Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, 40266-40298 [2021-15512]
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Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 35
[Docket No. RM21–17–000]
Building for the Future Through
Electric Regional Transmission
Planning and Cost Allocation and
Generator Interconnection
Federal Energy Regulatory
Commission.
ACTION: Advance notice of proposed
rulemaking.
AGENCY:
The Federal Energy
Regulatory Commission (Commission) is
issuing an Advance Notice of Proposed
Rulemaking (ANOPR) presenting
potential reforms to improve the electric
regional transmission planning and cost
allocation and generator interconnection
processes. The Commission invites all
SUMMARY:
interested persons to submit comments
on the potential reforms and in response
to specific questions.
DATES: Comments are due October 12,
2021 and Reply Comments are due
November 9, 2021.
ADDRESSES: Comments, identified by
docket number, may be filed in the
following ways. Electronic filing
through https://www.ferc.gov, is
preferred.
• Electronic Filing: Documents must
be filed in acceptable native
applications and print-to-PDF, but not
in scanned or picture format.
• For those unable to file
electronically, comments may be filed
by U.S. Postal Service mail or by hand
(including courier) delivery.
Æ Mail via U.S. Postal Service only:
Addressed to: Federal Energy
Regulatory Commission, Office of the
Secretary, 888 First Street NE,
Washington, DC 20426.
Æ For delivery via any other carrier
(including courier): Deliver to: Federal
Energy Regulatory Commission, Office
of the Secretary, 12225 Wilkins Avenue,
Rockville, MD 20852.
The Comment Procedures Section of
this document contains more detailed
filing procedures.
FOR FURTHER INFORMATION CONTACT:
David Borden (Technical Information),
Office of Energy Policy and
Innovation, 888 First Street NE,
Washington, DC 20426, (202) 502–
8734, david.borden@ferc.gov
Christopher Gore (Technical
Information), Office of Energy Market
Regulation, 888 First Street NE,
Washington, DC 20426, (202) 502–
8507, christopher.gore@ferc.gov.
Lina Naik (Legal Information), Office of
the General Counsel, 888 First Street
NE, Washington, DC 20426, (202)
502–8882, lina.naik@ferc.gov
SUPPLEMENTARY INFORMATION:
Table of Contents
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Paragraph Nos.
I. Introduction ..................................................................................................................................................................................................................
II. Background ..................................................................................................................................................................................................................
A. Regional Transmission Planning and Cost Allocation Process ........................................................................................................................
1. Regional Transmission Planning Requirements ..........................................................................................................................................
2. Nonincumbent Transmission Developer Reforms .......................................................................................................................................
3. Regional Transmission Cost Allocation .......................................................................................................................................................
4. Interregional Transmission Coordination ....................................................................................................................................................
B. Overview of Transmission Planning ...................................................................................................................................................................
1. Reliability Needs ...........................................................................................................................................................................................
2. Economic Needs ............................................................................................................................................................................................
3. Public Policy Requirement Needs ................................................................................................................................................................
4. Local Transmission Facilities in the Regional Transmission Planning Process .......................................................................................
C. Overview of Generator Interconnection ..............................................................................................................................................................
D. Interaction Between the Regional Transmission Planning and Cost Allocation and Generator Interconnection Processes ........................
E. Current Funding Paradigm ..................................................................................................................................................................................
1. Regional Transmission Cost Allocation .......................................................................................................................................................
2. Local Transmission Facilities .......................................................................................................................................................................
3. Interconnection-Related Network Upgrades ................................................................................................................................................
III. The Potential Need for Reform ..................................................................................................................................................................................
A. The Existing Regional Transmission Planning and Cost Allocation and Generator Interconnection Processes May Be Inadequate To
Ensure Just and Reasonable Rates ........................................................................................................................................................................
1. Considering Anticipated Future Generation ................................................................................................................................................
2. Results of Existing Local and Regional Transmission Planning Processes ...............................................................................................
3. Cost Responsibility for Transmission Facilities and Interconnection-Related Network Upgrades ..........................................................
IV. Consideration of Potential Reforms and Request for Comment ..............................................................................................................................
A. Regional Transmission Planning and Cost Allocation Processes .....................................................................................................................
1. Potential Reforms and Request for Comment ..............................................................................................................................................
a. Planning for the Transmission Needs of Anticipated Future Generation ..........................................................................................
i. Future Scenarios and Modeling Anticipated Future Generation .........................................................................................................
ii. Identifying Geographic Zones That Have Potential for High Amounts of Renewable Resource Development to Meet Increased
Demand ....................................................................................................................................................................................................
iii. Incentivizing Regional Transmission Facilities ..................................................................................................................................
iv. Enhanced Interregional or State-to-State Coordination ......................................................................................................................
b. Coordinating Between the Regional Transmission Planning and Cost Allocation and Generator Interconnection Processes .......
B. Identification of Cost and Responsibility for Regional Transmission Facilities and Interconnection-Related Network Upgrades .............
1. Relevant Cost Causation Precedent ..............................................................................................................................................................
2. Cost Allocation for Transmission Facilities Planned through the Regional Transmission Planning Process ........................................
a. Background .............................................................................................................................................................................................
b. Potential Need for Reform .....................................................................................................................................................................
c. Potential Reforms and Request for Comment .......................................................................................................................................
3. Participant Funding and Crediting Policy for Funding Interconnection-Related Network Upgrades .....................................................
a. Background .............................................................................................................................................................................................
i. Original Rationale for the Order No. 2003 Interconnection-Related Network Upgrade Funding Requirements .............................
(a) Crediting Policy .....................................................................................................................................................................................
(b) Participant Funding ..............................................................................................................................................................................
b. Potential Need for Reform .....................................................................................................................................................................
i. Participant Funding ................................................................................................................................................................................
ii. Crediting Policy .....................................................................................................................................................................................
c. Potential Reforms and Request for Comment .......................................................................................................................................
i. Eliminate Participant Funding for Interconnection-Related Network Upgrades ................................................................................
ii. Revisions to the Existing Crediting Policy ...........................................................................................................................................
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Paragraph Nos.
(a) Transmission Providers Provide Upfront Funding for All Interconnection-Related Network Upgrades ........................................
(b) Interconnection Customers Contribute to the Upfront Funding of Interconnection-Related Network Upgrades Through a Fee
(c) Transmission Providers Provide Upfront Funding for Only Higher Voltage Interconnection-Related Network Upgrades ...........
(d) Allocate the Upfront Cost of Interconnection-Related Network Upgrades on a Percentage Basis ..................................................
iii. Additional Considerations ...................................................................................................................................................................
(a) Interconnection-Related Network Upgrade Cost Sharing ...................................................................................................................
(b) Option To Build ....................................................................................................................................................................................
(c) Interconnection Request Limit .............................................................................................................................................................
(d) Fast-Track for Interconnection of Generating Facilities Committed to Regional Transmission Facilities .....................................
(e) Fast-Track for Interconnection of ‘‘Ready’’ Generating Facilities ......................................................................................................
(f) Grid-Enhancing Technologies ...............................................................................................................................................................
C. Enhanced Transmission Oversight ..............................................................................................................................................................
1. Potential Need for Reform ............................................................................................................................................................................
2. Potential Reforms and Request for Comment ..............................................................................................................................................
a. State Oversight ........................................................................................................................................................................................
b. Limitation on Recovery of Costs for Abandoned Projects ...................................................................................................................
c. Additional Oversight Approaches .........................................................................................................................................................
D. Transition .............................................................................................................................................................................................................
V. Comment Procedures ..................................................................................................................................................................................................
VI. Document Availability ...............................................................................................................................................................................................
I. Introduction
1. Pursuant to its authority under
section 206 of the Federal Power Act
(FPA),1 the Federal Energy Regulatory
Commission (Commission) is
considering the potential need for
reforms or revisions to existing
regulations to improve the electric
regional transmission planning and cost
allocation and generator interconnection
processes.
2. Approximately 10 years ago, the
Commission issued Order No. 1000.2
That order stated its purpose generally
in its introduction:
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The reforms herein are intended to
improve transmission planning processes
and cost allocation mechanisms under the
pro forma Open Access Transmission Tariff
(OATT) to ensure that the rates, terms and
conditions of service provided by public
utility transmission providers are just and
reasonable and not unduly discriminatory or
preferential. This Final Rule builds on Order
No. 890,3 in which the Commission, among
other things, reformed the pro forma OATT
to require each public utility transmission
provider to have a coordinated, open, and
transparent regional transmission planning
process. After careful review of the
voluminous record in this proceeding, the
Commission concludes that the additional
reforms adopted herein are necessary at this
time to ensure that rates for Commission1 16 U.S.C. 824e. Section 206 requires that
transmission rates be just and reasonable, and not
unduly discriminatory or preferential.
2 Transmission Planning and Cost Allocation by
Transmission Owning and Operating Public
Utilities, Order No. 1000, 136 FERC ¶ 61,051 (2011),
order on reh’g, Order No. 1000–A, 139 FERC
¶ 61,132, order on reh’g and 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).
3 Preventing Undue Discrimination and
Preference in Transmission Service, Order No. 890,
118 FERC ¶ 61,119, order on reh’g, Order No. 890–
A, 121 FERC ¶ 61,297 (2007), order on reh’g, Order
No. 890–B, 123 FERC ¶ 61,299 (2008), order on
reh’g, Order No. 890–C, 126 FERC ¶ 61,228, order
on clarification, Order No. 890–D, 129 FERC
¶ 61,126 (2009).
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jurisdictional service are just and reasonable
in light of changing conditions in the
industry. In addition, the Commission
believes that these reforms address
opportunities for undue discrimination by
public utility transmission providers.4
3. More than a decade after Order No.
1000, we believe it appropriate to
review the issues addressed by that
order and other transmission-related
regulations and determine whether
additional reforms to the regional
transmission planning and cost
allocation and generator interconnection
processes or revisions to existing
regulations are needed to ensure rates
for Commission-jurisdictional service
remain just and reasonable, and not
unduly discriminatory or preferential.
The electricity sector is transforming as
the generation fleet shifts from resources
located close to population centers
toward resources, including renewables,
that may often be located far from load
centers. The growth of new resources
seeking to interconnect to the
transmission system and the differing
characteristics of those resources are
creating new demands on the
transmission system. Ensuring just and
reasonable rates as the resource mix
changes, while maintaining grid
reliability, remains the priority in the
regional transmission planning and cost
allocation and generator interconnection
processes.
4. In light of these evolving
conditions, we believe it timely and
appropriate 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 transmission
rates remain just and reasonable and not
unduly discriminatory or preferential
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4 Order
No. 1000, 136 FERC ¶ 61,051 at P 1.
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and that reliability is maintained.5
Accordingly, we will consider herein
whether and which reforms and
revisions are necessary to the
Commission’s regulations on these
topics. This Advanced Notice of
Proposed Rulemaking (ANOPR)
discusses proposals or concepts for
changes to existing processes in several
broad categories: Regional transmission
planning, regional cost allocation,
generator interconnection funding,
generator interconnection queueing
processes and consumer protection, and
in several instances the ANOPR also
offers a potential rationale or argument
for potential proposals. We note that the
Commission has not predetermined that
any specific proposal discussed herein
shall or should be made or in what final
form; rather, we seek comment from the
public on these proposals and welcome
commenters to offer additional or
alternative proposals for consideration.
5. We believe it appropriate to review
whether there are questions that should
be explored and possible solutions
proposed regarding any potential
shortcomings in the existing regional
transmission planning and cost
allocation and generator interconnection
processes, which may have become
evident since the Commission issued
Order No. 2003,6 Order No. 890, and
Order No. 1000. We seek comment on
several topics across transmission
planning and cost allocation and
interconnection queue processes, as
well as oversight of transmission
infrastructure development. Examples
5 16
U.S.C. 824e.
6 Standardization
of Generator Interconnection
Agreements and Procedures, Order No. 2003, 104
FERC ¶ 61,103 (2003), order on reh’g, Order No.
2003–A, 106 FERC ¶ 61,220, order on reh’g, Order
No. 2003–B, 109 FERC ¶ 61,287 (2004), order on
reh’g, Order No. 2003–C, 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) (NARUC
v. FERC).
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of such questions for which we will
seek comment in this ANOPR include,
among others: (1) Whether the existing
regional transmission planning and cost
allocation processes appropriately
considers the transmission needs of
anticipated future generation to drive
study assumptions, or instead relies on
less comprehensive information, such as
existing interconnection requests with
completed facilities studies, and
whether such current planning criteria
are appropriate or should be revised; (2)
whether the regional transmission
planning and cost allocation processes’
consideration of transmission needs
driven by reliability, economic
considerations, and Public Policy
Requirements 7 are inappropriately
siloed from one another, and, if so,
whether this influences the
consideration of potential benefits of a
regional transmission facility (and the
associated beneficiaries for purposes of
allocating the costs of such a facility); 8
(3) whether criteria in addition to those
related to reliability, economic, and
Public Policy Requirements needs
should be planned for and considered in
the evaluation of benefits, and used to
determine cost allocation in the regional
transmission planning process, and
these needs should be clear, credibly
quantifiable and not speculative; (4)
how to appropriately identify and
allocate the costs of new transmission
infrastructure in a manner that satisfies
the Commission’s cost-causation
principle that costs are allocated to
beneficiaries in a manner that is at least
roughly commensurate with estimated
benefits; (5) whether or not it is
appropriate for the costs of state or local
public policy-driven transmission
facilities to be shifted through regional
cost allocation to consumers in nonparticipating states, or whether changes
to current interconnection cost
allocation mechanisms may unjustly
and unreasonably shift costs to
7 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). Order
No. 1000, 136 FERC ¶ 61,051 at P 2. The
Commission clarified that Public Policy
Requirements established by state or federal laws or
regulations include duly enacted laws or
regulations passed by a local governmental agency,
such as a municipal or county government. Order
No. 1000–A, 139 FERC ¶ 61,132 at P 319. Order No.
1000 left planning and cost allocation for Public
Policy Requirements largely to the discretion of
transmission providers. See also infra P 16.
8 A regional transmission facility is a
transmission facility located entirely in one
transmission planning region. Order No. 1000, 136
FERC ¶ 61,051 at n.374.
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customers of load serving entities; 9 (6)
whether and which reforms are
necessary to the generator
interconnection process to ensure a
more purposeful integration with the
regional transmission planning and cost
allocation processes, a more efficient
queueing process, and a more efficient
and cost-effective allocation of
interconnection costs; (7) whether the
regional transmission planning and cost
allocation processes may have resulted
in transmission facilities addressing an
unduly narrow set of transmission
needs, including needs located in a
single transmission owner’s footprint,
and having limited region-wide benefits,
but that, collectively, may impose
significant costs on customers; (8)
whether and how to better coordinate
between regional and local transmission
planning processes to identify more
efficient or cost-effective solutions; and
(9) whether it is necessary, and how, to
more clearly identify the lines of
regulatory authority and oversight
between states and federal authorities
with regard to regional and local
transmission facilities to ensure
appropriate vetting of transmission
infrastructure. In addition, we seek
comment regarding whether the current
approach to oversight of transmission
investment adequately protects
customers, particularly given the
potentially significant and very costly
investments proposed to meet the
transmission needs driven by a
changing resource mix, and, if
customers are not adequately protected
from excessive costs, which potential
reforms may be required and are legally
permissible to ensure just and
reasonable rates.
II. Background
A. Regional Transmission Planning and
Cost Allocation Process
6. In 1996, the Commission issued
Order No. 888 and the accompanying
pro forma OATT, setting forth certain
minimum requirements for transmission
planning.10 In 2007, the Commission
9 Under current Commission policy, the costs of
interconnection-related network upgrades are either
(1) directly assigned to the interconnection
customer or (2) funded initially by the
interconnection customer and reimbursed through
transmission service credits.
10 Promoting Wholesale Competition Through
Open Access Non-Discriminatory Transmission
Services by Public Utilities; Recovery of Stranded
Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996)
(cross-referenced at 75 FERC ¶ 61,080), order on
reh’g, Order No. 888–A, 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.
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issued Order No. 890 to remedy flaws in
the pro forma OATT, and in so doing,
required coordinated, open, and
transparent transmission planning on
both a local and regional level.
Specifically, the Commission required,
among other things, that each
transmission provider’s 11 local
transmission planning process 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.12
7. In 2011, the Commission issued
Order No. 1000 to build on the
transmission planning requirements of
Order No. 890. Order No. 1000 included
a package of reforms to ensure that the
transmission planning and cost
allocation mechanisms embodied in the
pro forma OATT were adequate to
support the development of more
efficient or cost-effective transmission
facilities.13 The reforms in Order No.
1000 fell into the following categories:
(1) Regional transmission planning; (2)
transmission needs driven by Public
Policy Requirements; (3) nonincumbent
transmission developer reforms; (4)
regional and interregional cost
allocation; and (5) interregional
transmission coordination. Here we
provide a brief overview of the Order
No. 1000 regional transmission planning
requirements, nonincumbent developer
reforms, regional transmission cost
allocation rules, and interregional
transmission coordination.
1. Regional Transmission Planning
Requirements
8. Order No. 1000 requires that each
transmission provider participate in a
regional transmission planning process
that produces a regional transmission
plan.14 Through the regional
transmission planning process,
transmission providers must evaluate,
in consultation with stakeholders,
Transmission Access Policy Study Group v. FERC,
225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New
York v. FERC, 535 U.S. 1 (2002).
11 In this order, we use the term ‘‘transmission
provider’’ when referring to a public utility that
owns, controls, or operates transmission facilities.
The term transmission provider should be read to
include the transmission owner when the
transmission owner is separate from the
transmission provider, as is the case in regional
transmission organizations (RTOs) and independent
system operators (ISOs).
12 Order No. 890, 118 FERC ¶ 61,119 at PP 418–
601.
13 Order No. 1000, 136 FERC ¶ 61,051 at PP 11–
12, 42–44; Order No. 1000–A, 139 FERC ¶ 61,132
at PP 3, 4–6.
14 Order No. 1000, 136 FERC ¶ 61,051 at PP 146,
148.
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alternative transmission solutions that
might meet the region’s reliability,
economic, and Public Policy
Requirements needs 15 more efficiently
or cost-effectively than solutions that
transmission providers identified in
their local transmission planning
processes.16 Order No. 1000 also
requires that the regional transmission
planning process satisfy the Order No.
890 transmission planning principles.17
Therefore, these transmission planning
principles, which the Commission
adopted with respect to local
transmission planning processes in
Order No. 890, also apply to the regional
transmission planning processes
established in Order No. 1000.
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2. Nonincumbent Transmission
Developer Reforms
9. Order No. 1000 institutes a number
of reforms that seek to ensure that
nonincumbent transmission developers
have an opportunity to participate in the
regional transmission development
process.18 In particular, Order No. 1000
requires that each transmission provider
eliminate provisions in Commissionjurisdictional tariffs and agreements that
establish a federal right of first refusal
for an incumbent transmission provider
with respect to transmission facilities
selected in a regional transmission plan
for purposes of cost allocation.19 Order
No. 1000 defines a transmission facility
selected in a regional transmission plan
for purposes of cost allocation as one
that has been selected because it is a
more efficient or cost-effective solution
to a regional transmission need.20
10. In addition, Order No. 1000
requires that each regional transmission
planning process include not unduly
discriminatory qualification criteria and
information requirements for
transmission developers that want to
propose a transmission facility for
selection in the regional transmission
plan for purposes of cost allocation.21
The regional transmission planning
process must also have a transparent
15 Order No. 1000’s requirement to consider
transmission needs driven by Public Policy
Requirements is described below.
16 Order No. 1000, 136 FERC ¶ 61,051 at PP 11,
148.
17 Id. P 151. Order No. 890 explains these
transmission planning principles.
18 For purposes of Order No. 1000,
‘‘nonincumbent transmission developer’’ refers to
two categories of transmission developer: (1) A
transmission developer that does not have a retail
distribution service territory or footprint; and (2) a
transmission provider that proposes a transmission
facility outside of its existing retail distribution
service territory or footprint, where it is not the
incumbent for purposes of that project. Id. P 225.
19 Id. P 313.
20 Id. PP 5, 63.
21 Id. PP 225, 323, 325.
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and not unduly discriminatory process
for evaluating whether to select a
proposed transmission facility in the
regional transmission plan for purposes
of cost allocation.22 Furthermore, the
regional transmission planning process
must provide a nonincumbent
transmission developer with the same
eligibility as an incumbent transmission
developer to use a cost allocation
method(s) for any sponsored
transmission facility selected in the
regional transmission plan for purposes
of cost allocation.23
3. Regional Transmission Cost
Allocation
11. Order No. 1000 requires each
transmission provider to have in place
a method, or set of methods, for
allocating the costs of new regional
transmission facilities selected in the
regional transmission plan for purposes
of cost allocation.24 Each regional cost
allocation method must satisfy six
regional cost allocation principles,25
including the principle that the cost of
transmission facilities must be allocated
to those in the transmission planning
region that benefit from the facilities in
a manner that is roughly commensurate
with estimated benefits.26
4. Interregional Transmission
Coordination
12. Order No. 1000 requires each
transmission provider, through its
regional transmission planning process,
to establish further procedures with
each of its neighboring transmission
planning regions for the purpose of
coordinating and sharing the results of
respective regional transmission plans
to identify possible interregional
transmission facilities that could
address transmission needs more
efficiently or cost-effectively than
separate regional transmission facilities.
The interregional coordination
processes must provide for: (1) The
sharing of information regarding the
respective needs of each region and
potential solutions to those needs; and
(2) the identification and evaluation of
interregional transmission facilities that
may be more efficient or cost-effective
solutions to those regional needs.27
B. Overview of Transmission Planning
13. The next few paragraphs provide
an overview of how transmission
providers plan their systems to meet
22 Id. P 328; Order No. 1000–A, 139 FERC
¶ 61,132 at P 452.
23 Order No. 1000, 136 FERC ¶ 61,051 at P 332.
24 Id. P 558.
25 Id. P 603.
26 Id. PP 622, 639.
27 Id. P 396.
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their reliability, economic, and Public
Policy Requirements needs, consistent
with Order Nos. 890 and 1000.
1. Reliability Needs
14. Transmission providers within
transmission planning regions conduct
reliability planning studies to help
ensure the ability of the transmission
system to serve firm transmission use.
These studies may extend 10 to 15 years
into the future depending on the
transmission planning region’s
transmission planning process and tests
for violations of established North
American Electric Reliability
Corporation (NERC) reliability
requirements.28 Additional regional and
local reliability criteria may also apply
in specific transmission planning
regions. In order to meet applicable
reliability planning criteria, the regional
transmission planning process focuses
on studying and producing a
transmission system that is robust
enough to be able to withstand a range
of probable contingencies (e.g., the
sudden loss of a generator or high
voltage transmission line) while reliably
serving customer demand and
preventing cascading outages.29
Generally, transmission providers
identify areas not in compliance with
planning criteria and develop plans to
achieve compliance. Transmission
providers examine facilities to mitigate
identified reliability criteria violations
for their feasibility, impact, and
comparative costs, culminating in a
recommended regional transmission
plan.
2. Economic Needs
15. Transmission providers within
transmission planning regions also plan
transmission facilities to meet economic
needs. In Order No. 1000, the
Commission recognized that Order No.
890 placed no affirmative obligation on
28 For example, Reliability Standard TPL–001–4
requires that Transmission Planners conduct an
annual planning assessment of their region’s
portion of the bulk electric system and document
summarized results of the steady state analyses,
short circuit analyses, and stability analyses. TPL–
001–4 also requires that Transmission Planners
conduct these analyses using a model of their
systems operating under a wide variety of potential
conditions to see under what, if any, conditions the
system will fail to meet reliability criteria. TPL–
001–4 lays out the variety of these conditions,
including system peak, off-peak, single
contingency, multiple contingencies (both
sequential and simultaneous), severe contingencies
on adjacent systems, sensitivity analyses to
underlying model assumptions, and extreme events.
29 The regional transmission planning process
will identify the necessary transmission system
facilities (which have varying costs and lead times
for when they can be placed into service) that are
needed to achieve reliable transmission system
operations.
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transmission providers to perform
economic planning studies absent a
request by stakeholders. To remedy this
deficiency, Order No. 1000 required
that, in addition to economic planning
studies requested by stakeholders,
transmission providers evaluate,
through a regional transmission
planning process and in consultation
with stakeholders, alternative
transmission solutions that might meet
the needs of the transmission planning
region more efficiently or costeffectively than solutions identified by
individual transmission providers in
their local transmission planning
process. These regional transmission
solutions could include transmission
facilities needed to meet reliability
requirements, address economic
considerations, and/or meet
transmission needs driven by Public
Policy Requirements.30 As Order No.
890 explains, the purpose of economic
transmission planning is to plan
transmission to alleviate congestion
through the integration of new
generation resources or an expansion of
the regional transmission system, by an
amount that justifies its cost, usually by
a defined threshold.31 However, to
implement the requirement in Order No.
1000 to affirmatively plan for economic
needs, transmission providers
implemented thresholds that vary across
the regions. Examples of regional
transmission facilities driven by
economic needs include transmission
facilities that relieve historical or
projected transmission congestion and
allow lower-cost power to flow to
consumers.
3. Public Policy Requirement Needs
16. Order No. 1000 requires
transmission providers to consider
transmission needs driven by Public
Policy Requirements in their local and
regional transmission planning
processes.32 However, the requirement
in Order No. 1000 to consider
transmission needs driven by Public
Policy Requirements is limited, and the
Commission provided transmission
providers with flexibility in how to
meet the requirement. For example,
Order No. 1000 does not require that a
separate class of transmission facilities
be created in the regional transmission
planning process to address
transmission needs driven by Public
Policy Requirements,33 nor does it
30 Order
No. 1000, 136 FERC ¶ 61,051 at PP 147–
148.
31 Order
No. 890, 118 FERC ¶ 61,119 at P 549.
No. 1000, 136 FERC ¶ 61,051 at PP 203,
222; Order No. 1000–A, 139 FERC ¶ 61,132 at P 208.
33 Order No. 1000, 136 FERC ¶ 61,051 at P 220
(explaining that the Final Rule is intended to
32 Order
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mandate the consideration of any
particular transmission need driven by
a Public Policy Requirement.34 As a
result, the process for identifying and
considering such needs varies from
transmission planning region to
transmission planning region.
4. Local Transmission Facilities in the
Regional Transmission Planning Process
17. Generally, the transmission
facilities that transmission providers
include in their individual local
transmission plans are incorporated into
regional transmission plans as inputs,
with minimal opportunity for
stakeholder review in the regional
transmission planning process. That is
because the analysis of local
transmission plans in the regional
transmission planning process is limited
mainly to a reliability analysis to ensure
that local transmission plans do not
negatively affect the reliability of the
regional transmission system.
C. Overview of Generator
Interconnection
18. In Order No. 2003, the
Commission recognized a need for a
single set of interconnection procedures
for jurisdictional transmission providers
and a single, uniformly applicable
interconnection agreement for large
generators.35 The Commission
explained that generator
interconnection is a ‘‘critical component
of open access transmission service and
thus is subject to the requirement that
utilities offer comparable service under
the OATT.’’ 36 The Commission also
determined that, because of the
inefficiency of addressing generator
interconnection issues on a case-by-case
basis,37 it was appropriate to establish a
standard set of generator
interconnection procedures to
‘‘minimize opportunities for undue
discrimination and expedite the
development of new generation, while
protecting reliability and ensuring that
rates are just and reasonable.’’ 38 To this
end, the Commission adopted the pro
forma Large Generator Interconnection
Procedures (LGIP) and pro forma Large
Generator Interconnection Agreement
(LGIA) 39 and required that all
‘‘provide flexibility for public utility transmission
providers to develop procedures appropriate for
their local and regional transmission planning
processes’’).
34 Id. P 215.
35 Order No. 2003, 104 FERC ¶ 61,103 at P 11.
36 Id. P 9 (citing Tenn. Power Co., 90 FERC
¶ 61,238 (2000)).
37 Id. P 10.
38 Id. P 11.
39 The pro forma LGIP and pro forma LGIA
govern large generating facilities, which are
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transmission providers’ OATTs
incorporate the pro forma LGIP and pro
forma LGIA.
19. In Order No. 2003, the
Commission also retained a distinction
between interconnection facilities,
which are located between the
interconnection customer’s generating
facility and the transmission provider’s
transmission system, and network
upgrades,40 which include only
facilities at or beyond the point where
the interconnection customer’s
generating facility interconnects to the
transmission provider’s transmission
system.41 This distinction is important
because the determination of which
entity is ultimately responsible for the
cost of a facility can depend on whether
that facility is an interconnection
facility or an interconnection-related
network upgrade.
20. To initiate the generator
interconnection process set forth in
Order No. 2003,42 the interconnection
customer submits an interconnection
request associated with its proposed
generating facility that includes
preliminary site documentation, certain
technical information about the
proposed generating facility, and the
expected in-service date along with a
deposit.43 The transmission provider
uses this information to determine the
interconnection facilities and
interconnection-related network
upgrades necessary to accommodate the
interconnection request and their
associated costs.44
21. After the transmission provider
determines that the interconnection
request is complete, the interconnection
request will enter the interconnection
queue with other pending requests, and
the transmission provider will assign
the request a queue position based on
the date and time of receipt. The queue
position will determine the order in
which the transmission provider will
perform three phases of interconnection
studies for the interconnection request.
The three phases in order are: (1) The
feasibility study; (2) the system impact
generating facilities that have a generating facility
capacity of more than 20 MW.
40 For clarity, this ANOPR will refer to these
facilities as interconnection-related network
upgrades.
41 Id. P 21.
42 While we provide a broad description of the
generator interconnection process under Order No.
2003 as background here, we recognize that many
transmission providers have adopted (and the
Commission has accepted) variations to many of the
terms in the pro forma LGIP and the pro forma
LGIA. Consequently, some or many of the details
of a particular transmission provider’s generator
interconnection process may vary considerably
from the broad description provided here.
43 Id. P 35.
44 Pro forma LGIP Section 3.1.
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study; and (3) the facilities study, all of
which are necessary to determine the
interconnection facilities and
interconnection-related network
upgrades needed to accommodate the
interconnection request and the
interconnection customer’s cost
responsibility for these facilities.45
22. At the completion of the facilities
study, the transmission provider will
issue a report, which includes a ‘‘best
estimate of the costs to effect the
requested interconnection,’’ and provide
a draft generator interconnection
agreement to the interconnection
customer.46 If the interconnection
customer wishes to proceed, after
negotiations, the interconnection
customer enters into a generator
interconnection agreement with the
transmission provider or requests that
the transmission provider file the
agreement with the Commission
unexecuted.47
D. Interaction Between the Regional
Transmission Planning and Cost
Allocation and Generator
Interconnection Processes
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23. The interaction between a
transmission provider’s current
generator interconnection process and
its regional transmission planning and
cost allocation processes appears to be
limited. The primary interaction is that
the baseline regional transmission
planning models generally only
incorporate interconnection projects
that are near the end of the
interconnection process and have
completed a facilities study. In addition,
when creating interconnection study
models, transmission providers
incorporate transmission planning
information into the interconnection
base cases, but what information is
incorporated varies for each
transmission provider. The base cases
for interconnection studies impact the
cost assignment for interconnection
customers, often dramatically, and at
present, most transmission providers’
OATTs do not contain requirements for
what information is included in base
cases.48
45 Order No. 2003, 104 FERC ¶ 61,103 at PP 35–
36. The interconnection customer is responsible for
the costs of interconnection studies and any
necessary restudies.
46 Id. P 38.
47 Id.
48 For example, some transmission providers have
details regarding what information is included in an
interconnection study base case in their tariffs, see
e.g. Sw. Power Pool, Inc., 172 FERC ¶ 61,283, at P10
(2020), while others limit that information to the
business practices manuals. See, e.g., NYISO
Manual 26, Reliability Planning Process Manual at
15–16.
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E. Current Funding Paradigm
1. Regional Transmission Cost
Allocation
24. As noted above, Order No. 1000’s
cost allocation reforms require each
transmission provider to participate in a
regional transmission planning process
that features a regional cost allocation
method or methods for allocating the
cost of new regional transmission
facilities selected in a regional
transmission plan for purposes of cost
allocation. The Commission also
required that such regional cost
allocation methods satisfy six regional
cost allocation principles, including the
principle that the cost of transmission
facilities must be allocated to those in
the transmission planning region that
benefit from the facilities in a manner
that is roughly commensurate with
estimated benefits.49
2. Local Transmission Facilities
25. In Order No. 1000, the
Commission explained that the local
transmission planning process is the
transmission planning process that a
transmission provider performs for its
individual retail distribution service
territory or footprint pursuant to the
requirements of Order No. 890.50 The
outcome of the local transmission
planning processes are local
transmission facilities. In Order No.
1000, the Commission defined a local
transmission facility as 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.51
26. The Commission clarified that, if
the transmission provider has a retail
distribution service territory and/or
footprint, then only a transmission
facility that it decides to build within
that retail distribution service territory
or footprint, and that is not selected in
a regional transmission plan for
purposes of cost allocation, may be
considered a local transmission facility.
Further, the Commission explained that,
in the case of an RTO/ISO whose
footprint covers the entire region, local
transmission facilities are defined by
reference to the retail distribution
service territories or footprints of its
underlying transmission owing
members.52 The Commission did not
require that the transmission facilities in
49 Order No. 1000, 136 FERC ¶ 61,051 at PP 622,
639. The six Order No. 1000 regional cost allocation
principles are discussed further below.
50 Id. P 68.
51 Id. P 63.
52 Order No. 1000–A, 139 FERC ¶ 61,132 at P 429.
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a transmission provider’s local
transmission plan be subject to approval
at the regional or interregional level,
unless that transmission provider seeks
to have any of those facilities selected
in the regional transmission plan for
purposes of cost allocation.53
27. Moreover, local transmission
facilities planned through a local
transmission planning process are not
eligible to use the Order No. 1000
regional cost allocation method and
instead their costs are allocated to the
transmission provider in whose retail
distribution service territory or footprint
the local transmission facility is located.
In support of this, the Commission
explained that it continues to permit an
incumbent transmission provider to
meet its reliability needs or service
obligations by choosing to build new
transmission facilities that are located
solely within its retail distribution
service territory or footprint as long as
the transmission provider does not
receive regional cost allocation for the
facilities.54 Further, the Commission
clarified that nothing in Order No. 1000
restricts an incumbent transmission
provider from developing a local
transmission solution that is not eligible
for regional cost allocation to meet its
reliability needs or service obligations
in its own retail distribution service
territory or footprint.55
3. Interconnection-Related Network
Upgrades
28. The Commission’s
interconnection pricing policy 56 allows
for two general approaches on how to
assign the cost of interconnectionrelated network upgrades, one of which
we refer to as the crediting policy and
the other as participant funding. We
will discuss the rationale that the
Commission provided when accepting
each of the two approaches in later
sections.
29. In Order No. 2003, the
Commission established the crediting
policy as a requirement of the
Commission’s interconnection pricing
policy. Pursuant to the crediting policy,
the interconnection customer is solely
responsible for the costs of
interconnection facilities, and
interconnection-related network
upgrades are funded initially by the
53 Id.
P 190.
PP 366, 379, 425, 428.
55 Order No. 1000, 136 FERC ¶ 61,051 at P 329.
56 We use the term interconnection pricing policy
to refer collectively to both Order No. 2003’s
establishment of the crediting policy for financing
interconnection-related network upgrades and
Order No. 2003’s allowance of participant funding
for interconnection-related network upgrades in
RTOs/ISOs.
54 Id.
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interconnection customer (unless the
transmission provider elects to fund
them) and the transmission provider
reimburses the interconnection
customer through transmission service
credits.57 The Commission reasoned
that ‘‘it is appropriate for the
Interconnection Customer to pay
initially the full cost of Interconnection
Facilities and [interconnection-related]
Network Upgrades that would not be
needed but for the interconnection.’’ 58
While the interconnection customer
pays for the costs of the
interconnection-related network
upgrades upfront, the transmission
provider must reimburse the total
amount that the interconnection
customer paid for interconnectionrelated network upgrades, plus interest,
as credits against the charges for
transmission service taken with respect
to the interconnection customer’s
generating facility as such charges are
incurred. The transmission provider
recovers the cost of interconnectionrelated network upgrades funded under
the crediting policy through its
embedded cost transmission rates.59
The second pricing approach for
interconnection-related network
upgrades is called participant funding.
Participant funding for interconnectionrelated network upgrades refers to the
direct assignment to a particular
interconnection customer of the costs of
interconnection-related network
upgrades that would not be needed but
for the interconnection.60 The
Commission has accepted as just and
reasonable various participant funding
approaches proposed by RTOs/ISOs as
independent entity variations from the
pro forma requirements of Order No.
2003.
57 Order
No. 2003, 104 FERC ¶ 61,103 at P 22.
P 694. ‘‘But for’’ interconnection-related
network upgrades are those interconnection-related
network upgrades that would not have been
constructed ‘‘but for’’ the interconnection request.
See N.Y. Indep. Sys. Operator, Inc., 122 FERC
¶ 61,267, at n.3 (2008).
59 The embedded cost pricing ‘‘attempts to
allocate costs among customers based upon usage.’’
Fla. Power & Light Co., 70 FERC ¶ 61,158 (1995).
Embedded cost rates reflect ‘‘system average costs
including the cost of the [interconnection-related]
network upgrades, and incremental cost rates
‘‘reflect [ ] just the cost of the [interconnectionrelated] network upgrades.’’ See Interstate Power &
Light Co. v. ITC Midwest, LLC, 144 FERC ¶ 61,052,
at P 36 (2013) (emphasis added).
60 Order No. 845–B, 166 FERC ¶ 61,092 at P 5; see
also Order No. 2003, 104 FERC ¶ 61,103 at P 679
(pursuant to a ‘‘policy of participant funding . . .
those [that] benefit from a particular project pay for
it’’).
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III. The Potential Need for Reform
A. The Existing Regional Transmission
Planning and Cost Allocation and
Generator Interconnection Processes
May Be Inadequate To Ensure Just and
Reasonable Rates
30. As a result of changing
circumstances since the Commission
issued Order Nos. 890, 1000, and 2003,
we believe it is now appropriate to
examine whether the existing regional
transmission planning and cost
allocation and generator interconnection
processes adequately account for the
transmission needs of the changing
resource mix, or whether reforms may
be necessary to ensure that transmission
rates remain just and reasonable and not
unduly discriminatory or preferential.
1. Considering Anticipated Future
Generation
31. Expansion of the transmission
system generally occurs by design
through a transmission provider’s
transmission planning processes, or ad
hoc through its generator
interconnection process. At present, it
appears that regional transmission
planning processes may not adequately
model future scenarios to ensure that
those scenarios incorporate sufficiently
long-term and comprehensive forecasts
of future transmission needs, including
considering the needs of anticipated
future generation in identifying needed
transmission facilities. Although
regional transmission planning
processes may include some level of
generation development in different
future scenarios analyses, it appears that
they tend to include in their baseline
reliability models only those generators
that have completed facilities studies,
and thus are far along in the generator
interconnection process. These baseline
reliability models, by relying only on
generators that have completed facilities
studies, may only account for generation
that will come online in the short term.
32. As a result, the generator
interconnection process appears to be
the principal means by which
infrastructure is built to accommodate
new generators. That process, however,
focuses on a single interconnection
request (or cluster of requests). In other
words, the generator interconnection
process is not designed to consider how
to address anything beyond the
reliability interconnection-related
network upgrades required for a specific
interconnection request or group of
interconnection requests.
33. New transmission facilities often
have a development lead time that
exceeds the interconnection timing
needs of those interconnection
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customers already in the queue. It
appears that these types of transmission
facilities may not currently be planned
and built in advance to meet the needs
of anticipated future generation and as
a result, interconnection customers are
assigned the costs to construct large,
high-voltage transmission facilities.
34. In addition, because transmission
planning processes generally do not
plan for the needs of anticipated future
generation, transmission infrastructure
that is being developed in order to
facilitate new generation is constructed
largely through the generator
interconnection process, which is
unlikely to result in the economies of
scale that could more efficiently or costeffectively meet the needs of the
changing resource mix.
35. Likewise, the existing generator
interconnection process appears to
focus on the limited set of facilities
needed to reliably interconnect a single
interconnection customer (or cluster of
requests) at the interconnection service
level that the interconnection customer
requests. The generator interconnection
process may not adequately consider
whether it may be more efficient or costeffective to consider the
interconnection-related network
upgrades needed for multiple
anticipated future generators that are
not in the same cluster or are not yet in
the interconnection queue in areas that
have abundant wind or solar attributes
that could support multiple future
generators.61
36. In addition, there may be a need
for coordination between the regional
transmission planning process and the
generator interconnection process, the
absence of which may result in
inefficient investment in transmission
infrastructure and ultimately unjust and
unreasonable or unduly discriminatory
or preferential rates. By considering the
transmission needs of anticipated future
generation in its regional transmission
planning and cost allocation processes,
a transmission provider may identify
transmission facilities that could
facilitate both the interconnection of
new generation as well as address other
identified transmission system needs—
such as mitigating a reliability violation
or reducing congestion—at a lower total
cost than pursuing two separate
transmission projects through the
61 We note that certain regions do have the ability
to share costs of network upgrades with future
generation, but this is generally limited to the short
term. For example, Midcontinent Independent
System Operator, Inc.’s (MISO’s) Shared Network
Upgrade construct allows interconnection
customers to be repaid for portions of an
interconnection-related network upgrade’s cost if
another interconnection customer uses that network
upgrade within five years.
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generator interconnection and regional
transmission planning and cost
allocation processes. Without cooptimization of the two processes,
however, there appears to be no system
in place to jointly assess the benefits
and allocate the costs of transmission
facilities that yield benefits to both
system loads and new generation.
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2. Results of Existing Local and Regional
Transmission Planning Processes
37. We seek to better understand
whether the current transmission
planning processes may be resulting
increasingly in transmission facilities
addressing a narrow set of transmission
needs, often located in a single
transmission owner’s footprint. To the
extent that the requirements of the
regional transmission planning process
result in transmission providers
expanding predominately local
transmission facilities, that process may
fail to identify more efficient or costeffective transmission facilities needed
to accommodate anticipated future
generation. We seek to better
understand how the reforms of the
federal right of first refusal in Order No.
1000 have shaped the type and
characteristics of transmission facilities
developed through regional and local
transmission planning processes, such
as a relative increase in investment in
local transmission facilities or the
diversity of projects resulting from
competitive bidding processes.
3. Cost Responsibility for Transmission
Facilities and Interconnection-Related
Network Upgrades
38. The Commission cannot ensure
just and reasonable rates without
considering how to allocate the costs of
transmission facilities and
interconnection-related network
upgrades that result from the regional
transmission planning and cost
allocation and generator interconnection
processes to the entities that benefit
from those facilities. As the Commission
explained in Order No. 1000, the costs
of transmission infrastructure must be
allocated to its beneficiaries in a manner
that is at least roughly commensurate
with the benefits that they draw from
those facilities.62 We seek to better
understand whether the current
approach to allocating the costs of
transmission infrastructure, including
transmission facilities developed
through the regional transmission
planning and cost allocation processes
and interconnection-related network
upgrades planned through the generator
interconnection process, continues to
62 Order
No. 1000, 136 FERC ¶ 61,051 at P 10.
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appropriately allocate the costs of those
transmission facilities to the entities
that ultimately benefit from them.
39. The current regional transmission
planning process considers transmission
needs driven by reliability, economics,
and Public Policy Requirements. We
seek comment whether, by separating
transmission facilities into types,
transmission planning processes may
fail to take into account the benefits of
multi-faceted projects for the purposes
of cost allocation.
40. The current approach to allocating
the costs of interconnection-related
network upgrades may fail to allocate
costs in a manner that is roughly
commensurate with benefits. As
discussed above, the generator
interconnection process identifies the
interconnection facilities and
interconnection-related network
upgrades needed to interconnect a
single interconnection request (or
cluster of requests). Under the
participant funding approach to
financing the cost of interconnectionrelated network upgrades, the
interconnection customer pays for the
costs of such upgrades, even where they
would provide benefits to other
customers such as resolving congestion
on the transmission system. At the time
that the Commission issued Order No.
2003, it was less likely that
interconnection customers would be
assigned significant interconnectionrelated network upgrades through the
interconnection study process. Now,
however, there is little remaining
existing interconnection capacity on the
transmission system, particularly in
areas with high degrees of renewable
resources that may require new
resources to fund interconnectionrelated network upgrades that are more
extensive and, as a result, more
expensive. The more significant the
interconnection-related network
upgrades needed to accommodate a new
resource, the greater the potential that
such upgrades may benefit more than
just the interconnection customer.
Where an interconnection customer
elects not to pursue a generating facility
with system-wide benefits that exceeds
such facility’s cost, net beneficial
infrastructure would not be developed,
potentially leaving a wide range of
customers worse off as a result.
41. We also note that the cost of
interconnection-related network
upgrades can depend entirely on both
the timing of when and the specific site
where the interconnection customer
enters the interconnection queue that
may result in interconnection customers
submitting multiple speculative
interconnection requests in an effort to
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receive a favorable queue position and
reduce their interconnection-related
network upgrade costs.63 When
interconnection customers ‘‘test the
waters’’ in this manner, it may lead to
late-stage withdrawals of the excess
interconnection requests that can then
impede the transmission provider’s
ability to process its interconnection
queue in an efficient manner. Because of
the changing interconnection landscape
since Order No. 2003, the Commission’s
interconnection pricing policy, and in
particular participant funding, now may
result in a situation where
interconnection customers have a
financial incentive to submit multiple
speculative projects. As a result, we
believe it may be time to reexamine the
rationale behind the Commission’s
pricing policy established for
interconnection-related network
upgrades and to consider reforms to
generator interconnection processes that
would make such processes more
efficient, less costly, and ensure that
generation projects that are more
‘‘ready’’ than others are not unduly
delayed in the queue. In consideration
of generator interconnection process
reforms, we remain mindful of the need
to ensure that interconnection costs are
not unjustly and unreasonably shifted to
customers of load-serving entities.
42. While a reassessment of Order No.
2003’s assumptions pertaining to the
Commission’s interconnection pricing
policy may be necessary, our focus is in
line with Order No. 2003’s finding that
‘‘relatively unencumbered entry into the
market is necessary for competitive
markets.’’ 64 Furthermore, the purpose
of this examination is also consistent
with the original objectives of Order No.
2003, namely to ‘‘limit opportunities for
Transmission Providers to favor their
owner generation’’ and to ‘‘facilitate
market entry for generation competitors
by reducing interconnection costs and
time.’’ 65 At the same time, there is
reason to question the contention in
Order No. 2003 that participant funding
provides more ‘‘efficient price signals
and a more equitable allocation of costs
than the crediting approach.’’ 66 Also,
while the crediting policy ‘‘recognizes
the reliability benefits of a stronger
63 See, e.g., Review of Generator Interconnection
Agreements and Procedures, Technical Conference
Transcript, Docket No. RM16–12–000, at Tr.
211:10–21 (May 13, 2016) (Steve Naumann, Exelon
Corporation) (filed Aug. 23, 2016) (‘‘We would look
at putting let’s say new gas fired generation in PJM,
it may have four queue positions. And we only
intend to go through with one, that’s not
speculation, that’s trying to get information on
which is the most viable.’’).
64 Order No. 2003, 104 FERC ¶ 61,103 at P 11.
65 Id. P 12.
66 Id. P 695.
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transmission infrastructure and more
competitive power markets that result
from a policy that facilitates the
interconnection of new generating
facilities,’’ 67 we raise questions on
whether there are improvements that
can be made to the crediting policy or
whether a different pricing policy may
be more efficient.
43. We note that ensuring just and
reasonable rates, while maintaining grid
reliability, remain the priorities for
regional transmission planning, and cost
allocation processes, and generator
interconnection processes, and any
comments proposing revisions to
existing regulations should address their
impact on reliability and costs to
customers. All proposed reforms or
revisions to regulations proposed in this
proceeding must be consistent with the
Commission’s authority under section
206 of the FPA.
