.\2224\ The Commission

[[Page 49442]]

proposed that, to the extent the Relevant State Entities in a 
transmission planning region agree to a State Agreement Process, as 
described in the Regional Transmission Cost Allocation section, the 
development schedule should also include relevant steps related to that 
process.\2225\
---------------------------------------------------------------------------

    \2224\ NOPR, 179 FERC ] 61,028 at P 247 (citing Order No. 1000-
A, 139 FERC ] 61,132 at P 442). The Commission also stated in Order 
No. 1000-A that, as part of the ongoing monitoring of the progress 
of a transmission facility once it is selected, the transmission 
providers in a transmission planning region must establish a date by 
which state approvals to construct must have been achieved that is 
tied to when construction must begin to timely meet the need that 
the facility is selected to address. If such critical steps have not 
been achieved by that date, then the transmission providers in a 
transmission planning region may ``remove the transmission project 
from the selected category and proceed with reevaluating the 
regional transmission plan to seek an alternative solution.'' Order 
1000-A,139 FERC ] 61,132 at P 442.
    \2225\ NOPR, 179 FERC ] 61,028 at P 247.
---------------------------------------------------------------------------

    1034. The Commission noted that, given the longer-term nature of 
transmission needs driven by changes in the resource mix and demand, 
the required development schedule for a transmission facility selected 
may make it unnecessary for the developer to take actions or incur 
expenses in the near-term if the transmission facility will not need to 
be in service in the near-term. The Commission also noted that a 
transmission provider may make that Long-Term Regional Transmission 
Facility's selection status subject to the outcomes of subsequent Long-
Term Regional Transmission Planning cycles, such that the previously 
selected transmission facility is no longer needed. The Commission 
proposed that transmission providers include in their selection 
criteria how they will address the selection status of a previously 
selected transmission facility based on the outcomes of subsequent 
Long-Term Regional Transmission Planning cycles.\2226\
---------------------------------------------------------------------------

    \2226\ Id. P 248.
---------------------------------------------------------------------------

b. Comments
    1035. Some commenters argue that the Commission should allow or 
require transmission providers to make the selection of a Long-Term 
Regional Transmission Facility subject to the outcomes of subsequent 
Long-Term Regional Transmission Planning cycles.\2227\ For example, 
Kansas Commission contends that transmission providers should be able 
to de-select any transmission facility selected through Long-Term 
Regional Transmission Planning if other regional transmission planning 
processes do not establish a need for that transmission facility.\2228\ 
Illinois Commission argues that periodic review and revision of the 
underlying modeling assumptions incorporated in Long-Term Scenarios 
will help to ensure that Long-Term Regional Transmission Planning 
allows transmission providers the opportunity to modify regional 
transmission plans.\2229\
---------------------------------------------------------------------------

    \2227\ See, e.g., Ameren Initial Comments at 20-21 (citing NOPR, 
179 FERC ] 61,028 at P 248).
    \2228\ Kansas Commission Initial Comments at 14.
    \2229\ Illinois Commission Initial Comments at 6.
---------------------------------------------------------------------------

    1036. APPA supports the NOPR proposal, stating that ``off ramps'' 
from Long-Term Regional Transmission Planning are necessary to protect 
customers from the costs of transmission facilities that are rendered 
unneeded or inefficient by material changes in available resources, 
technology, load characteristics, or laws.\2230\ APPA continues that 
the Commission should also require transmission providers to include in 
their selection criteria how they will address the selection status of 
previously selected transmission facilities in subsequent transmission 
planning cycles. APPA further argues that, to facilitate such review, 
the Commission should require transmission providers to have clear 
mechanisms for tracking costs and benefits of Long-Term Regional 
Transmission Facilities and to file periodic cost tracking reports with 
the Commission so that stakeholders have an opportunity to 
comment.\2231\
---------------------------------------------------------------------------

    \2230\ APPA Initial Comments at 22 (citing APPA ANOPR Initial 
Comments at 9-10; APPA ANOPR Reply Comments at 4; APPA, et al., 
Statement of Bryce Nielsen, Docket No. RM21-17-000, at 2 (filed Nov. 
12, 2021)).
    \2231\ Id. at 35-36.
---------------------------------------------------------------------------

    1037. LS Power argues that transmission providers should perform 
``variance analyses'' of all previously selected regional transmission 
facilities.\2232\ LS Power contends that all variations in costs, from 
the initial regional planning estimate through project completion, 
should be maintained in a single publicly available database.\2233\
---------------------------------------------------------------------------

    \2232\ LS Power Supplemental Comments at 13-15.
    \2233\ Id. at 13.
---------------------------------------------------------------------------

    1038. Certain TDUs argue that the Commission should require each 
transmission provider, at the time it selects a transmission facility 
that is expected to be in service more than three years later, (1) to 
identify the key assumptions that drove its inclusion in the regional 
transmission plan and (2) to review triennially whether those key 
assumptions remain valid or have materially changed. To promote 
customer affordability by avoiding over-building or under-building 
transmission facilities, Certain TDUs contend that if these key 
assumptions have materially changed, the Commission should require 
transmission providers to evaluate whether any revisions are necessary 
with respect to such transmission facilities.\2234\
---------------------------------------------------------------------------

    \2234\ Certain TDUs Initial Comments at 20.
---------------------------------------------------------------------------

    1039. Large Public Power argues that, following selection of 
transmission facilities in Long-Term Regional Transmission Planning, 
the Commission should require transmission providers to create a cost 
and risk management framework. Specifically, Large Public Power argues 
that the Commission should require transmission providers to develop 
and implement protocols requiring the developer of a transmission 
facility to file periodic reports with the Commission tracking 
anticipated project costs against cost projections and updating 
benefits information. In the period before construction begins, if such 
reports indicate that anticipated costs have exceeded an identified 
threshold, or that benefit-cost ratios have declined by an identified 
percentage, Large Public Power states that stakeholders could consider 
remedial action and the transmission developer could present 
stakeholders with mitigation plans. Further, if stakeholders do not 
reach consensus on the developer's mitigation plan, Large Public Power 
argues that stakeholders could petition the Commission to disallow 
regional cost allocation for the transmission facility. Finally, under 
Large Public Power's proposal, if the Commission disallowed regional 
cost allocation, the transmission developer would be eligible for 
abandoned plant cost recovery in the absence of imprudence.\2235\
---------------------------------------------------------------------------

    \2235\ Large Public Power Initial Comments at 11-12.
---------------------------------------------------------------------------

    1040. Large Public Power argues that its proposal would provide 
more protection to consumers than did Order No. 1000. Large Public 
Power further contends that its proposal is similar to, but more 
expansive than, MISO's existing variance analysis process, and that it 
would work together with the Commission's proposal to allow 
transmission providers to make the selection of a Long-Term Regional 
Transmission Facility subject to the outcome of subsequent Long-Term 
Regional Transmission Planning cycles.\2236\ APPA agrees with Large 
Public Power's proposal and argues that all interested stakeholders 
should have the opportunity to participate in any

[[Page 49443]]

process to reassess previously approved transmission projects.\2237\
---------------------------------------------------------------------------

    \2236\ Id. (citing NOPR, 179 FERC ] 61,028 at P 248; Order No. 
1000, 136 FERC ] 61,051 at PP 7, 263, 329; MISO, FERC Electric 
Tariff, MISO OATT, attach. FF (Transmission Expansion Planning 
Protocol) (90.0.0)).
    \2237\ APPA Reply Comments at 11-12 (citing Large Public Power 
Initial Comments at 11-12).
---------------------------------------------------------------------------

    1041. New York Commission and NYSERDA state that, while 
transmission providers can identify transmission needs using a 20-year 
transmission planning horizon, transmission facilities should be 
selected closer in time to when the need is anticipated to materialize. 
New York Commission and NYSERDA state the final order should direct 
transmission providers to develop ``off ramps'' in Long-Term Regional 
Transmission Planning so that previously identified Long-Term Regional 
Transmission Facilities can be reevaluated as the facility's needed-by 
date approaches. New York Commission and NYSERDA state that conducting 
ongoing review can help reduce the risk of stranded costs.\2238\
---------------------------------------------------------------------------

    \2238\ New York Commission and NYSERDA Initial Comments at 12.
---------------------------------------------------------------------------

    1042. NRECA contends that selecting transmission projects 20 years 
in advance is not necessary or even workable. NRECA contends that under 
the Commission's proposal, transmission providers would select Long-
Term Regional Transmission Facilities conditionally and wait until a 
subsequent Long-Term Regional Transmission Planning cycle to confirm 
that selection decision, at which point the transmission developer 
would become eligible to use the applicable regional cost allocation 
method. NRECA argues that the Commission should allow a transmission 
provider during such a subsequent cycle to find that a previously 
selected transmission facility is no longer needed, either because the 
transmission need no longer exists or because the facility is no longer 
the most efficient or cost-effective solution to meet the need.\2239\
---------------------------------------------------------------------------

    \2239\ NRECA Initial Comments at 25-26 (citing NOPR, 179 FERC ] 
61,028 at P 248).
---------------------------------------------------------------------------

    1043. ISO-NE takes no position on the Commission's proposal but 
argues that the Commission should allow transmission providers the 
flexibility to determine the treatment of previously selected 
transmission projects based on outcomes of subsequent Long-Term 
Regional Transmission Planning cycles.\2240\
---------------------------------------------------------------------------

    \2240\ ISO-NE Initial Comments at 36.
---------------------------------------------------------------------------

    1044. A number of commenters oppose or express concerns with the 
Commission's proposal to allow transmission providers to make the 
selection of a Long-Term Regional Transmission Facility subject to the 
outcome of subsequent Long-Term Regional Transmission Planning cycles. 
For example, AEP argues that, once selected through Long-Term Regional 
Transmission Planning, transmission providers should include 
transmission facilities in future scenario analysis except where a new 
study raises serious doubt that the transmission facilities continue to 
provide net benefits. AEP contends that re-studying such transmission 
facilities will lead to an endless cycle of study and ultimately 
underinvestment in necessary transmission infrastructure, as well as 
increased costs for customers.\2241\ Similarly, Indicated PJM TOs argue 
that, once selected, transmission facilities should remain in the 
regional transmission plan unless there is serious doubt a transmission 
facility would provide net benefits.\2242\
---------------------------------------------------------------------------

    \2241\ AEP Initial Comments at 13-14.
    \2242\ Indicated PJM TOs Initial Comments at 11.
---------------------------------------------------------------------------

    1045. Avangrid argues that there must be a high bar in subsequent 
Long-Term Regional Transmission Planning cycles for removing a 
previously selected transmission facility from the regional 
transmission plan because transmission developers must have confidence 
that selection in Long-Term Regional Transmission Planning represents a 
``definitive directive[ ] to invest capital.'' \2243\ Avangrid states 
that transmission facilities should not be de-selected unless there are 
changed circumstances that would make continued development of the 
project materially detrimental. Avangrid argues that otherwise, Long-
Term Regional Transmission Planning effectively will be an 
informational exercise on which investors cannot rely.\2244\
---------------------------------------------------------------------------

    \2243\ Avangrid Initial Comments at 11.
    \2244\ Id.
---------------------------------------------------------------------------

    1046. Eversource recommends that the Commission clarify that once 
transmission facilities are selected in a Long-Term Regional 
Transmission Planning cycle, they will not be subject to reevaluation, 
because such reevaluation would undermine the transmission planning 
process and deter transmission investment that the Commission is 
seeking to encourage.\2245\ Similarly, Exelon argues that the 
Commission should clarify that the selection of transmission facilities 
identified in Long-Term Regional Transmission Planning should be a 
conclusive action that is reasonably final and on which transmission 
developers can rely. Exelon explains that Long-Term Regional 
Transmission Facilities are likely to be high-voltage backbone 
facilities that meaningfully impact power flows on the transmission 
system and argues that restudy or reconsideration should be the 
exception and not the rule, allowing for their inclusion in system 
planning models used for other purposes (e.g., regional transmission 
planning addressing reliability and economic transmission needs and 
generator interconnection studies).\2246\
---------------------------------------------------------------------------

    \2245\ Eversource Initial Comments at 15-16.
    \2246\ Exelon Initial Comments at 17-18.
---------------------------------------------------------------------------

    1047. WIRES contends that the Commission should clarify that 
transmission providers need not reevaluate previously selected Long-
Term Regional Transmission Facilities after updating Long-Term 
Scenarios. WIRES claims that doing so would disrupt transmission 
facility development and raise costs.\2247\ Similarly, PPL argues that 
the Commission should exempt transmission facilities that are under 
construction or for which equipment has been purchased from any 
reevaluation in subsequent Long-Term Regional Transmission Planning 
cycles.\2248\ Invenergy argues that while Long-Term Scenarios should be 
regularly reassessed and updated, these updates should apply only to 
future Long-Term Regional Transmission Planning cycles and should not 
result in re-assessment of previously selected transmission 
facilities.\2249\
---------------------------------------------------------------------------

    \2247\ WIRES Initial Comments at 7.
    \2248\ PPL Initial Comments at 6.
    \2249\ Invenergy Initial Comments at 4-5 (citing NOPR, 179 FERC 
] 61,028 at app. B).
---------------------------------------------------------------------------

c. Commission Determination
    1048. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to include 
in their OATTs provisions that require them--in certain circumstances--
to reevaluate Long-Term Regional Transmission Facilities that 
previously were selected. These OATT provisions must meet the 
requirements set forth below, as well as the minimum requirements for 
transmission providers' broader evaluation process and selection 
criteria described above in the Minimum Requirements section.
    1049. Specifically, we direct transmission providers to revise 
their OATTs to require reevaluation of any selected Long-Term Regional 
Transmission Facilities in the following three situations, subject to 
limitations that we set forth below: (1) delays in the development of a 
previously selected Long-Term Regional Transmission Facility would 
jeopardize a transmission provider's ability to meet its reliability 
needs or reliability-related service obligations; \2250\ (2) the actual 
or

[[Page 49444]]

projected costs of a previously selected Long-Term Regional 
Transmission Facility significantly exceed cost estimates used in the 
selection of a Long-Term Regional Transmission Facility; or (3) 
significant changes in Federal, federally-recognized Tribal, state, or 
local laws or regulations cause reasonable concern that a previously 
selected Long-Term Regional Transmission Facility may no longer meet 
the transmission providers' selection criteria.\2251\
---------------------------------------------------------------------------

    \2250\ We note that this is the same as the requirement adopted 
in Order No. 1000. See Order No. 1000, 136 FERC ] 61,051 at P 329; 
Order No. 1000-A, 139 FERC ] 61,132 at P 442; NOPR, 179 FERC ] 
61,028 at P 247 & n.395.
    \2251\ NOPR, 179 FERC ] 61,028 at P 248.
---------------------------------------------------------------------------

    1050. In addition, we require transmission providers to include 
specific criteria in their OATTs that they will use to determine when 
one of these three situations occurs, thereby triggering the 
reevaluation of a previously selected Long-Term Regional Transmission 
Facility. For example, with respect to exceeding cost estimates (the 
second situation listed above), transmission providers may propose a 
specific threshold of cost escalation (e.g., a percent of total 
facility cost) above which the transmission providers would reevaluate 
a previously selected Long-Term Regional Transmission Facility. As 
another example, with respect to delays (the first situation listed 
above), transmission providers may propose specific development 
milestones that, if missed, may jeopardize the transmission developer's 
schedule and ultimately a transmission provider's ability to meet its 
reliability needs or reliability-related service obligations. We 
provide transmission providers with flexibility to propose these 
criteria on compliance, subject to the requirement that, as with the 
transmission providers' selection criteria, the reevaluation criteria 
must seek to maximize benefits accounting for costs over time without 
over-building transmission facilities. As such, in establishing such 
criteria, we expect transmission providers will balance the need to 
provide transmission developers with adequate investment certainty, 
absent which more efficient or cost-effective Long-Term Regional 
Transmission Facilities will not be developed, against the risk that, 
due to significant changes in circumstances, failing to reevaluate a 
selected Long-Term Regional Transmission Facility may result in the 
over-building of transmission. In addition, transmission providers must 
designate a point after which all selected Long-Term Regional 
Transmission Facilities will no longer be subject to reevaluation, such 
that the transmission developer of the selected Long-Term Regional 
Transmission Facility has adequate certainty to make investment 
decisions, e.g., when the facility's transmission developer has secured 
all relevant permits and authorizations for the Long-Term Regional 
Transmission Facility.
    1051. Further, as discussed further below, transmission providers 
may not reevaluate any selected Long-Term Regional Transmission 
Facility on the basis of significant changes in Federal, federally 
recognized-Tribal, state, or local laws or regulations unless, during 
the Long-Term Regional Transmission Planning cycle in which 
transmission providers selected the Long-Term Regional Transmission 
Facility, the Long-Term Regional Transmission Facility's targeted in-
service date was in the latter half of the 20-year transmission 
planning horizon for Long-Term Regional Transmission Planning.
    1052. We also require transmission providers to include in the 
reevaluation provisions in their OATTs the process and procedures that 
they will use to reevaluate a previously selected Long-Term Regional 
Transmission Facility, including the potential outcomes of reevaluation 
(e.g., taking no action, imposing a mitigation plan, reassigning the 
Long-Term Regional Transmission Facility to a different transmission 
developer, modifying the Long-Term Regional Transmission Facility, 
removing the Long-Term Regional Transmission Facility from the regional 
transmission plan).\2252\ In particular, transmission providers must 
describe the conditions under which they would remove a previously 
selected Long-Term Regional Transmission Facility from the regional 
transmission plan.\2253\ We provide flexibility to transmission 
providers to propose such processes and procedures, subject to the 
following requirements. First, reevaluation on the basis of cost 
increases or significant changes in Federal, federally-recognized 
Tribal, state, or local laws or regulations must be part of a 
subsequent Long-Term Regional Transmission Planning cycle following 
selection and must take into account not only the updated costs but 
also the updated benefits of the Long-Term Regional Transmission 
Facility.\2254\ Second, in order to allow for reevaluation to occur, 
these processes and procedures must include mechanisms for tracking 
costs so that transmission providers have an accurate way to determine 
if the actual or projected costs of the previously selected Long-Term 
Regional Transmission Facility exceed cost estimates by the relevant 
threshold, therefore requiring transmission providers to reevaluate 
that Long-Term Regional Transmission Facility. Third, the reevaluation 
processes and procedures must seek to maximize benefits accounting for 
costs over time without over-building transmission facilities. Again, 
we expect transmission providers in establishing these processes and 
procedures, including potential mitigation measures, to consider 
outcomes that enable more efficient or cost-effective Long-Term 
Regional Transmission Facilities to be developed, while addressing the 
risk of over-building.
---------------------------------------------------------------------------

    \2252\ See, e.g., MISO, FERC Electric Tariff, MISO OATT, attach. 
FF (Transmission Expansion Planning Protocol) (90.0.0), Sec.  IX.E 
(setting forth potential outcomes of MISO's variance analysis 
procedures). Mitigation plans would provide to transmission 
developers the opportunity to address the cause of the reevaluation. 
For example, where reevaluation occurs because there are delays in 
the development of a previously selected Long-Term Regional 
Transmission Facility, transmission providers might require the 
transmission developer to develop an operating procedure to ensure 
that the transmission providers are able to address the reliability 
need or meet the reliability-related service obligation in the 
period before the Long-Term Regional Transmission Facility will be 
placed in service.
    \2253\ We note that, in the event that the Long-Term Regional 
Transmission Facility was subject to competitive processes when it 
was selected, we do not require transmission providers to re-conduct 
these competitive processes in the event that the reevaluation 
process results in a change to the scope of the Long-Term Regional 
Transmission Facility. Instead, transmission providers have the 
flexibility to propose on compliance and explain whether, and if so 
when, they will re-run the competitive transmission development 
process as part of the reevaluation process.
    \2254\ Further, to perform the reevaluation analysis, we expect 
that transmission providers will use the updated Long-Term Scenarios 
and associated transmission system models that are developed for the 
Long-Term Regional Transmission Planning cycle in which the 
transmission provider reevaluates the selected Long-Term Regional 
Transmission Facility.
---------------------------------------------------------------------------

    1053. We note that in setting forth these requirements, we have 
carefully reviewed the record developed here and weighed commenters' 
countervailing arguments. We believe that the reevaluation requirements 
set forth above strike a careful balance between two broad objectives 
of Long-Term Regional Transmission Planning. On the one hand, we 
believe that transmission providers must have the opportunity to select 
more efficient or cost-effective Long-Term Regional Transmission 
Facilities, which requires sufficiently long-term, forward-looking, and 
comprehensive regional transmission planning practices. Moreover, for 
selection to meaningfully result in the development of such more 
efficient or cost-effective Long-Term Regional

[[Page 49445]]

Transmission Facilities, it must provide adequate certainty to 
transmission developers to support capital investment.
    1054. On the other hand, we also acknowledge the inherent 
uncertainty involved in predicting future transmission needs, and the 
continued selection of Long-Term Regional Transmission Facilities that 
no longer meet the transmission providers' selection criteria closer to 
the time that those facilities are expected to go into service could be 
costly for consumers. Where transmission providers have selected Long-
Term Regional Transmission Facilities further out in the transmission 
planning horizon, and where transmission providers timely obtain 
updated information about significant changes to the costs or benefits 
of such facilities, we believe that transmission providers must, 
consistent with the requirements in this final order, reevaluate a 
selected Long-Term Regional Transmission Facility in order to ensure 
that the facility continues to meet the transmission providers' 
selection criteria.
    1055. In the NOPR, the Commission attempted to balance these 
objectives by proposing that, because the required development schedule 
of a previously selected Long-Term Regional Transmission Facility may 
not require its transmission developer to take actions or incur 
expenses in the near-term, transmission providers might be able to make 
the selection status of a previously selected Long-Term Regional 
Transmission Facility subject to the outcome of subsequent Long-Term 
Regional Transmission Planning cycles.\2255\ On further reflection, 
however, and after reviewing comments submitted in response to the 
NOPR,\2256\ we find that conditioning the selection of a Long-Term 
Regional Transmission Facility in this manner and on a routine basis 
may introduce too much uncertainty into transmission providers' 
evaluation and selection of Long-Term Regional Transmission 
Facilities.\2257\ We agree with AEP that routine reevaluation would 
require repeated studies and ultimately could lead to underinvestment 
in Long-Term Regional Transmission Facilities that more efficiently or 
cost-effectively address Long-Term Transmission Needs.\2258\ Therefore, 
we do not adopt the NOPR proposal to allow transmission providers to 
make the selection status of a previously selected Long-Term Regional 
Transmission Facility subject to the outcome of subsequent Long-Term 
Regional Transmission Planning cycles.
---------------------------------------------------------------------------

    \2255\ NOPR, 179 FERC ] 61,028 at P 248.
    \2256\ See, e.g., Exelon Initial Comments at 17-18 (arguing that 
selection should be ``reasonably final'' and that routine 
reevaluation would harm the certainty required for developing Long-
Term Regional Transmission Facilities, inhibit efficient 
interconnection queue processing, and undermine system reliability 
as a whole).
    \2257\ For this reason, we are unpersuaded by NRECA's argument 
that transmission providers should conditionally select Long-Term 
Regional Transmission Facilities subject to confirmation in a 
subsequent Long-Term Regional Transmission Planning cycle. NRECA 
Initial Comments at 25-26 (citing NOPR, 179 FERC ] 61,028 at P 248).
    \2258\ See AEP Initial Comments at 13-14.
---------------------------------------------------------------------------

    1056. Nevertheless, we continue to believe that transmission 
providers may be reticent to select--and Relevant State Entities and 
other stakeholders may not support the selection of--certain Long-Term 
Regional Transmission Facilities in the absence of a requirement for 
transmission providers to reevaluate the selection of such facilities 
should significant new information become available that could give 
rise to concerns that those facilities no longer meet the transmission 
providers' selection criteria.\2259\ Further, as is required for 
regional transmission planning processes under Order No. 1000, 
transmission providers also must have the ability to take action when 
delays in developing a Long-Term Regional Transmission Facility risk 
jeopardizing a transmission provider's ability to meet its reliability 
needs or reliability-related service obligations.\2260\
---------------------------------------------------------------------------

    \2259\ See, e.g., APPA Initial Comments at 22 (arguing that 
there should be ``off ramps'' protecting transmission customers from 
Long-Term Regional Transmission Facilities that, following 
selection, are rendered unnecessary or inefficient by intervening 
changes (citations omitted)).
    \2260\ Order No. 1000, 136 FERC ] 61,051 at P 329; Order No. 
1000-A, 139 FERC ] 61,132 at P 442.
---------------------------------------------------------------------------

    1057. As discussed above, selection of a Long-Term Regional 
Transmission Facility is only one step in the process of developing, 
constructing, and placing that facility in service for the benefit of 
customers. Given the risks involved in transmission development, it is 
necessary to provide sufficient certainty to transmission developers 
and their financing partners that reevaluation will not lead to endless 
studies and protracted dispute. Therefore, we require transmission 
providers to set forth in their OATTs a reevaluation process, as 
outlined above, that ensures that any reevaluation of Long-Term 
Regional Transmission Facilities that have been selected will occur 
only in the circumstances that we have described.
    1058. We agree with APPA that reevaluation--and in particular any 
determination of whether a Long-Term Transmission Need continues to 
exist or whether a Long-Term Regional Transmission Facility continues 
to meet the transmission providers' selection criteria--will require 
transmission providers to be able to track the costs of developing 
Long-Term Regional Transmission Facilities.\2261\ We note above that 
transmission providers must propose on compliance the mechanism that 
they will use to track the costs of selected Long-Term Regional 
Transmission Facilities.
---------------------------------------------------------------------------

    \2261\ APPA Initial Comments at 36.
---------------------------------------------------------------------------

    1059. As discussed above, however, we note that, when conducting a 
reevaluation of a selected Long-Term Regional Transmission Facility, 
transmission providers must update not only actual and projected costs 
but also their calculation of the benefits of the selected Long-Term 
Regional Transmission Facility. Such a requirement will ensure that 
transmission providers are comparing the relevant costs and benefits, 
i.e., the updated costs and benefits of the selected Long-Term Regional 
Transmission Facility, to determine whether the Long-Term Regional 
Transmission Facility continues to be a more efficient or cost-
effective regional transmission solution to Long-Term Transmission 
Needs. Because updating the calculation of the benefits of a Long-Term 
Regional Transmission Facility is not as straightforward as tracking 
costs, we require reevaluation on the basis of cost escalations or of 
changes in Federal, federally-recognized Tribal, state, or local laws 
and regulations to occur as part of a subsequent Long-Term Regional 
Transmission Planning cycle. We find that this requirement is 
appropriate given the substantial time and resources that we expect 
will be necessary to update the underlying assumptions used in the 
transmission planning models, which must take place in order to update 
the calculation of the benefits of selected Long-Term Regional 
Transmission Facilities for purposes of such reevaluations. Requiring 
transmission providers to update these assumptions and their 
transmission planning models, including all Long-Term Scenarios and any 
associated sensitivities, beyond a subsequent Long-Term Regional 
Transmission Planning cycle would introduce unnecessary disruptions and 
potentially impede the efficient conduct of the next Long-Term Regional 
Transmission Planning cycle.
    1060. In response to Kansas Commission, we decline to allow 
transmission providers to remove a Long-Term Regional Transmission 
Facility from a regional transmission

[[Page 49446]]

plan for purposes of cost allocation solely because other regional 
transmission planning processes do not establish a need for that 
transmission facility.\2262\ Long-Term Regional Transmission Planning 
and existing Order No. 1000 regional transmission planning processes 
identify transmission needs differently, and we do not agree based on 
the requirements that we establish in this final order for Long-Term 
Regional Transmission Planning that reevaluation based solely on 
transmission needs identified through existing Order No. 1000 regional 
transmission planning processes is appropriate. We also decline Certain 
TDUs' request that the Commission require transmission providers to 
identify certain key assumptions driving the selection of Long-Term 
Regional Transmission Facilities and to review these assumptions in 
subsequent Long-Term Regional Transmission Planning cycles. Long-Term 
Regional Transmission Planning will necessitate that transmission 
providers compile a wide range of information from multiple data 
sources, analyze the effect of that information, develop Long-Term 
Scenarios that provide a view into what Long-Term Transmission Needs 
may be, and evaluate Long-Term Regional Transmission Facilities in 
light of these multiple different scenarios. In this light, we believe 
that Certain TDUs' suggested approach would not capture the complex 
interactions of the various factors giving rise to Long-Term 
Transmission Needs.
---------------------------------------------------------------------------

    \2262\ See Kansas Commission Initial Comments at 14.
---------------------------------------------------------------------------

    1061. Finally, we note that a coalition of diverse interests, 
including transmission developer, utility, and consumer interests, 
jointly expressed support for a framework that would provide for 
reconsideration of a Long-Term Regional Transmission Facility where 
cost and benefit projections deviate substantially from those at the 
time of selection.\2263\ We appreciate such efforts to bridge divergent 
interests to find common ground in a compromise proposal, and believe 
that the reevaluation requirements adopted here, like that widely 
supported compromise, strike a balance between competing interests.
---------------------------------------------------------------------------

    \2263\ See Advocates Advance Transmission Planning Cost 
Management Proposal At FERC, Large Public Power Council (Mar. 6, 
2024), https://www.lppc.org/news/lppc-and-advocacy-groups-advance-transmission-planning-cost-management-proposal-at-ferc (describing 
endorsements by LPPC, ACEG, CEBA, and NASUCA).
---------------------------------------------------------------------------

F. Implementation of Long-Term Regional Transmission Planning

1. NOPR Proposal
    1062. In the NOPR, the Commission proposed to require transmission 
providers to explain on compliance how the initial timing sequence for 
Long-Term Regional Transmission Planning interacts with existing 
regional transmission planning efforts. The Commission stated that it 
recognized the possibility that there may be overlap in the time 
horizon for the proposed Long-Term Regional Transmission Planning and 
existing near-term regional transmission planning processes and that 
they will likely inform each other.\2264\ The Commission also stated 
that it is possible that, in some cases, transmission facilities 
selected to address transmission needs driven by changes in the 
resource mix and demand may provide near-term reliability or economic 
benefits, and thus potentially displace regional transmission 
facilities that are under consideration as part of existing regional 
transmission planning processes.
---------------------------------------------------------------------------

    \2264\ NOPR, 179 FERC ] 61,028 at P 253.
---------------------------------------------------------------------------

    1063. In the NOPR, the Commission also sought comment on whether 
the Commission should host a periodic forum for transmission providers, 
transmission experts, relevant Federal and state agencies, and other 
stakeholders to share best practices in implementing Long-Term Regional 
Transmission Planning.\2265\
---------------------------------------------------------------------------

    \2265\ Id. P 255.
---------------------------------------------------------------------------

2. Comments
a. Comments on the Initial Timing Sequence
    1064. Several commenters support requiring transmission providers 
to explain on compliance how Long-Term Regional Transmission Planning 
will interact with existing Order No. 1000 regional transmission 
planning processes.\2266\ Several commenters urge the Commission to 
allow regional flexibility with respect to coordination between 
existing Order No. 1000 regional transmission planning processes and 
Long-Term Regional Transmission Planning.\2267\ NESCOE argues that it 
could be counterproductive and unnecessary for the Commission to 
dictate the initial timing of new processes to coordinate them with 
existing Order No. 1000 regional transmission planning processes.\2268\ 
PPL stresses the need for clarity on how the existing Order No. 1000 
regional transmission planning processes interacts with Long-Term 
Regional Transmission Planning and states that each transmission 
planning region will need to address how planned reliability and 
economic projects should or should not be reflected in, evaluated 
against, and affected by long-term studies.\2269\
---------------------------------------------------------------------------

    \2266\ Ameren Initial Comments at 22-23; APPA Initial Comments 
at 5, 24-25; Idaho Commission Initial Comments at 5; National Grid 
Initial Comments at 19; NYISO Initial Comments at 13.
    \2267\ Ameren Initial Comments at 22-23; Duke Initial Comments 
at 29; NARUC Initial Comments at 33; National Grid Initial Comments 
at 19; NESCOE Initial Comments at 51-52; NYISO Initial Comments at 
13; Pacific Northwest State Agencies Initial Comments at 20.
    \2268\ NESCOE Initial Comments at 51-52.
    \2269\ PPL Initial Comments at 4.
---------------------------------------------------------------------------

    1065. R Street states that the NOPR correctly identifies challenges 
in harmonizing existing Order No. 1000 and Long-Term Regional 
Transmission Planning. R Street argues that the two processes should 
use different time frames and assumptions, with timing optimized to 
account for uncertainty. R Street maintains that existing Order No. 
1000 transmission planning should be conducted annually over a 
transmission planning horizon of up to five years and should account 
for only those generators that are existing, under construction, or 
have interconnection agreements. R Street states that Long-Term 
Regional Transmission Planning should be conducted every two or three 
years over a 20-year transmission planning horizon and should account 
for representative generation development expectations and longer-term 
load growth. R Street posits that the long-term process should then 
feed into the near-term process, and transmission projects failing a 
cost-benefit test in one transmission planning cycle can roll over to 
the next in-kind cycle.\2270\
---------------------------------------------------------------------------

    \2270\ R Street Initial Comments at 10-11.
---------------------------------------------------------------------------

    1066. PIOs contend that the different timing for Order No. 1000 
transmission planning process cycles across transmission planning 
regions can create inconsistent assumptions, uncoordinated project 
identification between the two processes, confusion, and administrative 
burden.\2271\ To address this concern, PIOs assert that the Commission 
should: (1) mandate Order No. 1000 regional transmission planning 
process cycles be no longer than Long-Term Regional Transmission 
Planning cycles and if shorter, divide Long-Term Regional Transmission 
Planning cycles evenly; \2272\ (2) synchronize assumptions so that 
assumptions are identical for years

[[Page 49447]]

where both a Long-Term Regional Transmission Planning cycle and an 
existing Order No. 1000 regional transmission planning cycle start; (3) 
clarify the time period for existing Order No. 1000 regional 
transmission planning for economic and reliability needs; and (4) 
require transmission providers to clarify when results of one 
transmission planning process are incorporated into another, and 
require reasonable efforts to avoid one process disrupting the 
other.\2273\
---------------------------------------------------------------------------

    \2271\ PIOs Initial Comments at 47.
    \2272\ As an example, if a transmission provider uses a 36-month 
Long-Term Regional Transmission Planning cycle, its Order No. 1000 
transmission planning cycles should be 36, 18, or 12 months. Id.
    \2273\ Id. at 48-49.
---------------------------------------------------------------------------

b. Comments on Periodic Forums
    1067. Several commenters support the Commission's proposal to host 
a periodic forum for transmission providers, transmission experts, 
relevant Federal and state agencies, and other stakeholders to share 
best practices in implementing Long-Term Regional Transmission 
Planning.\2274\ For example, AEP states that periodic forums would 
allow stakeholders to discuss best available data, modeling inputs, and 
techniques for calculating benefits.\2275\ GridLab states that a 
periodic forum, along with follow-on technical conferences and a 
periodic forum, could promote greater convergence in planning methods 
among transmission providers.\2276\
---------------------------------------------------------------------------

    \2274\ ACORE Initial Comments at 15; AEP Initial Comments 6, 31; 
Arizona Commission Initial Comments at 9; GridLab Initial Comments 
at 3, 5, 19-20; Idaho Commission Initial Comments at 5; NARUC 
Initial Comments at 34; NESCOE Initial Comments at 52; Nevada 
Commission Initial Comments at 12; Northwest and Intermountain 
Initial Comments at 9, 17; NYISO Initial Comments at 14; Pacific 
Northwest State Agencies Initial Comments at 20; PJM Initial 
Comments at 7, 77; R Street Initial Comments at 11; SDG&E Initial 
Comments at 4; SPP Initial Comments at 24; US DOE Initial Comments 
at 35-36.
    \2275\ AEP Initial Comments at 31.
    \2276\ GridLab Initial Comments at 5.
---------------------------------------------------------------------------

    1068. Pacific Northwest State Agencies suggest that the Commission 
could hold technical conferences or regional sessions similar to the 
Federal State Task Force on Electric Transmission.\2277\ In contrast, 
PJM states that the periodic forum should be less formal than the 
technical conference format and that the Commission should consider 
using existing interconnection-wide organizations to host some of these 
forums.\2278\ SPP also notes that there are existing forums that could 
be leveraged, such as the Eastern Interconnection Planning 
Collaborative.\2279\
---------------------------------------------------------------------------

    \2277\ Pacific Northwest State Agencies Initial Comments at 20.
    \2278\ PJM Initial Comments at 77.
    \2279\ SPP Initial Comments at 24.
---------------------------------------------------------------------------

    1069. Some commenters recommend that the forums be held on an 
annual or a triennial schedule.\2280\ MISO notes that, while the 
current pace of change might warrant multiple technical discussions to 
understand emerging trends, over the long term such technical forums 
may only be necessary when new industry trends are identified.\2281\ 
Nevada Commission and Northwest and Intermountain suggest that the 
forum could be structured into two parts, separated by policy and 
technical discussion, by RTOs/ISOs and OATT transmission planning 
regions, or by Eastern and Western Interconnection.\2282\
---------------------------------------------------------------------------

    \2280\ AEP Initial Comments at 31; Arizona Commission Initial 
Comments at 9; Nevada Commission Initial Comments at 12.
    \2281\ MISO Initial Comments at 57.
    \2282\ Nevada Commission Initial Comments at 12; Northwest and 
Intermountain Initial Comments at 9, 17.
---------------------------------------------------------------------------

    1070. Dominion and Idaho Power oppose the Commission hosting 
additional periodic forums.\2283\ Dominion recommends that the 
Commission use the existing Joint Federal-State Task Force on Electric 
Transmission instead.\2284\ Idaho Power asserts that the most useful 
approach would be to allow transmission planning regions the time 
necessary to formulate processes that meet the Commission's 
requirements, and additional time for implementation and integration of 
those processes into current transmission planning processes.\2285\
---------------------------------------------------------------------------

    \2283\ Dominion Initial Comments at 15-16; Idaho Power Initial 
Comments at 8-9.
    \2284\ Dominion Initial Comments at 15-16.
    \2285\ Idaho Power Initial Comments at 8-9.
---------------------------------------------------------------------------

3. Commission Determination
a. Initial Timing Sequence Implementation
    1071. We adopt the NOPR proposal to require transmission providers 
to explain on compliance how the initial timing sequence for Long-Term 
Regional Transmission Planning interacts with existing regional 
transmission planning processes. Transmission providers must provide in 
their explanations any information necessary to ensure that 
stakeholders understand this interaction, including at least the 
following two components. First, we find that transmission providers 
must address the possible interaction between the transmission planning 
cycle for Long-Term Regional Transmission Planning and existing Order 
No. 1000 regional transmission planning processes. As the Commission 
stated in the NOPR, we recognize the possibility that there may be 
overlap in the time horizon for Long-Term Regional Transmission 
Planning and existing Order No. 1000 regional transmission planning 
processes and that these processes will likely inform each other. 
Second, we find that transmission providers must address the possible 
displacement of regional transmission facilities from the existing 
regional transmission planning processes. As the Commission noted in 
the NOPR, it is possible that, in some cases, Long-Term Regional 
Transmission Facilities selected to address Long-Term Transmission 
Needs may provide near-term reliability or economic benefits, and thus 
could displace regional transmission facilities that are under 
consideration as part of existing regional transmission planning 
processes.\2286\
---------------------------------------------------------------------------

    \2286\ NOPR, 179 FERC ] 61,028 at P 253.
---------------------------------------------------------------------------

    1072. We find that transmission providers should have the 
flexibility to integrate the existing regional transmission planning 
processes with Long-Term Regional Transmission Planning in a manner 
that mitigates the potential for disruption of the existing regional 
transmission planning processes, and we note the agreement of some 
commenters on this point.\2287\ However, we are also concerned that too 
much flexibility for transmission providers with respect to the date by 
which they must begin the first Long-Term Regional Transmission 
Planning cycle could lead to unnecessary delay in realizing these 
beneficial reforms for customers. Thus, we require transmission 
providers in each transmission planning region to propose on compliance 
a date, no later than one year from the date on which initial filings 
to comply with this final order are due, on which they will commence 
the first Long-Term Regional Transmission Planning cycle. However, we 
understand that it will likely be useful to align in some manner the 
Long-Term Regional Transmission Planning cycle with existing 
transmission planning cycles. In some cases, such alignment may not be 
possible to do within this one-year deadline. Therefore, transmission 
providers in a transmission planning region may propose to start the 
first Long-Term Regional Transmission Planning cycle on a date later 
than one year from the initial compliance filing due date, only to the 
extent needed to

[[Page 49448]]

align transmission planning cycles. While we encourage transmission 
providers to align transmission planning cycles if useful, to ensure 
that there is no inappropriate delay to starting Long-Term Regional 
Transmission Planning, transmission providers in a transmission 
planning region that propose a commencement date of later than one year 
from the compliance due date must include adequate support explaining 
how the proposed date to begin the first Long-Term Regional 
Transmission Planning cycle is necessary and appropriately tailored for 
their transmission planning region.
---------------------------------------------------------------------------

    \2287\ Ameren Initial Comments at 22-23; Anbaric Initial 
Comments at 4-5, 22-27; CAISO Initial Comments at 2-3, 9, 17-20; 
Duke Initial Comments at 29; Indicated PJM TOs Initial Comments at 
12; Large Public Power Initial Comments at 14-16; NARUC Initial 
Comments at 33; National Grid Initial Comments at 19; NESCOE Initial 
Comments at 51-52; NYISO Initial Comments at 13; PPL Initial 
Comments at 4; Pacific Northwest State Agencies Initial Comments at 
20; Transmission Dependent Utilities Initial Comments at 4-5.
---------------------------------------------------------------------------

    1073. In addition, we recognize commenters' concerns regarding the 
coordination of Long-Term Regional Transmission Planning and the 
existing Order No. 1000 regional transmission planning processes, and 
we encourage transmission providers to address in their explanation how 
their proposed Long-Term Regional Transmission Planning would 
facilitate moving beyond piecemeal transmission expansion to address 
relatively near-term transmission needs and toward a more robust, well-
planned transmission system.\2288\
---------------------------------------------------------------------------

    \2288\ See supra Need for Reform section.
---------------------------------------------------------------------------

    1074. With respect to the argument by NESCOE that it would be 
counterproductive and unnecessary for the Commission to dictate the 
initial timing of new processes,\2289\ we disagree. We find that it is 
necessary to establish a requirement for transmission providers to 
propose on compliance a date, no later than one year from the date on 
which initial filings to comply with this final order are due (subject 
to the limited exception described above), on which they will commence 
the first Long-Term Regional Transmission Planning Cycle, in order to 
guarantee that implementation will not be subject to unreasonable or 
unnecessary delay. With regard to the proposals made by PIOs and R 
Street,\2290\ we decline to adopt these proposals because we lack the 
record to assess the impacts that these more prescriptive proposed 
requirements would have on existing transmission planning processes, 
and whether these proposals would work effectively across the differing 
transmission planning processes in each transmission planning region.
---------------------------------------------------------------------------

    \2289\ NESCOE Initial Comments at 51-52.
    \2290\ PIOs Initial Comments at 44-48; R Street Initial Comments 
at 10-11.
---------------------------------------------------------------------------

b. Periodic Forums
    1075. We believe that it will be beneficial for the Commission to 
host a periodic forum for transmission providers, transmission experts, 
relevant Federal and state agencies, and other stakeholders to share 
best practices in implementing Long-Term Regional Transmission 
Planning, and note commenters' agreement on this point.\2291\ 
Accordingly, the Commission will organize forums to share best 
practices in implementing Long-Term Regional Transmission Planning and 
provide notice and relevant details in advance of the forums.
---------------------------------------------------------------------------

    \2291\ ACORE Initial Comments at 15; AEP Initial Comments 6, 31; 
Arizona Commission Initial Comments at 9; GridLab Initial Comments 
at 3, 5, 19-20; Idaho Commission Initial Comments at 5; NARUC 
Initial Comments at 34; NESCOE Initial Comments at 52; Nevada 
Commission Initial Comments at 12; Northwest and Intermountain 
Initial Comments at 9, 17; NYISO Initial Comments at 14; Pacific 
Northwest State Agencies Initial Comments at 20; PJM Initial 
Comments at 7, 77; R Street Initial Comments at 11; SDG&E Initial 
Comments at 4; SPP Initial Comments at 24; US DOE Initial Comments 
at 35-36.
---------------------------------------------------------------------------

IV. Coordination of Regional Transmission Planning and Generator 
Interconnection Processes

A. Need for Reform and Overall Reform

1. NOPR Proposal
    1076. In the NOPR, the Commission proposed to require that 
transmission providers consider, as part of their Long-Term Regional 
Transmission Planning, regional transmission facilities that address 
certain interconnection-related transmission needs that the 
transmission provider has identified multiple times in the generator 
interconnection process but that have never been constructed due to the 
withdrawal of the underlying interconnection request(s).\2292\
---------------------------------------------------------------------------

    \2292\ NOPR, 179 FERC ] 61,028 at P 166.
---------------------------------------------------------------------------

    1077. The Commission preliminarily found that this requirement will 
support the establishment of just and reasonable and not unduly 
discriminatory or preferential Commission-jurisdictional rates by 
addressing a potential barrier to integrating new sources of generation 
that may otherwise continue to exist absent such requirement in the 
regional transmission planning process.\2293\ As the Commission 
explained in the NOPR, the interaction between regional transmission 
planning and cost allocation processes and the generator 
interconnection process is limited--the baseline regional transmission 
planning models generally only incorporate interconnection projects 
that have completed an interconnection facilities study and are 
therefore near the end of the generator interconnection process.\2294\ 
The Commission stated, however, that where transmission system needs 
are repeatedly identified through generator interconnection processes, 
more efficient or cost-effective transmission expansion could be 
achieved through regional transmission planning and cost allocation 
that allocates costs in a manner that is at least roughly commensurate 
with estimated benefits and eliminates a potential barrier to entry for 
new generation resources.\2295\
---------------------------------------------------------------------------

    \2293\ Id. P 168.
    \2294\ Id. P 155 (citing ANOPR, 176 FERC ] 61,024 at P 23).
    \2295\ Id. P 161.
---------------------------------------------------------------------------

    1078. Additionally, the Commission sought comment on how the 
proposed requirement to evaluate such facilities for selection should 
interact with existing regional transmission planning processes and 
Long-Term Regional Transmission Planning.\2296\
---------------------------------------------------------------------------

    \2296\ Id. P 174.
---------------------------------------------------------------------------

2. Comments
a. On the Overall Reform
    1079. Multiple commenters express support for the general notion of 
coordinating the transmission planning and generator interconnection 
processes.\2297\ Other commenters explicitly support the coordination 
proposal laid out in the NOPR,\2298\ with some of these commenters 
arguing that the NOPR proposal does not go far enough (as described 
below).\2299\
---------------------------------------------------------------------------

    \2297\ ACEG Initial Comments at 51-53; Clean Energy Buyers 
Initial Comments at 19; DC and Maryland Office of People's Counsel 
Initial Comments at 16; Fervo Reply Comments at 1; Handy Law Initial 
Comments at 8-9; Interwest Initial Comments at 10-11; Invenergy 
Initial Comments at 2; Ohio Commission Federal Advocate Initial 
Comments at 8; PIOs Initial Comments at 72-73; R Street Initial 
Comments at 7-8.
    \2298\ ACEG Initial Comments at 51-53; California Commission 
Initial Comments at 27; SDG&E Initial Comments at 3.
    \2299\ Acadia Center and CLF Initial Comments at 25-26; ACORE 
Initial Comments at 13.
---------------------------------------------------------------------------

    1080. Other commenters offer more qualified support for the NOPR 
proposal. APPA and Exelon see value in the proposal but emphasize that 
any interconnection-related network upgrades that meet the specified 
criteria must independently satisfy any other applicable criteria for 
selection.\2300\ Similarly, NRECA requests that the Commission clarify 
that interconnection-related network upgrades associated with withdrawn 
interconnection requests will not receive preferential treatment in 
Long-Term Regional Transmission Planning.\2301\ Clean Energy 
Associations and ENGIE support the proposal but argue that the 
Commission's concern could be more efficiently addressed

[[Page 49449]]

with better regional transmission planning.\2302\
---------------------------------------------------------------------------

    \2300\ APPA Initial Comments at 31; Exelon Initial Comments at 
11-13.
    \2301\ NRECA Reply Comments at 10-11.
    \2302\ Clean Energy Associations Initial Comments at 15; ENGIE 
Initial Comments at 5.
---------------------------------------------------------------------------

b. Requesting Additional Reform
    1081. Some commenters suggest that the NOPR proposal does not go 
far enough to integrate the transmission planning and generator 
interconnection processes or to improve interconnection-related network 
upgrade cost allocation.\2303\ ACORE argues that more dramatic reforms 
are necessary.\2304\ Anbaric contends that a planning assessment should 
be conducted whenever an interconnection request triggers 
interconnection-related network upgrades on the larger transmission 
system beyond the interconnection substation and associated 
facilities.\2305\ ELCON states that Long-Term Regional Transmission 
Planning should be integrated with the generator interconnection 
queue.\2306\ It suggests that the Commission hold regular workshops to 
review best practices for coordinating the interconnection queue, 
current regional transmission planning, and Long-Term Regional 
Transmission Planning to reduce interconnection queue backlogs, leading 
to larger regional transmission projects that would both incorporate 
interconnection-related transmission needs and be eligible for 
competitive bidding.\2307\
---------------------------------------------------------------------------

    \2303\ Anbaric Initial Comments at 7-9; Clean Energy 
Associations Initial Comments at 25-26; Concerned Scientists Initial 
Comments at 21-22; ELCON Initial Comments at 13-14; Enel Initial 
Comments at 4-5; Invenergy Initial Comments at 10-13; Invenergy 
Reply Comments at 12-13; PIOs Initial Comments at 72-73; Shell Reply 
Comments at 3-7.
    \2304\ ACORE Initial Comments at 13.
    \2305\ Anbaric Initial Comments at 7-8.
    \2306\ ELCON Initial Comments at 13-14.
    \2307\ Id. at 14-15.
---------------------------------------------------------------------------

    1082. Similarly, Enel urges the Commission to consolidate the 
generator interconnection process into the regional transmission 
planning process to allow transmission providers to jointly assess the 
benefits, and allocate the costs, of transmission projects that benefit 
system loads and new generation.\2308\ Likewise, Shell suggests that 
the Commission integrate Long-Term Regional Transmission Planning and 
generator interconnection processes, requiring the use of the same 
benefits analysis under the same criteria, including reliability, 
economic, and public policy needs. Shell asserts that this approach 
would: increase opportunities to reduce costs to produce power and 
deliver it to load, unlock economies of scale and scope, improve 
processing times for generator interconnection requests, address first 
mover and free-rider risk, and potentially increase states' willingness 
to participate in cost allocation.\2309\
---------------------------------------------------------------------------

    \2308\ Enel Initial Comments at 4-5 (citing Enel, Plugging In: A 
Roadmap for Modernizing & Integrating Interconnection and 
Transmission Planning, https://www.enelgreenpower.com/content/dam/enel-egp/documenti/share/working-paper.pdf (last visited Apr. 
2024)).
    \2309\ Shell Reply Comments at 3, 5, 6-7.
---------------------------------------------------------------------------

    1083. Acadia Center and CLF argue that the proposal does not fully 
address shortfalls with the current method for cost allocation 
associated with interconnection-related network upgrades.\2310\ They 
also express concern that the NOPR proposal would address a limited 
subset of generator interconnection needs and call for additional 
changes to better allocate the costs of interconnection-related network 
upgrades (especially those related to offshore wind development) to 
regional beneficiaries.\2311\ Similarly, PIOs state the current cost 
allocation for interconnection-related network upgrades violates 
settled law that requires costs to be allocated both to cost causers 
and beneficiaries.\2312\ Relatedly, Invenergy argues that the most 
significant factor influencing an interconnection customer's decision 
to leave the interconnection queue is typically the cost of assigned 
interconnection-related network upgrades.\2313\
---------------------------------------------------------------------------

    \2310\ Acadia Center and CLF Initial Comments at 25-26.
    \2311\ Id. at 25.
    \2312\ PIOs Initial Comments at 72.
    \2313\ Invenergy Reply Comments at 14.
---------------------------------------------------------------------------

    1084. Invenergy also argues that interconnection-related network 
upgrades would remedy existing issues and should thus be addressed 
through the regional transmission planning process.\2314\ Invenergy 
asserts that some regions use different dispatch and other assumptions 
in the regional transmission planning and generator interconnection 
processes, which can result in persistent system overloads not being 
addressed through the regional transmission planning process.\2315\ 
Similarly, Concerned Scientists aver that generator interconnection 
requests could be 10 years old when the NOPR proposal designates the 
related interconnection-related network upgrades as suitable for 
consideration in future Long-Term Scenarios.\2316\ Concerned Scientists 
argue that the Commission should require the inclusion in Long-Term 
Scenarios of interconnection-related transmission needs that the 
generator interconnection process identified multiple times.\2317\
---------------------------------------------------------------------------

    \2314\ Id. at 12.
    \2315\ Id.
    \2316\ Concerned Scientists Reply Comments at 22.
    \2317\ Id.
---------------------------------------------------------------------------

c. Concerns With the Overall Reform
    1085. Some commenters oppose the Commission's proposal.\2318\ AEP, 
Ameren, CAISO, and Utah Division of Public Utilities argue that the 
proposal is unnecessary.\2319\ Duke argues that the Commission's 
proposal is unnecessarily prescriptive, difficult to implement, and 
risks introducing significant subjectivity and complex administration 
into the transmission planning process.\2320\ Ameren claims the 
proposal will result in inefficient regional transmission planning 
because it will not minimize total cost to end-use customers.\2321\
---------------------------------------------------------------------------

    \2318\ AEP Initial Comments at 6, 18; Ameren Initial Comments at 
17; CAISO Initial Comments at 34; Duke Initial Comments at 4; 
Illinois Commission Initial Comments at 8-9; MISO Initial Comments 
at 44-47; PJM Initial Comments at 7, 85-86; PPL Initial Comments at 
12.
    \2319\ AEP Initial Comments at 18-20; Ameren Initial Comments at 
18; CAISO Initial Comments at 6, 34-35; Utah Division of Public 
Utilities Initial Comments at 7.
    \2320\ Duke Initial Comments at 4, 20.
    \2321\ Ameren Initial Comments at 18.
---------------------------------------------------------------------------

    1086. Vistra argues that the NOPR proposal does not address how the 
newly created interconnection capacity will be allocated and how the 
timing and implementation of such upgrades would work.\2322\
---------------------------------------------------------------------------

    \2322\ Vistra Initial Comments at 33-34.
---------------------------------------------------------------------------

    1087. MISO contends that the Commission should not adopt 
prescriptive rules for integrating the generator interconnection and 
regional transmission planning processes, but instead continue to allow 
the RTOs/ISOs to develop those processes that best fit their 
footprint.\2323\ MISO argues that expanding the generator 
interconnection process beyond its current five-year outlook would slow 
the generator interconnection process.\2324\ MISO requests that if the 
Commission does not eliminate the NOPR proposal, as MISO would prefer, 
then the requirement should be altered so that transmission providers 
would only be required to post a list of generator interconnection 
upgrades that met the defined criteria.\2325\
---------------------------------------------------------------------------

    \2323\ MISO Initial Comments at 44; MISO Reply Comments at 28.
    \2324\ MISO Reply Comments at 29.
    \2325\ MISO Initial Comments at 45.
---------------------------------------------------------------------------

    1088. CAISO disagrees with California Commission's comments that 
the NOPR proposal could improve CAISO's existing interconnection-
related network upgrade provisions because the two processes have 
significantly different eligibility requirements,

[[Page 49450]]

purposes, and impacts.\2326\ CAISO further argues that the NOPR 
proposal could require transmission planners to study only outdated 
interconnection-related network upgrades.\2327\
---------------------------------------------------------------------------

    \2326\ CAISO Reply Comments at 28-29 (citing California 
Commission Initial Comments at 27).
    \2327\ Id. at 32.
---------------------------------------------------------------------------

    1089. Mississippi Commission states that interconnection-related 
network upgrades should focus on reducing costs and providing price 
signals and not be included in Long-Term Regional Transmission 
Planning.\2328\
---------------------------------------------------------------------------

    \2328\ Mississippi Commission Reply Comments at 9.
---------------------------------------------------------------------------

    1090. Some commenters argue that it is incorrect to assume that 
interconnection customers withdraw from the interconnection queue due 
solely to high interconnection-related network upgrade costs instead of 
other reasons \2329\ such as the project being uneconomic,\2330\ the 
project having insufficient site control or permitting delays,\2331\ 
the project being speculative,\2332\ or some other regulatory or 
economic factor.\2333\
---------------------------------------------------------------------------

    \2329\ CAISO Reply Comments at 29; NRECA Reply Comments at 9; 
PJM Initial Comments at 87.
    \2330\ American Municipal Power Initial Comments at 33-34; 
Indicated PJM TOs Initial Comments at 13-14; Pennsylvania Commission 
Initial Comments at 8; Vistra Initial Comments at 20.
    \2331\ Duke Initial Comments at 20-21; Idaho Power Initial 
Comments at 6; Pennsylvania Commission Initial Comments at 8; PJM 
Initial Comments at 88-89.
    \2332\ Entergy Initial Comments at 25.
    \2333\ PJM Initial Comments at 89.
---------------------------------------------------------------------------

    1091. PJM recommends an alternative proposal for funding generation 
interconnections in which states play the major role.\2334\ Under the 
PJM proposal, states that want to incent generation interconnections, 
perhaps to support a renewable portfolio standard, could fund a 
backbone transmission system to help facilitate these 
interconnections.\2335\
---------------------------------------------------------------------------

    \2334\ Id. at 89-90.
    \2335\ Id. at 90.
---------------------------------------------------------------------------

    1092. Invenergy asks the Commission not to consider certain 
alternative proposals advanced by other commenters.\2336\
---------------------------------------------------------------------------

    \2336\ Invenergy Reply Comments at 15 (citing MISO Initial 
Comments at 45; PJM Initial Comments 85, 90-92).
---------------------------------------------------------------------------

d. Cost Allocation
    1093. Some commenters oppose the NOPR proposal on the assumption 
that it could shift the cost for interconnection-related network 
upgrades from interconnection customers to load.\2337\ In addition, PJM 
states that the Commission's proposal could lead to undue 
discrimination and would distort the price signal that generator 
developers should see to make reasonable investment decisions.\2338\ 
Industrial Customers state that generators should be able to recover 
the costs of interconnection through market revenues if their projects 
are competitive.\2339\ Industrial Customers further argue that under 
the cost causation principle, a new generator should pay for 
interconnection-related network upgrades if such upgrades are only 
required because of the generator's interconnection.\2340\ Vistra 
asserts that, although the proposal shifts costs indirectly, the 
Commission still must rationally explain its decision to depart from 
the existing just and reasonable ``but-for'' policy of Order No. 
2003.\2341\
---------------------------------------------------------------------------

    \2337\ APPA Initial Comments at 31; Industrial Customers Initial 
Comments at 13; NRECA Initial Comments at 41-42 (citation omitted); 
NRECA Reply Comments at 8-9; PJM Initial Comments at 89-90; Vistra 
Initial Comments at 8; Xcel Initial Comments at 15.
    \2338\ PJM Initial Comments at 89.
    \2339\ Industrial Customers Initial Comments at 13-14.
    \2340\ Id. at 21-22.
    \2341\ Vistra Initial Comments at 9 (citation omitted).
---------------------------------------------------------------------------

    1094. Other commenters oppose the Commission's proposed reform 
because it will increase the cost to serve load. AEP asserts that such 
a proposal would possibly result in the development of unnecessary 
transmission infrastructure, which would lead to increased transmission 
customer costs for no benefit.\2342\ Dominion argues that this proposal 
could result in over-building and excessive rates for transmission 
customers.\2343\ TAPS asks the Commission to clarify that consideration 
of interconnection-related transmission needs would not foreclose 
transmission providers from proposing a cost allocation method that is 
different from the cost allocation for other types of Long-Term 
Regional Transmission Facilities.\2344\
---------------------------------------------------------------------------

    \2342\ AEP Initial Comments at 20.
    \2343\ Dominion Initial Comments at 32.
    \2344\ TAPS Initial Comments at 13-14.
---------------------------------------------------------------------------

e. Interconnection Queue Gaming Considerations
    1095. Several commenters express concerns that the NOPR proposal 
would incentivize gaming by interconnection customers to promote 
development of interconnection-related network upgrades through the 
regional transmission planning process.\2345\ Some commenters claim 
that the Commission's proposal could create a perverse incentive for 
interconnection customers to submit and withdraw multiple 
interconnection requests so that interconnection-related network 
upgrades can be considered for regional cost allocation,\2346\ 
especially in transmission planning regions with lower thresholds for 
entering and maintaining a position in the interconnection queue.\2347\
---------------------------------------------------------------------------

    \2345\ Ameren Initial Comments at 18-19; American Municipal 
Power Initial Comments at 34; Dominion Initial Comments at 32; 
Dominion Reply Comments at 7-8; EEI Initial Comments at 18; 
Eversource Initial Comments at 23-24; Idaho Power Initial Comments 
at 6; Pennsylvania Commission Initial Comments at 9; PJM Initial 
Comments at 89; PPL Initial Comments at 12-13; Shell Initial 
Comments at 29-30; SPP Initial Comments at 16; Xcel Initial Comments 
at 16.
    \2346\ Ameren Initial Comments at 18; American Municipal Power 
Initial Comments at 33-34; EEI Initial Comments at 18; Idaho Power 
Initial Comments at 6; PJM Initial Comments at 89.
    \2347\ EEI Initial Comments at 18.
---------------------------------------------------------------------------

    1096. Pennsylvania Commission, Shell, Eversource, and US DOE 
recommend the Commission modify the NOPR proposal to limit or prevent 
gaming. Pennsylvania Commission argues that adding more commitments on 
the part of the interconnection customer or requiring a more thorough 
analysis of the reasons for withdrawal is an appropriate way of 
addressing the concern.\2348\ Shell states that, to prevent gaming, the 
Commission should revise its proposal so that an upgrade is only 
eligible for inclusion in the Long-Term Regional Transmission Plan if 
it appears in one generator interconnection study cycle over a five-
year period.\2349\ Eversource asks the Commission to find that 
submitting and withdrawing interconnection requests simply so that the 
required interconnection-related network upgrades would be identified 
twice in the operative period, for example, would violate the 
Commission's regulations, including but not limited to the duty of 
candor and the prohibition of market manipulation.\2350\ US DOE states 
that the Commission should strive to ensure that the reforms do not 
create the potential for gaming by generators, which, absent 
mitigation, could increase delays and backlogs in the interconnection 
queue.\2351\
---------------------------------------------------------------------------

    \2348\ Pennsylvania Commission Initial Comments at 9.
    \2349\ Shell Initial Comments at 30.
    \2350\ Eversource Initial Comments at 23-24 (citing 18 CFR 
35.41; 18 CFR 1c.2)
    \2351\ US DOE Initial Comments at 27-28.
---------------------------------------------------------------------------

    1097. In response, Interwest argues that suggestions that increased 
coordination would result in gaming assumes that developers know in 
advance what interconnection-related network upgrades they will be 
assigned through the interconnection process.\2352\ Interwest argues 
that, given the uncertainty about whether, and when, such a process 
could apply and result in selection and construction of facilities 
under Long-Term Regional

[[Page 49451]]

Transmission Planning, it would not incentivize gaming.\2353\ 
Similarly, Invenergy argues that developers would have no reasonable 
expectation that any interconnection-related network upgrade meeting 
the NOPR criteria ultimately would be selected through the multi-year 
regional transmission planning process and actually constructed on a 
timeline that accommodates the developer's generation facility.\2354\ 
If the Commission is concerned about possible gaming, however, 
Invenergy urges the Commission to revise the proposal to require that 
withdrawn interconnection requests must have been submitted by 
unaffiliated entities.\2355\
---------------------------------------------------------------------------

    \2352\ Interwest Reply Comments at 5-6 (citing EEI Initial 
Comments at 18).
    \2353\ Id. at 6.
    \2354\ Invenergy Reply Comments at 14.
    \2355\ Id. at 14-15.
---------------------------------------------------------------------------

f. Miscellaneous
    1098. SEIA asks the Commission to clarify that the phrase 
``interconnection-related transmission needs'' would allow transmission 
providers to include either individual or aggregated transmission 
solutions that address specific needs.\2356\ SEIA asks the Commission 
to require transmission providers to assume that these interconnection-
related network upgrades will be built and include the interconnection-
related network upgrades in their Long-Term Regional Transmission 
Planning.\2357\
---------------------------------------------------------------------------

    \2356\ SEIA Initial Comments at 14 (citing SPP, 2020 Integrated 
Transmission Planning Assessment Report, at 87 (Oct. 27, 2020)).
    \2357\ Id.
---------------------------------------------------------------------------

    1099. Several commenters argue that the reforms issued under Order 
No. 2023, Improvements to Generator Interconnection Procedures and 
Agreements, will address interconnection-related issues more 
appropriately than the NOPR proposal.\2358\ Some commenters argue that 
the Commission should defer consideration of the NOPR proposal until 
the reforms issued under Order No. 2023 are implemented.\2359\
---------------------------------------------------------------------------

    \2358\ Dominion Reply Comments at 8; Idaho Power Initial 
Comments at 6-7; Illinois Commission Initial Comments at 9; Pacific 
Northwest Utilities Initial Comments at 15.
    \2359\ Duke Initial Comments at 20; EEI Initial Comments at 18; 
Entergy Initial Comments at 24-25.
---------------------------------------------------------------------------

3. Need for Reform
    1100. Based on the record, we find that there is substantial 
evidence to support the conclusion that the Commission's existing 
regional transmission planning requirements are unjust, unreasonable, 
and unduly discriminatory or preferential because they do not 
adequately consider certain interconnection-related transmission needs 
that the transmission provider has identified multiple times in the 
generator interconnection process but that have never been resolved due 
to the withdrawal of the underlying interconnection request(s). We 
therefore adopt the preliminary findings in the NOPR concerning the 
need for reform. Specifically, we find that there is insufficient 
coordination between the Commission's existing generator 
interconnection processes and regional transmission planning and cost 
allocation processes regarding interconnection-related transmission 
needs that are repeatedly identified in the generator interconnection 
process. As a result of this deficiency, transmission providers do not 
currently consider those identified interconnection-related 
transmission needs in their regional transmission planning processes, 
nor do they evaluate whether more efficient or cost-effective regional 
transmission solutions to these needs could be achieved through 
regional transmission planning processes and cost allocation. 
Accordingly, we find that existing regional transmission planning and 
cost allocation processes are insufficient to ensure just and 
reasonable rates, and we direct the reforms discussed below to address 
this deficiency.
    1101. As explained in the NOPR,\2360\ we are concerned about the 
prevalence of interconnection-related network upgrades being repeatedly 
identified in the generator interconnection process in multiple 
interconnection queue cycles during a short period of time (e.g., five 
years) but not being developed because the interconnection request(s) 
driving the need for the upgrade are withdrawn. The record indicates 
that the level of spending on interconnection-related network upgrades 
has dramatically increased in recent years, escalating the cost of 
interconnecting new generation to the transmission system.\2361\ The 
evidence also suggests that this trend is leading to more and more 
interconnection customers withdrawing their interconnection requests in 
the face of significant costs associated with interconnection-related 
network upgrades.\2362\ For example, between January 2016 and July 
2020, 245 generation projects in advanced stages in the MISO generator 
interconnection process withdrew from the queue, with the project 
developers citing high interconnection-related network upgrade costs as 
the primary reason for their withdrawal.\2363\ While interconnection 
customers may choose to withdraw from the interconnection queue for a 
number of reasons, in recent years, the deciding factor has 
increasingly become the interconnection customer's ``sticker shock'' at 
its cost responsibility for interconnection-related network 
upgrades.\2364\
---------------------------------------------------------------------------

    \2360\ NOPR, 179 FERC ] 61,028 at PP 161-165.
    \2361\ See ICF Resources, LLC, Just and Reasonable? Transmission 
Upgrades Charged to Interconnecting Generators Are Delivering 
System-Wide Benefits, 2 (Sept. 9, 2021), https://acore.org/wp-content/uploads/2021/09/Just-Reasonable-Transmission-Upgrades-Charged-to-Interconnecting-Generators-Are-Delivering-System-Wide-Benefits.pdf (ICF Sept. 2021 Interconnection Report); Jay Caspary et 
al., ACEG, Disconnected: The Need for a New Generator 
Interconnection Policy, 14 (2021)), https://cleanenergygrid.org/wp-content/uploads/2021/01/Disconnected-The-Need-for-a-New-Generator-Interconnection-Policy-1.pdf (ACEG 2021 Interconnection Report).
    \2362\ ACEG 2021 Interconnection Report at 17.
    \2363\ Id. (naming the high cost of interconnection-related 
network upgrades as the fundamental problem that interconnection 
queue reform has failed to address thus far).
    \2364\ See ACORE ANOPR Comments at 12; DC and Maryland Office of 
People's Counsel Initial Comments at 16; Invenergy Reply Comments at 
14; Northwest and Intermountain Initial Comments at 14; see also 
Order No. 2023, 184 FERC ] 61,054 at P 41; Order No. 2023-A, 186 
FERC ] 61,199 at P 14.
---------------------------------------------------------------------------

    1102. When interconnection customers withdraw from the 
interconnection queue, the identified interconnection-related network 
upgrades associated with those interconnection customers remain unbuilt 
and the underlying interconnection-related transmission needs go 
unaddressed. In many cases, when the interconnection-related 
transmission need is not addressed via development of interconnection-
related network upgrades in one interconnection queue cycle, the same 
interconnection-related transmission need--and oftentimes the same or a 
substantially similar interconnection-related network upgrade--will 
appear in subsequent interconnection queue cycles. One study, which 
analyzed 12 specific interconnection-related network upgrades 
identified by MISO and SPP, found that SPP identified three of the 
upgrades in two interconnection queue cycles and one in three 
interconnection queue cycles, and MISO identified three of the upgrades 
in two interconnection queue cycles and two in three interconnection 
queue cycles.\2365\ In other words, both SPP and MISO were repeatedly 
identifying the same interconnection-related network upgrades as 
interconnection customers withdrew from the interconnection queue, 
leaving later-in-time interconnection customers to address

[[Page 49452]]

the same interconnection-related transmission needs.
---------------------------------------------------------------------------

    \2365\ ICF Sept. 2021 Interconnection Report at 25-26.
---------------------------------------------------------------------------

    1103. Where interconnection-related transmission needs are 
repeatedly identified in interconnection studies, the implication may 
be that the area, despite the potentially prohibitive interconnection 
costs if borne by one or a small number of interconnection customers, 
is otherwise desirable for generators to locate (e.g., it is located 
close to fuel sources). This repeated interest in accessing the 
transmission system, combined with the lack of available transmission 
capacity and prohibitive costs of interconnection-related network 
upgrades, together create a barrier to accessing the transmission 
system and establish a known interconnection-related transmission need. 
We find that this barrier to entry can hinder the timely development of 
new generation, thereby stifling competition in wholesale electricity 
markets and limiting access to lower-cost generation.\2366\ We find 
that existing regional transmission planning processes do not 
adequately consider or account for this specific set of 
interconnection-related transmission needs that go unaddressed in the 
generator interconnection processes. By failing to consider such 
interconnection-related transmission needs, the regional transmission 
planning process is unable to identify the more efficient or cost-
effective regional transmission solutions.
---------------------------------------------------------------------------

    \2366\ The Commission has previously found that policies 
eliminating barriers to entry for generation resources can enhance 
competition in bulk power markets. Standardization of Generator 
Interconnection Agreements & Procs., Order No. 2003, 68 FR 49846 
(Aug. 19, 2003), 104 FERC ] 61,103, at PP 694 (2003), order on 
reh'g, Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), 106 FERC ] 
61,220 at P 579, order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 
4, 2005), 109 FERC ] 61,287 (2004), order on reh'g, Order No. 2003-
C, 70 FR 37661 (June 30, 2005), 111 FERC ] 61,401 (2005), aff'd sub 
nom. Nat'l Ass'n of Regul. Util. Comm'rs v. FERC, 475 F.3d 1277 
(D.C. Cir. 2007); Order No. 2023, 184 FERC ] 61,054 at P 44. Limited 
access to new and more competitive supplies of generation can 
increase the energy rates paid by wholesale customers. Order No. 
2023, 184 FERC ] 61,054 at P 43.
---------------------------------------------------------------------------

    1104. Moreover, the Commission has long recognized that 
interconnection-related network upgrades provide transmission benefits 
that extend beyond the interconnection customer.\2367\ By upgrading the 
transmission system in a piecemeal fashion through the generator 
interconnection process, as described above, the current regional 
transmission planning paradigm can impose costs on interconnection 
customers for transmission facilities that provide benefits beyond 
those received by the interconnection customer. This paradigm allocates 
transmission costs in a way that may not be roughly commensurate with 
the distribution of benefits, a result that can lead to unjust and 
unreasonable rates. The reform adopted below requires the consideration 
of regional transmission facilities to meet interconnection-related 
transmission needs repeatedly identified in the generator 
interconnection process in the Order No. 1000 regional transmission 
planning and cost allocation processes, which we believe will result in 
more efficient or cost-effective regional transmission expansion, cost 
allocation for such regional transmission facilities that is at least 
roughly commensurate with estimated benefits, and elimination of a 
barrier to entry for new generation resources (which can enhance 
competition in wholesale electricity markets and facilitate access to 
lower-cost generation). In turn, we expect that these reforms will 
ensure just and reasonable and not unduly discriminatory or 
preferential Commission-jurisdictional rates.
---------------------------------------------------------------------------

    \2367\ See, e.g., Order No. 2003, 104 FERC ] 61,103 at P 65 
(stating that ``[f]acilities beyond the Point of Interconnection 
[(i.e., interconnection-related network upgrades)] are part of the 
Transmission Provider's Transmission System and benefit all 
users'').
---------------------------------------------------------------------------

    1105. Additionally, as discussed further below, we disagree with 
commenters that question the necessity of this reform. In addition to 
our findings that this reform will help ensure just and reasonable 
rates, we find that the specific purpose of this reform--to require 
transmission providers to evaluate certain interconnection-related 
transmission needs--is not a requirement of any existing process. 
Additionally, we find that the qualifying criteria established by this 
reform will ensure that the reform avoids placing an onerous burden on 
transmission providers. Finally, we disagree that this reform is overly 
prescriptive; it does not dictate a specific result or require that 
transmission providers select a regional transmission facility to 
address identified interconnection-related transmission needs. This 
reform merely requires consideration of these interconnection-related 
transmission needs in the regional transmission planning process.
4. Commission Determination
    1106. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to revise 
the regional transmission planning processes in their OATTs, consistent 
with the requirements in this final order, to evaluate for selection 
regional transmission facilities that address certain identified 
interconnection-related transmission needs associated with certain 
interconnection-related network upgrades originally identified through 
the generator interconnection process, as more fully described below. 
We find that this requirement will ensure that more efficient or cost-
effective transmission expansion can be effectuated through regional 
transmission planning processes and will eliminate a potential barrier 
to entry for new generation resources, thereby enhancing competition in 
wholesale electricity markets and facilitating access to lower-cost 
generation. As a result, this reform will ensure just and reasonable 
and not unduly discriminatory or preferential Commission-jurisdictional 
rates.
    1107. In this final order, we adopt the NOPR proposal with 
modification. First, we require transmission providers to evaluate for 
selection regional transmission facilities to address certain 
identified interconnection-related transmission needs in their existing 
Order No. 1000 regional transmission planning and cost allocation 
processes, rather than in Long-Term Regional Transmission Planning. 
Second, we modify the NOPR proposal to require that an interconnection-
related network upgrade associated with identified interconnection-
related transmission needs must satisfy both the minimum cost and 
voltage criteria proposed in the NOPR to qualify for evaluation for 
selection.
    1108. In recent years, spending on interconnection-related network 
upgrades has increased dramatically, and the high cost of 
interconnection is increasing the rate at which generators withdraw 
from the interconnection queue.\2368\ While interconnection customers 
may withdraw for multiple reasons, the record in this proceeding shows 
that, in recent years, the deciding factor in many cases of withdrawal 
has become the interconnection customer's cost responsibility for 
expensive interconnection-related network upgrades.\2369\ Consequently, 
interconnection customers are unlikely to resolve these 
interconnection-related transmission needs through the generator 
interconnection process.
---------------------------------------------------------------------------

    \2368\ ACEG 2021 Interconnection Report at 17.
    \2369\ NOPR, 179 FERC ] 61,028 at P 162; DC and Maryland Office 
of People's Counsel Initial Comments at 16; Invenergy Reply Comments 
at 14; Northwest and Intermountain Initial Comments at 14.
---------------------------------------------------------------------------

    1109. Where interconnection-related transmission needs are 
repeatedly

[[Page 49453]]

identified but not constructed, the implication is that, despite the 
potentially prohibitive interconnection costs if borne by one or a 
small number of interconnection customers, there are compelling 
reasons, such as proximity to fuel sources, why generators seek to 
locate a point of interconnection at a specific location or locations 
associated with transmission constraints. When interconnection 
customers that have invested time and resources in engaging in the 
generator interconnection process choose to withdraw rather than fund 
interconnection-related network upgrades, it becomes increasingly 
apparent that interconnection customer(s) are unlikely to resolve 
interconnection-related transmission needs through the generator 
interconnection process.
    1110. At the same time, the Commission has found, and courts have 
affirmed, that interconnection-related network upgrades identified in 
the generator interconnection process can provide widespread 
transmission benefits that extend beyond the interconnection 
customer.\2370\ As a result, planning these types of upgrades to the 
transmission system in a piecemeal fashion, exclusively through the 
generator interconnection process, limits the development of 
transmission facilities that would provide benefits to the transmission 
system beyond those received by the interconnection customer. This is 
the case where interconnection-related network upgrades of substantial 
cost are repeatedly identified to address interconnection-related 
transmission needs, but those needs continue to go unresolved through 
the generator interconnection process. In such cases, it may be more 
efficient or cost-effective to address such needs through the regional 
transmission planning and cost allocation process. Therefore, reforms 
are necessary to require interconnection-related transmission needs 
associated with interconnection-related network upgrades that are 
repeatedly identified in the generator interconnection process to be 
evaluated through the regional transmission planning and cost 
allocation process. We believe that this approach will result in 
selection of more efficient or cost-effective regional transmission 
solutions that will provide benefits to the transmission system, cost 
allocation for such regional transmission facilities that is at least 
roughly commensurate with estimated benefits, and elimination of a 
barrier to entry for new generation resources (which will enhance 
competition in wholesale electricity markets and facilitate access to 
lower-cost generation).\2371\ As a result, these reforms will ensure 
just and reasonable and not unduly discriminatory or preferential 
Commission-jurisdictional rates.
---------------------------------------------------------------------------

    \2370\ See, e.g., Entergy Svs., Inc. v. FERC, 391 F.3d 1240, 
1247-48 (2004); Order No. 2003, 104 FERC ] 61,103 at P 65 (stating 
that ``[f]acilities beyond the Point of Interconnection [(i.e., 
interconnection-related network upgrades)] are part of the 
Transmission Provider's Transmission System and benefit all 
users''); see also ACORE ANOPR Comments, Ex. 5 at 4-7; CAISO ANOPR 
Comments at 53-54 (stating that in CAISO ``transmission facilities 
at 200 kV and above are eligible for regional cost allocation,'' 
including location-constrained resources interconnection facilities, 
because ``this voltage threshold . . . recognizes that high voltage 
transmission facilities support and provide benefits to all 
customers to the CAISO grid'').
    \2371\ While in this portion of the final order we discuss the 
requirement that transmission providers evaluate in their existing 
regional transmission planning and cost allocation processes 
regional transmission facilities that address certain 
interconnection-related needs, we also expect that many of the other 
reforms in this final order regarding Long-Term Regional 
Transmission Planning will address the difficulties generators face 
in interconnecting to the transmission system and the cost 
allocation mismatch described here, including required Factor 
Category Six, interconnection requests and withdrawals.
---------------------------------------------------------------------------

    1111. While we require transmission providers to evaluate regional 
transmission facilities that address certain interconnection-related 
transmission needs identified by this reform in the existing Order No. 
1000 regional transmission planning and cost allocation processes, we 
allow for flexibility in how transmission providers evaluate such 
facilities for selection. Transmission providers may adopt the 
evaluation method and selection criteria from any of their existing 
Order No. 1000 regional transmission planning and cost allocation 
processes (e.g., economic or reliability processes) to evaluate and 
potentially select these types of transmission facilities. By not 
requiring a specific process, we permit transmission providers to 
propose the best method to incorporate this requirement within their 
existing regional transmission planning processes. We also encourage 
transmission providers to consider, as part of the evaluation process, 
whether regional transmission facilities that address certain 
identified interconnection-related transmission needs may also address 
other regional transmission needs more efficiently or cost-effectively.
    1112. Several commenters suggest alternative reforms to coordinate 
or consolidate regional transmission planning and generator 
interconnection processes or to modify existing cost allocation 
criteria.\2372\ We find these requests to be outside the scope of this 
proceeding and lacking in record support to adequately consider whether 
to adopt them in this final order. In this final order, we are 
addressing the narrow issue of interconnection-related transmission 
needs being repeatedly identified yet continuing to go unresolved 
through the generator interconnection process, even though it may be 
more efficient and cost-effective to evaluate such needs through the 
regional transmission planning and cost allocation process.
---------------------------------------------------------------------------

    \2372\ E.g., Enel Initial Comments at 4-5.
---------------------------------------------------------------------------

    1113. We find uncompelling general arguments from commenters that 
oppose the Commission's proposal because the reform addresses a 
deficiency in existing regional transmission planning and cost 
allocation processes, will ensure just and reasonable and not unduly 
discriminatory or preferential Commission-jurisdictional rates, is not 
unduly burdensome, and does not dictate a particular outcome. The level 
of prescriptiveness of this reform strikes the right balance between an 
open-ended requirement, which might not address the need for reform, 
and a very prescriptive requirement that could be overly burdensome to 
transmission providers.
    1114. We are unpersuaded by Ameren's argument that this reform will 
result in inefficient regional transmission planning because it will 
not minimize the total cost to end-use customers.\2373\ As explained 
above, this reform will enable transmission providers to identify 
through regional transmission planning the more efficient or cost-
effective transmission solution to address an interconnection-related 
transmission need.
---------------------------------------------------------------------------

    \2373\ Ameren Initial Comments at 18.
---------------------------------------------------------------------------

    1115. We clarify in response to Vistra that transmission providers 
must make the newly created interconnection capacity equally available 
to all interconnection and transmission customers consistent with the 
Commission's open access policy.\2374\ Any interconnection customers 
whose interconnection requests related to the initial identification of 
the interconnection-related transmission need would not have any 
priority rights to that newly created interconnection or transmission 
capacity. Additionally, we clarify, in response to NRECA's request, 
that we are not requiring interconnection-related network upgrades 
associated with withdrawn interconnection requests to be given

[[Page 49454]]

preferential treatment in regional transmission planning.\2375\
---------------------------------------------------------------------------

    \2374\ Vistra Initial Comments at 33-34.
    \2375\ NRECA Reply Comments at 10-11.
---------------------------------------------------------------------------

    1116. In response to commenters arguing that it is incorrect to 
assume that interconnection customers withdraw from the interconnection 
queue due solely to high interconnection-related network upgrade 
costs,\2376\ we explain that we are not requiring transmission 
providers to evaluate regional transmission facilities that address 
interconnection-related transmission needs for every withdrawn 
interconnection request. Instead, this reform is focused only on 
certain interconnection-related transmission needs that meet the 
specific qualifying criteria detailed below. We do not assume that 
where these criteria are met, the relevant interconnection customers 
have necessarily withdrawn from the interconnection queue solely due to 
high interconnection-related network upgrade costs. Rather, we 
determine that these criteria only suggest that high costs were likely 
a factor prompting, or at least contributing to, the relevant 
withdrawals. We conclude that where the criteria are met, there may be 
an opportunity for a more efficient or cost-effective regional 
transmission solution, such that an evaluation of the relevant 
interconnection-related transmission need(s) is appropriate.
---------------------------------------------------------------------------

    \2376\ CAISO Reply Comments at 29; NRECA Reply Comments at 9; 
PJM Initial Comments at 87.
---------------------------------------------------------------------------

    1117. We are not persuaded to reject this reform based on 
commenters' assertions that this reform will shift the costs of 
interconnection-related network upgrades from interconnection customers 
to load.\2377\ This final order requires transmission providers to 
evaluate in their existing Order No. 1000 regional transmission 
planning and cost allocation processes regional transmission facilities 
that address certain identified interconnection-related transmission 
needs associated with certain interconnection-related network upgrades 
originally identified through the generator interconnection process. 
Transmission providers will still have to evaluate and select any 
regional transmission facilities that address the interconnection-
related transmission needs as the more efficient or cost-effective 
regional transmission solution as part of the regional transmission 
planning process in order for any regional cost allocation method to 
apply, and this final order does not alter the existing cost allocation 
methods in either the generator interconnection or existing Order No. 
1000 regional transmission planning process. If a regional transmission 
facility that addresses identified interconnection-related transmission 
needs is not selected as part of the regional transmission planning 
process, then the associated regional cost allocation method would not 
apply; however, if the facility is selected, then the regional 
transmission planning process has determined that the regional 
transmission facility is a more efficient or cost-effective regional 
transmission solution. Additionally, if such a facility is selected, 
the Commission-approved ex ante regional cost allocation method for 
that facility would allocate its costs at least roughly commensurate 
with its estimated benefits.
---------------------------------------------------------------------------

    \2377\ APPA Initial Comments at 31; Industrial Customers Initial 
Comments at 13; NRECA Initial Comments at 41-42 (citation omitted); 
NRECA Reply Comments at 8-9; PJM Initial Comments at 89-90; Vistra 
Initial Comments at 8; Xcel Initial Comments at 15.
---------------------------------------------------------------------------

    1118. In response to TAPS' request that the Commission clarify that 
regions may propose differing cost allocation methods for transmission 
facilities selected to address interconnection-related transmission 
needs versus transmission facilities selected to address other types of 
transmission needs,\2378\ we clarify that the requirements adopted here 
merely create an obligation for transmission providers to evaluate 
regional transmission facilities that address certain identified 
interconnection-related transmission needs in the existing regional 
transmission planning and cost allocation processes. As such, to the 
extent that transmission providers wish to propose further changes to 
their Order No. 1000 regional transmission planning cost allocation 
method(s) because of this requirement, they would need to do so in 
separate FPA section 205 filings rather than on compliance with this 
final order.
---------------------------------------------------------------------------

    \2378\ TAPS Initial Comments at 13-14.
---------------------------------------------------------------------------

    1119. We disagree with commenters that the requirements adopted 
herein will incentivize gaming by interconnection customers to include 
interconnection-related network upgrades in the regional transmission 
planning process.\2379\ We also disagree with commenters that claim 
that interconnection customers will submit spurious interconnection 
requests.\2380\ Interconnection requests require significant financial 
commitments from the interconnection customer (e.g., application fees, 
study deposits, and site control requirements), which the Commission 
made more stringent in Order No. 2023,\2381\ and therefore we find it 
unlikely that an interconnection customer would submit multiple 
interconnection requests (in multiple queue cycles) in order to trigger 
this requirement because of the possibility that transmission providers 
may eventually develop an interconnection-related network upgrade by 
selecting it in a regional transmission plan for purposes of cost 
allocation. An interconnection customer would face several risks in 
pursuing such a strategy, including the risk that the regional 
transmission solution for the interconnection-related transmission need 
is not selected, and the risk that the newly created interconnection or 
transmission capacity is allocated to a different transmission or 
interconnection customer. For these reasons, we decline to adopt 
Invenergy's request to modify the proposal to require that withdrawn 
interconnection requests must have been submitted by unaffiliated 
entities.\2382\
---------------------------------------------------------------------------

    \2379\ Ameren Initial Comments at 18-19; American Municipal 
Power Initial Comments at 34; Dominion Initial Comments at 32; 
Dominion Reply Comments at 7-8; EEI Initial Comments at 18; 
Eversource Initial Comments at 23-24; Idaho Power Initial Comments 
at 6; Pennsylvania Commission Initial Comments at 9; PJM Initial 
Comments at 89; PPL Initial Comments at 12-13; Shell Initial 
Comments at 29-30; SPP Initial Comments at 16; Xcel Initial Comments 
at 16.
    \2380\ Ameren Initial Comments at 18; American Municipal Power 
Initial Comments at 33-34; EEI Initial Comments at 18; Idaho Power 
Initial Comments at 6; PJM Initial Comments at 89.
    \2381\ See, e.g., Order No. 2023, 184 FERC ] 61,054 at P 502.
    \2382\ Invenergy Reply Comments at 14-15.
---------------------------------------------------------------------------

    1120. In response to Eversource's request that the Commission 
clarify that submitting and withdrawing interconnection requests with 
the intent of requiring transmission providers to evaluate the 
associated interconnection-related transmission needs in their regional 
transmission planning process is in violation of the Commission's 
regulations, including but not limited to the duty of candor and 
prohibition of market manipulation,\2383\ as noted above, the generator 
interconnection process requires significant financial commitments for 
interconnection requests to enter and proceed in the queue, and many 
transmission providers have imposed additional readiness requirements 
to encourage early withdrawal of non-viable interconnection requests. 
For these reasons, we disagree with the gaming concerns raised by 
Eversource.\2384\
---------------------------------------------------------------------------

    \2383\ Eversource Initial Comments at 23-24 (citing 18 CFR 
35.41; 18 CFR 1c.2).
    \2384\ While we are not concerned about gaming here, to the 
extent that there is evidence of a false representation or gaming of 
the market rules, a referral to the Office of Enforcement may be 
appropriate to determine whether a violation of the Commission's 
regulations has occurred.

---------------------------------------------------------------------------

[[Page 49455]]

    1121. We also grant SEIA's request to clarify that the phrase 
``interconnection-related transmission needs'' allows transmission 
providers to identify individual regional transmission solutions to 
address each identified interconnection-related transmission need, or 
an aggregate regional transmission solution to address multiple 
interconnection-related transmission needs. In response to commenters 
arguing that the reforms issued under Order No. 2023 will address 
interconnection-related issues more appropriately than the NOPR 
proposal,\2385\ we explain that the reforms in this rulemaking are 
intended to address situations when interconnection-related network 
upgrades are repeatedly identified but not constructed and instances 
when regional transmission solutions to address the needs that would 
have been addressed by those interconnection-related network upgrades 
would provide widespread transmission benefits that extend beyond the 
interconnection customer, which are not addressed in Order No. 2023.
---------------------------------------------------------------------------

    \2385\ Dominion Reply Comments at 8; Idaho Power Initial 
Comments at 6-7; Illinois Commission Initial Comments at 8; Pacific 
Northwest Utilities Initial Comments at 15.
---------------------------------------------------------------------------

B. Transmission Planning Process Evaluation

1. NOPR Proposal
    1122. In the NOPR, the Commission proposed to require the 
transmission providers in each transmission planning region to consider 
regional transmission facilities that address interconnection-related 
transmission needs pursuant to the proposed coordination reform through 
the Long-Term Regional Transmission Planning process proposed in the 
NOPR. Specifically, the Commission proposed to require that 
transmission providers in each transmission planning region incorporate 
the specific interconnection-related transmission needs identified 
through the coordination reform as a factor used to develop Long-Term 
Scenarios in the Long-Term Regional Transmission Planning proposed in 
the NOPR.\2386\
---------------------------------------------------------------------------

    \2386\ NOPR, 179 FERC ] 61,028 at P 167.
---------------------------------------------------------------------------

2. Comments
    1123. Several commenters assert that the NOPR proposal is 
unnecessary because well-executed Long-Term Regional Transmission 
Planning will identify the transmission needed to support 
interconnections.\2387\ For example, Xcel argues that Long-Term 
Scenarios will be driven by the same factors that cause interconnection 
customers to make interconnection requests, such as optimal geographic 
locations for generation development.\2388\ Similarly, EEI states that 
Long-Term Regional Transmission Planning, if properly implemented, 
already takes into account factors that support generator 
interconnection.\2389\
---------------------------------------------------------------------------

    \2387\ AEP Initial Comments at 19; EEI Initial Comments at 18; 
ENGIE Initial Comments at 5; Illinois Commission Initial Comments at 
8-9; Vistra Initial Comments at 33; Xcel Initial Comments at 15.
    \2388\ Xcel Initial Comments at 15.
    \2389\ EEI Initial Comments at 18.
---------------------------------------------------------------------------

    1124. Some of these commenters further claim that the Commission's 
coordination proposal's reliance on backward-looking interconnection 
needs would be less effective than planning on future system 
interconnection needs. CAISO argues that the Commission's proposal is 
backward-looking and therefore will not promote productive, forward-
looking transmission planning.\2390\ Vistra claims that an effective 
transmission planning process will identify interconnection needs and 
provide solutions within the context of a future system, rather than 
relying on prior interconnection studies addressing a specific 
generator interconnection request.\2391\ Similarly, ISO/RTO Council 
recommends that the Commission direct transmission planners to consider 
generator interconnection as a driver of Long-Term Transmission Needs 
on a forward-looking basis, rather than the coordination proposal's 
backwards-looking process.\2392\
---------------------------------------------------------------------------

    \2390\ CAISO Initial Comments at 6, 34-35.
    \2391\ Vistra Initial Comments at 33.
    \2392\ ISO/RTO Council Initial Comments at 9.
---------------------------------------------------------------------------

    1125. MISO states that because the generator interconnection 
process is designed to identify the minimum amount of interconnection-
related network upgrades to interconnect new resources, Long-Term 
Regional Transmission Planning is the proper avenue to holistically 
evaluate system needs. MISO notes that it already has a mechanism in 
place to include interconnection-related network upgrades in its Long-
Range Transmission Plan process if the interconnection-related network 
upgrade is found to have region-wide benefits.\2393\
---------------------------------------------------------------------------

    \2393\ MISO Initial Comments at 44, 46-47; MISO Reply Comments 
at 29.
---------------------------------------------------------------------------

3. Commission Determination
    1126. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to evaluate 
regional transmission facilities that address certain interconnection-
related transmission needs in their existing Order No. 1000 regional 
transmission planning and cost allocation processes instead of in Long-
Term Regional Transmission Planning. We find that this modification 
will better alleviate transmission limitations by providing a starting 
point for identifying and evaluating regional transmission solutions 
that are more efficient or cost-effective when analyzed in the near 
term.\2394\ Specifically, requiring transmission providers to evaluate 
identified interconnection-related transmission needs in existing Order 
No. 1000 regional transmission planning and cost allocation processes 
will allow such needs to be addressed within a timeframe that is 
relevant for identifying more efficient or cost-effective near-term 
regional transmission solutions. Evaluation of interconnection-related 
transmission needs in the existing Order No. 1000 regional transmission 
planning and cost allocation processes is most appropriate because such 
evaluation would occur at shorter intervals and would likely result in 
more expeditious development of regional transmission facilities to 
address the nearer-term interconnection-related transmission needs 
identified through the generator interconnection process.
---------------------------------------------------------------------------

    \2394\ See NOPR, 179 FERC ] 61,028 at P 165.
---------------------------------------------------------------------------

    1127. We agree with commenters that future interconnection-related 
transmission needs will be considered as part of Long-Term Regional 
Transmission Planning and incorporated in the development of Long-Term 
Scenarios. Nonetheless, for the reasons described above, we find that 
current interconnection-related transmission needs can be considered 
more effectively through the nearer-term existing Order No. 1000 
regional transmission planning and cost allocation processes. As such, 
we disagree with commenters that assert that the Commission's proposal 
is unnecessary because well-executed Long-Term Regional Transmission 
Planning will identify the transmission needed to support generator 
interconnections.\2395\ That said, we emphasize that, as transmission 
providers gain experience with Long-Term Regional Transmission 
Planning, we anticipate that they will identify

[[Page 49456]]

fewer interconnection-related transmission needs associated with 
certain interconnection-related network upgrades originally identified 
through the generator interconnection process because transmission 
providers will plan to address Long-Term Transmission Needs, including 
those driven by Factor Category One: Federal, federally-recognized 
Tribal, state, and local laws and regulations that affect the future 
resource mix and demand; Factor Category Two: Federal, federally-
recognized Tribal, state, and local laws and regulations on 
decarbonization and electrification; Factor Category Six: generator 
interconnection requests and withdrawals, and Factory Category Seven: 
utility and corporate commitments and Federal, federally-recognized 
Tribal, state, and local policy goals that affect Long-Term 
Transmission Needs, through Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------

    \2395\ AEP Initial Comments at 18-19; EEI Initial Comments at 
18; ENGIE Initial Comments at 5; Illinois Commission Initial 
Comments at 8-9; Vistra Initial Comments at 33; Xcel Initial 
Comments at 15.
---------------------------------------------------------------------------

    1128. Some commenters, including Vistra and ISO/RTO Council, claim 
that the NOPR proposal to rely on needs identified in prior 
interconnection studies would be less effective at planning for 
interconnection-related transmission needs compared to more future-
oriented approaches. We agree that an effective regional transmission 
planning process will identify interconnection-related transmission 
needs and evaluate regional transmission solutions to those needs 
within the context of a future system. We further agree that 
transmission providers should consider generator interconnection as a 
driver of Long-Term Transmission Needs on a forward-looking basis. For 
these reasons, we require transmission providers to incorporate seven 
specific categories of factors in their development of Long-Term 
Scenarios used in Long-Term Regional Transmission Planning, including 
Factory Category Six: generator interconnection requests and 
withdrawals. However, we disagree that the coordination proposal should 
not rely on past results from the generator interconnection process or 
specific interconnection requests in determining what interconnection-
related transmission needs should be evaluated in the existing Order 
No. 1000 regional transmission planning and cost allocation processes. 
Interconnection-related network upgrades repeatedly identified in past 
interconnection studies are strongly indicative that a location 
(despite presenting potentially prohibitive interconnection costs if 
borne by one or a small number of interconnection customers) is 
otherwise valuable for location of new generation.
    1129. Finally, because we are modifying the NOPR proposal to no 
longer apply to Long-Term Regional Transmission Planning, commenters' 
specific concerns that this proposal is duplicative to the categories 
of factors requirements in the development of Long-Term Scenarios are 
moot.

C. Qualifying Criteria

1. NOPR Proposal
    1130. In the NOPR, the Commission proposed to require that 
transmission providers evaluate for selection regional transmission 
facilities to address interconnection-related transmission needs that 
have been identified in the generator interconnection process as 
requiring interconnection-related network upgrades where: (1) the 
transmission provider has identified interconnection-related network 
upgrades in interconnection studies to address those interconnection-
related transmission needs in at least two interconnection queue cycles 
during the preceding five years (beginning at the time of the 
withdrawal of the first underlying interconnection request); (2) the 
interconnection-related network upgrade identified to meet those 
interconnection-related transmission needs has a voltage of at least 
200 kV and/or an estimated cost of at least $30 million; (3) those 
interconnection-related network upgrades have not been developed and 
are not currently planned to be developed because the interconnection 
request(s) driving the need for the upgrade has been withdrawn; and (4) 
the transmission provider has not identified an interconnection-related 
network upgrade to address the relevant interconnection-related 
transmission need in an executed generator interconnection agreement or 
in a generator interconnection agreement that the interconnection 
customer requested that the transmission provider file unexecuted with 
the Commission.\2396\
---------------------------------------------------------------------------

    \2396\ NOPR, 179 FERC ] 61,028 at P 166.
---------------------------------------------------------------------------

    1131. The Commission proposed that the initial five-year time 
period begin five calendar years prior to the initial effective date of 
the Commission-accepted tariff provisions proposed to comply with this 
reform such that, upon the Commission's acceptance of such tariff 
provisions, the transmission provider would consider interconnection-
related network upgrades identified to address the same 
interconnection-related transmission need in at least two 
interconnection queue cycles in the five calendar years prior to the 
effective date established in the order accepting those tariff 
revisions.\2397\ The Commission also proposed to require that 
transmission providers in each transmission planning region consider 
whether the interconnection-related transmission need for which the 
transmission provider identified the interconnection-related network 
upgrade is the same in multiple interconnection queue cycles.\2398\ 
That is, if an interconnection-related transmission need is driving the 
identification of an interconnection-related network upgrade on the 
transmission system in one interconnection queue cycle and an 
interconnection-related network upgrade with, for example, a different 
voltage, starting point, or ending point is identified in the next 
interconnection queue cycle to address the same interconnection-related 
transmission need, then the first criterion of the proposed 
coordination reform would be satisfied.\2399\ The Commission stated 
that it believes that this approach will appropriately account for 
differences in technology, study assumptions, system topology, and/or 
interconnection requests that may occur over time that may result in 
different interconnection-related network upgrades to address the same 
interconnection-related need.\2400\
---------------------------------------------------------------------------

    \2397\ Id. P 170.
    \2398\ Id. P 171.
    \2399\ Id.
    \2400\ Id.
---------------------------------------------------------------------------

    1132. The Commission stated that it believes that the proposed 
criteria the transmission provider must use to identify the 
interconnection-related transmission needs that should be considered in 
the regional transmission planning process will help to ensure that the 
associated interconnection-related network upgrades are likely to have 
produced benefits beyond those provided to the interconnection 
customers whose interconnection requests the interconnection-related 
network upgrades are needed to accommodate.\2401\
---------------------------------------------------------------------------

    \2401\ Id. P 168.
---------------------------------------------------------------------------

    1133. To avoid shifting costs inappropriately from generators in 
the generator interconnection process to transmission customers through 
the regional transmission planning process, the Commission further 
proposed to limit the scope of interconnection-related transmission 
needs to be considered in the regional transmission planning process to 
those interconnection-related transmission needs not addressed by 
interconnection-related network upgrades memorialized in an executed 
generator

[[Page 49457]]

interconnection agreement (or in a generator interconnection agreement 
that the interconnection customer requested to be filed unexecuted with 
the Commission).\2402\
---------------------------------------------------------------------------

    \2402\ Id. P 173.
---------------------------------------------------------------------------

2. Comments
    1134. Multiple commenters generally support the NOPR proposal but 
express concerns about the eligibility criteria proposed in the NOPR 
and request modification.\2403\ SDG&E states that the criteria defined 
in the NOPR strike an appropriate balance to cover many situations in 
which generation is needed, while also protecting ratepayers from 
unnecessary costs.\2404\
---------------------------------------------------------------------------

    \2403\ NARUC Initial Comments at 19-20; Pattern Energy Initial 
Comments at 28; Pine Gate Initial Comments 31-33; SEIA Initial 
Comments at 14-15; Shell Initial Comments at 30; TAPS Initial 
Comments at 13; US DOE Initial Comments at 28.
    \2404\ SDG&E Initial Comments at 3.
---------------------------------------------------------------------------

    1135. Avangrid argues that, while the NOPR proposal has merit, the 
Commission should allow transmission providers to determine the most 
appropriate thresholds.\2405\ SEIA asks the Commission to allow each 
transmission planning region to determine its own threshold, which may 
include lower voltage lines and substations.\2406\ Indicated PJM TOs 
further argue that the proposed criteria may not be appropriate in all 
transmission planning regions.\2407\
---------------------------------------------------------------------------

    \2405\ Avangrid Initial Comments at 12.
    \2406\ SEIA Initial Comments at 15.
    \2407\ Indicated PJM TOs Initial Comments at 15-16.
---------------------------------------------------------------------------

    1136. MISO argues that transmission planning regions should be able 
to develop their own cost and voltage criteria. MISO explains that it 
may be difficult to implement the requirement that interconnection-
related network upgrades that qualify must ``not currently be planned 
to be developed'' in the interconnection process because in MISO's 
experience interconnection-related network upgrades shift from queue 
cycle to queue cycle as withdrawals occur, and as a result MISO 
suggests deleting this requirement. MISO opposes the requirement to 
identify any interconnection-related network upgrade that is identified 
in multiple generator interconnection studies as it would require the 
review and comparison of numerous studies to comply with no increased 
benefit.\2408\
---------------------------------------------------------------------------

    \2408\ MISO Initial Comments at 45-46.
---------------------------------------------------------------------------

    1137. Multiple commenters that generally support the NOPR proposal 
suggest modification to the NOPR's proposed cost and voltage 
eligibility criteria. Pattern Energy suggests that the Commission 
should allow consideration of interconnection-related network upgrades 
that would meet either a voltage or a cost threshold because, for 
example, lower voltage lines that cost more than $30 million can often 
satisfy an interconnection need.\2409\ Pattern Energy and Pine Gate 
argue that the Commission should lower the voltage threshold to 100 
kV.\2410\ Shell asks the Commission to lower the 200 kV threshold to 
115 kV or to remove it entirely in favor of a cost threshold that is 
updated regularly based on inflation or some other Commission-approved 
indicator.\2411\
---------------------------------------------------------------------------

    \2409\ Pattern Energy Initial Comments at 28.
    \2410\ Pattern Energy Initial Comments at 28; Pine Gate Initial 
Comments at 32.
    \2411\ Shell Initial Comments at 30.
---------------------------------------------------------------------------

    1138. Pine Gate argues that the Commission should reduce the cost 
threshold to $10 million.\2412\ SEIA argues that the cost threshold 
should be replaced with a $100,000/MW threshold.\2413\ US DOE argues 
that a $30 million cost threshold may not be appropriate because some 
interconnection-related network upgrades that meet this eligibility 
factor may only benefit a limited number of interconnection customers. 
As an alternative, US DOE adds that the Commission should consider 
interconnection-related network upgrades ``that would provide benefits 
beyond the local interconnection level or that would improve 
interconnection efficiencies across a wider geographic area and not 
substations, voltage support devices, or other local connection 
upgrades.'' \2414\
---------------------------------------------------------------------------

    \2412\ Pine Gate Initial Comments at 32.
    \2413\ SEIA Initial Comments at 15.
    \2414\ US DOE Initial Comments at 28.
---------------------------------------------------------------------------

    1139. Dominion states that the relatively low voltage and cost 
thresholds in the Commission's proposal invites interconnection 
customers to seek bigger investments than needed or select a location 
that increases the cost of interconnection.\2415\ Dominion further 
argues that the number, size, or frequency of interconnection requests 
should not be used as a basis for planning transmission projects, 
because the process could be subject to gaming, where speculative 
interconnection requests could result in transmission buildouts and 
spending that are not justified by actual grid needs or 
economics.\2416\
---------------------------------------------------------------------------

    \2415\ Dominion Initial Comments at 32.
    \2416\ Dominion Reply Comments at 7-8.
---------------------------------------------------------------------------

    1140. Some commenters take issue with the NOPR's proposed criteria. 
Indicated PJM TOs argue that there is no record evidence to support the 
proposed 200 kV and $30 million cost threshold criteria.\2417\ PJM 
states that few interconnection studies have identified the need for 
interconnection-related network upgrades in excess of $30 
million.\2418\ Illinois Commission contends that many projects in the 
interconnection queue are associated with interconnection-related 
network upgrades that meet the repeatedly-identified and 200 kV 
thresholds and that simply folding interconnection costs into 
transmission planning may expedite the queue at the expense of 
efficiency and cost-effectiveness.\2419\ Indicated PJM TOs argue that 
limiting consideration to only generating facilities that have not yet 
signed (or had filed) an interconnection agreement will result in 
studying only uneconomic projects, which would run afoul of the cost 
causation principle.\2420\
---------------------------------------------------------------------------

    \2417\ Indicated PJM TOs Initial Comments at 15.
    \2418\ PJM Initial Comments at 88.
    \2419\ Illinois Commission Initial Comments at 8-9.
    \2420\ Indicated PJM TOs Initial Comments at 16.
---------------------------------------------------------------------------

    1141. Interwest argues that the Commission should not require the 
identification of the interconnection-related network upgrade in two 
queue cycles over the five-year lookback period because such a 
requirement would limit the number of identified interconnection-
related network upgrades that would trigger this newly proposed 
process.\2421\ Pine Gate states that the Commission's look-back period 
should be at least the two immediately preceding interconnection queue 
cycles, or, where serial studies have been performed, during the 
preceding five years beginning at the time of the withdrawal of the 
first underlying interconnection request.\2422\ Pine Gate argues that 
this revision will ensure that study results will be available for use 
in identifying interconnection-related network upgrades to 
evaluate.\2423\ SEIA argues that once a transmission provider 
identifies the same interconnection-related network upgrade in two 
interconnection cycles, that line should be included in the next Long-
Term Regional Transmission Planning update cycle even if five years 
have not passed since initial identification.\2424\ Pattern Energy 
supports SEIA's requests.\2425\
---------------------------------------------------------------------------

    \2421\ Interwest Initial Comments at 3, 11.
    \2422\ Pine Gate Initial Comments at 31.
    \2423\ Id.
    \2424\ SEIA Initial Comments at 15.
    \2425\ Pattern Energy Reply Comments at 10-11.
---------------------------------------------------------------------------

    1142. EEI and Eversource are unsure of the stage of the generator 
interconnection process at which a project would meet the proposed 
criteria.\2426\ Eversource requests that the

[[Page 49458]]

Commission require transmission providers to specify the stage in the 
interconnection process that an interconnection-related network upgrade 
is identified.\2427\
---------------------------------------------------------------------------

    \2426\ EEI Initial Comments at 17-18; Eversource Initial 
Comments at 24.
    \2427\ Eversource Initial Comments at 24.
---------------------------------------------------------------------------

    1143. Pine Gate asks the Commission to combine the third and fourth 
criteria into one criterion: those interconnection-related network 
upgrades that are not developed or in development and not currently 
committed to be built under an interconnection service agreement or any 
related construction agreement.\2428\
---------------------------------------------------------------------------

    \2428\ Pine Gate Initial Comments at 32-33.
---------------------------------------------------------------------------

    1144. Some commenters argue that the Commission's proposed criteria 
create too simplistic of a method for determining which 
interconnection-related network upgrades should be evaluated in Long-
Term Regional Transmission Planning.\2429\ Pennsylvania Commission 
argues that, without a rigorous examination of why an interconnection 
application failed, there is no proof that there exists a need for 
building interconnection-related network upgrades as part of Long-Term 
Regional Transmission Planning.\2430\ NARUC argues that the meaning of 
the term ``multiple times'' should be informed by a process that also 
examines the reasons why the previous interconnection requests were 
withdrawn, including generation developer land acquisition decisions or 
the identification of more economic transmission design 
alternatives.\2431\ Vistra takes issue with the fact that the 
Commission does not distinguish between situations when developers 
simply sought to develop in an uneconomic area versus when a more 
efficient or cost-effective transmission project would have been 
identified as part of the regional transmission planning process.\2432\
---------------------------------------------------------------------------

    \2429\ NARUC Initial Comments at 19; Pennsylvania Commission 
Initial Comments at 8; Vistra Initial Comments at 20.
    \2430\ Pennsylvania Commission Initial Comments at 8.
    \2431\ NARUC Initial Comments at 19.
    \2432\ Vistra Initial Comments at 20.
---------------------------------------------------------------------------

3. Commission Determination
    1145. We adopt the NOPR proposal, with modification, to require 
that, for a regional transmission facility to address an 
interconnection-related transmission need to qualify for evaluation 
through the regional transmission planning process for selection under 
this reform, any interconnection-related network upgrade identified to 
meet that interconnection-related transmission need must meet both the 
proposed voltage and cost criteria. Thus, we require transmission 
providers to evaluate for selection in their existing Order No 1000 
regional transmission planning processes regional transmission 
facilities to address interconnection-related transmission needs that 
have been identified in the generator interconnection process as 
requiring interconnection-related network upgrades where: (1) the 
transmission provider has identified interconnection-related network 
upgrades in interconnection studies to address those interconnection-
related transmission needs in at least two interconnection queue cycles 
during the preceding five years (looking back from the effective date 
of the Commission-accepted tariff provisions proposed to comply with 
this reform, and the later-in-time withdrawn interconnection request 
occurring after the effective date of the Commission-accepted tariff 
provisions); (2) an interconnection-related network upgrade identified 
to meet those interconnection-related transmission needs has a voltage 
of at least 200 kV and an estimated cost of at least $30 million; (3) 
such interconnection-related network upgrade(s) have not been developed 
and are not currently planned to be developed because the 
interconnection request(s) driving the need for the network upgrade(s) 
has been withdrawn; and (4) the transmission provider has not 
identified an interconnection-related network upgrade to address the 
relevant interconnection-related transmission need in an executed 
generator interconnection agreement or in a generator interconnection 
agreement that the interconnection customer requested that the 
transmission provider file unexecuted with the Commission.
    1146. We find it necessary to establish these criteria to limit the 
scope of the requirement for transmission providers to evaluate 
regional transmission facilities to address interconnection-related 
transmission needs in their regional transmission planning processes to 
those interconnection-related transmission needs that are likely to 
persist, are not unique to a single interconnection request, and might 
be addressed by regional transmission facilities that have the 
potential to provide more widespread benefits to transmission 
customers. We find that each of the four criteria are necessary to 
identify the appropriate set of interconnection-related transmission 
needs. Moreover, we find that the modification to require that an 
interconnection-related network upgrade identified to meet an 
interconnection-related transmission need must satisfy both the voltage 
and cost thresholds better limits the scope of this reform by ensuring 
that any regional transmission facilities evaluated to address such 
interconnection-related transmission needs are more likely to provide 
widespread benefits to transmission customers.\2433\
---------------------------------------------------------------------------

    \2433\ The Commission has previously found that network upgrades 
can benefit all transmission customers. See Order No. 2003, 104 FERC 
] 61,103 at PP 21, 65 (stating ``[m]ost improvements to the 
Transmission System, including Network Upgrades, benefit all 
transmission customers'' and ``the definition of Network Upgrade 
[includes] the phrase `at or beyond the Point of Interconnection,' . 
. . [f]acilities beyond the Point of Interconnection are part of the 
Transmission Provider's Transmission System and benefit all 
users''); Order No. 2003-A, 106 FERC ] 61,220 at P 584 (citing 
Entergy Servs., Inc. v. FERC, 319 F.3d 536, 543-544 (D.C. Cir. 
2003)). The Commission has also previously found, and the record 
demonstrates, that higher-voltage transmission facilities are more 
likely to provide widespread benefits to transmission customers. See 
NOPR, 179 FERC ] 61,028 at PP 32 (citing Order No. 1000, 136 FERC ] 
61,051 at P 486), 168; Sw. Power Pool, Inc., 131 FERC ] 61,252, at P 
73 (2010); Midwest Indep. Trans. Sys. Operator, Inc., 129 FERC ] 
61,060, at P 8 (2009). See also, e.g., CAISO ANOPR Comments at 54; 
Invenergy Initial Comments at 14; Southeast PIOs Initial Comments at 
24.
---------------------------------------------------------------------------

    1147. We further find that these criteria strike a reasonable 
balance between precision and workability. Our reforms here are 
intended to ensure that transmission providers must identify 
interconnection-related transmission needs for evaluation in their 
regional transmission planning processes that are likely to persist, 
are not unique to a single interconnection request, and might be 
addressed by regional transmission facilities that have the potential 
to provide more widespread benefits to transmission customers. 
Requiring in-depth qualitative analysis of individual interconnection 
requests, including consideration of why they were withdrawn, as some 
commenters suggest, would undermine these goals. Furthermore, these 
criteria simply determine whether transmission providers must evaluate 
regional transmission facilities to address any given interconnection-
related transmission need for potential selection; transmission 
providers may still separately assess whether any particular regional 
transmission facility qualifies for selection in the relevant existing 
regional transmission planning process(es). Therefore, we disagree with 
commenters that argue that the proposed criteria create too simplistic 
a method for determining which interconnection-related transmission 
needs should be evaluated in regional

[[Page 49459]]

transmission planning and cost allocation processes.\2434\
---------------------------------------------------------------------------

    \2434\ See NARUC Initial Comments at 19; Pennsylvania Commission 
Initial Comments at 8; Vistra Initial Comments at 20.
---------------------------------------------------------------------------

    1148. We decline to allow transmission providers to determine 
appropriate qualifying criteria,\2435\ because the record supports our 
adoption of the qualifying criteria established by this order. As 
described directly above, we find that these specific criteria ensure 
that the interconnection-related transmission needs that we require 
transmission providers to evaluate through their regional transmission 
planning processes are likely to persist, are not unique to a single 
interconnection request, and might be addressed by regional 
transmission facilities that have the potential to provide more 
widespread benefits to transmission customers. Furthermore, 
transmission providers retain the flexibility to determine whether to 
select a regional transmission facility, and these criteria will simply 
determine whether transmission providers, pursuant to this final order, 
must evaluate interconnection-related transmission needs in the Order 
No. 1000 regional transmission planning and cost allocation processes.
---------------------------------------------------------------------------

    \2435\ See Avangrid Initial Comments at 12; MISO Initial 
Comments at 45-46; SEIA Initial Comments at 15.
---------------------------------------------------------------------------

    1149. We also disagree with Indicated PJM TOs' argument that the 
proposed criteria may not be appropriate in all transmission planning 
regions because of the differences in scales, topology, and 
economics.\2436\ While each transmission planning region is unique, we 
find that the criteria that we establish here are broad enough to 
capture interconnection-related network upgrades that are likely to 
produce benefits beyond the interconnection customer across 
transmission planning regions despite their differences. Furthermore, 
as stated above, transmission providers in each transmission planning 
region retain the flexibility to select regional transmission 
facilities, and the criteria that we adopt here do not mandate that the 
transmission providers in any transmission planning region select any 
particular regional transmission facilities to address interconnection-
related transmission needs.
---------------------------------------------------------------------------

    \2436\ See Indicated PJM TOs Initial Comments at 15-16.
---------------------------------------------------------------------------

    1150. Additionally, we find that the qualifying criteria that we 
establish here that an interconnection-related need must be repeated 
twice and meet both voltage and cost thresholds are just and 
reasonable. We disagree with commenters that argue for the adoption of 
different criteria or for the elimination of one or both 
criteria.\2437\ We find that the purpose of the criteria established 
here is precisely to limit the number of interconnection-related 
transmission needs that transmission providers must evaluate to those 
that merit consideration in the existing Order No. 1000 regional 
transmission planning and cost allocation processes. The requirement of 
the repeat identification of an interconnection-related need in at 
least two interconnection queue cycles during the preceding five years 
criterion provides an important limit on the extent to which evaluation 
is required. Namely, this and the other criteria together indicate that 
it is likely that the relevant interconnection-related transmission 
needs will persist but were not resolved because the high associated 
interconnection-related network upgrade costs drove the withdrawal of 
the underlying interconnection requests. The repeat identification of 
interconnection-related network upgrades driven by a common 
interconnection-related transmission need also indicates that the 
constraint that the interconnection-related network upgrades were 
identified to address is not unique to a single interconnection request 
at a single point in time. Additionally, relaxing this repeat 
identification requirement may be overburdensome to transmission 
providers because it could increase the number of interconnection-
related transmission needs that transmission providers must evaluate in 
their regional transmission planning and cost allocation processes.
---------------------------------------------------------------------------

    \2437\ See Dominion Initial Comments at 32; Indicated PJM TOs 
Initial Comments at 15; Interwest Initial Comments at 3, 11; Pattern 
Energy Initial Comments at 28; Pine Gate Initial Comments at 32; 
SEIA Initial Comments at 15; Shell Initial Comments at 30.
---------------------------------------------------------------------------

    1151. We find that it is necessary to establish a cost threshold 
criterion that is stringent enough to capture those interconnection-
related network upgrades that are likely to have caused the underlying 
interconnection requests to withdraw. Additionally, we find that it is 
necessary to establish a voltage criterion that is high enough so that 
any regional transmission facility evaluated to address the underlying 
interconnection-related transmission need(s) is likely to produce 
benefits that extend beyond the interconnection customer. We further 
believe that these criteria are important to limit the number of 
interconnection-related transmission needs that transmission providers 
must evaluate to a practical set so that transmission providers do not 
have to evaluate numerous regional transmission facilities to address 
those needs that are unlikely to be selected.
    1152. Consequently, the modification adopted here to require that 
an interconnection-related network upgrade identified to meet an 
interconnection-related transmission need satisfies both the voltage 
and cost criteria will achieve these results. In particular, this 
modification will prevent transmission providers from evaluating 
interconnection-related transmission needs associated with 
interconnection-related network upgrades that are either above 200 kV 
but lower-cost or cost more than $30 million but are less than 200 kV, 
which means that they are less likely to provide more widespread 
benefits to transmission customers.
    1153. The change to the voltage and cost criteria also address 
commenters' concerns.\2438\ For example, as US DOE notes, in some 
instances, network upgrades that cost $30 million or more may only 
benefit a limited number of interconnection customers.\2439\ 
Consequently, the change that we adopt to require that an 
interconnection-related network upgrade identified to meet an 
interconnection-related transmission need satisfy both the voltage and 
cost criteria will more narrowly define a set of interconnection-
related transmission needs that the transmission provider must evaluate 
in the regional transmission planning process.
---------------------------------------------------------------------------

    \2438\ Pine Gate Initial Comments at 32; SEIA Initial Comments 
at 15; US DOE Initial Comments at 28.
    \2439\ US DOE Initial Comments at 28.
---------------------------------------------------------------------------

    1154. The record supports a 200 kV threshold. For example, as noted 
in the NOPR, the Commission has previously found CAISO's use of a 200 
kV threshold was just and reasonable for determining eligibility for 
evaluating interconnection-related network upgrades in the regional 
transmission planning process. The Commission found that CAISO's 
proposed threshold ``strikes a reasonable balance between . . . 
accommodating the generators' need to interconnect . . . in a timely 
manner, and the benefits that can flow from evaluating the larger 
projects in the comprehensive transmission planning process.'' \2440\ 
As such, we continue to believe that a 200 kV voltage threshold is 
sufficiently high such that the interconnection-related network 
upgrades can more reasonably be expected to produce regional benefits 
to

[[Page 49460]]

transmission customers than lower-voltage transmission facilities.
---------------------------------------------------------------------------

    \2440\ Cal Indep. Sys. Operator Corp., 133 FERC ] 61,224, at P 
103 (2010); see also NOPR, 179 FERC ] 61,028 at P 165 n.300 & P 172 
n.302.
---------------------------------------------------------------------------

    1155. We also continue to believe that $30 million is an 
appropriate threshold for the cost criteria related to this 
requirement. We find that the $30 million threshold is consistent with 
the record established in this proceeding regarding how the costs of 
interconnection-related network upgrades lead to interconnection 
customers withdrawing from the queue.\2441\ A lower cost criterion may 
require transmission providers to evaluate in the regional transmission 
planning process interconnection-related transmission needs associated 
with interconnection-related network upgrades that have a greater 
likelihood to be affordable for interconnection customers. 
Additionally, we are concerned that the $/kW cost threshold proposed by 
SEIA may not capture interconnection-related network upgrades that are 
more likely to provide regional benefits to transmission customers 
beyond the interconnection customer. Further, transmission providers 
may face practical challenges in identifying the specific kW size 
corresponding to the interconnection-related transmission need 
associated with an interconnection-related network upgrade because the 
same interconnection-related network upgrade can be identified as 
needed for multiple interconnection requests (or groups of requests) of 
different kW sizes.
---------------------------------------------------------------------------

    \2441\ NOPR, 179 FERC ] 61,028 at P 172 n.303.
---------------------------------------------------------------------------

    1156. Additionally, we reiterate that the criteria adopted herein 
do not require transmission providers to select any particular regional 
transmission facility to address interconnection-related transmission 
needs. Instead, we require transmission providers to simply evaluate 
regional transmission facilities to address interconnection-related 
transmission needs that meet these criteria for potential selection, 
recognizing that transmission providers may ultimately determine 
through their regional transmission planning processes that such 
regional transmission facilities are not eligible or sufficiently 
beneficial to be selected.
    1157. We disagree with Indicated PJM TOs' argument that limiting 
evaluation to exclude interconnection-related network upgrades 
identified in generator interconnection requests that have executed (or 
requested to be filed unexecuted) an interconnection agreement will 
result in studying only uneconomic projects.\2442\ This criterion 
ensures that transmission providers are not required to evaluate in 
their regional transmission planning process interconnection-related 
transmission needs associated with interconnection-related network 
upgrades for which an interconnection customer has already agreed to 
pay.\2443\ Furthermore, in response to MISO's suggestion to delete this 
limiting aspect, we clarify that this criterion excludes instances in 
which an interconnection-related network upgrade is identified in an 
executed generator interconnection agreement (or in a generator 
interconnection agreement that the interconnection customer requested 
to be filed unexecuted with the Commission),\2444\ not instances where 
an interconnection-related network upgrade that meets the criteria in 
this section is identified as needed for an interconnection request 
that has not proceeded to the generator interconnection agreement phase 
of the interconnection study process.
---------------------------------------------------------------------------

    \2442\ Indicated PJM TOs Initial Comments at 16.
    \2443\ NOPR, 179 FERC ] 61,028 at P 173.
    \2444\ MISO Initial Comments at 46.
---------------------------------------------------------------------------

    1158. The criterion requiring that interconnection-related 
transmission needs are identified in at least two interconnection queue 
cycles during the preceding five years will help to ensure that an 
interconnection-related transmission need is likely to persist and is 
not unique to a single interconnection request before requiring 
transmission providers to evaluate a regional transmission facility to 
address that need for potential selection.\2445\ We recognize that, in 
limited circumstances, it is possible that there may be only one 
interconnection queue cycle during a five-year period. We clarify that 
if more than five years pass between interconnection queue cycles, then 
this criterion should be read to include the interconnection queue 
cycle that immediately preceded the current interconnection queue where 
the interconnection-related transmission need is identified.\2446\
---------------------------------------------------------------------------

    \2445\ Pattern Energy Reply Comments at 10-11; Pine Gate Initial 
Comments at 31; SEIA Initial Comments at 14-15.
    \2446\ See Pine Gate Initial Comments at 31.
---------------------------------------------------------------------------

    1159. We adopt the NOPR proposal that the initial five-year period 
will begin five calendar years prior to the effective date of the 
Commission-accepted tariff provisions proposed to comply with this 
final order. Thus, transmission providers must evaluate an 
interconnection-related transmission need that has been previously 
identified multiple times within the five years prior to the effective 
date of the Commission-accepted tariff provisions, but never been 
resolved due to the withdrawal of the underlying interconnection 
request(s). This assumes that the other qualifying criteria are met for 
the interconnection-related transmission need. The evaluation for 
selection of regional transmission facilities that address certain 
identified interconnection-related transmission needs must occur in the 
first Order No. 1000 regional transmission planning and cost allocation 
processes cycle that commences after the later-in-time withdrawn 
interconnection request occurring after the effective date of the 
accepted tariff provisions.
    1160. Additionally, we clarify that if there are no queue cycles in 
the preceding five-year period because the transmission provider uses a 
first-come, first-served serial interconnection process, then this 
criterion will be met based on the identification of interconnection-
related transmission needs in individual interconnection studies. That 
is, if the interconnection-related transmission need is identified in 
at least two individual interconnection studies during the preceding 
five-year period for interconnection customers that subsequently 
withdrew from the interconnection queue, then this criterion is met. We 
further clarify, as discussed immediately above, that if a transmission 
provider identifies the same interconnection-related transmission need 
in two interconnection queue cycles during a five-year period or less, 
the transmission provider must evaluate that interconnection-related 
transmission need even if five years have not yet passed since the 
initial identification.\2447\
---------------------------------------------------------------------------

    \2447\ See Pattern Energy Reply Comments at 10-11; SEIA Initial 
Comments 15.
---------------------------------------------------------------------------

    1161. In response to Eversource's request that we require 
transmission providers to specify the stage in the generator 
interconnection process that an interconnection-related network upgrade 
is identified,\2448\ we clarify that the criterion discussed herein 
applies no matter the stage in which the upgrades are identified, 
because we are concerned with interconnection-related transmission 
needs going unaddressed due to withdrawals regardless of the stage of 
the generator interconnection process.
---------------------------------------------------------------------------

    \2448\ See EEI Initial Comments at 17-18; Eversource Initial 
Comments at 24.
---------------------------------------------------------------------------

    1162. Finally, we decline to combine the third and fourth criteria 
into one criterion as Pine Gate suggests, because we find that it is 
unnecessary.\2449\ This reform creates a process for the evaluation of 
interconnection-related

[[Page 49461]]

transmission needs in regional transmission planning and cost 
allocation processes if those needs have not been addressed and are 
unlikely to be addressed through the development of an interconnection-
related network upgrade in the generator interconnection process. The 
purpose of the third criterion is to limit the reform to those 
interconnection-related transmission needs where the associated 
interconnection requests have been withdrawn; that is, this criterion 
requires the repeat withdrawal. The fourth criterion, that the 
interconnection-related network upgrade not be identified in a 
generator interconnection agreement, ensures that the interconnection-
related network upgrade has not been developed and is not planned to be 
developed because a generator interconnection agreement memorializes 
the transmission owner's obligation to develop an identified 
interconnection-related network upgrade.\2450\
---------------------------------------------------------------------------

    \2449\ See Pine Gate Initial Comments at 32-33.
    \2450\ See Pro forma LGIA art. 11.3 (``Transmission Provider or 
Transmission Owner shall design, procure, construct, install, and 
own the Network Upgrades . . . described in Appendix B.'').
---------------------------------------------------------------------------

V. Consideration of Dynamic Line Ratings and Advanced Power Flow 
Control Devices

A. General Proposal

1. NOPR Proposal
    1163. In the NOPR, the Commission proposed to require transmission 
providers in each transmission planning region to consider two specific 
technologies more fully in regional transmission planning and cost 
allocation processes: dynamic line ratings and advanced power flow 
control devices. The Commission recognized that selecting transmission 
facilities that incorporate such technologies serving a transmission 
function in the regional transmission plan for purposes of cost 
allocation could be more efficient or cost-effective than a proposed 
regional transmission facility that does not use such 
technologies.\2451\
---------------------------------------------------------------------------

    \2451\ NOPR, 179 FERC ] 61,028 at PP 272-273.
---------------------------------------------------------------------------

    1164. More specifically, the Commission proposed to require 
transmission providers in each transmission planning region to consider 
for each identified regional transmission need whether selecting 
transmission facilities that incorporate dynamic line ratings or 
advanced power flow control devices would be more efficient or cost-
effective than selecting transmission facilities that do not 
incorporate these technologies. The Commission proposed that such 
consideration should first address whether incorporating dynamic line 
ratings or advanced power flow control devices into existing 
transmission facilities could meet the same regional transmission need 
more efficiently or cost-effectively than other transmission facilities 
that are being considered for potential selection. Second, the 
Commission proposed that, when evaluating transmission facilities for 
potential selection, transmission providers in each transmission 
planning region must also consider whether incorporating dynamic line 
ratings and advanced power flow control devices as part of any 
potential regional transmission facility would be more efficient or 
cost-effective than potential regional transmission facilities that do 
not incorporate such technologies. The Commission proposed to apply 
this requirement in all aspects of the regional transmission planning 
processes, including the existing regional transmission planning 
process for near-term regional transmission needs and Long-Term 
Regional Transmission Planning. As is the case for any other 
transmission facility selected, the Commission proposed that the costs 
to incorporate dynamic line ratings or advanced power flow control 
devices selected, whether as an addition to an existing transmission 
facility or as part of a new regional transmission facility, be 
allocated using the applicable regional cost allocation method.\2452\
---------------------------------------------------------------------------

    \2452\ Id. P 274.
---------------------------------------------------------------------------

    1165. The Commission noted that, as required by Order No. 1000, the 
evaluation process must culminate in a determination that is 
sufficiently detailed for stakeholders to understand why a particular 
transmission facility was selected or not selected.\2453\ The 
Commission proposed to extend this requirement such that transmission 
providers must ensure that the determination of whether to incorporate 
dynamic line ratings and advanced power flow control devices is 
sufficiently detailed for stakeholders to understand why they were or 
were not incorporated into selected regional transmission 
facilities.\2454\
---------------------------------------------------------------------------

    \2453\ Id. P 275 (citing Order No. 1000, 136 FERC ] 61,051 at P 
328; Order No. 1000-A, 139 FERC ] 61,132 at P 267).
    \2454\ Id.
---------------------------------------------------------------------------

    1166. The Commission also sought comment on whether non-RTO/ISO 
transmission planning regions should be required to update their energy 
management systems or make other similar changes if dynamic line 
ratings are identified as a more efficient or cost-effective 
transmission facility.\2455\
---------------------------------------------------------------------------

    \2455\ Id. P 277.
---------------------------------------------------------------------------

2. Comments on General Proposal
    1167. Many commenters, including technology developers, 
environmental advocates, ratepayer advocates, and independent market 
monitors, support the NOPR proposal.\2456\ For example, many commenters 
state that these technologies provide significant annual cost savings 
\2457\ or affect both the capital investment and consumer benefits of 
cost allocation.\2458\ Additionally, some Federal legislators support 
the NOPR proposal.\2459\ CARE

[[Page 49462]]

Coalition asserts that the Commission should use all available tools 
and technologies to increase the efficiency and capacity of the 
transmission network.\2460\ ELCON states that transmission planning 
processes should ascertain whether current infrastructure can be 
improved before reviewing costlier or slower options like greenfield 
transmission, and greater weight should be given to those transmission 
projects that incorporate grid enhancing technologies.\2461\ Certain 
TDUs state that they participate actively in the MISO transmission 
planning process, and that they have observed that grid enhancing 
technologies and other non-transmission alternatives do not receive the 
attention that they deserve.\2462\ AEE contends that the Commission has 
an obligation to promote the adoption of alternative transmission 
technologies, as directed by Congress in the Energy Policy Act of 2005, 
and AEE states that the Commission has not made explicit efforts to 
implement this mandate beyond offering rate incentives for alternative 
transmission technologies.\2463\
---------------------------------------------------------------------------

    \2456\ ACEG Initial Comments at 31; ACORE Initial Comments at 
15-16; ACORE Supplemental Comments at 1; Advanced Energy Buyers 
Initial Comments at 4; AEE Initial Comments at 27-28; CARE Coalition 
Initial Comments at 2-3; Certain TDUs Reply Comments at 7-9; Clean 
Energy Associations Initial Comments at 28; Clean Energy 
Associations Reply Comments at 7-8; Conservative Energy Network 
Supplemental Comments at 1-2; Conservatives for Clean Energy--
Florida Supplemental Comments at 1-2; Conservatives for Clean 
Energy--South Carolina Supplemental Comments at 1; Cross Sector 
Representatives Supplemental Comments at 1; DC and MD Offices of 
People's Counsel Initial Comments at 36; DC and MD Offices of 
People's Counsel Reply Comments at 8-9; Evergreen Action Initial 
Comments at 4; Hannon Armstrong Reply Comments at 2; Illinois 
Commission Initial Comments at 11-13; Indicated US Senators and 
Representatives Initial Comments at 2; Joint Consumer Advocates 
Initial Comments at 13; Massachusetts Attorney General Initial 
Comments at 16-18; Michigan Conservative Energy Forum Supplemental 
Comments at 1; Michigan State Entities Initial Comments at 10; NARUC 
Initial Comments at 35; NASEO Initial Comments at 6; NASUCA Initial 
Comments at 7-8; NESCOE Initial Comments at 53; Nevada Commission 
Initial Comments at 13; Ohio Conservative Energy Forum Supplemental 
Comments at 1; Pennsylvania Commission Initial Comments at 11; PIOs 
Initial Comments at 22; PJM Market Monitor Initial Comments at 6; 
Potomac Economics Initial Comments at 5; Prysmian Initial Comments 
at 1; Smart Wires Initial Comments at 1; SPP Market Monitor Initial 
Comments at 9; US DOE Initial Comments at 36-37; WATT Coalition 
Initial Comments at 2; WATT Coalition Supplemental Comments at 2-3; 
Western Way Colorado Supplemental Comments at 1-2; Western Way 
Nevada Supplemental Comments at 2; Wisconsin Conservative Energy 
Forum Supplemental Comments at 1.
    \2457\ Cross Sector Representatives Supplemental Comments at 1; 
WATT Coalition Supplemental Comments at 2-3.
    \2458\ Conservative Energy Network Supplemental Comments at 1-2; 
Conservatives for Clean Energy--Florida Supplemental Comments at 1-
2; Conservatives for Clean Energy--South Carolina Supplemental 
Comments at 1; Michigan Conservative Energy Forum Supplemental 
Comments at 1; Ohio Conservative Energy Forum at 1; Western Way 
Colorado Supplemental Comments at 2; Western Way Nevada Supplemental 
Comments at 2; Western Way Utah Supplemental Comments at 2; 
Wisconsin Conservative Energy Forum Supplemental Comments at 1.
    \2459\ Environmental Legislators Caucus Supplemental Comments at 
2; Senator Schumer Supplemental Comments at 2; Senator Whitehouse 
Supplemental Comments at 3.
    \2460\ CARE Coalition Initial Comments at 3.
    \2461\ ELCON Initial Comments at 5, 20.
    \2462\ Certain TDUs Reply Comments at 8.
    \2463\ AEE Initial Comments at 29 (citing 42 U.S.C. 16422).
---------------------------------------------------------------------------

    1168. Industrial Customers assert that requiring dynamic line 
ratings, advanced power flow control devices, and other grid enhancing 
technologies will require transmission utilities to deploy capital 
where it is needed most to maintain reliability, which will reduce 
transmission costs to consumers because dynamic line ratings extend the 
useful life of existing transmission infrastructure and optimize 
existing grid capabilities.\2464\ ENGIE claims that deploying grid 
enhancing technologies could help to contain costs and support 
efficient, advanced projects.\2465\ Invenergy argues that, even if 
there may be instances where dynamic line ratings and advanced power 
flow control devices do not provide the best option with respect to 
cost, transmission providers should still undertake the analysis.\2466\ 
Potomac Economics observes that incorporating grid enhancing 
technologies in the transmission planning process will help ensure that 
transmission owners do not incur inefficient transmission upgrade costs 
to mitigate congestion that can be reduced more cost-effectively by 
grid enhancing technologies.\2467\
---------------------------------------------------------------------------

    \2464\ Industrial Customers Reply Comments at 13-14.
    \2465\ ENGIE Reply Comments at 3-4.
    \2466\ Invenergy Reply Comments at 17.
    \2467\ Potomac Economics Initial Comments at 5.
---------------------------------------------------------------------------

    1169. Individual state governmental entities as well as NASEO, 
NASUCA, and NESCOE emphasize the importance of considering more 
efficient or cost-effective alternatives.\2468\ Some state commissions 
and US DOE cite the benefits of cost containment for customers.\2469\ 
DC and MD Offices of People's Counsel and Clean Energy Associations 
assert that grid enhancing technologies provide value beyond lowering 
transmission costs, as they can be deployed quickly, are modular, have 
low environmental and geographic footprints, and can be developed at 
low risk.\2470\ NARUC asserts that an effective transmission planning 
process should maximize the use of existing transmission and allow for 
building new transmission only where necessary or economic.\2471\ 
Indicated US Senators and Representatives support the use of advanced 
transmission technologies to increase the efficiency and resilience of 
the electric grid.\2472\
---------------------------------------------------------------------------

    \2468\ Massachusetts Attorney General Initial Comments at 16-18; 
Michigan State Entities Initial Comments at 10 (citing Institute for 
Policy Integrity ANOPR Reply Comments at 8); NASEO Initial Comments 
at 6; NASUCA Initial Comments at 7-8; NESCOE Initial Comments at 53.
    \2469\ Illinois Commission Initial Comments at 11-13; NARUC 
Initial Comments at 35-36; Nevada Commission Initial Comments at 13; 
Pennsylvania Commission Initial Comments at 11; US DOE Initial 
Comments at 36-37.
    \2470\ Clean Energy Associations Initial Comments at 27; DC and 
MD Offices of People's Counsel Reply Comments at 8.
    \2471\ Industrial Customers Reply Comments at 12; NARUC Initial 
Comments at 35.
    \2472\ Indicated US Senators and Representatives Initial 
Comments at 2.
---------------------------------------------------------------------------

    1170. Many commenters support the consideration of alternative 
transmission technologies in transmission planning. For example, 
Certain TDUs argue that the Commission must protect ratepayers and 
consider all alternatives to ensure safe, reliable, and cost-effective 
transmission solutions, including the use of alternative transmission 
technologies.\2473\ Invenergy avers that there may be instances where 
better using these technologies may require certain foundational 
investments (e.g., appropriate software), but that only reinforces the 
need to establish a requirement to drive change.\2474\ Industrial 
Customers state that transmission providers should have to consider 
grid enhancing technologies whenever additional transmission investment 
is the alternative because the cost of installing them will almost 
always be nominal compared to the benefits of reduced congestion, lower 
energy and capacity costs, and reduced need for increases in 
transmission system capability.\2475\
---------------------------------------------------------------------------

    \2473\ Certain TDUs Reply Comments at 8.
    \2474\ Invenergy Reply Comments at 17.
    \2475\ Industrial Customers Reply Comments at 16.
---------------------------------------------------------------------------

    1171. WATT Coalition asserts that alternative transmission 
technologies and new transmission capacity are complementary.\2476\ 
WATT Coalition and Industrial Customers further assert that there is 
substantial value in considering dynamic line ratings in Long-Term 
Regional Transmission Planning because they can provide data to 
strengthen assumptions made in the planning process.\2477\ 
Specifically, WATT Coalition explains that historical data sets of 
dynamic transmission line ratings can be analyzed to create 
probabilistic line ratings on a seasonal, monthly, or more granular 
level to inform the transmission planning process, helping to maximize 
its efficiency.\2478\ Finally, WATT Coalition states that the use of 
forecasted ambient-adjusted ratings (Ambient Adjusted Ratings) 
demonstrates that more granular data inputs can and should be captured 
to increase the value of new transmission investment, as well as 
increased reliability and market efficiency.\2479\
---------------------------------------------------------------------------

    \2476\ WATT Coalition Reply Comments at 2.
    \2477\ Industrial Customers Reply Comments at 18; WATT Coalition 
Reply Comments at 1-3 (citing Appendix B of its Reply Comments).
    \2478\ WATT Coalition Reply Comments Appendix B at 12. For 
example, WATT Coalition reports that ERCOT uses historical dynamic 
line rating data in its regional transmission plan. Id. (citing 
ERCOT 2021 Regional Transmission Plan Report, section 1.2, https://www.ercot.com/files/docs/2021/12/23/2021_Regional_Transmission_Plan_Report_Public.zip).
    \2479\ Id. Appendix B at 13.
---------------------------------------------------------------------------

    1172. Invenergy states that, if there are concerns about the burden 
associated with evaluating alternative transmission technologies, the 
Commission could adopt a reasonable threshold under which transmission 
providers are required to consider whether dynamic line ratings, 
advanced power flow control devices, and other grid enhancing 
technologies may be more efficient or cost-effective. For example, 
Invenergy suggests that, if an overload is identified and the relevant 
facilities are overloaded by 20% or less, the transmission provider 
should be required to consider grid enhancing technologies as a 
solution. Invenergy urges the Commission to reject calls to make the 
proposal an optional process, noting that transmission providers can 
already consider these technologies, but many do not.\2480\
---------------------------------------------------------------------------

    \2480\ Invenergy Reply Comments at 16-17.

