Managing Transmission Line Ratings, 6420-6444 [2020-26107]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 86, Number 12 (Thursday, January 21, 2021)]
[Proposed Rules]
[Pages 6420-6444]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-26107]



[[Page 6419]]

Vol. 86

Thursday,

No. 12

January 21, 2021

Part II





Department of Energy





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





Federal Energy Regulatory Commission





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





18 CFR Part 35





Managing Transmission Line Ratings; Proposed Rule

Federal Register / Vol. 86 , No. 12 / Thursday, January 21, 2021 / 
Proposed Rules

[[Page 6420]]


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

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM20-16-000]


Managing Transmission Line Ratings

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking.

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

SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes 
to reform both the pro forma Open Access Transmission Tariff and the 
Commission's regulations under the Federal Power Act to improve the 
accuracy and transparency of transmission line ratings. Specifically, 
the proposal would require: Transmission providers to implement 
ambient-adjusted ratings on the transmission lines over which they 
provide transmission service; Regional Transmission Organizations 
(RTOs) and Independent System Operators (ISOs) to establish and 
implement the systems and procedures necessary to allow transmission 
owners to electronically update transmission line ratings at least 
hourly; and transmission owners to share transmission line ratings and 
transmission line rating methodologies with their respective 
transmission provider(s) and, in RTOs/ISOs, with their respective 
market monitor(s).

DATES: Comments are due March 22, 2021.

ADDRESSES: Comments, identified by docket number RM20-16, may be filed 
electronically at https://www.ferc.gov 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 mail or hand-
delivery to: Federal Energy Regulatory Commission, Secretary of the 
Commission, 888 First Street NE, Washington, DC 20426. The Comment 
Procedures Section of this document contains more detailed filing 
procedures.

FOR FURTHER INFORMATION CONTACT: 
Dillon Kolkmann (Technical Information), Office of Energy Policy and 
Innovation, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426, (202) 502-8650, [email protected].
Mark Armamentos (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426, (202) 502-8103, [email protected].
Ryan Stroschein (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE, Washington, 
DC 20426, (202) 502-8099, [email protected].

SUPPLEMENTARY INFORMATION: 

 
                            Table of Contents
 
                                                             Paragraph
                                                              numbers
 
I. Introduction.........................................               1
II. Background..........................................               9
    A. Order Nos. 888 and 889...........................               9
    B. Order No. 890....................................              12
    C. ATC-Related Reliability Standards, Business                    13
     Practices, and Commission Regulations..............
    D. Reliability Standard FAC-008-3 (Facility Ratings)              15
    E. Commission Staff Paper and September 2019                      16
     Technical Conference...............................
III. Technical Background...............................              19
    A. Transmission Line Rating Fundamentals............              19
    B. Current Transmission Line Rating Practices.......              22
    C. Emergency Ratings................................              30
    D. Rating and Methodology Transparency..............              33
IV. Need for Reform.....................................              38
    A. Transmission Line Ratings........................              38
    B. Transparency.....................................              47
V. Discussion...........................................              48
    A. Transmission Line Ratings........................              48
        1. Comments.....................................              48
        2. Proposal.....................................              81
    B. Transparency.....................................             114
        1. Comments.....................................             115
        2. Proposal.....................................             125
VI. Compliance..........................................             131
VII. Information Collection Statement...................             136
VIII. Environmental Analysis............................             153
IX. Regulatory Flexibility Act..........................             154
X. Comment Procedures...................................             163
XI. Document Availability...............................             167
Appendix A: List of Short Names/Acronyms of Commenters..              --
Appendix B: Pro Forma Open Access Transmission Tariff...              --
 

I. Introduction

    1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy 
Regulatory Commission (Commission) proposes, pursuant to section 206 of 
the Federal Power Act (FPA),\1\ to reform the pro forma Open Access 
Transmission Tariff (OATT) and the Commission's regulations to improve 
the accuracy and transparency of transmission line ratings used by 
transmission providers. Transmission line ratings represent the maximum 
transfer capability of each transmission line. As explained below, 
transmission line ratings and the rules by which they are established 
are practices that directly affect the cost of wholesale energy, 
capacity and ancillary services, as well as the cost of delivering 
wholesale energy to transmission customers. Inaccurate transmission 
line ratings may result in Commission-

[[Page 6421]]

jurisdictional rates that are unjust and unreasonable.
---------------------------------------------------------------------------

    \1\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

    2. Transmission line ratings often are calculated based on 
assumptions about ambient conditions that do not accurately reflect the 
near-term transfer capability of the system.\2\ For example, 
transmission line ratings currently based on seasonal or static 
assumptions may indicate less transmission system transfer capability 
than the transmission system can actually provide, leading to 
restricted flows and increased congestion costs. Alternatively, 
transmission line ratings currently based on seasonal or static 
assumptions may overstate the near-term transfer capability of the 
system, creating potential reliability and safety problems. In either 
case, the current use of seasonal and static assumptions results in 
transmission line ratings that do not accurately represent the transfer 
capability of the transmission system.
---------------------------------------------------------------------------

    \2\ Federal Energy Regulatory Commission, Staff Paper, Managing 
Transmission Line Ratings, Docket No. AD19-15-000 (Aug. 2019) 
(Commission Staff Paper), https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf.
---------------------------------------------------------------------------

    3. To address these issues with respect to shorter-term requests 
for transmission service, we propose two requirements for greater use 
of ambient-adjusted line ratings (AARs),\3\ which are transmission line 
ratings that incorporate near-term forecasted ambient air temperatures. 
First, we propose to require that transmission providers use AARs as 
the basis for evaluation of transmission service requests that will end 
within ten days of the request. Second, we propose to require that 
transmission providers use AARs as the basis for determination of the 
necessity of certain curtailment, interruption, or redispatch of 
transmission service that is anticipated to occur within those ten 
days.
---------------------------------------------------------------------------

    \3\ As discussed below, we propose to define an ambient-adjusted 
line rating, or AAR, as a transmission line rating that: (1) Applies 
to a time period of not greater than one hour; (2) reflects an up-
to-date forecast of ambient air temperature across the time period 
to which the rating applies; and (3) is calculated at least each 
hour, if not more frequently. Proposed 18 CFR 35.28(b)(10).
---------------------------------------------------------------------------

    4. To address these issues with respect to longer-term requests for 
transmission service, we propose to require that transmission providers 
use seasonal line ratings as the basis for evaluation of such requests. 
We also propose to require that transmission providers use seasonal 
line ratings as the basis for the determination of the necessity of 
curtailment, interruption, or redispatch that is anticipated to occur 
more than ten days in the future.\4\
---------------------------------------------------------------------------

    \4\ The use of seasonal transmission line ratings for long-term 
requests for transmission service and as the basis for the 
determination of curtailment, interruption, or redispatch is 
currently standard practice. However, as detailed later, the 
Commission proposes changes to seasonal transmission line rating 
implementation.
---------------------------------------------------------------------------