IV. Consideration of Potential Reforms
and Request for Comment
A. Regional Transmission Planning and
Cost Allocation Processes
1. Potential Reforms and Request for
Comment
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a. Planning for the Transmission Needs
of Anticipated Future Generation
44. We seek comment regarding
whether transmission providers in each
transmission planning region should
amend the regional transmission
planning and cost allocation processes
to plan for the transmission needs of
anticipated future generation to meet a
changing resource mix, including
generation that is not yet in the
interconnection queue. We seek
comment on whether the existing
regional transmission planning and cost
allocation processes fail to adequately
account for anticipated future
generation. We also seek comment on
whether the possible failure to account
for anticipated future generation results
in inefficient investment in
transmission infrastructure and causes
customers to pay unjust and
unreasonable rates for transmission
service. We also seek comment on
whether, and, if so, how the
Commission could structure and
implement a framework for considering
the transmission needs of anticipated
future generation in the regional
transmission planning and cost
allocation processes. Commenters
should address how each suggested
reform or revision to existing rules is
consistent with the Commission’s
authority under the FPA.
67 Order
No. 2003–A, 106 FERC ¶ 61,220 at P 584.
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45. Below, we describe potential
changes to the regional transmission
planning and cost allocation processes
that may be components of a process
that plans for transmission needs
associated with anticipated future
generation. We seek comment on each
of these potential changes, including
whether and, if so, how the potential
changes may lead to identification of
more efficient or cost-effective
transmission solutions to meet the
needs of anticipated future generation.
We also seek comment on whether there
exist other potential revisions that could
improve regional transmission planning
and cost allocation for anticipated
future generation, either as alternatives
to potential reforms discussed herein or
as supplementary reforms.
i. Future Scenarios and Modeling
Anticipated Future Generation
46. We seek comment on whether
reforms are needed regarding how the
regional transmission planning and cost
allocation processes model future
scenarios to ensure that those scenarios
incorporate sufficiently long-term and
comprehensive forecasts of future
transmission needs. We seek comment
on what factors shaping the generation
mix are appropriate to use for
transmission planning purposes, such
as, for example: (1) Federal, state, and
local climate and clean energy laws and
regulations; (2) federal, state, and local
climate and clean energy goals that have
not been enshrined into law; (3) utility
and corporate energy and climate goals;
(4) trends in technology costs within
and outside of the electricity supply
industry, including shifts toward
electrification of buildings and
transportation; and (5) resource
retirements. With regard to each factor
that may be considered for inclusion in
scenario modeling, we seek comment on
the source of the Commission’s
authority to incorporate that factor in
the regional transmission planning and
cost allocation processes. In addition,
we seek comment on whether the
Commission should establish minimum
requirements regarding future scenarios
for transmission providers to use in
their regional transmission planning,
including modeling anticipated future
generation in those scenarios.
Commenters should also address
whether and how any reforms or
revisions to existing rules could
unjustly and unreasonably shift
additional costs to customers of load
serving entities. Commenters should
also address whether the status quo
does or does not allocate costs in a
manner roughly commensurate with
benefits, and whether the status quo
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leads to rates that are unjust or
unreasonable.
47. The current regional transmission
planning and cost allocation processes
vary regarding how far into the future
transmission providers look when
evaluating transmission needs driven by
reliability, economic considerations, or
Public Policy Requirements. In general,
however, the extent to which regional
transmission planning processes plan
for anticipated future generation is often
limited to generation in the generator
interconnection queue with a completed
facilities study, which represents a
relatively short-term outlook, and
therefore may under-forecast anticipated
future generation on a longer-term basis
(and the associated transmission needs
of that anticipated future generation). As
noted, planning and developing the
transmission facilities needed to address
more efficiently or cost-effectively the
transmission needs of a changing
resource mix will often take
considerably longer than the typical
development timeline of a generating
facility that has completed a facilities
study and by considering such a limited
subset of generation resources, more
cost-effective transmission facilities that
address longer-term needs may never be
developed.
48. In light of the above, we seek
comment on whether, and if so, how the
regional transmission planning process
should be restructured to consider a
longer-term outlook. We seek comment
on whether developing plausible longterm scenarios would lead to the
identification of more efficient or costeffective transmission solutions in
regional transmission plans, whether
building transmission facilities to
accommodate anticipated future
generation is required to render rates
just and reasonable, and whether there
are deficiencies in existing regional
transmission planning and cost
allocation processes that would be
cured by conducting such future
scenarios planning. Specifically, we
seek comment on whether the
development of longer-term scenarios
for planning purposes should be
pursued and, if so: (1) The number of
years into the future the scenarios
should consider (including an
explanation of how far ahead it is
reasonable to forecast anticipated future
generation and system requirements);
(2) the inputs that should be considered
in modeling anticipated future
generation; (3) different transmission
planning methods, including whether
consideration should be given to
multiple future scenarios, as well as
how the planning process should
consider the probabilities of future
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scenarios; (4) whether and how
transmission providers should account
for an array of different future scenarios
when identifying more efficient or costeffective transmission solutions in
regional transmission plans; (5) whether
and how transmission providers should
account for federal, state, local, and
individual utility energy and climate
goals (including federal, state and local
laws and regulations, as well as other
policies or goals), and the source of the
Commission’s authority to account for
such laws, regulations, policies and
goals; (6) whether and how transmission
providers should plan for expected
future generator retirements; (7) whether
and how Grid-Enhancing
Technologies 68 should be accounted for
in determining what transmission is
needed under such scenarios; (8) how
benefits and costs of transmission
infrastructure should be accounted for
in such models, including how adjusted
production costs should be calculated;
(9) any other aspects of future scenarios
modeling, including planning for
anticipated future generation and
associated transmission needs that
would be useful for the Commission to
consider.
49. In addition, we seek comment on
whether greater use of probabilistic
transmission planning approaches may
better assess the benefits of regional
transmission facilities. While some
transmission providers consider a small
number of future scenarios as part of
their transmission planning process,
more advanced approaches, such as
stochastic 69 techniques, may provide an
opportunity to consider a broader array
of potential future conditions.
Accordingly, we seek comment on
potential benefits and drawbacks of
such techniques in regional
transmission planning assessments,
including whether these or other new
approaches may facilitate the cooptimization of generation siting and
transmission development, whether
such methods capture savings in
generation capital costs as well as
production expenses that can be
realized from transmission additions,
and whether implementing such
methods is required to render rates just
and reasonable.
68 Grid Enhancing Technologies increase the
capacity, efficiency, or reliability of transmission
facilities. These technologies include, but are not
limited to: (1) Power flow control and transmission
switching equipment; (2) storage technologies, and
(3) advanced line rating management technologies.
FERC, Grid Enhancing Technologies, Notice of
Workshop, Docket No. AD19–9–000 (Sept. 9, 2019).
69 Stochastic models are frameworks for
addressing optimization problems that involve
uncertainty.
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50. We also seek comment on which
inputs and assumptions transmission
providers would need to model to
represent new generation sources, such
as renewable resources, in order to
reflect their actual performance, such as
active power-frequency control, reactive
power-voltage control, and fault ridethrough capabilities, in the planning
study cases and any additional studies
in order to ensure that transmission
planning solutions result in operating
reliability for the future.
51. We seek comment on the extent to
which anticipated generation and
transmission facility retirements are
reflected in future scenarios modeled by
transmission providers, and whether
modifications to regional market rules
and coordination processes between
local and regional plans could facilitate
more accurate regional transmission
plans that reflect such anticipated
retirements.
52. In addition, should the use of
certain long-term scenarios be shown
appropriate as part of ensuring just and
reasonable rates, we seek comment on
whether and how the Commission
should ensure that the regional
transmission planning and cost
allocation processes develop a
sufficiently wide range of future
scenarios. We seek comment on whether
the Commission should consider
principles or minimum requirements as
a basis for establishing such scenarios.
Given that states or other local
governing bodies may be uniquely
situated in determining how much
anticipated future generation is needed,
or in providing information related to
infrastructure siting or resource mix as
influenced by state and local policies,
we seek comment on how their input
should be reflected by transmission
providers in developing a sufficiently
wide range of future scenarios,
including those for anticipated future
generation, and the more efficient or
cost-effective transmission facilities that
may be necessary to facilitate those
future scenarios. We seek comment on
whether it is necessary to require
transmission providers to modify the
regional transmission planning and cost
allocation processes, such as requiring
additional stakeholder input, to develop
future scenarios, including those for
anticipated future generation, such that
there are sufficient opportunities for
stakeholders to assess the
reasonableness of the results, as well as
for future modifications to the planning
process.
53. Finally, we seek comment on
whether and how such long-term
scenarios should be used in identifying
and selecting solutions to meet future
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transmission needs. For example, as
discussed below, should transmission
providers focus on a broader set of
benefits for transmission facilities and a
portfolio of transmission facilities in
identifying the more efficient or costeffective transmission solutions? If so,
how should regional planning processes
determine the right set of benefits to
factor into such an evaluation? Is
maximizing net benefits an appropriate
criterion to use to identify efficient and
cost-effective transmission solutions?
Should the willingness of some
beneficiaries to pay for certain
transmission infrastructure, for example
utilities or corporations with renewable
resource or zero carbon goals, be
considered in determining whether to
include the benefits within a broader set
of benefits from transmission facilities,
and if so then how? Is there a need to
establish a minimum set of transmission
facility benefits that transmission
providers must incorporate into regional
transmission planning decisions, and if
so, is there also a need to regularly
update the minimum set of transmission
facility benefits?
ii. Identifying Geographic Zones That
Have Potential for High Amounts of
Renewable Resource Development To
Meet Increased Demand
54. We seek comment on whether the
Commission should require
transmission providers in each
transmission planning region to
establish, as part of their regional
transmission planning and cost
allocation processes, a process to
identify geographic zones that have the
potential for the development of large
amounts of renewable generation and
plan transmission to facilitate the
integration of renewable resources in
those zones.
55. Examples of transmission
planning and development initiatives
that have identified geographic zones
with the potential for the development
of significant amounts of renewable
resources and transmission to facilitate
the integration of renewable resources
in those zones include the Public Utility
Commission of Texas’s (Texas
Commission) Competitive Renewable
Energy Zones (CREZ) initiative 70 and
MISO’s Multi-Value Projects (MVP).71
56. California Independent System
Operator Corporation (CAISO) offers
another example of a regional
transmission planning process
identifying transmission facilities to
accommodate renewable resources in
70 https://www.ercot.com/committee/crez.
71 https://www.misoenergy.org/planning/
planning/multi-value-projects-mvps/.
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geographic zones that have the potential
for high amounts of renewable
resources. In a petition for declaratory
order, the Commission approved a
mechanism to facilitate the financing
and development of transmission
facilities to interconnect multiple
resources that met CAISO’s eligibility
requirements, including a high voltage
level and providing access to areas rich
in renewable energy.72
57. We seek comment on whether the
Commission should require
transmission providers in each
transmission planning region to
establish, as part of their regional
transmission planning and cost
allocation processes, a process that
identifies geographic zones that have
the potential for the development of
large amounts of new generation,
particularly renewable resources. We
seek comment on whether and how
such a process might interrelate with
existing regional transmission planning
and cost allocation processes within
each region, and how long-term scenario
planning discussed above may be used
in this process or other relevant regional
transmission planning and cost
allocation processes. In addition, we
seek comment on whether reforms to
the current interregional transmission
coordination process are needed or
appropriate for making an approach
along these lines effective. We also seek
comment on: (1) How the Commission
should structure this potential
requirement; and (2) any potential best
practices, analyses, models, and metrics
that could be used to identify such
zones, including the amount and type of
potential generation that could be
located there. As with the future
scenarios transmission planning
discussed above, we seek comment on
whether and how states and local
entities may provide input into the
identification of such zones. We seek
comment on whether, and, if so, how
transmission providers can assess
whether there is sufficient commercial
interest in developing generation in any
potential zones and transmission to
interconnect the potential generation
(for example, through studies or formal
declarations of interest). We also seek
comment on whether and, if so, what
safeguards or incentives might be
necessary to ensure that transmission
infrastructure is built only to satisfy
expected transmission needs and not
overly speculative commercial interests.
We also seek comment on whether any
such requirement is consistent with the
FPA’s prohibition of unduly
discriminatory or preferential rates.
58. We seek comment on whether the
Commission should require
transmission providers to account for
trends in the resource mix in developing
energy zones for anticipated future
generation as part of planning for
transmission needs related to such
resources and if so, what would be the
best way to do so? We seek comment
whether it would be appropriate, as the
resource mix further develops, to
develop similar zones for the
transmission needs driven by the
development and interconnection of
energy storage resources and how to do
so.
59. In order to ensure that the more
efficient or cost-effective transmission
facilities are selected and that rates are
just and reasonable, we also seek
comment on whether: (1) Eligibility
thresholds or criteria (e.g., voltage
levels, amount of new generation
located within a given geographic area
or load zone, etc.) may be appropriate to
determine whether a proposed regional
transmission facility should be
considered as part of the regional
transmission planning and cost
allocation process for transmission
facilities built for anticipated future
generation; (2) whether the CREZ, MISO
MVP, CAISO approaches, or other
processes for identifying and planning
for the needs of anticipated future
generation are models for any potential
requirements and, if so, which aspects
of those initiatives the Commission
should consider requiring transmission
providers to implement, for example,
the CREZ model of requiring future
generation to financially commit in
advance of construction; (3) whether
there is a need for mechanisms to limit
the risk to customers from planning for
anticipated future generation, for
example, we note CAISO’s use of an ex
ante cap on the total cost exposure to
transmission customers in addressing
generation resource interconnection, as
one potential approach; 73 and (4)
whether specific proposals are
consistent with the Commission’s FPA
section 206 authority.
60. We also seek comment on whether
the regional transmission planning
process could be structured in such a
way that is more collaborative, relying
on the knowledge and experience that
transmission providers, project
developers, state commissions, and
other stakeholders have regarding
optimal locations, the topography of the
transmission network, and Public Policy
Requirements, among other factors that
72 Cal. Indep. Sys. Operator Corp., 119 FERC
¶ 61,061 (2007).
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iii. Incentivizing Regional Transmission
Facilities
61. To prioritize regional transmission
facilities that may have greater benefitto-cost ratios than local alternatives, we
seek comment on whether and, if so,
how to expand or improve any
incentives to incent the development of
regional transmission facilities that
demonstrably may offer a more efficient
or cost-effective solution to an identified
need than local alternatives. As an
example of a possible regional
transmission incentive, we seek
comment on whether or not any
available return on equity adder
incentive that may be available for RTO/
ISO participation should be limited in
applicability only to regional, and not
local, transmission facilities, when
those regional transmission facilities are
selected as the more efficient or costeffective solution to an identified
transmission need.
iv. Enhanced Interregional or State-toState Coordination
62. We recognize that potential
reforms discussed for comment above
may require greater interregional or
74 See Texas Commission, Order on Rehearing,
Docket No. 33672, at 3 (Oct. 7, 2008).
P 6.
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will influence the location and amount
of future renewable resources. We note
that the CREZ process was highly
collaborative, with the Electric
Reliability Council of Texas (ERCOT)
conducting workshops with
stakeholders over a six-month period to
consider and evaluate multiple
transmission scenarios.74 In addition to
seeking comment on technical and
collaborative approaches to identify
geographic zones for future renewable
resources, we seek comment on
potential alternative proposals from
stakeholders on how to identify where
transmission facilities may be needed to
accommodate anticipated future
generation. Commenters should address
whether, if implemented, such a
scenario planning process should be the
same or different in non-RTO/ISO
versus RTO/ISO regions, and if
different, what those differences should
be. Commenters should address how
any proposed changes to the regional
planning and cost allocation processes
increase the efficiency, or lower the
costs, of such processes and whether
such changes will help ensure a reliable
power supply and/or will reduce or
control the costs of transmission and
generation services that are ultimately
passed on to customers of load serving
entities. Commenters should also
address proposed cost allocation.
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state-regional coordination to be fully
realized in a just, reasonable and not
unduly discriminatory or preferential
manner. As a result, we seek comment
on whether reforms to the current
interregional transmission coordination
process, including potentially requiring
interregional transmission planning, are
needed or appropriate for making the
potential approaches discussed above
effective, and whether such reforms are
consistent with the Commission’s
authority under section 206 of the FPA.
63. We seek comment on whether,
because an interregional project must
first be selected in each of the
neighboring regions’ regional planning
processes before being selected in the
interregional process, this challenge to
the current interregional coordination
process is impeding the selection and
development of efficient, cost-effective
interregional projects and, if so, what
revisions are necessary to address that
barrier. Should the Commission require
joint planning processes, rather than
simply joint coordination, for
neighboring regions? In light of the
potential reforms to regional planning
and cost allocation and generator
interconnection processes being
considered in this ANOPR, are there
core principles or approaches that the
Commission should also consider when
reviewing the existing approach to
interregional planning? For example,
should the Commission establish
interregional reliability planning criteria
or consider renewable resource
geographic zones during interregional
planning? Beyond interregional
planning, can and should the
Commission provide alternate pathways
for transmission facilities that benefit
multiple regions to be assigned cost
allocation to customers across multiple
regions? For example, should the
Commission allow for identification of
benefits, and allocation of
commensurate costs, to one region of a
project selected in a neighboring
region’s regional transmission planning
process? Finally, comments should
address whether taking any proposed
action is consistent with the
Commission’s authority under section
206 of the FPA.
64. In addition, we seek comment on
whether and, if so, how a regional states
committee or other organized body of
state officials should participate in the
development and evaluation of
assumptions or criteria used for regional
transmission planning and cost
allocation and interregional
coordination and cost allocation for
transmission needs related to future
scenarios, including for anticipated
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future generation or geographic
generation zones.
b. Coordinating Between the Regional
Transmission Planning and Cost
Allocation and Generator
Interconnection Processes
65. We seek comment on whether
reforms are needed to improve the
coordination between the regional
transmission planning and cost
allocation and generator interconnection
processes. We seek comment on
whether the Commission should require
transmission providers to operate their
regional transmission planning and cost
allocation and generator interconnection
processes on concurrent, coordinated
timeframes, with the same or similar
assumptions and methods, and whether
such a potential requirement may
identify more efficient or cost-effective
transmission solutions that could
address needs shared between the two
processes.
66. We seek comment on how the
regional transmission planning and cost
allocation and generator interconnection
processes could be better coordinated or
integrated. For example, would use of
similar timeframes and assumptions
facilitate more efficient or cost-effective
transmission solutions? How could
these processes most effectively be cooptimized? We seek comment on
whether and, if so, how interconnection
requests that trigger the need for
interconnection-related network
upgrades that may provide regional
transmission benefits could be studied
in a way that accounts for the potential
broader transmission benefits associated
with, for example, resource adequacy,
operating reliability, and similar needs,
and in coordination with the regional
transmission planning process? We seek
comment on whether and how relevant
information from the generator
interconnection process could be
integrated into regional transmission
planning in a timely manner, and
whether and how transmission
providers could move beyond using the
outputs of each process as a
deterministic input into the other rather
than optimizing together across
approaches. We also seek comment on
whether it may be possible and
beneficial to combine certain aspects of
the transmission planning and generator
interconnection processes, and if so,
how?
67. We also seek comment on whether
and how the Commission could revise
transmission planning criteria that
transmission providers use in the
generator interconnection process so
that they could better identify more
efficient or cost-effective
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interconnection-related network
upgrades. As indicated earlier, we also
seek comment on whether and how
transmission providers could
incorporate anticipated future
generation, including resources in the
interconnection queue, in the regional
transmission planning and cost
allocation processes. In particular, we
encourage commenters to discuss how
to address concerns regarding
uncertainty, including speculative
projects, in planning for anticipated
future generation.
68. Further, we seek comment on
whether and how more effectively
accounting for anticipated future
generation in transmission planning
may reduce the costs of interconnectionrelated network upgrades. To the extent
this is the case, how should such
benefits be identified, and should they
factor into the regional transmission
planning and cost allocation process?
B. Identification of Cost and
Responsibility for Regional
Transmission Facilities and
Interconnection-Related Network
Upgrades
69. The Commission has repeatedly
recognized that, where cost allocation
methods do not appropriately account
for benefits associated with new
transmission facilities, they may result
in rates that are not just and reasonable
or are unduly discriminatory or
preferential.75
70. We seek comment on whether the
existing approach to cost allocation in
regional transmission planning
processes fails to consider the full suite
of benefits—and the associated
beneficiaries—produced by
transmission facilities developed to
meet the transmission needs of the
changing resource mix. We seek
comment on whether the current
approach omits relevant benefits of new
transmission infrastructure and, if so,
thereby fails to consider the entities that
receive those benefits in the cost
allocation process. What, specifically,
are those other benefits that should be
considered? In addition, while the
regional transmission planning process
considers transmission needs driven by
reliability, economic considerations,
and Public Policy Requirements, these
types of transmission needs are, in
75 See Order No. 890, 118 FERC ¶ 61,119 at P 557
(finding that how ‘‘the costs of new transmission
facilities are allocated is critical to the development
of new infrastructure’’ because ‘‘[t]ransmission
providers and customers cannot be expected to
support the construction of new transmission
unless they understand who will pay the associated
cost’’); Order No. 1000, 136 FERC ¶ 61,051 at PP
484–487; see also Ill. Commerce Comm’n v. FERC,
576 F.3d 470, 476 (7th Cir. 2009) (ICC v. FERC).
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many cases, considered in isolation
from one another and the cost allocation
methods for transmission facilities
developed in response to these needs
are generally separated by type. We seek
comment as to whether the existing
regional transmission planning and cost
allocation processes may not fully
account for the full suite of benefits,
including hard-to-quantify benefits, and
may impede the allocation of the costs
of transmission facilities needed to meet
the transmission needs of the changing
resource mix in a manner that is at least
roughly commensurate with the actual
benefits of those facilities. Getting that
balance right is important not only to
comply with the cost causation
principle, but also because efforts to
plan the transmission system to meet
the needs of the changing resource mix
will succeed only if the associated cost
allocation methods are transparent,
equitable, and practicable.76
71. With respect to cost allocation in
the generator interconnection process,
we seek comment as to whether the
participant funding approach for
interconnection-related network
upgrades required for an
interconnection request in RTOs/ISOs
may no longer be just and reasonable.
Participant funding may result in costly
interconnection-related network
upgrades being allocated entirely to
interconnection customers while failing
to account for the significant benefits
that these interconnection-related
network upgrades may provide to other
anticipated future generators seeking to
interconnect and/or existing or future
transmission customers. We further seek
comment on whether the narrow focus
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76 Cf.
BNP Paribas Energy Trading GP v. FERC,
743 F.3d 264, 268–269 (D.C. Cir. 2014) (BNP
Paribas Energy) (‘‘[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.’’ (citing
Midwest ISO Transmission Owners v. FERC, 373
F.3d 1361, 1368 (D.C. Cir. 2004) and Se. Mich. Gas
Co. v. FERC, 133 F.3d 34, 41 (D.C. Cir. 1998)));
Order No. 1000, 136 FERC ¶ 61,051 at P 669
(explaining that requiring cost allocation methods
be open and transparent ensures that such methods
are just and reasonable and not unduly
discriminatory or preferential, aids in development
and construction of new transmission, and may
avoid contentious litigation or prolonged
stakeholder debate); KN Energy, Inc. v. FERC, 968
F.2d 1295, 1300–01 (D.C. Cir. 1992) (describing
properly designed rates as producing revenues
‘‘ ‘which match, as closely as practicable, the costs
to serve each class or individual customer’ ’’
(emphasis in original)) (quoting Ala. Elec. Coop.,
Inc. v. FERC, 684 F.2d 20, 27 (D.C. Cir. 1982)); Pub.
Serv. Co. of Colo., 163 FERC ¶ 61,204, at P 14 (2018)
(recognizing that ‘‘feasibility’’ is part of ratemaking,
such that the Commission may appropriately
‘‘balance maximally reflecting cost causation with
other competing policy goals,’’ such as promoting
more efficient or cost-effective regional
transmission planning).
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of the generator interconnection process
results in only a subset of beneficiaries
paying for transmission infrastructure
that, in practice, may benefit many.
72. We seek comment on whether
separating the regional transmission
planning and cost allocation and
generator interconnection processes
may increasingly result in an only
partial-accounting of the benefits of new
transmission infrastructure, leaving
some transmission and interconnection
customers potentially bearing a
disproportionate cost burden. We seek
comment on whether any changes to the
criteria used for considering which
transmission facilities are selected in
the regional transmission plan for
purposes of regional cost allocation, as
well as the formula for the regional
allocation of costs of regional
transmission facilities and for the cost of
interconnection-related network
upgrades, including changes to the
definition of beneficiary, hold the
potential to unjustly and unreasonably
shift costs to customers of load serving
entities. We seek comment on how any
contemplated reforms or revisions to
existing regulations are consistent with
the FPA and its requirement for just and
reasonable and not unduly
discriminatory or preferential rates.
73. In the following sections, we
address the relevant court and
Commission precedent governing cost
allocation and seek comment on a
number of potential reforms to address
these concerns and ensure that
transmission rates remain just and
reasonable and not unduly
discriminatory or preferential.
1. Relevant Cost Causation Precedent
74. Pursuant to FPA sections 205 and
206, the Commission is responsible for
ensuring that the rates, terms, and
conditions for transmission of electricity
in interstate commerce are just,
reasonable, and not unduly
discriminatory or preferential.77 For a
cost allocation approach to satisfy this
standard, it must satisfy the cost
causation principle. The cost causation
principle requires that ‘‘all approved
rates reflect to some degree the costs
actually caused by the customer who
must pay them’’ 78 and that costs ‘‘be
allocated to those who cause the costs
to be incurred and reap the resulting
benefits.’’ 79 As the U.S. Court of
Appeals for the Seventh Circuit
(Seventh Circuit) further explained, 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.’’ 80 Courts ‘‘evaluate
compliance with this . . . principle by
comparing the costs assessed against a
party to the burdens imposed or benefits
drawn by that party.’’ 81 In ICC v. FERC,
the Seventh Circuit also stated that a
cost allocation method can satisfy the
cost causation principle if the
Commission ‘‘has an articulable and
plausible reason to believe that the
benefits are at least roughly
commensurate with’’ the allocation of
the costs.82 The Seventh Circuit stated,
however, that satisfying this
requirement does not require exacting
precision, and the Commission need not
‘‘calculate benefits to the last penny, or
for that matter to the last million or ten
million or perhaps hundred million
dollars.’’ 83
2. Cost Allocation for Transmission
Facilities Planned Through the Regional
Transmission Planning Process
75. Potential reforms for which we
seek comment in this ANOPR
contemplate a more forward-looking
approach to the regional transmission
planning process that plans for
anticipated future generation,
potentially producing a different and
broader set of benefits and beneficiaries.
The following sections seek comment
on potential reforms that may be
necessary to ensure that the costs of
transmission facilities developed to
meet the transmission needs of the
changing resource mix are allocated in
a manner that is roughly commensurate
with those benefits, while ensuring that
any potential reforms or revisions to
existing cost-allocation rules do not
unjustly or unreasonably shift costs to
any type of market participant or
customers of load serving entities. We
seek comment on whether certain
benefits are not appropriate to account
for under the FPA, and whether
allocation of costs based on such
benefits may be inconsistent with the
Commission’s statutory mandate.
a. Background
76. In Order No. 1000, the
Commission determined that the lack of
clear ex ante cost allocation methods
that identify beneficiaries of proposed
regional transmission facilities was
80 ICC
v. FERC, 576 F.3d at 476.
ISO Transmission Owners v. FERC,
373 F.3d at 1368.
82 576 F.3d at 477.
83 Id. (citing Midwest ISO Transmission Owners v.
FERC, 373 F.3d at 1369).
81 Midwest
U.S.C. 824d, 824e.
Energy, Inc. v. FERC, 968 F.2d at 1300.
79 S.C. Pub. Serv. Auth., 762 F.3d at 87 (quoting
NARUC v. FERC, 475 F.3d at 1285).
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impairing the ability of transmission
providers to implement more efficient
or cost-effective transmission solutions
identified in the regional transmission
planning process. According to the
Commission, the failure to address cost
allocation in a way that aligns with the
benefits of new transmission facilities
could lead to needed transmission
facilities not being built, adversely
impacting ratepayers.84 The
Commission therefore required
transmission providers to have in place
a method, or set of methods, for
allocating the costs of new transmission
facilities selected in a regional
transmission plan for purposes of cost
allocation. To guide transmission
providers, the Commission established a
set of cost allocation principles that
transmission providers’ cost allocation
methods must satisfy, with the goal of
ensuring that the costs of transmission
solutions chosen to meet regional
transmission needs would be allocated
to those that received benefits from
them.85 The Commission determined
that this principles-based approach
would result in the allocation of the
costs of new transmission facilities in a
manner that is at least roughly
commensurate with the benefits
received by those that pay those costs
while allowing for regional flexibility.86
77. The six regional cost allocation
principles that the Commission adopted
in Order No. 1000 are: (1) Costs of
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; 87 (3) a benefit to cost
threshold ratio, if adopted, cannot
exceed 1.25 to 1; 88 (4) costs must be
allocated solely within the transmission
planning region unless another entity
outside the region voluntarily assumes a
portion of those costs; 89 (5) the method
for determining benefits and identifying
beneficiaries must be transparent; 90 and
(6) there may be different methods for
different types of transmission facilities,
such as those needed for reliability,
congestion relief, or to achieve Public
84 Order
No. 1000, 136 FERC ¶ 61,051 at P 499.
PP 9, 482–83.
86 Id. P 10; Order No. 1000–A, 139 FERC ¶ 61,132
at P 647.
87 Order No. 1000, 136 FERC ¶ 61,051 at P 637.
88 Id. P 646.
89 Id. P 657.
90 Id. P 668.
85 Id.
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Policy Requirements.91 Although the
Commission required the regional cost
allocation methods to determine
benefits and identify beneficiaries in a
transparent manner, the Commission
also recognized that ‘‘identifying which
types of benefits are relevant for cost
allocation purposes, which beneficiaries
are receiving those benefits, and the
relative benefits that accrue to various
beneficiaries can be difficult and
controversial.’’ 92 Consistent with this
notion, the Commission declined to
require transmission providers to adopt
a universal or comprehensive definition
of ‘‘benefits’’ and ‘‘beneficiaries’’ 93 of
regional transmission facilities, instead
allowing for regional flexibility and
examining each region’s definitions on
compliance.
78. The result is that transmission
providers in each transmission planning
region have implemented varying
regional transmission cost allocation
methods to comply with the cost
allocation principles of Order No. 1000,
the majority of which allocate the costs
of regional transmission facilities that
address reliability needs separately from
those that address economic needs and
separately from those that address
Public Policy Requirements. In other
words, most regional transmission cost
allocation methods do not consider
whether a regional transmission facility
addresses more than one category of
needs, and therefore provides more than
one category of transmission benefits.
79. That said, some transmission
providers’ Order No. 1000-compliant
regional transmission cost allocation
methods may recognize a broader
number of benefits than others and
identify the broader benefits across a
portfolio of transmission facilities rather
than on a facility-by-facility basis,
whereas others may be more
constrained. For example, MISO’s MVP
process is designed to identify a
portfolio of regional transmission
facilities that: (1) Reliably and
economically enable regional public
policy needs; (2) provide multiple types
of regional economic value; and/or (3)
provide a combination of regional
reliability and economic value.
Specifically, MISO MVPs must be above
100 kV, have a project cost of $20
million or more, and have a combined
benefit-to-cost ratio greater than 1.0 and
must be evaluated as part of a portfolio
P 685.
P 501.
93 Order No. 1000–A, 139 FERC ¶ 61,132 at P 679
(explaining that Order No. 1000 does not define
benefits and beneficiaries but rather requires
transmission providers to be definite about benefits
and beneficiaries for purposes of their cost
allocation methods).
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of transmission projects.94 The costs of
this MVP portfolio are allocated on a
postage stamp basis across the MISO
region.95
80. Southwest Power Pool’s (SPP)
Balanced Portfolio process similarly
considers broader transmission
benefits.96 SPP evaluates economic
benefits of a portfolio of transmission
facilities to achieve a balance where the
benefits of the portfolio to each zone (as
measured by adjusted production cost
savings) equal or exceed the costs
allocated to each zone over a 10-year
period. By allocating costs such that the
benefits to each zone will equal or
exceed those costs, the Balanced
Portfolio process ensures that SPP
allocates costs in a manner that is least
roughly commensurate with benefits by
design. In addition, SPP may reallocate
costs to ensure that the portfolio is
balanced and, under certain conditions,
including cancellation of a transmission
facility or unanticipated decreases in
benefits or increases in costs, may
review a previously approved Balanced
Portfolio and recommend reconfiguring
the portfolio.97
81. As for allocating the costs of
regional transmission facilities to
generators, in Order No. 1000, while
commenters requested that the
Commission allow such costs to be
allocated to generators as beneficiaries,
the Commission determined that
generator interconnection was outside
the scope of the rulemaking.98 However,
the Commission also stated that
transmission providers could propose a
regional transmission cost allocation
method that allocates costs directly to
generators as beneficiaries, but any
effort to do so must not be inconsistent
with the Order No. 2003 generator
interconnection process. The
Commission noted that in not
addressing these issues, it was neither
minimizing the importance of
evaluating the impact of generator
interconnection requests during
transmission planning, nor limiting the
ability of transmission providers to use
requests for generator interconnections
in developing assumptions to be used in
94 MISO, FERC Electric Tariff, Attachment FF,
Section II.C (85.0.0).
95 Id. Section III.A.2.g.
96 SPP’s Balanced Portfolio was an initiative to
develop a group of economic transmission projects
that benefit the entire SPP region and to allocate
those transmission project costs regionally. The SPP
Board of Directors approved the Balanced Portfolio
transmission projects in April 2009.
97 SPP OATT, attach. J (Recovery of Costs
Associated With New Facilities), Section III.D.
98 Order No. 1000, 136 FERC ¶ 61,051 at P 760.
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the regional transmission planning
process.99
82. Nevertheless, at least one
transmission provider considers
interconnection customers as
beneficiaries of new transmission
facilities. The Commission approved
CAISO’s proposal whereby transmission
customers initially fund the
transmission expansion needed to
facilitate interconnection through the
transmission revenue requirement of the
constructing transmission provider, and
interconnection customers are assigned
their pro rata share of the going-forward
costs of using the transmission facility
as their generators interconnect to the
transmission system. Under CAISO’s
proposal, all transmission system users
pay the costs of the unsubscribed
portion of a new transmission facility
until the line is fully subscribed.100 The
CAISO approach also includes an ex
ante cap on the total cost exposure to
transmission customers, which was set
at 15% of the sum total of the net highvoltage transmission plant of all
transmission providers, as reflected in
their transmission revenue requirements
and in the CAISO transmission access
charge.101
b. Potential Need for Reform
83. This statement in Order No. 1000
rings as true today as it did then—
‘‘identifying which types of benefits are
relevant for cost allocation purposes,
which beneficiaries are receiving those
benefits, and the relative benefits that
accrue to various beneficiaries can be
difficult and controversial.’’ 102 This is
especially true for larger, regional
transmission facilities that are both
costly and could have potentially broad
benefits. As the Commission recognized
in Order No. 890, the manner in which
the costs of new transmission facilities
are allocated is ‘‘critical’’ to developing
those facilities as is identifying the
types of benefits and the associated
beneficiaries of those facilities.103
84. The possible reforms for which we
seek comment in this ANOPR seek to
ensure the development of regional
transmission facilities needed to meet
the transmission needs of the changing
resource mix occurs in a more efficient
or cost-effective manner, at just and
reasonable rates. Commenters should
also address whether and how any
reforms or revisions to existing rules
could unjustly and unreasonably shift
99 Id.
P 760.
Indep. Sys. Operator Corp., 119 FERC
¶ 61,061.
101 Cal. Indep. Sys. Operator Corp., 119 FERC
¶ 61,061, at P 6.
102 Order No. 1000, 136 FERC ¶ 61,051 at P 501.
103 Order No. 890, 118 FERC ¶ 61,119 at P 557.
100 Cal.
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additional costs to customers of load
serving entities. These reforms cannot
be successful without ensuring that
transmission providers and customers
alike are able to identify the types of
benefits of these transmission facilities
can provide and also identify the
beneficiaries that would receive those
benefits, along with the relative
proportion of benefits that accrue to
each of those beneficiaries. The failure
to account for all the benefits of a
transmission facility while taking into
account all the costs of the transmission
facility does not allow for a fair
examination of whether the costs are
allocated roughly commensurate with
the benefits. We seek comment on
whether ignoring benefits of these
transmission facilities may impair more
efficient or cost-effective transmission
development by limiting the number of
facilities that overcome the cost-benefit
threshold needed to justify the cost of
new transmission, and if so, what the
appropriate standard should be for
identifying such benefits. This potential
concern goes to the need to not only
identify the types of benefits of these
new transmission facilities, and to
quantify those benefits where possible,
but likewise to the need for transparent
methods to calculate benefits and
ascertain beneficiaries without being so
burdensome that the methods hinder
transmission development. We seek
comment on whether customers of load
serving entities should be required to
pay the costs of regional transmission
facilities that provide them only with
unquantifiable or purported benefits, or
be required to pay for costs driven by
the public policies of state and local
governments in states other than their
own.104
85. Currently, most regional cost
allocation methods do not consider
whether a regional transmission facility
addresses more than one category of
needs, thereby providing more than one
category of transmission benefits.
Specifically, although the regional
transmission planning process considers
transmission needs driven by reliability,
economic considerations, and Public
Policy Requirements,105 these types of
transmission needs are generally
104 See, e.g., PJM’s State Agreement Approach.
PJM Interconnection, L.L.C., 142 FERC ¶ 61,214, at
PP 142–143 (2013), order on reh’g and compliance,
147 FERC ¶ 61,128, at P 92 (2014);
105 Order No. 1000 left planning and cost
allocation for Public Policy Requirements largely to
the discretion of transmission providers. See supra
P 16. Moreover, under PJM’s State Agreement
Approach (see supra n.104), the costs of
transmission facilities required to meet the public
policy requirements of an individual state or group
of states may not be shifted to customers in other,
non-participating states.
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considered in a silo from one another;
the cost allocation methods for regional
transmission facilities developed in
response to these needs are similarly for
the most part separated by type. We
seek comment on whether the result is
a paradigm that may potentially fail to
consider the suite of benefits that
transmission facilities provide and
therefore fails to allocate the costs of
such facilities roughly commensurate
with the benefits.
86. We seek comment as to whether
a shift to a more integrated and holistic
process for regional transmission
planning and cost allocation is
appropriate. Such a shift may raise
novel questions around which
customers should pay for new
transmission facilities and concerns
about free riders benefitting from the
transmission expansion without paying
for their fair share. Under the potential
reforms for which we seek comment in
this ANOPR, the regional transmission
planning process would identify
transmission facilities that support
future scenarios, including anticipated
future generation, and improve pricing
and cost allocation for interconnectionrelated network upgrades. In that
scenario, interconnection customers
themselves could be considered
beneficiaries of transmission facilities
that facilitate their interconnection,
even if those transmission facilities
were built prior to the generators
entering the interconnection queue. We
seek comment on whether merely
making interconnection customers the
beneficiaries fails to capture all of the
relevant types of benefits for purposes of
cost allocation of a regional
transmission facility built to
accommodate anticipated future
generation. We also seek comment on
whether it may therefore be preferable
to consider developing new regional
transmission cost allocation methods
that measure all of the benefits of
regional transmission facilities that are
being assessed for potential selection in
the regional transmission plan for
purposes of cost allocation and that
accrue to both transmission and
interconnection customers.
87. We cannot ignore, of course, that
it may be difficult to precisely quantify
some of the benefits of transmission
facilities, which can be a barrier to more
broadly allocating the costs of those
facilities among transmission and
interconnection customers. Unlike
costs, which are clearly defined and
easily quantified, the scope of which
transmission benefits count for purposes
of cost allocation, and how well they
need to be documented in order to be
allocated to customers, is a distinct
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challenge to achieving a fair allocation.
Requiring transmission providers to
produce overly detailed reports on
benefits before the costs of a
transmission facility can be allocated to
transmission and interconnection
customers could lead to cost allocations
that undervalue the largest transmission
expansions, no matter their efficiency.
The task is in striking the right balance
to ensure just and reasonable rates and
the allocation of transmission costs
roughly commensurate with benefits.
88. We also note that, with greater
deployment of renewable resources, and
in part to the extent that regions focus
on a project-specific regional
transmission cost allocation method, it
is possible that benefits may be
distributed unevenly across regions. For
example, there are likely zones or subzones within a region that are rich in
renewable resources and therefore have
generation significantly in excess of the
local load. These zones, and generators
in these zones, may not be the only
beneficiaries of regional transmission
facilities built to access these resources
as customers outside those zones may
reap reliability or economic benefits that
result from the expanded transmission
system and access to low cost resources.
We seek comment on whether current
regional transmission cost allocation
approaches may not adequately address
these circumstances and may not
provide workable frameworks for the
identification of transmission
beneficiaries and sharing of benefits.
89. We seek comment on whether
there should be reforms to cost
allocation in regional transmission
planning and cost allocation processes,
including considering potentially a
portfolio approach to assessing regional
transmission facilities and consideration
of a minimum set of transmission
benefits, while seeking additional
information about cost allocation
approaches that may inform such
reforms. Commenters proposing specific
changes to cost allocation should
address how such proposals will result
in costs being allocated in a manner
roughly commensurate with benefits,
and demonstrate that costs will not be
disproportionately borne by any given
class of customers in a manner
inconsistent with the requirements of
the FPA and precedent. Commenters
should also address how such proposals
impact customers of load serving
entities and whether and how proposed
new cost allocation formulae may shift
costs to new categories of customers and
whether such cost-shifting is just and
reasonable and consistent with the
requirements of the FPA.
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c. Potential Reforms and Request for
Comment
90. We seek comment on whether
broader transmission benefits should be
taken into account when planning the
transmission system for anticipated
future generation, and how such
benefits should be identified and
quantified. Some transmission
providers, e.g., SPP, MISO, CAISO, and
recently the New York Independent
System Operator, Inc. (NYISO), have
used broader transmission benefits in
selecting regional transmission facilities
for purposes of cost allocation in their
regional transmission planning
processes.
91. In addition, under a portfolio
approach to regional transmission cost
allocation, multiple transmission
facilities are considered together, and
the collective benefits of the
transmission facilities are measured.
MISO’s MVP and SPP’s Balanced
Portfolio method are examples of
portfolio approaches to regional
transmission cost allocation. We seek
comment on whether a portfolio
approach recognizes that a regional
transmission planning process that
considers a group of transmission
facilities that collectively provide
multiple benefits, including reliability,
economic, and Public Policy
Requirements benefits, among others,
may be able to better identify more
efficient or cost-effective transmission
facilities when compared to a process
that focuses only on individual
transmission facilities or individual
benefits. We seek comment on whether
an approach that both estimates broader
transmission benefits for regional
transmission facilities beyond those that
are currently considered and that also
allocates the costs for a portfolio of
those individual transmission facilities
may provide a cost allocation method
that better matches benefits to burdens
over time.106 We seek comment on
whether such an approach may also be
more accurate or less likely to lead to
anomalous results.
92. At the same time, we seek
comment on whether there are
circumstances in which the use of
criteria other than reliability and
economic considerations may result in
projects being selected in the regional
transmission plan for purposes of cost
allocation that do not represent the
optimal solution to the reliability or
congestion problems identified and thus
may not represent the most efficient or
106 See BNP Paribas Energy, 743 F.3d at 268–69
(framing the cost causation principle ‘‘as a matter
of making sure that burden is matched with
benefit’’).
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cost-effective solution for customers of
the load serving entities both inside an
RTO/ISO and in non-RTO/ISO region.
Any proposals for changes to planning
criteria and cost allocation should
consider whether such proposals result
in unjustly and unreasonably shifting
costs to customers. We seek comment
on whether the use of planning criteria
beyond reliability and economic
considerations may place the burden for
the costs driven by Public Policy
Requirements of one state on customers
of load serving entities in nonparticipating states.
93. We seek comment on the current
approaches that transmission providers
take in defining transmission benefits
for purposes transmission planning and
cost allocation. For example, we are
interested in how transmission
providers calculate adjusted production
costs, the extent to which transmission
providers go beyond adjusted
production costs in identifying
transmission benefits, the types of
benefits, and the methods for
estimating. We also seek comment on
the extent to which it may be
challenging, for certain types of benefits,
to identify the beneficiaries for cost
allocation purposes. We seek comment
on the extent to which the same set of
benefits is currently used in regional
transmission planning processes and
their associated cost allocation
processes, or whether some benefits are
identified but not factored into cost
allocation. Should the same set of
benefits be used in all processes? If not,
would it be appropriate to consider
different benefits during the
transmission planning and cost
allocation stages? If so, what would be
the basis for doing so?
94. We seek comment on the types of
benefits provided by transmission
facilities needed to meet the
transmission needs of anticipated future
generation that are relevant for cost
allocation purposes and the manner in
which those benefits can be quantified,
if at all. This includes consideration of
whether there are transmission benefits
beyond those that transmission
providers already take into account in
allocating costs that the Commission
should require all transmission
providers to consider for regional
transmission facilities. In other words,
should the Commission require
transmission providers to establish a
broader set of transmission benefits for
purposes of cost allocation than
currently in use and, likewise, should
the Commission adopt a minimum set of
transmission benefits that must be
considered? Such benefits could
encompass economic benefits (e.g.,
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congestion reduction); resource
adequacy benefits (e.g., allowing
imports to replace more expensive local
generation, lowering required planning
targets through increased diversity
benefits); and reliability benefits (e.g.,
avoided or deferred reliability
transmission facilities, improved
reserves sharing, increased voltage
support). And to what extent are there
benefits that will differ from region-toregion?
95. If there are types of benefits that
cannot be quantified, but which are real
and relevant to allocating the costs of
regional transmission facilities roughly
commensurate with benefits, we seek
comment on how transmission
providers can document and account for
those benefits in crafting a cost
allocation method. Similarly, we seek
comment on whether the inability to
precisely quantify benefits of
transmission facilities can be a barrier to
the development of those facilities,
particularly those with potentially broad
transmission benefits. If so, we are
interested in what types of transmission
facilities are most impacted and what
types of benefits are typically associated
with those types of transmission
facilities, and how those benefits can be
justified and quantified.
96. To the extent that there are
relevant benefits that are difficult to
quantify, we seek comment on ways in
which the Commission can consider
whether those benefits are appropriately
credited to a regional transmission
facility and accounted for as part of
allocating the costs to beneficiaries. This
includes consideration of when benefits
of a transmission facility are sufficiently
certain to justify a commensurately
broad cost allocation, especially where
those benefits are not susceptible to
precise quantification. We also seek
comment on whether it is appropriate to
credit benefits that cannot be credibly
quantified and whether, and if so, how,
it is appropriate to factor such benefits
into regional cost allocation.
97. In addition to identifying benefits,
we also seek comment on best practices
for identifying the beneficiaries of a
transmission facility. For example, some
interconnection-related network
upgrades for generator interconnection
may benefit more than a single
interconnecting generator, however the
scope (temporal and geographic) of such
beneficiaries may not be clear. We seek
comment on the efficacy and
desirability of a regional transmission
planning and cost allocation process
that seeks to plan for future scenarios,
including planning for anticipated
future generation. What methods for
ascertaining beneficiaries are most
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effective in allocating the costs of such
facilities roughly commensurate with
benefits? Are there threshold
transmission system conditions that
would enable the Commission to
reasonably conclude that regional (or
some greater or lesser geographical
scope) allocation of costs is appropriate
(such as the amount of congestion or
level of interconnectedness in a
particular area)? This necessarily links
to our earlier questions about how to
quantify benefits and what level of
precision is required.