---------------------------------------------------------------------------

[[Page 49463]]

    1173. Some commenters express partial support for the NOPR proposal 
but raise concerns about certain aspects.\2481\ California Water 
supports consideration of dynamic line ratings and advanced power flow 
control devices in Long-Term Regional Transmission Planning but 
recommends that any final order clarify that such technologies should 
be adopted only if they are considered in the regional transmission 
planning process as the Commission proposes, serve the purpose of cost 
containment, and are found to be efficient and cost-effective.\2482\ 
TAPS states that while it supports the implementation of grid enhancing 
technologies, they may be better suited for consideration on a shorter 
regional transmission planning horizon.\2483\ While Pattern Energy 
supports the consideration of grid enhancing technologies in Long-Term 
Regional Transmission Planning, it similarly notes that dynamic line 
ratings and advanced power flow control devices are shorter-term 
transmission solutions--helping to ``squeeze more'' out of the 
infrastructure that is operating or planned to be constructed.\2484\
---------------------------------------------------------------------------

    \2481\ CAISO Initial Comments at 37-39, California Water Initial 
Comments at 20; ENGIE Initial Comments at 6; Invenergy Initial 
Comments at 14-16; Ohio Consumers Initial Comments at 32-33; Pattern 
Energy Initial Comments at 29; SEIA Initial Comments at 21-22; SPP 
Initial Comments at 25-26, TAPS Initial Comments at 4, 21-22.
    \2482\ California Water Initial Comments at 20.
    \2483\ TAPS Initial Comments at 4, 21-22.
    \2484\ Pattern Energy Initial Comments at 29.
---------------------------------------------------------------------------

    1174. While ENGIE supports the Commission's proposal to require the 
evaluation and deployment of dynamic line ratings and advanced power 
flow control devices where beneficial in Long-Term Regional 
Transmission Planning, it notes that the operational data used by such 
devices are not yet easily incorporated into the transmission planning 
framework.\2485\ Similarly, SEIA and Invenergy raise concerns that 
utilities struggle to consider, evaluate, and select these technologies 
as transmission solutions due to a lack of information about how they 
might be integrated into the transmission planning process.\2486\
---------------------------------------------------------------------------

    \2485\ ENGIE Initial Comments at 6.
    \2486\ Invenergy Initial Comments at 14-16; SEIA Initial 
Comments at 21-22.
---------------------------------------------------------------------------

    1175. Finally, National Grid generally supports the notion that 
transmission providers should consider whether and how alternative 
transmission technologies can be incorporated into transmission 
planning and states that such technologies, in certain instances, may 
offer a more efficient or cost-effective alternative to other regional 
transmission facilities.\2487\ However, National Grid states that, if 
the Commission adopts in a final order the requirement to fully 
consider dynamic line ratings and advanced power flow control devices, 
it should explain how it expects RTOs/ISOs to implement the first step 
of the consideration process articulated in the NOPR, i.e., that the 
alternative transmission technologies being incorporated into existing 
transmission facilities ``could meet the same regional transmission 
need more efficiently or cost-effectively than other potential 
transmission facilities.'' \2488\ According to National Grid, such a 
requirement would exceed the RTO/ISO's authority as the independent 
administrator of the competitive solicitation process.\2489\
---------------------------------------------------------------------------

    \2487\ National Grid Initial Comments at 21.
    \2488\ Id. at 23 (quoting NOPR, 179 FERC ] 61,028 at P 274).
    \2489\ Id.
---------------------------------------------------------------------------

    1176. Many commenters oppose the NOPR proposal.\2490\ Some 
commenters warn the Commission of the potential reliability and 
operational impacts of the widespread use of dynamic line ratings and 
advanced power flow control devices.\2491\ APPA asserts that 
transmission dynamic line ratings and advanced power flow control 
devices should not be required until the industry has further 
experience with Ambient-Adjusted Ratings deployment.\2492\ Exelon 
asserts that transmission providers already consider grid enhancing 
technologies and notes that, in many instances, the selection and 
deployment of grid enhancing technologies are fundamentally 
incompatible with the competitive transmission requirements in Order 
No. 1000, particularly in the context of development of new 
transmission facilities, where grid enhancing technologies are unlikely 
to be the lower cost solution, and may be considerably more expensive 
than traditional transmission technologies.\2493\
---------------------------------------------------------------------------

    \2490\ AEP Initial Comments at 33; Ameren Initial Comments at 
23-24; APPA Initial Comments at 37; ATC Initial Comments at 7-8; 
Avangrid Initial Comments at 31; DATA Initial Comments at 17; 
Dominion Initial Comments at 40; Duke Initial Comments at 29-32; EEI 
Initial Comments at 20-22; Entergy Initial Comments at 26-28; 
Eversource Initial Comments at 27-28; Exelon Initial Comments at 18-
23; Georgia Commission Initial Comments at 7-8; Idaho Power Initial 
Comments at 9; Indicated PJM TOs Initial Comments at 19-20; ITC 
Initial Comments at 26-28; ITC Reply Comments at 27; LADWP Initial 
Comments at 5; Large Public Power Initial Comments at 31-34; MISO 
TOs Initial Comments at 23-24; Mississippi Commission Reply Comments 
at 8; New York TOs Initial Comments at 22-23; NRECA Initial Comments 
at 52; NYISO Initial Comments at 45, 47; OMS Initial Comments at 9; 
Pacific Northwest Utilities Initial Comments at 15-16; PJM Initial 
Comments at 105-109; PPL Initial Comments at 22-23; Southern Initial 
Comments at 35; SERTP Sponsors Initial Comments at 36-37; US Chamber 
of Commerce Initial Comments at 9.
    \2491\ Duke Initial Comments at 31-32; Entergy Initial Comments 
at 27-28; MISO Initial Comments at 59-60.
    \2492\ APPA Initial Comments at 5.
    \2493\ Exelon Initial Comments at 21.
---------------------------------------------------------------------------

    1177. Some commenters argue that further support is needed to 
justify any mandate to consider alternative transmission technologies 
in transmission planning.\2494\ Kansas Commission asserts that any new 
requirements should be based on a data-driven, robust analysis 
demonstrating ratepayer benefits; it also cautions against using such 
technologies as a short-term fix.\2495\ ATC states that the Commission 
should develop a record of the costs, risks, and potential impacts of 
widespread implementation of dynamic line ratings before mandating 
further action.\2496\
---------------------------------------------------------------------------

    \2494\ ATC Reply Comments at 3; Kansas Commission Initial 
Comments at 19-20.
    \2495\ Kansas Commission Initial Comments at 19-20.
    \2496\ ATC Reply Comments at 3.
---------------------------------------------------------------------------

    1178. Some commenters raise concerns about the costs of alternative 
transmission technologies. Mississippi Commission argues that mandating 
the use of technologies without considering their cost is not just and 
reasonable.\2497\ ATC asserts that the costs of implementing dynamic 
line ratings system wide would not be nominal.\2498\ US Chamber of 
Commerce asserts that dynamic line ratings are not a way to obtain 
``free'' transmission capacity because there are costs associated with 
monitoring the ratings.\2499\
---------------------------------------------------------------------------

    \2497\ Mississippi Commission Reply Comments at 8.
    \2498\ ATC Reply Comments at 3 (citing Pattern Energy Initial 
Comments at 30; Pine Gate Initial Comments at 40-41).
    \2499\ US Chamber of Commerce Initial Comments at 9.
---------------------------------------------------------------------------

    1179. Other commenters argue that the Commission should favor 
flexibility and not mandate that dynamic line ratings and advanced 
power flow control devices be considered.\2500\ Georgia Commission 
states that it is reasonable for the Commission to encourage, rather 
than require, consideration of dynamic line ratings and advanced power 
flow control devices in Long-Term Regional Transmission Planning.\2501\ 
LADWP suggests that instead of mandating consideration of specific 
technologies that become obsolete, the Commission

[[Page 49464]]

should require transmission providers to use Good Utility Practice to 
identify and use technologies that maximize the use of transmission 
assets in order to minimize impacts to ratepayers and the public.\2502\
---------------------------------------------------------------------------

    \2500\ Avangrid Initial Comments at 31; Clean Energy Buyers 
Initial Comments at 25; Eversource Initial Comments at 27; Georgia 
Commission Initial Comments at 7-8; Idaho Power Initial Comments at 
9; New York TOs Initial Comments at 23; OMS Initial Comments at 9; 
PPL Initial Comments at 23.
    \2501\ Georgia Commission Initial Comments at 7.
    \2502\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------

    1180. Similarly, National Grid argues that the Commission should 
not favor the deployment of the two proposed technologies over more 
efficient or cost-effective transmission facilities, and that focusing 
on specific technologies is likely to stifle innovation and will not 
lead to the identification of the more efficient or cost-effective 
transmission facilities.\2503\ ATC disagrees with commenters that state 
that utilities are reluctant to implement these technologies,\2504\ 
noting that it advocates for and uses advanced power flow control 
devices and other advanced technologies on its system.\2505\ However, 
ATC describes widespread dynamic line rating deployment as 
costly.\2506\
---------------------------------------------------------------------------

    \2503\ National Grid Initial Comments at 22-23.
    \2504\ ATC Reply Comments at 2 (citing Invenergy Initial 
Comments at 15).
    \2505\ Id. (citing ATC Initial Comments at 7).
    \2506\ Id. at 3.
---------------------------------------------------------------------------

    1181. Other commenters urge the Commission to complete its 
consideration of the record in the Notice of Inquiry on the 
Implementation of Dynamic Line Ratings\2507\ and/or wait for 
transmission providers to comply with Order No. 881\2508\ before 
implementing the NOPR proposal on dynamic line ratings.\2509\ Large 
Public Power states that the Commission appears to sidestep the record 
in the Notice of Inquiry on the Implementation of Dynamic Line Ratings, 
especially the technical and cybersecurity-related concerns in that 
docket.\2510\ MISO TOs state that imposing a mandate in this proceeding 
would complicate the issue.\2511\ ATC argues that a more prudent course 
of action would be to gain experience with Ambient-Adjusted Ratings 
before moving on to consideration of the use of dynamic line 
ratings.\2512\ ITC asserts that dynamic line ratings and advanced power 
flow control devices should be implemented on an operational basis 
through existing Commission proceedings addressing such 
technologies.\2513\
---------------------------------------------------------------------------

    \2507\ Implementation of Dynamic Line Ratings, 178 FERC ] 61,110 
(2022).
    \2508\ Managing Transmission Line Ratings, Order No. 881, 177 
FERC ] 61,179 (2021).
    \2509\ ATC Reply Comments at 4-5; Dominion Initial Comments at 
40; Large Public Power Initial Comments at 5, 32-33; MISO TOs 
Initial Comments at 23-24.
    \2510\ Large Public Power Initial Comments at 32.
    \2511\ MISO TOs Initial Comments at 23.
    \2512\ ATC Initial Comments at 10.
    \2513\ ITC Reply Comments at 27.
---------------------------------------------------------------------------

    1182. Several commenters specifically support the NOPR proposal of 
requiring consideration of both: (1) whether incorporating dynamic line 
ratings or advanced power flow control devices into existing 
transmission facilities could meet the same regional transmission need 
more efficiently or cost-effectively than other transmission facilities 
that are being considered for potential selection; and (2) whether 
incorporating dynamic line ratings and advanced power flow control 
devices as part of any potential regional transmission facility would 
be more efficient or cost-effective than those without incorporating 
such technologies.\2514\ Ohio Consumers emphasize the importance of 
considering dynamic line ratings and advanced power flow control 
devices for both proposed and existing projects, noting that the goal 
of using these technologies is to lower overall costs of new 
transmission for consumers, and citing to a DOE study that found that 
these technologies can defer or reduce the need for significant 
investment in new infrastructure projects, and increase the use of 
renewables by maximizing the capacity of current infrastructure.\2515\
---------------------------------------------------------------------------

    \2514\ ACORE Initial Comments at 15; Clean Energy Associations 
Initial Comments at 28; DC and MD Offices of People's Counsel 
Initial Comments at 36; Industrial Customers Initial Comments at 32-
34; Michigan State Entities Initial Comments at 11; NASEO Initial 
Comments at 6; Ohio Consumers Initial Comments at 34; State Agencies 
Initial Comments at 17-18.
    \2515\ Ohio Consumers Initial Comments at 32-34 (citing US DOE, 
Grid-Enhancing Technologies: A Case Study on Ratepayer Impact (Feb. 
2022), https://www.energy.gov/sites/default/files/2022-04/Grid%20Enhancing%20Technologies%20-%20A%20Case%20Study%20on%20Ratepayer%20Impact%20-%20February%202022%20CLEAN%20as%20of%20032322.pdf).
---------------------------------------------------------------------------

    1183. Others oppose the consideration of alternative transmission 
technologies on new transmission facilities.\2516\ CAISO contends that 
a requirement to consider whether to incorporate dynamic line ratings 
and advanced power flow control devices as part of every new regional 
transmission facility identified to meet a reliability need would 
create more work without yielding significant benefits because 
incorporating such measures would not alter the scope of the underlying 
transmission facilities that are necessary to meet the reliability 
need.\2517\ LADWP states that identification of specific technologies 
in a rulemaking seems inappropriate and asserts a transmission line 
that is not yet built has no operating history, and it should therefore 
be at the discretion of the transmission planner to consider and 
implement dynamic line ratings, as it would slow down the design and 
construction of the transmission line.\2518\ Exelon states that, 
particularly in the context of new transmission facilities, grid 
enhancing technologies are very unlikely to be the lower cost solution 
relative to traditional transmission technologies, and for many 
technologies, they should be expected to be considerably more expensive 
than traditional transmission technologies (notwithstanding any 
additional benefits they may offer).\2519\
---------------------------------------------------------------------------

    \2516\ CAISO Initial Comments at 6; LADWP Initial Comments at 5.
    \2517\ CAISO Initial Comments at 6. CAISO, however, supports 
considering these technologies in connection with new transmission 
facilities intended to meet economic or public policy needs. Id.
    \2518\ LADWP Initial Comments at 5.
    \2519\ Exelon Initial Comments at 21-22.
---------------------------------------------------------------------------

    1184. Clean Energy Associations, Industrial Customers, and WATT 
Coalition support the implementation of a requirement for non-RTO/ISO 
regions to update their energy management systems if dynamic line 
ratings are identified as a more efficient or cost-effective 
transmission facility selected.\2520\ ELCON agrees, asserting that the 
Commission's requirement for dynamic line ratings and advanced power 
flow control devices should apply to all Commission-jurisdictional 
transmission utilities, regardless of whether they are RTOs/ISOs.\2521\ 
WATT Coalition adds that all transmission providers should be required 
to upgrade their energy management systems and keep them consistent 
across all transmission providers to accommodate the latest 
technologies.\2522\ WATT Coalition further states that advanced power 
flow control devices and topology optimization do not require 
modifications to existing energy management systems, but that the 
implementation of such technologies would benefit from the increased 
flexibility of dynamic line rating-enabled energy management 
systems.\2523\
---------------------------------------------------------------------------

    \2520\ Clean Energy Associations Initial Comments at 28; 
Industrial Customers Initial Comments at 32-33; Industrial Customers 
Reply Comments at 11; WATT Coalition Initial Comments at 7.
    \2521\ ELCON Initial Comments at 21.
    \2522\ WATT Coalition Initial Comments at 7.
    \2523\ Id.
---------------------------------------------------------------------------

    1185. Pattern Energy states that energy management systems and 
other equipment will need upgrades to integrate readouts from the 
dynamic line ratings equipment to minimize operator intervention and 
enhance operational awareness. Pattern Energy

[[Page 49465]]

surmises, however, that any upgrades necessitated by a final order in 
this proceeding may be nominal given that dynamic line ratings and 
advanced power flow control devices should already be readily 
integrated with upgrades to energy management systems needed to comply 
with Order No. 881.\2524\
---------------------------------------------------------------------------

    \2524\ Pattern Energy Initial Comments at 30 (citing Order No. 
881, 177 FERC ] 61,179).
---------------------------------------------------------------------------

    1186. Some commenters suggest alternative approaches to 
incorporating alternative transmission technologies into the 
transmission system. Vistra asserts that the Commission should modify 
the NOPR proposal to require: (1) the long-term transmission planning 
evaluation to include a generation capacity expansion scenario that 
incorporates the potential for enhanced capability through new market 
services; (2) early input during the transmission planning cycle from 
independent market monitors and stakeholders on market improvements 
that could enhance grid operations; and (3) all solicitations for long-
term solutions to equally consider non-transmissions solutions that may 
include generation, technology, or market design changes that could 
more efficiently or cost-effectively address a need that otherwise 
would require construction or modification of transmission 
facilities.\2525\
---------------------------------------------------------------------------

    \2525\ Vistra Initial Comments at 32.
---------------------------------------------------------------------------

    1187. Some commenters request that the Commission establish more 
prescriptive requirements regarding the evaluation of the alternative 
transmission technologies than those proposed in the NOPR. Invenergy 
asserts that the NOPR proposal should be expanded to include other 
technologies and require transmission providers to select alternative 
transmission technologies when they provide the most efficient 
option.\2526\
---------------------------------------------------------------------------

    \2526\ Invenergy Reply Comments at 16 (citing Invenergy Initial 
Comments at 14-17).
---------------------------------------------------------------------------

    1188. WATT Coalition urges the Commission to include an operational 
planning timeframe for topology optimization, dynamic line ratings, and 
modular advanced power flow control devices, which can all be deployed 
quickly. WATT Coalition states that the Commission could require 
consideration of these technologies for the top 5 or 10 most costly or 
critical constraints on a quarterly basis.\2527\ WATT Coalition states 
that market participants should be able to request the use of grid 
enhancing technologies, and receive an answer from the transmission 
provider within a defined period of time, to be evaluated against 
alternatives used by the transmission provider.\2528\ WATT Coalition 
also asserts that grid enhancing technologies should be required in 
appropriate instances and encouraged through incentives because 
utilities have little incentive to deploy them under standard cost-of-
service regulation,\2529\ and after implementing this order, the 
Commission should develop transmission incentives to complement a 
congestion threshold requirement, driving other creative applications 
of grid enhancing technologies where they would create the most value 
to consumers.\2530\
---------------------------------------------------------------------------

    \2527\ WATT Coalition Initial Comments at 5.
    \2528\ Id. at 5-6.
    \2529\ WATT Coalition Reply Comments at 3.
    \2530\ WATT Coalition Supplemental Comments at 3.
---------------------------------------------------------------------------

    1189. Some commenters request more requirements regarding 
evaluation and/or deployment of alternative transmission technologies 
to meet transmission needs. WATT Coalition states that there are 
certain transmission technologies that are faster to deploy than 
traditional lines and urges the Commission to require an annual review 
of the Long-Term Regional Transmission Planning process and establish a 
fast track process for solutions with a lead time of less than 12 
months and a capital cost of less than $50 million.\2531\ WATT 
Coalition further states that the requirement to consider dynamic line 
ratings and advanced power flow control devices should also apply in 
any case where transmission capacity is valuable but the costs of a new 
line are not justified.\2532\
---------------------------------------------------------------------------

    \2531\ WATT Coalition Initial Comments at 8.
    \2532\ Id. at 4.
---------------------------------------------------------------------------

    1190. Smart Wires and WATT Coalition argue that the Commission 
should direct transmission providers to: (1) designate advanced power 
flow control devices as the default solution for projects requiring a 
series capacitor; (2) ``require evaluation of advanced power flow 
control devices for thermal overloads that fall within 50% of the line 
rating,'' which they argue is when such devices are often most 
economically advantageous; (3) require evaluation of advanced power 
flow control devices for interconnection-related network upgrades 
associated with new load connections, given that these technologies can 
be used to rebalance flows quickly and adjusted to mirror actual 
growth; and (4) mandate deployment of advanced power flow control 
devices as the default solution for voltage stability management on 
100-plus mile AC transmission lines.\2533\
---------------------------------------------------------------------------

    \2533\ Smart Wires Initial Comments at 1, 3-5; WATT Coalition 
Initial Comments at 3-4.
---------------------------------------------------------------------------

    1191. Some commenters suggest that the Commission should collect 
additional data and require reporting on the deployment of alternative 
transmission technologies. PIOs and DC and MD Offices of People's 
Counsel ask the Commission to require that transmission providers 
explain how they considered alternative transmission technologies in 
the transmission planning process and if they were not used, why.\2534\ 
DC and MD Offices of People's Counsel assert that data collected from 
dynamic line ratings should be shared with stakeholders to provide 
transparency as to the necessity or economic efficiency of certain 
transmission upgrades, and a mechanism should be implemented to 
independently review the projected costs and benefits of advanced 
transmission technologies from an efficiency and cost-allocation 
perspective.\2535\ NASEO states that the Commission should include a 
requirement for those seeking to make changes to RTOs/ISOs' facilities 
to provide an analysis of the new technologies and how they meet 
present and expected future challenges, suggesting that RTOs/ISOs be 
required to consult with US DOE, the DOE national laboratories, and 
state energy offices to ensure new technologies are incorporated into 
Long-Term Regional Transmission Planning.\2536\ Certain TDUs argue that 
the Commission should require transmission planners to document their 
evaluation of alternative transmission solutions in the transmission 
planning process, which should include the methods used to integrate 
grid enhancing technologies alone or in combination with transmission 
upgrades.\2537\
---------------------------------------------------------------------------

    \2534\ DC and MD Offices of People's Counsel Initial Comments at 
36; PIOs Initial Comments at 22.
    \2535\ DC and MD Offices of People's Counsel Initial Comments at 
36.
    \2536\ NASEO Initial Comments at 6-7.
    \2537\ Certain TDUs Reply Comments at 8-9 (citing OMS Initial 
Comments at 9; Certain TDUs Initial Comments at 24).
---------------------------------------------------------------------------

    1192. ENGIE recommends that the Commission require transmission 
providers to provide a report to the Commission every five years on the 
deployment and operational analysis of grid enhancing technologies to 
ensure these technologies are being properly evaluated in Long-Term 
Regional Transmission Planning.\2538\ R Street suggests that the 
Commission require the incorporation, not just consideration, of 
advanced transmission technologies, and should require the inclusion of 
commercially viable

[[Page 49466]]

technologies on a rolling basis as informed by a regularly updated list 
of qualifying technologies through, for example, a periodic forum with 
technology experts from US DOE.\2539\ SEIA states that the Commission 
should host regular technical conferences to discuss improvements and 
innovations in grid enhancing technologies as experience with these 
technologies grows.\2540\ SEIA states that to determine whether such 
technologies are feasible, transmission providers should provide the 
following information to market participants: modeling assumptions, 
contingency analysis results, asset age, and environmental and 
footprint constraints.\2541\
---------------------------------------------------------------------------

    \2538\ ENGIE Initial Comments at 6.
    \2539\ R Street Initial Comments at 4.
    \2540\ SEIA Initial Comments at 21.
    \2541\ Id. at 22.
---------------------------------------------------------------------------

    1193. Pattern Energy states that the Commission should be mindful 
that limited supplies of dynamic line ratings, advanced power flow 
control devices, and SCADA-based implementation equipment (and service 
providers thereto) may cause shortages that will constrain transmission 
facility developers and owners.\2542\ Pattern Energy adds that, when 
evaluating the costs to implement such devices, transmission providers 
may need to assume cost parameters (e.g., cost per mile or cost per 
installation) for such devices in order to have an ``apples-to-apples 
comparison.'' \2543\
---------------------------------------------------------------------------

    \2542\ Pattern Energy Initial Comments at 29-30.
    \2543\ Id. at 30.
---------------------------------------------------------------------------

3. Need for Reform
    1194. Based on the record, we find that there is substantial 
evidence to support the conclusion that the Commission's existing 
regional transmission planning requirements are unjust, unreasonable, 
and unduly discriminatory or preferential because they do not require 
consideration of alternative transmission technologies in the regional 
transmission planning process. We therefore adopt the preliminary 
findings in the NOPR concerning the need for reform. Specifically, we 
find that the Commission's existing regional transmission planning 
requirements fail to ensure that transmission providers consider 
whether to incorporate alternative transmission technologies into 
regional transmission facilities as part of their regional transmission 
planning processes and, consequently, fail to ensure that transmission 
providers are identifying more efficient or cost-effective regional 
transmission solutions through those processes. As a result, 
transmission providers overlook or undervalue the benefits of certain 
alternative transmission technologies and, in turn, undertake 
relatively inefficient and less cost-effective investments in 
transmission infrastructure, the costs of which are ultimately 
recovered through Commission-jurisdictional rates. Accordingly, we find 
that existing regional transmission planning requirements are 
insufficient to ensure just and reasonable and not unduly 
discriminatory or preferential rates.
    1195. In the NOPR, the Commission stated that commercially 
available alternative transmission technologies have the potential to 
improve the operation of new and existing transmission facilities and 
defer or mitigate the need for new transmission investments.\2544\ 
However, existing regional transmission planning processes are not 
necessarily designed to consider the benefits that alternative 
transmission technologies can provide.\2545\ Commenters state that some 
transmission providers are reluctant to implement alternative 
transmission technologies or that alternative transmission technologies 
are not consistently evaluated in regional transmission planning in a 
manner commensurate with the benefits that they can provide.\2546\ The 
failure to consistently consider these technologies in regional 
transmission planning prevents them from being identified, evaluated, 
and selected as a more efficient or cost-effective solution to 
transmission needs, to the detriment of customers that can benefit from 
their deployment.
---------------------------------------------------------------------------

    \2544\ NOPR, 179 FERC ] 61,028 at P 267.
    \2545\ See, e.g., AEE Initial Comments at 29.
    \2546\ Certain TDUs Initial Comments at 22-23; Invenergy Initial 
Comments at 15-16; NASUCA Initial Comments at 7; WATT Coalition 
Initial Comments at 4.
---------------------------------------------------------------------------

    1196. The record demonstrates that alternative transmission 
technologies can provide significant capacity increases when 
incorporated into transmission facilities, and that such incorporation 
may provide benefits that outweigh its costs.\2547\ For example, a 
white paper prepared by the Brattle Group highlights several recent 
examples in which dynamic line ratings, transmission switching, and 
advanced power flow control devices were deployed to cost-effectively 
meet transmission needs in SPP, MISO, and other utility service 
territories.\2548\ Additionally, a recent US DOE case study on dynamic 
line ratings and advanced power flow control devices estimates that 
these alternative transmission technologies can provide significant 
production cost savings, net import savings, and avoided curtailment 
savings.\2549\
---------------------------------------------------------------------------

    \2547\ See, e.g., WATT Coalition Supplemental Comments at 2-3.
    \2548\ The Brattle Group, Building a Better Grid: How Grid-
Enhancing Technologies Complement Transmission Buildouts 12-15 (Apr. 
20, 2023), https://watt-transmission.org/wp-content/uploads/2023/04/Building-a-Better-Grid-How-Grid-Enhancing-Technologies-Complement-Transmission-Buildouts.pdf.
    \2549\ US DOE, Grid-Enhancing Technologies: A Case Study on 
Ratepayer Impact v-x (Feb. 2022), https://www.energy.gov/sites/default/files/2022-04/Grid%20Enhancing%20Technologies%20-%20A%20Case%20Study%20on%20Ratepayer%20Impact%20-%20February%202022%20CLEAN%20as%20of%20032322.pdf.
---------------------------------------------------------------------------

    1197. We find that the failure to require transmission providers to 
consider alternative transmission technologies renders the Commission's 
existing regional transmission planning requirements insufficient to 
ensure just and reasonable and not unduly discriminatory or 
preferential rates, we are now requiring, pursuant to FPA section 206, 
that transmission providers consider in Long-Term Regional Transmission 
Planning and their existing Order No. 1000 regional transmission 
planning process the alternative transmission technologies discussed 
below. While the record indicates that some of the alternative 
transmission technologies enumerated in this final order are sometimes 
considered in certain transmission planning regions as solutions to 
specific transmission needs,\2550\ we find that inconsistent 
consideration of alternative transmission technologies in regional 
transmission planning results in transmission providers overlooking or 
undervaluing the benefits that these technologies can provide. We find 
that the reforms concerning the consideration of alternative 
transmission technologies that we adopt in this final order will render 
the Commission's existing regional transmission planning requirements 
just and reasonable, because they will result in transmission providers 
identifying, evaluating, and selecting regional transmission facilities 
that are more efficient or cost-effective, which will ensure that 
Commission-jurisdictional rates are just and reasonable.
---------------------------------------------------------------------------

    \2550\ See Exelon Initial Comments at 21-23.
---------------------------------------------------------------------------

4. Commission Determination
    1198. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to 
consider, in Long-Term Regional Transmission Planning and existing 
Order No. 1000 regional transmission planning processes, dynamic line

[[Page 49467]]

ratings and advanced power flow control devices for each identified 
transmission need. We modify the NOPR proposal to require that, in 
addition to dynamic line ratings and advanced power flow control 
devices, transmission providers must consider in Long-Term Regional 
Transmission Planning and existing Order No. 1000 regional transmission 
planning processes advanced conductors and transmission switching. 
Thus, under this modification, transmission providers must consider: 
(1) dynamic line ratings; \2551\ (2) advanced power flow control 
devices; \2552\ (3) advanced conductors; \2553\ and (4) transmission 
switching.\2554\ We clarify that transmission providers must consider 
each of these enumerated technologies when evaluating new regional 
transmission facilities, as well as upgrades to existing transmission 
facilities.\2555\ Thus, for each identified transmission need, when 
evaluating regional transmission facilities for potential selection, 
transmission providers must consider whether regional transmission 
facilities that incorporate, or solely consist of, any of the 
enumerated list of alternative transmission technologies would be more 
efficient or cost-effective than selecting new regional transmission 
facilities or upgrades to existing transmission facilities that do not 
incorporate these technologies.
---------------------------------------------------------------------------

    \2551\ A dynamic line rating is ``a transmission line rating 
that applies to a time period of not greater than one hour and 
reflects up-to-date forecasts of inputs such as (but not limited to) 
ambient air temperature, wind, solar heating, transmission line 
tension, or transmission line sag.'' NOPR, 179 FERC ] 61,028 at P 
259 n.408 (citations omitted); see also Order No. 881, 177 FERC ] 
61,179 at P 7; Implementation of Dynamic Line Ratings, 178 FERC ] 
61,110 at P 1.
    \2552\ Advanced power flow control devices serve a transmission 
function. These devices can help the system operator control power 
flows over a given path and can include phase shifting transformers 
(also known as phase angle regulators) and devices or systems 
necessary for implementing optimal transmission switching. Advanced 
power flow control devices allow power to be pushed and pulled to 
alternate lines with spare capacity leading to maximum utilization 
of existing transmission capacity. NOPR, 179 FERC ] 61,028 at P 270 
n.437.
    \2553\ Advanced conductors include present and future 
transmission line technologies whose power flow capacities exceed 
the power flow capacities of conventional aluminum conductor steel 
reinforced conductors. See Order No. 2023-A, 186 FERC ] 61,199 at 
631.
    \2554\ Transmission switching is the opening or closing of 
transmission elements to safely route power and direct flows away 
from congestion, based on pre-existing forward analysis.
    \2555\ We note that upgrades to existing transmission facilities 
include both: (1) the incorporation of an alternative transmission 
technology into an existing transmission facility with no additional 
changes to the underlying transmission facility (e.g., adding 
dynamic line ratings to an existing transmission facility); and (2) 
the incorporation of an alternative transmission technology into an 
existing transmission facility as part of a larger set of upgrades 
(e.g., adding dynamic line ratings to a transmission facility that 
is also being reconductored with a conventional aluminum conductor 
steel reinforced conductor).
---------------------------------------------------------------------------

    1199. However, transmission providers' evaluation of the enumerated 
alternative transmission technologies must be consistent with the 
requirements in their OATTs for other transmission solutions. This 
means that, for the purposes of Long Term Regional Transmission 
Planning, transmission providers must evaluate the benefits of 
incorporating the enumerated alternative transmission technologies into 
Long-Term Regional Transmission Facilities in the same manner that they 
evaluate any Long-Term Regional Transmission Facility, and in a manner 
consistent with the requirements in the Evaluation of Benefits of 
Regional Transmission Facilities and Evaluation and Selection of Long-
Term Regional Transmission Facilities sections of this final order. 
Accordingly, we require transmission providers to measure the required 
benefits and any additional benefits the transmission providers elect 
to measure, as discussed in detail in the Required Benefits 
section,\2556\ and use those measured benefits in their evaluation 
processes to determine if a regional transmission facility that 
incorporates, or solely consists of, any of the enumerated list of 
alternative transmission technologies would more efficiently or cost-
effectively address Long-Term Transmission Needs. As discussed in 
detail in the Evaluation and Selection of Long-Term Regional 
Transmission Facilities section,\2557\ that determination would involve 
applying the transmission providers' selection criteria, which must, 
among other things, seek to maximize benefits accounting for costs over 
time without over-building transmission facilities. Similarly, for the 
purposes of existing Order No. 1000 regional transmission planning 
processes, transmission providers must consider the benefits of 
incorporating the enumerated alternative transmission technologies into 
transmission facilities in the same way that they currently evaluate 
regional transmission facilities in those existing processes to 
determine if a regional transmission facility incorporating any of the 
enumerated transmission technologies would be a more efficient or cost-
effective regional transmission solution.
---------------------------------------------------------------------------

    \2556\ Supra Required Benefits section.
    \2557\ Supra Evaluation and Selection of Long-Term Regional 
Transmission Facilities section.
---------------------------------------------------------------------------

    1200. In response to concerns regarding the mandatory consideration 
of the enumerated alternative transmission technologies for new 
regional transmission facilities,\2558\ and the incremental increase in 
costs associated with incorporating an alternative transmission 
technology into new regional transmission facilities or upgrades to 
existing transmission facilities,\2559\ we reiterate that transmission 
providers must follow the evaluation process and selection criteria in 
their tariffs. As explained in the Evaluation and Selection of Long-
Term Regional Transmission Facilities section of this final order, this 
does not require transmission providers to select any particular Long-
Term Regional Transmission Facility to address Long-Term Transmission 
Needs (i.e., in this case it does not require the selection and 
deployment of any particular alternative transmission technology with 
regard to any particular Long-Term Transmission Need).\2560\ We 
recognize that, in addition to considering the costs and benefits 
associated with incorporating alternative transmission technologies 
into transmission facilities, transmission providers must continue to 
follow Good Utility Practice with regard to planning, evaluating, 
selecting, constructing, operating, and maintaining all transmission 
facilities, whether such transmission facilities are considered and 
implemented through existing regional transmission planning processes 
or as part of Long-Term Regional Transmission Planning as set forth in 
this final order.\2561\
---------------------------------------------------------------------------

    \2558\ CAISO Initial Comments at 6; Exelon Initial Comments at 
21-22.
    \2559\ Exelon Initial Comments at 19-20.
    \2560\ Supra Evaluation and Selection of Long-Term Regional 
Transmission Facilities section.
    \2561\ See pro forma OATT section 28.2 (Transmission Provider 
Responsibilities) (``The Transmission Provider will plan, construct, 
operate and maintain its Transmission System in accordance with Good 
Utility Practice and its planning obligations in Attachment K in 
order to provide the Network Customer with Network Integration 
Transmission Service over the Transmission Provider's Transmission 
System.'').
---------------------------------------------------------------------------

    1201. We find that it is appropriate to require transmission 
providers to consider whether it may be more efficient or cost-
effective to incorporate the enumerated alternative transmission 
technologies into both new regional transmission facilities and 
upgrades to existing transmission facilities because the record 
indicates that such technologies can provide benefits by improving the 
efficiency of transmission facilities, regardless of whether the 
facilities are already in-service or yet to be deployed.\2562\ We find 
that incorporating the enumerated

[[Page 49468]]

alternative transmission technologies as upgrades to existing 
transmission facilities has the potential to make the use of existing 
transmission infrastructure more efficient and optimize the performance 
of such infrastructure, mitigating or deferring the need for 
development of new regional transmission facilities.\2563\ Adding 
alternative transmission technologies to new regional transmission 
facilities may provide cost savings by improving operational efficiency 
of transmission facilities. Further, incorporating alternative 
transmission technologies into new transmission facilities may present 
more benefits and cost less than incorporating such technologies as 
retrofits after the regional transmission facility is deployed. We 
further find that requiring transmission providers to consider the 
enumerated alternative transmission technologies in Long-Term Regional 
Transmission Planning and existing regional transmission planning 
processes will ensure that transmission providers more fully consider a 
broader set of technologies that can address transmission needs more 
efficiently or cost-effectively.
---------------------------------------------------------------------------

    \2562\ See WATT Coalition Supplemental Comments at 2-3.
    \2563\ Pattern Energy Initial Comments at 29.
---------------------------------------------------------------------------

    1202. We clarify that the selection and use any of the enumerated 
alternative transmission technologies that are incorporated into an 
existing transmission facility should be treated as an upgrade to an 
existing transmission facility. Order No. 1000's elimination of any 
Federal right of right of first refusal for selected transmission 
facilities does not apply to upgrades to an existing transmission 
facility.\2564\ Therefore, an incumbent transmission provider would be 
designated to develop any alternative transmission technology that is 
selected for incorporation into that incumbent transmission provider's 
existing transmission facilities as the more efficient or cost-
effective solution.
---------------------------------------------------------------------------

    \2564\ The Commission stated in Order No. 1000 that the non-
incumbent transmission developer reforms do not affect the right of 
an incumbent transmission provider to build, own and recover costs 
for upgrades to its own transmission facilities, such as in the case 
of tower change outs or reconductoring, regardless of whether or not 
an upgrade has been selected in the regional transmission plan for 
purposes of cost allocation. In other words, an incumbent 
transmission provider would be permitted to maintain a Federal right 
of first refusal for upgrades to its own transmission facilities. 
Order No. 1000, 136 FERC ] 61,051 at P 319 (footnote omitted). The 
Commission clarified that ``the term upgrade means an improvement 
to, addition to, or replacement of a part of, an existing 
transmission facility. The term upgrades does not refer to an 
entirely new transmission facility.'' Order No. 1000-A, 139 FERC ] 
61,132 at P 426. The Commission further clarified that the 
requirement to eliminate a Federal right of first refusal does not 
apply to any upgrade, even where the upgrade requires the expansion 
of an existing right-of-way. Id. P 427.
---------------------------------------------------------------------------

    1203. With respect to alternative transmission technologies added 
or deployed on a new selected regional transmission facility, we 
clarify that the transmission developer that is designated to develop 
the underlying selected regional transmission facility, whether that 
developer is an incumbent transmission provider or a nonincumbent 
transmission developer, must also be designated to develop any 
alternative transmission technologies selected to be incorporated into 
the regional transmission facility, and thus, would be eligible to use 
the applicable regional cost allocation method.\2565\ For example, in a 
competitive bidding model, the transmission developer that submits the 
winning bid for a selected new regional transmission facility that 
includes an alternative transmission technology would be eligible to 
use the regional cost allocation method for that facility, including 
for the costs of any alternative transmission technologies. Similarly, 
in a sponsorship model, the transmission developer that sponsors a new 
regional transmission facility that includes any alternative 
transmission technologies would be eligible to use the regional cost 
allocation method for that facility, including for the costs of any 
alternative transmission technologies, consistent with the selection.
---------------------------------------------------------------------------

    \2565\ See FERC, Staff Report, 2017 Transmission Metrics 8 (Oct. 
6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf (describing the two general 
types of competitive transmission development processes, the 
``competitive bidding model'' and the ``sponsorship model'').
---------------------------------------------------------------------------

    1204. We further clarify that, under a sponsorship model, 
transmission providers' addition of an alternative transmission 
technology to a sponsored regional transmission facility proposal that 
is ultimately selected must not lead to the original sponsored regional 
transmission facility being labeled as an unsponsored regional 
transmission facility. Therefore, the sponsoring developer would be 
eligible to use the regional cost allocation method for the selected 
new regional transmission facility, as modified with the alternative 
transmission technology.
    1205. We also clarify that, for every competitive transmission 
development process in a given transmission planning region, 
transmission providers must identify with sufficient detail in their 
OATTs the point or points in a given process at which the transmission 
providers in the transmission planning region will consider the 
potential use of alternative transmission technologies, including the 
point at which qualified transmission developers must submit any 
proposal to incorporate alternative transmission technologies. This 
clarification is meant to ensure transparency for competing 
transmission developers and other stakeholders.\2566\
---------------------------------------------------------------------------

    \2566\ For example, in a competitive bidding model, transmission 
providers must make clear whether, and if so when, a qualified 
transmission developer can propose to incorporate alternative 
transmission technologies into a bid for a selected Long-Term 
Regional Transmission Facility. This transparency requirement 
ensures that competing transmission developers will be treated 
comparably because they will know whether and when they can propose 
to incorporate any additional alternative transmission technologies 
into a bid for a regional transmission facility that has been 
selected.
---------------------------------------------------------------------------

    1206. In response to comments that transmission providers should 
not be required to consider the enumerated alternative transmission 
technologies in regional transmission planning processes due to the 
costs and challenges associated with implementation,\2567\ we find that 
the examples in the record of implementation of dynamic line ratings, 
including ERCOT's experience with dynamic line ratings since 2005 and 
data from Oncor from 2011 to 2013,\2568\ and overall support for the 
consideration of advanced power flow control devices in transmission 
planning,\2569\ sufficiently demonstrate that transmission providers 
are capable of considering the enumerated alternative transmission 
technologies in Long-Term Regional Transmission Planning and existing 
regional transmission planning processes. Kansas Commission's position 
that consideration of alternative transmission technologies in regional 
transmission planning processes should be data-driven and supported by 
robust analysis demonstrating benefits is consistent with our 
determinations here.\2570\ Therefore, transmission providers must 
consider the incorporation of these enumerated alternative transmission 
technologies consistent with the specific requirements for analysis and 
evaluation of benefits in their OATTs, including those applicable to 
existing regional transmission planning processes and those required in 
this final order for Long-Term Regional

[[Page 49469]]

Transmission Planning.\2571\ We acknowledge Mississippi Commission's 
concerns about deploying alternative transmission technologies without 
consideration of their costs and note that, to the extent that a 
transmission provider selects a regional transmission facility that 
incorporates an enumerated alternative transmission technology, the 
transmission provider would only do so after evaluating the costs and 
benefits of that transmission facility, including the incorporation of 
the alternative transmission technology.\2572\
---------------------------------------------------------------------------

    \2567\ See, e.g., ATC Reply Comments at 3.
    \2568\ Hannon Armstrong Reply Comments at 2-3; WATT Coalition 
Reply Comments at app. B.
    \2569\ Ameren Initial Comments at 24-25; EEI Initial Comments at 
20-21; Entergy Initial Comments at 29; Exelon Initial Comments at 
23.
    \2570\ Kansas Commission Initial Comments at 19-20.
    \2571\ See supra Evaluation of the Benefits of Regional 
Transmission Facilities section.
    \2572\ Mississippi Commission Reply Comments at 8.
---------------------------------------------------------------------------

    1207. We disagree with commenter assertions that alternative 
transmission technologies are only operational tools and that 
transmission providers cannot rely on any additional capacity created 
by these technologies for the purpose of meeting transmission 
needs.\2573\ We note that Long-Term Regional Transmission Planning and 
existing regional transmission planning processes are designed to 
address a variety of needs, including not only reliability needs but 
also Long-Term Transmission Needs and economic needs. These processes 
are well-suited to evaluate the economic benefits of the enumerated 
alternative transmission technologies, which are relevant to assessing 
whether a regional transmission facility that incorporates such 
technologies is more efficient or cost-effective than a proposed 
regional transmission facility that does not use such technologies. We 
believe that the particular benefit measurement methods that 
transmission providers must develop, pursuant to requirements discussed 
below, to evaluate proposed Long-Term Regional Transmission Facilities 
can be used to measure the economic benefits of incorporating the 
enumerated alternative transmission technologies into transmission 
facilities.\2574\ As more fully described above in the Required 
Benefits section, these benefits include, but are not limited to, 
methods to measure production cost savings, reduced congestion due to 
fewer transmission outages, and capacity cost benefits from reduced 
peak energy losses. Similarly, we find that the enumerated alternative 
transmission technologies can provide those economic benefits that are 
already evaluated in existing regional transmission planning processes. 
Finally, contrary to commenters' concerns, the record here demonstrates 
that certain alternative transmission technologies are in some cases 
capable of enhancing reliability and providing additional 
capacity.\2575\
---------------------------------------------------------------------------

    \2573\ AEP Initial Comments at 6, 33; Indicated PJM TOs Initial 
Comments at 19; ITC Initial Comments at 6, 26-28; Louisiana 
Commission Initial Comments at 14 (citing Potomac Economics Initial 
Comments at 2); PJM Initial Comments at 8, 106, 108; PPL Initial 
Comments at 22; SERTP Sponsors Initial Comments at 36-37.
    \2574\ See supra Evaluation of the Benefits of Regional 
Transmission Facilities section.
    \2575\ See infra P 1241 for a more detailed discussion of the 
reliability benefits of dynamic line ratings and advanced power flow 
control devices; see also Ameren Initial Comments at 24; Bekaert 
Supplemental Comments at 1-2; CTC Global Initial Comments at 15.
---------------------------------------------------------------------------

    1208. In response to concerns about administrative burden and 
assertions that predictions about benefits are speculative,\2576\ we 
find that the potential advantages associated with adopting this reform 
(i.e., identifying more efficient or cost-effective regional 
transmission solutions) outweigh the potential administrative and 
analytical burden. As it pertains to dynamic line ratings, the 
information needed to inform the calculation of dynamic line ratings 
should be widely available. For example, NREL has published data on 
annual averages of windspeeds at 10 meters above the ground that could 
inform predictions for future wind conditions to facilitate 
calculations of economic benefits.\2577\ For the calculation of the 
economic benefits associated with dynamic lines ratings, it is 
appropriate for such calculations to use historical average wind speed 
and direction data to calculate average increases to transmission line 
transfer limits for use in benefit calculations. Average predicted wind 
speeds and direction should be sufficient to inform the transmission 
provider as to whether the implementation of dynamic line ratings on a 
specific transmission line may render that line a more efficient or 
cost-effective regional transmission solution, and such data are widely 
available.\2578\ We acknowledge that there is uncertainty with 
projections of any kind; however, it is not necessary to understand the 
precise future wind conditions at a specific future period to assess 
the expected economic benefits associated with the implementation of 
dynamic line ratings.
---------------------------------------------------------------------------

    \2576\ ATC Initial Comments at 10; Duke Initial Comments at 30-
31 (citing attach. A, Robert Pierce Aff. ]] 8-9); ISO-NE Initial 
Comments at 40-41; ITC Initial Comments at 26; Kansas Commission 
Initial Comments at 19-20; Large Public Power Initial Comments at 
32-33; MISO Initial Comments at 58; MISO TOs Initial Comments at 24; 
New York TOs Initial Comments at 22; Pacific Northwest Utilities 
Initial Comments at 15-16; SERTP Sponsors Initial Comments at 36-37; 
Southern Initial Comments at 35, Ex. 2, Daryl C. McGee at ] 16; US 
Chamber of Commerce Initial Comments at 9.
    \2577\ Data on annual averages of windspeeds at 10 meters above 
the ground is published by NREL in the form of both maps and tabular 
data. See NREL, Wind Resource Maps and Data, https://www.nrel.gov/gis/wind-resource-maps.html. As another example, data on monthly 
prevailing wind direction is published by the U.S. Department of 
Agriculture for various cities in all U.S. states in the form of 
graphical ``wind roses.'' See U.S. Dep't. of Agric., National. 
Weather and Climate Center, https://www.wcc.nrcs.usda.gov/ftpref/downloads/climate/windrose/.
    \2578\ See, e.g., NREL, Wind Resource Maps and Data, https://www.nrel.gov/gis/wind-resource-maps.html; U.S. Dep't of Agric., 
National Weather and Climate Center, https://www.wcc.nrcs.usda.gov/ftpref/downloads/climate/windrose/.
---------------------------------------------------------------------------

    1209. In response to arguments that the Commission should favor 
transmission provider flexibility with respect to consideration of 
alternative transmission technologies,\2579\ we note that the reforms 
adopted in this final order provide transmission providers with an 
appropriate amount of flexibility and do not require the selection of 
any particular enumerated alternative transmission technology to 
address any particular transmission need. As previously discussed, this 
requirement will ensure that transmission providers more consistently 
consider the costs and benefits associated with incorporating the 
enumerated alternative transmission technologies into regional 
transmission facilities. However, we recognize that transmission 
providers must also continue to follow Good Utility Practice when 
planning, evaluating, selecting, constructing, operating, and 
maintaining transmission facilities.
---------------------------------------------------------------------------

    \2579\ Avangrid Initial Comments at 31; Clean Energy Buyers 
Initial Comments at 25; Eversource Initial Comments at 27; Georgia 
Commission Initial Comments at 7-8; Idaho Power Initial Comments at 
9; New York TOs Initial Comments at 23; OMS Initial Comments at 9; 
PPL Initial Comments at 23.
---------------------------------------------------------------------------

    1210. Moreover, we decline to mandate further details on how 
transmission providers should evaluate the enumerated list of 
alternative transmission technologies as more efficient or cost-
effective solutions to transmission needs, beyond the requirements 
adopted in this final order. Thus, in response to comments from Smart 
Wires and WATT Coalition proposing that the Commission mandate either 
consideration or deployment of advanced power flow control devices in 
specific situations,\2580\ we find that transmission providers are the 
appropriate entity to identify, evaluate, and select specific solutions 
to specific transmission needs.\2581\
---------------------------------------------------------------------------

    \2580\ Smart Wires Initial Comments at 1, 3-5; WATT Coalition 
Initial Comments at 3-4.
    \2581\ See Order No. 1000, 136 FERC ] 61,051 at P 153 (noting 
that transmission providers retain the ultimate responsibility for 
transmission planning). As Entergy and Exelon attest, advanced power 
flow control devices are already considered in some transmission 
planning processes. See Entergy Initial Comments at 29; Exelon 
Initial Comments at 23.

---------------------------------------------------------------------------

[[Page 49470]]

    1211. In response to commenters urging the Commission to wait for 
transmission providers to comply with Order No. 881 before implementing 
the NOPR proposal,\2582\ such concerns are unpersuasive. Public utility 
transmission providers subject to Order No. 881 are required to 
implement these requirements by July 12, 2025.\2583\ As the Compliance 
Procedures section of the final order states, the date that 
transmission providers are required to begin considering the enumerated 
alternative transmission technologies will be the effective date of the 
applicable tariff provisions submitted to comply with this final order 
requirement. The final order also states that transmission providers 
must submit their compliance filings within ten months of the effective 
date of this final order, which is 60 days from the date of publication 
in the Federal Register. Moreover, even if the compliance submission 
deadline falls shortly before Order No. 881's implementation deadline, 
the operative date here is the date that the tariff revisions proposed 
in a transmission provider's compliance filing to this final order 
become effective, which is the effective date requested by the 
submitting transmission provider and accepted by the Commission.\2584\ 
Consequently, the transmission provider would not need to implement 
this final order requirement prior to the implementation of Order No. 
881 on July 12, 2025 unless it requests, and the Commission accepts, an 
earlier effective date for its tariff revisions.
---------------------------------------------------------------------------

    \2582\ ATC Reply Comments at 4-5; Dominion Initial Comments at 
40; Large Public Power Initial Comments at 5, 32-33; MISO TOs 
Initial Comments at 23-24.
    \2583\ See MATL LLP, 185 FERC ] 61,028, at P 10 (2023) (stating 
that July 12, 2025 is the implementation date of Order No. 
881(citing Order No. 881, 177 FERC ] 61,179 at P 361)).
    \2584\ See infra Compliance Procedures section.
---------------------------------------------------------------------------

    1212. Moreover, we find that concerns raised by commenters with 
respect to the interactions between the requirements that we establish 
in this final order and Order No. 881 to be speculative. We believe 
that the requirements to consider the enumerated alternative 
transmission technologies are separate from (but complementary to) the 
Commission's requirements in Order No. 881. In Order No. 881, as most 
relevant here, the Commission required the use of more accurate 
transmission line ratings using up-to-date forecasts of ambient air 
temperatures in transmission line ratings. By contrast, regarding the 
requirement to consider dynamic line ratings in this final order, 
transmission providers must consider the benefits associated with 
additional up-to-date transmission line rating input assumptions, 
specifically wind speed and direction and solar heating intensity.
    1213. We disagree with concerns that any mandate to consider 
dynamic line ratings in this proceeding might complicate the dynamic 
line ratings notice of inquiry (NOI) proceeding,\2585\ or that a 
mandate to consider dynamic line ratings in this proceeding ignores the 
record, and the technical challenges identified in, the dynamic line 
ratings NOI proceeding.\2586\ We find such concerns unpersuasive. Any 
potential future Commission action in the dynamic line ratings NOI 
proceeding remains hypothetical. Moreover, we expect transmission 
providers to consider both the benefits of dynamic line rating 
implementation and the challenges and costs associated with dynamic 
line rating implementation as part of their consideration of the 
technology in Long-Term Regional Transmission Planning and their 
existing regional transmission planning processes.
---------------------------------------------------------------------------

    \2585\ MISO TOs Initial Comments at 23-24.
    \2586\ Large Public Power Initial Comments at 32.
---------------------------------------------------------------------------

    1214. In response to requests for additional transparency,\2587\ we 
also adopt the NOPR proposal to expand the existing requirement 
established in Order No. 1000 for transmission providers' evaluation 
processes to culminate in a determination that is sufficiently detailed 
for stakeholders to understand why a particular transmission facility 
was selected or not selected. Specifically, we adopt the NOPR proposal 
to require that the determination include an explanation that is 
sufficiently detailed for stakeholders to understand why dynamic line 
ratings, advanced power flow control devices, advanced conductors, and/
or transmission switching were or were not incorporated into selected 
regional transmission facilities.
---------------------------------------------------------------------------

    \2587\ Certain TDUs Reply Comments at 8-9; DC and MD Offices of 
People's Counsel Initial Comments at 36; ENGIE Initial Comments at 
6; PIOs Initial Comments at 22.
---------------------------------------------------------------------------

    1215. With regard to the Commission's request for comment on 
whether to require non-RTO/ISO transmission planning regions to update 
their energy management systems or make other similar changes if 
dynamic line ratings are selected as a more efficient or cost-effective 
regional transmission facility, we require transmission providers to 
update their energy management systems, if needed to implement dynamic 
line ratings or any of the alternative transmission technologies. We 
note that some transmission providers in non-RTO/ISO transmission 
planning regions may already be able to implement the alternative 
transmission technologies, and, as a result of the Commission's 
Ambient-Adjusted Rating requirements in Order No. 881,\2588\ may have 
already updated their energy management systems, and therefore may not 
need further updates to their energy management systems. However, if a 
transmission provider must upgrade its energy management systems to 
implement any of the alternative transmission technologies, then 
consistent with other requirements in this final order, we require 
transmission providers to consider any possible energy management 
system upgrade costs needed to implement the selected alternative 
transmission technologies as part of their broader consideration of 
whether transmission facilities that incorporate alternative 
transmission technologies are more efficient or cost-effective regional 
transmission solutions. We further reiterate that transmission 
providers must provide an explanation that is sufficiently detailed for 
stakeholders to understand why any of the enumerated alternative 
transmission technologies were, or were not, incorporated into 
transmission facilities selected in the regional transmission plan for 
purposes of cost allocation. Moreover, we clarify that this explanation 
must be sufficiently clear to demonstrate whether the transmission 
provider did not select transmission facilities that incorporate any of 
the enumerated alternative transmission technologies, in part or 
primarily, due to concerns over the costs of upgrading energy 
management systems.
---------------------------------------------------------------------------

    \2588\ Order No. 881, 177 FERC ] 61,179 at P 84.
---------------------------------------------------------------------------

    1216. Finally, we find that WATT Coalition's request to consider 
incentives for deploying alternative transmission technologies is 
outside the scope of this proceeding.

B. Specific Alternative Transmission Technologies

1. NOPR Proposal
    1217. The Commission sought comment on whether there are other 
transmission technologies serving a transmission function that should 
be considered in regional transmission planning and cost allocation 
processes. The following section discusses comments on specific 
alternative transmission technologies that transmission providers are 
required to

[[Page 49471]]

consider pursuant to the requirements of this final order.
2. Comments on Specific Technologies
    1218. AEE notes that dynamic line ratings implementation will 
increase capacity and provide significant benefits to customers.\2589\ 
Michigan State Entities state that dynamic line ratings hold tremendous 
value for states like Michigan with cold, cloudy winters, during which 
there is a greater reliance on transmission to move distant wind 
generation.\2590\
---------------------------------------------------------------------------

    \2589\ AEE Reply Comments at 29 (citing US DOE, Dynamic Line 
Ratings Report to Congress 2019 26 (June 2022), https://www.energy.gov/sites/prod/files/2019/08/f66/Congressional_DLR_Report_June2019_final_508_0.pdf).
    \2590\ Michigan State Entities Initial Comments at 10.
---------------------------------------------------------------------------

    1219. AEE states that dynamic line ratings and similar technologies 
are so useful because they improve predictability.\2591\ AEE further 
contends that, in the longer-term, changing conditions will necessitate 
greater transmission deployment and the need for more transmission 
capacity, but without considering complementary technologies, the 
transmission buildout may be less efficient.\2592\
---------------------------------------------------------------------------

    \2591\ AEE Reply Comments at 30 (citing MISO Initial Comments at 
57-58).
    \2592\ Id.
---------------------------------------------------------------------------

    1220. Hannon Armstrong contends that ERCOT's experience with 
dynamic line ratings since 2005, as well as data from Oncor from 2011 
to 2013, demonstrates that this technology can provide significant 
savings through reduced congestion costs, allow for granular congestion 
management, and furnish congestion data. According to Hannon Armstrong, 
real-time dynamic ratings and reliability analysis improve transmission 
system operation and planning, provide opportunities for congestion 
mitigation, and could justify the cancellation of planned transmission 
upgrades. Hannon Armstrong concludes that dynamic line ratings can 
promote just and reasonable rates without compromising 
reliability.\2593\
---------------------------------------------------------------------------

    \2593\ Hannon Armstrong Reply Comments at 2.
---------------------------------------------------------------------------

    1221. As mentioned above, some commenters warn the Commission of 
potential reliability and operational impacts of the widespread use of 
dynamic line ratings.\2594\ Entergy explains that it has experienced 
significantly different weather readings at nearby weather sensors and 
cautions that the 2003 blackout was partially caused by overestimating 
the wind in transmission line ratings.\2595\
---------------------------------------------------------------------------

    \2594\ Duke Initial Comments at 31-32 (citing attach. A, Robert 
Pierce Aff. ] 11); Entergy Initial Comments at 27-28; MISO Initial 
Comments at 59-60.
    \2595\ Entergy Initial Comments at 27-28 (citing U.S. Canada 
Power System Outage Task Force, Final Report on the August 14, 2003 
Blackout in the United States and Canada: Causes and Recommendations 
58 (Apr. 2004)).
---------------------------------------------------------------------------

    1222. Some commenters that oppose the use of dynamic line ratings 
in transmission planning raise concerns about the reliability risks 
presented by dynamic line ratings.\2596\ PJM argues that dynamic line 
ratings are inappropriate for addressing reliability needs and may 
introduce operational risk because, for example, forecasted wind might 
not materialize and the actual real-time ratings would be lower than 
forecasted.\2597\ Southern argues that the assumption of dynamic line 
ratings leading to additional capacity will likely result in reduced 
system expansion, which could cause reliability problems in the long 
run.\2598\ Large Public Power and LADWP maintain that there is 
meaningful cybersecurity risk associated with the communications 
equipment needed to support dynamic line ratings.\2599\ However, WATT 
Coalition states that both traditional transmission solutions and grid 
enhancing technologies can result in problems, so the impact of 
solutions should be evaluated carefully to ensure that a solution to 
one problem does not create another.\2600\
---------------------------------------------------------------------------

    \2596\ ATC Initial Comments at 7, 10; Duke Initial Comments at 
31; Exelon Initial Comments at 22; Indicated PJM TOs Initial 
Comments at 19; LADWP Initial Comments at 5; NRECA Initial Comments 
at 53; PJM Initial Comments at 108-109; Southern Initial Comments at 
35 (citing Ex. 2, Daryl C. McGee at ] 17); SERTP Sponsors Initial 
Comments at 36-37.
    \2597\ PJM Initial Comments at 108-109.
    \2598\ Southern Initial Comments at 35, Ex. 2, Daryl McGee at ] 
17.
    \2599\ LADWP Initial Comments at 5; Large Public Power Initial 
Comments at 35.
    \2600\ WATT Coalition Reply Comments at 4-5.
---------------------------------------------------------------------------

    1223. Some commenters argue that dynamic line ratings are 
operational in nature and do not belong in the transmission planning 
process.\2601\ Dominion and Exelon state that a transmission provider 
must plan and build its system for worst case scenarios, which limits 
the usefulness of dynamic line ratings in transmission planning.\2602\ 
ITC asserts that transmission systems must be planned based on actual 
transfer capacity under the worst-case scenario, and not on contingent, 
variable capacity of the type that dynamic line ratings provide.\2603\ 
EEI and Entergy note that the inherent variability and unpredictability 
associated with wind speed, solar heating intensity, and transmission 
line tension make dynamic line ratings inappropriate for addressing 
longer-term system planning objectives.\2604\ MISO adds that for 
transmission planning horizons of five to 20 years or more into the 
future, it is impossible to predict the real-time conditions on which 
dynamic line ratings are based.\2605\ NRECA explains that dynamic line 
ratings are not a substitute for an upgraded or new transmission 
facility.\2606\
---------------------------------------------------------------------------

    \2601\ AEP Initial Comments at 33; Dominion Initial Comments at 
40; Duke Initial Comments at 5; EEI Initial Comments at 21-22; 
Entergy Initial Comments at 5-6; Exelon Initial Comments at 22; 
Indicated PJM TOs Initial Comments at 19; ISO-NE Initial Comments at 
40-41; ITC Initial Comments at 6, 26-28; Louisiana Commission 
Initial Comments at 14 (citing Potomac Economics Initial Comments at 
2); MISO Initial Comments at 57; MISO TOs Initial Comments at 23; 
NRECA Initial Comments at 52; Pacific Northwest Utilities Initial 
Comments at 15-16; PJM Initial Comments at 8, 106, 108; PPL Initial 
Comments at 22; Southern Initial Comments at 35; SERTP Sponsors 
Initial Comments at 36-37; US Chamber of Commerce Initial Comments 
at 9.
    \2602\ Dominion Initial Comments at 40; Exelon Initial Comments 
at 22.
    \2603\ ITC Initial Comments at 26.
    \2604\ EEI Initial Comments at 21; Entergy Initial Comments at 
27.
    \2605\ MISO Initial Comments at 57-58.
    \2606\ NRECA Initial Comments at 52.
---------------------------------------------------------------------------

    1224. Many opposing commenters argue that the benefits of dynamic 
line ratings are too speculative.\2607\ MISO states that dynamic line 
ratings may not always produce the benefits anticipated, explaining 
that static ratings are typically based on conservative wind speeds and 
best-case wind direction, so the assumptions used to develop static 
ratings are not always worst-case.\2608\ ISO-NE asserts that, for 
example, under summer peak load conditions, the dynamic line rating 
would be the same as that assumed in the planning study.\2609\ Southern 
cautions that including dynamic line ratings in transmission planning 
would likely assume additional capacity that may not materialize in 
real time, increasing congestion.\2610\ Large Public Power and MISO TOs 
argue that dynamic line ratings do not provide sufficient incremental 
benefits over Ambient Adjusted Ratings to justify the additional 
expense.\2611\
---------------------------------------------------------------------------

    \2607\ ATC Initial Comments at 10; Duke Initial Comments at 30 
(citing attach. A, Robert Pierce Aff. ] 8); ISO-NE Initial Comments 
at 40-41; ITC Initial Comments at 26; Kansas Commission Initial 
Comments at 19-20; Large Public Power Initial Comments at 32-33; 
MISO Initial Comments at 58; MISO TOs Initial Comments at 24; New 
York TOs Initial Comments at 22; Pacific Northwest Utilities Initial 
Comments at 15-16; SERTP Sponsors Initial Comments at 36-37; 
Southern Initial Comments at 35, Ex. 2, Daryl C. McGee at ]] 16-17; 
US Chamber of Commerce Initial Comments at 9.
    \2608\ MISO Initial Comments at 58.
    \2609\ ISO-NE Initial Comments at 40-41.
    \2610\ Southern Initial Comments at 35, Ex. 2, Daryl C. McGee at 
]] 16-17.
    \2611\ Large Public Power Initial Comments at 32-33; MISO TOs 
Initial Comments at 24.

---------------------------------------------------------------------------

[[Page 49472]]

    1225. Some commenters argue that advanced power flow control 
devices are appropriate technologies to consider in transmission 
planning, contrasting them with dynamic line ratings.\2612\ Southern 
states that it generally supports consideration of advanced power flow 
control devices, and Ameren argues that they may be appropriate in 
certain circumstances for regional transmission planning.\2613\ 
Additionally, while WATT Coalition agrees that conductor-mounted 
advanced power flow control devices are limited in impact, it contends 
that today's ground-mounted versions can significantly increase 
transfer capacity and integration of renewables.\2614\
---------------------------------------------------------------------------

    \2612\ EEI Initial Comments at 20-21; Entergy Initial Comments 
at 29; Exelon Initial Comments at 23-24.
    \2613\ Ameren Initial Comments at 24-25; Southern Initial 
Comments, Ex. 2, Daryl C. McGee at ] 15.
    \2614\ WATT Coalition Reply Comments at 4.
---------------------------------------------------------------------------

    1226. Industrial Customers assert that the Commission should compel 
the use of advanced power flow control devices because they are 
instrumental to ensuring that transmission lines are fully used to 
their safest and most efficient potential.\2615\ Industrial Customers 
further argue that the use of advanced power flow control devices will 
allow for the optimization of transmission lines under various weather 
conditions.\2616\ Smart Wires states that advanced power flow control 
devices can provide a more affordable means of servicing the type of 
load growth driving Long-Term Regional Transmission Facilities.\2617\ 
In addition, Smart Wires argues that several system studies have 
verified that advanced power flow control devices avoid sub-synchronous 
resonance events on long radial transmission lines, which can result in 
extensive damage.\2618\
---------------------------------------------------------------------------

    \2615\ Industrial Customers Reply Comments at 13-14.
    \2616\ Id. at 18-19 (citing PPL, Initial Comments, Docket No. 
AD22-5-000, at 3 (filed Apr. 25, 2022)).
    \2617\ Smart Wires Initial Comments at 3-4.
    \2618\ Id. at 1, 4.
---------------------------------------------------------------------------

    1227. In response to the administrative burden of considering 
advanced power flow control devices specifically, WATT Coalition states 
that it provides guidance and evidence of successful modeling schemes 
for such devices.\2619\ WATT Coalition argues that advanced power flow 
control devices are a valuable solution to limitations of power system 
studies because they can be adjusted by grid operators for unforeseen 
grid challenges.\2620\ WATT Coalition adds that advanced power flow 
control devices have a granular dispatchability that can also support 
real-time operational needs, which may differ from those identified in 
the transmission planning timeframe.\2621\
---------------------------------------------------------------------------

    \2619\ WATT Coalition Reply Comments at 3 (citing app. C).
    \2620\ Id. at 4.
    \2621\ Id.
---------------------------------------------------------------------------

    1228. Similar to dynamic line ratings, many commenters argue that 
advanced power flow control devices are not appropriate in the 
transmission planning context and are more appropriate for operational 
timeframes.\2622\ Duke and MISO caution against widespread deployment 
of advanced power flow control devices.\2623\ Duke argues that they 
should be applied judiciously, and that increased deployment creates a 
greater risk of wide area cascading events by increasing the 
probability of the system being in a previously unanalyzed state.\2624\ 
MISO states that, while advanced power flow control devices work best 
to address specific isolated issues, it is not feasible to coordinate 
the operation and deployment of these devices en masse, either manually 
or automatically. According to MISO, deployment of these devices could 
create other issues, and thus their operation and deployment must be 
managed on a holistic basis.\2625\ MISO further states that advanced 
power flow control devices could result in continued cascading issues 
across the system because of the potential widespread impact of 
adjusting line impedances that may get pushed to other 
facilities.\2626\
---------------------------------------------------------------------------

    \2622\ AEP Initial Comments at 6; Indicated PJM TOs Initial 
Comments at 19; ITC Initial Comments at 6, 26-28; Louisiana 
Commission Initial Comments at 14 (citing Potomac Economics Initial 
Comments at 2); PJM Initial Comments at 8, 106, 108; PPL Initial 
Comments at 22; SERTP Sponsors Initial Comments at 36-37.
    \2623\ Duke Initial Comments at 31-32; MISO Initial Comments at 
59-60.
    \2624\ Duke Initial Comments at 31-32.
    \2625\ MISO Initial Comments at 59.
    \2626\ Id. at 60.
---------------------------------------------------------------------------

    1229. A number of commenters assert that the Commission should 
expand the list of alternative transmission technologies that must be 
considered.\2627\ Several commenters suggest that the Commission should 
require transmission providers to consider specific additional 
technologies in Long-Term Regional Transmission Planning, including 
storage that performs a transmission function, advanced conductors, 
transmission switching, topology optimization, and dynamic reactive 
power devices.\2628\ Some Federal legislators agree, offering support 
for a requirement to consider energy storage, reconductoring using 
advanced conductors,\2629\ and topology optimization.\2630\ AEE argues 
that expanding the list of technologies that must be considered in 
transmission planning would fulfill the Commission's obligations under 
the FPA to encourage the adoption of advanced transmission 
technologies.\2631\
---------------------------------------------------------------------------

    \2627\ ACEG Initial Comments at 31; ACORE Initial Comments at 
16; ACORE Supplemental Comments at 1; AEE Reply Comments at 27-28; 
Bekaert Supplemental Comments at 1; Breakthrough Energy Initial 
Comments at 16; CARE Coalition Initial Comments at 2-3; CARE 
Coalition Reply Comments at 5; Certain TDUs Reply Comments at 8-9; 
City of New York Reply Comments at 4 (citing PIOs Initial Comments 
at 84); Clean Energy Associations Initial Comments at 27-28; Clean 
Energy Associations Reply Comments at 7; CTC Global Initial Comments 
at 14-15; Industrial Customers Reply Comments at 11; Invenergy 
Initial Comments at 16; Vermont State Entities Initial Comments at 
9.
    \2628\ Dynamic reactive power is produced from equipment that 
can quickly change the Mvar level independent of the voltage level. 
Thus, the equipment can increase its reactive power production level 
when voltage drops and prevent a voltage collapse. Static VAR 
compensators, synchronous condensers, and generators provide dynamic 
reactive power. FERC, Staff Report, Principles for Efficient and 
Reliable Reactive Power Supply and Consumption 7 (Feb. 4, 2005), 
https://www.ferc.gov/sites/default/files/2020-04/20050310144430-02-04-05-reactive-power.pdf.
    \2629\ Environmental Legislators Caucus Supplemental Comments at 
2; Senator Schumer Supplemental Comments at 2.
    \2630\ Environmental Legislators Caucus Supplemental Comments at 
2.
    \2631\ AEE Reply Comments at 27-28, 34 (citing 42 U.S.C. 
16422(b)).
---------------------------------------------------------------------------

    1230. Several commenters urge the Commission to require that 
storage be considered.\2632\ CARE Coalition states that utilities can 
use storage to defer investments as supply and demand patterns change, 
allowing them to avoid all-in, 50-year investments in favor of shorter-
term flexibility.\2633\ CARE Coalition cites a number of ways that 
storage can improve transmission,

[[Page 49473]]

including providing voltage support in a transmission-constrained zone, 
ensuring reliability while repairs are executed, reducing peak loads, 
increasing capacity on congested lines, directing power flow away from 
lower capacity transmission lines, and controlling the timing of power 
flows to remain under thresholds.\2634\
---------------------------------------------------------------------------

    \2632\ Advanced Energy Buyers Initial Comments at 4; AEP Initial 
Comments at 33-34; CAISO Initial Comments at 38; California 
Commission Initial Comments at 38-40 (citing Jennifer Chen & Devin 
Hartmann, Transmission Reform Strategy From A Customer Perspective: 
Optimizing Net Benefits And Procedural Vehicles R Street Policy 
Study 7 (May 2022), https://www.rstreet.org/wp-content/uploads/2022/05/RSTREET257.pdf); CARE Coalition Initial Comments at 2-3; Clean 
Energy Associations Initial Comments at 30-31; Conservative Energy 
Network Supplemental Comments at 1-2; Conservatives for Clean 
Energy--Florida Supplemental Comments at 1-2; Conservatives for 
Clean Energy--South Carolina Supplemental Comments at 1; DC and MD 
Offices of People's Counsel Initial Comments at 36-37; Illinois 
Commission Initial Comments at 12; Industrial Customers Reply 
Comments at 11; Joint Consumer Advocates Initial Comments at 13; 
Michigan Conservative Energy Forum Supplemental Comments at 1; NARUC 
Initial Comments at 36; National Grid Initial Comments at 3-4; Ohio 
Conservative Energy Forum Supplemental Comments at 1; OMS Initial 
Comments at 9; Western Way Colorado Supplemental Comments at 2; 
Western Way Nevada Supplemental Comments at 2; Western Way Utah 
Supplemental Comments at 2; Wisconsin Conservative Energy Forum 
Supplemental Comments at 1.
    \2633\ CARE Coalition Initial Comments at 42-43.
    \2634\ Id. at 42.
---------------------------------------------------------------------------

    1231. AEP states that the Commission should require better 
consideration of storage, noting that the technology has advanced 
significantly in the past several years, yet is still not being 
deployed as a transmission alternative. AEP cites two reasons for this: 
(1) despite the multiple uses and benefits of storage, it is currently 
categorized as only one of the following--transmission, generation, or 
distribution, and (2) there is no traditional approach that assesses 
the viability of storage proposals to solve reliability problems. AEP 
states that, to solve these problems, the Commission should provide 
more certainty around these questions, including how to schedule, 
dispatch, and charge storage, as well as guidance on how to assess the 
value of storage beyond reliability if, for example, the resource is 
only needed during certain times of year.\2635\
---------------------------------------------------------------------------

    \2635\ AEP Initial Comments at 33-34.
---------------------------------------------------------------------------

    1232. Some commenters suggest that the Commission should require 
consideration of advanced conductors in Long-Term Regional Transmission 
Planning.\2636\ CTC Global asserts that advanced conductors should be 
required to be considered because of their ease of installation onto 
existing structures, cost savings, lower line sag, and power flow 
increase.\2637\ CTC Global adds that even in the case of a total 
rebuild, advanced conductors can generate more capacity, efficiency, 
resilience, and reliability than rebuilds using standard 
conductors.\2638\ VEIR notes that if the final order requires the 
consideration of advanced conductors, the Commission should define 
advanced conductors to include all advanced conductor technologies, 
including superconductors.\2639\ Bekaert states that the definition of 
advanced conductors should extend beyond carbon fiber core technologies 
to also include steel core technologies, which it contends can raise 
ampacity, reduce line losses, and withstand extreme weather conditions, 
all while offering a cost-effective solution.\2640\
---------------------------------------------------------------------------

    \2636\ ACEG Initial Comments at 31; ACORE Initial Comments at 
16; Breakthrough Energy Initial Comments at 15-19; CTC Global 
Initial Comments at 15-16; DC and MD Offices of People's Counsel 
Initial Comments at 36-37; Indicated US Senators and Representatives 
Initial Comments at 2; NASEO Initial Comments at 6; Prysmian Initial 
Comments at 1; VEIR Initial Comments at 5-6.
    \2637\ CTC Global Initial Comments at 14-15.
    \2638\ Id. at 15.
    \2639\ VEIR Reply Comments at 5.
    \2640\ Bekaert Supplemental Comments at 1-2.
---------------------------------------------------------------------------

    1233. Some commenters suggest that the Commission should require 
consideration of transmission switching in Long-Term Regional 
Transmission Planning.\2641\ For example, Illinois Commission states 
that line switching is a tool to make better use of the extant 
transmission system.\2642\ NASEO states that the use of alternative 
transmission technologies, including transmission switching, is 
increasing.\2643\ However, MISO argues that grid enhancing technologies 
that introduce automatic topology changes are not appropriate for 
consideration over transmission planning horizons of 20 years or more 
because they would be considered remedial action schemes, which MISO 
and its transmission owners have attempted to reduce as a matter of 
Good Utility Practice.\2644\
---------------------------------------------------------------------------

    \2641\ Illinois Commission Initial Comments at 12; NASEO Initial 
Comments at 6; Potomac Economics Initial Comments at 5.
    \2642\ Illinois Commission Initial Comments at 12 (citing Pablo 
A. Ruiz, The Brattle Group, Transmission Topology Optimization (Aug. 
21, 2017) https://www.brattle.com/wp-content/uploads/2017/10/7204_transmission_topology_optimization.pdf (Brattle Group Aug. 2017 
Report)).
    \2643\ NASEO Initial Comments at 6.
    \2644\ MISO Initial Comments at 60.
---------------------------------------------------------------------------

    1234. A number of commenters suggest that the Commission should 
require consideration of topology optimization in Long-Term Regional 
Transmission Planning.\2645\ Potomac Economics states that network 
optimization can allow a transmission operator to circumvent a limiting 
transmission facility and substantially mitigate the associated 
congestion, averting transmission upgrades that could prove wasteful 
and inefficient.\2646\ With respect to topology optimization, WATT 
Coalition recommends that the information provided in the evaluation 
process should include modeling assumptions, contingency analysis 
results, asset age and condition, environmental and footprint 
constraints, etc.\2647\ In contrast, SPP states that technologies that 
optimize transmission system operation should be considered short-term 
solutions and not a replacement for long-term transmission 
capacity.\2648\
---------------------------------------------------------------------------

    \2645\ ACORE Initial Comments at 16; CARE Coalition Initial 
Comments at 2-3; ENGIE Initial Comments at 5-6; Illinois Commission 
Initial Comments at 11-13 (citing Brattle Group Aug. 2017 Report); 
Indicated US Senators and Representatives Initial Comments at 2; 
Potomac Economics Initial Comments at 5; R Street Initial Comments 
at 4; Tabors Caramanis Rudkevich Initial Comments at 5; WATT 
Coalition Initial Comments at 6.
    \2646\ Potomac Economics Initial Comments at 5.
    \2647\ WATT Coalition Initial Comments at 6.
    \2648\ SPP Initial Comments at 26.
---------------------------------------------------------------------------

    1235. ITC argues that the Commission should encourage transmission 
providers to modernize transmission planning criteria to better 
consider dynamic reactive power devices such as static VAR 
compensators, static synchronous compensators, and unified power flower 
controllers. ITC asserts that such technologies provide faster response 
times to changes in voltage and power factor, relative to capacitor 
banks and mechanically switched compensation schemes.\2649\
---------------------------------------------------------------------------

    \2649\ ITC Initial Comments at 28.
---------------------------------------------------------------------------

    1236. Industrial Customers and Ohio Consumers suggest that the 
Commission should require the consideration of distributed energy 
resources in Long-Term Regional Transmission Planning.\2650\ Industrial 
Customers contend that demand response and load-limiting devices should 
be considered as a way of optimizing the current transmission system, 
claiming that they are less costly than transmission expansions.\2651\ 
QCo states that the Commission should consider the use of the thermal 
mass of major buildings as a low-cost method to store energy and 
provide flexibility to the grid.\2652\
---------------------------------------------------------------------------

    \2650\ Industrial Customers Initial Comments at 35; Ohio 
Consumers Initial Comments at 34.
    \2651\ Industrial Customers Reply Comments at 11.
    \2652\ QCo Initial Comments at 1-3.
---------------------------------------------------------------------------

    1237. ENGIE asserts that the Commission should require 
consideration of dynamic transformer rating technology in Long-Term 
Regional Transmission Planning.\2653\
---------------------------------------------------------------------------

    \2653\ ENGIE Initial Comments at 5-6.
---------------------------------------------------------------------------

    1238. Exelon is concerned that making a list of technologies to 
consider in transmission planning will result in a ``time-consuming 
check-the-box exercise,'' increasing costs and creating litigation 
opportunities.\2654\
---------------------------------------------------------------------------

    \2654\ Exelon Initial Comments at 23-24.
---------------------------------------------------------------------------

3. Commission Determination
    1239. As stated above, we adopt the NOPR proposal, with 
modification, to require transmission providers in each transmission 
planning region to consider dynamic line ratings and advanced power 
flow control devices in Long-Term Regional Transmission Planning and 
existing Order No. 1000 regional transmission planning processes.
    1240. In response to comments that dynamic line ratings are 
operational in nature and are inappropriate in transmission planning, 
we continue to believe that there is enough real-world operational 
experience with dynamic

[[Page 49474]]

line ratings for transmission providers to be able to reasonably 
project their likely operations and, as such, the benefits that 
regional transmission facilities that incorporate dynamic line ratings 
can provide over the transmission planning horizon.\2655\ Dynamic line 
ratings have the ability to increase transmission line ratings, and 
thus permit more economic energy transfers in most intervals,\2656\ 
which, in turn, could result in benefits (including, but not limited 
to, production cost savings, reduced congestion due to fewer 
transmission outages resulting from improved situational awareness, and 
capacity cost benefits from reduced peak energy losses) that we require 
transmission providers to evaluate in Long-Term Regional Transmission 
Planning,\2657\ and in their existing regional transmission planning 
processes.
---------------------------------------------------------------------------

    \2655\ NOPR, 179 FERC ] 61,028 at P 276.
    \2656\ Hannon Armstrong Reply Comments at 1-3.
    \2657\ See supra Required Benefits section.
---------------------------------------------------------------------------

    1241. We acknowledge commenter concerns about the potential effects 
that the widespread use of dynamic line ratings or advanced power flow 
control devices could have on reliability.\2658\ But while these 
technologies cannot solve all reliability needs, as noted above, the 
record here demonstrates that alternative transmission technologies are 
in certain circumstances capable of enhancing reliability and providing 
additional capacity.\2659\ We recognize that, either dynamic line 
ratings or advanced power flow control devices, on their own, may be 
unlikely to resolve certain reliability needs that are assessed based 
on worst case conditions.\2660\ We also reiterate that nothing in this 
final order changes transmission providers' obligations to conduct 
transmission planning in a manner that ensures the long-term 
reliability of the bulk electric system.\2661\ However, we find that 
dynamic line ratings and advanced power flow control devices can also 
confer reliability benefits. For example, in Order No. 881, the 
Commission found that, by accounting for ambient air temperatures in 
transmission line ratings, transmission providers can reliably increase 
power transfer capability, which results in significant reliability 
benefits.\2662\ Such reliability benefits also apply to dynamic line 
ratings. Specifically, by accounting for actual wind conditions, 
dynamic line ratings can also reliably increase transfer capability and 
thereby provide reliability benefits. Similarly, as Ameren describes, 
it may be more efficient to use advanced power flow control devices, 
which can address stability limitations by allowing for greater use of 
a transmission facility.\2663\
---------------------------------------------------------------------------

    \2658\ See, e.g., CAISO Initial Comments at 41-42.
    \2659\ See supra P 1206 of this section.
    \2660\ For example, as ISO-NE explains, the dynamic line rating 
may be the same as the rating already assumed in the planning study 
as transmission providers may need to assume worst case weather 
inputs to transmission line ratings. ISO-NE Initial Comments at 40-
41.
    \2661\ See, for example, TPL-001-5.1, Transmission System 
Planning Performance Requirements, which establishes transmission 
system planning performance requirements within the planning horizon 
to develop a bulk electric system that will operate reliably over a 
broad spectrum of system conditions and following a wide range of 
probable contingencies.
    \2662\ Order No. 881, 177 FERC ] 61,179 at P 85.
    \2663\ Ameren Initial Comments at 24.
---------------------------------------------------------------------------

    1242. Additionally, Long-Term Regional Transmission Planning 
evaluates Long-Term Regional Transmission Facilities based on multiple 
benefits, and some existing regional transmission planning processes 
focus on economic benefits, while others may consider multiple 
benefits, including economic benefits. At a minimum, regional 
transmission solutions incorporating dynamic line ratings are 
appropriately considered as part of these processes. Given the 
potentially substantial economic benefits of dynamic line ratings, we 
find that it is important for transmission providers to consider 
dynamic line ratings in Long-Term Regional Transmission Planning and 
their existing regional transmission planning processes so as to ensure 
that they identify more efficient or cost-effective regional 
transmission facilities for selection.
    1243. We also disagree with commenters that argue that advanced 
power flow control devices are not appropriate in the transmission 
planning context and are more appropriate for operational timeframes. 
We find that the potential benefits of using advanced power flow 
control devices are sufficient to merit their consideration in Long-
Term Regional Transmission Planning and existing regional transmission 
planning processes. For example, as Ameren states, where a transmission 
line is stability-limited from carrying more power, the use of advanced 
power flow controls may address the limitation and allow greater use of 
the line. Ameren also notes that advanced power flow controls may be 
beneficial in a situation where a transmission line that needs to be 
upgraded traverses sensitive environmental areas.\2664\ Moreover, as 
Entergy and Exelon attest, advanced power flow control devices are 
already considered in some transmission planning processes.\2665\ As 
discussed above, we modify the NOPR proposal to add two additional 
alternative transmission technologies to the list of enumerated 
alternative transmission technologies required to be considered in 
Long-Term Regional Transmission Planning and existing regional 
transmission planning: advanced conductors and transmission switching. 
We find that advanced conductors may greatly increase the capacity of 
transmission facilities, and thus a new regional transmission facility 
or upgrade to an existing transmission facility that incorporates 
advanced conductors may be a more efficient or cost-effective 
alternative than a proposed regional transmission facility that does 
not incorporate such technologies. Consistent with Order No. 2023, we 
note that advanced conductors can increase transmission line ratings, 
providing more ``headroom'' on the system to address normal and 
contingency conditions.\2666\ We clarify that the definition of 
advanced conductors that we adopt in this final order constitutes a 
range of permissible present and future technologies, and is defined 
relative to conventional aluminum conductor steel reinforced 
conductors. Therefore, advanced conductors include, but are not limited 
to, superconducting cables, advanced composite conductors, advanced 
steel cores, high temperature low-sag conductors, fiber optic 
temperature sensing conductors, and advanced overhead conductors. We 
find that such advanced conductors can result in lower line sag and 
increased power flow and can be installed on existing transmission 
structures, thereby offering ease of installation.\2667\
---------------------------------------------------------------------------

    \2664\ Id.
    \2665\ Entergy Initial Comments at 29; Exelon Initial Comments 
at 23.
    \2666\ Order No. 2023, 184 FERC ] 61,054 at P 1597.
    \2667\ CTC Global Initial Comments at 14-15.
---------------------------------------------------------------------------

    1244. We agree with commenters that suggest that transmission 
switching should be added to the list of alternative transmission 
technologies that must be considered in Long-Term Regional Transmission 
Planning and existing regional transmission planning processes.\2668\ 
We clarify that, in this final order, we define transmission switching 
as the opening or closing of transmission elements to safely route 
power and direct flows away from congestion, based on pre-existing 
forward analysis. Transmission switching can be used to route energy 
around areas with high congestion and

[[Page 49475]]

improve the overall transfer capability of the system. In doing so, 
transmission switching may provide additional economic or reliability 
benefits, which could therefore render a transmission facility that 
uses transmission switching a more efficient or cost-effective 
alternative than a regional transmission facility that does not use 
transmission switching. In response to MISO's concern that automatic 
topology changes are not appropriate for consideration over 
transmission planning horizons of 20 years or more because they would 
be considered remedial action schemes,\2669\ we note that there are 
appropriate applications for transmission switching that offer the 
potential to be a more efficient or cost-effective alternative than a 
proposed regional transmission facility that does not use one of the 
enumerated alternative transmission technologies. For example, the 
record indicates that network optimization can allow a transmission 
operator to circumvent a limiting transmission facility and 
substantially mitigate the associated congestion, averting transmission 
upgrades that could prove wasteful and inefficient.\2670\
---------------------------------------------------------------------------

    \2668\ Illinois Commission Initial Comments at 12; NASEO Initial 
Comments at 6; Potomac Economics Initial Comments at 5.
    \2669\ MISO Initial Comments at 60.
    \2670\ Potomac Economics Initial Comments at 5.
---------------------------------------------------------------------------

    1245. We decline to add storage that performs a transmission 
function to the list of enumerated alternative transmission 
technologies. The Commission has determined that the evaluation of 
whether an electric storage resource performs a transmission function 
requires a case-by-case analysis of either how a particular electric 
storage resource would be operated or the requirements set forth in an 
OATT governing selection of such electric storage resources.\2671\ In 
the context of regional transmission planning, we continue to find that 
the evaluation of whether an electric storage resource performs a 
transmission function requires a case-by-case analysis, and therefore 
decline to generically require the consideration of storage that 
performs a transmission function in regional transmission planning 
processes.
---------------------------------------------------------------------------

    \2671\ Order No. 2023, 184 FERC ] 61,054 at P 1599.
---------------------------------------------------------------------------

    1246. For the following reasons, we also decline to add topology 
optimization to the list of enumerated alternative transmission 
technologies because it is technically much more challenging to 
implement. We clarify that topology optimization is not specific to 
individual transmission facilities but instead is the act of 
determining the optimal use of the transmission system, which may 
involve many different transmission facilities. Additionally, the 
optimal use of the transmission system may frequently change depending 
on system conditions throughout the operating day. By contrast, 
transmission switching focuses on opening or closing transmission 
elements in pre-determined circumstances based on prior analyses well 
in advance of the operational time horizon.\2672\ We do not find that 
it is necessary to require the consideration of topology optimization 
in regional transmission planning processes currently. While topology 
optimization software has been used to identify potential system 
reconfiguration actions that could result in a reduction in real-time 
congestion, it has not yet been deployed due to computational 
complexity. Specifically, given the size and complexity of the power 
grid and the large number of potential optimization solutions, finding 
optimization solutions in the necessary real-time timelines is 
extremely difficult and doing so risks poor model performance and lower 
quality solutions, which, in turn, could adversely impact reliability. 
While simplifications might be possible, such simplifications risk 
oversimplifying, which, in turn, could also jeopardize 
reliability.\2673\
---------------------------------------------------------------------------

    \2672\ See supra P 1243 of this section on transmission 
switching. We recognize that there may be overlap between the 
concepts of transmission switching and topology optimization. As 
noted below, nothing in this final order precludes transmission 
providers from considering topology optimization solutions as an 
alternative transmission technology, if they so choose.
    \2673\ US DOE, Advanced Transmission Technologies 11-15 (Dec. 
2020), https://www.energy.gov/oe/articles/advanced-transmission-technologies-report.
---------------------------------------------------------------------------

    1247. Finally, we decline to add further additional alternative 
transmission technologies suggested by commenters.\2674\ We note that, 
while commenters express support for the concept of considering 
additional alternative transmission technologies, in general, we do not 
believe that the record is sufficient to include these additional 
technologies on the enumerated list of alternative transmission 
technologies that transmission providers must consider in Long-Term 
Regional Transmission Planning and existing regional transmission 
planning processes at this time. However, we note that nothing in this 
final order precludes transmission providers from considering other 
alternative transmission technologies or other potential solutions in 
their Long-Term Regional Transmission Planning and existing regional 
transmission planning processes.
---------------------------------------------------------------------------

    \2674\ See supra PP 1235-1237.
---------------------------------------------------------------------------

VI. Regional Transmission Cost Allocation

A. Cost Allocation for Long-Term Regional Transmission Facilities

1. Cost Allocation Methods for Long-Term Regional Transmission 
Facilities
a. NOPR Proposal
    1248. In the NOPR, the Commission proposed to require transmission 
providers in each transmission planning region to revise their OATTs to 
include: (1) a Long-Term Regional Transmission Cost Allocation Method 
to allocate the costs of Long-Term Regional Transmission Facilities; 
(2) a State Agreement Process by which one or more Relevant State 
Entities \2675\ may voluntarily agree to a cost allocation method; or 
(3) a combination thereof.\2676\
---------------------------------------------------------------------------

    \2675\ The definition of Relevant State Entities is discussed 
below. See infra Requirement that Transmission Providers Seek the 
Agreement of Relevant State Entities Regarding the Cost Allocation 
Method or Methods for Long-Term Regional Transmission Facilities 
section.
    \2676\ NOPR, 179 FERC ] 61,028 at P 302. The Commission 
explained that, for example, a ``combination'' approach may entail: 
(1) providing a Long-Term Regional Transmission Cost Allocation 
Method for certain types of Long-Term Regional Transmission 
Facilities and providing a State Agreement Process for others; or 
(2) providing for cost allocation for a Long-Term Regional 
Transmission Facility, portfolio, or type of such facilities 
partially based on a Long-Term Regional Transmission Cost Allocation 
Method and partially based on funding contributions in accordance 
with a State Agreement Process. Id. P 302 n.510.
---------------------------------------------------------------------------

    1249. The Commission proposed to define a Long-Term Regional 
Transmission Cost Allocation Method as an ex ante regional cost 
allocation method that would be included in each transmission 
provider's OATT as part of Long-Term Regional Transmission Planning. 
The developer of a Long-Term Regional Transmission Facility would be 
entitled to use the Long-Term Regional Transmission Cost Allocation 
Method if it is the applicable method.\2677\ The Commission proposed to 
define a State Agreement Process as an ex post cost allocation process 
that would be included in each transmission provider's OATT as part of 
Long-Term Regional Transmission Planning, which may apply to an 
individual Long-Term Regional Transmission Facility or a portfolio of 
such Facilities grouped together for purposes of cost allocation. After 
a Long-Term Regional Transmission Facility is selected, the State 
Agreement Process would be followed to establish a cost allocation 
method for that facility (if agreement

[[Page 49476]]

can be reached). If the Commission approves the cost allocation method 
that results from the State Agreement Process, the developer of the 
Long-Term Regional Transmission Facility would be entitled to use that 
cost allocation method if it is the applicable method.\2678\
---------------------------------------------------------------------------

    \2677\ Id. P 302 n.508.
    \2678\ Id. P 302 n.509.
---------------------------------------------------------------------------

    1250. The Commission also proposed to apply the cost allocation 
reforms only to new Long-Term Regional Transmission Facilities. 
Therefore, these proposed reforms would neither provide grounds for re-
litigation of cost allocation decisions for transmission facilities 
that are selected prior to the effective date of any final order in 
this proceeding, nor would they apply to the cost allocation methods 
associated with regional transmission facilities that address shorter-
term transmission needs driven by reliability and/or economic 
considerations.\2679\
---------------------------------------------------------------------------

    \2679\ Id. P 314.
---------------------------------------------------------------------------

    1251. In addition, the Commission stated that, to the extent 
transmission providers believe that their existing cost allocation 
approaches comply with the requirements adopted in any final order in 
this proceeding, including those related to the agreement of Relevant 
State Entities, they could make such demonstration in their compliance 
filings in response to any final order.\2680\
---------------------------------------------------------------------------

    \2680\ Id.
---------------------------------------------------------------------------

b. Comments
i. Interest in the Proposed Cost Allocation Reforms
    1252. Some commenters offer general support for the cost allocation 
reforms proposed in the NOPR.\2681\
---------------------------------------------------------------------------

    \2681\ E.g., Breakthrough Energy Initial Comments at 6; Business 
Council for Sustainable Energy Initial Comments at 2; California 
Democratic Representatives Supplemental Comments at 2; Joint 
Consumer Advocates Initial Comments at 13; OMS Initial Comments at 
9; Pine Gate Initial Comments at 45; WE ACT Initial Comments at 5.
---------------------------------------------------------------------------

    1253. Several commenters indicate support for the proposal to 
require transmission providers to revise their OATTs to include: (1) a 
Long-Term Regional Transmission Cost Allocation Method to allocate the 
costs of Long-Term Regional Transmission Facilities; (2) a State 
Agreement Process by which one or more Relevant State Entities may 
voluntarily agree to a cost allocation method; or (3) a combination 
thereof.\2682\ Clean Energy Buyers state that this proposal will 
provide certainty in the cost allocation process, lessening disputes 
that may delay transmission development.\2683\ ITC suggests that the 
Commission look to OMS' role in State Agreement Processes as a guide 
for how other transmission planning regions can foster state 
participation in Long-Term Regional Transmission Planning.\2684\ AEP 
asserts that clear rules set in advance provide the regulatory 
certainty necessary to support large, long-term transmission 
investments and ensure customers and developers know how the associated 
costs will be allocated.\2685\
---------------------------------------------------------------------------

    \2682\ Certain TDUs Initial Comments at 2, 7; City of New 
Orleans Council Initial Comments at 9-10; Entergy Initial Comments 
at 29-30; Eversource Initial Comments at 29-30; ISO-NE Initial 
Comments at 37; ITC Initial Comments at 28; Kentucky Commission 
Chair Chandler Initial Comments at 3 (citing NOPR, 179 FERC ] 61,028 
at PP 302-303); Michigan Commission Initial Comments at 8; NARUC 
Initial Comments at 51; NESCOE Initial Comments at 10; New York 
Commission and NYSERDA Initial Comments at 12-13; New York TOs 
Initial Comments at 18; North Carolina Commission and Staff Initial 
Comments at 15-16; NYISO Initial Comments at 48-49; OMS Initial 
Comments at 10; Pacific Northwest State Agencies Initial Comments at 
27; Pattern Energy Initial Comments at 18; PIOs Initial Comments at 
64; PJM States Initial Comments at 9-10; Resale Iowa Initial 
Comments at 2, 12.
    \2683\ Clean Energy Buyers Initial Comments at 26-27.
    \2684\ ITC Reply Comments at 28-29.
    \2685\ AEP Initial Comments at 35.
---------------------------------------------------------------------------

    1254. New Jersey Commission states that a hybrid method that 
allocates costs partially ex ante, based on reliability and economic 
benefits, and partially ex post, through a State Agreement Process/
negotiated participant funding approach, could have value, arguing that 
negotiated cost allocations could reduce litigation and make it easier 
to construct beneficial transmission facilities.\2686\ SEIA supports a 
combination of a Long-Term Regional Transmission Cost Allocation Method 
and a State Agreement Process, asserting that states should be allowed 
to assume the costs of new transmission facilities to serve their 
needs.\2687\
---------------------------------------------------------------------------

    \2686\ New Jersey Commission Initial Comments at 17, 25.
    \2687\ SEIA Initial Comments at 24.
---------------------------------------------------------------------------

ii. Requested Clarifications and Concerns Related to the Proposed Cost 
Allocation Reforms
    1255. Some commenters raise concerns and request clarifications on 
the proposed reforms. For example, BP contends that, in the case of a 
multi-value project, it is unclear whether only a part of the cost of a 
transmission project associated with meeting changes in the resource 
mix and demand will be allocated under a Long-Term Regional 
Transmission Cost Allocation Method, as opposed to all of the 
costs.\2688\ NARUC requests that the Commission provide a mechanism for 
future review of cost allocation methods for Long-Term Regional 
Transmission Facilities.\2689\
---------------------------------------------------------------------------

    \2688\ BP Initial Comments at 12.
    \2689\ NARUC Initial Comments at 49-50.
---------------------------------------------------------------------------

    1256. Other commenters urge flexibility with respect to cost 
allocation methods and state involvement,\2690\ citing regional 
differences,\2691\ to improve the likelihood of achieving consensus 
between affected states.\2692\ OMS stresses the need for flexibility 
with respect to cost allocation methods to realize the NOPR's overall 
objectives of cost-effective regional transmission expansion.\2693\ 
Louisiana Commission, however, asserts that, whichever cost allocation 
method is adopted, it should not allow a majority to impose costs upon 
non-consenting states.\2694\
---------------------------------------------------------------------------

    \2690\ See, e.g., Entergy Initial Comments at 29-30; Eversource 
Initial Comments at 29-30; Idaho Power Initial Comments at 10; 
NESCOE Reply Comments at 5; Pacific Northwest Utilities Initial 
Comments at 5-6, 11, 13.
    \2691\ See, e.g., Dominion Initial Comments at 45; Ohio 
Commission Federal Advocate Initial Comments at 11.
    \2692\ New York TOs Initial Comments at 18; see also Northwest 
and Intermountain Initial Comments at 18.
    \2693\ OMS Initial Comments at 10.
    \2694\ Louisiana Commission Initial Comments at 33-34.
---------------------------------------------------------------------------

    1257. Shell states that the Commission should require coastal 
transmission providers to explain how their Long-Term Regional 
Transmission Planning processes facilitate transmission planning and 
cost allocation for offshore wind.\2695\ Shell further asserts that the 
Commission should require all transmission providers to account for the 
risk of free-ridership in their OATTs, arguing that regardless of the 
cost allocation method applied, the Commission should ensure that 
first-movers are protected from free-ridership.\2696\
---------------------------------------------------------------------------

    \2695\ Shell Initial Comments at 17.
    \2696\ Id. at 25, 28.
---------------------------------------------------------------------------

    1258. Some commenters express concerns about the proposed State 
Agreement Process.\2697\ Dominion states that a practical challenge in 
implementing the proposed reforms will be whether having an ex ante 
cost allocation method combined with alternative proposals or some 
combination thereof creates an additional opportunity to debate and 
challenge a transmission project, resulting in delays and increased 
costs.\2698\
---------------------------------------------------------------------------

    \2697\ We also address comments regarding the State Agreement 
Process in more detail below. See infra Proposals Relating to the 
Design and Operation of State Agreement Processes section.
    \2698\ Dominion Initial Comments at 52.

---------------------------------------------------------------------------

[[Page 49477]]

iii. Concerns With the Proposed Cost Allocation Reforms
    1259. Some commenters generally oppose the proposed reforms. For 
example, Southern states that the proposal to establish a specific cost 
allocation process before Long-Term Regional Transmission Planning has 
identified actual transmission projects is too abstract to work in 
practice and will most likely fail to attract requisite state 
support.\2699\ Southern further asserts that the NOPR's proposed cost 
allocation processes do not satisfy the second prong of the 
Commission's FPA section 206 burden of proof to establish a just and 
reasonable replacement rate.\2700\ Pacific Northwest State Agencies 
oppose the option in the NOPR proposal that allows transmission 
providers to propose a Long-Term Regional Transmission Cost Allocation 
Method without involving states in its development.\2701\
---------------------------------------------------------------------------

    \2699\ Southern Initial Comments at 6-7.
    \2700\ Id. at 7 n.7.
    \2701\ Pacific Northwest State Agencies Initial Comments at 24-
25.
---------------------------------------------------------------------------

iv. Comments on Specific Aspects of the Proposed Cost Allocation 
Reforms
(a) Use of Existing Cost Allocation Methods for Long-Term Regional 
Transmission Facilities
    1260. Some commenters assert that they should be able to use 
existing cost allocation methods for Long-Term Regional Transmission 
Planning, with some RTOs/ISOs \2702\ and RTO/ISO stakeholders \2703\ 
supporting these arguments. Other commenters support the Commission 
permitting transmission providers to keep their existing processes that 
involve states in cost allocation decisions.\2704\ PPL supports using 
the existing regional cost allocation structures as a default. PPL 
asserts that any change to the existing cost allocation method will 
require an FPA section 205 filing, and interested parties, including 
the states, may intervene and provide testimony and evidence regarding 
the appropriateness of any benefit used.\2705\
---------------------------------------------------------------------------

    \2702\ See, e.g., MISO Initial Comments at 61, 68; PJM Initial 
Comments at 116; SPP Initial Comments at 28-29.
    \2703\ See, e.g., Ameren Initial Comments at 25-27; Avangrid 
Initial Comments at 28; Dominion Initial Comments at 3, 45; Ohio 
Commission Federal Advocate Initial Comments at 2, 13; Omaha Public 
Power Initial Comments at 4; Pennsylvania Commission Initial 
Comments at 13-14; PJM States Initial Comments at 11-12; Virginia 
Commission Staff Initial Comments at 6.
    \2704\ Avangrid Initial Comments at 28; Dominion Reply Comments 
at 11; Omaha Public Power Initial Comments at 4.
    \2705\ PPL Initial Comments at 28-29.
---------------------------------------------------------------------------

    1261. APS states that it agrees with the Commission that 
collaboration with Relevant State Entities is a positive approach to 
transmission planning, but it believes that the current cost allocation 
process is appropriate and should not be altered. APS, noting that the 
Commission has determined that additional complexities and 
contentiousness may result from expanding the transmission planning 
horizon to 20 years, argues that underlying cost causation principles 
will apply, and, therefore, existing cost allocation processes remain 
appropriate.\2706\
---------------------------------------------------------------------------

    \2706\ APS Initial Comments at 11-12.
---------------------------------------------------------------------------

    1262. Similarly, PJM contends that the need for new or expanded 
transmission facilities identified through Long-Term Regional 
Transmission Planning would fall under the reliability or market 
efficiency studies that it performs today, and, therefore, the 
Commission should permit it to use its existing ex ante cost allocation 
methods as the default cost allocation method for transmission 
facilities selected through Long-Term Regional Transmission Planning 
(absent agreement by all affected states on an alternate method). PJM 
states that using its existing ex ante approaches will provide 
consistency and certainty in assigning cost responsibility.\2707\ PJM 
States disagree, arguing that the Commission should not presume that 
existing cost allocation methods are just and reasonable without a full 
examination and input from retail regulators. According to PJM States, 
the factors that make PJM's existing cost allocation methods just and 
reasonable in the short term may not exist in the long term.\2708\
---------------------------------------------------------------------------

    \2707\ PJM Initial Comments at 115.
    \2708\ PJM States Reply Comments at 5.
---------------------------------------------------------------------------

    1263. PJM further requests that the Commission clarify that if a 
transmission provider proposes to use an existing cost allocation 
method for regional transmission facilities selected through Long-Term 
Regional Transmission Planning, such a proposal may not be a cause for 
relitigating the use of that method for transmission projects selected 
prior to the issuance of the final order.\2709\ MISO states that if 
existing cost allocation methods previously were determined to comply 
with the Order No. 1000 regional cost allocation principles, the 
Commission should not require another demonstration and should clarify 
that its proposals do not require transmission providers to modify or 
set aside any existing regional cost allocation method.\2710\ 
Relatedly, ITC argues that the Commission should allow for streamlined 
compliance plans from transmission providers that already have 
substantial long-range planning processes in place.\2711\
---------------------------------------------------------------------------

    \2709\ PJM Initial Comments at 115 (citing NOPR, 179 FERC ] 
61,028 at P 314).
    \2710\ MISO Initial Comments at 61.
    \2711\ ITC Initial Comments at 29-30.
---------------------------------------------------------------------------

    1264. PIOs proffer that having two distinct cost allocation methods 
can be unjust, unreasonable, and unduly discriminatory even if those 
methods are reasonable on their own, and that multiple cost allocation 
methods may create uncertainty, which the Commission has recognized can 
be a barrier to transmission development.\2712\ PIOs therefore request 
that the Commission: (1) require transmission providers to identify and 
justify differences between Long-Term Regional Transmission Planning 
and near-term cost allocation; (2) find that compliance filings that 
create opportunities for ``cost allocation arbitrage'' may not be 
approved; and (3) require transmission providers to demonstrate that 
their current Order No. 1000 cost allocation methods are just, 
reasonable, and not unduly discriminatory or preferential.\2713\
---------------------------------------------------------------------------

    \2712\ PIOs Initial Comments at 71 (citing NOPR, 179 FERC ] 
61,028 at P 297).
    \2713\ Id. at 72.
---------------------------------------------------------------------------

    1265. Dominion requests that the Commission clarify that any cost 
allocation method directed through this rulemaking proceeding is: (1) 
limited to Long-Term Regional Transmission Facilities; and (2) limited 
to Order No. 1000 transmission planning regions.\2714\
---------------------------------------------------------------------------

    \2714\ Dominion Initial Comments at 49-50.
---------------------------------------------------------------------------

    1266. Clean Energy Associations request that the Commission adopt 
pro forma cost allocation provisions that would allow for regional 
variation where cost allocation practices are consistent with or 
superior to the requirements adopted in any final order. For example, 
Clean Energy Associations state, if vertically integrated public 
utilities subject to state-jurisdictional integrated resource planning 
can demonstrate that the state planning process appropriately 
identifies needs and assigns costs based on future planned generation 
consistent with state policies, certain requirements may not be 
applicable.\2715\
---------------------------------------------------------------------------

    \2715\ Clean Energy Associations Initial Comments at 36.
---------------------------------------------------------------------------

(b) Comments on Whether Filing an Ex Ante Cost Allocation Method Should 
Be Required
    1267. Some commenters support a requirement that transmission 
providers submit an ex ante cost allocation

[[Page 49478]]

method or methods that would apply to all Long-Term Regional 
Transmission Facilities either in place of, or as a backstop for, a 
State Agreement Process.\2716\ For example, Grid United suggests that 
the Commission mandate that transmission providers develop ex ante cost 
allocation methods for selected Long-Term Regional Transmission 
Facilities to remove development and financial uncertainty, provide 
transparency in how benefits are calculated, and ensure that cost 
allocation is roughly commensurate with the distribution of 
benefits.\2717\
---------------------------------------------------------------------------

    \2716\ See, e.g., Grid United Initial Comments at 6; Illinois 
Commission Initial Comments at 16-17; Minnesota State Entities 
Initial Comments at 6; MISO TOs Initial Comments at 45-48; PIOs 
Initial Comments at 70; RMI Supplemental Comments at 2-3.
    \2717\ Grid United Initial Comments at 6.
---------------------------------------------------------------------------

    1268. MISO TOs state that ex ante cost allocation provides upfront 
certainty, explaining that MISO's ex ante processes work well and align 
with past Commission findings regarding the difficulty of supporting 
new construction without knowing who will pay for it and the importance 
of working out cost allocation up front, rather than ``relitigating 
it'' each time a transmission project is proposed.\2718\ MISO TOs do 
not oppose states voluntarily agreeing to assume cost responsibility 
for regional transmission projects, which Commission policy already 
permits via participant funding, but argue that states that want to 
voluntarily assume cost responsibility for part or all of a 
transmission project should do so during the transmission planning 
process (i.e., when considering potential transmission projects) rather 
than after projects have been selected, so that those approving such 
projects can know how costs will be allocated.\2719\
---------------------------------------------------------------------------

    \2718\ MISO TOs Initial Comments at 45-48 (citing Order No. 890, 
118 FERC ] 61,119 at PP 557, 561; Order No. 1000, 136 FERC ] 61,051 
at P 499).
    \2719\ Id. at 48-49.
---------------------------------------------------------------------------

    1269. New Jersey Commission states that the Commission should not 
allow transmission providers to use cost allocation methods that rely 
solely on participant funding, such as PJM's State Agreement Approach. 
New Jersey Commission explains that such mechanisms are an unjust and 
unreasonable method for allocating the costs of holistically planned 
multi-driver projects and portfolios because if transmission projects 
can only be built if one or more states agree to assume 100% of the 
resulting costs, more expensive projects or portfolios that maximize 
net benefits to the transmission planning region will go unbuilt, 
ultimately driving up system-wide costs.\2720\
---------------------------------------------------------------------------

    \2720\ New Jersey Commission Initial Comments at 24.
---------------------------------------------------------------------------

    1270. Illinois Commission states that ex ante approaches should be 
the primary cost allocation method and include state input and 
approval, and that the State Agreement Process should only be used for 
exceptions in which public policy goals fall outside of the scope of 
Long-Term Regional Transmission Planning. Illinois Commission expresses 
concerns because it understands the NOPR to state that transmission 
projects without an ex ante cost allocation method would not be funded 
unless states decide to pay for them through a State Agreement Process, 
which could create more expensive and siloed transmission planning that 
does not meet future transmission needs.\2721\
---------------------------------------------------------------------------

    \2721\ Illinois Commission Initial Comments at 16-17.
---------------------------------------------------------------------------

    1271. Many commenters express concerns about the optionality of the 
proposal and argue that it is necessary to have a default ex ante cost 
allocation method where agreement cannot be reached among states and to 
preserve FPA section 205 filing rights.\2722\ Numerous entities support 
an ex ante cost allocation method for Long-Term Regional Transmission 
Facilities to be used in the event a State Agreement Process does not 
result in an agreed-upon cost allocation method.\2723\
---------------------------------------------------------------------------

    \2722\ ACORE Supplemental Comments at 1; APPA Initial Comments 
at 6, 44-45; Environmental Groups Supplemental Comments at 2-3; 
Evergreen Action Initial Comments at 6; Georgia Commission Initial 
Comments at 9; ITC Initial Comments at 30-31; Massachusetts Attorney 
General Initial Comments at 18-21; TAPS Initial Comments at 4-5, 24-
26; WIRES Initial Comments at 12-13.
    \2723\ Evergreen Action Initial Comments at 6; Exelon Initial 
Comments at 24, 26; Georgia Commission Initial Comments at 8-9; ITC 
Initial Comments at 30-31; Massachusetts Attorney General Initial 
Comments at 18-20, 22-23; MISO Initial Comments at 67-68; Northwest 
and Intermountain Initial Comments at 18; Pine Gate Initial Comments 
at 7; PIOs Initial Comments at 67; TAPS Initial Comments at 4-5, 24-
25; WIRES Initial Comments at 12-13.
---------------------------------------------------------------------------

    1272. For example, Minnesota State Entities contend that an ex ante 
process that allocates costs at least roughly proportional to benefits 
should be required as the default cost allocation method unless states 
can agree on an ex post cost allocation method within 90 days. 
Minnesota State Entities also recommend that the Commission require 
RTOs/ISOs to use postage stamp cost allocation as the default cost 
allocation method for Long-Term Regional Transmission Facilities (or 
portfolios of such Facilities) unless the RTO/ISO can develop an 
alternate cost allocation method that all affected states agree on 
within 90 days following RTO/ISO approval.\2724\
---------------------------------------------------------------------------

    \2724\ Minnesota State Entities Initial Comments at 6-7.
---------------------------------------------------------------------------

    1273. PIOs argue that without a default cost allocation method, 
transmission may be held up in stakeholder processes or by project-by-
project litigation to assign costs.\2725\ PIOs further caution that the 
Long-Term Regional Transmission Planning framework is at risk without 
an ex ante cost allocation method because successful negotiation of a 
State Agreement Process for each transmission project would be unwieldy 
and create opportunities for free-ridership and obstructionism.\2726\ 
Similarly, AEE argues that relying on a State Agreement Process would 
not be just and reasonable and likely would stall the transmission 
planning and cost allocation process.\2727\ Acadia Center and CLF 
assert that where the Commission anticipates that states will fail to 
agree, it should establish the Long-Term Regional Transmission Cost 
Allocation Method because, otherwise, ineffective regional transmission 
planning processes will remain in place.\2728\
---------------------------------------------------------------------------

    \2725\ PIOs Initial Comments at 70.
    \2726\ Id. at 67.
    \2727\ AEE Reply Comments at 15, 34.
    \2728\ Acadia Center and CLF Initial Comments at 31 (citing 
NOPR, 179 FERC ] 61,028 at P 310).
---------------------------------------------------------------------------

    1274. SEIA argues that having a default cost allocation method will 
ensure that transmission that promotes public policy will be built even 
in the face of disagreement.\2729\ R Street states that the Commission 
should require schedule discipline and a default cost allocation 
provision for circumstances where states cannot agree, which can 
include an accelerated Commission-led arbitration process or Commission 
application of preestablished criteria.\2730\
---------------------------------------------------------------------------

    \2729\ SEIA Initial Comments at 25 (citing 16 U.S.C. 824p(b)).
    \2730\ R Street Initial Comments at 4, 12.
---------------------------------------------------------------------------

    1275. Georgia Commission asserts that, if Relevant State Entities 
cannot reach agreement, or if a Relevant State Entity forgoes its 
opportunity to participate in the State Agreement Process, there should 
be a default Long-Term Regional Transmission Cost Allocation Method 
when clear benefits have been identified for a specific transmission 
facility or portfolio of facilities.\2731\
---------------------------------------------------------------------------

    \2731\ Georgia Commission Initial Comments at 9.
---------------------------------------------------------------------------

    1276. NYISO does not object to the final order directing each 
transmission provider to adopt an ex ante cost allocation method for 
transmission projects selected through Long-Term

[[Page 49479]]

Regional Transmission Planning for use when an alternative method is 
not identified in a process that involves the state. NYISO references, 
as an example, the process cited in the NOPR whereby the New York 
Commission plays a role in determining the cost allocation method for 
public policy transmission projects.\2732\
---------------------------------------------------------------------------

    \2732\ NYISO Initial Comments at 49 (citing NOPR, 179 FERC ] 
61,028 at P 300 & n.500).
---------------------------------------------------------------------------

    1277. Exelon supports requiring a default ex ante cost allocation 
method that would act as a backstop cost allocation method should the 
states in a transmission planning region fail to negotiate an 
alternative cost allocation method for a transmission project or 
portfolio of projects. Exelon states that failure to reach an agreement 
on cost allocation should not act as a barrier to needed transmission, 
and whatever mechanism is developed for receiving state input should 
not allow one or more states to thwart the goals of other states and 
stakeholders.\2733\
---------------------------------------------------------------------------

    \2733\ Exelon Initial Comments at 26.
---------------------------------------------------------------------------

    1278. PPL asserts that the proposal to require a Long-Term Regional 
Transmission Cost Allocation Method may not solve the problem of states 
refusing to site transmission projects where they do not agree on cost 
allocation, but in some transmission planning regions, it may 
nevertheless be helpful to have a default cost allocation method.\2734\
---------------------------------------------------------------------------

    \2734\ PPL Initial Comments at 26.
---------------------------------------------------------------------------

    1279. Some commenters oppose requiring a default ex ante cost 
allocation method, whether on its own or in combination with a State 
Agreement Process.\2735\ For example, California Commission asserts 
that the Commission should not mandate an ex ante cost allocation 
method if states cannot agree to a cost allocation method by a certain 
date.\2736\ NRG states that the Commission should focus on voluntary 
cost allocation and should not use involuntary cost allocation as a 
substitute to participant-funded interconnection and transmission 
expansion.\2737\ NRG states that it would be unrealistic to expect 
productive negotiation among states if recourse to an ex ante cost 
allocation method is an option for any objecting state.\2738\
---------------------------------------------------------------------------

    \2735\ See, e.g., Louisiana Commission Initial Comments at 30, 
34; NRG Initial Comments at 6; SERTP Sponsors Initial Comments at 
28; US Chamber of Commerce Initial Comments at 9-10.
    \2736\ California Commission Initial Comments at 57.
    \2737\ NRG Initial Comments at 6, 16.
    \2738\ Id. at 20.
---------------------------------------------------------------------------

    1280. SERTP Sponsors express concern that requiring state 
agreements or an ex ante cost allocation method before transmission 
projects are identified is unworkable because regulators in the 
Southeast will likely insist that the projects first be identified and 
their benefits and costs determined before the projects are selected 
and cost allocation commitments are made.\2739\ SERTP Sponsors state 
that expecting states to accept a cost allocation for transmission 
projects that they do not support, based on a process they have not 
chosen, and to which they do not assign value or benefit for retail 
ratepayers, will not succeed.\2740\ Alabama Commission agrees with 
SERTP Sponsors, stating that the State Agreement Process is a more 
appropriate and equitable mechanism for allocating the costs of Long-
Term Regional Transmission Facilities and should be the sole cost 
allocation method.\2741\ Similarly, US Chamber of Commerce contends 
that state utility regulators would risk not adequately protecting 
their constituents if they were to agree to an ex ante cost allocation 
method that assessed a fixed level of costs on ratepayers regardless of 
the design and/or benefits of a proposed regional transmission 
facility.\2742\
---------------------------------------------------------------------------

    \2739\ SERTP Sponsors Initial Comments at 3, 28.
    \2740\ Id. at 20.
    \2741\ Alabama Commission Initial Comments at 9.
    \2742\ US Chamber of Commerce Initial Comments at 9-10.
---------------------------------------------------------------------------

    1281. EPSA argues that because long-term transmission planning 
horizons introduce uncertainty risk that customers must bear, cost 
allocation should be voluntary to the maximum degree possible.\2743\ 
Louisiana Commission opposes proceeding with any transmission projects 
selected in Long-Term Regional Transmission Planning without the 
voluntary cost allocation agreement of all impacted states.\2744\ 
Mississippi Commission asserts that the Commission should not require a 
default ex ante cost allocation method because doing so would bias and 
undermine cost allocation negotiations between states.\2745\ 
Mississippi Commission further argues that the Commission should 
clarify that state agreement on cost allocation for each transmission 
facility, or portfolio of facilities, is what is required, not simply 
involvement in the stakeholder process.\2746\
---------------------------------------------------------------------------

    \2743\ EPSA Initial Comments at 7.
    \2744\ Louisiana Commission Initial Comments at 17-18, 30.
    \2745\ Mississippi Commission Initial Comments at 27; 
Mississippi Commission Reply Comments at 3.
    \2746\ Mississippi Commission Initial Comments at 28.
---------------------------------------------------------------------------

    1282. Xcel opposes a mandated ex ante cost allocation method, 
stating that the industry engaged in more effective long-term 
transmission planning before Order No. 1000, and that the Commission 
should give transmission planning regions flexibility to identify 
potential solutions before identifying the cost allocation for those 
solutions. In addition, Xcel supports allowing transmission planning 
regions flexibility to tailor the benefits evaluated to the purpose of 
the study and project, citing MISO's experience with Long-Range 
Transmission Planning.\2747\ Similarly, Southern states that the 
Commission should not require an ex ante cost allocation process, but 
if it does, it should adopt the NOPR proposal to allow transmission 
providers to determine the appropriate benefits.\2748\
---------------------------------------------------------------------------

    \2747\ Xcel Initial Comments at 11-12.
    \2748\ Southern Initial Comments at 27.
---------------------------------------------------------------------------

    1283. Duke asserts that the Commission has provided no support 
other than pointing to Order No. 1000 as to why Long-Term Regional 
Transmission Facilities should have a default ex ante cost allocation 
method.\2749\ Duke explains that if states disagree with the need, 
benefits, and cost allocation determined in Commission-jurisdictional 
transmission planning processes, then states are likely to exercise 
their jurisdiction over siting and retail cost allocation to thwart 
development of a Long-Term Regional Transmission Facility.\2750\ Duke 
asks that the Commission clarify that transmission providers may rely 
solely on a State Agreement Process and are not required to adopt an ex 
ante default Long-Term Regional Transmission Cost Allocation 
Method.\2751\ Duke argues that an ex post cost allocation method from a 
fully litigated Commission proceeding is a more durable solution than a 
default ex ante cost allocation, which may be similarly litigated but 
also delay siting approvals.\2752\
---------------------------------------------------------------------------

    \2749\ Duke Initial Comments at 37.
    \2750\ Id. at 3, 35-36.
    \2751\ Id. at 33.
    \2752\ Id. at 3, 36-37.
---------------------------------------------------------------------------

    1284. NESCOE requests that the Commission confirm that if a 
transmission provider files a State Agreement Process, the transmission 
provider does not need to file an ex ante cost allocation method, and 
the time period for a state-negotiated alternate cost allocation method 
would not apply.\2753\
---------------------------------------------------------------------------

    \2753\ NESCOE Initial Comments at 66-67.
---------------------------------------------------------------------------

v. Other Cost Allocation Method Proposals
    1285. ACEG recommends having a threshold level of voltage or 
capacity above which a transmission facility would receive regional 
cost allocation

[[Page 49480]]

because the benefits of transmission depend directly on having a robust 
grid capable not only of receiving diverse generation but also of 
withstanding extreme weather.\2754\
---------------------------------------------------------------------------

    \2754\ ACEG Initial Comments at 63.
---------------------------------------------------------------------------

    1286. Shell argues that the Commission should be open to non-
traditional cost allocation methods, such as the sharing of benefits 
when a defined benefit/cost ratio threshold is exceeded, to achieve the 
goal of minimizing first-mover risk. Shell contends that sharing the 
cost of interconnection-related network upgrades between first movers 
and subsequent customers is common in the industry and points to ISO-
NE, PJM, and MISO as examples of RTOs/ISOs that have revised their 
OATTs to attempt to address this concern.\2755\
---------------------------------------------------------------------------

    \2755\ Shell Initial Comments at 25-28.
---------------------------------------------------------------------------

    1287. ELCON notes that regardless of the funding mechanism or 
approved cost allocation method, benefits and risks may change over 
time as Long-Term Scenarios are updated and needs and solutions are 
reassessed. Therefore, ELCON states that the three-year reexamination 
of Long-Term Scenarios should also review cost allocation to ensure 
that cost causers and willing beneficiaries continue to be assessed the 
costs of a transmission project over its lifetime.\2756\
---------------------------------------------------------------------------

    \2756\ ELCON Initial Comments at 19.
---------------------------------------------------------------------------

    1288. Xcel proposes that transmission planning regions rely on 
scenario-based studies that reflect load-serving entity inputs 
regarding projected generation expansion, expected types and locations 
of generators, and expected load. Xcel states that the load-serving 
entities could then adjust their resource plans in light of the 
resulting costs and benefits. Xcel asserts that this flexibility would 
result in consensus-based cost allocation tied to the transmission that 
load-serving entities actually need and would reduce the reluctance to 
participate in planning as the outcomes could be adjusted to 
accommodate adjustments in load-serving entity needs and 
expectations.\2757\ Xcel also argues that the Commission should make 
clear that it is sometimes appropriate to allocate costs to generators, 
and that transmission access rights allocation should follow cost 
allocation.\2758\
---------------------------------------------------------------------------

    \2757\ Xcel Initial Comments at 18.
    \2758\ Id. at 12-13.
---------------------------------------------------------------------------

    1289. Certain TDUs argue that the Commission should require any ex 
ante cost allocation method to follow a ``beneficiary pays'' approach, 
as opposed to the default, postage stamp load ratio share model.\2759\ 
Certain TDUs claim that the advantages of adopting a beneficiary-pays 
cost allocation approach are well documented, as the circumstances 
appropriate for a postage stamp allocation are not necessarily present 
when allocating costs for Long-Term Regional Transmission 
Facilities.\2760\ R Street similarly asserts that the final order 
should adhere to the beneficiary-pays principle to allocate the costs 
of both transmission and interconnection-related network 
upgrades.\2761\
---------------------------------------------------------------------------

    \2759\ Certain TDUs Initial Comments at 2, 7.
    \2760\ Id. at 8-9.
    \2761\ R Street Initial Comments at 4, 12.
---------------------------------------------------------------------------

    1290. Cypress Creek contends that where ``cost allocation would 
hamper the use of contingent needs as a driver for multi-value 
projects,'' there should be a hybrid approach. Specifically, Cypress 
Creek suggests allocating costs up to the lesser of: (1) the cost of 
necessary reliability improvements and (2) the benefit-cost threshold 
ratio of the multi-value project to the party that needs the 
improvements. Cypress Creek suggests that the remaining costs be 
allocated according to multi-value project rules.\2762\
---------------------------------------------------------------------------

    \2762\ Cypress Creek Reply Comments at 12.
---------------------------------------------------------------------------

c. Commission Determination
    1291. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to file one 
or more ex ante cost allocation methods that apply to selected Long-
Term Regional Transmission Facilities. Specifically, we modify the NOPR 
proposal to require, instead of just permit, transmission providers in 
each transmission planning region to revise their OATTs to include one 
or more Long-Term Regional Transmission Cost Allocation Methods for 
Long-Term Regional Transmission Facilities that are selected. We adopt 
the NOPR's proposed definition, with modification, of Long-Term 
Regional Transmission Cost Allocation Method as an ex ante regional 
cost allocation method for one or more Long-Term Regional Transmission 
Facilities (or a portfolio of such Facilities) that are selected in the 
regional transmission plan for purposes of cost allocation. In addition 
to this required Long-Term Regional Transmission Cost Allocation 
Method, we also permit transmission providers to revise their OATTs to 
include a State Agreement Process, if Relevant State Entities indicate 
that they have agreed to such a process. Any State Agreement Process 
that transmission providers voluntarily propose to include in their 
OATTs would not comply with the requirements of this final order unless 
Relevant State Entities indicate to the transmission providers that 
Relevant State Entities have agreed to that process during the 
Engagement Period (which we discuss further below).\2763\
---------------------------------------------------------------------------

    \2763\ We discuss the definition of Relevant State Entities 
below. See infra the Requirement that Transmission Providers Seek 
the Agreement of Relevant State Entities Regarding the Cost 
Allocation Method or Methods for Long-Term Regional Transmission 
Facilities section.
---------------------------------------------------------------------------

    1292. While we permit transmission providers to include a State 
Agreement Process in their OATTs to determine cost allocation methods 
for selected Long-Term Regional Transmission Facilities if the process 
is agreed to by Relevant State Entities, it cannot be the sole method 
filed for cost allocation for Long-Term Regional Transmission 
Facilities. As discussed below, we find that sole reliance on a State 
Agreement Process to determine a cost allocation method for selected 
Long-Term Regional Transmission Facilities will not achieve the 
objectives of this final order. Additionally, we modify the NOPR 
proposal to require that, if a State Agreement Process fails to result 
in a cost allocation method agreed to by Relevant State Entities and 
any other authorized entities, or if the Commission ultimately finds 
that the cost allocation method that results from a State Agreement 
Process is unjust, unreasonable, or unduly discriminatory or 
preferential, then the relevant Long-Term Regional Transmission Cost 
Allocation Method on file would apply as a backstop. In other words, if 
a Long-Term Regional Transmission Facility or portfolio of such 
Facilities is selected but a State Agreement Process fails to result in 
a Commission-accepted cost allocation method for that facility or 
facilities, then their costs must be allocated through the Long-Term 
Regional Transmission Cost Allocation Method or Methods that would 
otherwise apply in the absence of a State Agreement Process (i.e., the 
backstop Long-Term Regional Transmission Cost Allocation Method).\2764\ 
We clarify that, if the transmission providers have more than one Long-
Term Regional Transmission Cost Allocation Method on file, then the

[[Page 49481]]

method that would otherwise apply to the specific selected Long-Term 
Regional Transmission Facility would serve as the backstop Long-Term 
Regional Transmission Cost Allocation Method.
---------------------------------------------------------------------------

    \2764\ For example, transmission providers could file two Long-
Term Regional Transmission Cost Allocation Methods, A and B. In this 
example, Method A would apply only to Long-Term Regional 
Transmission Facilities under 300 kV. Method B would apply to Long-
Term Regional Transmission Facilities at or above 300 kV only if an 
agreed-upon State Agreement Process fails to result in a Commission-
accepted cost allocation method. If, on compliance, transmission 
providers propose more than one Long-Term Regional Transmission Cost 
Allocation Method, they must specify to which Long-Term Regional 
Transmission Facilities each Long-Term Regional Transmission Cost 
Allocation Method applies.
---------------------------------------------------------------------------

    1293. We continue to find that facilitating state regulatory 
involvement in the cost allocation process could minimize delays and 
additional costs associated with state and local siting 
proceedings.\2765\ Nevertheless, we find that the requirement for 
transmission providers to include a Long-Term Regional Transmission 
Cost Allocation Method in their OATTs is necessary because, if 
transmission providers were to rely solely on a State Agreement Process 
to determine the cost allocation for Long-Term Regional Transmission 
Facilities and that process fails to result in agreement, there would 
be no cost allocation method for Long-Term Regional Transmission 
Facilities selected as the more efficient or cost-effective solutions 
to Long-Term Transmission Needs. As a result, such selected Long-Term 
Regional Transmission Facilities would be less likely to be developed, 
and the benefits that these facilities would provide would not be 
realized. Moreover, transmission providers would likely rely on 
relatively inefficient or less cost-effective transmission facilities 
to address the identified Long-Term Transmission Needs, or they may not 
even address these needs at all, leading to unjust and unreasonable 
Commission-jurisdictional rates. We further find that reliance solely 
on a State Agreement Process would suffer from the same flaws that led 
the Commission to require ex ante cost allocation for selected regional 
transmission facilities in Order No. 1000, as the allocation of 
transmission costs can be contentious and prone to litigation in multi-
state transmission planning regions.\2766\ Requiring a Long-Term 
Regional Transmission Cost Allocation Method, even when transmission 
providers also have a State Agreement Process in effect, provides a 
level of certainty critical to the development of needed Long-Term 
Regional Transmission Facilities.
---------------------------------------------------------------------------

    \2765\ NOPR, 179 FERC ] 61,028 at P 301.
    \2766\ Order No. 1000, 136 FERC ] 61,051 at PP 498-499; see also 
S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 70 (finding that the 
Commission reasonably balanced the benefits and claimed burdens of 
Order No. 1000's reforms in concluding that the requirement that 
each transmission provider include in its OATT a method(s) for 
allocating ex ante the costs of new regional transmission facilities 
``would reduce conflicts and `aid in the development and 
construction of new transmission' '' and allow stakeholders ``to 
determine ex ante `that the benefits associated with [a particular] 
set of transmission facilities outweigh the costs' '' (citing Order 
No. 1000, 136 FERC ] 61,051 at PP 499, 669)).
---------------------------------------------------------------------------

    1294. As noted above, the relevant Long-Term Regional Transmission 
Cost Allocation Method on file would serve as a backstop if the State 
Agreement Process does not result in a Commission-accepted cost 
allocation method for the selected Long-Term Regional Transmission 
Facility or portfolio of such Facilities subject to the State Agreement 
Process. This outcome could occur for several reasons. For instance, 
Relevant State Entities may not reach agreement on a cost allocation 
method pursuant to the terms of a State Agreement Process and the 
transmission providers may choose not to file any cost allocation 
method. In another instance, transmission providers may choose not to 
file a cost allocation method agreed to pursuant to a State Agreement 
Process and also choose not to file any alternative cost allocation 
method. And finally, the Commission might not accept a cost allocation 
method that results from a State Agreement Process and that 
transmission providers submit to the Commission for filing under FPA 
section 205 to the extent that it does not satisfy the requirement to 
allocate costs at least roughly commensurate with estimated benefits or 
is otherwise unjust or unreasonable.\2767\
---------------------------------------------------------------------------

    \2767\ See PPL Elec. Utils. Corp., 181 FERC ] 61,178, at P 33 
(2022) (``In light of the New Jersey state law, the New Jersey 
[State Agreement Approach] Projects will benefit customers 
throughout New Jersey, and thus we find that allocating the costs of 
the New Jersey [State Agreement Approach] Projects on a load-ratio 
share basis to all New Jersey customers is roughly commensurate with 
the benefits provided by those projects.'') (footnote omitted).
---------------------------------------------------------------------------

    1295. In response to NRG's and Mississippi Commission's concerns 
that a Long-Term Regional Transmission Cost Allocation Method could 
undermine productive negotiation among states if recourse to an ex ante 
cost allocation method is an option for any objecting state,\2768\ on 
balance, we find that this possibility is outweighed by the risk that 
Long-Term Regional Transmission Facilities selected as the more 
efficient or cost-effective solution to Long-Term Transmission Needs 
may not have an associated cost allocation method absent this 
requirement, and thus would be unlikely to be developed.\2769\ As we 
explain above, the lack of a cost allocation method for selected Long-
Term Regional Transmission Facilities would likely result in 
transmission providers relying on relatively inefficient or less cost-
effective transmission facilities to address identified Long-Term 
Transmission Needs, or they may not even address these needs at all, 
leading to unjust and unreasonable Commission-jurisdictional rates. We 
further note that a Long-Term Regional Transmission Cost Allocation 
Method provides certainty that the costs of Long-Term Regional 
Transmission Facilities for which a State Agreement Process does not 
result in a Commission-approved cost allocation method will be 
allocated in a manner that the Commission has found to be just and 
reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \2768\ Mississippi Commission Initial Comments at 27; 
Mississippi Commission Reply Comments at 3; NRG Initial Comments at 
20.
    \2769\ As discussed below in the Requirement that Transmission 
Providers Seek Agreement of Relevant State Entities Regarding the 
Cost Allocation Method or Methods for Long-Term Regional 
Transmission Facilities section, we decline to define what 
constitutes agreement among Relevant State Entities and, as such, we 
do not require unanimous agreement of Relevant State Entities 
participating in the Engagement Period on a Long-Term Regional 
Transmission Cost Allocation Method(s) and/or State Agreement 
Process.
---------------------------------------------------------------------------

    1296. In response to the arguments by SERTP Sponsors, Alabama 
Commission, and Louisiana Commission emphasizing the importance of 
voluntary cost allocation among states,\2770\ along with Mississippi 
Commission's request for clarification that state agreement to a cost 
allocation method be required for any Long-Term Regional Transmission 
Facility under this final order,\2771\ we note that Relevant State 
Entities will have the opportunity to provide their views on cost 
allocation methods during the Engagement Period, as discussed further 
below. Following this Engagement Period, Relevant State Entities may 
agree to, and ask the transmission providers to file, a State Agreement 
Process, which, if accepted by the Commission, would be the cost 
allocation process used by the transmission providers in the 
transmission planning region prior to the use of the relevant Long-Term 
Regional Transmission Cost Allocation Method as a backstop. Further, as 
discussed in the Proposals Relating to the Design and Operation of 
State Agreement Processes section below, during the Engagement Period 
or State Agreement Process, Relevant State Entities will have an 
opportunity to agree to and ask transmission providers to file a Long-
Term Regional Transmission Cost Allocation Method. Thus, there are 
multiple opportunities for Relevant State Entities to voluntarily

[[Page 49482]]

negotiate a cost allocation method for Long-Term Regional Transmission 
Facilities.
---------------------------------------------------------------------------

    \2770\ SERTP Sponsors Initial Comments at 3, 20, 28; Alabama 
Commission Initial Comments at 9; Louisiana Commission Initial 
Comments at 17-18, 30.
    \2771\ Mississippi Commission Initial Comments at 28.
---------------------------------------------------------------------------

    1297. We find that US Chamber of Commerce's concern, that state 
utility regulators might fail to protect constituents if they were to 
agree to an ex ante cost allocation method that assessed a fixed level 
of costs on ratepayers regardless of the design or benefits of a 
proposed regional transmission facility, is misplaced.\2772\ Any cost 
allocation method(s) that transmission providers propose, be it as a 
result of a State Agreement Process or a Long-Term Regional 
Transmission Cost Allocation Method, must allocate costs in a manner 
that is at least roughly commensurate with estimated benefits, as 
discussed further below.\2773\ For the same reasons, we disagree with 
EPSA's contention that, because Long-Term Regional Transmission 
Planning introduces uncertainty risk that customers must bear, all the 
relevant cost allocation methods on file should be voluntary.\2774\
---------------------------------------------------------------------------

    \2772\ US Chamber of Commerce Initial Comments at 9-10.
    \2773\ See infra Identification of Benefits Considered in Cost 
Allocation for Long-Term Regional Transmission Facilities.
    \2774\ EPSA Initial Comments at 7.
---------------------------------------------------------------------------

    1298. We also acknowledge Duke's concerns that a default ex ante 
cost allocation method could delay siting approvals and Xcel's concerns 
associated with a mandated ex ante cost allocation method claiming that 
the industry engaged more effectively in long-term transmission 
planning before Order No. 1000.\2775\ We note that another modification 
to the NOPR proposal that we adopt, as described below, allows State 
Agreement Processes to occur before, as well as up to six months after, 
selection of Long-Term Regional Transmission Facilities. This 
modification helps to address Duke's and Xcel's concerns by providing 
Relevant State Entities with an opportunity to agree on a cost 
allocation method for a particular Long-Term Regional Transmission 
Facility (or portfolio of such Facilities) after selection. However, we 
find that, even if such an agreement on a State Agreement Process cost 
allocation method cannot be achieved, on balance, the greater certainty 
that ex ante cost allocation methods provide to allow the development 
of Long-Term Regional Transmission Facilities outweighs the concerns 
that Duke and Xcel express.
---------------------------------------------------------------------------

    \2775\ Duke Initial Comments at 36; Xcel Initial Comments at 12.
---------------------------------------------------------------------------

    1299. Furthermore, we find that allowing the use of a State 
Agreement Process in addition to a Long-Term Regional Transmission Cost 
Allocation method will assist in the development of Long-Term Regional 
Transmission Facilities by taking into account state preferences. SEIA 
and New Jersey Commission support such flexibility.\2776\ We agree with 
New Jersey Commission that negotiated cost allocation methods may 
reduce litigation and make it easier to construct needed transmission 
facilities.\2777\ We recognize Dominion's concerns that implementing a 
State Agreement Process with an ex ante approach could lead to delays; 
\2778\ however, we find that both the backstop Long-Term Regional 
Transmission Cost Allocation Method, combined with a six-month limit 
after selection for deliberations under any State Agreement Process and 
the filing of any resulting cost allocation method, as detailed below, 
should limit such delays.
---------------------------------------------------------------------------

    \2776\ New Jersey Commission Initial Comments at 25; SEIA 
Initial Comments at 24.
    \2777\ New Jersey Commission Initial Comments at 17.
    \2778\ Dominion Initial Comments at 52.
---------------------------------------------------------------------------

    1300. Next, we adopt the NOPR proposal to apply the cost allocation 
reforms in this final order only to new Long-Term Regional Transmission 
Facilities. We find that this reform does not apply to regional 
reliability and economic transmission facilities that are selected 
pursuant to the existing Order No. 1000 regional transmission planning 
processes. We find, instead, that the existing Commission-accepted ex 
ante regional cost allocation methods adopted pursuant to Order No. 
1000 should continue to apply to those regional reliability and 
economic transmission facilities. We find no basis in the record to 
conclude that these existing regional cost allocation methods should 
change, given that this final order does not alter existing regional 
reliability and economic transmission planning processes. We believe 
that this distinction between cost allocation methods for regional 
reliability and economic transmission projects selected under existing 
Order No. 1000 regional transmission planning processes and those for 
new Long-Term Regional Transmission Facilities selected through Long-
Term Regional Transmission Planning will prevent the re-litigation of 
cost allocation decisions for transmission facilities that are selected 
prior to the effective date of this final order. In addition, we find 
this distinction to be consistent with our decision not to apply Long-
Term Regional Transmission Cost Allocation Methods to transmission 
facilities other than new Long-Term Regional Transmission 
Facilities.\2779\
---------------------------------------------------------------------------

    \2779\ As the Commission noted in the NOPR, the Commission took 
a similar approach with respect to its cost allocation reforms in 
Order No. 1000. See NOPR, 179 FERC ] 61,028 at P 314 n.517 (citing 
Order No. 1000, 136 FERC ] 61,051 at P 565).
---------------------------------------------------------------------------

    1301. We disagree with PIOs that allowing different cost allocation 
methods to apply to different regional transmission planning processes 
is unjust and unreasonable.\2780\ We find that because Long-Term 
Regional Transmission Planning is a more long-term, forward-looking, 
and comprehensive transmission planning process than existing Order No. 
1000 regional transmission planning processes, it is appropriate for 
transmission providers to consider, following the Engagement Period, 
whether different cost allocation methods should apply to selected 
Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------

    \2780\ PIOs Initial Comments at 71.
---------------------------------------------------------------------------

    1302. With respect to the potential use of existing regional cost 
allocation methods as Long-Term Regional Transmission Cost Allocation 
Methods, as well as assertions that existing cost allocation methods or 
current existing processes for state involvement in cost allocation 
decisions could be used for Long-Term Regional Transmission 
Planning,\2781\ we adopt the NOPR proposal that, to the extent 
transmission providers believe that their existing cost allocation 
methods comply with the requirements adopted in this final order, they 
may demonstrate in their compliance filings that such methods, as 
applied to Long-Term Regional Transmission Facilities, would comply 
with the requirements of this final order. This approach is consistent 
with the approach that the Commission took in Order No. 1000, in which 
the Commission declined commenter requests to decide in the rulemaking 
itself whether existing cost allocation methods complied with the 
requirements of Order No. 1000 and instead required transmission 
providers to demonstrate on compliance that their existing cost 
allocation methods met the rulemaking's requirements.\2782\
---------------------------------------------------------------------------

    \2781\ See, e.g., Ameren Initial Comments at 25-27; APS Initial 
Comments at 11-12; Avangrid Initial Comments at 28;Dominion Initial 
Comments at 3, 45; Dominion Reply Comments at 11; MISO Initial 
Comments at 61, 68; NYISO Initial Comments at 9, 50; Ohio Commission 
Federal Advocate Initial Comments at 2, 13; Omaha Public Power 
Initial Comments at 4; Pennsylvania Commission Initial Comments at 
13-14; PJM Initial Comments at 116; PJM States Initial Comments at 
11-12; SPP Initial Comments at 28-29; Virginia Commission Staff 
Initial Comments at 6.
    \2782\ See Order No. 1000, 136 FERC ] 61,051 at P 565; Order No. 
1000-A, 139 FERC ] 61,132 at P 747.