    5. Moreover, in certain situations, use of dynamic line ratings 
(DLRs) presents opportunities for transmission line ratings that may be 
more accurate than those established with AARs.\5\ DLRs are based not 
only on forecasted ambient air temperature, but also on other weather 
conditions such as wind, cloud cover, solar irradiance intensity, 
precipitation, and/or on transmission line conditions such as tension 
or sag. One factor that may contribute to the limited deployment of 
DLRs by transmission owners is that the regional transmission 
organizations (RTO) and independent system operators (ISO) that operate 
the transmission system and oversee organized wholesale electric 
markets may not be able to automatically incorporate frequently updated 
transmission line ratings such as DLRs into their operating and market 
models. To address this issue, we propose to require RTOs/ISOs to 
establish and implement the systems and procedures necessary to allow 
transmission owners to electronically update transmission line ratings 
on at least an hourly basis.
---------------------------------------------------------------------------

    \5\ As discussed below, the Commission proposes to define a 
dynamic line rating, or DLR, as a transmission line rating that: (1) 
Applies to a time period of not greater than one hour; (2) reflects 
up-to-date forecasts of inputs such as (but not limited to) ambient 
air temperature, wind, solar irradiance intensity, transmission line 
tension, or transmission line sag; and (3) is calculated at least 
each hour, if not more frequently. Proposed 18 CFR 35.28(b)(11).
---------------------------------------------------------------------------

    6. The proposed reforms noted above are intended to improve the 
accuracy of transmission line ratings used during normal (pre-
contingency) operations.\6\ We also seek comment on whether to require 
transmission providers to implement unique emergency ratings \7\ that 
would be used during post-contingency operations.
---------------------------------------------------------------------------

    \6\ The NERC Glossary defines ``normal rating'' as: ``[t]he 
rating as defined by the equipment owner that specifies the level of 
electrical loading . . . that a system, facility, or element can 
support or withstand through the daily demand cycles without loss of 
equipment life.'' NERC, Glossary of Terms Used in NERC Reliability 
Standards (June 2, 2020), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
    \7\ The NERC Glossary defines ``emergency rating'' as: ``T[t]he 
rating as defined by the equipment owner that specifies the level of 
electrical loading or output . . . that a system, facility, or 
element can support, produce, or withstand for a finite period. The 
rating assumes acceptable loss of equipment life or other physical 
or safety limitations for the equipment involved.'' Id. For purposes 
of this NOPR, the phrase ``unique emergency ratings'' describes an 
emergency rating that is a different value from a facility's normal 
rating. Typically, the emergency rating would be a higher value than 
the normal rating unless there is specific constraint that prohibits 
a higher emergency rating.
---------------------------------------------------------------------------

    7. Finally, we propose to require transmission owners to share 
transmission line ratings and methodologies with their transmission 
provider(s) and, in regions served by an RTO/ISO, also with the market 
monitor(s) of that RTO/ISO. We also seek comment on whether 
transmission line ratings and transmission line rating methodologies 
should be shared with other transmission providers, upon request.
    8. We seek comment on these proposed reforms by 60 days after 
publication of this NOPR in the Federal Register.

II. Background

A. Order Nos. 888 and 889

    9. In Order No. 888, the Commission required public utilities to 
unbundle their generation and transmission services and file open 
access non-discriminatory transmission tariffs (OATTs) to allow third 
parties equal access to their transmission system.\8\ In Order No. 889, 
issued at the same time as Order No. 888, the Commission established 
part 37 of the Commission's regulations that require each public 
utility that owns, controls, or operates facilities used for the 
transmission of electric energy in interstate commerce to create or 
participate in an Open Access Same-time Information System (OASIS) that 
would provide transmission customers the same access to information to 
enable them to obtain open access non-discriminatory transmission 
service.\9\ Among the new requirements, public utilities were directed 
to calculate their available transfer capability (ATC) as a way to give 
potential third party transmission customers information on 
transmission service availability. In Order No. 888, the Commission 
used the term ``Available Transmission Capability'' to describe the 
amount of additional

[[Page 6422]]

capability available in the transmission network to accommodate 
additional requests for transmission services. The Commission in Order 
No. 890 adopted the current term ATC in the pro forma OATT to be 
consistent with the term generally accepted throughout the 
industry.\10\ For the purposes of this proceeding, ATC will also refer 
to available flowgate capability.\11\
---------------------------------------------------------------------------

    \8\ 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, 61 FR 21,540 (May 10, 1996), FERC Stats. & Regs. ] 
31,036 (1996) (cross-referenced at 77 FERC ] 61,080), order on 
reh'g, Order No. 888-A, 62 FR 12,274 (Mar. 14, 1997), FERC Stats. & 
Regs. ] 31,048 (cross-referenced at 78 FERC ] 61,220), order on 
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, 
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub 
nom. Transmission Access 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).
    \9\ Open Access Same-Time Information System and Standards of 
Conduct, Order No. 889, FERC Stats. & Regs. ] 31,035 (1996) (cross-
referenced at 75 FERC ] 61,078), order on reh'g, Order No. 889-A, 
FERC Stats & Regs. ] 31,049 (cross-referenced at 78 FERC ] 61,221), 
reh'g denied, Order No. 889-B, 81 FERC ] 61,253 (1997).
    \10\ The NERC Glossary defines ATC as: ``A measure of the 
transfer capability remaining in the physical transmission network 
for further commercial activity over and above already committed 
uses. It is defined as Total Transfer Capability (TTC) less Existing 
Transmission Commitments (including retail customer service), less a 
Capacity Benefit Margin, less a Transmission Reliability Margin, 
plus Postbacks, plus counterflows.'' NERC, Glossary of Terms Used in 
NERC Reliability Standards (June 2, 2020), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
    \11\ Available flowgate capability is defined in the NERC 
Glossary as: ``A measure of the flow capability remaining on a 
Flowgate for further commercial activity over and above already 
committed uses. It is defined as [total flowgate capability] TFC 
less Existing Transmission Commitments (ETC), less a Capacity 
Benefit Margin, less a Transmission Reliability Margin, plus 
Postbacks, and plus counterflows.'' NERC, Glossary of Terms Used in 
NERC Reliability Standards (June 2, 2020), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
---------------------------------------------------------------------------

    10. In Order No. 889, the Commission required that ATC and Total 
Transfer Capability (TTC) be calculated based on a methodology 
described in the Transmission Provider's tariff, and that those 
calculations be based on current industry practices, standards and 
criteria.\12\ The Commission also made further changes to its 
regulations as part of Order No. 889 to ensure accuracy of the data 
posted on OASIS.\13\ For example, the Commission required that entities 
that calculate ATC or TTC on constrained posted paths make publicly 
available the underlying data and methodologies.\14\
---------------------------------------------------------------------------