98. Along the same lines of
identifying beneficiaries, we seek
comment on whether the costs of
transmission facilities planned in the
regional transmission planning process
for which we seek comment in this
ANOPR should be allocated to both
transmission and interconnection
customers. As explained earlier, we are
concerned about potential free-rider
problems associated with
interconnection customers that later
connect to transmission facilities
planned for anticipated future
generation. We are therefore interested
in approaches to cost allocation to
ensure that both transmission and
interconnection customers that benefit
from those facilities pay their fair share.
While we propose to potentially reform
participant funding by interconnection
customers of interconnection-related
network upgrades, we are also
considering how best to allocate costs of
regional transmission facilities to
interconnection customers (e.g.,
whether cost allocation methods for
regional transmission facilities should
allocate a portion of the costs of a
regional transmission facility directly to
interconnection customers based on, for
example, the capacity of the
interconnection customer’s generating
facility).
99. We seek comment on the cost
effectiveness of the reforms discussed
herein. If the regional transmission
planning and cost allocation processes
are to consider transmission needs
driven by anticipated future generation,
is there a tradeoff between facilitating
the construction of transmission
facilities that are needed to connect
such anticipated future generation, and
ensuring against building more
transmission than is necessary? If so,
how should the Commission approach
that tradeoff?
3. Participant Funding and Crediting
Policy for Funding InterconnectionRelated Network Upgrades
100. Since the issuance of Order No.
2003, the composition of the generation
fleet has rapidly shifted from
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predominately large, centralized
resources to include a large proportion
of smaller renewable generators that,
due to their distance from load centers,
often require extensive interconnectionrelated network upgrades to
interconnect to the transmission system.
The significant interconnection-related
network upgrades necessary to
accommodate geographically remote
generation are a result that the
Commission did not contemplate when
it established the interconnection
pricing policy for interconnectionrelated network upgrades. Because the
large-scale changes since Order No.
2003 may have impacted the underlying
rationale for the interconnection pricing
policy, we seek comment on whether
the Commission should modify the
participant funding and crediting
policies, as discussed in further detail
below.
a. Background
i. Original Rationale for the Order No.
2003 Interconnection-Related Network
Upgrade Funding Requirements
101. As discussed above, the
Commission in Order No. 2003
described two general approaches for
assigning the costs of interconnectionrelated network upgrades needed to
interconnect a generating facility to the
transmission system: (1) the crediting
policy, whereby the interconnection
customer initially funds the
interconnection-related network
upgrades and is reimbursed through
transmission credits; 107 and (2)
participant funding, where the costs of
interconnection-related network
upgrades in RTOs/ISOs are assigned
directly to the interconnection
customer. Central to discussions of the
Commission’s interconnection-related
network upgrade funding requirements
is Order No. 2003’s continued
prohibition of ‘‘and’’ pricing. This
prohibition provides that, when ‘‘a
Transmission Provider must construct
107 Order No. 2003–B states that ‘‘the period for
reimbursement may not be longer than the period
that would be required if the Interconnection
Customer paid for transmission service directly and
received credits on a dollar-for-dollar basis, or 20
years [from the generating facility’s commercial
operation date], whichever is less.’’ Order No.
2003–B, 109 FERC ¶ 61,287 at PP 3, 36. If credits
have not fully reimbursed the upfront payment
within 20 years, Order No. 2003 requires ‘‘a balloon
payment’’ at the end of year 20. Id. P 36. The
crediting policy also requires that affected system
operators provide credits for transmission service
taken on an affected system. Id. P 42. Even if the
interconnection customer does not take
transmission service over the affected system,
however, the affected system operator must still
provide the 20-year balloon payment to refund any
remaining balance to the interconnection customer.
Order No. 2003–C, 111 FERC ¶ 61,401 at P 13.
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[interconnection-related] Network
Upgrades to provide new or expanded
transmission service, the Commission
generally allows the Transmission
Provider to charge the higher of the
embedded costs of the Transmission
System with expansion costs rolled in,
or incremental expansion costs, but not
the sum of the two.’’ 108 The
Commission also explained that
allowing the transmission provider to
charge either the higher of an embedded
cost rate for transmission service or an
incremental rate designed to recover the
cost of the interconnection-related
network upgrades ‘‘provides the
Transmission Provider with a cost
recovery mechanism that ensures that
native load and other transmission
customers will not subsidize service to
the Interconnection Customer.’’ 109
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(a) Crediting Policy
102. The Commission instituted the
crediting policy to achieve multiple
objectives. First, the Commission found
that this policy would avoid prohibited
‘‘and’’ pricing for interconnectionrelated network upgrades because it
ensures that the interconnection
customer will not be charged twice for
the use of the transmission system by
paying both for the incremental cost of
the upgrade and an embedded-cost rate
(with the cost of that interconnectionrelated network upgrade rolled in) for
use of the transmission system.110 Also,
the Commission stated that the crediting
policy was intended to facilitate the
efficient construction of
interconnection-related network
upgrades and enhance competition in
bulk power markets by promoting the
construction of new generation 111
Furthermore, the Commission found
that the crediting policy would ensure
comparable treatment for
interconnection customers that are not
affiliated with the transmission
provider, as transmission providers
traditionally roll the costs of
interconnection-related network
upgrades associated with their own
generating facilities into their
transmission rates.112
103. Additionally, in Order No. 2003–
A, the Commission stated that it does
‘‘not believe that the costs of
[interconnection-related] Network
Upgrades required to interconnect a
Generating Facility to the Transmission
System of a non-independent
108 Order
109 Order
No. 2003, 104 FERC ¶ 61,103 at n.111.
No. 2003–A, 106 FERC ¶ 61,220 at P
613.
110 Order
No. 2003, 104 FERC ¶ 61,103 at P 694.
PP 612, 694.
112 Id. P 694.
111 Id.
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Transmission Provider are properly
allocable to the Interconnection
Customer through direct assignment
because upgrades to the transmission
grid benefit all customers.’’ 113 The
Commission also stated that the
crediting policy has a two-fold purpose.
First, by providing the transmission
provider with a source of funds to
construct the interconnection-related
network upgrades, the upfront payment
by the interconnection customer
alleviates any delay that might result if
the transmission provider were forced to
secure funding elsewhere. Second, by
placing the interconnection customer
initially at risk for the full cost of the
interconnection-related network
upgrades, the upfront payment provides
the interconnection customer with a
strong incentive to make efficient siting
decisions and, in general, to make good
faith requests for interconnection
service.114
104. In NARUC v. FERC,115 multiple
petitioners challenged the crediting
policy established in Order No. 2003.
The petitioners argued that the crediting
policy was inconsistent with the cost
causation principle because they
disagreed with the Commission’s
conclusions that ‘‘[interconnectionrelated] Network Upgrades benefit the
entire network,’’ 116 and therefore, all
transmission customers should
essentially pay for those
interconnection-related network
upgrades through the crediting
policy.117 The U.S. Court of Appeals for
the District of Columbia Circuit (D.C.
Circuit) agreed with the Commission’s
position and noted that the D.C. Circuit
had previously ‘‘endorsed the approach
of ‘assign[ing] the costs of system-wide
benefits to all customers on an
integrated transmission grid.’ ’’ 118
(b) Participant Funding
105. In Order No. 2003, the
Commission stated that ‘‘under the right
circumstances, a well-designed and
independently administered participant
funding policy for [interconnectionrelated] Network Upgrades offers the
potential to provide more efficient price
signals and a more equitable allocation
113 Order No. 2003–A, 106 FERC ¶ 61,220 at P
212. As noted in the discussion below on
participant funding, the Commission has allowed
direct assignment of interconnection-related
network upgrade costs to generators interconnecting
to independent transmission providers such as
RTOs/ISOs.
114 Id. P 613.
115 475 F.3d 1277.
116 Id., 475 F.3d at 1285.
117 Id. (citing Pub. Serv. Co. of Colo., 62 FERC
¶ 61,013, at 61,061 (1993)).
118 Id. (citing W. Mass. Elec. Co. v. FERC, 165 F.3d
922, 927 (DC Cir. 1999)).
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of costs than the crediting
approach.’’ 119 Therefore, the
Commission stated that it would
provide RTOs/ISOs with the flexibility
to propose participant funding for
interconnection-related network
upgrades for a generator
interconnection.120 In accordance with
this flexibility, the Commission did not
prescribe specific policies for RTOs/
ISOs but instead provided them with
the flexibility to adopt policies of their
own choosing, subject to Commission
approval.121 Over time, each RTO/ISO
sought, and the Commission accepted,
independent entity variations to adopt
some form of participant funding rather
than the crediting policy.
106. The Commission expressed its
willingness to consider a well-designed
participant funding approach in
response to commenter concerns that
the crediting policy ‘‘mutes somewhat
the Interconnection Customer’s
incentive to make an efficient siting
decision that takes new transmission
costs into account, and it provides the
Interconnection Customer with what
many view as an improper subsidy,
particularly when the Interconnection
Customer chooses to sell its output offsystem.’’ 122 Additionally, while the
Commission mandated the crediting
policy for non-independent
transmission providers, Order No. 2003
acknowledged that the concerns that
gave rise to the adoption of the crediting
policy do not apply to RTOs/ISOs. For
example, Order No. 2003 noted that ‘‘a
number of aspects of the ‘but for’
approach are subjective, and a
Transmission Provider that is not an
independent entity has the ability and
the incentive to exploit this subjectivity
to its own advantage’’ by, for example,
finding ‘‘that a disproportionate share of
the costs of expansions needed to serve
its own power customers is attributable
to competing Interconnection
Customers.’’ 123 In contrast, however,
the Commission noted that RTOs and
ISOs are independent, and neither own
nor have affiliates that own generating
facilities and thus do not have an
incentive to discourage new generation
by competitors.124
107. The Commission also explained
that participant funding might speed up
the development of new transmission
infrastructure. In particular, Order No.
2003 postulated that ‘‘participant
119 Order
No. 2003, 104 FERC ¶ 61,103 at P 695.
P 28.
121 Order No. 2003–A, 106 FERC ¶ 61,220 at P
696.
122 Order No. 2003, 104 FERC ¶ 61,103 at P 695.
123 Id. n.111.
124 Order No. 2003–A, 106 FERC ¶ 61,220 at P
691.
120 Id.
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funding of [interconnection-related
network] upgrades may provide the
pricing framework needed to overcome
the reluctance of incumbent
Transmission Owners in many parts of
the country to build transmission, with
the result that badly needed
transmission infrastructure could be put
in place quickly.’’ 125
108. RTOs/ISOs that have adopted a
participant funding approach do not
reimburse interconnection customers
with transmission service credits for the
cost of the interconnection-related
network upgrades. Instead, the
Commission allowed interconnection
customers to receive well-defined
capacity rights that are created by the
interconnection-related network
upgrades.126 As an example, the
Commission in Order No. 2003 pointed
to PJM Firm Transmission Rights and
Capacity Interconnection Rights, which,
it stated, are ‘‘created by the
[interconnection-related] Network
Upgrades for which the Interconnection
Customer pays, and they are welldefined, long-term and tradeable.’’ 127
The Commission stated that provision of
such ‘‘well-defined capacity rights’’ in
lieu of credits does not violate the
prohibition of ‘‘and’’ pricing because the
‘‘Interconnection Customer pays
separate charges for separate services,’’
namely ‘‘an access charge for
transmission service that may involve
an obligation to pay congestion charges,
and in exchange for its ‘but for’
payment, [the interconnection
customer] receives these well-defined
capacity rights, which provide some
protection for having to actually pay the
congestion charges.’’ 128
109. Commission precedent makes
clear that the purpose of providing
‘‘well-defined’’ rights is not to provide
full reimbursement for the costs of
interconnection-related network
upgrades. In fact, where an RTO/ISO
adopts a participant funding approach
for interconnection-related network
upgrades required to interconnect an
interconnection customer, there is no
requirement that the capacity rights
being awarded for interconnectionrelated network upgrades have equal
value to the cost of the interconnectionrelated network upgrades because the
costs would not exist ‘‘but for’’ the
proposed interconnection and are
simply part of a project’s construction
costs and business risk that the
interconnection customer must
125 Order
126 Id.
No. 2003, 104 FERC ¶ 61,103 at P 703.
P 700.
127 Id.
128 Id.
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consider.129 Moreover, RTOs/ISOs are
‘‘not required to provide transmission
capacity rights where . . . the network
upgrades create no additional
transmission capability.’’ 130 To this
point, the Commission in Old Dominion
Electric Cooperative v. PJM
Interconnection, L.L.C. explained that,
while Order No. 2003 ‘‘stated that
generation interconnection customers
would receive capacity rights, those
statements were based on the
assumption that a network upgrade
provided by an interconnection
customer would create additional
transmission capability beyond that
needed to simply interconnect with the
grid.’’ 131
110. Again, each RTO/ISO sought an
independent entity variation to adopt a
participant funding approach rather
than adopt the crediting policy. In
MISO, an interconnection customer is
responsible for 100% of
interconnection-related network
upgrade costs, with a possible 10%
reimbursement or ‘‘crediting’’ for
interconnection-related network
upgrades that are 345 kV and above.132
In CAISO, the interconnection
customer’s cost responsibility for a
particular interconnection-related
network upgrade depends on how
CAISO classified the interconnectionrelated network upgrade (i.e., whether
the interconnection-related network
upgrade is considered area, local, or
reliability) and the interconnectionrelated network upgrade’s deliverability
status (e.g., full capacity, partial
129 PJM Interconnection, L.L.C., 108 FERC
¶ 61,025, at P 20 (2004); see also Midwest Indep.
Transmission Sys. Operator, Inc., 114 FERC
¶ 61,106, at P 66 (2006).
130 Old Dominion Elec. Coop. v. PJM
Interconnection, L.L.C., 119 FERC ¶ 61,052, at P 18
(2007) (ODEC v. PJM).
131 ODEC v. PJM, 119 FERC ¶ 61,052 at P 18; see
also id. P 16 (‘‘Not every system upgrade required
simply to interconnect a generating facility safely to
the grid entitles the generator to capacity rights;
however, a generation interconnection customer
would be ‘allowed to receive’ capacity rights if a
[interconnection-related] network upgrade creates
additional transmission capability.’’).
132 See, e.g., Midcontinent Indep. Sys. Operator,
Inc., 164 FERC ¶ 61,158, at P 5 (2018) (‘‘MISO’s
Interconnection Customer Funding Policy . . .
requiring the interconnection customer to
‘participant fund’ 90–100 percent of its
[interconnection-related] network upgrades . . .
was accepted, under the Order No. 2003
independent entity variation standard in 2009.’’);
Midwest Indep. Transmission Sys. Operator, Inc.,
129 FERC ¶ 61,060, at P 8 (2009) (accepting MISO’s
‘‘proposed change [that] would result in the
interconnection customer bearing 100 percent of the
costs of [interconnection-related] network upgrades
rated below 345 kV and bearing 90 percent of the
costs of [interconnection-related] network upgrades
rated at 345 kV and above (with the remaining 10
percent being recovered on a system-wide basis’’));
Midwest Indep. Trans. Sys. Operator, Inc., 114
FERC ¶ 61,106, at P 62 (2006).
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capacity, or energy-only).133 In CAISO,
full cash reimbursement is only
available for the costs of certain
categories of interconnection-related
network upgrades, up to $60,000 per
MW of installed generation capacity,
and interconnecting generators receive
congestion revenue rights in exchange
for funding any upgrades that are not
eligible for cash reimbursement. SPP,
NYISO, PJM, and ISO-New England,
Inc. use a participant funding approach
where the transmission provider assigns
100% of the interconnection-related
network upgrade costs to the
interconnection customer and the
interconnection customer may receive
compensation through transmission
capacity rights.134
b. Potential Need for Reform
i. Participant Funding
111. Since the issuance of Order No.
2003, changing circumstances have cast
doubt on whether it continues to be just
and reasonable to provide RTOs/ISOs
with the flexibility to adopt participant
funding approaches for interconnectionrelated network upgrades. We seek
comment on whether these
developments suggest that the
allowance of participant funding for
interconnection-related network
upgrades, both as a concept and in its
application, may no longer be just and
reasonable. Moreover, it appears that the
incentives created by participant
funding in this context may produce
outcomes that are counter to the
Commission’s intentions in allowing
flexibility for RTOs/ISOs to adopt
participant funding in Order No. 2003.
112. To begin with, participant
funding may allocate the costs of
extensive interconnection-related
network upgrades entirely to
interconnection customers without
accounting for the significant benefits
that these interconnection-related
network upgrades may provide to
transmission customers. As a result,
there are circumstances where this
allocation of interconnection-related
network upgrade costs may not be
roughly commensurate with the
distribution of benefits. For instance, a
large interconnection-related network
upgrade built on a consistently
congested portion of the transmission
system may provide significant
133 Cal. Indep. Sys. Operator Corp., 140 FERC
¶ 61,070, at PP 24–27 (2012).
134 PJM Interconnection, L.L.C., 108 FERC
¶ 61,025 (2004); Sw. Power Pool, Inc., 127 FERC
¶ 61,283 (2009); Sw. Power Pool, Inc., 171 FERC
¶ 61,272 (2020); N.Y. Indep. Sys. Operator, Inc., 108
FERC ¶ 61,159 (2004), order on reh’g, 111 FERC
¶ 61,347 (2005); ISO New Eng. Inc., 133 FERC
¶ 61,229 (2010).
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economic and reliability benefits to
transmission customers. Also,
transmission customers, in some
instances, can make use of any excess
transmission capacity created by a
participant funded interconnectionrelated network upgrade without paying
any of the capital costs that are paid for
through a participant funding approach.
Allowing transmission customers to
receive the benefits of interconnectionrelated network upgrades without
paying for a proportionate share of their
costs is an example of the ‘‘free rider’’
problem that the Commission’s
‘‘beneficiary pays’’ cost causation
principle is supposed to avoid.135
113. Furthermore, while the
interconnection customer may receive
well-defined capacity rights associated
with the increased transfer capability
caused by the interconnection-related
network upgrade, these well-defined
capacity rights do not compensate the
interconnection customer for the broad
range of benefits that the
interconnection-related network
upgrades can provide to the
transmission system and therefore do
not solve the ‘‘free rider’’ problem. This
is because the well-defined capacity
rights do not capture reductions in
congestion costs paid by transmission
customers that were the result of the
expansion of the transfer capability
created by the interconnection-related
network upgrade; nor do they capture
transmission service charges for use of
the excess capacity created by the
interconnection-related network
upgrade. Instead, well-defined capacity
rights capture congestion costs paid by
transmission customers on a going
forward basis across the relevant
transmission path on which the
interconnection-related network
upgrade increased transmission
capacity. To the extent that the
interconnection-related network
upgrade may have eliminated most of
the ex ante congestion on the relevant
paths, the transmission customers that
transact across such paths and have
their congestion costs reduced as a
result of the large interconnectionrelated network upgrade now in service
will receive this benefit for free in most
cases.
135 See, e.g., Order No. 1000–A, 139 FERC
¶ 61,132 at P 562 (‘‘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.’’).
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114. We seek comment on whether
costs allocated to interconnection
customers pursuant to participant
funding approaches have increased over
time, and if so, why. We seek comment
on whether this increase in costs is
evidence that regional transmission
planning processes are not building
adequate transmission system capacity.
We seek comment on whether the
Commission’s policies on participant
funding have impacted the
interconnection queue, e.g., through
late-state withdrawals, and if so, how
and to what degree. In the case that
there are late-stage withdrawals from
the interconnection queue, we seek
comment on the ability of transmission
providers to efficiently process
interconnection requests from other
interconnection customers affected by
the withdrawal. Finally, we seek
comment on whether uncertainty
regarding interconnection costs drives
up the cost of developing supply
resources and thereby ultimately
increases the cost of electricity supply
for customers.
115. Participant funding also may
create a separate incentive for the
interconnection customer that may
undermine the development of
interconnection-related network
upgrades that produce greater benefits.
Specifically, the interconnection
customer, knowing that it will be
responsible for all interconnectionrelated network upgrade costs, is likely
to strongly oppose any addition or
modification to the transmission system
beyond what is necessary to support its
own interconnection, even if such
additions and modifications may
ultimately benefit it and others by
providing improved reliability or
economic outcomes.136
116. An additional rationale that the
Commission provided in Order No.
2003 for allowing participant funding
was the concern that the
interconnection crediting policy would
‘‘mute somewhat the Interconnection
Customer’s incentive to make an
efficient siting decision that takes
transmission costs into account.’’ 137
The Commission in Order No. 2003 also
found that participant funding in RTOs/
ISOs is consistent with the policy of
promoting competitive wholesale
136 See Review of Generator Interconnection
Agreements and Procedures, Technical Conference
Transcript, Docket No. RM16–12–000 at Tr: 193:
20–24 (Steve Naumann, Exelon) (filed Aug. 23,
2016) (‘‘[Y]ou need to also deal with the
[interconnection] customer who says, ‘Okay, I will
be perfectly willing to take the risk, but I don’t want
to pay for a single upgrade more than I have to [to]
have a the reliability interconnection.’’).
137 Order No. 2003, 104 FERC ¶ 61,103 at P 695.
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markets because it causes the
interconnection customer to face the
same marginal cost price signal that it
would face in a competitive market.138
We seek comment on whether to
reconsider these findings in light of
current circumstances.
117. We note, for instance, that the
Commission’s view of efficient siting of
generation in Order No. 2003 was from
a transmission costs perspective, i.e.,
which points of interconnection would
require the least expensive
interconnection-related network
upgrades. We seek comment on whether
this perspective may be at odds with the
primary siting considerations for
renewable generation developers
decades later. That is, interconnection at
locations where renewable generation
may experience higher efficiency factors
(e.g., because they have abundant wind
or sun) may still be uneconomic where
participant funding applies because the
costs of interconnection-related network
upgrades for that location may be
significant and would not be allocated
beyond the interconnection customer.
We seek comment on whether
interconnection at such locations may
be considered economic, however, if the
cost of the interconnection-related
network upgrades were allocated more
broadly among those that benefit. Thus,
because the price signal participant
funding sends does not account for the
broader economic efficiencies from
siting renewable generation in fuel-rich
areas, it can instead encourage the
development of renewable generation in
less productive locations. Because
increased renewable resource
penetration in RTOs/ISOs is likely to
continue, it may make less sense to
retain a policy that encourages
renewable developers to develop lower
quality, less dependable renewable
resources.
118. Further, given the uncertainty
created by the RTO/ISO queue backlogs
and cascading interconnection-related
network upgrade cost allocations that
move from withdrawing higher-queued
interconnection customers to lowerqueued interconnection customers,
participant funding may no longer
provide efficient price signals that allow
generators to act freely to achieve the
desirable level of entry of new costeffective generating capacity. We
understand that a contributing factor to
the interconnection queue backlog is a
tendency by interconnection customers
to submit multiple interconnection
requests at different points of
interconnection, with the intention of
discovering the lowest cost site for a
138 Id.
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project (from an interconnection
perspective), and then withdrawing
higher-cost projects from the queue later
in the process. This tendency can
require numerous restudies and
reallocation of interconnection-related
network upgrade costs, compounding
the uncertainty surrounding the amount
of interconnection-related network
upgrade costs that will be attributable to
viable projects as the queue progresses.
119. We seek comment on whether it
is appropriate to eliminate or reduce
participant funding for interconnectionrelated network upgrades in RTOs/ISOs
and whether any specific proposed
changes to interconnection funding
mechanisms allocate costs in a manner
roughly commensurate with benefits
and are otherwise consistent with the
Commission’s authority under the FPA
and do not unjustly or unreasonably
shift costs to customers of load serving
entities.
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ii. Crediting Policy
120. We seek comments on whether
we should revisit the crediting policy in
all regions by requiring that
transmission providers, instead of
interconnection customers, fund upfront
all or a portion of the interconnectionrelated network upgrade costs. We
describe multiple variations of this
proposal below. Some generation
developers may find it difficult to
provide upfront funding for the costs of
network upgrades when the
reimbursement period can be as long as
20 years. Accordingly, we seek
comment on whether the current
approach may unjustly and
unreasonably allocate significant
financing costs for interconnectionrelated network upgrades to
interconnection customers when the
benefits of the interconnection-related
network upgrades accrue to the broader
system. We seek comment on whether,
if interconnection-related network
upgrade costs are increasing on average,
it is possible that these upfront funding
costs may pose an unjust and
unreasonable barrier to entry for
generation developers. Given these
considerations, below we seek comment
on some potential reforms to the
crediting policy.
c. Potential Reforms and Request for
Comment
121. We seek comment on whether
the Commission should eliminate the
independent entity variations that allow
RTOs/ISOs to use participant funding
for interconnection-related network
upgrades. We also seek comment on
potential approaches for modifying or
replacing the existing crediting policy
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for the costs of interconnection-related
network upgrades in all regions. We
seek comment on these options and
invite alternative suggestions by
commenters that take into consideration
the concerns discussed above.
122. Additionally, for each of the
reforms contemplated below, we seek
comment on whether there are
articulable and plausible reasons to
believe that these reforms would
allocate the costs of interconnectionrelated network upgrades in a manner
that is at least roughly commensurate
with the benefits of those
interconnection-related network
upgrades and that do not unjustly and
unreasonably shift costs to customers of
load serving entities or are otherwise
inconsistent with the Commission’s
statutory authority.
i. Eliminate Participant Funding for
Interconnection-Related Network
Upgrades
123. We seek comment on whether
participant funding of interconnectionrelated network upgrades may be unjust
and unreasonable. We seek comment on
whether RTOs/ISOs with previously
approved independent entity variations
that directly assign some or all the cost
responsibility for interconnectionrelated network upgrades to
interconnection customers should be
required to revise their tariffs to remove
the participant funding of
interconnection-related network
upgrade requirements and instead
implement the crediting policy as
prescribed in the pro forma LGIA.
124. The potential proposal to
eliminate participant funding of
interconnection-related network
upgrades in RTOs/ISOs would
recognize, however, that simply because
an interconnection request makes an
interconnection-related network
upgrade necessary for interconnection
(and in that sense, ‘‘causes’’ the need for
interconnection-related network
upgrades that would not be needed ‘‘but
for’’ an interconnection request), an
interconnection-related network
upgrade may sufficiently benefit
transmission customers that it is
appropriate to allocate the
interconnection-related network
upgrade costs more broadly. Also, this
potential proposal could address the
free rider problem that is created by
participant funding of interconnectionrelated network upgrades. We note,
however, that the specific proposal is to
eliminate participant funding and
replace it with the crediting policy, a
pricing approach that still requires
interconnection customers to initially
fund interconnection-related network
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upgrades.139 Moreover, no potential
reform presented here would modify the
existing requirement that an
interconnection customer bear cost
responsibility for the interconnection
facilities that would not be needed but
for its interconnection request.
125. We seek comment on whether
the removal of participant funding of
interconnection-related network
upgrades may also have the potential to
increase integration of generation by
removing the possibly prohibitive cost
assignment that participant funding can
place on some interconnection
customers. Furthermore, it may reduce
cost uncertainty to those resources in
the interconnection queue, and by
extension, increase the likelihood that
an interconnection request will result in
a developed generating facility.140
126. Additionally, we seek comment
on whether eliminating participant
funding may reduce the queue backlogs
that plague many regions because
interconnection customers would have
less incentive to submit multiple
interconnection requests in an attempt
to lower their interconnection costs, and
may no longer drop out of
interconnection queues at late stages
due to unforeseen interconnectionrelated network upgrade cost increases.
To these points, we seek comment on
the number of interconnection requests
that have withdrawn from the queue
because the direct assignment of
significant interconnection-related
network upgrade costs made otherwise
viable interconnection requests
uneconomic.
127. We seek comment on whether
the independent entity variation granted
to RTOs/ISOs in Order No. 2003 is no
longer just and reasonable. In general,
we seek comment on whether the
incentives created by participant
funding of interconnection-related
network upgrades in RTOs/ISOs may
produce outcomes that are counter to
the Commission’s transmission
planning and cost allocation efforts.
139 As noted below, however, we are exploring
reforms to the existing crediting policy approach
(that could be adopted alone or in combination with
the elimination of participant funding) that could
reduce the level of upfront funding to be provided
by the interconnection customers.
140 See, e.g., Review of Generator Interconnection
Agreements and Procedures, Technical Conference
Transcript, Docket No. RM16–12–000, at Tr. 25: 8–
15 (May 13, 2016) (Dean Gosselin, NextEra) (filed
Aug. 23, 2016) (‘‘I’d like to just talk about what is
optimal . . . as a developer . . . trying to advance
[a project] to fruition . . . . I would say for the
interconnection queue that the initial results closely
match final results in a defined and reasonable
timeline, that would be my definition.’’); id. at
134:5–7 (Omar Martino, EDF Renewable Energy)
(‘‘[C]osts can change dramatically between [the]
system impact and [the] facility study.’’).
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128. We are aware that there could be
complications associated with
implementing the crediting policy in
RTOs/ISOs with zonal transmission
rates that do not occur outside RTOs/
ISOs. Outside RTOs/ISOs, a single
transmission provider owns and
operates its transmission system and
generally charges a single rate for the
entire system, regardless of the specific
transmission customer’s location. In
contrast, an RTO/ISO operates the
combined transmission assets of
multiple transmission owners within its
footprint at non-pancaked transmission
rates, and generally has separate
transmission pricing zones. The
transmission rates for each zone are
generally designed to recover the costs
of transmission facilities located within
each zone. As a result, we seek
comment on whether simply applying
the crediting policy currently used
outside RTOs/ISOs in RTOs/ISOs may
disproportionately increase the burden
to the native load of transmission zones
where large amounts of interconnectionrelated network upgrades are
constructed to facilitate the
interconnection of location-constrained
resources, which ultimately may benefit
the entire RTO/ISO footprint.
129. Under a crediting policy in an
RTO/ISO, there may be a need for an
appropriate mechanism to reimburse the
interconnection customers, including a
mechanism for determining which
transmission owner(s) or zonal
transmission rates will include the
interconnection-related network
upgrade costs. For example, there is a
question of whether it would be just and
reasonable to allocate the costs only
within the transmission zone where the
interconnection-related network
upgrade is located or more broadly to
multiple transmission zones.141 We
therefore seek comment on how to
implement the crediting policy in
RTOs/ISOs and what principles should
be used to guide the application of the
crediting policy in RTOs/ISOs.
130. Finally, given the concerns about
the free-rider problem and whether the
‘‘well-defined capacity rights’’ received
by interconnection customers capture
the benefits the interconnection-related
network upgrades provide to the system,
we seek comment on: (1) The value of
the ‘‘well-defined capacity rights’’ that
interconnection customers have
received for funding interconnectionrelated network upgrades; and (2) the
value of the benefits that
141 See, e.g., Interstate Power & Light Co. v. ITC
Midwest, LLC, 144 FERC ¶ 61,052, at P 40 (2013),
order on reh’g, clarification and compliance, 146
FERC ¶ 61,113 (2014). See also Sw. Power Pool,
Inc., 127 FERC ¶ 61,283, at P 5 (2009).
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interconnection-related network
upgrades have provided to the system,
such as the value of congestion relieved
by interconnection-related network
upgrades. We are also interested in any
other concerns related to the ‘‘welldefined capacity rights’’ that
interconnection customers receive and
the ability of these ‘‘well-defined
capacity rights’’ to reflect the value of
the full incremental capacity and
congestion benefits added to the
transmission system by the
interconnection-related network
upgrades.
ii. Revisions to the Existing Crediting
Policy
131. We seek comment on possible
revisions to the Order No. 2003
interconnection crediting policy, which
requires that interconnection customers
provide upfront funding for
interconnection-related network
upgrades and receive reimbursement
through transmission service credits or
a balloon payment after 20 years. We
enumerate multiple proposals below.
Not all of these proposals are mutually
exclusive, and some could be
implemented in tandem.
(a) Transmission Providers Provide
Upfront Funding for All
Interconnection-Related Network
Upgrades
132. Pursuant to this potential
proposal, each transmission provider
would provide upfront funding for all
the interconnection-related network
upgrades on its transmission system.
Then, once such an interconnectionrelated network upgrade is in service,
the transmission provider would be able
to include the cost of that
interconnection-related network
upgrade in its transmission service rate
base and recover a return on, and of, the
network upgrade capital costs through
the cost-of-service transmission rates in
its OATT. Thus, interconnection
customers that take transmission service
on a transmission system would still
pay for a portion of interconnectionrelated network upgrades through
transmission rates. We seek comment on
(1) this approach and (2) how this
approach could be implemented in a
just and reasonable manner.
133. This option would reduce the
initial financing burden that
interconnection customers currently
may encounter when significant
interconnection-related network
upgrades are required for their
interconnection request. Furthermore,
this option may increase generator
competition by lowering barriers to
entry, which in turn will benefit
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customers by creating a more
competitive market for energy.
134. There may also be additional
efficiency benefits to removing the
crediting policy because the financing of
interconnection-related network
upgrades would follow the same
financing process that the transmission
owners apply to the other transmission
infrastructure that they fund and build
on their system. That is, there could be
an efficiency gain from using one
financing process for all transmission
system facilities instead of the existing
two: one for interconnection-related
network upgrades and another for other
transmission system facilities. In
addition to that particular inefficiency,
under the current crediting approach
applied in non-RTO/ISO regions, each
interconnection-related network
upgrade is financed twice—initially by
the interconnection customer and then
again by the transmission provider
when the interconnection customer
receives credits as it takes transmission
service or receives a balloon payment
after 20 years. Without the initial
funding by the interconnection
customer, interconnection-related
network upgrades would only need to
be financed once.
(b) Interconnection Customers
Contribute to the Upfront Funding of
Interconnection-Related Network
Upgrades Through a Fee
135. Another possible reform to the
current crediting policy is to consider
the establishment of a non-refundable
fee to be charged for submitting an
interconnection request and that is not
reimbursable through transmission
service credits. Under this approach, an
appropriate fee should not be so large
that it creates barriers to entry for
smaller developers. Potential benefits of
this type of fee could include: (1)
Defraying some of the cost to
transmission customers for
interconnection-related network
upgrades and therefore decreasing the
overall impact on transmission
customers of the related potential
reform to eliminate participant funding
of interconnection-related network
upgrades in RTOs/ISOs; (2)
discouraging the submission of
speculative interconnection requests;
and (3) for some variable fees, providing
a price signal to interconnection
customers that could incent efficient
siting decisions where possible. We seek
comment on (1) whether to impose a
non-refundable, non-reimbursable fee
on each submitted interconnection
request and (2) how this approach could
be implemented in a just and reasonable
manner.
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136. We seek comment on two
specific versions of this approach. First,
we seek comment on the potential
establishment of a fixed fee applied to
each interconnection request, which
would be the same for all
interconnection requests, irrespective of
the generating facility’s capacity or
project location. We seek comment on
whether establishing a fixed fee would
be appropriate and, if so, the
appropriate amount of such a fee.
137. Second, we seek comment on the
potential establishment of a variable fee
applied to each interconnection request.
The amount of the variable fee could
depend upon the generating facility
capacity associated with the
interconnection request and/or the
identified interconnection-related
network upgrades. For example, the fee
could be based on a percentage of the
estimated interconnection-related
network upgrade costs or be calculated
based on the generating facility capacity
and/or the voltage rating of the
interconnection-related network
upgrade. We seek comment on the
appropriate size of this fee and the
structure of the fee, if the Commission
were to require one. We also seek
comment on whether it is possible to
use a percentage of interconnectionrelated network upgrade cost estimates
for this fee, and if so, at which point in
the generator interconnection process a
transmission provider would calculate
that cost.
138. Finally, we seek comment on
whether such a fee should be
established at the outset of the generator
interconnection process, or whether an
escalating fee should be imposed as the
interconnection request moves through
the study process. For example, a
smaller fee could be required for entry
into the feasibility study phase, with a
larger fee for the system impact study
phase and the largest fee required to
enter the facilities study.142 In this
manner, speculative projects could be
discouraged from entering the later
stages of the generator interconnection
process, while still allowing
interconnection customers to use the
feasibility study process as it was
designed, to determine project
feasibility for a broader range of project
sizes and locations.
142 These
non-refundable fees would be in
addition to, and distinct from, the initial deposit
submitted with an interconnection request and
study deposits that are applied toward an
interconnection customer’s interconnection study
costs.
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(c) Transmission Providers Provide
Upfront Funding for Only Higher
Voltage Interconnection-Related
Network Upgrades
139. We seek comment on whether it
would be appropriate to require
transmission providers to fund upfront
the costs of any interconnection-related
network upgrade that is rated at or
above a certain voltage threshold.
Interconnection customers would be
responsible for upfront funding the cost
of interconnection-related network
upgrades below that threshold and be
reimbursed through transmission
service credits pursuant to the crediting
policy.
140. Because higher voltage
transmission facilities tend to produce
greater and broader benefits to
transmission systems than lower voltage
transmission facilities, this option may
better satisfy the requirement that the
allocation of costs be at least roughly
commensurate with the distribution of
benefits.143 Thus, where an
interconnection-related network
upgrade’s voltage exceeds a defined
threshold and is likely to produce
system-wide benefits, it may be
appropriate to require that transmission
providers fund the costs of such
interconnection-related network
upgrades upfront.
141. The Commission could also
adopt a modified version of this
approach by requiring transmission
providers to upfront fund the portion of
the costs of higher voltage
interconnection-related network
upgrades that exceeds a pre-determined
cost threshold. For example, the
Commission could require transmission
providers to upfront fund the costs of a
345 kV interconnection-related network
upgrade that exceed $10 million.
Pursuant to this modified version, in
this example of a 345 kV
interconnection-related network
upgrade, the Commission would require
the interconnection customer to fund all
network upgrade costs up to $10 million
and require the transmission provider to
provide upfront funding for all
interconnection-related network
upgrade costs above the $10 million
threshold. Even in this situation,
however, the transmission provider
would still have to provide transmission
service credits to reimburse the
interconnection customer for its $10
million subject to the crediting policy.
142. We note that the Commission has
approved a version of this cost sharing
143 See, e.g., Old Dominion Elec. Coop. v. FERC,
898 F.3d 1254, 1260 (D.C. Cir. 2018) (adopting
Commission finding that ‘‘high-voltage power lines
produce significant regional benefits’’).
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approach in MISO, albeit in the context
of responsibility for payment of
interconnection-related network
upgrade costs themselves and not just
the upfront funding of them as
discussed here. MISO’s tariff provides
for some cost sharing for
interconnection-related network
upgrades under which transmission
providers recover the costs of 10% of
interconnection-related network
upgrades rated 345 kV and above on a
system-wide basis while directly
assigning through participant funding
90% of the costs of such upgrades to the
interconnection customer whose
interconnection required the network
upgrade.144 Furthermore, on multiple
occasions, the Commission has
permitted RTOs/ISOs to define different
transmission facility categories and
adopt different cost allocation methods
for transmission facilities based on the
transmission facility’s voltage
threshold.145
143. If the Commission were to split
the upfront funding responsibility for
interconnection-related network
upgrades between the transmission
provider and the interconnection
customer, it may be useful to create a
split based on voltage. For example,
adopting an interconnection-related
network upgrade voltage threshold to be
funded upfront by the transmission
provider has the potential to
significantly reduce interconnectionrelated network upgrade financing costs
by eliminating interconnection
customers’ need to fund upfront the
likely more expensive higher voltage
interconnection-related network
upgrades. It could be appropriate to
require the transmission provider to
fund upfront the cost of higher voltage
interconnection-related network
upgrades because higher voltage
transmission facilities are likely to
produce greater region-wide benefits
than lower voltage ones.
144. Whatever the selected voltage
threshold might be, interconnection
customers would still be required to
upfront fund the costs of
interconnection-related network
upgrades (subject to the crediting
policy) that do not meet that threshold.
Thus, the selection of a voltage
threshold would necessarily exclude
from transmission provider upfront
funding some interconnection-related
network upgrades that produce regional
144 MISO Tariff, Attach. FF (Transmission
Expansion Planning Protocol), Section III.A2.d
(81.0.0).
145 See Midcontinent Indep. Sys. Operator, Inc.,
172 FERC ¶ 61,095 (2020) (accepting MISO’s
proposal to change the qualifying voltage threshold
for a certain class of project from 345 kV to 230 kV).
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transmission benefits. We think it
important to ensure that, if the
Commission requires that transmission
providers establish a voltage threshold
for sharing the responsibility to fund
upfront the cost of interconnectionrelated network upgrades, then the
voltage threshold should be based upon
the likelihood that interconnectionrelated network upgrades that meet that
threshold produce more transmission
benefits than interconnection-related
network upgrades below that threshold.
Furthermore, we recognize that there is
some tension between such an
approach, which would eliminate the
requirement that interconnection
customers upfront fund some
interconnection-related network
upgrades based on voltage, thus
reducing the interconnection customers’
financing costs only on larger
interconnection-related network
upgrades, and Order No. 2003’s general
acknowledgement that interconnectionrelated network upgrades, regardless of
voltage or size, ‘‘benefit all users.’’ 146
Additionally, if the Commission
adopted this option, in order to avoid
the responsibility to upfront fund,
transmission providers will have an
incentive to identify a lower voltage
interconnection-related network
upgrade rather than identifying a higher
voltage project that may be more
efficient or cost-effective.
145. We seek comment on: (1) This
approach; (2) the appropriate voltage
threshold and any pre-determined cost
threshold; and (3) how this approach
could be implemented in a just and
reasonable manner.
(d) Allocate the Upfront Cost of
Interconnection-Related Network
Upgrades on a Percentage Basis
146. We seek comment on whether to
reduce the allowable percentage of
interconnection-related network
upgrade costs that interconnection
customers must fund upfront (i.e., from
100% to a lower percentage). The
crediting policy would apply to the
portion of the interconnection-related
network upgrade costs that the
interconnection customer upfront funds.
To allow flexibility, we seek comment
on whether an interconnection customer
should have the option to elect to
upfront fund 100% of the
interconnection-related network
upgrade if it chooses.
147. This method could benefit both
the interconnection customer and the
transmission provider. With the ability
to provide partial to full upfront funding
for interconnection-related network
146 Order
upgrades, interconnection customers
will have the ability to retain some
control over the speed of
interconnection-related network
upgrade construction because they will
be able to provide initial funding in
cases where the transmission owner
does not have the funding readily on
hand to pay for certain construction
milestones. Transmission providers will
benefit because this construct will retain
the price signal to interconnection
customers regarding siting decisions, as
interconnection customers would still
have to upfront fund (i.e., finance) the
costs of more expensive larger
interconnection-related network
upgrades associated with their
interconnection requests and the costs
related to financing interconnectionrelated network upgrades (e.g., interest
payments due on the loan) should
increase as the costs of the
interconnection-related network
upgrades increase.
148. We note that adoption of the
transmission planning and cost
allocation reforms discussed above is
likely to result in the development of
regional transmission facilities intended
to accommodate significant amounts of
generation, and thus, has the potential
to reduce the need for more extensive
and costly interconnection-related
network upgrades relative to those
identified in the generator
interconnection process at present.
Thus, the adoption of this generator
interconnection reform, in conjunction
with the regional transmission planning
and cost allocation reforms discussed
above, could result in a significant
reduction in interconnection customer
financing costs while still maintaining a
price signal for siting decisions.
149. We seek comment on: (1) This
approach; (2) the appropriate percentage
for the interconnection customer’s
upfront funding; and (3) how this
approach could be implemented in a
just and reasonable manner. As part of
this inquiry, we are interested in
hearing perspectives on the extent to
which partial upfront funding by an
interconnection customer may preserve
or reduce the incentive for that
customer to efficiently site a project. We
seek comment on whether there are
there other mechanisms, beyond
customer upfront funding, that may
incent a customer to site efficiently, and
that could be adopted in conjunction
with the elimination of participant
funding.
No. 2003, 104 FERC ¶ 61,103 at P 65.
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iii. Additional Considerations
(a) Interconnection-Related Network
Upgrade Cost Sharing
150. If the Commission does not
eliminate participant funding of
interconnection-related network
upgrades, we seek comment regarding
potential cost-sharing measures to
account for the fact that later-in-time
interconnection customers may accrue
benefits from interconnection-related
network upgrades built to accommodate
a prior interconnection request. That is,
if a later-in-time interconnection
customer benefits from the
interconnection-related network
upgrades required to interconnect an
earlier-in-time interconnection
customer, the later-in-time
interconnection customers may also be
assigned a portion of those costs. The
transmission provider could require the
allocation of costs in proportion to the
benefits that the later-in-time
interconnection customers receive from
network upgrades or be based on a
different method, such as a percent
share based on usage. To make this
approach workable, the transmission
provider could also dictate a point after
which a later-in-time interconnection
customer would be insulated from
bearing the costs of a specific
interconnection-related network
upgrade, e.g., prohibiting allocation of
interconnection-related network
upgrade costs to interconnection
customers that enter the queue five
years or more after the interconnectionrelated network upgrade’s
energization.147 As we noted above, the
Commission has previously approved
tariff provisions pursuant to which
earlier-in-time interconnection
customers receive a form of
reimbursement for the network upgrade
costs from later-in-time customers.148
We note that the sharing of costs
between earlier-in-time and later-intime interconnection customers would
only apply in situations where the
earlier-in-time interconnection customer
was assigned any of the costs of the
interconnection-related network
upgrade under the participant funding
framework. We seek comment on a just
and reasonable method to calculate cost
sharing for shared network upgrades.
We also seek comment on whether to
require, and the appropriate duration of,
a time after which a later-in-time
interconnection customer would not be
147 For the purpose of this order, we will refer to
this time period as the sunset period.
148 See NYISO Tariff, attach S (Rules to Allocate
Responsibility for the Cost of New Interconnection
Facilities), Section 25.7.2; see also MISO Tariff,
Attach. FF Section III.A.2.d.2 (81.0.0).
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interconnection-related network
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(b) Option To Build
151. Order No. 2003 established, and
Order No. 845 expanded, the
interconnection customer’s option to
build transmission provider’s
interconnection facilities 149 and stand
alone network upgrades.150 In a nonRTO/ISO, if an interconnection
customer elects to exercise the option to
build, the interconnection customer
assumes the responsibility to design,
procure, and construct the transmission
provider’s interconnection facilities and
stand alone network upgrades and is
repaid by the transmission provider
pursuant to the crediting policy.
152. Importantly, the option to build
allows interconnection customers to
have some control over their own
timelines and construction schedules
and potentially achieve cost savings
associated with the design,
procurement, and construction of the
transmission provider’s interconnection
facilities and stand alone network
upgrades. If the Commission revises the
requirement that interconnection
customers upfront fund all or some of
the costs all of interconnection-related
network upgrades, corresponding
changes may be necessary to the option
to build provisions as they apply to
stand alone network upgrades to
recognize that an interconnection
customer that wants to exercise the
option to build would no longer be
responsible to upfront fund the full cost
of those network upgrades. Therefore,
149 Order No. 2003 defined two categories of
interconnection facility: (1) Transmission provider’s
interconnection facilities, which refer to all
facilities and equipment owned, controlled or
operated by the transmission provider from the
point of change of ownership to the point of
interconnection, including any modifications,
additions or upgrades to such facilities and
equipment;’’ and (2) interconnection customer’s
interconnection facilities, which are located
between the generating facility and the point of
change of ownership and which the interconnection
customer must design, procure, construct, and own.
See pro forma LGIA art. 1 (Definitions); pro forma
LGIA art. 5.10.
150 Order No. 2003, 104 FERC ¶ 61,103 at P 353;
Reform of Generator Interconnection Procedures
and Agreements, Order No. 845, 163 FERC ¶ 61,043,
at P 85 (2018), order on reh’g, Order No. 845–A, 166
FERC ¶ 61,137, order on reh’g, Order No. 845–B,
168 FERC ¶ 61,092 (2019). Stand alone network
upgrades refer to interconnection-related network
upgrades ‘‘that are not part of an Affected System
that an Interconnection Customer may construct
without affecting day-to-day operations of the
Transmission System during their construction.