---------------------------------------------------------------------------

[[Page 49483]]

    1303. We disagree with PPL's contention that existing regional cost 
allocation methods accepted by the Commission should be considered the 
``default.'' The Commission accepted such ex ante regional cost 
allocation methods based on demonstrations of how they met the six 
Order No. 1000 regional cost allocation principles. We appreciate, as 
the Commission has recognized, that some existing regional cost 
allocation methods are complex, stakeholder-approved constructs and 
that some are specifically designed to apply to broad portfolios of 
transmission projects, such as MISO's regional cost allocation method 
for Multi-Value Projects.\2783\ However, as described above, to the 
extent that transmission providers propose on compliance to use an 
existing regional cost allocation method as a Long-Term Regional 
Transmission Cost Allocation Method, the transmission providers must 
demonstrate that such existing regional cost allocation method, as 
applied to Long-Term Regional Transmission Facilities, would comply 
with the requirements of this final order. We disagree with ITC's 
contention that the Commission should allow for streamlined compliance 
plans for transmission providers that already have long-range 
transmission planning processes; we reiterate that we require 
transmission providers to submit proposed cost allocation processes on 
compliance with this order so that the Commission may evaluate whether 
those processes comply with the requirements of this final order.
---------------------------------------------------------------------------

    \2783\ See, e.g., Midwest Indep. Transmission Sys. Operator, 
Inc., 142 FERC ] 61,215, at P 434 (2013); Sw. Power Pool, Inc., 144 
FERC ] 61,059, at P 347 (2013).
---------------------------------------------------------------------------

    1304. BP raises a concern that it is not clear, in the case of a 
multi-value project, whether only a part of the cost of a transmission 
project associated with meeting changes in the resource mix and demand 
will be allocated under a Long-Term Regional Transmission Cost 
Allocation Method as opposed to all of the costs. With the exception of 
Long-Term Regional Transmission Facilities that one or more Relevant 
State Entities or interconnection customers agree to voluntarily fund, 
we clarify that all costs associated with a selected Long-Term Regional 
Transmission Facility must be allocated using the applicable Long-Term 
Regional Transmission Cost Allocation Method or Methods, or an 
applicable Commission-accepted cost allocation method that results from 
a State Agreement Process.\2784\
---------------------------------------------------------------------------

    \2784\ See supra Evaluation and Selection of Long-Term Regional 
Transmission Facilities section. Moreover, in the Local Transmission 
Planning Inputs in the Regional Transmission Planning Process 
section below, we provide flexibility to transmission providers to 
propose a cost allocation method for right-sized replacement 
transmission facilities.
---------------------------------------------------------------------------

    1305. In response to requests that a beneficiary-pays approach be 
used rather than a postage stamp load ratio share model for cost 
allocation methods,\2785\ we reiterate that any cost allocation method 
applied to a Long-Term Regional Transmission Facility must ensure that 
costs are allocated in a manner that is at least roughly commensurate 
with the estimated benefits of the facility, consistent with cost 
causation and court precedent.\2786\ Load ratio share, which charges 
transmission customers in proportion to their use of the transmission 
system as measured by their relative share of load, is a cost 
allocation method that may be consistent with the beneficiary-pays 
approach. The Commission will evaluate whether a proposed cost 
allocation method allocates costs in a manner that is at least roughly 
commensurate with estimated benefits on a fact-specific basis, relying 
on the record in a given proceeding.
---------------------------------------------------------------------------

    \2785\ See Certain TDUs Initial Comments at 2, 7, 8-9; R Street 
Initial Comments at 4, 12.
    \2786\ The cost causation principle requires costs to be 
allocated to those who cause the costs to be incurred and reap the 
resulting benefits. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 87 
(citing Nat'l Ass'n of Regul. Util. Comm'rs v. FERC, 475 F.3d at 
1285); see also Order No. 1000, 136 FERC ] 61,051 at P 10 (``[T]he 
principles-based approach requires that all regional and 
interregional cost allocation methods allocate costs for new 
transmission facilities in a manner that is at least roughly 
commensurate with the benefits received by those who will pay those 
costs. Costs may not be involuntarily allocated to entities that do 
not receive benefits.''); ICC v. FERC I, 576 F.3d at 476 (``To the 
extent that a utility benefits from the costs of new facilities, it 
may be said to have `caused' a part of those costs to be incurred, 
as without the expectation of its contributions the facilities might 
not have been built, or might have been delayed.'').
---------------------------------------------------------------------------

    1306. In response to commenters that request flexibility in cost 
allocation,\2787\ we believe that the approach to cost allocation for 
Long-Term Regional Transmission Facilities that we adopt in this final 
order provides transmission providers and their stakeholders, and in 
particular Relevant State Entities, with the flexibility needed to 
address regional differences. Specifically, we find that the 
flexibility to submit one or more Long-Term Regional Transmission Cost 
Allocation Methods, as well as the flexibility to submit an additional 
State Agreement Process, accommodate regional differences.
---------------------------------------------------------------------------

    \2787\ See, e.g., Entergy Initial Comments at 29-30; Eversource 
Initial Comments at 29-30; Idaho Power Initial Comments at 10; 
NESCOE Reply Comments at 5; Pacific Northwest Utilities Initial 
Comments at 5-6, 11, 13.
---------------------------------------------------------------------------

    1307. We decline to adopt additional requirements with respect to 
cost allocation that we did not propose in the NOPR, such as Shell's 
request to require coastal transmission providers to explain how their 
Long-Term Regional Transmission Planning facilitates cost allocation 
for offshore wind.\2788\ We find that the record in this proceeding 
does not support imposing this or other additional requirements. 
Regarding certain cost allocation requirements suggested by 
commenters,\2789\ including ACEG's suggestion for implementing a 
voltage threshold level above which a transmission facility would 
receive regional cost allocation,\2790\ we find such proposals to be 
beyond the scope of this proceeding. The Commission did not make such 
proposals in the NOPR.
---------------------------------------------------------------------------

    \2788\ Shell Initial Comments at 17.
    \2789\ Cypress Creek Reply Comments at 12; ELCON Initial 
Comments at 19; R Street Initial Comments at 4, 12; Shell Initial 
Comments at 25-28; Xcel Initial Comments at 12-13, 18.
    \2790\ ACEG Initial Comments at 63.
---------------------------------------------------------------------------

2. Requirement That Transmission Providers Seek the Agreement of 
Relevant State Entities Regarding the Cost Allocation Method or Methods 
for Long-Term Regional Transmission Facilities
a. NOPR Proposal
    1308. The Commission proposed to require transmission providers in 
each transmission planning region to seek the agreement of Relevant 
State Entities within the transmission planning region regarding the 
Long-Term Regional Transmission Cost Allocation Method, State Agreement 
Process, or combination thereof.\2791\ The Commission proposed to 
require transmission providers in each transmission planning region to: 
(1) explain how the proposed Long-Term Regional Transmission Cost 
Allocation Method, State Agreement Process, or combination thereof 
reflects the agreement of Relevant State Entities; or (2) to the extent 
agreement of Relevant State Entities cannot be obtained, explain the 
good faith efforts by the relevant transmission provider(s) to seek 
agreement from such entities before proposing a Long-Term Regional 
Transmission Cost Allocation Method, State Agreement Process, or 
combination thereof.\2792\
---------------------------------------------------------------------------

    \2791\ NOPR, 179 FERC ] 61,028 at P 303.
    \2792\ Id. P 303.
---------------------------------------------------------------------------

    1309. The Commission proposed to define Relevant State Entities for 
purposes of the Long-Term Regional Transmission Planning cost 
allocation requirements as ``any state entity responsible for utility 
regulation or siting electric transmission facilities

[[Page 49484]]

within the state or portion of a state located in the transmission 
planning region, including any state entity as may be designated for 
that purpose by the law of such state.'' \2793\
---------------------------------------------------------------------------

    \2793\ Id. P 304.
---------------------------------------------------------------------------

    1310. The Commission proposed to require transmission providers in 
each transmission planning region to seek to determine whether, for all 
or a subset of Long-Term Regional Transmission Facilities, Relevant 
State Entities agree to: (1) a Long-Term Regional Transmission Cost 
Allocation Method; (2) a State Agreement Process; (3) forgo a role in 
determining the cost allocation approach for Long-Term Regional 
Transmission Facilities; or (4) some combination thereof.\2794\
---------------------------------------------------------------------------

    \2794\ Id. P 305.
---------------------------------------------------------------------------

    1311. The Commission proposed to afford transmission providers in 
each transmission planning region flexibility in the process by which 
they seek agreement from Relevant State Entities and to require 
transmission providers to provide the state entities with flexibility 
with regard to defining what constitutes ``agreement'' among the 
Relevant State Entities on the cost allocation approach for Long-Term 
Regional Transmission Facilities.\2795\ Although the Commission 
proposed to provide transmission providers flexibility in determining 
what constitutes state agreement, the Commission preliminarily found 
that, for each state, a single entity should be designated as the 
voting or representative entity to avoid confusion or over-
representation by a single state in a multi-state voting process.\2796\
---------------------------------------------------------------------------

    \2795\ Id. P 306.
    \2796\ Id. P 304.
---------------------------------------------------------------------------

    1312. Noting that the Relevant State Entities may forgo a role in 
determining the cost allocation approach for all or a subset of Long-
Term Regional Transmission Facilities, the Commission proposed that in 
the event that the Relevant State Entities do so, the Commission would 
require transmission providers to propose a Long-Term Regional 
Transmission Cost Allocation Method consistent with the requirements of 
Order No. 1000, including the prohibition on relying on voluntary 
agreement among states or participant funding.\2797\ The Commission 
explained that it was not proposing to impose any requirements on 
states to participate in processes to establish regional cost 
allocation methods for Long-Term Regional Transmission 
Facilities.\2798\
---------------------------------------------------------------------------

    \2797\ Id. P 307.
    \2798\ Id. P 308.
---------------------------------------------------------------------------

b. Comments
i. State Involvement in Cost Allocation Proposals
    1313. Many commenters generally support states having a role 
negotiating proposed cost allocation methods.\2799\ However, some 
commenters emphasize the importance of involving all stakeholders, and 
not just Relevant State Entities, in this reform. Clean Energy Buyers 
argue that the Commission should require transmission providers to 
allow all stakeholders (not just states) to participate in, or at least 
comment on, the development of the Long-Term Regional Transmission Cost 
Allocation Method and to recognize the importance of states and all 
other stakeholders.\2800\ Similarly, NEPOOL asserts that state 
involvement should not diminish the opportunity for stakeholder 
involvement from all market participants in the electric 
industry.\2801\ APPA asserts that while coordination with state 
regulators in cost allocation may aid in developing beneficial and 
cost-effective transmission projects, the perspectives of state 
regulators on cost allocation should not be elevated above those of 
other stakeholders.\2802\
---------------------------------------------------------------------------

    \2799\ See, e.g., AEP Initial Comments at 35; Ameren Initial 
Comments at 25; American Municipal Power Initial Comments at 12; 
Arizona Commission Initial Comments at 11; Clean Energy Associations 
Initial Comments at 35; Clean Energy Buyers Initial Comments at 28-
29; Clean Energy States Initial Comments at 7; Cross Sector 
Representatives Supplemental Comments at 1; Duke Initial Comments at 
35; ELCON Initial Comments at 17; ISO-NE Initial Comments at 2; 
Georgia Commission Initial Comments at 8-9; US House Republicans 
Supplemental Comments at 1; ITC Initial Comments at 28; Joint 
Consumer Advocates Initial Comments at 13; Maryland Energy 
Administration Initial Comments at 2; Massachusetts Attorney General 
Initial Comments at 19; Michigan Commission Initial Comments at 8; 
MISO Initial Comments at 61; NARUC Initial Comments at 45 (citing 
NOPR, 179 FERC ] 61,028 at PP 303-308), 46; New York Commission and 
NYSERDA Initial Comments at 1; NESCOE Initial Comments at 54; North 
Carolina Commission and Staff Initial Comments at 2; North Dakota 
Commission Initial Comments at 4; NRG Initial Comments at 6; NYISO 
Initial Comments at 49; OMS Initial Comments at 10; PacifiCorp and 
NV Energy Initial Comments at 15; PIOs Initial Comments at 64; 
Resale Iowa Initial Comments at 2; US Chamber of Commerce Initial 
Comments at 9 (citing NOPR, 179 FERC ] 61,028 at P 288); Virginia 
Commission Staff Initial Comments at 2; WIRES Initial Comments at 
12.
    \2800\ Clean Energy Buyers Initial Comments at 29.
    \2801\ NEPOOL Initial Comments at 9.
    \2802\ APPA Initial Comments at 42.
---------------------------------------------------------------------------

    1314. Idaho Power states that the Commission should continue to 
allow flexibility for transmission planning regions to determine the 
appropriate level of state involvement.\2803\ Pacific Northwest 
Utilities agree, stating that mandating additional state participation 
could be burdensome and problematic.\2804\
---------------------------------------------------------------------------

    \2803\ Idaho Power Initial Comments at 10.
    \2804\ Pacific Northwest Utilities Initial Comments at 13.
---------------------------------------------------------------------------

    1315. MISO states that the Commission should not extend any state 
involvement that may be adopted pursuant to the final order to near-
term reliability and economic regional transmission planning processes, 
which are beyond the scope of the final order.\2805\ MISO Coops state 
that MISO provides a stakeholder forum where states' voices are heard, 
and the final order should not diminish stakeholder processes that are 
effective today.\2806\
---------------------------------------------------------------------------

    \2805\ MISO Initial Comments at 71.
    \2806\ MISO Coops Initial Comments at 2.
---------------------------------------------------------------------------

    1316. Other commenters raise concerns about increased state 
involvement in cost allocation decisions. For example, Vistra asserts 
that a prioritized role for states in cost allocation is more likely to 
create new challenges than ease development, and observes that it may 
be difficult to coordinate state interests in multi-state transmission 
planning regions versus single-state transmission planning 
regions.\2807\ Six Cities opposes enhanced roles for Relevant State 
Entities, suggesting that the proposed reforms represent neither an 
appropriate oversight role for states under the FPA, nor a logical 
extension of Order No. 890 and Order No. 1000 policies.\2808\
---------------------------------------------------------------------------

    \2807\ Vistra Initial Comments at 2, 27-28.
    \2808\ Six Cities Initial Comments at 7.
---------------------------------------------------------------------------

    1317. ACEG and Georgia Commission agree with the Commission's 
proposed definition of Relevant State Entities.\2809\ ACEG and Dominion 
also support the proposal to have a single entity designated as the 
voting representative for the state.\2810\ MISO agrees that having a 
single entity designated for each state and/or applicable jurisdiction 
as the voting or representative entity for that state/jurisdiction 
makes sense, but notes that the City of New Orleans is an independent 
member of OMS separate from the Louisiana Commission and therefore may 
need to be considered a separate jurisdiction.\2811\ Louisiana 
Commission voices similar concerns.\2812\ North Carolina Commission and 
Staff state that it may be appropriate for different state entities to 
be designated for different roles,\2813\ and Duke asserts that the 
Commission should clarify that within a state there

[[Page 49485]]

may be multiple Relevant State Entities.\2814\
---------------------------------------------------------------------------

    \2809\ ACEG Initial Comments at 65-66; Georgia Commission 
Initial Comments at 8.
    \2810\ ACEG Initial Comments at 65-66; Dominion Initial Comments 
at 48 n.99.
    \2811\ MISO Initial Comments at 66.
    \2812\ Louisiana Commission Initial Comments at 33.
    \2813\ North Carolina Commission and Staff Initial Comments at 
17.
    \2814\ Duke Initial Comments at 38-39.
---------------------------------------------------------------------------

    1318. Some commenters generally agree with the Commission's 
proposed definition of Relevant State Entities but request that the 
definition be expanded or clarified to include self-regulated public 
power utilities and cooperatives.\2815\ TAPS argues that a multi-state 
voting process, as proposed, could fail to represent public power and 
cooperatives' interests.\2816\ NRECA contends that a more inclusive 
approach would be to use ``relevant electric regulatory authority,'' 
which includes a state public utility commission and the governing 
board of a cooperative or public power utility.\2817\ Large Public 
Power proposes to grant state and municipal utilities representation on 
a load ratio share basis.\2818\
---------------------------------------------------------------------------

    \2815\ American Municipal Power Initial Comments at 5; APPA 
Initial Comments at 3, 42-43 (citing 16 U.S.C. 796(7), (15)); 
California Municipal Utilities Initial Comments at 17; MISO Coops 
Initial Comments at 3-4; Six Cities Initial Comments at 10.
    \2816\ TAPS Initial Comments at 5, 26-27.
    \2817\ NRECA Initial Comments at 56-57.
    \2818\ Large Public Power Initial Comments at 41.
---------------------------------------------------------------------------

    1319. NASUCA urges the Commission to clarify that where applicable, 
an approved state cost allocation process should include agreement by a 
state's utility consumer advocate.\2819\ California Energy Commission 
recommends expanding the definition of Relevant State Entities to 
include any groups directly or indirectly affected by the construction 
of a project, such as Native American Tribes,\2820\ and NESCOE requests 
that the definition of Relevant State Entity be amended to accommodate 
individual transmission planning regions' particular approaches toward 
state involvement in cost allocation requirements, such as NESCOE 
managers designated by each New England Governor to represent that 
state's interests.\2821\
---------------------------------------------------------------------------

    \2819\ NASUCA Initial Comments at 10-11.
    \2820\ California Energy Commission Initial Comments at 3.
    \2821\ NESCOE Initial Comments at 57.
---------------------------------------------------------------------------

    1320. Nevada Commission requests flexibility in the term Relevant 
State Entity.\2822\ New Mexico RETA urges flexibility to account for 
state involvement of other entities not accounted for in the definition 
of Relevant State Entities, including state authorities specifically 
designated to assist in developing new electric transmission facilities 
(like New Mexico RETA).\2823\
---------------------------------------------------------------------------

    \2822\ Nevada Commission Initial Comments at 13.
    \2823\ New Mexico RETA Initial Comments at 8-9 (citing NOPR 179 
FERC ] 61,028 at P 304).
---------------------------------------------------------------------------

    1321. ACEG recommends that the Commission clarify that existing 
processes, such as SPP's Regional State Committee, MISO's OMS, and ISO-
NE's New England States Committee, should be used to determine the 
Relevant State Entity for each state, unless another process is 
demonstrated to be superior.\2824\
---------------------------------------------------------------------------

    \2824\ ACEG Initial Comments at 66.
---------------------------------------------------------------------------

    1322. SERTP Sponsors assert that which Relevant State Entity or 
Entities would be appropriate for a particular state will be a function 
of state law.\2825\ Pennsylvania Commission states that the 
Commission's proposed definition of Relevant State Entity is imperfect 
and may result in multiple entities within a single state being a 
Relevant State Entity, given that the Commission refers to utility 
regulation or siting authority in the definition, but a state's 
legislature could have delegated this different authority among 
different administrative agencies.\2826\
---------------------------------------------------------------------------

    \2825\ SERTP Sponsors Initial Comments at 28-29.
    \2826\ Pennsylvania Commission Initial Comments at 15.
---------------------------------------------------------------------------

ii. Requirement To Seek Agreement
    1323. Many commenters generally support requiring transmission 
providers in each transmission planning region to seek the agreement of 
Relevant State Entities within the transmission planning region 
regarding the Long-Term Regional Transmission Cost Allocation Method, 
State Agreement Process, or combination thereof.\2827\
---------------------------------------------------------------------------

    \2827\ See, e.g., Acadia Center and CLF Initial Comments at 29-
30; Avangrid Initial Comments at 28; City of New Orleans Council 
Initial Comments at 9; Entergy Initial Comments at 29-30; Georgia 
Commission Initial Comments at 8-9; ISO-NE Initial Comments at 37-
38; Louisiana Commission Initial Comments at 30; Michigan Commission 
Initial Comments at 8; NARUC Initial Comments at 45, 47; Nebraska 
Commission Initial Comments at 9; NESCOE Initial Comments at 54 
(citing NOPR, 179 FERC ] 61,028 at PP 303, 305); North Carolina 
Commission and Staff Initial Comments at 15-16; Ohio Commission 
Federal Advocate Initial Comments at 11; Pacific Northwest State 
Agencies Initial Comments at 27; PJM States Initial Comments at 9; 
SoCal Edison Initial Comments at 3; Southeast PIOs Initial Comments 
at 55 (citing NOPR, 179 FERC ] 61,028 at P 303); US Climate Alliance 
Initial Comments at 2; WIRES Initial Comments at 12.
---------------------------------------------------------------------------

    1324. Avangrid states that state input and collaboration is crucial 
to the transmission planning process, and that intensive state (and 
other stakeholder) participation and consensus-building will help to 
ensure that transmission will not be overbuilt.\2828\ SoCal Edison 
contends that without agreement among states on the respective benefits 
and share of related costs, the development of multi-state transmission 
projects will be nearly non-existent.\2829\ PPL supports transmission 
providers seeking agreement with the states on cost allocation methods, 
as well as voluntary coordination with states, which PPL argues will 
make public policy projects more likely to succeed.\2830\
---------------------------------------------------------------------------

    \2828\ Avangrid Initial Comments at 28.
    \2829\ SoCal Edison Initial Comments at 3.
    \2830\ PPL Initial Comments at 29.
---------------------------------------------------------------------------

    1325. NYISO and ISO-NE support state entities playing a role in 
determining the cost allocation method for transmission solutions to 
Long-Term Transmission Needs.\2831\ ISO-NE contends that states should 
be responsible for determining the cost allocation mechanism for 
policy-based, long-term transmission facility investments because they 
are uniquely situated to balance the benefits and costs of transmission 
investments intended to advance their policy goals.\2832\
---------------------------------------------------------------------------

    \2831\ NYISO Initial Comments at 49; ISO-NE Initial Comments at 
37.
    \2832\ ISO-NE Initial Comments at 37.
---------------------------------------------------------------------------

    1326. Mississippi Commission argues that opponents of state 
involvement in Long-Term Regional Transmission Planning fail to 
recognize the existing state regulatory role in siting electricity 
generation, transmission, and distribution facilities.\2833\
---------------------------------------------------------------------------

    \2833\ Mississippi Commission Reply Comments at 5.
---------------------------------------------------------------------------

    1327. In addition, some commenters support the agreement of states 
when determining a Long-Term Regional Transmission Cost Allocation 
Method. City of New Orleans Council comments that it is essential that 
state and local regulators agree to any Long-Term Regional Transmission 
Cost Allocation Method to ensure that the costs borne by retail 
customers are just and reasonable and not unduly discriminatory or 
preferential.\2834\ SoCal Edison concurs on the necessity for states to 
reach agreement.\2835\ Southern argues that unless state regulators 
agree to transmission project selection and cost allocation, 
transmission projects that result from the Commission's proposed Long-
Term Regional Transmission Planning are not likely to come to 
fruition.\2836\
---------------------------------------------------------------------------

    \2834\ City of New Orleans Council Initial Comments at 9.
    \2835\ SoCal Edison Initial Comments at 3, 13.
    \2836\ Southern Initial Comments at 9-10.
---------------------------------------------------------------------------

iii. Seek Changes To, Raise Concerns About, or Oppose the Requirement 
To Seek Agreement
    1328. Some commenters support requiring transmission providers to 
seek agreement with Relevant State Entities regarding the Long-Term 
Regional Transmission Cost Allocation Method, State Agreement Process, 
or a combination thereof, but propose changes to the proposal. For 
example,

[[Page 49486]]

Kentucky Commission Chair Chandler asserts that states should not be 
permanently bound by their agreement on an initial cost allocation 
method, and that the Commission should clarify that transmission 
providers should continue to seek agreement from states prior to 
seeking Commission approval for any change to the cost allocation 
method filed on compliance.\2837\ Similarly, PJM States request that 
the Commission require transmission providers to show they sought 
support of retail regulators for subsequent revisions of the initial 
cost allocation method.\2838\ PJM States ask that the Commission also 
require a regular check-in with retail regulators regarding the 
appropriateness of any existing cost allocation method.\2839\
---------------------------------------------------------------------------

    \2837\ Kentucky Commission Chair Chandler Initial Comments at 3.
    \2838\ PJM States Initial Comments at 10.
    \2839\ Id. at 10-11.
---------------------------------------------------------------------------

    1329. Resale Iowa states that it is concerned that large, multi-
state transmission projects may increase the number of participants to 
the point that agreement is difficult to achieve and suggests that 
multi-state organizations may provide an avenue for conveying state 
interests to transmission providers and reaching agreements.\2840\ DC 
and MD Offices of People's Counsel support giving state entities a 
``defined and expansive role'' in the regional transmission selection 
and cost allocation processes but argue that this role must be anchored 
by their ability to timely agree on cost allocation.\2841\
---------------------------------------------------------------------------

    \2840\ Resale Iowa Initial Comments at 2, 12.
    \2841\ DC and MD Offices of People's Counsel Initial Comments at 
37.
---------------------------------------------------------------------------

    1330. Other commenters offered modified versions of the NOPR 
proposal. California Commission states that the Commission should 
require that transmission providers use their FPA section 205 filing 
rights to submit the ex post cost allocation method (and/or combined 
method) agreed on by states even if the transmission providers in a 
transmission planning region determine that they will propose an ex 
ante cost allocation method for the Commission's consideration.\2842\
---------------------------------------------------------------------------

    \2842\ California Commission Initial Comments at 55-56.
---------------------------------------------------------------------------

    1331. Dominion states that it may be nearly impossible to achieve 
state consensus in multi-state RTOs/ISOs and that if the states in a 
transmission planning region are unable to agree on the proper cost 
allocation method, the transmission providers should be able to file 
their own proposed cost allocation method.\2843\
---------------------------------------------------------------------------

    \2843\ Dominion Initial Comments at 48.
---------------------------------------------------------------------------

    1332. Some commenters oppose the proposed requirement to seek 
agreement. For example, Minnesota State Entities state that the term 
``seeking state agreement'' is too vague and may lead to disputes over 
the rights and responsibilities of individual states or state 
commissions to veto or otherwise hold up needed region-wide 
transmission plans. Minnesota State Entities suggest replacing the term 
``seeking state agreement'' with ``take into account'' or ``evaluating 
and incorporating'' state concerns in the regional cost allocation 
approaches as regularly happens at MISO and other RTOs/ISOs.\2844\ MISO 
Coops state that the NOPR proposal for a transmission provider to seek 
agreement with Relevant State Entities is unnecessary and would be 
inferior to current stakeholder processes, setting up redundant and 
potentially conflicted processes.\2845\
---------------------------------------------------------------------------

    \2844\ Minnesota State Entities Initial Comments at 7.
    \2845\ MISO Coops Initial Comments at 4.
---------------------------------------------------------------------------

    1333. Kansas Commission questions the necessity of a requirement to 
seek the agreement of Relevant State Entities within a transmission 
planning region like SPP, where the SPP Regional State Committee has 
substantial influence over cost allocation.\2846\ PacifiCorp and NV 
Energy oppose a requirement for transmission providers to seek state 
agreement on a cost allocation method, contending that such a 
requirement would add complexity and significant process and 
time.\2847\ NRG states that under the proposal for transmission 
providers to seek the agreement of Relevant State Entities on cost 
allocation, customers that ultimately pay the cost of Long-Term 
Regional Transmission Facilities are left out of the cost allocation 
process. NRG suggests that the proposal be limited to transmission 
projects included in regional transmission plans that would not exist 
but for state public policy, as it is reasonable for states to fill 
this negotiating role as described in the NOPR.\2848\
---------------------------------------------------------------------------

    \2846\ Kansas Commission Initial Comments at 15-16.
    \2847\ PacifiCorp and NV Energy Initial Comments at 16.
    \2848\ NRG Initial Comments at 19.
---------------------------------------------------------------------------

    1334. MISO TOs contend that MISO and MISO TOs have already afforded 
opportunities for states to participate in the development of cost 
allocation methods,\2849\ and argue that the NOPR requirements as 
drafted are unnecessary for the MISO region.\2850\ MISO TOs argue that 
the Commission should find compelling the fact that MISO, MISO TOs, and 
OMS all support the existing collaborative process for cost allocation 
in MISO, and request that the Commission not impose changes on this 
process, but instead afford regional flexibility.\2851\
---------------------------------------------------------------------------

    \2849\ MISO TOs Initial Comments at 45.
    \2850\ MISO TOs Reply Comments at 3.
    \2851\ Id. at 9 (citing APS Initial Comments at 10-11; MISO 
Initial Comments at 55-69; MISO TOs Initial Comments at 41-45; OMS 
Initial Comments at 10-13).
---------------------------------------------------------------------------

    1335. MISO TOs disagree with commenters that argue that the NOPR 
provided too much discretion and deference to transmission 
providers,\2852\ or that the Commission should require transmission 
providers to add a mechanism that ensures compliance with the 
requirements to include Relevant State Entities in cost 
allocation.\2853\ MISO TOs state that these proposals are contrary to 
the FPA because they attempt to usurp the statutory rights of 
transmission providers and point to similar sentiments expressed by the 
Indicated PJM TOs.\2854\
---------------------------------------------------------------------------

    \2852\ Id. at 4 (citing California Commission Initial Comments 
at 51-54).
    \2853\ Id. at 4-5 (citing NARUC Initial Comments at 49; NESCOE 
Initial Comments at 16-19, 46 (requesting that the Commission either 
require codification of states' roles for cost allocation of long-
term regional transmission facilities in OATTs or require 
explanation following consultation with states of a different 
approach)).
    \2854\ Id. at 5, 8 (citing Indicated PJM TOs Initial Comments at 
23).
---------------------------------------------------------------------------

iv. Requirements Associated With Seeking Agreement of Relevant State 
Entities
    1336. ACEG, ACORE, and NESCOE support the NOPR proposal to require 
transmission providers to demonstrate their good faith efforts to seek 
agreement from Relevant State Entities before proposing a Long-Term 
Regional Transmission Cost Allocation Method, State Agreement Process, 
or combination thereof.\2855\ AEE states that the final order should 
better define what constitutes ``good faith effort'' to seek agreement 
on cost allocation from states, including the Commission's minimum 
expectations concerning the time that transmission providers must allow 
states to reach agreement, the need to hold meetings, and related 
topics.\2856\ OMS, on the other hand, urges the Commission to not 
require a formal process in which transmission providers must 
demonstrate how they sought the agreement of state entities.\2857\
---------------------------------------------------------------------------

    \2855\ ACEG Initial Comments at 65; ACORE Initial Comments at 18 
(citing NOPR, 179 FERC ] 61,028 at PP 306, 308); NESCOE Initial 
Comments at 59 (citing NOPR, 179 FERC ] 61,028 at P 308).
    \2856\ AEE Initial Comments at 33-34.
    \2857\ OMS Initial Comments at 11.
---------------------------------------------------------------------------

    1337. NARUC recommends that the Commission require, at a minimum, 
that transmission providers: (1)

[[Page 49487]]

communicate with Relevant State Entities promptly in a manner that is 
reasonably calculated to be received by the Relevant State Entities and 
(2) establish a forum for negotiation that enables robust participation 
from Relevant State Entities and transmission providers.\2858\ 
PacifiCorp and NV Energy urge the Commission to clarify that a 
transmission provider's obligation under any final order is only to 
provide state regulators an opportunity to participate in the process 
of establishing a cost allocation method, should they so choose.\2859\ 
NESCOE asserts that the Commission should require transmission 
providers to afford Relevant State Entities sufficient time to agree on 
a cost allocation approach. NESCOE advocates for the Commission to give 
states six months from the effective date of a final order to agree on 
a cost allocation method, which NESCOE argues is needed due to the 
complexity involved.\2860\
---------------------------------------------------------------------------

    \2858\ NARUC Initial Comments at 44.
    \2859\ PacifiCorp and NV Energy Initial Comments at 17.
    \2860\ NESCOE Initial Comments at 60.
---------------------------------------------------------------------------

    1338. Some commenters support the NOPR proposal to provide states 
flexibility in determining what constitutes agreement among Relevant 
State Entities on the cost allocation approach for Long-Term Regional 
Transmission Facilities.\2861\ Alabama Commission contends that the 
Commission should not establish any specific timeline for negotiation 
to allow sufficient time for states to reach such agreement.\2862\ In 
contrast, ACEG argues that there must be a firm time frame for any 
negotiations, because allowing Relevant State Entities more time to 
reach agreement could unnecessarily delay the process.\2863\ Likewise, 
Pine Gate and PIOs support requiring a firm deadline, arguing that 
absent such a requirement, a single state or a handful of states could 
significantly delay transmission development.\2864\
---------------------------------------------------------------------------

    \2861\ See, e.g., ACORE Initial Comments at 18 (citing NOPR, 179 
FERC ] 61,028 at PP 306, 308); Georgia Commission Initial Comments 
at 8; Massachusetts Attorney General Initial Comments at 20 (citing 
NOPR, 179 FERC ] 61,028 at PP 306, 308); NARUC Initial Comments at 
47-48 (citing NOPR, 179 FERC ] 61,028 at P 306); Nebraska Commission 
Initial Comments at 10; NESCOE Initial Comments at 58; Pacific 
Northwest State Agencies Initial Comments at 24-25 (citing NOPR, 179 
FERC ] 61,028 at PP 309, 318).
    \2862\ Alabama Commission Initial Comments at 9.
    \2863\ ACEG Initial Comments at 64-65.
    \2864\ Pine Gate Initial Comments at 46; PIOs Initial Comments 
at 69-70.
---------------------------------------------------------------------------

    1339. While ACEG supports the NOPR proposal, ACEG cautions that 
this flexibility should not grant states veto power over the 
agreement.\2865\ Similarly, PJM States argue that the Commission should 
not require unanimity in determining an initial Long-Term Regional 
Transmission Cost Allocation Method, and instead, retain the proposal 
in the NOPR to allow states to determine how they will come to 
agreement on a Long-Term Regional Transmission Facility cost allocation 
approach.\2866\ New Jersey Commission further asserts that the 
Commission must ensure that transmission providers cannot unilaterally 
veto proposals that result from states' negotiations on a cost 
allocation approach.\2867\
---------------------------------------------------------------------------

    \2865\ ACEG Initial Comments at 66.
    \2866\ PJM States Reply Comments at 4 (citing NOPR, 179 FERC ] 
61,028 at PP 304, 319).
    \2867\ New Jersey Commission Initial Comments at 17.
---------------------------------------------------------------------------

    1340. Nebraska Commission asserts that the Commission should allow 
RTOs/ISOs that have an existing decision-making process that includes 
state entity participation to continue using it, citing SPP's Regional 
State Committee and MISO's OMS as well-established processes developed 
over many years with stakeholder input. Nebraska Commission adds that 
providing flexibility in this process for transmission providers would 
be the least disruptive and most useful approach.\2868\ Relatedly, 
ACORE states that where agreements on cost allocation have already been 
reached with state entities for transmission projects with multiple 
benefits, the Commission should not require transmission providers to 
revisit those agreements.\2869\
---------------------------------------------------------------------------

    \2868\ Nebraska Commission Initial Comments at 10.
    \2869\ ACORE Initial Comments at 18 (NOPR, 179 FERC ] 61,028 at 
P 314).
---------------------------------------------------------------------------

    1341. ISO-NE also supports the Commission's proposal to afford 
transmission providers flexibility in determining what constitutes 
state agreement, as well as the process by which they seek agreement 
from the states. ISO-NE argues that if state agreement cannot be 
reached, the Commission should allow the transmission planning region 
to develop a fallback cost allocation method for use in the event that 
the states agree to move forward with a long-term transmission facility 
to advance public policy, but do not agree on a cost allocation method. 
ISO-NE requests that a final order be clear that the OATT will be the 
means by which the states will communicate the agreed cost allocation 
method to the transmission provider, but the OATT should not dictate 
the process by which states engage to achieve consensus.\2870\
---------------------------------------------------------------------------

    \2870\ ISO-NE Initial Comments at 37-38.
---------------------------------------------------------------------------

    1342. Some commenters favor mandating what constitutes agreement 
among Relevant State Entities. Pine Gate states that the Commission 
should establish a minimum set of criteria outlining when it will 
consider there to be such agreement. Pine Gate also asks for 
clarification as to whether unanimity is necessary for states to reach 
agreement on a cost allocation method.\2871\ Similarly, AEE requests 
additional guidance on what it means for states to ``agree'' to cost 
allocation approaches.\2872\ Shell states that an OATT mechanism that 
clearly delineates the process and timing for state input will 
facilitate the participation of Relevant States Entities. However, 
Shell further states, the OATT provision could provide flexibility for 
stakeholders to identify the relevant agency for each state as the 
voting entity for cost allocation decisions.\2873\
---------------------------------------------------------------------------

    \2871\ Pine Gate Initial Comments at 45-46.
    \2872\ AEE Initial Comments at 32-33 (citing NOPR, 179 FERC ] 
61,028 at P 306).
    \2873\ Shell Initial Comments at 16-17.
---------------------------------------------------------------------------

    1343. Acadia Center and CLF assert that the Commission should 
clarify that states within a given transmission planning region need 
not unanimously agree on a cost allocation method and can define 
agreement as necessary when a majority of states in such region approve 
a cost allocation method for transmission facilities.\2874\ Acadia 
Center and CLF explain that such an approach is consistent with 
NESCOE's memorandum of understanding in ISO-NE,\2875\ and similarly, 
New England for Offshore Wind argues that the Commission should not 
require agreement to be unanimous among states in a multi-state 
transmission planning region.\2876\
---------------------------------------------------------------------------

    \2874\ Acadia Center and CLF Initial Comments at 30.
    \2875\ Id. at 31 (citing Memorandum of Understanding Among ISO-
NE, NEPOOL, and NESCOE, at 3, 9 (Nov. 21, 2007), https://www.iso-ne.com/static-assets/documents/regulatory/part_agree/mou_final.pdf).
    \2876\ New England for Offshore Wind Initial Comments at 4-5.
---------------------------------------------------------------------------

    1344. PIOs also argue that the Commission should not require that 
states in a particular transmission planning region unanimously approve 
an ex ante cost allocation method. PIOs assert, rather, that the 
Commission should allow transmission providers to adopt a cost 
allocation method that is otherwise just and reasonable with agreement 
among a majority of states. PIOs state that each RTO/ISO has an 
organization of states that operates as a committee and that most of 
these committees require a simple majority vote (for example, the SPP 
Regional State Committee, OPSI, and OMS) and that the experience with 
the RTO/ISO regional state committees can be

[[Page 49488]]

extrapolated and applied to the non-RTO/ISO transmission planning 
regions as well.\2877\ Pattern Energy proposes that a reasonable 
threshold for ``agreement'' would be for one-half of the Relevant State 
Entities to agree to the Long-Term Regional Transmission Cost 
Allocation Method, State Agreement Process, or combination 
thereof.\2878\
---------------------------------------------------------------------------

    \2877\ PIOs Initial Comments at 66-67.
    \2878\ Pattern Energy Initial Comments at 19.
---------------------------------------------------------------------------

    1345. In contrast, Southeast PIOs propose that state agreement 
should require unanimous acceptance by the states in the relevant 
transmission planning region. Southeast PIOs state that in the event 
transmission providers are unable to achieve unanimity, the Commission 
could presumptively impose the cost allocation mechanism approved by a 
plurality of the transmission planning region's states.\2879\
---------------------------------------------------------------------------

    \2879\ Southeast PIOs Initial Comments at 56.
---------------------------------------------------------------------------

v. Outcome if Relevant State Entities Forgo a Role in Determining a 
Long-Term Regional Transmission Cost Allocation Method
    1346. Some commenters support the Commission's proposal that, in 
the event that states forgo a role in determining the cost allocation 
approach for all or a subset of Long-Term Regional Transmission 
Facilities, transmission providers must propose a Long-Term Regional 
Transmission Cost Allocation Method.\2880\
---------------------------------------------------------------------------

    \2880\ MISO Initial Comments at 67; NESCOE Initial Comments at 
59; Pennsylvania Commission Initial Comments at 13; PIOs Initial 
Comments at 67.
---------------------------------------------------------------------------

vi. Outcome if Relevant State Entities Fail To Reach Agreement on a 
Cost Allocation Method
    1347. Several commenters agree with the proposal that, in the event 
that Relevant State Entities fail to reach an agreement on a cost 
allocation method, transmission providers must file a cost allocation 
method with the Commission.\2881\ NARUC recommends that if Relevant 
State Entities are unable to reach agreement on cost allocation, the 
Commission should require transmission providers to file changes to 
their OATTs that reflect as much consensus as was reached.\2882\
---------------------------------------------------------------------------

    \2881\ ACEG Initial Comments at 64; Entergy Initial Comments at 
31; Pacific Northwest State Agencies Initial Comments at 29; 
PacifiCorp and NV Energy Initial Comments at 16; Pattern Energy 
Initial Comments at 19; TAPS Initial Comments at 4, 23-24.
    \2882\ NARUC Initial Comments at 48-49.
---------------------------------------------------------------------------

    1348. PIOs state that when cost allocation disputes occur, the 
Commission could use its authority to convene a joint board with 
affected states to consider issues and make decisions.\2883\ PIOs 
further state that if states cannot agree to an ex ante cost allocation 
method by the compliance deadline for the final order, the Commission 
should institute a default cost allocation method.\2884\
---------------------------------------------------------------------------

    \2883\ PIOs Initial Comments at 67 (citing 16 U.S.C. 824h; 18 
CFR 385.1304).
    \2884\ Id. at 69.
---------------------------------------------------------------------------

    1349. Similarly, Eversource and Vermont Electric and Vermont 
Transco state that when Relevant State Entities fail to agree on a cost 
allocation method, the Commission should establish the Long-Term 
Regional Transmission Cost Allocation Method.\2885\ To improve 
transparency and certainty, Clean Energy Associations state that the 
Commission should establish a cost allocation method upfront for 
situations where ``state concurrence on either an ex ante or ex post 
approach'' cannot be reached, submitting that a 90-day period would be 
reasonable for the Commission to determine a cost allocation method in 
the absence of state concurrence on either type of approach.\2886\
---------------------------------------------------------------------------

    \2885\ Eversource Initial Comments at 30 (citing NOPR, 179 FERC 
] 61,028 at P 310 (citation omitted)); Vermont Electric and Vermont 
Transco Initial Comments at 4.
    \2886\ Clean Energy Associations Initial Comments at 36.
---------------------------------------------------------------------------

    1350. In contrast, Pacific Northwest State Agencies oppose the 
Commission establishing a Long-Term Regional Transmission Cost 
Allocation Method on its own initiative.\2887\ NESCOE states that 
having the transmission provider file a cost allocation method when 
states cannot agree is preferable to the Commission establishing the 
cost allocation method. Specifically, NESCOE asserts that a more 
appropriate role for the Commission is to establish general principles 
under a final order and evaluate compliance filings made by 
transmission providers (or subsequent FPA section 205 proposals down 
the road) for adherence to those principles.\2888\
---------------------------------------------------------------------------

    \2887\ Pacific Northwest State Agencies Initial Comments at 29.
    \2888\ NESCOE Initial Comments at 61 (citing NOPR, 179 FERC ] 
61,028 at P 314).
---------------------------------------------------------------------------

    1351. NESCOE further suggests that if the states cannot reach 
agreement within the first four months after the effective date of a 
final order, they should be provided the opportunity to request that 
the Commission appoint one or more senior staff members to facilitate 
agreement.\2889\
---------------------------------------------------------------------------

    \2889\ Id. at 60.
---------------------------------------------------------------------------

    1352. In contrast, where agreement is not reached in the 
established timeframe, ACEG states that the Commission should permit 
transmission providers to explain their good faith efforts undertaken 
to seek agreement.\2890\
---------------------------------------------------------------------------

    \2890\ ACEG Initial Comments at 64-65.
---------------------------------------------------------------------------

    1353. Clean Energy Associations, some state legislators, and some 
US Senators state that the final order should provide clarity around 
how disagreements among states or transmission providers regarding cost 
allocation will be handled.\2891\ Clean Energy Associations recommend, 
and [Oslash]rsted agrees, that in the absence of such agreement, the 
Commission should require cost allocation to track the identified and 
quantifiable benefits of Long-Term Regional Transmission 
Facilities.\2892\ Senator Schumer supports providing guidance when 
there is no state agreement on cost allocation to prevent state vetoes 
of cost allocation methods and to prevent states being incentivized to 
free ride on transmission planning and avoid costs.\2893\
---------------------------------------------------------------------------

    \2891\ Clean Energy Associations Initial Comments at 35-36 
(citing NOPR, 179 FERC ] 61,028 at P 310); Environmental Legislators 
Caucus Supplemental Comments at 2; Senator Schumer Supplemental 
Comments at 2; US Senators Supplemental Comments at 2.
    \2892\ Clean Energy Associations Initial Comments at 35-36; 
[Oslash]rsted Initial Comments at 9.
    \2893\ Senator Schumer Supplemental Comments at 2.
---------------------------------------------------------------------------

c. Commission Determination
    1354. We decline to adopt the NOPR proposal to require transmission 
providers to seek the agreement of Relevant State Entities within the 
transmission planning region regarding the relevant cost allocation 
method to be applied to Long-Term Regional Transmission Facilities. 
Instead, we modify the NOPR proposal to establish a six-month time 
period (Engagement Period), during which transmission providers must: 
(1) provide notice of the starting and end dates for the six-month time 
period; (2) post contact information that Relevant State Entities may 
use to communicate with transmission providers about any agreement 
among Relevant State Entities on a Long-Term Regional Transmission Cost 
Allocation Method(s) and/or a State Agreement Process, as well as a 
deadline for communicating such agreement; and (3) provide a forum for 
negotiation of a Long-Term Regional Transmission Cost Allocation 
Method(s) and/or a State Agreement Process that enables meaningful 
participation by Relevant State Entities.
    1355. We adopt the NOPR proposal, with modification, to define 
Relevant State Entities as any state entity responsible for electric 
utility regulation or siting electric transmission facilities within 
the state or portion of a state located in the transmission planning

[[Page 49489]]

region, including any state entity as may be designated for that 
purpose by the law of such state.\2894\ We modify the definition to add 
the word ``electric'' before ``utility regulation'' to make clear that 
Relevant State Entities are those state agencies responsible for 
electric utility regulation, and not other types of utility regulation.
---------------------------------------------------------------------------

    \2894\ See NOPR, 179 FERC ] 61,028 at P 304.
---------------------------------------------------------------------------

    1356. Specifically, with respect to the mechanics of the Engagement 
Period, we require that transmission providers in each transmission 
planning region provide notice, such as on its OASIS page or public 
website, of the opportunity for any Relevant State Entity to 
participate in, and the starting and end dates of, the Engagement 
Period. The notice must include contact information for a single point 
of contact in the transmission planning region that the Relevant State 
Entities can use to communicate any agreement among Relevant State 
Entities on a Long-Term Regional Transmission Cost Allocation Method(s) 
and/or a State Agreement Process, as well as a deadline for 
communicating such agreement.\2895\ Such deadline must be no earlier 
than the end date of the Engagement Period.
---------------------------------------------------------------------------

    \2895\ As we discuss above in the Cost Allocation for Long-Term 
Regional Transmission Facilities section, Relevant State Entities 
must indicate that they have agreed to any State Agreement Process 
in order for any such process to be eligible for acceptance by the 
Commission in compliance with this final order. Consistent with FPA 
section 205, however, transmission providers have the right to not 
file a State Agreement Process. See infra Filing Rights Under the 
FPA section for a further discussion. See also Atl. City Elec. Co. 
v. FERC, 295 F.3d 1, 9 (D.C. Cir. 2002) (finding that the Commission 
may not require utility owners to give up statutory rights under FPA 
section 205).
---------------------------------------------------------------------------

    1357. We require transmission providers in each transmission 
planning region to provide a forum for negotiation that enables 
meaningful participation by Relevant State Entities during the 
Engagement Period, consistent with NARUC's suggestion.\2896\ We require 
transmission providers to explain on compliance how they complied with 
the requirement to establish and provide notice of an Engagement Period 
for Relevant State Entities to negotiate a Long-Term Regional 
Transmission Cost Allocation Method(s) and/or State Agreement Process, 
as well as how they complied with the requirement to provide a forum 
for such negotiation. In response to commenters that argue that their 
transmission planning regions already have mechanisms for state 
involvement in regional transmission planning and cost allocation 
processes,\2897\ we note that Relevant State Entities can choose to use 
existing mechanisms for state involvement in regional transmission 
planning and cost allocation processes, such as the SPP Regional State 
Committee and the Organization of MISO States, to negotiate a Long-Term 
Regional Transmission Cost Allocation Method(s) and/or a State 
Agreement Process. However, even where Relevant State Entities indicate 
to the transmission providers in a transmission planning region that 
they will use such existing mechanisms as the forum for their 
negotiations, transmission providers must still demonstrate on 
compliance that, consistent with the requirements of this final order, 
they provided notice of the starting and end dates for the six-month 
time period and posted contact information that Relevant State Entities 
may use to communicate with transmission providers about their proposed 
Long-Term Regional Transmission Cost Allocation Method(s) and/or a 
State Agreement Process to which Relevant State Entities have agreed, 
as well as a deadline for communicating such agreement.
---------------------------------------------------------------------------

    \2896\ NARUC Initial Comments at 44.
    \2897\ E.g., MISO Initial Comments at 61; SPP Initial Comments 
at 28-30; PJM Initial Comments at 116.
---------------------------------------------------------------------------

    1358. As described above, we adopt a six-month time period for the 
Engagement Period. While the NOPR did not propose a particular time 
period for the Engagement Period, we believe that the six-month time 
period that we adopt here balances the need to ensure that Relevant 
State Entities have sufficient time to negotiate a Long-Term Regional 
Transmission Cost Allocation Method(s) and/or State Agreement Process 
if they choose to do so, particularly given the complexity that such 
negotiations may involve, with the need to ensure that an extended 
Engagement Period does not unduly delay the implementation of the 
reforms that we adopt in this final order. We appreciate Alabama 
Commission's concerns about establishing a specific time period for 
negotiations, but we find that limiting the Engagement Period to six 
months is necessary to ensure that transmission providers have 
sufficient time to prepare their compliance filings in advance of the 
compliance deadlines that we establish in this final order.\2898\
---------------------------------------------------------------------------

    \2898\ Alabama Commission Initial Comments at 9.
---------------------------------------------------------------------------

    1359. If the Relevant State Entities participating in an Engagement 
Period agree on a Long-Term Regional Transmission Cost Allocation 
Method(s) and/or State Agreement Process and provide that Method or 
Methods and/or State Agreement Process to the transmission providers no 
later than the deadline for communicating agreement, which must be no 
earlier than the end date of the Engagement Period, the transmission 
providers may file the agreed-to Long-Term Regional Transmission Cost 
Allocation Method(s) and/or State Agreement Process on compliance. We 
note, however, that the ultimate decision as to whether to file a Long-
Term Regional Transmission Cost Allocation Method(s) and/or State 
Agreement Process to which Relevant State Entities have agreed will 
continue to lie with the transmission providers.
    1360. We do not adopt the NOPR proposal that for each state, a 
single entity should be designated as the voting or representative 
entity. In light of the fact that we now require an Engagement Period, 
rather than mandating that transmission providers seek agreement with 
Relevant Sate Entities on the relevant cost allocation method or 
process, we decline to adopt a requirement that a single entity be 
designated for each state as the voting or representative entity. In 
addition, we decline to define what constitutes agreement among 
Relevant State Entities, how such agreement is reached, and which 
Relevant State Entities must reach such agreement during the Engagement 
Period. Instead, we leave such matters, including whether to use 
existing state processes as a forum for negotiations, as Nebraska 
Commission advocates,\2899\ to the Relevant State Entities 
participating in the Engagement Period to determine. The requirements 
that we establish in the final order are that transmission providers 
must demonstrate on compliance that they established and provided 
notice of an Engagement Period for Relevant State Entities to negotiate 
a Long-Term Regional Transmission Cost Allocation Method(s) and/or 
State Agreement Process, as well as that they provided a forum for such 
negotiation.
---------------------------------------------------------------------------

    \2899\ Nebraska Commission Initial Comments at 10.
---------------------------------------------------------------------------

    1361. Likewise, we do not agree with commenters, like Pine Gate, 
that the Commission should establish a minimum set of criteria for a 
state agreement.\2900\ Instead, we find that the criteria for agreement 
are more appropriately determined by the Relevant State Entities 
participating in the Engagement Period. Whether agreement should 
require a majority,\2901\ a threshold of one-half of the participating 
Relevant State Entities,\2902\ or unanimity (Southeast PIOs) \2903\ is 
a

[[Page 49490]]

decision for the Relevant State Entities participating in the 
Engagement Period. We find that this approach also addresses many of 
the issues commenters raised relating to the potential difficulties 
associated with mandating agreement on a Long-Term Regional 
Transmission Cost Allocation Method(s), including ACEG's concern that 
requiring agreement could lead to certain states holding a veto power 
over the agreement.\2904\ Moreover, we reiterate that, as discussed in 
the Cost Allocation Methods for Long-Term Regional Transmission 
Facilities section above, transmission providers must file a Long-Term 
Regional Transmission Cost Allocation Method on compliance with this 
final order; a State Agreement Process cannot be the sole method filed 
for cost allocation for Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------

    \2900\ Pine Gate Initial Comments at 45-46.
    \2901\ Acadia Center and CLF Initial Comments at 30; PIOs 
Initial Comments at 66-67.
    \2902\ Pattern Energy Initial Comments at 19.
    \2903\ Southeast PIOs Initial Comments at 56.
    \2904\ ACEG Initial Comments at 66.
---------------------------------------------------------------------------

    1362. We acknowledge commenters' support of the NOPR proposal to 
require transmission providers to seek the agreement of Relevant State 
Entities regarding the relevant cost allocation method or process to be 
applied to Long-Term Regional Transmission Facilities, based upon the 
rationale that states play a critical role in transmission planning, 
and that facilitating their engagement in cost allocation may minimize 
delays and additional costs that can be associated with associated 
transmission siting proceedings.\2905\ We find that requiring an 
Engagement Period provides the same opportunity for robust engagement 
in the cost allocation process as the NOPR proposal, and thus has the 
potential to achieve the same important benefits, but will reduce the 
practical challenges associated with requiring transmission providers 
to seek the agreement of Relevant State Entities.\2906\
---------------------------------------------------------------------------

    \2905\ NOPR, 179 FERC ] 61,028 at P 301 (footnote omitted); see, 
e.g., Avangrid Initial Comments at 28; City of New Orleans Council 
Initial Comments at 9; SoCal Edison Initial Comments at 3, 13.
    \2906\ See, e.g., Minnesota State Entities Initial Comments at 7 
(claiming that a requirement to seek agreement could lead to 
disputes over the rights and responsibilities of individual states 
or state commissions to veto or otherwise hold up needed region-wide 
transmission plans).
---------------------------------------------------------------------------

    1363. While we agree with commenters regarding the value of an 
opportunity for state engagement regarding cost allocation, and 
accordingly adopt the Engagement Period, we do not agree that the views 
of state regulators regarding the appropriate cost allocation approach 
are dispositive.\2907\ Transmission providers retain the ultimate 
responsibility for transmission planning, and, as discussed below, they 
have FPA section 205 filing rights to propose tariff changes to rates, 
which the Commission cannot deprive them of via this final order.\2908\ 
The Commission has a statutory responsibility to review such filings to 
ensure that any proposed cost allocation is just and reasonable and not 
unduly discriminatory or preferential. Robust state engagement can 
valuably inform a cost allocation approach, but it cannot supplant 
these distinct, statutorily defined roles.
---------------------------------------------------------------------------

    \2907\ See, e.g., Southern Initial Comments at 9.
    \2908\ See, e.g., Atl. City Elec. Co. v. FERC, 295 F.3d at 9 
(noting that section 205 of the FPA gives utilities the right to 
file rates and terms for services rendered, and finding that the 
Commission cannot require that utility owners give up those 
statutory rights under FPA section 205); infra Filing Rights Under 
the FPA section.
---------------------------------------------------------------------------

    1364. We appreciate that certain commenters request to expand or 
clarify the NOPR's proposed definition of Relevant State Entities to 
include additional entities, or to otherwise allow the participation of 
other entities in the Engagement Period. For example, some commenters 
request that the definition be expanded to include Native American 
Tribes, self-regulated public power utilities, cooperatives, non-
jurisdictional transmission providers, customer interests, state 
utility consumer advocates, non-traditional state agencies, and local 
regulatory bodies.\2909\ However, we decline to expand participation in 
the Engagement Period beyond Relevant State Entities. As discussed in 
the NOPR, ``regional transmission facilities face significant 
uncertainty and risk of not reaching construction if certain 
stakeholders--in particular, a state regulator responsible for 
permitting transmission facilities--do not perceive the regional 
transmission facilities' value as commensurate with their costs.'' 
\2910\ The Commission further stated, and we continue to believe, that 
``providing state regulators with a formal opportunity to develop a 
cost allocation method for [Long-Term Regional Transmission Facilities] 
selected through Long-Term Regional Transmission Planning could help 
increase stakeholder--and state--support for those facilities, which, 
in turn, may increase the likelihood that those facilities are sited 
and ultimately developed with fewer costly delays and better ensure 
just and reasonable Commission-jurisdictional rates.'' \2911\ For the 
same reasons, we also do not find it necessary to allow other 
stakeholders to participate in the Engagement Period, as some 
commenters advocate.\2912\ In response to Nevada Commission's request 
for additional flexibility in the term Relevant State Entity,\2913\ and 
NESCOE's request to amend the definition to accommodate individual 
transmission planning regions' particular approaches to cost allocation 
requirements, we find that the definition of Relevant State Entities, 
as amended, recognizes the important role of states while providing 
sufficient regional flexibility for effective Engagement Period 
participation.\2914\
---------------------------------------------------------------------------

    \2909\ American Municipal Power Initial Comments at 5; APPA 
Initial Comments at 3, 42-43 (citing 16 U.S.C. 796(7), (15)); 
California Energy Commission Initial Comments at 3; California 
Municipal Utilities Initial Comments at 16-17; Large Public Power 
Initial Comments at 41; MISO Coops Initial Comments at 3-4; 
Northwest and Intermountain Initial Comments at 18; NRECA Initial 
Comments at 56-57; Six Cities Initial Comments at 10.
    \2910\ NOPR, 179 FERC ] 61,028 at P 297 (footnote omitted).
    \2911\ Id. at P 299.
    \2912\ See, e.g., Clean Energy Buyers Initial Comments at 29.
    \2913\ Nevada Commission Initial Comments at 13.
    \2914\ NESCOE Initial Comments at 57. As discussed below in the 
Proposals Relating to the Design and Operation of State Agreement 
Process section, we will permit other participants beyond Relevant 
State Entities to participate in the State Agreement Process, if 
agreed to by Relevant State Entities.
---------------------------------------------------------------------------

    1365. We acknowledge SERTP Sponsors' concern that determining which 
Relevant State Entities would be appropriate to participate will be a 
function of state law,\2915\ and, as Pennsylvania Commission points 
out, a state's legislature could have divided utility regulation and 
siting authority among different state agencies.\2916\ In response to 
these concerns and Duke's clarification request,\2917\ and as we note 
above, we provide flexibility on how Relevant State Entities reach 
agreement during the Engagement Period and decline to adopt the 
requirement that, for each state, a single entity should be designated 
as the voting or representative entity. We clarify that there may be 
multiple Relevant State Entities for each state, so long as each 
Relevant State Entity meets the definition as provided in this final 
order. As noted above, the definition of Relevant State Entity provides 
sufficient flexibility for participation in the Engagement Period.
---------------------------------------------------------------------------

    \2915\ SERTP Sponsors Initial Comments at 28-29.
    \2916\ Pennsylvania Commission Initial Comments at 15.
    \2917\ Duke Initial Comments at 38-39.
---------------------------------------------------------------------------

    1366. We find that the decision to modify the NOPR proposal, which 
would have required transmission providers to seek agreement of 
Relevant State Entities, to instead require transmission providers to 
establish a six-month Engagement Period largely moots several other 
reforms proposed in the NOPR. We therefore decline to adopt other 
proposed reforms that

[[Page 49491]]

detailed the requirements associated with transmission providers 
seeking agreement of Relevant State Entities.
    1367. We note that transmission providers' compliance with this 
final order is not contingent on Relevant State Entities' participation 
in the Engagement Period. Transmission providers' compliance with this 
final order is also not contingent on Relevant State Entities reaching 
an agreement on a Long-Term Regional Transmission Cost Allocation 
Method(s) and/or State Agreement Process. If Relevant State Entities 
fail to reach agreement on a Long-Term Regional Transmission Cost 
Allocation Method(s) and/or State Agreement Process, transmission 
providers must still file one or more Long-Term Regional Transmission 
Cost Allocation Methods in compliance with this final order. We 
acknowledge commenters' recommendations on action we should take in the 
event Relevant State Entities fail to reach an agreement. But we 
decline to convene a joint board of affected states if Relevant State 
Entities cannot agree, as suggested by PIOs,\2918\ and the Commission 
will not establish a Long-Term Regional Transmission Cost Allocation 
Method in the event that Relevant State Entities fail to agree, as 
proposed by Eversource and Vermont Electric and Vermont Transco.\2919\ 
Because this final order requires transmission providers to file a 
Long-Term Regional Transmission Cost Allocation Method, these 
additional steps are not necessary to ensure that there will be a cost 
allocation method for Long-Term Regional Transmission Facilities that 
are selected as the more efficient or cost-effective regional 
transmission solutions to Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \2918\ PIOs Initial Comments at 67.
    \2919\ Eversource Initial Comments at 30; Vermont Electric and 
Vermont Transco Initial Comments at 4.
---------------------------------------------------------------------------

    1368. Furthermore, we decline to adopt NARUC's request that the 
Commission provide a mechanism for future review of cost allocation 
methods for Long-Term Regional Transmission Facilities.\2920\ This 
final order requires that transmission providers establish a one-time 
Engagement Period for purposes of compliance with this final order; 
transmission providers may file subsequent changes to their cost 
allocation methods for Long-Term Regional Transmission Facilities 
pursuant to their filing rights under FPA section 205, at which point 
parties may file comments in support of or protests to such filings. We 
note, however, that some RTOs/ISOs have stakeholder processes that 
occur prior to making FPA section 205 filings on cost allocation, which 
could provide an additional opportunity for stakeholders to present 
their views on a proposed cost allocation method for Long-Term Regional 
Transmission Facilities. We decline to require future Engagement 
Periods beyond the initial Engagement Period but note that transmission 
providers may hold future Engagement Periods if they believe such 
periods would be beneficial.
---------------------------------------------------------------------------

    \2920\ NARUC Initial Comments at 49-50.
---------------------------------------------------------------------------

3. Proposals Relating to the Design and Operation of State Agreement 
Processes
a. NOPR Proposal
    1369. The Commission preliminarily found that a State Agreement 
Process by which one or more Relevant State Entities voluntarily agree 
to a cost allocation method for Long-Term Regional Transmission 
Facilities (or a portfolio of such Facilities) after they are selected 
may be a just and reasonable approach to cost allocation for such 
regional transmission facilities and that the State Agreement Process 
could apply to all Long-Term Regional Transmission Facilities or only 
to a subset thereof.\2921\
---------------------------------------------------------------------------

    \2921\ NOPR, 179 FERC ] 61,028 at P 311.
---------------------------------------------------------------------------

    1370. The Commission proposed to require that if the Relevant State 
Entities agree on a State Agreement Process, then the transmission 
providers in each transmission planning region must describe in their 
OATTs the process by which Relevant State Entities would reach 
voluntary agreement pursuant to that State Agreement Process regarding 
the cost allocation for Long-Term Regional Transmission Facilities, 
including the timeline for such processes. The Commission noted that, 
for example, the transmission providers in each transmission planning 
region could specify in their OATTs the procedures by which such 
voluntary agreements by the Relevant State Entities may be filed with 
the Commission for consideration under FPA section 205. The Commission 
proposed to require that such procedures include a process by which 
Relevant State Entities would agree to funding contributions and the 
mechanism by which such costs would be allocated (e.g., through a pro 
forma contract).\2922\
---------------------------------------------------------------------------

    \2922\ Id. P 313.
---------------------------------------------------------------------------

b. Comments
i. Support for State Agreement Process
    1371. Several commenters generally support the Commission's 
proposal to permit transmission providers to submit a State Agreement 
Process as a Long-Term Regional Transmission Cost Allocation 
Method.\2923\ NARUC supports allowing Relevant State Entities to agree 
to using the State Agreement Process to commit their customers to fund 
all or a portion of the costs of a Long-Term Regional Transmission 
Facility as a means of meeting a transmission planning region's 
selection criteria.\2924\
---------------------------------------------------------------------------

    \2923\ American Municipal Power Initial Comments at 12; City of 
New Orleans Initial Comments at 9-10; Entergy Initial Comments at 
34-35; Georgia Commission Initial Comments at 8-9; ISO-NE Initial 
Comments at 37; ITC Initial Comments at 28-32; Louisiana Commission 
Initial Comments at 33: Mississippi Commission Initial Comments at 
6; NARUC Initial Comments at 53-54; NESCOE Initial Comments at 62; 
North Carolina Commission and Staff Initial Comments at 15-16; Ohio 
Commission Federal Advocate Initial Comments at 12; Pacific 
Northwest State Agencies Initial Comments at 27, Pennsylvania 
Commission Initial Comments at 12-13; PIOs Initial Comments at 64; 
TAPS Initial Comments at 4-5, 24-26; Resale Iowa Initial Comments at 
2, 12; Southern Initial Comments at 9; SERTP Sponsors Initial 
Comments at 28-29.
    \2924\ NARUC Initial Comments at 53-54 (citing NOPR, 179 FERC ] 
61,028 at P 252).
---------------------------------------------------------------------------

    1372. Mississippi Commission contends that the State Agreement 
Process will likely promote transmission construction because authority 
over transmission construction and siting rests with the states.\2925\ 
Mississippi Commission asserts that the State Agreement Process is 
particularly suited to transmission facilities that promote state 
policies, noting that Long-Term Regional Transmission Planning should 
address state laws and utility integrated resource plans that affect 
the resource mix, but the cost of the transmission facilities needed to 
address those issues must be borne by the states and utilities whose 
laws and integrated resource plans require those facilities.\2926\ 
Likewise, Ohio Commission Federal Advocate asserts that a State 
Agreement Process is a just and reasonable way of allocating costs for 
public policy projects.\2927\ Relatedly, ELCON states that the 
Commission should emphasize that one state's public policy goals cannot 
supplant the cost causation principle or be used to impose costs on 
customers in states that do not have the same goals.\2928\
---------------------------------------------------------------------------

    \2925\ Mississippi Commission Initial Comments at 22.
    \2926\ Mississippi Commission Reply Comments at 3, 24 (citing 
Alabama Commission Initial Comments at 4; Illinois Commission at 4, 
7-8).
    \2927\ Ohio Commission Federal Advocate Initial Comments at 12.
    \2928\ ELCON Initial Comments at 17-18. Under the cost causation 
principle, the cost of transmission facilities must be allocated to 
those who benefit from those facilities in a manner that is at least 
roughly commensurate with estimated benefits. See S.C. Pub. Serv. 
Auth. v. FERC, 762 F.3d at 53 (quoting Order No. 1000, 136 FERC ] 
61,051 at P 586); see also ICC v. FERC I, 576 F.3d at 476.

---------------------------------------------------------------------------

[[Page 49492]]

    1373. Southern also notes that state support for transmission 
projects is crucial as the states retain primary jurisdiction over 
transmission siting and certification.\2929\ Southern asserts that 
states should generally be allowed to make transmission project 
selection and cost allocation decisions pursuant to the State Agreement 
Process after the planning is performed and specific costs and benefits 
are identified.\2930\ North Carolina Commission and Staff agree that 
the Commission should allow states to negotiate a cost allocation 
method after a transmission facility has been selected through Long-
Term Regional Transmission Planning.\2931\ Similarly, Pennsylvania 
Commission states that having the State Agreement Process occur after 
project selection will put planning in the driver's seat, and state 
negotiation will be centered around a transmission project already 
selected, which will ensure that project planning and selection run 
smoothly while not frustrating the fulfillment of a state's need during 
the state negotiation process.\2932\
---------------------------------------------------------------------------

    \2929\ Southern Initial Comments at 9.
    \2930\ Id. at 27.
    \2931\ North Carolina Commission and Staff Initial Comments at 
15-16.
    \2932\ Pennsylvania Commission Initial Comments at 12-13.
---------------------------------------------------------------------------

    1374. Massachusetts Attorney General states that, due to the range 
and complexity of benefits and the uncertainty associated with using a 
long transmission planning horizon, permitting states to diverge from 
ex ante cost allocation requirements for particular transmission 
projects or portfolios of projects may increase the likelihood that 
those facilities are sited and developed with fewer costly delays and 
will better ensure just and reasonable rates. Massachusetts Attorney 
General states that the potential benefits of the State Agreement 
Process outweigh any concerns about free ridership.\2933\ R Street 
agrees that the proposal for a State Agreement Process could reduce 
cost allocation and siting disputes, but asserts that states lack the 
jurisdiction and resources to serve an economic oversight role and thus 
that state participation is not a substitute for the Commission's 
economic oversight or for competitive mechanisms.\2934\
---------------------------------------------------------------------------

    \2933\ Massachusetts Attorney General Initial Comments at 19 
(citing NOPR, 179 FERC ] 61,028 at PP 299, 314).
    \2934\ R Street Initial Comments at 4, 12.
---------------------------------------------------------------------------

    1375. NESCOE supports the proposal that the State Agreement Process 
may apply to all, or a subset of, Long-Term Regional Transmission 
Facilities. NESCOE contends that, depending on the circumstances, 
Relevant State Entities may find it unnecessary to have the State 
Agreement Process apply to all such facilities, and having the 
flexibility to apply the State Agreement Process to a subset of 
facilities is a reasonable approach.\2935\
---------------------------------------------------------------------------

    \2935\ NESCOE Initial Comments at 62-63 (citing NOPR, 179 FERC ] 
61,028 at P 311).
---------------------------------------------------------------------------

ii. Concerns and Conditions for Support Regarding State Agreement 
Process
    1376. Some commenters qualified their support for the State 
Agreement Process and/or suggest that the Commission impose conditions 
upon the process, including those that advocated for flexibility and 
deference to existing efforts to incorporate state involvement.\2936\ 
US DOE, on behalf of its Federal power marketing administrations, notes 
that, to the extent that state agreements may involve the participation 
of Federal power marketing administrations, the process will need to 
accommodate the jurisdictional implications of the parties involved and 
that any agreements Federal power marketing administrations execute 
must be consistent with their statutory authorities.\2937\
---------------------------------------------------------------------------

    \2936\ Supra note 2923.
    \2937\ US DOE Initial Comments at 50.
---------------------------------------------------------------------------

    1377. Entergy states its understanding that state agreements will 
not bind retail commissions in exercising other authorities like siting 
and permitting.\2938\ Likewise, Pennsylvania Commission states that any 
State Agreement Process cannot serve to waive or diminish the state's 
siting authority over transmission facilities.\2939\
---------------------------------------------------------------------------

    \2938\ Entergy Initial Comments at 29-30 (citing NOPR, 179 FERC 
] 61,028 at PP 302-309, 314).
    \2939\ Pennsylvania Commission Initial Comments at 14.
---------------------------------------------------------------------------

    1378. Mississippi Commission states that involving state regulators 
in cost allocation ensures that one state's policy choices are not 
imposed on another state's consumers without their consent and that no 
state should be forced to subsidize implementation of another state's 
laws and policies.\2940\ Likewise, Avangrid states that one state 
should not be required to fund public policies of another state, as 
this could derail clean energy efforts and allow states to avoid paying 
their fair share.\2941\ NRG supports a role for states on transmission 
projects that would not exist but for state public policy.\2942\ 
Virginia Commission Staff avers that state entities should retain the 
right to assume cost responsibility for transmission projects intended 
to advance their public policy goals.\2943\
---------------------------------------------------------------------------

    \2940\ Mississippi Commission Reply Comments at 2-3.
    \2941\ Avangrid Initial Comments at 29.
    \2942\ NRG Initial Comments at 6.
    \2943\ Virginia Commission Staff Initial Comments at 6.
---------------------------------------------------------------------------

    1379. Pennsylvania Commission argues that the terms ex ante and ex 
post used in the definitions of the Long-Term Regional Transmission 
Cost Allocation Method and State Agreement Process are vague and that 
instead, the Commission should include in the definitions that the 
Long-Term Regional Transmission Cost Allocation Method and State 
Agreement Process are determined either before or after a transmission 
facility is selected.\2944\
---------------------------------------------------------------------------

    \2944\ Pennsylvania Commission Initial Comments at 14-15.
---------------------------------------------------------------------------

    1380. Entergy asserts that the Commission should permit flexibility 
as to when a State Agreement Process occurs despite the NOPR's 
reference to the State Agreement Process as ``an ex post cost 
allocation process'' because in some transmission planning regions, it 
may be appropriate for the State Agreement Process to begin before 
transmission projects are selected.\2945\ Entergy states that any State 
Agreement Process should be finalized before a portfolio is submitted 
to the MISO Board of Directors because it will provide certainty to 
stakeholders as to how costs will be allocated and ensure that the MISO 
Board of Directors understands how the cost allocation for the 
portfolio is consistent with the law and capable of withstanding legal 
challenges.\2946\ Relatedly, Mississippi Commission argues that Long-
Term Regional Transmission Facilities should not be presented to an 
RTO/ISO governing board until states have reached agreement on cost 
allocation.\2947\
---------------------------------------------------------------------------

    \2945\ Entergy Initial Comments at 34-35.
    \2946\ Id. at 35.
    \2947\ Mississippi Commission Initial Comments at 25-26.
---------------------------------------------------------------------------

    1381. Similarly, MISO asserts that the ex post nature of the State 
Agreement Process renders it unsuitable as the sole cost allocation 
method for Long-Term Regional Transmission Facilities. As such, MISO 
contends, cost allocation should be available only during a defined 
time set forth in the OATT, after the approval of the transmission 
projects, to avoid delays in the competitive transmission development 
process. MISO further states that failure to conclude the State 
Agreement Process in that timeframe should result in the transmission 
provider reverting to its

[[Page 49493]]

default Long-Term Regional Transmission Cost Allocation Method. 
Finally, MISO asks that the Commission clarify that transmission 
providers can make changes to their competitive transmission 
development process to accommodate the State Agreement Process.\2948\
---------------------------------------------------------------------------

    \2948\ MISO Initial Comments at 69.
---------------------------------------------------------------------------

    1382. DC and MD Offices of People's Counsel recommend that the 
State Agreement Process afford an opportunity for state entities to 
participate in transmission project evaluation and selection. They 
recommend this approach because of regional grid expansions that 
optimize the interconnection of portfolios of resources that likely 
result from power supply commitments made in conformity with state 
policies, and because state entity participation in cost allocation 
after a transmission project has already been selected may foreclose 
the consideration of state-specific benefits of grid decarbonization 
during project evaluation and selection.\2949\
---------------------------------------------------------------------------

    \2949\ DC and MD Offices of People's Counsel Initial Comments at 
37-38.
---------------------------------------------------------------------------

    1383. Alabama Commission contends that the Commission should 
provide for flexibility in the form and substance of any state 
agreement. Specifically, Alabama Commission explains that under Alabama 
law, it is unclear how the Alabama Commission would enter into such 
agreement and that its agreement may instead have to take the form of 
an order directed to Alabama Power.\2950\ SERTP Sponsors also state 
that the Commission should recognize the importance of flexibility in 
the development and structure of state agreements, agreeing that a 
state public service commission may not have authority to enter into 
binding state agreements. SERTP Sponsors offer that a state agreement 
for a state public service commission could be an endorsement of a 
voluntary participant funding agreement among its jurisdictional 
transmission providers.\2951\ Southeast PIOs state that the applicable 
cost allocation method should account for regional preferences and adds 
that an ex ante method is likely a non-starter in the Southeast, but 
that a State Agreement Process has real potential.\2952\
---------------------------------------------------------------------------

    \2950\ Alabama Commission Initial Comments at 10 n.8.
    \2951\ SERTP Sponsors Initial Comments at 28-29.
    \2952\ Southeast PIOs Reply Comments at 22-23 (citing Dominion 
Initial Comments at 50-52; Duke Initial Comments at 35-37; SERTP 
Sponsors Initial Comments at 28-29; Southern Initial Comments at 27-
28).
---------------------------------------------------------------------------

    1384. Acadia Center and CLF state that voluntary state agreements 
relating to offshore wind could result in more efficient and cost-
effective Long-Term Regional Transmission Facilities but request 
further clarity on voluntary agreements to assist states in 
understanding how these agreements allocate costs of transmission 
upgrades necessary for increased interconnection of renewable 
projects.\2953\ New England Systems states that the Commission should 
clarify that any State Agreement Process cannot increase the costs paid 
by a non-consenting transmission customer under an existing cost 
allocation method.\2954\ Pennsylvania Commission seeks clarification 
that a state that is not a party to a cost allocation agreement 
developed through the State Agreement Process cannot be required to pay 
for a selected transmission project.\2955\
---------------------------------------------------------------------------

    \2953\ Acadia Center and CLF Initial Comments at 32 & n.93.
    \2954\ New England Systems Initial Comments at 23.
    \2955\ Pennsylvania Commission Initial Comments at 12.
---------------------------------------------------------------------------

    1385. Cypress Creek states that the involvement of states in Long-
Term Regional Transmission Planning is important but that a State 
Agreement Process should not be required.\2956\ MISO requests that the 
State Agreement Process be optional so as not to disrupt current 
frameworks of state collaboration or delay transmission 
expansion.\2957\ MISO further asserts that the proposed cost allocation 
reforms may undermine existing cost allocation methods and that the 
Commission should not extend any requirements regarding state 
involvement to near-term reliability and economic regional transmission 
planning processes, which are beyond the scope of the final 
order.\2958\
---------------------------------------------------------------------------

    \2956\ Cypress Creek Reply Comments at 14 (citing Clean Energy 
Associations Initial Comments at 34).
    \2957\ MISO Reply Comments at 19.
    \2958\ MISO Initial Comments at 60, 71.
---------------------------------------------------------------------------

    1386. In addition, MISO argues that there should be no requirement 
for unanimous agreement under the State Agreement Process, particularly 
if the decision to adopt it rests with Relevant State Entities.\2959\ 
MISO states that some flexibility as to what constitutes agreement of 
Relevant State Entities may be justified.\2960\ While Interwest 
supports increased state engagement, it argues that state entities 
should not be authorized to limit regional transmission plans by veto 
or by using unjust and unreasonable cost allocation principles that are 
subjective or fail to comprehensively consider benefits.\2961\
---------------------------------------------------------------------------

    \2959\ Id. at 66-67; MISO Reply Comments at 19.
    \2960\ MISO Initial Comments at 66.
    \2961\ Interwest Initial Comments at 16.
---------------------------------------------------------------------------

    1387. Chemistry Council contends that consultation with affected 
states should not give individual states the power to ``hijack'' the 
transmission planning process by rejecting necessary investments, 
withholding consent, or delaying the decision-making process. Chemistry 
Council asserts that the Commission should clarify that in requiring 
transmission providers to ``seek agreement'' from states in 
transmission project selection, it is not suggesting that individual 
states would have a veto in the process or the ability to unduly 
influence the timing or outcome of decision-making.\2962\
---------------------------------------------------------------------------

    \2962\ Chemistry Council Initial Comments at 7.
---------------------------------------------------------------------------

    1388. Evergreen Action encourages the Commission to prohibit one 
state or stakeholder from vetoing transmission projects or cost 
allocation decisions. Evergreen Action further states that if consensus 
is not reached under a State Agreement Process, transmission providers 
should not extend the time allotted to reach agreement, because this 
would allow individual parties to delay the approval of needed 
transmission and remove the time pressure on Relevant State Entities to 
reach agreement. Evergreen Action avers that instead transmission 
providers should simply explain that they conducted a good-faith effort 
to reach agreement.\2963\
---------------------------------------------------------------------------

    \2963\ Evergreen Action Initial Comments at 6.
---------------------------------------------------------------------------

    1389. SEIA also urges the Commission to limit the opportunity for 
any single state to veto a transmission line and to use its backstop 
authority under section 216 of the FPA if parties are unable to reach 
an agreement and a relevant state authority withholds or denies the 
siting permit for the transmission facility.\2964\ US Climate Alliance 
agrees that the process should encourage states to engage in good faith 
discussions to realize common benefits without over-leveraging a single 
state's power over a regional transmission project.\2965\ National Grid 
suggests that if states cannot agree within a reasonable period on a 
proposed cost allocation method for a specific set of Long-Term 
Regional Transmission Facilities, then the transmission providers or 
developers building those facilities should be required to file a 
proposed cost allocation method for them.\2966\ In contrast, NRG states 
that without recourse to an ex ante cost allocation method, 
negotiations under the State Agreement Process would be more 
productive.\2967\
---------------------------------------------------------------------------

    \2964\ SEIA Initial Comments at 25 (citing 16 U.S.C. 824p(b)).
    \2965\ US Climate Alliance Initial Comments at 2.
    \2966\ National Grid Initial Comments at 25-26.
    \2967\ NRG Initial Comments at 20-21.

---------------------------------------------------------------------------

[[Page 49494]]

    1390. California Commission is concerned that the NOPR proposal 
grants too much deference to transmission providers and will enable 
them to exercise veto power over state-negotiated cost allocation 
agreements.\2968\ California Municipal Utilities and TANC ask that the 
Commission require that local regulatory authorities be included in any 
State Agreement Process, stating that the jurisdictional implications 
of the NOPR proposal are unclear given that public power entities are 
not generally subject to the jurisdiction of their respective state 
commissions.\2969\ Mississippi Commission and Northwest and 
Intermountain support expanding a State Agreement Process to include 
non-jurisdictional utilities.\2970\ California Municipal Utilities 
further assert that, if any state body is created to examine 
transmission planning issues, it must include public power 
entities.\2971\ Because the written comment process is not sufficient 
to facilitate a constructive dialogue, California Municipal Utilities 
urge the Commission to refrain from adopting any specific proposals 
from the NOPR until such a dialogue between states and public power can 
occur.\2972\
---------------------------------------------------------------------------

    \2968\ California Commission Initial Comments at 51, 54-55 
(citing NOPR, 179 FERC ] 61,028 at P 319).
    \2969\ California Municipal Utilities Initial Comments at 16; 
TANC Initial Comments at 17.
    \2970\ Mississippi Commission Reply Comments at 5 (citing MISO 
Coops Initial Comments at 3-4); Northwest and Intermountain Initial 
Comments at 18.
    \2971\ California Municipal Utilities Initial Comments at 4.
    \2972\ California Municipal Utilities Reply Comments at 10.
---------------------------------------------------------------------------

    1391. Some commenters are concerned about the reliance on voluntary 
contributions that may occur under a State Agreement Process. Clean 
Energy Associations states that while ex post frameworks that rely on 
voluntary contributions from states or interconnection customers may be 
useful in some circumstances, they may not appropriately acknowledge 
system-wide benefits of high-voltage elements, which under the State 
Agreement Process could be treated as benefitting only a single state. 
According to Clean Energy Associations, courts have found such an 
outcome improper, and this approach is unlikely to yield agreement in 
practice.\2973\ Likewise, Cypress Creek asserts that any ex post cost 
allocation method should acknowledge wide-spread benefits without 
imposing new restrictions.\2974\ AEE contends that the State Agreement 
Process, and more broadly the requirement to seek agreement of states 
regarding applicable cost allocation methods, should not substitute for 
allocating costs to all beneficiaries based on the broad set of 
benefits that regional transmission investment can provide. AEE states 
that reliance on voluntary state agreement should allow all states to 
consider the broad benefits that additional regional transmission 
facilities provide and the legal obligation to allocate costs 
commensurate with benefits received.\2975\
---------------------------------------------------------------------------

    \2973\ Clean Energy Associations Initial Comments at 35 (citing 
Old Dominion Elec. Coop. v. FERC, 898 F.3d at 1261).
    \2974\ Cypress Creek Reply Comments at 14.
    \2975\ AEE Reply Comments at 15-16.
---------------------------------------------------------------------------

    1392. DC and MD Offices of People's Counsel suggest that cost 
allocation should be based on the NOPR's defined benefits to all 
appropriate beneficiaries, with a further cost allocation to states 
that opt to submit additional transmission needs. DC and MD Offices of 
People's Counsel state that this approach would be more expansive than 
the existing State Agreement Approach in PJM because it would allow for 
a parallel default allocation of costs to the state entities not opting 
in, but narrowed to align with the NOPR-listed benefits, and a second 
round of cost allocation after the participating Relevant State 
Entities have shared costs aligned with the broader measure of 
benefits, which would help avoid the free-rider problem.\2976\
---------------------------------------------------------------------------

    \2976\ DC and MD Offices of People's Counsel Initial Comments at 
38-39 (citing PJM Interconnection, L.L.C., 179 FERC ] 61,024).
---------------------------------------------------------------------------

    1393. Avangrid states that a fair approach to cost allocation under 
the State Agreement Process could be payments and benefits based on 
tiers, providing the example that if states A and B have public 
policies supported by new transmission while state C does not, then 
only states A and B should pay the cost of public policy benefits while 
all three states should be responsible for the cost associated with 
economic and reliability benefits.\2977\ Similarly, PIOs assert that 
under the State Agreement Process, costs identified in Long-Term 
Regional Transmission Planning should first be allocated to 
transmission customers as the primary beneficiaries, and then states 
and/or interconnection customers can voluntarily accept cost allocation 
for the alternative or expanded transmission projects compared to 
projects identified in the regional base case plan.\2978\
---------------------------------------------------------------------------

    \2977\ Avangrid Initial Comments at 29-30.
    \2978\ PIOs Initial Comments at 68 (citing NOPR, 179 FERC ] 
61,028 at PP 75-76).
---------------------------------------------------------------------------

    1394. AEE asks that the Commission provide additional guardrails 
for the State Agreement Process to ensure that there are not 
transmission project delays.\2979\ According to AEE, the Commission 
must ensure that excessive reliance on the State Agreement Process does 
not exacerbate free-ridership problems where states outside of those 
agreements receive benefits from transmission projects developed under 
state agreements but are not expected to contribute to the costs.\2980\
---------------------------------------------------------------------------

    \2979\ AEE Initial Comments at 33 (citing NOPR, 179 FERC ] 
61,028 at PP 311-318).
    \2980\ Id.
---------------------------------------------------------------------------

    1395. Duke argues that any tariff language memorializing the State 
Agreement Process must specify that the transmission provider ``will 
not be obligated to accept cost allocation methods proposed by Relevant 
State Entities.'' \2981\ Duke also asks that the Commission clarify 
that if transmission providers only adopt a State Agreement Process, 
and that fails, then transmission providers are free to make an FPA 
section 205 filing to implement an ex post cost allocation 
method.\2982\ Further, Duke asks that the Commission clarify that the 
regulatory text's reference to ``transmission provider'' is ``the 
entity with the section 205 rights to initiate rate changes, which 
depending upon the applicable governance and OATT structures, may be 
the transmission owner, but not the transmission provider.'' \2983\
---------------------------------------------------------------------------

    \2981\ Duke Initial Comments at 39-40.
    \2982\ Id. at 3.
    \2983\ Id. at 40 n.77.
---------------------------------------------------------------------------

    1396. Some commenters support requiring state involvement in cost 
allocation. For example, New York Commission and NYSERDA state that 
state-led cost allocation should be a requirement in any final order 
and that cost allocation for public policy-driven transmission projects 
should be subject to state review and approval.\2984\ Pacific Northwest 
State Agencies support requiring transmission providers to have an ex 
post State Agreement Process as an alternative to an ex ante cost 
allocation method.\2985\
---------------------------------------------------------------------------

    \2984\ New York Commission and NYSERDA Initial Comments at 12, 
14.
    \2985\ Pacific Northwest State Agencies Initial Comments at 27.
---------------------------------------------------------------------------

iii. Opposition to a State Agreement Process
    1397. Some commenters express concern that a State Agreement 
Process may not be a just and reasonable approach to cost allocation 
for regional transmission facilities.\2986\ R Street contends that 
states do not represent all beneficiaries who may be assigned costs 
and, as such, cost allocation predicated on state agreement may be 
unjust and

[[Page 49495]]

unreasonable. R Street states, however, that a state advisory or 
partial approval mechanism could be structured to give state agreement 
pivotal influence over cost allocation decisions.\2987\
---------------------------------------------------------------------------

    \2986\ APPA Initial Comments at 40, 44; MISO Coops Initial 
Comments at 2; R Street Initial Comments at 12.
    \2987\ R Street Initial Comments at 12.
---------------------------------------------------------------------------

    1398. APPA claims that the proposed State Agreement Process is 
unworkable and creates significant uncertainty and potential for 
litigation.\2988\ APPA further asserts that providing state regulators 
with an exclusive role in determining cost allocation methods will not 
likely result in a broad consensus across stakeholders.\2989\ MISO 
Coops add that it is unjust and unreasonable, arguing that, because 
cooperatives are often not jurisdictional to a state entity, it is 
unclear how cooperatives would be represented. Thus, MISO Coops state, 
the State Agreement Process would reduce the involvement of 
cooperatives in regional transmission planning processes while granting 
states authority over entities outside their jurisdiction. MISO Coops 
further state that the proposed State Agreement Process is unnecessary 
because the current MISO stakeholder process is superior.\2990\ MISO 
TOs oppose any provision that would mandate a State Agreement 
Process.\2991\
---------------------------------------------------------------------------

    \2988\ APPA Initial Comments at 40, 44.
    \2989\ Id. at 43.
    \2990\ MISO Coops Initial Comments at 2-4.
    \2991\ MISO TOs Initial Comments at 5, 46.
---------------------------------------------------------------------------

iv. Requirement To Document State Agreement Process in OATT
    1399. Some commenters agree with the NOPR proposal that for any 
State Agreement Process, transmission providers in each transmission 
planning region must detail in their OATTs the process by which 
Relevant State Entities would reach agreement regarding the cost 
allocation for Long-Term Regional Transmission Facilities pursuant to 
the State Agreement Process, including the timeline for such 
processes.\2992\ NESCOE contends that if the State Agreement Process is 
chosen by the Relevant State Entities, the details of how the state 
entities would agree to funding contributions and the mechanisms by 
which the costs would be allocated should be mostly informed by states 
and then filed by the transmission provider.\2993\ NESCOE suggests that 
the Commission be open to variations in the State Agreement Process as 
long as the details of all those variations are filed with the 
Commission.\2994\
---------------------------------------------------------------------------

    \2992\ Louisiana Commission Initial Comments at 33; NESCOE 
Initial Comments at 63; SDG&E Initial Comments at 5; TAPS Initial 
Comments at 24.
    \2993\ NESCOE Initial Comments at 63.
    \2994\ NESCOE Reply Comments at 5.
---------------------------------------------------------------------------

    1400. Northwest and Intermountain state that the Commission should 
review negotiated cost allocation methods.\2995\ Likewise, APPA argues 
that the Commission should require that any state agreement to 
voluntarily fund transmission facilities must be filed with the 
Commission for approval, in order to afford parties the opportunity to 
comment.\2996\
---------------------------------------------------------------------------

    \2995\ Northwest and Intermountain Initial Comments at 18-19.
    \2996\ APPA Initial Comments at 34-35.
---------------------------------------------------------------------------

    1401. Some commenters disagree that the Commission should require 
transmission providers in each transmission planning region to detail 
such processes in their OATTs. For example, OMS argues that it is 
unnecessary for transmission providers to explicitly define such a 
process in their OATTs.\2997\ Mississippi Commission argues that the 
Commission should clarify that OATT language describing the process by 
which states reach agreement should not be prescriptive or limiting 
and, instead, should provide only a general discussion of a 
process.\2998\
---------------------------------------------------------------------------

    \2997\ OMS Initial Comments at 12-13.
    \2998\ Mississippi Commission Initial Comments at 27-28.
---------------------------------------------------------------------------

c. Commission Determination
    1402. We adopt the NOPR proposal, with modification, to allow, but 
not require, transmission providers in each transmission planning 
region to adopt a State Agreement Process for allocating the costs of 
all, or a subset of, Long-Term Regional Transmission Facilities. We 
also modify the definition of State Agreement Process to be a process 
by which one or more Relevant State Entities may voluntarily agree to a 
cost allocation method for Long-Term Regional Transmission Facilities 
(or a portfolio of such Facilities) either before or no later than six 
months after the facilities are selected in the regional transmission 
plan for purposes of cost allocation. We note that Relevant State 
Entities have the option to include the participation of other entities 
in a State Agreement Process.
    1403. As discussed in more detail below, we also adopt the NOPR 
proposal to require transmission providers that choose to file any 
State Agreement Process agreed to by Relevant State Entities to 
describe the State Agreement Process in proposed tariff provisions in 
their OATTs. The tariff provisions must describe key information on how 
the State Agreement Process will result in a cost allocation being 
filed, including which entities can participate in the State Agreement 
Process; what constitutes an agreement on cost allocation in that 
process; how agreement is communicated to the transmission providers; 
and the circumstances under which, or the information necessary for, 
transmission providers to file or to consider filing the agreed cost 
allocation method.\2999\
---------------------------------------------------------------------------

    \2999\ NOPR, 179 FERC ] 61,028 at P 313.
---------------------------------------------------------------------------

    1404. Consistent with the NOPR, we find that a State Agreement 
Process can be a just and reasonable approach to allocate costs for 
Long-Term Regional Transmission Facilities. We also find that State 
Agreement Processes may apply to all Long-Term Regional Transmission 
Facilities or only to a subset thereof.\3000\ We believe that allowing 
State Agreement Processes will help to address some commenters' request 
for a stronger state role in the cost allocation of Long-Term Regional 
Transmission Facilities,\3001\ increasing the likelihood that more 
efficient or cost-effective Long-Term Regional Transmission Facilities 
that are selected will be developed. However, as discussed in Cost 
Allocation Methods for Long-Term Regional Transmission Facilities 
section above, a State Agreement Process cannot be the sole method 
filed for cost allocation for Long-Term Regional Transmission 
Facilities; we also require transmission providers to file a Long-Term 
Regional Transmission Cost Allocation Method on compliance with this 
final order so that if the State Agreement Process on file fails to 
result in a Commission-accepted cost allocation method, there will 
still be a cost allocation method for Long-Term Regional Transmission 
Facilities that are selected as the more efficient or cost-effective 
regional transmission solutions to Long-Term Transmission Needs.
---------------------------------------------------------------------------

    \3000\ Id. P 311.
    \3001\ See, e.g., Mississippi Commission Initial Comments at 22; 
Southern Initial Comments at 9.
---------------------------------------------------------------------------

    1405. We note that this final order provides significant 
flexibility to Relevant State Entities with respect to the design and 
implementation of any State Agreement Process. Such flexibility 
includes, for example, the opportunity to decide which entities beyond 
Relevant State Entities will participate in the State Agreement 
Process, the ability to identify the Long-Term Regional Transmission 
Facilities to which the State Agreement Process will apply, and how 
agreement as to a cost allocation method will be reached.
    1406. We further expand these flexibilities by modifying the NOPR 
proposal to clarify that a State Agreement Process can occur either 
before or no later than six months after

[[Page 49496]]

a Long-Term Regional Transmission Facility (or portfolio of such 
Facilities) is selected. We believe that providing flexibility for a 
State Agreement Process to occur (and thus for the Relevant State 
Entities to agree on a cost allocation method) before Long-Term 
Regional Transmission Facilities (or a portfolio of such Facilities) 
are selected will increase the likelihood that Regional State Entities 
support their selection and future development. We note that this 
flexibility with regard to the timing of a State Agreement Process 
should accommodate the timing preferences expressed by certain 
commenters.\3002\ However, we also require that any State Agreement 
Process must be completed, i.e., any resulting cost allocation method 
must be filed with the Commission, no later than six months after 
selection of the applicable Long-Term Regional Transmission Facility 
(or portfolio of such Facilities).\3003\
---------------------------------------------------------------------------

    \3002\ See, e.g., Pennsylvania Commission Initial Comments at 
12-13; Entergy Initial Comments at 35.
    \3003\ We discuss this duration requirement infra at P 1413.
---------------------------------------------------------------------------

    1407. As the Commission has previously noted, agreements outside of 
the context of Order No. 1000 regional cost allocation methods, such as 
PJM's State Agreement Approach, can result in cost allocations that are 
just and reasonable.\3004\ We also note that Order No. 1000 allows 
market participants to negotiate alternative cost sharing arrangements 
voluntarily and separately from the regional cost allocation method or 
set of methods, and nothing in this final order would prohibit such 
voluntary cost sharing arrangements.\3005\ Moreover, as the Commission 
noted in the NOPR, the Commission recently issued a Policy Statement 
addressing state efforts to develop transmission facilities through 
voluntary agreements to plan and pay for those facilities, recognizing 
that such voluntary agreements may allow state-prioritized transmission 
facilities to be planned and built more quickly than would comparable 
facilities that are through the regional transmission planning 
process.\3006\ Further, while we require in this final order that 
transmission providers have a Long-Term Regional Transmission Cost 
Allocation Method for selected Long-Term Regional Transmission 
Facilities, we note that nothing in this final order limits a 
transmission provider's ability to propose under FPA section 205 any 
other cost allocation methods in addition to the cost allocation method 
used to comply with this final order.
---------------------------------------------------------------------------

    \3004\ See PJM Interconnection, L.L.C., 142 FERC ] 61,214 at P 
142; PJM Interconnection, L.L.C., 179 FERC ] 61,024 at PP 40-43.
    \3005\ See Order No. 1000, 136 FERC ] 61,051 at P 561.
    \3006\ NOPR, 179 FERC ] 61,028 at P 300 (citing State Voluntary 
Agreements to Plan & Pay for Transmission Facilities, 175 FERC ] 
61,225 at PP 2, 6).
---------------------------------------------------------------------------

    1408. In the NOPR, the Commission noted that it has previously 
expressed concern regarding participant funding, which shares some 
similarities with State Agreement Processes.\3007\ In Order No. 1000, 
for example, the Commission explained that reliance on participant 
funding as a regional cost allocation method ``increases the incentive 
of any individual beneficiary to defer investment in the hopes that 
other beneficiaries will value a transmission project enough to fund 
its development'' and would therefore not comply with the Order No. 
1000 regional cost allocation principles.\3008\ The Commission declined 
to allow transmission providers to file participant funding cost 
allocation approaches as their ex ante cost allocation methods for 
selected regional transmission facilities.\3009\ We take a similar 
approach here: we require transmission providers to include in their 
OATTs one or more Long-Term Regional Transmission Cost Allocation 
Methods (i.e., their ex ante cost allocation method(s)) that can be 
used to allocate the costs of selected Long-Term Regional Transmission 
Facilities. As in Order No. 1000, the Long-Term Regional Transmission 
Cost Allocation Method cannot be participant funding. We find that 
requiring a Long-Term Regional Transmission Cost Allocation Method or 
Methods that will apply to any selected Long-Term Regional Transmission 
Facility reduces the incentive for project beneficiaries to defer 
investment.
---------------------------------------------------------------------------

    \3007\ See id. P 316 (citing Order No. 1000, 136 FERC ] 61,051 
at P 723).
    \3008\ Id. P 316 (quoting Order No. 1000, 136 FERC ] 61,051 at P 
723). Under a participant funding approach to cost allocation, the 
costs of a transmission facility are allocated only to those 
entities that volunteer to bear those costs. Id. P 316 n.519 (citing 
Order No. 1000, 136 FERC ] 61,051 at P 486 n.375).
    \3009\ See Order No. 1000, 136 FERC ] 61,051 at P 723.
---------------------------------------------------------------------------

    1409. However, in addition to requiring a Long-Term Regional 
Transmission Cost Allocation Method, we also provide flexibility to 
Relevant State Entities to agree to a State Agreement Process, which 
transmission providers may choose to file as part of their compliance 
filings. We conclude that allowing such an approach as an option is 
reasonable despite the Commission's previously-stated concerns with 
participant funding, because a State Agreement Process is an 
established process, agreed to in advance and described in transmission 
providers' OATTs, through which Relevant State Entities agree to a cost 
allocation method. We find that, for the purposes of Long-Term Regional 
Transmission Planning, a State Agreement Process will help to 
facilitate agreement and cooperation among Relevant State Entities. We 
find that this approach balances the need for the certainty with 
respect to cost allocation provided by an ex ante cost allocation 
method with the flexibility of allowing for a State Agreement Process-
derived cost allocation method for selected Long-Term Regional 
Transmission Facilities (or portfolios of such Facilities). We 
emphasize, however, that the Commission will still review any cost 
allocation method that results from a State Agreement Process to ensure 
that it is just and reasonable and not unduly discriminatory or 
preferential, and that it allocates costs in a manner that is at least 
roughly commensurate with estimated benefits.
    1410. In the context of Long-Term Regional Transmission Planning, 
we believe that allowing the use of State Agreement Processes to derive 
a cost allocation method for selected Long-Term Regional Transmission 
Facilities will provide states with an opportunity to be more involved 
in cost allocation for these transmission facilities, leading to an 
increased likelihood that such facilities are developed. Specifically, 
the engagement of Relevant State Entities in cost allocation 
discussions could reduce instances in which a Long-Term Regional 
Transmission Facility is selected and has an established ex ante cost 
allocation method that applies to it, but ultimately is not developed 
because it does not receive a necessary state approval.\3010\ We also 
find that a State Agreement Process could provide greater confidence to 
Relevant State Entities that customers are receiving benefits in a 
manner that is at least roughly commensurate with the costs they are 
paying for Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------

    \3010\ NOPR, 179 FERC ] 61,028 at P 314.
---------------------------------------------------------------------------

    1411. We acknowledge commenters' concerns that a State Agreement 
Process could present free-ridership issues.\3011\ For example, there 
could be free-ridership concerns if the Relevant State Entities in 
certain states agree to be allocated all of the costs for a particular 
Long-Term Regional Transmission Facility but that facility also 
benefits other entities in other states that are not similarly 
allocated costs under the cost allocation method arrived at through the 
State Agreement Process. However, we

[[Page 49497]]

continue to find that allowing a State Agreement Process for Long-Term 
Regional Transmission Facilities, where agreed to by the Relevant State 
Entities, appropriately balances free-ridership concerns with the 
benefit of greater state involvement in determining the cost allocation 
method for Long-Term Regional Transmission Facilities and the increased 
likelihood that such facilities will be built.\3012\ Additionally, 
nothing in this final order changes the requirements for all cost 
allocation methods, including those that result from a State Agreement 
Process, to allocate costs in a manner that is at least roughly 
commensurate with estimated benefits, and we believe that Commission 
review to ensure that cost allocation methods meet that standard will 
act to prevent free ridership.
---------------------------------------------------------------------------

    \3011\ See, e.g., R Street Initial Comments at 12.
    \3012\ NOPR, 179 FERC ] 61,028 at P 317.
---------------------------------------------------------------------------

    1412. As noted above, there is significant commenter support for a 
State Agreement Process, particularly among state entities. In 
addition, we believe that many of the concerns expressed about the 
State Agreement Process proposal appear to be based on a lack of 
sufficient explanation in the NOPR regarding the implications of the 
proposal, which we clarify here. Contrary to some comments, we do not 
require transmission providers to adopt a State Agreement Process; 
rather, as discussed in the Filing Rights Under the FPA section, 
transmission providers may choose to file a State Agreement Process for 
all, or a subset of, Long-Term Regional Transmission Facilities on 
compliance. Also, we neither impose an obligation on a state or states 
to agree to a cost allocation method for Long-Term Regional 
Transmission Facilities, nor do we create any obligation that 
transmission providers file a cost allocation method resulting from a 
State Agreement Process, unless the transmission providers had clearly 
indicated assent to do so in their OATTs.\3013\ As we note in the 
discussion of transmission provider filing rights in the Filing Rights 
Under the FPA section below, we believe that the applicable statute and 
precedent require us to preserve the right of transmission providers to 
file with the Commission their preferred cost allocation method for 
Long-Term Regional Transmission Facilities to comply with the 
requirements of this final order.
---------------------------------------------------------------------------

    \3013\ For example, transmission providers may voluntarily agree 
as part of a State Agreement Process in their OATTs that 
transmission providers shall file any cost allocation method that 
meets the requirements of their State Agreement Process, even if 
those transmission providers do not agree with that method.
---------------------------------------------------------------------------

    1413. However, as noted earlier in this section, we establish a 
deadline of no later than six months after selection of a Long-Term 
Regional Transmission Facility (or portfolio of such Facilities) by 
which transmission providers must file any cost allocation method that 
results from a State Agreement Process. We believe that the State 
Agreement Process can only be effective if there is a limit on the time 
to reach agreement before defaulting to the Long-Term Regional 
Transmission Cost Allocation Method that we require transmission 
providers include in their OATTs. The lack of such a deadline could 
cause delay and increase uncertainty regarding selected Long-Term 
Regional Transmission Facilities. In addition, we agree with some 
commenters \3014\ that a deadline, bolstered by a default Long-Term 
Regional Transmission Cost Allocation Method, may increase the 
incentive for Relevant State Entities to reach agreement on cost 
allocation for a particular Long-Term Regional Transmission Facility 
through a State Agreement Process.
---------------------------------------------------------------------------

    \3014\ See Evergreen Action Initial Comments at 6; MISO Initial 
Comments at 67-68; National Grid Initial Comments at 25-26.
---------------------------------------------------------------------------

    1414. We find that six months is a reasonable period for State 
Agreement Process deliberations on a cost allocation method because it 
balances the need for adequate time for negotiations with transmission 
providers' need for finality in their Long-Term Regional Transmission 
Planning. While few commenters directly addressed the time period for 
negotiation under a State Agreement Process for a particular Long-Term 
Regional Transmission Facility (or portfolio of such Facilities), many 
commenters favored this duration for the NOPR proposed reform of a 
post-selection time period for states to negotiate an alternate cost 
allocation method for selected Long-Term Regional Transmission 
Facilities (or portfolios of such Facilities) when an ex ante cost 
allocation method would otherwise apply.\3015\
---------------------------------------------------------------------------

    \3015\ California Commission Initial Comments at 56; Kentucky 
Commission Chair Chandler Initial Comments at 4; Louisiana 
Commission Initial Comments at 34-35; NARUC Initial Comments at 52-
53; NRG Initial Comments at 21; Pacific Northwest State Agencies 
Initial Comments at 27-28.
---------------------------------------------------------------------------

    1415. We clarify that, if the Relevant State Entities indicate to 
transmission providers, as part of the required Engagement Period 
outlined above, that the Relevant State Entities have agreed to a State 
Agreement Process, and the transmission providers decide to include 
that State Agreement Process in their final order compliance filings, 
then the transmission providers must also detail the State Agreement 
Process in proposed tariff provisions to their OATTs. The tariff 
provisions must describe how agreement would be reached regarding the 
cost allocation method for Long-Term Regional Transmission Facilities 
pursuant to the State Agreement Process, which also necessarily 
requires that it be clear which entities can participate in the 
specific State Agreement Process.\3016\ This requirement is in 
furtherance of one of the goals of the final order, which is to allow a 
greater role for states in establishing a cost allocation method for 
Long-Term Regional Transmission Facilities (or portfolios of such 
Facilities).
---------------------------------------------------------------------------

    \3016\ NOPR, 179 FERC ] 61,028 at P 313.
---------------------------------------------------------------------------

    1416. As noted above, after the required initial Engagement Period, 
a State Agreement Process could include other entities beyond Relevant 
State Entities, and those entities would need to be enumerated in the 
State Agreement Process included in the OATT. Transmission providers 
must first specify in their OATTs a description of how such voluntary 
agreements by the Relevant State Entities may be shared with 
transmission providers, as well as whether the transmission providers 
voluntarily agree to undertake an obligation to file the agreed-upon 
cost allocation method with the Commission for consideration under FPA 
section 205 (in other words, whether the transmission providers 
voluntarily waive their FPA section 205 filing rights such that they 
commit themselves to file with the Commission any cost allocation 
method that results from the State Agreement Process). Their OATT 
provisions must, at a minimum, also include the event triggering the 
beginning of the State Agreement Process, the duration of the State 
Agreement Process (not to exceed six months after selection), and a 
description of the Long-Term Regional Transmission Facilities to which 
the process applies. Further, the State Agreement Process procedures 
outlined in transmission providers' OATTs must set forth the manner in 
which a transmission provider would file a section 205 filing to seek 
Commission acceptance of a cost allocation method resulting from a 
State Agreement Process. We note that Relevant State Entities that 
participate in a State Agreement Process may need to provide relevant 
information to transmission

[[Page 49498]]

providers to enable them to demonstrate that any cost allocation method 
that results from a State Agreement Process is just, reasonable, and 
not unduly discriminatory or preferential, and allocates cost in a 
manner that is at least roughly commensurate with estimated benefits.
    1417. We do not agree with the commenters that recommend against 
memorializing and filing cost allocation methods resulting from a State 
Agreement Process with the Commission.\3017\ To fulfill the 
Commission's statutory obligations, any cost allocation method that 
results from a State Agreement Process must be filed for review by the 
Commission and determined to be just, reasonable, and not unduly 
discriminatory or preferential. In addition, we believe that 
transparency regarding such cost allocation methods and the opportunity 
for stakeholders, particularly those that will be responsible for 
paying the costs of Long-Term Regional Transmission Facilities, to 
comment on them are an important safeguard to ensure that costs are 
allocated in a manner that is at least roughly commensurate with 
estimated benefits.
---------------------------------------------------------------------------

    \3017\ Mississippi Commission Initial Comments at 27-28; OMS 
Initial Comments at 12-13.
---------------------------------------------------------------------------

    1418. We will not specify the level of agreement among Relevant 
State Entities or other entities that is necessary before a 
transmission provider files a cost allocation method derived from a 
State Agreement Process. As a state-led process, we believe that 
Relevant State Entities should have the ability to determine this 
important facet of their State Agreement Process. To this end, we 
decline to require unanimity or a set minimum threshold for agreement 
of Relevant State Entities to participate in the State Agreement 
Process.
    1419. Some commenters request that the Commission clarify whether 
and to what extent a cost allocation method that results from a State 
Agreement Process can impose costs on entities that do not agree to 
that cost allocation method. However, we decline to prejudge any State 
Agreement Process or any cost allocation method that may result from a 
State Agreement Process. Any cost allocation method for a Long-Term 
Regional Transmission Facility (or portfolio of such Facilities) that 
results from a State Agreement Process must be filed with the 
Commission pursuant to FPA section 205, and the Commission must make a 
finding as to whether that cost allocation method is just, reasonable, 
and not unduly discriminatory or preferential. And, as noted above, we 
reiterate that all cost allocation methods, including those resulting 
from a State Agreement Process, must allocate costs in a manner that is 
at least roughly commensurate with estimated benefits.\3018\ Parties 
are free to raise any concerns about the costs that they may be 
allocated under a State Agreement Process-derived cost allocation 
method if and when that method is filed with the Commission.\3019\
---------------------------------------------------------------------------

    \3018\ See ICC v. FERC I, 576 F.3d at 477; ICC v. FERC III, 756 
F.3d at 564.
    \3019\ E.g., New England Systems Initial Comments at 23; 
Pennsylvania Commission Initial Comments at 12; Mississippi 
Commission Reply Comments at 3.
---------------------------------------------------------------------------

    1420. MISO asks that the final order make clear that transmission 
providers can make necessary changes to the competitive transmission 
developer selection process to accommodate the State Agreement 
Process.\3020\ We clarify that the Commission will review any proposed 
changes to transmission providers' competitive transmission developer 
selection processes to accommodate State Agreement Processes as part of 
their compliance filings to this final order.
---------------------------------------------------------------------------

    \3020\ MISO Initial Comments at 68-70.
---------------------------------------------------------------------------

    1421. With respect to California Municipal Utilities' and TANC's 
requests that the Commission require that local regulatory authorities 
be included in any State Agreement Process, the Mississippi 
Commission's statement that it would support expanding the State 
Agreement Approach to include non-jurisdictional utilities, we do not 
proscribe in this final order that the State Agreement Processes 
include other entities beyond Relevant State Entities. However, as 
noted above, Relevant State Entities have the option to include the 
participation of other entities in a State Agreement Process. Finally, 
with respect to US DOE's comments related to the jurisdictional 
implications of Federal power marketing administrations participating 
in State Agreement Processes, we do not establish any specific 
requirements for how State Agreement Processes will be designed. To the 
extent that a Federal power marketing administration does participate 
in such a process, it may advocate that such process facilitates its 
participation in a manner that is consistent with its statutory 
authority.\3021\
---------------------------------------------------------------------------

    \3021\ US DOE Initial Comments at 50.
---------------------------------------------------------------------------

4. Filing Rights Under the FPA
a. Comments
    1422. A number of commenters express concerns that a requirement to 
seek agreement from Relevant State Entities regarding a cost allocation 
approach could conflict with transmission providers' filing rights 
under the FPA.\3022\ For example, AEP contends that in at least one 
region where AEP operates, such a requirement would deprive 
transmission owners of their exclusive right to file tariffs governing 
the rates and terms of their transmission service under section 205 of 
the FPA. AEP states that in Atlantic City Electric Company v. FERC, the 
D.C. Circuit, held that ``[w]hen FERC attempts to deprive the utilities 
of their rights to initiate rate design changes with respect to 
services provided by their own assets, FERC has exceeded its 
jurisdiction.'' \3023\
---------------------------------------------------------------------------

    \3022\ AEP Initial Comments at 6, 36 (citing Atl. City Elec. Co. 
v. FERC, 295 F.3d at 9-11 (``[T]his Court, among others, has 
stressed that the power to initiate rate changes rests with the 
utility and cannot be appropriated by FERC in the absence of a 
finding that the existing rate was unlawful.''); Atl. City Elec. Co. 
v. FERC, 329 F.3d 856, 858-59 (D.C. Cir. 2003) (per curiam)); MISO 
Initial Comments at 63-64 (citing Atl. City Elec. Co. v. FERC, 295 
F.3d at 9-11); MISO TOs Initial Comments at 37, 39-40 (citing 16 
U.S.C. 824d; Atl. City Elec. Co. v. FERC, 295 F.3d at 9-11; Sw. 
Power Pool, Inc., 132 FERC ] 61,042, at P 107 (2010); Mass. Dep't of 
Pub. Utils. v. FERC, 729 F.2d 886, 887-88 (1st Cir. 1984)); PPL 
Initial Comments at 25 & n.66 (``[T]he Atlantic City case makes 
clear that the transmission owners are able to make Section 205 
filings regarding cost allocation without additional conditions and 
the Commission cannot compel the transmission owners to cede these 
rights.'').
    \3023\ AEP Initial Comments at 36 (quoting Atl. City Elec. Co. 
v. FERC, 329 F.3d at 859); accord MISO Initial Comments at 63; MISO 
TOs Initial Comments at 40; PPL Initial Comments at 25 n.66.
---------------------------------------------------------------------------

    1423. Similarly, Dominion reminds the Commission that the 
transmission provider has FPA section 205 rights, and that those rights 
cannot be ceded to the state through this proceeding.\3024\ National 
Grid asserts that the FPA gives transmission providers the ability to 
make section 205 filings on cost allocation, and that the State 
Agreement Process should be based on transmission providers voluntarily 
affording a role for states.\3025\
---------------------------------------------------------------------------

    \3024\ Dominion Initial Comments at 48-49 (citing Atl. City 
Elec. Co. v. FERC, 295 F.3d 1; Atl. City Elec. Co. v. FERC, 329 F.3d 
856).
    \3025\ National Grid Initial Comments at 25.
---------------------------------------------------------------------------

    1424. APPA contends that requiring public utilities to file rate 
terms dictated by non-public utility entities raises jurisdictional 
issues under the FPA. APPA does not believe it is reasonable to provide 
to state regulators exclusive authority over the proposed cost 
allocation method in the absence of agreement by relevant stakeholders, 
and argues that if the Commission requires public utilities to file 
cost allocation methods agreed to by Relevant State Entities, public 
power utilities should be considered Relevant State Entities have a 
formal voting role in agreeing on

[[Page 49499]]

the cost allocation method(s) for Long-Term Regional Transmission 
Facilities.\3026\ Six Cities and Large Public Power argue that the 
Commission's proposal is an unlawful delegation of the Commission's 
exclusive statutory authority over rates under the FPA.\3027\
---------------------------------------------------------------------------

    \3026\ APPA Initial Comments at 42-45.
    \3027\ Large Public Power Initial Comments at 37-38 (citing City 
of Tacoma v. FERC, 331 F.3d 106, 115 (D.C. Cir. 2002) (finding that 
the Commission unlawfully delegated its responsibility to assess 
annual charges imposed under the FPA against hydroelectric utilities 
licenses to other Federal agencies) (additional citations omitted)); 
Six Cities Initial Comments at 8-9 (citing 16 U.S.C. 824d(a), 824e; 
Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 965-66 
(1986); EPSA, 577 U.S. at 277).
---------------------------------------------------------------------------

    1425. Some commenters seek clarification on the Commission's 
proposal. MISO and Vistra request that the Commission clarify that 
nothing in the final order should be read to override or diminish the 
filing rights held, jointly and/or individually, by the RTOs/ISOs and 
their transmission owning members.\3028\ Indicated PJM TOs argue that, 
while seeking the agreement of Relevant State Entities is appropriate, 
the Commission does not have the authority to require that transmission 
providers obtain their agreement.\3029\ Similarly, WIRES states that 
the Commission should clarify that transmission providers are only 
required to seek agreement of Relevant State Entities and that they are 
not required to achieve such agreement.\3030\ Duke asserts that the 
Commission should clarify and revise the proposed State Agreement 
Process to ensure that it does not conflict with transmission 
providers' FPA section 205 rights to initiate rate changes.\3031\
---------------------------------------------------------------------------

    \3028\ MISO Initial Comments at 64; Vistra Initial Comments at 
29-30.
    \3029\ Indicated PJM TOs Initial Comments at 20 (citing Atl. 
City Elec. Co. v. FERC, 295 F.3d at 10-11).
    \3030\ WIRES Initial Comments at 12 (citing 16 U.S.C. 824d; Atl. 
City Elec. Co. v. FERC, 295 F.3d at 9-11; Atl. City Elec. Co. v. 
FERC, 329 F.3d at 858-59).
    \3031\ Duke Initial Comments at 39 (citing Atl. City Elec. Co. 
v. FERC, 329 F.3d at 858-59).
---------------------------------------------------------------------------

    1426. PJM States propose that if retail regulators reach an 
agreement on cost allocation, transmission providers should be required 
to file it for consideration under section 205 of the FPA.\3032\ PJM 
States recommend that if the transmission providers in a transmission 
planning region prefer a different cost allocation method, they can 
file their preferred alternative while also presenting the method 
agreed on by the Relevant State Entities.\3033\ PJM States add that 
these proposals should be ``balanced'' and explain how the retail 
regulators' preferences were considered.\3034\ Similarly, NESCOE states 
that in cases of disagreement between state entities and transmission 
providers, they would prefer that the transmission providers file a 
state-preferred cost allocation method alongside their own preferred 
method, arguing that such an approach would respect the FPA section 205 
rights that public utilities hold.\3035\ Similarly, New Jersey 
Commission recommends that in the event that the transmission provider 
disagrees with the approach desired by states, the Commission should 
require them to submit the states' approach as well as their own in 
their section 205 filing. New Jersey Commission proposes that the 
Commission would then decide which OATT filing to accept.\3036\
---------------------------------------------------------------------------

    \3032\ PJM States Initial Comments at 10 (citing NOPR, 179 FERC 
] 61,028 at P 303).
    \3033\ Id. at 10.
    \3034\ Id. at 10.
    \3035\ NESCOE Reply Comments at 4.
    \3036\ New Jersey Commission Initial Comments at 17-18.
---------------------------------------------------------------------------

    1427. Entergy contends that the proposal is within the Commission's 
authority because the Commission's proposal allows transmission 
providers to retain their filing rights consistent with Atlantic City. 
Entergy argues that the NOPR proposal does not conflict with Atlantic 
City because it would only establish a process where states are 
consulted on designing a cost allocation method, and that transmission 
providers still must make a cost allocation filing, even if there is no 
agreement.\3037\
---------------------------------------------------------------------------

    \3037\ Entergy Initial Comments at 31-33 (citing Atl. City Elec. 
Co. v. FERC, 295 F.3d at 11).
---------------------------------------------------------------------------

b. Commission Determination
    1428. As a threshold matter, we note that the Commission is acting 
pursuant to FPA section 206 in this final order. Under FPA section 206, 
the Commission has determined that existing regional transmission 
planning and cost allocation requirements are unjust, unreasonable, 
unduly discriminatory or preferential, and thus has both the authority 
and responsibility to establish a just and reasonable replacement rate 
consistent with the final order's requirements.\3038\
---------------------------------------------------------------------------

    \3038\ 16 U.S.C. 824e(a) (``[T]he Commission shall determine the 
just and reasonable . . . practice . . . to be thereafter observed 
and in force, and shall fix the same by order.'' (emphasis added)).
---------------------------------------------------------------------------

    1429. As to commenters' FPA section 205 arguments, we find that our 
directives in this final order regarding the development of a State 
Agreement Process and any cost allocation methods to which the Relevant 
State Entities agree pursuant to that process do not alter existing FPA 
section 205 filing rights.\3039\ Specifically, we clarify that, after 
the required Engagement Period, transmission providers in each 
transmission planning region will decide what Long-Term Regional 
Transmission Cost Allocation Method(s) and any State Agreement Process 
to file as part of their compliance filings.\3040\ Therefore, 
transmission providers in a transmission planning region could elect to 
propose on compliance a Long-Term Regional Transmission Cost Allocation 
Method and not file a State Agreement Process or other ex ante cost 
allocation method to which Relevant State Entities agreed. In addition, 
we do not impose any obligation on transmission providers to file a 
cost allocation method for Long-Term Regional Transmission Facilities 
with which they disagree, even if such a method were proposed to the 
transmission providers pursuant to a Commission-approved State 
Agreement Process, unless the transmission providers have clearly 
indicated their assent to do so as part of a Commission-approved State 
Agreement Process in their OATTs. In the same vein, we decline to 
require, as PJM States, NESCOE, and New Jersey Commission suggest, that 
transmission providers file two cost allocation methods--the 
transmission providers' preferred cost allocation method and the cost 
allocation method agreed to by the Relevant State Entities--if the 
transmission providers disagree with a proposed cost allocation method 
to which the Relevant State Entities agree.\3041\ Entities that oppose 
or prefer a different cost allocation method than the transmission 
providers' preferred cost allocation method can provide their comments 
if and when such cost allocation method is filed with the Commission.
---------------------------------------------------------------------------

    \3039\ See Dominion Initial Comments at 48-49 (citing Atl. City 
Elec. Co. v. FERC, 295 F.3d 1; Atl. City Elec. Co. v. FERC, 329 F.3d 
856).
    \3040\ We note that the filing must include a Long-Term Regional 
Transmission Cost Allocation Method (i.e., an ex ante cost 
allocation method).
    \3041\ PJM States Initial Comments at 10; NESCOE Reply Comments 
at 4; New Jersey Commission Initial Comments at 17-18.
---------------------------------------------------------------------------

    1430. We further clarify that unless voluntarily waived, a 
transmission provider retains its FPA section 205 filing rights to 
submit an ex ante cost allocation method for Long-Term Regional 
Transmission Facilities at any time,\3042\ consistent with any 
limitations a transmission provider may have agreed to, for example, as 
part of its membership in an RTO/ISO. In response

[[Page 49500]]

to MISO and Vistra,\3043\ we also clarify that nothing in this final 
order should be read to override or diminish the filing rights held, 
jointly or individually, by RTOs/ISOs and their transmission owning 
members.
---------------------------------------------------------------------------

    \3042\ See Atl. City Elec. Co. v. FERC, 295 F.3d at 9-11; Atl. 
City Elec. Co. v. FERC, 329 F.3d at 858-859.
    \3043\ MISO Initial Comments at 64; Vistra Initial Comments at 
29-30.
---------------------------------------------------------------------------

    1431. In response to commenters arguing that the NOPR proposal to 
require transmission providers to seek agreement of Relevant State 
Entities regarding the Long-Term Regional Transmission Cost Allocation 
Method, State Agreement Process, or combination thereof would interfere 
with transmission providers' filing rights under FPA section 205,\3044\ 
those concerns are moot, as we decline to adopt this NOPR proposal, as 
discussed above. We reiterate that transmission providers retain their 
right to decide what Long-Term Regional Transmission Cost Allocation 
Method(s) and any State Agreement Process to file in compliance with 
this final order after the Engagement Period.
---------------------------------------------------------------------------

    \3044\ AEP Initial Comments at 36; APPA Initial Comments at 42; 
Dominion Initial Comments at 48-49; MISO Initial Comments at 63-64; 
MISO TOs Initial Comments at 37, 39-40; MISO TOs Reply Comments at 
5-7; PPL Initial Comments at 25 & n.66.
---------------------------------------------------------------------------

5. Time Period and Related Issues in the Long-Term Regional 
Transmission Planning Cost Allocation Processes for State-Negotiated 
Alternate Cost Allocation Method
a. NOPR Proposal
    1432. In the NOPR, the Commission proposed to require transmission 
providers to detail in their OATTs a process to provide a state or 
states (in multi-state transmission planning regions) with a time 
period to negotiate a cost allocation method for a transmission 
facility (or portfolio of facilities) selected through Long-Term 
Regional Transmission Planning that is different than any ex ante 
regional cost allocation method (i.e., Long-Term Regional Transmission 
Cost Allocation Method) that would otherwise apply. During this time 
period, if a state or all states within the transmission planning 
region in which the selected regional transmission facility will be 
located unanimously agree on an alternate cost allocation method, the 
transmission provider may elect to file that method with the Commission 
for consideration under FPA section 205. The Commission explained that 
the transmission provider may elect to file an alternate cost 
allocation method because doing so increases the likelihood that 
relevant stakeholders perceive the cost allocation as fair and that the 
needed regional transmission facilities will actually be 
constructed.\3045\
---------------------------------------------------------------------------

    \3045\ NOPR, 179 FERC ] 61,028 at P 319.
---------------------------------------------------------------------------

    1433. If the relevant state or states cannot agree on an alternate 
cost allocation method memorialized in writing within the specified 
timeframe after a transmission developer's transmission facility is 
selected through Long-Term Regional Transmission Planning (e.g., 90 
days), the Commission proposed that then the transmission developer 
would be entitled to use any ex ante Long-Term Regional Transmission 
Cost Allocation Method that would otherwise apply for that Long-Term 
Regional Transmission Facility.\3046\
---------------------------------------------------------------------------

    \3046\ Id. P 320.
---------------------------------------------------------------------------

    1434. In particular, the Commission proposed to require that the 
OATT provisions that describe the state-negotiated alternate cost 
allocation method include when this time period will occur, what its 
duration will be, and an affirmation that any alternate cost allocation 
method must be submitted to the Commission for review and approval 
under FPA section 205 prior to taking effect. Under this proposal, when 
filed, the Commission would evaluate the alternate cost allocation 
method to ensure that it is just and reasonable and allocates costs in 
a manner that is at least roughly commensurate with estimated benefits. 
If the Commission rejects a state-negotiated alternate cost allocation 
method, the transmission developer of the Long-Term Regional 
Transmission Facility would be entitled to use the applicable ex ante 
regional cost allocation method that would have applied to it in the 
absence of the proposed alternative cost allocation method.\3047\ The 
Commission proposed to prescribe a 90-day time period for a state-
negotiated cost allocation method to be memorialized in writing.\3048\
---------------------------------------------------------------------------

    \3047\ Id. P 322.
    \3048\ Id. P 323.
---------------------------------------------------------------------------

    1435. Finally, the Commission sought comment on whether to 
establish a requirement for a time period for state involvement in 
regional cost allocation for transmission facilities selected in 
existing near-term reliability and economic regional transmission 
planning processes.\3049\
---------------------------------------------------------------------------

    \3049\ Id. P 324.
---------------------------------------------------------------------------

b. Comments
    1436. Several commenters support the Commission's proposal to 
require transmission providers to detail in their OATTs a process to 
provide a state or states with a time period to negotiate a cost 
allocation method for a transmission facility (or portfolio of 
facilities) selected through Long-Term Regional Transmission Planning 
that is different than any ex ante regional cost allocation method 
(i.e., Long-Term Regional Transmission Cost Allocation Method).\3050\ 
NESCOE, Pennsylvania Commission, and PJM States support a requirement 
for transmission providers to detail in their OATT provisions that 
describe the state-negotiated cost allocation method.\3051\ Clean 
Energy Buyers, Dominion, and PIOs agree that any alternate cost 
allocation method must be submitted to the Commission for review and 
approval under FPA section 205 prior to taking effect.\3052\
---------------------------------------------------------------------------

    \3050\ Entergy Initial Comments at 29-30; Nebraska Commission 
Initial Comments at 9; New England for Offshore Wind Initial 
Comments at 5; Northwest and Intermountain Initial Comments at 18-
19; NRG Initial Comments at 21; Pacific Northwest State Agencies 
Initial Comments at 27-28; PIOs Initial Comments at 69; SEIA Initial 
Comments at 24.
    \3051\ NESCOE Initial Comments at 71; Pennsylvania Commission 
Initial Comments at 16; PJM States Initial Comments at 12-13.
    \3052\ Clean Energy Buyers Initial Comments at 29-30; Dominion 
Initial Comments at 52; PIOs Initial Comments at 71.
---------------------------------------------------------------------------

    1437. PJM and Nebraska Commission support the proposal to require a 
time period for state-negotiated alternate cost allocation with 
suggested modifications. Nebraska Commission states that a process that 
builds consensus is important for contentious issues such as cost 
allocation and suggests adoption of a model similar to SPP's Regional 
State Committee, which it contends has a proven track record for 
achieving consensus among stakeholders.\3053\ PJM recommends that the 
Commission provide clear direction as to the circumstances under which 
a process for states to negotiate an alternate cost allocation method 
would be appropriate. PJM also proposes that states seeking a state-
negotiated alternate cost allocation method should be required to 
explain why the ex ante cost allocation method is not appropriate for 
the identified transmission facility or facilities.\3054\
---------------------------------------------------------------------------

    \3053\ Nebraska Commission Initial Comments at 9.
    \3054\ PJM Initial Comments at 117.
---------------------------------------------------------------------------

    1438. PJM States disagree, arguing that there is no proposed 
requirement that retail regulators show why an ex ante approach is 
inappropriate before agreeing to and advocating for an alternate. PJM 
States further assert that allowing states to agree on an alternate 
cost allocation approach after seeing what transmission projects are 
selected may be beneficial since states will have more information on 
specific projects.\3055\
---------------------------------------------------------------------------

    \3055\ PJM States Reply Comments at 6.