    \12\ Order No. 889, FERC Stats. & Regs. ] 31,035 at ] 31,607.
    \13\ Id. ] 31,608.
    \14\ See 18 CFR 37.6 (b)(2)(ii) (stating that, on request, the 
responsible party must make all data used to calculate ATC, TTC, 
CBM, and TRM for any constrained posted paths publicly available 
(including the limiting element(s) and the cause of the limit (e.g., 
thermal, voltage, stability), as well as load forecast assumptions) 
in electronic form within one week of the posting.).
---------------------------------------------------------------------------

    11. At the time, no formal methodologies existed to calculate ATC, 
and the Commission encouraged the industry to develop a consistent 
transmission line rating methodology.\15\ While Order No. 888 required 
transmission providers to include descriptions of ATC methodologies in 
their tariffs,\16\ Order No. 889 required public utilities to post ATC 
values and certain related information to their OASIS.\17\
---------------------------------------------------------------------------

    \15\ Order No. 889, FERC Stats. & Regs. ] 31,035 at ] 31,607.
    \16\ The Commission requires ``all public utilities that own, 
control or operate facilities used for transmitting electric energy 
in interstate commerce [t]o file open access non-discriminatory 
transmission tariffs that contain minimum terms and conditions of 
non-discriminatory service.'' Order No. 888, FERC Stats. & Regs. ] 
31,036 at 31,635. Public utilities also are ``required to make 
section 206 compliance filings to meet . . . pro forma tariff non-
price minimum terms and conditions of non-discriminatory 
transmission. Id. at 31,636. The pro forma OATT's ``Methodology To 
Assess Available Transmission Capability'' is proscribed in 
Attachment C of the Order. Id. at 31,930.
    \17\ Order No. 889, FERC Stats. & Regs. ] 31,035 at 31,587.
---------------------------------------------------------------------------

B. Order No. 890

    12. In Order No. 890, the Commission addressed and remedied 
opportunities for undue discrimination under the regulations and the 
pro forma OATT adopted in Order Nos. 888 and 889.\18\ Among other 
things, the Commission found that the lack of ATC consistency and 
transparency throughout the industry allowed for undue discrimination, 
with transmission providers able to favor themselves and their 
affiliates over third parties in allocating ATC.\19\ The Commission 
also stated that ATC inconsistencies made it difficult for parties to 
detect discrimination.\20\ In response to these concerns, the 
Commission directed public utilities, working through North American 
Electric Reliability Corporation (NERC) Reliability Standards and North 
American Energy Standards Board (NAESB) business practices development 
processes, to produce workable solutions to complex and contentious 
issues surrounding improving the consistency and transparency of ATC 
calculations.\21\ This included the development of standard ATC 
calculation methodologies, definitions for the components in the ATC 
equation, and standards for data inputs, assumptions, and information 
exchanges to be applied across the industry.\22\
---------------------------------------------------------------------------

    \18\ 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 and 
clarification, Order No. 890-B, 123 FERC ] 61,299 (2008), order on 
reh'g, Order No. 890-C, 126 FERC ] 61,228 (2009), order on 
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
    \19\ Order No. 890, 118 FERC ] 61,119 at P 83.
    \20\ Id. P 21. In regions with RTOs/ISOs, the RTO/ISO in most 
cases calculated the ATC for paths within their territory.
    \21\ Id. P 196.
    \22\ Id. P 207.
---------------------------------------------------------------------------

C. ATC-Related Reliability Standards, Business Practices, and 
Commission Regulations

    13. The Commission in Order No. 729,\23\ pursuant to section 215 of 
the FPA,\24\ approved six Reliability Standards,\25\ subsequently 
referred to as the ``MOD A Reliability Standards'' by NERC, and stated 
the Commission believes that these Reliability Standards address the 
potential for undue discrimination by requiring industry-wide 
transparency and increased consistency regarding all components of the 
ATC calculation methodology and certain definitions, data, and modeling 
assumptions.\26\
---------------------------------------------------------------------------

    \23\ Mandatory Reliability Standards for the Calculation of 
Available Transfer Capability, Capacity Benefit Margins, 
Transmission Reliability Margins, Total Transfer Capability, and 
Existing Transmission Commitments and Mandatory Reliability 
Standards for the Bulk-Power System, Order No. 729, 129 FERC ] 
61,155, at P 13 (2009), order on clarification, Order No. 729-A, 131 
FERC ] 61,109, order on reh'g, Order No. 729-B, 132 FERC ] 61,027 
(2010).
    \24\ 16 U.S.C. 824o.
    \25\ The Reliability Standards were: MOD-001-1--Available 
Transmission System Capability; MOD-004-1--Capacity Benefit Margin; 
MOD-008-1--TRM Calculation Methodology; MOD-028-1--Area Interchange 
Methodology; MOD-029-1--Rated System Path Methodology; and MOD-030-
1--Flowgate Methodology.
    \26\ Order No. 729, 129 FERC ] 61,155 at P 2.
---------------------------------------------------------------------------

    14. On July 16, 2020, the Commission issued a NOPR \27\ proposing 
to amend its regulations because of the importance of the ATC 
calculation and as a result of the proposed retirement of NERC's MOD A 
standards. The Commission proposed to revise its regulations to 
establish the general criteria transmission owners must use in 
calculating ATC.\28\ The Commission also proposed to adopt the NAESB 
wholesale electric quadrant

[[Page 6423]]

(WEQ) Business Practice Standards that include commercially relevant 
requirements from the existing MOD A Reliability Standards as they 
appeared generally consistent with those criteria.\29\ On September 17, 
2020, the Commission, in Order No. 873, approved the retirement of 18 
Reliability Standard requirements identified by NERC, the Commission-
certified Electric Reliability Organization.\30\ The Commission also 
remanded proposed Reliability Standard FAC-008-4 for further 
consideration by NERC and took no action on the proposed retirement of 
56 MOD A Reliability Standard requirements.\31\
---------------------------------------------------------------------------