Both the Transmission Provider and the
Interconnection Customer must agree as to what
constitutes Stand Alone Network Upgrades and
identify them in Appendix A to the Standard Large
Generator Interconnection Agreement.’’ See pro
forma LGIP Section 1 (Definitions).
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we seek comment on what changes may
be necessary to ensure that the option to
build provisions remain just and
reasonable and to retain flexibility for
interconnection customers in light of
the potential change to the funding
policy.
(c) Interconnection Request Limit
153. We understand that a
contributing factor to the
interconnection queue backlog is a
tendency by interconnection customers
to submit multiple interconnection
requests at different points of
interconnection, with the intention of
discovering the lowest cost location to
site the generating facility (from an
interconnection perspective), and then
withdrawing higher-cost
interconnection requests from the queue
later in the process. We also understand
that, absent an appropriately-sized
penalty (or reasonable restriction)
associated with submitting an
interconnection request and then
subsequently withdrawing such an
interconnection request, there still may
be an incentive to submit speculative
interconnection requests under any of
the potential interconnection reforms
discussed above. Therefore, we seek
comment on whether there should
penalties for submitting speculative
requests, how such should be defined,
and whether there should be a limit on
the number of interconnection requests
that a developer can submit in an
interconnection queue study year and
how narrowly such a limit should apply
(e.g., by transmission provider or by
transmission pricing zone). We also seek
comment on how to determine a just
and reasonable limit to the number of
interconnection requests. Finally, we
seek comment on how to address
interconnection requests made by
affiliated companies and whether those
interconnection requests should count
against the limit to the number of
interconnection requests if one is
imposed.
(d) Fast-Track for Interconnection of
Generating Facilities Committed to
Regional Transmission Facilities
154. As discussed above, we seek
comment on the model established by
ERCOT to construct the CREZ
transmission projects. For those
transmission projects to be approved,
ERCOT required a certain percentage of
capacity to be reserved by generation
developers with existing projects,
projects under construction, projects
with signed interconnection agreements,
or posted collateral. In the case that this
model may improve the coordination
between transmission planning and the
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development of future generation, it
may become important to streamline the
generator interconnection process for
generating facilities that are committed
to interconnecting to these transmission
facilities.
155. Therefore, we seek comment on
whether a fast-track generator
interconnection process should be
developed to facilitate interconnection
of generating facilities that have firmly
committed to connecting to new
regional transmission facilities. An
example of such a fast-track option may
be to allow the transmission provider to
perform a limited system impact study
for only the cluster of generating
facilities committed under the regional
transmission planning process and to
move to the facilities study without
waiting for earlier studies to complete.
We recognize that the timeline for
transmission facility permitting and
construction often far exceeds that of
the generator interconnection and
construction process but seek comment
nonetheless on whether a faster
generator interconnection process in
this scenario would be beneficial.
156. We seek comment on whether
such a process would constitute
inappropriate ‘‘queue jumping,’’ or
instead would be more appropriately
viewed as an extension of the
previously approved first-ready, firstserved queueing practice. In this case,
are generating facilities that have put up
financial collateral to ensure that a
regional transmission facility is
constructed to serve them appropriately
considered ‘‘ready’’ projects? We seek
comment on the feasibility of
establishing such a proposal, as well as
the implications on the rest of the
generator interconnection queue and on
any legal challenges related to a
potential ‘‘queue jumping’’ concern.
(e) Fast-Track for Interconnection of
‘‘Ready’’ Generating Facilities
157. In addition to considering a fasttrack generator interconnection process
for interconnection customers that have
committed financially to new regional
transmission facilities, we are
considering whether allowing a fasttrack for ‘‘ready’’ interconnection
requests would remove barriers to entry
for interconnection requests that have
met certain readiness criteria. For
example, interconnection requests for
which the developer has already
executed a power purchase agreement
or that have been chosen in a state or
utility request for proposals may be
appropriately deemed more ‘‘ready’’
than projects that enter the
interconnection queue without either
contractual arrangement. Another
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example of an interconnection request
that demonstrates a higher degree of
readiness could be one sited at a
previously developed point of
interconnection that can make use of
existing interconnection facilities. Such
interconnection requests may be
considered more ready because they
have more ready access to the
transmission system. Both of these
examples could be considered more
ready than interconnection requests
proposed at points of interconnection
where the interconnection customer or
the transmission provider must acquire
new rights-of-way, permits, and
agreements with landowners, or that
face other obstacles to rapid
development. We seek comment on
which types of interconnection requests
could be considered more ‘‘ready’’ and
able to advance through the
interconnection queue more quickly, as
well as comments on the just and
reasonable structure for such a fast-track
option. We also seek comment on how
to implement such a proposal in a
manner that is not unduly
discriminatory. As in the prior proposed
reform, we seek comment on how to
address possible concerns related to
what some may consider ‘‘queue
jumping’’ or whether appropriate factors
may justify such measures.
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(f) Grid-Enhancing Technologies
158. We seek comment on whether
there is the potential for Grid-Enhancing
Technologies not only to increase the
capacity, efficiency, and reliability of
transmission facilities, but, in so doing,
also to reduce the cost of
interconnection-related network
upgrades.151 In light of the potential of
Grid-Enhancing Technologies, we seek
comment on whether the Commission
should require that transmission
providers consider Grid-Enhancing
Technologies in interconnection studies
to assess whether their deployment can
more cost-effectively facilitate
interconnections. To the extent
transmission providers currently
consider Grid-Enhancing Technologies
in the generator interconnection
process, what, if any, shortcomings exist
in that consideration? If the Commission
were to require greater consideration of
Grid-Enhancing Technologies, how
should it do so? What, if any, challenges
exist in establishing such a requirement
and how might these challenges be
addressed?
151 Commission staff led a workshop in 2019 to
explore the role, benefits, and challenges of GridEnhancing Technologies. FERC, Grid-Enhancing
Technologies, Notice of Workshop, Docket No.
AD19–19–000 (Sept. 9, 2019).
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C. Enhanced Transmission Oversight
159. The potential for a significant
investment in the transmission system
in the coming years underscores the
importance of ensuring that ratepayers
are not saddled with costs for
transmission facilities that are unneeded
or imprudent. As part of this package of
potential reforms, we are considering
whether reforms may be needed to
enhance oversight of transmission
planning and transmission providers’
spending on transmission facilities to
ensure that transmission rates remain
just and reasonable.
1. Potential Need for Reform
160. As discussed above, the
electricity sector is in the midst of a
fundamental transition as the generation
mix shifts rapidly from largely
centralized resources located close to
population centers towards renewable
resources located far from customers.
Potential reforms to regional
transmission planning and cost
allocation and generator interconnection
should help protect customers
throughout this transition by directing
planning toward the more efficient or
cost-effective transmission facilities.
Nevertheless, particularly in light of
potential costs of new transmission
infrastructure that may be needed to
meet the needs of the changing resource
mix, we seek comment on whether
additional measures may be necessary
to ensure that the planning processes for
the development of new transmission
facilities, and the costs of the facilities,
do not impose excessive costs on
consumers.
161. We seek comment on whether
the relatively large investment in
transmission facilities resulting from the
regional transmission planning and cost
allocation processes reflects the more
efficient or cost-effective solutions for
meeting transmission needs, including
those associated with a changing
resource mix. The transparency with
which transmission needs are identified
and transmission facilities approved is
an important element in ensuring that
excessive costs are not being imposed
on consumers. Although Order No. 890
requires that transmission planning
processes comply with the transmission
planning principles, including
transparency and openness,
transmission providers comply with
those requirements in various ways.
162. We seek comment on whether
the current transmission planning
processes provide sufficient
transparency for stakeholders to
understand how best to obtain
information and fully participate in the
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various processes. For example, we seek
comment whether in non-RTO/ISO
regions individual transmission owning
members’ local transmission planning
processes may not be as well publicized
or follow as well understood processes
to provide information as in RTO/ISO
regions. We seek comment on whether
this may result in material costs being
imposed on consumers with limited
visibility into the actual need for a local
transmission facility or support for a
specific local transmission solution. We
also seek comment on whether, in light
of the significant potential costs of
transmission and this potential deficit
in transparency, customers and other
stakeholders might benefit from
enhanced oversight over identification
and costs of transmission facilities.
2. Potential Reforms and Request for
Comment
a. Independent Transmission Monitor
163. We seek comment on which
potential measures the Commission
could take to ensure that there is
appropriate oversight over how new
regional transmission facilities are
identified and paid for. For example, we
seek comment on whether, to improve
oversight of transmission facility costs,
it would be appropriate for the
Commission to require that transmission
providers in each RTO/ISO, or more
broadly, in non-RTO/ISO transmission
planning regions, establish an
independent entity to monitor the
planning and cost of transmission
facilities in the region.
164. We seek comment on the
Commission’s authority to require an
independent entity to monitor
transmission spending in each
transmission planning region, as well as
the role that such monitor(s) would
play. For example, this independent
transmission monitor might potentially
review transmission planning processes,
planning criteria that lead to the
identification of particular transmission
needs and facilities, as well as the rules
and regulations governing such
processes. Additionally, the
independent transmission monitor
could review transmission provider
spending on transmission facilities and
identify instances of potentially
excessive transmission facility costs,
including through inefficiencies
between local and regional transmission
planning processes. Further, the
independent transmission monitor
could identify instances in which
transmission facilities were selected in
the regional transmission plan for cost
allocation when it may not be clear that
such projects were the more efficient or
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cost-effective transmission solutions, or
were approved for regional cost
allocation when credible less-costly
alternatives were available. If the
independent transmission monitor
identifies such examples, it could make
a referral to the Commission. The
Commission could then conduct a
review of the relevant transmission
planning processes and/or transmission
facility costs under section 206 of the
FPA. We seek comment on the proposal
outlined in this paragraph.
165. We seek comment on whether
the independent transmission monitor’s
review could potentially focus on the
transmission planning process and costs
of transmission facilities before
construction starts.152 We seek comment
on whether and how the Commission
might modify the regional transmission
planning and cost allocation processes
or rate recovery rules and procedures so
as to facilitate such up-front review.
166. We also seek comment on how
an independent transmission monitor
could approach cost oversight. One
possible method would be to scrutinize
the relevant regional transmission
plan(s) to determine whether a different
portfolio of local and regional
transmission facilities would lead to
higher net benefits. With regard to
individual transmission facilities
selected via the regional transmission
planning processes or chosen through
the local transmission planning
processes, the independent entity could
provide information to assist the
Commission in determining whether the
selection of a given transmission facility
warrants additional Commission review.
Such assistance may include the
development of independent cost
152 This is different than the safeguards provided
under the transmission formula rate protocols that
have been implemented for formula rates in
transmission providers’ OATTs. The transmission
formula rate protocols are generally designed to
provide interested parties sufficient opportunity to
obtain and review information necessary to evaluate
the implementation of the formula rate, which
allows public utilities to recover the cost for
transmission facilities that are already constructed
and placed in service, except in limited
circumstances (e.g., a transmission provider may
recover a return on costs of plant that is in the
process of construction by receiving regulatory
approval to include such costs of construction work
in progress in rate base under its formula rate). The
protocols outline the process for the annual formula
rate informational filing at the Commission,
transparency around the transmission formula rate
information exchange, the scope of participation,
and the ability of customers to challenge
transmission providers’ implementation of the
formula rate. See Midwest Indep. Transmission Sys.
Operator, Inc., 139 FERC ¶ 61,127 (2012); Midwest
Indep. Transmission Sys. Operator, Inc., 143 FERC
¶ 61,149 (2013); Midcontinent Indep. Sys. Operator,
Inc., 146 FERC ¶ 61,212 (2014); Midcontinent
Indep. Sys. Operator, Inc., 150 FERC ¶ 61,025
(2015).
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estimates for transmission facilities.
Given the challenges of reviewing all
transmission facilities, we seek
comment on whether it would be useful
for the Commission or the independent
entity to develop criteria (such as a
minimum spending threshold) to
determine which transmission facilities
should be subject to review.
167. We seek comment on tools that
could be developed to assist such a
transmission monitor or the
Commission in reviewing transmissionrelated spending. For example, such a
monitor might develop benchmark cost
estimates that would be independent of
cost estimates developed by a
transmission provider, which could
serve as a mechanism to assess
performance for each transmission
provider for the applicable transmission
facilities. The independent transmission
monitor could create separate estimates
for regional versus local transmission
facilities and classify facility costs by
criteria (such as voltage level), with
estimates based on well-established
methods using the best information
available just prior to the start of
construction to minimize the error in
cost estimation. The Commission could
then review the costs for transmission
facilities that significantly exceed the
cost estimates, either sua sponte or on
the recommendation of the independent
transmission monitor or a third party.
An independent transmission monitor
could also seek information from
transmission providers regarding the
variances between actual and estimated
costs for selected regional transmission
facilities and use this information in its
assessment of whether further
Commission review is recommended.
168. We seek comment on whether an
independent transmission monitor
should provide advice on the design
and implementation of the regional
transmission planning and cost
allocation processes in addition to
oversight of the regional transmission
planning process and the costs of the
development of individual transmission
facilities. The independent transmission
monitor could review the design of the
regional transmission planning and cost
allocation processes on an ongoing basis
and highlight areas where
improvements could be made (for
example, optimization between local
and regional transmission planning).
The independent transmission monitor
could also review mechanisms used in
transmission planning processes, such
as adjusted production cost modeling
tools, and assess the extent to which
modifications to such mechanisms
might yield more efficient transmission
spending decisions.
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169. The independent transmission
monitor could also identify and report
on situations in which non-wires
alternatives could more cost-effectively
address transmission system needs. We
seek comment on the value of such
reporting and whether such information
could improve the ability for states to
participate in the regional transmission
planning process and provide a greater
opportunity for input. Similarly, we
seek comment on whether an
independent transmission monitor or
other oversight mechanism should
evaluate and report on transmission
providers’ consideration of GridEnhancing Technologies in the
transmission planning process. If so,
how should that evaluation be
conducted and what information should
be reported?
170. Additionally, we seek comment
on whether oversight of the planning
and approval of local transmission
facilities is necessary to ensure that
transmission rates are just and
reasonable. We seek comment on
whether an independent transmission
monitor should evaluate whether the
transmission needs identified in the
local transmission planning processes
could be better considered during
regional transmission planning
processes to allow for the identification
of more efficient or cost-effective
transmission solutions. In addition, we
seek comment on whether oversight
should consider the development and
application of transmission planning
criteria. Finally, we encourage
commenters to identify any other factors
that they believe the Commission
should consider for oversight within the
local transmission planning process. At
the same time, we seek comment on
whether such a role for a federallyregulated regional transmission monitor
would improperly or inappropriately
expand the role of federal regulation
over local utility regulation and/or
potentially increase administrative and
legal costs of local transmission
planning with no commensurate
benefits for customers. More broadly,
we seek comment on whether there is a
need to delineate more clearly the
oversight roles of federal and state
regulators over local transmission
planning.
171. In addition, we seek comment on
whether there is sufficient clarity on the
roles and responsibilities between state
and federal regulators regarding the
local transmission planning criteria and
the development of local transmission
facilities (e.g., ‘‘Supplemental Projects’’
in PJM). We seek comment on whether
such transmission facilities require
additional oversight and whether
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additional coordination among state and
federal regulators would be beneficial.
Similarly, we seek comment on whether
and how greater oversight may improve
coordination between individual
transmission provider’s planning
processes and regional transmission
planning processes. Order No. 1000
requires the evaluation of ‘‘alternative
transmission solutions that might meet
the needs of the transmission planning
region more efficiently or costeffectively than solutions identified by
individual public utility transmission
providers.’’ 153 We seek comment on
whether current rules and processes are
adequately aligned with and facilitate
such consideration or evaluation, and if
not, whether there are oversight
measures or other mechanisms,
including via an independent
transmission monitor, that could better
facilitate the consideration of more
efficient or cost-effective alternatives.
For example, we seek comment on
whether individual transmission
provider practices regarding retirement
and replacement of transmission
facilities sufficiently align with the
directive to ensure evaluation of
alternative transmission solutions and
whether these practices sufficiently
consider the more efficient or costeffective ways to serve future needs. We
also seek comment on whether
sufficient transparency exists in
retirement decisions to allow for such
regional assessment. We seek comment
on what role can or should an
independent transmission monitor play
in facilitating enhanced coordination.
172. Furthermore, we seek comment
on whether additional transparency
measures are appropriate or should be
in place for transmission providers,
including those outside of RTO/ISO
regions. If so, we seek comment on
whether the Commission should apply
transparency measures, some of which
are currently utilized within RTO/ISO
regions (e.g., dedicated transmission
planning web pages, requirements to
publish and detail full transmission
plan at end of each transmission
planning cycle, scorecards), or consider
different or new transparency measures
for transmission providers outside of
RTO/ISO regions. We seek comment on
whether new or different transparency
measures are needed within the RTO/
ISO regions.
173. An independent transmission
monitor would not replace the
Commission’s rate jurisdiction but
instead could provide the Commission
with an additional means of ensuring
that rates are just and reasonable. With
153 Order
No. 1000, 136 FERC ¶ 61,050 at P 148.
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respect to other aspects of prudence, or
transmission facility selection against
alternatives, the independent
transmission monitor would not
supplant the Commission’s authority
with respect to prudence, but could
inform the Commission as to whether a
further review is warranted; the final
determination on whether costs are
prudently incurred remains with the
Commission. Similarly, the record
created by the independent
transmission monitor could help the
Commission in ensuring that the design
of the regional transmission planning
and cost allocation processes remain
just and reasonable and not unduly
discriminatory or preferential.
174. We seek comment on (1) the
independent transmission monitor
proposal, and (2) any alternative options
for improving oversight of transmission
costs or the effectiveness of
transmission planning processes.
Additionally, we seek comment on
whether the concerns regarding
transmission oversight are best
addressed by an independent entity
similar to the role of an independent
market monitor, or whether the
concerns can be adequately addressed
by the RTO/ISO or transmission
providers in non-RTO/ISO regions, or
through another approach.
175. We also seek comment on (1)
how an independent transmission
monitor (or set of regional monitors)
would be created or authorized; (2)
whether a single monitor should be
appointed for each transmission region,
or instead a given monitor might review
transmission across several regions; (3)
the Commission’s authority to require
an independent transmission monitor in
all transmission planning regions; (4)
how this entity would work in practice,
in both the RTO/ISO and non-RTO/ISO
regions; and (5) the scope of review
such monitor(s) should be charged with
carrying out, including whether such
monitoring should extend to oversight
of the generator interconnection
process.
b. State Oversight
176. Another way to add oversight to
the transmission planning and cost
allocation processes could be to involve
state commissions in those processes.
By way of example, SPP has a Regional
State Committee (RSC), which provides
collective state regulatory agency input
in areas under the RSC’s primary
responsibilities and on matters of
regional importance related to the
development and operation of the bulk
electric transmission system. Pursuant
to the SPP Bylaws, ‘‘with respect to
transmission planning, the RSC will
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determine whether transmission
upgrades for remote resources will be
included in the regional transmission
planning process and the role of
transmission owners in proposing
transmission upgrades in the regional
planning process.’’ 154
177. We seek comment on whether
this type of model, or other models that
may be proposed, could be expanded to
other regions and other topics; for
example, whether a state-led committee
could: Provide insight into regional
transmission facility costs and cost
allocation methods; evaluate whether
the transmission needs identified in the
local transmission planning processes
could be better considered during
regional transmission planning
processes; inform the Commission as to
whether a further review is warranted of
whether incurred costs are prudent; or
provide the Commission with an
additional means of ensuring that rates
are just and reasonable. We also seek
comment on how such a model may be
combined with other oversight tools or
mechanisms explored herein. For
example, given state regulatory
authority over the approval of non-wires
solutions, can or should a regional state
committee play a role in identifying
circumstances under which a non-wires
solution would be the more efficient or
cost-effective solution to solving an
identified regional transmission need,
and facilitating a process by which the
relevant state regulator could be given
an opportunity to approve such a
solution?
c. Limitation on Recovery of Costs for
Abandoned Projects
178. There is always a risk that once
approved, a regional project may be
abandoned before going into service for
a variety of reasons including a failure
to obtain all necessary state and federal
approvals, including, for example, state
certificates of public convenience and
necessity. The Commission’s general
policy for recovery of the costs of
abandoned plant under section 205 of
the FPA allows recovery of and return
on 50% of the prudently incurred
investment costs incurred in connection
with the abandoned plant.155 In
154 SPP, Governing Documents Tariff, Bylaws,
Section 7.2 (Regional State Committee) (1.0.0).
155 New Eng. Power Co., Opinion No. 295, 42
FERC ¶ 61,016, at 61,081–82, order on reh’g,
Opinion No. 295–A, 43 FERC ¶ 61,285 (1988). The
Commission also allows recovery under section 205
of return on 50% of investment costs incurred to
construct transmission facilities (and other nonpollution control plant) through the inclusion of
Construction Work in Progress (CWIP) in rate base
during the construction period, provided certain
conditions are met. Construction Work In Progress
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addition, the Commission may grant as
an incentive under section 219 of the
FPA for transmission facilities meeting
the qualifications for the incentive,
recovery of 100% of prudently-incurred
costs related to such facilities if they are
abandoned for reasons beyond the
control of the transmission owner.156 In
light of potential costs of new regional
transmission infrastructure and the
corresponding risk that some of those
projects may be abandoned, we seek
comment on whether the Commission
should revisit its policies regarding
abandoned plant to better protect
consumers from increased costs due to
never-built transmission facilities.
179. For example, one proposal to
protect consumers would be to limit the
recovery of costs through abandonment
by allowing only the recovery of some
portion of actual development or precommercial costs, and/or no recovery of
a return on equity on such costs prior
to the project receiving all necessary
regulatory approvals. We therefore seek
comment on this or other proposals to
limit the amount that can be recovered
for regional transmission facilities that
are abandoned prior to going into
service. Commenters are, of course,
welcome to address all issues and
concerns pertinent to such proposals.
d. Additional Oversight Approaches
180. Finally, we seek comment on
additional oversight approaches the
Commission might take to ensure that
wholesale transmission spending is cost
effective. For example, performancebased regulation. We ask how
performance-based regulation may be
designed to ensure that rates are just
and reasonable, ensure reliability of the
transmission system, promote regional
expansion of transmission facilities for
a sufficiently wide range of future
scenarios, including anticipated future
generation, and encourage transmission
provider participation.
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D. Transition
181. To implement any of the
proposals outlined above, transmission
providers must transition to new
interconnection pricing paradigms and
new regional transmission planning and
cost allocation processes. Therefore, we
seek comment on appropriate transition
for Public Utilities; Inclusion of Costs in Rate Base,
Order No. 298, 48 FR 24,323 (June 1, 1983), FERC
Stats. & Regs. ¶ 30,455, order on reh’g, Order No.
298–A, 48 FR 46,012 (Oct. 11, 1983), FERC Stats.
& Regs., ¶ 30,500 (1983), order on reh’g, Order No.
298–B, 48 FR 55,281 (Dec. 12, 1983), FERC Stats.
& Regs. ¶ 30,524 (1983) (Order No. 298).
156 Promoting Transmission Investment through
Pricing Reform, Order No. 679, 116 FERC ¶ 61,057,
order on reh’g, Order No. 679–A, 117 FERC ¶ 61,345
(2006), order on reh’g, 119 FERC ¶ 61,062 (2007).
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plans, including treatment of
interconnection customers in the
various stages of the generator
interconnection process and those that
have already interconnected as well as
when the more holistic regional
transmission planning and cost
allocation processes would begin
(including when the broader category of
regional transmission facilities would be
established).
182. The Commission also seeks input
as to the length of time that might be
necessary to implement any reforms that
result from this process. Specifically,
the Commission requests input as to
how much time transmission providers
might need to develop compliance
filings related to all of the proposals in
this ANOPR.
V. Comment Procedures
183. The Commission invites
interested persons to submit comments
on these matters and any related matters
or alternative proposals that
commenters may wish to discuss.
Comments are October 12, 2021 and
Reply Comments are due November 9,
2021. Comments must refer to Docket
No. RM21–17–000 and must include the
commenter’s name, the organization
they represent, if applicable, and their
address in their comments. All
comments will be placed in the
Commission’s public files and may be
viewed, printed, or downloaded
remotely as described in the Document
Availability section below. Commenters
on this proposal are not required to
serve copies of their comments on other
commenters
184. The Commission encourages
comments to be filed electronically via
the eFiling link on the Commission’s
website at https://www.ferc.gov. The
Commission accepts most standard
word processing formats. Documents
created electronically using word
processing software must be filed in
native applications or print-to-PDF
format and not in a scanned format.
Commenters filing electronically do not
need to make a paper filing.
185. Commenters that are not able to
file comments electronically may file an
original of their comment by USPS mail
or by courier-or other delivery services.
For submission sent via USPS only,
filings should be mailed to: Federal
Energy Regulatory Commission, Office
of the Secretary, 888 First Street NE,
Washington, DC 20426. Submission of
filings other than by USPS should be
delivered to: Federal Energy Regulatory
Commission, 12225 Wilkins Avenue,
Rockville, MD 20852.
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VI. Document Availability
186. 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). At this time, the
Commission has suspended access to
the Commission’s Public Reference
Room due to the President’s March 13,
2020 proclamation declaring a National
Emergency concerning the Novel
Coronavirus Disease (COVID–19).
187. From the Commission’s Home
Page on the internet, this information is
available in its eLibrary. The full text of
this document is available in the
eLibrary in PDF and Microsoft Word
format for viewing, printing, and/or
downloading. To access this document
in eLibrary, type the docket number of
this document excluding the last three
digits in the docket number field.
188. User assistance is available for
eLibrary and the Commission’s website
during normal business hours from the
Commission’s Online Support at 202–
502–6652 (toll free at 1–866–208–3676)
or email at ferconlinesupport@ferc.gov,
or the Public Reference Room at (202)
502–8371, TTY (202) 502–8659. Email
the Public Reference Room at
public.referenceroom@ferc.gov.
By direction of the Commission.
Chairman Glick and Commissioner
Clements are concurring with a joint
separate statement attached.
Commissioner Chatterjee is not
participating. Commissioner Danly is
concurring with a separate statement.
Commissioner Christie is concurring
with a separate statement.
Issued: July 15, 2021.
Debbie-Anne A. Reese,
Deputy Secretary.
Department of Energy
Federal Energy Regulatory Commission
Building for the Future Through Electric
Regional Transmission Planning and
Cost Allocation and Generator
Interconnection
Docket No. RM21–17–000
GLICK, Chairman, CLEMENTS,
Commissioner, concurring:
1. The generation resource mix is
changing rapidly. Due to a myriad of
factors—including improving
economics, customer and corporate
demand for clean energy, public utility
commitments and integrated resource
plans, as well as federal, state, and local
public policies—renewable resources in
particular are coming online at an
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unprecedented rate.1 As a result, the
transmission needs of the electricity
grid of the future are going to look very
different than those of the electricity
grid of the past.
2. We are concerned that the current
approach to transmission planning and
cost allocation cannot meet those future
transmission needs in a manner that is
just and reasonable and not unduly
discriminatory or preferential. In
particular, we believe that the status
quo approach to planning and allocating
the costs of transmission facilities may
lead to an inefficient, piecemeal
expansion of the transmission grid that
would ultimately be far more expensive
for customers than a more forwardlooking, holistic approach that
proactively plans for the transmission
needs of the changing resource mix. A
myopic transmission development
process that leaves customers paying
more than necessary to meet their
transmission needs is not just and
reasonable.
3. In that regard, we are pleased to see
the Commission taking a consensus first
step toward updating its rules and
regulations to ensure that we are
meeting the nation’s evolving
transmission needs in a cost-effective
and efficient fashion. Today’s action
complements our recently established
joint federal-state task force with the
National Association of Regulatory
Utility Commissioners,2 which we
expect to produce a robust dialogue on
many of the issues addressed herein. In
our view, this advance notice of
proposed rulemaking (ANOPR) is just
the first step. Ensuring that transmission
rates remain just and reasonable will
require further action, including reforms
to interregional transmission planning
and cost allocation, as well as other
reforms to our regional transmission
planning and cost allocation and
generator interconnection processes
beyond those contemplated herein.
Nevertheless, we believe that today’s
unanimous Commission action
represents a solid foundation for an
expeditious inquiry into how we can
regulate to achieve the transmission
needs of our changing electricity system
in a manner consistent with our
1 See, e.g., Joseph Rand et al., Queued Up:
Characteristics of Power Plants Seeking
Transmission Interconnection as of the End of 2020,
Lawrence Berkeley National Laboratory, May 2021,
https://eta-publications.lbl.gov/sites/default/files/
queued_up_may_2021.pdf; Electric Power Monthly,
Table 6.1 Electric Generating Summer Capacity
Changes (MW), U.S. Energy Information
Administration, (Mar. 2021 to Apr. 2021), https://
www.eia.gov/electricity/monthly/epm_table_
grapher.php?t=table_6_01.
2 Joint Federal-State Task Force on Electric
Transmission, 175 FERC ¶ 61,224 (2021).
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statutory obligations under the Federal
Power Act.
*
*
*
*
*
4. The generation mix is shifting
rapidly from large resources located
close to population centers toward
renewable resources, often combined
with onsite storage, that tend to be
located where their fuel source is best—
i.e., where the wind blows hardest or
the sun shines brightest. According to
the National Renewable Energy
Laboratory (NREL), total renewable
generation capacity nearly doubled from
2009 to 2018, increasing from 11.7% of
total generation capacity to 20.5%.3 And
that is just the beginning: Of the roughly
750 GW of generation in
interconnection queues around the
country, nearly 700 GW are renewable
resources,4 providing every reason to
believe that the dramatic shift toward
renewable generation will only
accelerate in the years ahead.
5. That shift is the result of many
factors. First and foremost, the cost of
renewable resources is plummeting. For
example, in its annual report on the
levelized cost of energy, Lazard found
that between 2009 to 2020, the levelized
cost of energy from unsubsidized wind
generation and unsubsidized utilityscale solar generation decreased by 71%
and 90%, respectively 5—enough to
3 2018 Renewable Energy Data Book at 26, NREL,
https://www.nrel.gov/docs/fy20osti/75284.pdf.
Wind and solar resources, in particular, have grown
at a disproportionate rate, with solar generation
capacity increasing roughly 5,000% from 1,054 MW
to 51,899 MW nationwide, and wind generation
capacity more than tripling from 31,155 MW to
96,442 MW.
4 See Joseph Rand, Queued Up: Characteristics of
Power Plants Seeking Transmission Interconnection
as of the End of 2020, Lawrence Berkeley National
Laboratory, May 2021, https://etapublications.lbl.gov/sites/default/files/queued_up_
may_2021.pdf. Equally important, this shift is
taking place across the country, not just in a few
areas. For example, as of the issuance of this
ANOPR, in Midcontinent Independent System
Operator, Inc. (MISO), solar and wind projects
comprise 80% of all active projects in the current
interconnection queue, or about 73 GW of total
capacity. MISO, Generator Interconnection Queue—
Active Projects Map, https://
giqueue.misoenergy.org/PublicGiQueueMap/
index.html. Similarly, in PJM Interconnection,
L.L.C. (PJM), solar and wind projects with a total
capacity of 62 GW comprise 79% of all active
projects in the current interconnection queue as of
the issuance of this ANOPR. PJM, New Services
Queue, https://www.pjm.com/planning/servicesrequests/interconnection-queues.aspx. In California
Independent System Operator Corporation (CAISO),
renewable and storage capacity of 23 GW comprise
78% of all active projects in the current
interconnection queue as of the issuance of this
ANOPR. CAISO, Generator Interconnection Queue,
https://www.caiso.com/Documents/
ISOGeneratorInterconnectionQueueExcel.xls.
5 See, e.g., Lazard’s Levelized Cost of Energy
Analysis—Version 14.0, at 9 (Oct. 19, 2020), https://
www.lazard.com/perspective/levelized-cost-ofenergy-and-levelized-cost-of-storage-2020/#:∼:text=
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40295
make utility-scale solar and wind
generation cost-competitive with central
station fossil generation sources in
many parts of the country.6 Moreover,
customers—both residential and
commercial—are increasingly
demanding clean energy, particularly
energy from renewable resources—
which is itself causing utilities and
independent power producers to
attempt to send large quantities of
renewable energy onto the grid.7 In
addition, dozens of the biggest utilities
in the country have established their
own decarbonization goals, the
achievement of which will require their
Lazard’s%20latest%20annual%20Levelized% 20
Cost,build%20basis%2C%20continue%20to
%20maintain; Ryan Wiser et al., Expert elicitation
survey predicts 37% to 49% declines in wind
energy costs by 2050, Lawrence Berkeley National
Laboratory (Apr. 2021), https://etapublications.lbl.gov/sites/default/files/wind_lcoe_
elicitation_ne_pre-print_april2021.pdf (finding that
the decrease in levelized cost of energy for wind
power from 2015–2020 outpaced the decrease
predicted by experts, and that experts continue to
predict significant declines in levelized cost of
energy).
6 See Lazard’s Levelized Cost of Energy
Analysis—Version 14.0, at 3, 7 (Oct. 19, 2020),
https://www.lazard.com/perspective/levelized-costof-energy-and-levelized-cost-of-storage-2020/#:∼:
text=Lazard’s%20latest%20annual%20Levelized%
20Cost,build%20basis%2C%20continue%20to
%20maintain.
7 See, e.g., Deloitte Resources 2020 Study at 22,
https://www2.deloitte.com/content/dam/insights/
us/articles/6655_Resources-study-2020/DI_
Resources-study-2020.pdf (showing that U.S.
corporate renewable generation purchase power
agreements increased from 0.3 GW in 2009 to 13.6
GW in 2019); Kevin O’Rourke & Charles Harper,
Corporate Renewable Procurement and
Transmission Planning: Communicating Demand to
RTOs Necessary to Secure Future Procurement
Options, A Renewable America (October 2018),
https://acore.org/wp-content/uploads/2020/04/
Corporates-Renewable-Procurement-andTransmission-Report.pdf (indicating that a group of
corporations, forming the Renewable Energy Buyers
Alliance, has set a goal to purchase 60 GW of new
renewable energy capacity in the U.S. by 2025);
Stanley Porter et al., Utility Decarbonization
Strategies, Renew, Reshape, and Refuel to Zero,
Deloitte Insights (Sept. 2021), https://
www2.deloitte.com/us/en/insights/industry/powerand-utilities/utility-decarbonization-strategies.html
(indicating that 43 of 55 utilities surveyed have
emissions reductions targets and 22 have net-zero
or carbon-free electricity goals); Esther Whieldon,
Path to net zero: 70% of biggest US utilities have
deep decarbonization targets, S&P Global Market
Intelligence (Dec. 9, 2020) at 3–6, https://
www.spglobal.com/marketintelligence/en/newsinsights/latest-news-headlines/path-to-net-zero-70of-biggest-us-utilities-have-deep-decarbonizationtargets-61622651 (indicating that review of utilities’
climate goals decarbonization plans, as of December
2020, shows that 70% of the 30 largest utilities have
net-zero carbon targets or are moving to comply
with similarly aggressive state mandates); see also
Rich Glick and Matthew Christiansen, FERC and
Climate Change, 40 Energy L.J. 1, 7–12 (2019) (‘‘The
growth of renewable resources is also a function of
consumers’ desire for clean energy. Customers—
including residential, commercial, and even
industrial consumers—are increasingly demanding
that their energy come from renewable or zeroemissions sources’’).
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own significant investment in
renewable generation.8
6. Finally, federal, state, and local
policymakers have adopted a range of
public policies that are driving the
changing resource mix. For example, 30
states and the District of Columbia have
adopted renewable portfolio standards,9
with those standards contributing to
roughly 50% of the total growth in
renewable generation over the last two
decades.10 In addition, several states
have doubled down on the clean energy
transition by enacting measures that
require that most or all of their
electricity come from zero emissions
resources.11 All told, ‘‘states and
utilities that have committed to
transitioning to 100 percent clean power
serve nearly 83 million households and
businesses, representing around 50
percent of all U.S. electricity demand in
2019.’’ 12
8 See, e.g., Corporate Renewable Procurement and
Transmission Planning: Communicating Demand to
RTOs Necessary to Secure Future Procurement
Options, A Renewable America, October 2018,
https://acore.org/wp-content/uploads/2020/04/
Corporates-Renewable-Procurement-andTransmission-Report.pdf; Esther Whieldon, Path to
net zero: 70% of biggest US utilities have deep
decarbonization targets, S&P Global Market
Intelligence, Dec. 9, 2020, at 3–6, https://
www.spglobal.com/marketintelligence/en/newsinsights/latest-news-headlines/path-to-net-zero-70of-biggest-us-utilities-have-deep-decarbonizationtargets-61622651.
9 Nat’l Conference of State Legislatures, State
Renewable Portfolio Standards and Goals (Nov. 7,
2021), https://www.ncsl.org/research/energy/
renewable-portfolio-standards.aspx#:∼:text=Thirty
%20states%2C%20Washington%2C%20DC
%2C,have%20set%20renewable%20energy
%20goals. Renewable portfolio standards are
policies that are designed to increase the amount of
renewable energy sources used for electricity
generation.
10 See, e.g., Berkeley Lab, U.S. Renewables
Portfolio Standards: 2019 Annual Status Update
(Aug. 2019), https://emp.lbl.gov/publications/usrenewables-portfolio-standards-2.
11 Carbon Pricing in Organized Wholesale Elec.
Markets, 175 FERC ¶ 61,036, at P 2 (2021)
(‘‘Thirteen states—California, Hawaii, Maine,
Maryland, Massachusetts, Nevada, New Jersey, New
Mexico, New York, Oregon, Vermont, Virginia, and
Washington—and the District of Columbia have
adopted clean energy or renewable portfolio
standards of 50% or greater.’’). In addition, ‘‘a
number of states—including Colorado, Connecticut,
Nevada, Rhode Island, and Wisconsin—have
established 100% clean electricity goals or targets
by executive order or other non-binding
commitment.’’ See id. At the local level, cities and
counties are also accelerating clean energy
commitments. Kelly Trumbull et al., Progress
Toward 100% Clean Energy in Cities and States
Across the U.S., University of California—Los
Angeles Luskin Center for Innovation (November
2019) at 10, https://innovation.luskin.ucla.edu/wpcontent/uploads/2019/11/100-Clean-EnergyProgress-Report-UCLA-2.pdf (finding over 200 cities
and counties across 37 U.S. states have 100 percent
clean energy commitments).
12 National Resources Defense Council (NRDC),
NRDC’s 8th Annual Energy Report: Slow and
Steady Will Not Win the Climate Race (Dec. 2,
2020), https://www.nrdc.org/resources/nrdcs-8th-
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7. Dramatic changes in the resource
mix inevitably come with similarly
dramatic changes in transmission needs.
As noted, the increasingly costcompetitive renewable resources that
customers and public policies demand
tend to be developed farther away from
customers where their fuel sources are
strong and development costs are low
rather than in close proximity to their
ultimate customers. As a result, the
future resource mix will likely present
new transmission needs, different from
those of the large resources located close
to population centers that have
dominated electricity generation in the
past. Meeting those transmission needs
will likely require both the
infrastructure necessary to interconnect
new resources to the transmission
system efficiently and the infrastructure
necessary to reliably move the
electricity produced by those resources
to where it is needed. This could make
it considerably more expensive than
necessary to bring in the low-cost
generation demanded by customers and
meet federal, state, and local public
policies.
8. This Commission cannot sit idly
by. Our role is to ensure just and
reasonable rates and support reliability
in light of changes in the market, not to
pretend those changes are not
happening. We are concerned that, in
light of evolving transmission needs, the
current regional transmission planning
and cost allocation and generator
interconnection processes may no
longer ensure just and reasonable rates
for transmission service.13 In particular,
we are concerned that existing regional
transmission planning processes may be
siloed, fragmented, and not sufficiently
forward-looking, such that transmission
facilities are being developed through a
piecemeal approach that is unlikely to
produce the type of transmission
solutions that could more efficiently
and cost-effectively meet the needs of
the changing resource mix. Regional
transmission planning processes
generally do little to proactively plan for
the resource mix of the future, including
both commercially established
resources, such as onshore wind and
solar, as well as emerging ones, such as
offshore wind. We are also concerned
that current regional transmission
planning processes are not sufficiently
integrated with the generator
interconnection processes, and are
overwhelmingly focused on relatively
near-term transmission needs, and that
annual-energy-report-slow-and-steady-will-not-winrace?nrdcpreviewlink=rmmB6NM6zpiOTruhuObZ
JdH92bCOvmZTY1hx72xCSzQ#renewables.
13 16 U.S.C. 824e.
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attempting to meet the needs of the
changing resource mix through such a
short-term lens will lead to inefficient
transmission investments. As a result,
under the status quo, customers could
end up paying far more to meet their
transmission needs than they would
under a more forward-looking approach
that identifies the more efficient or costeffective investments in light of the
changing resource mix.14
9. Relatedly, we are also concerned
that the current approach to
transmission planning and cost
allocation is failing to adequately
identify the benefits and allocate the
costs of new transmission infrastructure.
Although the regional transmission
planning process considers transmission
needs driven by reliability, economics,
and Public Policy Requirements,15 those
transmission needs are often viewed in
isolation from one another and the cost
allocation methods for projects selected
to meet those needs are similarly siloed.
As a result, the status quo may be
disproportionately producing
transmission facilities that address a
narrow set of needs, providing
comparatively modest benefits, but at a
still-substantial total cost instead of
developing the type of transmission
infrastructure that could provide the
most significant benefits for customers.
In the same vein, we are also concerned
that many customers who share in the
diverse array of benefits that
transmission infrastructure can offer
may not be paying their fair share, as
required by the cost causation
principle.16
10. In addition, we are concerned
that, largely due to the potential
shortcomings with the current regional
transmission planning and cost
allocation processes, transmission
infrastructure is increasingly being
14 See generally Eric Larson et al., Net-Zero
America: Potential Pathways, Infrastructure, and
Impact (2020), Princeton_NZA_Interim_Report_15_
Dec_2020_FINAL.pdf (discussing different
pathways for meeting decarbonization goals,
including differing approaches to transmission
investment).
15 See Transmission Planning and Cost Allocation
by Transmission Owning and Operating Public
Utilities, Order No. 1000, 136 FERC ¶ 61,051, at P
11 (2011), order on reh’g, Order No. 1000–A, 139
FERC ¶ 61,132, order on reh’g and 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).
16 Cf. BNP Paribas Energy Trading GP v. FERC,
743 F.3d 264, 268–269 (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.’’ (citing Midwest ISO Transmission Owners
v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004) and
Se. Michigan Gas Co. v. FERC, 133 F.3d 34, 41 (D.C.
Cir. 1998))).
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developed through the generator
interconnection process. That means
that infrastructure with potentially
significant benefits for a broad range of
entities may be developed through a
process that focuses exclusively on the
needs of a comparatively small number
of interconnection customers—a
dynamic that is almost sure to result in
comparatively inefficient investment
decisions. The participant funding
approach to financing interconnectionrelated network upgrades will often
mean that the interconnection
customer(s) alone must pay for all—or
the vast majority—of the costs of that
transmission infrastructure, even where
it provides significant benefits to other
entities. That, in turn, may cause those
interconnection customers to withdraw
projects from the queue, causing
considerable uncertainty and delay, and
may mean that net beneficial
transmission infrastructure is never
developed due to a misalignment in
how that infrastructure would be paid
for.
11. Finally, we are also concerned
that the Commission’s current approach
to overseeing transmission investment
may not adequately protect consumers.
While transmission infrastructure can
provide a broad spectrum of benefits, it
is itself a significant investment that
represents a major component of
customers’ electric bills. The
Commission must vigorously oversee
the rules governing how transmission
projects are planned and paid for if we
are to satisfy our responsibility to
protect customers from excessive rates
and charges.17 The potential bases for
invigorating our oversight of
transmission spending contemplated in
today’s order have the potential to go a
long way toward ensuring that we fulfill
that function.
12. Today’s action plants the seeds for
addressing the concerns outlined above.
A forward-looking, holistic approach to
transmission planning has the potential
to identify the more efficient or costeffective solutions for meeting the
transmission needs of the changing
resource mix, including those resources
that are not yet under development.
Such an approach would allow
transmission planners to proactively
identify the areas of the transmission
grid that will have significant
17 Cf., e.g., California ex rel. Lockyer v. FERC, 383
F.3d 1006, 1017 (9th Cir. 2004) (rejecting ‘‘an
interpretation [that] comports neither with the
statutory text nor with the Act’s ‘primary purpose’
of protecting consumers’’); City of Chicago v. FPC,
458 F.2d 731, 751 (D.C. Cir. 1971) (‘‘[T]he primary
purpose of the Natural Gas Act is to protect
consumers.’’ (citing, inter alia, City of Detroit v.
FPC, 230 F.2d 810, 815 (D.C. Cir. 1955)).
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transmission needs and select the more
efficient or cost-effective solution to
meet those needs, including needs
driven by resources that are not yet in
operation or even under development.
Doing so has the potential to address the
transmission needs of the future
generation mix while costing customers
considerably less than they would pay
to meet those same needs under the
status quo. That, in our view, is what is
necessary to ensure that the rates for
transmission service remain just and
reasonable as the resource mix changes.
13. We anticipate that this effort will
be the Commission’s principal focus in
the months to come. In addition to
reviewing the record assembled in
response to today’s order, we intend to
explore technical conferences and other
avenues for augmenting that record—
including through the joint federal-state
task force 18—before proceeding to
reform our rules and regulations. We
recognize that the issues addressed
herein are highly technical, complex
problems that do not lend themselves to
easy solutions. That being said, we also
recognize the urgent need to address the
transmission needs of the changing
resource mix and appreciate that we do
not have the luxury of sitting back and
debating these issues ad nauseum.
*
*
*
*
*
14. The electricity sector is at a
pivotal moment. With the clean energy
transition gaining steam, we can either
continue with the status quo, trying to
meet the transmission needs of the
future by building out the grid in a
myopic, piecemeal fashion, or we can
start holistically and proactively
planning for those future transmission
needs. We believe that today’s advance
notice of proposed rulemaking
represents an important and essential
first step in the right direction and
toward the type of transmission
planning and cost allocation paradigm
that is necessary to protect customers,
support reliability, and ensure just and
reasonable rates.
For these reasons, we respectfully
concur.
40297
Department of Energy
Federal Energy Regulatory Commission
Building for the Future Through Electric
Regional Transmission Planning and
Cost Allocation and Generator
Interconnection
Docket No. RM21–17–000
(Issued July 15, 2021)
DANLY, Commissioner, concurring:
1. I concur with the issuance of this
Advance Notice of Proposed
Rulemaking (ANOPR) because the
Commission is always entitled to solicit
comments on possible changes to
existing rules and a number of the
questions raised here are worthy of
consideration.
2. I write separately to highlight one
overarching concern. The ANOPR poses
several questions where the answer is
‘‘no.’’ Many of the contemplated
proposals would exceed or cede our
jurisdictional authority, violate cost
causation principles, create stifling
layers of oversight and ‘‘coordination,’’
trample transmission owners’ rights,
force neighboring states’ ratepayers to
shoulder the costs of other states’ public
policy choices, treat renewables as a
new favored class of generation with
line-jumping privileges, and perhaps
inadvertently lead to much less
transmission being built and at much
greater all-in cost to ratepayers.
3. There are obviously problems with
the existing transmission regime. I, for
example, have long been troubled by
interconnection logjams and have
wondered whether we are needlessly
propping up fantasy projects while
viable projects get lost in the crowd.1
This is but one example; there are any
number of other critical transmission
planning reforms that bear investigation.
4. My hope therefore is that
commenters will supply us with a full
record on each issue raised in the
ANOPR: Whether and why the existing
rule works or not, and whether and why
the possible reform may work or not.