---------------------------------------------------------------------------

[[Page 49501]]

    1439. Some commenters seek clarification on the NOPR proposal. 
Pennsylvania Commission explains that because this negotiation would 
occur after transmission facility selection, it is an ex post ``State 
Agreement Process.'' As such, Pennsylvania Commission contends, it 
could create confusion if the Commission does not clarify that 
different rules apply to the 90-day ``renegotiation'' process.\3056\ 
Similarly, MISO states that it is not clear whether the proposed 
requirements are intended as an alternative to the State Agreement 
Process or to define how the State Agreement Process would be 
implemented.\3057\
---------------------------------------------------------------------------

    \3056\ Pennsylvania Commission Initial Comments at 15.
    \3057\ MISO Initial Comments at 71.
---------------------------------------------------------------------------

    1440. Some commenters oppose a requirement to provide a time period 
for a state or states to negotiate a cost allocation method for a 
transmission facility (or portfolio of facilities) selected in the 
regional transmission plan that is different than any ex ante regional 
cost allocation method (i.e., Long-Term Regional Transmission Cost 
Allocation Method) that would otherwise apply.\3058\ Dominion and Idaho 
Power argue that the Commission should permit regional flexibility as 
to whether to adopt such a time period.\3059\ Idaho Power further 
contends that the Commission's transmission planning processes are not 
the primary barriers to transmission development; instead, Federal 
permitting and siting processes and coordination with stakeholders are 
greater barriers.\3060\
---------------------------------------------------------------------------

    \3058\ Dominion Initial Comments at 51; Idaho Power Initial 
Comments at 10-11; PPL Initial Comments at 27.
    \3059\ Dominion Initial Comments at 51; Idaho Power Initial 
Comments at 10-11.
    \3060\ Idaho Power Initial Comments at 11 (noting National 
Environmental Policy Act review and siting decisions with the Bureau 
of Land Management as examples of Federal permitting and siting 
processes).
---------------------------------------------------------------------------

    1441. MISO recommends that rather than requiring the specific 
process and ex post opportunities for states to negotiate an alternate 
cost allocation method, the Commission should identify the opportunity 
for state involvement in the development of cost allocation and leave 
the details for that involvement to each transmission planning 
region.\3061\ Pennsylvania Commission states that it does not view the 
time period for state-negotiated alternate cost allocation as a 
principal negotiation method for cost allocation and asserts that more 
appropriate processes are the proposed State Agreement Process or PJM's 
existing State Agreement Approach.\3062\
---------------------------------------------------------------------------

    \3061\ MISO Initial Comments at 71.
    \3062\ Pennsylvania Commission Initial Comments at 16.
---------------------------------------------------------------------------

    1442. Dominion supports allowing but not requiring that ex ante 
processes be coupled with an option for states to propose an alternate 
method, stating that the process for establishing an alternative cost 
allocation method could become cumbersome as the NOPR proposes to 
require it to comply with the six Order No. 1000 regional cost 
allocation principles.\3063\ Exelon recommends allowing states the 
opportunity to propose an alternative cost allocation method to the ex 
ante method after transmission project selection, but states that FPA 
section 205 rights holders should be able to accept, modify, or reject 
the proposed alternative cost allocation method. Exelon claims that 
this approach would respect the legal rights of transmission owners, 
pointing to PJM's State Agreement Approach as an example.\3064\ NESCOE 
urges the Commission to reject Exelon's request that transmission 
providers be free to accept or reject cost allocation methods proposed 
by state entities.\3065\
---------------------------------------------------------------------------

    \3063\ Dominion Initial Comments at 51.
    \3064\ Exelon Initial Comments at 26-27.
    \3065\ NESCOE Reply Comments at 3-4.
---------------------------------------------------------------------------

i. Permissive Right of Transmission Provider To File Alternate Cost 
Allocation Method With the Commission Upon Unanimous State Agreement
    1443. NARUC and NESCOE argue that if states unanimously agree on an 
alternate cost allocation method, then the transmission provider should 
be obligated to file it.\3066\ NARUC states that the transmission 
provider may also file the cost allocation method that would otherwise 
apply if it concludes that the negotiated cost allocation method does 
not comply with the six Order No. 1000 regional cost allocation 
principles or is otherwise deficient. NARUC contends that this approach 
would not violate the transmission providers' FPA section 205 filing 
rights.\3067\ Similarly, NESCOE asserts that the Commission should 
allow the transmission provider to file its preferred approach, but 
also require that the transmission provider file the state-negotiated 
alternate cost allocation method, an approach that could be modeled 
after existing provisions in NYISO and SPP.\3068\
---------------------------------------------------------------------------

    \3066\ NARUC Initial Comments at 53; NESCOE Initial Comments at 
68.
    \3067\ NARUC Initial Comments at 53.
    \3068\ NESCOE Initial Comments at 68-70.
---------------------------------------------------------------------------

    1444. NESCOE also requests that the Commission clarify whether 
unanimity means that each opting-in state has agreed to fund the Long-
Term Regional Transmission Facility or that all the states in the 
transmission planning region have agreed that a subset of states will 
fund the Long-Term Regional Transmission Facility.\3069\ NESCOE further 
requests that the Commission clarify how it intends to reconcile the 
unanimous agreement requirement in this proposal with the other NOPR 
proposal that gives states the ability to choose the definition of 
state agreement for purposes of a cost allocation method and where the 
NOPR expressed a willingness to abide by the bylaws of an individual 
regional state committee, which may not define agreement as full 
unanimity.\3070\
---------------------------------------------------------------------------

    \3069\ Id. at 10, 67-68.
    \3070\ Id. at 68 (citing NOPR, 179 FERC ] 61,028 at P 306 & 
n.512).
---------------------------------------------------------------------------

    1445. Indiana Commission expresses concern that the requirement to 
obtain unanimous state approval regarding an ex post cost allocation 
process might prove unworkable. Indiana Commission argues that it may 
be unrealistic to expect that states can reach unanimity on something 
as contentious as cost allocation. Moreover, Indiana Commission is 
concerned that states may use the requirement for unanimous agreement 
to leverage their vote and to gain ground in other areas of 
contention.\3071\
---------------------------------------------------------------------------

    \3071\ Indiana Commission Initial Comments at 5.
---------------------------------------------------------------------------

    1446. PIOs seek clarification on the intent behind the NOPR 
language that ``the public utility transmission provider may elect to 
file [a state-negotiated alternate cost allocation method] with the 
Commission for consideration under FPA section 205.'' \3072\ Similarly, 
Pennsylvania Commission and PJM States request clarification regarding 
whether transmission providers could choose not to file an alternative 
cost allocation method to which the states in a transmission planning 
region have unanimously agreed.\3073\ Pennsylvania Commission asserts 
that it sees no reason why a transmission provider should be able to 
override the unanimous agreement of affected states.\3074\
---------------------------------------------------------------------------

    \3072\ PIOs Initial Comments at 71 (citing NOPR, 179 FERC ] 
61,028 at P 319).
    \3073\ Pennsylvania Commission Initial Comments at 16-17; PJM 
States Reply Comments at 6.
    \3074\ Pennsylvania Commission Initial Comments at 17.
---------------------------------------------------------------------------

    1447. In addition, PJM States recommend that to address the 
inability for states to voice their cost allocation concerns, the 
Commission should

[[Page 49502]]

consider how it can afford retail regulators greater participation 
status in the FPA section 205 filing process.\3075\ Further, PJM States 
note that other regional states committees have varying processes, 
including the ability to request that a transmission provider file a 
cost allocation method on their behalf.\3076\
---------------------------------------------------------------------------

    \3075\ PJM States Reply Comments at 6-7.
    \3076\ Id. at 7.
---------------------------------------------------------------------------

ii. Duration for the Time Period for State-Negotiated Cost Allocation
    1448. A few commenters agree with the Commission's proposal to 
require a 90-day time period for a state-negotiated cost allocation 
method to be memorialized in writing.\3077\ For example, New England 
for Offshore Wind states that it is essential that deadlines are 
imposed to prevent delays caused by disagreements over cost 
allocation.\3078\ PIOs assert that the 90-day time period should begin 
when the transmission project or portfolio of projects is 
selected.\3079\
---------------------------------------------------------------------------

    \3077\ New England for Offshore Wind Initial Comments at 5; 
Northwest and Intermountain Initial Comments at 18; PIOs Initial 
Comments at 69; SEIA Initial Comments at 24.
    \3078\ New England for Offshore Wind Initial Comments at 5.
    \3079\ PIOs Initial Comments at 70.
---------------------------------------------------------------------------

    1449. Many commenters, however, argue that the 90-day time period 
is too short. For example, NARUC, National Grid, and Southern contend 
that 90 days may be insufficient time for the states in large, multi-
state transmission planning regions to negotiate a cost allocation 
method.\3080\ Similarly, NRG argues that the Commission might consider 
alternative timelines for multi-state collaboration versus where there 
is a single state entity responsible for the cost allocation.\3081\ US 
Chamber of Commerce contends that the 90-day timeline for state-
negotiated cost allocation agreements is unreasonably tight and may 
undermine the potential for agreement.\3082\
---------------------------------------------------------------------------

    \3080\ NARUC Initial Comments at 52-53; National Grid Initial 
Comments at 24-25; Southern Initial Comments at 7-8.
    \3081\ NRG Initial Comments at 21.
    \3082\ US Chamber of Commerce Initial Comments at 10.
---------------------------------------------------------------------------

    1450. Several commenters, including state commissions, propose 
longer time periods. For example, California Commission, Kentucky 
Commission Chair Chandler, Louisiana Commission, NARUC, NRG, and 
Pacific Northwest State Agencies propose at least six months (180 days) 
as a more appropriate time period for state negotiation.\3083\ 
California Commission and Louisiana Commission request that states 
should be provided with the opportunity to request extensions if they 
fail to agree on a cost allocation method after six months (180 
days).\3084\ OMS recommends that the Commission establish periodic 
reporting requirements for transmission providers during the 90-day 
period with an option to extend the deliberations for good cause.\3085\
---------------------------------------------------------------------------

    \3083\ California Commission Initial Comments at 56; Kentucky 
Commission Chair Chandler Initial Comments at 4; Louisiana 
Commission Initial Comments at 34-35; NARUC Initial Comments at 52-
53; NRG Initial Comments at 21; Pacific Northwest State Agencies 
Initial Comments at 27-28.
    \3084\ California Commission Initial Comments at 56; Louisiana 
Commission Initial Comments at 35.
    \3085\ OMS Initial Comments at 13.
---------------------------------------------------------------------------

    1451. Several other commenters contend that it should be left to 
the transmission planning regions, with input from states, to determine 
the appropriate time period.\3086\ For example, Dominion states that 
the Commission should not dictate any particular timetable and should 
instead evaluate proposals on a case-by-case basis.\3087\ Similarly, 
Nevada Commission proposes that the Commission require relevant state 
agencies to be involved in the process as early as possible, but to 
provide no less than 120 days to allow for appropriate notice and 
review of any state-negotiated agreement.\3088\ Exelon, Indiana 
Commission, and SERTP Sponsors recommend allowing flexibility in 
determining the appropriate time period to reflect regional 
differences.\3089\ Idaho Power agrees but cautions that any process 
should not extend the length of transmission planning processes or 
development.\3090\ Pennsylvania Commission also supports flexibility in 
determining the appropriate time period given that this process is new 
and there is little knowledge and experience with respect to how it 
will function in practice.\3091\
---------------------------------------------------------------------------

    \3086\ Dominion Initial Comments at 51-52; Exelon Initial 
Comments at 28-29; Indiana Commission Initial Comments at 5-6; 
National Grid Initial Comments at 24-25; NESCOE Initial Comments at 
71; Pennsylvania Commission Initial Comments at 16; PJM States 
Initial Comments at 12-13; SERTP Sponsors Initial Comments at 15.
    \3087\ Dominion Initial Comments at 51-52.
    \3088\ Nevada Commission Initial Comments at 13-14.
    \3089\ Exelon Initial Comments at 28-29; Indiana Commission 
Initial Comments at 5-6; SERTP Sponsors Initial Comments at 15.
    \3090\ Idaho Power Initial Comments at 10-11.
    \3091\ Pennsylvania Commission Initial Comments at 16.
---------------------------------------------------------------------------

    1452. NESCOE and PJM States assert that NYISO's process referenced 
by the Commission can last longer than the 90-day time period for 
state-negotiated cost allocation proposed in the NOPR.\3092\ Further, 
NESCOE emphasizes that the NYISO process involves only one state 
entity, whereas other transmission planning regions have multiple 
states. Thus, NESCOE and PJM States argue, the Commission should allow 
transmission planning regions to determine what time period is 
appropriate.\3093\
---------------------------------------------------------------------------

    \3092\ NESCOE Initial Comments at 70-71 (citing NOPR, 179 FERC ] 
61,028 at P 323); PJM States Initial Comments at 12-13 (citing N.Y. 
Indep. Sys. Operator, Inc., 151 FERC ] 61,040, at PP 119-121 
(2015)).
    \3093\ NESCOE Initial Comments at 71; PJM States Initial 
Comments at 12-13.
---------------------------------------------------------------------------

    1453. A few other commenters contend that state negotiation on an 
alternate cost allocation method should not be limited by any time 
period. For example, PPL asserts that limiting the timeframe merely 
lowers the chance of state agreement, and thus the prospects for the 
underlying transmission project to be constructed.\3094\ Southern 
states that the Commission should allow transmission planning regions 
to develop a process that has state support.\3095\ Similarly, Xcel 
contends that transmission planning regions should have as much time as 
needed to negotiate and identify cost allocation methods.\3096\
---------------------------------------------------------------------------

    \3094\ PPL Initial Comments at 27.
    \3095\ Southern Initial Comments at 7-8.
    \3096\ Xcel Initial Comments at 11-12.
---------------------------------------------------------------------------

iii. Other Issues
    1454. NESCOE, Northwest and Intermountain, PJM, and SEIA agree with 
the proposal that if states cannot unanimously agree on an alternate 
cost allocation method within the specified timeframe, then the 
transmission developer would be entitled to use the cost allocation 
method that would otherwise apply for that Long-Term Regional 
Transmission Facility.\3097\ In contrast, NRG recommends that in the 
case where states do not agree, the Commission could either require the 
transmission provider to make a filing or subject rival state filings 
to ``jump ball'' treatment. NRG contends that either of these 
approaches would encourage comity and resolution of states' 
differences.\3098\
---------------------------------------------------------------------------

    \3097\ NESCOE Initial Comments at 70; Northwest and 
Intermountain Initial Comments at 19; PJM Initial Comments at 117-
118; SEIA Initial Comments at 24.
    \3098\ NRG Initial Comments at 21.
---------------------------------------------------------------------------

    1455. MISO and PPL oppose establishing a requirement for a time 
period for state involvement in regional cost allocation for 
transmission facilities selected in existing near-term reliability and 
economic regional transmission planning processes. MISO states that

[[Page 49503]]

there is no evidence in the record of this proceeding to support 
extending the state involvement proposed in the NOPR to existing near-
term transmission planning processes.\3099\ PPL argues that departures 
from an ex ante cost allocation method would lead to uncertainty, 
delay, and costly litigation.\3100\
---------------------------------------------------------------------------

    \3099\ MISO Initial Comments at 71.
    \3100\ PPL Initial Comments at 27-28.
---------------------------------------------------------------------------

c. Commission Determination
    1456. We decline to adopt the NOPR proposal to require transmission 
providers to provide a time period after selection of Long-Term 
Regional Transmission Facilities for states to negotiate an alternate 
cost allocation that is different than any ex ante regional cost 
allocation method that would otherwise apply. We find that requiring a 
time period after selection for states to negotiate an alternate ex 
post cost allocation method is largely duplicative given our decision 
above to allow the use of a State Agreement Process before or after the 
selection of a Long-Term Regional Transmission Facility (or a portfolio 
of such Facilities). Furthermore, having two separate processes that 
serve similar functions could add unnecessary complexity and create 
confusion in the cost allocation process.\3101\ Relevant State Entities 
will have an opportunity to provide input on and to potentially agree 
to a Long-Term Regional Transmission Cost Allocation Method(s) and/or a 
State Agreement Process as part of the Engagement Period that we 
require transmission providers to establish. We are also concerned that 
the burden associated with the NOPR proposal would have been 
significant, as it would have created a requirement to allow for such 
negotiations for all Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------

    \3101\ See, e.g., MISO Initial Comments at 71 (seeking 
clarification as to whether the proposed time period for states to 
negotiate cost allocation is an alternative to the State Agreement 
Process); Pennsylvania Commission Initial Comments at 16 (stating 
that it does not view the proposed time period as the principal 
method for negotiating cost allocation and that the more appropriate 
process is the proposed State Agreement Process).
---------------------------------------------------------------------------

    1457. Because we are declining to require that transmission 
providers establish a time period after selection of Long-Term Regional 
Transmission Facilities to allow states to negotiate an alternate ex 
post cost allocation method, we need not address the comments on the 
duration of such a time period and the requests for clarification by 
MISO, Pennsylvania Commission, PIOs, and PJM States.\3102\
---------------------------------------------------------------------------

    \3102\ MISO Initial Comments at 71; Pennsylvania Commission 
Initial Comments at 15; PIOs Initial Comments at 71 (citing NOPR, 
179 FERC ] 61,028 at P 319); PJM States Reply Comments at 6.
---------------------------------------------------------------------------

B. Long-Term Regional Transmission Facility Cost Allocation Compliance 
With the Existing Six Order No. 1000 Regional Cost Allocation 
Principles

1. NOPR Proposal
    1458. The Commission proposed to require that the Long-Term 
Regional Transmission Cost Allocation Method and any cost allocation 
method resulting from the State Agreement Process for Long-Term 
Regional Transmission Facilities comply with the existing six Order No. 
1000 regional cost allocation principles.\3103\ The six regional 
transmission cost allocation principles adopted in Order No. 1000 are: 
(1) the costs of selected transmission facilities must be allocated to 
those within the transmission planning region that benefit from those 
facilities in a manner that is at least roughly commensurate with 
estimated benefits; (2) those that receive no benefit from transmission 
facilities, either at present or in a likely future scenario, must not 
be involuntarily allocated any of the costs of those transmission 
facilities; (3) a benefit to cost threshold ratio, if adopted, cannot 
exceed 1.25 to 1; (4) costs must be allocated solely within the 
transmission planning region unless another entity outside the region 
voluntarily assumes a portion of those costs; (5) the method for 
determining benefits and identifying beneficiaries must be transparent; 
and (6) there may be different regional cost allocation methods for 
different types of transmission facilities, such as those needed for 
reliability, congestion relief, or to achieve Public Policy 
Requirements.\3104\
---------------------------------------------------------------------------

    \3103\ NOPR, 179 FERC ] 61,028 at P 302.
    \3104\ Order No. 1000, 136 FERC ] 61,051 at PP 622, 637, 646, 
657, 668, 685.
---------------------------------------------------------------------------

2. Comments
a. General Proposal
    1459. Some commenters agree with the Commission's proposal that any 
Long-Term Regional Transmission Cost Allocation Method and any cost 
allocation method resulting from the State Agreement Process for Long-
Term Regional Transmission Facilities must comply with the existing six 
Order No. 1000 regional cost allocation principles.\3105\ APPA requests 
that the Commission clarify that it is not requiring changes to 
existing Commission-approved Order No. 1000 regional cost allocation 
principles.\3106\
---------------------------------------------------------------------------

    \3105\ APPA Initial Comments at 40; Dominion Initial Comments at 
45; Kentucky Commission Chair Chandler Initial Comments at 3; NESCOE 
Initial Comments at 56; NRECA Initial Comments at 56; Ohio Consumers 
Initial Comments at 12-13.
    \3106\ APPA Initial Comments at 5.
---------------------------------------------------------------------------

    1460. New Jersey Commission supports requiring that any negotiated 
cost allocation method, whether ex ante or ex post, comply with the 
Order No. 1000 regional cost allocation principles, except for 
Principle 4.\3107\ New Jersey Commission opines that requiring that 
cost allocation methods be consistent with the beneficiary-pays 
principle is particularly necessary in a State Agreement Process to 
avoid potential free ridership.\3108\
---------------------------------------------------------------------------

    \3107\ New Jersey Commission Initial Comments at 18 (citing New 
Jersey Commission ANOPR Comments at 7-8 (explaining why it opposes 
Principle 4's policy of allowing beneficiaries in other transmission 
planning regions to evade all cost allocation for transmission 
projects that provide them with substantial benefits)).
    \3108\ Id.
---------------------------------------------------------------------------

    1461. Industrial Customers argue that, regardless of the cost 
allocation method that is chosen, the Commission should explicitly 
state that the cost causation principle must apply, as compliance with 
Order No. 1000 may not ensure compliance with cost causation principles 
on its own.\3109\ Large Public Power argues that the Commission must 
hew closely to the first two principles governing cost allocation 
articulated in Order No. 1000: (1) that costs must be allocated in a 
way that is roughly commensurate with benefits; and (2) that there will 
be no involuntary allocation of costs to non-beneficiaries.\3110\ Pine 
Gate asserts that transmission providers must be required to propose 
cost allocation methods that comport with the well-established 
``roughly commensurate'' principle.\3111\ City of New Orleans Council 
and Ohio Commission Federal Advocate state that cost allocation must 
adhere to cost causation and beneficiary-pays principles.\3112\
---------------------------------------------------------------------------

    \3109\ Industrial Customers Initial Comments at 23-24.
    \3110\ Large Public Power Initial Comments at 29.
    \3111\ Pine Gate Initial Comments at 42-44.
    \3112\ City of New Orleans Council Initial Comments at 10; Ohio 
Commission Federal Advocate Initial Comments at 14.
---------------------------------------------------------------------------

    1462. OMS states that it developed its own principles through a 
committee of regulators focused on cost allocation for long-range 
transmission projects in response to the NOPR, which include: (1) costs 
of new transmission projects should be allocated to cost causers and 
beneficiaries in a manner roughly commensurate with the costs caused 
and benefits of those projects; (2) cost

[[Page 49504]]

allocation should be as granular and accurate as possible such that 
benefit-cost analysis uses metrics that are quantifiable, capable of 
replication, non-duplicative, and forward-looking; (3) costs should not 
be allocated to parties that receive negligible or negative benefits; 
and (4) generators and load each can be considered cost causers, 
beneficiaries, or both and should be allocated costs accordingly.\3113\ 
Louisiana Commission supports OMS' position on benefit metrics as 
articulated in OMS' second principle.\3114\ OMS highlights that 
regional flexibility must be preserved, pointing to MISO's Targeted 
Market Efficiency Projects process as an example of a process that did 
not strictly comply with Order No. 1000 but was effective and widely 
supported.\3115\
---------------------------------------------------------------------------

    \3113\ OMS Initial Comments at 12.
    \3114\ Louisiana Commission Reply Comments at 10.
    \3115\ OMS Initial Comments at 13.
---------------------------------------------------------------------------

    1463. Ohio Consumers argue that the Commission should espouse three 
fundamental principles when considering the benefits and cost 
allocations associated with any Long-Term Regional Transmission 
Facilities: (1) costs should be allocated to those who caused the costs 
to be incurred; (2) subsidies are bad for competitive markets, because 
they result in noncompetitive outcomes and inaccurate price signals; 
and (3) consumers should not be charged until transmission projects are 
found to be used and useful.\3116\ Also, Ohio Consumers assert, cost 
allocations to consumers should adhere to the Commission's current 
ratemaking standards in PJM.\3117\
---------------------------------------------------------------------------

    \3116\ Ohio Consumers Initial Comments at 6-7, 12-14.
    \3117\ Id. at 1.
---------------------------------------------------------------------------

    1464. PIOs assert that the Commission should require that 
transmission providers demonstrate on compliance that the cost 
allocation method complies with the beneficiary-pays principle by 
considering all quantifiable benefits.\3118\ ELCON states that cost 
allocation proposals must comply with the cost causation principle ``by 
comparing the costs assessed against a party to the burdens imposed or 
benefits drawn by that party.'' ELCON remains concerned that, in an 
effort to reach public policy goals, costs will be socialized among all 
consumers without consideration of the cost causers, and states that 
cost allocation must evaluate the drivers of the specific transmission 
need and the party that caused the need for the additional 
transmission.\3119\ Utah Division of Public Utilities asks that when 
states or other stakeholders disagree on the cost allocation method due 
to differing renewable goals, the Long-Term Regional Transmission Cost 
Allocation Method be required to use cost causation principles to 
determine what portion of the proposed transmission projects are due to 
state policies.\3120\
---------------------------------------------------------------------------

    \3118\ PIOs Initial Comments at 68.
    \3119\ ELCON Initial Comments at 15.
    \3120\ Utah Division of Public Utilities Initial Comments at 9-
10.
---------------------------------------------------------------------------

    1465. West Virginia Commission states that it supports retention of 
the cost-causation principles in Order No. 1000, noting that the Order 
No. 1000 cost allocation principles are grounded in the beneficiary-
pays principle that the costs of transmission facilities should be 
allocated commensurate with the benefits of those facilities. However, 
West Virginia Commission contends that the beneficiary-pays principle 
cannot and should not be applied on a presumptive regional basis when 
new transmission is identified as needed to accommodate one or more 
states' public policy decisions.\3121\ West Virginia Commission states 
that longstanding legal precedent on cost causation and ratemaking 
principles require that rates remain just and reasonable, that 
customers pay for transmission upgrades based upon their roughly 
commensurate benefits, and that new generators, or the willing and 
voluntary benefactors of new generators, pay the costs for the 
interconnection-related network upgrades if such upgrades would not be 
needed but for the new generators.\3122\ West Virginia Commission 
contends that to adopt a cost allocation that requires any non-
volunteering state to pay costs caused by another state's public 
policies would depart from years of Commission precedent and would be 
unjust and unreasonable.\3123\
---------------------------------------------------------------------------

    \3121\ West Virginia Commission Reply Comments at 3; West 
Virginia Commission Supplemental Comments at 3-4.
    \3122\ West Virginia Commission Reply Comments at 6 (citing K N 
Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992); ICC v. 
FERC I, 576 F.3d at 477; ISO New England, Inc., 115 FERC ] 61,145, 
at P 13 (2006), aff'd, TransCanada Power Mktg. Ltd. v. FERC, 811 
F.3d 1 (D.C. Cir. 2015); El Paso Elec. Co. v. FERC, 832 F.3d 495, 
499-500 & n.10 (5th Cir. 2016); Midcontinent Indep. Sys. Operator, 
Inc., 159 FERC ] 63,016, at P 138 (2017), aff'd, 164 FERC ] 61,194 
(2018); Order No. 1000, 136 FERC ] 61,051 at P 622); West Virginia 
Commission Supplemental Comments at 5-6.
    \3123\ West Virginia Commission Reply Comments at 6-7.
---------------------------------------------------------------------------

    1466. Vermont Electric and Vermont Transco encourage the Commission 
to ensure that any cost allocation approach ensures that the benefits 
of transmission facilities are roughly commensurate with the costs 
thereof for both small rural states and larger, more populated states. 
Vermont Electric and Vermont Transco argue that the final order should 
reflect equitable principles in accordance with which the significant 
investments made by Vermont prior to the issuance of the final order 
are taken into account in cost allocation processes.\3124\ MISO states 
that the final order should not preclude applying different cost 
allocation methods to transmission projects of the same type, noting 
that Order No. 2000 contemplated ``the potential for different cost 
allocation methodologies'' as RTO/ISO footprints grew.\3125\
---------------------------------------------------------------------------

    \3124\ Vermont Electric and Vermont Transco Initial Comments at 
3-4.
    \3125\ MISO Reply Comments at 17-19.
---------------------------------------------------------------------------

b. Comments Specific to a State Agreement Process
    1467. Certain commenters discuss the interaction between the Order 
No. 1000 regional cost allocation principles and any cost allocation 
methods resulting from the State Agreement Process. Pennsylvania 
Commission supports the proposed requirement while also contending that 
the Commission should defer to unanimous agreement by affected 
states.\3126\ Avangrid argues that the Commission should relax this 
requirement and defer to the balance achieved via state 
agreement.\3127\ Mississippi Commission argues that the proposed 
requirement is unnecessary because the State Agreement Process will 
result in voluntary assumption of costs.\3128\ Likewise, PacifiCorp and 
NV Energy argue that the Order No. 1000 regional cost allocation 
principles should not apply to the State Agreement Process because 
there will be no involuntary cost allocation given that states have 
already agreed. They further contend that beneficiary analyses and 
minimum cost-benefit ratios will foreclose state-favored cost 
allocation solutions.\3129\ PacifiCorp and NV Energy argue that 
agreeing to cost allocation will be a difficult task for states, and 
the Commission should not further dictate the type of agreement.\3130\
---------------------------------------------------------------------------

    \3126\ Pennsylvania Commission Initial Comments at 13.
    \3127\ Avangrid Initial Comments at 30.
    \3128\ Mississippi Commission Initial Comments at 25.
    \3129\ PacifiCorp and NV Energy Initial Comments at 17.
    \3130\ Id.
---------------------------------------------------------------------------

    1468. PJM States ask the Commission not to preclude or limit the 
availability of the PJM State Agreement Approach, which they assert is 
not required to comply with the Order No. 1000

[[Page 49505]]

regional cost allocation principles.\3131\ Similarly, Exelon notes that 
the Commission has indicated that voluntary state cost allocation 
agreements need not comply with Order No. 1000.\3132\ Therefore, Exelon 
asks the Commission to clarify that the proposed State Agreement 
Process is supplementary to any previously accepted provisions for 
state agreement-based cost allocation.\3133\
---------------------------------------------------------------------------

    \3131\ PJM States Initial Comments at 11-12 (citing PJM 
Interconnection, L.L.C., 142 FERC ] 61,214 at P 142).
    \3132\ Exelon Initial Comments at 27-28 (citing State Voluntary 
Agreements to Plan & Pay for Transmission Facilities, 175 FERC ] 
61,225 at P 4).
    \3133\ Exelon Initial Comments at 27-28 (citing PJM 
Interconnection, L.L.C., 142 FERC ] 61,214).
---------------------------------------------------------------------------

3. Commission Determination
    1469. We adopt the NOPR proposal, with modification, to require 
Long-Term Regional Transmission Cost Allocation Methods to comply with 
five of the six existing Order No. 1000 regional cost allocation 
principles. Specifically, we require transmission providers in each 
transmission planning region to demonstrate on compliance with this 
final order that any Long-Term Regional Transmission Cost Allocation 
Methods, that they propose that Relevant State Entities have not 
indicated that they agree to, comply with Order No. 1000 regional cost 
allocation principles (1) through (5). However, we do not require 
transmission providers to demonstrate that any Long-Term Regional 
Transmission Cost Allocation Methods that they propose complies with 
Order No. 1000 regional cost allocation principle (6), and, as a 
result, unlike under Order No. 1000, transmission providers cannot 
adopt different Long-Term Regional Transmission Cost allocation Methods 
for different types of Long-Term Regional Transmission Facilities, such 
as those needed for reliability, congestion relief, or to achieve 
Public Policy Requirements.
    1470. However, as discussed further below, we do not adopt the NOPR 
proposal to require compliance with the Order No. 1000 regional cost 
allocation principles in two situations. First, we do not require a 
Long-Term Regional Transmission Cost Allocation Method to comply with 
any of the Order No. 1000 regional cost allocation principles if 
Relevant State Entities indicate that they agreed to that method as 
part of the Engagement Period. Second, we do not require a cost 
allocation method resulting from a State Agreement Process to comply 
with the Order No. 1000 regional cost allocation principles.
    1471. The first five Order No. 1000 regional transmission cost 
allocation principles are: (1) the costs of selected transmission 
facilities must be allocated to those within the transmission planning 
region that benefit from those facilities in a manner that is at least 
roughly commensurate with estimated benefits; \3134\ (2) those that 
receive no benefit from transmission facilities, either at present or 
in a likely future scenario, must not be involuntarily allocated any of 
the costs of those transmission facilities; \3135\ (3) a benefit to 
cost threshold ratio, if adopted, cannot exceed 1.25 to 1; \3136\ (4) 
costs must be allocated solely within the transmission planning region 
unless another entity outside the region voluntarily assumes a portion 
of those costs; \3137\ and (5) the method for determining benefits and 
identifying beneficiaries must be transparent.\3138\
---------------------------------------------------------------------------

    \3134\ Order No. 1000, 136 FERC ] 61,051 at P 622.
    \3135\ Id. P 637.
    \3136\ Id. P 646.
    \3137\ Id. P 657.
    \3138\ Id. P 668.
---------------------------------------------------------------------------

    1472. We find that Order No. 1000 regional cost allocation 
principles (1) through (5) remain relevant for ex ante cost allocation 
methods for Long-Term Regional Transmission Facilities that 
transmission providers propose on compliance but with which Relevant 
State Entities have not indicated their agreement. In Order No. 1000, 
regarding regional cost allocation principle (1), the Commission stated 
that ``[r]equiring a beneficiaries pay cost allocation method or 
methods is fully consistent with the cost causation principle as 
recognized by the Commission and the courts.'' \3139\ Since making that 
statement, the Commission and the courts have only further strengthened 
this connection between beneficiaries-pay cost allocation and the cost 
causation principle.\3140\ Similarly, principle (2) continues to 
``express[ ] a central tenet of cost causation'' and is ``thus 
essential to proper cost allocation.'' \3141\
---------------------------------------------------------------------------

    \3139\ Id. P 623. See also id. P 586 & n.453 (citing ICC v. FERC 
I, 576 F.3d at 476-77; Midwest ISO Transmission Owners v. FERC, 373 
F.3d 1361, 1369 (D.C. Cir. 2004); Sithe/Indep. Power Partners, L.P. 
v. FERC, 285 F.3d 1, 5 (D.C. Cir. 2002)).
    \3140\ Long Island Power Auth. v. FERC, 27 F.4th 705, 713-14 
(D.C. Cir. 2022); Old Dominion Elec. Coop. v. FERC, 898 F.3d at 
1261-63.
    \3141\ Order No. 1000, 136 FERC ] 61,051 at P 637.
---------------------------------------------------------------------------

    1473. Concerning regional cost allocation principle (3), as noted 
in Order No. 1000, transmission providers may choose to establish such 
a threshold to mitigate against uncertainty in the measurement of 
benefits and costs, and this principle limits the threshold to one that 
is not so high as to block inclusion of many worthwhile transmission 
projects in the regional transmission plan.\3142\ As to regional cost 
allocation principle (4), this final order maintains the close link 
established by Order No. 1000 between regional transmission planning 
and cost allocation to the region being planned for.\3143\ Further, we 
find, similar to the Commission's findings in Order No. 1000, that 
removing regional cost allocation principle (4) would be tantamount to 
interconnection-wide transmission planning because unilateral 
allocation of costs from one transmission planning region to another 
would require stakeholders to actively monitor regional transmission 
planning processes in numerous other regions.\3144\ Lastly, we find, 
similar to Order No. 1000, that regional cost allocation principle (5) 
will ensure that Long-Term Regional Transmission Cost Allocation 
Methods are just and reasonable and not unduly discriminatory or 
preferential, will help aid in development and construction of new 
transmission, and may avoid contentious litigation or prolonged debate 
among stakeholders.\3145\
---------------------------------------------------------------------------

    \3142\ Id. PP 647-648.
    \3143\ Id. P 660. See also S.C. Pub. Serv. Auth. v. FERC, 762 
F.3d at 87-88.
    \3144\ Order No. 1000, 136 FERC ] 61,051 at P 660. See also S.C. 
Pub. Serv. Auth. v. FERC, 762 F.3d at 87-88.
    \3145\ Order No. 1000, 136 FERC ] 61,051 at P 669.
---------------------------------------------------------------------------

    1474. In contrast to the first five regional cost allocation 
principles, Order No. 1000 regional cost allocation principle (6) is 
inconsistent with Long-Term Regional Transmission Planning as directed 
in this final order. Order No. 1000 Regional cost allocation principle 
(6) provides that there may be different regional cost allocation 
methods for different types of transmission facilities in the regional 
transmission plan but that there can be only one cost allocation method 
for each type of facility, and that method must be determined in 
advance.\3146\ As we explain below, however, transmission providers may 
not establish reliability, economic, or public policy transmission 
facility types as part of Long-Term Regional Transmission Planning and, 
therefore, may not establish Long-Term Regional Transmission Cost 
Allocation Methods based on reliability, economic, or public policy 
transmission facility types. Permitting such project-type-limited Long-
Term Regional Transmission Cost Allocation Methods would be 
inconsistent with the long-term, forward-looking, more comprehensive 
regional transmission planning that we require in this final order. 
Accordingly, in declining to require that Long-Term Regional

[[Page 49506]]

Transmission Cost Allocation Methods comply with Order No. 1000 
regional cost allocation principle (6), consistent with the request of 
some commenters,\3147\ we find that reliability, economic, or public 
policy transmission facility types reflect a more siloed approach to 
regional transmission planning that is misaligned with our Long-Term 
Regional Transmission Planning reforms and would likely lead to the 
allocation of the costs of Long-Term Regional Transmission Facilities 
in a manner that is not at least roughly commensurate with estimated 
benefits.
---------------------------------------------------------------------------

    \3146\ Id. P 685.
    \3147\ Massachusetts Attorney General Initial Comments at 15, 
21; [Oslash]rsted Initial Comments at 9.
---------------------------------------------------------------------------

    1475. We clarify that this final order does not preclude the 
adoption of multiple Long-Term Regional Transmission Cost Allocation 
Methods, provided that the Long-Term Regional Transmission Cost 
Allocation Method that will apply to a Long-Term Regional Transmission 
Facility (or portfolio of such Facilities) is known before selection, 
i.e., is an ex ante cost allocation method, and does not allocate costs 
by project type. We find that knowing the applicability of a Long-Term 
Regional Transmission Cost Allocation Method in advance is inherent to 
the definition of, and one of the primary reasons for, requiring 
transmission providers to include an ex ante cost allocation method in 
their OATTs. As such, transmission providers that choose to propose 
more than one Long-Term Regional Transmission Cost Allocation Method on 
compliance are required to make clear in their OATTs which Long-Term 
Regional Transmission Cost Allocation Method applies to which Long-Term 
Regional Transmission Facilities (e.g., cost allocation methods that 
apply to Long-Term Regional Transmission Facilities above a certain 
voltage threshold or to Long-Term Regional Transmission Facilities 
located within a specific portion of a transmission planning region's 
footprint).\3148\ However, we emphasize that any Long-Term Regional 
Transmission Cost Allocation Method that transmission providers 
propose, except for those that Relevant State Entities indicate that 
they agreed to and asked the transmission providers in their 
transmission planning region to file, must comply with Order No. 1000 
regional cost allocation principles (1) through (5) and the other 
requirements of this final order.
---------------------------------------------------------------------------

    \3148\ We believe that this finding should address MISO's 
request that the final order not preclude applying different cost 
allocation methods to projects of the same type.
---------------------------------------------------------------------------

    1476. Regarding cost allocation methods resulting from a State 
Agreement Process and Long-Term Regional Transmission Cost Allocation 
Methods that Relevant State Entities indicate that they have agreed to 
and asked transmission providers to file after the Engagement Period, 
the Commission has previously found that ``Order No. 1000 allows market 
participants, including states, to negotiate voluntarily alternative 
cost sharing arrangements that are distinct from the relevant regional 
cost allocation method(s).'' \3149\ Additionally, where transmission 
providers have proposed cost allocation methods corresponding to such 
voluntary arrangements, the Commission has held that it need not find 
that those cost allocation methods comply with Order No. 1000.\3150\ 
Consistent with this precedent, we find that cost allocation methods 
resulting from a State Agreement Process and Long-Term Regional 
Transmission Cost Allocation Methods that Relevant State Entities 
indicate that they have agreed to and have asked transmission providers 
to file also qualify as voluntary alternative cost sharing arrangements 
and, accordingly, we decline to require those methods to adhere to the 
six Order No. 1000 regional cost allocation principles. However, those 
methods must still comply with the cost causation principle and any 
other legal requirements for cost allocation.
---------------------------------------------------------------------------

    \3149\ State Voluntary Agreements to Plan & Pay for Transmission 
Facilities, 175 FERC ] 61,225 at P 3 (citing Order No. 1000, 136 
FERC ] 61,051 at PP 561, 724; Order No. 1000-A, 139 FERC ] 61,132 at 
PP 728-729).
    \3150\ See PJM Interconnection, L.L.C., 142 FERC ] 61,214 at PP 
142-143, order on reh'g and compliance, 147 FERC ] 61,128 at P 92; 
ISO New England Inc., 143 FERC ] 61,150 at P 121; Consol. Edison Co. 
of N.Y., Inc., 180 FERC ] 61,106, at PP 48-50 (2022).
---------------------------------------------------------------------------

    1477. We decline to adopt the NOPR proposal that required adherence 
to the six Order No. 1000 regional cost allocation principles because 
cost allocation methods resulting from a State Agreement Process and 
Long-Term Regional Transmission Cost Allocation Methods that Relevant 
State Entities indicate that they have agreed to are likely to 
facilitate agreement over development of such Long-Term Regional 
Transmission Facilities by, for example, making the Relevant State 
Entities more confident that customers in the state are receiving 
benefits at least roughly commensurate with their share of the cost of 
such facilities and by reducing the likelihood that selected Long-Term 
Regional Transmission Facilities cannot be constructed because they do 
not receive necessary state regulatory approvals. Affording additional 
flexibility for these methods may encourage their use, which would 
facilitate the selection of more efficient or cost-effective Long-Term 
Regional Transmission Facilities. However, as described in the next 
section, we note that cost allocation methods resulting from a State 
Agreement Process and Long-Term Regional Transmission Cost Allocation 
Methods that Relevant State Entities indicate that they have agreed to 
must be just and reasonable and not unduly discriminatory or 
preferential and must allocate costs in a manner that is at least 
roughly commensurate with estimated benefits.\3151\
---------------------------------------------------------------------------

    \3151\ See, e.g., PPL Elec. Utils. Corp., 181 FERC ] 61,178 at P 
33.
---------------------------------------------------------------------------

    1478. ELCON and West Virginia Commission express concern that the 
NOPR's proposals for cost allocation methods, including requiring 
compliance with the six Order No. 1000 regional cost allocation 
principles, might not sufficiently recognize specific Public Policy 
Requirements as driving the needs for specific Long-Term Regional 
Transmission Facilities and, therefore, allow cost allocation methods 
that contradict precedent on cost causation. Similarly, Utah Division 
of Public Utilities asks that the Long-Term Regional Transmission Cost 
Allocation Method be required to use cost causation principles to 
determine what portion of Long-Term Regional Transmission Facilities 
are due to state policies when states or other stakeholders disagree on 
the cost allocation method due to differing renewable goals. We believe 
these concerns are misplaced and no further requirements are necessary. 
First, while state laws, regulations, and goals make up some of the 
drivers of Long-Term Transmission Needs, they do not comprise the 
entirety of those needs, as described in the Development of Long-Term 
Scenarios section of this final order. Second, as described below, all 
cost allocation methods for Long-Term Regional Transmission Facilities 
must allocate costs to transmission customers in a manner that is at 
least roughly commensurate with their estimated benefits. Third, for 
Long-Term Regional Transmission Cost Allocation Methods, except for 
those that Relevant State Entities indicate that they agreed to and 
asked the transmission providers in their transmission planning region 
to file, compliance with five of the Order No. 1000 regional cost 
allocation principles further safeguards against cost causation 
concerns; notably, principles (1) and (2) require that benefits 
received are at least roughly commensurate with costs paid and that 
costs may not be involuntarily allocated

[[Page 49507]]

to those that do not benefit, respectively. Further, Order No. 1000 
regional cost allocation principle (5), as well as the requirements in 
this final order to disclose estimates of the benefits of selected 
Long-Term Regional Transmission Facilities, ensures sufficient 
transparency for stakeholders to understand how the costs of selected 
Long-Term Regional Transmission Facilities will be allocated to 
transmission customers in relation to the benefits that they are 
forecasted to provide. Lastly, for cost allocation methods resulting 
from a State Agreement Process and Long-Term Regional Transmission Cost 
Allocation Methods that Relevant State Entities have agreed to and 
asked transmission providers to file, we believe that states will have 
an opportunity to come to consensus on cost allocation methods that 
they perceive as allocating costs in a manner that is at least roughly 
commensurate with estimated benefits.
    1479. Regarding Vermont Electric and Vermont Transco's concern 
regarding possible discrepancies between benefits received by small 
rural states and larger, more populated states, we believe that our 
requirement that all cost allocation methods for Long-Term Regional 
Transmission Facilities must allocate costs in a manner that is at 
least roughly commensurate with estimated benefits addresses this 
concern. Regarding OMS's, Louisiana Commission's, and Ohio Consumers' 
requests that the Commission adopt certain cost allocation principles 
distinct from the six Order No. 1000 regional cost allocation 
principles, the Commission did not propose adoption of any additional 
principles or that the six Order No. 1000 regional cost allocation 
principles be substituted for others. Accordingly, we find these 
requests beyond the scope of this final order. Additionally, in 
response to Exelon's request that the Commission clarify that the 
proposed State Agreement Process is supplementary to any previously 
accepted provisions for state agreement-based cost allocation,\3152\ we 
clarify that any State Agreement Process that the Commission accepts in 
compliance with this final order will apply to only Long-Term Regional 
Transmission Facilities, while any existing voluntary state cost 
allocation processes that the Commission has previously accepted apply 
to other transmission facilities and, thus, are unaltered by this final 
order.
---------------------------------------------------------------------------

    \3152\ Exelon Initial Comments at 27-28.
---------------------------------------------------------------------------

C. Identification of Benefits Considered in Cost Allocation for Long-
Term Regional Transmission Facilities

1. NOPR Proposal
    1480. The Commission proposed to require transmission providers in 
each transmission planning region to identify on compliance the 
benefits they will use in ex ante Long-Term Regional Transmission Cost 
Allocation Methods associated with Long-Term Regional Transmission 
Planning, how they will calculate those benefits, and how the benefits 
will reasonably reflect the benefits of regional transmission 
facilities to meet identified transmission needs driven by changes in 
the resource mix and demand. The Commission proposed that as part of 
this compliance obligation, transmission providers must explain the 
rationale for using the benefits identified.\3153\ The Commission also 
requested comment on whether the Commission should require that 
transmission providers account for the full list of benefits, as 
described in the Evaluation of the Benefits of Regional Transmission 
Facilities section above, in Long-Term Regional Transmission Planning, 
or whether no change to the benefits currently used in existing 
regional transmission planning processes is needed.\3154\
---------------------------------------------------------------------------

    \3153\ NOPR, 179 FERC ] 61,028 at P 326.
    \3154\ Id. P 327.
---------------------------------------------------------------------------

    1481. The Commission also proposed, for purposes of cost 
allocation, to require that transmission providers in each transmission 
planning region evaluate, as part of Long-Term Regional Transmission 
Planning, the benefits of regional transmission facilities over a time 
horizon that covers, at a minimum, 20 years starting from the estimated 
in-service date of the transmission facilities.\3155\
---------------------------------------------------------------------------

    \3155\ Id. P 228.
---------------------------------------------------------------------------

2. Comments
a. Agree With Proposal
    1482. Some commenters agree with the NOPR proposal.\3156\ NESCOE 
contends that it is critical that costs as well as benefits be clearly 
identified in connection with project evaluation.\3157\
---------------------------------------------------------------------------

    \3156\ Avangrid Initial Comments at 29; California Energy 
Commission Initial Comments at 3; Idaho Power Initial Comments at 
11; ITC Initial Comments at 30; NESCOE Initial Comments at 72; 
Northwest and Intermountain Initial Comments at 18-19.
    \3157\ NESCOE Initial Comments at 72.
---------------------------------------------------------------------------

    1483. Many commenters supporting the proposal emphasize the 
importance of flexibility and the lack of a proposed requirement in the 
NOPR to require that specific benefits be accounted for in cost 
allocation.\3158\ Dominion opposes making the NOPR's listed benefits 
mandatory for cost allocation because identifying and measuring them 
would be difficult and lead to disputes and litigation that would add 
to the costs, borne by consumers, of transmission development.\3159\ 
NYISO states that considering the list of benefits in the NOPR in cost 
allocation would introduce significant complexity and create a 
burdensome and perhaps infeasible process.\3160\ Xcel states that not 
all benefits need to be studied given that such study can be costly and 
add little value, and that the analysis of future benefits should 
balance uncertainties to ensure that it is not too speculative.\3161\
---------------------------------------------------------------------------

    \3158\ APPA Initial Comments at 46; Dominion Initial Comments at 
45-46; Dominion Reply Comments at 6, 9; Exelon Initial Comments at 
29-30 (citing NOPR, 179 FERC ] 61,028 at P 312 & n.516; Midwest ISO 
Transmission Owners, 373 F.3d at 1369); Louisiana Commission Initial 
Comments at 35-36; NARUC Initial Comments at 38; National Grid 
Initial Comments at 26-27; NYISO Initial Comments at 51-52; Pacific 
Northwest Utilities Initial Comments at 8-9; PPL Initial Comments at 
28; SERTP Sponsors Initial Comments at 30-31; Southern Initial 
Comments at 27; Xcel Initial Comments at 12.
    \3159\ Dominion Reply Comments at 6-7.
    \3160\ NYISO Initial Comments at 52.
    \3161\ Xcel Initial Comments at 12.
---------------------------------------------------------------------------

    1484. Pacific Northwest Utilities and SERTP Sponsors argue that 
many of the NOPR's proposed benefits would work only in RTO/ISO 
transmission planning regions and are not appropriate in non-RTO/ISO 
regions.\3162\ Pacific Northwest Utilities state that several of the 
benefits listed in the NOPR do not benefit transmission providers and 
argue that--in non-RTO/ISO transmission planning regions, like 
NorthernGrid, where there is neither a single independent transmission 
system operator nor any single independent transmission provider 
through which to affect transmission rate impacts due to cost 
allocation--costs allocated to transmission providers must be based on 
benefits to the transmission provider, not benefits realized by others, 
such as generators and load-serving entities.\3163\ California 
Municipal Utilities argue that requiring consideration of the list of 
benefits in the NOPR would not reflect the state and local nature of 
resource portfolio planning and would fail to account for the costs of 
such prescriptive measures and consumer protection against speculative

[[Page 49508]]

projects.\3164\ Louisiana Commission states that transmission providers 
and retail regulators should be allowed to develop and agree on an 
appropriate set of metrics to be used for cost allocation.\3165\
---------------------------------------------------------------------------

    \3162\ Pacific Northwest Utilities Initial Comments at 8-10; 
SERTP Sponsors Initial Comments at 29-30.
    \3163\ Pacific Northwest Utilities Initial Comments at 9-10.
    \3164\ California Municipal Utilities Reply Comments at 5-6 
(citing ACEG Initial Comments at 26-48, 50-51, 60-63).
    \3165\ Louisiana Commission Initial Comments at 35.
---------------------------------------------------------------------------

    1485. APPA argues that regional flexibility should include allowing 
transmission providers to demonstrate on compliance that the benefits 
that they use to allocate the costs of transmission projects identified 
through their existing regional transmission planning processes are 
sufficient for Long-Term Regional Transmission Planning.\3166\ National 
Grid asserts that flexibility avoids the risk of a static list of 
benefits becoming outdated, citing as an example the growing numbers of 
distributed resources in New England driving the need for transmission-
level upgrades in New England. National Grid claims that more granular 
(state-specific or even direct assignment) cost allocation is 
appropriate for such upgrades.\3167\
---------------------------------------------------------------------------

    \3166\ APPA Initial Comments at 46.
    \3167\ National Grid Initial Comments at 26-27.
---------------------------------------------------------------------------

    1486. City of New Orleans Council, OMS, Louisiana Commission, and 
Michigan Commission argue that any benefit metrics should comply with 
OMS Cost Allocation Principle Committee Principle No. 2, which states 
that ``[c]ost allocation should be as granular and accurate as 
possible. Benefit-cost analysis should use metrics that are 
quantifiable, capable of replication, non-duplicative, and forward-
looking.'' \3168\ NARUC similarly asserts that transmission benefits 
must be verifiable and quantifiable to justify allocating costs to 
ratepayers.\3169\ Likewise, Idaho Power, Pacific Northwest Utilities, 
and West Virginia Commission state that benefits must be quantifiable 
and justified, arguing that many benefits in the NOPR proposal would be 
difficult to quantify, a difficulty, Idaho Power and Pacific Northwest 
Utilities argue, exacerbated by the proposed 20-year transmission 
planning horizon.\3170\
---------------------------------------------------------------------------

    \3168\ City of New Orleans Council Initial Comments at 11; 
Louisiana Commission Initial Comments at 35-36; Michigan Commission 
Initial Comments at 9; OMS Initial Comments at 7-8, 14 (citing 
Organization of MISO States, Inc., Organization of MISO States 
Statement of Principles: Cost Allocation for Long Range Transmission 
Planning Projects, https://www.misostates.org/images/PositionStatements/OMS_Position_Statement_of_Principles_Cost_Allocation_for_LRTPs.pdf).
    \3169\ NARUC Initial Comments at 25, 38.
    \3170\ Idaho Power Initial Comments at 11; Pacific Northwest 
Utilities Initial Comments at 6-9; West Virginia Commission Reply 
Comments at 4.
---------------------------------------------------------------------------

    1487. West Virginia Commission argues that use of these benefits 
allows for unfettered discretion by transmission providers to adopt 
cost allocation methods that do not meet the cost causation 
principle.\3171\
---------------------------------------------------------------------------

    \3171\ West Virginia Commission Reply Comments at 4.
---------------------------------------------------------------------------

    1488. Southern states that a cost allocation premised on an overly 
broad, non-quantifiable construction of benefits would likely exceed 
the Commission's authority because there must be a correlation between 
the charges proposed and the expected benefits, as articulated by the 
courts.\3172\ Southern states that the Commission must apply the 
roughly commensurate standard by determining whether the benefits to 
the intended beneficiaries are quantifiable and spread evenly across a 
transmission planning region. Otherwise, Southern states, the 
Commission must compile a record based on substantial evidence to 
support the proposed allocation of costs.\3173\ Dominion similarly 
cautions that assignment of costs requires more than generalized 
articulation of benefits and that the list of benefits in the NOPR are 
broadly defined and generalized.\3174\
---------------------------------------------------------------------------

    \3172\ Southern Initial Comments at 28-30 (citing Pac. Gas & 
Elec. Co. v. FERC, 373 F.3d 1315, 1321 (D.C. Cir. 2004)).
    \3173\ Id. at 29-30 (citing ICC v. FERC I, 576 F.3d at 476-77; 
Ill. Com. Comm'n v. FERC, 721 F.3d 764, 777 (7th Cir. 2013) (ICC v. 
FERC II); ICC v. FERC III, 756 F.3d at 564-565).
    \3174\ Dominion Initial Comments at 43-44.
---------------------------------------------------------------------------

    1489. Ohio Consumers state that the Commission should base the 
benefits attributable to Long-Term Regional Transmission Planning on 
the electrons to be delivered from generating facilities. Ohio 
Consumers point out that state consumer advocates disagree as to which 
benefits should be considered in cost allocation.\3175\ Ohio Consumers 
argue that adopting a broad definition of benefits that includes state 
decarbonization plans and socialization of some portion of the 
associated costs across a transmission planning region would violate 
the Order No. 1000 regional cost allocation principles and the cost 
causation principle.\3176\
---------------------------------------------------------------------------

    \3175\ Ohio Consumers Reply Comments at 10.
    \3176\ Ohio Consumers Reply Comments at 11 (citing DC and MD 
Offices of People's Counsel Initial Comments at 31, 34, 38-39).
---------------------------------------------------------------------------

    1490. Pennsylvania Commission takes no position on requiring 
certain benefits to be accounted for in cost allocation, but states 
that the need for objective, well-defined, and measurable benefits 
applies not only to transmission planning but also to cost allocation, 
noting that it is important that customers who pay the costs allocated 
to them agree that they are paying for real and appreciable 
benefits.\3177\
---------------------------------------------------------------------------

    \3177\ Pennsylvania Commission Initial Comments at 11.
---------------------------------------------------------------------------

b. Requests To Reflect the Full Breadth of Benefits in Cost Allocation 
Methods While Maintaining Flexibility
    1491. Some commenters request that transmission providers reflect 
the full breadth of benefits in cost allocation methods for Long-Term 
Regional Transmission Facilities while also supporting 
flexibility.\3178\ Vistra asserts that benefits considered in cost 
allocation should not be confined to a prescriptive list.\3179\ NESCOE 
argues that the Commission should include a list of benefits in the 
final order as a required starting point and allow transmission 
providers to add or subtract benefits from the list on compliance 
following consultation with states in their transmission planning 
region.\3180\
---------------------------------------------------------------------------

    \3178\ APPA Initial Comments at 45-46; Massachusetts Attorney 
General Initial Comments at 21; NESCOE Initial Comments at 72; 
Vistra Initial Comments at 15.
    \3179\ Vistra Initial Comments at 15.
    \3180\ NESCOE Initial Comments at 43, 72.
---------------------------------------------------------------------------

c. Disagree With Proposal, Mostly Require Benefits
    1492. Some commenters disagree with the Commission's proposal, 
arguing that the Commission should require transmission providers to 
account for a minimum set of benefits in cost allocation.\3181\ 
Indicated U.S. Senators and Representatives argue that unless all 
benefits and costs are incorporated into transmission planning and cost 
allocation, the result will be biased, resulting in unjust and 
unreasonable costs and cost allocation.\3182\ Acadia Center and CLF 
contend that failure to consider a minimum set of benefits could result 
in the failure to select transmission projects that would have 
benefited customers.\3183\ Certain TDUs argue that guardrails should be 
put in place to require transmission providers to adequately define 
quantifiable benefits and to make transparent their method for 
identifying benefits; however, Certain TDUs contend that the

[[Page 49509]]

Commission should require transmission providers to account for, at 
minimum, production cost savings and avoided or deferred reliability 
transmission facilities and aging transmission infrastructure 
replacement, as may be refined by transmission planning regions as 
necessary.\3184\ US Climate Alliance states that each transmission 
planning region could determine additional categories of benefits most 
relevant to them.\3185\
---------------------------------------------------------------------------

    \3181\ Acadia Center and CLF Initial Comments at 16-19; Certain 
TDUs Reply Comments at 2-3; Indicated U.S. Senators and 
Representatives Initial Comments at 2; U.S. Climate Alliance Initial 
Comments at 2; U.S. Senators Supplemental Comments at 2.
    \3182\ Indicated U.S. Senators and Representatives Initial 
Comments at 2.
    \3183\ Acadia Center and CLF Initial Comments at 16-19.
    \3184\ Certain TDUs Reply Comments at 2-3.
    \3185\ U.S. Climate Alliance Initial Comments at 2.
---------------------------------------------------------------------------

    1493. Other commenters that disagree with the Commission's proposal 
similarly argue for a required minimum set of benefits, but argue that 
the Commission should require transmission providers to account for the 
full list of 12 benefits in the NOPR.\3186\ ACEG and PIOs state that it 
would be unjust and unreasonable for transmission providers to allocate 
costs in a manner that ignores certain benefits or fails to provide a 
full accounting of those benefits, including, PIOs assert, cost 
allocation agreed to by states.\3187\ PIOs further argue that allowing 
transmission providers to agree to a cost allocation method that does 
not reflect all quantifiable benefits would re-introduce the risk of 
free ridership.\3188\
---------------------------------------------------------------------------

    \3186\ ACEG Initial Comments at 60; Clean Energy Associations 
Initial Comments at 20-21, 34; DC and MD Offices of People's Counsel 
Initial Comments at 20, 34; PIOs Initial Comments at 64-65.
    \3187\ ACEG Initial Comments at 60-61 (citing ICC v. FERC I, 576 
F.3d at 477); PIOs Initial Comments at 65; PIOs Reply Comments at 3.
    \3188\ PIOs Initial Comments at 65.
---------------------------------------------------------------------------

    1494. Clean Energy Buyers state that they support the Commission 
requiring each transmission provider to either adopt the benefits 
identified by the Commission to be used for cost allocation for Long-
Term Regional Transmission Facilities or demonstrate why the exclusion 
of any such benefit(s) is just and reasonable. However, Clean Energy 
Buyers also recommend that the Commission consider how the factors 
required for Long-Term Scenarios will translate into benefits and 
ensure that there is no double-counting of benefits.\3189\
---------------------------------------------------------------------------

    \3189\ Clean Energy Buyers Initial Comments at 30.
---------------------------------------------------------------------------

    1495. Southwestern Power Group states that existing regional cost 
allocation methods do not account for the range of benefits that 
regional transmission expansion can provide. Consequently, Southwestern 
Power Group argues, the costs of regional transmission projects are 
allocated to too few of the beneficiaries, discouraging the development 
of regional transmission projects.\3190\ Environmental Groups argue 
that the Commission must ensure that any cost allocation method agreed 
to by states complies with the beneficiary-pays principle by showing 
that the method considers all quantifiable benefits of 
transmission.\3191\
---------------------------------------------------------------------------

    \3190\ Southwestern Power Group Initial Comments at 14-15.
    \3191\ Environmental Groups Supplemental Comments at 2.
---------------------------------------------------------------------------

    1496. SPP states that its regional cost allocation method does not 
quantify the specific benefits of transmission facilities within each 
planning assessment but instead analyzes the benefits and costs of 
facilities approved in multiple assessments in a comprehensive manner. 
SPP states that potential inequities are not appropriately quantified 
in a single regional planning assessment cycle because potential 
imbalances in one cycle may be offset in later cycles or changed 
because of topology. SPP emphasizes that quantification of whether 
benefits of transmission facilities are roughly commensurate with 
allocated costs should be performed through multiple transmission 
planning cycles that evaluate project portfolios, citing SPP's Highway-
Byway cost allocation method as an example.\3192\
---------------------------------------------------------------------------

    \3192\ SPP Initial Comments at 31.
---------------------------------------------------------------------------

d. Alignment of Benefits Between Transmission Planning and Cost 
Allocation
    1497. Various commenters proffer arguments as to whether benefits 
used in the evaluation and selection of Long-Term Regional Transmission 
Facilities must align with the benefits used in cost allocation. For 
example, SERTP Sponsors state that there could be differences between 
the types of benefits used for evaluation and selection and those used 
for cost allocation, asserting that benefits used in cost allocation 
must be measured in a consistent and objective manner to limit 
disputes.\3193\
---------------------------------------------------------------------------

    \3193\ SERTP Sponsors Initial Comments at 30-31.
---------------------------------------------------------------------------

    1498. Some commenters argue that the benefits used in the 
evaluation and selection of Long-Term Regional Transmission Facilities 
should closely align with, but need not be the same as, those used in 
cost allocation.\3194\ For example, Clean Energy Associations state 
that close alignment does not preclude regional variation and points to 
MISO's Multi-Value Projects' and SPP's Highway/Byway projects' cost 
allocation methods.\3195\
---------------------------------------------------------------------------

    \3194\ Clean Energy Associations Initial Comments at 34; Cypress 
Creek Reply Comments at 14-15; [Oslash]rsted Initial Comments at 9.
    \3195\ Clean Energy Associations Initial Comments at 34-35.
---------------------------------------------------------------------------

    1499. Some commenters argue that the same set of benefits used in 
transmission planning should be used in cost allocation.\3196\ DC and 
MD Offices of People's Counsel and the New Jersey Commission link such 
a requirement with the beneficiary-pays principle.\3197\ New Jersey 
Commission states that enforcing the beneficiary-pays principle based 
on all of a transmission project's quantified benefits is necessary to 
avoid free-rider problems that could arise, especially in the State 
Agreement Process.\3198\ Additionally, New Jersey Commission states, 
the policy of preventing states from involuntarily bearing the costs of 
others' policies must not require states to always pay the full cost of 
any transmission solution that supports their public policies or 
prevent states from committing to paying more than what they perceive 
to be their fair share to overcome disagreements over who will 
benefit.\3199\ Similarly, BP recommends requiring that those 
benefitting from transmission facilities that meet policy objectives, 
but without similar policies themselves, be allocated an appropriate 
share of costs to avoid free ridership.\3200\
---------------------------------------------------------------------------

    \3196\ DC and MD Offices of People's Counsel Initial Comments at 
34; Fervo Reply Comments at 2-3; New Jersey Commission Initial 
Comments at 18-23; SEIA Initial Comments at 24; Vermont Electric and 
Vermont Transco Initial Comments at 4; WATT Coalition Initial 
Comments at 8.
    \3197\ DC and MD Offices of People's Counsel Initial Comments at 
34 (citing ICC v. FERC I, 576 F.3d 470; ICC v. FERC II, 721 F.3d 
764; ICC v. FERC III, 756 F.3d 556); New Jersey Commission Initial 
Comments at 18-23 (citing Old Dominion Elec. Coop. v. FERC, 898 F.3d 
at 1262-63; Entergy Ark. v. FERC, 40 F.4th 689, 701 (D.C. Cir. 
2022)).
    \3198\ New Jersey Commission Initial Comments at 18.
    \3199\ Id. at 21-23.
    \3200\ BP Initial Comments at 9-12.
---------------------------------------------------------------------------

    1500. Massachusetts Attorney General states that ex ante cost 
allocation methods should reflect the same benefits considered in Long-
Term Regional Transmission Planning and not consider benefits in 
silos.\3201\ [Oslash]rsted similarly supports a requirement that 
transmission providers adopt cost allocation methods that recognize the 
full breadth of benefits that transmission facilities provide.\3202\
---------------------------------------------------------------------------

    \3201\ Massachusetts Attorney General Initial Comments at 21.
    \3202\ [Oslash]rsted Initial Comments at 9.
---------------------------------------------------------------------------

    1501. PIOs argue that cost allocation is necessarily implicated in 
the NOPR's preliminary finding that failure to consider a broader set 
of benefits and beneficiaries of transmission facilities may result in 
unjust, unreasonable, and unduly discriminatory or preferential rates, 
reasoning that cost allocation cannot be based on unlawful

[[Page 49510]]

identification of benefits and beneficiaries.\3203\
---------------------------------------------------------------------------

    \3203\ PIOs Initial Comments at 71.
---------------------------------------------------------------------------

e. Additional Benefits or Suggestions for Refinement
    1502. DC and MD Offices of People's Counsel recommend that the 
Commission allow Relevant State Entities to propose additional benefit 
categories for evaluation and to consent to the allocation of costs 
that align with these additional benefits. At a minimum, DC and MD 
Offices of People's Counsel argue, costs should be allocated to the 
benefitting Relevant State Entities.\3204\
---------------------------------------------------------------------------

    \3204\ DC and MD Offices of People's Counsel Initial Comments at 
34.
---------------------------------------------------------------------------

    1503. California Energy Commission recommends that transmission 
providers be required to consider equity and environmental justice in 
the calculation of benefits, including economic, health, and social 
benefits to disadvantaged communities.\3205\ WE ACT recommends that the 
Commission include non-energy benefits like pollution reduction, 
health, jobs, and local economic development in the list of benefits 
that transmission providers should be required to utilize in 
identifying and evaluating Long-Term Regional Transmission Facility 
need, selection, and cost allocation.\3206\
---------------------------------------------------------------------------

    \3205\ California Energy Commission Initial Comments at 3.
    \3206\ WE ACT Initial Comments at 5.
---------------------------------------------------------------------------

    1504. Louisiana Commission states that the Commission should permit 
transmission providers to consider allocations to all cost causers and 
beneficiaries, including generators.\3207\ Vistra argues that if 
achieving voluntary corporate and utility clean energy goals is 
factored into demand driving the need for an upgrade, then the costs of 
such upgrades should not be assigned to regional load.\3208\
---------------------------------------------------------------------------

    \3207\ Louisiana Commission Initial Comments at 32.
    \3208\ Vistra Initial Comments at 21-22.
---------------------------------------------------------------------------

3. Commission Determination
    1505. We decline to adopt the NOPR proposal to require transmission 
providers to identify on compliance the benefits that they will use in 
Long-Term Regional Transmission Cost Allocation Methods, how they will 
calculate those benefits, and how the benefits will reasonably reflect 
the benefits of regional transmission facilities to meet identified 
transmission needs driven by changes in the resource mix and demand.
    1506. Instead, as we discuss above in the Long-Term Regional 
Transmission Facility Cost Allocation Compliance with the Existing Six 
Order No. 1000 Regional Cost Allocation Principles section, we require 
transmission providers in each transmission planning region to 
demonstrate on compliance that the required Long-Term Regional 
Transmission Cost Allocation Method(s) that Relevant State Entities 
have not indicated that they agree to comply with Order No. 1000 
regional transmission cost allocation principles (1) through (5) and do 
not allocate costs by project type (i.e., reliability, economic, or 
transmission needs driven by Public Policy Requirements). While we do 
not require that cost allocation methods resulting from State Agreement 
Processes or Long-Term Regional Transmission Cost Allocation Methods 
that Relevant States Entities indicate they agreed to, must comply with 
any of the Order No. 1000 regional cost allocation principles, if filed 
with the Commission, transmission providers must nonetheless 
demonstrate that either of these types of cost allocation methods will 
allocate costs in a manner at least roughly commensurate with estimated 
benefits.\3209\ We do not require that any particular benefit used in 
the evaluation and selection of Long-Term Regional Transmission 
Facilities be reflected in a Long-Term Regional Transmission Cost 
Allocation Method filed with the Commission. We adopt this modified 
approach to the relationship of benefits used in Long-Term Regional 
Transmission Planning and Long-Term Regional Transmission Cost 
Allocation Methods because it provides transmission providers with 
flexibility to propose a Long-Term Regional Transmission Cost 
Allocation Method(s), allowing for negotiation in the Engagement 
Period, which we believe will increase the chances that Long-Term 
Regional Transmission Facilities selected as the more efficient or 
cost-effective regional transmission solution will be developed. At the 
same time, the requirements in this final order to disclose estimates 
of the benefits of selected Long-Term Regional Transmission Facilities 
will provide transparency and help to ensure a cost allocation is just 
and reasonable.
---------------------------------------------------------------------------

    \3209\ See ICC v. FERC I, 576 F.3d at 477; ICC v. FERC III, 756 
F.3d at 564.
---------------------------------------------------------------------------

    1507. We note that this flexible approach is consistent with the 
approach that the Commission took in Order No. 1000 and in subsequent 
orders on transmission providers' Order No. 1000 compliance filings, 
where the Commission allowed a wide variety of cost allocation methods 
and did not require that such methods specifically account for all 
benefits used in evaluation and selection processes.\3210\ The cost 
allocation method for MISO's Multi-Value Projects and the SPP Highway/
Byway cost allocation method are examples that reflect the flexibility 
that transmission providers have had in adopting cost allocation 
methods suited to their circumstances and that may not have been 
possible under a less flexible approach.
---------------------------------------------------------------------------

    \3210\ Order No. 1000, 136 FERC ] 61,051 at PP 560, 624.
---------------------------------------------------------------------------

    1508. The one exception to that flexibility, however, is the second 
component of our compliance requirement, that transmission providers 
must not allocate costs based on project types; namely, reliability, 
economic, or Public Policy Requirements needs-driven cost allocation 
methods. As described in the Long-Term Regional Transmission Facility 
Cost Allocation Compliance with Existing Six Order No. 1000 Regional 
Cost Allocation Principles section, we adopt this requirement because 
permitting such project-type-limited cost allocation methods for Long-
Term Regional Transmission Facilities would be inconsistent with the 
long-term, forward-looking, more comprehensive regional transmission 
planning that we require in this final order. As we note above in the 
Need for Reform section, allocating costs based on these project types 
would result in transmission providers undertaking investments in 
relatively inefficient or less cost-effective transmission 
infrastructure, the costs of which are ultimately recovered through 
Commission-jurisdictional rates. Allocating costs based on these 
project types could, for example, encourage the selection of 
transmission facilities based on either their economic or reliability 
benefits alone rather than based on an evaluation of the wider range of 
benefits that they may provide. This dynamic results in, among other 
things, transmission customers paying more than is necessary or 
appropriate to meet their transmission needs, customers forgoing 
benefits that outweigh their costs, or some combination thereof, which 
results in less efficient or cost-effective transmission investments. 
We further find that permitting the use of such project-type-limited 
cost allocation methods for Long-Term Transmission Facilities would not 
allocate costs in a manner that is at least roughly commensurate to 
estimated benefits.
    1509. We decline to adopt the NOPR proposal to require transmission 
providers to evaluate benefits over a 20-year time horizon for Long-
Term Regional Transmission Planning for

[[Page 49511]]

purposes of cost allocation. Given our decision to not require 
transmission providers to explain the benefits that they are using in 
cost allocation for Long-Term Regional Transmission Facilities, we 
believe this proposal is moot.
    1510. We acknowledge New Jersey Commission's concern that 
permissive state-negotiated cost allocation could result in free 
riders. However, we note that, even for cost allocation methods filed 
pursuant to a State Agreement Process and Long-Term Regional 
Transmission Cost Allocation Methods that Relevant State Entities 
indicate that they have agreed, the costs allocated in accordance with 
such methods must be, as noted above, at least roughly commensurate 
with estimated benefits consistent with legal precedent. On compliance 
with this final order, the Commission will evaluate whether any cost 
allocation method agreed to pursuant to a State Agreement Process, or 
Long-Term Regional Transmission Cost Allocation Methods that Relevant 
State Entities indicate that they have agreed to, and filed with the 
Commission, allocates the costs of Long-Term Regional Transmission 
Facilities in a manner that is at least roughly commensurate with the 
estimated benefits. Further, we believe that New Jersey Commission's 
concern is reduced by our modification to the NOPR proposal to require 
transmission providers to file a Long-Term Regional Transmission Cost 
Allocation Method that must be used where a State Agreement Process 
fails to result in agreement; to the extent Relevant State Entities do 
not agree to a cost allocation method through the State Agreement 
Process, the transmission provider's ex ante Long-Term Regional 
Transmission Cost Allocation Method will apply.
    1511. Given our modification to the NOPR proposal to not require 
transmission providers to identify on compliance the benefits that they 
will use in Long-Term Regional Transmission Cost Allocation Methods, we 
find moot APPA's request that regional flexibility should include 
allowing transmission providers to demonstrate on compliance that their 
existing benefits used for cost allocation of transmission projects 
identified through their existing regional transmission planning 
processes are sufficient for Long-Term Regional Transmission 
Planning.\3211\
---------------------------------------------------------------------------

    \3211\ APPA Initial Comments at 46. We also discuss related 
concerns in the Cost Allocation for Long-Term Transmission 
Facilities section, above.
---------------------------------------------------------------------------

    1512. With respect to the comments of City of New Orleans Council, 
OMS, Louisiana Commission, and Michigan Commission arguing that any 
benefit metrics should comply with OMS Cost Allocation Principle 
Committee Principle No. 2,\3212\ which states that ``[c]ost allocation 
should be as granular and accurate as possible,'' \3213\ we note that 
the flexibility we provide as to the consideration of benefits in cost 
allocation does not prevent transmission providers in a particular 
transmission planning region from adopting a more granular approach.
---------------------------------------------------------------------------

    \3212\ City of New Orleans Council Initial Comments at 11; 
Louisiana Commission Initial Comments at 35-36; Michigan Commission 
Initial Comments at 9; OMS Initial Comments at 7-8, 14.
    \3213\ OMS Initial Comments at 7-8.
---------------------------------------------------------------------------

    1513. With respect to Southern and Dominion's assertions that the 
Commission must ensure that costs are allocated in a manner that is at 
least roughly commensurate with benefits by conducting its evaluation 
of proposed cost allocation methods in a particular manner,\3214\ we 
reiterate that we will apply existing Commission and judicial 
precedent, including that cited by Dominion and Southern, in our 
evaluation of any proposed cost allocation methods for Long-Term 
Regional Transmission Facilities. With respect to Louisiana 
Commission's assertion that the cost allocation process should be 
allowed to consider allocations to all cost causers and beneficiaries, 
including generators,\3215\ we continue to adhere to the flexibility we 
provided in Order No. 1000-A. In that order, we found that with respect 
to generators being identified as beneficiaries and ultimately 
responsible for costs, just as each transmission planning region 
retains the flexibility to define benefit and beneficiary, the public 
utility transmission providers in each transmission planning region, in 
consultation with their stakeholders, may consider proposals to 
allocate costs directly to generators as beneficiaries that could be 
subject to regional or interregional cost allocation. However, we also 
found that any effort to do so must not be inconsistent with the 
generator interconnection process under Order No. 2003 because, as we 
stated in Order No. 1000, the generator interconnection process and 
interconnection cost recovery were outside the scope of that 
rulemaking.\3216\
---------------------------------------------------------------------------

    \3214\ Southern Initial Comments at 29-30 (citing ICC v. FERC I, 
576 F.3d at 476-77; ICC v. FERC II, 721 F.3d at 777; ICC v. FERC 
III, 756 F.3d at 564-565); Dominion Initial Comments at 43-44 
(citing ICC v. FERC I, 576 F.3d at 477).
    \3215\ Louisiana Commission Initial Comments at 32.
    \3216\ Order No. 1000-A, 139 FERC ] 61,132 at P 680. While 
interconnection customers may voluntarily fund the cost of, or a 
portion of the cost of, a Long-Term Regional Transmission Facility 
as discussed in the Evaluation and Selection of Long-Term Regional 
Transmission Facilities section, this process is distinct from 
allocating costs to generators under the Long-Term Regional 
Transmission Cost Allocation Method, as the Louisiana Commission 
appears to contemplate.
---------------------------------------------------------------------------

    1514. We find Pacific Northwest Utilities' assertion that costs 
allocated to transmission providers in non-RTO/ISO transmission 
planning regions, like NorthernGrid, must be based on benefits to the 
transmission provider, not benefits realized by others, such as 
generators and load-serving entities,\3217\ to be misplaced, as nothing 
in this final order requires that only transmission providers in non-
RTO/ISO transmission planning regions bear the ultimate responsibility 
for the costs of Long-Term Regional Transmission Facilities. We 
recognize that, in the absence of a single regional transmission 
provider who can recover the costs of Long-Term Regional Transmission 
Facilities on behalf of its transmission-owning members from all of its 
transmission customers in its transmission planning region, 
transmission providers in non-RTO/ISO regions require alternative 
arrangements to allocate and recover the costs of Long-Term Regional 
Transmission Facilities from the transmission customers that benefit 
from them. We expect that in non-RTO/ISO transmission planning regions, 
as is the case with Order No. 1000 regional transmission planning and 
cost allocation processes today,\3218\ transmission providers will 
establish arrangements to implement the cost allocation methods for 
Long-Term Regional Facilities and recover the costs of such facilities 
from the transmission customers that benefit from them.
---------------------------------------------------------------------------

    \3217\ Pacific Northwest Utilities Initial Comments at 9-10.
    \3218\ See e.g., Duke Energy Carolinas, LLC, 147 FERC ] 61,241 
at P 453; Pub. Serv. Co. of Colo., 142 FERC ] 61,206 at P 314.
---------------------------------------------------------------------------

    1515. Some commenters advocate for accounting for public policy 
benefits in cost allocation methods for Long-Term Regional Transmission 
Facilities.\3219\ Although we are not requiring transmission providers 
to account for public policy benefits in cost allocation methods for 
Long-Term Regional Transmission Facilities, we are also not foreclosing 
the possibility that transmission providers and stakeholders may seek 
to account for certain public

[[Page 49512]]

policy benefits when developing Long-Term Regional Transmission Cost 
Allocation Methods. We believe that states are well-positioned to value 
the benefits of achieving their respective public policy goals, 
consistent with past precedent in which we have affirmed the use of 
public policy benefits in regional transmission planning cost 
allocation,\3220\ and they or other stakeholders can similarly do so 
through engagement with transmission providers in their efforts to 
develop Long-Term Regional Transmission Cost Allocation Methods. In 
addition, to the extent states believe that a particular Long-Term 
Regional Transmission Facility would help achieve their public policy 
goals, we note our adoption in the Evaluation and Selection of Long-
Term Regional Transmission Facilities section of this final order of 
opportunities for Relevant State Entities to voluntarily fund a portion 
of the cost of a Long-Term Regional Transmission Facility so that the 
facility can qualify for selection.\3221\ The rule, consistent with the 
cost causation principle, does not allow allocation of costs based on 
benefits to entities that do not receive benefits or receive only 
trivial benefits in relationship to costs of those transmission 
facilities.\3222\
---------------------------------------------------------------------------

    \3219\ See e.g., California Energy Commission Initial Comments 
at 3 (recommending that equity and environmental justice benefits be 
accounted for in cost allocation, including economic, health, and 
social benefits to disadvantaged communities); WE ACT Initial 
Comments at 5 (recommending the following benefits be accounted for 
in cost allocation: pollution reduction, health, jobs, and local 
economic development).
    \3220\ As noted in the Evaluation of the Benefits of Regional 
Transmission Facilities section, RTOs/ISOs that have used some form 
of public policy benefit in regional transmission planning include 
PJM and NYISO. Although explicitly not part of PJM's Order No. 1000 
regional transmission planning, PJM uses a State Agreement Approach 
to allow the development of public policy projects. See PPL Elec. 
Utils. Corp., 181 FERC ] 61,178 at P 33 (finding that ``allocating 
the costs of the New Jersey [State Agreement Approach] Projects on a 
load-ratio share basis to all New Jersey customers is roughly 
commensurate with the benefits provided by those projects''). NYISO 
provides for cost allocations developed by the New York State Public 
Service Commission for transmission projects developed to meet 
public policy needs. See Consol. Edison Co. of N.Y., Inc., 180 FERC 
] 61,106 at P 50 (finding that a volumetric load-ratio share cost 
allocation for certain local transmission upgrades was appropriate 
because the projects ``benefit customers throughout the state 
insofar as they facilitate compliance with the New York State 
climate and renewable energy goals as required by New York State law 
and have been determined by the NYPSC to be necessary to meet such 
obligation'').
    \3221\ Supra Evaluation and Selection of Long-Term Regional 
Transmission Facilities section.
    \3222\ See Coal. of MISO Transmission Customers v. FERC, 45 
F.4th 1004, 1009 (D.C. Cir. 2022) (``The cost-causation principle 
requires that `the cost of transmission facilities be allocated to 
those within the transmission planning region that benefit from 
those facilities in a manner that is at least roughly commensurate 
with estimated benefits.''') (cleaned up) (quoting S.C. Pub. Serv. 
Auth. v. FERC, 762 F.3d at 53); ICC v. FERC I, 576 F.3d at 477.
---------------------------------------------------------------------------

D. Miscellaneous Cost Allocation Comments and Proposals

1. Comments
    1516. Some commenters discuss the appropriate time frame for cost 
allocation for Long-Term Regional Transmission Facilities. Dominion 
states that costs should not be allocated until closer in time to when 
a transmission project will be built and beneficiaries identified 
rather than when the Long-Term Regional Transmission Facilities are 
identified.\3223\ Ohio Consumers state that cost allocation decisions 
must be made on the basis of current or near-term transmission needs, 
and the Commission should not require subsidization for transmission 
lines on the theory that the line may be needed to serve future 
generation.\3224\ OMS supports a requirement that transmission 
providers identify beneficiaries of transmission projects before any 
costs are allocated.\3225\
---------------------------------------------------------------------------

    \3223\ Dominion Initial Comments at 42.
    \3224\ Ohio Consumers Initial Comments at 19.
    \3225\ OMS Initial Comments at 9.
---------------------------------------------------------------------------

    1517. Acadia Center and CLF state that the Commission should expand 
its cost allocation proposals to encompass interregional transmission 
planning and the generator interconnection processes.\3226\
---------------------------------------------------------------------------

    \3226\ Acadia Center and CLF Initial Comments at 17.
---------------------------------------------------------------------------

    1518. Some commenters stress the importance of cost containment 
oversight by the Commission. Joint Commenters support a cost management 
framework overseen by the Commission ensuring that the costs and 
benefits on which transmission projects are initially approved for cost 
allocation remain within initially contemplated parameters.\3227\ State 
Water Contractors assert that the need for cost containment is acute 
for consumers in California, asserting that the CAISO high voltage 
transmission access charge has increased nearly 136% over the last 
decade. State Water Contractors argue that as increases in transmission 
costs have a direct impact on the cost of water delivery and treatment 
and given that water and energy are particularly intertwined in 
California, cost containment and regional flexibility are essential 
components to the justness and reasonableness of any final order.\3228\
---------------------------------------------------------------------------

    \3227\ Joint Commenters Reply Comments at 1.
    \3228\ State Water Contractors Reply Comments at 2-3.
---------------------------------------------------------------------------

    1519. Ohio Consumers state that the Commission should require that 
the transmission providers implementing any Long-Term Regional 
Transmission Planning requirements give appropriate consideration to 
public grants and other external sources of funding in any cost 
allocation processes, adding that transmission providers should first 
seek public grants prior to charging customers, because infrastructure 
funds must be accounted for, or else they would distort cost allocation 
processes.\3229\
---------------------------------------------------------------------------

    \3229\ Ohio Consumers Reply Comments at 15 (citing 
Infrastructure Investment and Jobs Act of 2021, Public Law 117-58, 
135 Stat 429).
---------------------------------------------------------------------------

    1520. NextEra renews its request for the Commission to initiate a 
new rulemaking to prohibit regional allocation of the costs of 
transmission projects developed pursuant to an incumbent transmission 
owner's exercise of state right-of-first-refusal rights and require the 
direct assignment of such costs to customers in the incumbent 
transmission owner's zone.\3230\
---------------------------------------------------------------------------

    \3230\ NextEra Reply Comments at 26.
---------------------------------------------------------------------------

2. Commission Determination
    1521. We decline to adopt a particular time frame for determining 
the cost allocation for a Long-Term Regional Transmission Facility, as 
requested by Dominion, Ohio Consumers, and OMS. We believe that 
imposing a standardized time frame to determine cost allocation is 
unnecessary and could impede the regional flexibility that we provide 
to transmission providers under this final order. However, as discussed 
above in the Long-Term Regional Transmission Facility Cost Allocation 
Compliance with the Existing Six Regional Cost Allocation Principles 
section, if only a Long-Term Regional Transmission Cost Allocation 
Method is available for a particular Long-Term Regional Transmission 
Facility (or portfolio of such Facilities), the determination of the 
applicable cost allocation must occur by or before its selection.
    1522. We find Acadia Center and CLF's assertion that the Commission 
should expand its cost allocation proposals to encompass interregional 
transmission planning and the generator interconnection processes to be 
outside the scope of this proceeding, as is NextEra's request for the 
Commission to initiate a new rulemaking to prohibit regional allocation 
of the costs of transmission projects developed pursuant to an 
incumbent transmission owner's exercise of a state right of first 
refusal and require the direct assignment of such costs to customers in 
the incumbent transmission owner's zone. These suggestions are beyond 
the scope of the Commission's NOPR proposals and we believe that the 
record

[[Page 49513]]

in this proceeding is insufficient to proceed with them.
    1523. We also find outside the scope of this proceeding various 
commenters' statements regarding cost containment. We note that the 
Commission is examining issues related to transmission planning and 
cost containment in other proceedings.\3231\
---------------------------------------------------------------------------

    \3231\ See, e.g., Supplemental Notice of Technical Conference, 
Transmission Planning and Cost Management, Docket No. AD22-8-000 
(Oct. 4, 2022).
---------------------------------------------------------------------------

VII. Construction Work in Progress Incentive

A. NOPR Proposal

    1524. In the NOPR, the Commission proposed to not permit 
transmission providers to take advantage of the allowance for inclusion 
of 100% of Construction Work In Progress (CWIP) costs in rate base 
(CWIP Incentive) for Long-Term Regional Transmission Facilities.\3232\ 
The Commission noted that transmission providers may still accrue 
carrying costs incurred during the pre-construction or construction 
phase as Allowance for Funds Used During Construction (AFUDC) and only 
recover those costs from customers after the project is in service, in 
accordance with generally accepted utility accounting principles for 
AFUDC.\3233\ The Commission explained that this proposal would not 
affect Commission policy and regulations established before Order No. 
679.\3234\
---------------------------------------------------------------------------

    \3232\ NOPR, 179 FERC ] 61,028 at PP 328-329 n.522-523, 525-527 
(citing Order No. 679, 71 FR 43294 (July 31, 2006), 116 FERC ] 
61,057 at PP 9, 116-117, n.70). The Commission stated that the 
Commission has also provided that any public utility engaged in the 
sale of electric power for resale can file to include in rate base 
up to 50% of CWIP, subject to limitations. Construction Work in 
Progress for Pub. Utils.; Inclusion of Costs in Rate Base, Order No. 
298, 48 FR 24323 (June 1, 1983), FERC Stats. & Regs. ] 30,455 (1983) 
(cross-referenced at 23 FERC ] 61,224), order on reh'g, 25 FERC ] 
61,023 (1983). NOPR, 179 FERC ] 61,028 at P 329 n.524.
    \3233\ NOPR, 179 FERC ] 61,028 at P 333.
    \3234\ Id. P 333 n.530. There, the Commission stated that public 
utility transmission providers would still be allowed to request 50% 
CWIP in rate base, as is permitted pursuant to 18 CFR 35.25(c)(3), 
subject to an FPA section 205 filing detailing how the request meets 
the requirements of Order No. 298. The Commission believed that the 
ability to include 50% CWIP in rate base, if requested and granted, 
reflects a more reasonable sharing of risks and benefits than the 
CWIP Incentive for Long-Term Regional Transmission Facilities given 
the greater uncertainty inherent in Long-Term Regional Transmission 
Planning, as proposed in this NOPR.
---------------------------------------------------------------------------

B. Comments

1. Interest in the NOPR Proposal
    1525. Many commenters support the Commission's NOPR proposal to 
prohibit Long-Term Regional Transmission Facilities from being eligible 
for the CWIP Incentive and generally support permitting cost recovery 
instead through AFUDC, agreeing that extending the CWIP Incentive to 
Long-Term Regional Transmission Facilities would expose ratepayers to 
risks and cost burdens by requiring them to pay for Long-Term Regional 
Transmission Facilities that receive the incentive prior to those 
facilities being placed into service.\3235\
---------------------------------------------------------------------------

    \3235\ American Municipal Power Initial Comments at 34; APPA 
Initial Comments at 6, 46-47; California Commission Initial Comments 
at 58; California Water Initial Comments at 19-20; Clean Energy 
Buyers Initial Comments at 30-31; ELCON Initial Comments at 19; 
Industrial Customers Initial Comments at 24-26; Joint Consumer 
Advocates Initial Comments at 14; Kentucky Commission Chair Chandler 
Initial Comments at 4; Large Public Power Initial Comments at 41-42; 
Louisiana Commission Initial Comments at 36; Massachusetts Attorney 
General Initial Comments at 23; NARUC Initial Comments at 54-55; 
NASUCA Initial Comments at 8-9; NESCOE Initial Comments at 73; 
Nevada Commission Initial Comments at 14; North Carolina Commission 
and Staff Initial Comments at 17-18; NRG Initial Comments at 21-22; 
Ohio Commission Federal Advocate Initial Comments at 15-16; Ohio 
Consumers Initial Comments at 29; Pennsylvania Commission Initial 
Comments at 17; PJM States Initial Comments at 13; Resale Iowa 
Initial Comments at 2, 12-13; Six Cities Initial Comments at 11; 
State Agencies Initial Comments at 24; TAPS Initial Comments at 5, 
27-29; Transmission Dependent Utilities Initial Comments at 2-4; 
Virginia Attorney General Initial Comments at 4-6.
---------------------------------------------------------------------------

    1526. California Commission and New England Systems argue that 
there is no evidence that any of the incentives established under FPA 
section 219, including the CWIP Incentive, have spurred investment in 
transmission infrastructure.\3236\ California Commission argues that 
there was a great need to develop new transmission to bolster 
reliability and alleviate congestion when the CWIP Incentive was first 
introduced in Order No. 679, but that the prior decline in transmission 
investment has since been reversed.\3237\ Further, California 
Commission argues that an inability to receive the CWIP Incentive would 
not present a barrier to entry for transmission development,\3238\ 
stating that disallowing the CWIP Incentive for Long-Term Regional 
Transmission Facilities would affect incumbent and nonincumbent 
transmission developers equally, and that developers could continue to 
seek the CWIP Incentive for economic and reliability transmission 
projects.\3239\ Louisiana Commission states that if an independent 
transmission developer or utility has won a competitive bidding process 
to construct transmission facilities, that entity should have the 
financial wherewithal to finance the project without a loan from 
ratepayers.\3240\
---------------------------------------------------------------------------

    \3236\ California Commission Reply Comments at 11-12; New 
England Systems Reply Comments at 15-16.
    \3237\ California Commission Reply Comments at 8-10 (citing US 
DOE, National Electric Transmission Congestion Study, at 21(Sept. 
2020), https://www.energy.gov/sites/default/files/2020/10/f79/2020%20Congestion%20Study%20FINAL%2022Sept2020.pdf).
    \3238\ Id. at 19-20 (citing CAISO Initial Comments at 44).
    \3239\ Id.
    \3240\ Louisiana Commission Initial Comments at 36.
---------------------------------------------------------------------------

    1527. Several commenters assert that the CWIP Incentive shifts 
risks to customers.\3241\ Pennsylvania Commission, Large Public Power, 
and Resale Iowa argue that allowing the CWIP Incentive could 
substantially increase the risk of customers paying for transmission 
facilities that are never built and from which they derive no benefit, 
leading to rates that are unjust and unreasonable.\3242\ NARUC, New 
England Systems, and Virginia Attorney General agree with the proposed 
reform because it better aligns risk and reward between shareholders 
and customers with respect to Long-Term Regional Transmission 
Facilities.\3243\
---------------------------------------------------------------------------

    \3241\ California Commission Reply Comments at 14; Large Public 
Power Initial Comments at 41; Louisiana Commission Initial Comments 
at 36; NARUC Initial Comments at 55-56; New England Systems Reply 
Comments at 15; Ohio Commission Federal Advocate Initial Comments at 
16; Pennsylvania Commission Initial Comments at 17; Resale Iowa 
Initial Comments at 12-13; Virginia Attorney General Reply Comments 
at 2.
    \3242\ Large Public Power Initial Comments at 41; Pennsylvania 
Commission Initial Comments at 17; Resale Iowa Initial Comments at 
12-13.
    \3243\ NARUC Initial Comments at 55-56; New England Systems 
Reply Comments at 15 (citing NARUC Initial Comments at 56); Virginia 
Attorney General Reply Comments at 2 (citing NARUC Initial Comments 
at 55).
---------------------------------------------------------------------------

    1528. Several other commenters state that the longer the 
transmission planning horizon, the higher the risk that resulting 
transmission facilities will not be needed, which may result in 
stranded costs.\3244\ For this reason, Industrial Customers state that 
shifting risks from transmission developers to customers is 
particularly problematic for Long-Term Regional Transmission 
Facilities.\3245\ Dominion states that it does not take a position on 
the proposal to prohibit Long-Term Regional Transmission Facilities 
from being eligible for the CWIP Incentive, but nevertheless asserts 
that shifting the risk for long-term transmission projects to 
transmission providers will help ensure that only those long-term 
projects that are ``confidently needed'' will be developed. However, 
for states that may

[[Page 49514]]

allow or require the inclusion of the CWIP Incentive in rate base, 
Dominion states that the Commission should allow for deference to the 
state cost recovery structure.\3246\
---------------------------------------------------------------------------

    \3244\ Clean Energy Buyers Reply Comments at 10-11; Dominion 
Initial Comments at 53-54; Industrial Customers Reply Comments at 9; 
Transmission Dependent Utilities Reply Comments at 4; Virginia 
Attorney General Reply Comments at 3.
    \3245\ Industrial Customers Reply Comments at 9.
    \3246\ Dominion Initial Comments at 53.
---------------------------------------------------------------------------

    1529. Several commenters suggest that such reform may mitigate 
certain risks of the transmission provider over-building the 
system.\3247\ For example, Massachusetts Attorney General and North 
Dakota Commission state that the Commission's proposed limit on the 
CWIP Incentive would provide ratepayers greater protection from 
financing inefficient or over-built regional transmission 
projects.\3248\ New England Systems argue that entities in favor of 
continuing the CWIP Incentive gain financially from the 
incentive.\3249\ Industrial Customers state that the alleged benefits 
of the CWIP Incentive to customers are tenuous at best.\3250\
---------------------------------------------------------------------------

    \3247\ Massachusetts Attorney General Initial Comments at 24-25; 
North Carolina Commission and Staff Initial Comments at 18; North 
Dakota Commission Initial Comments at 6; Pennsylvania Commission 
Initial Comments at 17-18; PJM States Initial Comments at 13; US 
Climate Alliance Initial Comments at 2.
    \3248\ Massachusetts Attorney General Initial Comments at 24-25; 
North Dakota Commission Initial Comments at 6.
    \3249\ New England Systems Reply Comments at 15-16 (citing 
Avangrid Initial Comments at 26).
    \3250\ Industrial Customers Reply Comments at 9-10.
---------------------------------------------------------------------------

    1530. Multiple commenters suggest that prohibiting Long-Term 
Regional Transmission Facilities from being eligible for the CWIP 
Incentive may improve the planning and building of new transmission 
facilities.\3251\ New England Systems, PJM States, and North Carolina 
Commission and Staff assert that removing the CWIP Incentive will 
appropriately reduce incentives to over-build transmission, which could 
lead to rates being unjust and unreasonable.\3252\ Similarly, US 
Climate Alliance supports prohibiting Long-Term Regional Transmission 
Facilities from being eligible for the CWIP Incentive, as doing so 
would align incentives for transmission providers to deliver 
transmission projects on time and within budget.\3253\
---------------------------------------------------------------------------

    \3251\ North Carolina Commission and Staff Initial Comments at 
18; Pennsylvania Commission Initial Comments at 17; PJM States 
Initial Comments at 13; US Climate Alliance Initial Comments at 2.
    \3252\ New England Systems Reply Comments at 14-15; North 
Carolina Commission and Staff Initial Comments at 18; PJM States 
Initial Comments at 13.
    \3253\ US Climate Alliance Initial Comments at 2.
---------------------------------------------------------------------------

    1531. California Commission argues that money paid earlier as CWIP 
is more valuable than money paid later and that comparisons of savings 
under the CWIP Incentive and under AFUDC are only meaningful if an 
interest adjustment is made to account for the time in which payments 
are made.\3254\ Industrial Customers explain that, to customers, the 
difference between the AFUDC and CWIP approaches is primarily the time 
value of money.\3255\ Kentucky Commission Chair Chandler, NASUCA, and 
California Commission express concern that today's ratepayers are 
forced to pay for tomorrow's transmission projects, which they refer to 
as intergenerational inequity, and they are especially concerned if a 
project will not provide service until a much later date.\3256\
---------------------------------------------------------------------------

    \3254\ California Commission Reply Comments at 13.
    \3255\ Industrial Customers Reply Comments at 9.
    \3256\ Kentucky Commission Chair Chandler Initial Comments at 8; 
NASUCA Initial Comments at 9; California Commission Reply Comments 
at 17 (citing NASUCA Initial Comments at 9).
---------------------------------------------------------------------------

2. Concerns With the NOPR Proposal

    1532. Many commenters oppose the NOPR proposal to prohibit Long-
Term Regional Transmission Facilities from being eligible for the CWIP 
Incentive.\3257\ Several commenters cite the Commission's findings in 
Order No. 679 explaining that the CWIP Incentive can help remove a 
disincentive to construct new transmission infrastructure, which can 
involve very long lead times and considerable risk to the utility that 
the project may not go forward.\3258\ National Grid and Avangrid, for 
example, argue that Long-Term Regional Transmission Facilities will 
likely have very long lead times and place even greater risk on 
transmission providers relative to transmission facilities planned and 
developed on a more typical timeframe.\3259\ Similarly, WIRES argues 
that the rationale underlying the CWIP Incentive remains valid 
today.\3260\
---------------------------------------------------------------------------

    \3257\ AEP Initial Comments at 38-40; Ameren Initial Comments at 
48-51; Avangrid Initial Comments at 24-28; CAISO Initial Comments at 
43-45; Consumer Organizations Initial Comments at 7-10; Duke Initial 
Comments at 44-45; Duquesne Light Initial Comments at 2-6; EEI 
Initial Comments at 42-45; EEI Reply Comments at 17-18; Entergy 
Initial Comments at 35-37; Eversource Initial Comments at 31-35; 
Eversource Reply Comments at 2; Harvard ELI Initial Comments at 7-
10; Indicated PJM TOs Initial Comments at 26-28; MISO TOs Initial 
Comments at 65-66; National Grid Initial Comments at 27-30; New York 
TOs Initial Comments at 23-24; New York Transco Initial Comments at 
13-16; Pattern Energy Initial Comments at 34-36; PG&E Initial 
Comments at 18-20; PPL Initial Comments at 29-30; SoCal Edison 
Initial Comments at 13-14; Transource Initial Comments at 3; WIRES 
Initial Comments at 17-19.
    \3258\ Ameren Initial Comments at 49; EEI Initial Comments at 
42-43; EEI Reply Comments at 17-18; Eversource Reply Comments at 2; 
MISO TOs Initial Comments at 66; National Grid Initial Comments at 
28-29; WIRES Initial Comments at 17-18 (all citing Order No. 679, 
116 FERC ] 61,057 at P 115).
    \3259\ Avangrid Reply Comments at 6-7; National Grid Initial 
Comments at 28-29.
    \3260\ WIRES Initial Comments at 17-18.
---------------------------------------------------------------------------

    1533. Some commenters also cite the Commission's 2012 Transmission 
Incentive Policy Statement as support for the CWIP Incentive as a risk-
reducing mechanism to transmission providers, which these commenters 
state can increase credit ratings and lower capital costs.\3261\ In 
addition, several commenters reference Commission findings in numerous 
prior incentive proceedings where the Commission has affirmed the 
benefits that the CWIP Incentive provides to customers and transmission 
providers, attesting that the NOPR proposal is in direct opposition to 
such findings.\3262\
---------------------------------------------------------------------------

    \3261\ Ameren Initial Comments at 49; EEI Initial Comments at 
42; Eversource Initial Comments at 32 (all citing Promoting 
Transmission Investment Through Pricing Reform, Policy Statement, 
141 FERC ] 61,129, at P 12 (2012)).
    \3262\ AEP Initial Comments at 38 (citing Ne. Utils. Serv. Co. & 
Nat'l Grid USA, 125 FERC ] 61,183, at P 89 (2008)); Ameren Initial 
Comments at 49 (citing United Illuminating, 119 FERC ] 61,182, at P 
63 (2007)); Duquesne Light Initial Comments at 3 (citing Xcel Energy 
Servs., Inc., 121 FERC ] 61,284, at P 58 (2007); Am. Elec. Power 
Service Corp., 116 FERC ] 61,059, at P 3 (2006)); EEI Initial 
Comments at 44 (citing PPL Elec. Utils. Corp., 123 FERC ] 61,068, at 
PP 42-43 (2008), reh'g denied, 124 FERC ] 61,229 (2008)); National 
Grid Initial Comments at 29 (citing Tucson Elec. Power Co., 174 FERC 
] 61,223, at P 25 (2021); S. Cal. Edison Co., 172 FERC ] 61,241, at 
P 31 (2020); United Illuminating Co., 167 FERC ] 61,126, at P 36 
(2019)); MISO TOs Initial Comments at 66-67 (citing PJM 
Interconnection, L.L.C., 135 FERC ] 61,229, at P 78 (2011); Duquesne 
Light Co., 166 FERC ] 61,074, at P 32 (2019); United Illuminating, 
Co., 167 FERC ] 61,126 at P 36; GridLiance W. Transco LLC, 164 FERC 
] 61,049, at P 25 (2018); NextEra Energy Transmission N.Y., Inc., 
162 FERC ] 61,196, at P 64 (2018); PJM Interconnection, L.L.C., 158 
FERC ] 61,089, at P 33 (2017); Duquesne Light Co., 179 FERC ] 
61,218, at P 17 (2022)); New York TOs Initial Comments at 23 (citing 
Okla. Gas & Elec. Co., 133 FERC ] 61,274, at P 48 (2010); Pepco 
Holdings, Inc., 125 FERC ] 61,130, at P 63 (2008)).
---------------------------------------------------------------------------

    1534. Some commenters assert that the NOPR proposal runs counter to 
obligations established in the Energy Policy Act of 2005 and FPA 
section 219 to facilitate capital investment in transmission 
infrastructure and would likely impede the development of regional 
transmission facilities identified to meet changes in the resource mix 
and demand.\3263\
---------------------------------------------------------------------------

    \3263\ Ameren Initial Comments at 48; CAISO Initial Comments at 
43-44; EEI Initial Comments at 42-43; Indicated PJM TOs Initial 
Comments at 26-28; MISO TOs Initial Comments at 71-72; National Grid 
Initial Comments at 28; PPL Initial Comments at 29-30; WIRES Initial 
Comments at 17-18.
---------------------------------------------------------------------------

    1535. Numerous commenters argue that the proposal runs counter to 
the objectives of the NOPR that seek to encourage the development and 
completion of regional transmission facilities needed to address 
changes in

[[Page 49515]]

the resource mix or demand over a longer time horizon.\3264\ For 
example, CAISO, MISO TOs, and Avangrid suggest that it is 
counterintuitive for the Commission to acknowledge a lack of regional 
transmission facilities in the NOPR, yet propose to undo the most 
reasonable tool that aids cash flow and reduces uncertainty associated 
with building those facilities.\3265\ Certain commenters state that the 
CWIP Incentive assists with getting needed transmission projects 
built.\3266\ AEP and Avangrid state that the CWIP Incentive is 
particularly well-suited to incentivizing the type of large, regional 
transmission projects that the Commission hopes to increase through the 
NOPR, which often present higher costs, longer lead times, an increase 
in possible rate shock, and present cash flow difficulties.\3267\
---------------------------------------------------------------------------

    \3264\ AEP Initial Comments at 39; Ameren Initial Comments at 
50-51; Avangrid Initial Comments at 25; Avangrid Reply Comments at 
6-8; Eversource Initial Comments at 2, 31-32; MISO TOs Initial 
Comments at 70-76; Pattern Energy Initial Comments at 35-36; PG&E 
Initial Comments at 18-19.
    \3265\ Avangrid Reply Comments at 7 (citing CAISO Initial 
Comments at 45; MISO TOs Initial Comments at 71-72, 74-75); CAISO 
Initial Comments at 45; MISO TOs Initial Comments at 74-76 (citing 
NOPR, 179 FERC ] 61,028 at PP 1, 9, 25, 35, 47, 330-331).
    \3266\ AEP Initial Comments at 39; Ameren Initial Comments at 
50; Avangrid Initial Comments at 26; MISO TOs Initial Comments at 
69.
    \3267\ AEP Initial Comments at 39; Avangrid Reply Comments at 
10.
---------------------------------------------------------------------------

    1536. Several commenters point to cash flow benefits enabled 
through the CWIP Incentive and associated benefits to customers.\3268\ 
For example, New York TOs and PG&E contend that the cash flow benefits 
from the CWIP Incentive allow a utility to reduce the need for external 
financing and instead allocate capital to other projects that benefit 
additional ratepayers.\3269\
---------------------------------------------------------------------------

    \3268\ AEP Initial Comments at 38-39; Ameren Initial Comments at 
49; Avangrid Initial Comments at 25; EEI Initial Comments at 44-45; 
EEI Reply Comments at 17; Entergy Initial Comments at 37; Eversource 
Initial Comments at 31; Indicated PJM TOs Initial Comments at 26-28; 
MISO TOs Initial Comments at 66-67, 71, 74-76; National Grid Initial 
Comments at 28-29; New York TOs Initial Comments at 23-24; New York 
Transco Initial Comments at 13; Pattern Energy Initial Comments at 
35; PG&E Initial Comments at 19; Transource Initial Comments at 3; 
WIRES Initial Comments at 17-18.
    \3269\ New York TOs Initial Comments at 23-24; PG&E Initial 
Comments at 19.
---------------------------------------------------------------------------

    1537. Several commenters contend that the Commission has failed to 
adequately justify the NOPR proposal, asserting that the rationale is 
weak or arguing that the Commission has not shown that its existing 
policy is unjust and unreasonable.\3270\ MISO TOs argue that the 
Commission's claim that ratepayers do not receive benefits from the 
regional transmission facilities during the construction period is 
unsupported by precedent or analysis and is contrary to longstanding 
Commission policy. Further, they observe that a transmission facility 
cannot be developed and placed into service overnight, so artificially 
dividing up the customer benefits to pre-operation and post-operation 
ignores the realities of transmission development.\3271\ Where the 
proposal identified that additional ratepayer protections may be 
necessary to balance customers' interest in just and reasonable rates 
against investors' interest in earning a return on invested capital or 
mitigating against over-investment in regional transmission facilities, 
MISO TOs reiterate that the CWIP Incentive's benefits promote just and 
reasonable rates by providing incentives encouraging transmission 
construction consistent with the Commission's FPA mandate and assert 
that an investor's rate of return is set in unrelated 
proceedings.\3272\
---------------------------------------------------------------------------

    \3270\ Ameren Initial Comments at 50-51; Duke Initial Comments 
at 44-45; Duquesne Light Initial Comments at 2-3; EEI Initial 
Comments at 44-45; Eversource Initial Comments at 33-34; MISO TOs 
Initial Comments at 66-67 (citing NOPR, 179 FERC ] 61,028 at P 331); 
Pattern Energy Initial Comments at 35.
    \3271\ MISO TOs Initial Comments at 69 (citing NOPR, 179 FERC ] 
61,028 at P 331).
    \3272\ Id. at 72-73 (citing NOPR, 179 FERC ] 61,028 at P 331).
---------------------------------------------------------------------------

    1538. Pattern Energy states that the Commission has provided no 
policy justification or factual basis to distinguish the risk incurred 
during the planning phase from other risk factors, such as size, scope, 
or cost, which it asserts is a departure from the Order No. 679 policy 
on the CWIP Incentive.\3273\
---------------------------------------------------------------------------

    \3273\ Pattern Energy Initial Comments at 35.
---------------------------------------------------------------------------

    1539. Many commenters also argue that, while the NOPR proposal to 
prohibit Long-Term Regional Transmission Facilities from being eligible 
for the CWIP Incentive is intended to mitigate shifting too much risk 
to customers, the proposal ignores many of the benefits that the 
current CWIP Incentive policy providers to customers.\3274\ EEI argues 
that commenters that support the proposal also fail to recognize these 
benefits and the important role that this incentive serves in 
facilitating new transmission investment.\3275\ Many commenters that 
oppose the NOPR proposal tout such benefits, such as improved cash flow 
and the ability for transmission providers to secure better financing 
through higher credit ratings, resulting in lower interest expense 
costs that benefit customers.\3276\ Consumer Organizations and 
Eversource contend that carrying a significant amount of debt in AFUDC 
rather than being recovered through the CWIP Incentive can result in 
lower credit ratings and higher capital costs, which are passed through 
to customers, and assert that ``with AFUDC, consumers are likely to pay 
more in the long run.'' \3277\
---------------------------------------------------------------------------

    \3274\ AEP Initial Comments at 38-39; Ameren Initial Comments at 
48-51; Avangrid Initial Comments at 27-28; Duke Initial Comments at 
45; Duquesne Light Initial Comments at 3-5; EEI Initial Comments at 
44-45; EEI Reply Comments at 18; Eversource Initial Comments at 31-
34; Indicated PJM TOs Initial Comments at 26; MISO TOs Initial 
Comments at 66-76; National Grid Initial Comments at 29; New York 
TOs Initial Comments at 23-24; New York Transco Initial Comments at 
13-14; PG&E Initial Comments at 19-20; SoCal Edison Initial Comments 
at 3, 13-14; WIRES Initial Comments at 18-19.
    \3275\ EEI Reply Comments at 18 (citing NASUCA Initial Comments 
at 8-9; Transmission Dependent Utilities Initial Comments at 2-4).
    \3276\ Ameren Initial Comments at 42, 50; Avangrid Initial 
Comments at 27; Duke Initial Comments at 45; Duquesne Light Initial 
Comments at 4-6; EEI Initial Comments at 44-45; MISO TOs Initial 
Comments at 66-67; PG&E Initial Comments at 19.
    \3277\ Consumer Organizations Initial Comments at 7-8; 
Eversource Reply Comments at 4 (quoting Consumer Organizations 
Initial Comments at 7).
---------------------------------------------------------------------------

    1540. Some commenters state that the CWIP Incentive helps to avoid 
rate shock and provides other cost savings relative to AFUDC.\3278\ 
Avangrid states that arguments about the sharing of risk between 
utilities and customers that the Commission used to support the NOPR 
proposal fail to consider the budgeting risk to customers under the 
AFUDC approach, and claims that these arguments ignore the benefit of 
price stability.\3279\
---------------------------------------------------------------------------

    \3278\ AEP Initial Comments at 38-39; Ameren Initial Comments at 
50; Avangrid Initial Comments at 27-28; Avangrid Reply Comments at 
10 (citing Kentucky Commission Chair Chandler Initial Comments at 4-
9); Consumer Organizations Initial Comments at 7-10; Duquesne Light 
Initial Comments at 4; EEI Initial Comments at 44; EEI Reply 
Comments at 17-18; Eversource Initial Comments at 31-32; Eversource 
Reply Comments at 4-5; Indicated PJM TOs Initial Comments at 26; 
MISO TOs Initial Comments at 66-76; National Grid Initial Comments 
at 28-29; New York TOs Initial Comments at 23-24; PG&E Initial 
Comments at 19; PG&E Reply Comments at 13-14; SoCal Edison Initial 
Comments at 13-14; WIRES Initial Comments at 19.
    \3279\ Avangrid Reply Comments at 10 (citing Kentucky Commission 
Chair Chandler Initial Comments at 4-9).
---------------------------------------------------------------------------

    1541. Several commenters state that the Commission can take more 
targeted action to address concerns of uncertainty in Long-Term 
Regional Transmission Planning rather than prohibiting Long-Term 
Regional Transmission Facilities from being eligible for the CWIP 
Incentive, for instance, by ensuring sufficiently robust selection 
criteria, project review, and

[[Page 49516]]

approval processes.\3280\ CAISO contends that these measures are more 
appropriate ways to account for the root cause of the risk of over-
building and to ensure that customers are protected from the costs of 
transmission facilities that may be less certain.\3281\ R Street states 
that the NOPR's proposal to remove the CWIP Incentive by itself will 
not thwart increasing transmission costs, and the Commission must 
recognize preserving and expanding competition as a way to contain 
costs.\3282\
---------------------------------------------------------------------------

    \3280\ Avangrid Reply Comments at 8 (citing CAISO Initial 
Comments at 45); CAISO Initial Comments at 45; EEI Reply Comments at 
18; PG&E Reply Comments at 13-14.
    \3281\ CAISO Initial Comments at 6-7, 45.
    \3282\ R Street Reply Comments at 2.
---------------------------------------------------------------------------

    1542. Eversource and New York Transco assert that case-by-case 
evaluation for any request for transmission incentives, including the 
CWIP Incentive, affords interested parties the opportunity to intervene 
and provide comments, culminating in a Commission determination of 
whether the incentive is just and reasonable, thereby protecting 
customer interests.\3283\
---------------------------------------------------------------------------

    \3283\ Eversource Reply Comments at 4-5; New York Transco Reply 
Comments at 7-8.
---------------------------------------------------------------------------

    1543. Eversource, Harvard ELI, and National Grid state that it 
would be best to make changes in incentives policy in a comprehensive 
transmission incentives rulemaking instead of in this final 
order.\3284\ Eversource and National Grid argue that, at a minimum, the 
Commission should defer a decision on the CWIP Incentive to the 
rulemaking proceeding on transmission incentives in Docket No. RM20-10-
000, where the Commission has already established a full and complete 
record.\3285\ Harvard ELI suggests that any action on the CWIP 
Incentive be deferred to another proceeding to develop a holistic 
package of incentives, penalties, and oversight mechanisms after the 
Commission has established the full goals and procedural rules for 
Long-Term Regional Transmission Planning.\3286\
---------------------------------------------------------------------------

    \3284\ Eversource Initial Comments at 33; Harvard ELI Initial 
Comments at 4-5, 7-8, 10; National Grid Initial Comments at 27.
    \3285\ Eversource Initial Comments at 33; National Grid Initial 
Comments at 27.
    \3286\ Harvard ELI Initial Comments at 4-5, 7-8, 10.
---------------------------------------------------------------------------

    1544. Certain commenters raise concerns of unintended consequences 
of the proposal. CAISO and Transource state that new transmission 
developers may be disadvantaged if the Commission prohibits Long-Term 
Regional Transmission Facilities from being eligible for the CWIP 
Incentive.\3287\ Specifically, CAISO notes that the Commission approved 
a provision in its OATT that permits a nonincumbent transmission 
developer within CAISO to recover Commission-authorized transmission 
revenue requirements associated with transmission projects under 
construction before the facilities are turned over to CAISO operational 
control, which CAISO contends is a way that it addresses barriers to 
transmission development by nonincumbent transmission developers.\3288\ 
CAISO contends that the Commission should not preclude transmission 
developers from using the CWIP Incentive for Long-Term Regional 
Transmission Facilities, especially because the Commission would 
continue to allow the CWIP Incentive for reliability and economic 
transmission projects.\3289\
---------------------------------------------------------------------------

    \3287\ CAISO Initial Comments at 43-45; Transource Initial 
Comments at 3.
    \3288\ CAISO Initial Comments at 43-44 (citing Cal. Indep. Sys. 
Operator Corp., 146 FERC ] 61,237 (2014)).
    \3289\ Id. at 44-45.
---------------------------------------------------------------------------

3. Interaction of the CWIP Incentive With the Abandoned Plant Incentive
    1545. Many commenters raise concerns with the interaction between 
the CWIP Incentive and the transmission incentive that allows 
applicants to request 100% of prudently-incurred costs associated with 
abandoned transmission projects be included in transmission rates if 
such abandonment is outside the control of management (Abandoned Plant 
Incentive).\3290\ APPA, California Commission, Industrial Customers, 
NARUC, and Virginia Attorney General suggest that unless and until the 
Commission reconsiders the Abandoned Plant Incentive, customers will 
continue to face risks associated with Long-Term Regional Transmission 
Facilities.\3291\ Specifically, APPA states that the proposal to 
prohibit Long-Term Regional Transmission Facilities from being eligible 
for the CWIP Incentive will not necessarily protect customers from the 
costs of potentially unneeded facilities identified through Long-Term 
Regional Transmission Planning, given the Commission's policies on 
recovery of abandoned plant costs (including the Abandoned Plant 
Incentive under Order No. 679).\3292\ Similarly, NARUC, Virginia 
Attorney General, and Industrial Customers request that the Commission 
review the current abandoned plant policy to ensure that customer 
benefits from the adoption of the NOPR proposal with respect to the 
CWIP Incentive do not disappear if those costs are still recovered from 
customers as abandoned plant.\3293\
---------------------------------------------------------------------------

    \3290\ Order No. 679, 116 FERC ] 61,057 at P 163.
    \3291\ APPA Initial Comments at 46-47; California Commission 
Reply Comments at 19 (citing Industrial Customers Initial Comments 
at 27); Industrial Customers Initial Comments at 24-27; Industrial 
Customers Reply Comments at 9; NARUC Initial Comments at 55; 
Virginia Attorney General Initial Comments at 6-7; Virginia Attorney 
General Reply Comments at 5-6.
    \3292\ APPA Initial Comments at 46-47.
    \3293\ Industrial Customers Reply Comments at 10 (citing MISO 
States Initial Comments at 14; NARUC Initial Comments at 55); NARUC 
Initial Comments at 55; Virginia Attorney General Reply Comments at 
5 (citing NARUC Initial Comments at 55).
---------------------------------------------------------------------------

    1546. Industrial Customers suggest that, without additional reforms 
limiting the recovery of abandoned plant costs, customers will continue 
to face the possibility of paying for transmission that is never 
built.\3294\ Further, Industrial Customers and California Commission 
state that AFUDC could be a superior approach for customers, but only 
in a final order that adopts certain protections to ensure that 
customers do not pay for abandoned plant costs.\3295\ Industrial 
Customers argue that the Commission should adopt customer safeguards 
for transmission projects that are abandoned, including a more thorough 
review of whether costs were prudently incurred prior to 
abandonment.\3296\
---------------------------------------------------------------------------

    \3294\ Industrial Customers Initial Comments at 25-26.
    \3295\ California Commission Reply Comments at 19 (citing 
Industrial Customers Initial Comments at 27); Industrial Customers 
Initial Comments at 26-27.
    \3296\ Industrial Customers Reply Comments at 9.
---------------------------------------------------------------------------

C. Commission Determination
    1547. We decline to act at this time to finalize the NOPR proposal 
to limit the availability of the CWIP Incentive for Long-Term Regional 
Transmission Facilities. We agree with commenters \3297\ that any 
action on the CWIP Incentive is more appropriately considered in a 
separate proceeding to allow for a holistic approach to transmission 
incentives after the Commission has finalized its Long-Term Regional 
Transmission Planning reforms. In particular, we conclude that whether 
the Commission's transmission incentives are appropriately 
``benefitting consumers by ensuring reliability and reducing the cost 
of delivered power'' \3298\ is a question better evaluated by 
considering the Commission's transmission incentives comprehensively 
for all regional transmission facilities.
---------------------------------------------------------------------------

    \3297\ Eversource Initial Comments at 33; Harvard ELI Initial 
Comments at 4-5, 7-8, 10; National Grid Initial Comments at 27.
    \3298\ 16 U.S.C. 824s(a).