    \27\ Standards for Business Practices and Communication 
Protocols for Public Utilities, Notice of Proposed Rulemaking, 172 
FERC ] 61,047, at P 49 (2020).
    \28\ Id. P 50 (proposing new language, shown in italics, for the 
Commission's regulations governing the calculation of ATC and TTC in 
18 CFR 37.6(b)(2)(i)), that calculation methods, availability of 
information, and requests. Information used to calculate any posting 
of ATC and TTC must be dated and time-stamped and all calculations 
shall be performed according to consistently applied methodologies 
referenced in the Transmission Provider's transmission tariff and 
shall be based on Commission-approved Reliability Standards, 
business practice and electronic communication standards, and 
related implementation documents, as well as current industry 
practices, standards and criteria. Transmission Providers shall 
calculate ATC and TTC in coordination with and consistent with 
capability and usage on neighboring systems, calculate system 
capability using factors derived from operations and planning data 
for the time frame for which data are being posted (including 
anticipated outages), and update ATC and TTC calculations as inputs 
change. Such calculations shall be conducted in a manner that is 
transparent, consistent, and not unduly discriminatory or 
preferential.)
    \29\ Id. P 51, NAESB WEQ-023 Modeling Business Practice 
Standards.
    \30\ Electric Reliability Organization Proposal to Retire 
Requirements in Reliability Standards Under the NERC Standards 
Efficiency Review, Order No. 873, 85 FR 65,207, 172 FERC ] 61,225 
(2020).
    \31\ Id. P 4 (noting that the Standard Efficiency Review NOPR 
indicated that the Commission intended to ``coordinate the effective 
dates for the retirement of the MOD A Reliability Standards with 
successor North American Energy Standards Board (NAESB) business 
practice standards'' and that, on July 16, 2020, ``the Commission 
issued a NOPR in Docket Nos. RM05-5-029 and RM05-5-030 proposing to 
amend its regulations to incorporate by reference, with certain 
enumerated exceptions, NAESB's Version 003.3 Business Practices'').
---------------------------------------------------------------------------

D. Reliability Standard FAC-008-3 (Facility Ratings)

    15. The requirements of Reliability Standard FAC-008-3 (Facility 
Ratings) \32\ are generally as follows:
---------------------------------------------------------------------------

    \32\ NERC, Reliability Standard FAC-008-3 (Facility Ratings), 
https://www.nerc.com/pa/Stand/Reliability%20Standards/FAC-008-3.pdf.
---------------------------------------------------------------------------

     Requirement number 1 (``R1'') requires a generator owner 
to provide documentation for determining the facility ratings of its 
generator facility(ies).
     Requirement R2 requires each generator owner to have a 
documented methodology for determining facility ratings of its 
equipment connected between the location specified in Requirement R1 
and the point of interconnection with the transmission owner.
     Requirement R3 requires each transmission owner to have a 
documented methodology for determining facility ratings (facility 
ratings methodology) of its facilities.\33\
---------------------------------------------------------------------------

    \33\ Requirements R4 and R5 have been retired effective January 
21, 2014.
---------------------------------------------------------------------------

     Requirement R6 requires that the generator owner and 
transmission owner also establish facility ratings for their facilities 
that are consistent with the associated facility rating methodology or 
documentation for determining their facility ratings.
     Requirement R7 provides that facility ratings must be 
provided to other entities as specified in the requirements.
     Requirement R8 requires the identification and 
documentation of the limiting component for all facilities and the 
increase in rating if that component were no longer the limiting 
component (i.e., the rating for the second most limiting component) for 
facilities associated with an Interconnection reliability operating 
limit, a limitation of TTC, an impediment to generator deliverability, 
or an impediment to service to a major load center.
     Requirement R8 also requires entities to provide 
information to requesting entities regarding their facilities. 
Requirement R8, Part 8.1 requires an entity to provide the identity of 
the most limiting equipment of a facility as well as the facility 
rating to requesting entities. Requirement R8, Part 8.2 requires an 
entity to provide the identity of the next most limiting equipment of a 
facility as well as the thermal rating of that equipment.

E. Commission Staff Paper and September 2019 Technical Conference

    16. In August 2019, the Commission issued the Commission Staff 
Paper, ``Managing Transmission Line Ratings'' drawing on Commission 
staff outreach conducted in spring 2019 with RTOs/ISOs, transmission 
owners, and trade groups, as well as staff participation in a November 
2017 Idaho National Laboratory workshop. The report included background 
on common transmission line rating approaches, current practices in 
RTOs/ISOs, a review of pilot projects, and a discussion of potential 
improvements.\34\
---------------------------------------------------------------------------

    \34\ Commission Staff Paper, https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf.
---------------------------------------------------------------------------

    17. On September 10 and 11, 2019, Commission staff convened a 
technical conference (September 2019 Technical Conference) to discuss 
what transmission line ratings and related practices might constitute 
best practices, and what, if any, Commission action in these areas 
might be appropriate. In particular, the September 2019 Technical 
Conference covered issues such as: (1) Common transmission line rating 
methodologies; (2) AAR and DLR implementation benefits and challenges; 
(3) the ability of RTOs/ISOs to accept and use DLRs; and (4) the 
transparency of transmission line rating methodologies.\35\ 
Participants at the September 2019 Technical Conference included 
utilities (some of which implement both AARs and DLRs), technology 
vendors, RTO/ISO market monitors, and organizations representing 
customers.
---------------------------------------------------------------------------

    \35\ Supplemental Notice of Technical Conference, Docket No. 
AD19-15-000 (Sep. 4, 2019).
---------------------------------------------------------------------------

    18. In October 2019, the Commission requested comments on questions 
that arose from the September 2019 Technical Conference.\36\ In 
response, commenters addressed issues related to AARs and DLRs, 
emergency ratings, and transparency, as discussed below.\37\
---------------------------------------------------------------------------

    \36\ Notice Inviting Post-Technical Conference Comments, Docket 
No. AD19-15-000 (Oct. 2, 2019).
    \37\ A list of commenters and the abbreviated names used in this 
NOPR appears in appendix A.
---------------------------------------------------------------------------

III. Technical Background

A. Transmission Line Rating Fundamentals

    19. Transmission line ratings represent the maximum transfer 
capability of each transmission line. A variety of entities use them in 
their reliability models, including transmission providers, reliability 
coordinators, transmission system operators, planning authorities, 
transmission owners, and transmission planners. Transmission line 
ratings in reliability models are used to determine operating limits 
and can affect transmission system operator action, such as 
curtailment, interruption, or redispatch decisions. As market 
operators, RTOs/ISOs use transmission line ratings in their market 
models to establish commitment and dispatch. In these market models, 
transmission line ratings affect congestion, and, thereby, affect the 
prices of energy, operating reserves, and other ancillary services. 
Transmission line ratings are based on the most limiting of three types 
of transmission line ratings/limits: Thermal ratings, voltage limits, 
and stability limits. Thermal ratings can change with ambient 
conditions; however, voltage and stability limits are fixed values that 
limit the power flow on a transmission line from exceeding the point 
above which there is an unacceptable risk of a voltage or stability 
problem. Transmission line ratings are dictated by the most limiting 
element across the entire transmission facility, which includes the 
overhead conductors and the associated equipment necessary for the 
transfer or movement of electric energy across a transmission facility 
(e.g., switches, breakers, busses, metering equipment, relay equipment, 
etc.).\38\
---------------------------------------------------------------------------

    \38\ The NERC Glossary defines a facility as ``a set of 
electrical equipment that operates as a single Bulk Electric System 
Element (e.g., a line, a generator, a shunt compensator, 
transformer, etc.)'', defines a facility rating as: ``the maximum or 
minimum voltage, current, frequency, or real or reactive power flow 
through a facility that does not violate the applicable equipment 
rating of any equipment comprising the facility''. NERC, Glossary of 
Terms Used in NERC Reliability Standards (June 2, 2020), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.