With every proposed change, I
specifically solicit comments on two
subjects. First: Is the contemplated
reform a proper exercise of the
Commission’s authority, i.e., is it within
our jurisdiction? That is always the
lllllllllllllllllllll threshold question before we turn to
Richard Glick,
policy. Second: what will be the
ultimate effect on ratepayers? I fear that
Chairman.
lllllllllllllllllllll in the enthusiasm to build transmission,
many may tout the benefits of new
Allison Clements,
transmission while overlooking the
Commissioner.
costs that will eventually be borne by
ratepayers. No proposed policy,
PO 00000
18 See
1 See, e.g., PacifiCorp, 171 FERC ¶ 61,112 (2020)
(Danly, Comm’r, concurring).
supra n.2.
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Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 / Proposed Rules
challenge of maintaining reliability
through the changing generation mix
and efforts to reduce carbon emissions.
2. The broad goal of the Commission’s
regulation of our nation’s power grid
under the Federal Power Act (FPA) is to
ensure a reliable power supply to
consumers, which includes residential
customers as well as the businesses
providing jobs for tens of millions of
Americans, at just and reasonable rates.
Transmission is one of the three
essential elements of a reliable power
system, along with generation and
lllllllllllllllllllll distribution, so continually working to
James P. Danly,
make America’s transmission system
more reliable, more efficient, and more
Commissioner.
cost-effective is our job at FERC.
Department of Energy
3. As with Order No. 1000, the
Federal Energy Regulatory Commission statutory framework governing our
potential actions in this proceeding
Building for the Future Through Electric
remains section 206 of the FPA, which
Regional Transmission Planning and
requires us to ensure that all
Cost Allocation and Generator
transmission planning processes and
Interconnection
cost allocation mechanisms subject to
Docket No. RM21–17–000
our jurisdiction result in jurisdictional
services being provided at rates, terms
(Issued July 15, 2021)
and conditions that are just, reasonable,
CHRISTIE, Commissioner, concurring:
and not unduly discriminatory or
1. I concur with today’s ANOPR
preferential. Any proposals ultimately
because approximately ten years after
adopted by this Commission for reforms
the Commission issued Order No. 1000, or revisions to existing regulations must
it is appropriate to review the
be consistent with this authority.
implementation of that order, assess the
4. As Paragraph 4 of the ANOPR
successes and problems that have
makes clear,1 we have not
become evident over the past decade,
1 ANOPR at P 4 (‘‘We note that the Commission
and consider reforms and revisions to
has not predetermined that any specific proposal
existing regulations governing regional
discussed herein shall or should be made or in what
transmission planning and cost
final form; rather, we seek comment from the public
allocation. This consideration of
on those proposals and welcome commenters to
potential reforms is especially timely as offer additional or alternative proposals for
consideration.’’).
the transmission system faces the
lotter on DSK11XQN23PROD with PROPOSALS2
however worthy, can evade our
statutory duty to ensure that rates are
just and reasonable.
5. I encourage everyone with an
interest to file. I look forward to learning
from the parties that submit comments
and to engaging with my colleagues to
consider whether there are legally
durable, economically sound reforms
that we might consider to improve the
reliability of the transmission system at
just and reasonable rates.
For these reasons, I respectfully
concur.
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predetermined that any specific
proposal in this ANOPR has already
been or will ultimately be approved.
Rather, we seek comment from all
interested persons and organizations on
the wide range of proposals contained
herein, as well as the submission of
alternative proposals. Today is the
beginning of a long process and I look
forward to hearing from all concerned.
5. Similarly, my concurrence to issue
today’s ANOPR does not represent an
endorsement at this point in the process
of any one or more of the proposals
included in the order. This ANOPR
contains a number of good proposals,
some potentially good proposals
(depending on how they are fleshed
out), and frankly, some proposals that
are not—and may never be—ready for
prime time, or could potentially cause
massive increases in consumers’ bills
for little to no commensurate benefit or
inappropriately expand the role of
federal regulation over local utility
regulation. Given the early stage of this
process, however, I agree it is
worthwhile to submit a broad range of
proposals to the public for comment in
the hope that the final result will be a
more reliable, more efficient, and more
cost-effective transmission system.
For these reasons, I respectfully
concur.
lllllllllllllllllllll
Mark C. Christie,
Commissioner.
[FR Doc. 2021–15512 Filed 7–26–21; 8:45 am]
BILLING CODE 6717–01–P
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]]>Agencies
[Federal Register Volume 86, Number 141 (Tuesday, July 27, 2021)]
[Proposed Rules]
[Pages 40266-40298]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2021-15512]
[[Page 40265]]
Vol. 86
Tuesday,
No. 141
July 27, 2021
Part III
Department of Energy
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Federal Energy Regulatory Commission
18 CFR Part 35
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Building for the Future Through Electric Regional Transmission Planning
and Cost Allocation and Generator Interconnection; Proposed Rule
Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 /
Proposed Rules
[[Page 40266]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM21-17-000]
Building for the Future Through Electric Regional Transmission
Planning and Cost Allocation and Generator Interconnection
AGENCY: Federal Energy Regulatory Commission.
ACTION: Advance notice of proposed rulemaking.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
issuing an Advance Notice of Proposed Rulemaking (ANOPR) presenting
potential reforms to improve the electric regional transmission
planning and cost allocation and generator interconnection processes.
The Commission invites all interested persons to submit comments on the
potential reforms and in response to specific questions.
DATES: Comments are due October 12, 2021 and Reply Comments are due
November 9, 2021.
ADDRESSES: Comments, identified by docket number, may be filed in the
following ways. Electronic filing through https://www.ferc.gov, is
preferred.
Electronic Filing: Documents must be filed in acceptable
native applications and print-to-PDF, but not in scanned or picture
format.
For those unable to file electronically, comments may be
filed by U.S. Postal Service mail or by hand (including courier)
delivery.
[cir] Mail via U.S. Postal Service only: Addressed to: Federal
Energy Regulatory Commission, Office of the Secretary, 888 First Street
NE, Washington, DC 20426.
[cir] For delivery via any other carrier (including courier):
Deliver to: Federal Energy Regulatory Commission, Office of the
Secretary, 12225 Wilkins Avenue, Rockville, MD 20852.
The Comment Procedures Section of this document contains more
detailed filing procedures.
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]
Christopher Gore (Technical Information), Office of Energy Market
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8507,
[email protected].
Lina Naik (Legal Information), Office of the General Counsel, 888 First
Street NE, Washington, DC 20426, (202) 502-8882, [email protected]
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph Nos.
I. Introduction....................................... 1
II. Background........................................ 6
A. Regional Transmission Planning and Cost 6
Allocation Process...............................
1. Regional Transmission Planning Requirements 8
2. Nonincumbent Transmission Developer Reforms 9
3. Regional Transmission Cost Allocation...... 11
4. Interregional Transmission Coordination.... 12
B. Overview of Transmission Planning.............. 13
1. Reliability Needs.......................... 14
2. Economic Needs............................. 15
3. Public Policy Requirement Needs............ 16
4. Local Transmission Facilities in the 17
Regional Transmission Planning Process.......
C. Overview of Generator Interconnection.......... 18
D. Interaction Between the Regional Transmission 23
Planning and Cost Allocation and Generator
Interconnection Processes........................
E. Current Funding Paradigm....................... 24
1. Regional Transmission Cost Allocation...... 24
2. Local Transmission Facilities.............. 25
3. Interconnection-Related Network Upgrades... 28
III. The Potential Need for Reform.................... 30
A. The Existing Regional Transmission Planning and 30
Cost Allocation and Generator Interconnection
Processes May Be Inadequate To Ensure Just and
Reasonable Rates.................................
1. Considering Anticipated Future Generation.. 31
2. Results of Existing Local and Regional 37
Transmission Planning Processes..............
3. Cost Responsibility for Transmission 38
Facilities and Interconnection-Related
Network Upgrades.............................
IV. Consideration of Potential Reforms and Request for 44
Comment..............................................
A. Regional Transmission Planning and Cost 44
Allocation Processes.............................
1. Potential Reforms and Request for Comment.. 44
a. Planning for the Transmission Needs of 44
Anticipated Future Generation............
i. Future Scenarios and Modeling 46
Anticipated Future Generation............
ii. Identifying Geographic Zones That Have 54
Potential for High Amounts of Renewable
Resource Development to Meet Increased
Demand...................................
iii. Incentivizing Regional Transmission 61
Facilities...............................
iv. Enhanced Interregional or State-to- 62
State Coordination.......................
b. Coordinating Between the Regional 65
Transmission Planning and Cost Allocation
and Generator Interconnection Processes..
B. Identification of Cost and Responsibility for 69
Regional Transmission Facilities and
Interconnection-Related Network Upgrades.........
1. Relevant Cost Causation Precedent.......... 74
2. Cost Allocation for Transmission Facilities 75
Planned through the Regional Transmission
Planning Process.............................
a. Background............................. 76
b. Potential Need for Reform.............. 83
c. Potential Reforms and Request for 90
Comment..................................
3. Participant Funding and Crediting Policy 100
for Funding Interconnection-Related Network
Upgrades.....................................
a. Background............................. 101
i. Original Rationale for the Order No. 101
2003 Interconnection-Related Network
Upgrade Funding Requirements.............
(a) Crediting Policy...................... 102
(b) Participant Funding................... 105
b. Potential Need for Reform.............. 111
i. Participant Funding.................... 111
ii. Crediting Policy...................... 120
c. Potential Reforms and Request for 121
Comment..................................
i. Eliminate Participant Funding for 123
Interconnection-Related Network Upgrades.
ii. Revisions to the Existing Crediting 131
Policy...................................
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(a) Transmission Providers Provide Upfront 132
Funding for All Interconnection-Related
Network Upgrades.........................
(b) Interconnection Customers Contribute 135
to the Upfront Funding of Interconnection-
Related Network Upgrades Through a Fee...
(c) Transmission Providers Provide Upfront 139
Funding for Only Higher Voltage
Interconnection-Related Network Upgrades.
(d) Allocate the Upfront Cost of 146
Interconnection-Related Network Upgrades
on a Percentage Basis....................
iii. Additional Considerations............ 150
(a) Interconnection-Related Network 150
Upgrade Cost Sharing.....................
(b) Option To Build....................... 151
(c) Interconnection Request Limit......... 153
(d) Fast-Track for Interconnection of 154
Generating Facilities Committed to
Regional Transmission Facilities.........
(e) Fast-Track for Interconnection of 157
``Ready'' Generating Facilities..........
(f) Grid-Enhancing Technologies........... 158
C. Enhanced Transmission Oversight............ 159
1. Potential Need for Reform.................. 160
2. Potential Reforms and Request for Comment.. 163
a. State Oversight........................ 176
b. Limitation on Recovery of Costs for 178
Abandoned Projects.......................
c. Additional Oversight Approaches........ 180
D. Transition..................................... 181
V. Comment Procedures................................. 183
VI. Document Availability............................. 186
I. Introduction
1. Pursuant to its authority under section 206 of the Federal Power
Act (FPA),\1\ the Federal Energy Regulatory Commission (Commission) is
considering the potential need for reforms or revisions to existing
regulations to improve the electric regional transmission planning and
cost allocation and generator interconnection processes.
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\1\ 16 U.S.C. 824e. Section 206 requires that transmission rates
be just and reasonable, and not unduly discriminatory or
preferential.
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2. Approximately 10 years ago, the Commission issued Order No.
1000.\2\ That order stated its purpose generally in its introduction:
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\2\ Transmission Planning and Cost Allocation by Transmission
Owning and Operating Public Utilities, Order No. 1000, 136 FERC ]
61,051 (2011), order on reh'g, Order No. 1000-A, 139 FERC ] 61,132,
order on reh'g and 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).
The reforms herein are intended to improve transmission planning
processes and cost allocation mechanisms under the pro forma Open
Access Transmission Tariff (OATT) to ensure that the rates, terms
and conditions of service provided by public utility transmission
providers are just and reasonable and not unduly discriminatory or
preferential. This Final Rule builds on Order No. 890,\3\ in which
the Commission, among other things, reformed the pro forma OATT to
require each public utility transmission provider to have a
coordinated, open, and transparent regional transmission planning
process. After careful review of the voluminous record in this
proceeding, the Commission concludes that the additional reforms
adopted herein are necessary at this time to ensure that rates for
Commission-jurisdictional service are just and reasonable in light
of changing conditions in the industry. In addition, the Commission
believes that these reforms address opportunities for undue
discrimination by public utility transmission providers.\4\
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\3\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 118 FERC ] 61,119, order on
reh'g, Order No. 890-A, 121 FERC ] 61,297 (2007), order on reh'g,
Order No. 890-B, 123 FERC ] 61,299 (2008), order on reh'g, Order No.
890-C, 126 FERC ] 61,228, order on clarification, Order No. 890-D,
129 FERC ] 61,126 (2009).
\4\ Order No. 1000, 136 FERC ] 61,051 at P 1.
3. More than a decade after Order No. 1000, we believe it
appropriate to review the issues addressed by that order and other
transmission-related regulations and determine whether additional
reforms to the regional transmission planning and cost allocation and
generator interconnection processes or revisions to existing
regulations are needed to ensure rates for Commission-jurisdictional
service remain just and reasonable, and not unduly discriminatory or
preferential. The electricity sector is transforming as the generation
fleet shifts from resources located close to population centers toward
resources, including renewables, that may often be located far from
load centers. The growth of new resources seeking to interconnect to
the transmission system and the differing characteristics of those
resources are creating new demands on the transmission system. Ensuring
just and reasonable rates as the resource mix changes, while
maintaining grid reliability, remains the priority in the regional
transmission planning and cost allocation and generator interconnection
processes.
4. In light of these evolving conditions, we believe it timely and
appropriate 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
transmission rates remain just and reasonable and not unduly
discriminatory or preferential and that reliability is maintained.\5\
Accordingly, we will consider herein whether and which reforms and
revisions are necessary to the Commission's regulations on these
topics. This Advanced Notice of Proposed Rulemaking (ANOPR) discusses
proposals or concepts for changes to existing processes in several
broad categories: Regional transmission planning, regional cost
allocation, generator interconnection funding, generator
interconnection queueing processes and consumer protection, and in
several instances the ANOPR also offers a potential rationale or
argument for potential proposals. We note that the Commission has not
predetermined that any specific proposal discussed herein shall or
should be made or in what final form; rather, we seek comment from the
public on these proposals and welcome commenters to offer additional or
alternative proposals for consideration.
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\5\ 16 U.S.C. 824e.
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5. We believe it appropriate to review whether there are questions
that should be explored and possible solutions proposed regarding any
potential shortcomings in the existing regional transmission planning
and cost allocation and generator interconnection processes, which may
have become evident since the Commission issued Order No. 2003,\6\
Order No. 890, and Order No. 1000. We seek comment on several topics
across transmission planning and cost allocation and interconnection
queue processes, as well as oversight of transmission infrastructure
development. Examples
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of such questions for which we will seek comment in this ANOPR include,
among others: (1) Whether the existing regional transmission planning
and cost allocation processes appropriately considers the transmission
needs of anticipated future generation to drive study assumptions, or
instead relies on less comprehensive information, such as existing
interconnection requests with completed facilities studies, and whether
such current planning criteria are appropriate or should be revised;
(2) whether the regional transmission planning and cost allocation
processes' consideration of transmission needs driven by reliability,
economic considerations, and Public Policy Requirements \7\ are
inappropriately siloed from one another, and, if so, whether this
influences the consideration of potential benefits of a regional
transmission facility (and the associated beneficiaries for purposes of
allocating the costs of such a facility); \8\ (3) whether criteria in
addition to those related to reliability, economic, and Public Policy
Requirements needs should be planned for and considered in the
evaluation of benefits, and used to determine cost allocation in the
regional transmission planning process, and these needs should be
clear, credibly quantifiable and not speculative; (4) how to
appropriately identify and allocate the costs of new transmission
infrastructure in a manner that satisfies the Commission's cost-
causation principle that costs are allocated to beneficiaries in a
manner that is at least roughly commensurate with estimated benefits;
(5) whether or not it is appropriate for the costs of state or local
public policy-driven transmission facilities to be shifted through
regional cost allocation to consumers in non-participating states, or
whether changes to current interconnection cost allocation mechanisms
may unjustly and unreasonably shift costs to customers of load serving
entities; \9\ (6) whether and which reforms are necessary to the
generator interconnection process to ensure a more purposeful
integration with the regional transmission planning and cost allocation
processes, a more efficient queueing process, and a more efficient and
cost-effective allocation of interconnection costs; (7) whether the
regional transmission planning and cost allocation processes may have
resulted in transmission facilities addressing an unduly narrow set of
transmission needs, including needs located in a single transmission
owner's footprint, and having limited region-wide benefits, but that,
collectively, may impose significant costs on customers; (8) whether
and how to better coordinate between regional and local transmission
planning processes to identify more efficient or cost-effective
solutions; and (9) whether it is necessary, and how, to more clearly
identify the lines of regulatory authority and oversight between states
and federal authorities with regard to regional and local transmission
facilities to ensure appropriate vetting of transmission
infrastructure. In addition, we seek comment regarding whether the
current approach to oversight of transmission investment adequately
protects customers, particularly given the potentially significant and
very costly investments proposed to meet the transmission needs driven
by a changing resource mix, and, if customers are not adequately
protected from excessive costs, which potential reforms may be required
and are legally permissible to ensure just and reasonable rates.
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\6\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, 104 FERC ] 61,103 (2003), order on
reh'g, Order No. 2003-A, 106 FERC ] 61,220, order on reh'g, Order
No. 2003-B, 109 FERC ] 61,287 (2004), order on reh'g, Order No.
2003-C, 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) (NARUC
v. FERC).
\7\ 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). Order No. 1000, 136 FERC ] 61,051 at
P 2. The Commission clarified that Public Policy Requirements
established by state or federal laws or regulations include duly
enacted laws or regulations passed by a local governmental agency,
such as a municipal or county government. Order No. 1000-A, 139 FERC
] 61,132 at P 319. Order No. 1000 left planning and cost allocation
for Public Policy Requirements largely to the discretion of
transmission providers. See also infra P 16.
\8\ A regional transmission facility is a transmission facility
located entirely in one transmission planning region. Order No.
1000, 136 FERC ] 61,051 at n.374.
\9\ Under current Commission policy, the costs of
interconnection-related network upgrades are either (1) directly
assigned to the interconnection customer or (2) funded initially by
the interconnection customer and reimbursed through transmission
service credits.
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II. Background
A. Regional Transmission Planning and Cost Allocation Process
6. In 1996, the Commission issued Order No. 888 and the
accompanying pro forma OATT, setting forth certain minimum requirements
for transmission planning.\10\ In 2007, the Commission issued Order No.
890 to remedy flaws in the pro forma OATT, and in so doing, required
coordinated, open, and transparent transmission planning on both a
local and regional level. Specifically, the Commission required, among
other things, that each transmission provider's \11\ local transmission
planning process 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.\12\
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\10\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996) (cross-referenced
at 75 FERC ] 61,080), order on reh'g, Order No. 888-A, 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 Policy Study Group v. FERC, 225 F.3d 667
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1
(2002).
\11\ In this order, we use the term ``transmission provider''
when referring to a public utility that owns, controls, or operates
transmission facilities. The term transmission provider should be
read to include the transmission owner when the transmission owner
is separate from the transmission provider, as is the case in
regional transmission organizations (RTOs) and independent system
operators (ISOs).
\12\ Order No. 890, 118 FERC ] 61,119 at PP 418-601.
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7. In 2011, the Commission issued Order No. 1000 to build on the
transmission planning requirements of Order No. 890. Order No. 1000
included a package of reforms to ensure that the transmission planning
and cost allocation mechanisms embodied in the pro forma OATT were
adequate to support the development of more efficient or cost-effective
transmission facilities.\13\ The reforms in Order No. 1000 fell into
the following categories: (1) Regional transmission planning; (2)
transmission needs driven by Public Policy Requirements; (3)
nonincumbent transmission developer reforms; (4) regional and
interregional cost allocation; and (5) interregional transmission
coordination. Here we provide a brief overview of the Order No. 1000
regional transmission planning requirements, nonincumbent developer
reforms, regional transmission cost allocation rules, and interregional
transmission coordination.
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\13\ Order No. 1000, 136 FERC ] 61,051 at PP 11-12, 42-44; Order
No. 1000-A, 139 FERC ] 61,132 at PP 3, 4-6.
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1. Regional Transmission Planning Requirements
8. Order No. 1000 requires that each transmission provider
participate in a regional transmission planning process that produces a
regional transmission plan.\14\ Through the regional transmission
planning process, transmission providers must evaluate, in consultation
with stakeholders,
[[Page 40269]]
alternative transmission solutions that might meet the region's
reliability, economic, and Public Policy Requirements needs \15\ more
efficiently or cost-effectively than solutions that transmission
providers identified in their local transmission planning
processes.\16\ Order No. 1000 also requires that the regional
transmission planning process satisfy the Order No. 890 transmission
planning principles.\17\ Therefore, these transmission planning
principles, which the Commission adopted with respect to local
transmission planning processes in Order No. 890, also apply to the
regional transmission planning processes established in Order No. 1000.
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\14\ Order No. 1000, 136 FERC ] 61,051 at PP 146, 148.
\15\ Order No. 1000's requirement to consider transmission needs
driven by Public Policy Requirements is described below.
\16\ Order No. 1000, 136 FERC ] 61,051 at PP 11, 148.
\17\ Id. P 151. Order No. 890 explains these transmission
planning principles.
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2. Nonincumbent Transmission Developer Reforms
9. Order No. 1000 institutes a number of reforms that seek to
ensure that nonincumbent transmission developers have an opportunity to
participate in the regional transmission development process.\18\ In
particular, Order No. 1000 requires that each transmission provider
eliminate provisions in Commission-jurisdictional tariffs and
agreements that establish a federal right of first refusal for an
incumbent transmission provider with respect to transmission facilities
selected in a regional transmission plan for purposes of cost
allocation.\19\ Order No. 1000 defines a transmission facility selected
in a regional transmission plan for purposes of cost allocation as one
that has been selected because it is a more efficient or cost-effective
solution to a regional transmission need.\20\
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\18\ For purposes of Order No. 1000, ``nonincumbent transmission
developer'' refers to two categories of transmission developer: (1)
A transmission developer that does not have a retail distribution
service territory or footprint; and (2) a transmission provider that
proposes a transmission facility outside of its existing retail
distribution service territory or footprint, where it is not the
incumbent for purposes of that project. Id. P 225.
\19\ Id. P 313.
\20\ Id. PP 5, 63.
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10. In addition, Order No. 1000 requires that each regional
transmission planning process include not unduly discriminatory
qualification criteria and information requirements for transmission
developers that want to propose a transmission facility for selection
in the regional transmission plan for purposes of cost allocation.\21\
The regional transmission planning process must also have a transparent
and not unduly discriminatory process for evaluating whether to select
a proposed transmission facility in the regional transmission plan for
purposes of cost allocation.\22\ Furthermore, the regional transmission
planning process must provide a nonincumbent transmission developer
with the same eligibility as an incumbent transmission developer to use
a cost allocation method(s) for any sponsored transmission facility
selected in the regional transmission plan for purposes of cost
allocation.\23\
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\21\ Id. PP 225, 323, 325.
\22\ Id. P 328; Order No. 1000-A, 139 FERC ] 61,132 at P 452.
\23\ Order No. 1000, 136 FERC ] 61,051 at P 332.
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3. Regional Transmission Cost Allocation
11. Order No. 1000 requires each transmission provider to have in
place a method, or set of methods, for allocating the costs of new
regional transmission facilities selected in the regional transmission
plan for purposes of cost allocation.\24\ Each regional cost allocation
method must satisfy six regional cost allocation principles,\25\
including the principle that the cost of transmission facilities must
be allocated to those in the transmission planning region that benefit
from the facilities in a manner that is roughly commensurate with
estimated benefits.\26\
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\24\ Id. P 558.
\25\ Id. P 603.
\26\ Id. PP 622, 639.
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4. Interregional Transmission Coordination
12. Order No. 1000 requires each transmission provider, through its
regional transmission planning process, to establish further procedures
with each of its neighboring transmission planning regions for the
purpose of coordinating and sharing the results of respective regional
transmission plans to identify possible interregional transmission
facilities that could address transmission needs more efficiently or
cost-effectively than separate regional transmission facilities. The
interregional coordination processes must provide for: (1) The sharing
of information regarding the respective needs of each region and
potential solutions to those needs; and (2) the identification and
evaluation of interregional transmission facilities that may be more
efficient or cost-effective solutions to those regional needs.\27\
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\27\ Id. P 396.
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B. Overview of Transmission Planning
13. The next few paragraphs provide an overview of how transmission
providers plan their systems to meet their reliability, economic, and
Public Policy Requirements needs, consistent with Order Nos. 890 and
1000.
1. Reliability Needs
14. Transmission providers within transmission planning regions
conduct reliability planning studies to help ensure the ability of the
transmission system to serve firm transmission use. These studies may
extend 10 to 15 years into the future depending on the transmission
planning region's transmission planning process and tests for
violations of established North American Electric Reliability
Corporation (NERC) reliability requirements.\28\ Additional regional
and local reliability criteria may also apply in specific transmission
planning regions. In order to meet applicable reliability planning
criteria, the regional transmission planning process focuses on
studying and producing a transmission system that is robust enough to
be able to withstand a range of probable contingencies (e.g., the
sudden loss of a generator or high voltage transmission line) while
reliably serving customer demand and preventing cascading outages.\29\
Generally, transmission providers identify areas not in compliance with
planning criteria and develop plans to achieve compliance. Transmission
providers examine facilities to mitigate identified reliability
criteria violations for their feasibility, impact, and comparative
costs, culminating in a recommended regional transmission plan.
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\28\ For example, Reliability Standard TPL-001-4 requires that
Transmission Planners conduct an annual planning assessment of their
region's portion of the bulk electric system and document summarized
results of the steady state analyses, short circuit analyses, and
stability analyses. TPL-001-4 also requires that Transmission
Planners conduct these analyses using a model of their systems
operating under a wide variety of potential conditions to see under
what, if any, conditions the system will fail to meet reliability
criteria. TPL-001-4 lays out the variety of these conditions,
including system peak, off-peak, single contingency, multiple
contingencies (both sequential and simultaneous), severe
contingencies on adjacent systems, sensitivity analyses to
underlying model assumptions, and extreme events.
\29\ The regional transmission planning process will identify
the necessary transmission system facilities (which have varying
costs and lead times for when they can be placed into service) that
are needed to achieve reliable transmission system operations.
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2. Economic Needs
15. Transmission providers within transmission planning regions
also plan transmission facilities to meet economic needs. In Order No.
1000, the Commission recognized that Order No. 890 placed no
affirmative obligation on
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transmission providers to perform economic planning studies absent a
request by stakeholders. To remedy this deficiency, Order No. 1000
required that, in addition to economic planning studies requested by
stakeholders, transmission providers evaluate, through a regional
transmission planning process and in consultation with stakeholders,
alternative transmission solutions that might meet the needs of the
transmission planning region more efficiently or cost-effectively than
solutions identified by individual transmission providers in their
local transmission planning process. These regional transmission
solutions could include transmission facilities needed to meet
reliability requirements, address economic considerations, and/or meet
transmission needs driven by Public Policy Requirements.\30\ As Order
No. 890 explains, the purpose of economic transmission planning is to
plan transmission to alleviate congestion through the integration of
new generation resources or an expansion of the regional transmission
system, by an amount that justifies its cost, usually by a defined
threshold.\31\ However, to implement the requirement in Order No. 1000
to affirmatively plan for economic needs, transmission providers
implemented thresholds that vary across the regions. Examples of
regional transmission facilities driven by economic needs include
transmission facilities that relieve historical or projected
transmission congestion and allow lower-cost power to flow to
consumers.
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\30\ Order No. 1000, 136 FERC ] 61,051 at PP 147-148.
\31\ Order No. 890, 118 FERC ] 61,119 at P 549.
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3. Public Policy Requirement Needs
16. Order No. 1000 requires transmission providers to consider
transmission needs driven by Public Policy Requirements in their local
and regional transmission planning processes.\32\ However, the
requirement in Order No. 1000 to consider transmission needs driven by
Public Policy Requirements is limited, and the Commission provided
transmission providers with flexibility in how to meet the requirement.
For example, Order No. 1000 does not require that a separate class of
transmission facilities be created in the regional transmission
planning process to address transmission needs driven by Public Policy
Requirements,\33\ nor does it mandate the consideration of any
particular transmission need driven by a Public Policy Requirement.\34\
As a result, the process for identifying and considering such needs
varies from transmission planning region to transmission planning
region.
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\32\ Order No. 1000, 136 FERC ] 61,051 at PP 203, 222; Order No.
1000-A, 139 FERC ] 61,132 at P 208.
\33\ Order No. 1000, 136 FERC ] 61,051 at P 220 (explaining that
the Final Rule is intended to ``provide flexibility for public
utility transmission providers to develop procedures appropriate for
their local and regional transmission planning processes'').
\34\ Id. P 215.
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4. Local Transmission Facilities in the Regional Transmission Planning
Process
17. Generally, the transmission facilities that transmission
providers include in their individual local transmission plans are
incorporated into regional transmission plans as inputs, with minimal
opportunity for stakeholder review in the regional transmission
planning process. That is because the analysis of local transmission
plans in the regional transmission planning process is limited mainly
to a reliability analysis to ensure that local transmission plans do
not negatively affect the reliability of the regional transmission
system.
C. Overview of Generator Interconnection
18. In Order No. 2003, the Commission recognized a need for a
single set of interconnection procedures for jurisdictional
transmission providers and a single, uniformly applicable
interconnection agreement for large generators.\35\ The Commission
explained that generator interconnection is a ``critical component of
open access transmission service and thus is subject to the requirement
that utilities offer comparable service under the OATT.'' \36\ The
Commission also determined that, because of the inefficiency of
addressing generator interconnection issues on a case-by-case
basis,\37\ it was appropriate to establish a standard set of generator
interconnection procedures to ``minimize opportunities for undue
discrimination and expedite the development of new generation, while
protecting reliability and ensuring that rates are just and
reasonable.'' \38\ To this end, the Commission adopted the pro forma
Large Generator Interconnection Procedures (LGIP) and pro forma Large
Generator Interconnection Agreement (LGIA) \39\ and required that all
transmission providers' OATTs incorporate the pro forma LGIP and pro
forma LGIA.
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\35\ Order No. 2003, 104 FERC ] 61,103 at P 11.
\36\ Id. P 9 (citing Tenn. Power Co., 90 FERC ] 61,238 (2000)).
\37\ Id. P 10.
\38\ Id. P 11.
\39\ The pro forma LGIP and pro forma LGIA govern large
generating facilities, which are generating facilities that have a
generating facility capacity of more than 20 MW.
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19. In Order No. 2003, the Commission also retained a distinction
between interconnection facilities, which are located between the
interconnection customer's generating facility and the transmission
provider's transmission system, and network upgrades,\40\ which include
only facilities at or beyond the point where the interconnection
customer's generating facility interconnects to the transmission
provider's transmission system.\41\ This distinction is important
because the determination of which entity is ultimately responsible for
the cost of a facility can depend on whether that facility is an
interconnection facility or an interconnection-related network upgrade.
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\40\ For clarity, this ANOPR will refer to these facilities as
interconnection-related network upgrades.
\41\ Id. P 21.
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20. To initiate the generator interconnection process set forth in
Order No. 2003,\42\ the interconnection customer submits an
interconnection request associated with its proposed generating
facility that includes preliminary site documentation, certain
technical information about the proposed generating facility, and the
expected in-service date along with a deposit.\43\ The transmission
provider uses this information to determine the interconnection
facilities and interconnection-related network upgrades necessary to
accommodate the interconnection request and their associated costs.\44\
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\42\ While we provide a broad description of the generator
interconnection process under Order No. 2003 as background here, we
recognize that many transmission providers have adopted (and the
Commission has accepted) variations to many of the terms in the pro
forma LGIP and the pro forma LGIA. Consequently, some or many of the
details of a particular transmission provider's generator
interconnection process may vary considerably from the broad
description provided here.
\43\ Id. P 35.
\44\ Pro forma LGIP Section 3.1.
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21. After the transmission provider determines that the
interconnection request is complete, the interconnection request will
enter the interconnection queue with other pending requests, and the
transmission provider will assign the request a queue position based on
the date and time of receipt. The queue position will determine the
order in which the transmission provider will perform three phases of
interconnection studies for the interconnection request. The three
phases in order are: (1) The feasibility study; (2) the system impact
[[Page 40271]]
study; and (3) the facilities study, all of which are necessary to
determine the interconnection facilities and interconnection-related
network upgrades needed to accommodate the interconnection request and
the interconnection customer's cost responsibility for these
facilities.\45\
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\45\ Order No. 2003, 104 FERC ] 61,103 at PP 35-36. The
interconnection customer is responsible for the costs of
interconnection studies and any necessary restudies.
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22. At the completion of the facilities study, the transmission
provider will issue a report, which includes a ``best estimate of the
costs to effect the requested interconnection,'' and provide a draft
generator interconnection agreement to the interconnection
customer.\46\ If the interconnection customer wishes to proceed, after
negotiations, the interconnection customer enters into a generator
interconnection agreement with the transmission provider or requests
that the transmission provider file the agreement with the Commission
unexecuted.\47\
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\46\ Id. P 38.
\47\ Id.
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D. Interaction Between the Regional Transmission Planning and Cost
Allocation and Generator Interconnection Processes
23. The interaction between a transmission provider's current
generator interconnection process and its regional transmission
planning and cost allocation processes appears to be limited. The
primary interaction is that the baseline regional transmission planning
models generally only incorporate interconnection projects that are
near the end of the interconnection process and have completed a
facilities study. In addition, when creating interconnection study
models, transmission providers incorporate transmission planning
information into the interconnection base cases, but what information
is incorporated varies for each transmission provider. The base cases
for interconnection studies impact the cost assignment for
interconnection customers, often dramatically, and at present, most
transmission providers' OATTs do not contain requirements for what
information is included in base cases.\48\
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\48\ For example, some transmission providers have details
regarding what information is included in an interconnection study
base case in their tariffs, see e.g. Sw. Power Pool, Inc., 172 FERC
] 61,283, at P10 (2020), while others limit that information to the
business practices manuals. See, e.g., NYISO Manual 26, Reliability
Planning Process Manual at 15-16.
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E. Current Funding Paradigm
1. Regional Transmission Cost Allocation
24. As noted above, Order No. 1000's cost allocation reforms
require each transmission provider to participate in a regional
transmission planning process that features a regional cost allocation
method or methods for allocating the cost of new regional transmission
facilities selected in a regional transmission plan for purposes of
cost allocation. The Commission also required that such regional cost
allocation methods satisfy six regional cost allocation principles,
including the principle that the cost of transmission facilities must
be allocated to those in the transmission planning region that benefit
from the facilities in a manner that is roughly commensurate with
estimated benefits.\49\
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\49\ Order No. 1000, 136 FERC ] 61,051 at PP 622, 639. The six
Order No. 1000 regional cost allocation principles are discussed
further below.
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2. Local Transmission Facilities
25. In Order No. 1000, the Commission explained that the local
transmission planning process is the transmission planning process that
a transmission provider performs for its individual retail distribution
service territory or footprint pursuant to the requirements of Order
No. 890.\50\ The outcome of the local transmission planning processes
are local transmission facilities. In Order No. 1000, the Commission
defined a local transmission facility as 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.\51\
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\50\ Id. P 68.
\51\ Id. P 63.
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26. The Commission clarified that, if the transmission provider has
a retail distribution service territory and/or footprint, then only a
transmission facility that it decides to build within that retail
distribution service territory or footprint, and that is not selected
in a regional transmission plan for purposes of cost allocation, may be
considered a local transmission facility. Further, the Commission
explained that, in the case of an RTO/ISO whose footprint covers the
entire region, local transmission facilities are defined by reference
to the retail distribution service territories or footprints of its
underlying transmission owing members.\52\ The Commission did not
require that the transmission facilities in a transmission provider's
local transmission plan be subject to approval at the regional or
interregional level, unless that transmission provider seeks to have
any of those facilities selected in the regional transmission plan for
purposes of cost allocation.\53\
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\52\ Order No. 1000-A, 139 FERC ] 61,132 at P 429.
\53\ Id. P 190.
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27. Moreover, local transmission facilities planned through a local
transmission planning process are not eligible to use the Order No.
1000 regional cost allocation method and instead their costs are
allocated to the transmission provider in whose retail distribution
service territory or footprint the local transmission facility is
located. In support of this, the Commission explained that it continues
to permit an incumbent transmission provider to meet its reliability
needs or service obligations by choosing to build new transmission
facilities that are located solely within its retail distribution
service territory or footprint as long as the transmission provider
does not receive regional cost allocation for the facilities.\54\
Further, the Commission clarified that nothing in Order No. 1000
restricts an incumbent transmission provider from developing a local
transmission solution that is not eligible for regional cost allocation
to meet its reliability needs or service obligations in its own retail
distribution service territory or footprint.\55\
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\54\ Id. PP 366, 379, 425, 428.
\55\ Order No. 1000, 136 FERC ] 61,051 at P 329.
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3. Interconnection-Related Network Upgrades
28. The Commission's interconnection pricing policy \56\ allows for
two general approaches on how to assign the cost of interconnection-
related network upgrades, one of which we refer to as the crediting
policy and the other as participant funding. We will discuss the
rationale that the Commission provided when accepting each of the two
approaches in later sections.
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\56\ We use the term interconnection pricing policy to refer
collectively to both Order No. 2003's establishment of the crediting
policy for financing interconnection-related network upgrades and
Order No. 2003's allowance of participant funding for
interconnection-related network upgrades in RTOs/ISOs.
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29. In Order No. 2003, the Commission established the crediting
policy as a requirement of the Commission's interconnection pricing
policy. Pursuant to the crediting policy, the interconnection customer
is solely responsible for the costs of interconnection facilities, and
interconnection-related network upgrades are funded initially by the
[[Page 40272]]
interconnection customer (unless the transmission provider elects to
fund them) and the transmission provider reimburses the interconnection
customer through transmission service credits.\57\ The Commission
reasoned that ``it is appropriate for the Interconnection Customer to
pay initially the full cost of Interconnection Facilities and
[interconnection-related] Network Upgrades that would not be needed but
for the interconnection.'' \58\ While the interconnection customer pays
for the costs of the interconnection-related network upgrades upfront,
the transmission provider must reimburse the total amount that the
interconnection customer paid for interconnection-related network
upgrades, plus interest, as credits against the charges for
transmission service taken with respect to the interconnection
customer's generating facility as such charges are incurred. The
transmission provider recovers the cost of interconnection-related
network upgrades funded under the crediting policy through its embedded
cost transmission rates.\59\ The second pricing approach for
interconnection-related network upgrades is called participant funding.
Participant funding for interconnection-related network upgrades refers
to the direct assignment to a particular interconnection customer of
the costs of interconnection-related network upgrades that would not be
needed but for the interconnection.\60\ The Commission has accepted as
just and reasonable various participant funding approaches proposed by
RTOs/ISOs as independent entity variations from the pro forma
requirements of Order No. 2003.
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\57\ Order No. 2003, 104 FERC ] 61,103 at P 22.
\58\ Id. P 694. ``But for'' interconnection-related network
upgrades are those interconnection-related network upgrades that
would not have been constructed ``but for'' the interconnection
request. See N.Y. Indep. Sys. Operator, Inc., 122 FERC ] 61,267, at
n.3 (2008).
\59\ The embedded cost pricing ``attempts to allocate costs
among customers based upon usage.'' Fla. Power & Light Co., 70 FERC
] 61,158 (1995). Embedded cost rates reflect ``system average costs
including the cost of the [interconnection-related] network
upgrades, and incremental cost rates ``reflect [ ] just the cost of
the [interconnection-related] network upgrades.'' See Interstate
Power & Light Co. v. ITC Midwest, LLC, 144 FERC ] 61,052, at P 36
(2013) (emphasis added).
\60\ Order No. 845-B, 166 FERC ] 61,092 at P 5; see also Order
No. 2003, 104 FERC ] 61,103 at P 679 (pursuant to a ``policy of
participant funding . . . those [that] benefit from a particular
project pay for it'').
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III. The Potential Need for Reform
A. The Existing Regional Transmission Planning and Cost Allocation and
Generator Interconnection Processes May Be Inadequate To Ensure Just
and Reasonable Rates
30. As a result of changing circumstances since the Commission
issued Order Nos. 890, 1000, and 2003, we believe it is now appropriate
to examine whether the existing regional transmission planning and cost
allocation and generator interconnection processes adequately account
for the transmission needs of the changing resource mix, or whether
reforms may be necessary to ensure that transmission rates remain just
and reasonable and not unduly discriminatory or preferential.
1. Considering Anticipated Future Generation
31. Expansion of the transmission system generally occurs by design
through a transmission provider's transmission planning processes, or
ad hoc through its generator interconnection process. At present, it
appears that regional transmission planning processes may not
adequately model future scenarios to ensure that those scenarios
incorporate sufficiently long-term and comprehensive forecasts of
future transmission needs, including considering the needs of
anticipated future generation in identifying needed transmission
facilities. Although regional transmission planning processes may
include some level of generation development in different future
scenarios analyses, it appears that they tend to include in their
baseline reliability models only those generators that have completed
facilities studies, and thus are far along in the generator
interconnection process. These baseline reliability models, by relying
only on generators that have completed facilities studies, may only
account for generation that will come online in the short term.
32. As a result, the generator interconnection process appears to
be the principal means by which infrastructure is built to accommodate
new generators. That process, however, focuses on a single
interconnection request (or cluster of requests). In other words, the
generator interconnection process is not designed to consider how to
address anything beyond the reliability interconnection-related network
upgrades required for a specific interconnection request or group of
interconnection requests.
33. New transmission facilities often have a development lead time
that exceeds the interconnection timing needs of those interconnection
customers already in the queue. It appears that these types of
transmission facilities may not currently be planned and built in
advance to meet the needs of anticipated future generation and as a
result, interconnection customers are assigned the costs to construct
large, high-voltage transmission facilities.
34. In addition, because transmission planning processes generally
do not plan for the needs of anticipated future generation,
transmission infrastructure that is being developed in order to
facilitate new generation is constructed largely through the generator
interconnection process, which is unlikely to result in the economies
of scale that could more efficiently or cost-effectively meet the needs
of the changing resource mix.
35. Likewise, the existing generator interconnection process
appears to focus on the limited set of facilities needed to reliably
interconnect a single interconnection customer (or cluster of requests)
at the interconnection service level that the interconnection customer
requests. The generator interconnection process may not adequately
consider whether it may be more efficient or cost-effective to consider
the interconnection-related network upgrades needed for multiple
anticipated future generators that are not in the same cluster or are
not yet in the interconnection queue in areas that have abundant wind
or solar attributes that could support multiple future generators.\61\
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\61\ We note that certain regions do have the ability to share
costs of network upgrades with future generation, but this is
generally limited to the short term. For example, Midcontinent
Independent System Operator, Inc.'s (MISO's) Shared Network Upgrade
construct allows interconnection customers to be repaid for portions
of an interconnection-related network upgrade's cost if another
interconnection customer uses that network upgrade within five
years.
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36. In addition, there may be a need for coordination between the
regional transmission planning process and the generator
interconnection process, the absence of which may result in inefficient
investment in transmission infrastructure and ultimately unjust and
unreasonable or unduly discriminatory or preferential rates. By
considering the transmission needs of anticipated future generation in
its regional transmission planning and cost allocation processes, a
transmission provider may identify transmission facilities that could
facilitate both the interconnection of new generation as well as
address other identified transmission system needs--such as mitigating
a reliability violation or reducing congestion--at a lower total cost
than pursuing two separate transmission projects through the
[[Page 40273]]
generator interconnection and regional transmission planning and cost
allocation processes. Without co-optimization of the two processes,
however, there appears to be no system in place to jointly assess the
benefits and allocate the costs of transmission facilities that yield
benefits to both system loads and new generation.
2. Results of Existing Local and Regional Transmission Planning
Processes
37. We seek to better understand whether the current transmission
planning processes may be resulting increasingly in transmission
facilities addressing a narrow set of transmission needs, often located
in a single transmission owner's footprint. To the extent that the
requirements of the regional transmission planning process result in
transmission providers expanding predominately local transmission
facilities, that process may fail to identify more efficient or cost-
effective transmission facilities needed to accommodate anticipated
future generation. We seek to better understand how the reforms of the
federal right of first refusal in Order No. 1000 have shaped the type
and characteristics of transmission facilities developed through
regional and local transmission planning processes, such as a relative
increase in investment in local transmission facilities or the
diversity of projects resulting from competitive bidding processes.
3. Cost Responsibility for Transmission Facilities and Interconnection-
Related Network Upgrades
38. The Commission cannot ensure just and reasonable rates without
considering how to allocate the costs of transmission facilities and
interconnection-related network upgrades that result from the regional
transmission planning and cost allocation and generator interconnection
processes to the entities that benefit from those facilities. As the
Commission explained in Order No. 1000, the costs of transmission
infrastructure must be allocated to its beneficiaries in a manner that
is at least roughly commensurate with the benefits that they draw from
those facilities.\62\ We seek to better understand whether the current
approach to allocating the costs of transmission infrastructure,
including transmission facilities developed through the regional
transmission planning and cost allocation processes and
interconnection-related network upgrades planned through the generator
interconnection process, continues to appropriately allocate the costs
of those transmission facilities to the entities that ultimately
benefit from them.
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\62\ Order No. 1000, 136 FERC ] 61,051 at P 10.
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39. The current regional transmission planning process considers
transmission needs driven by reliability, economics, and Public Policy
Requirements. We seek comment whether, by separating transmission
facilities into types, transmission planning processes may fail to take
into account the benefits of multi-faceted projects for the purposes of
cost allocation.
40. The current approach to allocating the costs of
interconnection-related network upgrades may fail to allocate costs in
a manner that is roughly commensurate with benefits. As discussed
above, the generator interconnection process identifies the
interconnection facilities and interconnection-related network upgrades
needed to interconnect a single interconnection request (or cluster of
requests). Under the participant funding approach to financing the cost
of interconnection-related network upgrades, the interconnection
customer pays for the costs of such upgrades, even where they would
provide benefits to other customers such as resolving congestion on the
transmission system. At the time that the Commission issued Order No.
2003, it was less likely that interconnection customers would be
assigned significant interconnection-related network upgrades through
the interconnection study process. Now, however, there is little
remaining existing interconnection capacity on the transmission system,
particularly in areas with high degrees of renewable resources that may
require new resources to fund interconnection-related network upgrades
that are more extensive and, as a result, more expensive. The more
significant the interconnection-related network upgrades needed to
accommodate a new resource, the greater the potential that such
upgrades may benefit more than just the interconnection customer. Where
an interconnection customer elects not to pursue a generating facility
with system-wide benefits that exceeds such facility's cost, net
beneficial infrastructure would not be developed, potentially leaving a
wide range of customers worse off as a result.
41. We also note that the cost of interconnection-related network
upgrades can depend entirely on both the timing of when and the
specific site where the interconnection customer enters the
interconnection queue that may result in interconnection customers
submitting multiple speculative interconnection requests in an effort
to receive a favorable queue position and reduce their interconnection-
related network upgrade costs.\63\ When interconnection customers
``test the waters'' in this manner, it may lead to late-stage
withdrawals of the excess interconnection requests that can then impede
the transmission provider's ability to process its interconnection
queue in an efficient manner. Because of the changing interconnection
landscape since Order No. 2003, the Commission's interconnection
pricing policy, and in particular participant funding, now may result
in a situation where interconnection customers have a financial
incentive to submit multiple speculative projects. As a result, we
believe it may be time to reexamine the rationale behind the
Commission's pricing policy established for interconnection-related
network upgrades and to consider reforms to generator interconnection
processes that would make such processes more efficient, less costly,
and ensure that generation projects that are more ``ready'' than others
are not unduly delayed in the queue. In consideration of generator
interconnection process reforms, we remain mindful of the need to
ensure that interconnection costs are not unjustly and unreasonably
shifted to customers of load-serving entities.