---------------------------------------------------------------------------

[[Page 49517]]

VIII. Exercise of a Federal Right of First Refusal in Commission-
Jurisdictional Tariffs and Agreements

A. NOPR Proposal

    1548. In the NOPR, the Commission proposed to use the discretion 
afforded by FPA section 309 to amend Order No. 1000's findings and 
nonincumbent transmission developer reforms in part, so as to permit 
the exercise of Federal rights of first refusal for selected 
transmission facilities, conditioned on the incumbent transmission 
provider with the Federal right of first refusal for such regional 
transmission facilities establishing joint ownership of the 
transmission facilities consistent with certain proposed requirements 
described in the NOPR.\3299\ The Commission reasoned that given the 
investment trends observed since Order No. 1000's implementation, it is 
possible that the Commission's Order No. 1000 nonincumbent transmission 
developer reforms may be inadvertently discouraging investment in and 
development of regional transmission facilities to some extent.\3300\ 
Specifically, the Commission posited that incumbent transmission 
providers, as a result of those reforms, may be presented with perverse 
investment incentives that do not adequately encourage those incumbent 
transmission providers to develop and advocate for transmission 
facilities that benefit more than just their own local retail 
distribution service territory or footprint.\3301\
---------------------------------------------------------------------------

    \3299\ See NOPR, 179 FERC ] 61,028 at P 351.
    \3300\ Id. P 350.
    \3301\ Id.
---------------------------------------------------------------------------

    1549. The Commission preliminarily found that, while the 
unconditional exercise of Federal rights of first refusal for entirely 
new selected transmission facilities remains unjust and unreasonable, 
Order No. 1000's remedy--requiring the elimination of all Federal 
rights of first refusal for entirely new selected transmission 
facilities--was overly broad.\3302\ The Commission further 
preliminarily found that, while Order No. 1000's reforms have a sound 
theoretical basis, the remedy prescribed by Order No. 1000 failed to 
recognize that some of the expected benefits from the competitive 
transmission development processes could be achieved or at least 
reasonably approximated through other means.\3303\
---------------------------------------------------------------------------

    \3302\ Id. PP 351-352, 354.
    \3303\ Id. P 353.
---------------------------------------------------------------------------

    1550. Accordingly, the Commission proposed to allow transmission 
providers to propose, pursuant to FPA section 205, new Federal rights 
of first refusal for incumbent transmission providers, conditioned on 
the incumbent transmission provider with the Federal right of first 
refusal for such regional transmission facilities establishing joint 
ownership of the transmission facilities consistent with certain 
requirements described in the NOPR.\3304\ The Commission asserted that 
if the NOPR proposal was adopted, Order No. 1000's findings and 
mandates would be amended such that joint ownership conditions would 
presumptively be found to ensure just and reasonable Commission-
jurisdictional rates and limit opportunities for undue discrimination 
by transmission providers, if imposed upon the exercise of an incumbent 
transmission provider's Federal right of first refusal for selected 
transmission facilities.
---------------------------------------------------------------------------

    \3304\ Id. P 354.
---------------------------------------------------------------------------

    1551. The Commission explained that an incumbent transmission 
provider could establish qualifying joint ownership with unaffiliated 
nonincumbent transmission developers as defined in Order No. 1000, or 
another unaffiliated entity, including another incumbent transmission 
provider.\3305\ However, the Commission also proposed that to qualify 
for the presumption, incumbent transmission providers with a 
conditional Federal right of first refusal would not be allowed to 
structure joint-ownership arrangements such that unaffiliated entities 
were offered less than a meaningful level of participation and 
investment in the proposed regional transmission facility.\3306\ The 
Commission further explained that an incumbent transmission provider's 
conditional Federal right of first refusal should not significantly 
delay the regional transmission planning process or result in prolonged 
uncertainty regarding which transmission facilities will (or, 
alternatively, will not) be subject to competitive transmission 
development processes.\3307\
---------------------------------------------------------------------------

    \3305\ Id. P 365.
    \3306\ Id. P 371.
    \3307\ Id. P 366.
---------------------------------------------------------------------------

    1552. The Commission noted that proposals for jointly owned 
regional transmission facilities would still need to be evaluated by 
transmission providers in the transmission planning region and would 
not be exempt from selection requirements. However, the Commission also 
explained that the evaluation process for such jointly owned regional 
transmission facility proposals would not involve running the region's 
competitive transmission development process.\3308\
---------------------------------------------------------------------------

    \3308\ Id. P 370.
---------------------------------------------------------------------------

B. Comments

1. General Perspectives and Approach To Reform
    1553. Commenters share a variety of perspectives on the track 
record of competitive transmission development processes, the wisdom of 
the nonincumbent transmission developer reforms adopted in Order No. 
1000, and the steps they believe the Commission should take in response 
to the concerns identified in the NOPR. Several state entities, 
customer-affiliated groups, and nonincumbent transmission developers, 
such as LS Power, NextEra, and the US DOJ and FTC, defend competitive 
transmission development processes as beneficial and argue for their 
expansion.\3309\ Some US Senators agree, arguing that allowing for a 
conditional Federal right of first refusal would be anti-competitive, 
could hinder development of new transmission, and could cause excessive 
costs to consumers.\3310\ On the other hand, representatives of 
incumbent transmission providers and others (e.g., EEI, WIRES, DATA, 
the MISO TOs) critique such processes and many call for the Commission 
to restore unconditional Federal rights of first refusal.\3311\ Each 
side of the debate

[[Page 49518]]

offers consultant reports to substantiate their position, with pro-
competition advocates relying on studies by the Brattle Group (Brattle) 
that present competitive transmission development processes in a 
largely favorable light,\3312\ and advocates for Federal rights of 
first refusal relying on contrasting studies by Concentric Energy 
Advisors (Concentric).\3313\ In general, pro-competition advocates, 
such as LS Power, contend that competitive transmission development 
processes are essential to just and reasonable rates, while 
representatives of incumbent transmission providers counter that just 
and reasonable transmission rates are separately and independently 
ensured by and through FPA section 205 rate proceedings.\3314\
---------------------------------------------------------------------------

    \3309\ See, e.g., American Municipal Power Reply Comments at 3-
4; Anbaric Initial Comments at 4-5; California Commission Initial 
Comments at 100, 103-104; Competition Advocates Supplemental 
Comments at 1-3 & n.17 (citing Jennifer Chen & Devin Hartman, R 
Street Institute, Transmission Reform Strategy from a Customer 
Perspective: Optimizing Net Benefits and Procedural Vehicles (May 
2022), https://www.rstreet.org/research/transmission-reform-strategy-from-a-customer-perspective-optimizing-net-benefits-and-procedural-vehicles); Competition Coalition Initial Comments at 16-22, 68-70; 
LS Power Initial Comments at 38-39, 44; LS Power Partial Reply 
Comments at 20-23; LS Power and NRG Supplemental Comments at 38-39; 
NextEra Initial Comments at 18-19, 24-27, 29; Ohio Consumers Reply 
Comments at 16-18; Resale Iowa Reply Comments at 5-6; US DOJ and FTC 
Initial Comments at 7-8, 10-11, 13, 22.
    \3310\ U.S. Senators Heinrich and Lee Supplemental Comments at 
1-2. See also Freeport-McMoRan Supplemental Comments at 6 (asserting 
that the Federal right of first refusal is anticompetitive and would 
enrich transmission owning utility shareholders).
    \3311\ See, e.g., DATA Initial Comments at 3-7 (detailing 
experiences by transmission planning regions and concluding that 
``competitive processes have become a distraction from, and an 
impediment to, the larger goal of expanding the transmission system 
to support current and future needs''); EEI Initial Comments at 24, 
26, 27-31; EEI Supplemental Comments at 1-3 (citing Concentric 
Energy Advisors, Competitive Transmission: Experience To-Date Shows 
Order No. 1000 Solicitations Fail to Show Benefits, at 1 (Aug. 2022) 
(2022 Concentric Report); DATA Supplemental Comments at 4); MISO TOs 
Initial Comments at 53-56; National Grid Initial Comments at 4-5, 31 
(doubting that Order No. 1000 competitive transmission development 
processes have broadly produced beneficial outcomes); PJM Initial 
Comments at 47-48 (enumerating the challenges faced in and resources 
required to complete competitive transmission development 
processes); Vermont Electric and Vermont Transco Initial Comments at 
4-5 (referencing ``a number of unintended consequences that have not 
benefited the regional grid''); WIRES Initial Comments at 14-15; 
WIRES Reply Comments at 4-8; Xcel Initial Comments at 5 (``[Right of 
first refusal] elimination was a policy experiment that did not 
bring about the desired result.'').
    \3312\ In general, Brattle's analysis has found that competitive 
transmission development processes have yielded ``cost savings 
averaging between 20% and 30%'' once historical levels of cost 
escalation in transmission development were taken into account. See 
Brattle Apr. 2019 Competition Report at 39-43. US DOJ and FTC also 
contend that there are many instances in which competitive 
transmission development processes have benefitted consumers. See US 
DOJ & FTC Initial Comments at 13-16 (collecting examples); but see 
DATA Initial Comments at 7-9 (critiquing Brattle's analyses); WIRES 
Reply Comments at 5 (same).
    \3313\ In addition to citations to past Concentric reports, DATA 
attaches to its initial comments a 2022 Concentric report, which 
DATA characterizes as showing that competitive transmission 
development processes add significant time, delay customer benefits, 
and do not produce clear evidence of customer savings given cost cap 
exclusions and delays. DATA Initial Comments at 1-2, 7-11, 14-15; 
id. at attach. A (2022 Concentric Report). DATA also attaches to its 
comments a whitepaper that DATA alleges updates the Brattle Apr. 
2019 Competition Report, and which DATA contends shows that Order 
No. 1000-mandated competition resulted in exceeding cost baselines 
by at least six percent. DATA Supplemental Comments at 3-4; id. at 
attach.: Whitepaper (DATA, Revisiting the Evidence on Cost Savings 
from Transmission Competition (Dec. 2023) (2023 DATA Whitepaper)). 
But see Massachusetts Attorney General Reply Comments at 8-9 
(critiquing the 2022 Concentric Report); NextEra Reply Comments at 
3, 7-17 (same); see also Competition Coalition Supplemental Comments 
at 2-7 (arguing that, in addition to DATA lacking good cause and 
failing to file a motion to lodge new evidence, the 2023 DATA 
Whitepaper fails to, among other things, demonstrate that cost-of-
service regulation is as effective as competition in establishing 
just and reasonable transmission rates).
    \3314\ Compare LS Power Initial Comments at 32-37, with Ameren 
Initial Comments at 36-37, and DATA Initial Comments at 13-14, and 
MISO TOs Initial Comments at 60-61. Several commenters argue at 
length about the NOPR proposal's invocation of FPA sections 309 and 
206 as legal authority and explore various alternatives. See, e.g., 
Ameren Initial Comments at 38-39; California Commission Initial 
Comments at 101-103; DATA Initial Comments at 17-18 & n.43; 
Eversource Initial Comments at 39-42; Indicated PJM TOs Initial 
Comments at 34-35; ITC Initial Comments at 36; LS Power Initial 
Comments at 14, 19-20, 24, 57-61; MISO TOs Initial Comments at 50-
53; NextEra Initial Comments at 51-53.
---------------------------------------------------------------------------

    1554. At a high level, pro-competition commenters express concern 
that the NOPR proposal could divert regional transmission facility 
development opportunities to incumbent transmission providers, 
opportunities that would otherwise be subject to competitive 
transmission development processes. For example, US DOJ and FTC argue 
that relying on Federal rights of first refusal to address the problems 
the Commission has identified would eliminate or distort the benefits 
of competitive transmission development processes, which generally 
``make transmission development less costly, more resilient, and more 
innovative.'' \3315\ NESCOE ``implores the Commission to maintain 
flexibility that enables ISO-NE to issue competitive solicitations to 
identify projects in furtherance of state laws.'' \3316\ Some pro-
competition commenters believe that states and state commissions are 
best positioned to determine whether competition between nonincumbent 
transmission developers and incumbent transmission providers is 
beneficial.\3317\
---------------------------------------------------------------------------

    \3315\ See US DOJ & FTC Initial Comments at 22.
    \3316\ NESCOE Supplemental Comments at 6-7.
    \3317\ E.g., California Commission Initial Comments at 104-105; 
Harvard ELI Initial Comments at 5-6, 31-33; see also Minnesota State 
Entities Initial Comments at 9; Mississippi Commission Reply 
Comments at 8 & n.31; New Jersey Commission Initial Comments at 37; 
PIOs Initial Comments at 85; PJM States Initial Comments at 13-14. 
But see NextEra Reply Comments at 23-25 (questioning whether 
allowing states to dictate the terms of a filed rate would be 
legally sound); PJM Reply Comments at 25-29 (raising potential legal 
ambiguities and practical issues).
---------------------------------------------------------------------------

    1555. Meanwhile, commenters that generally support Federal rights 
of first refusal express skepticism that the NOPR proposal would be 
sufficient to address the identified problems, or offer only qualified 
support for the NOPR proposal as an inferior alternative to the 
Commission fully restoring unconditional Federal rights of first 
refusal.\3318\ In addition, if adopted, several incumbent transmission 
providers advocate for requiring transmission providers to implement 
the NOPR proposal instead of permitting them to decide whether to 
implement it.\3319\
---------------------------------------------------------------------------

    \3318\ E.g., Avangrid Initial Comments at 18-24; DATA Initial 
Comments at 20-22; Eversource Initial Comments at 35-36, 42-45; 
Indicated PJM TOs Reply Comments at 2, 13-14; ITC Initial Comments 
at 32-43; Xcel Initial Comments at 5.
    \3319\ See, e.g., DATA Initial Comments at 19-21; Exelon Initial 
Comments at 49-51; National Grid Initial Comments at 36-37; PG&E 
Initial Comments at 2, 11; PPL Initial Comments at 34; SoCal Edison 
Initial Comments at 2; WIRES Initial Comments at 16; see also LS 
Power Initial Comments at 74-76 (discussing FPA section 205 rights 
in various regions); PJM Initial Comments at 30 (questioning whether 
there are any ``regional differences'' on this policy issue). But 
see Idaho Power Initial Comments at 12 (urging the Commission to 
ensure that any proposed reforms provide sufficient flexibility to 
tailor transmission planning and cost allocation processes to 
accommodate unique regional characteristics).
---------------------------------------------------------------------------

    1556. While commenters offer numerous variations on these high-
level opposing views, several commenters argue that there are problems 
with the basic structure of competitive transmission development 
processes and express concerns that generally align with those 
expressed by the Commission in the NOPR. For example, while not 
agreeing with the NOPR proposal, ELCON expresses concern that ``current 
competition regimes have led eligible developers to retreat to their 
various corners, which reduces transparency, information sharing, and 
open dialogue in the planning process[,]'' and contends that both 
incumbent transmission owners and nonincumbent transmission developers 
have adopted a zero-sum posture to transmission planning that leads to 
a patchwork of planning and lack of innovation.\3320\ Similarly, WIRES, 
citing a report by Grid Strategies, suggests that reforms under Order 
No. 1000 often prevent information sharing about transmission needs and 
available solutions, and lead to less cooperation and coordination 
within transmission planning regions.\3321\ Harvard ELI disagrees, 
however, arguing that the report cited by WIRES provides evidence that 
information asymmetry, secrecy, and utilities' incentives demonstrate 
undue discrimination.\3322\
---------------------------------------------------------------------------

    \3320\ ELCON Initial Comments at 21-22; see also DATA Reply 
Comments at 14 (arguing that ``the Order No. 1000 status quo creates 
an inexorable drive towards minimalist, short-term solutions''). 
Despite its opposition to the NOPR proposal, ELCON sees some 
potential benefit of encouraging joint ownership and cooperation-
based approaches, which ELCON thinks may help remedy the ```us 
versus them' problems with the current regional planning process.'' 
ELCON Initial Comments at 23-24.
    \3321\ WIRES Supplemental Comments at 4 (citing Rob Gramlich, 
Richard Doying, & Zach Zimmerman, Grid Strategies, Fostering 
Collaboration Would Help Build Needed Transmission (Feb. 2024)).
    \3322\ Harvard ELI Supplemental Comments at 5.
---------------------------------------------------------------------------

    1557. Though it does not support the NOPR proposal, Cypress Creek 
contends that Order No. 1000 led to misaligned incentives such that 
``competition today has not necessarily fostered just and

[[Page 49519]]

reasonable rates.'' \3323\ Similarly, American Municipal Power states 
that many municipal electric systems are located on the fringe of an 
incumbent transmission provider's system and would significantly 
benefit from regional transmission projects that improve reliability, 
although because such projects require coordination between two 
incumbent transmission providers, they are ``largely ignored.'' \3324\ 
American Municipal Power also states that another disincentive to 
incumbent transmission provider regional transmission facility 
development is the possibility of losing the project to another 
developer through the competitive process.\3325\ While not taking a 
position on competitive transmission development processes, Indiana 
Commission agrees that Order No. 1000 has produced unintended 
consequences, including that transmission development now mostly takes 
the form of transmission facilities not subject to competitive 
transmission development processes,\3326\ and states that little 
region-wide economic transmission development is occurring.\3327\
---------------------------------------------------------------------------

    \3323\ Cypress Creek Reply Comments at 16.
    \3324\ American Municipal Power Initial Comments at 31-32.
    \3325\ Id. at 32. However, American Municipal Power states that 
because regional transmission facilities typically traverse more 
than one incumbent transmission provider's service territory, 
allowing individual incumbent transmission providers to exercise a 
Federal right of first refusal without other reforms also designed 
to promote coordination and cooperation between such providers would 
not ``result in a shift from local to regional projects.'' Id. 
(referencing the ``interzonal nature of regional projects'').
    \3326\ Indiana Commission Initial Comments at 12 (referring to 
`` `immediate need reliability' or `end of life replacement' or 
`supplemental' or `other' '' types of transmission facility 
projects).
    \3327\ Id.
---------------------------------------------------------------------------

    1558. But some commenters, such as NextEra, contend that if 
regional transmission investment has lagged behind expectations under 
Order No. 1000, that is a planning issue, not an incentives issue, and 
that some of the NOPR's proposed transmission planning reforms will 
help lead to greater investment in regional transmission 
facilities.\3328\ LS Power argues that the NOPR only generally observed 
that there have been increases in local transmission facility 
investment and static or declining investment in regional transmission 
facilities, and did not specify particular transmission planning 
regions in which this problem is occurring or which incumbent 
transmission providers face perverse investment incentives.\3329\ 
However, other commenters, such as WIRES, contend that the elimination 
of Federal rights of first refusal may be connected to flat or 
declining regional transmission investment,\3330\ as suggested by the 
NOPR.
---------------------------------------------------------------------------

    \3328\ See NextEra Initial Comments at 18-19, 25; see also id. 
at 43 (arguing that the NOPR proposal is insufficiently based on 
speculation about potentially flawed investment incentives); 
Americans for Fair Energy Prices Reply Comments at 5-6; Northwest 
and Intermountain Initial Comments at 19-20 (arguing that even a 
limited or conditional right of first refusal eliminates any 
incentive for the incumbent transmission provider to reduce costs or 
delays); Ohio Commission Federal Advocate Initial Comments at 18 
(arguing that adopting the NOPR proposal would further misalign 
incentives for incumbent transmission providers, not improve them).
    \3329\ LS Power Initial Comments at 73-74. But see PJM Initial 
Comments at 30 (questioning whether there are any ``regional 
differences'' on this policy issue).
    \3330\ WIRES Reply Comments at 2 (citing WIRES Initial Comments 
at 13-14).
---------------------------------------------------------------------------

    1559. Finally, several commenters argue that the Commission should 
not adopt Federal right of first refusal reforms in this docket, but 
rather explore those and related issues in another forum. Advanced 
Energy United, Advanced Energy Buyers, State Agencies, and California 
Commission, for example, urge the Commission to consider these issues 
either in a different proceeding or at a technical conference.\3331\ 
Competition Advocates support alternative reforms that they argue can 
better address the problem of perverse incentives, including better 
enforcement of existing orders or taking action to reduce Order No. 
1000 exemptions, and establishing an independent transmission 
monitor.\3332\
---------------------------------------------------------------------------

    \3331\ Advanced Energy Buyers Initial Comments at 4 n.6; AEE 
Initial Comments at 4, 35-37; AEE Reply Comments at 31-33; 
California Commission Initial Comments at 103-104; State Agencies 
Initial Comments at 11; State Agencies Reply Comments at 6; see also 
Chemistry Council Initial Comments at 8; Enel Initial Comments at 3; 
Harvard ELI Initial Comments at 7-10; NESCOE Initial Comments at 11, 
74-77.
    \3332\ Competition Advocates Supplemental Comments at 3-4.
---------------------------------------------------------------------------

2. Comments on the NOPR's Joint Ownership Proposal
    1560. Some commenters, including TAPS, highlight various ways in 
which the Commission's joint ownership proposal would alleviate 
challenges associated with current regional transmission planning 
processes.\3333\ Some commenters, such as ELCON and the Omaha Public 
Power District, argue that the Commission's joint ownership proposal 
would benefit customers or encourage incumbent transmission providers 
to pursue larger and more comprehensive transmission solutions to the 
benefit of customers, and create incentives for transmission providers 
to find beneficial opportunities and investments for joint ownership 
partners and customers.\3334\ Other commenters agree that adopting the 
NOPR proposal may incentivize incumbent transmission providers to 
``look beyond the provincial'' needs and consider regional and 
interregional solutions to transmission needs.\3335\
---------------------------------------------------------------------------

    \3333\ See TAPS Initial Comments at 29-30 (stating that joint 
ownership arrangements provide benefits such as ``improving 
transmission planning to produce a more efficient build-out; 
facilitating state siting; making it easier for [load-serving 
entities] to accept cost increases associated with new transmission 
by providing a hedge; and reducing the costs of needed 
facilities''), id. at 34-37; see also Eversource Initial Comments at 
36-39; Pattern Energy Initial Comments at 37; PPL Initial Comments 
at 32-33; Vermont Electric and Vermont Transco Initial Comments at 
4.
    \3334\ See ELCON Initial Comments at 23-24; see also Cross 
Sector Representatives Supplemental Comments at 1 (arguing that the 
provisions are appropriately tied to collaborative and holistic 
planning outcomes that provide clear benefits to customers and would 
benefit the goals enunciated by the Commission throughout this 
rulemaking process); Omaha Public Power Initial Comments at 5 
(suggesting that the joint ownership proposal will likely encourage 
neighboring incumbent transmission providers to develop facilities 
that benefit multiple transmission providers under certain 
conditions); Pattern Energy Initial Comments at 37 (asserting that 
joint ownership arrangements will open the market to additional 
investment opportunities for all parties).
    \3335\ Tabors Caramanis Rudkevich Initial Comments at 2; see 
also Citizens Energy Initial Comments at 9-10; PG&E Initial Comments 
at 11 (arguing that a conditional Federal right of first refusal 
will help mitigate development challenges by promoting collaboration 
between partners).
---------------------------------------------------------------------------

    1561. However, numerous commenters criticize the NOPR proposal and 
its approach to joint ownership partner selection, especially its 
inclusion of another incumbent transmission provider as a potential 
joint ownership partner.\3336\ In general, these commenters contend 
that incumbent transmission providers would be free to only team up 
with fellow incumbent transmission providers with the same interests 
and exclude others, leading to results that would be contrary to the 
goals of Order No. 1000. As Anbaric states, two incumbent transmission 
providers (or their affiliates) could ``team up and swap a portion of 
their respective projects as a means to satisfy the joint ownership 
requirement'' and thereby ``maintain the status quo'' \3337\ rather

[[Page 49520]]

than advance innovation, cost savings, or new entry. NextEra and others 
decry this potential outcome, which could keep nonincumbent 
transmission developers from obtaining investment opportunities.\3338\ 
Relatedly, several commenters argue that the NOPR proposal would raise 
antitrust and competition concerns,\3339\ including US DOJ and FTC, 
which argue that because the joint venture will not be facing pressure 
to compete, the conditional Federal right of first refusal does not 
create the incentive for incumbent transmission providers to seek out 
the best partner.\3340\ In other words, US DOJ and FTC argue, the mere 
existence of a joint venture partner does not bring competition to a 
project, nor does it necessarily result in the best partner for a 
project being selected, in terms of skill, cost, or innovation.\3341\
---------------------------------------------------------------------------

    \3336\ E.g., Anbaric Initial Comments at 18; see also, e.g., 
APPA Initial Comments at 11-12; California Commission Initial 
Comments at 80-88; Competition Coalition Initial Comments at 49-50; 
LS Power Initial Comments at 92-94; Massachusetts Attorney General 
Initial Comments at 48-49; New Jersey Commission Initial Comments at 
31-33; NextEra Initial Comments at 49-51; NRECA Initial Comments at 
58, 61; PJM States Initial Comments at 14; Policy Integrity Initial 
Comments at 21-22; TANC Initial Comments at 13; TAPS Initial 
Comments at 48-51; TAPS Reply Comments at 5-6 & n.25.
    \3337\ Anbaric Initial Comments at 18.
    \3338\ See Harvard ELI Initial Comments at 35; NextEra Initial 
Comments at 49-51. In contrast, some commenters such as APPA urge 
the Commission to adopt a requirement that incumbent transmission 
providers offer joint ownership on reasonable terms at a load ratio 
share level to all unaffiliated load-serving entities in the 
incumbent transmission provider's footprint. See APPA Reply Comments 
at 5-6; TAPS Initial Comments at 30-32 (advocating for a similar 
proposal).
    \3339\ See, e.g., Competition Coalition Initial Comments at 59-
62; LS Power Initial Comments at 122-125, 131-134; US DOJ & FTC 
Initial Comments at 17-18.
    \3340\ US DOJ & FTC Initial Comments at 17.
    \3341\ Id. at 17-18; see also LS Power Initial Comments at 93 
(arguing that the NOPR proposal would not require any independent 
check that the incumbent transmission provider is partnering with 
the entity that offers the most benefits).
---------------------------------------------------------------------------

    1562. Commenters also highlight the potential for uncertainty, 
litigation, and delays in attempting to implement the NOPR proposal. 
Anbaric asserts that a conditional Federal right of first refusal could 
add delays due to litigation over whether incumbent transmission 
providers provided meaningful opportunities to third parties.\3342\ EEI 
cautions against putting transmission providers in a position where 
they must adjudicate what constitutes meaningful ownership of jointly 
owned transmission facilities on a case-by-case basis, recommending 
instead that the Commission provide guidance on the types of ownership 
rights or operational obligations that will qualify and establish a 
process for seeking Commission approval in a timely manner for other 
arrangements.\3343\ MISO asserts that the process envisioned by the 
NOPR would be time-consuming, as would developing a joint ownership 
proposal, and asks that the Commission adopt clearly defined criteria 
for joint ownership, such as a pro forma agreement, in order not to 
impede transmission development.\3344\ National Grid calls for planning 
authorities to be given the authority to determine the appropriate 
criteria and conditions that constitute a valid joint ownership 
arrangement, though it also asks for guidance regarding particular 
types of combinations of potential joint owners.\3345\
---------------------------------------------------------------------------

    \3342\ Anbaric Initial Comments at 16; see also Avangrid Initial 
Comments at 18 (noting that establishing a conditional Federal right 
of first refusal adds a layer of complexity to the development of 
transmission); NYISO Initial Comments at 55-56 (asking the 
Commission to consider the complications, disputes, and delays that 
may arise from attempting to implement a conditional Federal right 
of first refusal and other practical issues).
    \3343\ EEI Initial Comments at 36-37; see also Ameren Initial 
Comments at 44; DATA Initial Comments at 21-22; PJM Initial Comments 
at 4-5, 51-52, 53-54.
    \3344\ MISO Initial Comments at 80-83; see also APPA Initial 
Comments at 4-7, 20-22 (outlining a detailed proposed implementation 
process by which APPA believes incumbent transmission providers and 
load-serving entities could work together and help avoid disputes 
and delay); Invenergy Reply Comments at 7-8 (calling for the 
adoption of pro forma agreements to ease implementation); TAPS 
Initial Comments at 53-54 (expressing concern that the NOPR 
proposal's anticipated period for formulation of joint ownership 
agreements is too short).
    \3345\ See National Grid Initial Comments at 37.
---------------------------------------------------------------------------

C. Commission Determination
    1563. We decline to act at this time to finalize the NOPR proposal. 
Rather, we will continue to consider the NOPR proposal and potential 
Federal right of first refusal issues in other proceedings. We do not 
adopt in this final order any changes to Order No. 1000's nonincumbent 
transmission developer reforms.
    1564. As summarized above, commenters raise substantial concerns 
about whether incumbent transmission providers, as a result of Order 
No. 1000's reforms, face perverse investment incentives that do not 
adequately encourage those incumbent transmission providers to develop 
and advocate for transmission facilities that benefit more than just 
their own local retail distribution service territory or footprint. To 
the extent that incumbent transmission providers face perverse 
investment incentives, commenters also raise substantial concerns about 
whether the NOPR proposal adequately and appropriately addresses those 
incentives and whether adopting the proposal is necessary or 
appropriate in carrying out the provisions of the FPA. Therefore, after 
careful consideration of the record, we decline to finalize the NOPR 
proposal at this time. The Commission will continue to consider 
potential Federal right of first refusal reforms along with other 
transmission reforms in the future.\3346\
---------------------------------------------------------------------------

    \3346\ We note, for example, the ongoing proceeding in Docket 
No. AD22-8 on Transmission Planning and Cost Management.
---------------------------------------------------------------------------

IX. Local Transmission Planning Inputs in the Regional Transmission 
Planning Process

A. Need for Reform

1. NOPR
    1565. In the NOPR, the Commission explained that it was concerned 
that local transmission planning processes may lack adequate provisions 
for transparency and meaningful input from stakeholders, and that 
regional transmission planning processes may not adequately coordinate 
with local transmission planning processes.\3347\ The Commission stated 
in the NOPR that it was concerned that the lack of minimal standards or 
specified procedures may contribute to inadequate transparency and 
opportunities for stakeholders to engage in local transmission planning 
processes.\3348\ Accordingly, the Commission stated that it believed 
reforms to better ensure transparency and opportunities for stakeholder 
engagement may be timely and important in light of the significant 
investments in transmission that now occur through local transmission 
planning processes.\3349\
---------------------------------------------------------------------------

    \3347\ NOPR, 179 FERC ] 61,028 at P 398 & n. 639 (providing that 
regional transmission planning processes should identify 
``alternative transmission solutions that might meet the needs of 
the transmission planning region more efficiently or cost-
effectively than solutions identified by individual utility 
transmission providers in their local transmission planning 
process'' (quoting Order No. 1000, 136 FERC ] 61,051 at P 148)).
    \3348\ Id.
    \3349\ See supra The Overall Need for Reform section.
---------------------------------------------------------------------------

    1566. In addition, the Commission explained in the NOPR that it was 
concerned that, given the age of the Nation's transmission 
infrastructure, many incumbent transmission providers are replacing 
aging transmission infrastructure as it reaches the end of its useful 
life without evaluating whether those replacement transmission 
facilities could be modified (i.e., right-sized) to more efficiently or 
cost-effectively address regional transmission needs, and, more 
generally, that transmission providers developing regional transmission 
plans may lack the information necessary to identify the benefits that 
regional transmission facilities may provide in deferring or 
eliminating the need for in-kind replacements. Specifically, the NOPR 
stated that in-kind replacements

[[Page 49521]]

of existing transmission facilities are managed by individual incumbent 
transmission providers according to their company practices, and that 
there is no requirement that transmission providers plan these in-kind 
replacement transmission facilities through an Order No. 890-compliant 
transmission planning process.\3350\ The Commission stated that, 
because in-kind replacement of existing transmission facilities is not 
subject to any transmission planning process, it was concerned that, 
absent reform, there may be a lack of coordination between regional 
transmission planning processes and in-kind replacement of existing 
transmission facilities to identify whether these replacement 
transmission facilities could be modified to more efficiently or cost-
effectively address transmission needs identified through Long-Term 
Regional Transmission Planning. The Commission explained that this lack 
of coordination may result in a regional transmission planning process 
that fails to identify opportunities to right size planned in-kind 
replacement transmission facilities and may result in the development 
of duplicative or unnecessary transmission facilities that increase 
costs to customers and render Commission-jurisdictional rates unjust 
and unreasonable.\3351\
---------------------------------------------------------------------------

    \3350\ NOPR, 179 FERC ] 61,028 at P 399 (citing S. Cal. Edison 
Co., 164 FERC ] 61,160 at P 33; Cal. Pub. Utils. Comm'n v. Pac. Gas 
& Elec. Co., 164 FERC ] 61,161, at P 68 (2018); PJM Interconnection, 
L.L.C., 172 FERC ] 61,136, at PP 12, 89 (2020); PJM Interconnection, 
L.L.C., 173 FERC ] 61,242, at P 54 (2020)).
    \3351\ Id.
---------------------------------------------------------------------------

2. Comments
    1567. Some commenters argue that the NOPR proposal regarding 
improved transparency in local transmission planning processes is not 
justified.\3352\ EEI argues that the Commission has not found that any 
of the approved transmission planning processes under Order Nos. 890 
and 1000 are unjust and unreasonable or unduly discriminatory or 
preferential and that, absent such a finding, the Commission should not 
move forward with changes to local transmission planning 
processes.\3353\ Idaho Power states that the Commission should not use 
a general rulemaking to address localized problems.\3354\ On the other 
hand, Indicated PJM TOs state that the NOPR proposal to enhance 
transparency in the local transmission planning processes is needed in 
each transmission planning region to satisfy the requirements set forth 
by Order No. 890.\3355\
---------------------------------------------------------------------------

    \3352\ Dominion Initial Comments at 76 (citing NOPR, 179 FERC ] 
61,028 at P 395 n.634); EEI Initial Comments at 40; Idaho Power 
Initial Comments at 12-13.
    \3353\ EEI Initial Comments at 40; see also Dominion Initial 
Comments at 76.
    \3354\ Idaho Power Initial Comments at 12-13.
    \3355\ Indicated PJM TOs Initial Comments at 41 (citing Order 
No. 890, 118 FERC ] 61,119 at PP 426-561).
---------------------------------------------------------------------------

    1568. With respect to the Commission's proposed right-sizing 
reforms, LS Power and NextEra argue that the NOPR fails to make 
findings required under FPA section 206 to permit a right of first 
refusal for right-sized projects. LS Power and NextEra assert that the 
NOPR does not satisfy the first prong of FPA section 206, as it fails 
to make an affirmative finding that either the regional transmission 
planning process or the local transmission planning process are unjust 
and unreasonable such that abandonment of the existing tariff 
provisions is warranted.\3356\ Competition Coalition also asserts that 
the Commission failed to demonstrate the alleged need for reform on any 
section 206 finding.\3357\
---------------------------------------------------------------------------

    \3356\ LS Power Initial Comments at 50-53 (citations omitted); 
NextEra Initial Comments at 54-56 (citations omitted). A number of 
commenters challenge the NOPR right-sizing proposal, including the 
proposal to permit a Federal right of first refusal for certain 
replacement facilities. We address those arguments below in the 
Identifying Potential Opportunities to Right-Size Replacement 
Transmission Facilities section below.
    \3357\ Competition Coalition Initial Comments at 64.
---------------------------------------------------------------------------

3. Commission Determination
    1569. Based on the record, we find that there is substantial 
evidence to support the conclusion that existing requirements governing 
transparency in local transmission planning processes and coordination 
between local and regional transmission planning processes are unjust, 
unreasonable, and unduly discriminatory or preferential. We therefore 
adopt the preliminary findings in the NOPR concerning the need for 
reform of the local transmission planning process and coordination 
between the local and regional transmission planning processes, 
including the evaluation of whether replacement transmission facilities 
could be modified (i.e., right-sized) to more efficiently or cost-
effectively address transmission needs.\3358\
---------------------------------------------------------------------------

    \3358\ Below, we clarify that the new transparency requirements 
do not apply to transmission facilities that are otherwise exempt 
from Order No. 890's transparency requirements, such as asset 
management projects. See infra Enhanced Transparency of Local 
Transmission Planning Inputs in the Regional Transmission Planning 
Process section.
---------------------------------------------------------------------------

    1570. Local and regional transmission planning processes serve 
essential and complementary roles in ensuring that customers' 
transmission needs are identified and met at a just and reasonable 
cost, including through the identification, evaluation, and selection 
of more efficient or cost-effective transmission solutions through 
regional transmission planning. Information and transmission solutions 
developed through local transmission planning serve as a foundation for 
regional transmission planning, and it is therefore critical that the 
processes are appropriately designed and aligned to ensure that 
transmission providers and stakeholders have the information needed, 
including from the local transmission planning process, to conduct 
effective regional transmission planning. While the broader reforms 
directed in this final order are focused on improving the regional 
transmission planning process, we nonetheless have identified discrete 
deficiencies in the local transmission planning process and its 
coordination with the regional transmission planning process that also 
must be addressed to ensure that Commission-jurisdictional rates are 
just and reasonable.
    1571. First, we find that local transmission planning processes 
lack adequate provisions for transparency and meaningful input from 
stakeholders. The Commission has recognized the critical role that 
stakeholders serve in effective transmission planning,\3359\ and in 
Order Nos. 890 and 1000, directed reforms to facilitate their 
meaningful participation in both local and regional transmission 
planning.\3360\ However, the record demonstrates that existing 
transparency and coordination requirements in local transmission 
planning do not consistently provide stakeholders with sufficient 
information regarding the development of local transmission 
plans.\3361\ We further find that the

[[Page 49522]]

absence of minimal standards or specified procedures to implement the 
transmission planning principles required by Order No. 890 contributes 
to inadequate transparency and opportunities for stakeholders to engage 
in local transmission planning processes.
---------------------------------------------------------------------------

    \3359\ See, e.g., Order No. 890, 118 FERC ] 61,119 at P 454 
(``[C]ustomers must be included at the early stages of the 
development of the transmission plan and not merely given an 
opportunity to comment on transmission plans that were developed in 
the first instance without their input.''); Order No. 1000, 136 FERC 
] 61,051 at P 152 (``[A]bsent timely and meaningful participation by 
all stakeholders, the regional transmission planning process will 
not determine which transmission project or group of transmission 
projects could satisfy local and regional needs more efficiently or 
cost-effectively.'').
    \3360\ See, e.g., Order No. 890, 118 FERC ] 61,119 at PP 454, 
488, 557; Order No. 1000, 136 FERC ] 61,051 at P 152.
    \3361\ E.g., OMS Initial Comments at 15 (``OMS members have 
varying levels of oversight and visibility into the utility-driven, 
local planning processes that are incorporated into the overall MISO 
transmission expansion plan.''); Concerned Scientists ANOPR Initial 
Comments at 24-31 (discussing challenges obtaining information to 
assess projects developed through local transmission planning 
processes) (citations omitted); New Jersey Commission ANOPR Initial 
Comments at 6-7 (discussing limited information and analysis 
provided regarding projects considered in local transmission 
planning) (citations omitted).
---------------------------------------------------------------------------

    1572. The combined effect of these deficiencies is that 
stakeholders who wish to participate in transmission planning, at both 
the local and regional level, may not be able to effectively do so. 
More specifically, we find that, when engaging in the regional 
transmission planning process, stakeholders lack sufficient information 
about underlying local transmission needs and potential solutions that 
is necessary to ensure that the more efficient or cost-effective 
regional transmission solutions are identified, evaluated, and 
selected. Given the recognized importance of stakeholder participation 
in effective transmission planning, we find that reforms are needed to 
ensure that Commission-jurisdictional local and regional transmission 
planning processes remain just, reasonable, and not unduly 
discriminatory or preferential. Furthermore, we believe that reforms to 
better ensure more consistent implementation of the Order No. 890 
transmission planning principles are timely and important in light of 
the significant investments in transmission infrastructure that now 
occur through local transmission planning processes.\3362\
---------------------------------------------------------------------------

    \3362\ See supra The Overall Need for Reform section.
---------------------------------------------------------------------------

    1573. Second, we find that additional coordination between the 
local and regional transmission planning processes regarding 
replacement of aging infrastructure is needed. The record shows that 
many incumbent transmission providers are replacing aging transmission 
infrastructure as it reaches the end of its useful life. For example, 
we note that PJM estimated that roughly two-thirds of all PJM 
transmission system assets are more than 40 years old, with some 
transmission facilities approaching 90 years old.\3363\ NYISO 
highlights that 80 percent of transmission lines in its footprint are 
at least 50 years old and are either being replaced or will soon need 
to be replaced.\3364\ Replacing these transmission facilities will 
require substantial investment, which will directly affect Commission-
jurisdictional transmission rates. For example, the California 
Commission notes that PG&E anticipates spending roughly $11 billion 
between 2022 and 2027 to address aging transmission 
infrastructure.\3365\
---------------------------------------------------------------------------

    \3363\ See PJM Interconnection, L.L.C., The Benefits of the PJM 
Transmission System 5 (2019), https://www.pjm.com/-/media/library/reports-notices/special-reports/2019/the-benefits-of-the-pjm-transmission-system.pdf. Moreover, AEP estimates that approximately 
30 percent of its line miles and circuit breakers will need to be 
replaced over the next 10 years. See AEP, Wolfe Utilities, 
Midstream, & Clean Energy Conference 40 (Sept. 30, 2021), https://www.aep.com/Assets/docs/investors/eventspresentationsandwebcasts/WolfeConferencePresentation093021.pdf.
    \3364\ NYISO Initial Comments at 58.
    \3365\ California Commission Initial Comments at 110.
---------------------------------------------------------------------------

    1574. However, because the Commission's existing requirements do 
not obligate transmission providers to share sufficient information 
regarding these replacement projects, transmission providers in the 
regional transmission planning process are not consistently evaluating 
whether those replacement transmission facilities could be modified 
(i.e., right-sized) to more efficiently or cost-effectively address 
transmission needs. We therefore find that the lack of a requirement 
for transmission providers in each transmission planning region to 
evaluate whether those replacement transmission facilities could be 
modified (i.e., right-sized) to more efficiently or cost-effectively 
address Long-Term Transmission Needs results in a regional transmission 
planning process that fails to identify opportunities to right-size 
planned in-kind replacement transmission facilities and may result in 
the development of inefficiently sized or designed, duplicative, or 
unnecessary transmission facilities that increase costs to customers 
and render Commission-jurisdictional rates unjust and unreasonable.
    1575. With respect to the claim by commenters that the Commission 
lacks jurisdiction to impose the proposed transparency and coordination 
requirements or that the Commission has not justified the 
requirements,\3366\ we disagree. Consistent with Order Nos. 890 and 
1000, the Commission has authority to establish requirements related to 
local transmission planning processes and the inputs to regional 
transmission planning processes.\3367\ Our findings above are supported 
by substantial evidence in the record, and we address any concerns 
regarding our remedy to address the transparency and coordination 
deficiencies below.
---------------------------------------------------------------------------

    \3366\ Dominion Initial Comments at 76; EEI Initial Comments at 
40; Idaho Power Initial Comments at 12-13.
    \3367\ See, e.g., Order No. 890, 118 FERC ] 61,119 at P 435 
(``In order to limit the opportunities for undue discrimination . . 
. and to ensure that comparable transmission service is provided by 
all public utility transmission providers, including RTOs and ISOs, 
the Commission concludes that it is necessary to amend the existing 
pro forma OATT to require coordinated, open, and transparent 
transmission planning on both a local and regional level.''); Order 
No. 1000, 136 FERC ] 61,051 at PP 68, 148, 152.
---------------------------------------------------------------------------

    1576. We also disagree with LS Power, Competition Coalition, and 
NextEra's arguments regarding whether the Commission properly 
demonstrated under FPA section 206 that existing rates are unjust, 
unreasonable, or unduly discriminatory or preferential in instituting a 
Federal right of first refusal for right-sized replacement transmission 
facilities.\3368\ First, we clarify that the Commission is not finding 
that existing transmission planning processes are unjust, unreasonable, 
or unduly discriminatory or preferential due to a lack of a Federal 
right of first refusal for these facilities. Rather, we find here that 
transmission providers' OATTs are unjust and unreasonable due to the 
lack of right-sizing requirements that may lead to the identification, 
evaluation, and selection of more efficient or cost-effective Long-Term 
Regional Transmission Facilities. As discussed above, the record 
demonstrates that many incumbent transmission providers are replacing 
aging transmission infrastructure as it reaches the end of its useful 
life without evaluating, through the regional transmission planning 
process, whether those replacement transmission facilities could be 
modified (i.e., right-sized) to more efficiently or cost-effectively 
address transmission needs. As a result of this identified deficiency, 
we find that transmission providers' OATTs are unjust and unreasonable. 
We address LS Power, NextEra, and other commenters' concerns regarding 
the Commission's proposed replacement rate, including our findings 
regarding a Federal right of first refusal for right-sized replacement 
transmission facilities, below.
---------------------------------------------------------------------------

    \3368\ Competition Coalition Initial Comments at 64; LS Power 
Initial Comments at 51-53; NextEra Initial Comments at 54-56.
---------------------------------------------------------------------------

    1577. Because we find that the Commission's existing requirements 
governing transparency in local transmission planning processes and 
coordination between local and regional transmission planning processes 
are insufficient to ensure just and reasonable and not unduly 
discriminatory or preferential rates, we are now requiring, pursuant to 
FPA section 206, that transmission providers

[[Page 49523]]

adopt, with certain modifications, the two reforms that the Commission 
identified in the NOPR: (1) enhance the transparency of local 
transmission planning processes; and (2) require transmission providers 
to evaluate whether transmission facilities that need replacing can be 
``right-sized'' to more efficiently or cost-effectively address Long-
Term Transmission Needs identified in Long-Term Regional Transmission 
Planning.\3369\ We find that the first reform will result in 
transmission providers providing enhanced transparency for stakeholders 
while providing those same stakeholders with opportunities to more 
effectively engage in local and regional transmission planning 
processes. We find that the second reform will result in transmission 
providers identifying, evaluating, and selecting replacement 
transmission facilities that more efficiently or cost-effectively 
address Long-Term Transmission Needs. Taken together, we find that 
these reforms will ensure that Commission-jurisdictional rates are just 
and reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \3369\ NOPR, 179 FERC ] 61,028 at PP 400-403.
---------------------------------------------------------------------------

B. Enhanced Transparency of Local Transmission Planning Inputs in the 
Regional Transmission Planning Process

1. NOPR Proposal
    1578. In the NOPR, the Commission proposed to require transmission 
providers in each transmission planning region to revise the regional 
transmission planning process in their OATTs with additional provisions 
to enhance transparency of: (1) the criteria, models, and assumptions 
that they use in their local transmission planning process; (2) the 
local transmission needs that they identify through that process; and 
(3) the potential local or regional transmission facilities that they 
will evaluate to address those local transmission needs.\3370\ The 
Commission explained that transmission providers would be required to 
establish an iterative process that would provide stakeholders with 
meaningful opportunities to participate and provide feedback on local 
transmission planning throughout the regional transmission planning 
process.\3371\ The Commission proposed to require that the regional 
transmission planning process include at least three publicly-noticed 
stakeholder meetings concerning the local transmission planning process 
of each transmission provider that is a member of the transmission 
planning region before a transmission provider's local transmission 
plan can be incorporated into the transmission planning region's 
planning models.\3372\
---------------------------------------------------------------------------

    \3370\ NOPR, 179 FERC ] 61,028 at P 400.
    \3371\ Id.
    \3372\ Id.
---------------------------------------------------------------------------

    1579. Specifically, the Commission proposed to require transmission 
providers in each transmission planning region, prior to the submission 
of local transmission planning information to the transmission planning 
region for inclusion in the regional transmission planning process, to 
convene, collectively, as part of the regional transmission planning 
process, a stakeholder meeting to review the criteria, assumptions, and 
models related to each transmission provider's local transmission 
planning (Assumptions Meeting). Next, no fewer than 25 calendar days 
after the Assumptions Meeting, transmission providers that are members 
of the transmission planning region would be required to convene, 
collectively, as part of the regional transmission planning process, a 
stakeholder meeting to review identified reliability criteria 
violations and other transmission needs that drive the need for local 
transmission facilities (Needs Meeting). Finally, the Commission 
proposed to require that, no fewer than 25 calendar days after the 
Needs Meeting, transmission providers that are members of the 
transmission planning region convene, collectively, as part of the 
regional transmission planning process, a stakeholder meeting to review 
potential solutions to those reliability criteria violations and other 
transmission needs (Solutions Meeting). The Commission also proposed to 
require that all materials for stakeholder review during these three 
meetings be publicly posted and that stakeholders have opportunities 
before and after each meeting to submit comments.\3373\
---------------------------------------------------------------------------

    \3373\ Id. P 401.
---------------------------------------------------------------------------

    1580. The Commission preliminarily found that these proposed 
requirements will result in needed additional transparency into local 
transmission planning processes, which inform the regional transmission 
planning process in a transmission planning region.\3374\
---------------------------------------------------------------------------

    \3374\ Id. P 402.
---------------------------------------------------------------------------

2. Comments
a. Interest in Enhanced Transparency of Local Transmission Planning 
Inputs
    1581. Many commenters support the NOPR proposal.\3375\ ITC argues 
that the Commission's proposed transparency requirements strike an 
appropriate balance between the need for oversight and the need to 
timely address asset management needs.\3376\ Southeast PIOs state that 
closer coordination between the regional and local transmission 
planning processes would help to ensure that the local process does not 
dull the effectiveness of the regional process.\3377\ Vermont State 
Entities support enhancing transparency and visibility of local 
transmission planning processes and coordinating with Long-Term 
Regional Transmission Planning and other processes, including the 
generator interconnection process.\3378\ City of New Orleans Council 
states that increased transparency, collaboration, and coordination 
between the regional and local transmission planning processes will 
result in more efficient local transmission development.\3379\ OMS 
asserts that enhanced transparency will enable retail regulators to 
more effectively participate in identifying the best set of projects to 
meet both local and regional needs.\3380\
---------------------------------------------------------------------------

    \3375\ See AEE Initial Comments at 3; AEP Reply Comments at 10; 
APPA Initial Comments at 47; Breakthrough Energy Initial Comments at 
19; Center for Biological Diversity Initial Comments at 28; Certain 
TDUs Initial Comments at 13; City of New Orleans Council Initial 
Comments at 11; Clean Energy Associations Initial Comments at 36; 
Clean Energy Buyers Initial Comments at 33; Colorado Consumer 
Advocates Initial Comments at 30-31; Cross Sector Representatives 
Supplemental Comments at 1; Exelon Initial Comments at 3, 51-52; 
Indicated PJM TOs Initial Comments at 40; Interwest Initial Comments 
at 17-18; ITC Initial Comments at 45-47; National and State 
Conservation Organizations Initial Comments at 2; New York Transco 
Initial Comments at 1; NextEra Initial Comments at 66-67; Northwest 
and Intermountain Initial Comments at 20; OMS Initial Comments at 
16; PJM States Initial Comments at 4-6; Resale Iowa Initial Comments 
at 8; Resale Iowa Reply Comments at 5; SEIA Initial Comments at 25-
26; Shell Initial Comments at 34; Southeast PIOs Initial Comments at 
54-55; Vermont State Entities Initial Comments at 10.
    \3376\ ITC Initial Comments at 45-47 (citations omitted).
    \3377\ Southeast PIOs Initial Comments at 54-55.
    \3378\ Vermont State Entities Initial Comments at 10 (citing 
NOPR, 179 FERC ] 61,028 at P 400).
    \3379\ City of New Orleans Council Initial Comments at 11.
    \3380\ OMS Initial Comments at 16.
---------------------------------------------------------------------------

    1582. Colorado Consumer Advocates state that the Commission must 
ensure that transmission providers maintain coordinated, open, and 
transparent transmission planning processes on both a local and 
regional level that meet stakeholder needs.\3381\ Interwest asserts 
that the NOPR proposal is needed to incentivize the coordination of 
generation and resource planning and transmission planning beyond state 
lines, adding that transparency measures, such as a process for 
information sharing, could allow customers or stakeholders to evaluate 
or replicate the findings from transmission

[[Page 49524]]

providers and reduce after-the-fact disputes regarding allocated 
costs.\3382\
---------------------------------------------------------------------------

    \3381\ Colorado Consumer Advocates Initial Comments at 17, 20-
21.
    \3382\ Interwest Initial Comments at 17-18. As an example, 
Interwest cites WestConnect's Colorado Coordinated Planning Group, 
which conducts transmission planning through task forces and work 
groups consisting of stakeholders. Id.
---------------------------------------------------------------------------

    1583. Exelon and Indicated PJM TOs note that the NOPR proposal 
mirrors PJM TOs' local transmission planning process.\3383\ Indicated 
PJM TOs state that the NOPR proposal will help to ensure the 
coordination of local and regional transmission planning while 
preserving transmission owner responsibility for local transmission 
planning.\3384\ Indicated PJM TOs state that the PJM Attachment M-3 
process avoids duplication of projects between local and regional 
transmission planning processes.\3385\ Clean Energy Associations state 
that each transmission planning region should have the opportunity to 
regularly review local transmission planning criteria for consistency 
with regional transmission planning, as PJM's manuals require.\3386\
---------------------------------------------------------------------------

    \3383\ Exelon Initial Comments at 3-4, 51-52 (citing PJM, Intra-
PJM Tariffs, OATT, attach. M-3 (1.0.0)); see Indicated PJM TOs 
Initial Comments at 42-43.
    \3384\ Indicated PJM TOs Initial Comments at 42-43.
    \3385\ Id. at 42.
    \3386\ Clean Energy Associations Initial Comments at 37 (citing 
PJM Manual 14B, section 1.1 Planning Process Work Flow).
---------------------------------------------------------------------------

    1584. Clean Energy Buyers state that existing local transmission 
planning has not met expectations for openness, coordination, and 
transparency, and that the NOPR proposal will help remedy such 
deficiencies and better identify cost-effective transmission 
projects.\3387\ Northwest and Intermountain agree that the Commission 
should reform local transmission planning processes to enhance 
transparency and provide meaningful opportunities for public 
input.\3388\ Similarly, Resale Iowa asserts that MISO's stakeholder 
processes do not address local transmission planning issues, especially 
those related to asset management, end-of-life, and other forms of 
local transmission planning that are exempt from Order No. 890's 
transmission planning requirements. Thus, Resale Iowa contends, its 
members believe they must bear the cost of new or upgraded transmission 
facilities without the opportunity to discuss less costly 
alternatives.\3389\
---------------------------------------------------------------------------

    \3387\ Clean Energy Buyers Initial Comments at 33.
    \3388\ Northwest and Intermountain Initial Comments at 20.
    \3389\ Resale Iowa Reply Comments at 4-5.
---------------------------------------------------------------------------

    1585. National and State Conservation Organizations suggest that 
early and consistent community engagement are key elements to 
successful development and timely completion of transmission projects, 
as the voices and concerns of affected local communities must be heard 
and acted upon to prevent environmental injustices and environmental 
damage.\3390\ WE ACT states that, in addition to coordination with 
state entities, there must also be meaningful engagement and robust 
input from affected and overburdened communities so that states and 
transmission providers are aware of the potential harms of siting 
transmission projects in environmental justice communities. WE ACT 
recommends that the Commission, its Office of Public Participation, 
state officials, and transmission providers familiarize themselves with 
several key documents relating to environmental justice to ensure 
meaningful community engagement and to inform comprehensive 
environmental justice analyses to reduce or eliminate undue 
burdens.\3391\
---------------------------------------------------------------------------

    \3390\ National and State Conservation Organizations Initial 
Comments at 2.
    \3391\ WE ACT Initial Comments at 5-6 (citing U.S. Env't Prot. 
Agency, Promising Practices for EJ Methodologies in NEPA Reviews 
(Mar. 2016), https://www.epa.gov/environmentaljustice/ej-iwg-promising-practices-ej-methodologies-nepa-reviews; U.S. Env't Prot. 
Agency, Technical Guidance for Assessing Environmental Justice in 
Regulatory Analysis (June 2016), https://www.epa.gov/sites/default/files/2016-06/documents/ejtg_5_6_16_v5.1.pdf; The Principles of 
Environmental Justice (EJ), Energy Justice Network, https://www.ejnet.org/ej/principles.pdf; Jemez Principles of Democratic 
Organizing, Energy Justice Network, https://www.ejnet.org/ej/jemez.pdf).
---------------------------------------------------------------------------

b. Suggested Modifications to the NOPR Proposal
    1586. Some commenters support the NOPR proposal, but also suggest 
modifications to make it more effective or request that the Commission 
provide flexibility for transmission planning regions to determine the 
best manner to meet the requirements.\3392\ NARUC requests flexibility 
for transmission planning regions to determine the timeline for 
stakeholder processes.\3393\ NRECA requests that the Commission allow 
transmission planning regions that currently have transparent processes 
to maintain them.\3394\
---------------------------------------------------------------------------

    \3392\ See ACORE Initial Comments at 18-19; AEP Initial Comments 
at 7, 40-41, 43-44; Ameren Initial Comments at 46-47; NARUC Initial 
Comments at 58-59; NESCOE Initial Comments at 77-78; North Carolina 
Commission and Staff Initial Comments at 18-20; NRECA Initial 
Comments at 65-66; NYISO Initial Comments at 9, 57-58; TANC Initial 
Comments at 11; WE ACT Initial Comments at 5-6; WIRES Initial 
Comments at 8-10.
    \3393\ NARUC Initial Comments at 58-59 (citing NOPR, 179 FERC ] 
61,028 at PP 400-401).
    \3394\ NRECA Initial Comments at 65-66; see also Ameren Initial 
Comments at 46 (citing Ameren ANOPR Initial Comments at 20-21).
---------------------------------------------------------------------------

    1587. TANC encourages the Commission to provide regional 
flexibility by allowing transmission providers to propose on compliance 
alternative frameworks for consideration of local transmission plans in 
the regional transmission planning process and allow transmission 
planning regions to consider the burden versus benefit of such as a 
requirement to maximize transparency and project efficiencies.\3395\
---------------------------------------------------------------------------

    \3395\ TANC Initial Comments at 11 (citing NOPR, 179 FERC ] 
61,028 at PP 400, 402).
---------------------------------------------------------------------------

    1588. NESCOE contends that aspects of the proposal are too 
prescriptive, such as the Commission dictating the number of 
stakeholder meetings. However, NESCOE states that enhanced transparency 
could help states and ratepayers better understand proposed 
transmission facilities and the costs associated with them.\3396\ 
NESCOE states that stakeholders should have meaningful opportunities to 
participate and provide feedback on local transmission planning 
throughout the regional transmission planning process, asserting that 
transmission owners in ISO-NE currently do little more than present 
their proposals for in-kind replacements of existing transmission 
infrastructure to ISO-NE's Planning Advisory Committee.\3397\
---------------------------------------------------------------------------

    \3396\ NESCOE Initial Comments at 77-78 (citing NOPR, 179 FERC ] 
61,028 at P 400).
    \3397\ Id.; NESCOE Reply Comments at 6 (citation omitted).
---------------------------------------------------------------------------

    1589. ACORE states that the proposed stakeholder involvement in 
local transmission planning is beneficial but that the NOPR proposal 
lacks clarity on whether transmission providers must consider local 
transmission projects alongside other options in Long-Term Regional 
Transmission Planning.
    1590. Joint Consumer Advocates argue that, while the NOPR proposal 
will increase transparency, it will not address the inability of 
consumer advocates to meaningfully review planning inputs or models 
because the inputs are not maintained in a format that enables 
stakeholders to review them, understand the assumptions, or replicate 
the transmission planning results, as contemplated in Order No. 
890.\3398\ Pine Gate recommends that the Commission require that 
transmission providers make available to stakeholders information about 
the local transmission planning process for review and comment prior to 
the finalization or approval of the local transmission plan.\3399\
---------------------------------------------------------------------------

    \3398\ Joint Consumer Advocates Initial Comments at 21-22.
    \3399\ Pine Gate Initial Comments at 49-50.

---------------------------------------------------------------------------

[[Page 49525]]

c. Concern With the NOPR Proposal
    1591. Several commenters state that they oppose or have concerns 
with the NOPR proposal.\3400\ Ohio Commission Federal Advocate argues 
that the NOPR proposal is of limited value given that it does not 
require a more comprehensive review of local transmission projects; 
instead, these projects will continue to be chosen, designed, and 
approved by the transmission owner.\3401\ Similarly, American Municipal 
Power states that new transmission projects that expand or enhance the 
transmission grid and have regional benefits should be planned by the 
regional transmission entity and not by individual transmission owners. 
Further, American Municipal Power asserts that use of the PJM 
Attachment M-3 process, which American Municipal Power contends the 
NOPR ``essentially'' proposes to require nationwide, has resulted in 
additional balkanization of the transmission planning process, has 
increased the problem of planning based on individual transmission 
owners' criteria for determining need, and has disenfranchised PJM as 
the regional transmission planner.\3402\
---------------------------------------------------------------------------

    \3400\ See American Municipal Power Initial Comments at 13-25; 
APS Initial Comments at 12-13; Avangrid Initial Comments at 13-15; 
CAISO Initial Comments at 7, 47-51; California Water Initial 
Comments at 5-8; DC and MD Offices of People's Counsel Initial 
Comments at 6-7; Dominion Initial Comments at 69-70; EEI Initial 
Comments at 40; Eversource Initial Comments at 47-49; Idaho Power 
Initial Comments at 12-13; MISO Initial Comments at 84-86; MISO TOs 
Initial Comments at 28-31; National Grid Initial Comments at 39-40; 
New York TOs Initial Comments at 16-17; Pennsylvania Commission 
Initial Comments at 20; PG&E Initial Comments at 15-18; PPL Initial 
Comments at 35-36; Xcel Initial Comments at 16-17.
    \3401\ See Ohio Commission Federal Advocate Initial Comments at 
20-21 (citing NOPR, 179 FERC ] 61,028 (Christie, Comm'r, concurring 
at P 16)).
    \3402\ American Municipal Power Initial Comments at 17; see 
American Municipal Power Supplemental Comments at 1, 6 (citations 
omitted).
---------------------------------------------------------------------------

    1592. Relatedly, Pennsylvania Commission states that enhancing 
transparency in local transmission planning is a laudable goal but 
notes that the proposal will not enhance PJM's process because the NOPR 
proposal adopts the existing PJM Attachment M-3 process.\3403\
---------------------------------------------------------------------------

    \3403\ Pennsylvania Commission Initial Comments at 20-21 (citing 
NOPR, 179 FERC ] 61,028 at PP 399-400).
---------------------------------------------------------------------------

    1593. Several commenters argue that the existing regional 
transmission planning process in their transmission planning region is 
already transparent and therefore oppose the NOPR proposal.\3404\ New 
York TOs assert that New York's regional and local transmission 
planning processes almost fully satisfy the proposed requirements and, 
as such, the Commission should allow NYISO to retain these 
processes.\3405\ MISO argues that the additional requirements proposed 
in the NOPR are not needed in an RTO such as MISO with a fully 
developed, open, and transparent transmission planning process in 
effect.\3406\ MISO TOs agree, stating that MISO's existing processes 
provide for transparency in local transmission planning through 
subregional planning meetings, published materials, and workshops 
throughout the transmission planning process.\3407\
---------------------------------------------------------------------------

    \3404\ APS Initial Comments at 12-13; Avangrid Initial Comments 
at 13-15; CAISO Initial Comments at 46-50; Dominion Initial Comments 
at 69; Eversource Initial Comments at 46-49; MISO Initial Comments 
at 84-86; MISO TOs Initial Comments at 29-31; National Grid Initial 
Comments at 39; New York TOs Initial Comments at 16-17; Pennsylvania 
Commission Initial Comments at 20; PG&E Initial Comments at 16-18.
    \3405\ New York TOs Initial Comments at 7.
    \3406\ MISO Initial Comments at 84-85.
    \3407\ MISO TOs Initial Comments at 29-31 (citing MISO Business 
Practice Manual, Transmission Planning, BPM-20, section 4.1; MISO, 
FERC Electric Tariff, MISO OATT, attach. FF (Transmission Expansion 
Planning Protocol) (90.0.0), Sec.  I.C.9; MISO, Subregional Planning 
Meeting, https://www.misoenergy.org/engage/committees/subregional-planning-meeting/; Midwest Indep. Transmission Sys. Operator, Inc., 
142 FERC ] 61,215, at PP 80, 114 (2013), order on reh'g, 144 FERC ] 
61,020 (2013), order on reh'g & compliance, 147 FERC ] 61,127 
(2014), aff'd sub nom. MISO Transmission Owners v. FERC, 819 F.3d 
329 (7th Cir. 2016)).
---------------------------------------------------------------------------

    1594. CAISO states that the Commission should not disrupt existing 
processes that are working efficiently, arguing that its transmission 
planning process already considers both local and regional assumptions, 
needs, and solutions as part of a single integrated process.\3408\ PG&E 
agrees that the NOPR proposal is unnecessary for California utilities 
and CAISO because many CAISO transmission owners already have extensive 
stakeholder programs. Therefore, PG&E states, the Commission should 
clarify that transmission providers are not required to enhance the 
transparency of local transmission planning processes where such 
transparent processes already exist.\3409\
---------------------------------------------------------------------------

    \3408\ CAISO Initial Comments at 47-50 (citations omitted).
    \3409\ PG&E Initial Comments at 15-18.
---------------------------------------------------------------------------

    1595. In addition, PG&E argues that the Commission should revise 
the NOPR proposal to state that the proposed enhancements to the local 
transmission planning process should not apply to asset management 
projects, including in-kind replacements, that are outside the scope of 
Order No. 890.\3410\ PG&E asserts that including asset management 
projects would significantly increase the volume and complexity of 
regional and local transmission planning and potentially delay needed 
repairs and maintenance. PG&E further states that all of PG&E's asset 
replacement projects are already scrutinized through the annual update 
to its formula transmission rate.\3411\
---------------------------------------------------------------------------

    \3410\ Id. at 15-16 (citing Cal. Pub. Utils. Comm'n v. Pac. Gas 
& Elec., 164 FERC ] 61,161 at P 66).
    \3411\ PG&E Reply Comments at 6-7.
---------------------------------------------------------------------------

    1596. Eversource contends that the current local transmission 
planning process in New England, which is based on the principles in 
Order No. 890, is largely consistent with the Commission's proposed 
transparency principles and has worked well.\3412\ Similarly, APS 
states that it currently uses its local transmission plans in the base 
model assumptions for its regional transmission planning process and 
provides stakeholders with an opportunity for input twice a year in 
public meetings as required by Order No. 890.\3413\
---------------------------------------------------------------------------

    \3412\ Eversource Initial Comments at 46-47 (citing ISO New 
England, Inc., Transmittal, Docket No. OA08-58 (filed Dec. 7, 
2007)).
    \3413\ APS Initial Comments at 12 (citing Order No. 890, 118 
FERC ] 61,119 at PP 257-258, 451).
---------------------------------------------------------------------------

    1597. Some commenters request that the Commission adopt a less 
prescriptive reform that outlines principles or goals for transparency 
and allow each transmission provider to either explain how its existing 
local transmission planning process already complies with those 
principles or propose targeted modifications to bring its existing 
process into compliance with the new requirements.\3414\ New York TOs 
note that efforts to improve transparency between local and regional 
transmission planning are beginning in NYISO, and they recommend that 
the Commission allow NYISO and New York TOs to demonstrate on 
compliance how any resulting enhancements will meet or exceed any new 
requirements.\3415\ Vermont Electric and Vermont Transco suggest that 
the Commission adopt a performance-based approach under which the 
Commission would specify expectations for transparency in local 
transmission planning processes and then allow transmission providers 
to determine how they will achieve those goals within longer 
timelines.\3416\
---------------------------------------------------------------------------

    \3414\ See Avangrid Initial Comments at 15; EEI Initial Comments 
at 40; Eversource Initial Comments at 48; Kansas Commission Initial 
Comments at 17; MISO Initial Comments at 84; MISO TOs Initial 
Comments at 31; National Grid Initial Comments at 39; New York TOs 
Initial Comments at 7, 16-17; Xcel Initial Comments at 17.
    \3415\ See New York TOs Initial Comments at 6-7, 16-17 
(citations omitted).
    \3416\ Vermont Electric and Vermont Transco Initial Comments at 
5.

---------------------------------------------------------------------------

[[Page 49526]]

    1598. Several commenters argue that the NOPR proposal is too 
prescriptive or may interfere with existing processes.\3417\ Eversource 
states that, if the Commission adopts a more prescriptive approach to 
local transmission planning, it could conflict with existing, state-
jurisdictional planning processes for local transmission projects, 
creating barriers to distribution facility upgrades that are needed to 
support expanded use of distributed energy resources and load growth 
from electrification.\3418\ Dominion cautions against adding more 
process when transmission providers already participate in extensive 
local transmission planning processes that consider Long-Term Regional 
Transmission Planning and stakeholder positions.\3419\ Avangrid agrees, 
asserting that the NOPR proposal could override existing processes that 
have been established over years of stakeholder consensus 
building.\3420\ PPL and American Municipal Power state that the NOPR 
proposal may not be appropriate for all transmission planning regions 
and may interfere with efficient and well-functioning local 
transmission planning.\3421\
---------------------------------------------------------------------------

    \3417\ Avangrid Initial Comments at 13; CAISO Initial Comments 
at 7-8, 47, 50; Dominion Initial Comments at 70; Eversource Initial 
Comments at 47-48; MISO Initial Comments at 86; PG&E Initial 
Comments at 17-18; PPL Initial Comments at 36; Xcel Initial Comments 
at 16-17.
    \3418\ Eversource Initial Comments at 49.
    \3419\ Dominion Initial Comments at 69-70.
    \3420\ Avangrid Initial Comments at 13.
    \3421\ American Municipal Power Initial Comments at 16; PPL 
Initial Comments at 36.
---------------------------------------------------------------------------

    1599. Certain commenters also argue that the NOPR proposal is 
unduly burdensome.\3422\ APS argues that the NOPR proposal could delay 
local transmission planning and prevent APS from providing necessary 
services.\3423\ National Grid asserts that the NOPR proposal ignores 
the reality that local transmission planning processes address 
different needs than the regional transmission planning process. 
National Grid argues that the proposal will introduce delay and 
uncertainty in both the local and regional transmission planning 
processes, disrupting currently effective procedures at a time when 
participants in the regional transmission planning process should be 
focused on Long-Term Regional Transmission Planning.\3424\
---------------------------------------------------------------------------

    \3422\ See Dominion Initial Comments at 68; Eversource Initial 
Comments at 49; National Grid Initial Comments at 39-40; Xcel 
Initial Comments at 16-17.
    \3423\ APS Initial Comments at 13.
    \3424\ National Grid Initial Comments at 39-40.
---------------------------------------------------------------------------

    1600. In addition, National Grid argues that the NOPR proposal will 
complicate transmission planning because individual transmission 
providers in each transmission planning region will need to integrate 
their local transmission planning efforts into the regional 
transmission planning process. Further, National Grid states that in 
multi-state RTO/ISO transmission planning regions, it could also lead 
to second guessing individual state policies as part of the regional 
transmission planning process. National Grid also avers that regional 
transmission planners, such as NYISO and ISO-NE, may not have 
visibility into the operation of lower voltage local transmission 
facilities and therefore may not have the expertise that is needed to 
consider local transmission needs as part of the regional transmission 
planning process.\3425\
---------------------------------------------------------------------------

    \3425\ Id.
---------------------------------------------------------------------------

    d. Specific Stakeholder Meeting Requirements
    1601. With respect to the length of time between stakeholder 
meetings, some commenters state that the 25-day minimum period between 
meetings in the NOPR proposal is too short.\3426\ PIOs state the 
Commission should require transmission providers to submit local 
transmission planning information, including information concerning 
planned local transmission projects, with enough time for the regional 
transmission planning process to effectively find, propose, approve, 
and construct cost-effective and beneficial regional alternatives where 
appropriate.\3427\
---------------------------------------------------------------------------

    \3426\ American Municipal Power Initial Comments at 24; 
Northwest and Intermountain Initial Comments at 21; PIOs Initial 
Comments at 51-54; TAPS Initial Comments at 6, 62.
    \3427\ PIOs Initial Comments at 51-52, 54 (citing PIOs ANOPR 
Initial Comments at 92-94; Concerned Scientists ANOPR Initial 
Comments at 24-31).
---------------------------------------------------------------------------

    1602. American Municipal Power contends that the NOPR proposal 
fails to identify whether and when transmission providers must provide 
information in advance of the three meetings. Moreover, American 
Municipal Power argues, 25 days between meetings is too short, even 
assuming all of the models, criteria, and needs are shared with 
stakeholders sufficiently in advance. Further, American Municipal Power 
states that the time between the Needs and Solutions Meetings should be 
based on the time required for transmission providers to incorporate 
comments received during the Needs Meeting and develop responses.\3428\
---------------------------------------------------------------------------

    \3428\ American Municipal Power Initial Comments at 24.
---------------------------------------------------------------------------

    1603. Eversource argues that the proposed meeting schedules are not 
workable in New England, where regional transmission planning studies 
focus on sub-areas of the transmission system and proceed on different 
timelines. Moreover, Eversource contends that it is not feasible in New 
England to have a three-meeting process that aligns with ISO-NE's 
annual transmission planning cycle because no such annual planning 
cycle exists.\3429\
---------------------------------------------------------------------------

    \3429\ Eversource Initial Comments at 47.
---------------------------------------------------------------------------

    1604. Dominion, Eversource, and Xcel state that the three separate 
stakeholder meetings to review assumptions, needs, and solutions are 
unnecessary and will increase workload without any benefit.\3430\ Xcel 
contends that a single meeting that addresses the transparency 
requirements of Order Nos. 890 and 1000, as well as any requirements 
from the final order, would be more efficient than the NOPR 
proposal.\3431\ NESCOE asserts that the final order should not dictate 
the number of stakeholder meetings.\3432\ MISO states that the 
Commission should allow each transmission planning region to determine 
the timing of the iterative meetings, as well as the specific 
information to be covered at the meetings.\3433\
---------------------------------------------------------------------------

    \3430\ Dominion Initial Comments at 68; Eversource Initial 
Comments at 47-48; Xcel Initial Comments at 17.
    \3431\ Xcel Initial Comments at 16-17.
    \3432\ NESCOE Initial Comments at 78 (citation omitted).
    \3433\ MISO Initial Comments at 84.
---------------------------------------------------------------------------

    1605. TAPS states that the Commission should require transmission 
providers to post their criteria, models, and assumptions so that 
stakeholders can evaluate or replicate their findings. Moreover, TAPS 
argues, the Commission should require that transmission providers 
distribute this information ``sufficiently in advance'' (and not just 
``in advance,'' as the NOPR proposed) of each meeting to allow 
stakeholders to review and evaluate the information.\3434\ Finally, 
TAPS states that a second Solutions Meeting would provide a meaningful 
opportunity to consider alternatives.\3435\
---------------------------------------------------------------------------

    \3434\ TAPS Initial Comments at 61 (citing NOPR, 179 FERC ] 
61,028 at P 402).
    \3435\ Id. at 62.
---------------------------------------------------------------------------

    1606. Likewise, American Municipal Power recommends that the 
Commission require a minimum of two Solutions Meetings, with the 
transmission provider presenting the solutions at the first meeting and 
the final solution, including alternatives considered, at the second. 
Further, American Municipal Power recommends that the first Solutions 
Meeting be no sooner than 90 days after the Needs Meeting and the 
second

[[Page 49527]]

Solutions Meeting no sooner than 30 days after the first Solutions 
Meeting. To the extent the Commission does not require a second 
Solutions Meeting, American Municipal Power recommends that it require 
transmission providers to provide additional clarity regarding how 
alternatives were developed and why they were not selected during the 
single Solutions Meeting.\3436\
---------------------------------------------------------------------------

    \3436\ American Municipal Power Initial Comments at 24-25.
---------------------------------------------------------------------------

    1607. While PJM States support requiring Assumptions, Needs, and 
Solutions Meetings as part of local transmission planning processes, 
similar to PJM's existing Attachment M-3 process, they express concern 
that PJM's process is not sufficiently responsive and that the growth 
of transmission-related costs in PJM is occurring without effective 
oversight.\3437\ PJM States reference PJM's requirement that 
transmission providers provide information on their local transmission 
plan and consider any comments received, but state that they are not 
required to ``meaningfully respond to, engage with, or incorporate'' 
these comments.\3438\
---------------------------------------------------------------------------

    \3437\ PJM States Initial Comments at 4-5 (citing PJM, 2021 
Regional Transmission Planning Expansion Plan 290 (Mar. 2022), 
https://www.pjm.com/-/media/library/reports-notices/2021-rtep/2021-rtep-report.ashx).
    \3438\ Id. at 6 (citing PJM, Intra-PJM Tariffs, OATT, attach. M-
3 (1.0.0), section (c) 1-6).
---------------------------------------------------------------------------

    1608. California Commission notes that the key elements of the 
California stakeholder processes that may be relevant for the 
Commission to consider including in a final order to increase 
transparency into local transmission planning include: (1) detailed 
project and capital expenditure data; (2) ample time to review proposed 
capital forecasts; (3) the ability for stakeholders to issue data 
requests and receive responses; (4) in-depth stakeholder meetings; and 
(5) consideration of stakeholder comments.\3439\
---------------------------------------------------------------------------

    \3439\ California Commission Initial Comments at 112-113.
---------------------------------------------------------------------------

    1609. New England for Offshore Wind argues that all transmission 
planning processes should include transparency into the evaluation of 
alternative options that could optimize the performance of renewable 
energy, as well as justification of proposed transmission projects 
based on how they compare to no action alternatives.\3440\ NRG 
encourages the Commission to require that the local transmission 
planning process produce an estimated rate impact for each year if the 
local transmission plan were to be executed.\3441\
---------------------------------------------------------------------------

    \3440\ New England for Offshore Wind Initial Comments at 6.
    \3441\ NRG Initial Comments at 7, 36.
---------------------------------------------------------------------------

    1610. Several commenters contend that transmission providers should 
be required to respond to comments and questions submitted by 
stakeholders in the local transmission planning process.\3442\ PJM 
States raise the same issue but look to the relevant RTOs/ISOs to 
resolve them.\3443\
---------------------------------------------------------------------------

    \3442\ See American Municipal Power Initial Comments at 18-19; 
California Commission Initial Comments at 112-113; DC and MD Offices 
of People's Counsel Initial Comments at 6; Kentucky Commission Chair 
Chandler Initial Comments at 22; Northwest and Intermountain Initial 
Comments at 20-21; TAPS Initial Comments at 62.
    \3443\ PJM States Initial Comments at 6.
---------------------------------------------------------------------------

    1611. American Municipal Power and DC and MD Offices of People's 
Counsel state that transmission providers are not obligated to respond 
to stakeholder questions, which, when considered alongside the other 
barriers to effective participation, creates unnecessary barriers to 
open communication, is not just and reasonable, and is unduly 
discriminatory.\3444\ American Municipal Power further asserts that 
comparability principles require transmission providers to consider 
transmission customers' comments in order to meet their needs and to 
treat similarly situated customers comparably while conducting 
transmission system planning.\3445\ However, PJM and Indicated PJM TOs 
disagree that stakeholder comments are being ignored in PJM's 
Attachment M-3 process.\3446\
---------------------------------------------------------------------------

    \3444\ See American Municipal Power Initial Comments at 19-20; 
DC and MD Offices of People's Counsel Initial Comments at 6-7.
    \3445\ American Municipal Power Initial Comments at 19.
    \3446\ Indicated PJM TOs Reply Comments at 4, 18-19 (citations 
omitted); PJM Reply Comments at 13-15 (citing American Municipal 
Power Initial Comments at 19).
---------------------------------------------------------------------------

    1612. TAPS states that dispute resolution on criteria, assumptions, 
needs, and proposed solutions should be available if stakeholder 
comments are ignored.\3447\ TAPS asserts that the Commission should 
include such provisions in any final order or clarify that they are 
already encompassed in the Commission's transparency proposal.\3448\
---------------------------------------------------------------------------

    \3447\ TAPS Initial Comments at 62 (citing Order No. 890, 118 
FERC ] 61,119 at PP 501-503).
    \3448\ Id.
---------------------------------------------------------------------------

e. Additional Issues
    1613. Pattern Energy and American Municipal Power state that the 
NOPR proposal does not go far enough in ensuring stakeholder access to 
transmission planning data from the local transmission planning 
processes and propose additional requirements to make certain 
information more readily available, subject to execution of a CEII non-
disclosure agreement.\3449\ Similarly, Pattern Energy states that 
continued stakeholder access to the source data used in transmission 
modeling by transmission providers is essential to ensure fair and 
reasonable outcomes in any transmission planning process.\3450\ PPL 
requests that the Commission clarify that confidential or sensitive 
information will be protected under the NOPR proposal in the local 
transmission planning processes as they currently are in PJM.\3451\
---------------------------------------------------------------------------

    \3449\ See American Municipal Power Initial Comments at 22; 
Pattern Energy Initial Comments at 30-31.
    \3450\ Pattern Energy Initial Comments at 30-31.
    \3451\ PPL Initial Comments at 36.
---------------------------------------------------------------------------

    1614. Certain TDUs state that the Commission should require 
transmission providers to coordinate with load-serving entities to 
transfer data and information and increase transparency in the 
stakeholder process.\3452\ ACEG recommends that the Commission require 
minimum data transparency standards in the local transmission planning 
processes, drawing on MISO's and SPP's cost recording and tracking 
processes for transmission projects approved through their regional 
transmission planning processes.\3453\ Maryland Energy Administration 
asserts that additional reforms beyond those proposed in the NOPR are 
needed to support transparency and better incorporate stakeholder 
contributions in local transmission planning processes.\3454\ 
California Water recommends that the Commission allow data requests, 
similar to the opportunity for data requests in the SoCal Edison and 
PG&E stakeholder review processes, which ensure that stakeholders can 
participate and that transmission providers exercise good faith efforts 
to respond.\3455\
---------------------------------------------------------------------------

    \3452\ Certain TDUs Initial Comments at 18.
    \3453\ ACEG Initial Comments at 56 (citing Johannes 
Pfeifenberger et al., The Brattle Group, Cost Savings Offered by 
Competition in Electric Transmission: Experience to Date and the 
Potential for Additional Customer Value 26 (Apr. 2019)).
    \3454\ See Maryland Energy Administration Reply Comments at 2-3 
(citations omitted).
    \3455\ California Water Initial Comments at 7-8 (citing S. Cal. 
Edison, Filing, App. XII, ER19-1553-000, at section 2.2 (filed July 
2, 2020); Pac. Gas & Elec. Co., Filing, App. IX, ER19-13-001, at 
section 3.2 (filed Mar. 31, 2020)).
---------------------------------------------------------------------------

    1615. American Municipal Power requests that the Commission direct 
transmission providers to provide detailed information consisting of 
more than generic or high-level network models, along with power flow 
models and power system analyses used in their

[[Page 49528]]

local transmission planning.\3456\ According to American Municipal 
Power, to allow stakeholders to evaluate the outputs of transmission 
providers' studies--i.e., the identified transmission needs--on their 
own, transmission providers must be required to provide the 
models.\3457\ Furthermore, American Municipal Power argues, the 
Commission should require transmission providers to provide information 
on how assets have been prioritized for replacement, how the 
replacement versus maintenance decision is made, how assets rank 
relative to other assets on the system, and the system average 
values.\3458\
---------------------------------------------------------------------------

    \3456\ American Municipal Power Initial Comments at 20-21.
    \3457\ Id. at 21.
    \3458\ Id. at 22-23.
---------------------------------------------------------------------------

    1616. Several commenters state that the NOPR proposal does not go 
far enough to protect customers' interests and suggest the addition of 
more process, more oversight, more monitoring (including establishing 
an independent transmission monitor), or more prudence reviews.\3459\ 
According to PIOs, transmission providers have incentives to avoid 
independent transmission planning processes because local transmission 
projects are presumed to be prudent, avoid competition, and receive 
high rates of return. PIOs state that the Commission should reduce the 
rate of return for local transmission projects and issue a rule or 
policy statement that puts the burden of proof on transmission 
providers to demonstrate that the cost of a proposed transmission 
project is just and reasonable.\3460\
---------------------------------------------------------------------------

    \3459\ California Commission Initial Comments at 111-112 & 
n.401; Colorado Consumer Advocates Initial Comments at 31; Joint 
Consumer Advocates Initial Comments at 25-29; NRG Initial Comments 
at 7, 36; Ohio Consumers Initial Comments at 23-24; OMS Initial 
Comments at 16-17; Pattern Energy Initial Comments at 31-34; Pine 
Gate Initial Comments at 49-50; PIOs Initial Comments at 51-52; PJM 
States Initial Comments at 4-6; TAPS Initial Comments at 61-62; US 
DOJ and FTC Initial Comments at 20-21.
    \3460\ PIOs Initial Comments at 52-53.
---------------------------------------------------------------------------

    1617. Joint Consumer Advocates state that, while the NOPR proposal 
is an improvement, more needs to be done to address the imbalance 
between consumer advocates and incumbent transmission owners. 
Therefore, Joint Consumer Advocates assert, the Commission should 
authorize the creation of an independent transmission monitor to 
evaluate the effective coordination of local transmission projects with 
more holistic transmission planning to identify the most efficient or 
cost-effective approach to meeting local, regional, and interregional 
transmission needs.\3461\ Relatedly, California Commission and Colorado 
Consumer Advocates suggest that the Commission give independent 
transmission monitors the responsibility to evaluate stakeholder 
comments, independently analyze whether there are potentially more 
efficient and cost-effective alternative transmission solutions to meet 
identified transmission needs, and make a recommendation.\3462\ Potomac 
Economics argues that the Commission's transparency goals likely cannot 
be met without an independent transmission monitor.\3463\
---------------------------------------------------------------------------

    \3461\ Joint Consumer Advocates Initial Comments at 26-29 
(citations omitted).
    \3462\ California Commission Initial Comments at 111-112; 
Colorado Consumer Advocates Initial Comments at 31.
    \3463\ See Potomac Economics Initial Comments at 6.
---------------------------------------------------------------------------

    1618. Some commenters opine on whether the regional transmission 
planning process should assume an expanded role in reviewing or 
approving identified local transmission projects.\3464\ In addition, 
NARUC recommends that the Commission allow the proposed stakeholder 
review process to apply to repair and replacement projects that do not 
expand the capacity of the transmission system, or do so only 
incidentally, in particular those that are forecast to cost $3 million 
or more. NARUC asserts that, limiting the reforms to local transmission 
planning may exclude review of these projects, which currently comprise 
half of investor-owned utilities' transmission spending in the RTOs/
ISOs. Further, NARUC urges the Commission to allow these projects, 
along with local transmission projects, to be reviewed and approved as 
part of the regional transmission planning process.\3465\ California 
Commission agrees, stating that there should be more external scrutiny 
of such projects to reduce incumbent utilities' existing perverse 
incentive to overinvest in these types of projects due to their lack of 
external review.\3466\
---------------------------------------------------------------------------

    \3464\ See American Municipal Power Reply Comments at 3-7; 
California Commission Initial Comments at 108-110; DC and MD Offices 
of People's Counsel Initial Comments at 7; NARUC Initial Comments at 
60-61; Ohio Consumers Reply Comments at 17-18; PJM States Initial 
Comments at 6-7.
    \3465\ NARUC Initial Comments at 60-63 (citations omitted).
    \3466\ California Commission Initial Comments at 109-110 
(citations omitted).
---------------------------------------------------------------------------

    1619. PJM States call on RTOs/ISOs to go beyond evaluating whether 
local transmission projects ``do no harm'' by actively taking a stance 
on such projects, discussing how this stance was reached, and by 
proposing transmission projects that may be the most cost-
effective.\3467\ However, PJM States ask the Commission to explicitly 
avoid impinging on state-jurisdictional processes.\3468\
---------------------------------------------------------------------------

    \3467\ PJM States Initial Comments at 6-7 (citation omitted).
    \3468\ Id. at 7.
---------------------------------------------------------------------------

    1620. DC and MD Offices of People's Counsel and American Municipal 
Power assert that the remedy for the current lack of a requirement to 
incorporate or respond to stakeholder feedback in the local 
transmission planning process is an empowered regional transmission 
planner that is independent and incorporates meaningful participation 
from all stakeholders beginning with the determination of any 
transmission needs through the project selection phase.\3469\ 
Relatedly, Ohio Consumers state that the NOPR proposal leaves sole 
discretion in selection of transmission projects and the costs of the 
projects to transmission providers.\3470\
---------------------------------------------------------------------------

    \3469\ American Municipal Power Reply Comments at 3-7 (citations 
omitted); DC and MD Offices of People's Counsel Initial Comments at 
7.
    \3470\ Ohio Consumers Reply Comments at 18.
---------------------------------------------------------------------------

    1621. However, some commenters defend the separation between local 
and regional transmission planning processes.\3471\ For instance, AEP 
disagrees that transmission providers seek to build local transmission 
projects to circumvent the regional transmission planning 
process.\3472\ According to AEP, local and regional transmission 
planning processes are not interchangeable because most local 
transmission facilities directly serve load and local utilities must 
address local needs when those needs are not addressed by a regional 
transmission facility in a cost-effective manner.\3473\ Nevertheless, 
AEP states, there can be an effective and efficient intersection 
between local and regional transmission planning, citing PJM's open and 
transparent local transmission planning process that requires 
coordination with the regional transmission planning process and in 
which PJM is an active participant.\3474\ Similarly, WIRES states that 
there are good reasons for maintaining a distinction between regional 
and local transmission planning, noting that the regional transmission 
planning process is directed toward addressing certain

[[Page 49529]]

reliability, economic criteria, and public policy initiatives, not the 
additional system needs related to resilience, asset management, 
customer needs, customer impact, and aging infrastructure replacement 
that are the focus of local transmission planning.\3475\
---------------------------------------------------------------------------

    \3471\ AEP Reply Comments at 6-7; MISO Reply Comments at 27; 
PG&E Reply Comments at 4-9; WIRES Initial Comments at 9.
    \3472\ AEP Reply Comments at 6-7 (citing AEE Initial Comments at 
38; PIOs Initial Comments at 8-9; Resale Iowa Initial Comments at 7-
8; US DOJ and FTC Initial Comments at 7).
    \3473\ Id. at 2-3.
    \3474\ Id. at 8 (citing PJM, Intra-PJM Tariffs, OATT, attach. M-
3 (1.0.0)).
    \3475\ WIRES Initial Comments at 9 (citing Charles River 
Associates, The Value of Local Transmission Planning 9, 13 (Dec. 
2021), https://wiresgroup.com/wp-content/uploads/2021/12/Value-of-Local-Transmission-Planning-report-WIRES-CRA.pdf).
---------------------------------------------------------------------------

    1622. Eversource states that, if the Commission decides to require 
a more prescriptive local transmission planning process, it should 
clarify that the process applies only to upgrades that are developed 
primarily to increase the capacity of the local transmission system, 
and not to upgrades that are incidental to state-jurisdictional 
distribution system planning or other unique local requirements.\3476\
---------------------------------------------------------------------------

    \3476\ Eversource Initial Comments at 49.
---------------------------------------------------------------------------

    1623. MISO defends the transparency of local transmission planning 
in MISO by stating that commenters who criticize existing local 
transmission planning processes ``ignore the open, transparent process 
in effect, and fail to recognize the ongoing need for near-term 
planning.'' \3477\ MISO states that local and regional transmission 
planning are complementary and that ``near-, mid- and long-term 
planning work in concert.'' \3478\ MISO contends that its existing 
process includes extensive stakeholder involvement that ensures that 
issues are identified and alternatives are considered.\3479\
---------------------------------------------------------------------------

    \3477\ MISO Reply Comments at 27 (citing PIOs Initial Comments 
at 32).
    \3478\ Id.
    \3479\ Id.
---------------------------------------------------------------------------

    1624. PG&E opposes comments in favor of removing the role of local 
transmission planning from local transmission owners, as well as 
requests to expand the NOPR proposal to apply to asset management 
projects. PG&E notes that California Commission has not provided any 
evidence that RTOs/ISOs are currently unable to adequately handle the 
regional and local transmission planning processes.\3480\
---------------------------------------------------------------------------

    \3480\ PG&E Reply Comments at 4-9 (citations omitted).
---------------------------------------------------------------------------

3. Commission Determination
    1625. We adopt the NOPR proposal, with modification, to require 
transmission providers in each transmission planning region to revise 
the regional transmission planning process in their OATTs to enhance 
the transparency of: (1) the criteria, models, and assumptions that 
they use in their local transmission planning process; (2) the local 
transmission needs that they identify through the local transmission 
planning process; and (3) the potential local or regional transmission 
facilities that they will evaluate to address those local transmission 
needs. For each of these three categories of local transmission 
planning information, and as discussed further below, transmission 
providers must identify and publicly post the information identified 
below, then conduct publicly-noticed stakeholder meetings to provide an 
opportunity for comment on the information both before and after the 
stakeholder meetings, as part of the regional transmission planning 
process. In response to comments from PG&E,\3481\ we clarify that this 
requirement applies only to local transmission planning that is within 
the scope of Order No. 890 and is therefore already subject to Order 
No. 890 transparency requirements. As such, this requirement does not 
apply to asset management projects.\3482\ However, nothing in this 
final order prevents transmission providers from choosing to apply 
these requirements to asset management projects.
---------------------------------------------------------------------------

    \3481\ PG&E Initial Comments at 17 (citing Cal. Pub. Utils. 
Comm'n v. Pac. Gas & Elec., 164 FERC ] 61,161 at P 66).
    \3482\ See S. Cal. Edison Co., 164 FERC ] 61,160 at PP 30-40; 
Cal. Pub. Utils. Comm'n v. Pac. Gas. & Elec. Co., 164 FERC ] 61,161 
at PP 65-74 (finding that Order No. 890's local transmission 
planning requirements do not apply to asset management projects that 
do not increase capacity or do so incidentally).
---------------------------------------------------------------------------

    1626. In complying with this requirement, transmission providers 
must establish an iterative process that ensures that stakeholders have 
meaningful opportunities to participate in and provide feedback on 
local transmission planning throughout the regional transmission 
planning process. To provide the needed transparency and opportunities 
for stakeholder participation, we require that the regional 
transmission planning process include at least three publicly-noticed 
stakeholder meetings per regional transmission planning cycle 
concerning the local transmission planning process of each transmission 
provider that is a member of the transmission planning region before 
each transmission provider's local transmission plan can be 
incorporated into the transmission planning region's planning models.
    1627. Specifically, we adopt the NOPR proposal to require that, 
prior to the submission of local transmission planning information to 
the transmission planning region for inclusion in the regional 
transmission planning process, transmission providers in each 
transmission planning region must convene, collectively, as part of the 
regional transmission planning process, a stakeholder meeting to review 
the criteria, assumptions, and models related to each transmission 
provider's local transmission planning (Assumptions Meeting). Next, no 
fewer than 25 calendar days after the Assumptions Meeting, transmission 
providers in each transmission planning region must convene, 
collectively, as part of the regional transmission planning process, a 
stakeholder meeting to review identified reliability criteria 
violations and other transmission needs that drive the need for local 
transmission facilities (Needs Meeting). Finally, no fewer than 25 
calendar days after the Needs Meeting, transmission providers in each 
transmission planning region must convene, collectively, as part of the 
regional transmission planning process, a stakeholder meeting to review 
potential solutions to those reliability criteria violations and other 
transmission needs (Solutions Meeting). Additionally, we require that 
all materials for stakeholder review during these three meetings be 
publicly posted and that stakeholders have opportunities before and 
after each meeting to submit comments.
    1628. In addition to these requirements, we modify the NOPR 
proposal to also require transmission providers to publicly post the 
meeting materials no fewer than five calendar days prior to each of the 
three publicly-noticed stakeholder meetings to allow time for 
stakeholders to review materials in advance of each meeting. Also, we 
require that transmission providers allow for a period of no fewer than 
25 calendar days following the Solutions Meeting to review and consider 
stakeholder feedback on the local transmission solutions identified to 
meet the local transmission needs before the local transmission plan 
can be incorporated in the transmission planning region's planning 
models. Requiring this minimum 25 calendar day period is consistent 
with Order No. 1000, where the Commission stated that the Commission 
intends that the regional transmission planning processes provide for 
the timely and meaningful input and participation of stakeholders in 
the development of regional transmission plans.\3483\ Lastly, we 
require that transmission providers must respond to questions or 
comments from stakeholders such that it allows stakeholders to 
meaningfully participate in these three required stakeholder meetings.
---------------------------------------------------------------------------

    \3483\ Order No. 1000, 136 FERC ] 61,051 at P 153 (citing Order 
No. 890, 118 FERC ] 61,119 at P 454).

---------------------------------------------------------------------------

[[Page 49530]]

    1629. We find that establishing a standard baseline of transparency 
into transmission providers' local transmission planning processes will 
ensure that stakeholders have an opportunity to review and provide 
feedback on local transmission planning assumptions, needs, and 
solutions that are used as inputs to the regional transmission planning 
process. We expect that this additional transparency will help reduce 
the possibility that transmission providers will develop local 
transmission facilities without adequately considering whether there is 
a more efficient or cost-effective regional transmission solution that 
could address their local transmission needs. This additional 
transparency will enable transmission providers to satisfy their 
requirements for regional transmission planning under Order No. 
1000.\3484\
---------------------------------------------------------------------------

    \3484\ Id. PP 78-84.
---------------------------------------------------------------------------

    1630. We believe that the local transmission planning information 
provided pursuant to the enhanced transparency requirements that we 
adopt in this final order will better facilitate the identification 
through the regional transmission planning process of regional 
transmission facilities that may be more efficient or cost-effective 
than proposed local transmission facilities.\3485\ Specifically, 
transmission providers' local transmission planning information will be 
subject to review and comment by stakeholders that may provide 
additional information or identify considerations that could inform the 
criteria, models, and assumptions used in local transmission planning, 
the identification of local transmission needs, and the identification 
of transmission facilities to address those local transmission needs. 
Because local transmission planning information serves as an input to 
the regional transmission planning process, these improvements will, in 
turn, facilitate the identification of more efficient or cost-effective 
transmission facilities in the regional transmission planning process, 
resulting in Commission-jurisdictional rates that are just and 
reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \3485\ NOPR, 179 FERC ] 61,028 at P 402.
---------------------------------------------------------------------------

    1631. With respect to the comments from National and State 
Conservation Organizations and WE ACT \3486\ that robust input from 
affected and overburdened communities in the local transmission 
planning process is important, we believe that the added transparency 
requirements that require transmission providers to identify and 
publicly post the information and then conduct stakeholder meetings as 
part of the regional transmission planning process, provides an 
opportunity for interested parties to engage and comment on the 
information.
---------------------------------------------------------------------------

    \3486\ National and State Conservation Organizations Initial 
Comments at 2; WE ACT Initial Comments at 5-6.
---------------------------------------------------------------------------

    1632. With regard to commenters that suggest that the additional 
transparency requirements proposed in the NOPR will not be effective 
because they do not go far enough in making changes to local 
transmission planning processes,\3487\ we find that the enhanced 
transparency requirements that we adopt in this final order are 
specifically designed to provide needed transparency to ensure that 
Commission-jurisdictional rates are just and reasonable and not unduly 
discriminatory or preferential. In addition, we find that other 
commenters' suggestions for changes to local transmission planning 
processes were not proposed in the NOPR and therefore are outside the 
scope of this proceeding. We conclude that the replacement rate set 
forth herein is just and reasonable and addresses the deficiencies 
identified herein.\3488\ We note that the Commission continues to 
examine a suite of related issues in its Transmission Planning and Cost 
Management proceeding.\3489\
---------------------------------------------------------------------------

    \3487\ See American Municipal Power Initial Comments at 17-18; 
Ohio Commission Federal Advocate Initial Comments at 19-20.
    \3488\ See New York v. FERC, 535 U.S.at 26-28 (upholding 
Commission's decision not to assert jurisdiction over bundled retail 
transmission).
    \3489\ See Transmission Planning and Cost Management, Notice of 
Technical Conference, Docket No. AD22-8-000 (Apr. 21, 2022).
---------------------------------------------------------------------------

    1633. In response to American Municipal Power's assertion that the 
PJM Attachment M-3 process has increased the problem of planning based 
on individual transmission owners' criteria and the balkanization of 
the transmission planning process,\3490\ we find that American 
Municipal Power has not persuasively explained why these concerns are 
the result of increasing the transparency of local transmission 
planning, rather than other factors associated with the PJM Attachment 
M-3 process. Based on the record before us, we do not expect that 
requiring enhanced transparency in local transmission planning, in the 
manner directed in this final order, will result in greater incentives 
for transmission providers to develop local transmission facilities in 
lieu of regional transmission facilities. Instead, we expect that 
additional opportunities for stakeholder review of and comment on local 
transmission planning inputs into the regional transmission planning 
process will help to facilitate the identification of regional 
transmission facilities that are more efficient or cost-effective 
compared to transmission facilities identified in the local 
transmission planning process.
---------------------------------------------------------------------------

    \3490\ American Municipal Power Initial Comments at 17.
---------------------------------------------------------------------------

    1634. We disagree with commenters that state that the NOPR proposal 
is not needed in their transmission planning region because their local 
transmission planning process is already sufficiently 
transparent.\3491\ The reforms that we adopt here are necessary to 
ensure just and reasonable rates, as more fully explained above. 
Additionally, we believe that these reforms to enhance the transparency 
of local transmission planning inputs into the regional transmission 
planning process are necessary to ensure that interested stakeholders 
have an opportunity to meaningfully participate in the review of the 
local transmission planning assumptions, needs, and solutions before 
each transmission provider's local transmission plan can be 
incorporated into the transmission planning region's planning models.
---------------------------------------------------------------------------

    \3491\ APS Initial Comments at 12-13; Avangrid Initial Comments 
at 13-15; CAISO Initial Comments at 46-50; Dominion Initial Comments 
at 69-70; Eversource Initial Comments at 46-49; MISO Initial 
Comments at 84-86; MISO TOs Initial Comments at 29-31; National Grid 
Initial Comments at 39; New York TOs Initial Comments at 16; 
Pennsylvania Commission Initial Comments at 20; PG&E Initial 
Comments at 16-18.
---------------------------------------------------------------------------

    1635. Similarly, we disagree with commenters that oppose the 
proposal because it may interfere with existing transmission planning 
processes.\3492\ As we explain above, the enhanced transparency and 
opportunities for stakeholder participation are needed to ensure just 
and reasonable Commission-jurisdictional rates. Although we appreciate 
that there may be differences in how transmission providers currently 
conduct local transmission planning, we believe that the standard 
baseline of transparency established by the requirements adopted in 
this final order is needed to ensure that stakeholders have an 
opportunity to review and provide feedback on local transmission 
planning inputs that go into the regional transmission planning process 
and to ensure that the regional transmission planning process can 
identify regional transmission facilities that address transmission 
needs more efficiently or

[[Page 49531]]

cost-effectively than local transmission facilities. The fact that 
transmission providers may need to adjust their existing processes to 
comply with these requirements is not a sufficient reason for the 
Commission to decline to adopt them.
---------------------------------------------------------------------------

    \3492\ Avangrid Initial Comments at 13; CAISO Initial Comments 
at 7, 47; Dominion Initial Comments at 70; Eversource Initial 
Comments at 47-48; MISO Initial Comments at 86; PG&E Initial 
Comments at 17-18; PPL Initial Comments at 36; Xcel Initial Comments 
at 16-17.
---------------------------------------------------------------------------

    1636. We also disagree with commenters that argue that the proposal 
is too prescriptive.\3493\ We believe that these requirements strike a 
reasonable balance between the need for transparency of local 
transmission planning inputs that are used in regional transmission 
planning and providing transmission providers with flexibility in how 
they conduct their local transmission planning processes. In fact, 
experience with the PJM Attachment M-3 process, which includes similar 
requirements to those adopted in this final order, provides evidence 
that it is possible to satisfy these requirements with a process that 
allows transmission providers to produce their local transmission plans 
on a timely basis.\3494\ In response to National Grid's concern that 
the NOPR proposal would impose a new requirement to integrate their 
local transmission planning with regional transmission planning,\3495\ 
the final order imposes no new requirements beyond the three meetings 
and associated opportunities for comment described above. We believe 
that these requirements add only a small but manageable burden for 
transmission providers, which is outweighed by the transparency 
benefits that would accrue to stakeholders participating in the local 
and regional transmission planning processes.
---------------------------------------------------------------------------

    \3493\ See Avangrid Initial Comments at 13-15; EEI Initial 
Comments at 40; Eversource Initial Comments at 47-48; Kansas 
Commission Initial Comments at 17; MISO Initial Comments at 84-86; 
MISO TOs Initial Comments at 29-31; National Grid Initial Comments 
at 39-41; New York TOs Initial Comments at 7, 16-17; Xcel Initial 
Comments at 17.
    \3494\ See Indicated PJM TOs Initial Comments at 42-43 
(citations omitted).
    \3495\ National Grid Initial Comments at 39-40.
---------------------------------------------------------------------------

    1637. With respect to the comments of APS and National Grid that 
local transmission planning cycles might be delayed by the new 
transparency requirements,\3496\ we reiterate that the final order 
strikes a reasonable balance between the need for transparency of local 
transmission planning inputs that are used in regional transmission 
planning and providing transmission providers with flexibility in how 
they conduct their local transmission planning processes. We believe 
that, even with the additional requirements that we establish here, it 
is possible for transmission providers to produce local transmission 
plans within a 12-month period, especially given that when scheduling 
the three required meetings, transmission providers need not leave more 
than 25 calendar days between each meeting. The experience of PJM TOs, 
whose local transmission planning processes are subject to similar 
requirements, demonstrates that it is possible to satisfy these 
requirements in a timely manner.\3497\
---------------------------------------------------------------------------

    \3496\ APS Initial Comments at 13; National Grid Initial 
Comments at 39-40.
    \3497\ Exelon Initial Comments at 3-4, 51-52 (citing PJM, Intra-
PJM Tariffs, OATT, attach. M-3 (1.0.0)); Indicated PJM TOs Initial 
Comments at 42-43.
---------------------------------------------------------------------------

a. Specific Stakeholder Meeting Requirements
    1638. We address in this section the requirements specific to the 
implementation details associated with the three publicly-noticed 
stakeholder meetings that transmission providers are required to 
conduct: the Assumptions Meeting, the Needs Meeting, and the Solutions 
Meeting, that were discussed above. We believe that these requirements 
strike a reasonable balance between providing adequate time to allow 
interested stakeholders to review and comment on local transmission 
planning inputs that are used in regional transmission planning and 
allowing the efficient and timely execution of the local transmission 
planning process. In our view, allowing transmission providers to limit 
the length of time between the three required meetings accomplishes 
this balance.
    1639. With respect to commenters who argue that a minimum of 25 
calendar days between publicly-noticed stakeholder meetings is too 
short,\3498\ we disagree. The minimum period between stakeholder 
meetings is just that, a minimum, and we expect that transmission 
providers and their stakeholders will, in practice, implement a 
schedule for the required stakeholder meetings that best meets the 
needs of their transmission planning region. However, we find that a 
minimum of less than 25 calendar days between stakeholder meetings 
would not allow stakeholders to participate in a meaningful way, and we 
therefore adopt this minimum period as an appropriate baseline for 
providing stakeholders with a meaningful opportunity to review and 
comment on local transmission planning inputs that are used in regional 
transmission planning. And, in fact, at least some transmission 
providers have adopted this minimum duration between stakeholder 
meetings.\3499\
---------------------------------------------------------------------------

    \3498\ American Municipal Power Initial Comments at 24; 
Northwest and Intermountain Initial Comments at 21; TAPS Initial 
Comments at 6, 62.
    \3499\ See PJM, Intra-PJM Tariffs, OATT, attach. M-3 (1.0.0.), 
which, briefly, refers to the additional transparency and 
stakeholder input rules around transmission facilities that are not 
eligible for selection, but, though classified as local transmission 
facilities, nonetheless impact the identification and selection of 
regional transmission facilities. See also Duke Energy Carolinas, 
LLC, 186 FERC ] 61,178, at PP 13, 27 (2024) (accepting Duke's OATT 
revisions to adopt a stakeholder meeting process that includes an 
Assumptions Meeting, Needs Meeting, and Solutions Meeting, each no 
fewer than 25 calendar days apart).
---------------------------------------------------------------------------

    1640. We clarify that transmission providers are required to 
provide information at least five calendar days prior to each of the 
three publicly-noticed stakeholder meetings. As stated above, 
transmission providers must publicly notice each meeting and publicly 
post all materials for stakeholder review during the three meetings and 
provide opportunities for stakeholders to submit comments before and 
after each meeting. We believe that providing this information at least 
five calendar days prior to each of the three stakeholder meetings 
strikes a balance between giving stakeholders meaningful opportunity to 
review the meeting materials ahead of each meeting and limiting the 
burden to transmission providers in posting the materials ahead of 
time. Furthermore, the information that we require transmission 
providers to share is information that they use in their local 
transmission planning processes and, thus, is information that they 
generally already possess.
    1641. We disagree with commenters that argue that three separate 
publicly-noticed stakeholder meetings are unnecessary and will increase 
workload without any benefit, or that a single meeting would address 
the Commission's transparency concerns more efficiently, or request 
that the Commission not dictate the number of stakeholder 
meetings.\3500\ We note that Indicated PJM TOs state that the PJM 
Attachment M-3 process has the benefit of avoiding duplication of 
projects between local and regional transmission planning 
processes.\3501\ We also disagree with MISO's argument that we should 
allow each transmission planning region to have complete discretion 
over the timing of the meetings, as well as the specific information to 
be covered at the meetings.\3502\ While we allow flexibility in certain 
aspects of the transmission planning processes, we find that the 
requirement to hold three separate

[[Page 49532]]

stakeholder meetings a minimum of 25 calendar days apart and 
prescribing the type of information that transmission providers must 
share at each meeting is necessary to ensure that Commission-
jurisdictional rates remain just and reasonable and not unduly 
discriminatory or preferential. We balance the increased burden imposed 
on transmission providers with the benefits associated with providing 
increased information and opportunities for stakeholder review of and 
comment on the local transmission planning inputs that are used in the 
regional transmission planning process. In addition, as discussed 
above, we believe that these reforms will reduce after-the-fact 
disputes and will help facilitate the identification of regional 
transmission facilities that may be more efficient or cost-effective 
than proposed local transmission facilities. As a result, the 
incremental burden of having to hold three stakeholder meetings to 
share this information and to consider input from stakeholders in 
response to this information is outweighed by the benefits that the 
increased transparency will provide.
---------------------------------------------------------------------------

    \3500\ Dominion Initial Comments at 68; Eversource Initial 
Comments at 47-48; NESCOE Initial Comments at 78; Xcel Initial 
Comments at 17.
    \3501\ Indicated PJM TOs Initial Comments at 42.
    \3502\ MISO Initial Comments at 84.
---------------------------------------------------------------------------

    1642. We also find unconvincing Eversource's assertion that the 
reforms will not work where there is not a precisely defined regional 
transmission planning cycle, such as is the case in ISO-NE.\3503\ The 
requirement to hold three publicly-noticed stakeholder meetings is 
triggered by the submission of local transmission planning information 
to the transmission planning region for inclusion in the regional 
transmission planning process and is not tied to a particular 
transmission planning cycle. Nevertheless, we recognize that these 
reforms may require transmission providers to propose adjustments to 
their existing processes. But as explained above, we believe that the 
need for transparency and stakeholder involvement requires these 
changes to ensure that Commission-jurisdictional rates are just and 
reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \3503\ Eversource Initial Comments at 47.
---------------------------------------------------------------------------

    1643. In response to TAPS' request that transmission providers be 
required to post their transmission planning criteria, models, and 
assumptions,\3504\ we reiterate that transmission providers must 
provide this information as part of the Assumptions Meeting. We further 
note that the requirement for transmission providers to disclose to all 
customers and other stakeholders the basic criteria, assumptions, and 
data that underlie their transmission systems is an existing 
requirement of Order No. 890. This information must enable customers, 
other stakeholders, or an independent third party to replicate the 
results of planning studies and thereby reduce the incidence of after-
the-fact disputes regarding whether planning has been conducted in an 
unduly discriminatory fashion.\3505\ The Commission recognized in Order 
No. 890 that safeguards must be put in place to ensure that 
confidentiality and CEII concerns are adequately addressed in 
transmission planning activities and, therefore, requires that 
transmission providers have mechanisms in place in their OATTs to 
manage confidentiality and CEII concerns, such as confidentiality 
agreements and password-protected access to information.\3506\ However, 
we reiterate that information must be disclosed, under applicable 
confidentiality provisions, if the information is needed to participate 
in the transmission planning process and to replicate transmission 
planning studies, which necessarily includes access to the models that 
underlie transmission planning processes.
---------------------------------------------------------------------------

    \3504\ TAPS Initial Comments at 61.
    \3505\ Order No. 890, 118 FERC ] 61,119 at P 471.
    \3506\ Id. P 460.
---------------------------------------------------------------------------

    1644. We decline to require, as requested by American Municipal 
Power and TAPS, that transmission providers hold two Solutions 
Meetings.\3507\ While a transmission provider may determine that 
additional stakeholder meetings are appropriate or necessary, we only 
require transmission providers to conduct the three publicly-noticed 
stakeholder meetings discussed above. However, there is nothing in this 
final order that prohibits transmission providers from holding 
additional meetings, beyond those required here. We find NRG's request 
that the Commission require the local transmission planning process 
include an estimated rate impact for each year if the local 
transmission plan were to be executed to be beyond the scope of the 
proposal, although transmission providers may choose to provide this 
information outside of the context of this order.
---------------------------------------------------------------------------

    \3507\ American Municipal Power Initial Comments at 24-25; TAPS 
Initial Comments at 62 (citing NOPR, 179 FERC ] 61,028 at P 402).
---------------------------------------------------------------------------

    1645. In response to commenters that request that the Commission 
require transmission providers to respond to all comments and questions 
submitted by stakeholders in the local transmission planning 
process,\3508\ we clarify that such a requirement could be too 
prescriptive in certain circumstances and thus we decline to set a 
bright-line rule that transmission providers must respond to each and 
every question or comment received through the stakeholder process. 
Nevertheless, we require transmission providers to respond to questions 
or comments in a manner that allows stakeholders to meaningfully 
participate in these stakeholder meetings. For example, in the context 
of live discussions in any of the three required publicly-noticed 
stakeholder meetings, we expect transmission providers to offer 
stakeholders an opportunity to speak, engage, and ask questions, as 
well as receive reasonable responses at the meeting consistent with 
meaningful participation. Overall, we encourage transmission providers 
to be as responsive as possible to stakeholder comments and questions. 
However, we recognize that not all comments or questions require an 
answer or a response, or that some responses may be unduly burdensome 
to the transmission provider. To the extent that there are 
disagreements, we note that stakeholders have dispute resolution 
procedures available, as required under Order No. 890.\3509\ Some 
commenters have asked the Commission to require transmission providers 
to provide ``additional clarity'' regarding how alternatives were 
developed and why they were not selected during the Solutions Meeting, 
as requested by American Municipal Power.\3510\ In balancing the need 
for transparency and the burden for transmission providers, we find 
that a meaningful participation standard regarding sharing of local 
transmission planning inputs that are used in the regional transmission 
planning process that are established by the Commission is reasonable.
---------------------------------------------------------------------------

    \3508\ See American Municipal Power Initial Comments at 18-19; 
California Commission Initial Comments at 112-113; DC and MD Offices 
of People's Counsel Initial Comments at 6; Kentucky Commission Chair 
Chandler Initial Comments at 21-22; Northwest and Intermountain 
Initial Comments at 20-21; TAPS Initial Comments at 62.
    \3509\ Order No. 890, 118 FERC ] 61,119 at PP 501-503.
    \3510\ American Municipal Power Initial Comments at 24-25.
---------------------------------------------------------------------------

    1646. In addition, in response to TAPS' request regarding disputes 
over local transmission planning inputs,\3511\ we clarify that where 
disputes arise regarding transparency into the local transmission 
planning inputs, the transmission provider's existing dispute 
resolution process, as established in Order No. 890, governing the 
transmission planning process should be used.\3512\ Further, affected 
entities

[[Page 49533]]

retain any rights that they may have under FPA section 206 to file 
complaints with the Commission.
---------------------------------------------------------------------------

    \3511\ TAPS Initial Comments at 62 (citing Order No. 890, 118 
FERC ] 61,119 at PP 501-503).
    \3512\ Order No. 890, 118 FERC ] 61,119 at P 501.
---------------------------------------------------------------------------

b. Additional Issues
    1647. As it pertains to PPL's request that the Commission clarify 
that confidential or sensitive information will be protected,\3513\ we 
clarify that transmission providers must continue to apply the same 
safeguards to protect sensitive or critical information, such as 
confidentiality agreements and password protected access to 
information, as the Commission required in Order No. 890 and that 
transmission providers currently apply to the sharing of transmission 
planning information to protect against inappropriate disclosure of 
confidential information.\3514\
---------------------------------------------------------------------------

    \3513\ PPL Initial Comments at 36.
    \3514\ Order No. 890, 118 FERC ] 61,119 at PP 460, 471.
---------------------------------------------------------------------------

    1648. Many commenters suggest additional reforms because these 
commenters find the NOPR proposal insufficient. These suggested reforms 
include additional measures to protect customers' interests and 
additional process, more oversight, more monitoring (including 
establishing an independent transmission monitor), or prudence 
reviews;\3515\ requiring RTOs/ISOs to assume a larger role in reviewing 
or approving identified local transmission projects;\3516\ requiring a 
performance-based method of enhancing transparency in local 
transmission planning processes;\3517\ and requiring transmission 
providers to make available additional transmission planning 
data,\3518\ improve formatting of transmission planning inputs,\3519\ 
or otherwise coordinate with load-serving entities to transfer data and 
information.\3520\ The Commission did not make such proposals in the 
NOPR and, as a result, we find these requests to be beyond the scope of 
this proceeding and decline to adopt them. We note, however, that 
several of these issues may be examined in the Commission's ongoing 
Transmission Planning and Cost Management proceeding.\3521\
---------------------------------------------------------------------------

    \3515\ California Commission Initial Comments at 111-112 &n.401; 
Colorado Consumer Advocates Initial Comments at 31; Joint Consumer 
Advocates Initial Comments at 25-29; NRG Initial Comments at 7, 36; 
Ohio Consumers Initial Comments at 23-24; OMS Initial Comments at 
16-17; Pattern Energy Initial Comments at 31-34; Pine Gate Initial 
Comments at 49-50; PIOs Initial Comments at 51-52; PJM States 
Initial Comments at 4-6; TAPS Initial Comments at 61-62; US DOJ and 
FTC Initial Comments at 20-21.
    \3516\ See American Municipal Power Reply Comments at 3-7; 
California Commission Initial Comments at 108-110; DC and MD Offices 
of People's Counsel Initial Comments at 7; NARUC Initial Comments at 
60-61; Ohio Consumers Reply Comments at 17-18; PJM States Initial 
Comments at 6-7.
    \3517\ Vermont Electric and Vermont Transco Initial Comments at 
5.
    \3518\ American Municipal Power Initial Comments at 21-24 
(citations omitted); Pattern Energy Initial Comments at 30-34.
    \3519\ Joint Consumer Advocates Initial Comments at 21-22.
    \3520\ Certain TDUs Initial Comments at 18.
    \3521\ Transmission Planning and Cost Management, Notice of 
Technical Conference, Docket No. AD22-8-000 (Apr. 21, 2022).
---------------------------------------------------------------------------

C. Identifying Potential Opportunities to Right-Size Replacement 
Transmission Facilities

1. Eligibility
a. NOPR Proposal
    1649. The Commission proposed to require, as part of each Long-Term 
Regional Transmission Planning cycle, transmission providers in each 
transmission planning region to evaluate whether transmission 
facilities operating at or above 230 kV that an individual transmission 
provider that owns the transmission facility anticipates replacing in-
kind with a new transmission facility during the next 10 years can be 
``right-sized'' to more efficiently or cost-effectively address 
regional transmission needs identified in Long-Term Regional 
Transmission Planning. The Commission proposed to define ``right-
sizing'' as the process of modifying a transmission provider's in-kind 
replacement of an existing transmission facility to increase that 
facility's transfer capability.\3522\
---------------------------------------------------------------------------

    \3522\ NOPR, 179 FERC ] 61,028 at P 403.
---------------------------------------------------------------------------

    1650. The Commission described the process under this proposed 
reform as entailing the following steps. First, sufficiently early in 
each Long-Term Regional Transmission Planning cycle, each transmission 
provider would submit its in-kind replacement estimates for use in 
Long-Term Regional Transmission Planning. Then, if a right-sized 
replacement transmission facility is identified as a potential solution 
to a Long-Term Regional Transmission Planning need, that right-sized 
replacement transmission facility would be evaluated in the same manner 
as any other proposed transmission facility to determine whether it is 
the more efficient or cost-effective transmission facility to address 
the transmission need. If a right-sized replacement transmission 
facility addresses the transmission provider's need to replace an 
existing transmission facility, meets all of the applicable selection 
criteria included in Long-Term Regional Transmission Planning, and is 
found to be the more efficient or cost-effective solution to a 
transmission need identified through Long-Term Regional Transmission 
Planning, then the right-sized replacement transmission facility may be 
selected in the regional transmission plan for purposes of cost 
allocation.\3523\
---------------------------------------------------------------------------

    \3523\ Id. P 407.
---------------------------------------------------------------------------

    1651. The Commission explained that nothing in the reforms proposed 
in the NOPR would alter a transmission provider's existing rights and 
responsibilities under existing laws with respect to maintaining, and 
when necessary, replacing, existing transmission facilities. Further, 
as the Commission explained, it may be possible for an in-kind 
replacement transmission facility to be included in the regional 
transmission plan for informational purposes, but not be 
selected.\3524\
---------------------------------------------------------------------------

    \3524\ Id. PP 412-413.
---------------------------------------------------------------------------

b. Comments
    1652. Several commenters support the NOPR's proposals related to 
right-sizing.\3525\ ITC states that the NOPR proposal will result in 
better use of existing facilities and rights-of-way to quickly deliver 
additional transmission capacity. ITC maintains that increasing the 
transfer capability of existing transmission facilities lessens the 
impacts on communities and other land users, in addition to raising 
fewer environmental considerations.\3526\ ITC adds that right-sizing 
will form a critical input to transmission planning and state siting 
processes by encouraging designs that meet future needs.\3527\
---------------------------------------------------------------------------

    \3525\ ACORE Initial Comments at 19; Ameren Initial Comments at 
46-47; APPA Initial Comments at 48; California Energy Commission 
Initial Comments at 3; CTC Global Initial Comments at 18; ELCON 
Initial Comments at 27; Evergreen Action Initial Comments at 4; ITC 
Initial Comments at 45; ITC Reply Comments at 29; New York 
Commission and NYSERDA Initial Comments at 15; Northwest and 
Intermountain Initial Comments at 21; OMS Initial Comments at 17; 
PJM Initial Comments at 9, 121-122; SEIA Initial Comments at 26; 
U.S. Chamber of Commerce Initial Comments at 11; Vermont Electric 
and Vermont Transco Initial Comments at 5.
    \3526\ ITC Initial Comments at 45.
    \3527\ ITC Reply Comments at 29.
---------------------------------------------------------------------------

    1653. OMS also supports the Commission's proposed realignment of 
incentives to ensure that transmission providers are not incentivized 
through right-sizing to rebuild and replace facilities before 
considering other opportunities, instead providing a level playing 
field to consider other solutions.\3528\ PJM states that right-sizing 
allows transmission owners to meet their reliability obligations while 
transmission providers have the opportunity to find more efficient

[[Page 49534]]

solutions to regional transmission needs and avoid duplicative 
transmission development.\3529\
---------------------------------------------------------------------------

    \3528\ OMS Initial Comments at 17.
    \3529\ PJM Initial Comments at 121-122 (citing NOPR, 179 FERC ] 
61,028 at PP 406, 408).
---------------------------------------------------------------------------

    1654. AEP supports applying the right-sizing evaluation to 
transmission facilities operating at or above 230 kV because 
replacement transmission facilities that will operate at or above 230 
kV are most susceptible to modification to meet long-term regional 
transmission needs.\3530\ PG&E also supports the proposed voltage 
threshold, claiming that the inclusion of lower voltage transmission 
projects would substantially expand the number of projects that would 
need to be evaluated for right-sizing while offering little benefit. 
Specifically, PG&E contends that lower voltage transmission projects 
are typically needed for specific, local purposes and thus do not need 
to be right-sized, and that a requirement that they be evaluated for 
right-sizing would burden the RTO/ISO process.\3531\
---------------------------------------------------------------------------

    \3530\ AEP Initial Comments at 44-45 (citing NOPR, 179 FERC ] 
61,028 at P 406).
    \3531\ PG&E Reply Comments at 14-15.
---------------------------------------------------------------------------

    1655. APPA supports the NOPR proposal's use of a 10-year timeframe 
for the right-sizing reform.\3532\ AEP also supports a 10-year horizon 
for identifying in-kind replacements, so long as the list of 
transmission facilities is non-binding and may be modified as 
transmission projects mature or expected facility lives can be extended 
through other means.\3533\
---------------------------------------------------------------------------

    \3532\ APPA Initial Comments at 48 (citing NOPR, 179 FERC ] 
61,028 at P 403).
    \3533\ AEP Initial Comments at 44-45.
---------------------------------------------------------------------------

    1656. CAISO requests that the Commission clarify that the NOPR does 
not preclude it from continuing to consider modifications to in-kind 
replacements for transmission facilities below 230 kV in its annual 
transmission planning process.\3534\
---------------------------------------------------------------------------

    \3534\ CAISO Initial Comments at 50.
---------------------------------------------------------------------------

    1657. Several commenters support the NOPR's right-sizing proposal 
but with certain conditions.\3535\ Further, some commenters argue that 
if the Commission adopts the NOPR proposal, the Commission must ensure 
that the proposal does not disrupt or impair existing local 
transmission planning processes.\3536\ For example, AEP asserts that 
the Commission must ensure that the NOPR proposal does not undermine 
the local transmission planning process or transmission owners' rights 
to build transmission projects that address local needs.\3537\ 
Mississippi Commission asserts that, if the NOPR proposal is adopted, 
the ultimate decision as to which local transmission project is 
constructed must rest with the states that have transmission siting 
authority and the incumbent transmission owners.\3538\ PJM States ask 
for clarification on how the NOPR proposal will interact with existing 
processes, noting that in PJM, any need that appears both on a five-
year end-of-life needs list and in PJM's regional transmission plan is 
eligible for competition (as compared to the NOPR proposal, under which 
transmission projects to address 10-year-out needs would not be 
eligible for competition).\3539\
---------------------------------------------------------------------------

    \3535\ ACEG Initial Comments at 8-9, 56-58; AEP Initial Comments 
at 43-44; Avangrid Initial Comments at 15-16; Breakthrough Energy 
Initial Comments at 3, 19; California Commission Initial Comments at 
113-118; California Water Initial Comments at 8-9; Clean Energy 
Associations Initial Comments at 36-37; EEI Initial Comments at 41; 
Eversource Initial Comments at 52; Exelon Initial Comments at 3, 51; 
ISO-NE Initial Comments at 39; MISO Initial Comments at 87; NARUC 
Initial Comments at 58-59, 63-64; NESCOE Initial Comments at 21-22, 
78-79; NESCOE Reply Comments at 6-8; NESCOE Supplemental Comments at 
7-9; NextEra Initial Comments at 66-67; NRECA Initial Comments at 
67; NYISO Initial Comments at 58-60; PG&E Initial Comments at 12-14; 
Pine Gate Initial Comments at 46-50; PIOs Initial Comments at 57-58; 
State Agencies Initial Comments at 20-22; TAPS Initial Comments at 
6-7, 64; VEIR Initial Comments at 6; Vermont State Entities Initial 
Comments at 11-13; WIRES Initial Comments at 10.
    \3536\ See AEP Initial Comments at 43-44; CAISO Initial Comments 
at 50; Mississippi Commission Initial Comments at 30-31; Mississippi 
Commission Reply Comments at 9-10; PJM States Initial Comments at 8; 
WIRES Initial Comments at 10.
    \3537\ AEP Initial Comments at 43-44.
    \3538\ Mississippi Commission Initial Comments at 30-31.
    \3539\ PJM States Initial Comments at 8 (citing PJM, Intra-PJM 
Tariffs, OATT, attach. M-3 (1.0.0), section (d)1.iii).
---------------------------------------------------------------------------

    1658. NESCOE states that ISO-NE lacks the clear standards required 
to support right-sizing, citing an Eversource transmission project that 
improved grid reliability but was ineligible for regional cost 
allocation because it did not meet the standards to qualify as a right-
sized project.\3540\ NESCOE argues that more transparency into the 
right-sizing processes is necessary to ensure that the results are 
disciplined, cost-conscious investments.\3541\
---------------------------------------------------------------------------

    \3540\ NESCOE Reply Comments at 6-8.
    \3541\ NESCO Supplemental Comments at 9.
---------------------------------------------------------------------------

    1659. Several commenters oppose the NOPR's right-sizing 
proposal.\3542\ Competition Coalition asserts that the NOPR proposal 
would result in over-building the transmission system now for 
speculative future transmission needs, leaving customers with the bill 
for any stranded costs.\3543\ Louisiana Commission claims that the NOPR 
right-sizing proposal should not be adopted because it will intrude on 
its retail authority.\3544\
---------------------------------------------------------------------------

    \3542\ Anbaric Initial Comments at 7; Competition Coalition 
Initial Comments at 62-63; DC and MD Offices of People's Counsel 
Initial Comments at 47-48; Idaho Power Initial Comments at 13; 
Kentucky Commission Chair Chandler Initial Comments at 16-19; 
Louisiana Commission Initial Comments at 39; LS Power Initial 
Comments at 135-136, 138, 141-142, 145-146; Massachusetts Attorney 
General Initial Comments at 51-52; Ohio Consumers Initial Comments 
at 23; Resale Iowa Initial Comments at 8-9.
    \3543\ Competition Coalition Initial Comments at 62-63.
    \3544\ Louisiana Commission Initial Comments at 39.
---------------------------------------------------------------------------

    1660. Other commenters argue that the proposed 230 kV threshold is 
inappropriate.\3545\ For example, Avangrid contends that it is overly 
prescriptive and does not reflect regional conditions, needs, and 
stakeholder interests.\3546\ Avangrid states that, in ISO-NE, a 230 kV 
threshold would result in in-kind replacement of lower voltage 
transmission facilities rather than right-sizing facilities to most 
efficiently meet transmission needs identified through Long-Term 
Regional Transmission Planning.
---------------------------------------------------------------------------

    \3545\ Avangrid Initial Comments at 15-16; California Commission 
Initial Comments at 117-118; Kentucky Commission Chair Chandler 
Initial Comments at 18-19; New York TOs Initial Comments at 17-18; 
NYISO Initial Comments at 59; Ohio Consumers Initial Comments at 23; 
PJM Initial Comments at 9, 121-122; State Agencies Initial Comments 
at 20-21; TAPS Initial Comments at 6, 66.
    \3546\ Avangrid Initial Comments at 15-16.
---------------------------------------------------------------------------

    1661. Kentucky Commission Chair Chandler argues that 200 kV or 230 
kV are no longer adequate rules of thumb to delineate local versus 
regional transmission facilities, as transmission facilities that may 
have been formerly classified as local are likely to be regional in the 
future. Rather, Kentucky Commission Chair Chandler states that 
transmission facilities rated between 100 kV and 200 kV will play a 
greater role in the regional delivery of energy.\3547\ Ohio Consumers 
argue that the Commission should lower the threshold to 69 kV because 
many end-of-life transmission facilities in the PJM transmission 
planning process are expensive rebuilds of transmission facilities that 
are rated below 230 kV.\3548\ TAPS argues that excluding lower voltage 
facilities prevents transmission planning regions from being able to 
consider more efficient and cost-effective alternatives.\3549\
---------------------------------------------------------------------------

    \3547\ Kentucky Commission Chair Chandler Initial Comments at 
18-19.
    \3548\ Ohio Consumers Initial Comments at 23.
    \3549\ TAPS Initial Comments at 6, 66.
---------------------------------------------------------------------------

    1662. LS Power asserts that the Commission should not limit its 
right-sizing proposal to facilities above 230 kV and that such reforms 
should apply

[[Page 49535]]

to lower voltage transmission facilities as well.\3550\ Specifically, 
LS Power argues that transmission facilities that operate at or above 
100 kV (and sometimes facilities operating at a lower voltage) are 
regional in nature and should be subject to exclusively regional 
transmission planning.\3551\
---------------------------------------------------------------------------

    \3550\ See LS Power Partial Reply Comments at 61-64 (citing 
California Commission Initial Comments at 117; Eversource Initial 
Comments at 38; ISO-NE Initial Comments at 39; Kentucky Commission 
Chair Chandler Initial Comments at 19; LS Power Initial Comments at 
142; NARUC Initial Comments at 64; Ohio Consumers Initial Comments 
at 23; State Agencies Initial Comments at 21).
    \3551\ Id. at 64.
---------------------------------------------------------------------------

    1663. Shell states that the Commission should consider lowering the 
proposed voltage threshold to 115 kV, but notes that doing so may 
include lower voltage facilities that predominantly serve sub-
transmission, wholesale distribution, or retail distribution purposes 
and have only local benefits.\3552\ To ensure that the costs of sub-
transmission, wholesale distribution, or retail distribution facilities 
are not rolled into transmission rates, Shell argues that the 
Commission should reexamine its standards for rolling the costs of 
transmission facilities into rates, its application of the Seven Factor 
test for functionalizing facilities as distribution or transmission, 
and its Mansfield integration analysis.\3553\ Western Utilities contend 
that the Commission should not adopt Shell's proposal to lower the 
right-sizing threshold to 115 kV because whether or not a facility is a 
transmission facility is a fact-specific question.\3554\
---------------------------------------------------------------------------

    \3552\ Shell Reply Comments at 10 (citing Shell Initial Comments 
at 34).
    \3553\ Shell Initial Comments at 34-36; Shell Reply Comments at 
10-11 (citing Commonwealth Edison Co., 167 FERC ] 61,173, at P 12 
n.23 (2019); Buckeye Power, Inc. v. Am. Transmission Sys. Inc., 
Opinion No. 533, 148 FERC ] 61,174, at PP 12, 41, 69 (2014), order 
on reh'g, 151 FERC ] 61,091 (2015); Mansfield Mun. Elec. Dep't v. 
New England Power Co., Opinion No. 454, 97 FERC ] 61,134 (2001), 
order on reh'g, Opinion No. 454-A, 98 FERC ] 61,115 (2002)).
    \3554\ See Western Utilities Reply Comments at 2 (citing Shell 
Initial Comments at 34-35).
---------------------------------------------------------------------------

    1664. Pine Gate recommends against the Commission adopting the 
bright-line voltage threshold specified in the NOPR, but urges the 
Commission require each transmission provider to: (1) list and evaluate 
existing transmission facilities operating at or above 230 kV that it 
owns and estimates may need to be replaced with a new in-kind 
transmission facility over the next 10 years; and (2) establish 
criteria by which it will identify lower-voltage facilities that could 
potentially be right-sized through Long-Term Regional Transmission 
Planning.\3555\ Relatedly, WIRES states that the Commission should 
either: (1) clarify that transmission providers would not be prohibited 
from considering right-sizing transmission facilities at a lower 
voltage threshold if existing transmission planning processes already 
do so; or (2) provide flexibility for transmission planning regions to 
justify the use of a different voltage threshold.\3556\
---------------------------------------------------------------------------

    \3555\ Pine Gate Initial Comments at 48.
    \3556\ WIRES Initial Comments at 10.
---------------------------------------------------------------------------

    1665. Some commenters oppose the NOPR proposal's use of a 10-year 
timeframe for the right-sizing reform.\3557\ Exelon states that the 
Commission's proposed requirement to have a 10-year time horizon for 
identifying a list of potential end-of-useful life needs is infeasible 
and inconsistent with utility practices. Specifically, Exelon states 
that it does not develop a concrete plan for transmission projects to 
meet end-of-useful life needs five years in advance--let alone 10 
years--but instead maintains a ``dynamic list'' of older assets, the 
condition of which is evaluated on a rolling basis, based on numerous 
factors such as equipment inspection and testing, maintenance history, 
historical performance, obsolescence, operational experience, asset 
criticality, equipment failure data, and age.\3558\
---------------------------------------------------------------------------

    \3557\ Eversource Initial Comments at 53; Exelon Initial 
Comments at 54-55; Indicated PJM TOs Initial Comments at 46-47; 
Kentucky Commission Chair Chandler Initial Comments at 17-18; SERTP 
Sponsors Initial Comments at 38-39.
    \3558\ Exelon Initial Comments at 54-55 (Exelon Utilities Asset 
Management Guidelines and Practices 3 (Nov. 18, 2020), https://pjm.com/-/media/committees-groups/committees/srrtep-ma/2020/20201216/20201216-exelon-final-end-eol-guidelines.ashx).
---------------------------------------------------------------------------

    1666. Some commenters argue that the NOPR proposal is not 
applicable to their transmission planning regions or that their 
existing processes are sufficient.\3559\ For example, CAISO explains 
that it plans all upgrades and expansions of transmission facilities 
under its operational control, which include transmission facilities at 
all voltage levels and at all locations on the system. Further, CAISO 
states that, if an asset management, maintenance, or in-kind 
replacement project can be expanded or modified to address a CAISO-
identified transmission need in a local area (or system wide), CAISO 
can order such expansion or modification in its regional transmission 
planning process.\3560\
---------------------------------------------------------------------------

    \3559\ CAISO Initial Comments at 47-48; Dominion Initial 
Comments at 69-70, 72; Duke Initial Comments at 46; MISO Initial 
Comments at 87-88; MISO Reply Comments at 28; New York TOs Initial 
Comments at 17; SERTP Sponsors Initial Comments at 38-39; SPP 
Initial Comments at 34-35.
    \3560\ CAISO Initial Comments at 47-48 (citing CAISO ANOPR 
Initial Comments at 73; Cal. Pub. Utils. Comm'n v. Pac. Gas and 
Elec. Co., 164 FERC ] 61,161 at PP 35-37, 69).
---------------------------------------------------------------------------

    1667. MISO asserts that right-sizing is fundamental to transmission 
planning and should always be considered as part of Good Utility 
Practice, but that right-sizing decisions are best made on a case-by-
case basis, as there are both quantitative and qualitative 
considerations that must be taken into account.\3561\ MISO contends 
that its existing local transmission planning achieves the Commission's 
objectives, as the MISO process provides for right-sizing where MISO 
selects the most robust solution. Accordingly, MISO states that, for 
its footprint, no changes are needed.\3562\
---------------------------------------------------------------------------

    \3561\ MISO Initial Comments at 87.
    \3562\ MISO Reply Comments at 28 (citing OMS Initial Comments at 
15-17).
---------------------------------------------------------------------------

    1668. SERTP Sponsors argue that replacement decisions for 
particular equipment may be triggered more by the conditions of a 
particular facility than its age. SERTP Sponsors argue that a process 
like right-sizing already occurs in SERTP's regional transmission 
planning, which requires that the SERTP Sponsors affirmatively look to 
determine if there are regional transmission alternatives that would be 
more efficient or cost-effective than the transmission solutions 
otherwise included in SERTP's regional transmission plan, including 
projects to replace aging infrastructure.\3563\
---------------------------------------------------------------------------

    \3563\ SERTP Sponsors Initial Comments at 38-39 (citations 
omitted).
---------------------------------------------------------------------------

    1669. Several commenters argue that the Commission should adopt 
alternative or additional requirements that apply when transmission 
providers evaluate transmission facilities for right-sizing.\3564\ For 
example, Ameren requests that the Commission require transmission 
providers to consider the following additional criteria when 
determining whether a transmission facility is eligible for right-
sizing: (1) whether a transmission line is in the top 10 limiting 
elements on an import or transfer study; (2) whether a line has shown 
up as a real-time binding

[[Page 49536]]

constraint in the last two years; or (3) whether a line shows up as a 
binding constraint in future security constrained economic dispatch 
simulations.\3565\ California Energy Commission argues that the 
Commission should develop a definition of ``right-sizing,'' possibly 
tied to a specified planning reserve margin as well as an expected 
level of demand growth.\3566\ Furthermore, ACEG and PG&E both request 
that the Commission consider the use of existing transmission facility 
rights-of-way as an eligibility threshold for potentially right-sized 
replacement transmission facilities.\3567\
---------------------------------------------------------------------------

    \3564\ ACEG Initial Comments at 58; Ameren Initial Comments at 
46-47; American Municipal Power Initial Comments at 27; Breakthrough 
Energy Initial Comments at 18-19; California Energy Commission 
Initial Comments at 3; Competition Coalition Initial Comments at 68; 
CTC Global Initial Comments at 18; Eversource Initial Comments at 
53; Exelon Initial Comments at 56-58; Grid United Initial Comments 
at 3-4; Pennsylvania Commission Initial Comments at 21; PG&E Initial 
Comments at 13-14; Pine Gate Initial Comments at 48; PIOs Initial 
Comments at 57-58; PJM Initial Comments at 9, 121-122; PPL Initial 
Comments at 36-37; Shell Initial Comments at 34.
    \3565\ Ameren Initial Comments at 46-47.
    \3566\ California Energy Commission Initial Comments at 3.
    \3567\ ACEG Initial Comments at 57-58; PG&E Initial Comments at 
13.
---------------------------------------------------------------------------

    1670. Eversource asserts that it would be more efficient to 
evaluate potential right-sizing: (1) through a review of the 
transmission facilities that could be upgraded to address identified 
long-term transmission needs, including an evaluation of whether an in-
kind replacement is likely to occur during the planning horizon; or (2) 
through transmission owner identification of right-sizing options that 
align with needs identified in the longer-term study as they perform 
their normal asset condition projects.\3568\
---------------------------------------------------------------------------

    \3568\ Eversource Initial Comments at 53.
---------------------------------------------------------------------------

    1671. Entergy asserts that the Commission should clarify that 
storm-hardening transmission projects are not subject to a right-sizing 
requirement because it would add complications and delays to the right-
sizing process.\3569\ Pennsylvania Commission argues that a 
transmission facility should not be right-sized if its total cost 
exceeds the total cost of the local transmission project and a 
competitively procured transmission project to address the regional 
need.\3570\
---------------------------------------------------------------------------

    \3569\ Entergy Initial Comments at 38.
    \3570\ Pennsylvania Commission Initial Comments at 21.
---------------------------------------------------------------------------

    1672. Some commenters call for the Commission to expand the right-
sizing reform to other categories of transmission facilities.\3571\ 
Eversource argues that the Commission should encourage transmission 
providers to incorporate right-sizing considerations into other 
transmission planning processes, such as the reliability planning 
process, as appropriate.\3572\ Similarly, ACORE and American Municipal 
Power request that the Commission clarify that right-sizing also 
applies in any short-term transmission planning for reliability and 
economic transmission projects.\3573\ Grid United states that the 
Commission should require Long-Term Regional Transmission Planning to 
assess and allow for up-sizing transmission projects, such as building 
a single circuit transmission line that is double-circuit ready.\3574\
---------------------------------------------------------------------------

    \3571\ American Municipal Power Initial Comments at 27; Avangrid 
Initial Comments at 16; Clean Energy Associations Initial Comments 
at 26-27, 37; Eversource Initial Comments at 54; MISO Initial 
Comments at 88; NYISO Initial Comments at 59-60; PIOs Initial 
Comments at 57-58; TAPS Initial Comments at 6, 64-65.
    \3572\ Eversource Initial Comments at 54.
    \3573\ ACORE Initial Comments at 19; American Municipal Power 
Initial Comments at 27.
    \3574\ Grid United Initial Comments at 4.
---------------------------------------------------------------------------

    1673. Several commenters argue that the Commission should allow 
flexibility on the thresholds for evaluating transmission facilities 
for right-sizing.\3575\ To prevent needless litigation that will cause 
delays and cost increases for customers, Dominion states that any final 
order should be clear that transmission providers will not be penalized 
if a replacement project arises that was not previously 
identified.\3576\
---------------------------------------------------------------------------

    \3575\ American Municipal Power Initial Comments at 27; APPA 
Initial Comments at 48; Avangrid Initial Comments at 15-16; 
California Commission Initial Comments at 117; Clean Energy 
Associations Initial Comments at 36-37; Dominion Initial Comments at 
72-73; EEI Initial Comments at 41; Eversource Initial Comments at 
52-53; ISO-NE Initial Comments at 39; NARUC Initial Comments at 58-
59, 63-64; National Grid Initial Comments at 40-41; NESCOE Initial 
Comments at 80; New York TOs Initial Comments at 18; NRECA Initial 
Comments at 67; NYISO Initial Comments at 9, 60; PG&E Reply Comments 
at 14-15; PPL Initial Comments at 37; US DOE Initial Comments at 48; 
Vermont State Entities Initial Comments at 13; WIRES Initial 
Comments at 10.
    \3576\ Dominion Initial Comments at 73.
---------------------------------------------------------------------------

    1674. NYISO contends that the final order should permit 
transmission providers, with input from state entities and 
stakeholders, to integrate planning for right-sizing transmission 
replacements into existing transmission planning processes, including 
by considering transmission facilities that they anticipate will be 
replaced in-kind when identifying transmission needs in short-term or 
long-term transmission planning.\3577\
---------------------------------------------------------------------------

    \3577\ NYISO Initial Comments at 9, 60.
---------------------------------------------------------------------------

    1675. US DOE encourages the Commission to provide sufficient 
flexibility to ensure that the proposed reforms are cost-effective and 
do not overburden the transmission planning process. US DOE asserts 
that transmission providers should not be required to submit every in-
kind replacement for all equipment above 230 kV for consideration for 
right-sizing and that regional transmission planning processes should 
not be required to consider each piece of equipment provided by each 
member of a transmission planning region.\3578\
---------------------------------------------------------------------------

    \3578\ US DOE Initial Comments at 48.
---------------------------------------------------------------------------

    1676. PG&E argues that the Commission should allow for flexibility 
in any right-sizing-related requirements, noting that a transmission 
provider may need to replace an aging or failing transmission facility 
sooner than a right-sized transmission project can be developed. In 
that case, PG&E states that the transmission owner would need to 
proceed with the replacement project to ensure reliability or protect 
public safety even if the RTO/ISO had determined that a transmission 
facility would benefit from being right-sized.\3579\
---------------------------------------------------------------------------

    \3579\ PG&E Reply Comments at 15.
---------------------------------------------------------------------------

c. Commission Determination
    1677. We adopt the NOPR proposal, with modification, to require 
that, as part of each Long-Term Regional Transmission Planning cycle, 
transmission providers in each transmission planning region evaluate 
whether transmission facilities (1) operating above a specified kV 
threshold and (2) that an individual transmission provider that owns 
the transmission facility anticipates replacing in-kind with a new 
transmission facility during the next 10 years can be ``right-sized'' 
to more efficiently or cost-effectively address a Long-Term 
Transmission Need. To effectuate this reform, we also adopt the NOPR 
proposal, with modification, to require that, sufficiently early in 
each Long-Term Regional Transmission Planning cycle, each transmission 
provider submit its in-kind replacement estimates (i.e., estimates of 
the transmission facilities operating at and above the specified kV 
threshold that an individual transmission provider that owns the 
transmission facility anticipates replacing in-kind with a new 
transmission facility during the next 10 years) for use in Long-Term 
Regional Transmission Planning. With respect to the specified kV 
threshold, transmission providers must propose on compliance a 
threshold that does not exceed 200 kV (e.g., 115 kV and above). In 
adopting the right-sizing reform in this final order, we recognize that 
a transmission provider may have existing rights and responsibilities 
with respect to maintaining and, when necessary, replacing existing 
transmission facilities. We also adopt the NOPR proposals regarding a 
Federal right of first refusal and cost allocation method for right-
sized replacement transmission facilities, as discussed below.