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

[[Page 6424]]

    20. Thermal ratings are determined by taking into consideration the 
physical characteristics of the conductor and making assumptions about 
ambient weather conditions to determine the maximum amount of power 
that can flow through a conductor while keeping the conductor under its 
maximum operating temperature. Transmission conductors that exceed 
their maximum operating temperature can sag and/or become damaged 
through material weakening (or ``annealing''), resulting in reduced 
capability and causing potential reliability and/or public safety 
concerns.
    21. Conductor temperatures are impacted by a variety of factors, 
notably ambient air temperatures. Specifically, increases in ambient 
air temperatures tend to increase a transmission line's operating 
temperature. Electric power flowing through a transmission line 
increases the temperature of the line above ambient temperature due to 
the line's electrical resistance. Other conditions and phenomena also 
tend to increase transmission line temperature, particularly solar 
irradiance intensity. Conversely, some conditions and phenomena tend to 
lower transmission line temperature, particularly wind. Thermal 
transmission line limits, therefore, generally decrease with warmer 
ambient air temperatures and greater solar irradiance intensity, and 
generally increase with cooler ambient air temperatures and higher wind 
speeds. Engineering standards help translate line characteristics and 
ambient weather assumptions into transmission line ratings. The 
different approaches to transmission line ratings discussed below 
primarily reflect differences in how frequently ambient weather 
assumptions are updated (which can range from decades to hours or even 
minutes) and what types of ambient weather assumptions are updated (air 
temperature, solar irradiance intensity, wind speed, etc.).

B. Current Transmission Line Rating Practices

    22. In practice, thermal rating methodologies have evolved along a 
spectrum from fully static, with no change in ambient condition 
assumptions for thermal limits on conductors, to nearly ``real-time'' 
dynamic ratings. Static ratings are intended to reflect conservative 
assumptions about the worst-case ambient conditions that equipment 
might face (e.g., the hottest summer day) and are typically updated 
only when equipment is changed or ambient condition assumptions are 
updated. Thus, they often remain unchanged for years or even decades. 
Seasonal ratings are similar to static ratings in that they change 
infrequently, but they use different ambient condition assumptions for 
different seasons.\39\
---------------------------------------------------------------------------

    \39\ Although transmission owners typically define seasonal 
ratings as summer and winter seasonal ratings, transmission owners 
may create more granular seasonal ratings that could include unique 
seasonal ratings for the spring and fall seasons.
---------------------------------------------------------------------------

    23. Generally, AARs are transmission line ratings that apply to a 
time period not greater than one hour, reflect an up-to-date forecast 
of ambient air temperature (and possibly other forecasted inputs) \40\ 
across the time period to which the rating applies, and is calculated 
at least each hour, if not more frequently. AAR implementation can be a 
multi-step process that requires selecting an appropriate line, 
receiving information about ambient air temperatures (prevailing and 
forecasted, typically from the National Oceanic and Atmospheric 
Administration or a private service), rating forecasting, and rating 
validation. Implementation of AARs often involves transmission owners 
developing electronic rating ``look-up'' tables for their transmission 
facilities, which yield transmission line ratings for any air 
temperature. Transmission line ratings are then determined by using the 
rating that corresponds to the ambient air temperature that is 
forecasted over the period of the rating (e.g., hour or 15 or 5 
minutes).
---------------------------------------------------------------------------

    \40\ For example, PJM implements day and night ambient air 
temperature tables, where the night ambient air temperature table 
assumes zero solar irradiance. Exelon Comments at 25.
---------------------------------------------------------------------------

    24. AAR methodologies usually result in higher transmission line 
ratings relative to seasonal or static rating methodologies because, 
while seasonal or static ratings are based on the conservative, worst-
case temperature values, AARs are usually based on ambient air 
temperatures lower than the conservative, worst-case temperature 
values. For a small percentage of intervals, however, AARs will 
identify that the near-term ambient temperature conditions are actually 
more extreme than the long-term assumptions used in seasonal or static 
ratings, and will therefore result in a line rating that is lower than 
a seasonal or static rating would have allowed.
    25. On the opposite end of the spectrum from static ratings are 
DLRs, which use assumptions that are updated in near real-time. In 
addition to ambient air temperature, DLRs can incorporate additional 
ambient conditions such as wind speed and direction, solar irradiance 
intensity (considering cloud cover), and/or precipitation. DLRs may 
also incorporate measurements from sensors installed on or near the 
line, such as wind speed sensors, line tension sensors, conductor 
temperature sensors, and/or photo-spatial sensors (e.g., 3-D laser 
scanning) monitoring line sag. Such weather and other data are not 
immediately converted to transmission line ratings in real-time. 
Instead, DLR implementation combines current sensor data with data from 
the recent past to create reliable short-term forecasts of the relevant 
weather and other variables for longer periods of time (potentially as 
granular as five minute increments, but, more likely, larger time 
periods that could be as long as an hour). Such forecasts are used to 
develop transmission line ratings that can be depended on by system 
operators for a specified period (e.g., an hour or 15 or 5 minutes). 
Under DLR approaches, the use of additional data (beyond the ambient 
temperature data used in AAR approaches) can allow DLRs to even more 
accurately reflect transfer capability.
    26. DLR methodologies usually result in higher transmission line 
ratings relative to AAR and other methodologies. However, as discussed 
above for AAR, for a small percentage of intervals, DLRs will identify 
that the near-term weather and/or other conditions are actually more 
extreme than the assumptions under other methodologies, and will 
therefore result in a line rating that is lower than a static, 
seasonal, or AAR rating would have allowed. Moreover, the additional 
weather and conductor data that the sensors can provide, such as wind 
speed and direction, solar irradiance intensity, precipitation, and 
line conditions such as tension and sag, improve operational and 
situational awareness by helping transmission operators to better 
understand real-time transmission line conditions and potential 
anomalies, such as possible clearance violations or galloping.
    27. While DLRs have unique benefits, they also have unique 
implementation challenges. The additional data and communications 
required under DLR approaches increase implementation costs and system 
complexity. DLR implementation requires the strategic deployment and 
maintenance of sensors. By increasing the amounts of transmission line 
rating data and by introducing additional communication nodes inside a 
transmission owner network, DLRs introduce additional physical and 
cyber security risks.