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\63\ See, e.g., Review of Generator Interconnection Agreements
and Procedures, Technical Conference Transcript, Docket No. RM16-12-
000, at Tr. 211:10-21 (May 13, 2016) (Steve Naumann, Exelon
Corporation) (filed Aug. 23, 2016) (``We would look at putting let's
say new gas fired generation in PJM, it may have four queue
positions. And we only intend to go through with one, that's not
speculation, that's trying to get information on which is the most
viable.'').
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42. While a reassessment of Order No. 2003's assumptions pertaining
to the Commission's interconnection pricing policy may be necessary,
our focus is in line with Order No. 2003's finding that ``relatively
unencumbered entry into the market is necessary for competitive
markets.'' \64\ Furthermore, the purpose of this examination is also
consistent with the original objectives of Order No. 2003, namely to
``limit opportunities for Transmission Providers to favor their owner
generation'' and to ``facilitate market entry for generation
competitors by reducing interconnection costs and time.'' \65\ At the
same time, there is reason to question the contention in Order No. 2003
that participant funding provides more ``efficient price signals and a
more equitable allocation of costs than the crediting approach.'' \66\
Also, while the crediting policy ``recognizes the reliability benefits
of a stronger
[[Page 40274]]
transmission infrastructure and more competitive power markets that
result from a policy that facilitates the interconnection of new
generating facilities,'' \67\ we raise questions on whether there are
improvements that can be made to the crediting policy or whether a
different pricing policy may be more efficient.
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\64\ Order No. 2003, 104 FERC ] 61,103 at P 11.
\65\ Id. P 12.
\66\ Id. P 695.
\67\ Order No. 2003-A, 106 FERC ] 61,220 at P 584.
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43. We note that ensuring just and reasonable rates, while
maintaining grid reliability, remain the priorities for regional
transmission planning, and cost allocation processes, and generator
interconnection processes, and any comments proposing revisions to
existing regulations should address their impact on reliability and
costs to customers. All proposed reforms or revisions to regulations
proposed in this proceeding must be consistent with the Commission's
authority under section 206 of the FPA.
IV. Consideration of Potential Reforms and Request for Comment
A. Regional Transmission Planning and Cost Allocation Processes
1. Potential Reforms and Request for Comment
a. Planning for the Transmission Needs of Anticipated Future Generation
44. We seek comment regarding whether transmission providers in
each transmission planning region should amend the regional
transmission planning and cost allocation processes to plan for the
transmission needs of anticipated future generation to meet a changing
resource mix, including generation that is not yet in the
interconnection queue. We seek comment on whether the existing regional
transmission planning and cost allocation processes fail to adequately
account for anticipated future generation. We also seek comment on
whether the possible failure to account for anticipated future
generation results in inefficient investment in transmission
infrastructure and causes customers to pay unjust and unreasonable
rates for transmission service. We also seek comment on whether, and,
if so, how the Commission could structure and implement a framework for
considering the transmission needs of anticipated future generation in
the regional transmission planning and cost allocation processes.
Commenters should address how each suggested reform or revision to
existing rules is consistent with the Commission's authority under the
FPA.
45. Below, we describe potential changes to the regional
transmission planning and cost allocation processes that may be
components of a process that plans for transmission needs associated
with anticipated future generation. We seek comment on each of these
potential changes, including whether and, if so, how the potential
changes may lead to identification of more efficient or cost-effective
transmission solutions to meet the needs of anticipated future
generation. We also seek comment on whether there exist other potential
revisions that could improve regional transmission planning and cost
allocation for anticipated future generation, either as alternatives to
potential reforms discussed herein or as supplementary reforms.
i. Future Scenarios and Modeling Anticipated Future Generation
46. We seek comment on whether reforms are needed regarding how the
regional transmission planning and cost allocation processes model
future scenarios to ensure that those scenarios incorporate
sufficiently long-term and comprehensive forecasts of future
transmission needs. We seek comment on what factors shaping the
generation mix are appropriate to use for transmission planning
purposes, such as, for example: (1) Federal, state, and local climate
and clean energy laws and regulations; (2) federal, state, and local
climate and clean energy goals that have not been enshrined into law;
(3) utility and corporate energy and climate goals; (4) trends in
technology costs within and outside of the electricity supply industry,
including shifts toward electrification of buildings and
transportation; and (5) resource retirements. With regard to each
factor that may be considered for inclusion in scenario modeling, we
seek comment on the source of the Commission's authority to incorporate
that factor in the regional transmission planning and cost allocation
processes. In addition, we seek comment on whether the Commission
should establish minimum requirements regarding future scenarios for
transmission providers to use in their regional transmission planning,
including modeling anticipated future generation in those scenarios.
Commenters should also address whether and how any reforms or revisions
to existing rules could unjustly and unreasonably shift additional
costs to customers of load serving entities. Commenters should also
address whether the status quo does or does not allocate costs in a
manner roughly commensurate with benefits, and whether the status quo
leads to rates that are unjust or unreasonable.
47. The current regional transmission planning and cost allocation
processes vary regarding how far into the future transmission providers
look when evaluating transmission needs driven by reliability, economic
considerations, or Public Policy Requirements. In general, however, the
extent to which regional transmission planning processes plan for
anticipated future generation is often limited to generation in the
generator interconnection queue with a completed facilities study,
which represents a relatively short-term outlook, and therefore may
under-forecast anticipated future generation on a longer-term basis
(and the associated transmission needs of that anticipated future
generation). As noted, planning and developing the transmission
facilities needed to address more efficiently or cost-effectively the
transmission needs of a changing resource mix will often take
considerably longer than the typical development timeline of a
generating facility that has completed a facilities study and by
considering such a limited subset of generation resources, more cost-
effective transmission facilities that address longer-term needs may
never be developed.
48. In light of the above, we seek comment on whether, and if so,
how the regional transmission planning process should be restructured
to consider a longer-term outlook. We seek comment on whether
developing plausible long-term scenarios would lead to the
identification of more efficient or cost-effective transmission
solutions in regional transmission plans, whether building transmission
facilities to accommodate anticipated future generation is required to
render rates just and reasonable, and whether there are deficiencies in
existing regional transmission planning and cost allocation processes
that would be cured by conducting such future scenarios planning.
Specifically, we seek comment on whether the development of longer-term
scenarios for planning purposes should be pursued and, if so: (1) The
number of years into the future the scenarios should consider
(including an explanation of how far ahead it is reasonable to forecast
anticipated future generation and system requirements); (2) the inputs
that should be considered in modeling anticipated future generation;
(3) different transmission planning methods, including whether
consideration should be given to multiple future scenarios, as well as
how the planning process should consider the probabilities of future
[[Page 40275]]
scenarios; (4) whether and how transmission providers should account
for an array of different future scenarios when identifying more
efficient or cost-effective transmission solutions in regional
transmission plans; (5) whether and how transmission providers should
account for federal, state, local, and individual utility energy and
climate goals (including federal, state and local laws and regulations,
as well as other policies or goals), and the source of the Commission's
authority to account for such laws, regulations, policies and goals;
(6) whether and how transmission providers should plan for expected
future generator retirements; (7) whether and how Grid-Enhancing
Technologies \68\ should be accounted for in determining what
transmission is needed under such scenarios; (8) how benefits and costs
of transmission infrastructure should be accounted for in such models,
including how adjusted production costs should be calculated; (9) any
other aspects of future scenarios modeling, including planning for
anticipated future generation and associated transmission needs that
would be useful for the Commission to consider.
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\68\ Grid Enhancing Technologies increase the capacity,
efficiency, or reliability of transmission facilities. These
technologies include, but are not limited to: (1) Power flow control
and transmission switching equipment; (2) storage technologies, and
(3) advanced line rating management technologies. FERC, Grid
Enhancing Technologies, Notice of Workshop, Docket No. AD19-9-000
(Sept. 9, 2019).
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49. In addition, we seek comment on whether greater use of
probabilistic transmission planning approaches may better assess the
benefits of regional transmission facilities. While some transmission
providers consider a small number of future scenarios as part of their
transmission planning process, more advanced approaches, such as
stochastic \69\ techniques, may provide an opportunity to consider a
broader array of potential future conditions. Accordingly, we seek
comment on potential benefits and drawbacks of such techniques in
regional transmission planning assessments, including whether these or
other new approaches may facilitate the co-optimization of generation
siting and transmission development, whether such methods capture
savings in generation capital costs as well as production expenses that
can be realized from transmission additions, and whether implementing
such methods is required to render rates just and reasonable.
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\69\ Stochastic models are frameworks for addressing
optimization problems that involve uncertainty.
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50. We also seek comment on which inputs and assumptions
transmission providers would need to model to represent new generation
sources, such as renewable resources, in order to reflect their actual
performance, such as active power-frequency control, reactive power-
voltage control, and fault ride-through capabilities, in the planning
study cases and any additional studies in order to ensure that
transmission planning solutions result in operating reliability for the
future.
51. We seek comment on the extent to which anticipated generation
and transmission facility retirements are reflected in future scenarios
modeled by transmission providers, and whether modifications to
regional market rules and coordination processes between local and
regional plans could facilitate more accurate regional transmission
plans that reflect such anticipated retirements.
52. In addition, should the use of certain long-term scenarios be
shown appropriate as part of ensuring just and reasonable rates, we
seek comment on whether and how the Commission should ensure that the
regional transmission planning and cost allocation processes develop a
sufficiently wide range of future scenarios. We seek comment on whether
the Commission should consider principles or minimum requirements as a
basis for establishing such scenarios. Given that states or other local
governing bodies may be uniquely situated in determining how much
anticipated future generation is needed, or in providing information
related to infrastructure siting or resource mix as influenced by state
and local policies, we seek comment on how their input should be
reflected by transmission providers in developing a sufficiently wide
range of future scenarios, including those for anticipated future
generation, and the more efficient or cost-effective transmission
facilities that may be necessary to facilitate those future scenarios.
We seek comment on whether it is necessary to require transmission
providers to modify the regional transmission planning and cost
allocation processes, such as requiring additional stakeholder input,
to develop future scenarios, including those for anticipated future
generation, such that there are sufficient opportunities for
stakeholders to assess the reasonableness of the results, as well as
for future modifications to the planning process.
53. Finally, we seek comment on whether and how such long-term
scenarios should be used in identifying and selecting solutions to meet
future transmission needs. For example, as discussed below, should
transmission providers focus on a broader set of benefits for
transmission facilities and a portfolio of transmission facilities in
identifying the more efficient or cost-effective transmission
solutions? If so, how should regional planning processes determine the
right set of benefits to factor into such an evaluation? Is maximizing
net benefits an appropriate criterion to use to identify efficient and
cost-effective transmission solutions? Should the willingness of some
beneficiaries to pay for certain transmission infrastructure, for
example utilities or corporations with renewable resource or zero
carbon goals, be considered in determining whether to include the
benefits within a broader set of benefits from transmission facilities,
and if so then how? Is there a need to establish a minimum set of
transmission facility benefits that transmission providers must
incorporate into regional transmission planning decisions, and if so,
is there also a need to regularly update the minimum set of
transmission facility benefits?
ii. Identifying Geographic Zones That Have Potential for High Amounts
of Renewable Resource Development To Meet Increased Demand
54. We seek comment on whether the Commission should require
transmission providers in each transmission planning region to
establish, as part of their regional transmission planning and cost
allocation processes, a process to identify geographic zones that have
the potential for the development of large amounts of renewable
generation and plan transmission to facilitate the integration of
renewable resources in those zones.
55. Examples of transmission planning and development initiatives
that have identified geographic zones with the potential for the
development of significant amounts of renewable resources and
transmission to facilitate the integration of renewable resources in
those zones include the Public Utility Commission of Texas's (Texas
Commission) Competitive Renewable Energy Zones (CREZ) initiative \70\
and MISO's Multi-Value Projects (MVP).\71\
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\70\ https://www.ercot.com/committee/crez.
\71\ https://www.misoenergy.org/planning/planning/multi-value-projects-mvps/.
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56. California Independent System Operator Corporation (CAISO)
offers another example of a regional transmission planning process
identifying transmission facilities to accommodate renewable resources
in
[[Page 40276]]
geographic zones that have the potential for high amounts of renewable
resources. In a petition for declaratory order, the Commission approved
a mechanism to facilitate the financing and development of transmission
facilities to interconnect multiple resources that met CAISO's
eligibility requirements, including a high voltage level and providing
access to areas rich in renewable energy.\72\
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\72\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061 (2007).
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57. We seek comment on whether the Commission should require
transmission providers in each transmission planning region to
establish, as part of their regional transmission planning and cost
allocation processes, a process that identifies geographic zones that
have the potential for the development of large amounts of new
generation, particularly renewable resources. We seek comment on
whether and how such a process might interrelate with existing regional
transmission planning and cost allocation processes within each region,
and how long-term scenario planning discussed above may be used in this
process or other relevant regional transmission planning and cost
allocation processes. In addition, we seek comment on whether reforms
to the current interregional transmission coordination process are
needed or appropriate for making an approach along these lines
effective. We also seek comment on: (1) How the Commission should
structure this potential requirement; and (2) any potential best
practices, analyses, models, and metrics that could be used to identify
such zones, including the amount and type of potential generation that
could be located there. As with the future scenarios transmission
planning discussed above, we seek comment on whether and how states and
local entities may provide input into the identification of such zones.
We seek comment on whether, and, if so, how transmission providers can
assess whether there is sufficient commercial interest in developing
generation in any potential zones and transmission to interconnect the
potential generation (for example, through studies or formal
declarations of interest). We also seek comment on whether and, if so,
what safeguards or incentives might be necessary to ensure that
transmission infrastructure is built only to satisfy expected
transmission needs and not overly speculative commercial interests. We
also seek comment on whether any such requirement is consistent with
the FPA's prohibition of unduly discriminatory or preferential rates.
58. We seek comment on whether the Commission should require
transmission providers to account for trends in the resource mix in
developing energy zones for anticipated future generation as part of
planning for transmission needs related to such resources and if so,
what would be the best way to do so? We seek comment whether it would
be appropriate, as the resource mix further develops, to develop
similar zones for the transmission needs driven by the development and
interconnection of energy storage resources and how to do so.
59. In order to ensure that the more efficient or cost-effective
transmission facilities are selected and that rates are just and
reasonable, we also seek comment on whether: (1) Eligibility thresholds
or criteria (e.g., voltage levels, amount of new generation located
within a given geographic area or load zone, etc.) may be appropriate
to determine whether a proposed regional transmission facility should
be considered as part of the regional transmission planning and cost
allocation process for transmission facilities built for anticipated
future generation; (2) whether the CREZ, MISO MVP, CAISO approaches, or
other processes for identifying and planning for the needs of
anticipated future generation are models for any potential requirements
and, if so, which aspects of those initiatives the Commission should
consider requiring transmission providers to implement, for example,
the CREZ model of requiring future generation to financially commit in
advance of construction; (3) whether there is a need for mechanisms to
limit the risk to customers from planning for anticipated future
generation, for example, we note CAISO's use of an ex ante cap on the
total cost exposure to transmission customers in addressing generation
resource interconnection, as one potential approach; \73\ and (4)
whether specific proposals are consistent with the Commission's FPA
section 206 authority.
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\73\ Id. P 6.
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60. We also seek comment on whether the regional transmission
planning process could be structured in such a way that is more
collaborative, relying on the knowledge and experience that
transmission providers, project developers, state commissions, and
other stakeholders have regarding optimal locations, the topography of
the transmission network, and Public Policy Requirements, among other
factors that will influence the location and amount of future renewable
resources. We note that the CREZ process was highly collaborative, with
the Electric Reliability Council of Texas (ERCOT) conducting workshops
with stakeholders over a six-month period to consider and evaluate
multiple transmission scenarios.\74\ In addition to seeking comment on
technical and collaborative approaches to identify geographic zones for
future renewable resources, we seek comment on potential alternative
proposals from stakeholders on how to identify where transmission
facilities may be needed to accommodate anticipated future generation.
Commenters should address whether, if implemented, such a scenario
planning process should be the same or different in non-RTO/ISO versus
RTO/ISO regions, and if different, what those differences should be.
Commenters should address how any proposed changes to the regional
planning and cost allocation processes increase the efficiency, or
lower the costs, of such processes and whether such changes will help
ensure a reliable power supply and/or will reduce or control the costs
of transmission and generation services that are ultimately passed on
to customers of load serving entities. Commenters should also address
proposed cost allocation.
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\74\ See Texas Commission, Order on Rehearing, Docket No. 33672,
at 3 (Oct. 7, 2008).
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iii. Incentivizing Regional Transmission Facilities
61. To prioritize regional transmission facilities that may have
greater benefit-to-cost ratios than local alternatives, we seek comment
on whether and, if so, how to expand or improve any incentives to
incent the development of regional transmission facilities that
demonstrably may offer a more efficient or cost-effective solution to
an identified need than local alternatives. As an example of a possible
regional transmission incentive, we seek comment on whether or not any
available return on equity adder incentive that may be available for
RTO/ISO participation should be limited in applicability only to
regional, and not local, transmission facilities, when those regional
transmission facilities are selected as the more efficient or cost-
effective solution to an identified transmission need.
iv. Enhanced Interregional or State-to-State Coordination
62. We recognize that potential reforms discussed for comment above
may require greater interregional or
[[Page 40277]]
state-regional coordination to be fully realized in a just, reasonable
and not unduly discriminatory or preferential manner. As a result, we
seek comment on whether reforms to the current interregional
transmission coordination process, including potentially requiring
interregional transmission planning, are needed or appropriate for
making the potential approaches discussed above effective, and whether
such reforms are consistent with the Commission's authority under
section 206 of the FPA.
63. We seek comment on whether, because an interregional project
must first be selected in each of the neighboring regions' regional
planning processes before being selected in the interregional process,
this challenge to the current interregional coordination process is
impeding the selection and development of efficient, cost-effective
interregional projects and, if so, what revisions are necessary to
address that barrier. Should the Commission require joint planning
processes, rather than simply joint coordination, for neighboring
regions? In light of the potential reforms to regional planning and
cost allocation and generator interconnection processes being
considered in this ANOPR, are there core principles or approaches that
the Commission should also consider when reviewing the existing
approach to interregional planning? For example, should the Commission
establish interregional reliability planning criteria or consider
renewable resource geographic zones during interregional planning?
Beyond interregional planning, can and should the Commission provide
alternate pathways for transmission facilities that benefit multiple
regions to be assigned cost allocation to customers across multiple
regions? For example, should the Commission allow for identification of
benefits, and allocation of commensurate costs, to one region of a
project selected in a neighboring region's regional transmission
planning process? Finally, comments should address whether taking any
proposed action is consistent with the Commission's authority under
section 206 of the FPA.
64. In addition, we seek comment on whether and, if so, how a
regional states committee or other organized body of state officials
should participate in the development and evaluation of assumptions or
criteria used for regional transmission planning and cost allocation
and interregional coordination and cost allocation for transmission
needs related to future scenarios, including for anticipated future
generation or geographic generation zones.
b. Coordinating Between the Regional Transmission Planning and Cost
Allocation and Generator Interconnection Processes
65. We seek comment on whether reforms are needed to improve the
coordination between the regional transmission planning and cost
allocation and generator interconnection processes. We seek comment on
whether the Commission should require transmission providers to operate
their regional transmission planning and cost allocation and generator
interconnection processes on concurrent, coordinated timeframes, with
the same or similar assumptions and methods, and whether such a
potential requirement may identify more efficient or cost-effective
transmission solutions that could address needs shared between the two
processes.
66. We seek comment on how the regional transmission planning and
cost allocation and generator interconnection processes could be better
coordinated or integrated. For example, would use of similar timeframes
and assumptions facilitate more efficient or cost-effective
transmission solutions? How could these processes most effectively be
co-optimized? We seek comment on whether and, if so, how
interconnection requests that trigger the need for interconnection-
related network upgrades that may provide regional transmission
benefits could be studied in a way that accounts for the potential
broader transmission benefits associated with, for example, resource
adequacy, operating reliability, and similar needs, and in coordination
with the regional transmission planning process? We seek comment on
whether and how relevant information from the generator interconnection
process could be integrated into regional transmission planning in a
timely manner, and whether and how transmission providers could move
beyond using the outputs of each process as a deterministic input into
the other rather than optimizing together across approaches. We also
seek comment on whether it may be possible and beneficial to combine
certain aspects of the transmission planning and generator
interconnection processes, and if so, how?
67. We also seek comment on whether and how the Commission could
revise transmission planning criteria that transmission providers use
in the generator interconnection process so that they could better
identify more efficient or cost-effective interconnection-related
network upgrades. As indicated earlier, we also seek comment on whether
and how transmission providers could incorporate anticipated future
generation, including resources in the interconnection queue, in the
regional transmission planning and cost allocation processes. In
particular, we encourage commenters to discuss how to address concerns
regarding uncertainty, including speculative projects, in planning for
anticipated future generation.
68. Further, we seek comment on whether and how more effectively
accounting for anticipated future generation in transmission planning
may reduce the costs of interconnection-related network upgrades. To
the extent this is the case, how should such benefits be identified,
and should they factor into the regional transmission planning and cost
allocation process?
B. Identification of Cost and Responsibility for Regional Transmission
Facilities and Interconnection-Related Network Upgrades
69. The Commission has repeatedly recognized that, where cost
allocation methods do not appropriately account for benefits associated
with new transmission facilities, they may result in rates that are not
just and reasonable or are unduly discriminatory or preferential.\75\
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\75\ See Order No. 890, 118 FERC ] 61,119 at P 557 (finding that
how ``the costs of new transmission facilities are allocated is
critical to the development of new infrastructure'' because
``[t]ransmission providers and customers cannot be expected to
support the construction of new transmission unless they understand
who will pay the associated cost''); Order No. 1000, 136 FERC ]
61,051 at PP 484-487; see also Ill. Commerce Comm'n v. FERC, 576
F.3d 470, 476 (7th Cir. 2009) (ICC v. FERC).
---------------------------------------------------------------------------
70. We seek comment on whether the existing approach to cost
allocation in regional transmission planning processes fails to
consider the full suite of benefits--and the associated beneficiaries--
produced by transmission facilities developed to meet the transmission
needs of the changing resource mix. We seek comment on whether the
current approach omits relevant benefits of new transmission
infrastructure and, if so, thereby fails to consider the entities that
receive those benefits in the cost allocation process. What,
specifically, are those other benefits that should be considered? In
addition, while the regional transmission planning process considers
transmission needs driven by reliability, economic considerations, and
Public Policy Requirements, these types of transmission needs are, in
[[Page 40278]]
many cases, considered in isolation from one another and the cost
allocation methods for transmission facilities developed in response to
these needs are generally separated by type. We seek comment as to
whether the existing regional transmission planning and cost allocation
processes may not fully account for the full suite of benefits,
including hard-to-quantify benefits, and may impede the allocation of
the costs of transmission facilities needed to meet the transmission
needs of the changing resource mix in a manner that is at least roughly
commensurate with the actual benefits of those facilities. Getting that
balance right is important not only to comply with the cost causation
principle, but also because efforts to plan the transmission system to
meet the needs of the changing resource mix will succeed only if the
associated cost allocation methods are transparent, equitable, and
practicable.\76\
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\76\ Cf. BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264,
268-269 (D.C. Cir. 2014) (BNP Paribas Energy) (``[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.'' (citing Midwest ISO Transmission Owners v. FERC, 373 F.3d
1361, 1368 (D.C. Cir. 2004) and Se. Mich. Gas Co. v. FERC, 133 F.3d
34, 41 (D.C. Cir. 1998))); Order No. 1000, 136 FERC ] 61,051 at P
669 (explaining that requiring cost allocation methods be open and
transparent ensures that such methods are just and reasonable and
not unduly discriminatory or preferential, aids in development and
construction of new transmission, and may avoid contentious
litigation or prolonged stakeholder debate); KN Energy, Inc. v.
FERC, 968 F.2d 1295, 1300-01 (D.C. Cir. 1992) (describing properly
designed rates as producing revenues `` `which match, as closely as
practicable, the costs to serve each class or individual customer'
'' (emphasis in original)) (quoting Ala. Elec. Coop., Inc. v. FERC,
684 F.2d 20, 27 (D.C. Cir. 1982)); Pub. Serv. Co. of Colo., 163 FERC
] 61,204, at P 14 (2018) (recognizing that ``feasibility'' is part
of ratemaking, such that the Commission may appropriately ``balance
maximally reflecting cost causation with other competing policy
goals,'' such as promoting more efficient or cost-effective regional
transmission planning).
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71. With respect to cost allocation in the generator
interconnection process, we seek comment as to whether the participant
funding approach for interconnection-related network upgrades required
for an interconnection request in RTOs/ISOs may no longer be just and
reasonable. Participant funding may result in costly interconnection-
related network upgrades being allocated entirely to interconnection
customers while failing to account for the significant benefits that
these interconnection-related network upgrades may provide to other
anticipated future generators seeking to interconnect and/or existing
or future transmission customers. We further seek comment on whether
the narrow focus of the generator interconnection process results in
only a subset of beneficiaries paying for transmission infrastructure
that, in practice, may benefit many.
72. We seek comment on whether separating the regional transmission
planning and cost allocation and generator interconnection processes
may increasingly result in an only partial-accounting of the benefits
of new transmission infrastructure, leaving some transmission and
interconnection customers potentially bearing a disproportionate cost
burden. We seek comment on whether any changes to the criteria used for
considering which transmission facilities are selected in the regional
transmission plan for purposes of regional cost allocation, as well as
the formula for the regional allocation of costs of regional
transmission facilities and for the cost of interconnection-related
network upgrades, including changes to the definition of beneficiary,
hold the potential to unjustly and unreasonably shift costs to
customers of load serving entities. We seek comment on how any
contemplated reforms or revisions to existing regulations are
consistent with the FPA and its requirement for just and reasonable and
not unduly discriminatory or preferential rates.
73. In the following sections, we address the relevant court and
Commission precedent governing cost allocation and seek comment on a
number of potential reforms to address these concerns and ensure that
transmission rates remain just and reasonable and not unduly
discriminatory or preferential.
1. Relevant Cost Causation Precedent
74. Pursuant to FPA sections 205 and 206, the Commission is
responsible for ensuring that the rates, terms, and conditions for
transmission of electricity in interstate commerce are just,
reasonable, and not unduly discriminatory or preferential.\77\ For a
cost allocation approach to satisfy this standard, it must satisfy the
cost causation principle. The cost causation principle requires that
``all approved rates reflect to some degree the costs actually caused
by the customer who must pay them'' \78\ and that costs ``be allocated
to those who cause the costs to be incurred and reap the resulting
benefits.'' \79\ As the U.S. Court of Appeals for the Seventh Circuit
(Seventh Circuit) further explained, 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.'' \80\ Courts ``evaluate compliance
with this . . . principle by comparing the costs assessed against a
party to the burdens imposed or benefits drawn by that party.'' \81\ In
ICC v. FERC, the Seventh Circuit also stated that a cost allocation
method can satisfy the cost causation principle if the Commission ``has
an articulable and plausible reason to believe that the benefits are at
least roughly commensurate with'' the allocation of the costs.\82\ The
Seventh Circuit stated, however, that satisfying this requirement does
not require exacting precision, and the Commission need not ``calculate
benefits to the last penny, or for that matter to the last million or
ten million or perhaps hundred million dollars.'' \83\
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\77\ 16 U.S.C. 824d, 824e.
\78\ KN Energy, Inc. v. FERC, 968 F.2d at 1300.
\79\ S.C. Pub. Serv. Auth., 762 F.3d at 87 (quoting NARUC v.
FERC, 475 F.3d at 1285).
\80\ ICC v. FERC, 576 F.3d at 476.
\81\ Midwest ISO Transmission Owners v. FERC, 373 F.3d at 1368.
\82\ 576 F.3d at 477.
\83\ Id. (citing Midwest ISO Transmission Owners v. FERC, 373
F.3d at 1369).
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2. Cost Allocation for Transmission Facilities Planned Through the
Regional Transmission Planning Process
75. Potential reforms for which we seek comment in this ANOPR
contemplate a more forward-looking approach to the regional
transmission planning process that plans for anticipated future
generation, potentially producing a different and broader set of
benefits and beneficiaries. The following sections seek comment on
potential reforms that may be necessary to ensure that the costs of
transmission facilities developed to meet the transmission needs of the
changing resource mix are allocated in a manner that is roughly
commensurate with those benefits, while ensuring that any potential
reforms or revisions to existing cost-allocation rules do not unjustly
or unreasonably shift costs to any type of market participant or
customers of load serving entities. We seek comment on whether certain
benefits are not appropriate to account for under the FPA, and whether
allocation of costs based on such benefits may be inconsistent with the
Commission's statutory mandate.
a. Background
76. In Order No. 1000, the Commission determined that the lack of
clear ex ante cost allocation methods that identify beneficiaries of
proposed regional transmission facilities was
[[Page 40279]]
impairing the ability of transmission providers to implement more
efficient or cost-effective transmission solutions identified in the
regional transmission planning process. According to the Commission,
the failure to address cost allocation in a way that aligns with the
benefits of new transmission facilities could lead to needed
transmission facilities not being built, adversely impacting
ratepayers.\84\ The Commission therefore required transmission
providers to have in place a method, or set of methods, for allocating
the costs of new transmission facilities selected in a regional
transmission plan for purposes of cost allocation. To guide
transmission providers, the Commission established a set of cost
allocation principles that transmission providers' cost allocation
methods must satisfy, with the goal of ensuring that the costs of
transmission solutions chosen to meet regional transmission needs would
be allocated to those that received benefits from them.\85\ The
Commission determined that this principles-based approach would result
in the allocation of the costs of new transmission facilities in a
manner that is at least roughly commensurate with the benefits received
by those that pay those costs while allowing for regional
flexibility.\86\
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\84\ Order No. 1000, 136 FERC ] 61,051 at P 499.
\85\ Id. PP 9, 482-83.
\86\ Id. P 10; Order No. 1000-A, 139 FERC ] 61,132 at P 647.
---------------------------------------------------------------------------
77. The six regional cost allocation principles that the Commission
adopted in Order No. 1000 are: (1) Costs of 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; \87\ (3) a benefit to cost threshold ratio, if
adopted, cannot exceed 1.25 to 1; \88\ (4) costs must be allocated
solely within the transmission planning region unless another entity
outside the region voluntarily assumes a portion of those costs; \89\
(5) the method for determining benefits and identifying beneficiaries
must be transparent; \90\ and (6) there may be different methods for
different types of transmission facilities, such as those needed for
reliability, congestion relief, or to achieve Public Policy
Requirements.\91\ Although the Commission required the regional cost
allocation methods to determine benefits and identify beneficiaries in
a transparent manner, the Commission also recognized that ``identifying
which types of benefits are relevant for cost allocation purposes,
which beneficiaries are receiving those benefits, and the relative
benefits that accrue to various beneficiaries can be difficult and
controversial.'' \92\ Consistent with this notion, the Commission
declined to require transmission providers to adopt a universal or
comprehensive definition of ``benefits'' and ``beneficiaries'' \93\ of
regional transmission facilities, instead allowing for regional
flexibility and examining each region's definitions on compliance.
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\87\ Order No. 1000, 136 FERC ] 61,051 at P 637.
\88\ Id. P 646.
\89\ Id. P 657.
\90\ Id. P 668.
\91\ Id. P 685.
\92\ Id. P 501.
\93\ Order No. 1000-A, 139 FERC ] 61,132 at P 679 (explaining
that Order No. 1000 does not define benefits and beneficiaries but
rather requires transmission providers to be definite about benefits
and beneficiaries for purposes of their cost allocation methods).
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78. The result is that transmission providers in each transmission
planning region have implemented varying regional transmission cost
allocation methods to comply with the cost allocation principles of
Order No. 1000, the majority of which allocate the costs of regional
transmission facilities that address reliability needs separately from
those that address economic needs and separately from those that
address Public Policy Requirements. In other words, most regional
transmission cost allocation methods do not consider whether a regional
transmission facility addresses more than one category of needs, and
therefore provides more than one category of transmission benefits.
79. That said, some transmission providers' Order No. 1000-
compliant regional transmission cost allocation methods may recognize a
broader number of benefits than others and identify the broader
benefits across a portfolio of transmission facilities rather than on a
facility-by-facility basis, whereas others may be more constrained. For
example, MISO's MVP process is designed to identify a portfolio of
regional transmission facilities that: (1) Reliably and economically
enable regional public policy needs; (2) provide multiple types of
regional economic value; and/or (3) provide a combination of regional
reliability and economic value. Specifically, MISO MVPs must be above
100 kV, have a project cost of $20 million or more, and have a combined
benefit-to-cost ratio greater than 1.0 and must be evaluated as part of
a portfolio of transmission projects.\94\ The costs of this MVP
portfolio are allocated on a postage stamp basis across the MISO
region.\95\
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\94\ MISO, FERC Electric Tariff, Attachment FF, Section II.C
(85.0.0).
\95\ Id. Section III.A.2.g.
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80. Southwest Power Pool's (SPP) Balanced Portfolio process
similarly considers broader transmission benefits.\96\ SPP evaluates
economic benefits of a portfolio of transmission facilities to achieve
a balance where the benefits of the portfolio to each zone (as measured
by adjusted production cost savings) equal or exceed the costs
allocated to each zone over a 10-year period. By allocating costs such
that the benefits to each zone will equal or exceed those costs, the
Balanced Portfolio process ensures that SPP allocates costs in a manner
that is least roughly commensurate with benefits by design. In
addition, SPP may reallocate costs to ensure that the portfolio is
balanced and, under certain conditions, including cancellation of a
transmission facility or unanticipated decreases in benefits or
increases in costs, may review a previously approved Balanced Portfolio
and recommend reconfiguring the portfolio.\97\
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\96\ SPP's Balanced Portfolio was an initiative to develop a
group of economic transmission projects that benefit the entire SPP
region and to allocate those transmission project costs regionally.
The SPP Board of Directors approved the Balanced Portfolio
transmission projects in April 2009.
\97\ SPP OATT, attach. J (Recovery of Costs Associated With New
Facilities), Section III.D.
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81. As for allocating the costs of regional transmission facilities
to generators, in Order No. 1000, while commenters requested that the
Commission allow such costs to be allocated to generators as
beneficiaries, the Commission determined that generator interconnection
was outside the scope of the rulemaking.\98\ However, the Commission
also stated that transmission providers could propose a regional
transmission cost allocation method that allocates costs directly to
generators as beneficiaries, but any effort to do so must not be
inconsistent with the Order No. 2003 generator interconnection process.
The Commission noted that in not addressing these issues, it was
neither minimizing the importance of evaluating the impact of generator
interconnection requests during transmission planning, nor limiting the
ability of transmission providers to use requests for generator
interconnections in developing assumptions to be used in
[[Page 40280]]
the regional transmission planning process.\99\
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\98\ Order No. 1000, 136 FERC ] 61,051 at P 760.
\99\ Id. P 760.
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82. Nevertheless, at least one transmission provider considers
interconnection customers as beneficiaries of new transmission
facilities. The Commission approved CAISO's proposal whereby
transmission customers initially fund the transmission expansion needed
to facilitate interconnection through the transmission revenue
requirement of the constructing transmission provider, and
interconnection customers are assigned their pro rata share of the
going-forward costs of using the transmission facility as their
generators interconnect to the transmission system. Under CAISO's
proposal, all transmission system users pay the costs of the
unsubscribed portion of a new transmission facility until the line is
fully subscribed.\100\ The CAISO approach also includes an ex ante cap
on the total cost exposure to transmission customers, which was set at
15% of the sum total of the net high-voltage transmission plant of all
transmission providers, as reflected in their transmission revenue
requirements and in the CAISO transmission access charge.\101\
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\100\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061.
\101\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061, at P
6.
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b. Potential Need for Reform
83. This statement in Order No. 1000 rings as true today as it did
then--``identifying which types of benefits are relevant for cost
allocation purposes, which beneficiaries are receiving those benefits,
and the relative benefits that accrue to various beneficiaries can be
difficult and controversial.'' \102\ This is especially true for
larger, regional transmission facilities that are both costly and could
have potentially broad benefits. As the Commission recognized in Order
No. 890, the manner in which the costs of new transmission facilities
are allocated is ``critical'' to developing those facilities as is
identifying the types of benefits and the associated beneficiaries of
those facilities.\103\
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\102\ Order No. 1000, 136 FERC ] 61,051 at P 501.
\103\ Order No. 890, 118 FERC ] 61,119 at P 557.
---------------------------------------------------------------------------
84. The possible reforms for which we seek comment in this ANOPR
seek to ensure the development of regional transmission facilities
needed to meet the transmission needs of the changing resource mix
occurs in a more efficient or cost-effective manner, at just and
reasonable rates. Commenters should also address whether and how any
reforms or revisions to existing rules could unjustly and unreasonably
shift additional costs to customers of load serving entities. These
reforms cannot be successful without ensuring that transmission
providers and customers alike are able to identify the types of
benefits of these transmission facilities can provide and also identify
the beneficiaries that would receive those benefits, along with the
relative proportion of benefits that accrue to each of those
beneficiaries. The failure to account for all the benefits of a
transmission facility while taking into account all the costs of the
transmission facility does not allow for a fair examination of whether
the costs are allocated roughly commensurate with the benefits. We seek
comment on whether ignoring benefits of these transmission facilities
may impair more efficient or cost-effective transmission development by
limiting the number of facilities that overcome the cost-benefit
threshold needed to justify the cost of new transmission, and if so,
what the appropriate standard should be for identifying such benefits.
This potential concern goes to the need to not only identify the types
of benefits of these new transmission facilities, and to quantify those
benefits where possible, but likewise to the need for transparent
methods to calculate benefits and ascertain beneficiaries without being
so burdensome that the methods hinder transmission development. We seek
comment on whether customers of load serving entities should be
required to pay the costs of regional transmission facilities that
provide them only with unquantifiable or purported benefits, or be
required to pay for costs driven by the public policies of state and
local governments in states other than their own.\104\
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\104\ See, e.g., PJM's State Agreement Approach. PJM
Interconnection, L.L.C., 142 FERC ] 61,214, at PP 142-143 (2013),
order on reh'g and compliance, 147 FERC ] 61,128, at P 92 (2014);
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85. Currently, most regional cost allocation methods do not
consider whether a regional transmission facility addresses more than
one category of needs, thereby providing more than one category of
transmission benefits. Specifically, although the regional transmission
planning process considers transmission needs driven by reliability,
economic considerations, and Public Policy Requirements,\105\ these
types of transmission needs are generally considered in a silo from one
another; the cost allocation methods for regional transmission
facilities developed in response to these needs are similarly for the
most part separated by type. We seek comment on whether the result is a
paradigm that may potentially fail to consider the suite of benefits
that transmission facilities provide and therefore fails to allocate
the costs of such facilities roughly commensurate with the benefits.
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\105\ Order No. 1000 left planning and cost allocation for
Public Policy Requirements largely to the discretion of transmission
providers. See supra P 16. Moreover, under PJM's State Agreement
Approach (see supra n.104), the costs of transmission facilities
required to meet the public policy requirements of an individual
state or group of states may not be shifted to customers in other,
non-participating states.
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86. We seek comment as to whether a shift to a more integrated and
holistic process for regional transmission planning and cost allocation
is appropriate. Such a shift may raise novel questions around which
customers should pay for new transmission facilities and concerns about
free riders benefitting from the transmission expansion without paying
for their fair share. Under the potential reforms for which we seek
comment in this ANOPR, the regional transmission planning process would
identify transmission facilities that support future scenarios,
including anticipated future generation, and improve pricing and cost
allocation for interconnection-related network upgrades. In that
scenario, interconnection customers themselves could be considered
beneficiaries of transmission facilities that facilitate their
interconnection, even if those transmission facilities were built prior
to the generators entering the interconnection queue. We seek comment
on whether merely making interconnection customers the beneficiaries
fails to capture all of the relevant types of benefits for purposes of
cost allocation of a regional transmission facility built to
accommodate anticipated future generation. We also seek comment on
whether it may therefore be preferable to consider developing new
regional transmission cost allocation methods that measure all of the
benefits of regional transmission facilities that are being assessed
for potential selection in the regional transmission plan for purposes
of cost allocation and that accrue to both transmission and
interconnection customers.
87. We cannot ignore, of course, that it may be difficult to
precisely quantify some of the benefits of transmission facilities,
which can be a barrier to more broadly allocating the costs of those
facilities among transmission and interconnection customers. Unlike
costs, which are clearly defined and easily quantified, the scope of
which transmission benefits count for purposes of cost allocation, and
how well they need to be documented in order to be allocated to
customers, is a distinct
[[Page 40281]]
challenge to achieving a fair allocation. Requiring transmission
providers to produce overly detailed reports on benefits before the
costs of a transmission facility can be allocated to transmission and
interconnection customers could lead to cost allocations that
undervalue the largest transmission expansions, no matter their
efficiency. The task is in striking the right balance to ensure just
and reasonable rates and the allocation of transmission costs roughly
commensurate with benefits.
88. We also note that, with greater deployment of renewable
resources, and in part to the extent that regions focus on a project-
specific regional transmission cost allocation method, it is possible
that benefits may be distributed unevenly across regions. For example,
there are likely zones or sub-zones within a region that are rich in
renewable resources and therefore have generation significantly in
excess of the local load. These zones, and generators in these zones,
may not be the only beneficiaries of regional transmission facilities
built to access these resources as customers outside those zones may
reap reliability or economic benefits that result from the expanded
transmission system and access to low cost resources. We seek comment
on whether current regional transmission cost allocation approaches may
not adequately address these circumstances and may not provide workable
frameworks for the identification of transmission beneficiaries and
sharing of benefits.
89. We seek comment on whether there should be reforms to cost
allocation in regional transmission planning and cost allocation
processes, including considering potentially a portfolio approach to
assessing regional transmission facilities and consideration of a
minimum set of transmission benefits, while seeking additional
information about cost allocation approaches that may inform such
reforms. Commenters proposing specific changes to cost allocation
should address how such proposals will result in costs being allocated
in a manner roughly commensurate with benefits, and demonstrate that
costs will not be disproportionately borne by any given class of
customers in a manner inconsistent with the requirements of the FPA and
precedent. Commenters should also address how such proposals impact
customers of load serving entities and whether and how proposed new
cost allocation formulae may shift costs to new categories of customers
and whether such cost-shifting is just and reasonable and consistent
with the requirements of the FPA.
c. Potential Reforms and Request for Comment
90. We seek comment on whether broader transmission benefits should
be taken into account when planning the transmission system for
anticipated future generation, and how such benefits should be
identified and quantified. Some transmission providers, e.g., SPP,
MISO, CAISO, and recently the New York Independent System Operator,
Inc. (NYISO), have used broader transmission benefits in selecting
regional transmission facilities for purposes of cost allocation in
their regional transmission planning processes.
91. In addition, under a portfolio approach to regional
transmission cost allocation, multiple transmission facilities are
considered together, and the collective benefits of the transmission
facilities are measured. MISO's MVP and SPP's Balanced Portfolio method
are examples of portfolio approaches to regional transmission cost
allocation. We seek comment on whether a portfolio approach recognizes
that a regional transmission planning process that considers a group of
transmission facilities that collectively provide multiple benefits,
including reliability, economic, and Public Policy Requirements
benefits, among others, may be able to better identify more efficient
or cost-effective transmission facilities when compared to a process
that focuses only on individual transmission facilities or individual
benefits. We seek comment on whether an approach that both estimates
broader transmission benefits for regional transmission facilities
beyond those that are currently considered and that also allocates the
costs for a portfolio of those individual transmission facilities may
provide a cost allocation method that better matches benefits to
burdens over time.\106\ We seek comment on whether such an approach may
also be more accurate or less likely to lead to anomalous results.
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\106\ See BNP Paribas Energy, 743 F.3d at 268-69 (framing the
cost causation principle ``as a matter of making sure that burden is
matched with benefit'').
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92. At the same time, we seek comment on whether there are
circumstances in which the use of criteria other than reliability and
economic considerations may result in projects being selected in the
regional transmission plan for purposes of cost allocation that do not
represent the optimal solution to the reliability or congestion
problems identified and thus may not represent the most efficient or
cost-effective solution for customers of the load serving entities both
inside an RTO/ISO and in non-RTO/ISO region. Any proposals for changes
to planning criteria and cost allocation should consider whether such
proposals result in unjustly and unreasonably shifting costs to
customers. We seek comment on whether the use of planning criteria
beyond reliability and economic considerations may place the burden for
the costs driven by Public Policy Requirements of one state on
customers of load serving entities in non-participating states.
93. We seek comment on the current approaches that transmission
providers take in defining transmission benefits for purposes
transmission planning and cost allocation. For example, we are
interested in how transmission providers calculate adjusted production
costs, the extent to which transmission providers go beyond adjusted
production costs in identifying transmission benefits, the types of
benefits, and the methods for estimating. We also seek comment on the
extent to which it may be challenging, for certain types of benefits,
to identify the beneficiaries for cost allocation purposes. We seek
comment on the extent to which the same set of benefits is currently
used in regional transmission planning processes and their associated
cost allocation processes, or whether some benefits are identified but
not factored into cost allocation. Should the same set of benefits be
used in all processes? If not, would it be appropriate to consider
different benefits during the transmission planning and cost allocation
stages? If so, what would be the basis for doing so?
94. We seek comment on the types of benefits provided by
transmission facilities needed to meet the transmission needs of
anticipated future generation that are relevant for cost allocation
purposes and the manner in which those benefits can be quantified, if
at all. This includes consideration of whether there are transmission
benefits beyond those that transmission providers already take into
account in allocating costs that the Commission should require all
transmission providers to consider for regional transmission
facilities. In other words, should the Commission require transmission
providers to establish a broader set of transmission benefits for
purposes of cost allocation than currently in use and, likewise, should
the Commission adopt a minimum set of transmission benefits that must
be considered? Such benefits could encompass economic benefits (e.g.,
[[Page 40282]]
congestion reduction); resource adequacy benefits (e.g., allowing
imports to replace more expensive local generation, lowering required
planning targets through increased diversity benefits); and reliability
benefits (e.g., avoided or deferred reliability transmission
facilities, improved reserves sharing, increased voltage support). And
to what extent are there benefits that will differ from region-to-
region?
95. If there are types of benefits that cannot be quantified, but
which are real and relevant to allocating the costs of regional
transmission facilities roughly commensurate with benefits, we seek
comment on how transmission providers can document and account for
those benefits in crafting a cost allocation method. Similarly, we seek
comment on whether the inability to precisely quantify benefits of
transmission facilities can be a barrier to the development of those
facilities, particularly those with potentially broad transmission
benefits. If so, we are interested in what types of transmission
facilities are most impacted and what types of benefits are typically
associated with those types of transmission facilities, and how those
benefits can be justified and quantified.
96. To the extent that there are relevant benefits that are
difficult to quantify, we seek comment on ways in which the Commission
can consider whether those benefits are appropriately credited to a
regional transmission facility and accounted for as part of allocating
the costs to beneficiaries. This includes consideration of when
benefits of a transmission facility are sufficiently certain to justify
a commensurately broad cost allocation, especially where those benefits
are not susceptible to precise quantification. We also seek comment on
whether it is appropriate to credit benefits that cannot be credibly
quantified and whether, and if so, how, it is appropriate to factor
such benefits into regional cost allocation.
97. In addition to identifying benefits, we also seek comment on
best practices for identifying the beneficiaries of a transmission
facility. For example, some interconnection-related network upgrades
for generator interconnection may benefit more than a single
interconnecting generator, however the scope (temporal and geographic)
of such beneficiaries may not be clear. We seek comment on the efficacy
and desirability of a regional transmission planning and cost
allocation process that seeks to plan for future scenarios, including
planning for anticipated future generation. What methods for
ascertaining beneficiaries are most effective in allocating the costs
of such facilities roughly commensurate with benefits? Are there
threshold transmission system conditions that would enable the
Commission to reasonably conclude that regional (or some greater or
lesser geographical scope) allocation of costs is appropriate (such as
the amount of congestion or level of interconnectedness in a particular
area)? This necessarily links to our earlier questions about how to
quantify benefits and what level of precision is required.