[[Page 49537]]

    1678. We adopt the NOPR proposal to define ``right-sizing'' as the 
process of modifying a transmission provider's in-kind replacement of 
an existing transmission facility to increase that facility's transfer 
capability.\3580\ Additionally, we clarify that, for purposes of this 
right-sizing reform, an ``in-kind replacement transmission facility'' 
is a new transmission facility that: (1) would replace an existing 
transmission facility that a transmission provider has identified in 
its in-kind replacement estimate as needing to be replaced; (2) would 
result in no more than an incidental increase in capacity over the 
existing transmission facility identified as needing to be 
replaced;\3581\ and (3) is located in the same general route as, and/or 
uses the existing rights-of-way of, the existing transmission facility 
identified as needing to be replaced.
---------------------------------------------------------------------------

    \3580\ NOPR, 179 FERC ] 61,028 at P 403 (``Right-sizing could 
include, for example, increasing the transmission facility's voltage 
level, adding circuits to the towers (e.g., redesigning a single-
circuit line as a double-circuit line), or incorporating advanced 
technologies (such as advanced conductor technologies).'').
    \3581\ The Commission has addressed the meaning of an incidental 
increase in the context of a replacement transmission facility in 
several orders. See, e.g., S. Cal. Edison Co., 164 FERC ] 61,160 at 
P 33, order on reh'g, 168 FERC ] 61,170 (2019); Cal. Pub. Utils. 
Comm'n v. Pac. Gas & Elec. Co., 164 FERC ] 61,161 at P 68; see also 
PJM Interconnection, L.L.C., 172 FERC ] 61,136 at P 84, order on 
reh'g, 173 FERC ] 61,225 (2020); PJM Interconnection, L.L.C., 173 
FERC ] 61,242 at P 54, order on reh'g, 176 FERC ] 61,053 (2021).
---------------------------------------------------------------------------

    1679. Further, we clarify that a ``right-sized replacement 
transmission facility'' is a new transmission facility that: (1) would 
meet the need to replace an existing transmission facility that a 
transmission provider has identified in its in-kind replacement 
estimate as one that it plans to replace with an in-kind replacement 
transmission facility while also addressing a Long-Term Transmission 
Need; (2) results in more than an incidental increase in the capacity 
of an existing transmission facility that a transmission provider has 
identified for replacement in its in-kind replacement estimate; and (3) 
is located in the same general route as, and/or uses or expands the 
existing rights-of-way of, the existing transmission facility that a 
transmission provider has identified for replacement in its in-kind 
replacement estimate. We believe these clarifications are necessary to 
ensure that use of the right-sizing reform addresses replacement 
transmission facilities and not entirely new transmission facilities.
    1680. As an example, assume that transmission providers determine 
that an existing transmission facility included in a transmission 
provider's in-kind replacement estimate can be right-sized (Segment 1) 
and, together with a separate new transmission facility (Segment 2), is 
the more efficient or cost-effective solution to a Long-Term 
Transmission Need. In this example, Segment 1 is a new 50-mile, 345 kV 
transmission facility between interconnection points A and B that 
requires the expansion of an existing right-of-way, and replaces an 
existing 50-mile, 230 kV transmission facility between interconnection 
points A and B. Segment 2 in this example is a new 25-mile, 345 kV 
transmission facility requiring entirely new rights-of-way from 
interconnection points B to C. If both Segment 1 and Segment 2 are 
selected to address a Long-Term Transmission Need, then, for purposes 
of the requirements of this final order, only Segment 1 would be 
considered a right-sized replacement transmission facility.
    1681. Consistent with the NOPR proposal, and as discussed further 
below, the process under this proposed right-sizing reform entails 
taking the following steps, which transmission providers must describe 
in their OATTs. The transmission providers in each transmission 
planning region must propose a point sufficiently early in each Long-
Term Regional Transmission Planning cycle at which each individual 
transmission provider in the transmission planning region will submit 
its in-kind replacement estimates for use in Long-Term Regional 
Transmission Planning. Then, if transmission providers identify a 
right-sized replacement transmission facility as a potential solution 
to a Long-Term Transmission Need as part of Long-Term Regional 
Transmission Planning, that right-sized replacement transmission 
facility must be evaluated in the same manner as any other proposed 
Long-Term Regional Transmission Facility to determine whether it is the 
more efficient or cost-effective transmission facility to address the 
transmission need. More specifically, it is at this stage of the right-
sizing reform where transmission providers must use the in-kind 
replacement estimates to determine if in-kind replacement transmission 
facilities could be right-sized to more efficiently or cost-effectively 
address a Long-Term Transmission Need(s). If a right-sized replacement 
transmission facility addresses the transmission provider's need to 
replace an existing transmission facility, meets the applicable 
selection criteria included in Long-Term Regional Transmission 
Planning, and is found to be the more efficient or cost-effective 
solution to a Long-Term Transmission Need, then the right-sized 
replacement transmission facility must be considered for selection.
    1682. We find that a right-sized replacement transmission facility 
has the potential to both meet an individual transmission provider's 
responsibility to maintain the reliability of its existing transmission 
system and address a Long-Term Transmission Need more efficiently or 
cost-effectively than an in-kind replacement transmission facility or 
another Long-Term Regional Transmission Facility.\3582\ Further, we 
find that, if opportunities for right-sized replacement transmission 
facilities are not considered, the Long-Term Regional Transmission 
Planning process may not select the more efficient or cost-effective 
transmission facilities to meet Long-Term Transmission Needs, 
potentially rendering Commission-jurisdictional rates unjust and 
unreasonable.\3583\
---------------------------------------------------------------------------

    \3582\ NOPR, 179 FERC ] 61,028 at P 406.
    \3583\ Id.
---------------------------------------------------------------------------

    1683. As noted above, for purposes of implementing the right-sizing 
requirements that we adopt in this final order, transmission providers 
must propose on compliance a threshold that does not exceed 200 kV that 
is used in identifying the transmission facilities that an individual 
transmission provider anticipates replacing in-kind with a new 
transmission facility during the next 10 years, which it must then 
include in its in-kind replacement estimates. In other words, each 
transmission provider in the transmission planning region must include 
in its in-kind replacement estimates the transmission facilities 
operating at and above 200 kV, or at and above a lower proposed 
threshold, that it owns and anticipates replacing in-kind with a new 
transmission facility during the next 10 years.\3584\ We find that this 
threshold strikes a reasonable balance between capturing the 
transmission facilities that are the most likely candidates for right-
sizing without overburdening transmission providers by requiring them 
to identify all transmission facilities planned for in-kind 
replacement, including lower voltage transmission facilities that may 
be less likely to provide regional benefits, and therefore potentially 
less likely to be more efficient or cost-effective transmission 
solutions to Long-

[[Page 49538]]

Term Transmission Needs. Specifically, we believe adopting the 230 kV 
threshold proposed in the NOPR could have excluded from consideration 
some transmission facilities planned for in-kind replacement that are 
likely to provide regional benefits.\3585\ In adopting a specified kV 
threshold (so long as that threshold does not exceed 200 kV), as 
opposed to the 230 kV threshold proposed in the NOPR, we note that the 
Commission ``has wide discretion to determine where to draw 
administrative lines.'' \3586\
---------------------------------------------------------------------------

    \3584\ We note that while transmission providers may not propose 
a kV threshold that exceeds 200 kV, they may propose a lower kV 
threshold (e.g., 100 kV or 115 kV), which would require transmission 
providers in that transmission planning region to include in their 
in-kind replacement estimates a wider range of transmission 
facilities that they own and anticipate replacing in-kind with a new 
transmission facility during the next 10 years.
    \3585\ For example, the maximum 200 kV threshold that we adopt 
here mirrors existing processes (e.g., CAISO) for determining 
whether a transmission facility provides regional benefits or more 
localized benefits. Appendix A of CAISO's OATT defines a ``Large 
Project'' as ``[a] transmission upgrade or addition that exceeds 
$200 million in capital costs and consists of a proposed 
transmission line or substation facilities capable of operating at 
voltage levels greater than 200 kV.'' CAISO, CAISO eTariff, app. A, 
Definitions (0.0.0), section Large Project. Moreover, we note that a 
200 kV threshold aligns with the 200 kV threshold for 
interconnection reforms discussed in the Coordination of Regional 
Transmission Planning and Generator Interconnection Process section 
of this final order.
    \3586\ ExxonMobil Gas Mktg. Co. v. FERC, 297 F.3d 1071, 1085 
(D.C. Cir. 2002) (quoting AT&T Corp. v. FCC, 220 F.3d 607, 627 (D.C. 
Cir. 2000)).
---------------------------------------------------------------------------

    1684. We find that the requirement for transmission providers to 
identify a kV threshold not to exceed 200 kV to identify in-kind 
replacements recognizes that the NOPR proposal did not align with the 
region-specific characteristics outlined by some transmission 
providers. For example, as ISO-NE notes, a large portion of ISO-NE's 
transmission system consists of 115 kV transmission facilities.\3587\ 
We find that the maximum kV threshold that we adopt allows flexibility 
for transmission providers, like ISO-NE, to tailor their proposed kV 
threshold to their specific transmission planning regions (as long as 
the threshold they apply is equal or lower than 200 kV), while ensuring 
that the in-kind replacement transmission facilities that are most 
susceptible to modification that could more efficiently or cost-
effectively address Long-Term Transmission Needs are considered for 
right-sizing.
---------------------------------------------------------------------------

    \3587\ ISO-NE Initial Comments at 39.
---------------------------------------------------------------------------

    1685. With regard to the 10-year timeframe for in-kind replacement 
estimates, we believe that 10 years is an appropriate timeframe to 
evaluate potential in-kind replacement transmission facilities for 
right-sizing because it balances the long lead times associated with 
developing certain transmission facilities with the uncertainty 
associated with the exact timing of when aging transmission facilities 
may need to be replaced.\3588\ We also clarify that the 10-year 
timeframe for in-kind replacement estimates should reflect a 
transmission provider's estimates of the transmission facilities 
operating at and above the specified kV threshold that an individual 
transmission provider that owns the transmission facility anticipates 
replacing in-kind with a new transmission facility during the next 10 
years beginning at the start of each Long-Term Regional Transmission 
Planning cycle. Furthermore, we believe that a 10-year timeframe is 
more likely to capture a larger pool of potential in-kind replacement 
transmission facilities that would be eligible for right-sizing. We 
recognize, however, that transmission providers may obtain better 
information about a transmission facility's condition as the 
anticipated replacement date approaches and may also identify 
additional transmission facilities that require replacement in fewer 
than 10 years based on updated assessments of their condition. As such, 
we clarify that transmission providers may update the lists of 
transmission facilities that they anticipate replacing in subsequent 
transmission planning cycles if they believe that an anticipated in-
kind replacement transmission facility is more urgently needed than 
previously thought or if existing transmission facilities do not 
deteriorate as quickly as previously expected.
---------------------------------------------------------------------------

    \3588\ NOPR, 179 FERC ] 61,028 at P 406.
---------------------------------------------------------------------------

    1686. Several commenters oppose the right-sizing reform. They 
suggest that adopting the reform would harm competition or existing 
transmission planning processes that already evaluate whether 
replacement transmission facilities can be increased in transfer 
capability. We are unpersuaded by these arguments. We adopt the right-
sizing reform because it captures certain transmission planning 
efficiencies by addressing aging transmission infrastructure issues 
while also providing an opportunity to increase transfer capability 
(i.e., develop the right-sized replacement transmission facility) to 
address Long-Term Transmission Needs more efficiently or cost-
effectively. With respect to concerns about the right-sizing reform's 
impact on competition, we address that issue below under the section on 
Rights of First Refusal. Regarding commenters' arguments that existing 
transmission planning processes already evaluate whether replacement 
transmission facilities can be right-sized, we note that we require 
transmission providers to consider right-sizing as part of Long-Term 
Regional Transmission Planning. If transmission providers wish to 
continue to consider right-sizing opportunities in some or all of their 
existing transmission planning processes in addition to Long-Term 
Regional Transmission Planning, this reform does not address those 
processes, and they may continue to adhere to existing practices that 
are not modified by this final order. Further, we emphasize that 
transmission providers may propose compliance approaches that are 
consistent with or superior to these requirements, and as such, 
depending on their individual circumstances and approaches, may be able 
to demonstrate that a method akin to their existing practice is also 
appropriate for right-sizing in Long-Term Regional Transmission 
Planning.
    1687. In response to PJM States' request for clarification 
regarding the interaction between existing processes and whether the 
right-sizing reform necessitates competitive transmission development 
processes, we recognize that a transmission provider may have existing 
rights and responsibilities with respect to maintaining and, when 
necessary, replacing existing transmission facilities. Regarding PJM 
States' request for clarification on competitive transmission 
development processes, we refer to the Right of First Refusal section 
below.
    1688. In response to Exelon's concerns regarding the timing of 
replacement transmission facilities, we clarify that the 10-year 
timeframe associated with the right-sizing reform applies to 
transmission facilities that a transmission provider anticipates 
replacing. In other words, the requirement for a transmission provider 
to include in its in-kind replacement estimates any transmission 
facilities that it anticipates replacing in-kind during the next 10 
years does not create an obligation for the transmission provider to 
change any existing process that it has to identify which transmission 
facilities it anticipates replacing. However, a transmission provider 
must include in its in-kind replacement estimates any transmission 
facilities it anticipates replacing during the next 10 years beginning 
at the start of each Long-Term Regional Transmission Planning cycle, 
regardless of the process it uses to identify the facilities.
    1689. In response to SERTP Sponsors and PG&E's arguments that 
replacement decisions may be triggered more by the conditions of a 
particular transmission facility than its age, we reiterate, consistent 
with the statement the Commission made in the NOPR, we recognize that a 
transmission provider may have existing rights and responsibilities 
with respect to maintaining, and when necessary,

[[Page 49539]]

replacing existing transmission facilities. We recognize that, as SERTP 
Sponsors note, replacement decisions may be triggered by other 
conditions than a transmission facility's age or condition, and since 
we recognize that a transmission provider may have existing rights and 
responsibilities under existing laws with respect to maintaining and, 
when necessary, replacing transmission facilities, we note that SERTP 
Sponsors, as well as any other transmission providers, may address such 
replacements of existing transmission facilities according to their 
existing processes.
    1690. In response to Entergy's request for clarification regarding 
storm-hardening, we reiterate that the right-sizing reform we adopt 
here pertains to transmission facilities that a transmission provider 
anticipates replacing with an in-kind replacement transmission 
facility. To the extent that storm-hardening transmission projects do 
not encompass the replacement of existing transmission facilities with 
an in-kind replacement transmission facility, those storm-hardening 
transmission projects need not be included on a transmission provider's 
list of in-kind replacement estimates.
    1691. In response to US DOE's argument that transmission providers 
should not be required to submit every in-kind replacement for all 
equipment, we clarify that the right-sizing reform we adopt here 
requires transmission providers to list in their in-kind replacement 
estimates only the transmission facilities operating at and above the 
specified kV threshold that they own and anticipate replacing in-kind 
with a new transmission facility during the next 10 years, provided 
transmission providers may not propose a specified kV threshold higher 
than 200 kV.
    1692. WIRES requests that the Commission clarify that transmission 
providers would not be prohibited from considering right-sizing 
transmission facilities lower than 230 kV if existing transmission 
planning processes already do so. We clarify that, given our 
modification to the NOPR proposal, transmission providers may propose 
on compliance a threshold lower than 200 kV for considering right-
sizing transmission facilities. We reiterate that the 200 kV threshold 
is a maximum threshold (i.e., transmission providers may not propose a 
right-sizing threshold higher than 200 kV).
2. Right of First Refusal
a. NOPR Proposal
    1693. In the NOPR, the Commission proposed, for any right-sized 
replacement transmission facility that is selected to meet transmission 
needs identified through Long-Term Regional Transmission Planning, to 
require the establishment of a Federal right of first refusal for the 
transmission provider that includes the in-kind replacement 
transmission facility in its in-kind replacement estimates, which would 
extend to any portion of such a transmission facility located within 
the applicable transmission provider's retail distribution service 
territory or footprint.\3589\
---------------------------------------------------------------------------

    \3589\ Id. PP 408-409.
---------------------------------------------------------------------------

b. Comments
    1694. Some commenters support the proposed Federal right of first 
refusal for right-sized replacement transmission facilities.\3590\ AEP 
argues that without it, transmission providers may develop an in-kind 
replacement facility instead of the right-sized transmission facility 
identified in the regional transmission planning process.\3591\ 
Similarly, PG&E states that providing a Federal right of first refusal 
for right-sized replacement transmission facilities will provide an 
incentive for transmission providers to develop such projects, where 
appropriate.\3592\
---------------------------------------------------------------------------

    \3590\ AEP Initial Comments at 46-47; Ameren Reply Comments at 
14-15; Dominion Initial Comments at 75; EEI Initial Comments at 41; 
Exelon Initial Comments at 58; MISO TOs Initial Comments at 27-28; 
PG&E Reply Comments at 15-16; US Chamber of Commerce Initial 
Comments at 11; Vermont Electric and Vermont Transco Initial 
Comments at 5.
    \3591\ AEP Initial Comments at 46-47 (citing NOPR, 179 FERC ] 
61,028 at PP 408-409).
    \3592\ PG&E Reply Comments at 16.
---------------------------------------------------------------------------

    1695. MISO TOs argue that, whether through in-kind replacement or 
right-sized replacement, ``what is being done is an upgrade of an 
existing transmission facility,'' for which the Commission has afforded 
transmission owners Federal rights of first refusal through Order No. 
1000 (and prior actions).\3593\ US Chamber of Commerce states that a 
Federal right of first refusal for right-sized replacement transmission 
facilities should also apply to right-sized transmission facilities, as 
it would eliminate incentives to withhold in-kind replacements from the 
regional transmission planning process.\3594\
---------------------------------------------------------------------------

    \3593\ MISO TOs Initial Comments at 27-28.
    \3594\ US Chamber of Commerce Initial Comments at 11 (citing 
NOPR, 179 FERC ] 61,028 at P 409).
---------------------------------------------------------------------------

    1696. Ameren states that critics of the NOPR's proposal to provide 
transmission providers a Federal right of first refusal for right-
sizing projects question whether the Commission has met its FPA section 
206 burden to demonstrate that the regional transmission planning 
tariffs are currently unjust and unreasonable or unduly discriminatory 
in order to justify this proposal.\3595\ Ameren contends that this 
argument misses a critical point because, currently, replacement of 
transmission facilities in-kind is generally not subject to the 
regional transmission planning process or competitive transmission 
development processes. Ameren asserts that the Commission need not find 
any existing rate unjust and unreasonable in order to signal an intent 
to approve such right of first refusals for right-sizing projects when 
filed with the Commission under FPA section 205.\3596\
---------------------------------------------------------------------------

    \3595\ Ameren Reply Comments at 14 (citing LS Power Initial 
Comments at 50).
    \3596\ Id.
---------------------------------------------------------------------------

    1697. Several commenters oppose the proposed Federal right of first 
refusal for right-sized replacement transmission facilities.\3597\ 
Massachusetts Attorney General argues that the Commission has not 
demonstrated a ``rational connection'' between the Commission's 
findings and the right-sizing reform. Massachusetts Attorney General 
adds that the NOPR proposal is directly at odds with the Commission's 
findings in Order Nos. 890 and 1000 and that the Commission fails to 
provide ``good reasons'' for departing from those prior findings.\3598\ 
American Municipal Power argues that, even if incumbent transmission 
owners currently have a right of first refusal for local transmission 
facilities, that right should be limited to maintenance (i.e., in-kind 
replacements) and not situations where a transmission facility would 
expand or

[[Page 49540]]

enhance the transmission system.\3599\ LS Power argues that the right-
sizing proposal changes definitions in Order No. 1000, including the 
definitions of an upgrade and a local transmission facility, and allows 
a Federal right of first refusal for transmission facilities located on 
an existing right-of-way instead of leaving the issue to state 
law.\3600\ LS Power asserts that, even if the Commission could meet the 
first prong of its section 206 analysis and find that the existing 
transmission planning process is unjust and unreasonable, the 
Commission must still establish that the entirety of the replacement 
rate is just and reasonable which, LS Power argues, the Commission 
cannot because of the tie to a Federal right of first refusal. Taken 
together, LS Power argues that the NOPR proposal, if adopted, would 
fail as a replacement rate.\3601\ Furthermore, LS Power argues that the 
Federal right of first refusal for right-sized replacement transmission 
facilities would essentially provide a Federal franchise, mandating 
that transmission customers accept the ownership right of the existing 
transmission owners to continue in perpetuity.\3602\
---------------------------------------------------------------------------

    \3597\ AEE Reply Comments at 31; American Municipal Power 
Initial Comments at 28-29; Anbaric Initial Comments at 7; California 
Commission Initial Comments at 115-117; California Water Initial 
Comments at 8-9; City of New York Initial Comments at 11-13; 
Competition Coalition Initial Comments at 64; Competition Coalition 
Reply Comments at 2; Industrial Customers Initial Comments at 4; 
Kentucky Commission Chair Chandler Initial Comments at 19; LS Power 
Initial Comments at 22, 25-26, 84-85; Massachusetts Attorney General 
Initial Comments at 51-53; NextEra Initial Comments at 54-61; 
Northwest and Intermountain Initial Comments at 21-22; Pennsylvania 
Commission Initial Comments at 22-23; R Street Initial Comments at 
3-4, 12-21; Resale Iowa Initial Comments at 8-9; TAPS Initial 
Comments at 68.
    \3598\ Massachusetts Attorney General Initial Comments at 40, 51 
(citing 5 U.S.C. 706(2); 16 U.S.C. 825l(b); FCC v. Fox Television 
Stations, Inc., 556 U.S. 502, 515 (2009); Motor Vehicle Mfrs. Ass'n 
of the U. S. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 
(1983)).
    \3599\ American Municipal Power Initial Comments at 28.
    \3600\ LS Power Initial Comments at 22.
    \3601\ Id. at 147-48 (citing Nat'l Fuel Gas Supply Corp. v. 
FERC, 468 F.3d 831, 845 (D.C. Cir. 2006); SEC v. Chenery Corp., 318 
U.S. 80, 95 (1943)).
    \3602\ Id. at 84-85.
---------------------------------------------------------------------------

    1698. Northwest and Intermountain support clarifying that a Federal 
right of first refusal for right-sized replacement transmission 
facilities does not apply to any facilities that replace equipment that 
has reached the end of its useful life. Moreover, Northwest and 
Intermountain contend that the Commission should require a competitive 
solicitation for any right-sized transmission projects that meet 
regional transmission needs.\3603\ AEE contends that the record does 
not support further action on the proposed Federal right of first 
refusal for right-sized replacement transmission facilities, and 
instead reflects the complexity of the issues involved and the need for 
a holistic review of competitive transmission development processes and 
options for improving them.\3604\
---------------------------------------------------------------------------

    \3603\ Northwest and Intermountain Initial Comments at 21-22.
    \3604\ AEE Reply Comments at 31.
---------------------------------------------------------------------------

    1699. Several commenters raise concerns about the incentives that 
the proposed ederal right of first refusal for right-sized replacement 
transmission facilities would introduce.\3605\ Pennsylvania Commission 
argues that incumbent transmission owners may use it as a new tool to 
avoid competition by displacing other regional transmission 
facilities.\3606\ Given that transmission providers may not secure cost 
recovery for imprudently incurred expenses, NextEra disagrees that, 
without a Federal right of first refusal for right-sized replacement 
transmission facilities, incumbent transmission owners may engage in 
duplicative or inefficient transmission development.\3607\
---------------------------------------------------------------------------

    \3605\ Anbaric Initial Comments at 7; California Commission 
Initial Comments at 114-115; Competition Coalition Initial Comments 
at 65-67; LS Power Initial Comments at 81-82; Massachusetts Attorney 
General Initial Comments at 51-52; NextEra Initial Comments at 58; 
Pennsylvania Commission Initial Comments at 22; Resale Iowa Initial 
Comments at 8-9.
    \3606\ Pennsylvania Commission Initial Comments at 22.
    \3607\ NextEra Initial Comments at 59-61 (citations omitted).
---------------------------------------------------------------------------

    1700. Some commenters oppose the proposed Federal right of first 
refusal for right-sized replacement transmission facilities because 
they argue that it would increase costs for customers.\3608\ California 
Water argues that allowing a Federal right of first refusal for right-
sized replacement transmission facilities would permit incumbent 
transmission owners to construct right-sized transmission facilities 
without any cost guardrails, which could end up being more expensive 
than the in-kind replacements.\3609\ Alternatively, some commenters 
argue that their existing transmission planning processes already 
consider ``right-sizing'' replacement transmission facilities and may 
not include a Federal right of first refusal.\3610\
---------------------------------------------------------------------------

    \3608\ See California Commission Initial Comments at 117; 
California Water Initial Comments at 9; Competition Coalition 
Initial Comments at 66-67; DC and MD Offices of People's Counsel 
Initial Comments at 47-48; R Street Reply Comments at 5-6; State 
Agencies Initial Comments at 21-22.
    \3609\ California Water Initial Comments at 9.
    \3610\ CAISO Initial Comments at 47-49; New York Commission and 
NYSERDA Initial Comments at 15-16; New York TOs Initial Comments at 
17-18; NYISO Initial Comments at 58-59.
---------------------------------------------------------------------------

    1701. In response to claims that there is no logical basis for a 
Federal right of first refusal for right-sized replacement transmission 
facilities, MISO TOs state that the proposal applies to upgrades of an 
existing transmission facility and that in Order No. 1000, the 
Commission expressly reserved a Federal right of first refusal for an 
individual utility to upgrade its own property. As such, MISO TOs 
argue, a right-sizing requirement should neither deprive a transmission 
owner of its rights regarding its own property or its right to 
construct and own upgrades to its own system, nor should it implement 
an unconstitutional taking of such owner's property.\3611\ Therefore, 
MISO TOs state that the final order should clarify that nothing in the 
right-sizing proposal eliminates an incumbent transmission owner's 
Federal right of first refusal for any transmission facilities selected 
through a right-sizing process.\3612\
---------------------------------------------------------------------------

    \3611\ MISO TOs Reply Comments at 33 (citing Order No. 1000, 136 
FERC ] 61,051 at PP 226, 319; Order No. 1000-A, 139 FERC ] 61,132 at 
P 426; N.Y. Indep. Sys. Operator, Inc., 175 FERC ] 61,038, at PP 30, 
33 (2021)).
    \3612\ MISO TOs Reply Comments at 33 (citing MISO TOs Initial 
Comments at 25-28).
---------------------------------------------------------------------------

c. Commission Determination
    1702. We adopt the NOPR proposal to require the establishment of a 
Federal right of first refusal for a right-sized replacement 
transmission facility \3613\ that is selected to meet Long-Term 
Transmission Needs. This Federal right of first refusal will apply to 
the transmission provider that included in its in-kind replacement 
estimate the existing transmission facility that the right-sized 
replacement transmission facility would replace, and extends to any 
portion of the right-sized replacement facility located within that 
transmission provider's retail distribution service territory or 
footprint, recognizing that any such portion must satisfy the 
definition of a right-sized replacement facility, as revised by this 
final order, including that the right-sized replacement transmission 
facility is located in the same general route as, and/or uses or 
expands the existing rights-of-way of, the existing transmission 
facility.
---------------------------------------------------------------------------

    \3613\ As noted above, right-sizing could include, for example, 
increasing the transmission facility's voltage level, adding 
circuits to the towers (e.g., redesigning a single-circuit line as a 
double-circuit line), or incorporating advanced technologies (e.g., 
advanced conductor technologies). Additionally, we reiterate that, 
as noted above, a right-sized replacement transmission facility is, 
for purposes of this right-sizing reform, a new transmission 
facility that: (1) would meet the need to replace an existing 
transmission facility that a transmission provider has identified in 
its in-kind replacement estimate as one that it plans to replace 
with an in-kind replacement transmission facility while also 
addressing a Long-Term Transmission Need; (2) results in more than 
an incidental increase in the capacity of an existing transmission 
facility that a transmission provider has identified for replacement 
in its in-kind replacement estimate; and (3) is located in the same 
general route as, and/or uses or expands the existing rights-of-way 
of, the existing transmission facility that a transmission provider 
has identified for replacement in its in-kind replacement estimate.
---------------------------------------------------------------------------

    1703. In adopting the NOPR proposal to require the establishment of 
a Federal right of first refusal for a right-sized replacement 
transmission facility, we find that permitting a Federal right of first 
refusal for right-sized replacement

[[Page 49541]]

transmission facilities will encourage transmission providers to 
provide their best in-kind replacement estimates, because they will 
have certainty that they will not lose the opportunity to invest in any 
in-kind replacement transmission facility that is then selected as a 
right-sized replacement transmission facility. As such, we find that a 
Federal right of first refusal will remove a disincentive for 
transmission providers to consider right-sizing in Long-Term Regional 
Transmission Planning, helping to ensure that the more efficient or 
cost-effective regional transmission solution to Long-Term Transmission 
Needs is selected and likely built, and therefore that Commission-
jurisdictional rates are just and reasonable. Moreover, we note that 
the definitions of ``in-kind replacement transmission facility'' and 
``right-sized replacement transmission facility'' that we adopt, as 
discussed above, are necessary to ensure that use of the right-sizing 
reform addresses replacement transmission facilities and not entirely 
new transmission facilities.\3614\
---------------------------------------------------------------------------

    \3614\ See supra PP 1681-1683.
---------------------------------------------------------------------------

    1704. We note that the establishment of a Federal right of first 
refusal for right-sized replacement transmission facilities is an 
exception to Order No. 1000's general requirement for transmission 
providers to eliminate any Federal right of first refusal for regional 
transmission facilities selected in a regional transmission plan.\3615\ 
In response to comments challenging this approach as violating the 
precedent set in Order No. 1000, which eliminated Federal rights of 
first refusal for new selected transmission facilities,\3616\ we find 
that requiring a Federal right of first refusal for right-sized 
replacement transmission facilities aligns with Order No. 1000.
---------------------------------------------------------------------------

    \3615\ See supra P 1576.
    \3616\ Order No. 1000, 136 FERC ] 61,051 at P 313.
---------------------------------------------------------------------------

    1705. In Order No. 1000, the Commission required transmission 
providers to remove Federal rights of first refusal from their OATTs 
because they undermined the consideration of more efficient or cost-
effective potential transmission solutions proposed at the regional 
level, which could lead to unjust and unreasonable rates for 
Commission-jurisdictional services.\3617\ The Commission found that 
Federal rights of first refusal created a barrier to entry that 
discouraged nonincumbent transmission developers from proposing 
alternative solutions for consideration at the regional level.\3618\ 
The Commission did not require the elimination of Federal rights of 
first refusal for local transmission facilities,\3619\ and did not 
alter the rights of incumbent transmission providers to build, own, and 
recover costs for upgrades to its own transmission facilities, 
regardless of whether the upgrade is selected.\3620\
---------------------------------------------------------------------------

    \3617\ Id. PP 253, 256.
    \3618\ Id. P 257.
    \3619\ Id. P 318.
    \3620\ Id. P 319 (citation omitted).
---------------------------------------------------------------------------

    1706. We find that the Commission's reasons for removing Federal 
rights of first refusal in Order No. 1000 do not apply to right-sized 
replacement transmission facilities. Specifically, requiring a Federal 
right of first refusal for right-sized replacement transmission 
facilities does not undermine the consideration of more efficient or 
cost-effective potential transmission solutions proposed at the 
regional level; rather, we find that it will promote the consideration 
of more efficient or cost-effective potential regional transmission 
solutions to address Long-Term Transmission Needs. When compared 
against the alternative of piecemeal development of in-kind replacement 
transmission facilities, a Federal right of first refusal for right-
sized transmission facilities does not frustrate the goals of Order No. 
1000 or lead to inefficiency in transmission development because the 
right-sized replacement transmission facility represents the more 
efficient or cost-effective regional transmission solution to address 
Long-Term Transmission Needs (otherwise it would not be selected). We 
recognize that a transmission provider may have existing rights and 
responsibilities with respect to maintaining and, when necessary, 
replacing their transmission facilities. Because the right-sizing 
reform does not alter existing laws related to an individual 
transmission provider's ability to proceed with an in-kind replacement 
transmission facility, absent a Federal right of first refusal, we 
believe the incumbent transmission provider whose in-kind replacement 
transmission facility is selected to be right-sized would likely 
proceed to develop the less efficient or cost-effective in-kind 
replacement transmission facility. We find that the transmission 
provider would prefer the assurance of a Federal right of first refusal 
for the in-kind replacement transmission facility over the uncertainty 
of subjecting a right-sized replacement transmission facility to the 
Order No. 1000 competitive transmission development process. Because of 
this incentive structure and the fact that the transmission provider 
holds the leverage as to whether to build a right-sized replacement 
transmission facility or a less efficient in-kind replacement 
transmission facility, the establishment of the Federal right of first 
refusal is necessary to effectuate this reform and ensure that 
Commission-jurisdictional rates are just and reasonable.\3621\
---------------------------------------------------------------------------

    \3621\ See NOPR, 179 FERC ] 61,028 at P 408 & n.652.
---------------------------------------------------------------------------

    1707. By establishing a process that requires transmission 
providers to evaluate opportunities to right-size in-kind replacement 
transmission facilities to meet Long-Term Transmission Needs, and by 
establishing a Federal right of first refusal for such right-sized 
replacement transmission facilities, we believe that the right-sizing 
reform in this final order will encourage transmission providers to 
provide their best in-kind replacement estimates, as they will have 
certainty that they will not lose the opportunity to invest in any in-
kind replacement transmission facility that is then selected as a 
right-sized replacement transmission facility. Moreover, permitting a 
Federal right of first refusal for right-sized replacement transmission 
facilities will enable transmission providers to ensure that the more 
efficient or cost-effective regional transmission solution to Long-Term 
Transmission Needs is selected and that Commission-jurisdictional rates 
are consequently just and reasonable.\3622\
---------------------------------------------------------------------------

    \3622\ In response to those commenters who argue that their 
existing transmission planning processes already consider ``right-
sizing'' replacement transmission facilities without the inclusion 
of a Federal right of first refusal, we note that, separate from 
compliance with this final order, transmission providers in each 
transmission planning region can agree to participant funding 
arrangements for right-sized replacement transmission facilities 
that are not selected through Long-Term Regional Transmission 
Planning, in which case the requirement to establish a Federal right 
of first refusal for right-sized replacement transmission facilities 
selected to meet Long-Term Transmission Needs would not apply.
---------------------------------------------------------------------------

    1708. In response to MISO TOs' request regarding upgrades to 
existing transmission facilities, we reiterate that nothing in the 
right-sizing reform affects the right of an incumbent transmission 
provider to build, own, and recover the costs for upgrades to its own 
transmission facilities, regardless of whether an upgrade to an 
existing transmission facility has been identified through a right-
sizing process and selected to address Long-Term Transmission Needs.
    1709. We deny Northwest and Intermountain's request to clarify that 
the right-sizing reform excludes transmission facilities that replace 
equipment that has reached the end of its useful life. As explained 
above, the Federal right of first refusal will apply to selected right-
sized replacement

[[Page 49542]]

transmission facilities, including those that are intended to replace 
transmission facilities that have reached the end of their useful life.
3. Cost Allocation
a. NOPR Proposal
    1710. With respect to cost allocation, the Commission proposed that 
if a right-sized replacement transmission facility is selected, only 
the incremental costs of right-sizing the transmission facility would 
be eligible to use the applicable Long-Term Regional Transmission Cost 
Allocation Method. The Commission proposed that the costs the incumbent 
transmission provider would have otherwise incurred to construct the 
in-kind replacement transmission facility be allocated in a manner 
consistent with the allocation that would have otherwise occurred for 
the in-kind replacement. The Commission preliminarily found that it is 
just and reasonable and not unduly discriminatory or preferential for 
only the portion of the costs associated with a right-sized replacement 
transmission facility that is selected to be eligible to use the Long-
Term Regional Transmission Cost Allocation Method because it is the 
right-sizing of the in-kind replacement transmission facility that 
allows the transmission facility to meet the transmission needs 
identified in Long-Term Regional Transmission Planning.\3623\
---------------------------------------------------------------------------

    \3623\ NOPR, 179 FERC ] 61,028 at P 410.
---------------------------------------------------------------------------

    1711. The Commission also proposed to require transmission 
providers in each transmission planning region to amend their regional 
transmission planning processes to provide transparency with respect to 
which right-sized replacement transmission facilities have been 
selected (and thus found to be a more efficient or cost-effective 
transmission facility to meet regional transmission needs) and which 
transmission facilities are simply included in the regional 
transmission plan for informational (and not cost allocation) 
purposes.\3624\
---------------------------------------------------------------------------

    \3624\ Id. P 413.
---------------------------------------------------------------------------

b. Comments
    1712. Some commenters support the NOPR proposal that the 
incremental costs of right-sizing a transmission facility that is 
selected would be eligible to use the applicable Long-Term Regional 
Transmission Cost Allocation Method.\3625\ ACEG contends that without 
it, a large amount of new transmission investment--directed solely at 
replacement facilities--will be outside of Long-Term Regional 
Transmission Planning and thus not given an opportunity to contribute 
to the grid's overall efficiency and cost-effectiveness.\3626\ 
Eversource asserts that, in New England, asset condition projects 
receive regional cost allocation, and requests clarification that the 
Commission is not proposing to disturb the existing cost allocation 
method for asset condition projects in ISO-NE that are not selected for 
right-sizing in Long-Term Regional Transmission Planning.\3627\ NESCOE 
recommends that the Commission require transmission providers to 
explain on compliance the method that they will use to determine the 
incremental costs of right-sizing a replacement transmission facility. 
In addition, NESCOE supports the proposal to require transmission 
providers to amend their regional transmission planning processes to 
provide transparency with respect to which right-sized replacement 
transmission facilities have been selected.\3628\
---------------------------------------------------------------------------

    \3625\ ACEG Initial Comments at 57-58; Eversource Initial 
Comments at 54; NARUC Initial Comments at 65; NESCOE Initial 
Comments at 81.
    \3626\ ACEG Initial Comments at 57-58.
    \3627\ Eversource Initial Comments at 54.
    \3628\ NESCOE Initial Comments at 81.
---------------------------------------------------------------------------

    1713. Other commenters support the proposed cost allocation for 
right-sized replacement transmission facilities, but express 
reservations.\3629\ Entergy asserts that the Commission should clarify 
that costs incurred absent right-sizing will be allocated under the 
cost allocation method(s) that otherwise would apply to such costs, 
which may include regional cost allocation.\3630\ With regard to 
incremental costs, CTC Global urges the Commission to require the 
transmission planning process to be based on future needs, future 
benefits, total lifecycle costs, and total benefits for the life of the 
resource. More specifically, CTC Global suggests that when considering 
incremental costs, the Commission should consider including energy 
savings, generating capacity reduction benefits, and resulting 
reductions in greenhouse gas emissions as benefits associated with the 
right-sized replacement transmission facility.\3631\
---------------------------------------------------------------------------

    \3629\ CTC Global Initial Comments at 19; Dominion Initial 
Comments at 75-76; Entergy Initial Comments at 39; MISO Initial 
Comments at 87; NRG Initial Comments at 36-37.
    \3630\ Entergy Initial Comments at 39.
    \3631\ CTC Global Initial Comments at 19.
---------------------------------------------------------------------------

    1714. Dominion states that it may be difficult to quantify and 
allocate the incremental costs of right-sizing a replacement 
transmission facility.\3632\ MISO agrees, stating that it will be 
challenging to identify the portion of costs that should be recovered 
as part of the age and condition upgrade using one cost allocation 
method and a different cost allocation for the portion of the right-
sized upgrade identified as part of Long-Term Regional Transmission 
Planning. MISO argues that this complexity will continue going forward 
given that the accounting for two types of cost allocation to different 
customers will have to be tracked for each right-sized replacement 
transmission facility.\3633\
---------------------------------------------------------------------------

    \3632\ Dominion Initial Comments at 75-76.
    \3633\ MISO Initial Comments at 87.
---------------------------------------------------------------------------

    1715. Some commenters oppose the NOPR proposal.\3634\ LS Power 
argues that the proposal violates cost causation principles as it would 
limit regional cost allocation to the incremental portion of the right-
sized replacement transmission facilities, regardless of beneficiary 
analysis.\3635\ Indicated PJM TOs state that the Commission should not 
impose any requirements with respect to the cost allocation of right-
sized replacement transmission facilities and instead should provide 
transmission providers with the flexibility to determine a cost 
allocation method.\3636\ Exelon agrees, adding that the Commission's 
proposed approach creates unnecessary complications and adds a further 
variable (base versus incremental cost) to the already complex and 
often contentious cost allocation process. According to Exelon, the 
proposal (1) incorrectly assumes that a transmission owner has 
identified an in-kind replacement transmission facility and its cost; 
(2) incorrectly assumes that a perfect overlap exists between the 
displaced transmission facility (or need) and the right-sized 
replacement transmission facility; and (3) fails to address adjustments 
for cost savings or overruns on the right-sized portion of the 
transmission facility.\3637\
---------------------------------------------------------------------------

    \3634\ Exelon Initial Comments at 59; Indicated PJM TOs Initial 
Comments at 47; LS Power Initial Comments at 86-87.
    \3635\ LS Power Initial Comments at 86-87 (citing Old Dominion 
Elec. Coop. v. FERC, 898 F.3d 1254, reh'g denied, 905 F.3d 671 (D.C. 
Cir. 2018)).
    \3636\ Indicated PJM TOs Initial Comments at 47 (citation 
omitted).
    \3637\ See Exelon Initial Comments at 59 & n.103.
---------------------------------------------------------------------------

c. Commission Determination
    1716. We decline to adopt the NOPR proposal to require that, if a 
right-sized replacement transmission facility is selected, only the 
incremental costs of right-sizing the transmission facility will be 
eligible to use the applicable Long-Term Regional Transmission Cost 
Allocation Method, while the costs that the transmission provider would 
otherwise have incurred to construct the in-kind replacement 
transmission

[[Page 49543]]

facility must be allocated in a manner consistent with the allocation 
that would have otherwise occurred for the in-kind replacement 
transmission facility. This is because we find persuasive comments that 
identify the complexities and challenges associated with tracking 
portions of costs of two different transmission projects through time, 
as well as allocating the costs of a right-sized replacement 
transmission facility pursuant to two separate cost allocation 
methods.\3638\ While the approach that the NOPR proposed to require may 
still be a just and reasonable cost allocation approach for right-sized 
replacement transmission facilities, should the relevant transmission 
providers choose to take on these challenges and address them 
adequately, we find it appropriate to provide flexibility to 
transmission providers to propose a cost allocation method for selected 
right-sized replacement transmission facilities. However, in providing 
such flexibility, transmission providers must nevertheless demonstrate 
on compliance that the cost allocation method for selected right-sized 
replacement transmission facilities is just and reasonable and not 
unduly discriminatory or preferential and, consistent with cost 
causation, allocates costs in a manner that is at least roughly 
commensurate with the estimated benefits of such facilities.\3639\
---------------------------------------------------------------------------

    \3638\ Dominion Initial Comments at 75-76; Exelon Initial 
Comments at 59; MISO Initial Comments at 87.
    \3639\ See ICC v. FERC I, 576 F.3d at 477; Order No. 1000, 136 
FERC ] 61,051 at PP 622, 639 (requiring costs of regional 
transmission facilities to be allocated in a manner that is at least 
roughly commensurate with estimated benefits).
---------------------------------------------------------------------------

    1717. Further, we also require transmission providers in each 
transmission planning region to amend their regional transmission 
planning processes to provide transparency with respect to which right-
sized replacement transmission facilities have been selected, as well 
as which transmission facilities are simply included in the regional 
transmission plan for informational (and not cost allocation) purposes.
    1718. We disagree with LS Power's assertion that the right-sizing 
cost allocation method proposed in the NOPR violates cost causation 
principles because it would limit regional cost allocation to the 
incremental portion of the right-sized replacement transmission 
facilities, regardless of other potential beneficiaries.\3640\ The 
customers of the transmission provider that would be allocated the 
costs associated with the original in-kind replacement transmission 
facility would have otherwise been responsible for paying those costs 
had the in-kind replacement transmission facility not been right-sized. 
Further, we find that it is not unjust, unreasonable, or unduly 
discriminatory or preferential that, for a right-sized replacement 
transmission facility selected, only the portion of the costs 
associated with right-sizing be eligible to use the Long-Term Regional 
Transmission Cost Allocation Method. Specifically, we find that it is 
the right-sizing of the in-kind replacement transmission facility that 
allows the transmission facility to meet Long-Term Transmission Needs 
identified in Long-Term Regional Transmission Planning. As such, we 
disagree that allowing only the incremental costs of right-sizing the 
right-sized replacement transmission facility to be eligible to use the 
applicable Long-Term Regional Transmission Cost Allocation Method would 
violate cost causation principles.
---------------------------------------------------------------------------

    \3640\ LS Power Initial Comments at 86-87 (citing Old Dominion 
Elec. Coop. v. FERC, 898 F.3d 1254).
---------------------------------------------------------------------------

    1719. As we note above, we find merit with respect to commenters' 
concerns about the difficulty in determining the portion of the costs 
of a right-sized replacement transmission facility attributable to 
right-sizing and the complexity in tracking portions of differing cost 
allocation methods through time. For this reason, to the extent that 
transmission providers propose to allocate the costs of right-sized 
replacement transmission facilities pursuant to the cost allocation 
method described in the NOPR, we require the transmission providers to 
explain on compliance (1) the method that they will use to determine 
the portion of the costs of a right-sized replacement transmission 
facility that is incremental to the costs that would have been incurred 
for the underlying in-kind replacement transmission facility, and (2) 
the method by which they will track the portion of costs over time that 
are allocated in accordance with the Long-Term Regional Transmission 
Cost Allocation Method (or, if adopted, subject to a State Agreement 
Process), as well as the portion of costs that would have been 
allocated pursuant to the cost allocation method that otherwise would 
have applied to the in-kind replacement transmission facility. We 
believe that transmission providers are best positioned to determine 
both the portion of the costs of a right-sized replacement transmission 
facility that is incremental to the costs that would have been incurred 
for the underlying in-kind replacement transmission facility, as well 
as how to best track these costs over time for purposes of cost 
allocation.
    1720. In response to Eversource and Entergy's requests that the 
Commission clarify the cost allocation method for in-kind replacement 
transmission facilities that are not selected for right-sizing,\3641\ 
we clarify that we are not requiring any changes pursuant to this 
right-sizing requirement that would affect the existing cost allocation 
method(s) for in-kind replacement transmission facilities that are not 
identified for right-sizing, or for the costs of the underlying in-kind 
replacement transmission facilities that would have been incurred 
absent right-sizing. Similarly, in response to Entergy's request for 
clarification that costs incurred absent right-sizing will be allocated 
under the cost allocation method(s) that otherwise would apply to such 
costs, which may include regional cost allocation, we clarify that the 
costs that the transmission provider would otherwise have incurred to 
construct the in-kind replacement transmission facility must be 
allocated in a manner consistent with the cost allocation method that 
would have otherwise applied to that facility, which could include a 
regional cost allocation method.
---------------------------------------------------------------------------

    \3641\ Entergy Initial Comments at 39; Eversource Initial 
Comments at 54.
---------------------------------------------------------------------------

    1721. We also confirm, in response to comments from CTC Global, 
that benefits associated with a potential right-sized replacement 
transmission facility to address Long-Term Transmission Needs should be 
evaluated in the same manner as for any potential regional transmission 
facility that could address those needs, which includes evaluating all 
of the costs of, and all of the benefits provided by, the right-sized 
replacement transmission facility consistent with reforms outlined in 
this final order.
    1722. In response to Exelon's comments that the NOPR proposal 
relies on incorrect assumptions regarding the transmission provider 
identifying an in-kind replacement transmission facility and its cost, 
as well as there being an overlap between the displaced transmission 
facility and the right-sized replacement transmission facility, we 
disagree and note that these conditions are prerequisites that serve as 
the foundation for the right-sizing requirement. Where a transmission 
provider has not identified an in-kind replacement transmission 
facility that could be right-sized to address Long-Term Transmission 
Needs more efficiently or cost-effectively, no basis exists to select a 
right-sized replacement transmission facility.

[[Page 49544]]

4. Miscellaneous
a. Comments
    1723. Some commenters recommend that the Commission adopt 
confidentiality safeguards.\3642\ AEP and Indicated PJM TOs contend 
that the Commission must adopt confidentiality provisions to ensure 
that information related to right-sizing is not shared beyond the 
regional planning entity because identification of end-of-life 
transmission facilities demonstrates potential vulnerabilities that 
could create security and reliability risks and could also provide 
advantages to competitors.\3643\ WIRES argues that the Commission 
should allow for the transmission owner to provide to the transmission 
provider a non-public, confidential, non-binding list of transmission 
facilities that may need to be replaced based on an appropriate time 
horizon as determined by the transmission provider.\3644\ SERTP 
Sponsors request that the Commission protect CEII information for 
transmission facilities that are anticipated to be replaced.\3645\
---------------------------------------------------------------------------

    \3642\ AEP Initial Comments at 46; Exelon Initial Comments at 
57-58; Indicated PJM TOs Initial Comments at 45-46; SERTP Sponsors 
Initial Comments at 39; WIRES Initial Comments at 10.
    \3643\ AEP Initial Comments at 46; Indicated PJM TOs Initial 
Comments at 45.
    \3644\ WIRES Initial Comments at 10.
    \3645\ SERTP Sponsors Initial Comments at 39.
---------------------------------------------------------------------------

    1724. Conversely, PJM States request that the Commission require 
the information on the in-kind replacement estimate list to be non-
confidential to the greatest extent possible or to require 
justification as to why confidentiality is merited.\3646\
---------------------------------------------------------------------------

    \3646\ PJM States Initial Comments at 7-8.
---------------------------------------------------------------------------

    1725. Several commenters call for the Commission to increase 
scrutiny on, or alter the presumption of prudence for, transmission 
projects related to the right-sizing reform.\3647\ American Municipal 
Power argues that if an incumbent transmission owner replaces local 
transmission facilities at the end of their useful lives despite a 
determination that a right-sized replacement transmission facility is 
the more efficient or cost-effective transmission solution, the 
incumbent transmission owner's in-kind replacement should be presumed 
to be unjust and unreasonable for purposes of cost recovery.\3648\
---------------------------------------------------------------------------

    \3647\ American Municipal Power Initial Comments at 29-30; 
California Commission Initial Comments at 114-115; California Water 
Initial Comments at 9; Harvard ELI Initial Comments at 5; 
Massachusetts Attorney General Initial Comments at 52; Ohio 
Consumers Initial Comments at 23-24; Pine Gate Initial Comments at 
49-50; PIOs Initial Comments at 58; Resale Iowa Initial Comments at 
9; TAPS Initial Comments at 6-7, 67-68.
    \3648\ American Municipal Power Initial Comments at 29.
---------------------------------------------------------------------------

    1726. ACEG asserts that the Commission has the authority under FPA 
section 205 to review replacement transmission facility projects and 
address problems in the local transmission planning process.\3649\ LS 
Power argues that the Commission should use its existing authority to 
confirm through show cause orders that transmission providers are 
evaluating whether local transmission solutions can be displaced by a 
regional transmission solution that is more efficient or cost-
effective.\3650\
---------------------------------------------------------------------------

    \3649\ ACEG Initial Comments at 57.
    \3650\ LS Power Initial Comments at 145 (citing LS Power ANOPR 
Initial Comments at 134-135).
---------------------------------------------------------------------------

    1727. Similarly, TAPS asserts that the NOPR imposes no consequences 
on transmission owners that proceed with in-kind replacement projects 
even when the transmission planning region has selected more efficient 
and cost-effective alternatives for regional cost allocation. TAPS 
argues that the Commission should exclude cost recovery for such 
facilities from the scope of formula rates and require transmission 
owners to make a separate filing pursuant to FPA section 205. 
Alternatively, TAPS states that the Commission should impose a 
presumption of imprudence and require such transmission owners to 
demonstrate that the proposed replacement is more cost-effective and 
efficient than the alternative selected by the transmission planning 
region.\3651\
---------------------------------------------------------------------------

    \3651\ TAPS Initial Comments at 6-7, 67-68 (citations omitted).
---------------------------------------------------------------------------

    1728. On the other hand, PG&E argues that the Commission should 
clarify that a transmission owner's right to decline to proceed with a 
selected right-sized replacement transmission facility does not justify 
disallowance of cost recovery for the in-kind replacement transmission 
facility.\3652\
---------------------------------------------------------------------------

    \3652\ PG&E Initial Comments at 14.
---------------------------------------------------------------------------

    1729. Several commenters support consideration of alternative 
transmission technologies and grid enhancing technologies when 
evaluating right-sized replacement transmission facilities.\3653\ CTC 
Global urges the Commission to require all transmission owners with a 
line requiring in-kind replacement within 10 years to analyze whether a 
transmission line's conductor should be replaced with an advanced 
conductor through rebuild or reconductoring.\3654\ PIOs argue that 
right-sizing opportunities should include increasing voltage, adding 
circuits, and utilizing advanced technologies, and further argue that 
right-sized replacement transmission facilities that use grid enhancing 
technologies can create economies of scale to capture public policy and 
economic benefits in addition to reliability.\3655\ VEIR agrees with 
the Commission's proposal to include advanced conductors in its 
definition of right-sizing, explaining that superconductors can enable 
a five-fold increase in the power flow capacity of an existing 
transmission corridor. VEIR therefore urges the Commission to 
explicitly affirm that the deployment of advanced conductors would 
constitute right-sizing.\3656\
---------------------------------------------------------------------------

    \3653\ CTC Global Initial Comments at 18, 20; Maryland Energy 
Administration Reply Comments at 5-6; NARUC Initial Comments at 58-
59; PIOs Initial Comments at 57-58; VEIR Initial Comments at 6.
    \3654\ CTC Global Initial Comments at 18.
    \3655\ PIOs Initial Comments at 57-58 (citing PIOs ANOPR Initial 
Comments at 50).
    \3656\ VEIR Initial Comments at 6.
---------------------------------------------------------------------------

    1730. Some commenters argue that the NOPR's right-sizing proposal 
is insufficient and call upon the Commission to take further 
action.\3657\ For example, ACEG, American Municipal Power, and 
California Commission argue that the Commission should expand the scope 
of the right-sizing proposal.\3658\ American Municipal Power argues 
that the Commission should require RTOs/ISOs to plan for all new 
transmission facilities that have regional impacts, including: (1) 
transmission facilities that meet the North American Electric 
Reliability Corporation Bulk Electric System definition; and (2) 
transmission projects that will replace an existing transmission 
facility that was turned over to the RTO/ISO irrespective of the 
voltage.\3659\ Similarly, LS Power argues that the Commission has the 
authority to require regional transmission planning for existing 
transmission facilities reaching the end of operational life, and that 
such transmission

[[Page 49545]]

planning should be performed by an independent transmission 
planner.\3660\
---------------------------------------------------------------------------

    \3657\ ACEG Initial Comments at 57; American Municipal Power 
Initial Comments at 25-26; American Municipal Power Reply Comments 
at 5; California Commission Initial Comments at 106-108; California 
Water Initial Comments at 10; Competition Coalition Initial Comments 
at 68-70; Grid United Initial Comments at 3-4; Harvard ELI Initial 
Comments at 4-5; LS Power Initial Comments at 136, 138, 141-142, 
145-146; Ohio Consumers Initial Comments at 24; PIOs Initial 
Comments at 53; TAPS Initial Comments at 6, 64-65.
    \3658\ See ACEG Initial Comments at 57-58; American Municipal 
Power Initial Comments at 25-26; American Municipal Power Reply 
Comments at 5; California Commission Initial Comments at 113-118.
    \3659\ American Municipal Power Reply Comments at 5.
    \3660\ LS Power Initial Comments at 83-84, 141 (citations 
omitted).
---------------------------------------------------------------------------

    1731. Massachusetts Attorney General asserts that all right-sized 
replacement transmission facilities should be subject to cost 
containment, stating that transmission owners may present transmission 
projects that look like good opportunities for right-sizing at low 
cost, but without cost containment and competition, the final cost 
could be much higher.\3661\ ACEG argues that the Commission could issue 
policy guidance regarding its scope and process for review of new 
replacement transmission facilities in transmission rate cases.\3662\
---------------------------------------------------------------------------

    \3661\ Massachusetts Attorney General Initial Comments at 52.
    \3662\ ACEG Initial Comments at 57 (citation omitted).
---------------------------------------------------------------------------

    1732. Competition Coalition and LS Power argue that the Commission 
should protect customers by expanding the benefits of regional 
transmission planning and competition to all transmission projects 100 
kV and above.\3663\ Ameren responds that this request by LS Power to 
expand the range of transmission projects subject to competition is 
outside the scope of the NOPR.\3664\
---------------------------------------------------------------------------

    \3663\ Competition Coalition Initial Comments at 68-69; LS Power 
Initial Comments at 136, 141 (citations omitted); LS Power and NRG 
Post-Technical Conference Comments at 10 & n.17 (noting that its 
comment on this issue is attributed to LS Power only).
    \3664\ Ameren Reply Comments at 15 (citing LS Power Initial 
Comments at 116).
---------------------------------------------------------------------------

    1733. Harvard ELI favors additional scrutiny of right-sized 
replacement transmission facilities. Harvard ELI states generally that 
the Commission could address the perverse incentives of current rules 
leading to a focus on local transmission development by subjecting 
local transmission planning to heightened scrutiny.\3665\
---------------------------------------------------------------------------

    \3665\ Harvard ELI Initial Comments at 4.
---------------------------------------------------------------------------

    1734. PIOs claim that the Commission should consider an ``ROE 
subtractor'' analogous to an ROE adder that automatically reduces ROE 
with certain criteria.\3666\
---------------------------------------------------------------------------

    \3666\ PIOs Initial Comments at 53.
---------------------------------------------------------------------------

b. Commission Determination
    1735. We decline to adopt ACEG's and LS Power's requests that the 
Commission itself review in-kind replacement transmission facilities, 
via section 205 or 206 authority or through policy guidance, to ensure 
that they cannot be displaced by a regional transmission solution that 
is more efficient or cost-effective.\3667\ These arguments are outside 
the scope of this proceeding because the Commission did not propose in 
the NOPR that the Commission review in-kind replacement transmission 
facilities or local transmission facilities.
---------------------------------------------------------------------------

    \3667\ ACEG Initial Comments at 57 (citations omitted); LS Power 
Initial Comments at 145-146 (citing LS Power ANOPR Initial Comments 
at 134-135).
---------------------------------------------------------------------------

    1736. We decline to adopt commenters' requests for additional 
confidentiality safeguards related to right-sizing.\3668\ We note that 
a transmission provider's list of in-kind replacement estimates (i.e., 
estimates of the transmission facilities operating at and above the 
specified kV threshold that an individual transmission provider that 
owns the transmission facility anticipates replacing in-kind with a new 
transmission facility during the next 10 years) is a non-binding 
estimate and does not require that transmission provider to undertake 
replacement work. To the extent that customers or stakeholders request 
access to a transmission provider's list of in-kind replacement 
estimates, that transmission provider may subject access to that list 
of in-kind replacement estimates to confidentiality provisions. 
However, once the transmission providers have determined, as part of 
Long-Term Regional Transmission Planning, that an in-kind replacement 
transmission facility can be right-sized to constitute a right-sized 
replacement transmission facility, we find that the transmission 
providers must make public the underlying in-kind replacement 
transmission facility.
---------------------------------------------------------------------------

    \3668\ AEP Initial Comments at 46; Exelon Initial Comments at 
57-58; Indicated PJM TOs Initial Comments at 45-46; SERTP Sponsors 
Initial Comments at 39; WIRES Initial Comments at 10.
---------------------------------------------------------------------------

    1737. We decline to adopt commenter requests for increased scrutiny 
of, or altering the presumption of prudence for, transmission projects 
related to right-sizing.\3669\ We reject these requests as outside the 
scope of this proceeding because the Commission did not propose in the 
NOPR to increase scrutiny of in-kind replacement transmission 
facilities beyond the right-sizing proposal and did not propose to 
alter existing Commission policy on prudence. Likewise, in response to 
PG&E's request for clarification that a transmission provider's 
declining to proceed with a right-sized replacement transmission 
facility does not justify disallowance of cost recovery for the in-kind 
replacement transmission facility, nothing in the reforms we adopt here 
alters existing Commission policy on cost recovery for transmission 
facilities.\3670\
---------------------------------------------------------------------------

    \3669\ American Municipal Power Initial Comments at 29-30; 
California Commission Initial Comments at 114-115; California Water 
Initial Comments at 9; Harvard ELI Initial Comments at 4; 
Massachusetts Attorney General Initial Comments at 52; Mississippi 
Commission Initial Comments at 30; Ohio Consumers Initial Comments 
at 23; Pine Gate Initial Comments at 49-50; PIOs Initial Comments at 
58; Resale Iowa Initial Comments at 9; TAPS Initial Comments at 6-7, 
67.
    \3670\ New England Power Co., 31 FERC ] 61,047, at 61,084 (1985) 
(explaining that the Commission evaluates ``prudence of the 
utility's actions and the costs resulting therefrom based on the 
particular circumstances existing either at the time the challenged 
costs were actually incurred, or the time the utility became 
committed to incur those expenses'').
---------------------------------------------------------------------------

    1738. We acknowledge commenter support for the consideration of 
alternative transmission technologies with regard to right-
sizing.\3671\ However, we find that adopting additional requirements 
for consideration of alternative transmission technologies with respect 
to right-sizing are unnecessary. This is because, as discussed in the 
Consideration of Dynamic Line Ratings and Advanced Power Flow Control 
Devices section of this final order, we require transmission providers 
in each transmission planning region to more fully consider, in Long-
Term Regional Transmission Planning and existing Order No. 1000 
regional transmission planning, dynamic line ratings, advanced power 
flow control devices, advanced conductors, and transmission 
switching.\3672\ We believe that the requirements in the Consideration 
of Dynamic Line Ratings and Advanced Power Flow Control Devices section 
of this final order adequately address consideration of alternative 
transmission technologies in the regional transmission planning 
process, including when considering right-sizing.
---------------------------------------------------------------------------

    \3671\ CTC Global Initial Comments at 18, 20; Maryland Energy 
Administration Reply Comments at 5-6; NARUC Initial Comments at 58-
59, 63-64; PIOs Initial Comments at 57-58; VEIR Initial Comments at 
6.
    \3672\ See Consideration of Dynamic Line Ratings and Advanced 
Power Flow Control Devices section.
---------------------------------------------------------------------------

    1739. Some commenters request that the Commission take other 
actions and suggest alternative reforms to the Commission's proposal 
related to right-sizing.\3673\ We find these requests to be outside the 
scope of this proceeding and lacking in record support to adequately

[[Page 49546]]

consider whether to adopt them in this final order.
---------------------------------------------------------------------------

    \3673\ ACEG Initial Comments at 57; American Municipal Power 
Initial Comments at 5, 25; American Municipal Power Reply Comments 
at 5; California Commission Initial Comments at 106-108; California 
Water Initial Comments at 10; Competition Coalition Initial Comments 
at 68-69; Grid United Initial Comments at 3-4; Harvard ELI Initial 
Comments at 4; LS Power Initial Comments at 83, 136, 138, 141-142, 
145-146; Massachusetts Attorney General Initial Comments at 52; Ohio 
Consumers Initial Comments at 24; PIOs Initial Comments at 53; TAPS 
Initial Comments at 6, 64-65.
---------------------------------------------------------------------------

X. Interregional Transmission Coordination

A. NOPR Proposal

    1740. In the NOPR, the Commission proposed to require each 
transmission provider to revise its existing interregional transmission 
coordination procedures to reflect the Long-Term Regional Transmission 
Planning reforms proposed in the NOPR.\3674\
---------------------------------------------------------------------------

    \3674\ NOPR, 179 FERC ] 61,028 at P 426.
---------------------------------------------------------------------------

    1741. Specifically, the Commission proposed to require transmission 
providers in neighboring transmission planning regions to revise their 
existing interregional transmission coordination procedures (and 
regional transmission planning processes as needed) to provide for: (1) 
the sharing of information regarding their respective transmission 
needs identified in Long-Term Regional Transmission Planning, as well 
as potential transmission facilities to meet those needs; and (2) the 
identification and joint evaluation of interregional transmission 
facilities that may be more efficient or cost-effective transmission 
facilities to address transmission needs identified through Long-Term 
Regional Transmission Planning.\3675\
---------------------------------------------------------------------------

    \3675\ Id. P 427.
---------------------------------------------------------------------------

    1742. The Commission also proposed to require transmission 
providers in neighboring transmission planning regions to revise their 
interregional transmission coordination procedures (and regional 
transmission planning processes as needed) to allow an entity to 
propose an interregional transmission facility in the regional 
transmission planning process as a potential solution to transmission 
needs identified through Long-Term Regional Transmission 
Planning.\3676\ The Commission noted that this proposal would align the 
existing requirement for an entity to propose an interregional 
transmission facility in the regional transmission planning processes 
of each of the neighboring transmission planning regions in which the 
transmission facility is proposed to be located with the proposed 
requirement for transmission providers to conduct Long-Term Regional 
Transmission Planning as part of their regional transmission planning 
processes.
---------------------------------------------------------------------------

    \3676\ Id. P 428.
---------------------------------------------------------------------------

    1743. The Commission stated that this proposed reform aims to 
ensure that transmission needs driven by changes in the resource mix 
and demand identified through Long-Term Regional Transmission Planning 
can be considered in existing interregional transmission coordination 
and cost allocation processes.\3677\ The Commission preliminarily 
concluded that the proposed interregional transmission coordination 
reforms will also ensure that there is an opportunity for the 
transmission providers in neighboring transmission planning regions to 
consider whether there are interregional transmission facilities that 
could more efficiently or cost-effectively meet the transmission needs 
identified through Long-Term Regional Transmission Planning, in turn 
helping to ensure just and reasonable Commission-jurisdictional rates.
---------------------------------------------------------------------------

    \3677\ Id. P 429.
---------------------------------------------------------------------------

B. Comments

    1744. Many commenters support the Commission's proposal to require 
transmission providers to revise their existing interregional 
transmission coordination procedures to reflect the Long-Term Regional 
Transmission Planning reforms proposed in the NOPR.\3678\ Such 
commenters assert that this proposed reform would give transmission 
providers in neighboring transmission planning regions the opportunity 
to consider whether interregional transmission facilities could meet 
the transmission needs identified through Long-Term Regional 
Transmission Planning in a more efficient or cost-effective manner than 
separate regional transmission facilities, which would help to ensure 
just and reasonable rates.
---------------------------------------------------------------------------

    \3678\ Acadia Center and CLF Initial Comments at 23-24; ACEG 
Initial Comments at 74; Ameren Initial Comments at 47; Arizona 
Commission Initial Comments at 10; BP Initial Comments at 13-14; 
Breakthrough Energy Initial Comments at 2; California Commission 
Initial Comments at 118-121; California Energy Commission Initial 
Comments at 4; California Water Initial Comments at 20-21; Clean 
Energy Associations Initial Comments at 40-42; EEI Initial Comments 
at 48; Enel Initial Comments at 4-5; Eversource Initial Comments at 
55-56; Exelon Initial Comments at 60-61; Grid United Initial 
Comments at 7-9; Idaho Power Initial Comments at 13; Indiana 
Commission Initial Comments at 7-9; Interwest Initial Comments at 
18-20; MISO Initial Comments at 88-89; NARUC Initial Comments at 67-
70; National and State Conservation Organizations Initial Comments 
at 1-2; Northwest and Intermountain Initial Comments at 10, 22; OMS 
Initial Comments at 18-20; Pennsylvania Commission Initial Comments 
at 23-25; Pine Gate Initial Comments at 50-51; PIOs Initial Comments 
at 75-79; PJM Initial Comments at 9-10, 123-125; R Street Initial 
Comments at 4-5; State Agencies Initial Comments at 22-23; State 
Officials Supplemental Comments at 1 (citing U.S. Climate Alliance 
Initial Comments at 3); U.S. Climate Alliance Initial Comments at 3; 
U.S. DOE Initial Comments at 38-40; U.S. DOJ and FTC Initial 
Comments at 19-20.
---------------------------------------------------------------------------

    1745. Some commenters condition their support on the Commission 
providing transmission providers with flexibility. For example, EEI 
asserts that providing transmission providers with flexibility in 
developing Long-Term Regional Transmission Planning will help ensure 
that transmission planning regions can determine the processes that 
work for them and collaborate with neighboring regions.\3679\ Idaho 
Power requests that the Commission allow flexibility in the methods 
used to determine transmission benefits.\3680\ Pennsylvania Commission 
conditions its support on the Commission maintaining flexibility for 
transmission providers to define criteria for considering and selecting 
transmission facilities, including criteria that permit the selection 
of proposed regional transmission facilities over a proposed 
interregional transmission facility.\3681\
---------------------------------------------------------------------------

    \3679\ EEI Initial Comments at 48.
    \3680\ Idaho Power Initial Comments at 13.
    \3681\ Pennsylvania Commission Initial Comments at 24-25.
---------------------------------------------------------------------------

    1746. Other commenters suggest that the Commission could improve 
the proposed reforms to interregional transmission coordination by 
requiring additional information sharing. For example, U.S. DOE 
recommends that the Commission require neighboring transmission 
planning regions to share information with one another about their 
geographic zones.\3682\ California Energy Commission recommends that 
transmission providers be required to share with neighboring 
transmission planning regions how other planning processes, such as 
integrated resource plans, resource adequacy, and state requirements, 
are considered in regional transmission planning.\3683\ State Agencies 
suggest that transmission providers should provide an annual report to 
the Commission on their interregional transmission coordination 
activities, including the number of interregional transmission projects 
identified, the results of the cost/benefit evaluation overall and to 
each transmission planning region, whether other regions have been or 
should be included to maximize the value of the project, and any 
barriers to development of interregional transmission projects.\3684\ 
NARUC urges the Commission to encourage additional coordination and 
information sharing between non-RTO/ISO transmission planning regions 
like NorthernGrid and WestConnect.\3685\
---------------------------------------------------------------------------

    \3682\ U.S. DOE Initial Comments at 18-20.
    \3683\ California Energy Commission Initial Comments at 4.
    \3684\ State Agencies Initial Comments at 23.
    \3685\ NARUC Initial Comments at 69-70.
---------------------------------------------------------------------------

    1747. Pattern Energy asserts that the Commission should require 
neighboring transmission planning regions to hold forums for 
stakeholders to discuss right-

[[Page 49547]]

sizing or expanding proposed regional transmission facilities in 
consideration of the needs of both regions.\3686\ Further, Pattern 
Energy argues that if no interregional transmission facilities are 
approved in a Long-Term Regional Transmission Planning cycle, the 
Commission should require transmission planning regions to provide 
transparent reasoning to help stakeholders and regulators understand 
whether interregional transmission coordination requires reform.\3687\
---------------------------------------------------------------------------

    \3686\ Pattern Energy Reply Comments at 14.
    \3687\ Id. at 14-15.
---------------------------------------------------------------------------

    1748. MISO asserts that the Commission should institute a separate 
and longer compliance period for the interregional transmission 
coordination requirements than for the regional transmission planning 
requirements proposed in this rulemaking.\3688\ Further, to reduce the 
compliance burden on transmission providers, MISO requests that the 
Commission include all interregional transmission coordination and 
planning requirements in a single rulemaking rather than require 
interregional compliance in multiple, separate proceedings.\3689\
---------------------------------------------------------------------------

    \3688\ MISO Initial Comments at 89.
    \3689\ Id. at 88-89.
---------------------------------------------------------------------------

    1749. Many commenters assert that the Commission's proposals with 
respect to interregional transmission coordination do not go far 
enough.\3690\ Several commenters urge the Commission to require 
holistic interregional transmission planning and cost allocation.\3691\ 
Some commenters encourage the Commission to require a minimum amount of 
Interregional Transfer Capability between neighboring transmission 
planning regions.\3692\ Several commenters urge the Commission to 
require neighboring transmission planning regions to adopt a common 
system model and planning assumptions, common Long-Term Scenarios, and 
consistent data inputs.\3693\ AEP argues that the Commission should 
require consistency across transmission planning regions in terms of 
the transmission planning horizon, planning frequency, and minimum set 
of benefits considered.\3694\
---------------------------------------------------------------------------

    \3690\ See, e.g., ACEG Initial Comments at 76-78; Breakthrough 
Energy Initial Comments at 2; Clean Energy Associations Initial 
Comments at 41-42; Enel Initial Comments at 4-5; Evergreen Action 
Initial Comments at 5-6; Eversource Initial Comments at 56; Grid 
United Initial Comments at 7-8; Indiana Commission Initial Comments 
at 9; Interwest Initial Comments at 18-19; Invenergy Reply Comments 
at 18; National Grid Initial Comments at 20; OMS Initial Comments at 
18; Pattern Energy Reply Comments at 12-15; Pine Gate Initial 
Comments at 50-51; PIOs Initial Comments at 75-77; PJM Initial 
Comments at 9-10, 123-124; Rail Electrification Initial Comments at 
2, 8-11; RMI Initial Comments at 1-2; State Agencies Initial 
Comments at 23; Transmission Dependent Utilities Initial Comments at 
6-7; U.S. DOE Initial Comments at 38-39; Xcel Initial Comments at 
17.
    \3691\ See, e.g., ACEG Initial Comments at 76-78; Clean Energy 
Associations Initial Comments at 41-42; Enel Initial Comments at 4-
5; Evergreen Action Initial Comments at 5-6; Grid United Initial 
Comments at 7-8; Indiana Commission Initial Comments at 9; Interwest 
Initial Comments at 18-19; Invenergy Reply Comments at 18; National 
Grid Initial Comments at 20; OMS Initial Comments at 18; Pattern 
Energy Reply Comments at 12-15; Pine Gate Initial Comments at 50-51; 
PIOs Initial Comments at 75-77; PJM Initial Comments at 9-10, 123-
124; Rail Electrification Initial Comments at 2, 8-11; RMI Initial 
Comments at 1-2; Shell Reply Comments at 8-9; U.S. DOE Initial 
Comments at 38-39; Xcel Initial Comments at 17.
    \3692\ See, e.g., ACEG Initial Comments at 70-76; AEP Initial 
Comments at 17-18; Breakthrough Energy Initial Comments at 2; 
Evergreen Action Initial Comments at 5-6; Eversource Initial 
Comments at 55-56; Interwest Initial Comments at 18-20; Invenergy 
Initial Comments at 20-27; Invenergy Reply Comments at 19-22; Kansas 
Commission Initial Comments at 4-10; PJM Initial Comments at 9-10, 
123-125.
    \3693\ Hannon Armstrong Reply Comments at 1; Invenergy Reply 
Comments at 19-22; National Grid Initial Comments at 19-20; 
Transmission Dependent Utilities Initial Comments at 6-7; U.S. DOE 
Initial Comments at 18-21.
    \3694\ AEP Reply Comments at 3-5.
---------------------------------------------------------------------------

    1750. MISO encourages the Commission to examine interregional 
transmission planning, including analysis of the assumptions related to 
transfer capacity and the effectiveness of collaboration between RTO 
and non-RTO neighbors, in a separate docket.\3695\ Eversource and State 
Agencies suggest that the Commission encourage RTOs/ISOs to increase 
staffing to address interregional transmission planning.\3696\ National 
Grid suggests that the Commission provide appropriate rate incentives 
for interregional transmission facilities.\3697\ Rail Electrification 
urges the Commission to support the siting of large interregional 
transmission facilities along available interstate transportation 
rights-of-way to advance the grid of the future more quickly.\3698\
---------------------------------------------------------------------------

    \3695\ MISO Reply Comments at 29-30.
    \3696\ Eversource Initial Comments at 55-56; State Agencies 
Initial Comments at 23.
    \3697\ National Grid Initial Comments at 20.
    \3698\ Rail Electrification Initial Comments at 8-12.
---------------------------------------------------------------------------

C. Commission Determination

    1751. We adopt, with modification, the NOPR proposal to require 
transmission providers in each transmission planning region to revise 
their existing interregional transmission coordination procedures to 
reflect the Long-Term Regional Transmission Planning reforms adopted in 
this final order. Specifically, we adopt the NOPR proposal to require 
transmission providers in neighboring transmission planning regions to 
revise their existing interregional transmission coordination 
procedures (and regional transmission planning processes, as needed) to 
provide for: (1) the sharing of information regarding their respective 
Long-Term Transmission Needs, as well as Long-Term Regional 
Transmission Facilities to meet those needs; and (2) the identification 
and joint evaluation of interregional transmission facilities that may 
be more efficient or cost-effective transmission facilities to address 
Long-Term Transmission Needs.
    1752. Additionally, we adopt the NOPR proposal to require 
transmission providers in neighboring transmission planning regions to 
revise their interregional transmission coordination procedures (and 
regional transmission planning processes, as needed) to allow an entity 
to propose an interregional transmission facility in the regional 
transmission planning process as a potential solution to Long-Term 
Transmission Needs. We find that this requirement will align the 
existing requirement, for an entity to propose an interregional 
transmission facility in the regional transmission planning processes 
of each of the neighboring transmission planning regions in which the 
transmission facility is proposed to be located, with the new 
requirement in this final order for transmission providers to conduct 
Long-Term Regional Transmission Planning as part of their regional 
transmission planning processes.
    1753. In response to commenter requests for additional information 
sharing and transparency of the interregional transmission coordination 
process, we find that additional transparency as applied to Long-Term 
Regional Transmission Planning is warranted.\3699\ Order No. 1000 
requires that transmission providers in neighboring transmission 
planning regions maintain a website or email list for the communication 
of information related to interregional transmission coordination 
procedures.\3700\ We modify the NOPR proposal, and require transmission 
providers in each transmission planning region to provide the following 
additional information concerning Long-Term Regional Transmission 
Planning on their public website or through the email list used for 
communication of information related to interregional transmission 
coordination procedures: (1) the Long-Term Transmission Needs discussed 
in the interregional transmission coordination meetings; (2) any

[[Page 49548]]

interregional transmission facilities proposed or identified in 
response to Long-Term Transmission Needs; (3) the voltage level, 
estimated cost, and estimated in-service date of the interregional 
transmission facilities proposed or identified as part of Long-Term 
Regional Transmission Planning; (4) the results of any cost-benefit 
evaluation of such interregional transmission facilities, with such 
results including both any overall benefits identified (which may occur 
across multiple transmission planning regions), as well as any benefits 
particular to each transmission planning region; and (5) the 
interregional transmission facilities, if any, selected to meet Long-
Term Transmission Needs. We find that this modification will enhance 
transparency and facilitate stakeholder engagement in the interregional 
transmission coordination procedures as applied to Long-Term Regional 
Transmission Planning, thereby ensuring just and reasonable rates. We 
believe that this requirement to make this information publicly 
available will not create a significant burden because transmission 
providers will already share or develop such information with the 
transmission providers in neighboring transmission planning regions to 
comply with the requirement in this final order to revise their 
existing interregional transmission coordination procedures to reflect 
the Long-Term Regional Transmission Planning reforms.
---------------------------------------------------------------------------

    \3699\ See, e.g., California Energy Commission Initial Comments 
at 4; NARUC Initial Comments at 69-70; Pattern Energy Reply Comments 
at 14-15; State Agencies Initial Comments at 23.
    \3700\ Order No. 1000, 136 FERC ] 61,051 at PP 345, 458.
---------------------------------------------------------------------------

    1754. Taken together, we find that these reforms will ensure that 
Long-Term Transmission Needs identified through Long-Term Regional 
Transmission Planning can be considered in existing interregional 
transmission coordination and cost allocation processes. Further, doing 
so will ensure that there is an opportunity for the transmission 
providers in neighboring transmission planning regions to consider 
whether there are interregional transmission facilities that could more 
efficiently or cost-effectively address the identified Long-Term 
Transmission Needs, in turn helping to ensure just and reasonable 
Commission-jurisdictional rates.
    1755. We decline to require the transmission providers in 
neighboring transmission planning regions to hold forums for 
stakeholders to discuss right-sizing or expanding proposed regional 
transmission facilities in consideration of the transmission needs of 
both regions, as requested by Pattern Energy. The Commission did not 
propose such a reform in the NOPR, and we decline to require it here.
    1756. Regarding Idaho Power's request that the Commission provide 
transmission providers with flexibility in the methods used to 
determine the benefits of interregional transmission facilities, we 
note that this issue is addressed above in the Evaluation of the 
Benefits of Regional Transmission Facilities section of this final 
order.\3701\ Regarding Pennsylvania Commission's comment that its 
support for the interregional transmission coordination reforms 
proposed in the NOPR are conditioned on the Commission maintaining 
flexibility for transmission providers to define criteria for 
considering and selecting transmission facilities, we note that the 
requirements regarding selection criteria are addressed in the section 
above on the Evaluation and Selection of Long-Term Regional 
Transmission Facilities.\3702\
---------------------------------------------------------------------------

    \3701\ See supra Evaluation of the Benefits of Regional 
Transmission Facilities section.
    \3702\ See supra Evaluation and Selection of Long-Term Regional 
Transmission Facilities section.
---------------------------------------------------------------------------

    1757. Regarding MISO's request for a longer compliance period for 
transmission providers to comply with the interregional transmission 
coordination requirements of this final order, we address MISO's 
request in the Compliance section below.\3703\
---------------------------------------------------------------------------

    \3703\ See infra Compliance Procedures section.
---------------------------------------------------------------------------

    1758. With respect to commenter requests for the Commission to: (1) 
require holistic interregional transmission planning and cost 
allocation; (2) require a minimum amount of Interregional Transfer 
Capability between neighboring transmission planning regions; (3) 
require neighboring transmission planning regions to adopt a common 
system model, consistent data inputs, and a uniform transmission 
planning horizon and transmission planning frequency; (4) encourage 
RTOs/ISOs to increase staffing to address interregional transmission 
planning; (5) adopt new rate incentives for interregional transmission 
facilities; and (6) support the siting of large interregional 
transmission facilities along available transportation rights-of-way, 
we find such requests to be outside the scope of this proceeding. We 
recognize that one or more of these reforms hold the potential to 
enhance system reliability or provide significant consumer benefits. 
However, the Commission did not propose such reforms in the NOPR, and 
we decline to adopt them in the final order. However, we note that the 
Commission currently has an open proceeding in Docket No. AD23-3-000 to 
consider whether and how to establish a minimum requirement for 
Interregional Transfer Capability, and may consider further reforms in 
other proceedings, as appropriate.\3704\
---------------------------------------------------------------------------

    \3704\ See Supplemental Notice of Staff-Led Workshop, 
Establishing Interregional Transfer Capability Transmission Planning 
and Cost Allocation Requirements, Docket No. AD23-3-000 (Nov. 30, 
2022).
---------------------------------------------------------------------------

XI. Compliance Procedures

A. NOPR Proposal

    1759. In the NOPR, the Commission proposed to require each 
transmission provider to submit a compliance filing within eight months 
of the effective date of any final order in this proceeding revising 
its OATT and other document(s) subject to the Commission's jurisdiction 
as necessary to demonstrate that it meets the requirements adopted in 
any final order in this proceeding.\3705\ The Commission proposed that 
transmission providers that are not public utilities would have to 
adopt the requirements adopted in any final order in this proceeding as 
a condition of maintaining the status of their safe harbor tariff or 
otherwise satisfying the reciprocity requirement of Order No. 
888.\3706\
---------------------------------------------------------------------------

    \3705\ NOPR, 179 FERC ] 61,028 at P 430.
    \3706\ Id. P 432 (citing Order No. 888, FERC Stats. & Regs. ] 
31,036 at 31,760-63).
---------------------------------------------------------------------------

    1760. Additionally, in the NOPR, the Commission proposed to require 
transmission providers to demonstrate on compliance that proposed 
variations from the requirements in the final order are consistent with 
or superior to the final order.\3707\
---------------------------------------------------------------------------

    \3707\ Id. PP 74-75, 105, 229.
---------------------------------------------------------------------------

B. Comments

    1761. Several commenters support a compliance period of eight 
months or more to allow stakeholders, including Relevant State 
Entities, sufficient time to negotiate and agree on proposals to comply 
with this rulemaking.\3708\ PJM states that while an eight-month period 
to submit compliance filings is reasonable, the Commission should 
thereafter allow time for transmission planners to develop the tools 
and hire the employees they will need to implement the final 
order.\3709\ NEPOOL states that the Commission should be flexible in 
considering requests for extensions of time.\3710\ Pacific Northwest 
State Agencies urge the

[[Page 49549]]

Commission to provide flexibility rather than a rigid time period of 
eight months to comply with the final order.\3711\
---------------------------------------------------------------------------

    \3708\ Idaho Power Initial Comments at 14; ISO-NE Initial 
Comments at 41; MISO Initial Comments at 90; NARUC Initial Comments 
at 50-51; NEPOOL Initial Comments at 10; NESCOE Reply Comments at 9 
(citing ISO-NE Initial Comments at 41); North Carolina Commission 
and Staff Initial Comments at 17; Northwest and Intermountain 
Initial Comments at 22-23; Pacific Northwest State Agencies Initial 
Comments at 28; PJM Initial Comments at 10, 129.
    \3709\ PJM Initial Comments at 10, 129.
    \3710\ NEPOOL Initial Comments at 10.
    \3711\ Pacific Northwest State Agencies Initial Comments at 28.
---------------------------------------------------------------------------

    1762. Certain TDUs argue that the Commission should require 
transmission providers to submit compliance filings no later than 270 
days after the final order becomes effective to reflect the 
requirements to include an ex ante Long-Term Regional Transmission Cost 
Allocation Method, define benefits, and identify the method by which 
benefits are selected.\3712\
---------------------------------------------------------------------------

    \3712\ Certain TDUs Initial Comments at 16.
---------------------------------------------------------------------------

    1763. Some commenters request that the Commission provide longer 
than eight months to comply with the final order. For example, NARUC 
argues that eight months is unlikely to allow sufficient time for 
Relevant State Entities to meaningfully engage.\3713\ Given the 
complexity of the proposals and the need to coordinate with 
stakeholders, Idaho Power and ISO-NE propose that the Commission allow 
at least one year for transmission providers to comply with the final 
order.\3714\ For similar reasons, MISO urges the Commission to provide 
a compliance period of at least 18 months. In addition, to avoid 
interfering with ongoing transmission expansion efforts in some 
transmission planning regions, MISO argues that the Commission should 
allow such regions to propose their own compliance date or instead 
should state that the final order would not apply to any such ongoing 
transmission expansion efforts, including MISO's Long-Range 
Transmission Planning initiative.\3715\ Additionally, MISO requests 
that the new order and tariff revisions complying with the final order 
be made effective upon the Commission's acceptance of the filing 
party's compliance filing.\3716\
---------------------------------------------------------------------------

    \3713\ NARUC Initial Comments at 50-51.
    \3714\ Idaho Power Initial Comments at 14; ISO-NE Initial 
Comments at 41.
    \3715\ MISO Initial Comments at 90-92.
    \3716\ Id. at 90-91; MISO Reply Comments at 32.
---------------------------------------------------------------------------

    1764. PJM states that it would be more efficient and less confusing 
if PJM could first build the long-term model and then comply with the 
selection and cost allocation requirements at a later date. PJM 
therefore requests that the Commission clarify whether it is necessary 
for transmission providers to develop compliance procedures with 
respect to selection and cost allocation of transmission projects to be 
selected through Long-Term Regional Transmission Planning before they 
have had a chance to create and finalize their long-term transmission 
planning processes.\3717\
---------------------------------------------------------------------------

    \3717\ PJM Initial Comments at 98-104.
---------------------------------------------------------------------------

    1765. MISO asserts that the Commission should allow a separate and 
longer compliance period for the interregional transmission 
coordination requirements.\3718\
---------------------------------------------------------------------------

    \3718\ MISO Initial Comments at 89.
---------------------------------------------------------------------------

    1766. Separately, MISO states that while the NOPR indicates that 
the Commission might permit regional flexibility in some areas, it 
adopts the ``consistent with or superior to'' legal standard for 
evaluating proposed deviations on compliance.\3719\ MISO argues that 
this standard is too inflexible to achieve the Commission's objectives 
because it neither recognizes the independent nature of RTOs/ISOs nor 
has a built-in mechanism to acknowledge legitimate regional 
differences.\3720\ Therefore, MISO recommends that the Commission 
instead apply a version of the ``independent entity'' variation 
standard to RTOs/ISOs or otherwise make clear that the proposed reforms 
contemplate regional flexibility to allow RTOs to retain their best 
transmission planning practices, particularly those RTOs that are 
``early movers'' of the types of reforms in the NOPR.\3721\ If the 
Commission decides not to adopt the independent entity variation 
standard for this final order, MISO urges the Commission to clarify 
that it will recognize as ``consistent with or superior to'' any 
existing regional transmission planning processes that are 
substantially equivalent to the proposed requirements to avoid impeding 
progress already made, while compelling reform in transmission planning 
regions where needed.\3722\
---------------------------------------------------------------------------

    \3719\ MISO Reply Comments at 4 (citing NOPR, 179 FERC ] 61,028 
at PP 74-75).
    \3720\ MISO Initial Comments at 21-22; MISO Reply Comments at 5.
    \3721\ MISO Reply Comments at 4. For example, MISO states that 
its MVP and Long-Range Transmission Plan processes are broadly 
consistent with the principles and goals of the NOPR and some of its 
specific proposals, including development of multiple futures, 
review of various benefit metrics, and use of a 20-year transmission 
planning horizon. MISO states that repeating the extensive 
stakeholder effort involved in developing these processes to comply 
with the new requirements would stall its momentum. MISO Initial 
Comments at 10.
    \3722\ MISO Initial Comments at 25; MISO Reply Comments at 8-9.
---------------------------------------------------------------------------

    1767. ISO-NE and ISO RTO Council argue that flexibility should 
extend to determining the rules for inclusion in the tariff, with 
implementation details in planning procedures or guides, consistent 
with the Commission's ``rule of reason'' standard.\3723\
---------------------------------------------------------------------------

    \3723\ ISO-NE Initial Comments at 20; ISO/RTO Council Initial 
Comments at 8-9 (citing City of Cleveland v. FERC, 773 F.2d. at 
1376).
---------------------------------------------------------------------------

C. Commission Determination

    1768. We adopt the NOPR proposal, with modification, and require 
each transmission provider to submit a compliance filing within ten 
months of the effective date of this final order revising its OATT and 
other document(s) subject to the Commission's jurisdiction as necessary 
to demonstrate that it meets all of the requirements adopted in this 
final order, except those adopted in the Interregional Transmission 
Coordination section of this final order. In response to comments from 
NARUC, Idaho Power, ISO-NE, and MISO requesting a longer compliance 
timeline, we find that requiring a ten-month compliance period instead 
of the eight-month compliance period proposed in the NOPR will allow 
transmission providers to fully develop proposals to comply with this 
final order and allow stakeholders, including Relevant State Entities, 
to meaningfully engage in the process of developing such proposals. As 
discussed in the Implementation of Long-Term Regional Transmission 
Planning section, we require transmission providers in each 
transmission planning region to propose on compliance a date, no later 
than one year from the date on which initial filings to comply with 
this final order are due, on which they will commence the first Long-
Term Regional Transmission Planning cycle (unless additional time is 
needed to align the first Long-Term Regional Transmission Planning 
cycle with existing transmission planning cycles). Therefore, 
transmission providers in each transmission planning region must 
propose an effective date for the OATT revisions necessary to comply 
with this final order that is no later than the date on which they will 
commence the first Long-Term Regional Transmission Planning cycle. 
However, transmission providers may propose an earlier effective date 
for some or all parts of their revised OATTs to allow them to begin 
implementing any aspects of the required reforms sooner than the one-
year deadline to commence the first Long-Term Regional Transmission 
Planning cycle.
    1769. We deny PJM's request for clarification to allow a later 
compliance deadline for the selection and cost allocation requirements 
of this final order and find it appropriate to require

[[Page 49550]]

that transmission providers submit a compliance filing that addresses 
all the requirements of this final order within ten months of the 
effective date of this final order, with the exception of the 
requirements related to interregional transmission coordination, as 
previously noted.
    1770. In response to MISO's request for a separate, longer 
compliance timeline for the interregional transmission coordination 
requirements, we also modify the NOPR proposal and require each 
transmission provider to submit a separate compliance filing within 12 
months of the effective date of this final order revising its OATT and 
other document(s) subject to the Commission's jurisdiction as necessary 
to demonstrate that it meets the interregional transmission 
coordination requirements adopted in this final order.\3724\ We find 
that the additional time to comply with the interregional transmission 
coordination requirements will allow transmission providers to 
coordinate with the transmission providers in each of their neighboring 
transmission planning regions to develop interregional transmission 
coordination proposals.
---------------------------------------------------------------------------

    \3724\ See supra Interregional Transmission Coordination 
section.
---------------------------------------------------------------------------

    1771. Additionally, we adopt the proposed requirement that 
transmission providers that are not public utilities must adopt the 
requirements of this final order as a condition of maintaining the 
status of their safe harbor tariff or otherwise satisfying the 
reciprocity requirement of Order No. 888.\3725\
---------------------------------------------------------------------------

    \3725\ NOPR, 179 FERC ] 61,028 at P 432 (citing Order No. 888, 
FERC Stats. & Regs. ] 31,036 at 31,760-63).
---------------------------------------------------------------------------

    1772. In this final order, we make no changes to the standards used 
to judge requested variations, as described in Order Nos. 888, 2000, 
890, and 1000.\3726\ Accordingly, we decline to grant MISO's request 
that the Commission apply the independent entity variation standard, 
rather than the ``consistent with or superior to'' standard, for 
proposed deviations from the requirements in this final order on 
compliance. Consistent with the Commission's findings in Order No. 890, 
we will continue to apply the ``consistent with or superior to'' 
standard in the context of transmission planning.\3727\
---------------------------------------------------------------------------

    \3726\ Order No. 1000, 136 FERC ] 61,051 at P 815; Order No. 
890, 118 FERC ] 61,119 at P 109; Order No. 2000, FERC Stats. & Regs. 
] 31,089 at 31,164; Order No. 888, FERC Stats. & Regs. ] 31,036, at 
31,769-70.
    \3727\ Order No. 890, 118 FERC ] 61,119 at P 160.
---------------------------------------------------------------------------

    1773. Regarding MISO's request for clarification, we decline to 
clarify as part of this final order that any existing transmission 
planning processes are consistent with or superior to the requirements 
in this final order. Rather, it is more appropriate for a transmission 
provider to submit such a request as part of its compliance filing, in 
which the transmission provider must demonstrate that any deviation 
from the requirements of this final order, including any existing 
processes and/or OATT provisions, are consistent with or superior to 
the requirements of this final order. Similarly, to the extent that a 
transmission provider believes that it already complies with any of the 
requirements of this final order, it should describe in its compliance 
filing how the relevant requirements are satisfied, including by 
referencing specific tariff sheets already on file with the Commission.
    1774. In response to ISO-NE's and ISO RTO Council's comment that 
the final order should provide flexibility as to which implementation 
details should be included in planning procedures or guides consistent 
with the Commission's ``rule of reason'' standard, we note that the 
Commission has broad discretion in applying the rule of reason 
policy,\3728\ under which provisions that ``significantly affect rates, 
terms, and conditions'' of service, are realistically susceptible of 
specification, and are not generally understood in a contractual 
agreement, must be included in the tariff. The tariff need not include 
``mere implementation details,'' \3729\ which instead may be included 
only in the business practice manuals. ``[E]ven specifiable practices 
that significantly affect rates need not be included if they are 
clearly implied by the tariff's express terms.'' \3730\ The final order 
specifies with respect to each requirement the information that must be 
incorporated into the transmission provider's OATT. We find that the 
requirements in this final order regarding what information 
transmission providers must specify in their tariff on compliance is 
consistent with the Commission's rule of reason policy.
---------------------------------------------------------------------------

    \3728\ Hecate Energy Greene Cnty. 3 LLC v. FERC, 72 F.4th at 
1314 (citing City of Cleveland v. FERC, 773 F.2d at 1376 (the FPA's 
``amorphous'' requirement that tariffs include ``practices affecting 
rates'' means that the Commission has ``broad discretion'' in giving 
the act ``concrete application.'')).
    \3729\ Id. at 1312.
    \3730\ Id. at 1314 (citing City of Cleveland v. FERC, 773 F.2d 
at 1376).
---------------------------------------------------------------------------

XII. Information Collection Statement

    1775. The information collection requirements contained in this 
final order are subject to review by the Office of Management and 
Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of 
1995.\3731\ OMB's regulations require approval of certain information 
collection requirements imposed by agency rules.\3732\ Upon approval of 
a collection of information, OMB will assign an OMB control number and 
expiration date. Respondents subject to the filing requirements of this 
final order will not be penalized for failing to respond to these 
collections of information unless the collections of information 
display a valid OMB control number.
---------------------------------------------------------------------------

    \3731\ 44 U.S.C. 3507(d).
    \3732\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    1776. The reforms adopted in this final order revise the 
Commission's pro forma OATT to remedy deficiencies in the Commission's 
existing regional transmission planning and cost allocation and local 
transmission planning requirements to ensure that Commission-
jurisdictional rates and practices are just and reasonable and not 
unduly discriminatory or preferential.
    1777. In the NOPR, the Commission solicited comments on: the 
Commission's need for this information; whether the information will 
have practical utility; the accuracy of the burden estimates; ways to 
enhance the quality, utility, and clarity of the information to be 
collected or retained; and any suggested methods for minimizing 
respondents' burden, including the use of automated information 
techniques. The Commission received one comment from PJM specifically 
about the time and effort required to comply with the information 
collection requirement.\3733\
---------------------------------------------------------------------------

    \3733\ PJM Initial Comments at 10, 125-29.
---------------------------------------------------------------------------

    1778. PJM claims that the Commission significantly underestimates 
the cost for PJM and other transmission providers to comply with the 
final order. PJM states that its compliance will require additional 
staff of between seven to 14 new staff members and that the added cost 
will be at least $2.1 million per year. However, PJM adds that it 
generally supports the proposed reforms in the NOPR and provides this 
information only to give the Commission a better understanding of the 
time and costs associated with implementing the final order.\3734\
---------------------------------------------------------------------------

    \3734\ Id. at 128-29.
---------------------------------------------------------------------------

    1779. In response to PJM's comments on the NOPR, we note that this 
information collection statement estimates the burdens \3735\ to 
generate,

[[Page 49551]]

maintain, retain, or disclose or provide information to or for a 
Federal agency. In light of the information that PJM supplied, we have 
revised the table below to increase the estimated amount of labor 
required for a transmission provider to perform Long-Term Regional 
Transmission Planning.\3736\ We expect that the information collection 
requirements associated with updating these datasets for subsequent 
cycles will entail substantially less effort than the initial Long-Term 
Regional Transmission Planning cycle.
---------------------------------------------------------------------------

    \3735\ ``Burden'' is the total time, effort, or financial 
resources expended by persons to generate, maintain, retain, or 
disclose or provide information to or for a Federal agency. For 
further explanation of what is included in the information 
collection burden, refer to 5 CFR 1320.3(b)(1).
    \3736\ For example, for an entire transmission planning region, 
we anticipate that 10 people each working 2,000 hours per year would 
spend 20,000 hours per year to develop these datasets.
---------------------------------------------------------------------------

    1780. Summary of the Revisions to the Collection of Information due 
to the final order in Docket No. RM21-17-000:
     Title: Electric Transmission Facilities (FERC-917).\3737\
---------------------------------------------------------------------------

    \3737\ In the NOPR, in addition to proposing to revise the FERC-
917 information collection, the Commission proposed to revise the 
pro forma LGIP and, therefore, to revise the FERC-516 information 
collection (Reform of Generator Interconnection Procedures and 
Agreements). In this final order, we decline to revise the pro forma 
LGIP, and therefore we are not revising the FERC-516 information 
collection.
---------------------------------------------------------------------------

     Action: Revision of collections of information in 
accordance with Docket No. RM21-17-000.
     OMB Control Nos.: 1902-0233 (FERC-917).
     Respondents: Transmission providers, including RTOs/ISOs.
     Frequency of Information Collection: One time during Year 
1. Occasional times during subsequent years, at least once every five 
years.
     Necessity of Information: The reforms in this final order 
will correct deficiencies in the Commission's existing regional 
transmission planning and cost allocation requirements to ensure that 
Commission-jurisdictional rates remain just and reasonable and not 
unduly discriminatory or preferential.
     Internal Review: We have reviewed the reforms and have 
determined that such reforms are necessary. These reforms conform to 
the Commission's need for efficient information collection, 
communication, and management within the energy industry. We have 
specific, objective support for the burden estimates associated with 
the information collection requirements.
     Public Reporting Burden: The burden and cost estimates 
below are based on the need for applicable entities to revise 
documentation, already required by the Commission's pro forma OATT. Our 
estimates are based on the North American Electric Reliability 
Corporation Compliance Registry as of January 11, 2024, which indicates 
that there are 48 transmission service providers \3738\ with OATTs and 
118 transmission owners that are registered within the United States 
and are subject to this rulemaking.\3739\ Because 41 of the 118 
transmission owners are also included in the count of 48 transmission 
service providers, there are 125 distinct entities (i.e., 125 distinct 
transmission providers 3740 3741 3742) in total that must 
comply this final order. We note that, for the purposes of regional 
transmission planning, these 125 entities are grouped into 11 
transmission planning regions.
---------------------------------------------------------------------------

    \3738\ The transmission service provider (TSP) function is a 
North American Electric Reliability Corporation registration 
function, which is similar to the transmission provider that is 
referenced in the pro forma OATT. The TSP function is being used as 
a proxy to estimate the number of transmission providers that are 
impacted by this proposed rulemaking.
    \3739\ The number of entities listed from the North American 
Electric Reliability Corporation Compliance Registry reflects the 
omission of the Texas registered entities. Note that the 48 
transmission providers with OATTs do not include non-public utility 
transmission providers with reciprocity tariffs.
    \3740\ See supra note 2.
    \3741\ In the table, Year 1 figures are one-time implementation 
hours and cost. ``Subsequent years'' show ongoing burdens and costs 
starting in Year 2.
    \3742\ The hourly cost (for salary plus benefits) uses the 
figures from the Bureau of Labor Statistics (BLS) for three 
positions involved in the reporting and recordkeeping requirements. 
These figures include salary (based on BLS data for May 2022, issued 
April 25, 2023, https://bls.gov/oes/current/naics2_22.htm) and 
benefits (based on BLS data for September 2023; issued December 15, 
2023, https://www.bls.gov/news.release/ecec.nr0.htm) and are Manager 
(Occupation Code 11-0000, $122.48/hour), Electrical Engineer 
(Occupation Code 17-2071, $89.04/hour), and File Clerk (Occupation 
Code 43-4071, $42.43/hour). The hourly cost for the reporting 
requirements ($105.76) is an average of the hourly cost (wages plus 
benefits) of a manager and engineer. The hourly cost for 
recordkeeping requirements uses the cost of a file clerk.
---------------------------------------------------------------------------

    1781. We estimate that the final order would affect the burden and 
cost of FERC-917 as follows:

                           Changes Due to Final Order in Docket No. RM21-17-000 \3741\
----------------------------------------------------------------------------------------------------------------
                                                                                               total estimated
                                                         Total annual      Average burden       burden hours &
       Area of modification         Annual number  of      estimated    hours & cost \3742\    total estimated
                                       respondents        number  of        per response      cost  (column C x
                                                           responses                              column D)
A                                  B..................               C  D..................  E
----------------------------------------------------------------------------------------------------------------
                     FERC-917, Electric Transmission Facilities (OMB Control No. 1902-0233)
----------------------------------------------------------------------------------------------------------------
Draft OATT revisions to comply     48 transmission                  48  One Time: 770        One Time: 36,960
 with the requirements of the       providers with                       hours; $71,683.      hours; $3,440,783.
 final order.                       OATTs.                              Ongoing: 0 hours     Ongoing: 0 hours
                                                                         per year; $0 per     per year; $0 per
                                                                         year.                year.
Establish a six-month time period  48 transmission                  48  One Time: 390        One Time: 18,720
 during which transmission          providers with                       hours; $36,307.      hours; $1,742,734.
 providers must, among other        OATTs.                              Ongoing: 0 hours     Ongoing: 0 hours
 things, provide a forum for                                             per year; $0 per     per year; $0 per
 negotiation that enables                                                year.                year.
 participation by Relevant State
 Entities and to discuss
 potential Long-Term Regional
 Transmission Cost Allocation
 Methods and/or a State Agreement
 Process.

[[Page 49552]]

 
Participate in Long-Term Regional  48 transmission                  48  One Time: 0 hours;   One Time: 0 hours;
 Transmission Planning, which       providers with      ..............   $0.                  $0.
 includes creating and updating     OATTs.              ..............  Ongoing: 4,500       Ongoing: 216,000
 datasets, developing Long-Term    ...................  ..............   hours per year;      hours per year;
 Scenarios, evaluating the         ...................  ..............   $418,926 per year.   $20,108,471 per
 benefits of Long-Term Regional    ...................              77  One Time: 0 hours;    year.
 Transmission Facilities, and      77 transmission                       $0.                 ...................
 establishing criteria in           providers without                   Ongoing: 200 hours   ...................
 consultation with Relevant State   OATTs.                               per year; $18,619.  One Time: 0 hours;
 Entities and stakeholders to                                                                 $0.
 select Long-Term Regional                                                                   Ongoing: 15,400
 Transmission Facilities in the                                                               hours per year;
 regional transmission plan for                                                               $1,433,659 per
 purposes of cost allocation.                                                                 year.
Revise the regional transmission   48 transmission                  48  One Time: 30 hours;  One Time: 1,440
 planning process to enhance        providers with      ..............   $2,793.              hours; $134,056.
 transparency of local              OATTs.              ..............  Ongoing: 120 hours   Ongoing: 5,760
 transmission planning and         ...................  ..............   per year; $11,172    hours per year;
 identifying potential             ...................  ..............   per year.            $536,226 per year.
 opportunities to right-size       ...................              77  One Time: 20 hours;  ...................
 replacement transmission          77 transmission                       $1,862.             One Time: 1,540
 facilities.                        providers without                   Ongoing: 40 hours     hours; $143,366.
                                    OATTs.                               per year; $3,724    Ongoing: 3,080
                                                                         per year.            hours per year;
                                                                                              $286,732 per year.
Evaluate whether certain           48 transmission                  48  One Time: 0 hours;   One Time: 0 hours;
 alternative transmission           providers with      ..............   $0.                  $0.
 technologies can meet the          OATTs.              ..............  Ongoing: 100 hours   Ongoing: 4,800
 transmission needs identified in  ...................  ..............   per year; $9,309     hours per year;
 Order No. 1000 regional           ...................  ..............   per year.            $446,855 per year.
 transmission planning processes   ...................              77  One Time: 0 hours;   ...................
 and in Long-Term Regional         77 transmission                       $0.                 ...................
 Transmission Planning process      providers without                   Ongoing: 20 hours    One Time: 0 hours;
 more efficiently or cost-          OATTs.                               per year; $1,862     $0.
 effectively than transmission                                           per year.           Ongoing: 1540 hours
 facilities without such                                                                      per year; $143,366
 alternative transmission                                                                     per year.
 technologies.
Consider in the Order No. 1000     48 transmission                  48  One Time: 0 hours;   One Time: 0 hours;
 regional transmission planning     providers with                       $0.                  $0.
 processes regional transmission    OATTs.                              Ongoing: 50 hours    Ongoing: 2,400
 facilities that address certain                                         per year; $4,655     hours per year;
 interconnection-related needs..                                         per year.            $223,427 per year.
Share with the transmission        48 transmission                  48  One Time: 0 hours;   One Time: 0 hours;
 providers in neighboring           providers with                       $0.                  $0.
 transmission planning regions      OATTs.                              Ongoing: 25 hours     Ongoing: 1,200
 information regarding Long-Term                                         per year; $2,327     hours per year;
 Transmission Needs and potential                                        per year.            $111,714 per year.
 transmission facilities to meet
 those needs; identify and
 jointly evaluate interregional
 transmission facilities with the
 transmission providers in
 neighboring transmission
 planning regions; and publicly
 post certain information
 regarding interregional
 coordination processes applied
 to Long-Term Regional
 Transmission Planning..
Total burden for the revisions of  48 transmission                  48  One Time: 1,190      One Time: 57,120
 FERC 917 due to RM21-17.           providers with                       hours; $110,783.     hours; $5,317,573.
                                    OATTs.                              Ongoing: 4,795       Ongoing: 230,160
                                                                         hours per year;      hours per year;
                                                                         $446,390 per year.   *$21,426,693 per
                                                                                              year.
1................................  77 transmission                  77  One Time: 20 hours;  One Time: 1,540
                                    providers without                    $1,862.              hours; $143,366.
                                    OATTs.                              Ongoing: 260 hours   Ongoing: 20,020
                                                                         per year; $24,205    hours per year;
                                                                         per year.            $1,863,757 per
                                                                                              year.
                                  ------------------------------------------------------------------------------
                                   Totals for all 125 transmission providers                 One Time: 58,660
                                                                                              hours; $5,460,939.
                                                                                             Ongoing: 250,180
                                                                                              hours per year;
                                                                                              $23,290,450 per
                                                                                              year.
----------------------------------------------------------------------------------------------------------------


[[Page 49553]]

    1782. Our estimates conservatively assume the maximum number of 
respondents and burdens. We acknowledge that the actual burdens for 
some respondents may be lower than estimated and that other respondents 
may incur the maximum burdens.
    1783. Interested persons may obtain information on the reporting 
requirements by contacting Jean Sonneman, Office of the Executive 
Director, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426 via email ([email protected]) or telephone 
(202) 502-8663.

XIII. Environmental Analysis

    1784. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\3743\ We 
conclude that neither an Environmental Assessment nor an Environmental 
Impact Statement is required for this final order under Sec.  
380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale of electric energy subject to 
the Commission's jurisdiction, plus the classification, practices, 
contracts and regulations that affect rates, charges, classifications, 
and services.\3744\
---------------------------------------------------------------------------

    \3743\ Regulations Implementing the Nat'l Env'l Pol'y Act, Order 
No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles 
1986-1990 ] 30,783 (1987) (cross-referenced at 41 FERC ] 61,284).
    \3744\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

XIV. Regulatory Flexibility Act

    1785. The Regulatory Flexibility Act of 1980 (RFA) \3745\ generally 
requires a description and analysis of rulemakings that will have 
significant economic impact on a substantial number of small entities. 
The Small Business Administration (SBA) sets the threshold for what 
constitutes a small business. Under SBA's size standards,\3746\ RTOs/
ISOs, transmission planning regions, and transmission owners all fall 
under the category of Electric Bulk Power Transmission and Control 
(NAICS code 221121), with a size threshold of 950 employees (including 
the entity and its associates).\3747\
---------------------------------------------------------------------------

    \3745\ 5 U.S.C. 601-612.
    \3746\ 13 CFR 121.201.
    \3747\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. The 
SBA's regulations define the threshold for a small Electric Bulk 
Power Transmission and Control entity (NAICS code 221121) to be 950 
employees. 13 CFR 121.201; see 5 U.S.C. 601(3) (citing section 3 of 
the Small Business Act, 15 U.S.C. 632).
---------------------------------------------------------------------------

    1786. We have determined that the entities impacted by this final 
order are transmission providers in transmission planning regions that 
span across the United States.\3748\
---------------------------------------------------------------------------

    \3748\ See FERC, Regions Map Printable Version Order No. 1000 
(Nov. 9, 2021), https://www.ferc.gov/media/regions-map-printable-version-order-no-1000.
---------------------------------------------------------------------------

    1787. To identify small firms among the transmission providers that 
comprise the transmission planning regions, we created a list of 
transmission service providers and transmission owners from the North 
American Electric Reliability Corporation Registry (dated January 11, 
2024), totaling 125 entities. We conducted research using both open-
source information and data from paid services such as Dunn & 
Bradstreet. We find that, out of the population of 125 transmission 
providers, 18 would be considered small using the SBA threshold (14% 
rounded). Therefore, we do not consider this number of small entities 
to be substantial.
    1788. As shown in the table above, we estimate the one-time costs 
associated with the final order to be $110,783 per transmission 
provider with an OATT and $1,862 per transmission provider without an 
OATT. We estimate the ongoing costs in subsequent years to be $446,390 
per year for transmission providers with an OATT and $24,205 per year 
for transmission providers without an OATT. Further, we note that 
Commission regulations allow for transmission providers to fully 
recover the costs of participating in the regional transmission 
planning process.\3749\ Therefore, we do not believe that this cost is 
economically significant. Accordingly, we certify that the reforms in 
this final order will not have a significant economic impact on a 
substantial number of small entities.
---------------------------------------------------------------------------

    \3749\ Order No. 890, 118 FERC ] 61,119 at P 586.
---------------------------------------------------------------------------

XV. Document Availability

    1789. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
internet through the Commission's Home Page (https://www.ferc.gov).
    1790. From the Commission's Home Page on the internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    1791. User assistance is available for eLibrary and the 
Commission's website during normal business hours from FERC Online 
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202)502-8659. Email the Public Reference Room at 
[email protected].

XVI. Effective Date and Congressional Notification

    1792. This final order is effective August 12, 2024. The Commission 
has determined, with the concurrence of the Administrator of the Office 
of Information and Regulatory Affairs of OMB, that this order is a 
``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By the Commission.

    Chairman Phillips and Commissioner Clements are concurring with a 
joint separate statement attached.
    Commissioner Christie is dissenting with a separate statement 
attached.

    Issued May 13, 2024.
Debbie-Anne A. Reese,
Acting Secretary.

    Note:  The following appendices will not appear in the Code of 
Federal Regulations.

Appendix A: Abbreviated Names of Commenters

                     Abbreviated Names of Commenters
------------------------------------------------------------------------
         Abbreviation                         Commenter(s)
------------------------------------------------------------------------
Acadia Center and CLF........  Acadia Center and Conservation Law
                                Foundation.

[[Page 49554]]

 
ACEG.........................  Americans for a Clean Energy Grid.
ACORE........................  American Council on Renewable Energy.
Advanced Energy Buyers.......  Advanced Energy Buyers Group.
AEE..........................  Advanced Energy Economy.
AEP..........................  American Electric Power Service
                                Corporation.
Alabama Commission...........  Alabama Public Service Commission.
Amazon.......................  Amazon Energy LLC.
Ameren.......................  Ameren Services Company.
American Municipal Power.....  American Municipal Power, Inc.
Americans for Fair Energy      Americans for Fair Energy Prices, Inc.
 Prices.
Anbaric......................  Anbaric Development Partners, LLC.
APPA.........................  American Public Power Association.
APS..........................  Arizona Public Service Company.
Arizona Commission...........  Arizona Corporation Commission.
ATC..........................  American Transmission Company LLC.
Avangrid.....................  Avangrid, Inc.
Bekaert......................  Bekaert Corporation.
BP...........................  bp America.
Breakthrough Energy..........  Breakthrough Energy.
Business Council for           Business Council for Sustainable Energy.
 Sustainable Energy.
CAISO........................  California Independent System Operator
                                Corporation.
California Commission........  California Public Utilities Commission.
California Democratic          U.S. Representatives Jared Huffman; Mike
 Representatives.               Levin; Nanette Diaz Barrag[aacute]n;
                                Grace F. Napolitano; Anna G. Eshoo;
                                Katie Porter; Judy Chu; Mike Thompson;
                                Ted W. Lieu; Julia Brownley; Mark
                                DeSaulnier; and Juan Vargas.
California Energy Commission.  California Energy Commission.
California Municipal           California Municipal Utilities
 Utilities.                     Association.
California Water.............  California Department of Water Resources
                                State Water Project.
CARE Coalition...............  The National Audubon Society; Defenders
                                of Wildlife; Environmental Law & Policy
                                Center; National Wildlife Federation;
                                The Nature Conservancy; Center for
                                Renewables Integration; and Vote Solar,
                                jointly the Conservation and Renewable
                                Energy Coalition.
Center for Biological          The Center for Biological Diversity.
 Diversity.
Ceres........................  Ceres.
Certain TDUs.................  Alliant Energy Corporate Services, Inc.;
                                Consumers Energy Company; and DTE
                                Electric Company.
Chemistry Council............  American Chemistry Council.
Citizens Energy..............  Citizens Energy Corporation.
City of New Orleans Council..  Council of the City of New Orleans.
City of New York.............  City of New York.
Clean Energy Associations....  The American Clean Power Association;
                                Alliance for Clean Energy--New York;
                                Clean Grid Alliance; the Mid-Atlantic
                                Renewable Energy Council Action; and the
                                New York Offshore Wind Alliance,
                                collectively Clean Energy Associations.
Clean Energy Buyers..........  Clean Energy Buyers Association.
Clean Energy States..........  Clean Energy States Alliance.
Colorado Consumer Advocate...  Colorado Office of the Utility Consumer
                                Advocate.
Competition Advocates........  Niskanen Center; R Street Institute;
                                Institute for Local Self Reliance;
                                Public Citizen, Inc.; Center for
                                Biological Diversity; and Open Markets
                                Institute.
Competition Coalition........  Electricity Transmission Competition
                                Coalition.
Concerned Scientists.........  The Union of Concerned Scientists.
Conservative Energy Network..  Conservative Energy Network.
Conservatives for Clean        Conservatives for Clean Energy--Florida.
 Energy--Florida.
Conservatives for Clean        Conservatives for Clean Energy--South
 Energy--SC.                    Carolina.
Consumer Organizations.......  NJ Charge, Inc.; Keryn Newman (Stop Path
                                WV); Illinois Landowners Alliance; Block
                                Grain Belt Express--Missouri; Citizens
                                to Stop Transource--York; Coalition for
                                Rural Property Rights; Eastern Missouri
                                Landowners Alliance; Missouri Landowners
                                Association; Protect Sudbury Inc.; Say
                                No to NECEC; Stop B2H Coalition; Eastern
                                Missouri Landowners Alliance; SOUL of
                                Wisconsin; Block RICL; Matthew
                                Stallbaumer; Vickie Husbands; Elena
                                Guardincerri; Martha Peine; Kerry
                                Beheler; Barron Shaw; and STOP
                                Transource Power Lines MD, Inc.
Cross Sector Representatives.  Ameren Transmission; Blue-Green Alliance;
                                Consolidated Edison Company of New York,
                                Inc.; Edison International; Exelon
                                Corporation; Greater Warren County
                                Economic Development Council;
                                International Brotherhood of Electric
                                Workers IBEW 1245; IBEW Illinois State
                                Conference; IBEW International; IBEW
                                Sixth District; ITC Holdings Corp.;
                                National Audubon Society; Pacific Gas &
                                Electric Co.; The Permitting Institute;
                                Public Service Electric and Gas Company;
                                WEG Transformers USA; and Xcel Energy.
CTC Global...................  CTC Global Corporation.
Cypress Creek................  Cypress Creek Renewables, LLC.
DATA.........................  Ameren Services Company; Eversource
                                Energy; Exelon Corporation; ITC Holdings
                                Corp.; National Grid USA; Public Service
                                Electric and Gas Company; and Xcel
                                Energy; collectively Developers
                                Advocating Transmission Advancements
                                (DATA).
DC and MD Offices of People's  The Office of the People's Counsel for
 Counsel.                       the District of Columbia and the
                                Maryland Office of People's Counsel.