[[Page 6425]]

Moreover, DLRs can require additional training or knowledge for some 
transmission providers or transmission owner personnel.
    28. DLRs are not widely deployed in the United States. Transmission 
owners have tested DLRs on some transmission lines,\41\ but they 
generally have not incorporated DLRs into operations. For transmission 
owners in RTOs/ISOs, they must also work with the RTO/ISO to determine 
whether RTO/ISO Energy Management Systems (EMSs) are able to accept a 
frequently changing transmission line rating signal. If the RTO/ISO EMS 
cannot accept the information provided by DLRs, such a limitation would 
significantly reduce the potential benefits of DLRs.
---------------------------------------------------------------------------

    \41\ For example, some prominent DLR pilot projects have been 
undertaken in ERCOT, NYISO, and PJM. In ERCOT, ONCOR tested 
conductor tension-monitor technology, conductor sag, and clearance 
monitors on eight transmission circuits (138 kilovolt (kV) and 345 
kV). In NYISO, the New York Power Authority partnered with the 
Electric Power Research Institute to install sensor technology 
designed to measure conductor temperature, weather conditions, and 
conductor sag on three 230 kV ransmission lines. In PJM, pilot 
studies were conducted on the 345 kV Cook-Olive transmission line 
and an additional line to quantify the financial impact of DLRs.
---------------------------------------------------------------------------

    29. Several participants at the September 2019 Technical 
Conference, have already implemented AARs, including AEP, Dominion, 
Entergy, and Exelon. ERCOT explained in its testimony that, of its 
nearly 7,000 transmission lines, approximately two thirds are rated 
dynamically using a process comparable to what we refer to as AARs.\42\ 
Likewise, PJM explained in its post-conference comments that use of 
AARs is commonplace among the overwhelming majority of transmission 
owners in the PJM region.\43\ According to Potomac Economics, Entergy 
and one additional transmission line owner implement AARs in MISO.\44\ 
Outside of ERCOT and PJM, most transmission owners implement seasonal 
transmission ratings. Seasonal ratings are the norm among non-RTO/ISO 
transmission owners as well as in CAISO, ISO-NE, NYISO, MISO, and SPP, 
although at least some transmission owners in RTO/ISO regions use 
static ratings.\45\
---------------------------------------------------------------------------

    \42\ September 2019 Technical Conference, AD19-15, Day One Tr. 
at 79 (filed Oct. 8, 2019) (September 2019 Technical Conference, Day 
1 Tr.).
    \43\ PJM Comments at 2 (citing Testimony of Michael Kormos 
(Exelon) at 1. (``Exelon has adopted ambient-adjusted facility 
ratings for the transmission facilities of five of our six 
utilities, with Commonwealth Edison scheduled to complete the 
transition to ambient-adjusted facility ratings next year.''); 
Testimony of Francisco Velez (Dominion) at 2-3.
    \44\ Potomac Economics Comments at 6-7.
    \45\ Commission Staff Paper at 2, 12.
---------------------------------------------------------------------------

C. Emergency Ratings

    30. For short periods of time, most transmission equipment can 
withstand high currents without sustaining damage. This fact allows 
transmission owners to develop two sets of ratings for most facilities: 
Normal ratings and emergency ratings. Normal ratings are ratings that 
can be safely used continuously (i.e., not time-limited) without 
overheating the transmission equipment. Emergency ratings are ratings 
that can be safely used for a limited period of time. This period of 
time can vary from as short as five minutes to as long as four hours or 
more.\46\
---------------------------------------------------------------------------

    \46\ In practice, emergency ratings can vary significantly in 
duration. As was observed in the September 2019 Technical 
Conference, there does not appear to be clear standardization of the 
emergency rating timeframes. September 2019 Technical Conference, 
Day 1 Tr. at 175.
---------------------------------------------------------------------------

    31. Whether and how a transmission owner establishes emergency 
ratings is important because emergency ratings are a critical input 
into determining operating limits in market models, both during normal 
operations and during post-contingency operations. In general, 
operating limits (i.e., the maximum allowable MW flow) for any facility 
or set of facilities are set at a level to ensure that the flows on all 
facilities will be within applicable facility ratings both during 
normal operations and during post-contingency operations. Therefore, 
these operating limits create binding transmission constraints and 
result in congestion during normal operations and post-contingency, 
which increases the cost of production for electric energy. Following a 
contingency, if a transmission provider is able to use emergency 
ratings, system operators are afforded the flexibility to allow higher 
loading on transmission facilities for a short time while they 
reconfigure the transmission system, dispatch generation, or take other 
measures (e.g., load shedding) to stabilize the system and return it to 
within normal limits. Because emergency ratings are generally higher 
than normal ratings, using emergency ratings allows for higher 
operating limits, and, thus, more efficient system commitment and 
dispatch solutions. More efficient commitment and dispatch solutions, 
in turn, reduce the prices paid by consumers for electric energy.
    32. However, not all transmission owners use emergency ratings that 
are different from their normal ratings. For example, Potomac 
Economics, the market monitor for MISO, NYISO, ISO-NE, and ERCOT, notes 
that while MISO requires transmission owners to submit both normal and 
emergency ratings, 63% of transmission line ratings provided to MISO 
reflect emergency ratings that are equal to the normal ratings.\47\ 
Generally, RTOs/ISOs do not require unique emergency ratings. Instead, 
transmission owners can decide whether to submit unique emergency 
ratings, or whether to submit emergency ratings that equal their normal 
ratings.\48\
---------------------------------------------------------------------------

    \47\ September 2019 Technical Conference, Day 2 Tr. at 311-312.
    \48\ For example, SPP and ISO-NE allow their transmission owners 
to use unique emergency ratings, but neither RTO/ISO specifically 
requires them, see SPP Planning Criteria, Revision 2.2 (3/16/2020), 
Section 7.2. See also ISO-NE, ISO New England Planning Procedure No. 
7: Procedures for Determining and Implementing Transmission Facility 
Ratings in New England (Revision 4) (Nov. 7, 2014), https://www.iso-ne.com/static-assets/documents/rules_proceds/isone_plan/pp07/pp7_final.pdf.
---------------------------------------------------------------------------

D. Rating and Methodology Transparency

    33. There are two categories of information relevant to 
transparency concerns: Transmission line rating methodologies and the 
resulting transmission line ratings. Generally, transmission line 
ratings and ratings methodologies are not currently available to 
transmission providers or the public at large, although certain 
transmission owners and/or operators make public their transmission 
line ratings and, less commonly, their ratings methodologies. Certain 
transmission providers explained that they do not provide such 
information because it is governed by confidentiality restrictions.\49\
---------------------------------------------------------------------------

    \49\ MISO Transmission Owners claim that some of the information 
related to the limiting element used to establish a transmission 
line rating is ``confidential.'' MISO Transmission Owners Comments 
at 20; Dominion claims that FAC-008's Requirement 8 requires 
confidential sharing of limiting element information only with 
``associated Reliability Coordinator(s), Planning Coordinator(s), 
Transmission Planner(s), Transmission Owner(s) and Transmission 
Operator(s) when requested.'' Dominion Comments at 14.
---------------------------------------------------------------------------