98. Along the same lines of identifying beneficiaries, we seek
comment on whether the costs of transmission facilities planned in the
regional transmission planning process for which we seek comment in
this ANOPR should be allocated to both transmission and interconnection
customers. As explained earlier, we are concerned about potential free-
rider problems associated with interconnection customers that later
connect to transmission facilities planned for anticipated future
generation. We are therefore interested in approaches to cost
allocation to ensure that both transmission and interconnection
customers that benefit from those facilities pay their fair share.
While we propose to potentially reform participant funding by
interconnection customers of interconnection-related network upgrades,
we are also considering how best to allocate costs of regional
transmission facilities to interconnection customers (e.g., whether
cost allocation methods for regional transmission facilities should
allocate a portion of the costs of a regional transmission facility
directly to interconnection customers based on, for example, the
capacity of the interconnection customer's generating facility).
99. We seek comment on the cost effectiveness of the reforms
discussed herein. If the regional transmission planning and cost
allocation processes are to consider transmission needs driven by
anticipated future generation, is there a tradeoff between facilitating
the construction of transmission facilities that are needed to connect
such anticipated future generation, and ensuring against building more
transmission than is necessary? If so, how should the Commission
approach that tradeoff?
3. Participant Funding and Crediting Policy for Funding
Interconnection-Related Network Upgrades
100. Since the issuance of Order No. 2003, the composition of the
generation fleet has rapidly shifted from predominately large,
centralized resources to include a large proportion of smaller
renewable generators that, due to their distance from load centers,
often require extensive interconnection-related network upgrades to
interconnect to the transmission system. The significant
interconnection-related network upgrades necessary to accommodate
geographically remote generation are a result that the Commission did
not contemplate when it established the interconnection pricing policy
for interconnection-related network upgrades. Because the large-scale
changes since Order No. 2003 may have impacted the underlying rationale
for the interconnection pricing policy, we seek comment on whether the
Commission should modify the participant funding and crediting
policies, as discussed in further detail below.
a. Background
i. Original Rationale for the Order No. 2003 Interconnection-Related
Network Upgrade Funding Requirements
101. As discussed above, the Commission in Order No. 2003 described
two general approaches for assigning the costs of interconnection-
related network upgrades needed to interconnect a generating facility
to the transmission system: (1) the crediting policy, whereby the
interconnection customer initially funds the interconnection-related
network upgrades and is reimbursed through transmission credits; \107\
and (2) participant funding, where the costs of interconnection-related
network upgrades in RTOs/ISOs are assigned directly to the
interconnection customer. Central to discussions of the Commission's
interconnection-related network upgrade funding requirements is Order
No. 2003's continued prohibition of ``and'' pricing. This prohibition
provides that, when ``a Transmission Provider must construct
[[Page 40283]]
[interconnection-related] Network Upgrades to provide new or expanded
transmission service, the Commission generally allows the Transmission
Provider to charge the higher of the embedded costs of the Transmission
System with expansion costs rolled in, or incremental expansion costs,
but not the sum of the two.'' \108\ The Commission also explained that
allowing the transmission provider to charge either the higher of an
embedded cost rate for transmission service or an incremental rate
designed to recover the cost of the interconnection-related network
upgrades ``provides the Transmission Provider with a cost recovery
mechanism that ensures that native load and other transmission
customers will not subsidize service to the Interconnection Customer.''
\109\
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\107\ Order No. 2003-B states that ``the period for
reimbursement may not be longer than the period that would be
required if the Interconnection Customer paid for transmission
service directly and received credits on a dollar-for-dollar basis,
or 20 years [from the generating facility's commercial operation
date], whichever is less.'' Order No. 2003-B, 109 FERC ] 61,287 at
PP 3, 36. If credits have not fully reimbursed the upfront payment
within 20 years, Order No. 2003 requires ``a balloon payment'' at
the end of year 20. Id. P 36. The crediting policy also requires
that affected system operators provide credits for transmission
service taken on an affected system. Id. P 42. Even if the
interconnection customer does not take transmission service over the
affected system, however, the affected system operator must still
provide the 20-year balloon payment to refund any remaining balance
to the interconnection customer. Order No. 2003-C, 111 FERC ] 61,401
at P 13.
\108\ Order No. 2003, 104 FERC ] 61,103 at n.111.
\109\ Order No. 2003-A, 106 FERC ] 61,220 at P 613.
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(a) Crediting Policy
102. The Commission instituted the crediting policy to achieve
multiple objectives. First, the Commission found that this policy would
avoid prohibited ``and'' pricing for interconnection-related network
upgrades because it ensures that the interconnection customer will not
be charged twice for the use of the transmission system by paying both
for the incremental cost of the upgrade and an embedded-cost rate (with
the cost of that interconnection-related network upgrade rolled in) for
use of the transmission system.\110\ Also, the Commission stated that
the crediting policy was intended to facilitate the efficient
construction of interconnection-related network upgrades and enhance
competition in bulk power markets by promoting the construction of new
generation \111\ Furthermore, the Commission found that the crediting
policy would ensure comparable treatment for interconnection customers
that are not affiliated with the transmission provider, as transmission
providers traditionally roll the costs of interconnection-related
network upgrades associated with their own generating facilities into
their transmission rates.\112\
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\110\ Order No. 2003, 104 FERC ] 61,103 at P 694.
\111\ Id. PP 612, 694.
\112\ Id. P 694.
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103. Additionally, in Order No. 2003-A, the Commission stated that
it does ``not believe that the costs of [interconnection-related]
Network Upgrades required to interconnect a Generating Facility to the
Transmission System of a non-independent Transmission Provider are
properly allocable to the Interconnection Customer through direct
assignment because upgrades to the transmission grid benefit all
customers.'' \113\ The Commission also stated that the crediting policy
has a two-fold purpose. First, by providing the transmission provider
with a source of funds to construct the interconnection-related network
upgrades, the upfront payment by the interconnection customer
alleviates any delay that might result if the transmission provider
were forced to secure funding elsewhere. Second, by placing the
interconnection customer initially at risk for the full cost of the
interconnection-related network upgrades, the upfront payment provides
the interconnection customer with a strong incentive to make efficient
siting decisions and, in general, to make good faith requests for
interconnection service.\114\
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\113\ Order No. 2003-A, 106 FERC ] 61,220 at P 212. As noted in
the discussion below on participant funding, the Commission has
allowed direct assignment of interconnection-related network upgrade
costs to generators interconnecting to independent transmission
providers such as RTOs/ISOs.
\114\ Id. P 613.
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104. In NARUC v. FERC,\115\ multiple petitioners challenged the
crediting policy established in Order No. 2003. The petitioners argued
that the crediting policy was inconsistent with the cost causation
principle because they disagreed with the Commission's conclusions that
``[interconnection-related] Network Upgrades benefit the entire
network,'' \116\ and therefore, all transmission customers should
essentially pay for those interconnection-related network upgrades
through the crediting policy.\117\ The U.S. Court of Appeals for the
District of Columbia Circuit (D.C. Circuit) agreed with the
Commission's position and noted that the D.C. Circuit had previously
``endorsed the approach of `assign[ing] the costs of system-wide
benefits to all customers on an integrated transmission grid.' '' \118\
---------------------------------------------------------------------------
\115\ 475 F.3d 1277.
\116\ Id., 475 F.3d at 1285.
\117\ Id. (citing Pub. Serv. Co. of Colo., 62 FERC ] 61,013, at
61,061 (1993)).
\118\ Id. (citing W. Mass. Elec. Co. v. FERC, 165 F.3d 922, 927
(DC Cir. 1999)).
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(b) Participant Funding
105. In Order No. 2003, the Commission stated that ``under the
right circumstances, a well-designed and independently administered
participant funding policy for [interconnection-related] Network
Upgrades offers the potential to provide more efficient price signals
and a more equitable allocation of costs than the crediting approach.''
\119\ Therefore, the Commission stated that it would provide RTOs/ISOs
with the flexibility to propose participant funding for
interconnection-related network upgrades for a generator
interconnection.\120\ In accordance with this flexibility, the
Commission did not prescribe specific policies for RTOs/ISOs but
instead provided them with the flexibility to adopt policies of their
own choosing, subject to Commission approval.\121\ Over time, each RTO/
ISO sought, and the Commission accepted, independent entity variations
to adopt some form of participant funding rather than the crediting
policy.
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\119\ Order No. 2003, 104 FERC ] 61,103 at P 695.
\120\ Id. P 28.
\121\ Order No. 2003-A, 106 FERC ] 61,220 at P 696.
---------------------------------------------------------------------------
106. The Commission expressed its willingness to consider a well-
designed participant funding approach in response to commenter concerns
that the crediting policy ``mutes somewhat the Interconnection
Customer's incentive to make an efficient siting decision that takes
new transmission costs into account, and it provides the
Interconnection Customer with what many view as an improper subsidy,
particularly when the Interconnection Customer chooses to sell its
output off-system.'' \122\ Additionally, while the Commission mandated
the crediting policy for non-independent transmission providers, Order
No. 2003 acknowledged that the concerns that gave rise to the adoption
of the crediting policy do not apply to RTOs/ISOs. For example, Order
No. 2003 noted that ``a number of aspects of the `but for' approach are
subjective, and a Transmission Provider that is not an independent
entity has the ability and the incentive to exploit this subjectivity
to its own advantage'' by, for example, finding ``that a
disproportionate share of the costs of expansions needed to serve its
own power customers is attributable to competing Interconnection
Customers.'' \123\ In contrast, however, the Commission noted that RTOs
and ISOs are independent, and neither own nor have affiliates that own
generating facilities and thus do not have an incentive to discourage
new generation by competitors.\124\
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\122\ Order No. 2003, 104 FERC ] 61,103 at P 695.
\123\ Id. n.111.
\124\ Order No. 2003-A, 106 FERC ] 61,220 at P 691.
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107. The Commission also explained that participant funding might
speed up the development of new transmission infrastructure. In
particular, Order No. 2003 postulated that ``participant
[[Page 40284]]
funding of [interconnection-related network] upgrades may provide the
pricing framework needed to overcome the reluctance of incumbent
Transmission Owners in many parts of the country to build transmission,
with the result that badly needed transmission infrastructure could be
put in place quickly.'' \125\
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\125\ Order No. 2003, 104 FERC ] 61,103 at P 703.
---------------------------------------------------------------------------
108. RTOs/ISOs that have adopted a participant funding approach do
not reimburse interconnection customers with transmission service
credits for the cost of the interconnection-related network upgrades.
Instead, the Commission allowed interconnection customers to receive
well-defined capacity rights that are created by the interconnection-
related network upgrades.\126\ As an example, the Commission in Order
No. 2003 pointed to PJM Firm Transmission Rights and Capacity
Interconnection Rights, which, it stated, are ``created by the
[interconnection-related] Network Upgrades for which the
Interconnection Customer pays, and they are well-defined, long-term and
tradeable.'' \127\ The Commission stated that provision of such ``well-
defined capacity rights'' in lieu of credits does not violate the
prohibition of ``and'' pricing because the ``Interconnection Customer
pays separate charges for separate services,'' namely ``an access
charge for transmission service that may involve an obligation to pay
congestion charges, and in exchange for its `but for' payment, [the
interconnection customer] receives these well-defined capacity rights,
which provide some protection for having to actually pay the congestion
charges.'' \128\
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\126\ Id. P 700.
\127\ Id.
\128\ Id.
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109. Commission precedent makes clear that the purpose of providing
``well-defined'' rights is not to provide full reimbursement for the
costs of interconnection-related network upgrades. In fact, where an
RTO/ISO adopts a participant funding approach for interconnection-
related network upgrades required to interconnect an interconnection
customer, there is no requirement that the capacity rights being
awarded for interconnection-related network upgrades have equal value
to the cost of the interconnection-related network upgrades because the
costs would not exist ``but for'' the proposed interconnection and are
simply part of a project's construction costs and business risk that
the interconnection customer must consider.\129\ Moreover, RTOs/ISOs
are ``not required to provide transmission capacity rights where . . .
the network upgrades create no additional transmission capability.''
\130\ To this point, the Commission in Old Dominion Electric
Cooperative v. PJM Interconnection, L.L.C. explained that, while Order
No. 2003 ``stated that generation interconnection customers would
receive capacity rights, those statements were based on the assumption
that a network upgrade provided by an interconnection customer would
create additional transmission capability beyond that needed to simply
interconnect with the grid.'' \131\
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\129\ PJM Interconnection, L.L.C., 108 FERC ] 61,025, at P 20
(2004); see also Midwest Indep. Transmission Sys. Operator, Inc.,
114 FERC ] 61,106, at P 66 (2006).
\130\ Old Dominion Elec. Coop. v. PJM Interconnection, L.L.C.,
119 FERC ] 61,052, at P 18 (2007) (ODEC v. PJM).
\131\ ODEC v. PJM, 119 FERC ] 61,052 at P 18; see also id. P 16
(``Not every system upgrade required simply to interconnect a
generating facility safely to the grid entitles the generator to
capacity rights; however, a generation interconnection customer
would be `allowed to receive' capacity rights if a [interconnection-
related] network upgrade creates additional transmission
capability.'').
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110. Again, each RTO/ISO sought an independent entity variation to
adopt a participant funding approach rather than adopt the crediting
policy. In MISO, an interconnection customer is responsible for 100% of
interconnection-related network upgrade costs, with a possible 10%
reimbursement or ``crediting'' for interconnection-related network
upgrades that are 345 kV and above.\132\ In CAISO, the interconnection
customer's cost responsibility for a particular interconnection-related
network upgrade depends on how CAISO classified the interconnection-
related network upgrade (i.e., whether the interconnection-related
network upgrade is considered area, local, or reliability) and the
interconnection-related network upgrade's deliverability status (e.g.,
full capacity, partial capacity, or energy-only).\133\ In CAISO, full
cash reimbursement is only available for the costs of certain
categories of interconnection-related network upgrades, up to $60,000
per MW of installed generation capacity, and interconnecting generators
receive congestion revenue rights in exchange for funding any upgrades
that are not eligible for cash reimbursement. SPP, NYISO, PJM, and ISO-
New England, Inc. use a participant funding approach where the
transmission provider assigns 100% of the interconnection-related
network upgrade costs to the interconnection customer and the
interconnection customer may receive compensation through transmission
capacity rights.\134\
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\132\ See, e.g., Midcontinent Indep. Sys. Operator, Inc., 164
FERC ] 61,158, at P 5 (2018) (``MISO's Interconnection Customer
Funding Policy . . . requiring the interconnection customer to
`participant fund' 90-100 percent of its [interconnection-related]
network upgrades . . . was accepted, under the Order No. 2003
independent entity variation standard in 2009.''); Midwest Indep.
Transmission Sys. Operator, Inc., 129 FERC ] 61,060, at P 8 (2009)
(accepting MISO's ``proposed change [that] would result in the
interconnection customer bearing 100 percent of the costs of
[interconnection-related] network upgrades rated below 345 kV and
bearing 90 percent of the costs of [interconnection-related] network
upgrades rated at 345 kV and above (with the remaining 10 percent
being recovered on a system-wide basis'')); Midwest Indep. Trans.
Sys. Operator, Inc., 114 FERC ] 61,106, at P 62 (2006).
\133\ Cal. Indep. Sys. Operator Corp., 140 FERC ] 61,070, at PP
24-27 (2012).
\134\ PJM Interconnection, L.L.C., 108 FERC ] 61,025 (2004); Sw.
Power Pool, Inc., 127 FERC ] 61,283 (2009); Sw. Power Pool, Inc.,
171 FERC ] 61,272 (2020); N.Y. Indep. Sys. Operator, Inc., 108 FERC
] 61,159 (2004), order on reh'g, 111 FERC ] 61,347 (2005); ISO New
Eng. Inc., 133 FERC ] 61,229 (2010).
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b. Potential Need for Reform
i. Participant Funding
111. Since the issuance of Order No. 2003, changing circumstances
have cast doubt on whether it continues to be just and reasonable to
provide RTOs/ISOs with the flexibility to adopt participant funding
approaches for interconnection-related network upgrades. We seek
comment on whether these developments suggest that the allowance of
participant funding for interconnection-related network upgrades, both
as a concept and in its application, may no longer be just and
reasonable. Moreover, it appears that the incentives created by
participant funding in this context may produce outcomes that are
counter to the Commission's intentions in allowing flexibility for
RTOs/ISOs to adopt participant funding in Order No. 2003.
112. To begin with, participant funding may allocate the costs of
extensive interconnection-related network upgrades entirely to
interconnection customers without accounting for the significant
benefits that these interconnection-related network upgrades may
provide to transmission customers. As a result, there are circumstances
where this allocation of interconnection-related network upgrade costs
may not be roughly commensurate with the distribution of benefits. For
instance, a large interconnection-related network upgrade built on a
consistently congested portion of the transmission system may provide
significant
[[Page 40285]]
economic and reliability benefits to transmission customers. Also,
transmission customers, in some instances, can make use of any excess
transmission capacity created by a participant funded interconnection-
related network upgrade without paying any of the capital costs that
are paid for through a participant funding approach. Allowing
transmission customers to receive the benefits of interconnection-
related network upgrades without paying for a proportionate share of
their costs is an example of the ``free rider'' problem that the
Commission's ``beneficiary pays'' cost causation principle is supposed
to avoid.\135\
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\135\ See, e.g., Order No. 1000-A, 139 FERC ] 61,132 at P 562
(``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.'').
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113. Furthermore, while the interconnection customer may receive
well-defined capacity rights associated with the increased transfer
capability caused by the interconnection-related network upgrade, these
well-defined capacity rights do not compensate the interconnection
customer for the broad range of benefits that the interconnection-
related network upgrades can provide to the transmission system and
therefore do not solve the ``free rider'' problem. This is because the
well-defined capacity rights do not capture reductions in congestion
costs paid by transmission customers that were the result of the
expansion of the transfer capability created by the interconnection-
related network upgrade; nor do they capture transmission service
charges for use of the excess capacity created by the interconnection-
related network upgrade. Instead, well-defined capacity rights capture
congestion costs paid by transmission customers on a going forward
basis across the relevant transmission path on which the
interconnection-related network upgrade increased transmission
capacity. To the extent that the interconnection-related network
upgrade may have eliminated most of the ex ante congestion on the
relevant paths, the transmission customers that transact across such
paths and have their congestion costs reduced as a result of the large
interconnection-related network upgrade now in service will receive
this benefit for free in most cases.
114. We seek comment on whether costs allocated to interconnection
customers pursuant to participant funding approaches have increased
over time, and if so, why. We seek comment on whether this increase in
costs is evidence that regional transmission planning processes are not
building adequate transmission system capacity. We seek comment on
whether the Commission's policies on participant funding have impacted
the interconnection queue, e.g., through late-state withdrawals, and if
so, how and to what degree. In the case that there are late-stage
withdrawals from the interconnection queue, we seek comment on the
ability of transmission providers to efficiently process
interconnection requests from other interconnection customers affected
by the withdrawal. Finally, we seek comment on whether uncertainty
regarding interconnection costs drives up the cost of developing supply
resources and thereby ultimately increases the cost of electricity
supply for customers.
115. Participant funding also may create a separate incentive for
the interconnection customer that may undermine the development of
interconnection-related network upgrades that produce greater benefits.
Specifically, the interconnection customer, knowing that it will be
responsible for all interconnection-related network upgrade costs, is
likely to strongly oppose any addition or modification to the
transmission system beyond what is necessary to support its own
interconnection, even if such additions and modifications may
ultimately benefit it and others by providing improved reliability or
economic outcomes.\136\
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\136\ See Review of Generator Interconnection Agreements and
Procedures, Technical Conference Transcript, Docket No. RM16-12-000
at Tr: 193: 20-24 (Steve Naumann, Exelon) (filed Aug. 23, 2016)
(``[Y]ou need to also deal with the [interconnection] customer who
says, `Okay, I will be perfectly willing to take the risk, but I
don't want to pay for a single upgrade more than I have to [to] have
a the reliability interconnection.'').
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116. An additional rationale that the Commission provided in Order
No. 2003 for allowing participant funding was the concern that the
interconnection crediting policy would ``mute somewhat the
Interconnection Customer's incentive to make an efficient siting
decision that takes transmission costs into account.'' \137\ The
Commission in Order No. 2003 also found that participant funding in
RTOs/ISOs is consistent with the policy of promoting competitive
wholesale markets because it causes the interconnection customer to
face the same marginal cost price signal that it would face in a
competitive market.\138\ We seek comment on whether to reconsider these
findings in light of current circumstances.
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\137\ Order No. 2003, 104 FERC ] 61,103 at P 695.
\138\ Id. P 702.
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117. We note, for instance, that the Commission's view of efficient
siting of generation in Order No. 2003 was from a transmission costs
perspective, i.e., which points of interconnection would require the
least expensive interconnection-related network upgrades. We seek
comment on whether this perspective may be at odds with the primary
siting considerations for renewable generation developers decades
later. That is, interconnection at locations where renewable generation
may experience higher efficiency factors (e.g., because they have
abundant wind or sun) may still be uneconomic where participant funding
applies because the costs of interconnection-related network upgrades
for that location may be significant and would not be allocated beyond
the interconnection customer. We seek comment on whether
interconnection at such locations may be considered economic, however,
if the cost of the interconnection-related network upgrades were
allocated more broadly among those that benefit. Thus, because the
price signal participant funding sends does not account for the broader
economic efficiencies from siting renewable generation in fuel-rich
areas, it can instead encourage the development of renewable generation
in less productive locations. Because increased renewable resource
penetration in RTOs/ISOs is likely to continue, it may make less sense
to retain a policy that encourages renewable developers to develop
lower quality, less dependable renewable resources.
118. Further, given the uncertainty created by the RTO/ISO queue
backlogs and cascading interconnection-related network upgrade cost
allocations that move from withdrawing higher-queued interconnection
customers to lower-queued interconnection customers, participant
funding may no longer provide efficient price signals that allow
generators to act freely to achieve the desirable level of entry of new
cost-effective generating capacity. We understand that a contributing
factor to the interconnection queue backlog is a tendency by
interconnection customers to submit multiple interconnection requests
at different points of interconnection, with the intention of
discovering the lowest cost site for a
[[Page 40286]]
project (from an interconnection perspective), and then withdrawing
higher-cost projects from the queue later in the process. This tendency
can require numerous restudies and reallocation of interconnection-
related network upgrade costs, compounding the uncertainty surrounding
the amount of interconnection-related network upgrade costs that will
be attributable to viable projects as the queue progresses.
119. We seek comment on whether it is appropriate to eliminate or
reduce participant funding for interconnection-related network upgrades
in RTOs/ISOs and whether any specific proposed changes to
interconnection funding mechanisms allocate costs in a manner roughly
commensurate with benefits and are otherwise consistent with the
Commission's authority under the FPA and do not unjustly or
unreasonably shift costs to customers of load serving entities.
ii. Crediting Policy
120. We seek comments on whether we should revisit the crediting
policy in all regions by requiring that transmission providers, instead
of interconnection customers, fund upfront all or a portion of the
interconnection-related network upgrade costs. We describe multiple
variations of this proposal below. Some generation developers may find
it difficult to provide upfront funding for the costs of network
upgrades when the reimbursement period can be as long as 20 years.
Accordingly, we seek comment on whether the current approach may
unjustly and unreasonably allocate significant financing costs for
interconnection-related network upgrades to interconnection customers
when the benefits of the interconnection-related network upgrades
accrue to the broader system. We seek comment on whether, if
interconnection-related network upgrade costs are increasing on
average, it is possible that these upfront funding costs may pose an
unjust and unreasonable barrier to entry for generation developers.
Given these considerations, below we seek comment on some potential
reforms to the crediting policy.
c. Potential Reforms and Request for Comment
121. We seek comment on whether the Commission should eliminate the
independent entity variations that allow RTOs/ISOs to use participant
funding for interconnection-related network upgrades. We also seek
comment on potential approaches for modifying or replacing the existing
crediting policy for the costs of interconnection-related network
upgrades in all regions. We seek comment on these options and invite
alternative suggestions by commenters that take into consideration the
concerns discussed above.
122. Additionally, for each of the reforms contemplated below, we
seek comment on whether there are articulable and plausible reasons to
believe that these reforms would allocate the costs of interconnection-
related network upgrades in a manner that is at least roughly
commensurate with the benefits of those interconnection-related network
upgrades and that do not unjustly and unreasonably shift costs to
customers of load serving entities or are otherwise inconsistent with
the Commission's statutory authority.
i. Eliminate Participant Funding for Interconnection-Related Network
Upgrades
123. We seek comment on whether participant funding of
interconnection-related network upgrades may be unjust and
unreasonable. We seek comment on whether RTOs/ISOs with previously
approved independent entity variations that directly assign some or all
the cost responsibility for interconnection-related network upgrades to
interconnection customers should be required to revise their tariffs to
remove the participant funding of interconnection-related network
upgrade requirements and instead implement the crediting policy as
prescribed in the pro forma LGIA.
124. The potential proposal to eliminate participant funding of
interconnection-related network upgrades in RTOs/ISOs would recognize,
however, that simply because an interconnection request makes an
interconnection-related network upgrade necessary for interconnection
(and in that sense, ``causes'' the need for interconnection-related
network upgrades that would not be needed ``but for'' an
interconnection request), an interconnection-related network upgrade
may sufficiently benefit transmission customers that it is appropriate
to allocate the interconnection-related network upgrade costs more
broadly. Also, this potential proposal could address the free rider
problem that is created by participant funding of interconnection-
related network upgrades. We note, however, that the specific proposal
is to eliminate participant funding and replace it with the crediting
policy, a pricing approach that still requires interconnection
customers to initially fund interconnection-related network
upgrades.\139\ Moreover, no potential reform presented here would
modify the existing requirement that an interconnection customer bear
cost responsibility for the interconnection facilities that would not
be needed but for its interconnection request.
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\139\ As noted below, however, we are exploring reforms to the
existing crediting policy approach (that could be adopted alone or
in combination with the elimination of participant funding) that
could reduce the level of upfront funding to be provided by the
interconnection customers.
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125. We seek comment on whether the removal of participant funding
of interconnection-related network upgrades may also have the potential
to increase integration of generation by removing the possibly
prohibitive cost assignment that participant funding can place on some
interconnection customers. Furthermore, it may reduce cost uncertainty
to those resources in the interconnection queue, and by extension,
increase the likelihood that an interconnection request will result in
a developed generating facility.\140\
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\140\ See, e.g., Review of Generator Interconnection Agreements
and Procedures, Technical Conference Transcript, Docket No. RM16-12-
000, at Tr. 25: 8-15 (May 13, 2016) (Dean Gosselin, NextEra) (filed
Aug. 23, 2016) (``I'd like to just talk about what is optimal . . .
as a developer . . . trying to advance [a project] to fruition . . .
. I would say for the interconnection queue that the initial results
closely match final results in a defined and reasonable timeline,
that would be my definition.''); id. at 134:5-7 (Omar Martino, EDF
Renewable Energy) (``[C]osts can change dramatically between [the]
system impact and [the] facility study.'').
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126. Additionally, we seek comment on whether eliminating
participant funding may reduce the queue backlogs that plague many
regions because interconnection customers would have less incentive to
submit multiple interconnection requests in an attempt to lower their
interconnection costs, and may no longer drop out of interconnection
queues at late stages due to unforeseen interconnection-related network
upgrade cost increases. To these points, we seek comment on the number
of interconnection requests that have withdrawn from the queue because
the direct assignment of significant interconnection-related network
upgrade costs made otherwise viable interconnection requests
uneconomic.
127. We seek comment on whether the independent entity variation
granted to RTOs/ISOs in Order No. 2003 is no longer just and
reasonable. In general, we seek comment on whether the incentives
created by participant funding of interconnection-related network
upgrades in RTOs/ISOs may produce outcomes that are counter to the
Commission's transmission planning and cost allocation efforts.
[[Page 40287]]
128. We are aware that there could be complications associated with
implementing the crediting policy in RTOs/ISOs with zonal transmission
rates that do not occur outside RTOs/ISOs. Outside RTOs/ISOs, a single
transmission provider owns and operates its transmission system and
generally charges a single rate for the entire system, regardless of
the specific transmission customer's location. In contrast, an RTO/ISO
operates the combined transmission assets of multiple transmission
owners within its footprint at non-pancaked transmission rates, and
generally has separate transmission pricing zones. The transmission
rates for each zone are generally designed to recover the costs of
transmission facilities located within each zone. As a result, we seek
comment on whether simply applying the crediting policy currently used
outside RTOs/ISOs in RTOs/ISOs may disproportionately increase the
burden to the native load of transmission zones where large amounts of
interconnection-related network upgrades are constructed to facilitate
the interconnection of location-constrained resources, which ultimately
may benefit the entire RTO/ISO footprint.
129. Under a crediting policy in an RTO/ISO, there may be a need
for an appropriate mechanism to reimburse the interconnection
customers, including a mechanism for determining which transmission
owner(s) or zonal transmission rates will include the interconnection-
related network upgrade costs. For example, there is a question of
whether it would be just and reasonable to allocate the costs only
within the transmission zone where the interconnection-related network
upgrade is located or more broadly to multiple transmission zones.\141\
We therefore seek comment on how to implement the crediting policy in
RTOs/ISOs and what principles should be used to guide the application
of the crediting policy in RTOs/ISOs.
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\141\ See, e.g., Interstate Power & Light Co. v. ITC Midwest,
LLC, 144 FERC ] 61,052, at P 40 (2013), order on reh'g,
clarification and compliance, 146 FERC ] 61,113 (2014). See also Sw.
Power Pool, Inc., 127 FERC ] 61,283, at P 5 (2009).
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130. Finally, given the concerns about the free-rider problem and
whether the ``well-defined capacity rights'' received by
interconnection customers capture the benefits the interconnection-
related network upgrades provide to the system, we seek comment on: (1)
The value of the ``well-defined capacity rights'' that interconnection
customers have received for funding interconnection-related network
upgrades; and (2) the value of the benefits that interconnection-
related network upgrades have provided to the system, such as the value
of congestion relieved by interconnection-related network upgrades. We
are also interested in any other concerns related to the ``well-defined
capacity rights'' that interconnection customers receive and the
ability of these ``well-defined capacity rights'' to reflect the value
of the full incremental capacity and congestion benefits added to the
transmission system by the interconnection-related network upgrades.
ii. Revisions to the Existing Crediting Policy
131. We seek comment on possible revisions to the Order No. 2003
interconnection crediting policy, which requires that interconnection
customers provide upfront funding for interconnection-related network
upgrades and receive reimbursement through transmission service credits
or a balloon payment after 20 years. We enumerate multiple proposals
below. Not all of these proposals are mutually exclusive, and some
could be implemented in tandem.
(a) Transmission Providers Provide Upfront Funding for All
Interconnection-Related Network Upgrades
132. Pursuant to this potential proposal, each transmission
provider would provide upfront funding for all the interconnection-
related network upgrades on its transmission system. Then, once such an
interconnection-related network upgrade is in service, the transmission
provider would be able to include the cost of that interconnection-
related network upgrade in its transmission service rate base and
recover a return on, and of, the network upgrade capital costs through
the cost-of-service transmission rates in its OATT. Thus,
interconnection customers that take transmission service on a
transmission system would still pay for a portion of interconnection-
related network upgrades through transmission rates. We seek comment on
(1) this approach and (2) how this approach could be implemented in a
just and reasonable manner.
133. This option would reduce the initial financing burden that
interconnection customers currently may encounter when significant
interconnection-related network upgrades are required for their
interconnection request. Furthermore, this option may increase
generator competition by lowering barriers to entry, which in turn will
benefit customers by creating a more competitive market for energy.
134. There may also be additional efficiency benefits to removing
the crediting policy because the financing of interconnection-related
network upgrades would follow the same financing process that the
transmission owners apply to the other transmission infrastructure that
they fund and build on their system. That is, there could be an
efficiency gain from using one financing process for all transmission
system facilities instead of the existing two: one for interconnection-
related network upgrades and another for other transmission system
facilities. In addition to that particular inefficiency, under the
current crediting approach applied in non-RTO/ISO regions, each
interconnection-related network upgrade is financed twice--initially by
the interconnection customer and then again by the transmission
provider when the interconnection customer receives credits as it takes
transmission service or receives a balloon payment after 20 years.
Without the initial funding by the interconnection customer,
interconnection-related network upgrades would only need to be financed
once.
(b) Interconnection Customers Contribute to the Upfront Funding of
Interconnection-Related Network Upgrades Through a Fee
135. Another possible reform to the current crediting policy is to
consider the establishment of a non-refundable fee to be charged for
submitting an interconnection request and that is not reimbursable
through transmission service credits. Under this approach, an
appropriate fee should not be so large that it creates barriers to
entry for smaller developers. Potential benefits of this type of fee
could include: (1) Defraying some of the cost to transmission customers
for interconnection-related network upgrades and therefore decreasing
the overall impact on transmission customers of the related potential
reform to eliminate participant funding of interconnection-related
network upgrades in RTOs/ISOs; (2) discouraging the submission of
speculative interconnection requests; and (3) for some variable fees,
providing a price signal to interconnection customers that could incent
efficient siting decisions where possible. We seek comment on (1)
whether to impose a non-refundable, non-reimbursable fee on each
submitted interconnection request and (2) how this approach could be
implemented in a just and reasonable manner.
[[Page 40288]]
136. We seek comment on two specific versions of this approach.
First, we seek comment on the potential establishment of a fixed fee
applied to each interconnection request, which would be the same for
all interconnection requests, irrespective of the generating facility's
capacity or project location. We seek comment on whether establishing a
fixed fee would be appropriate and, if so, the appropriate amount of
such a fee.
137. Second, we seek comment on the potential establishment of a
variable fee applied to each interconnection request. The amount of the
variable fee could depend upon the generating facility capacity
associated with the interconnection request and/or the identified
interconnection-related network upgrades. For example, the fee could be
based on a percentage of the estimated interconnection-related network
upgrade costs or be calculated based on the generating facility
capacity and/or the voltage rating of the interconnection-related
network upgrade. We seek comment on the appropriate size of this fee
and the structure of the fee, if the Commission were to require one. We
also seek comment on whether it is possible to use a percentage of
interconnection-related network upgrade cost estimates for this fee,
and if so, at which point in the generator interconnection process a
transmission provider would calculate that cost.
138. Finally, we seek comment on whether such a fee should be
established at the outset of the generator interconnection process, or
whether an escalating fee should be imposed as the interconnection
request moves through the study process. For example, a smaller fee
could be required for entry into the feasibility study phase, with a
larger fee for the system impact study phase and the largest fee
required to enter the facilities study.\142\ In this manner,
speculative projects could be discouraged from entering the later
stages of the generator interconnection process, while still allowing
interconnection customers to use the feasibility study process as it
was designed, to determine project feasibility for a broader range of
project sizes and locations.
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\142\ These non-refundable fees would be in addition to, and
distinct from, the initial deposit submitted with an interconnection
request and study deposits that are applied toward an
interconnection customer's interconnection study costs.
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(c) Transmission Providers Provide Upfront Funding for Only Higher
Voltage Interconnection-Related Network Upgrades
139. We seek comment on whether it would be appropriate to require
transmission providers to fund upfront the costs of any
interconnection-related network upgrade that is rated at or above a
certain voltage threshold. Interconnection customers would be
responsible for upfront funding the cost of interconnection-related
network upgrades below that threshold and be reimbursed through
transmission service credits pursuant to the crediting policy.
140. Because higher voltage transmission facilities tend to produce
greater and broader benefits to transmission systems than lower voltage
transmission facilities, this option may better satisfy the requirement
that the allocation of costs be at least roughly commensurate with the
distribution of benefits.\143\ Thus, where an interconnection-related
network upgrade's voltage exceeds a defined threshold and is likely to
produce system-wide benefits, it may be appropriate to require that
transmission providers fund the costs of such interconnection-related
network upgrades upfront.
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\143\ See, e.g., Old Dominion Elec. Coop. v. FERC, 898 F.3d
1254, 1260 (D.C. Cir. 2018) (adopting Commission finding that
``high-voltage power lines produce significant regional benefits'').
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141. The Commission could also adopt a modified version of this
approach by requiring transmission providers to upfront fund the
portion of the costs of higher voltage interconnection-related network
upgrades that exceeds a pre-determined cost threshold. For example, the
Commission could require transmission providers to upfront fund the
costs of a 345 kV interconnection-related network upgrade that exceed
$10 million. Pursuant to this modified version, in this example of a
345 kV interconnection-related network upgrade, the Commission would
require the interconnection customer to fund all network upgrade costs
up to $10 million and require the transmission provider to provide
upfront funding for all interconnection-related network upgrade costs
above the $10 million threshold. Even in this situation, however, the
transmission provider would still have to provide transmission service
credits to reimburse the interconnection customer for its $10 million
subject to the crediting policy.
142. We note that the Commission has approved a version of this
cost sharing approach in MISO, albeit in the context of responsibility
for payment of interconnection-related network upgrade costs themselves
and not just the upfront funding of them as discussed here. MISO's
tariff provides for some cost sharing for interconnection-related
network upgrades under which transmission providers recover the costs
of 10% of interconnection-related network upgrades rated 345 kV and
above on a system-wide basis while directly assigning through
participant funding 90% of the costs of such upgrades to the
interconnection customer whose interconnection required the network
upgrade.\144\ Furthermore, on multiple occasions, the Commission has
permitted RTOs/ISOs to define different transmission facility
categories and adopt different cost allocation methods for transmission
facilities based on the transmission facility's voltage threshold.\145\
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\144\ MISO Tariff, Attach. FF (Transmission Expansion Planning
Protocol), Section III.A2.d (81.0.0).
\145\ See Midcontinent Indep. Sys. Operator, Inc., 172 FERC ]
61,095 (2020) (accepting MISO's proposal to change the qualifying
voltage threshold for a certain class of project from 345 kV to 230
kV).
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143. If the Commission were to split the upfront funding
responsibility for interconnection-related network upgrades between the
transmission provider and the interconnection customer, it may be
useful to create a split based on voltage. For example, adopting an
interconnection-related network upgrade voltage threshold to be funded
upfront by the transmission provider has the potential to significantly
reduce interconnection-related network upgrade financing costs by
eliminating interconnection customers' need to fund upfront the likely
more expensive higher voltage interconnection-related network upgrades.
It could be appropriate to require the transmission provider to fund
upfront the cost of higher voltage interconnection-related network
upgrades because higher voltage transmission facilities are likely to
produce greater region-wide benefits than lower voltage ones.
144. Whatever the selected voltage threshold might be,
interconnection customers would still be required to upfront fund the
costs of interconnection-related network upgrades (subject to the
crediting policy) that do not meet that threshold. Thus, the selection
of a voltage threshold would necessarily exclude from transmission
provider upfront funding some interconnection-related network upgrades
that produce regional
[[Page 40289]]
transmission benefits. We think it important to ensure that, if the
Commission requires that transmission providers establish a voltage
threshold for sharing the responsibility to fund upfront the cost of
interconnection-related network upgrades, then the voltage threshold
should be based upon the likelihood that interconnection-related
network upgrades that meet that threshold produce more transmission
benefits than interconnection-related network upgrades below that
threshold. Furthermore, we recognize that there is some tension between
such an approach, which would eliminate the requirement that
interconnection customers upfront fund some interconnection-related
network upgrades based on voltage, thus reducing the interconnection
customers' financing costs only on larger interconnection-related
network upgrades, and Order No. 2003's general acknowledgement that
interconnection-related network upgrades, regardless of voltage or
size, ``benefit all users.'' \146\ Additionally, if the Commission
adopted this option, in order to avoid the responsibility to upfront
fund, transmission providers will have an incentive to identify a lower
voltage interconnection-related network upgrade rather than identifying
a higher voltage project that may be more efficient or cost-effective.
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\146\ Order No. 2003, 104 FERC ] 61,103 at P 65.
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145. We seek comment on: (1) This approach; (2) the appropriate
voltage threshold and any pre-determined cost threshold; and (3) how
this approach could be implemented in a just and reasonable manner.
(d) Allocate the Upfront Cost of Interconnection-Related Network
Upgrades on a Percentage Basis
146. We seek comment on whether to reduce the allowable percentage
of interconnection-related network upgrade costs that interconnection
customers must fund upfront (i.e., from 100% to a lower percentage).
The crediting policy would apply to the portion of the interconnection-
related network upgrade costs that the interconnection customer upfront
funds. To allow flexibility, we seek comment on whether an
interconnection customer should have the option to elect to upfront
fund 100% of the interconnection-related network upgrade if it chooses.
147. This method could benefit both the interconnection customer
and the transmission provider. With the ability to provide partial to
full upfront funding for interconnection-related network upgrades,
interconnection customers will have the ability to retain some control
over the speed of interconnection-related network upgrade construction
because they will be able to provide initial funding in cases where the
transmission owner does not have the funding readily on hand to pay for
certain construction milestones. Transmission providers will benefit
because this construct will retain the price signal to interconnection
customers regarding siting decisions, as interconnection customers
would still have to upfront fund (i.e., finance) the costs of more
expensive larger interconnection-related network upgrades associated
with their interconnection requests and the costs related to financing
interconnection-related network upgrades (e.g., interest payments due
on the loan) should increase as the costs of the interconnection-
related network upgrades increase.
148. We note that adoption of the transmission planning and cost
allocation reforms discussed above is likely to result in the
development of regional transmission facilities intended to accommodate
significant amounts of generation, and thus, has the potential to
reduce the need for more extensive and costly interconnection-related
network upgrades relative to those identified in the generator
interconnection process at present. Thus, the adoption of this
generator interconnection reform, in conjunction with the regional
transmission planning and cost allocation reforms discussed above,
could result in a significant reduction in interconnection customer
financing costs while still maintaining a price signal for siting
decisions.
149. We seek comment on: (1) This approach; (2) the appropriate
percentage for the interconnection customer's upfront funding; and (3)
how this approach could be implemented in a just and reasonable manner.
As part of this inquiry, we are interested in hearing perspectives on
the extent to which partial upfront funding by an interconnection
customer may preserve or reduce the incentive for that customer to
efficiently site a project. We seek comment on whether there are there
other mechanisms, beyond customer upfront funding, that may incent a
customer to site efficiently, and that could be adopted in conjunction
with the elimination of participant funding.
iii. Additional Considerations
(a) Interconnection-Related Network Upgrade Cost Sharing
150. If the Commission does not eliminate participant funding of
interconnection-related network upgrades, we seek comment regarding
potential cost-sharing measures to account for the fact that later-in-
time interconnection customers may accrue benefits from
interconnection-related network upgrades built to accommodate a prior
interconnection request. That is, if a later-in-time interconnection
customer benefits from the interconnection-related network upgrades
required to interconnect an earlier-in-time interconnection customer,
the later-in-time interconnection customers may also be assigned a
portion of those costs. The transmission provider could require the
allocation of costs in proportion to the benefits that the later-in-
time interconnection customers receive from network upgrades or be
based on a different method, such as a percent share based on usage. To
make this approach workable, the transmission provider could also
dictate a point after which a later-in-time interconnection customer
would be insulated from bearing the costs of a specific
interconnection-related network upgrade, e.g., prohibiting allocation
of interconnection-related network upgrade costs to interconnection
customers that enter the queue five years or more after the
interconnection-related network upgrade's energization.\147\ As we
noted above, the Commission has previously approved tariff provisions
pursuant to which earlier-in-time interconnection customers receive a
form of reimbursement for the network upgrade costs from later-in-time
customers.\148\ We note that the sharing of costs between earlier-in-
time and later-in-time interconnection customers would only apply in
situations where the earlier-in-time interconnection customer was
assigned any of the costs of the interconnection-related network
upgrade under the participant funding framework. We seek comment on a
just and reasonable method to calculate cost sharing for shared network
upgrades. We also seek comment on whether to require, and the
appropriate duration of, a time after which a later-in-time
interconnection customer would not be
[[Page 40290]]
allocated the costs of an interconnection-related network upgrade.
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\147\ For the purpose of this order, we will refer to this time
period as the sunset period.
\148\ See NYISO Tariff, attach S (Rules to Allocate
Responsibility for the Cost of New Interconnection Facilities),
Section 25.7.2; see also MISO Tariff, Attach. FF Section III.A.2.d.2
(81.0.0).
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(b) Option To Build
151. Order No. 2003 established, and Order No. 845 expanded, the
interconnection customer's option to build transmission provider's
interconnection facilities \149\ and stand alone network upgrades.\150\
In a non-RTO/ISO, if an interconnection customer elects to exercise the
option to build, the interconnection customer assumes the
responsibility to design, procure, and construct the transmission
provider's interconnection facilities and stand alone network upgrades
and is repaid by the transmission provider pursuant to the crediting
policy.
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\149\ Order No. 2003 defined two categories of interconnection
facility: (1) Transmission provider's interconnection facilities,
which refer to all facilities and equipment owned, controlled or
operated by the transmission provider from the point of change of
ownership to the point of interconnection, including any
modifications, additions or upgrades to such facilities and
equipment;'' and (2) interconnection customer's interconnection
facilities, which are located between the generating facility and
the point of change of ownership and which the interconnection
customer must design, procure, construct, and own. See pro forma
LGIA art. 1 (Definitions); pro forma LGIA art. 5.10.
\150\ Order No. 2003, 104 FERC ] 61,103 at P 353; Reform of
Generator Interconnection Procedures and Agreements, Order No. 845,
163 FERC ] 61,043, at P 85 (2018), order on reh'g, Order No. 845-A,
166 FERC ] 61,137, order on reh'g, Order No. 845-B, 168 FERC ]
61,092 (2019). Stand alone network upgrades refer to
interconnection-related network upgrades ``that are not part of an
Affected System that an Interconnection Customer may construct
without affecting day-to-day operations of the Transmission System
during their construction. Both the Transmission Provider and the
Interconnection Customer must agree as to what constitutes Stand
Alone Network Upgrades and identify them in Appendix A to the
Standard Large Generator Interconnection Agreement.'' See pro forma
LGIP Section 1 (Definitions).
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152. Importantly, the option to build allows interconnection
customers to have some control over their own timelines and
construction schedules and potentially achieve cost savings associated
with the design, procurement, and construction of the transmission
provider's interconnection facilities and stand alone network upgrades.
If the Commission revises the requirement that interconnection
customers upfront fund all or some of the costs all of interconnection-
related network upgrades, corresponding changes may be necessary to the
option to build provisions as they apply to stand alone network
upgrades to recognize that an interconnection customer that wants to
exercise the option to build would no longer be responsible to upfront
fund the full cost of those network upgrades. Therefore, we seek
comment on what changes may be necessary to ensure that the option to
build provisions remain just and reasonable and to retain flexibility
for interconnection customers in light of the potential change to the
funding policy.
(c) Interconnection Request Limit
153. We understand that a contributing factor to the
interconnection queue backlog is a tendency by interconnection
customers to submit multiple interconnection requests at different
points of interconnection, with the intention of discovering the lowest
cost location to site the generating facility (from an interconnection
perspective), and then withdrawing higher-cost interconnection requests
from the queue later in the process. We also understand that, absent an
appropriately-sized penalty (or reasonable restriction) associated with
submitting an interconnection request and then subsequently withdrawing
such an interconnection request, there still may be an incentive to
submit speculative interconnection requests under any of the potential
interconnection reforms discussed above. Therefore, we seek comment on
whether there should penalties for submitting speculative requests, how
such should be defined, and whether there should be a limit on the
number of interconnection requests that a developer can submit in an
interconnection queue study year and how narrowly such a limit should
apply (e.g., by transmission provider or by transmission pricing zone).
We also seek comment on how to determine a just and reasonable limit to
the number of interconnection requests. Finally, we seek comment on how
to address interconnection requests made by affiliated companies and
whether those interconnection requests should count against the limit
to the number of interconnection requests if one is imposed.