[[Page 49555]]

 
Dominion.....................  Dominion Energy Services, Inc.
Duke.........................  Duke Energy Corporation.
Duquesne Light...............  Duquesne Light Company.
EEI..........................  Edison Electric Institute.
ELCON........................  Electricity Consumers Resource Council.
Enel.........................  Enel North America, Inc.
ENGIE........................  ENGIE North America, Inc.
Entergy......................  Entergy Services, LLC.
Environmental Groups.........  Advanced Energy United; American Clean
                                Power Association; Clean Air Task Force;
                                EarthJustice; Environmental Defense
                                Fund; Evergreen Action; Fresh Energy;
                                Interwest Energy Alliance; League of
                                Conservation Voters; National Wildlife
                                Federation; Natural Resources Defense
                                Council; Northwest Energy Coalition;
                                Rewiring America; Sierra Club; Southern
                                Environmental Law Center; The
                                Environmental Law & Policy Center; Union
                                of Concerned Scientists; WE ACT for
                                Environmental Justice; and Western
                                Resource Advocates.
Environmental Legislators      National Caucus of Environmental
 Caucus.                        Legislators.
EPSA.........................  Electric Power Supply Association.
Evergreen Action.............  Evergreen Action and 4,440 Individual
                                Signers.
Eversource...................  Eversource Energy Service Company.
Exelon.......................  Exelon Corporation.
Fervo........................  Fervo Energy Company.
Form Energy..................  Form Energy, Inc.
Freeport-McMoRan.............  Freeport-McMoRan, Inc.
Georgia Commission...........  Georgia Public Service Commission.
Governor of Kansas Laura       Governor of the State of Kansas Laura
 Kelly.                         Kelly.
Grand Rapids NAACP...........  Greater Grand Rapids Chapter of The
                                National Association for the Advancement
                                of Colored People.
Grid United..................  Grid United LLC.
GridLab......................  GridLab.
Handy Law....................  Seth Handy, Handy Law, LLC.
Hannon Armstrong.............  Hannon Armstrong Sustainable
                                Infrastructure Capital, Inc.
Harvard ELI..................  Harvard Electricity Law Initiative.
Idaho Commission.............  The Idaho Public Utilities Commission.
Idaho Power..................  Idaho Power Company.
Illinois Commission..........  The Illinois Commerce Commission.
Indiana Commission...........  Indiana Utility Regulatory Commission.
Indicated PJM TOs............  The Dayton Power and Light Company;
                                Dominion Energy Services, Inc. on behalf
                                of Virginia Electric and Power Company;
                                Duke Energy Corporation on behalf of its
                                affiliates Duke Energy Ohio, Inc., Duke
                                Energy Kentucky, Inc., and Duke Energy
                                Business Services LLC; Duquesne Light
                                Company; East Kentucky Power
                                Cooperative; Exelon Corporation;
                                FirstEnergy Service Company, on behalf
                                of its affiliates American Transmission
                                Systems, Incorporated, Jersey Central
                                Power & Light Company, Mid-Atlantic
                                Interstate Transmission LLC, West Penn
                                Power Company, The Potomac Edison
                                Company, Monongahela Power Company,
                                Keystone Appalachian Transmission
                                Company, and Trans-Allegheny Interstate
                                Line Company; PPL Electric Utilities
                                Corporation; Public Service Electric and
                                Gas Company; Rockland Electric Company;
                                and UGI Utilities Inc.
Indicated U.S. Senators and    U.S. Senators Tina Smith; Edward J.
 Representatives.               Markey; and Sheldon Whitehouse; U.S.
                                Representatives Kathy Castor; Bobby L.
                                Rush; Paul Tonko; Sean Casten; Raja
                                Krishnamoorthi; Jared Huffman; Veronica
                                Escobar; and Julia Brownley
Industrial Customers.........  American Forest & Paper Association; the
                                PJM Industrial Customer Coalition; and
                                the Coalition of MISO Transmission
                                Customers, collectively the Industrial
                                Customer Organizations.
Interwest....................  Interwest Energy Alliance.
Invenergy....................  Invenergy Solar Development North America
                                LLC; Invenergy Thermal Development LLC;
                                Invenergy Wind Development North America
                                LLC; and Invenergy Transmission LLC.
Iowa Commission..............  Iowa Utilities Board.
ISO/RTO Council..............  The ISO/RTO Council.
ISO-NE.......................  ISO New England Inc.
ITC..........................  International Transmission Company;
                                Michigan Electric Transmission Company,
                                LLC; ITC Midwest LLC; and ITC Great
                                Plains, LLC.
Joint Commenters.............  American Public Power Association;
                                Electricity Consumers Resource Council;
                                Indiana Office of Utility Consumer
                                Counselor; Large Public Power Council;
                                National Association of State Utility
                                Consumer Advocates; Office of People's
                                Counsel for the District of Columbia;
                                Public Advocate for the State of
                                Delaware; and Solar Energy Industries
                                Association.
Joint Consumer Advocates.....  Iowa Office of Consumer Advocate and
                                Indiana Office of Utility Consumer
                                Counselor.
Kansas Commission............  Kansas Corporation Commission.
Kansas Commission Chair Keen.  Kansas Corporation Commission Chairman
                                Dwight D. Keen.
Kansas Ratepayers Advocates..  Kansas Industrial Consumers Group, Inc.
                                and Kansans for Lower Electric Rates,
                                Inc.
Kentucky Commission Chair      Kentucky Public Service Commission
 Chandler.                      Chairman and Commissioner Kent A.
                                Chandler.
LADWP........................  Los Angeles Department of Water & Power.

[[Page 49556]]

 
Large Energy Customers.......  Akamai Technologies, Inc.; Amazon.com,
                                Inc.; Amy's Kitchen, Inc.; Apple, Inc.;
                                Applied Materials, Inc.; ARC Homes;
                                Atlassian Corporation; Autodesk, Inc.;
                                BASF Corporation; Best Buy Co., Inc.;
                                Brookfield Properties; Budderfly, Inc.;
                                Build Efficiently, LLC.; Cargill, Inc.;
                                Clean Energy Buyers Association; Eastman
                                Chemical Company; eBay, Inc.; Equinix,
                                Inc.; Freeport-McMoRan, Inc.; General
                                Motors LLC; Google LLC; Green Impact
                                Technologies; Hewlett Packard Enterprise
                                Company; Humanscale Corporation; IHG
                                Hotels & Resorts; Marriott
                                International, Inc.; Mars, Inc.; Meta
                                Platforms, Inc.; Microsoft Corporation;
                                Monarch Energy; Nike, Inc.; Nucor
                                Corporation; Oatly Group AB; PepsiCo,
                                Inc.; Prologis, Inc.; Rivian Automotive,
                                Inc.; Saint-Gobain North America;
                                Salesforce, Inc.; Schneider Electric SE;
                                Target Corporation; Thermo Fisher
                                Scientific, Inc.; The STAAC Group, LLC.,
                                Walmart, Inc.; Workday, Inc.; and World
                                Energy, LLC.
Large Public Power...........  The Large Public Power Council.
Louisiana Commission.........  Louisiana Public Service Commission.
LS Power.....................  LS Power Grid, LLC.
Maine Public Advocate........  The Maine Office of the Public Advocate.
Maryland Energy                Maryland Energy Administration.
 Administration.
Massachusetts Attorney         Massachusetts Attorney General Maura
 General.                       Healey.
Michigan Commission..........  Michigan Public Service Commission.
Michigan Conservative Energy   Michigan Conservative Energy Forum.
 Forum.
Michigan State Entities......  Michigan Attorney General and the
                                Citizens Utility Board of Michigan.
Microgrid Resources..........  Microgrid Resources Coalition.
Middle River Power...........  Middle River Power LLC.
Minnesota State Entities.....  The Minnesota Public Utilities Commission
                                and The Minnesota Department of
                                Commerce.
MISO.........................  Midcontinent Independent System Operator,
                                Inc.
MISO Coops...................  The Coalition of MISO Generation and
                                Transmission Cooperatives.
MISO TOs.....................  Ameren Services Company, as agent for
                                Union Electric Company, Ameren Illinois
                                Company, and Ameren Transmission Company
                                of Illinois; American Transmission
                                Company LLC; Big Rivers Electric
                                Corporation; Central Minnesota Municipal
                                Power Agency; City Water, Light & Power
                                (Springfield, IL); Cleco Power LLC;
                                Cooperative Energy; Dairyland Power
                                Cooperative; Duke Energy Business
                                Services, LLC for Duke Energy Indiana,
                                LLC; East Texas Electric Cooperative;
                                Great River Energy; Hoosier Energy Rural
                                Electric Cooperative, Inc.; Indiana
                                Municipal Power Agency; Indianapolis
                                Power & Light Company; International
                                Transmission Company; ITC Midwest LLC;
                                Lafayette Utilities System; Michigan
                                Electric Transmission Company, LLC;
                                MidAmerican Energy Company; Minnesota
                                Power (and its subsidiary Superior
                                Water, L&P); Montana-Dakota Utilities
                                Co.; Northern Indiana Public Service
                                Company LLC; Northern States Power
                                Company, a Minnesota corporation, and
                                Northern States Power Company, a
                                Wisconsin corporation, subsidiaries of
                                Xcel Energy Inc.; Northwestern Wisconsin
                                Electric Company; Otter Tail Power
                                Company; Prairie Power, Inc.; Southern
                                Illinois Power Cooperative; Southern
                                Indiana Gas & Electric Company; Southern
                                Minnesota Municipal Power Agency; Wabash
                                Valley Power Association, Inc.; and
                                Wolverine Power Supply Cooperative, Inc.
Mississippi Commission.......  The Mississippi Public Service
                                Commission.
Montana QF Developers........  Cl[emacr]nera, LLC and Greenfields
                                Irrigation District.
Montclair Congregation.......  40 Undersigned Congregants of Montclair
                                Presbyterian Church.
NARUC........................  The National Association of Regulatory
                                Utility Commissioners.
NASEO........................  The National Association of State Energy
                                Officials.
NASUCA.......................  The National Association of State Utility
                                Consumer Advocates.
National and State             National Wildlife Federation;
 Conservation Organizations.    Conservation Coalition of Oklahoma;
                                Environment Council of Rhode Island;
                                Environmental League of Massachusetts;
                                Idaho Wildlife Federation; Iowa Wildlife
                                Federation; Kentucky Waterways Alliance;
                                Natural Resources Council of Maine;
                                Nevada Wildlife Federation; New Jersey
                                Audubon; Southeast Alaska Conservation
                                Council; Texas Conservation Alliance;
                                Utah Wildlife Federation; WV Rivers
                                Coalition; and Wyoming Wildlife
                                Federation.
National Grid................  National Grid Plc.
Nebraska Commission..........  The Nebraska Power Review Board.
NEMA.........................  National Electrical Manufacturers
                                Association.
NEPOOL.......................  The New England Power Pool Participants
                                Committee.
NERC.........................  North American Electric Reliability
                                Corporation; Midwest Reliability
                                Organization; Northeast Power
                                Coordinating Council, Inc.;
                                ReliabilityFirst Corporation; SERC
                                Reliability Corporation, Texas
                                Reliability Entity, Inc., and Western
                                Electricity Coordinating Council.
NESCOE.......................  The New England States Committee on
                                Electricity.
Nevada Commission............  The Public Utilities Commission of
                                Nevada.
New England for Offshore Wind  New England for Offshore Wind.
New England Systems..........  Belmont Municipal Light Department; Block
                                Island Utility District; Braintree
                                Electric Light Department; Chicopee
                                Municipal Light Department; Georgetown
                                Municipal Light Department; Hingham
                                Municipal Lighting Plant; Littleton
                                Electric Light & Water Department;
                                Middleborough Gas & Electric Department;
                                Middleton Electric Light Department;
                                North Attleborough Electric Department;
                                Norwood Municipal Light Department;
                                Pascoag Utility District; Reading
                                Municipal Light Department; Stowe
                                Electric Department; Taunton Municipal
                                Lighting Plant; Wallingford Electric
                                Division; and Westfield Gas & Electric
                                Light Department.
New Jersey Commission........  The New Jersey Board of Public Utilities.
New Mexico RETA..............  The New Mexico Renewable Energy
                                Transmission Authority.

[[Page 49557]]

 
New York Commission and        New York Public Service Commission and
 NYSERDA.                       New York State Energy Research and
                                Development Authority.
New York State Department....  New York State Department of State
                                Utility Intervention Unit.
New York TOs.................  Central Hudson Gas & Electric
                                Corporation; Consolidated Edison Company
                                of New York, Inc.; Niagara Mohawk Power
                                Corporation; New York Power Authority;
                                New York State Electric & Gas
                                Corporation; Orange and Rockland
                                Utilities, Inc.; Long Island Power
                                Authority; and Rochester Gas and
                                Electric Corporation.
New York Transco.............  New York Transco, LLC.
NextEra......................  NextEra Energy, Inc.
Non-RTO NASUCA...............  North Carolina Utilities Commission
                                Public Staff; the Utah Office of
                                Consumer Service; the South Carolina
                                Office of Regulatory Staff; and the
                                Wyoming Office of Consumer Advocate.
North Carolina Commission and  The North Carolina Utilities Commission
 Staff.                         and the North Carolina Utilities
                                Commission Public Staff.
North Dakota Commission......  North Dakota Public Service Commission
                                Public Utilities Division.
Northwest and Intermountain..  Northwest & Intermountain Power Producers
                                Coalition.
NRECA........................  National Rural Electric Cooperative
                                Association.
NRG..........................  NRG Energy, Inc.
NYISO........................  New York Independent System Operator,
                                Inc.
NYPA.........................  New York Power Authority.
Ohio Commission Federal        The Public Utilities Commission of Ohio's
 Advocate.                      Office of the Federal Energy Advocate.
Ohio Conservative Energy       Ohio Conservative Energy Forum.
 Forum.
Ohio Consumers...............  Office of The Ohio Consumers' Counsel.
Omaha Public Power...........  The Omaha Public Power District.
OMS..........................  The Organization of Midcontinent
                                Independent System Operator States, Inc.
Onward Energy................  Onward Energy Holdings, LLC.
[Oslash]rsted................  [Oslash]rsted North America.
Pacific Northwest State        The Washington Utilities and
 Agencies.                      Transportation Commission; Oregon Public
                                Utility Commission; Washington State
                                Department Of Commerce; and Oregon
                                Department Of Energy.
Pacific Northwest Utilities..  Avista Corporation; Portland General
                                Electric; Puget Sound Energy, Inc.; and
                                Tacoma Power.
PacifiCorp and NV Energy.....  PacifiCorp; Nevada Power Company and
                                Sierra Pacific Power Company (together,
                                NV Energy).
Pattern Energy...............  Pattern Energy Group LP.
Payton Alaama................  Payton Alaama.
Pennsylvania Commission......  The Pennsylvania Public Utility
                                Commission.
PG&E.........................  Pacific Gas and Electric Company.
Pine Gate....................  Pine Gate Renewables, LLC.
PIOs.........................  Sustainable FERC Project; Natural
                                Resources Defense Council; Sierra Club;
                                Environmental Defense Fund; Southern
                                Environmental Law Center; Conservation
                                Law Foundation; Western Resource
                                Advocates; Acadia Center; NW Energy
                                Coalition; Southface Institute; and
                                Fresh Energy, jointly Public Interest
                                Organizations.
PJM..........................  PJM Interconnection, L.L.C.
PJM Market Monitor...........  The Independent Market Monitor of PJM
                                Interconnection, L.L.C.
PJM States...................  The Organization of PJM States, Inc.
                                (OPSI).
Policy Integrity.............  The Institute for Policy Integrity at New
                                York University School of Law.
Potomac Economics............  Potomac Economics, Ltd.
PPL..........................  PPL Electric Utilities Corporation;
                                Louisville Gas & Electric and Kentucky
                                Utilities (collectively LG&E/KU); and
                                The Narragansett Electric Company.
Prysmian.....................  The Prysmian Group.
Public Systems...............  Massachusetts Municipal Wholesale
                                Electric Company; New Hampshire Electric
                                Cooperative, Inc.; Connecticut Municipal
                                Electric Energy Cooperative; and Vermont
                                Public Power Supply Authority.
QCo..........................  QCoefficient, Inc.
R Street.....................  R Street Institute.
Rail Electrification.........  The Rail Electrification Council.
Renewable Northwest..........  Renewable Northwest.
Resale Iowa..................  Resale Power Group of Iowa.
RMI..........................  RMI.
SDG&E........................  San Diego Gas & Electric Company.
SEIA.........................  The Solar Energy Industries Association.
SEPA.........................  The Smart Electric Power Alliance.
SERTP Sponsors...............  Associated Electric Cooperative, Inc.;
                                Dalton Utilities; Duke Energy Carolinas,
                                LLC and Duke Energy Progress, LLC;
                                Georgia Transmission Corporation;
                                Louisville Gas and Electric Company and
                                Kentucky Utilities Company; the
                                Municipal Electric Authority of Georgia;
                                PowerSouth Energy Cooperative; Southern
                                Company Services, Inc., acting as agent
                                for Alabama Power Company, Georgia Power
                                Company, and Mississippi Power Company;
                                the Tennessee Valley Authority; and Gulf
                                Power Company, collectively Sponsors of
                                the Southeastern Regional Transmission
                                Planning Process (SERTP).
Shell........................  Shell Energy North America (U.S.), L.P.;
                                Shell New Energies U.S., LLC; and Savion
                                L.L.C.

[[Page 49558]]

 
Signatories..................  American Council on Renewable Energy;
                                Americans for a Clean Energy Grid;
                                American Clean Power Association; AES
                                Corporation; Advance Energy Economy;
                                Center for Rural Affairs; Clean Air Task
                                Force; Clean Energy Buyers Alliance;
                                Conservative Energy Network; ConEd
                                Transmission, Inc.; Enel North America,
                                Inc.; Exelon Corporation; GE Renewables;
                                Grid United LLC; Google; Holy Cross
                                Energy; Invenergy; ITC Holdings Corp.;
                                Land & Liberty Coalition; Macro Grid
                                Initiative; National Audubon Society;
                                National Electrical Manufacturer
                                Association; National Wildlife
                                Federation; Natural Resources Defense
                                Council; NextEra Energy, Inc.; Northwest
                                & Intermountain Power Producers
                                Coalition; Pattern Energy; Rail
                                Electrification Council; Rocky Mountain
                                Institute (RMI); Sierra Club; Solar
                                Energy Industries of America; and
                                Southern Renewable Energy Association.
Six Cities...................  The Cities of Anaheim, Azusa, Banning,
                                Colton, Pasadena, and Riverside,
                                California.
Smart Wires..................  Smart Wires.
SoCal Edison.................  Southern California Edison Company.
Southeast PIOs...............  Southern Environmental Law Center; Energy
                                Alabama; North Carolina Sustainable
                                Energy Association; South Carolina
                                Coastal Conservation League; Southface
                                Energy Institute; and Southern Alliance
                                for Clean Energy, jointly Southeast
                                Public Interest Groups.
Southern.....................  Southern Company Services, Inc.
Southwestern Power Group.....  Southwestern Power Group.
SPP..........................  Southwest Power Pool Inc.
SPP Market Monitor...........  The Southwest Power Pool Market
                                Monitoring Unit.
SREA.........................  Southern Renewable Energy Association.
State Agencies...............  Connecticut Department of Energy and
                                Environmental Protection; Connecticut
                                Attorney General; Connecticut Office of
                                Consumer Counsel; Connecticut Public
                                Utilities Regulatory Authority;
                                California Energy Commission; Delaware
                                Division of the Public Advocate;
                                Attorney General of the District of
                                Columbia; Maine Office of the Public
                                Advocate; Maryland Attorney General;
                                Massachusetts Attorney General; Michigan
                                Attorney General; Pennsylvania Office of
                                The Consumer Advocate; and the Rhode
                                Island Attorney General.
State of Tennessee...........  State of Tennessee.
State Officials..............  Maine Governor's Energy Office;
                                Washington State Department of Commerce;
                                Arizona Governor's Office of Resiliency;
                                California Natural Resources Agency;
                                Colorado Energy Office; Deputy Governor
                                of Illinois; Maryland Energy
                                Administration; Michigan Department of
                                Environment, Great Lakes, and Energy;
                                New Mexico Energy Minerals and Natural
                                Resources Department; Office of New York
                                Governor Kathy Hochul; and Office of
                                North Carolina Governor Roy Cooper.
State Water Contractors......  State Water Contractors.
Tabors Caramanis Rudkevich...  Tabors Caramanis & Rudkevich.
TANC.........................  Transmission Agency of Northern
                                California.
TAPS.........................  Transmission Access Policy Study Group.
Transmission Dependent         Golden Spread Electric Cooperative, Inc.;
 Utilities.                     North Carolina Electric Membership
                                Corporation; and Seminole Electric
                                Cooperative, Inc., collectively,
                                Transmission Dependent Utility Systems.
Transource...................  Transource Energy, LLC.
Undersigned States [Initial    Utah Attorney General; Alaska Attorney
 Comments].                     General; Georgia Attorney General; Idaho
                                Attorney General; Indiana Attorney
                                General; Kansas Attorney General;
                                Kentucky Attorney General; Louisiana
                                Attorney General; Mississippi Attorney
                                General; Montana Attorney General;
                                Nebraska Attorney General; North Dakota
                                Attorney General; Ohio Attorney General;
                                Oklahoma Attorney General; South
                                Carolina Attorney General; Texas
                                Attorney General; West Virginia Attorney
                                General; and Wyoming Attorney General.
Undersigned States [Reply      Utah Attorney General; Alabama Attorney
 Comments].                     General; Alaska Attorney General;
                                Arkansas Attorney General; Florida
                                Attorney General; Georgia Attorney
                                General; Kansas Attorney General;
                                Kentucky Attorney General; Louisiana
                                Attorney General; Mississippi Attorney
                                General; Montana Attorney General;
                                Nebraska Attorney General; Ohio Attorney
                                General; Oklahoma Attorney General;
                                South Carolina Attorney General; Texas
                                Attorney General; and West Virginia
                                Attorney General.
U.S. Chamber of Commerce.....  U.S. Chamber of Commerce.
U.S. Climate Alliance........  United States Climate Alliance.
U.S. Democratic                U.S. Representatives Paul D. Tonko and
 Representatives.               112 additional U.S. Representatives.
U.S. DOE.....................  United States Department of Energy.
U.S. DOJ and FTC.............  United States Department of Justice and
                                the Federal Trade Commission.
U.S. House Republicans.......  U.S. Representatives Andrew R. Garbarino;
                                Anthony D'Espositio; Nicholas A.
                                Langworthy; and Brandon Williams.
U.S. Senator Barrasso........  U.S. Senator John Barrasso.
U.S. Senator Heinrich........  U.S. Senator Martin Heinrich.
U.S. Senators................  U.S. Senators Martin Heinrich; Edward J.
                                Markey; Peter Welch; John Hickenlooper;
                                Angus S. King, Jr.; Ron Wyden; Robert P.
                                Casey, Jr.; Sheldon Whitehouse; Tina
                                Smith; Ben Ray Luj[aacute]n; Chris Van
                                Hollen; Mazie K. Hirono; Jeffrey A.
                                Merkley; Brian Schatz; Thomas R. Carper;
                                Bernard Sanders; Patty Murray; John
                                Fetterman; Michael F. Bennet; Elizabeth
                                Warren; and Alex Padilla.
U.S. Senators Heinrich and     U.S. Senators Martin Heinrich and Mike
 Lee.                           Lee.
U.S. Senators Hickenlooper     U.S. Senators John Hickenlooper and Angus
 and King.                      S. King, Jr.
U.S. Senator Schumer.........  U.S. Senator Charles E. Schumer.
U.S. Senator Whitehouse......  U.S. Senator Sheldon Whitehouse.

[[Page 49559]]

 
Utah Commission..............  The Utah Public Service Commission.
Utah Division of Public        Utah Department of Commerce, Division of
 Utilities.                     Public Utilities.
VEIR.........................  VEIR Inc.
Vermont Electric and Vermont   Vermont Electric Power Company, Inc., and
 Transco.                       Vermont Transco LLC.
Vermont State Entities.......  The Vermont Public Utility Commission and
                                the Vermont Department of Public
                                Service.
Virginia Attorney General....  Virginia Office of the Attorney General,
                                Division of Consumer Counsel.
Virginia Commission Staff....  The Staff of the Virginia State
                                Corporation Commission.
Vistra.......................  Vistra Corp.
WATT Coalition...............  The Working for Advanced Transmission
                                Technologies (WATT) Coalition.
WE ACT.......................  WE ACT for Environmental Justice.
West Virginia Commission.....  The Public Service Commission of West
                                Virginia.
Western PIOs.................  Center for Energy Efficiency and
                                Renewable Technologies; NW Energy
                                Coalition; Western Resource Advocates;
                                and Renewable Northwest; collectively,
                                Western Public Interest Organizations.
Western State Representatives  Agency Representatives from the states of
                                Arizona; California; Idaho; Montana;
                                Nevada; Oregon; South Dakota; Utah;
                                Washington; and Wyoming.
Western Way Colorado.........  Western Way Colorado.
Western Way Nevada...........  Western Way Nevada.
Western Way Utah.............  Western Way Utah.
Wildlife Federation Action     8,610 Supporters of the National Wildlife
 Fund Supporters.               Federation Action Fund.
WIRES........................  WIRES.
Wisconsin Conservative Energy  Wisconsin Conservative Energy Forum.
 Forum.
Wisconsin Legislators........  Wisconsin State Senator Julian Bradley
                                and Wisconsin State Representative David
                                Steffen.
Wisconsin Senator Cowles.....  Wisconsin State Senator Robert L. Cowles.
Xcel.........................  Xcel Energy Services Inc.
------------------------------------------------------------------------

Appendix B: Pro Forma Open Access Transmission Tariff Attachment K

    Note:  Proposed deletions are in brackets and proposed additions 
are in italics.

Attachment K

Transmission Planning Process

Local Transmission Planning

    The Transmission Provider shall establish a coordinated, open, 
and transparent local transmission planning process with its Network 
and Firm Point-to-Point Transmission Customers and other interested 
parties to ensure that the Transmission System is planned to meet 
the needs of both the Transmission Provider and its Network and Firm 
Point-to-Point Transmission Customers on a comparable and not unduly 
discriminatory basis. The Transmission Provider's coordinated, open, 
and transparent local transmission planning process shall be 
provided as an attachment to the Transmission Provider's Tariff. The 
Transmission Provider's local transmission planning process shall 
provide stakeholders with meaningful opportunities to participate 
and provide feedback, and shall satisfy the following nine 
principles, as defined in Order No. 890: coordination, openness, 
transparency, information exchange, comparability, dispute 
resolution, regional participation, economic planning studies, and 
cost allocation for new transmission projects. The local 
transmission planning process also shall include the procedures and 
mechanisms for considering transmission needs driven by Public 
Policy Requirements consistent with Order No. 1000. The local 
transmission planning process also shall provide a mechanism for the 
recovery and allocation of transmission planning costs consistent 
with Order No. 890. The description of the Transmission Provider's 
local transmission planning process must include sufficient detail 
to enable Transmission Customers to understand:
    (i) The process for consulting with customers;
    (ii) The notice procedures and anticipated frequency of 
meetings;
    (iii) The methodology, criteria, and processes used to develop a 
transmission plan;
    (iv) The method of disclosure of criteria, assumptions, and data 
underlying a transmission plan;
    (v) The obligations of and methods for Transmission Customers to 
submit data to the Transmission Provider;
    (vi) The dispute resolution process;
    (vii) The Transmission Provider's study procedures for economic 
upgrades to address congestion or the integration of new resources;
    (viii) The Transmission Provider's procedures and mechanisms for 
considering transmission needs driven by Public Policy Requirements, 
consistent with Order No. 1000; and
    (ix) The relevant cost allocation method or methods.

Regional Transmission Planning

    The Transmission Provider shall participate in a regional 
transmission planning process through which transmission facilities 
and non-transmission alternatives may be proposed and evaluated. The 
regional transmission planning process also shall develop a regional 
transmission plan that identifies the transmission facilities 
necessary to meet the needs of transmission providers and 
transmission customers in the transmission planning region. The 
regional transmission planning process must be consistent with the 
provision of Commission-jurisdictional services at rates, terms, and 
conditions that are just and reasonable and not unduly 
discriminatory or preferential, as described in Order Nos. 1000 and 
1920. The regional transmission planning process shall be described 
in an attachment to the Transmission Provider's Tariff.
    The Transmission Provider's regional transmission planning 
process shall satisfy the following seven principles, as [set out 
and explained]established in Order Nos. 890 and 1000: coordination, 
openness, transparency, information exchange, comparability, dispute 
resolution, and economic planning studies. The description of the 
regional transmission planning process in the Tariff also shall 
include the procedures and mechanisms for considering transmission 
needs driven by Public Policy Requirements, consistent with Order 
No. 1000. The regional transmission planning process shall provide a 
mechanism for the recovery and allocation of ``transmission planning 
costs'' consistent with Order Nos. 890 and 1000.
    The regional transmission planning process shall include a clear 
enrollment process for public and non-public utility transmission 
providers that make the choice to become part of a transmission 
planning region. The regional transmission planning process shall be 
clear that enrollment will subject enrollees to cost allocation if 
they are found to be beneficiaries of new transmission facilities 
selected in the regional transmission plan for purposes of cost 
allocation. Each Transmission Provider shall maintain a list of 
enrolled entities in the Transmission Provider's Tariff.
    The regional transmission planning process must include at least 
three stakeholder meetings concerning the local transmission 
planning process of each Transmission Provider that is a member of 
the transmission planning region. The three

[[Page 49560]]

meetings must occur before each Transmission Provider's local 
transmission planning information can be incorporated into the 
transmission planning region's transmission planning models. The 
three stakeholder meetings for local transmission planning 
information are the Assumptions Meeting, the Needs Meeting, and the 
Solutions Meeting, and the three stakeholder meetings must meet the 
requirements in Order No. 1920.
    As part of the regional transmission planning process, the 
Transmission Providers in each transmission planning region shall 
conduct Long-Term Regional Transmission Planning, meaning regional 
transmission planning on a sufficiently long-term, forward-looking, 
and comprehensive basis to identify Long-Term Transmission Needs, 
identify transmission facilities that meet such needs, measure the 
benefits of those transmission facilities, and evaluate those 
transmission facilities for potential selection in the regional 
transmission plan for purposes of cost allocation as the more 
efficient or cost-effective regional transmission facilities to meet 
Long-Term Transmission Needs. As part of this Long-Term Regional 
Transmission Planning, the Transmission Providers in each 
transmission planning region shall meet the requirements set forth 
in Order No. 1920, including: (1) identifying Long-Term Transmission 
Needs and Long-Term Regional Transmission Facilities to meet those 
needs through the development of Long-Term Scenarios that satisfy 
the requirements set forth in Order No. 1920; (2) measuring the 
required seven benefits consistent with the requirements set forth 
in Order No. 1920; (3) using the measured benefits to evaluate Long-
Term Regional Transmission Facilities; and (4) using selection 
criteria consistent with the requirements set forth in Order No. 
1920 that provide the opportunity for Transmission Providers to 
select Long-Term Regional Transmission Facilities in the regional 
transmission plan for purposes of cost allocation that more 
efficiently or cost-effectively address Long-Term Transmission 
Needs.
    The process through which the Transmission Providers in each 
transmission planning region develop Long-Term Scenarios must comply 
with the following six transmission planning principles established 
in Order No. 890: coordination; openness; transparency; information 
exchange; comparability; and dispute resolution. The Transmission 
Providers in each transmission planning region shall outline in 
their Tariffs an open and transparent process that provides 
stakeholders, including states, with a meaningful opportunity to 
propose potential factors and to provide input on how to account for 
specific factors in the development of Long-Term Scenarios. The 
Transmission Providers in each transmission planning region shall 
also outline in their Tariffs an open and transparent process that 
provides stakeholders, including states, with a meaningful 
opportunity to propose which future outcomes are probable and can be 
captured through assumptions made in the development of Long-Term 
Scenarios.
    The Transmission Providers in each transmission planning region 
shall include in their Tariffs a general description of how they 
will measure each of the seven required benefits used to evaluate 
Long-Term Regional Transmission Facilities. The Transmission 
Providers in each transmission planning region shall measure and use 
the seven benefits, as described in Order No. 1920, in Long-Term 
Regional Transmission Planning.
    As part of Long-Term Regional Transmission Planning, the 
Transmission Providers in each transmission planning region shall 
include in their Tariffs an evaluation process, including selection 
criteria, that: (1) is transparent and not unduly discriminatory; 
(2) aims to ensure that more efficient or cost-effective 
transmission facilities are selected in the regional transmission 
plan for purposes of cost allocation; (3) seeks to maximize benefits 
accounting for costs over time without over-building transmission 
facilities; and (4) otherwise satisfies the requirements set forth 
in Order No. 1920.
    The Transmission Providers in each transmission planning region 
shall include in their Tariffs one or more Long-Term Regional 
Transmission Cost Allocation Methods, which is an ex ante regional 
cost allocation method for one or more Long-Term Regional 
Transmission Facilities (or portfolio of such Facilities) that are 
selected in the regional transmission plan for purposes of cost 
allocation and that complies with the requirements set forth in 
Order No. 1920. The Transmission Providers in each transmission 
planning region may also, subject to (1) the agreement of Relevant 
State Entities and (2) Commission acceptance, include in their 
Tariffs a State Agreement Process. A State Agreement Process is a 
process by which one or more Relevant State Entities may voluntarily 
agree to a cost allocation method for Long-Term Regional 
Transmission Facilities (or a portfolio of such Facilities) either 
before or no later than six months after the facilities are selected 
in the regional transmission plan for purposes of cost allocation. 
The Tariff must describe how the State Agreement Process will result 
in a cost allocation being filed, including which entities can 
participate in the State Agreement Process; what constitutes an 
agreement on cost allocation in that process; how agreement is 
communicated to the transmission provider; and the circumstances 
under which, or the information necessary for, a transmission 
provider to file or to consider filing the agreed cost allocation.
    As part of evaluating new regional transmission facilities, as 
well as upgrades to existing transmission facilities, the 
Transmission Providers in each transmission planning region shall 
consider in all of their regional transmission planning and cost 
allocation processes whether selecting transmission facilities that 
incorporate the following technologies would be more efficient or 
cost-effective than selecting new regional transmission facilities 
or upgrades to existing transmission facilities that do not 
incorporate these technologies: dynamic line ratings, as defined in 
18 CFR 35.28(b)(14), advanced power flow control devices, advanced 
conductors, and/or transmission switching. Specifically, such 
consideration must include both: (1) whether incorporating dynamic 
line ratings, advanced power flow control devices, advanced 
conductors, and/or transmission switching into existing transmission 
facilities could meet the same regional transmission need more 
efficiently or cost-effectively than other potential transmission 
facilities; and (2) when evaluating transmission facilities for 
potential selection in the regional transmission plan for purposes 
of cost allocation, whether incorporating dynamic line ratings, 
advanced power flow control devices, advanced conductors, and/or 
transmission switching as part of any potential regional 
transmission facility would be more efficient or cost-effective. 
Transmission providers must evaluate the benefits of incorporating 
the enumerated alternative transmission technologies into Long-Term 
Regional Transmission Facilities in a manner consistent with the 
requirements in the Evaluation of Benefits of Regional Transmission 
Facilities and Evaluation and Selection of Long-Term Regional 
Transmission Facilities sections of Order No. 1920.
    The Transmission Providers in each transmission planning region 
shall evaluate for potential selection in the regional transmission 
plan for purposes of cost allocation regional transmission 
facilities that address interconnection-related transmission needs 
originally identified through the generator interconnection process. 
This requirement applies in the existing Order No. 1000 regional 
transmission planning processes. The Transmission Providers must 
modify their Tariffs to include these requirements. The 
interconnection-related transmission needs that Transmission 
Providers must evaluate in the existing Order No. 1000 regional 
transmission planning process are those for which:
    (1) Transmission Providers in the transmission planning region 
have identified the relevant interconnection-related transmission 
need in interconnection studies in at least two interconnection 
queue cycles during the preceding five years (looking back from the 
effective date of the accepted tariff provisions proposed to comply 
with this reform in Order No. 1920, and the later-in-time withdrawn 
interconnection request occurring after the effective date of the 
accepted tariff provisions);
    (2) the interconnection-related Network Upgrade identified 
through the generator interconnection process to meet the relevant 
interconnection-related transmission need has a voltage of at least 
200 kV and an estimated cost of at least $30 million;
    (3) the interconnection-related Network Upgrade identified 
through the generator interconnection process to meet the relevant 
interconnection-related transmission need is not currently planned 
to be developed because the interconnection request(s) that led to 
the identification of the interconnection-related transmission need 
has been withdrawn; and
    (4) the Transmission Providers have not identified a different 
interconnection-related Network Upgrade to meet the relevant 
interconnection-related transmission need in an executed Generator 
Interconnection

[[Page 49561]]

Agreement or in a Generator Interconnection Agreement that the 
interconnection customer requested that the Transmission Provider 
file unexecuted with the Commission.
    The description of the regional transmission planning process 
must include sufficient detail to enable Transmission Customers to 
understand:
    (i) The process for enrollment in the regional transmission 
planning process;
    (ii) The process for consulting with customers;
    (iii) The notice procedures and anticipated frequency of 
meetings;
    (iv) The methodology, criteria, and processes used to develop a 
transmission plan;
    (v) The method of disclosure of criteria, assumptions, and data 
underlying a transmission plan;
    (vi) The obligations of and methods for transmission customers 
to submit data;
    (vii) The process for submission of data by nonincumbent 
developers of transmission projects that wish to participate in the 
regional transmission planning process and seek regional cost 
allocation;
    (viii) The process for submission of data by merchant 
transmission developers that wish to participate in the regional 
transmission planning process;
    (ix) The dispute resolution process;
    (x) The study procedures for economic upgrades to address 
congestion or the integration of new resources; and
    [The procedures and mechanisms for considering transmission 
needs driven by Public Policy Requirements, consistent with Order 
Nos. 1000; and]
    (xi) The relevant cost allocation method or methods.
    The regional transmission planning process must include [a ]cost 
allocation methods [or methods ]that satisfy the [six regional cost 
allocation principles]requirements set forth in Order Nos. 1000 and 
1920.

Identifying Potential Opportunities to Right-Size Replacement 
Transmission Facilities

    As part of each Long-Term Regional Transmission Planning cycle, 
Transmission Providers in each transmission planning region shall 
evaluate whether transmission facilities operating at or above a 
voltage threshold not to exceed 200 kV that an individual 
Transmission Provider that owns the transmission facility 
anticipates replacing in-kind with a new transmission facility 
during the next 10 years can be ``right-sized'' to more efficiently 
or cost-effectively address Long-Term Transmission Needs, as 
discussed in Order No. 1920. The process to identify potential 
opportunities to right-size replacement transmission facilities must 
follow the process outlined in Order No. 1920. The Transmission 
Providers in each transmission planning region shall include in 
their Tariffs a cost allocation method for right-sized replacement 
transmission facilities that are selected in the regional 
transmission plan for purposes of cost allocation.

Interregional Transmission Coordination

    The Transmission Provider, through its regional transmission 
planning process, must coordinate with the public utility 
transmission providers in each neighboring transmission planning 
region within its interconnection to address transmission planning 
coordination issues related to interregional transmission 
facilities. The interregional transmission coordination procedures 
must include a detailed description of the process for coordination 
between public utility transmission providers in neighboring 
transmission planning regions (i) with respect to each interregional 
transmission facility that is proposed to be located in both 
transmission planning regions and (ii) to identify possible 
interregional transmission facilities that could address 
transmission needs more efficiently or cost-effectively than 
separate regional transmission facilities. The interregional 
transmission coordination procedures shall be described in an 
attachment to the Transmission Provider's Tariff.
    The Transmission Provider must ensure that the following 
requirements are included in any applicable interregional 
transmission coordination procedures:
    (1) A commitment to coordinate and share the results of each 
transmission planning region's regional transmission plans 
(including information regarding the Long-Term Transmission Needs 
and potential transmission facilities to meet those needs) to 
identify possible interregional transmission facilities that could 
address transmission needs more efficiently or cost-effectively than 
separate regional transmission facilities, as well as a procedure 
for doing so;
    (2) A formal procedure to identify and jointly evaluate 
transmission facilities that are proposed to be located in both 
transmission planning regions, including those that may be more 
efficient or cost-effective transmission solutions to Long-Term 
Transmission Needs;
    (3) An agreement to exchange, at least annually, planning data 
and information; and
    (4) A commitment to maintain a website or email list for the 
communication of information related to the coordinated planning 
process, including:
    (a) the Long-Term Transmission Needs discussed in the 
interregional transmission coordination meetings;
    (b) any interregional transmission facilities proposed or 
identified in response to the Long-Term Transmission Needs;
    (c) the voltage level, estimated cost, and estimated in-service 
date of the interregional transmission facilities proposed or 
identified as part of Long-Term Regional Transmission Planning;
    (d) the results of any cost-benefit evaluation of such 
interregional transmission facilities, with results including both 
any overall benefits identified, as well as any benefits particular 
to each transmission planning region; and
    (e) the interregional transmission facilities, if any, selected 
in the regional transmission plan for purposes of cost allocation to 
meet Long-Term Transmission Needs.
    The Transmission Provider must work with transmission providers 
located in neighboring transmission planning regions to develop a 
mutually agreeable method or methods for allocating between the two 
transmission planning regions the costs of a new interregional 
transmission facility that is located within both transmission 
planning regions. Such cost allocation method or methods must 
satisfy the six interregional cost allocation principles set forth 
in Order No. 1000 and must be included in the Transmission 
Provider's Tariff.

United States of America--Federal Energy Regulatory Commission

Building for the Future Through Electric Regional Transmission 
Planning and Cost Allocation

Docket No. RM21-17-000

(Issued May 13, 2024)

PHILLIPS, Chairman, CLEMENTS, Commissioner, concurring:

    1. The electric transmission grid is the backbone of the 
American economy and essential to the national security of our 
country. The mission of this agency is to ensure reliable, safe, 
secure, and economically efficient energy for consumers at a 
reasonable cost. Ensuring we have a robust, well-planned electric 
transmission grid is the single most important step that this 
Commission can take to fulfill that statutory mandate. It is a 
reliability imperative. The transmission grid ultimately allows 
consumers to have access to the electricity they need--when they 
need it--to power their homes and businesses. It is equally an 
affordability imperative. The transmission grid gives those same 
consumers access to diverse, low-cost sources of electricity that 
help ensure energy bills remain just and reasonable. All told, a 
strong electric transmission grid is the foundation for how this 
Commission meets its most important statutory responsibilities under 
the Federal Power Act (FPA).
    2. That has never been more true than it is today. We are in the 
midst of a pivotal moment for the electricity system. As a nation, 
we are seeing unprecedented demands on the grid from extreme 
weather, increasing and rapidly changing patterns of electricity 
use, and fundamental shifts in the resource mix. And there is every 
reason to believe those trends will continue, and, indeed, 
accelerate, in the years ahead.
    3. At the same time, our transmission grid is old. More than 70 
percent of the grid was built over 25 years ago and much of it was 
put into service in the 1960s and 1970s, when this agency was still 
the Federal Power Commission. Our country cannot meet the challenges 
of today, let alone tomorrow, with yesterday's transmission system. 
And being unprepared to meet those increased demands jeopardizes the 
safety and security of our grid. Nevertheless, as a country, we have 
so far failed to make the investments in the types of transmission 
facilities needed to ensure continued reliability and affordability 
at anywhere near the scale or speed needed to meet this pivotal 
moment.
    4. The cost of continued inaction is immeasurable. Failure to 
act now would hamper the reliability and resilience of our electric 
grid while leaving customers holding the bag for the inevitably more 
costly upgrades in the future. Indeed, under the

[[Page 49562]]

status quo, with its de facto emphasis on the piecemeal, just-in-
time development of the grid to meet near-term reliability and 
economic needs, customers are being forced to fund investments that 
could have been more beneficial, less costly, or both had they been 
better planned from the start. That result undermines our economy 
and leaves customers less safe and secure, with enormous costs for 
both our grid and our country.
    5. Avoiding those costs requires a forward-looking, 
comprehensive, and holistic transmission planning and cost 
allocation framework. That framework must consider the diverse 
challenges facing the transmission grid, identify the solutions that 
will address those challenges, and ensure only customers who benefit 
from those facilities pay their share of the cost, while ensuring 
that customers who do not benefit do not pay. Period.
    6. We must conduct this planning and cost allocation on a 
regional basis and with an aperture consistent with the scope and 
scale of the challenges we face. That is, after all, why Congress 
enacted Title II of the FPA: To provide a coherent regional and 
national regulatory regime and avoid the harms and costs that come 
from a balkanized electricity system in which every state is its own 
regulatory island.\1\
---------------------------------------------------------------------------

    \1\ New York v. FERC, 535 U.S. 1, 6 (2002) (``When it enacted 
the FPA in 1935, Congress authorized federal regulation of 
electricity in areas beyond the reach of state power,'' tasking the 
Commission's predecessor with ``effective federal regulation of the 
expanding business of transmitting and selling electric power in 
interstate commerce.'' (quoting Gulf States Utils. Co. v. F.P.C., 
411 U.S. 747, 758 (1973))); FERC v. Elec. Power Supply Ass'n, 577 
U.S. 260, 265-66 (2016) (EPSA) (same); cf. First Iowa Hydro-Elec. 
Co-op v. F.P.C., 328 U.S. 152, 180 (1946) (The Federal Water Power 
Act of 1920 was ``a complete scheme of national regulation which 
would promote the comprehensive development of the water resources 
of the Nation, in so far as it was within the reach of the federal 
power to do so, instead of the piecemeal, restrictive, negative 
approach of the River and Harbor Acts and other federal laws 
previously enacted.'').
---------------------------------------------------------------------------

    7. Today's final rule does just that. We are requiring 
transmission planners to plan Long-Term Regional Transmission 
Facilities using the factors we know drive the transmission needs of 
tomorrow and consider the reliability and affordability benefits 
those facilities will provide. At the same time, we are giving 
transmission planners discretion regarding whether and how to select 
which transmission facilities to build, recognizing no two regions 
of the country are alike and a one-size-fits-all solution simply 
will not produce the infrastructure we so badly need.
    8. When it comes to the critical question of ``who pays,'' we 
are providing transmission planners with the maximum flexibility we 
can legally allow in order to facilitate negotiated, regionally 
appropriate solutions. And, as part of a multi-pronged approach to 
protecting customers, we are requiring transmission planners to 
reevaluate any previously selected Long-Term Regional Transmission 
Facility when the actual or projected costs of that facility 
significantly exceed the cost estimates used during selection. 
Finally, we are also providing states with unprecedented, expanded 
opportunities to work with transmission providers to shape the cost 
allocation approaches of their regions, while meeting the 
beneficiary pays requirement that is the foundation of cost 
causation under the FPA's just and reasonable standard.

I. The Dissent's Approach Would Not Result in the Energy Infrastructure 
Buildout We Need

    9. Commissioner Christie provides a stark alternative vision in 
his dissent, one that would violate the cost causation principle and 
harm electric reliability. While we agree with his emphasis on the 
importance of cooperation with states--and have created 
unprecedented opportunities for such cooperation throughout this 
final rule--his radical new approach would permit a state to receive 
economic, resilience, and reliability benefits from new energy 
infrastructure, but not be charged a single cent unless they 
expressly agree to pay. That myopic view does not satisfy the 
requirements of the FPA and would not adequately facilitate the 
development of transmission we desperately need to ensure 
reliability and affordability. Contrary to the dissent's assertion 
that this final rule is the product of a political agenda, failing 
to act based on the dissent's flawed reading of the circumstances 
through the lens of politics would abdicate the Commission's duty.
    10. The dissent's approach would necessarily require the 
Commission to ignore evidence about which consumers benefit from the 
increased reliability, resilience, and affordability due to grid 
expansion. Instead, backbone regional transmission could not be 
built unless every state unanimously opted into an agreed cost 
allocation. But for the same reason that passing around a hat is no 
way to fund the fire department, roads, or bridges, such an approach 
to building critical, public interest infrastructure that relies 
entirely on the voluntary contributions of individual states (or 
could even be defeated by the refusal to contribute by a single 
state) will not beget the transmission infrastructure needed to 
maintain reliability and affordability.
    11. Put another way, there is little reason to believe that we, 
as a country, would build the infrastructure needed to power the 
world's largest economy if individual states that benefit from that 
infrastructure could simply decline to pay. Instead, Commissioner 
Christie's approach would be far more likely to result in a failure 
to make needed investments entirely, or else to down-size those 
investments in a way that results in exactly the type of piecemeal 
transmission development that led us to conclude existing 
transmission planning practices are rendering transmission rates 
unjust and unreasonable. That result would leave America far worse 
off. Just as the Articles of Confederation were not a sufficient 
platform to develop and sustain a national economy, so too would a 
wholly voluntary approach to paying for the needed infrastructure be 
inadequate to develop a transmission grid capable of powering the 
world's largest economy. That alone is a reason to reject 
Commissioner Christie's dissenting views.
    12. In addition, the dissent's approach would result in subpar 
transmission planning. Our nation needs transmission planning that 
looks ahead on the decades-long timeframe that is relevant to 
building backbone transmission facilities that will likely last a 
half-century or more. And transmission needs can best be predicted 
by considering many factors to discern their aggregate effect. Those 
include economics and technology fundamentals, changing demand 
patterns across customers of all types (including corporations), the 
full panoply of federal, Tribal, state, and local policy 
contributions, and even the changing weather patterns, which pose 
increasing challenges to maintaining a reliable and resilient 
electric grid. Rather than reflect that integrated reality, 
Commissioner Christie's approach asks planners to isolate select 
state public policies and focus on how each individually shapes the 
grid. That too is a recipe for down-sizing needed infrastructure in 
a way that will result in less efficient or cost-effective 
investments that fail to meet this critical moment.

II. The Dissent Misrepresents the Final Rule

    13. Commissioner Christie's dissent responds to a strawman of 
his own making, not the final rule. And, even so, the dissent's 
critique of the final rule ultimately boils down to one principal 
issue: the failure of the rule (in his view) to give every state an 
absolute right to veto the costs of a transmission facility, even 
one from which the state's consumers would derive economic and 
reliability benefits. Although we respect his perspective, we 
disagree that the changes he seeks are legal--much less legally 
required--or that a final rule premised on his vision would beget 
the energy infrastructure needed to maintain reliability and 
affordability. In any case, his statement mischaracterizes critical 
aspects of the final rule, the most fundamental of which we address 
below.
    14. First and foremost, Commissioner Christie asserts that Long-
Term Regional Transmission Facilities are public policy projects 
whose purpose is to facilitate state efforts to shape the resource 
mix. He is wrong. This final rule requires transmission providers to 
comprehensively consider the factors that will shape the 
transmission needs of tomorrow. Although state efforts to shape the 
resource mix are one of many factors transmission planners are 
required to consider under this final rule, Commissioner Christie's 
narrow focus on them misses the forest for a couple trees. The 
requirement to consider state public policies is part of the much 
broader requirement to comprehensively consider all significant 
factors shaping future transmission needs, where other factors, 
including the fundamental economic and reliability drivers, play a 
much bigger role. That Commissioner Christie is focused 
overwhelmingly on the state public policies with which he disagrees 
does not mean that the same is true of Long-Term Regional 
Transmission Facilities.
    15. In any case, Commissioner Christie's proposal is arbitrary 
and capricious in its lack of any limiting principle. Transmission

[[Page 49563]]

needs of all sorts--economic or reliability, near-term or long-
term--are shaped by all manner of state public policy choices. 
Fundamental state decisions, such as tax rates, zoning and land use 
laws, and almost every use of the police power more generally, 
inevitably shape the supply and demand of electricity. No 
transmission need is unaffected by those basic exercises of state 
power, which means that no transmission need can be fairly or 
accurately described as entirely divorced from the effects or 
consequences of state policy decisions.
    16. While taking issue with some state policy choices, 
Commissioner Christie's vision contains no method for determining 
which state policies must be considered and which might escape 
scrutiny even though they too contribute to underlying transmission 
needs. Similarly, it contains no rubric for determining how to 
evaluate the cumulative effects of state public policies--such as 
taxation and land use laws--that are, in many cases, far in excess 
of those derived from the public policies on which he chooses to 
focus. Nor does it contain any explanation for subjecting Long-Term 
Regional Transmission Facilities to this suite of planning and cost 
allocation requirements, but not economic and reliability projects--
which are, for the reasons noted above, inevitably at least in part 
the product of public policies. That sort of unexplained, arbitrary 
line drawing is exactly what the APA prohibits.\2\
---------------------------------------------------------------------------

    \2\ See, e.g., Prometheus Radio Project v. F.C.C., 373 F.3d 372, 
390 (3rd. Cir. 2004) (explaining that when an agency has engaged in 
line-drawing, ``its decisions may not be `patently unreasonable' or 
run counter to the evidence before the agency'' (citations 
omitted)); Sinclair Broadcast Grp., Inc. v. F.C.C., 284 F.3d 148, 
162 (D.C. Cir. 2002) (explaining that lines drawn cannot be 
``patently unreasonable, having no relationship to the underlying 
regulatory problem'' (citing Cassell v. F.C.C., 154 F.3d 478, 485 
(D.C. Cir. 1998)); Am. Trucking Assocs., Inc. v. I.C.C., 697 F.2d 
1146, 1151 (D.C. Cir. 1983) (``The arbitrariness which the 
[Administrative Procedure Act] proscribes is the failure to draw 
reasoned distinctions where reasoned distinctions are required.'').
---------------------------------------------------------------------------

    17. Let us be clear: These are reliability and affordability 
projects. As the final rule explains, the minimum standards we 
establish provide that Long-Term Regional Transmission Facilities 
are to be identified and evaluated based on their reliability and 
economic benefits. To call them anything else--no matter how many 
times--is a misnomer, plain and simple.
    18. Similarly, Commissioner Christie's claim that states will be 
forced to subsidize other states' public policy choices could not be 
further from the truth. A bedrock requirement of this final rule is 
that customers will only be required to pay for a share of a Long-
Term Regional Transmission Facility to the extent they benefit from 
that facility. That is cost causation 101. While we provide 
transmission planners, in cooperation with their state regulators, 
ample flexibility to determine how to satisfy that bedrock 
requirement, any cost allocation methodology that causes customers 
to pay for projects from which they do not benefit--or to pay a cost 
share out of proportion to the benefits they draw from the project--
would be patently unjust and unreasonable. That is black letter law 
under the FPA,\3\ which we have expressly incorporated into the 
requirements of this final rule.\4\
---------------------------------------------------------------------------

    \3\ See City of Lincoln v. FERC, 89 F.4th 926, 930 (D.C. Cir. 
2024) (``The FPA's just and reasonable standard incorporates a cost-
causation principle.''); Old Dominion Elec. Coop. v. FERC, 898 F.3d 
1254, 1255 (D.C. Cir. 2018) (``Under the [FPA], electric utilities 
must charge just and reasonable rates. For decades, the Commission 
and the courts have understood this requirement to incorporate a 
cost-causation principle--the rates charged for electricity should 
reflect the costs of providing it.'' (citations omitted)); see also 
BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264, 268 (D.C. Cir. 
2014) (``[T]he cost causation principle itself manifests a kind of 
equity. This is most obvious when we frame the principle (as we and 
the Commission often do) as a matter of making sure that burden is 
matched with benefit.'').
    \4\ Bldg. for the Future Through Elec. Reg'l Transmission 
Planning & Cost Allocation & Generator Interconnection, Order No. 
1920, 187 FERC ] 61,068, at P 1305 & n.2786 (2024).
---------------------------------------------------------------------------

    19. The dissent is equally wrong to suggest that anything less 
than a unilateral right to veto cost responsibility for a regional 
transmission project is unfair to states. To the contrary, both 
courts and the Commission have long recognized that the just and 
reasonable standard of the FPA requires that customers pay for 
infrastructure they use and benefit from.\5\ The dissent's approach, 
by contrast, would permit free ridership, allowing states to avoid 
paying by withholding their approval, while still receiving the 
substantial benefits of a more integrated, robust transmission 
system. Here too, both the Commission and the courts have expressly 
rejected that approach as inconsistent with cost causation.\6\ 
Rather than ensure fairness, the dissent's approach would create 
perverse incentives, rewarding states that decline to pay for 
infrastructure development that demonstrably provides reliability 
and economic benefits to those states, while penalizing those who 
roll up their sleeves to get those projects built. That is a recipe 
for inaction, not for building the energy infrastructure we so badly 
need to maintain reliability and affordability.
---------------------------------------------------------------------------

    \5\ Beneficiary pays is founded on a recognition, grounded in 
the unbreakable laws of physics, that ``the nature of power flows 
over an interconnected transmission system does not permit a public 
utility transmission provider to withhold service from those who 
benefit from those services but have not agreed to pay for them.'' 
Order No. 1000, 136 FERC ] 61,051 at P 534; see also id P 535 (``the 
cost causation principle provides that costs should be allocated to 
those who cause them to be incurred and those that otherwise benefit 
from them''); Ill. Commerce Comm'n v. FERC, 576 F.3d 470, 476-77 
(7th Cir. 2009) (ICC v. FERC I) (``All approved rates must reflect 
to some degree the costs actually caused by the customer who must 
pay them . . . To the extent that a utility benefits from the costs 
of new facilities, it may be said to have caused a part of those 
costs to be incurred, as without the expectation of its 
contributions the facilities might not have been built, or might 
have been delayed.'' (internal citations omitted)); K N Energy, Inc. 
v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992) (``FERC and the courts 
have added flesh to these bare statutory bones, establishing what 
has become known in Commission parlance as the `cost-causation' 
principle. Simply put, it has been traditionally required that all 
approved rates reflect to some degree the costs actually caused by 
the customer who must pay them.''); see, e.g., Sw. Power Pool, 182 
FERC ] 61,141, at PP 12, 99-103 (2023).
    \6\ Order No. 890, 118 FERC ] 61,119 at P 561 (``there are free 
rider problems associated with new transmission investment, such 
that customers who do not agree to support a particular project may 
nonetheless receive substantial benefits from it''); Order No. 1000, 
136 FERC ] 61,051 at P 535 (``[if] the Commission could not address 
free rider problems associated with new transmission investment, [ ] 
it could not ensure that rates, terms and conditions of 
jurisdictional service are just and reasonable and not unduly 
discriminatory''); El Paso Elec. Co. v. FERC, 76 F.4th 352, 363 (5th 
Cir. 2023) (``No amount of emphasizing other competing interests 
permits FERC to sacrifice the foundational principle of cost-
causation by refusing to allocate costs to those who cause the costs 
to be incurred and who reap the resulting benefits.'' (citations 
omitted)).
---------------------------------------------------------------------------

    20. We agree with Commissioner Christie that transmission 
development works best when states are key partners in the process. 
That is why we take the unprecedented steps described in the final 
rule to give them a central role. But partnership and collaboration 
are not the same thing as giving every state the right to veto cost 
responsibility for transmission projects thus allowing their 
residents to reap a windfall by benefitting from transmission 
facilities for which they did not pay their legally required share.
    21. Commissioner Christie also asserts that the final rule 
deprives states of their long-standing authority. That is 
categorically false. Let us again be clear: States retain all the 
same authorities over retail rates and transmission siting they held 
prior to the final rule. Rather than deprive states of authority, 
the final rule empowers them with unprecedented opportunities to 
engage with transmission providers in developing a cost allocation 
framework.
    22. Commissioner Christie's objection is to the structure of the 
FPA, and long-established, court-upheld Commission regulation of 
regional transmission planning under Order No. 1000, not the final 
rule. He objects to the transmission provider's role in deciding, 
without state approval, whether to invest in a transmission project 
and determine, subject to Commission oversight, which consumers must 
pay for it. But that basic structure is not new to the final rule--
it is how transmission planning occurs today, consistent with the 
FPA and Commission precedent, including Order No. 1000. At 
Congress's direction, public utilities, not states, have the right 
to propose to the Commission rates and practices affecting those 
rates and we cannot deprive them of those rights.\7\ Neither states' 
siting authority nor their exclusive jurisdiction over retail rates 
give them the unilateral right to dictate matters subject to the 
Commission's exclusive jurisdiction, such as the transmission rates 
and practices affecting those rates that are the subject of this 
final rule.\8\ For example, a state could reject siting

[[Page 49564]]

or other approvals for the portion of a regional transmission 
project located within its jurisdiction, provided that its 
determination was consistent with relevant state and federal law. 
But states cannot stymie needed regional transmission projects by 
simply declining to pay for them. Nor is that concept new to this 
final rule. Under established economic and reliability planning, 
state policies are contributing factors to needed transmission, and 
states have never held a veto authority over costs for such 
facilities under Order No. 1000.\9\ Nothing in this final rule 
changes those basic facts.
---------------------------------------------------------------------------

    \7\ 16 U.S.C. 824d; Atl. City Elec. Co. v. FERC, 295 F.3d 1, 9 
(D.C. Cir. 2002) (``Section 205 of the Federal Power Act gives a 
utility the right to file rates and terms for services rendered with 
its assets.'').
    \8\ See Order No. 1920, 187 FERC ] 61,068 at PP 253-83 
(affirming Commission's legal authority to require participation in 
Long-Term Regional Transmission Planning).
    \9\ Indeed, Commissioner Christie recently approved, over the 
objection of other states, PJM's plan to regionally allocate the 
costs of transmission to address reliability concerns driven, at 
least in part, by Virginia's policy to incent siting of data centers 
in that state. See PJM Interconnection, L.L.C., 187 FERC ] 61,012 
(2024).
---------------------------------------------------------------------------

    23. What has changed is that states now, as a result of this 
final rule, have an unprecedented opportunity to shape transmission 
planning and cost allocation, elevating our system of cooperative 
federalism with the states to a degree not previously seen in the 
history of this Commission. Most significantly, we are requiring 
transmission providers to host a dedicated forum for meaningful 
state participation in proposing cost allocation methods and 
processes. And the rule also permits a State Agreement Process for 
allocating the costs of all, or a subset of, Long-Term Transmission 
Facilities. Beyond cost allocation, states will have an opportunity 
to provide input on how to account for specific factors in Long-Term 
Scenarios, and states can provide information on how their own 
policies and planning affect Long-Term Transmission Needs. The rule 
also requires transmission providers to consult with and seek the 
support of states regarding how Long-Term Regional Transmission 
Facilities are evaluated and selected. We expect that where states 
come together to articulate workable, legal frameworks for planning 
and paying for needed infrastructure, their transmission providers 
will listen.
    24. Indeed, under the State Agreement Process provided in the 
final rule, states very well could agree to, and transmission 
planners could adopt, a version of Commissioner Christie's preferred 
cost allocation approach.\10\ So long as those expected to use the 
Long-Term Regional Transmission Facilities pay a share of the cost 
that is roughly commensurate with the benefits they will receive, 
nothing in this final rule prohibits states in a transmission 
planning region from adopting Commissioner Christie's preferred 
approach for funding the transmission facilities they need to ensure 
reliability and affordability.
---------------------------------------------------------------------------

    \10\ We find Commissioner Christie's contention that the final 
rule would end PJM's use of its existing State Agreement Approach, 
and MISO and SPP's respective regional state committees, puzzling. 
Order No. 1920, 187 FERC ] 61,068 (2024) (Christie, Comm'r, 
dissenting, at P 11). The final rule enhances states' role and 
relaxes certain Order No. 1000 requirements for state-approved cost 
allocations. It is inexplicable that these additional flexibilities 
would result in transmission providers rolling back opportunities 
for state engagement in existing Order No. 1000 processes, where 
that is the opposite of the thrust of the final rule. Moreover, 
PJM's State Agreement Approach was approved outside of compliance 
with Order No. 1000 and has never served as PJM's exclusive ex ante 
cost allocation method, as Commissioner Christie suggests.
---------------------------------------------------------------------------

    25. Commissioner Christie also asserts that this final rule 
breaks with Order No. 1000 by mandating outcomes rather than 
regulating transmission planning processes. Here, too, he is wrong. 
The rule is clear that no transmission provider is required to 
select any particular project.\11\ Instead, just as in Order No. 
1000, the obligation on the transmission provider is to plan for the 
world as we expect it to be and then make its own business decisions 
after having conducted that planning process. The final rule's 
minimum planning standards do not un-do that core discretion. 
Requiring planning to be based upon documented drivers of 
transmission needs and to incorporate objective measures of how 
potential investments pay off improves the planning process, it does 
not mandate any particular outcome.\12\ In short, in recasting the 
rule to fit his narrative, Commissioner Christie conveniently 
ignores one of its core elements: that it imposes no obligation to 
develop any regional transmission project.
---------------------------------------------------------------------------

    \11\ Order No. 1920, 187 FERC ] 61,068 at P 1026 (``The 
Commission did not propose in the NOPR, and we will not require in 
this final rule, that transmission providers select any particular 
Long-Term Regional Transmission Facility--even where a particular 
transmission facility meets the transmission providers' selection 
criteria in their OATTs.'').
    \12\ Id. (``In other words, as in Order No. 1000, our focus is 
on ensuring that regional transmission planning processes result in 
just and reasonable rates, and not on requiring that these processes 
achieve any particular substantive outcome.'').
---------------------------------------------------------------------------

    26. Finally, Commissioner Christie is also incorrect in arguing 
that this final rule violates the Major Questions Doctrine. He 
asserts two bases for that argument, neither of which hold water.
    27. First, he contends that our intention in issuing this final 
rule is to elicit trillions in spending on transmission. As an 
initial matter, the goal of this final rule is to facilitate the 
development of transmission infrastructure needed to maintain 
reliability and affordability. That is the case no matter how many 
times or in how many ways Commissioner Christie purports to ascribe 
our `true' intentions. In any case, his trillion-dollar estimates 
are nothing more than a sleight of hand that is unsupported by the 
record before us. To support his claim that this final rule will 
cause ``literally trillions'' in transmission investment, he cites 
to one academic study and one news article stating that in order to 
achieve a ``net-zero'' emissions level by 2050, trillions will need 
to be spent on transmission.\13\ Putting aside whether that figure 
is accurate and whether ``net zero'' is an appropriate policy goal 
for the country--a question which we agree is not for this 
Commission to resolve--it is an astounding logical leap to say that 
because certain individuals believe a certain amount of investment 
is necessary to achieve a certain policy goal, that this rule will 
necessary cause customers to spend that amount of money. In any 
case, as the dissent points out, significant investments in 
transmission are already being made by public utilities around the 
country regardless of anything we do--or do not do--here today. This 
final rule regulates the process by which those investments are 
identified, evaluated and, where appropriate, selected in order to 
help ensure that they reflect the most efficient and cost-effective 
options available. That is what the Commission has been doing for 
decades; the fact that transmission has become a more politically 
salient topic does not transform our longstanding practice into a 
major question.
---------------------------------------------------------------------------

    \13\ Id. (Christie, Comm'r, dissenting at P 3 & n.7.
---------------------------------------------------------------------------

    28. Second, he contends that our statement that the Commission 
has exclusive jurisdiction over the transmission planning practices 
that directly affect wholesale rates means that this Commission has 
crossed the major questions Rubicon. But it was the courts, not this 
Commission, that took that step. As he observes in his dissent, 
South Carolina concluded that the transmission planning practices 
regulated by Order No. 1000--which are the same practices addressed 
by this final rule--were practices that directly affected wholesale 
rates and thus fall squarely within the Commission's 
jurisdiction.\14\ And as the courts have explained, where a practice 
meets that directly affecting standard, it falls within the 
Commission's exclusive jurisdiction.\15\ This long-settled law in no 
way alters or dilutes the significant and critical role for states 
to play under their jurisdiction and, as noted above, we have 
significantly expanded that role in this final rule. Rather it means 
that the specific practices in the tariffs on file with this 
Commission, as required by this final rule, are within the 
Commission's exclusive jurisdiction, not that of the states. The 
final rule's recitation of black letter law hardly runs afoul of the 
major questions doctrine.
---------------------------------------------------------------------------

    \14\ In South Carolina, it was undisputed that transmission 
planning generally was a practice that directly affected wholesale 
rates, but the court further held that the absence of regional 
transmission planning was itself such a practice. S.C. Pub. Serv. 
Auth. v. FERC, 762 F.3d 41, 56-59 (D.C. Cir. 2014).
    \15\ See, e.g., Nat'l Ass'n of Regul. Util. Comm'rs v. FERC, 964 
F.3d 1177, 1181 (D.C. Cir. 2020) (``Congress g[ave] the Federal 
Energy Regulatory Commission . . . exclusive authority over the 
regulation of the sale of electric energy at wholesale in interstate 
commerce, including both wholesale electricity rates and any rule or 
practice affecting such rates.'' (cleaned up)).
---------------------------------------------------------------------------

III. We Encourage Transmission Providers To Facilitate Joint Ownership 
Structures

    29. Finally, we would be remiss not to mention one policy 
priority that is not finalized in this rule: The creation of a 
federal right of first refusal for certain transmission facilities 
developed through a joint ownership structure. As the final rule 
explains, we find that proposal is better considered as part of our 
generic proceeding on Transmission Planning and Cost Management, 
where it can be evaluated

[[Page 49565]]

alongside other proposals for ensuring that transmission facilities 
are developed as efficiently and cost-effectively as possible.\16\
---------------------------------------------------------------------------

    \16\ Order No. 1920, 187 FERC ] 61,068 at PP 1563-64 & n.3346.
---------------------------------------------------------------------------

    30. Nevertheless, we underscore that our decision today should 
not be construed as a lack of support for the concept of joint 
ownership or the potential for a federal ROFR to effectively 
encourage its use. Indeed, joint ownership structures that partner 
transmission owners with other load-serving entities in their 
footprint, such as public power or non-profit cooperatives, can 
provide many benefits and should be encouraged.
    31. In these arrangements, the load-serving entity partner's 
participation can reduce costs for customers in the footprint. Such 
joint ownership structures bring together diverse parties, allowing 
the participating entities to better allocate risks and 
responsibilities, capture efficiencies, and promote innovation, all 
to customers' ultimate benefit.\17\ Moreover, by bringing a wider 
range of entities into the transmission development fold, joint 
ownership can leverage additional sources of capital, including 
those that do not typically invest in transmission facilities, which 
can itself have significant benefits for customers.\18\
---------------------------------------------------------------------------

    \17\ See, e.g., TAPS Initial Comments at 33-34 (``As explained 
in the TAPS 2021 White Paper, inclusive joint transmission ownership 
arrangements--whether structured as an inclusive transco, a shared 
system, or joint ownership of new transmission facilities--result in 
collaborative and inclusive planning, development, and siting of 
transmission, and have proven highly effective in getting 
transmission built to meet the needs of all LSEs.'' (citing TAPS, 
Inclusive Joint Transmission Ownership Arrangements: An Effective 
Means to Site and Build Transmission Need to Support Our Changing 
Resource Mix (June 2021), https://www.tapsgroup.org/wp-content/uploads/2021/09/TAPS-Inclusive-Joint-Ownership-White-Paper.pdf)); 
see also Rob Gramlich et al., Grid Strategies, Fostering 
Collaboration Would Help Build Needed Transmission, at 11-30 (Feb. 
2024) (attached to WIRES Supplemental Comments) (highlighting 
specific examples of large regional transmission projects that 
resulted from diverse partnerships, including with public power 
entities and cooperatives, and which met many transmission needs and 
produced a wide range of benefits).
    \18\ See, e.g., APPA Initial Comments, attach. at 4-10 
(Declaration of James Pardikes) (listing advantages in equity ratio, 
debt cost, and income tax expense, and opportunities for risk 
diversification as potential benefits of joint ownership 
arrangements with public power utilities); NRECA Reply Comments at 
15-16; Citizens Energy Reply Comments at 2-4 (describing how its 
unique joint ownership business model enables Citizens to provide 
direct support to low-income ratepayers and disadvantaged 
communities, addresses multiple concerns that arise in transmission 
development, and advances multiple Commission policy goals).
---------------------------------------------------------------------------

    32. For example, TAPS highlights specific instances of joint 
ownership arrangements with tax-exempt public power entities 
providing significant savings to customers.\19\ TAPS and APPA 
estimate these kinds of joint ownership arrangements can typically 
yield a ``more than a 5% annual cost reduction in ratepayer-funded 
return and associated tax costs,'' which could produce billions of 
dollars in savings when applied to reasonable transmission 
investment forecasts.\20\ Relatedly, NRECA highlights examples of 
joint ownership arrangements with electric cooperatives yielding 
reliability and efficiency benefits, including, among others, 
leveraging electric cooperative's ability to provide increased 
operations and maintenance support and access to lower cost 
financing through the Rural Utilities Service.\21\
---------------------------------------------------------------------------

    \19\ TAPS Initial Comments at 45 (examining savings across 
Vermont Transco, ATCLLC, Fargo Project, and SE Missouri Project).
    \20\ TAPS Initial Comments at 45-46 & nn.133-135; APPA Reply 
Comments at 4.
    \21\ GDS Assocs., National Rural Electric Cooperative 
Association, at 25-27 (Aug. 17, 2021) (attached to NRECA Initial 
Comments).
---------------------------------------------------------------------------

    33. In light of those substantial benefits, we clarify that 
nothing in this final rule should be interpreted to prohibit or 
impair joint ownership arrangements. To the contrary, we encourage 
transmission providers, in compliance with this rule and elsewhere, 
to find ways to encourage these arrangements. For example, in 
compliance with this rule, transmission planners could use joint 
ownership as a factor to be considered in evaluating and selecting 
the more efficient or cost-effective solution to meet a long-term 
transmission need. Similarly, we note that the developers of a 
jointly owned transmission facility can consider seeking 
transmission incentives under section 205 of the FPA that reflect 
the risks and challenges associated with developing such 
facilities.\22\ In addition, the Commission will continue to 
evaluate other potential actions to incentivize joint ownership, 
including considering in the Commission's cost management proceeding 
whether to provide a right of first refusal or other mechanisms to 
encourage its use.
---------------------------------------------------------------------------

    \22\ See Promoting Transmission Investment Through Pricing 
Reform, 141 FERC ] 61,129, at P 24 (2012) (``The Commission 
encourages incentives applicants to participate in joint ownership 
arrangements and agrees with commenters to the NOI that such 
arrangements can be beneficial by diversifying financial risk across 
multiple owners and minimizing siting risks.''); Promoting 
Transmission Investment Through Pricing Reform, Order No. 679, 116 
FERC 61,057, at P 354 (2006) (``[T]o the extent our jurisdiction 
allows, the Commission will entertain appropriate requests for 
incentive ratemaking for investment in new transmission projects 
when public power participates with jurisdictional entities as part 
of a proposal for incentives for a particular joint project. 
Encouraging public power participation in such projects is 
consistent with the goals of section 219 by encouraging a deep pool 
of participants.'').
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* * * * *
    34. Our electric transmission grid is at a crossroads. Our 
nation is facing down an extended period of unprecedented change in 
demand, supply, and the myriad other factors that fundamentally 
shape our energy needs. And we do so with a network of transmission 
infrastructure that was overwhelmingly built in the last century and 
in the face of a very different reality.
    35. We have a choice: We can take consequential action to build 
the infrastructure needed to ensure reliability and affordability. 
Or we can pursue half-measures, which may help on the margins, but 
will ultimately leave us lacking the infrastructure we need to keep 
the lights on at a price that customers can afford. With this final 
rule, we emphatically choose the former path.
    36. But we are not going down this road alone. As discussed 
above, we have opened the door for our state partners to play a 
leading role in shaping the next generation of energy 
infrastructure. We urge them to walk through it and deploy their 
unique perspectives as regulators and siting authorities of electric 
infrastructure to develop regionally tailored solutions. Together, 
we can forge a process that will serve customers for generations to 
come. This is the moment to step up, to develop both processes and 
physical infrastructure to withstand the changes and challenges 
ahead. This is the moment to build an electric transmission grid for 
the 21st century.

    For these reasons, we respectfully concur.
-----------------------------------------------------------------------
Willie L. Phillips

Chairman
-----------------------------------------------------------------------
Allison Clements

Commissioner

United States of America--Federal Energy Regulatory Commission

Building for the Future Through Electric Regional Transmission 
Planning and Cost Allocation

Docket No. RM21-17-000

(Issued May 13, 2024)

CHRISTIE, Commissioner, dissenting:

I. The Final Rule Is a Pretext for Enacting a Sweeping Policy Agenda 
Never Passed by Congress, Denies the States the Authority Promised by 
the NOPR, and Fails the Commission's Consumer Protection Duty Under the 
Federal Power Act

    1. The Federal Power Act (FPA) is, at its core, a consumer 
protection statute.\1\ In FPA section 206, which today's final rule 
purports to be based on, Congress explicitly directed this 
Commission to protect consumers from public utility ``rates'' that 
are ``unjust, unreasonable, unduly discriminatory or preferential.'' 
\2\ This final rule, however, fails

[[Page 49566]]

to fulfill the Commission's consumer protection duty required by the 
statute. The final rule should be seen for what it is: a pretext to 
enact, through administrative action, a sweeping legislative and 
policy agenda that Congress never passed.\3\ The final rule claims 
statutory authority the Commission does not have to issue an 
absurdly complex bureaucratic blizzard of mandates and 
micromanagement \4\ to be imposed on every transmission provider in 
the United States for the transparent goal of spending trillions of 
consumers' dollars on transmission not to serve consumers in 
accordance with the FPA, but instead to serve political, corporate, 
and other special-interest agendas that were never enacted into 
law.\5\ The rates for transmission that will result from the final 
rule will not only be unjust, unreasonable, unduly discriminatory 
and preferential, but grossly unfair to tens of millions of American 
consumers already burdened with rapidly growing monthly power bills.
---------------------------------------------------------------------------

    \1\ E.g., Towns of Alexandria, Minn. v. FPC, 555 F.2d 1020, 1028 
(D.C. Cir. 1977) (explaining that the FPA's `` `primary aim is the 
protection of consumers from excessive rates and charges' '') 
(quoting Mun. Light Bds. v. FPC, 450 F.2d 1341, 1348 (D.C. Cir. 
1971)); see also Elec. Dist. No. 1 v. FERC, 774 F.2d 490, 492 (D.C. 
Cir. 1985) (recognizing that the benefits of rate predictability, 
which are the ``whole purpose'' of the filed rate doctrine, ought to 
be considered in light of the FPA's ``primary purpose of protecting 
the utility's customers'').
    \2\ 16 U.S.C. 824e. Under the FPA, the Commission is a regulator 
of wholesale public utility rates, not a national integrated 
resource planner (known in the lingo as an ``IRP'') of generation 
and/or transmission. See, e.g., Entergy Nuclear Vt. Yankee, LLC v. 
Shumlin, 733 F.3d 393, 417 (2d Cir. 2013) (quoting S. Cal. Edison 
Co. San Diego Gas & Elec. Co., 71 FERC ] 61,269, at 62,080 (1995) 
(``[S]tates have broad powers under state law to direct the planning 
and resource decisions of utilities under their jurisdiction. States 
may, for example, order utilities to build renewable generators 
themselves, or . . . order utilities to purchase renewable 
generation.''). Further, FPA section 215, pertaining to electric 
reliability, explicitly leaves the construction of generation and 
transmission assets to state regulatory authority. 16 U.S.C. 
824o(i)(2). Section 215 makes clear congressional intent to leave 
integrated resource planning to the states. Indeed, the overall 
statutory framework of the FPA--consistent with America's federal 
constitutional structure--makes it clear that states are the primary 
regulators of which utility assets get planned and built, both 
generation and transmission, not FERC.
    \3\ See, e.g., W. Va. v. EPA, 597 U.S. 697 (2022) (West Virginia 
v. EPA); Dept. of Commerce v. N.Y., 139 S. Ct. 2551 (2019).
    \4\ In truly Kafkaesque fashion, the final rule is a doorstopper 
weighing in at just below 1300 pages, likely one of the longest, 
most complicated, and confusing orders the Commission has ever 
issued. Regulated entities--it applies to all public utility 
transmission providers in the United States, RTO and non-RTO--will 
need weeks just to read through it, much less decipher it, and then 
months of figuring out how to comply. Its very complexity raises the 
prospect of multiple rounds of compliance filings, no doubt 
punctuated by multiple deficiency letters, in order to push the 
transmission provider towards the outcomes the Commission wants to 
achieve. The final rule's very complexity renders it, if not 
arbitrary and capricious on its face, likely to be arbitrary and 
capricious in its enforcement.
    \5\ See, e.g., Heather Richards, Zach Bright, Christian Robles, 
3 energy issues to watch this spring at DOE, Interior and FERC, 
Energywire, Mar. 18, 2024 (``FERC has promised a closely watched 
rule this spring on transmission that could be key to President Joe 
Biden's ambitious aim to decarbonize the electricity grid by 2035 . 
. . . `The sooner we get a final rule, the better. . .,' said 
Caitlin Marquis [of] Advanced Energy United, a pro-clean-energy 
group . . . . [T]he Biden administration is in a race . . . until 
roughly midyear to finalize rules before they are subject to the 
Congressional Review Act (CRA) . . . . The Biden administration has 
said [today's final rule] will facilitate a build-out of 
interregional lines and grid interconnections needed to . . . allow 
more wind and solar power to come online . . . .'') (emphases added) 
https://www.eenews.net/articles/3-energy-issues-to-watch-this-spring-at-doe-interior-and-ferc/; see also Peter Behr, EPA power 
plant rule targets coal. Does that spell trouble for the grid? 
Climatewire, May 3, 2024 (``But climate activists will not give up 
the `zero by 2035' goal without a fight. President Biden made that 
steep commitment at a critical point in his 2020 candidacy to win 
the support of primary rival Sen. Bernie Sanders (I-Vt.) and his 
climate action activists . . . . [T]he hard road to a zero-carbon 
grid in 2035 is real precisely because the Biden administration has 
pursued it . . . . [Study authors] highlighted estimates that the 
rate of high-voltage transmission line construction must double to 
deliver the necessary new wind and solar energy . . . . The [Biden] 
administration . . . is putting a strategy for big new lines in 
place. FERC, with the support of Biden appointees, is preparing new 
policy to support big wires projects . . . . `You can't get around 
the fact that you're going to need tens of thousands of miles of new 
transmission lines if you want to build the hundreds of gigawatts of 
wind and solar and batteries that many of us predict are needed to 
achieve decarbonization goals,' said [former Obama energy secretary 
Ernest] Moniz.'') (emphases added), https://www.eenews.net/articles/epa-power-plant-rule-targets-coal-does-that-spell-trouble-for-the-grid-2/; see also Zach Bright, FERC sets date for landmark 
transmission rule, Energywire, Apr. 19, 2024 (``FERC said it plans 
to hold a special May 13 meeting to consider its . . . transmission 
planning and cost-allocation proposal that's been a focus of 
[lobbying] for expanding the grid to . . . move more renewable 
energy . . . . The Biden administration's goal of [net zero] by 2035 
hinges on expanding the transmission system by two-thirds, the 
Energy Department said last year.'') (emphases added), https://www.eenews.net/articles/ferc-sets-date-for-landmark-transmission-rule/; It's raining rules: Why the Biden administration is rushing 
to produce regulations, The Economist, May 4, 2024, at 19 (``More 
regulations, big and small, are expected soon. The Federal Energy 
Regulatory Commission is planning to rewrite the rules governing 
interstate electricity transmission, which is critical to President 
Joe Biden's decarbonisation plans . . . . Why the sudden spate? A 
previously obscure law, the [CRA], helps explain the rush. It allows 
Congress, for a limited period, to pass resolutions of disapproval 
against finalised administrative regulations with which it 
disagrees. If both chambers of Congress pass such a resolution, and 
the president signs it, the rule is cancelled, short-circuiting the 
usual drawn-out process of litigation or a subsequent administration 
beginning a whole new rule-making effort. So once a regulation is 
properly created the clock starts ticking: the cancellation 
procedure is allowed for up to 60 days that the Senate is in 
session--including the last 60 days of an administration that loses 
a presidential election.'') (emphasis added), https://www.economist.com/united-states/2024/05/02/why-the-biden-administration-is-rushing-to-produce-regulations; see infra nn.8, 
10, 13, 15, 16, 67.
---------------------------------------------------------------------------

    2. The fundamental principle historically embedded in utility 
regulation in the United States is to provide consumers with 
reliable power at the least cost under applicable law. This 
principle is fair and compelling because the vast majority of 
American utility consumers are captive customers who pay a monopoly 
utility for a vital public service--electrical power--which no one 
can live without in modern society. Transmission is an essential 
component of this vital public service,\6\ so necessary transmission 
must be built.
---------------------------------------------------------------------------

    \6\ The transmission component of utility service has typically 
been provided by the incumbent monopoly utility at the load-serving 
local level, and local transmission planning and/or construction is 
generally subject to state-regulated IRP or permitting processes, 
especially in non-RTO regions. The final rule imposes numerous 
additional requirements for local transmission planning, including 
even micromanaging how local ``stakeholder'' meetings are supposed 
to be conducted, which may conflict with state IRP proceedings and 
represent yet another FERC encroachment into areas of traditional 
state authority. See Bldg. for the Future Through Elec. Reg'l 
Transmission Planning & Cost Allocation & Generator Interconnection, 
Order No. 1920, 187 FERC ] 61,068, at Section IX.B.3.a (2024) (Final 
Rule). It is highly doubtful that the micromanagement of stakeholder 
meetings in local planning would pass judicial review under CAISO v. 
FERC, in which FERC's attempted micromanagement of an ISO's 
governing board appointments was rejected as not sufficiently 
grounded in FERC's rate-setting authority under the FPA. See Cal. 
Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395, 400 (D.C. Cir 
2004) (CAISO v. FERC).
---------------------------------------------------------------------------

    3. Today's final rule, however, is not about providing reliable 
power to consumers at least cost through just and reasonable rates 
as required by the FPA, despite the final rule's claim. And it is 
certainly not about being fair. On the contrary, the final rule 
inflicts staggering costs on consumers by promoting the construction 
of trillions of dollars of transmission projects,\7\ not to serve 
consumers in accordance with the FPA, but to serve a major policy 
agenda never passed by Congress, to serve the profit-making 
interests of developers of politically preferred generation, 
primarily wind and solar, and to serve corporate ``green energy'' 
preferential purchasing policies.\8\ As such, the final rule

[[Page 49567]]

does not deserve a shred of deference under Chevron U.S.A., Inc. v. 
Natural Resources Defense Council, Inc.\9\ in any form. Today's 
final rule is much less the product of reasoned decision-making or 
the agency's specialized expertise, as of political pressure and 
special interest lobbying.\10\ In the chapter on ``regulatory 
capture'' \11\ in future economics textbooks, today's final rule 
should be a featured case study.
---------------------------------------------------------------------------

    \7\ The Princeton Net Zero study is often cited, but it is only 
one of many estimates of the trillions of dollars in additional 
costs to be imposed on consumers. Using the Princeton study, the 
cost estimates of the transmission buildout necessary to achieve 
``net zero'' range across different scenarios, with one scenario 
calling for transmission capacity to quintuple (5x) between 2020 and 
2050, which is predicted to cost $3.56 trillion. See Princeton 
University Net Zero America Final Report Summary, Slide 29, https://netzeroamerica.princeton.edu/img/Princeton%20NZA%20FINAL%20REPORT%20SUMMARY%20(29Oct2021).pdf. I 
would emphasize that the sticker price of a utility asset is only a 
fraction of the ultimate cost to consumers, because the ``going in'' 
price will increase by a multiple of many times the original cost 
over the life of the asset, because the cost of capital, both a 
profit to the utility (known as Return on Equity, or ROE) and the 
cost of debt, will be paid by consumers. So, if Princeton gives an 
estimate of $3.56 trillion for new utility assets needed to reach 
the ``net zero'' goal, the actual cost to consumers over the life of 
the assets will be many times more than that estimate. See also 
Diana DiGangi, U.S. won't reach net zero emissions without 
transmission buildout: DNV, Utility Dive, Sept. 25, 2023 (``$12 
trillion will be spent on clean energy in North America by 2050 . . 
. to meet . . . net zero emissions targets . . . . Some of the 
biggest barriers to net zero in the U.S. include the lack of 
transmission buildout . . . .) (emphases added), https://www.utilitydive.com/news/net-zero-transition-clean-energy-north-america-transmission-buildout/694621/.
    \8\ See, e.g., Peter Behr, DOE unveils critical grid corridors 
for Biden climate goals, Energywire, May 8, 2024 (`` `To meet our 
climate goals we have to more than double our transmission 
capacity,' said top White House clean energy adviser John Podesta, 
who has led a Cabinet-level push to get long-delayed transmission 
projects under construction.'') (emphasis added), https://www.eenews.net/articles/doe-unveils-critical-grid-corridors-for-biden-climate-goals/; Peter Behr, More, More, More: Biden's clean 
grid hinges on power lines, Energywire, May 23, 2022 (stating that 
``the Biden administration is seeking an unprecedented expansion of 
high-voltage electric lines to open new paths to wind and solar 
energy. `We obviously need more, more, more transmission to run on 
100 percent clean energy . . .,' Energy Secretary Jennifer Granholm 
said in February.'') (emphasis added), https://subscriber.politicopro.com/article/eenews/2022/05/23/more-more-more-bidens-clean-grid-hinges-on-power-lines-00030117; see also supra n.5 
and infra nn.10, 13, 15, 16, 67.
    \9\ 467 U.S. 837 (1984) (Chevron).
    \10\ See Catherine Morehouse, FERC to tackle ``historic'' 
transmission planning rule in May, PoliticoPRO, Apr. 18, 2024 
(``FERC has been under enormous pressure from lawmakers, clean 
energy developers, environmentalists and others to finalize the rule 
that Chair Willie Phillips has promised will be `historic' and the 
`greatest development regarding electric transmission rules in the 
country in over a generation.' '') (emphases added), https://subscriber.politicopro.com/article/2024/04/ferc-to-tackle-massive-transmission-planning-rule-next-month-00153191; see also, e.g., Sen. 
Charles E. Schumer July 24, 2023 Comments at 1-2 (urging the 
Commission to ensure that ``any final rule must . . . prescribe a 
set of benefits'' to be used in transmission planning and that ``it 
will be necessary that either'' [the transmission provider, or FERC 
shall impose cost allocation] ``when any state withholds support on 
a cost allocation method'' [which risks] ``states that benefit from 
a transmission line'' [acting as] ``free riders [to] avoid any 
costs.'') (emphases added); Sen. Martin Heinrich, et al. (consisting 
of 20 additional Senators) Jan. 19, 2024 Comments at 2 (urging the 
Commission that ``the final rule must require consideration of a . . 
. specific set of transmission benefits for . . . cost allocation 
processes'') (emphases added); Sen. Sheldon Whitehouse Nov. 7, 2023 
Comments at 2 (stating that ``FERC should include [a list of 
required benefits] in its final rule''). As explained extensively 
herein, mandating benefits is a device for imposing costs on 
consumers in states that never agreed to the selection criteria or 
cost allocation. The deeply granular nature of the instructions to 
the Commission in these letters is more evidence that this final 
rule is a pretext to use an administrative agency to enact 
legislation that Congress never passed. See also supra nn.5, 8 and 
infra nn.13, 15, 16, 67.
    \11\ Luigi Zingales, Preventing Economists' Capture, University 
of Chicago Booth School of Business Review, July 1, 2014 (``In 
simple words, regulatory capture exists when a regulatory agency, 
created to act in the public interest, ends up advancing interests 
of the industry it is charged with regulating.''), https://www.chicagobooth.edu/review/preventing-economists-capture.
---------------------------------------------------------------------------

    4. The final rule orders all transmission providers, RTO and 
non-RTO, to plan costly regional transmission for some allegedly 
predictable generation mix 20 years in the future (a generation mix 
which, as a practical matter, is impossible to predict so far into 
the future).\12\ The obviously pretextual agenda of the final rule, 
however, is not to predict the generation mix 20 years forward, but 
to produce the preferred generation mix that the current 
presidential administration, some huge multinational 
corporations,\13\ some members of Congress, and other special 
interests want now. In fact, the final rule is not even about 
planning transmission, but is about planning policy, and it is very 
preferential about the policies it wants to promote. As with the 
Great Oz,\14\ pulling back the curtain exposes the final rule for 
what it really is: An essential component in a comprehensive plan by 
the current presidential administration to push what the media 
describe as ``green policies'' designed to prefer and promote the 
wind and solar generation it favors while simultaneously forcing the 
shutdown of the fossil fuel generation it disfavors,\15\ both needed 
to meet its political commitment. Let me emphasize: Whether the 
policies being promoted in this final rule can be described as 
``green, purple, red or blue'' is irrelevant. The point is that 
FERC, as an independent agency, has no business promoting the 
policies of any one party or presidential administration, especially 
when, as here, the effort to do so goes far beyond FERC's legal 
authority and fails to perform our consumer protection function 
under the FPA.
---------------------------------------------------------------------------

    \12\ The example of the Potomac-Appalachian Transmission 
Highline (PATH) fiasco is a strong warning about the folly of 
spending billions of consumers' dollars to build transmission based 
on predictions of a generation mix in 20 years. Potomac-Appalachian 
Transmission Highline, LLC, 185 FERC ] 61,198 (2023) (Christie, 
Comm'r, concurring at P 3) (PATH Concurrence) (``[C]onsumers have 
paid roughly $250 million for a project that was never built nor 
found needed by a single state regulator.'') (emphasis in original), 
https://www.ferc.gov/news-events/news/e-4-commissioner-christies-concurrence-letter-order-approving-path-settlement-er12; see also 
PJM Initial Comments at 62 (``In short, the volatility of input 
parameters cancelled the need for a $1.8 billion transmission line 
identified in 2007, that was confirmed to be needed five years out 
in 2012, but by 2012 was no longer needed for at least another 15 
years, if at all.''). Rather than wind or solar--which the final 
rule implicitly presumes will be the predominant generating resource 
in 20 years--it is just as foreseeable that the predominant share of 
generation in the U.S. could be nuclear, an essential dispatchable 
resource, as small modular reactor technology matures and economies 
of scale produce lower costs, or it could be green hydrogen. It 
could even be fusion or some new technology currently either nascent 
or unknown. No one knows today. Building trillions of dollars of 
transmission on a prediction that intermittent wind and solar will 
be the predominant generating resource in 20 years is just a costly 
guess.
    \13\ See, e.g., Clean Energy Buyers Jan. 22, 2024 Comments 
(``Many of our businesses cannot grow without more clean generation 
resources . . . . States may miss out on economic growth 
opportunities without . . . access to the types of generation 
resources needed to attract growing and innovative industries.'') 
(emphases added). Among the signers of these comments were Amazon, 
Apple, eBay, Google, Green Impact Technologies, Meta, Microsoft, 
Nike, Rivian, Salesforce, Target, Walmart and several other 
multinational corporations. The FPA gives FERC no authority 
whatsoever to use the ``green energy'' purchasing preferences of 
privately owned, for-profit multinational corporations as the basis 
to impose a mandatory transmission planning and cost allocation rule 
that will cost consumers trillions of dollars. The FPA does not 
recognize such corporate preferences; indeed, the FPA forbids 
preferences. See also supra nn.5, 8, 10 and infra nn.15, 16, 67.
    \14\ The Wizard of Oz (Metro-Goldwyn-Mayer 1939).
    \15\ See, e.g., Catherine Morehouse, DOE launches effort to cut 
federal permitting for new power lines in half, PoliticoPRO, Apr. 
25, 2024 (``The [U.S. Dept. of Energy] program is the latest move by 
the Biden administration to speed up the . . . process for new 
transmission lines deemed critical to carrying dispersed wind and 
solar resources . . . . It also comes on the heels of an 
announcement from the EPA to tighten emissions standards for fossil-
fueled power plants--a move that will necessitate bringing more low-
carbon resources onto the power grid to meet growing demand as 
[fossil fuel] resources are forced offline. `DOE's work complements 
what our partners across the administration are doing . . . to 
deliver cleaner power . . . ,' Energy Secretary Jennifer Granholm 
told reporters . . . .'') (emphases added), https://subscriber.politicopro.com/article/2024/04/doe-launches-effort-to-cut-federal-permitting-for-new-power-lines-in-half-00154189; see 
also Catherine Morehouse, Energy regulator's exit may flummox 
Biden's green plans, Politico, Feb. 9, 2024 (``[FERC] is poised to 
lose its biggest climate advocate and potentially shut down one of 
the White House's best avenues to push its green policies. . . . 
That buildout is needed to accommodate . . . wind and solar projects 
that are critical to meeting the Biden administration's climate and 
clean energy goals.'') (emphases added), https://subscriber.politicopro.com/article/2024/02/energy-regulators-exit-may-flummox-bidens-green-plans-00140774; Molly Christian, US 
transmission ``in desperate need of an upgrade,'' Vice President 
Harris says, Megawatt Daily, Jan. 20, 2023 (``Achieving lofty US 
climate goals will require `thousands of miles of new high-voltage 
transmission lines all across our country,' US Vice President Kamala 
Harris said . . . . `To create our clean energy future, we must 
construct thousands of miles of new high-voltage transmission lines 
all across our country,' [Harris said].'') (emphases added), https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/electric-power/012023-us-transmission-in-desperate-need-of-an-upgrade-vice-president-harris-says; Alex Guill[eacute]n, Ben 
Lefebvre, Annie Snider, Kelsey Tamborrino, Catherine Morehouse, 
James Bikales, Biden administration eyes spring to finalize key 
climate regulations, PoliticoPro, Dec. 6, 2023 (``The Biden 
administration is planning to finalize several major energy and 
environmental regulations in the first half of 2024 . . . . That 
timeframe would help cement many of President Joe Biden's policy 
priorities in the event he does not win reelection . . . . One of 
the top [FERC] priorities . . . has been to finalize a rule on power 
line planning and cost allocation . . . . that is considered 
critical to unlocking new wind and solar resources.'') (emphases 
added), https://subscriber.politicopro.com/article/2023/12/biden-administration-plots-busy-spring-finalizing-key-climate-regulations-00130496. See also supra nn.5, 8, 10, 13 and infra nn.16, 67.
---------------------------------------------------------------------------

    5. Yet here's the legal rub with the final rule's pretextual 
agenda: Congress never voted to amend the FPA to direct or even 
allow FERC (which is supposed to be independent) to be what Energy 
Secretary Granholm describes as one of ``our partners across the 
administration'' in implementing this ``green energy'' 
transformation agenda.\16\ Such a sweeping policy agenda, which 
involves the transfer of literally trillions of dollars of wealth 
from consumers to special interests, is the epitome of a major 
question

[[Page 49568]]

of public policy under West Virginia v. EPA. The final rule clearly 
intends to socialize trillions of dollars of costs for the 
transmission necessary to pursue this transformational agenda, and 
unlike the NOPR,\17\ the final rule removes the principle that the 
states must consent to how and whether these massive costs are 
imposed on their consumers. The final rule goes to great lengths to 
use ``nothing to see here'' rhetoric,\18\ but looking behind the 
curtain at what is really going on makes it obvious that the final 
rule is pretextual and a blatant violation of the major questions 
doctrine.\19\ In its transparent effort to plan and fund trillions 
of dollars' worth of transmission to facilitate a preferred 
generation mix predominantly of wind and solar, both for public 
policies as well as corporate purchasing preferences, it is also 
``preferential'' and thus a clear violation of FPA section 206.
---------------------------------------------------------------------------

    \16\ See Brad Plumer, Energy Dept. Aims to Speed Up Permits for 
Power Lines, The New York Times, Apr. 25, 2024 (``[Biden] 
Administration officials are increasingly worried that their plans 
to fight climate change could falter unless the nation can quickly 
add vast amounts of grid capacity to handle more wind and solar 
power . . . . But experts say a rapid, large-scale expansion may 
ultimately depend on Congress.'') (emphases added), https://www.nytimes.com/2024/04/25/climate/energy-dept-speed-transmission.html. See also supra nn.5, 8, 10, 13, 15 and infra 
n.67.
    \17\ Bldg. for the Future Through Elec. Reg'l Transmission 
Planning & Cost Allocation & Generator Interconnection, Notice of 
Proposed Rulemaking, 87 FR 26504 (May 4, 2022), 179 FERC ] 61,028, 
at P 303 (2022) (NOPR).
    \18\ See, e.g., Final Rule, 187 FERC ] 61,068 at P 265 (``[W]hat 
matters is that this final rule aims to regulate and, in fact, does 
regulate only practices that affect the transmission of electric 
energy in interstate commerce, which are squarely within the 
Commission's jurisdiction under the FPA.'').
    \19\ See infra Section III.C. The final rule insists that it 
most assuredly does not implicate a major question of public policy, 
Final Rule, 187 FERC ] 61,068 at PP 275-279, much like Captain 
Renault in Casablanca is ``shocked, shocked to find gambling going 
on in here'' as he pockets his winnings. Casablanca (Warner Bros. 
Pictures 1942); but see Brad Plumer, Energy Dept. Aims to Speed Up 
Permits for Power Lines, Apr. 25, 2024 (quoting Rob Gramlich, the 
president of the consulting group Grid Strategies, `` `I've called 
[the final] rule the biggest energy policy in the country.' '') 
(emphasis added), https://www.nytimes.com/2024/04/25/climate/energy-dept-speed-transmission.html. See Catherine Morehouse, FERC to 
tackle ``historic'' transmission planning rule in May, PoliticoPRO, 
Apr. 18, 2024 (quoting Chairman Phillips describing the final rule 
as ``historic'' and the ``greatest development regarding electric 
transmission rules in the country in over a generation . . . .'') 
(emphases added).
---------------------------------------------------------------------------

    6. Put most simply, the final rule is a shell game that plays 
this way:

    Step One: For planning and cost allocation purposes, throw 
transmission projects that solve specific reliability problems or 
reduce congestion costs into the same bucket as projects designed to 
promote public policies or corporate ``green energy'' preferences 
and disguise the purpose of very different projects by re-labeling 
all projects in the new bucket with the innocuous-sounding name 
``Long-Term Regional Transmission Facilities.''
    Step Two: Mandate planning inputs that must be used in 
determining which projects get selected for regional plans, which 
starts the money flowing from consumers to developers before any 
state has even evaluated the need for, or cost of, the projects.
    Step Three: Mandate benefits that will ultimately affect the 
allocation of costs to consumers across a multi-state region. 
Combined with Steps One and Two, this makes consumers involuntary 
``beneficiaries'' who will then be forced to pay for projects that 
promote another state's public policy or corporate ``green power'' 
commitments.
    Step Four: Order all transmission providers to develop and file 
a cost allocation formula that will automatically be the default 
applicable to the entire bucket of Long-Term Regional Transmission 
Facilities.
    Step Five: Remove the NOPR's requirement that states must 
consent to the details of Steps One through Four before their 
consumers can be burdened with costs.

    7. Let's drill down on the details of the final rule's shell 
game. The final rule seeks to shift the costs of transmission 
projects whose purpose is to implement state or local public 
policies promoting wind and solar generation (commonly referred to 
as ``public policy projects'' or ``policy-driven projects'') and big 
corporation ``green energy'' preferences by putting those projects 
into the same regulatory bucket--both for planning and cost-
allocation purposes--with fundamentally different types of projects, 
those designed either to solve identified reliability problems (an 
engineering purpose, not a political or corporate purpose) or to 
provide quantifiable congestion cost savings (economic 
projects).\20\ The final rule labels all projects thrown into the 
new bucket as ``Long-Term Regional Transmission Facilities.'' \21\ 
Lumping policy-driven projects with the other very different types 
of projects is a sleight-of-hand move to disguise the costs of the 
policy-driven and corporate-driven projects that the final rule is 
promoting.\22\ Put most simply, reliability projects are driven by 
engineering, economic projects by economics, public policy projects 
by politicians, and corporate ``green energy'' policies by 
management and investors looking to maximize their returns or 
satisfy investment goals not recognized by the FPA.
---------------------------------------------------------------------------

    \20\ See, e.g., Final Rule, 187 FERC ] 61,068 at PP 1474 
(``[T]ransmission providers may not establish reliability, economic, 
or public policy transmission facility types as part of Long-Term 
Regional Transmission Planning and, therefore, may not establish 
Long-Term Regional Transmission Cost Allocation Methods based on 
reliability, economic, or public policy transmission facility 
types.'').
    \21\ Id.; see also id. PP 41, 250-251. In terms of labeling, at 
least Order No. 1000 described public policy projects honestly, as 
those that address ``transmission needs driven by Public Policy 
Requirements.'' See, e.g., Transmission Plan. & Cost Allocation by 
Transmission Owning & Operating Pub. Utils., Order No. 1000, 136 
FERC ] 61,051, at PP 2, 6 (2011), order on reh'g, Order No. 1000-A, 
139 FERC ] 61,132, order on reh'g & clarification, Order No. 1000-B, 
141 FERC ] 61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. 
FERC, 762 F.3d 41 (D.C. Cir. 2014) (South Carolina); see also id. PP 
11, 47.
    \22\ See PJM Interconnection, L.L.C., 187 FERC ] 61,012 (2024) 
(Christie, Comm'r, concurring at P 6 n.12) (``I note too that in 
PJM's [Regional Transmission Expansion Plan (RTEP)] review it offers 
a good example of how components of two different types of projects, 
a specific reliability solution and [State Agreement Approach (SAA)] 
Project, can be combined into one project that meets both needs. PJM 
describes in its filing how it solved a Window 3 specific 
reliability problem by combining that solution with an SAA project 
into an Incremental Multi-Driver Project . . . . This is a good 
example of how a multi-driver project should work: The reliability 
need is specific and would require a specific reliability solution 
that would, on its own, merit inclusion in the RTEP as a reliability 
project, and the SAA project, which is a supplemental--not a 
reliability--project, if feasible as it is in this specific case, 
can be planned in a way to meet the specific reliability need. Costs 
are allocated by PJM proportionately to each component of the 
project, one percentage allocated as a reliability project under 
PJM's formula, the other percentage wholly allocated to New Jersey 
for the SAA project.'') (internal citation omitted).
---------------------------------------------------------------------------

    8. Then to further promote its preferred policy projects, the 
final rule mandates planning criteria to be used in the planning of 
Long-Term Regional Transmission Facilities,\23\ including the 
``categories of factors'' that must be used in developing long-term 
planning scenarios \24\ and the list of benefits that must be used 
by planners in cost-benefit analyses.\25\ All of these mandatory 
features are transparently intended to ``pre-cook'' outcomes by 
manipulating the planning and evaluations that determine which 
projects are selected for regional transmission plans. (It is 
emblematic of the entire final rule that it did not include ``saves 
retail customers money'' as one of its mandatory benefits for 
evaluating projects.) \26\ The shell game's purpose is to ensure 
that preferential policy and corporate-driven projects are selected 
for regional transmission plans, which conveniently ensures that 
such projects are eligible for cost recovery through FERC's very 
generous (to developers, not consumers) formula rate mechanism. As 
further proof of the nature of the shell game, the final rule does 
not require transmission providers to identify the benefits used 
(other than those mandated), or how those benefits were specifically 
calculated, for cost allocation purposes.\27\ While the final rule 
insists that it is not mandating outcomes, when you manipulate the 
inputs of transmission planning, you are effectively mandating 
outputs.\28\
---------------------------------------------------------------------------

    \23\ Final Rule, 187 FERC ] 61,068 at Section III.
    \24\ Id. P 409. Among the mandatory categories of factors that 
the final rule dictates must be used to drive long-term planning 
throughout the entire country are, inter alia: (i) state and local 
laws affecting the resource mix, (ii) state and local laws on 
decarbonization, (iii) generator interconnection requests and 
withdrawals (another way to subsidize and prefer wind and solar 
developers which dominate the queues), and (iv) corporate, state and 
local government commitments to purchase ``green'' energy. Let me 
emphasize: these planning factors are mandatory for transmission 
providers to use, exposing the final rule's pretextual agenda for 
what it really is.
    \25\ Id. PP 3, 269, 719-720.
    \26\ See, e.g., id. P 720.
    \27\ Id. PP 1505-1511.
    \28\ Id. P 965.
---------------------------------------------------------------------------

    9. But that's not all; here comes the worst part of the shell 
game. The final rule then requires every transmission provider in 
America to file an ex ante cost allocation formula that is 
applicable to the whole bucket of projects,\29\ which now includes 
public and corporate-driven policy projects, in order to socialize 
the costs of these projects across the entire region, even when 
states in a region have never consented for their consumers to bear 
the costs of such projects. The final rule seeks to justify this

[[Page 49569]]

imposition of costs on non-consenting states by treating their 
consumers as ``cost causers'' or ``beneficiaries,'' \30\ which is 
justified by--now circle back to earlier in the shell game--the 
final rule's imposition of mandatory factors and benefits that must 
be used in the evaluations of projects.\31\ By lumping reliability 
and economic projects into the same planning bucket as public and 
corporate-driven policy projects, the final rule seeks to affix the 
tags of ``cost causer'' and ``beneficiary'' to all consumers in a 
multi-state region, to justify sticking them with costs even if 
their state officials never consented. So despite the final rule's 
disingenuous claims to the contrary,\32\ the intent and effect of 
this shell game is to enable the costs of corporate and public 
policy-driven projects to be socialized across an entire multi-state 
region and thus shifted onto consumers in states that never agreed 
to bear such costs. The explicit promise of the NOPR, that states 
would have to consent for their consumers to bear such costs, has 
been broken in this final rule.
---------------------------------------------------------------------------

    \29\ Id. P 1291.
    \30\ See, e.g., id. P 1305 n.2786 (``The cost causation 
principle requires costs to be allocated to those who cause the 
costs to be incurred and reap the resulting benefits.'') (emphasis 
added). A true statement on its face, but utterly disingenuous here. 
By mandating its preferred factors to be used in long-term planning, 
by mandating certain benefits to be used in evaluating projects, and 
by denying transparency as to what other benefits are used to 
evaluate projects and how benefits are being calculated, which 
drives cost allocation, the final rule effectively will hide the 
specific costs of policy and corporate-driven projects and essential 
information as to how costs are being calculated and allocated 
across a multi-state region. See also supra n.10.
    \31\ These key elements of the shell game respond almost 
precisely to the lobbying demands of various interest groups. See, 
e.g., Environmental Groups Dec. 8, 2023 Comments (``Transmission 
providers must perform long-term (at least 20-year), forward-looking 
assessments . . . . They must . . . [include] planning for state 
clean energy laws and policies, [and] scenarios with high renewable 
penetration . . . . Scenarios must evaluate all benefits that 
transmission projects would deliver and use these assessed benefits 
as a basis for project selection . . . . The Commission also should 
create a default cost allocation policy that meets this same 
standard . . . .'') (emphases added). Among others, the signers of 
this letter include: Advanced Energy United, American Clean Power 
Association, Clean Air Task Force, Earthjustice, Environmental 
Defense Fund, Evergreen Action, League of Conservation Voters, 
National Wildlife Federation, Natural Resources Defense Council 
(NRDC), Sierra Club, Union of Concerned Scientists, and WE ACT for 
Environmental Justice. See also supra nn.8, 10.
    \32\ Final Rule, 187 FERC ] 61,068 at P 267 (``[N]othing in this 
final rule requires states to subsidize other states' public 
policies and, indeed, this final rule requires . . . that 
transmission customers within a transmission planning region need 
only pay costs that are `roughly commensurate' with the benefits 
that transmission providers estimate they will receive from a 
transmission facility.'') (emphasis added).
---------------------------------------------------------------------------

    10. When I voted for the NOPR, I made it absolutely clear I was 
voting for it because it reflected a compromise in which public and 
corporate policy-driven projects could be incorporated into long-
term planning, but only if the states had the authority to consent 
both to planning criteria, including benefits used in cost-benefit 
analyses to evaluate projects and selection criteria, as well as to 
cost allocation.\33\ In my concurrence to the NOPR I wrote:
---------------------------------------------------------------------------

    \33\ NOPR, 179 FERC ] 61,028 (Christie, Comm'r, concurring at PP 
11-12, 14) (NOPR Concurrence); see also id. P 5.

    Even more importantly though, for these [long-term] projects, 
the NOPR proposes to require the regional planning entities to 
consult with and seek the agreement of the relevant states to both 
the selection criteria for these projects and to the regional cost 
allocation arrangements. State approval is especially important in a 
multi-state region, where different states have different policies. 
The NOPR proposes to provide the maximum opportunity for creativity 
and flexibility to the states and regional entities in developing 
the process for designing and approving regional selection criteria 
and cost allocation arrangements. States can agree to an ex ante 
formula for regional cost allocation of these types of projects--
such as, for example, the ``highway-byway'' formula approved by the 
SPP Regional State Committee--or states can agree to a process for a 
project-by-project agreement on cost allocation among one or several 
states--such as, for example, the State Agreement Approach in PJM--
or states may choose some combination of both.\34\
---------------------------------------------------------------------------

    \34\ Id. P 11 (emphasis in original and added).
---------------------------------------------------------------------------

    And let me emphasize . . . no individual state's consumers can 
be forced to bear the costs of another state's policy-driven project 
or element of a project against its consent.\35\
---------------------------------------------------------------------------

    \35\ Id. P 12 (emphasis added).
---------------------------------------------------------------------------

    The bottom line for me is this: I believe that elevating the 
role in planning and cost allocation of state regulators--who are, 
as a group, deeply concerned about the monthly bills paid by 
consumers, of which transmission is a rapidly growing component--
will make it more likely, not less, that necessary transmission can 
get built while ensuring that rates resulting from these types of 
policy-driven projects will not be unjust and unreasonable, which 
they clearly have the potential to be.\36\
---------------------------------------------------------------------------

    \36\ Id. P 14 (emphasis in original and added).

    The other members of the Commission, including the then-Chairman 
and both other members of today's Commission, also recognized the 
NOPR as a compromise.\37\
---------------------------------------------------------------------------

    \37\ From the Transcript of Apr. 21, 2022 Commission Open 
Meeting (April 2022 Open Meeting Tr.):
    ``CHAIRMAN GLICK: And I also want to finally thank my 
colleagues. I think this [NOPR] is a really good product. It is a 
product of a lot of discussion, a lot of compromise--which is what 
the Commission is all about--and I think all of us can say we did 
not get everything in there, in the document, that we would like, 
but I think we all got enough in there and I think we achieved a 
significant and really remarkable level of consensus. And I think 
that is very notable today.'' April 2022 Open Meeting Tr. 44:17-24 
(emphases added).
    ``COMMISSIONER CLEMENTS: As the Chairman [stated] that reaching 
agreement on this proposal was not easy. I can say with confidence 
that none of us voting for it would have written it this way if we 
were writing on our own. But I am proud that it is a bipartisan 
effort, and I am thankful to my colleagues for proactively engaging 
and for thinking creatively to find alignment.'' Id. at 55:17-23 
(emphasis added).
    ``COMMISSIONER CHRISTIE: But I think on balance the positive 
aspects of this [NOPR], particularly for state regulators at the 
heart of planning and cost allocation for these types of projects, 
changing [CWIP] to AFUDC[,] I think those are positive, big steps 
forward for me on balance and it makes it worth voting for this 
[NOPR].'' Id. at 67:15-20 (emphasis added).
    ``COMMISSIONER PHILLIPS: I would first like to thank my 
colleagues for working collaboratively with me on this. . . . I 
don't think I have ever been a part of a process more collaborative 
than this process that we had in this NOPR.'' Id. at 67:24-25, 68:6-
8.
    To those who say that many elements of this final rule were also 
in the NOPR for which I voted, such as, for example, the mandatory 
categories of factors, I would respond: If I agree to get a root 
canal with anesthetic, but learn upon arrival at the dentist's 
office that I can still get the root canal but with no anesthetic, 
that is not the original deal.
---------------------------------------------------------------------------

    11. Yet the many fundamental changes made in this final rule 
\38\ subvert and violate that compromise. Of particular importance 
to my willingness--and that of many state regulator organizations--
to support the compromise NOPR, was the explicit principle of state 
agreement to planning and selection criteria and cost allocation 
embodied in the NOPR. The final rule, however, denies what the NOPR 
promised: it denies state agreement to selection criteria,\39\ it 
denies state agreement to the benefits to be used in evaluating 
projects for selection in regional plans and ultimate selection 
(which can start the money flowing from consumers to developers 
before a state siting or construction permit has even been 
issued),\40\ and most importantly, it denies state agreement to cost 
allocation for public policy and corporate-driven projects.\41\ The 
State Agreement Approach, used successfully in PJM for over a 
decade, is effectively terminated by the final rule. The final rule 
says that, even if states in a planning region agree, a ``State 
Agreement Process'' cannot be the sole chosen method for allocating 
costs of these projects; the transmission provider's own ex ante 
formula must be the default method, regardless of whether states 
have agreed to it.\42\ In addition to a de facto termination of the 
PJM State Agreement Approach, the final rule could call into 
question mechanisms to facilitate the states' role in cost 
allocation that have been used in other RTOs and ISOs for years, 
including in SPP and MISO.\43\
---------------------------------------------------------------------------

    \38\ See infra Section II.
    \39\ Final Rule, 187 FERC ] 61,068 at P 996.
    \40\ Id. PP 3, 269, 719-720, 903.
    \41\ Id. PP 1291-1292, 1294, 1354, 1356 n.2895, 1359, 1367, 
1429.
    \42\ Id. To be clear, even if the states agreed on an 
alternative ex ante cost allocation method, or if they agreed on a 
cost allocation method under the State Agreement Process, the 
transmission provider could choose to file it but also could ignore 
it. See infra n.195.
    \43\ See Final Rule, 187 FERC ] 61,068 at PP 1291-1292, 1294, 
1354, 1356 n.2895, 1359, 1367, 1429.
---------------------------------------------------------------------------

    12. And let's get real: Telling the states to negotiate for an 
alternative cost allocation when the transmission provider's ex ante 
formula has already been designated as the default is no real 
negotiation at all. The final rule points a regulatory gun at 
states' heads redolent of The Godfather: \44\ ``Here's an offer

[[Page 49570]]

you can't refuse.'' And contrary to NARUC's eminently reasonable and 
practical request,\45\ the final rule even requires only one 
Engagement Period for states to negotiate a different cost 
allocation from the transmission providers' ex ante cost allocation 
before that ex ante cost allocation becomes the default.\46\ It is 
obvious that the final rule intends to lock in each transmission 
provider's own ex ante formula for many years to come and to deny 
states any avenue to challenge it even as times and circumstances 
change, no matter how high their consumers' power bills escalate due 
to rising transmission costs.
---------------------------------------------------------------------------

    \44\ The Godfather (Paramount 1972).
    \45\ Final Rule, 187 FERC ] 61,068 at P 1255 (``NARUC requests 
that the Commission provide a mechanism for future review of cost 
allocation methods for Long-Term Regional Facilities.'' (citing 
NARUC Initial Comments at 49-50)).
    \46\ Id. P 1368; see also id. P 1291.
---------------------------------------------------------------------------

    13. Essentially, the final rule replaces the NOPR's principle of 
requiring state agreement to selection criteria, benefits, and cost 
allocation with a charade of suggesting to transmission providers 
that they ``consult with and seek support'' from the states--while 
paradoxically ``clarifying'' that transmission providers do not 
actually need to obtain state consent--and the final rule uses other 
empty phrases such as allowing states to ``inform'' or ``provide 
input on'' the evaluation process and cost allocation.\47\ But the 
final rule's real attitude towards the states and state regulators 
is embodied in this airily regal but perhaps unintentionally 
straightforward pronouncement: ``[W]e do not agree that the views of 
state regulators regarding the appropriate cost allocation approach 
are dispositive.'' \48\
---------------------------------------------------------------------------

    \47\ See, e.g., id. PP 268, 959, 994, 996-997, 1456.
    \48\ Id. P 1363 (citation omitted). A different attitude towards 
state regulators was apparent in the NOPR. See April 2022 Open 
Meeting Tr. 46:10-16 (``CHAIRMAN GLICK: [This] NOPR proposes to give 
the states a much more significant role in addressing cost 
allocation. I think it helps to have Commissioner Christie and 
Commissioner Phillips, two of our five Commissioners are former 
state regulators, and I think that really helps to have their 
background and their interest.'').
---------------------------------------------------------------------------

    14. The principle of cost allocation that was described in my 
concurrence to the NOPR--that states must consent to regional cost 
allocation of corporate and public policy-driven projects--reflects 
a core principle of American democracy: fairness. In this ratemaking 
context, fairness means that the people have the right to choose the 
policymakers who impose costs on them, so they can hold them 
accountable. This final rule is unfair because it gives FERC and the 
transmission providers it regulates the power to impose costs on 
consumers to pay for transmission driven by huge corporations and 
politicians in states other than theirs, and for whom they never 
voted. The final rule truly subverts the principle that the people, 
through their state's policymakers, must consent to bear the costs 
of another state's politicians and their policy choices, or the 
energy purchasing preferences of corporate managers and investors.
    15. And from the consumer standpoint, the timing of this rule 
could not be worse. American residential customers will pay about 
16.23 cents per kWh next year, the highest retail power cost for 
consumers in almost three decades.\49\ Unlike in years past, fuel 
costs are not the primary driver of these mounting prices to 
consumers; rather, transmission is. Transmission costs are rising 
rapidly, becoming an ever more burdensome part of consumers' power 
bills.\50\ To cite just one major example, in PJM, the largest RTO 
by load in the country, the transmission component of wholesale 
power costs has essentially tripled over the past decade, from just 
$5.65/MWh in 2013 to $16.54/MWh last year. Transmission now 
constitutes almost a third of wholesale power costs, up from 
approximately 10% just a decade earlier.\51\ In 2020, the PJM Market 
Monitor reported that the cost of transmission exceeded the cost of 
capacity for the first time.\52\ Nationally, transmission rate base 
nearly tripled in a decade,\53\ and--assuming an 8.2% year-over-year 
growth rate, which occurred in 2022--is on track to double again in 
the next nine years, even without this rule's intent to spend 
trillions more on transmission. According to the U.S. Energy 
Information Administration, already one in three American households 
reports difficulty in paying their power bills.\54\
---------------------------------------------------------------------------

    \49\ See Robert Walton, U.S. electricity prices outpace annual 
inflation, Utility Dive, Mar. 13, 2024 (``U.S. electricity prices 
rose 3.6% over the last 12 months, outstripping the broader 
inflation rate of 3.2%, the Bureau of Labor Statistics reported 
Tuesday. And experts say there is little chance for near-term 
consumer relief. . . . And federal policies aimed at electrifying 
end uses and reducing emissions could lead to even higher prices, 
Travis Fisher, director of energy and environmental policy studies 
at the Cato Institute, told a House subcommittee Wednesday.'') 
(emphasis added), https://www.utilitydive.com/news/us-electricity-prices-rise-customer-eia-outlook/710113/.
    \50\ See, e.g., Zach Bright, Electricity prices rise faster than 
inflation, EnergyWire, Apr. 12, 2024 (``The Bureau of Labor 
Statistics found that electricity prices rose 5 percent over the 
past year. That's higher than the overall consumer price index (3.5 
percent) and any other single commodity, like food . . . and 
gasoline . . . .'') (emphases added), https://www.eenews.net/articles/electricity-prices-rise-faster-than-inflation/; Electricity 
Inflation 30% Higher Than CPI Over Last 12 Months'' Electricity 
Transmission Competition Coalition, Apr. 10, 2024 (``Electricity 
inflation remains the highest consumer goods cost among the items in 
the Consumer Price Index according to the latest release of data by 
the Bureau of Labor Statistics. . . . The price of electricity has 
soared because of the accelerating cost of transmission . . . .'') 
(emphasis added), https://electricitytransmissioncompetitioncoalition.org/electricity-inflation-30-higher-than-cpi-over-last-12-months/.
    \51\ State of the Market Report 2023, PJM Market Monitor, Vol. 
II, Section 1, at 18, Table 1-9, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2023.shtml; State of the Market Report 2014, PJM Market Monitor, 
Vol. II, Section 1, at 16, Table 1-9, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2014/2014-som-pjm-volume2-sec1.pdf; State of the Market Report 2013, PJM 
Market Monitor, Vol. II, Section 1, at 12, Table 1-9, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2013/2013-som-pjm-volume2-sec1.pdf; see also State of the Market Report 
2019, PJM Market Monitor, Vol. II, Section 1, at 18, Table 1-10, 
https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2019/2019-som-pjm-sec1.pdf.
    \52\ State of the Market Report 2020, PJM Market Monitor, Vol. 
I, at 17, Table 8, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2020/2020-som-pjm-vol1.pdf.
    \53\ See Jim O'Reilly, Led by AEP and Duke, transmission growth 
poised to rebound from dip in 2022, S&P Global Market Intelligence, 
Nov. 15, 2023 (showing bar graph providing that aggregate 
transmission rate base grew from $61.4 billion in 2012 to $163.1 
billion in 2022), https://www.spglobal.com/marketintelligence/en/news-insights/research/led-by-aep-and-duke-transmission-growth-poised-to-rebound-from-dip-in-2022. Under this Commission's rate 
recovery protocols, the transmission owner gets to collect the 
annual costs of transmission depreciation from rate base, plus a 
profit, known as Return on Equity, or ``ROE,'' often inflated by the 
many incentives the Commission typically approves, as well as 
operations and maintenance costs. As any utility regulator knows, 
``what goes into rate base comes out in customers' bills.'' So a 
rapidly rising rate base means rapidly growing consumers bills.
    \54\ Amanda Durish Cook & Tom Kleckner, Overheard at 10th Annual 
GCPA MISO-SPP Forum, RTO Insider, Mar. 12, 2024, https://www.rtoinsider.com/73311-overheard-10th-annual-gcpa-miso-spp-forum/.
---------------------------------------------------------------------------

    16. Don't fall for the absurd claim that this rule will somehow 
save consumers money through more holistic or efficient planning, a 
vacuous bureaucratic argument divorced from reality.\55\ The sheer 
amount of new transmission costs that the final rule inflicts on 
consumers--and special interest groups want--is staggering, measured 
in the trillions,\56\ not `merely' hundreds of billions, of 
dollars.\57\ And these staggering costs will not be incurred to 
provide consumers with reliable power, but to serve political and 
corporate agendas. It is truly Orwellian newspeak \58\ to claim that 
adding multiple trillions of dollars in transmission costs to 
consumer's bills will somehow ``save'' consumers money (even Orwell 
would be impressed at the sheer audacity of such a claim).
---------------------------------------------------------------------------

    \55\ See, e.g., Final Rule, 187 FERC ] 61,068 at P 89.
    \56\ See supra n.7.
    \57\ Illinois Senator Everett Dirksen is said to have once 
quipped, ``In Washington, a billion here, a billion there, and 
pretty soon you're talking about real money.'' The final rule 
updates his quip to a ``trillion here, a trillion there . . . .''
    \58\ George Orwell, 1984 (first published by Secker & Warburg 
1949).
---------------------------------------------------------------------------

    17. If FERC were seriously interested in saving consumers' 
money, it would be acting to rein in the wide array of transmission 
incentives regularly handed out to transmission developers that are 
direct transfers of wealth from consumers to developers (long known 
as ``FERC candy''),\59\

[[Page 49571]]

and acting to reform the automatic awarding of the presumption of 
prudence in formula rate proceedings. Literally nothing is being 
done about these forms of consumer exploitation in this final rule; 
instead, the final rule goes in the exact opposite direction.
---------------------------------------------------------------------------

    \59\ See, e.g., Office of Ohio Consumers' Counsel v. Am. Elec. 
Power Serv. Corp., 181 FERC ] 61,214 (2022) (Christie, Comm'r, 
concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-addressing-rto-adders-related-e-2-ohio; MISO, 181 FERC ] 61,094 (2022) (Christie, Comm'r, concurring 
at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-urging-action-re-rto-participation-adder-docket; Mary O'Driscoll, FERC approves incentives for AEP, Allegheny 
grid projects, Greenwire, July 21, 2006 (``The approvals came as the 
commission finalized rules intended to promote transmission-grid 
additions that outline specific rate and other incentives that FERC 
will consider for future construction projects--the `FERC candy' 
that critics contend gives the utilities incentives but not much in 
the way of corresponding requirements.'') (emphasis added), https://subscriber.politicopro.com/article/eenews/2006/07/21/ferc-approves-incentives-for-aep-allegheny-grid-projects-234508.
---------------------------------------------------------------------------

    18. To add further insult to consumers' injury, the final rule 
walks back the NOPR proposal that would have denied transmission 
developers the Construction Work in Progress (CWIP) incentive.\60\ I 
have written many times that CWIP is simply unfair. CWIP is unfair 
because it makes consumers the unwilling ``bank'' for developers, 
but unlike a real bank, consumers don't get paid any interest and 
this Commission forces them to make involuntary loans.\61\ Removing 
CWIP was strongly supported by those concerned with protecting 
consumers: by state regulators, by public power providers, and by 
state consumer advocates.
---------------------------------------------------------------------------

    \60\ Final Rule, 187 FERC ] 61,068 at P 1547.
    \61\ Baltimore Gas & Elec. Co., 187 FERC ] 61,030 (2024) 
(Christie, Comm'r, dissenting at P 7), https://www.ferc.gov/news-events/news/commissioner-christies-dissent-award-incentives-exelon-er24-1313; PJM Interconnection, L.L.C., 185 FERC ] 61,200 (2023) 
(Christie, Comm'r, concurring at P 3), https://www.ferc.gov/news-events/news/e-7-commissioner-christies-concurrence-exelons-application-abandoned-plant; The Potomac Edison Co., 185 FERC ] 
61,083 (2023) (Christie, Comm'r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-potomac-edisons-abandoned-plant; Montana-Dakota Utils. 
Co., 185 FERC ] 61,015 (2023) (Christie, Comm'r, concurring at P 3), 
https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-montana-dakota-utilities-co-regarding; Midcontinent 
Indep. Sys. Operator, Inc., 184 FERC ] 61,136 (2023) (Christie, 
Comm'r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-midcontinent-independent-system-operator-inc-0; GridLiance W. LLC, 184 FERC ] 61,129 (2023) 
(Christie, Comm'r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-gridliance-west-regarding-transmission; Midcontinent Indep. Sys. Operator, Inc., 184 
FERC ] 61,034 (2023) (Christie, Comm'r, dissenting at P 8), https://www.ferc.gov/news-events/news/commissioner-christies-dissent-award-transmission-incentives-nipsco-er23-1904; Otter Tail Power Co., 183 
FERC ] 61,121 (2023) (Christie, Comm'r, concurring at P 8), https://www.ferc.gov/news-events/news/e-18-commissioner-christies-concurrence-otter-tail-power-company-regarding; LS Power Grid Cal., 
LLC, 182 FERC ] 61,201 (2023) (Christie, Comm'r, concurring at P 3), 
https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-ls-power-grid-regarding-transmission-incentives; Nev. 
Power Co., 182 FERC ] 61,186 (2023) (Christie, Comm'r, concurring at 
P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-nv-energy-regarding-transmission-incentives; The Dayton 
Power and Light Co., 182 FERC ] 61,147 (2023) (Christie, Comm'r, 
concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-dayton-power-and-light-company-regarding; Midcontinent Indep. Sys. Operator, Inc., 182 FERC ] 
61,039 (2023) (Christie, Comm'r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-midcontinent-independent-system-operator-inc; NextEra Energy 
Transmission Sw., LLC, 180 FERC ] 61,032 (2022) (Christie, Comm'r, 
concurring at P 3) (July 2022 Concurrence), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-nextera-energy-transmission-southwest-llc; NextEra Energy Transmission Sw., LLC, 
178 FERC ] 61,082 (2022) (Christie, Comm'r, concurring at P 3) 
(February 2022 Concurrence), https://www.ferc.gov/news-events/news/commissioner-mark-c-christie-concurrence-nextera-energy-transmission-southwest-llc.
---------------------------------------------------------------------------

    19. In my concurrence to the NOPR, I wrote:

    CWIP is the award of cost recovery of construction costs during 
the pre-construction and construction phases to the developer. CWIP 
is, of course, passed through as a cost to consumers, making 
consumers effectively an involuntary lender to the developer. . . . 
Consumers should be protected from paying CWIP costs during this 
potentially long period before a project actually enters service, if 
it ever does. This NOPR proposal represents a major step forward in 
consumer protection and is a big reason I am voting for it.\62\
---------------------------------------------------------------------------

    \62\ NOPR Concurrence at P 15.