    34. The Commission Staff Paper observed that some entities noted 
the lack of transparency regarding transmission line rating 
information.\50\ At the subsequent September 2019 Technical Conference, 
some participants expressed a desire for additional line rating 
transparency regardless of whether the Commission acts on requirements 
for AARs or DLRs. Potomac Economics stated that additional transparency 
regarding rating methodologies was ``essential'' for administering an 
AAR requirement.\51\

[[Page 6426]]

WATT noted that transmission owners may have an incentive to be overly 
conservative with their line rating methodologies and that increasing 
transparency around these methodologies could improve efficiency.\52\
---------------------------------------------------------------------------

    \50\ Commission Staff Paper at 28.
    \51\ September 2019 Technical Conference, Day 2 Tr. at 309.
    \52\ September 2019 Technical Conference, Day 1 Tr. at 23.
---------------------------------------------------------------------------

    35. At the September 2019 Technical Conference, panelists also 
discussed auditing of line ratings and rating methodologies. Panelists 
disagreed over whether methodologies and ratings were sufficiently 
audited by NERC Regional Entities or other parties to ensure just and 
reasonable rates.
    36. Separate from the outreach and technical conference 
discussions, NERC Reliability Standard FAC-008-3 requires transmission 
owners to document their facility ratings methodology. While NERC 
Regional Entities are responsible for auditing line ratings for 
compliance with Reliability Standards, FAC-008-3 Requirement R8 allows 
other entities, including other transmission service providers, 
planning coordinators, reliability coordinators, or transmission 
operators, to request facility ratings up to 13 months later for 
internal examination.\53\ Such data requests remain non-public.
---------------------------------------------------------------------------

    \53\ NERC Reliability Standard FAC-008-3--Facility Ratings, 
Requirement R8.
---------------------------------------------------------------------------

    37. Lastly, some transmission owners periodically report rating 
methodologies in FERC Form 715, Part IV.\54\
---------------------------------------------------------------------------

    \54\ FERC Form 715 is a multi-part annual transmission planning 
and evaluation report which each transmitting utility that operates 
integrated transmission system facilities rated at or above 100 
kilovolts (kV), must annually submit.
---------------------------------------------------------------------------

IV. Need for Reform

A. Transmission Line Ratings

    38. For the reasons discussed below, we preliminarily find that 
transmission line ratings and the rules by which they are established 
are practices that directly affect the cost of wholesale energy, 
capacity and ancillary services, as well as the cost of delivering 
wholesale energy to transmission customers. Because of those 
relationships, inaccurate transmission line ratings may result in 
Commission-jurisdictional rates that are unjust and unreasonable.
    39. First, most transmission owners implement seasonal or static 
transmission line rating methodologies. Such seasonal or static line 
ratings are based on conservative, worst-case assumptions about the 
long-term conditions, such as the expected high temperatures that are 
likely to occur over the longer term.\55\ While such long-term 
assumptions may be appropriate in various planning contexts, they often 
do not reflect the true near-term transfer capability of transmission 
facilities as relevant to the availability of, and arrangement for, 
point-to-point transmission service. Thus, they fail to reflect the 
true cost of delivering wholesale energy to transmission customers.
---------------------------------------------------------------------------

    \55\ For example, transmission providers appropriately utilize 
conservative long-term assumptions about long-term conditions to 
incorporate requests for long-term firm point-to-point transmission 
service, which the pro forma OATT defines as ``firm point-to-point 
transmission service under Part II of the Tariff with a term of one 
year or more'' (pro forma OATT section 1.19) and requests for 
network integration transmission service, whose applications require 
10-year projections of all network resources (pro forma OATT section 
29.2). Additionally, planning authorities appropriately utilize 
conservative long-term assumptions in the long-term transmission 
planning horizon and the near-term transmission planning horizon.
---------------------------------------------------------------------------

    40. In the RTO/ISO markets, line ratings directly affect the 
dispatch and unit commitment computations by constraining power flows 
on individual transmission facilities. The resulting congestion costs 
are directly reflected in locational marginal prices (LMPs). Outside of 
RTOs/ISOs, LMPs are not generally used; however, transmission line 
ratings can still directly affect the cost to deliver wholesale energy 
to transmission customers by limiting transmission of electric energy 
under both network transmission service and point-to-point transmission 
service offered under the pro forma OATT.
    41. In both RTO/ISO and non-RTO/ISO areas, incorporating near-term 
forecasts of ambient air temperatures in transmission line ratings 
would result in more accurately reflecting the actual cost of 
delivering wholesale energy to transmission customers. Because actual 
ambient temperatures are usually not as high as the ambient 
temperatures conservatively assumed in seasonal and static ratings, 
updating transmission line ratings used in near-term transmission 
service to reflect ambient temperatures usually results in increased 
system transfer capability. By increasing transfer capability, 
congestion costs will, on average, decline because transmission 
providers will be able to import less expensive power into what were 
previously constrained areas. For example, Potomac Economics has found 
that AAR implementation by those not already doing so in MISO alone 
would have produced approximately $94 million and $78 million in 
reduced congestion costs in 2017 and in 2018, respectively.\56\ Such 
congestion cost changes and related overall price changes will more 
accurately reflect the actual congestion on the system and, similarly, 
more accurately reflect the cost of delivering wholesale energy to 
transmission customers. Likewise, the ability to increase transmission 
flows into load pockets may reduce transmission provider reliance on 
local reserves inside load pockets, which may reduce local reserve 
requirements and the costs to maintain that required level of reserves.
---------------------------------------------------------------------------

    \56\ Potomac Economics Comments at 6-7.
---------------------------------------------------------------------------

    42. While current line rating practices usually understate 
transmission capability, they can also overstate transmission 
capability. While actual ambient temperatures are usually not as high 
as the assumed seasonal or static temperature input, in some instances 
actual ambient temperatures exceed those assumed temperatures. In those 
instances, seasonal or static transmission line rating methodologies 
result in ratings that reflect more transfer capability than physically 
exists, and therefore such line ratings allow access to some electric 
power supplies and/or demand that would not be available if ratings 
reflected the true transfer capability. Overstating transmission 
capability, like understating transmission capability, results in 
wholesale energy rates that fail to reflect the actual cost of 
delivering wholesale energy to transmission customers, but, by 
contrast, results in inaccurately low congestion pricing. Moreover, 
overstating transmission capability may risk damage to equipment, and 
may prevent occurrences of rates for scarcity pricing or transmission 
constraint penalty factors that serve as important signals to the 
market that more generation and/or transmission investment may be 
needed in the long-term.
    43. Second, regarding potential DLR implementation, some RTOs/ISOs 
may rely on software that cannot accommodate line ratings that 
frequently change, such as DLRs. Without reflecting such frequent 
changes to line ratings, such software may serve as a barrier that 
prevents transmission owners in RTOs/ISOs from implementing DLRs that 
can better reflect the actual transmission capability of the 
transmission system. As noted above, in addition to ambient air 
temperature, other weather conditions such as wind, cloud cover, solar 
irradiance intensity, and precipitation, and transmission line 
conditions such as tension and sag, can affect the