(d) Fast-Track for Interconnection of Generating Facilities Committed
to Regional Transmission Facilities
154. As discussed above, we seek comment on the model established
by ERCOT to construct the CREZ transmission projects. For those
transmission projects to be approved, ERCOT required a certain
percentage of capacity to be reserved by generation developers with
existing projects, projects under construction, projects with signed
interconnection agreements, or posted collateral. In the case that this
model may improve the coordination between transmission planning and
the development of future generation, it may become important to
streamline the generator interconnection process for generating
facilities that are committed to interconnecting to these transmission
facilities.
155. Therefore, we seek comment on whether a fast-track generator
interconnection process should be developed to facilitate
interconnection of generating facilities that have firmly committed to
connecting to new regional transmission facilities. An example of such
a fast-track option may be to allow the transmission provider to
perform a limited system impact study for only the cluster of
generating facilities committed under the regional transmission
planning process and to move to the facilities study without waiting
for earlier studies to complete. We recognize that the timeline for
transmission facility permitting and construction often far exceeds
that of the generator interconnection and construction process but seek
comment nonetheless on whether a faster generator interconnection
process in this scenario would be beneficial.
156. We seek comment on whether such a process would constitute
inappropriate ``queue jumping,'' or instead would be more appropriately
viewed as an extension of the previously approved first-ready, first-
served queueing practice. In this case, are generating facilities that
have put up financial collateral to ensure that a regional transmission
facility is constructed to serve them appropriately considered
``ready'' projects? We seek comment on the feasibility of establishing
such a proposal, as well as the implications on the rest of the
generator interconnection queue and on any legal challenges related to
a potential ``queue jumping'' concern.
(e) Fast-Track for Interconnection of ``Ready'' Generating Facilities
157. In addition to considering a fast-track generator
interconnection process for interconnection customers that have
committed financially to new regional transmission facilities, we are
considering whether allowing a fast-track for ``ready'' interconnection
requests would remove barriers to entry for interconnection requests
that have met certain readiness criteria. For example, interconnection
requests for which the developer has already executed a power purchase
agreement or that have been chosen in a state or utility request for
proposals may be appropriately deemed more ``ready'' than projects that
enter the interconnection queue without either contractual arrangement.
Another
[[Page 40291]]
example of an interconnection request that demonstrates a higher degree
of readiness could be one sited at a previously developed point of
interconnection that can make use of existing interconnection
facilities. Such interconnection requests may be considered more ready
because they have more ready access to the transmission system. Both of
these examples could be considered more ready than interconnection
requests proposed at points of interconnection where the
interconnection customer or the transmission provider must acquire new
rights-of-way, permits, and agreements with landowners, or that face
other obstacles to rapid development. We seek comment on which types of
interconnection requests could be considered more ``ready'' and able to
advance through the interconnection queue more quickly, as well as
comments on the just and reasonable structure for such a fast-track
option. We also seek comment on how to implement such a proposal in a
manner that is not unduly discriminatory. As in the prior proposed
reform, we seek comment on how to address possible concerns related to
what some may consider ``queue jumping'' or whether appropriate factors
may justify such measures.
(f) Grid-Enhancing Technologies
158. We seek comment on whether there is the potential for Grid-
Enhancing Technologies not only to increase the capacity, efficiency,
and reliability of transmission facilities, but, in so doing, also to
reduce the cost of interconnection-related network upgrades.\151\ In
light of the potential of Grid-Enhancing Technologies, we seek comment
on whether the Commission should require that transmission providers
consider Grid-Enhancing Technologies in interconnection studies to
assess whether their deployment can more cost-effectively facilitate
interconnections. To the extent transmission providers currently
consider Grid-Enhancing Technologies in the generator interconnection
process, what, if any, shortcomings exist in that consideration? If the
Commission were to require greater consideration of Grid-Enhancing
Technologies, how should it do so? What, if any, challenges exist in
establishing such a requirement and how might these challenges be
addressed?
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\151\ Commission staff led a workshop in 2019 to explore the
role, benefits, and challenges of Grid-Enhancing Technologies. FERC,
Grid-Enhancing Technologies, Notice of Workshop, Docket No. AD19-19-
000 (Sept. 9, 2019).
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C. Enhanced Transmission Oversight
159. The potential for a significant investment in the transmission
system in the coming years underscores the importance of ensuring that
ratepayers are not saddled with costs for transmission facilities that
are unneeded or imprudent. As part of this package of potential
reforms, we are considering whether reforms may be needed to enhance
oversight of transmission planning and transmission providers' spending
on transmission facilities to ensure that transmission rates remain
just and reasonable.
1. Potential Need for Reform
160. As discussed above, the electricity sector is in the midst of
a fundamental transition as the generation mix shifts rapidly from
largely centralized resources located close to population centers
towards renewable resources located far from customers. Potential
reforms to regional transmission planning and cost allocation and
generator interconnection should help protect customers throughout this
transition by directing planning toward the more efficient or cost-
effective transmission facilities. Nevertheless, particularly in light
of potential costs of new transmission infrastructure that may be
needed to meet the needs of the changing resource mix, we seek comment
on whether additional measures may be necessary to ensure that the
planning processes for the development of new transmission facilities,
and the costs of the facilities, do not impose excessive costs on
consumers.
161. We seek comment on whether the relatively large investment in
transmission facilities resulting from the regional transmission
planning and cost allocation processes reflects the more efficient or
cost-effective solutions for meeting transmission needs, including
those associated with a changing resource mix. The transparency with
which transmission needs are identified and transmission facilities
approved is an important element in ensuring that excessive costs are
not being imposed on consumers. Although Order No. 890 requires that
transmission planning processes comply with the transmission planning
principles, including transparency and openness, transmission providers
comply with those requirements in various ways.
162. We seek comment on whether the current transmission planning
processes provide sufficient transparency for stakeholders to
understand how best to obtain information and fully participate in the
various processes. For example, we seek comment whether in non-RTO/ISO
regions individual transmission owning members' local transmission
planning processes may not be as well publicized or follow as well
understood processes to provide information as in RTO/ISO regions. We
seek comment on whether this may result in material costs being imposed
on consumers with limited visibility into the actual need for a local
transmission facility or support for a specific local transmission
solution. We also seek comment on whether, in light of the significant
potential costs of transmission and this potential deficit in
transparency, customers and other stakeholders might benefit from
enhanced oversight over identification and costs of transmission
facilities.
2. Potential Reforms and Request for Comment
a. Independent Transmission Monitor
163. We seek comment on which potential measures the Commission
could take to ensure that there is appropriate oversight over how new
regional transmission facilities are identified and paid for. For
example, we seek comment on whether, to improve oversight of
transmission facility costs, it would be appropriate for the Commission
to require that transmission providers in each RTO/ISO, or more
broadly, in non-RTO/ISO transmission planning regions, establish an
independent entity to monitor the planning and cost of transmission
facilities in the region.
164. We seek comment on the Commission's authority to require an
independent entity to monitor transmission spending in each
transmission planning region, as well as the role that such monitor(s)
would play. For example, this independent transmission monitor might
potentially review transmission planning processes, planning criteria
that lead to the identification of particular transmission needs and
facilities, as well as the rules and regulations governing such
processes. Additionally, the independent transmission monitor could
review transmission provider spending on transmission facilities and
identify instances of potentially excessive transmission facility
costs, including through inefficiencies between local and regional
transmission planning processes. Further, the independent transmission
monitor could identify instances in which transmission facilities were
selected in the regional transmission plan for cost allocation when it
may not be clear that such projects were the more efficient or
[[Page 40292]]
cost-effective transmission solutions, or were approved for regional
cost allocation when credible less-costly alternatives were available.
If the independent transmission monitor identifies such examples, it
could make a referral to the Commission. The Commission could then
conduct a review of the relevant transmission planning processes and/or
transmission facility costs under section 206 of the FPA. We seek
comment on the proposal outlined in this paragraph.
165. We seek comment on whether the independent transmission
monitor's review could potentially focus on the transmission planning
process and costs of transmission facilities before construction
starts.\152\ We seek comment on whether and how the Commission might
modify the regional transmission planning and cost allocation processes
or rate recovery rules and procedures so as to facilitate such up-front
review.
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\152\ This is different than the safeguards provided under the
transmission formula rate protocols that have been implemented for
formula rates in transmission providers' OATTs. The transmission
formula rate protocols are generally designed to provide interested
parties sufficient opportunity to obtain and review information
necessary to evaluate the implementation of the formula rate, which
allows public utilities to recover the cost for transmission
facilities that are already constructed and placed in service,
except in limited circumstances (e.g., a transmission provider may
recover a return on costs of plant that is in the process of
construction by receiving regulatory approval to include such costs
of construction work in progress in rate base under its formula
rate). The protocols outline the process for the annual formula rate
informational filing at the Commission, transparency around the
transmission formula rate information exchange, the scope of
participation, and the ability of customers to challenge
transmission providers' implementation of the formula rate. See
Midwest Indep. Transmission Sys. Operator, Inc., 139 FERC ] 61,127
(2012); Midwest Indep. Transmission Sys. Operator, Inc., 143 FERC ]
61,149 (2013); Midcontinent Indep. Sys. Operator, Inc., 146 FERC ]
61,212 (2014); Midcontinent Indep. Sys. Operator, Inc., 150 FERC ]
61,025 (2015).
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166. We also seek comment on how an independent transmission
monitor could approach cost oversight. One possible method would be to
scrutinize the relevant regional transmission plan(s) to determine
whether a different portfolio of local and regional transmission
facilities would lead to higher net benefits. With regard to individual
transmission facilities selected via the regional transmission planning
processes or chosen through the local transmission planning processes,
the independent entity could provide information to assist the
Commission in determining whether the selection of a given transmission
facility warrants additional Commission review. Such assistance may
include the development of independent cost estimates for transmission
facilities. Given the challenges of reviewing all transmission
facilities, we seek comment on whether it would be useful for the
Commission or the independent entity to develop criteria (such as a
minimum spending threshold) to determine which transmission facilities
should be subject to review.
167. We seek comment on tools that could be developed to assist
such a transmission monitor or the Commission in reviewing
transmission-related spending. For example, such a monitor might
develop benchmark cost estimates that would be independent of cost
estimates developed by a transmission provider, which could serve as a
mechanism to assess performance for each transmission provider for the
applicable transmission facilities. The independent transmission
monitor could create separate estimates for regional versus local
transmission facilities and classify facility costs by criteria (such
as voltage level), with estimates based on well-established methods
using the best information available just prior to the start of
construction to minimize the error in cost estimation. The Commission
could then review the costs for transmission facilities that
significantly exceed the cost estimates, either sua sponte or on the
recommendation of the independent transmission monitor or a third
party. An independent transmission monitor could also seek information
from transmission providers regarding the variances between actual and
estimated costs for selected regional transmission facilities and use
this information in its assessment of whether further Commission review
is recommended.
168. We seek comment on whether an independent transmission monitor
should provide advice on the design and implementation of the regional
transmission planning and cost allocation processes in addition to
oversight of the regional transmission planning process and the costs
of the development of individual transmission facilities. The
independent transmission monitor could review the design of the
regional transmission planning and cost allocation processes on an
ongoing basis and highlight areas where improvements could be made (for
example, optimization between local and regional transmission
planning). The independent transmission monitor could also review
mechanisms used in transmission planning processes, such as adjusted
production cost modeling tools, and assess the extent to which
modifications to such mechanisms might yield more efficient
transmission spending decisions.
169. The independent transmission monitor could also identify and
report on situations in which non-wires alternatives could more cost-
effectively address transmission system needs. We seek comment on the
value of such reporting and whether such information could improve the
ability for states to participate in the regional transmission planning
process and provide a greater opportunity for input. Similarly, we seek
comment on whether an independent transmission monitor or other
oversight mechanism should evaluate and report on transmission
providers' consideration of Grid-Enhancing Technologies in the
transmission planning process. If so, how should that evaluation be
conducted and what information should be reported?
170. Additionally, we seek comment on whether oversight of the
planning and approval of local transmission facilities is necessary to
ensure that transmission rates are just and reasonable. We seek comment
on whether an independent transmission monitor should evaluate whether
the transmission needs identified in the local transmission planning
processes could be better considered during regional transmission
planning processes to allow for the identification of more efficient or
cost-effective transmission solutions. In addition, we seek comment on
whether oversight should consider the development and application of
transmission planning criteria. Finally, we encourage commenters to
identify any other factors that they believe the Commission should
consider for oversight within the local transmission planning process.
At the same time, we seek comment on whether such a role for a
federally-regulated regional transmission monitor would improperly or
inappropriately expand the role of federal regulation over local
utility regulation and/or potentially increase administrative and legal
costs of local transmission planning with no commensurate benefits for
customers. More broadly, we seek comment on whether there is a need to
delineate more clearly the oversight roles of federal and state
regulators over local transmission planning.
171. In addition, we seek comment on whether there is sufficient
clarity on the roles and responsibilities between state and federal
regulators regarding the local transmission planning criteria and the
development of local transmission facilities (e.g., ``Supplemental
Projects'' in PJM). We seek comment on whether such transmission
facilities require additional oversight and whether
[[Page 40293]]
additional coordination among state and federal regulators would be
beneficial. Similarly, we seek comment on whether and how greater
oversight may improve coordination between individual transmission
provider's planning processes and regional transmission planning
processes. Order No. 1000 requires the evaluation of ``alternative
transmission solutions that might meet the needs of the transmission
planning region more efficiently or cost-effectively than solutions
identified by individual public utility transmission providers.'' \153\
We seek comment on whether current rules and processes are adequately
aligned with and facilitate such consideration or evaluation, and if
not, whether there are oversight measures or other mechanisms,
including via an independent transmission monitor, that could better
facilitate the consideration of more efficient or cost-effective
alternatives. For example, we seek comment on whether individual
transmission provider practices regarding retirement and replacement of
transmission facilities sufficiently align with the directive to ensure
evaluation of alternative transmission solutions and whether these
practices sufficiently consider the more efficient or cost-effective
ways to serve future needs. We also seek comment on whether sufficient
transparency exists in retirement decisions to allow for such regional
assessment. We seek comment on what role can or should an independent
transmission monitor play in facilitating enhanced coordination.
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\153\ Order No. 1000, 136 FERC ] 61,050 at P 148.
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172. Furthermore, we seek comment on whether additional
transparency measures are appropriate or should be in place for
transmission providers, including those outside of RTO/ISO regions. If
so, we seek comment on whether the Commission should apply transparency
measures, some of which are currently utilized within RTO/ISO regions
(e.g., dedicated transmission planning web pages, requirements to
publish and detail full transmission plan at end of each transmission
planning cycle, scorecards), or consider different or new transparency
measures for transmission providers outside of RTO/ISO regions. We seek
comment on whether new or different transparency measures are needed
within the RTO/ISO regions.
173. An independent transmission monitor would not replace the
Commission's rate jurisdiction but instead could provide the Commission
with an additional means of ensuring that rates are just and
reasonable. With respect to other aspects of prudence, or transmission
facility selection against alternatives, the independent transmission
monitor would not supplant the Commission's authority with respect to
prudence, but could inform the Commission as to whether a further
review is warranted; the final determination on whether costs are
prudently incurred remains with the Commission. Similarly, the record
created by the independent transmission monitor could help the
Commission in ensuring that the design of the regional transmission
planning and cost allocation processes remain just and reasonable and
not unduly discriminatory or preferential.
174. We seek comment on (1) the independent transmission monitor
proposal, and (2) any alternative options for improving oversight of
transmission costs or the effectiveness of transmission planning
processes. Additionally, we seek comment on whether the concerns
regarding transmission oversight are best addressed by an independent
entity similar to the role of an independent market monitor, or whether
the concerns can be adequately addressed by the RTO/ISO or transmission
providers in non-RTO/ISO regions, or through another approach.
175. We also seek comment on (1) how an independent transmission
monitor (or set of regional monitors) would be created or authorized;
(2) whether a single monitor should be appointed for each transmission
region, or instead a given monitor might review transmission across
several regions; (3) the Commission's authority to require an
independent transmission monitor in all transmission planning regions;
(4) how this entity would work in practice, in both the RTO/ISO and
non-RTO/ISO regions; and (5) the scope of review such monitor(s) should
be charged with carrying out, including whether such monitoring should
extend to oversight of the generator interconnection process.
b. State Oversight
176. Another way to add oversight to the transmission planning and
cost allocation processes could be to involve state commissions in
those processes. By way of example, SPP has a Regional State Committee
(RSC), which provides collective state regulatory agency input in areas
under the RSC's primary responsibilities and on matters of regional
importance related to the development and operation of the bulk
electric transmission system. Pursuant to the SPP Bylaws, ``with
respect to transmission planning, the RSC will determine whether
transmission upgrades for remote resources will be included in the
regional transmission planning process and the role of transmission
owners in proposing transmission upgrades in the regional planning
process.'' \154\
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\154\ SPP, Governing Documents Tariff, Bylaws, Section 7.2
(Regional State Committee) (1.0.0).
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177. We seek comment on whether this type of model, or other models
that may be proposed, could be expanded to other regions and other
topics; for example, whether a state-led committee could: Provide
insight into regional transmission facility costs and cost allocation
methods; evaluate whether the transmission needs identified in the
local transmission planning processes could be better considered during
regional transmission planning processes; inform the Commission as to
whether a further review is warranted of whether incurred costs are
prudent; or provide the Commission with an additional means of ensuring
that rates are just and reasonable. We also seek comment on how such a
model may be combined with other oversight tools or mechanisms explored
herein. For example, given state regulatory authority over the approval
of non-wires solutions, can or should a regional state committee play a
role in identifying circumstances under which a non-wires solution
would be the more efficient or cost-effective solution to solving an
identified regional transmission need, and facilitating a process by
which the relevant state regulator could be given an opportunity to
approve such a solution?
c. Limitation on Recovery of Costs for Abandoned Projects
178. There is always a risk that once approved, a regional project
may be abandoned before going into service for a variety of reasons
including a failure to obtain all necessary state and federal
approvals, including, for example, state certificates of public
convenience and necessity. The Commission's general policy for recovery
of the costs of abandoned plant under section 205 of the FPA allows
recovery of and return on 50% of the prudently incurred investment
costs incurred in connection with the abandoned plant.\155\ In
[[Page 40294]]
addition, the Commission may grant as an incentive under section 219 of
the FPA for transmission facilities meeting the qualifications for the
incentive, recovery of 100% of prudently-incurred costs related to such
facilities if they are abandoned for reasons beyond the control of the
transmission owner.\156\ In light of potential costs of new regional
transmission infrastructure and the corresponding risk that some of
those projects may be abandoned, we seek comment on whether the
Commission should revisit its policies regarding abandoned plant to
better protect consumers from increased costs due to never-built
transmission facilities.
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\155\ New Eng. Power Co., Opinion No. 295, 42 FERC ] 61,016, at
61,081-82, order on reh'g, Opinion No. 295-A, 43 FERC ] 61,285
(1988). The Commission also allows recovery under section 205 of
return on 50% of investment costs incurred to construct transmission
facilities (and other non-pollution control plant) through the
inclusion of Construction Work in Progress (CWIP) in rate base
during the construction period, provided certain conditions are met.
Construction Work In Progress for Public Utilities; Inclusion of
Costs in Rate Base, Order No. 298, 48 FR 24,323 (June 1, 1983), FERC
Stats. & Regs. ] 30,455, order on reh'g, Order No. 298-A, 48 FR
46,012 (Oct. 11, 1983), FERC Stats. & Regs., ] 30,500 (1983), order
on reh'g, Order No. 298-B, 48 FR 55,281 (Dec. 12, 1983), FERC Stats.
& Regs. ] 30,524 (1983) (Order No. 298).
\156\ Promoting Transmission Investment through Pricing Reform,
Order No. 679, 116 FERC ] 61,057, order on reh'g, Order No. 679-A,
117 FERC ] 61,345 (2006), order on reh'g, 119 FERC ] 61,062 (2007).
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179. For example, one proposal to protect consumers would be to
limit the recovery of costs through abandonment by allowing only the
recovery of some portion of actual development or pre-commercial costs,
and/or no recovery of a return on equity on such costs prior to the
project receiving all necessary regulatory approvals. We therefore seek
comment on this or other proposals to limit the amount that can be
recovered for regional transmission facilities that are abandoned prior
to going into service. Commenters are, of course, welcome to address
all issues and concerns pertinent to such proposals.
d. Additional Oversight Approaches
180. Finally, we seek comment on additional oversight approaches
the Commission might take to ensure that wholesale transmission
spending is cost effective. For example, performance-based regulation.
We ask how performance-based regulation may be designed to ensure that
rates are just and reasonable, ensure reliability of the transmission
system, promote regional expansion of transmission facilities for a
sufficiently wide range of future scenarios, including anticipated
future generation, and encourage transmission provider participation.
D. Transition
181. To implement any of the proposals outlined above, transmission
providers must transition to new interconnection pricing paradigms and
new regional transmission planning and cost allocation processes.
Therefore, we seek comment on appropriate transition plans, including
treatment of interconnection customers in the various stages of the
generator interconnection process and those that have already
interconnected as well as when the more holistic regional transmission
planning and cost allocation processes would begin (including when the
broader category of regional transmission facilities would be
established).
182. The Commission also seeks input as to the length of time that
might be necessary to implement any reforms that result from this
process. Specifically, the Commission requests input as to how much
time transmission providers might need to develop compliance filings
related to all of the proposals in this ANOPR.
V. Comment Procedures
183. The Commission invites interested persons to submit comments
on these matters and any related matters or alternative proposals that
commenters may wish to discuss. Comments are October 12, 2021 and Reply
Comments are due November 9, 2021. Comments must refer to Docket No.
RM21-17-000 and must include the commenter's name, the organization
they represent, if applicable, and their address in their comments. All
comments will be placed in the Commission's public files and may be
viewed, printed, or downloaded remotely as described in the Document
Availability section below. Commenters on this proposal are not
required to serve copies of their comments on other commenters
184. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's website at https://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software must be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
185. Commenters that are not able to file comments electronically
may file an original of their comment by USPS mail or by courier-or
other delivery services. For submission sent via USPS only, filings
should be mailed to: Federal Energy Regulatory Commission, Office of
the Secretary, 888 First Street NE, Washington, DC 20426. Submission of
filings other than by USPS should be delivered to: Federal Energy
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.
VI. Document Availability
186. 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). At
this time, the Commission has suspended access to the Commission's
Public Reference Room due to the President's March 13, 2020
proclamation declaring a National Emergency concerning the Novel
Coronavirus Disease (COVID-19).
187. From the Commission's Home Page on the internet, this
information is available in its eLibrary. The full text of this
document is available in the eLibrary in PDF and Microsoft Word format
for viewing, printing, and/or downloading. To access this document in
eLibrary, type the docket number of this document excluding the last
three digits in the docket number field.
188. User assistance is available for eLibrary and the Commission's
website during normal business hours from the Commission's 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].
By direction of the Commission. Chairman Glick and Commissioner
Clements are concurring with a joint separate statement attached.
Commissioner Chatterjee is not participating. Commissioner Danly is
concurring with a separate statement. Commissioner Christie is
concurring with a separate statement.
Issued: July 15, 2021.
Debbie-Anne A. Reese,
Deputy Secretary.
Department of Energy
Federal Energy Regulatory Commission
Building for the Future Through Electric Regional Transmission Planning
and Cost Allocation and Generator Interconnection
Docket No. RM21-17-000
GLICK, Chairman, CLEMENTS, Commissioner, concurring:
1. The generation resource mix is changing rapidly. Due to a myriad
of factors--including improving economics, customer and corporate
demand for clean energy, public utility commitments and integrated
resource plans, as well as federal, state, and local public policies--
renewable resources in particular are coming online at an
[[Page 40295]]
unprecedented rate.\1\ As a result, the transmission needs of the
electricity grid of the future are going to look very different than
those of the electricity grid of the past.
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\1\ See, e.g., Joseph Rand et al., Queued Up: Characteristics of
Power Plants Seeking Transmission Interconnection as of the End of
2020, Lawrence Berkeley National Laboratory, May 2021, https://eta-publications.lbl.gov/sites/default/files/queued_up_may_2021.pdf;
Electric Power Monthly, Table 6.1 Electric Generating Summer
Capacity Changes (MW), U.S. Energy Information Administration, (Mar.
2021 to Apr. 2021), https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=table_6_01.
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2. We are concerned that the current approach to transmission
planning and cost allocation cannot meet those future transmission
needs in a manner that is just and reasonable and not unduly
discriminatory or preferential. In particular, we believe that the
status quo approach to planning and allocating the costs of
transmission facilities may lead to an inefficient, piecemeal expansion
of the transmission grid that would ultimately be far more expensive
for customers than a more forward-looking, holistic approach that
proactively plans for the transmission needs of the changing resource
mix. A myopic transmission development process that leaves customers
paying more than necessary to meet their transmission needs is not just
and reasonable.
3. In that regard, we are pleased to see the Commission taking a
consensus first step toward updating its rules and regulations to
ensure that we are meeting the nation's evolving transmission needs in
a cost-effective and efficient fashion. Today's action complements our
recently established joint federal-state task force with the National
Association of Regulatory Utility Commissioners,\2\ which we expect to
produce a robust dialogue on many of the issues addressed herein. In
our view, this advance notice of proposed rulemaking (ANOPR) is just
the first step. Ensuring that transmission rates remain just and
reasonable will require further action, including reforms to
interregional transmission planning and cost allocation, as well as
other reforms to our regional transmission planning and cost allocation
and generator interconnection processes beyond those contemplated
herein. Nevertheless, we believe that today's unanimous Commission
action represents a solid foundation for an expeditious inquiry into
how we can regulate to achieve the transmission needs of our changing
electricity system in a manner consistent with our statutory
obligations under the Federal Power Act.
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\2\ Joint Federal-State Task Force on Electric Transmission, 175
FERC ] 61,224 (2021).
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* * * * *
4. The generation mix is shifting rapidly from large resources
located close to population centers toward renewable resources, often
combined with onsite storage, that tend to be located where their fuel
source is best--i.e., where the wind blows hardest or the sun shines
brightest. According to the National Renewable Energy Laboratory
(NREL), total renewable generation capacity nearly doubled from 2009 to
2018, increasing from 11.7% of total generation capacity to 20.5%.\3\
And that is just the beginning: Of the roughly 750 GW of generation in
interconnection queues around the country, nearly 700 GW are renewable
resources,\4\ providing every reason to believe that the dramatic shift
toward renewable generation will only accelerate in the years ahead.
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\3\ 2018 Renewable Energy Data Book at 26, NREL, https://www.nrel.gov/docs/fy20osti/75284.pdf. Wind and solar resources, in
particular, have grown at a disproportionate rate, with solar
generation capacity increasing roughly 5,000% from 1,054 MW to
51,899 MW nationwide, and wind generation capacity more than
tripling from 31,155 MW to 96,442 MW.
\4\ See Joseph Rand, Queued Up: Characteristics of Power Plants
Seeking Transmission Interconnection as of the End of 2020, Lawrence
Berkeley National Laboratory, May 2021, https://eta-publications.lbl.gov/sites/default/files/queued_up_may_2021.pdf.
Equally important, this shift is taking place across the country,
not just in a few areas. For example, as of the issuance of this
ANOPR, in Midcontinent Independent System Operator, Inc. (MISO),
solar and wind projects comprise 80% of all active projects in the
current interconnection queue, or about 73 GW of total capacity.
MISO, Generator Interconnection Queue--Active Projects Map, https://giqueue.misoenergy.org/PublicGiQueueMap/. Similarly, in
PJM Interconnection, L.L.C. (PJM), solar and wind projects with a
total capacity of 62 GW comprise 79% of all active projects in the
current interconnection queue as of the issuance of this ANOPR. PJM,
New Services Queue, https://www.pjm.com/planning/services-requests/interconnection-queues.aspx. In California Independent System
Operator Corporation (CAISO), renewable and storage capacity of 23
GW comprise 78% of all active projects in the current
interconnection queue as of the issuance of this ANOPR. CAISO,
Generator Interconnection Queue, https://www.caiso.com/Documents/ISOGeneratorInterconnectionQueueExcel.xls.
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5. That shift is the result of many factors. First and foremost,
the cost of renewable resources is plummeting. For example, in its
annual report on the levelized cost of energy, Lazard found that
between 2009 to 2020, the levelized cost of energy from unsubsidized
wind generation and unsubsidized utility-scale solar generation
decreased by 71% and 90%, respectively \5\--enough to make utility-
scale solar and wind generation cost-competitive with central station
fossil generation sources in many parts of the country.\6\ Moreover,
customers--both residential and commercial--are increasingly demanding
clean energy, particularly energy from renewable resources--which is
itself causing utilities and independent power producers to attempt to
send large quantities of renewable energy onto the grid.\7\ In
addition, dozens of the biggest utilities in the country have
established their own decarbonization goals, the achievement of which
will require their
[[Page 40296]]
own significant investment in renewable generation.\8\
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\5\ See, e.g., Lazard's Levelized Cost of Energy Analysis--
Version 14.0, at 9 (Oct. 19, 2020), https://www.lazard.com/
perspective/levelized-cost-of-energy-and-levelized-cost-of-storage-
2020/#:~:text=Lazard's%20latest%20annual%20Levelized%
20Cost,build%20basis%2C%20continue%20to%20maintain; Ryan Wiser et
al., Expert elicitation survey predicts 37% to 49% declines in wind
energy costs by 2050, Lawrence Berkeley National Laboratory (Apr.
2021), https://eta-publications.lbl.gov/sites/default/files/wind_lcoe_elicitation_ne_pre-print_april2021.pdf (finding that the
decrease in levelized cost of energy for wind power from 2015-2020
outpaced the decrease predicted by experts, and that experts
continue to predict significant declines in levelized cost of
energy).
\6\ See Lazard's Levelized Cost of Energy Analysis--Version
14.0, at 3, 7 (Oct. 19, 2020), https://www.lazard.com/perspective/
levelized-cost-of-energy-and-levelized-cost-of-storage-2020/
#:~:text=Lazard's%20latest%20annual%20Levelized%
20Cost,build%20basis%2C%20continue%20to%20maintain.
\7\ See, e.g., Deloitte Resources 2020 Study at 22, https://www2.deloitte.com/content/dam/insights/us/articles/6655_Resources-study-2020/DI_Resources-study-2020.pdf (showing that U.S. corporate
renewable generation purchase power agreements increased from 0.3 GW
in 2009 to 13.6 GW in 2019); Kevin O'Rourke & Charles Harper,
Corporate Renewable Procurement and Transmission Planning:
Communicating Demand to RTOs Necessary to Secure Future Procurement
Options, A Renewable America (October 2018), https://acore.org/wp-content/uploads/2020/04/Corporates-Renewable-Procurement-and-Transmission-Report.pdf (indicating that a group of corporations,
forming the Renewable Energy Buyers Alliance, has set a goal to
purchase 60 GW of new renewable energy capacity in the U.S. by
2025); Stanley Porter et al., Utility Decarbonization Strategies,
Renew, Reshape, and Refuel to Zero, Deloitte Insights (Sept. 2021),
https://www2.deloitte.com/us/en/insights/industry/power-and-utilities/utility-decarbonization-strategies.html (indicating that
43 of 55 utilities surveyed have emissions reductions targets and 22
have net-zero or carbon-free electricity goals); Esther Whieldon,
Path to net zero: 70% of biggest US utilities have deep
decarbonization targets, S&P Global Market Intelligence (Dec. 9,
2020) at 3-6, https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/path-to-net-zero-70-of-biggest-us-utilities-have-deep-decarbonization-targets-61622651 (indicating
that review of utilities' climate goals decarbonization plans, as of
December 2020, shows that 70% of the 30 largest utilities have net-
zero carbon targets or are moving to comply with similarly
aggressive state mandates); see also Rich Glick and Matthew
Christiansen, FERC and Climate Change, 40 Energy L.J. 1, 7-12 (2019)
(``The growth of renewable resources is also a function of
consumers' desire for clean energy. Customers--including
residential, commercial, and even industrial consumers--are
increasingly demanding that their energy come from renewable or
zero-emissions sources'').
\8\ See, e.g., Corporate Renewable Procurement and Transmission
Planning: Communicating Demand to RTOs Necessary to Secure Future
Procurement Options, A Renewable America, October 2018, https://acore.org/wp-content/uploads/2020/04/Corporates-Renewable-Procurement-and-Transmission-Report.pdf; Esther Whieldon, Path to
net zero: 70% of biggest US utilities have deep decarbonization
targets, S&P Global Market Intelligence, Dec. 9, 2020, at 3-6,
https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/path-to-net-zero-70-of-biggest-us-utilities-have-deep-decarbonization-targets-61622651.
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6. Finally, federal, state, and local policymakers have adopted a
range of public policies that are driving the changing resource mix.
For example, 30 states and the District of Columbia have adopted
renewable portfolio standards,\9\ with those standards contributing to
roughly 50% of the total growth in renewable generation over the last
two decades.\10\ In addition, several states have doubled down on the
clean energy transition by enacting measures that require that most or
all of their electricity come from zero emissions resources.\11\ All
told, ``states and utilities that have committed to transitioning to
100 percent clean power serve nearly 83 million households and
businesses, representing around 50 percent of all U.S. electricity
demand in 2019.'' \12\
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\9\ Nat'l Conference of State Legislatures, State Renewable
Portfolio Standards and Goals (Nov. 7, 2021), https://www.ncsl.org/
research/energy/renewable-portfolio-
standards.aspx#:~:text=Thirty%20states%2C%20Washington%2C%20DC%2C,hav
e%20set%20renewable%20energy%20goals. Renewable portfolio standards
are policies that are designed to increase the amount of renewable
energy sources used for electricity generation.
\10\ See, e.g., Berkeley Lab, U.S. Renewables Portfolio
Standards: 2019 Annual Status Update (Aug. 2019), https://emp.lbl.gov/publications/us-renewables-portfolio-standards-2.
\11\ Carbon Pricing in Organized Wholesale Elec. Markets, 175
FERC ] 61,036, at P 2 (2021) (``Thirteen states--California, Hawaii,
Maine, Maryland, Massachusetts, Nevada, New Jersey, New Mexico, New
York, Oregon, Vermont, Virginia, and Washington--and the District of
Columbia have adopted clean energy or renewable portfolio standards
of 50% or greater.''). In addition, ``a number of states--including
Colorado, Connecticut, Nevada, Rhode Island, and Wisconsin--have
established 100% clean electricity goals or targets by executive
order or other non-binding commitment.'' See id. At the local level,
cities and counties are also accelerating clean energy commitments.
Kelly Trumbull et al., Progress Toward 100% Clean Energy in Cities
and States Across the U.S., University of California--Los Angeles
Luskin Center for Innovation (November 2019) at 10, https://innovation.luskin.ucla.edu/wp-content/uploads/2019/11/100-Clean-Energy-Progress-Report-UCLA-2.pdf (finding over 200 cities and
counties across 37 U.S. states have 100 percent clean energy
commitments).
\12\ National Resources Defense Council (NRDC), NRDC's 8th
Annual Energy Report: Slow and Steady Will Not Win the Climate Race
(Dec. 2, 2020), https://www.nrdc.org/resources/nrdcs-8th-annual-energy-report-slow-and-steady-will-not-win-race?nrdcpreviewlink=rmmB6NM6zpiOTruhuObZJdH92bCOvmZTY1hx72xCSzQ#renewables.
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7. Dramatic changes in the resource mix inevitably come with
similarly dramatic changes in transmission needs. As noted, the
increasingly cost-competitive renewable resources that customers and
public policies demand tend to be developed farther away from customers
where their fuel sources are strong and development costs are low
rather than in close proximity to their ultimate customers. As a
result, the future resource mix will likely present new transmission
needs, different from those of the large resources located close to
population centers that have dominated electricity generation in the
past. Meeting those transmission needs will likely require both the
infrastructure necessary to interconnect new resources to the
transmission system efficiently and the infrastructure necessary to
reliably move the electricity produced by those resources to where it
is needed. This could make it considerably more expensive than
necessary to bring in the low-cost generation demanded by customers and
meet federal, state, and local public policies.
8. This Commission cannot sit idly by. Our role is to ensure just
and reasonable rates and support reliability in light of changes in the
market, not to pretend those changes are not happening. We are
concerned that, in light of evolving transmission needs, the current
regional transmission planning and cost allocation and generator
interconnection processes may no longer ensure just and reasonable
rates for transmission service.\13\ In particular, we are concerned
that existing regional transmission planning processes may be siloed,
fragmented, and not sufficiently forward-looking, such that
transmission facilities are being developed through a piecemeal
approach that is unlikely to produce the type of transmission solutions
that could more efficiently and cost-effectively meet the needs of the
changing resource mix. Regional transmission planning processes
generally do little to proactively plan for the resource mix of the
future, including both commercially established resources, such as
onshore wind and solar, as well as emerging ones, such as offshore
wind. We are also concerned that current regional transmission planning
processes are not sufficiently integrated with the generator
interconnection processes, and are overwhelmingly focused on relatively
near-term transmission needs, and that attempting to meet the needs of
the changing resource mix through such a short-term lens will lead to
inefficient transmission investments. As a result, under the status
quo, customers could end up paying far more to meet their transmission
needs than they would under a more forward-looking approach that
identifies the more efficient or cost-effective investments in light of
the changing resource mix.\14\
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\13\ 16 U.S.C. 824e.
\14\ See generally Eric Larson et al., Net-Zero America:
Potential Pathways, Infrastructure, and Impact (2020),
Princeton_NZA_Interim_Report_15_Dec_2020_FINAL.pdf (discussing
different pathways for meeting decarbonization goals, including
differing approaches to transmission investment).
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9. Relatedly, we are also concerned that the current approach to
transmission planning and cost allocation is failing to adequately
identify the benefits and allocate the costs of new transmission
infrastructure. Although the regional transmission planning process
considers transmission needs driven by reliability, economics, and
Public Policy Requirements,\15\ those transmission needs are often
viewed in isolation from one another and the cost allocation methods
for projects selected to meet those needs are similarly siloed. As a
result, the status quo may be disproportionately producing transmission
facilities that address a narrow set of needs, providing comparatively
modest benefits, but at a still-substantial total cost instead of
developing the type of transmission infrastructure that could provide
the most significant benefits for customers. In the same vein, we are
also concerned that many customers who share in the diverse array of
benefits that transmission infrastructure can offer may not be paying
their fair share, as required by the cost causation principle.\16\
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\15\ See Transmission Planning and Cost Allocation by
Transmission Owning and Operating Public Utilities, Order No. 1000,
136 FERC ] 61,051, at P 11 (2011), order on reh'g, Order No. 1000-A,
139 FERC ] 61,132, order on reh'g and 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).
\16\ Cf. BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264,
268-269 (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.'' (citing Midwest ISO
Transmission Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004)
and Se. Michigan Gas Co. v. FERC, 133 F.3d 34, 41 (D.C. Cir.
1998))).
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10. In addition, we are concerned that, largely due to the
potential shortcomings with the current regional transmission planning
and cost allocation processes, transmission infrastructure is
increasingly being
[[Page 40297]]
developed through the generator interconnection process. That means
that infrastructure with potentially significant benefits for a broad
range of entities may be developed through a process that focuses
exclusively on the needs of a comparatively small number of
interconnection customers--a dynamic that is almost sure to result in
comparatively inefficient investment decisions. The participant funding
approach to financing interconnection-related network upgrades will
often mean that the interconnection customer(s) alone must pay for
all--or the vast majority--of the costs of that transmission
infrastructure, even where it provides significant benefits to other
entities. That, in turn, may cause those interconnection customers to
withdraw projects from the queue, causing considerable uncertainty and
delay, and may mean that net beneficial transmission infrastructure is
never developed due to a misalignment in how that infrastructure would
be paid for.
11. Finally, we are also concerned that the Commission's current
approach to overseeing transmission investment may not adequately
protect consumers. While transmission infrastructure can provide a
broad spectrum of benefits, it is itself a significant investment that
represents a major component of customers' electric bills. The
Commission must vigorously oversee the rules governing how transmission
projects are planned and paid for if we are to satisfy our
responsibility to protect customers from excessive rates and
charges.\17\ The potential bases for invigorating our oversight of
transmission spending contemplated in today's order have the potential
to go a long way toward ensuring that we fulfill that function.
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\17\ Cf., e.g., California ex rel. Lockyer v. FERC, 383 F.3d
1006, 1017 (9th Cir. 2004) (rejecting ``an interpretation [that]
comports neither with the statutory text nor with the Act's `primary
purpose' of protecting consumers''); City of Chicago v. FPC, 458
F.2d 731, 751 (D.C. Cir. 1971) (``[T]he primary purpose of the
Natural Gas Act is to protect consumers.'' (citing, inter alia, City
of Detroit v. FPC, 230 F.2d 810, 815 (D.C. Cir. 1955)).
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12. Today's action plants the seeds for addressing the concerns
outlined above. A forward-looking, holistic approach to transmission
planning has the potential to identify the more efficient or cost-
effective solutions for meeting the transmission needs of the changing
resource mix, including those resources that are not yet under
development. Such an approach would allow transmission planners to
proactively identify the areas of the transmission grid that will have
significant transmission needs and select the more efficient or cost-
effective solution to meet those needs, including needs driven by
resources that are not yet in operation or even under development.
Doing so has the potential to address the transmission needs of the
future generation mix while costing customers considerably less than
they would pay to meet those same needs under the status quo. That, in
our view, is what is necessary to ensure that the rates for
transmission service remain just and reasonable as the resource mix
changes.
13. We anticipate that this effort will be the Commission's
principal focus in the months to come. In addition to reviewing the
record assembled in response to today's order, we intend to explore
technical conferences and other avenues for augmenting that record--
including through the joint federal-state task force \18\--before
proceeding to reform our rules and regulations. We recognize that the
issues addressed herein are highly technical, complex problems that do
not lend themselves to easy solutions. That being said, we also
recognize the urgent need to address the transmission needs of the
changing resource mix and appreciate that we do not have the luxury of
sitting back and debating these issues ad nauseum.
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\18\ See supra n.2.
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* * * * *
14. The electricity sector is at a pivotal moment. With the clean
energy transition gaining steam, we can either continue with the status
quo, trying to meet the transmission needs of the future by building
out the grid in a myopic, piecemeal fashion, or we can start
holistically and proactively planning for those future transmission
needs. We believe that today's advance notice of proposed rulemaking
represents an important and essential first step in the right direction
and toward the type of transmission planning and cost allocation
paradigm that is necessary to protect customers, support reliability,
and ensure just and reasonable rates.
For these reasons, we respectfully concur.
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Richard Glick,
Chairman.
-----------------------------------------------------------------------
Allison Clements,
Commissioner.
Department of Energy
Federal Energy Regulatory Commission
Building for the Future Through Electric Regional Transmission Planning
and Cost Allocation and Generator Interconnection
Docket No. RM21-17-000
(Issued July 15, 2021)
DANLY, Commissioner, concurring:
1. I concur with the issuance of this Advance Notice of Proposed
Rulemaking (ANOPR) because the Commission is always entitled to solicit
comments on possible changes to existing rules and a number of the
questions raised here are worthy of consideration.
2. I write separately to highlight one overarching concern. The
ANOPR poses several questions where the answer is ``no.'' Many of the
contemplated proposals would exceed or cede our jurisdictional
authority, violate cost causation principles, create stifling layers of
oversight and ``coordination,'' trample transmission owners' rights,
force neighboring states' ratepayers to shoulder the costs of other
states' public policy choices, treat renewables as a new favored class
of generation with line-jumping privileges, and perhaps inadvertently
lead to much less transmission being built and at much greater all-in
cost to ratepayers.
3. There are obviously problems with the existing transmission
regime. I, for example, have long been troubled by interconnection
logjams and have wondered whether we are needlessly propping up fantasy
projects while viable projects get lost in the crowd.\1\ This is but
one example; there are any number of other critical transmission
planning reforms that bear investigation.
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\1\ See, e.g., PacifiCorp, 171 FERC ] 61,112 (2020) (Danly,
Comm'r, concurring).
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4. My hope therefore is that commenters will supply us with a full
record on each issue raised in the ANOPR: Whether and why the existing
rule works or not, and whether and why the possible reform may work or
not. With every proposed change, I specifically solicit comments on two
subjects. First: Is the contemplated reform a proper exercise of the
Commission's authority, i.e., is it within our jurisdiction? That is
always the threshold question before we turn to policy. Second: what
will be the ultimate effect on ratepayers? I fear that in the
enthusiasm to build transmission, many may tout the benefits of new
transmission while overlooking the costs that will eventually be borne
by ratepayers. No proposed policy,
[[Page 40298]]
however worthy, can evade our statutory duty to ensure that rates are
just and reasonable.
5. I encourage everyone with an interest to file. I look forward to
learning from the parties that submit comments and to engaging with my
colleagues to consider whether there are legally durable, economically
sound reforms that we might consider to improve the reliability of the
transmission system at just and reasonable rates.
For these reasons, I respectfully concur.
-----------------------------------------------------------------------
James P. Danly,
Commissioner.
Department of Energy
Federal Energy Regulatory Commission
Building for the Future Through Electric Regional Transmission Planning
and Cost Allocation and Generator Interconnection
Docket No. RM21-17-000
(Issued July 15, 2021)
CHRISTIE, Commissioner, concurring:
1. I concur with today's ANOPR because approximately ten years
after the Commission issued Order No. 1000, it is appropriate to review
the implementation of that order, assess the successes and problems
that have become evident over the past decade, and consider reforms and
revisions to existing regulations governing regional transmission
planning and cost allocation. This consideration of potential reforms
is especially timely as the transmission system faces the challenge of
maintaining reliability through the changing generation mix and efforts
to reduce carbon emissions.
2. The broad goal of the Commission's regulation of our nation's
power grid under the Federal Power Act (FPA) is to ensure a reliable
power supply to consumers, which includes residential customers as well
as the businesses providing jobs for tens of millions of Americans, at
just and reasonable rates. Transmission is one of the three essential
elements of a reliable power system, along with generation and
distribution, so continually working to make America's transmission
system more reliable, more efficient, and more cost-effective is our
job at FERC.
3. As with Order No. 1000, the statutory framework governing our
potential actions in this proceeding remains section 206 of the FPA,
which requires us to ensure that all transmission planning processes
and cost allocation mechanisms subject to our jurisdiction result in
jurisdictional services being provided at rates, terms and conditions
that are just, reasonable, and not unduly discriminatory or
preferential. Any proposals ultimately adopted by this Commission for
reforms or revisions to existing regulations must be consistent with
this authority.
4. As Paragraph 4 of the ANOPR makes clear,\1\ we have not
predetermined that any specific proposal in this ANOPR has already been
or will ultimately be approved. Rather, we seek comment from all
interested persons and organizations on the wide range of proposals
contained herein, as well as the submission of alternative proposals.
Today is the beginning of a long process and I look forward to hearing
from all concerned.
---------------------------------------------------------------------------
\1\ ANOPR at P 4 (``We note that the Commission has not
predetermined that any specific proposal discussed herein shall or
should be made or in what final form; rather, we seek comment from
the public on those proposals and welcome commenters to offer
additional or alternative proposals for consideration.'').
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5. Similarly, my concurrence to issue today's ANOPR does not
represent an endorsement at this point in the process of any one or
more of the proposals included in the order. This ANOPR contains a
number of good proposals, some potentially good proposals (depending on
how they are fleshed out), and frankly, some proposals that are not--
and may never be--ready for prime time, or could potentially cause
massive increases in consumers' bills for little to no commensurate
benefit or inappropriately expand the role of federal regulation over
local utility regulation. Given the early stage of this process,
however, I agree it is worthwhile to submit a broad range of proposals
to the public for comment in the hope that the final result will be a
more reliable, more efficient, and more cost-effective transmission
system.
For these reasons, I respectfully concur.
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Mark C. Christie,
Commissioner.
[FR Doc. 2021-15512 Filed 7-26-21; 8:45 am]
BILLING CODE 6717-01-P