    By walking back the proposed CWIP denial, the final rule results 
in a major step backwards for consumers.\63\
---------------------------------------------------------------------------

    \63\ By doing nothing about the consumer-paid ``FERC candy'' 
incentives that this Commission regularly hands out to developers, 
and even removing the provisions dialing back the CWIP incentive--
and with its overall aim to pile trillions of dollars of additional 
costs for big corporate and politically-driven transmission on 
consumers, which will largely flow to the increased profits of wind, 
solar and transmission developers--the final rule could be the 
inspiration for one of the great country and western songs ``Lord 
Have Mercy on the Working Man.'' Warner Bros. Nashville 1992 
(``Why's the rich man busy dancing while the poor man pays the band? 
Oh they're billing me for killing me, Lord have mercy on the working 
man!'').
---------------------------------------------------------------------------

    20. In yet another major slap at consumers, the final rule seeks 
to shift the substantial costs caused by generation developers' 
interconnection requests from developers to consumers.\64\ It does 
this by ordering transmission providers to revise their regional 
transmission planning processes to evaluate for selection regional 
transmission facilities that address identified interconnection-
related transmission needs, and the final rule specifies that if 
such a facility is selected, its costs will be regionally 
allocated.\65\ It also does this by ordering transmission providers 
to incorporate generator interconnection requests and withdrawals in 
their long-term transmission planning.\66\ These are only schemes to 
shift interconnection costs from developers to consumers and will 
result in rates that are blatantly unjust, unreasonable, unduly 
discriminatory and preferential. Similarly, the final rule also 
inappropriately shifts preferential corporate-driven project costs 
onto all other consumers, who may disagree with, or even compete 
against, the corporate customers imposing their preferences. These 
provisions alone render the final rule's replacement rate unlawful 
under FPA section 206.
---------------------------------------------------------------------------

    \64\ Final Rule, 187 FERC ] 61,068 at PP 472, 1106-1107, 1126, 
1145.
    \65\ Id. PP 125, 1106-1107, 1126, 1145. Under ``participant 
funding'' mechanisms the generation developer pays the costs of the 
network upgrades costs it causes and consumers do not pay, which is 
only fair. The Commission's Order No. 2023 did not violate this 
principle. See generally Improvements to Generator Interconnection 
Procs. & Agreements, Order No. 2023, 88 FR 61014 (Sept. 6, 2023), 
184 FERC ] 61,054, order on reh'g, 185 FERC ] 61,063 (2023), order 
on reh'g, Order No. 2023-A, 89 FR 27006 (Apr. 16, 2024), 186 FERC ] 
61,199 (2024). This final rule clearly intends to undermine this 
principle by moving interconnection costs into regional transmission 
planning and cost allocation, so consumers get stuck with the costs 
of interconnection, even though it is developers who profit from 
interconnection.
    \66\ Final Rule, 187 FERC ] 61,068 at P 472.
---------------------------------------------------------------------------

    21. This Commission is, by statute, supposed to be independent 
of any presidential administration, but it has failed to defend that 
independence in this final rule, which is a naked pretext to enact 
the current administration's ``net zero 2035'' policy agenda, as 
well as to serve corporate agendas, and those of other profit-
seeking special interests.\67\ In failing to act independently,\68\ 
this Commission has broken faith with state regulators and, even 
more importantly, broken faith with tens of millions of American 
consumers, who could be forced to bear literally trillions of 
dollars in costs for transmission lines to serve political, 
corporate and other special-interest agendas. This will not produce 
just and reasonable rates and is grossly unfair. This final rule is 
a dereliction of the Commission's duty under the FPA to protect 
consumers and far exceeds its authority under that statute.
---------------------------------------------------------------------------

    \67\ See Miranda Willson, Heather Richards, Brian Dabbs, Biden 
regulatory plan set to shake up energy sector, Energywire, Dec. 7, 
2023 (``The White House released a regulatory plan Wednesday that 
could shape President Joe Biden's energy legacy . . . . [T]wo of the 
Federal Energy Regulatory Commission's most high-profile proposed 
transmission rules are listed on the [White House] agenda . . . . 
One of those FERC rules would change how large electric power lines 
are planned and paid for . . . .'') (emphases added), https://www.eenews.net/articles/biden-regulatory-plan-set-to-shake-up-energy-sector/; see also supra nn.5, 8, 10, 13, 15, 16.
    \68\ In the very recent past, this Commission stood up for its 
independence despite intense pressure from a presidential 
administration. See, e.g., Steven Mufson, Trump-appointed regulators 
reject plan to rescue coal and nuclear plants, The Washington Post, 
Jan. 8, 2018 (explaining that ``[t]he independent five-member 
commission [that rejected the president's proposal] includes four 
people appointed by President Trump''), https://www.washingtonpost.com/news/energy-environment/wp/2018/01/08/trump-appointed-regulators-reject-plan-to-rescue-coal-and-nuclear-plants/.
---------------------------------------------------------------------------

II. The Final Rule Is Fundamentally Different From the NOPR

    22. The very essence of due process is notice and opportunity to 
be heard. Given the large number of fundamental changes to the NOPR, 
the final rule should be viewed as effectively a second NOPR and 
clearly should have been put out for additional public comment on 
the many fundamental changes. Because it was not, deliberately so, 
this final rule invites a court to remand with instructions for the 
Commission to give the public an opportunity to comment on the many 
fundamental changes from the NOPR.
    23. The final rule issuing today is not the NOPR for which I 
voted. This pretextual final

[[Page 49572]]

rule is fundamentally different in numerous ways, yet these 
fundamental changes were never put out for additional public 
comment.\69\ These fundamental changes include, but are not limited 
to, the following:
---------------------------------------------------------------------------

    \69\ The process leading to the adoption of Order No. 1000, the 
final rule's direct predecessor but one not nearly as sweeping in 
its application, was described in paragraphs 22 through 24 of that 
order. Order No. 1000, 136 FERC ] 61,051 at PP 22-24.
---------------------------------------------------------------------------

    24. The Final Rule Imposes Preferential Policy and Corporate-
Driven Project Costs on Consumers in Non-Consenting States: Contrary 
to the NOPR, the final rule requires the filing of one or more ex 
ante cost allocation methods to apply to selected Long-Term Regional 
Transmission Facilities, setting up a mechanism to impose a regional 
cost allocation for preferential policy and corporate-driven 
projects when states do not consent, either by approving a cost 
allocation proposed by transmission owners, by RTOs, or one directly 
imposed by the Commission itself.\70\ This is a fundamental change 
from the NOPR.
---------------------------------------------------------------------------

    \70\ Final Rule, 187 FERC ] 61,068 at PP 1291-1292.
---------------------------------------------------------------------------

    25. The Final Rule Mandates Planning Criteria and Purported 
Benefits: Contrary to the NOPR, the final rule mandates a specific 
set of planning criteria, and specifically purported benefits, that 
must be used by transmission providers for these preferential policy 
and corporate-driven projects.\71\ Mandating the planning criteria 
and benefits is simply a way of ``pre-cooking'' outcomes and is 
directly contrary to the NOPR's explicit language that said it was 
not mandating outcomes, only a planning process.\72\ This is a 
fundamental change from the NOPR.
---------------------------------------------------------------------------

    \71\ Id. PP 3, 269, 719-720.
    \72\ See NOPR, 179 FERC ] 61,028 at PP 9, 245.
---------------------------------------------------------------------------

    26. The Final Rule Abandons Regional Cost Allocation Principle 
(6): Contrary to the NOPR,\73\ the final rule abandons the regional 
cost allocation principle \74\ that would allow a transmission 
planning region to use different cost allocation methods for 
different types of facilities in a regional transmission plan. The 
final rule replaces this flexibility with a one-size-fits-all 
model.\75\ This is a fundamental change from the NOPR.
---------------------------------------------------------------------------

    \73\ See id. P 302.
    \74\ See Order No. 1000, 136 FERC ] 61,051 at P 685.
    \75\ Final Rule, 187 FERC ] 61,068 at P 1469 (``[U]nlike under 
Order No. 1000, transmission providers cannot adopt different Long-
Term Regional Transmission Cost [A]llocation Methods for different 
types of Long-Term Regional Transmission Facilities, such as those 
needed for reliability, congestion relief, or to achieve Public 
Policy Requirements.'') (emphasis added); see also id. P 1474.
---------------------------------------------------------------------------

    27. The Final Rule Effectively Eliminates a Voluntary State 
Agreement Process: Contrary to the NOPR, the final rule effectively 
eliminates the use of a voluntary State Agreement Process, such as 
the one that has been used by PJM since Order No. 1000.\76\ Not only 
is this directly contrary to comments filed by state regulators,\77\ 
but it represents a fundamental change from the NOPR.
---------------------------------------------------------------------------

    \76\ See, e.g., id. PP 1291-1292. A more detailed discussion on 
how the final rule effectively guts the State Agreement Process is 
in infra Section IV.B.1.b.
    \77\ See Final Rule, 187 FERC ] 61,068 at P 1323 (citations 
omitted).
---------------------------------------------------------------------------

    28. The Final Rule Leaves the CWIP Incentive Intact: Contrary to 
the NOPR, the final rule walks back the proposal not to allow use of 
the CWIP incentive.\78\ This NOPR provision was one of the strongest 
consumer protection features.\79\ Instead, the Commission leaves the 
CWIP incentive intact and that consumer protection has been removed. 
This is a fundamental change from the NOPR.
---------------------------------------------------------------------------

    \78\ Id. P 1547.
    \79\ See NOPR, 179 FERC ] 61,028 at P 333; NOPR Concurrence at P 
15.
---------------------------------------------------------------------------

    29. The Final Rule Makes Local Transmission Planning Less 
Transparent: Contrary to the NOPR,\80\ the final rule makes 
fundamental changes to the NOPR's section on Local Transmission 
Planning.\81\ Local Transmission Planning disclosure and 
transparency requirements no longer apply to asset management 
projects. This is a fundamental change from the NOPR.
---------------------------------------------------------------------------

    \80\ See NOPR, 179 FERC ] 61,028 at PP 400-413.
    \81\ Final Rule, 187 FERC ] 61,068 at P 1625.
---------------------------------------------------------------------------

III. The Final Rule Exceeds FERC's Authority Under the FPA

    30. The final rule's determination that its reforms are within 
the Commission's legal authority under section 206 is flat 
wrong.\82\ The final rule is just a pretext for enacting the current 
presidential administration's ``net zero 2035'' policy agenda, as 
well as that of large corporate buyers of preferential power and 
other special interests.\83\ As such, the final rule goes far beyond 
the scope of Order No. 1000, as affirmed by South Carolina,\84\ and 
exceeds FERC's authority under the FPA. Specifically, the final rule 
requires transmission providers to incorporate into their 
transmission planning seven categories of factors and a set of seven 
required benefits to drive the construction of projects to achieve 
the final rule's preferred substantive outcomes: namely, the 
development and purchase of certain preferred generation resources. 
In so doing, the final rule seeks to recast FERC as a national IRP 
planner with extraordinary powers to oversee and dictate to all 
public utility transmission providers in the country, in RTO and 
non-RTO regions, detailed instructions on planning transmission that 
fulfills the current administration's preferred policies as to the 
types of generation it wants to build, and to charge consumers 
trillions of dollars for this transmission. This transformation of 
FERC into a national IRP planner violates FPA section 201 by 
infringing on the authority of the states, and it reflects a 
tremendous expansion of the agency's power not permitted under the 
major questions doctrine.
---------------------------------------------------------------------------

    \82\ See id. PP 86, 253.
    \83\ See supra Section I.
    \84\ 762 F.3d 41.
---------------------------------------------------------------------------

A. South Carolina Does Not Provide a Legal Justification for the 
Commission's Actions in the Final Rule

    31. In arguing that the Commission is acting within its legal 
authority under section 206 to adopt its reforms for Long-Term 
Regional Transmission Planning, today's final rule heavily relies on 
South Carolina.\85\ However, given the significant differences 
between Order No. 1000 and the final rule, that reliance is grossly 
misplaced.
---------------------------------------------------------------------------

    \85\ E.g., Final Rule, 187 FERC ] 61,068 at PP 86, 253, 256 & 
n.604, 257 & n.605, 277.
---------------------------------------------------------------------------

    32. Order No. 1000 included reforms intended to ensure that the 
transmission planning and cost allocation requirements embodied in 
the Commission's pro forma open access transmission tariff could 
support the development of more efficient or cost-effective 
transmission facilities.\86\ Such reforms included, inter alia, the 
requirement for transmission providers to participate in regional 
planning processes; the requirement that such regional transmission 
planning processes must consider transmission needs that are driven 
by public policy requirements; and the requirement that transmission 
providers develop a regional cost allocation method for new 
transmission facilities selected in the regional transmission plan 
for purposes of cost allocation, with such method having to satisfy 
six regional cost allocation principles.
---------------------------------------------------------------------------

    \86\ Id. P 16 (citing Order No. 1000, 136 FERC ] 61,051 at P 3).
---------------------------------------------------------------------------

    33. But Order No. 1000 was built on what may be a foundation of 
sand known as ``Chevron deference.'' As the D.C. Circuit explained 
in South Carolina, ``[t]he court reviews challenges to the 
Commission's interpretation of the FPA under the familiar two-step 
framework of [Chevron].'' \87\ The D.C. Circuit further explained 
that, ``[i]f the court determines `Congress has directly spoken to 
the precise question at issue,' and `the intent of Congress is 
clear, that is the end of the matter.' '' \88\ This is often 
referred to as ``Chevron step one.'' \89\ The court stated, in 
contrast, that ``[i]f . . . `the statute is silent or ambiguous with 
respect to the specific issue,' then the court must determine 
`whether the agency's answer is based on a permissible construction 
of the statute.' '' \90\ This is often referred to as ``Chevron step 
two.'' \91\ The D.C. Circuit explained that ``Chevron step two . . . 
requires [the court] to uphold an agency's reasonable interpretation 
of a statute it administers.'' \92\ That is, the court applies 
Chevron deference.\93\
---------------------------------------------------------------------------

    \87\ South Carolina, 762 F.3d at 54 (citing Chevron, 467 U.S. 
837).
    \88\ Id. (quoting Chevron, 467 U.S. at 842).
    \89\ See, e.g., id. at 84.
    \90\ Id. at 54 (quoting Chevron, 467 U.S. at 843).
    \91\ See, e.g., id. at 58-59 (citing Chevron, 467 U.S. at 843), 
84.
    \92\ Id. at 76 (citing Nat'l Cable & Telecomms. Ass'n v. Brand X 
internet Servs., 545 U.S. 967, 982 (2005)).
    \93\ Note, however, that the U.S. Supreme Court is revisiting 
the 40-year-old doctrine and has indicated that it may narrow or 
overturn it in the pending cases, Loper Bright Enterprises v. 
Raimondo, No. 22-451 (argued Jan. 17, 2024) and Relentless v. Dep't 
of Commerce, No. 22-1219 (argued Jan. 17, 2024).
---------------------------------------------------------------------------

    34. In South Carolina, the D.C. Circuit applied Chevron 
deference to the Commission's interpretation of FPA section 206 in 
affirming many aspects of Order No.

[[Page 49573]]

1000, including its planning mandates.\94\ In affirming the planning 
mandates, the court emphasized that Order No. 1000 focused on 
process and not substantive outcomes:
---------------------------------------------------------------------------

    \94\ See South Carolina, 762 F.3d at 56-59 (internal citations 
omitted).

    In Order No. 1000, the Commission expressly ``decline[d] to 
impose obligations to build or mandatory processes to obtain 
commitments to construct transmission facilities in the regional 
transmission plan.'' More generally, the Commission disavowed that 
it was purporting to ``determine what needs to be built, where it 
needs to be built, and who needs to build it.'' As the Commission 
explained on rehearing, ``Order No. 1000's transmission planning 
reforms are concerned with process'' and ``are not intended to 
dictate substantive outcomes.'' The substance of a regional 
transmission plan and any subsequent formation of agreements to 
construct or operate regional transmission facilities remain within 
the discretion of the decision-makers in each planning region.\95\
---------------------------------------------------------------------------

    \95\ Id. at 57-58 (emphasis added; internal citations omitted).

    35. Similarly, in determining that Order No. 1000's public 
policy mandate fell within the Commission's authority under section 
206, the D.C. Circuit noted the mandate did not promote any 
---------------------------------------------------------------------------
particular public policy:

    [Petitioners] seem to argue that the Commission can only 
exercise authority to promote goals specified in the FPA and that 
the public policy mandate cannot be justified with respect to any of 
those goals. This argument misunderstands the nature of the mandate. 
It does not promote any particular public policy or even the public 
welfare generally. The mandate simply recognizes that state and 
federal policies might affect the transmission market and directs 
transmission providers to consider that impact in their planning 
decisions. . . . This fits comfortably within the Commission's 
authority under Section 206. . . . [T]he public policy mandate bears 
directly on the provision of transmission service.\96\
---------------------------------------------------------------------------

    \96\ Id. at 89-90 (citation omitted).
---------------------------------------------------------------------------

    Just as with Order No. 1000's planning mandates, the court again 
emphasized Order No. 1000's public policy mandate required the 
establishment of processes:

    But petitioners' attack is once again based on a 
misunderstanding of the orders. The orders merely require regions to 
establish processes for identifying and evaluating public policies 
that might affect transmission needs. The regions are free to choose 
their own manner of determining how best to identify and accommodate 
these policies.\97\
---------------------------------------------------------------------------

    \97\ Id. at 91 (emphasis in original; internal citations 
omitted).

    36. Finally, in affirming Order No. 1000's requirements 
pertaining to cost allocation, the court again applied Chevron 
deference to its interpretation of section 206.\98\ The court noted 
that Order No. 1000 used a ``light touch'' in its cost allocation 
reforms:
---------------------------------------------------------------------------

    \98\ Id. at 84-86.

    In keeping with the overall approach of the transmission 
planning reforms, [Order No. 1000] uses a light touch: it does not 
dictate how costs are to be allocated. Rather, [Order No. 1000] 
provides for general cost allocation principles and leaves the 
details to transmission providers to determine in the planning 
processes.\99\
---------------------------------------------------------------------------

    \99\ Id. at 81.

    37. While Order No. 1000 used a ``light touch,'' this pretextual 
final rule is heavy handed. To ensure that policy and corporate-
driven projects are ultimately built so that the preferred 
generation is built, the final rule seeks to promote particular 
public policies and to dictate substantive outcomes through its 
reforms to the Commission's transmission planning and cost 
allocation processes.\100\ If Order No. 1000 was upheld precisely 
because it was only mandating processes, not outcomes, then this 
final rule cannot stand on South Carolina because it nakedly intends 
to produce very specific outcomes.
---------------------------------------------------------------------------

    \100\ In so doing, the final rule violates section 201 as well. 
See infra Section III.B.
---------------------------------------------------------------------------

    38. How does it intend to do this? First, in contrast to Order 
No. 1000, which mandated consideration of public policies in 
transmission planning but not a particular policy,\101\ the final 
rule requires transmission providers in their Long-Term Regional 
Transmission Planning to incorporate seven categories of factors--
i.e., specific policies, as I have emphasized. Most of these 
mandatory categories of factors, which drive long-term transmission 
planning, specifically relate to the development and purchase of 
``green energy,'' including, inter alia: (i) state and local laws 
affecting the resource mix, (ii) state and local laws on 
decarbonization, (iii) generator interconnection requests and 
withdrawals,\102\ and (iv) corporate, state and local government 
commitments to purchase ``green energy.''
---------------------------------------------------------------------------

    \101\ See South Carolina, 762 F.3d at 89-90.
    \102\ This factor category is another way to subsidize and 
prefer wind and solar developers, which dominate the interconnection 
queues.
---------------------------------------------------------------------------

    39. The final rule describes the relationship between the 
categories of factors, transmission needs, and benefits, among other 
terms:

    For purposes of this final rule, Long-Term Regional Transmission 
Planning means regional transmission planning on a sufficiently 
long-term, forward-looking, and comprehensive basis to identify 
Long-Term Transmission Needs, identify transmission facilities that 
meet such needs, measure the benefits of those transmission 
facilities, and evaluate those transmission facilities for potential 
selection in the regional transmission plan for purposes of cost 
allocation as the more efficient or cost-effective regional 
transmission facilities to meet Long-Term Transmission Needs.
    For purposes of this final rule, Long-Term Transmission Needs 
are transmission needs identified through Long-Term Regional 
Transmission Planning, which, as discussed in this final rule, 
includes running scenarios and considering the enumerated categories 
of factors.\103\
---------------------------------------------------------------------------

    \103\ Final Rule, 187 FERC ] 61,068 at PP 38-39 (emphasis 
added).

    Thus, categories of factors clearly shape the identification of 
transmission needs. Demonstrating this causal relationship, the 
final rule explains that ``best available data inputs are data 
inputs that . . . reflect the list of factors that transmission 
providers account for in their Long-Term Scenarios,'' \104\ and, in 
turn, ``Long-Term Scenarios . . . incorporate various assumptions 
using best available data inputs about the future electric power 
system . . . to identify Long-Term Transmission Needs and enable the 
identification and evaluation of transmission facilities to meet 
such transmission needs.'' \105\
---------------------------------------------------------------------------

    \104\ Id. PP 42, 633 (emphasis added).
    \105\ Id. PP 40 and 302 (emphasis added).
---------------------------------------------------------------------------

    40. And, as we know, the identification of needs leads to the 
identification of transmission facilities that meet such needs; the 
identification of transmission facilities in turn leads to the 
measure of the benefits associated with those facilities; and the 
measure of benefits informs the evaluation of those transmission 
facilities for potential selection in the regional transmission plan 
for purposes of cost allocation. Thus, as the categories of factors 
are slanted toward transmission to facilitate preferred generation, 
the resulting output of the transmission planning process will 
inevitably have a similar bent. In other words, the final rule's 
mandate of the categories of factors starts the domino effect toward 
the final rule's agenda, an agenda that goes far beyond Order No. 
1000.
    41. Second, in contrast to Order No. 1000, whose reforms 
``[were] concerned with process'' and ``[were] not intended to 
dictate substantive outcomes,'' \106\ the final rule requires 
transmission providers to measure a set of seven required benefits 
in their long-term transmission planning so that the pretextual 
agenda will be realized. By mandating minimum benefits that the 
transmission providers must use to evaluate potential transmission 
facilities,\107\ the final rule is doing the opposite of using a 
``light touch;'' rather, the final rule is putting its thumb on the 
scale, seeking to dictate outcomes of the transmission planning 
process. As I must continue to emphasize, by mandating benefits, the 
final rule makes consumers into involuntary ``beneficiaries,'' who, 
through regional cost allocation, will be forced to pay for 
transmission projects that support the development and purchase of 
preferential power. Accordingly, as with the final rule's mandated 
categories of factors, the mandatory minimum benefits serve to 
advance the final rule's specific policy objectives regarding the 
resource mix. Such favoritism is blatantly unduly discriminatory and 
preferential in contravention of section 206, and therefore, the 
final rule is, simply put, not entitled to Chevron deference in any 
form.
---------------------------------------------------------------------------

    \106\ See South Carolina, 762 F.3d at 58 (internal citation 
omitted).
    \107\ Final Rule, 187 FERC ] 61,068 at P 965.
---------------------------------------------------------------------------

B. The Final Rule Violates FPA Section 201

    42. The final rule also infringes on the states' authority over 
electric generation reserved to them by FPA section 201 and is thus 
ultra vires.
    43. As relevant here, FPA section 201(b) provides:


[[Page 49574]]


    The Commission shall have jurisdiction over all facilities for 
such transmission or sale of electric energy, but shall not have 
jurisdiction, except as specifically provided in this subchapter and 
subchapter III of this chapter, over facilities used for the 
generation of electric energy or over facilities used in local 
distribution or only for the transmission of electric energy in 
intrastate commerce, or over facilities for the transmission of 
electric energy consumed wholly by the transmitter.\108\
---------------------------------------------------------------------------

    \108\ 16 U.S.C. 824(b)(1) (emphases added).

    Further, section 201(a) also specifies that ``such Federal 
regulation . . . extend[s] only to those matters which are not 
subject to regulation by the States.'' Courts have found that 
``states have broad powers under state law to direct the planning 
and resource decisions of utilities under their jurisdiction. States 
may, for example, order utilities to build renewable generators 
themselves, or . . . order utilities to purchase renewable 
generation.'' \109\ These powers are reserved to the states under 
section 201.
---------------------------------------------------------------------------

    \109\ See, e.g., Entergy Nuclear Vt. Yankee, LLC v. Shumlin, 733 
F.3d at 417 (quoting S. Cal. Edison Co. San Diego Gas & Elec. Co., 
71 FERC at 62,080).
---------------------------------------------------------------------------

    44. In South Carolina, the D.C. Circuit rejected the argument 
that section 201 prohibited Order No. 1000's transmission planning 
mandate.\110\ The D.C. Circuit emphasized that ``because the 
planning mandate relates wholly to electricity transmission, as 
opposed to electricity sales, it involves a subject matter over 
which the Commission has relatively broader authority.'' \111\ The 
court also reasoned that ``because [Order No. 1000's] planning 
mandate is directed at ensuring the proper functioning of the 
interconnected grid spanning state lines, . . . the mandate fits 
comfortably within Section 201(b)'s grant of jurisdiction over `the 
transmission of electric energy in interstate commerce.' '' \112\ 
The court thus concluded that ``Section 201 [did] not preclude the 
Commission's regulation of transmission planning in [Order No. 
1000]'' and that Order No. 1000 ``[did] not interfere with the 
traditional state authority that is preserved by Section 201.'' 
\113\
---------------------------------------------------------------------------

    \110\ 762 F.3d at 62-64.
    \111\ Id. at 63 (emphasis added) (footnote omitted)
    \112\ Id. (internal citations omitted).
    \113\ Id. at 64.
---------------------------------------------------------------------------

    45. However, in contrast to Order No. 1000, the final rule 
absolutely does ``interfere with the traditional state authority 
that is preserved by Section 201'' to ensure that its preferential 
policy and corporate-driven projects get built. By mandating, inter 
alia, categories of factors that drive the transmission planning 
process and by mandating minimum benefits to be used in the 
evaluation of potential Long-Term Regional Transmission Facilities, 
the final rule seeks to spur the building of transmission so as to 
promote a specific policy objective: the development and purchase of 
preferential generation. Accordingly, although the final rule 
strenuously insists that it is not mandating outcomes,\114\ it is 
doing so by manipulating the inputs of transmission planning (i.e., 
``pre-cooking'').\115\ In other words, the final rule seeks to do 
indirectly what it may not do directly.
---------------------------------------------------------------------------

    \114\ See Final Rule, 187 FERC ] 61,068 at PP 954-955, 1026-
1028.
    \115\ Id. P 965.
---------------------------------------------------------------------------

    46. As I explained in my concurrence to the NOPR:

    States can prefer, mandate or subsidize specific types of 
generation resources, but the Commission cannot use its authority 
over transmission to pressure, steer or require regional planning 
entities to act as the Commission's agents and do indirectly what 
the Commission cannot do directly. The Commission is not a national 
integrated resource planner. Order No. 1000, to its credit, 
recognized this clear delineation between federal and state 
authority.\116\
---------------------------------------------------------------------------

    \116\ NOPR Concurrence at P 2; see also id. n.4 (quoting Order 
No. 1000, 136 FERC ] 61,051 at P 154 (``[T]he regional transmission 
planning process is not the vehicle by which integrated resource 
planning is conducted; that may be a separate obligation imposed on 
many public utility transmission providers and under the purview of 
the states.'') (emphases added in NOPR Concurrence)).

    I also explained that ``the Commission cannot impose a 
preference for certain types of generation nor require regional 
entities to plan transmission designed to prefer or facilitate one 
type of generation over another.'' \117\
---------------------------------------------------------------------------

    \117\ Id. P 12 (emphases in original).
---------------------------------------------------------------------------

    47. The text of the FPA gives this Commission no authority 
whatsoever to act as a national IRP planner for the purpose of 
promoting its preferred generation resource mix. Pulling back the 
curtain, that is exactly what this pretextual final rule seeks to 
do. By extending FERC's control over every public utility 
transmission planner in the country, RTO or non-RTO, and ordering 
them to plan transmission lines intended to advance preferred policy 
and corporate goals, the Commission is stepping into the role of 
national IRP planner. FERC's authority under the FPA is limited to 
matters that directly affect rates, not practices that may 
theoretically have some tangential, indirect effect on rates,\118\ 
especially improper purposes such as ordering transmission planning 
to promote one or more states' public policies or corporate goals as 
to preferred generation resources. Congress intended FERC to be a 
rate regulator, not a planner of generation or transmission designed 
to bring about the construction of preferred types of generation. 
Indeed, FPA section 215 explicitly states that FERC may not order 
the construction of any generation or transmission asset.\119\ FERC 
cannot order transmission providers to do what FERC itself has no 
authority to do, yet that is exactly what this final rule aims to 
do.
---------------------------------------------------------------------------

    \118\ See, e.g., CAISO v. FERC, 372 F.3d at 400 (holding that 
FERC cannot prescribe the membership of the CAISO board, as FERC has 
authority over only ``rates, charges, classifications, and closely 
related matters''); see also Ari Peskoe, Replacing the Utility 
Transmission Syndicate's Control, Energy Law Journal, Vol. 44.3 547, 
578 (2023) (Peskoe Article) (``FERC's authority over utility 
`practices' is best understood as referring to `actions habitually 
being taken by a utility in connection with a rate found to be 
unjust and unreasonable.''') (footnote omitted), https://www.eba-net.org/wp-content/uploads/2023/11/8-Peskoe547-618.pdf.
    \119\ FERC regulates RTOs and RTO markets to ensure just and 
reasonable rates to consumers, but FERC has no authority to order a 
load-serving public utility to build a specific generation facility, 
only states can. See 16 U.S.C. 824(b)(1); see also Hughes v. Talen 
Energy Mktg., 578 U.S. 150, 154 (2016) (``The States' reserved 
authority includes control over in-state `facilities used for the 
generation of electric energy.''' (quoting 16 U.S.C. 824(b)(1))); 
see also 16 U.S.C. 824o(i)(2) (``[Section 215 of the FPA] does not 
authorize the [Electric Reliability Organization, i.e., NERC] or the 
Commission to order the construction of additional generation or 
transmission capacity or to set and enforce compliance with 
standards for adequacy or safety of electric facilities or 
service.''). Congress recently gave FERC a narrowly limited form of 
``backstop'' siting authority for certain designated transmission 
lines, but that authority is not implicated in this final rule.
---------------------------------------------------------------------------

    48. The final rule purports to order transmission planners to 
plan for a ``predicted'' generation mix in a distant future 20 years 
away, but the exact generation mix in 20 years is impossible to 
predict.\120\ The real goal of this pretextual final rule is not to 
try the impossible by predicting the generation mix in 20 years. 
Instead, the final rule is an attempt to become a national IRP 
planner and bring about a preferred generation mix through 
transmission planning by manipulating and shaping the future 
generation mix the special interests supporting this final rule want 
now.
---------------------------------------------------------------------------

    \120\ PATH Concurrence at P 4 (``PATH graphically illustrates 
the inherent dangers in approving for regional cost allocation long-
distance projects based on a prediction (i.e., a guess) of what the 
generation mix will be in 20 years or more. PATH was originally part 
of the huge ``Project Mountaineer'' scheme--announced with great 
fanfare right here at the Commission itself--to build three high-
voltage lines across hundreds of miles from West Virginia to East 
Coast load centers. The vast majority of the power to be delivered 
along these lines was to be coal-generated. After running into a 
firestorm of opposition in both the states in the path (no pun 
intended), as well as the end-user load states, Project Mountaineer 
was abandoned except for the PATH project, which represented a 
segment of one of the proposed Project Mountaineer lines. That 
segment was never built either. Yet, consumers have been paying for 
it ever since. The lesson here is clear: For policy-driven long-
distance, regional transmission projects affecting consumers in 
multiple states, it is absolutely essential that state regulators 
have the authority to approve--or disapprove--the construction of 
these lines and how they are selected for regional cost allocation 
and what that cost allocation formula is, if their consumers are 
going to be hit with the costs.'') (emphasis in original).
---------------------------------------------------------------------------

    49. The final rule denies that it is infringing on state 
authority reserved under FPA section 201, arguing, inter alia, that 
it directly regulates only those practices that affect the rates for 
the transmission of electric energy in interstate commerce and that 
it is not aiming to indirectly regulate any matter reserved to the 
states by FPA section 201.\121\

[[Page 49575]]

The final rule is chock-full of ``nothing to see here'' rhetoric 
asserting that it does not seek to shape the generation resource 
mix, but merely responds to changes in the electric industry.\122\ 
``Pay no attention to the [agenda] behind the [green] curtain! '' 
\123\ the final rule insists across 1300 pages. But it should be 
obvious by now that the final rule is just a pretext for enacting 
this administration's ``net zero 2035'' policy agenda, as well those 
of corporate and other special interests.\124\ The true intent of 
the final rule is revealed by mandated categories of factors and 
minimum benefits, which drive the transmission development necessary 
to achieve the final rule's preferred generation resource mix. Any 
honest account of the final rule cannot ignore the monetary windfall 
it would shower on generation and transmission developers; it is no 
wonder, therefore, why they were among the strongest supporters for 
the final rule. Nor can any rational individual--unless living in 
the Land of Oz--reasonably deny the role the final rule plays in 
furthering this pretextual agenda.\125\ In light of this backdrop, 
the final rule's repeated assertions that it does not seek to shape 
the country's resource mix are simply not credible. Contrary to the 
final rule's claims, in violation of FPA section 201, the final rule 
transforms the Commission into a national IRP planner to promote the 
construction of transmission lines to further the development of the 
final rule's preferred generation resources.
---------------------------------------------------------------------------

    \121\ Final Rule, 187 FERC ] 61,068 at P 263; see also, e.g., 
id. P 271 (``[T]he requirements in this final rule respect and do 
not unlawfully infringe on state authority. Rather . . . the 
Commission is acting in an area squarely within its jurisdiction--
transmission planning and cost allocation--by requiring transmission 
providers to engage in Long-Term Regional Transmission Planning to 
remedy deficiencies in the current transmission planning and cost 
allocation processes.'').
    \122\ E.g., id. PP 129, 130, 254, 259-263, 266, 271, 275.
    \123\ You can decide for yourself whether the ``green curtain'' 
represents ``green energy'' or something else that's green.
    \124\ See supra Sections I, III.B.
    \125\ See supra nn.5, 8, 10, 13, 15, 16, 67.
---------------------------------------------------------------------------

C. The Final Rule Violates the Major Questions Doctrine

    50. Courts generally look with suspicion on ``cryptic'' 
delegations of authority,\126\ and they are generally skeptical of 
agencies that seek to find ``elephants in mouseholes,'' or otherwise 
seek to rely on tiny grants of authority to justify major 
actions.\127\ As the Supreme Court explained in West Virginia v. 
EPA:
---------------------------------------------------------------------------

    \126\ See FDA v. Brown & Williamson Tobacco Corp., 529 U.S. 120, 
160 (2000).
    \127\ See West Virginia v. EPA, 597 U.S. at 746-47 (Gorsuch, J., 
concurring) (quoting Whitman v. Am. Trucking Ass'ns, 531 U.S. 457, 
468 (2001)).
---------------------------------------------------------------------------

    Where the statute at issue is one that confers authority upon an 
administrative agency, that inquiry must be ``shaped, at least in 
some measure, by the nature of the question presented''--whether 
Congress in fact meant to confer the power the agency has asserted. 
In the ordinary case, that context has no great effect on the 
appropriate analysis. Nonetheless, our precedent teaches that there 
are ``extraordinary cases'' that call for a different approach--
cases in which the ``history and the breadth of the authority that 
[the agency] has asserted,'' and the ``economic and political 
significance'' of that assertion, provide a ``reason to hesitate 
before concluding that Congress'' meant to confer such 
authority.\128\
---------------------------------------------------------------------------

    \128\ Id. at 700 (internal citations omitted).
---------------------------------------------------------------------------

    51. I invoked the major questions doctrine in my dissent to the 
proposed changes to the Commission's certificate policy, even before 
West Virgina v. EPA was handed down. In my dissent, I wrote that:

    ``The federal government's powers . . . are not general[ ] but 
limited and divided. Not only must the federal government properly 
invoke a constitutionally enumerated source of authority to regulate 
in this area or any other, it must also act consistently with the 
Constitution's separation of powers. And when it comes to that 
obligation, this Court has established at least one firm rule: `We 
expect Congress to speak clearly' if it wishes to assign to an 
executive agency decisions `of vast economic and political 
significance.' We sometimes call this the major questions 
doctrine.''
    In short, the major questions doctrine presumes that Congress 
reserves major issues to itself, so unless a grant of authority to 
address a major issue is explicit in a statute administered by an 
agency, it cannot be inferred to have been granted.
* * * * *
    Yet the Supreme Court has made it clear that broad deference to 
administrative agencies on major questions of public policy is not 
in order when statutes are lacking in any explicit statutory grant 
of authority. ``When much is sought from a statute, much must be 
shown. . . . [B]road assertions of administrative power demand 
unmistakable legislative support.'' \129\
---------------------------------------------------------------------------

    \129\ Certification of New Interstate Nat. Gas Facilities, 178 
FERC ] 61,107 (2022) (Christie, Comm'r, dissenting at P 22-23 
(quoting Nat'l Fed'n of Indep. Bus. v. Dep't of Labor, OSHA, 595 
U.S. 109, 121-22 (2022) (Gorsuch, J., concurring); In re MCP No. 
165, 20 F.4th 264, 267-68 (6th Cir. 2021) (Sutton, C.J., dissenting 
(emphases added))) (internal citations omitted) (Certificate 
Dissent), https://www.ferc.gov/news-events/news/items-c-1-and-c-2-commissioner-christies-dissent-certificate-policy-and-interim.
---------------------------------------------------------------------------

    52. The final rule's actions clearly implicate the major 
questions doctrine. If imposing a final rule intended to cost 
consumers literally trillions of dollars to build transmission 
projects designed to implement a sweeping policy agenda never passed 
by Congress is not a major question of public policy, then there is 
no such thing.\130\
---------------------------------------------------------------------------

    \130\ See Brad Plumer, Energy Dept. Aims to Speed Up Permits for 
Power Lines, The New York Times, Apr. 25, 2024 (quoting Rob 
Gramlich, the president of the consulting group Grid Strategies, `` 
`I've called [the final] rule the biggest energy policy in the 
country.' '' (emphasis added)), https://www.nytimes.com/2024/04/25/climate/energy-dept-speed-transmission.html.
---------------------------------------------------------------------------

    53. Yet the final rule brushes aside arguments that it would not 
withstand scrutiny under the major questions doctrine.\131\ Against 
these arguments, the final rule denies that its aim is to influence 
the generation mix; \132\ asserts that it ``neither transforms nor 
expands the Commission's authority; it merely applies existing 
authority;'' \133\ asserts that ``the differences in transmission 
planning required by this final rule represent differences in 
degree, not kind, from the Commission's longstanding regulations;'' 
\134\ and asserts that its ``incremental process improvements [from 
Order No. 1000], while necessary to ensure just and reasonable 
Commission-jurisdictional rates, do not have the `vast economic and 
political significance' that would implicate the major questions 
doctrine.'' \135\ None of these assertions are credible.
---------------------------------------------------------------------------

    \131\ Final Rule, 187 FERC ] 61,068 at P 275.
    \132\ Id.
    \133\ Id. P 277.
    \134\ Id.
    \135\ Id. P 278 (quoting West Virginia v. EPA, 597 U.S. at 735 
(J. Gorsuch, concurring)).
---------------------------------------------------------------------------

    54. This final rule violates the major questions doctrine. As 
discussed above, it is axiomatic that Congress has not intended for 
the Commission to be a national IRP planner. On the contrary, it has 
left both the siting of transmission and the development of 
generation to the states.\136\ Yet the final rule encroaches on 
these traditional state prerogatives in the absence of any explicit 
Congressional authorization to do so.
---------------------------------------------------------------------------

    \136\ See supra Section III.B. Since 2005, FERC has had very 
limited backstop siting authority for certain transmission projects 
that has never been used. See generally Applications for Permits to 
Site Interstate Elec. Transmission Facilities, Order No. 1977, 187 
FERC ] 61,069 (2024).
---------------------------------------------------------------------------

    55. The final rule seeks to shape specific policy outcomes by 
mandating categories of factors and minimum benefits. In addition, 
the final rule does something else that also arguably makes it 
transformative. Citing, inter alia, South Carolina, the final rule 
declares that the Commission has exclusive jurisdiction over 
regional transmission planning and cost allocation processes:

    As the D.C. Circuit has recognized, regional transmission 
planning and cost allocation processes are practices affecting rates 
subject to the Commission's exclusive jurisdiction.\137\
---------------------------------------------------------------------------

    \137\ Final Rule, 187 FERC ] 61,068 at P 86 & n.184 (emphasis 
added) (citing South Carolina, 762 F.3d at 55-59, 84 (affirming the 
Commission's authority to regulate transmission planning and cost 
allocation as practices affecting rates); Order No. 1000-A, 139 FERC 
] 61,132 at P 577 (holding that ``requirements regarding 
transmission planning and cost allocation . . . are practices 
affecting rates.'')); see also id. P 130 (``Instead, because 
practices directly affecting Commission-jurisdictional rates, terms, 
and conditions of service for interstate transmission and wholesale 
electricity are the exclusive jurisdiction of the Commission, we 
must ensure that Commission-jurisdictional processes associated with 
regional transmission planning and cost allocation result in rates 
that are just and reasonable and not unduly discriminatory or 
preferential.'') (emphasis added); id. P 770.

    In fact, the South Carolina court did not state that the 
Commission has exclusive jurisdiction over regional transmission 
planning and cost allocation. In fact, that court noted, for 
example, that the Florida Public Service Commission is statutorily 
vested with authority to ``plan[], develop[ ], and main[tain] . . . 
a coordinated electric power grid'' throughout the state.\138\
---------------------------------------------------------------------------

    \138\ See, e.g., South Carolina, 762 F.3d at 62 n.3.
---------------------------------------------------------------------------

    56. Whether the Commission can exclusively supplant the states 
in transmission planning and cost allocation is a major question--
particularly considering the enormous breadth of the transmission

[[Page 49576]]

grid, the importance of electricity in everyday life, and the 
trillions of dollars in transmission investment (read, cost 
increases) this final rule intends to impose on consumers.\139\ The 
final rule's conclusion that regional transmission planning and cost 
allocation processes are subject to the Commission's exclusive 
jurisdiction suggests that the Commission ``occupies the field'' 
\140\ in these areas.\141\ But this is wrong. This pretextual final 
rule erodes the states' authority, which is inconsistent with the 
principle of cooperative federalism reflected in the FPA. Under the 
major questions doctrine, absent an act of Congress, the Commission 
may not usurp the powers of the states in this manner.
---------------------------------------------------------------------------

    \139\ See FERC v. Elec. Power Supply Ass'n, 577 U.S. 260, 281 
(2016) (``It is a fact of economic life that the wholesale and 
retail markets in electricity, as in every other known product, are 
not hermetically sealed from each other. To the contrary, 
transactions that occur on the wholesale market have natural 
consequences at the retail level.'').
    \140\ See Silkwood v. Kerr-McGee Corp., 464 U.S. 238, 248 (1984) 
(``If Congress evidences an intent to occupy a given field, any 
state law falling within that field is preempted.'' (citation 
omitted)); PPL EnergyPlus, LLC v. Nazarian, 753 F.3d 467, 475-476 
(4th Cir. 2014) (``Even where state regulation operates within its 
own field, it may not intrude indirectly on areas of exclusive 
federal authority.'' (quoting Pub. Utils. Comm'n of State of Cal. v. 
FERC, 900 F.2d 269, 274 n.2 (D.C. Cir.1990) (internal quotation 
marks omitted))).
    \141\ The final rule's determination here aligns with the final 
rule's complete gutting of the roles of the states in transmission 
planning and cost allocation. See infra Section IV.B.1.
---------------------------------------------------------------------------

IV. The Final Rule Fails Under Both Prongs of FPA Section 206

    57. I cannot support the final rule because it has been 
fundamentally changed from the NOPR. In jettisoning essential 
components of the NOPR, the final rule has been reduced to a mere 
pretext for this supposedly independent Commission's effort to 
implement the current administration's ``net zero 2035'' policies. 
It will not produce rates that are just and reasonable and not 
unduly discriminatory or preferential. This final rule does not 
satisfy either of the requirements of FPA section 206. Under section 
206, the Commission must first find that the rate on file is no 
longer just and reasonable and not unduly discriminatory or 
preferential. Then the Commission must find that a particular 
replacement rate would be just and reasonable and not unduly 
discriminatory or preferential.\142\ The final rule fails on both 
counts.
---------------------------------------------------------------------------

    \142\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

    58. Although the current regional transmission planning 
processes could be improved--they are certainly not in need of the 
final rule's solutions. Even if these solutions were the only way 
forward to reform regional transmission planning, an act of Congress 
would be necessary first because the final rule is far beyond the 
reach of the FPA. While the Commission might prefer a different 
rate, that preference alone does not make all the filed rates of 
every transmission provider unjust and unreasonable.

A. The Final Rule Fails To Justify Its Action Under Section 206

    59. The final rule presents no justification for taking action 
in this proceeding against all of the filed transmission rates 
pursuant to FPA section 206. The record, while consisting of 
thousands of pages of comments, simply does not contain substantial 
evidence sufficient to make a generic showing that the existing 
filed rates of all transmission providers are unjust, unreasonable, 
unduly discriminatory or preferential.\143\ In South Carolina, the 
D.C. Circuit explained that ``the substantial evidence test'' for a 
rulemaking proceeding `` `requires the Commission to specify the 
evidence on which it relied and to explain how that evidence 
supports the conclusion it reached.' '' \144\ Here, the final rule's 
``rel[iance] on `generic' or `general' findings of a systemic 
problem to support imposition of an industry-wide solution'' \145\ 
fails because it relies on cherry-picked special interest comments 
to support the pre-baked and pretextual findings needed to enact the 
administration's preferential, and discriminatory, policy agenda as 
well those of corporate and other special interests.
---------------------------------------------------------------------------

    \143\ See South Carolina, 762 F.3d at 64-65 (citations omitted).
    \144\ Id. at 54 (quoting Wis. Gas Co. v. FERC, 770 F.2d 1114, 
1156) (alterations in the original)).
    \145\ See Final Rule, 187 FERC ] 61,068 at P 132 (citing South 
Carolina, 762 F.3d at 67) (additional citation omitted).
---------------------------------------------------------------------------

    1. The Record Is Not Sufficient to Make a Generic Showing That 
Every Transmission Providers' Regional Transmission Planning and 
Cost Allocation Processes Are Unjust, Unreasonable, and Unduly 
Discriminatory or Preferential
    60. The evidence in the record that is used to support the final 
rule's section 206 finding consists largely of comments from special 
interests that will profit from the final rule. The final rule also 
signals that there has been limited regional transmission 
development since Order No. 1000. This evidence should not be used 
to mean that every transmission provider in the country has 
transmission practices that are unjust and unreasonable.
    61. The final rule declines to analyze the ``justness and 
reasonableness of either generator interconnection processes or 
local transmission planning processes'' in its survey of issues in 
regional transmission planning.\146\ The final rule identifies 
benefits of transmission planning.\147\ The final rule states that 
``transmission planning that considers both evolving reliability 
needs and other drivers of transmission needs more comprehensively 
can enable transmission providers to identify potential reliability 
problems and economic constraints.'' \148\ The final rule states 
that transmission spending has increased, which turns into higher 
customer bills.\149\ The final rule identifies projections are 
necessary for growing future transmission needs, including load 
growth \150\ and changing reliability needs.\151\ And supply is 
changing due to state policies, customer preferences, and utility 
preferences (the latter two can also be driven by state policies or 
by activist investor preferences).\152\
---------------------------------------------------------------------------

    \146\ Id. P 111.
    \147\ Id. PP 90-91.
    \148\ Id. P 90.
    \149\ Id. P 92.
    \150\ Id. P 95.
    \151\ Id. PP 93-94.
    \152\ Id. PP 96-97.
---------------------------------------------------------------------------

    62. Translating FERC-speak, we are left with bland statements of 
the obvious: Transmission is expensive to build; transmission 
spending is up; generators front a lot of the needed money; 
consumers eventually pay them back; lack of regional integrated 
planning results in piecemeal transmission construction; this is 
inefficient and costs consumers more. Yet simply because a rate 
could be more efficient, that alone is not enough to make the filed 
rate unjust and unreasonable.
    63. Many of the special interest commenters point to studies, 
projections, and reports that show that regional transmission 
planning could be done more efficiently.\153\ When we peel back the 
``green curtain'' shrouding this final rule, however, we see that 
these comments are almost exclusively from self-interested entities 
which would gain substantially from the very Commission action that 
they support.\154\ Indeed, the record being used to support the 
section 206 finding consists of special interests who are going to 
profit monetarily from the final rule, including generation 
developers, transmission developers, and corporate purchasers of 
preferred power.\155\ None of these comments (individually or taken 
together) are sufficient to meet the high burden of proof that all 
transmission providers' tariffs are unjust and unreasonable due to 
the profit-seeking motivations behind them.
---------------------------------------------------------------------------

    \153\ See, e.g., Johannes Pfeifenberger, et al., The Brattle 
Group and Grid Strategies, Transmission Planning for the 21st 
Century: Proven Practices that Increase Value and Reduce Costs, at 
48-49 (Oct. 2021), https://www.brattle.com/wp-content/uploads/2021/10/2021-10-12-Brattle-GridStrategies-Transmission-Planning-Report_v2.pdf; Rob Gramlich and Jay Caspary, Americans for a Clean 
Energy Grid, Planning for the Future: FERC's Opportunity to Spur 
More Cost-Effective Transmission Infrastructure, at 26-28 (Jan. 
2021), https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf; Johannes P. Pfeifenberger, et 
al., The Brattle Group, Cost Savings Offered by Competition in 
Electric Transmission: Experience to Date and the Potential for 
Additional Customer Value (Apr. 2019), https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf.
    \154\ Such commenters include ACORE, PIOs, ACEG, Advanced Energy 
Buyers, AEE, Renewable Northwest, SREA, and Clean Energy Buyers.
    \155\ See Final Rule, 187 FERC ] 61,068 at P 96.
---------------------------------------------------------------------------

    64. In addition, the final rule looks back over the period 
following Order No. 1000 and states that regional transmission 
planning processes have yielded only ``limited investments in 
regional transmission planning projects.'' \156\ Let's suppose that 
over the last decade a transmission developer had instead proposed 
massively expanding transmission while the load growth projections 
remained flat. Consumers commenting on that aggressive plan would 
have challenged it as gold-plating. Regulators

[[Page 49577]]

would have rejected it as imprudent. The so-called ``limited 
investments'' were instead a sign of responsiveness to projections 
made during that era. Rather than seeing this outcome as a feature 
of considered ratemaking during a period of low load growth, the 
final rule attributes this lack of investment to the shortcomings of 
the existing regional transmission planning processes--meaning the 
tariff changes mandated by Order No. 1000.\157\ For these reasons, 
the final rule's reliance on a lack of regional transmission 
development post-Order No. 1000 is not persuasive, especially to 
support the finding that all transmission providers' tariffs are 
unjust and unreasonable.
---------------------------------------------------------------------------

    \156\ Id. P 101.
    \157\ Id.
---------------------------------------------------------------------------

2. The Record Shows That Regional Planning Deficiencies Exist Only in 
Isolated Pockets

    65. The evidence in this record does not demonstrate a single 
nationwide systemic problem. Rather, the record shows that the 
``deficiencies identified by the Commission `exist[ ] only in 
isolated pockets.' '' \158\ The final rule even recognizes the many 
regions representing a substantial percentage of consumers where 
regional transmission planning is working.\159\ The final rule 
points to the MISO Multi-Value Project transmission planning process 
as an effective example of regional transmission planning.\160\ From 
this, it could be concluded that the final rule suggests that 
regional transmission planning is working in MISO, including on a 
long-term basis. It is logical to conclude similarly regarding 
CAISO's \161\ and New York's regional transmission planning.\162\ 
Vertically integrated monopoly public utilities have expanded their 
transmission capacity by engaging in integrated resource planning 
that is reviewed and approved by their state regulators.\163\ NRECA, 
an organization representing both transmission providers and 
transmission-dependent entities, highlights that its members have 
observed regional transmission planning processes that range from 
successful to broken.\164\ According to NRECA, some RTO regions are 
working, and others are not. NRECA similarly states that some non-
RTO regions are working, and others are not.
---------------------------------------------------------------------------

    \158\ See South Carolina, 762 F.3d at 67 (quoting Associated Gas 
Distribs. v. FERC, 824 F.2d 981, 1019 (D.C. Cir. 1987)) (alteration 
in the original).
    \159\ See generally Final Rule, 187 FERC ] 61,068 at PP 71-77.
    \160\ Id. P 102; see OMS Initial Comments at 2 (stating that 
``it is critically important to note at the outset that MISO's 
regional planning process already reflects many of the elements and 
features contained in the [NOPR], and it should be looked to as a 
model for other regions to emulate.''); MISO Initial Comments at 1-
2.
    \161\ CAISO Initial Comments at 3 (``The CAISO already engages 
in long-term planning, and its existing transmission planning 
process is consistent with the direction of the NOPR.''); CAISO 
Reply Comments at 1-2 (stating that ``the Commission should not 
unduly disrupt or undo existing planning processes and approaches 
that are functioning well and enabling transmission providers to 
plan for system needs efficiently and cost-effectively.'').
    \162\ New York Commission and NYSERDA Initial Comments at 5.
    \163\ See, e.g., Southern Companies Initial Comments at 13-15 
(stating that its ``IRP/RFP-driven transmission planning is 
successfully expanding their electric grid to address the changing 
resource mix and load''); Undersigned States Reply Comments at 6-7.
    \164\ NRECA Initial Comments at 14-16.
---------------------------------------------------------------------------

    66. This is hardly ironclad evidence sufficient to support a 
generic finding that the regional transmission planning processes 
are no longer just and reasonable. The record here shows that 
regional and multistate regional planning is happening in 
significant and large swaths of the country subject to our rate 
jurisdiction, including on longer-term horizons, and that other 
regions have room for improvement. These circumstances are entirely 
different than those facing the Commission when it issued Order No. 
1000. The factual justification for a single, national FPA section 
206 finding is simply not present in the way it was for Order No. 
1000. No amount of hand waving or misdirection can change the lack 
of sufficient evidentiary support for this Commission to take the 
sweeping national action pursuant to FPA section 206 in this rule. 
This significant deficiency leaves this entire exercise open to 
meaningful challenge.

B. The Replacement Rate Is Not Just and Reasonable

    67. Not only does the final rule fail to meet its evidentiary 
burden, but the replacement rate that the final rule imposes is not 
just and reasonable and has no basis in law. The final rule has 
removed any serious state role in agreeing to the final rule's 
planning and cost allocation processes, and the final rule fails to 
protect consumers as FERC is required to do under the FPA. Further, 
the cost causation principle cannot, and should not, extend as far 
as the today's final rule suggests, and should not require that the 
ratepayers of a non-consenting state pay costs of other states' 
public policies where there is mismatch between planning criteria 
and benefits.

1. The Final Rule Reverses the States' Roles in Transmission Planning 
and Cost Allocation Promised by the NOPR

    68. The main reason I supported the NOPR was that it ``formally 
put the states--for the first time--at the center of regional 
transmission planning and cost allocation decision-making for 
policy-driven projects in all regional transmission entities, if the 
states choose.'' \165\ Specifically, I explained:
---------------------------------------------------------------------------

    \165\ NOPR Concurrence at P 5 (emphases in original) (footnote 
omitted).

    [F]or these [Long-Term Regional Transmission Facilities] the 
NOPR propose[d] to require the regional planning entities to consult 
with and seek the agreement of the relevant states to both the 
selection criteria for these projects and to the regional cost 
allocation arrangements. State approval is especially important in a 
multi-state region, where different states have different policies. 
The NOPR proposes to provide the maximum opportunity for creativity 
and flexibility to the states and regional entities in developing 
the process for designing and approving regional selection criteria 
and cost allocation arrangements. States can agree to an ex ante 
formula for regional cost allocation of these types of projects--
such as, for example, the ``highway-byway'' formula approved by the 
SPP Regional State Committee--or states can agree to a process for a 
project-by-project agreement on cost allocation among one or several 
states--such as, for example, the State Agreement Approach in PJM--
or states may choose some combination of both. States in a multi-
state RTO or ISO can even agree to defer the decision on cost 
allocation to the governing board of the RTO/ISO. The result is, 
while we are proposing to require regional planning entities to 
study and evaluate a broad, forward-looking array of information--
including information addressing states' individual energy policies 
and goals--any projects identified through this new process will not 
be built, or more importantly, paid for by consumers, until the 
states representing such consumers have agreed that such projects 
are indeed needed and wanted by those same consumers.\166\
---------------------------------------------------------------------------

    \166\ Id. P 11 (emphases in original) (footnotes omitted).

    I wrote about the advantages of elevating the role of the 
---------------------------------------------------------------------------
states:

    [E]levating the role in planning and cost allocation of state 
regulators--who are, as a group, deeply concerned about the monthly 
bills paid by consumers, of which transmission is a rapidly growing 
component--will make it more likely, not less, that necessary 
transmission can get built while ensuring that rates resulting from 
these types of policy-driven projects will not be unjust and 
unreasonable, which they clearly have the potential to be.\167\
---------------------------------------------------------------------------

    \167\ Id. P 14 (emphasis in original).

    The day the Commission issued the NOPR, some of my colleagues 
expressed similar sentiments.\168\
---------------------------------------------------------------------------

    \168\ See supra n.48; NOPR, 179 FERC ] 61,028 (Phillips, Comm'r, 
concurring at P 4) (``I support the proposal to require transmission 
providers to consult with and incorporate states' views in project 
selection and cost allocation. I invite comment on the value of such 
state involvement for increasing the likelihood that those 
facilities are sited and ultimately developed with fewer costly 
delays.''), https://www.ferc.gov/news-events/news/item-e-1-commissioner-phillips-concurrence-building-future-through-electric.
---------------------------------------------------------------------------

    69. Unfortunately--perhaps emanating from the final rule's 
erroneous legal conclusion that the Commission has exclusive 
jurisdiction over regional transmission planning and cost allocation 
\169\--the final rule completely eviscerates the states' role 
contemplated in the NOPR in both the transmission planning and cost 
allocation processes. Other than a few cosmetic gestures, the final 
role essentially treats the state regulators like other stakeholders 
in the RTO/ISO. But states are not mere ``stakeholders:''
---------------------------------------------------------------------------

    \169\ See supra Section III.C.

    State regulators have the duty to act in the public interest and 
states alone are sovereign authorities with inherent police powers 
to regulate utilities through their designated state officers. The 
FPA itself explicitly recognizes state authority. So it is perfectly 
fitting for state regulators to have the important roles proposed in 
this NOPR,

[[Page 49578]]

without preempting the regional planning entities from seeking 
additional input through their existing stakeholder processes.\170\
---------------------------------------------------------------------------

    \170\ NOPR Concurrence at P 13 (emphasis in original).

    The evisceration of the states' role in transmission planning 
and cost allocation and the relegation of state regulators to mere 
``stakeholder'' status is alone reason enough for me to dissent.

a. The Final Rule Undercuts the States' Role in the Transmission 
Planning Process

    70. A major example of the final rule's undercutting of the 
states' role in the transmission planning process is with respect to 
the selection criteria. As a reminder, the selection criteria are a 
key component of the planning process because once a project is 
selected, money starts to flow from the ratepayers to transmission 
developers. Recognizing the states' important role in the planning 
process, the NOPR required that the states approve the selection 
criteria that transmission providers use in the planning process:

    Given the important role states play and the wide variety of 
potential approaches to selection criteria, we propose, as part of 
this requirement, that public utility transmission providers must 
consult with and seek support from the relevant state entities, as 
defined below, within their transmission planning region's footprint 
to develop the selection criteria.\171\
---------------------------------------------------------------------------

    \171\ NOPR, 179 FERC ] 61,028 at P 244; see also NOPR 
Concurrence at P 11 (``State approval is especially important in a 
multi-state region, where different states have different policies. 
The NOPR proposes to provide the maximum opportunity for creativity 
and flexibility to the states and regional entities in developing 
the process for designing and approving regional selection criteria 
and cost allocation arrangements.'').

    To implement this requirement, the NOPR proposed ``to require 
that public utility transmission providers demonstrate on compliance 
that they developed their proposed selection criteria in 
consultation with the relevant state entities in their transmission 
planning region's footprint.'' \172\ And it was clear at that time 
exactly what that meant--agreement, nothing less.\173\ However, the 
final rule outright undermines these requirements--and the states' 
role as a whole--by ``clarifying'' that state approval of the 
evaluation process and selection criteria is not actually required:
---------------------------------------------------------------------------

    \172\ NOPR, 179 FERC ] 61,028 at P 246.
    \173\ See NOPR Concurrence at P 11; see also supra n.48.

    We clarify that we require transmission providers to seek 
support from Relevant State Entities, but do not require 
transmission providers to obtain their support, before proposing an 
evaluation process and selection criteria on compliance.\174\
---------------------------------------------------------------------------

    \174\ Final Rule, 187 FERC ] 61,068 at P 996 (emphases added).

    Starkly demonstrating how milquetoast the requirement for 
transmission providers to ``consult with and seek support from'' the 
states has now become under the final rule, the final rule even 
fails to require that transmission providers indicate in their 
compliance filings whether the states agree with their selection 
criteria proposal.\175\ So, from the NOPR requiring state agreement, 
the final rule does not even require the states' views to merit mere 
mention. Adding insult to injury, the final rule specifies that 
``transmission providers may not include in their evaluation process 
or selection criteria any prohibition on the selection of a Long-
Term Regional Transmission Facility based on the transmission 
providers' anticipated response of a state public utility commission 
or consumer advocates to particular Long-Term Regional Transmission 
Facilities.'' \176\
---------------------------------------------------------------------------

    \175\ Id. P 999.
    \176\ Id. P 962 (emphasis added).
---------------------------------------------------------------------------

    71. The final rule acknowledges that ``Long-Term Regional 
Transmission Planning is more likely to be successful where 
transmission providers, Relevant State Entities, and other 
stakeholders collaborate to develop an evaluation process and 
selection criteria.'' \177\ But the final rule emphasizes that 
transmission providers are ultimately the only ones responsible for 
transmission planning and complying with the obligations of the 
final rule, and it notes that achieving consensus may simply not be 
possible in every instance.\178\ Neither explanation provides a 
sufficient rationale to justify undercutting the requirement for 
state approval when states alone have the inherent police power to 
regulate the utilities within their states. One cannot help but see 
this as part of the larger pretextual shell game the final rule 
seeks to accomplish. Sadly, this is one of many examples where the 
final rule provides for a little extra process involving the states 
to demonstrate ostensibly that the Commission is committed to the 
principle of cooperative federalism, but in substance, states are 
relegated back to mere stakeholders, whose input can simply be 
disregarded if inconvenient.\179\
---------------------------------------------------------------------------

    \177\ Id. P 996.
    \178\ Id.
    \179\ See supra P 69.
---------------------------------------------------------------------------

    72. Unfortunately, not only the states' role with respect to the 
selection criteria has been gutted. As I must continue 
emphasize,\180\ by mandating categories of factors and minimum 
benefits, the final rule seeks to shape specific policies and 
outcomes, regardless of the consent of the states.\181\ The goal of 
this pretextual final rule is to plan preferential policy and 
corporate-driven projects regardless of states' support. One must 
also ask whether the extent to which this final rule requires 
prescriptive planning processes also limits the states' role to 
participate meaningfully when most are resource-strapped.
---------------------------------------------------------------------------

    \180\ See supra Section I. Another example, of course, is 
micromanaging how local ``stakeholder'' meetings must be conducted, 
which, as noted, runs a strong risk of conflicting with state IRP 
proceedings and state authority. See Final Rule, 187 FERC ] 61,068 
at PP 1625-1646. As above, I question whether prescriptive 
requirements to this degree can truly pass muster under court 
precedent.
    \181\ And transmission providers themselves cannot even 
voluntarily account for states' input in the planning. Today's final 
rule requires that transmission providers may not include in their 
evaluation process or selection criteria any prohibition on the 
selection of a Long-Term Regional Transmission Facility based on the 
transmission providers' anticipated response of a state public 
utility commission or consumer advocates to particular Long-Term 
Regional Transmission Facilities. Final Rule, 187 FERC ] 61,068 at P 
962.
---------------------------------------------------------------------------

    73. States did not join RTOs \182\ to pay for these preferential 
policy and corporate-driven projects. Rather, as I wrote in my 
concurrence to the NOPR, ``States joined to provide their retail 
consumers with the promised benefits of lower transmission costs and 
strengthened reliability through regional planning of core 
Reliability projects.'' \183\ I speak from personal experience. When 
I was a Commissioner at the Virginia State Corporation Commission, 
my colleagues and I considered applications to permit Virginia's 
major utilities to join PJM. The Virginia Commission's rules 
required us to examine ``among other things, an [RTO's] reliability 
practices, pricing and access policies, and independent 
governance.'' \184\ When we voted to approve the applications, PJM's 
planning for public policy projects that would be cost allocated 
regionally was not even on our radar.
---------------------------------------------------------------------------

    \182\ I am aware that states qua states do not join RTOs/ISOs. 
Rather, they use their regulatory power to allow or require their 
regulated transmission-owning utilities to join.
    \183\ NOPR Concurrence at P 13.
    \184\ Commonwealth of Virginia, ex rel. State Corporation 
Commission, Ex Parte: In the matter concerning the application of 
Virginia Electric and Power Company d/b/a Dominion Virginia Power 
for approval of a plan to transfer functional and operational 
control of certain transmission facilities to a regional 
transmission entity, Case No. PUE-2000-00551 (Nov. 10, 2004). The 
order included a stipulation in which Dominion agreed that joining 
PJM would not alter its legal obligation to seek a CPCN from the 
Virginia Commission to construct generation or transmission assets. 
Id., Partial Stip. ] 6.
---------------------------------------------------------------------------

b. The Final Rule Guts the States' Role in Cost Allocation as Proposed 
in the NOPR

    74. Given the pretextual nature of this rule, it should not be 
surprising that it eviscerates the states' role in deciding cost 
allocation matters. NARUC strongly supported the NOPR's proposal to 
involve states in the cost allocation for Long-Term Regional 
Transmission Facilities and conversely disagreed with a requirement 
that transmission providers include a Long-Term Regional 
Transmission Cost Allocation Method in their OATTs without being 
obligated to seek agreement from the states.\185\ NARUC explained:
---------------------------------------------------------------------------

    \185\ NARUC Initial Comments at 45.

    [S]ince the projects under consideration in the Long-Term 
Regional Transmission Planning process are largely driven by state 
public policies, state regulators should have a key role in 
evaluating the benefits and allocating the costs. State regulators 
are attuned to the concerns of the local communities where the 
transmission will be sited and the retail ratepayers who must, in 
many instances, foot a large fraction of the cost.\186\
---------------------------------------------------------------------------

    \186\ Id. at 46 (citations omitted).

    Of course, to effectuate the pretextual agenda, the final rule 
simply ignores NARUC's entreaties and instead cuts the

[[Page 49579]]

states out of any meaningful role in cost allocation.
    75. First, the final rule essentially terminates the State 
Agreement Process by making the ex ante cost allocation method the 
default approach. While the NOPR proposed to require transmission 
providers to revise their OATTs to include either (1) an ex ante 
cost allocation method (i.e., a Long-Term Regional Transmission Cost 
Allocation Method) to allocate the costs of Long-Term Regional 
Transmission Facilities, (2) a State Agreement Process, or (3) a 
combination thereof,\187\ the final rule substantially modifies the 
NOPR proposal to require the use of one or more ex ante cost 
allocation methods.\188\ Although the final rule permits 
transmission providers to include a State Agreement Process in their 
OATTs if the states agree, the final rule specifies that the State 
Agreement Process ``cannot be the sole method filed for cost 
allocation for Long-Term Regional Transmission Facilities,'' \189\ 
and the final rule modifies the NOPR proposal to require an ex ante 
cost allocation method to apply as a backstop.\190\ The ex ante cost 
allocation method backstop would apply if a State Agreement Process 
fails to result in a cost allocation method agreed to by Relevant 
State Entities and others or if the Commission ultimately finds that 
the cost allocation method that results from a State Agreement 
Process is unjust, unreasonable, or unduly discriminatory or 
preferential.\191\
---------------------------------------------------------------------------

    \187\ NOPR, 179 FERC ] 61,028 at P 302.
    \188\ Final Rule, 187 FERC ] 61,068 at P 1291.
    \189\ Id. PP 1292, 1361, 1404.
    \190\ Id. P 1292.
    \191\ Id. P 1293.
---------------------------------------------------------------------------

    76. Second, under the final rule, state consent on cost 
allocation is not required. The final rule explicitly declines to 
adopt the NOPR proposal to require transmission providers to seek 
the agreement of the states regarding the relevant cost allocation 
method to be applied to Long-Term Regional Transmission 
Facilities.\192\ Instead, the final rule merely requires 
transmission providers to establish a six-month Engagement Period 
``to provide a forum'' for the states to negotiate an ex ante cost 
allocation method(s) and/or a State Agreement Process.\193\ Under 
the final rule, if the negotiations fail, transmission providers 
must still file an ex ante cost allocation method(s).\194\ Worse 
still, the final rule specifies that, even if the states do reach an 
agreement on an ex ante cost allocation method(s) and/or a State 
Agreement Process, the transmission providers may ignore it and file 
their own ex ante cost allocation method(s) instead.\195\ Similarly, 
the final rule declines to require that, if the transmission 
providers disagree with a proposed cost allocation method agreed on 
by the states, transmission providers must file both cost allocation 
methods: the transmission providers' preferred cost allocation 
method and the cost allocation method agreed to by the Relevant 
State Entities. So to the states, the final rule says, ``Heads I 
win, tails you lose.''
---------------------------------------------------------------------------

    \192\ Id. P 1354.
    \193\ Id. P 1357.
    \194\ Id. P 1367.
    \195\ E.g., id. P 1359 (``[T]he ultimate decision as to whether 
to file a Long-Term Regional Transmission Cost Allocation Method(s) 
and/or State Agreement Process to which Relevant State Entities have 
agreed will continue to lie with the transmission providers.''); id. 
P 1429 (``[A]fter the required Engagement Period, transmission 
providers in each transmission planning region will decide what 
Long-Term Regional Transmission Cost Allocation Method(s) and any 
State Agreement Process to file as part of their compliance filings. 
Therefore, transmission providers in a transmission planning region 
could elect to propose on compliance a Long-Term Regional 
Transmission Cost Allocation Method and not file a State Agreement 
Process or other ex ante cost allocation method to which Relevant 
State Entities agreed. In addition, we do not impose any obligation 
on transmission providers to file a cost allocation method for Long-
Term Regional Transmission Facilities with which they disagree, even 
if such a method were proposed to the transmission providers 
pursuant to a Commission-approved State Agreement Process, unless 
the transmission providers have clearly indicated their assent to do 
so as part of a Commission-approved State Agreement Process in their 
OATTs.'') (emphases added; footnote omitted); see also id. P 1356 
n.2895 (citing Atl. City Elec. Co. v. FERC, 295 F.3d 1, 9 (D.C. Cir. 
2002) (Atlantic City)).
---------------------------------------------------------------------------

    77. Further, under the final rule, at the end of the Engagement 
Period, the states' role--however small--in shaping an ex ante cost 
allocation formula is effectively over. NARUC argued that the 
Commission should provide some mechanism for future review of cost 
allocation methodologies for Long-Term Regional Transmission 
Facilities given that state public policies may evolve:

    As the name suggests, these transmission facilities are expected 
to be planned over a longer period of time than projects built for 
reliability or economic reasons. States that do not currently have 
public policies requiring extensive transmission investments may 
forego an opportunity to participate in discussions regarding cost 
allocation, but their public policies may evolve over time. For the 
reforms proposed in this NOPR to be successful, the positions of 
relevant state entities should not be frozen in time.\196\
---------------------------------------------------------------------------

    \196\ NARUC Initial Comments at 49.

    But the final rule denies this request.\197\ Further, the final 
rule specifies that transmission providers may file subsequent 
changes to their cost allocation method(s) without establishing 
future Engagement Periods beyond the initial one.\198\
---------------------------------------------------------------------------

    \197\ Final Rule, 187 FERC ] 61,068 at P 1368.
    \198\ Id.
---------------------------------------------------------------------------

    78. As noted above, the upshot of these changes, taken together, 
is that the states are simply cut out of any significant role in the 
cost allocation of the of Long-Term Regional Transmission 
Facilities. The final rule completely eviscerates the State 
Agreement Process and renders it non-viable. The final rule 
eliminates the core element of that approach--that states enter such 
cost allocation arrangements voluntarily. Now--with an ex ante cost 
allocation method that must serve as a backstop in the event that 
the states' negotiations fail, looming over the states' heads like 
the sword of Damocles--the final rule gives states ``an offer they 
can't refuse,'' telling the states that must they agree to a cost 
allocation or the transmission providers will impose one on them 
anyway. In such a circumstance, fruitful negotiation between the 
states is virtually impossible, as states simply cannot say ``no.'' 
At the risk of stating the obvious, this forced cost allocation on 
the states is, of course, contrary to comments of NARUC and many of 
the individual states.\199\
---------------------------------------------------------------------------

    \199\ See NARUC Initial Comments at 45 (``NARUC strongly 
supports the Commission's proposal to involve states in cost 
allocation for Long-Term Regional Transmission Facilities and 
conversely explicitly rejects a requirement that public utility 
transmission providers include a Long-Term Regional Transmission 
Cost Allocation Method in their OATTs without being obligated to 
seek agreement from relevant state entities.'') (footnotes omitted); 
see, e.g., Alabama Commission Initial Comments at 9 (``In other 
words, states may not force their preferences on their neighbors, or 
compel them to subsidize their achievement. Thus, it goes without 
saying that Alabama ratepayers should not be required to pay for 
transmission projects that are designed to promote or facilitate the 
public goals of other states, localities, or entities.''); West 
Virginia Commission Reply Comments at 2-3 (``The [West Virginia 
Commission] opposes any changes in transmission cost allocation that 
would require West Virginia customers, or customers of any State, to 
involuntarily pay for new transmission facilities that are needed to 
support the public policy generation choices of other States.''); 
North Carolina Commission and Staff Initial Comments at 15-16 (``The 
[North Carolina Commission and Staff] strongly support the NOPR 
proposals regarding cost allocation for regional transmission 
facilities developed through the Long-Term Regional Transmission 
Planning process, as that term is defined in the NOPR, specifically 
the requirement for transmission providers to seek state agreement 
on cost allocation methodologies and the requirement to create an 
opportunity for states to negotiate a cost allocation method after a 
transmission facility has been selected through the Long-Term 
Regional Transmission Planning process.''); Utah Commission Initial 
Comments at 9 (``[I]mposing a single set of federally mandated, 
highly prescriptive transmission planning and cost allocation 
requirements for the purpose of privileging the selection of costly 
transmission projects to serve remote and speculative renewable 
generation is not a lawful exercise of FERC's authority under 
Section 206.'').
---------------------------------------------------------------------------

    79. Just as concerning, as I discuss in Sections I and IV.B.2 of 
this dissent, the final rule will enable the ratepayers of non-
consenting states to be assessed the cost of public policy projects 
of other states, which is anti-democratic and violates the basic 
principle of fairness. As NARUC points out, NARUC and individual 
state commissions supported the State Agreement Process to address 
this concern:

    NARUC is particularly supportive of the State Agreement Process, 
which is similar to the PJM State Agreement Approach that has been 
approved by FERC and that NARUC and state commissions advocated to 
be included in the final rule. A state agreement approach allows 
states to further their public policy goals without burdening the 
ratepayers of states that have different priorities.\200\
---------------------------------------------------------------------------

    \200\ NARUC Initial Comments at 51 (footnote omitted).

    The final rule's gutting of the very State Agreement Process 
that NARUC supports as part of the final rule's choice to ignore the 
consent of the states on cost allocation removes this key protection 
for the states and their ratepayers.
    80. Further, given the final rule's determinations undercutting 
the states' role,

[[Page 49580]]

I highly doubt that PJM's State Agreement Approach or other existing 
mechanisms involving the states in other RTOs will remain viable 
with respect to the cost allocation of Long-Term Regional 
Transmission Facilities.\201\ In addition to PJM's State Agreement 
Approach, NARUC notes that the country's other multi-state RTOs have 
mechanisms in place for the states to participate in regional 
transmission cost allocation:
---------------------------------------------------------------------------

    \201\ PJM's State Agreement Approach exemplified the proper way 
to involve states in decisions regarding cost allocation for public 
policy projects. The PJM State Agreement Approach was not directed 
by Order No. 1000, but rather by PJM's own voluntary act of reaching 
out to the states in PJM States and asking PJM States to propose a 
cost allocation for public policy projects. PJM accepted PJM States' 
proposal--which became the PJM State Agreement Approach--and 
submitted it to FERC in its compliance filing. It was accepted by 
FERC, but as today's final rule shows, only grudgingly and only 
until the chance came to extinguish it.

    In many regions, state regulators are at the forefront of 
successful efforts to coordinate regional transmission, including 
what many understand to be the most challenging issue, cost 
allocation. For instance, in SPP, the Regional State Committee has 
the primary authority for setting the basis of any regional cost 
allocation. In both MISO and ISO-New England, state committees have 
the ability to propose alternative cost allocation methodologies 
under some circumstances.\202\
---------------------------------------------------------------------------

    \202\ NARUC Initial Comments at 46 (citing MISO Transmission 
Owners Agreement, Appendix K, Article II, Section II.E.3.b 
(providing regional state committee with the opportunity to develop 
and request MISO file an alternative cost-allocation methodology 
under certain circumstances); ISO New England, Agreements and 
Contracts, Transmission Operating Agreement, Section 3.04 (h)(vi)(A-
C) (providing regional state committee with opportunity to provide 
alternative cost allocation proposal in connection with certain 
transmission cost allocation provisions in ISO-NE's tariff)).

    81. Specifically, SPP has a Regional State Committee (RSC) 
process by which the RSC has agreed to a ``highway-byway'' ex ante 
cost allocation and SPP will file it,\203\ and MISO's Tariff 
provides that MISO will file under FPA section 205 OMS's alternative 
cost allocation to MISO's proposal.\204\ Given that the final rule's 
determination that transmission providers may ignore any agreement 
or alternative proposed by the states,\205\ such mechanisms could be 
called into question--unless the RTOs voluntarily agree to preserve 
them in their OATTs.\206\ If these mechanisms are weakened, or even 
eliminated, the only alternatives left for the states to shape the 
RTOs' cost allocation would be to file comments to the RTOs' cost 
allocation filings or to file a section 206 complaint--no different 
than any RTO stakeholder.
---------------------------------------------------------------------------

    \203\ See SPP, Governing Documents Tariff, Sec.  7.2 (Bylaws 7.2 
Regional State Committee) (2.0.0); see also Sw. Power Pool, Inc., 
106 FERC ] 61,110, at P 219, order on reh'g, 109 FERC ] 61,010, at 
PP 93-94 (2004); Entergy Arkansas, Inc., 133 FERC ] 61,211, at P 15 
(2010).
    \204\ E.g., Midwest Indep. Transmission Sys. Operator, Inc., 143 
FERC ] 61,165, at PP 30-31 (2013) (citations omitted).
    \205\ See, e.g., Final Rule, 187 FERC ] 61,068 at PP 1359, 1429; 
see also id. P 1356 n.2895 (citation omitted).
    \206\ See, e.g., id. P 1412 (``[N]or do we create any obligation 
that transmission providers file a cost allocation method resulting 
from a State Agreement Process, unless the transmission providers 
had clearly indicated assent to do so in their OATTs); id. n.3013 
(``[T]ransmission providers may voluntarily agree as part of a State 
Agreement Process in their OATTs that transmission providers shall 
file any cost allocation method that meets the requirements of their 
State Agreement Process, even if those transmission providers do not 
agree with that method.'').
---------------------------------------------------------------------------

    82. The final rule acknowledges that ``experience with Order No. 
1000 has reinforced the critical role that states play in the 
development of new transmission infrastructure, particularly at the 
regional level, where transmission projects may physically span, and 
their costs may be allocated across, multiple states.'' \207\ 
However, the final rule's determinations on cost allocation undercut 
this critical role. It appears obvious that the final rule does not 
in fact view the states as partners in a cooperative federal system, 
but rather as potential obstacles to its pretextual political, 
corporate, and ideological agendas.
---------------------------------------------------------------------------

    \207\ Id. P 124.
---------------------------------------------------------------------------

    83. The final rule sets forth two central arguments for its 
dramatic reduction of the states' role. First, the final rule 
suggests that, per Atlantic City,\208\ the Commission cannot deprive 
transmission providers of their FPA section 205 filing rights to 
propose tariff changes to rates.\209\ And second, the final rule 
claims that if transmission providers were permitted to rely solely 
on a State Agreement Process to determine the cost allocation and 
that process were to fail, ``there would be no cost allocation 
method for Long-Term Regional Transmission Facilities selected as 
the more efficient or cost-effective solutions to Long-Term 
Transmission Needs,'' and ``[a]s a result, such selected Long-Term 
Regional Transmission Facilities would be less likely to be 
developed, and the benefits that these facilities would provide 
would not be realized.'' \210\ Both arguments are without merit.
---------------------------------------------------------------------------

    \208\ 295 F.3d 1.
    \209\ E.g., Final Rule, 187 FERC ] 61,068 at P 1363 & n.2909; 
id. P 1356 n.2895.
    \210\ Id. P 1293.
---------------------------------------------------------------------------

i. The Final Rule Takes Far Too Broad a View of Atlantic City

    84. Atlantic City is often discussed as a bar to FERC's ability 
to take meaningful action on many issues, including transmission 
cost allocation.\211\ But Atlantic City does not stand for an 
outright prohibition on Commission action, especially under FPA 
section 206, under which this pretextual rule purports to act. All 
Atlantic City stands for is that ``transmission-owning utilities 
have `filing rights' under section 205 that FERC may not revoke.'' 
\212\ Atlantic City does not prevent FERC from granting additional 
filing rights to other entities, including state regulators, if it 
determines that existing practices, including RTO independence, are 
unjust and unreasonable and unduly discriminatory or 
preferential.\213\
---------------------------------------------------------------------------

    \211\ 295 F.3d at 9-11.
    \212\ See also Peskoe Article at 572 (emphasis added), a 
thorough and helpful distillation of the intricacies of FPA sections 
205 and 206 as to RTO governance. See also id. at 567.
    \213\ See id. at 614-615 (``To bolster RTO independence, FERC 
could expand filing rights over regionally significant issues that 
are currently controlled by the [investor-owned utilities (IOUs)], 
such as cost allocation for regional transmission expansion. . . . 
State regulators are also potential beneficiaries. State utility 
commissions comprehensively regulate IOUs' local service and are 
familiar with IOUs' local operations and planning. State filing 
rights might serve a consumer protection function, as state 
regulators are ultimately responsible for ensuring that retail 
rates, which include costs of RTO-planned transmission projects and 
RTO-administered markets, appropriately account for consumers' 
interests. As noted, MISO and SPP agreements already provide state 
regulators with limited filing rights over transmission cost 
allocation or resource adequacy, two areas where states have 
overlapping oversight . . . . Providing states with meaningful roles 
in RTO processes might mitigate future conflicts between states' 
priorities and RTO rules and planning processes.'') (emphases added) 
(footnotes omitted). Let me add my strong endorsement to granting 
states section 205 filing rights with respect to cost allocation. 
The final rule, of course, goes in the opposite direction.
---------------------------------------------------------------------------

    85. In a similar vein, Atlantic City does not require FERC to 
force non-consenting states to pay for other states' policy 
projects, as today's final rule implies.\214\ The final rule's 
reliance on Atlantic City in this regard is simply a way for FERC to 
sidestep action that will truly ensure that needed transmission gets 
built with the cooperation, support, and assent of the states. 
Instead, what we have in today's final rule is a patent instance of 
regulatory capture with the singular goal to build out preferential 
policy and corporate-driven projects, steamrolling the states and 
consumers alike. And to be clear, nothing meaningfully prevents the 
NOPR compromise that would have maintained or elevated the states' 
role in transmission planning and cost allocation even further. In 
fact, even accounting for Atlantic City, the NOPR compromise was a 
worthwhile solution to getting the transmission that is actually 
needed to serve organic load built.
---------------------------------------------------------------------------

    \214\ See e.g., Final Rule, 187 FERC ] 61,068 at PP 1356 n.2895, 
1429-1431.
---------------------------------------------------------------------------

ii. The Commission Fails Consumers by Unreasonably and Unfairly 
Socializing Policy- and Corporate-Driven Costs Across Captive Customers

    86. The final rule's claim that the Long-Term Regional 
Transmission Facilities selected are ``the more efficient or cost-
effective solutions to Long-Term Transmission Needs'' \215\ is 
disingenuous. As I discuss above in Section I, in a sleight of hand 
move, the final rule lumps together in one bucket for planning and 
for cost allocation purposes projects that address policy-driven and 
corporate-driven needs with those that address reliability and 
economic needs. The final rule's goal is to socialize the costs 
associated with preferential policy and corporate-driven projects 
across the multi-state regions, even when the states have never 
consented for their consumers to pay for such projects. But

[[Page 49581]]

requiring the ratepayers of a non-consenting state to pay for the 
public policy projects of another state cannot reasonably be deemed 
``efficient'' or ``cost-effective.''
---------------------------------------------------------------------------

    \215\ Id. P 1293.
---------------------------------------------------------------------------

2. The Final Rule Requires Consumers in Non-Consenting States To Pay 
the Costs of Other States' Public Policy Projects

a. The Costs of Public Policy-Driven Projects Must Not Be Imposed on 
Non-Consenting Consumers Without State Regulatory Oversight

    87. In my NOPR Concurrence, I noted that ``no individual state's 
consumers can be forced to bear the costs of another state's policy-
driven project or element of a project against its consent.'' \216\ 
I have adamantly maintained this position in subsequent Statements:
---------------------------------------------------------------------------

    \216\ NOPR Concurrence at P 12 (citing NOPR, 179 FERC ] 61,028 
at PP 302, 312).

    The costs related to a public policy project . . . should be 
borne by the sponsoring state and not shifted to consumers in other 
states without the consent of responsible officials in those states, 
who can then be held accountable by the voters of that state for 
their decisions (as can officials in the sponsoring state). That is 
how democracy is supposed to work.\217\
---------------------------------------------------------------------------

    \217\ N.Y. Power Auth., 185 FERC ] 61,102 (2023) (Christie, 
Comm'r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-nypas-abandoned-plant-incentive-el23; N.Y. Indep. Sys. Operator, Inc., 180 FERC ] 61,004 
(2022) (Christie, Comm'r, concurring at P 2).

    I have explained that if the people and businesses of the 
sponsoring state do not like the impacts of their state's public 
policies, ``their recourse is to the ballot box,'' \218\ but that in 
contrast, ``[c]onsumers in other states do not have such recourse, 
which is why these costs must be confined to [the sponsoring 
state].'' \219\
---------------------------------------------------------------------------

    \218\ E.g., N.Y. Indep. Sys. Operator, Inc., 178 FERC ] 61,101 
(2022) (Christie, Comm'r, concurring at P 5), https://www.ferc.gov/news-events/news/item-e-2-commissioner-mark-c-christie-concurrence-regarding-new-york-independent.
    \219\ N.Y. Indep. Sys. Operator, Inc., 186 FERC ] 61,184 (2024) 
(Christie, Comm'r, concurring at P 2).
---------------------------------------------------------------------------

    88. I have written before that ``imposing the costs of a project 
driven by one state's public policies onto another state that has 
not consented to such cost allocation would, in my view, presumably 
result in unjust and unreasonable rates.'' \220\ Such imposition 
would be contrary to basic fairness, a core principle of American 
democracy:
---------------------------------------------------------------------------

    \220\ NSTAR Elec Co., 179 FERC ] 61,200 (2022) (Christie, 
Comm'r, concurring at P 10), https://www.ferc.gov/media/e-13-er22-1247-000; see also N.Y. Indep. Sys. Operator, Inc., 178 FERC ] 
61,101 (Christie, Comm'r, concurring at P 6) (``A similar analysis 
could well lead to a different outcome in a multi-state RTO, if the 
record showed that the RTO was implementing one state's public 
policies as to preferred resources, and that implementation resulted 
in impacts being shifted to consumers in one or more other states in 
the multi-state RTO. Such impacts and cost-shifting in multi-state 
RTOs, if proven by the record, could well be unjust, unreasonable 
and unduly discriminatory or preferential under the FPA.'') 
(emphasis in the original and added); N.Y. Pub. Serv. Comm'n v. N.Y. 
Indep. Sys. Operator, Inc., 174 FERC ] 61,110 (2021) (Christie, 
Comm'r, concurring at P 3) (``I also note that the NYISO is a 
single-state ISO and I have been able to locate no evidence in the 
record that the New York policies at issue in today's order are 
causing cost-shifting onto consumers in other states. If consumers 
in other states were disadvantaged, I may well view this matter 
differently.'') (emphasis added), https://www.ferc.gov/news-events/news/item-e-2-commissioner-mark-c-christie-concurrence-regarding-new-york-state-public; cf. Commissioner Mark C. Christie, Fair RATES 
Act Statement on PJM Minimum Offer Price Rule (MOPR) Revisions, 
Docket No. ER21-2582-000 at P 6 (Oct. 19, 2021) (``I would have 
proposed that PJM formulate a replacement for the current MOPR based 
on three broad principles: (1) a state may designate specific or 
categorical resources as `public policy resources' and such 
designated resources will be funded through a mechanism chosen by 
the state outside of the capacity market . . . and (3) non-
sponsoring state consumers would not be forced to pay for another 
state's designated public-policy resources.'') (footnotes omitted) 
(emphasis in the original and added), https://www.ferc.gov/news-events/news/commissioner-christies-fair-rates-act-statement-pjm-mopr.

    For if democracy means anything at all, it means that the people 
have an inherent right to choose the legislators to whom the people 
grant the power to decide the major questions of public policy that 
impact how the people live their daily lives. . . . That is the 
basic constitutional framework of the United States and it is the 
same for any liberal democracy worth the name.\221\
---------------------------------------------------------------------------

    \221\ Certificate Dissent at P 63.

    The final rule subverts this principle.\222\
---------------------------------------------------------------------------

    \222\ Infra Section IV.B.2.b.
---------------------------------------------------------------------------

b. Certain States Are Not ``Cost Causers'' for Cost Allocation Purposes

    89. Today's final rule provides very little in the way of 
support for its cost allocation requirements, despite the extensive 
changes to planning requirements.\223\ This final rule simply 
assumes that it is on sound footing as to cost causation. But that 
is not the case. While some precedent cited by today's final rule 
sheds some indirect light on the cost allocation issues implicated 
here,\224\ at its core, today's final rule involves a new 
application of the cost causation principle to justify the final 
rule's pretextual agenda. It intends to force consumers in one state 
to pay for the costs of public policies enacted by politicians in 
another state and corporate purchasing preferences. But those costs 
and the resulting rates cannot be considered just and reasonable in 
any universe.
---------------------------------------------------------------------------

    \223\ See, e.g., Final Rule, 187 FERC ] 61,068 at PP 266, 269, 
279, 1304, 1478-1479.
    \224\ As an aside, I question whether some of the precedent 
cited by today's final rule in support of the cost causation issue 
is truly apposite when you look at the facts in those cases.
---------------------------------------------------------------------------

    90. We are at the point where we must argue that not all 
consumers in certain states are ``cost causers'' simply because they 
have joined a multi-state RTO or fall within a transmission planning 
region. These consumers are not the ``but for'' cause of many of the 
Long-Term Transmission Needs required by the consideration of the 
specified categories of factors in today's policy agenda-driven 
rule. Nor are such consumers the intended beneficiaries of public 
policies in states enacted by politicians for whom they never voted. 
Indeed, absent rational limits on the ``free rider'' concept that 
the cost causation principle is meant to address, anyone can be 
deemed a beneficiary of any transmission project anywhere.
    91. That policy-caused costs cannot be attributed to consumers 
who did not cause the policy is consistent with case law. As 
articulated mostly clearly by the D.C. Circuit, the cost causation 
principle means that ``all approved rates [must] reflect to some 
degree the costs actually caused by the customer who must pay 
them.'' \225\ This has been oft repeated by many courts over the 
years, including most notably the U.S. Court of Appeals for the 
Seventh Circuit (Seventh Circuit) in Illinois Commerce Commission v. 
FERC.\226\ The Seventh Circuit expanded on this further to state 
that, ``[t]o the extent that a utility benefits from the costs of 
new facilities, it may be said to have `caused' a part of those 
costs to be incurred, as without the expectation of its 
contributions the facilities might not have been built, or might 
have been delayed.'' \227\
---------------------------------------------------------------------------

    \225\ KN Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 
1992) (emphasis added).
    \226\ 576 F.3d 470, 476 (7th Cir. 2009) (ICC).
    \227\ Id.
---------------------------------------------------------------------------

    92. Tied to the cost causation principle is the concept of 
``free ridership.'' As explained by the Commission in Order No. 
1000-A, a free rider is an ``entity is not required to pay for a 
benefit it receives'' \228\ and is the form of ``subsidization'' 
against which the cost causation principle is supposed to 
protect.\229\
---------------------------------------------------------------------------

    \228\ Order No. 1000-A, 139 FERC ] 61,132 at P 573.
    \229\ Id. P 578.
---------------------------------------------------------------------------

    93. As explained in Order No. 1000-A, the Commission treats each 
transmission customer not as using a single transmission path but 
rather as usual the entire transmission system and views such 
service as service over the entire grid.\230\ The Commission 
explained:
---------------------------------------------------------------------------

    \230\ Id. P 560 (citations omitted).

    Given the nature of transmission operations, it is possible that 
an entity that uses part of the transmission grid will obtain 
benefits from transmission facility enlargements and improvements in 
another part of that grid regardless of whether they have a contract 
for service on that part of the grid and regardless of whether they 
pay for those benefits. This is the essence of the ``free rider'' 
problem the Commission is seeking to address through its cost 
allocation reforms. Any individual beneficiary of a new transmission 
facility has an incentive to defer investment in the anticipation 
that other beneficiaries in the region will value the project enough 
to fund its development. This can lead to situations in which no 
developer moves forward, adversely affecting development of 
transmission facilities and, as a result, rates for jurisdictional 
services.\231\
---------------------------------------------------------------------------

    \231\ Id. P 562 (internal citation omitted).

    Therefore, the Commission explained that the cost allocation 
provisions of Order No. 1000 (the failures of which allegedly 
justify the changes contemplated by today's final rule), which seek 
to allocate costs to beneficiaries in a region roughly commensurate 
with benefits they receive, were consistent with the statement in 
ICC

[[Page 49582]]

that ``[a]ll approved rates [must] reflect to some degree the costs 
actually caused by the customer who must pay them.'' \232\ Indeed, 
all of the precedent relied upon in today's final rule signals that 
free ridership is a concern solely based on the assumptions 
underlying the transmission planning. And herein lies the 
deception--the more you plan and account for, the bigger and more 
regionalized you can argue the cost allocation framework should be. 
Which makes sense when the goal of today's final rule is to enact a 
sweeping policy agenda and thus socialize the costs across consumers 
in a multi-state region.
---------------------------------------------------------------------------

    \232\ Id. P 565 (citing ICC, 576 F.3d 470 at 476) (alterations 
in the original). In Order No. 1000, the Commission also found that 
``[b]eneficiaries in one state are not subsidizing anyone in another 
state when they are allocated costs that are commensurate with the 
benefits that accrue to them, even if the transmission facility in 
question was built in whole or part as a result of the other state's 
transmission needs driven by Public Policy Requirements.'' Order No. 
1000, 136 FERC ] 61,051 at P 545. ``If no benefits accrue, the cost 
allocation principles we adopt below would prohibit the allocation 
of costs to the non-beneficiaries. If benefits do accrue, however, 
there are no less benefits because Public Policy Requirements played 
a role in the decision to construct the transmission facility.'' Id. 
While Order No. 1000 may have successfully established this to be 
the case, per South Carolina, today's final rule is not similarly 
situated to Order No. 1000 with its required minimum benefits, 
selection criteria, and utter disregard of the states' role in 
planning and cost allocation. See supra Section III.A. Today's final 
rule instead creates beneficiaries for projects that are primarily 
public policy-driven, based on the categories of factors required to 
be considered in today's final rule's planning requirements.
---------------------------------------------------------------------------

    94. The main support for the cost causation principle is 
ICC,\233\ for the exact quote noted above. However, often omitted 
from the discussion of ICC is the context and outcome of the case. 
In that case, the Seventh Circuit remanded the Commission's approval 
of cost allocation concerning ``Project Mountaineer'' \234\ (yes, 
the same one that prompted PATH) for lack of substantial evidence 
regarding the FERC-approved cost allocation. In addition to the 
quote above, the Seventh Circuit also expressed the following: 
``FERC is not authorized to approve a pricing scheme that requires a 
group of utilities to pay for facilities from which its members 
derive no benefits, or benefits that are trivial in relation to the 
costs sought to be shifted to its members.'' \235\ And it merits 
repeating that ``[t]o the extent that a utility benefits from the 
costs of new facilities, it may be said to have `caused' a part of 
those costs to be incurred, as without the expectation of its 
contributions the facilities might not have been built, or might 
have been delayed.'' \236\ So, given the extent to which the Long-
Term Transmission Needs contemplated by today's final rule factor in 
state public policies and special interests' goals, you would expect 
the only beneficiaries for cost allocation purposes to be states 
with those public policies or other special interest drivers of the 
transmission.
---------------------------------------------------------------------------

    \233\ 576 F.3d 470.
    \234\ See PATH Concurrence at P 4 (providing a history on 
Project Mountaineer). Relying on a case that remanded the 
Commission's approval of cost allocation associated with a regional 
transmission project that never came to fruition is nothing short of 
ironic.
    \235\ ICC, 576 F.3d at 476 (emphasis added).
    \236\ Id. (emphasis added). See NARUC Initial Comments at 33-34 
(``Long-Term Regional Transmission Planning must recognize that 
benefits inherently become more speculative as the planning horizon 
increases. Additionally, planning based on public policy objectives 
must be transparent about identifying projects that would not be 
selected but for those public policy objectives. Benefits assigned 
to projects must recognize these principles.'') (emphasis added).
---------------------------------------------------------------------------

    95. Unfortunately, you would be wrong. Due to the final rule 
requiring planning for any and every transmission need and mandating 
minimum reliability and economic benefits as part of the planning 
process, projects developed primarily for preferential policy and 
corporate purposes will necessarily have the broadest array of so-
called beneficiaries possible, all identified prior to 
selection.\237\ These so-called beneficiaries will then be forced to 
pay for these projects, simply because they may receive some trivial 
benefits due to their participation in a regional transmission 
system. These so-called beneficiaries will be treated as ``cost 
causers'' even though their contributions do not ensure the projects 
get built nor ensure that the projects are not delayed. Today's 
final rule, of course, even emphasizes that, as to why today's final 
rule does not require the consideration of public policy benefits, 
it ``does not allow allocation of costs based on benefits to 
entities that do not receive benefits or receive only trivial 
benefits in relationship to costs of those transmission 
facilities.'' \238\ But this is because today's final rule already 
determined the minimum reliability and economic benefits that all 
projects contemplated by the final rule must have. Adding in public 
policy benefits would shift the resulting cost allocation to show 
the actual beneficiaries--the states with preferred policies and 
corporate and special interests. So, through a mismatch in planning 
criteria and benefits, today's final rule ensures socializing the 
costs of preferential policy and corporate-driven projects onto 
states and consumers that will ultimately receive trivial benefits, 
in violation of ICC. If you find all this confusing, the final rule 
is intended to be. That's why it's a shell game.
---------------------------------------------------------------------------

    \237\ See supra Sections I, III.A; see also Final Rule, 187 FERC 
] 61,068 at P 965.
    \238\ Final Rule, 187 FERC ] 61,068 at P 1515. This is why I 
have described this final rule as a shell game with respect to the 
issue of the benefit mismatch between planning and costs. By making 
the minimum required benefits reliability- and economic-focused, 
today's final rule ensures that the ``beneficiaries'' are those that 
are receiving some reliability and economic benefits. As we know 
from basic transmission planning, any transmission built is going to 
bring some reliability and economic benefits. So, any transmission 
planned through Long-Term Regional Transmission Planning for the 
identified Long-Term Transmission Needs will necessarily bring some 
reliability and economic benefits. And by not requiring a matching 
of benefits to the Long-Term Transmission Needs that are planned 
for, in this case public policy benefits, the resulting benefits of 
any one project will be skewed to indicate more ``beneficiaries'' 
than there would be if today's final rule accounted for public 
policy benefits separately. See NARUC Initial Comments at 33-34. If 
today's final rule accounted for public policy benefits or corporate 
goals separately, it would be clear who the actual drivers, and 
actual beneficiaries, of any one project are.
---------------------------------------------------------------------------

    96. At its core, ICC is simply a baseline regarding the cost 
causation principle's application. That is, the Commission cannot 
require cost allocation to a particular group of utilities, i.e., 
consumers, where there is no evidence of benefits. Its findings 
should not be distorted, as today's final rule suggests through 
Orwellian newspeak, to support a mismatch of planning criteria to 
benefits to strongarm a cost allocation regime to get preferential 
policy and corporate-driven projects built.
    97. Also referenced by today's final rule for cost causation is 
South Carolina.\239\ In the context of cost causation, the D.C. 
Circuit concluded that ``the Commission's adoption of a beneficiary-
based cost allocation method is a logical extension of the cost 
causation principle.'' \240\ The court added that it had ``endorsed 
the approach of `assign[ing] the costs of system-wide benefits to 
all customers on an integrated transmission grid.' '' \241\
---------------------------------------------------------------------------

    \239\ 762 F.3d 41.
    \240\ Id. at 85.
    \241\ Id. (citations omitted).
---------------------------------------------------------------------------

    98. The final rule does not simply require a beneficiary-based 
cost allocation, like Order No. 1000. Instead, as I must continue to 
emphasize, it requires mandating reliability and economic benefits 
during the planning process to shoehorn the broadest group of 
beneficiaries possible for projects that do not remotely relate to 
reliability and economic needs.\242\ This is not a ``light touch'' 
that ``does not dictate how costs are to be allocated.'' \243\ 
Today's final rule may attempt to sequester the beneficiaries of 
these reliability and congestion benefits from the cost allocation 
``benefits'' by not clearly linking the two,\244\ but in what 
reality will a transmission provider seeking to comply with today's 
final rule identify different beneficiaries from those identified in 
the planning process? The result of this shell game is to ensure 
preferential policy and corporate-driven projects are selected with 
the widest group of beneficiaries possible, so as to socialize the 
costs across the widest group of consumers.\245\
---------------------------------------------------------------------------

    \242\ See supra Sections I, III.A.
    \243\ See South Carolina, 762 F.3d at 81; see also supra Section 
III.A.
    \244\ See, e.g., Final Rule, 187 FERC ] 61,068 at P 1506 (``We 
do not require that any particular benefit used in the evaluation 
and selection of Long-Term Regional Transmission Facilities be 
reflected in a Long-Term Regional Transmission Cost Allocation 
Method filed with the Commission.''). This provision illustrates the 
confusing and contradictory nature of the final rule and provides 
another example of the shell game.
    \245\ Today's final rule relies on several other cases in 
support of its oversimplification of the cost causation principle, 
such as Old Dominion Electric Coop. v. FERC, 898 F.3d 1254 (D.C. 
Cir. 2018), and Long Island Power Authority v. FERC, 27 F.4th 705 
(D.C. Cir. 2022), among others, but the same is true of these 
cases--the Commission cannot strong-arm beneficiaries to get 
transmission built, and override the states to do so. Of course, 
this is primarily a problem in multi-state RTOs, but overriding the 
states with regulation based on a cooperative federalism statute is 
not in good faith and the result is terrible for consumers 
everywhere.

---------------------------------------------------------------------------

[[Page 49583]]

    99. Today's final rule ultimately presents the wrong solution to 
the perceived problem of ``balkanized'' transmission planning.\246\ 
Unfortunately, today's final rule devises the shell game to ensure 
that the biggest planning bucket means the biggest pool of potential 
beneficiaries. And to carry out the shell game, the final rule walks 
back cost allocation principle (6) because, without this change, 
today's final rule's preferred cost allocation framework does not 
work.\247\
---------------------------------------------------------------------------

    \246\ See supra Section IV.A.
    \247\ See Final Rule, 187 FERC ] 61,068 at P 1474.
---------------------------------------------------------------------------

    100. NARUC and many individual states oppose the Commission's 
imposition of mandatory minimum benefits and would prefer a bottom-
up rather than a top-down approach: ``The proposed list of benefits 
for consideration is a better way to accomplish the objectives of 
the NOPR than specification of benefits that must always be used in 
Long-Term Regional Transmission Planning.'' \248\ Today's final rule 
blithely brushed these concerns aside.
---------------------------------------------------------------------------

    \248\ See NARUC Comments at 25; see also New York Commission and 
NYSERDA Initial Comments at 7 (``We urge the Commission to ensure 
that any final rule in this proceeding is sufficiently flexible to 
accommodate regional differences and avoid disrupting the processes 
already in place and otherwise underway in New York that are working 
well for the region.''); SPP Initial Comments at 18 (``How and when 
transmission benefits are calculated and incorporated in any 
regional transmission planning assessment should be at the 
discretion of each public utility transmission provider and its 
stakeholders. This would allow for agility in process decisions to 
balance the value the analysis provides with the burden of the 
effort.''); ISO-NE Initial Comments at 5 (``Individual regions 
should be permitted to determine the benefits that will lead to 
transmission in the region.''); NYISO Initial Comments at 39 (``The 
final rule should confirm that each planning region is not required 
to use the specific benefits described in the NOPR . . . . While, in 
practice, the NYISO already uses most of the 12 illustrative 
benefits identified in the NOPR, the NYISO should be permitted to 
retain its flexibility to identify, with input from state entities 
and stakeholders, the benefits used in its processes and how such 
benefits are calculated.''); id. at 11 (``The final rule should not 
mandate strict requirements concerning how long-term transmission 
planning must be conducted.'').
---------------------------------------------------------------------------

    101. To effectuate purported compliance with the cost causation 
principle, today's final rule ignores the principle of the optimal 
solution in transmission planning. For each identified reliability 
problem, there is an optimal solution that solves the reliability 
problem at the least cost to consumers. For an economic project, 
consumers should receive the maximum reduction in congestion costs 
relative to the cost of the project, or put in another way, for a 
given reduction of congestion costs, consumers should pay the least 
costs for the project. The final rule, by contrast, claims that a 
project that is driven by one state's public policies will still 
provide some reliability and congestion benefits to other states, so 
consumers in those states must be treated as beneficiaries.\249\ But 
even assuming that consumers in those other states hypothetically 
receive some marginal reliability or congestion benefits, they are 
being overcharged for those benefits because the project includes 
the costs of another state's public policies or costs of projects to 
meet corporate goals, and the only benefits required to be 
considered by today's final rule are reliability and economic 
benefits. Consumers in the non-policy causing states are not 
receiving or paying for the optimal solution to an identified 
reliability problem or maximum congestion relief compared to the 
costs they are being forced to pay. As a consequence, the 
transmission rates--let's ignore the planning practices for a 
moment--they will be forced to pay are clearly unjust and 
unreasonable under the FPA.
---------------------------------------------------------------------------

    \249\ Final Rule, 187 FERC ] 61,068 at Section III.D.1.c.
---------------------------------------------------------------------------

3. The Final Rule Violates the Commission's Consumer Protection Duty 
Under the FPA

    102. To add to the number of already unjust and unreasonable 
aspects in today's final rule, today's final rule is patently unfair 
to consumers. That much is apparent from its decision, through 
transmission planning and cost allocation processes: (1) to shift 
interconnection costs from generation developers to consumers 
through transmission planning, and (2) to shift the costs of, inter 
alia, a transmission project accommodating a corporate commitment 
from corporate consumers to other consumers. Today's final rule, 
equally harmful to consumers, walk backs the NOPR proposal to remove 
the CWIP Incentive, one of the major reasons I supported the NOPR in 
the first place. The final rule essentially uses the justification 
of efficiency and cost-effectiveness to create catastrophic outcomes 
for consumers. Such an anti-consumer outcome is simply unjust and 
unreasonable, and in this case, even unduly discriminatory and 
preferential.

a. The Final Rule Unlawfully Shifts Interconnection Costs From 
Developers to Consumers

    103. In prior statements, I have frequently discussed the basic 
principle that generation developers should pay the costs to 
interconnect their generators to the grid:

    [G]eneration developers in RTOs should pay the full ``but for'' 
costs of their interconnection, including network upgrades. 
Consumers (i.e., load) should not pay one nickel. They are not the 
ones seeking to profit from the interconnection. New generation in 
RTOs is supposed to be driven by the market, not by integrated 
resource planning, as in non-RTOs. This is the compelling principle 
underlying participant funding of interconnection in RTOs.\250\
---------------------------------------------------------------------------

    \250\ See Midcontinent Indep. Sys. Operator, Inc., 184 FERC ] 
61,190 (2023) (Christie, Comm'r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-mpfca-order-concerning-funding; Midcontinent Indep. Sys. 
Operator, Inc., 184 FERC ] 61,156 (2023) (Christie, Comm'r, 
concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-gia-order-concerning-funding; Midcontinent Indep. Sys. Operator, Inc., 183 FERC ] 61,113 
(2023) (Christie, Comm'r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-fsa-order-concerning-funding; Midcontinent Independent System Operator, Inc., 
182 FERC ] 61,225 (2023) (Christie, Comm'r, concurring at P 2), 
https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-mpfca-and-fsa-orders-concerning-funding; see also 
Midcontinent Indep. Sys. Operator, Inc., 185 FERC ] 61,182 (2023), 
order on reh'g, 187 FERC ] 61,015 (2024), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-order-rejecting-miso-gia-concerning-funding. This principle also applies to developers of 
merchant transmission lines who seek to interconnect. Midcontinent 
Indep. Sys. Operator, Inc., 181 FERC ] 61,218 (2022) (Christie, 
Comm'r, concurring at P 1), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-funding-interconnection-costs-rtos. If state regulators in a multi-state 
region agreed on a different cost allocation related to 
interconnection costs that they believed protected consumers from 
unfair treatment, then such alternative would merit consideration.

    By requiring the coordination of regional transmission planning 
and generator interconnection processes and by requiring the 
incorporation of Factor Category Six: generator interconnection 
requests and withdrawals in the development of Long-Term Scenarios, 
the final rule causes consumers to subsidize generation developers 
and thus subverts this basic principle.

i. Coordination of Regional Transmission Planning and Generator 
Interconnection Processes Will Result in Unlawful Cost Shifts to 
Consumers

    104. The final rule requires transmission providers in each 
transmission planning region to revise their existing Order No. 1000 
regional transmission planning processes to evaluate for selection 
regional transmission facilities that address certain identified 
interconnection-related transmission needs associated with certain 
interconnection-related network upgrades originally identified 
through the generator interconnection process.\251\ As a result of 
this requirement, transmission providers may select in regional 
transmission plans for purposes of cost allocation transmission 
facilities designed to address certain interconnection needs and 
will allocate the costs of such facilities to the load in that 
region. This practice will force consumers to subsidize the 
interconnection costs of generator developers and in so doing turn 
them into the banks for the ventures, viable or otherwise, of 
generation developers--a classic example of the socialization of 
costs to enable private profit. Of course, this will result in rates 
that are blatantly unjust, unreasonable, unduly discriminatory and 
preferential.
---------------------------------------------------------------------------

    \251\ Final Rule, 187 FERC ] 61,068 at PP 1106-1107, 1126, 1145. 
Specifically, the final rule requires transmission providers to 
evaluate for selection regional transmission facilities to address 
interconnection-related transmission needs that have been identified 
in the generator interconnection process as requiring 
interconnection-related network upgrades where, inter alia, ``an 
interconnection-related network upgrade identified to meet those 
interconnection-related transmission needs has a voltage of at least 
200 kV and an estimated cost of at least $30 million.'' Id. P 1145 
(emphasis in original).
---------------------------------------------------------------------------

    105. The final rule's attempted justifications for this effort 
to shift interconnection costs to consumers are vacuous and fail to 
disguise the real agenda, which is to subsidize developers of 
preferred

[[Page 49584]]

resources. For example, the final rule asserts that reforms are 
necessary because ``it may be more efficient or cost-effective to 
address [interconnection-related transmission needs] through the 
regional transmission planning and cost allocation process.'' \252\ 
The final rule professes that its requirements ``will result in 
selection of more efficient or cost-effective regional transmission 
solutions that will provide benefits to the transmission system, 
cost allocation for such regional transmission facilities that is at 
least roughly commensurate with estimated benefits, and elimination 
of a barrier to entry for new generation resources (which will 
enhance competition in wholesale electricity markets and facilitate 
access to lower-cost generation).'' \253\ But more efficient or 
cost-effective for whom? Certainly not for consumers who will be 
conscripted to subsidize tens or hundreds of millions of dollars of 
interconnection costs so that generator developers may more cheaply 
interconnect and make higher profits (and likely receive government 
subsidies). The final rule's speculation that extracting such 
subsidies from consumers will ``facilitate access to lower-cost 
generation'' is purely pretextual.
---------------------------------------------------------------------------

    \252\ Id. P 1110.
    \253\ Id.
---------------------------------------------------------------------------

    106. The final rule notes that ``the Commission has found, and 
courts have affirmed, that interconnection-related network upgrades 
identified in the generator interconnection process can provide 
widespread transmission benefits that extend beyond the 
interconnection customer.'' \254\ Further, it asserts that the 
regional transmission facilities designed to address the 
interconnection needs ``may have the potential to provide more 
widespread benefits to transmission customers.'' \255\ Today's final 
rule does not even come close to justifying the enormous cost shifts 
this will place on consumers.
---------------------------------------------------------------------------

    \254\ Id. (footnote omitted).
    \255\ Id. PP 1146-1148.
---------------------------------------------------------------------------

    107. The final rule summarily brushes aside the concern that its 
reform will shift interconnection costs from interconnection 
customers (i.e., generation developers) to load.\256\ It explains 
that ``[t]ransmission providers will still have to evaluate and 
select any regional transmission facilities that address the 
interconnection-related transmission needs as the more efficient or 
cost-effective regional transmission solution as part of the 
regional transmission planning process in order for any regional 
cost allocation method to apply.'' \257\ The final rule also 
explains that ``if such a facility is selected, the Commission-
approved ex ante regional cost allocation method for that facility 
would allocate its costs at least roughly commensurate with its 
estimated benefits.'' \258\ But the regional cost allocation methods 
allocate cost only to load, not to generation. So, how could 
allocating interconnection costs to load enable them to be ``roughly 
commensurate to benefits'' when generator developers, the primary 
beneficiaries of the transmission facilities and the ``but for'' 
cause of their development be allocated nothing? Here, as elsewhere, 
the final rule deviates from the FPA's consumer protection purpose: 
under the final rule, rather than generation existing to serve load, 
load is being conscripted to serve (the profits) of generation.
---------------------------------------------------------------------------

    \256\ See id. P 1117.
    \257\ Id.
    \258\ Id.; see also id. P 1110.
---------------------------------------------------------------------------

    108. Finally, the final rule's conclusion that it will not 
incentivize gaming by interconnection customers to include 
interconnection-related network upgrades in the regional 
transmission planning process is detached from reality.\259\ The 
final rule notes that interconnection requests require significant 
financial commitments from the interconnection customer (e.g., 
application fees, study deposits, and site control requirements) and 
that interconnection customers employing such a strategy would face 
several risks.\260\ As with so much FERC does, today's final rule 
woefully underestimates at its peril the profit-seeking, and at 
times, gambling behavior of generator developers. In issuing this 
final rule, the Commission appears to forget that a main driver in 
issuing Order No. 2023 was to reduce speculative interconnection 
requests and interconnection request withdrawals spurred by this 
behavior.\261\ Despite the significant financial commitments and 
risks that the final rule describes, I can foresee generators 
submitting speculative or spurious interconnection requests in the 
efforts to be subsidized by load if the estimated interconnection 
costs are high enough. In any event, I think it obvious that, 
ceteris paribus, the final rule will encourage more disruptive 
withdrawals--particularly for requests that necessitate high 
interconnection costs--as the final rule provides generator 
developers dissatisfied with high interconnection costs a chance at 
another bite at the apple. And of course, apples taste sweeter when 
they're paid for by someone else.
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    \259\ See id. PP 1119-1120.
    \260\ Id. P 1119.
    \261\ See, e.g., Order No. 2023, 184 FERC ] 61,054 at P 47 
(stating that the existing serial first-come, first-served study 
process ``create[d] incentives for interconnection customers to 
submit exploratory or speculative interconnection requests pursuant 
to which interconnection customers seek to secure valuable queue 
positions as early as possible, even if they are not prepared to 
move forward with the proposed generating facility. Such generating 
facilities are often not commercially viable and, thus, the 
interconnection customers ultimately withdraw from the 
interconnection queue.'').
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ii. Factor Category Six Will Result in Unlawful Cost Shifts to 
Consumers

    109. For similar reasons, I oppose the final rule's requirement 
that transmission providers in each transmission planning region 
incorporate in the development of Long-Term Scenarios, Factor 
Category Six: interconnection requests and withdrawals.\262\ Such a 
requirement would ultimately result in consumers paying for the 
transmission that generators need to interconnect to the grid. This 
again is a way to cost shift interconnection costs from generation 
developers to consumers.
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    \262\ See Final Rule, 187 FERC ] 61,068 at P 472.
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b. Factor Category Seven Forces Some Consumers To Subsidize Others

    110. The Commission's requirement that transmission providers 
incorporate Factor Category Seven, utility and corporate commitments 
and federal, federally-recognized Tribal, state, and local goals 
that affect Long-Term Transmission Needs, in the development of 
Long-Term Scenarios \263\ is unjust and unreasonable because it will 
unfairly saddle consumers with unnecessary transmission costs that 
they did not cause. In addition, comments on Factor Category Seven 
identify several additional regulatory and practical obstacles that 
the final rule attempts to resolve by allowing transmission 
providers to dial the impact of these commitments and goals up or 
down.\264\ Further, this provision is yet another count in the final 
rule's pattern of diminishing the states' role in regional 
transmission planning by elevating mere corporate preferences to 
have equal if not greater stature as the policy choices of states 
and federally-recognized Tribes.
---------------------------------------------------------------------------

    \263\ Id. PP 481-484.
    \264\ Id. P 484.
---------------------------------------------------------------------------

    111. It is worth starting the examination of Factor Category 
Seven simply by pulling the curtain back and highlighting the 
coalitions of comments that the final rule cites supporting it and 
opposed to it.\265\ The strongest support for this provision comes 
from where we would all expect: the corporate interests with 
something to gain by shifting the costs that result from their 
preferential power purchase commitments to others along with the 
other special interests whose policy preferences have no place in 
developing a rate that is just and reasonable.\266\ I am similarly 
unsurprised that the skeptics and opponents of this provision are 
led by retail rate authorities, load-serving entities from coast to 
coast, and large multi-state RTOs. They understand that adopting 
Factor Category Seven is unfair, unworkable, and a mistake.
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    \265\ Commenters in favor include ACEG, AEE, Advanced Energy 
Buyers, Amazon, Breakthrough Energy, Center for Biological 
Diversity, Environmental Groups, [Oslash]rsted, PIOs, SEIA, and 
SREA. Id. PP 474-476. Commenters expressing qualified support 
include LADWP, MISO, and NRECA. Id. P 477. Commenters opposed 
include the Alabama Commission, California Commission, Duke, 
Illinois Commission, New York TOs, Pennsylvania Commission, PJM, and 
PPL. Id. PP 478-480.
    \266\ See James Downing, FERC Observers, Stakeholders Lay out 
What is at Stake with Tx Rule Looming, RTO Insider, Apr. 22, 2024 
(``State renewable portfolio standards are not driving as much of 
the need for new transmission as the corporate renewable energy 
buyers that [Clean Energy Buyers] represents are, [Clean Energy 
Buyers Senior Director Bryn Baker] added.''), https://www.rtoinsider.com/76831-ferc-experts-what-at-stake-transmission-rule-looming/.
---------------------------------------------------------------------------

    112. Factor Category Seven is as unlawful as it is unfair 
because it grossly violates cost causation principles of 
ratemaking.\267\ Whether a corporate commitment or a state/Tribal 
policy goal is directly attributed to increased transmission costs, 
the entities

[[Page 49585]]

with the self-imposed aspirations are the direct beneficiaries. Cost 
causation principles of ratemaking--not to mention reviewing 
courts--will dictate that those entities, and not any other 
transmission customer, are the beneficiaries of the resulting 
transmission built to accommodate the corporate commitments. As the 
direct beneficiaries, they will be responsible for the increased 
transmission costs driven by those commitments, goals, and 
preferences. Even worse, if one of these cost causers changes its 
commitment or goal, all of the transmission provider's customers 
could still be left paying for the increased costs that are no 
longer attributable to any beneficiary. This is not how a just or 
reasonable rate works.
---------------------------------------------------------------------------

    \267\ For a reminder on the shell game and how it seeks to use 
the cost causation principle, see supra Sections I, III.A, IV.B.2.b.
---------------------------------------------------------------------------

    113. Even if the unfair and unlawful Factor Category Seven is 
allowed to take effect, it will fail on its own terms for practical 
reasons. The final rule acknowledges that the corporate commitment 
or a state/Tribal policy goal are ``more likely to change over the 
transmission planning horizon than factors in other required factor 
categories.'' \268\ As a balm for this uncertainty, the final rule 
grants the transmission providers the discretion to apply the salve 
of a discount on the likelihood that any of these aspirations will 
come to pass. Nothing in the final rule will prevent transmission 
providers from discounting these commitments one hundred percent. 
This discount is simply an invitation for transmission providers to 
ignore Factor Category Seven.
---------------------------------------------------------------------------

    \268\ Final Rule, 187 FERC ] 61,068 at P 484.
---------------------------------------------------------------------------

    114. Even worse, when a transmission provider expends its 
limited resources to read the tea leaves of corporate commitments 
and include them in the Long-Term Scenarios, that inclusion will 
result in a violation of the FPA. Applying the costs of one 
corporation's commitments to all of the transmission provider's 
customers amounts to undue discrimination against similarly situated 
customers without corporate commitments while bestowing an undue 
preference for those similarly situated customers with corporate 
commitments. Further, most utility customers are at a resource and 
access disadvantage to the deep-pocketed special interests 
(including the corporate commitments driven by their wealthy and 
sophisticated investor class) that enjoy influence and power. Rather 
than sticking the consumers with any part of the bill for the gold 
plating necessary for a different customer's corporate preferences, 
this Commission should not depart from its cost allocation 
precedent. Under that precedent, the beneficiaries are required to 
pay for the upgrades they are driving. This Commission should not 
now saddle less powerful people and small businesses with the costs 
of the choices made by influential corporations and their managers 
and investors.\269\
---------------------------------------------------------------------------

    \269\ I also have grave concerns that the final rule tasks 
transmission planning engineers to try their hands at becoming Wall 
Street analysts when they attempt to guess how serious any of the 
corporate commitments really are.
---------------------------------------------------------------------------

    115. Let me be clear about how egregious and unfair this idea is 
with a hypothetical scenario. Suppose that a Fortune 500 company 
pressured by its investors commits to a corporate goal that it will 
only purchase electric power from certain preferred generation 
sources within a decade. It similarly commits to discriminate 
against power sourced from non-preferred generation resources. The 
transmission provider then informs the corporate customer that 
transmission upgrades will be necessary in order for those favored 
generation resources to actually deliver power to the corporate 
customer's facilities and to avoid receiving power from the non-
preferred resources. Next, the transmission provider includes those 
upgrades in Factor Category Seven. Later, the transmission provider 
builds the necessary upgrades according to its regional transmission 
plan and incurs significant cost in doing so. Instead of attributing 
those costs to the corporate customer, the transmission provider 
socializes the upgrade costs to all of its customers. Rather than 
holding the actual cost causer accountable for the increase, the 
final rule instead dictates that the costs directly resulting from 
the customer's corporate commitment benefit all ratepayers because 
there are necessarily reliability and economic benefits that result 
from all transmission development. Then these increased costs are 
socialized across all of the transmission provider's customers. This 
realistic outcome is, to put it mildly, grossly unfair to consumers 
and a violation of the FPA.
    116. Now suppose that a neighboring corporate customer (that 
receives an identical class of electric service as the customer in 
the prior hypothetical) announces in response its own corporate goal 
that it will never consider any factors other than reliability and 
cost in purchasing electric power because it wants to keep its costs 
as low as possible no matter what. How is a transmission provider 
supposed to accommodate that second corporate goal? Do the two 
commitments simply cancel each other out? Will the transmission 
provider carve out the second corporate customer? Where would that 
leave the customers who are silent with respect to these competing 
corporate goals? The final rule fails to answer these questions.

c. The Final Rule Walks Back the NOPR Proposal To Remove the CWIP 
Incentive

    117. Today's final rule also walks back the widely supported 
proposal to remove the CWIP transmission incentive. As I have 
discussed above, it is apparent that the pretextual goal of this 
final rule is to get transmission built to serve political and 
corporate goals, no matter the cost and no matter who actually 
benefits from it.
    118. As I noted on numerous occasions, a core principle of 
utility law and regulation for decades is that consumers can be 
forced to pay costs only for assets that are ``used and useful'' to 
them. In Order No. 679, the Commission determined that it may be 
necessary to depart from this long-standing ratemaking principle to 
``address the substantial challenges and risks in constructing new 
transmission.'' \270\ And in my prior statements, I questioned, 
among other concerns, whether the Commission's determination of 
whether ``substantial challenges and risks'' exist when granting the 
various transmission incentives has becoming nothing more than a 
check-the-box exercise.\271\ In particular, I noted:
---------------------------------------------------------------------------

    \270\ Promoting Transmission Inv. through Pricing Reform, Order 
No. 679, 116 FERC ] 61,057, at PP 26, 117, order on reh'g, Order No. 
679-A, 117 FERC ] 61,345 (2006), order on reh'g, 119 FERC ] 61,062 
(2007).
    \271\ See supra n.61.

    The Commission's incentive policies--particularly the CWIP 
Incentive, which allows recovery of costs before a project has been 
put into service--run the risk of making consumers ``the bank'' for 
the transmission developer; but, unlike a real bank, which gets to 
charge interest for the money it loans, under our existing 
incentives policies the consumer not only effectively ``loans'' the 
money through the formula rates mechanism, but also pays the utility 
a profit, known as Return on Equity, or ``ROE,'' for the privilege 
of serving as the utility's de facto lender.\272\
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    \272\ February 2022 Concurrence at P 3 (emphasis in original); 
July 2022 Concurrence at P 3 (citation omitted); see also NOPR 
Concurrence at P 15 (``CWIP is, of course, passed through as a cost 
to consumers, making consumers effectively an involuntary lender to 
the developer . . . . Consumers should be protected from paying CWIP 
costs during this potentially long period before a project actually 
enters service, if it ever does.''), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-e-1-regional-transmission-planning-and-cost.

    119. The proposal to remove the CWIP Incentive was a major 
reason why I supported the NOPR, despite its flaws, and a massive 
step in the right direction to remedy the harm to consumers that 
these incentives have caused over the years.\273\ However, instead 
of adopting the proposal to remove the CWIP Incentive, today's final 
rule chose to side with developers and special interest groups, 
rather than with consumers. Today's final rule rationalizes the 
decision to walk back the removal of the CWIP Incentive by finding 
that any action on the CWIP Incentive is more appropriately 
considered in a separate proceeding where incentives can be 
comprehensively evaluated for all regional transmission 
facilities.\274\ I regard that as nothing more than an excuse for a 
continuing failure to act.
---------------------------------------------------------------------------

    \273\ See supra PP 18-19.
    \274\ Final Rule, 187 FERC ] 61,068 at P 1547.
---------------------------------------------------------------------------

    120. Many commenters share my concerns that the CWIP Incentive 
inappropriately shifts risks to ratepayers and runs afoul of the 
core principle of utility law and regulation that consumers should 
pay costs only for assets that are ``used and useful'' to them.\275\ 
Others argue that removing the CWIP Incentive may mitigate the risk 
of

[[Page 49586]]

overbuilding that may result from the other changes cemented in 
today's final rule.\276\ Today's final rule, however, is 
astoundingly silent on the consumer impact of retaining the CWIP 
Incentive.
---------------------------------------------------------------------------

    \275\ See, e.g., California Commission Reply Comments at 14; 
Kentucky Commission Chair Chandler Initial Comments at 4-9; NARUC 
Initial Comments at 55-56 (referencing PATH and that the Commission 
granted several transmission incentives, resulting in a 14.3% return 
on equity); NASUCA Initial Comments at 8-9; North Carolina 
Commission and Staff Initial Comments at 17-18; North Dakota 
Commission Initial Comments at 6; Ohio Commission Federal Advocate 
Initial Comments at 15-16; Ohio Consumers Initial Comments at 29-31; 
OMS Initial Comments at 14-15; Pennsylvania Commission Initial 
Comments at 17-18; PJM States Initial Comments at 13; Virginia 
Attorney General Reply Comments at 3-4.
    \276\ See, e.g., Massachusetts Attorney General Initial Comments 
at 24-25; North Carolina Commission and Staff Initial Comments at 
17-18; Pennsylvania Commission Initial Comments at 17-18; PJM States 
Initial Comments at 13.
---------------------------------------------------------------------------

    121. Unfortunately, this is simply a continuation of the 
Commission punting on any meaningful reevaluation of transmission 
incentives. In my three years on the Commission, there has been no 
action to reevaluate the check-the-box award of transmission 
incentives, and it is far past time for me to begin dissenting from 
this lack of action on the Commission's part to change this shameful 
status quo.\277\ By walking back the removal of the CWIP Incentive, 
today's final rule reveals, one again, its failure to protect 
consumers as required by the FPA.
---------------------------------------------------------------------------

    \277\ See, e.g., Baltimore Gas & Elec. Co., 187 FERC ] 61,030 
(Christie, Comm'r, dissenting at P 6).
---------------------------------------------------------------------------

V. Conclusion

    122. Had the states been given the authority to protect their 
consumers, as promised by the NOPR, I would have supported this rule 
just as I voted for the NOPR, as an imperfect but acceptable 
compromise.\278\ If transmission projects that are planned to 
implement public policies--the product of political decisions made 
by politicians--or to implement corporate ``green energy'' power 
purchasing preferences--the product of corporate management and 
investors--are going to be included in long-term planning mandated 
by FERC, then the states must have the authority to consent to (i) 
the planning criteria (which determines which projects go into 
regional plans and receive cost recovery from consumers), and (ii) 
the formula for regional cost allocation of such projects.
---------------------------------------------------------------------------

    \278\ To reiterate what I said earlier: If I agree to get a root 
canal with anesthetic but learn upon arrival at the dentist's office 
that I still get the root canal but no anesthetic, that is not the 
original deal.
---------------------------------------------------------------------------

    123. This role for the states is not only essential but fair: 
fair to state policymakers and regulators and fair to the tens of 
millions of consumers they represent. The final rule, however, 
denies states that essential role and that denial renders this order 
unfair to the states and unfair to tens of millions of consumers.
    124. As has been said before, denial is not just a river in 
Egypt. The short-sightedness of the final rule and the special 
interests who lobbied this Commission to deny states this key role 
is a denial of the reality of how transmission actually gets built 
in the union of states that is the United States of America. As a 
former state regulator who voted to approve scores of transmission 
projects, both regional and local, I will testify from experience 
that to get transmission built--especially the big, controversial 
regional lines of 500 kV and above--the states should not be 
dismissed as annoying obstacles that must be pushed out of the way 
by an omnipotent, omniscient FERC. Rather, state regulators must be 
respected as potential partners and, most importantly, advocates of 
such controversial lines, who will be invested in them and work to 
get them sited and built within their borders. That will never 
happen if states are denied the role that I advocated in the NOPR, 
that of full partners in deciding how, when and whether their 
consumers are burdened with costs for politically and corporate-
driven policy projects.
    125. This final rule could have corrected the single biggest 
flaw in Order No. 1000: the exclusion of the states from decision-
making roles in FERC-mandated regional transmission planning for 
public policy projects. Instead, the final rule doubles down on that 
error with a blizzard of new planning mandates to serve political, 
corporate, and ideological agendas, while leaving the states with no 
real power to protect their consumers from the trillions of dollars 
of costs that this order brazenly wants to impose on them. The final 
rule is nothing but a pretext for enacting a sweeping policy agenda 
that Congress never passed. As such, it blatantly violates the major 
questions doctrine. In producing rates that will be unjust, 
unreasonable, and unduly discriminatory and preferential, it 
violates the actual text of the FPA. And in that violation, it fails 
to fulfill our most important duty under the FPA, which is to 
protect consumers.

    For these many reasons, I respectfully dissent.

-----------------------------------------------------------------------
Mark C. Christie

Commissioner

[FR Doc. 2024-10872 Filed 6-10-24; 8:45 am]
 BILLING CODE 6717-01-P