[[Page 6427]]

amount of transfer capability of a given transmission facility. DLRs 
incorporate these additional inputs and thereby provide transmission 
line ratings that are closer to the true thermal transmission line 
limit than AARs, which can result in rates that even more accurately 
reflect the costs of delivering wholesale energy to transmission 
customers. But, even if a transmission owner sought to implement DLRs, 
the RTO/ISO's EMS may not be able to accept and use the resulting 
transmission line rating. This inability to automatically accept and 
use a DLR may prevent the market from benefiting from the more accurate 
representation of current system conditions that would otherwise 
produce prices that more accurately reflect the costs of delivering 
wholesale energy to transmission customers. Therefore, we preliminarily 
find that current transmission line rating practices in RTOs/ISOs that 
do not permit the acceptance of DLRs from transmission owners may 
result in rates that do not reflect the actual costs of delivering 
wholesale energy to transmission customers.
    44. Third, regarding emergency ratings, current transmission line 
rating practices may fail to use emergency ratings, and in failing to 
do so, may result in ratings that do not accurately reflect the near-
term transfer capability of the system and therefore may result in 
rates that do not reflect actual costs to delivering wholesale energy 
to transmission customers. As discussed above, transmission owners 
often develop two sets of ratings for most facilities: Normal ratings 
that can be safely used continuously, and emergency ratings that can be 
used for a specified shorter period of time, typically during post-
contingency operations.
    45. In RTO/ISO markets, market models, such as security-constrained 
economic dispatch (SCED) and security-constrained unit commitment 
(SCUC) models, generally calculate resource dispatch and commitments 
that ensure that all facilities will be within applicable facility 
ratings both during normal operations and following any modeled 
contingency (e.g., following the loss of a transmission line). In 
ensuring that the system is stable and reliable following a 
contingency, SCED and SCUC models often allow post-contingency flows on 
lines to exceed normal ratings for short periods of time, as long as 
the flows do not exceed the applicable emergency rating for the 
corresponding timeframe. Because these emergency ratings are a more 
accurate representation of the flow limits over those shorter 
timeframes, their use in models of post-contingency flows may produce 
prices which more accurately reflect actual costs to delivering 
wholesale energy to transmission customers.
    46. While most or all RTO/ISO markets consider both normal and 
emergency ratings as part of their SCUC and SCED models, not all 
transmission owners have chosen to incorporate unique emergency ratings 
into their transmission line rating methodologies. That is, some 
transmission owners in RTO/ISO regions provide to the RTOs/ISOs 
emergency ratings that are just a copy of the normal ratings,\57\ 
essentially creating the same situation as if the RTO/ISO did not use 
emergency ratings at all when modeling contingencies. As discussed 
above, this may result in the use of less accurate flow limits, and 
less accurate costs for delivering wholesale energy to transmission 
customers. According to Potomac Economics, for example, this failure to 
implement unique emergency ratings resulted in approximately $62 
million and $68 million in additional costs in 2017 and in 2018, 
respectively, in MISO alone.\58\ Therefore, we seek comment on whether 
not using unique emergency ratings, as discussed below, similarly may 
not be just and reasonable.
---------------------------------------------------------------------------

    \57\ Here we are describing the situation where the emergency 
ratings are arbitrarily set equal to the normal ratings. On the 
other hand, there may be some instances where, after a proper 
technical analysis considering the relevant rating timeframes, the 
emergency rating is nonetheless equal to the normal rating. As 
relevant to the discussion here, such ratings would be considered 
``unique'' because they were developed from the appropriate, unique 
technical inputs.
    \58\ Potomac Economics Comments at 6-7.
---------------------------------------------------------------------------

B. Transparency

    47. We preliminarily find that the current level of transparency 
into transmission line ratings and transmission line rating 
methodologies may result in unjust and unreasonable rates. The current 
level of transparency may prevent transmission provider(s) and market 
monitors from having the opportunity to validate transmission line 
ratings. This may result in transmission owners submitting inaccurate 
near-term transmission line ratings, which may result in rates that do 
not accurately reflect congestion and reserve costs on the system, as 
discussed above. For example, without knowing the basis for a given 
line rating that frequently binds and elevates prices, a transmission 
provider and/or market monitor cannot determine whether the line rating 
is miscalculated or accurately calculated.

V. Discussion

A. Transmission Line Ratings

1. Comments
a. Ambient-Adjusted Line Ratings
    48. At the September 2019 Technical Conference, participants and 
staff explored whether the Commission should require the implementation 
of AARs.\59\ Several participants supported a requirement to implement 
AARs, with several stating their support for AAR implementation as a 
best practice. Supporters contend that while AAR implementation 
requires an initial investment to upgrade the EMS, these costs are a 
manageable way to increase transfer capability.\60\ Potomac Economics 
noted that significant economic benefits would have accrued to market 
participants if all MISO transmission owners had implemented AARs and 
unique emergency ratings.\61\
---------------------------------------------------------------------------

    \59\ Panelists participating in the discussion of a potential 
requirement to implement AARs included representatives from AEP, 
Ameren (on behalf of the MISO Transmission Owners), CAISO, Entergy, 
PacifiCorp, Potomac Economics, and Vistra Energy.
    \60\ September 2019 Technical Conference, Day 1 Tr. at 142.
    \61\ Id. at 171.
---------------------------------------------------------------------------

    49. Several participants did not support an AAR requirement. 
Ameren, on behalf of the MISO Transmission Owners, argued that AAR 
implementation would be costly and complex. PacifiCorp argued that the 
benefits of implementing AARs and DLRs would not materialize on all 
lines, and therefore cautioned that the Commission should not require 
AAR implementation on all lines.\62\ Finally, Ameren argued that 
because forecasting was necessary for day-ahead AAR implementation, 
there could be liability associated with an incorrect forecast.\63\
---------------------------------------------------------------------------

    \62\ Id. at 163.
    \63\ Id. at 148.
---------------------------------------------------------------------------

    50. Following the September 2019 Technical Conference, the 
Commission requested comments on all conference discussion items, 
including the appropriateness of a Commission requirement to implement 
AARs, how a requirement might be structured, whether an AAR requirement 
should be extended to day-ahead markets, and whether any forecasted 
ambient conditions other than temperature should be considered in an 
AAR requirement.
    51. Many entities filed comments in support of a requirement to 
implement AARs, noting that an AAR requirement represents a cost-
effective industry best practice that would achieve significant savings 
to ratepayers. Some transmission owners reiterated points

[[Page 6428]]

made in the September 2019 Technical Conference. AEP explains that it 
has used AARs in real-time operations for more than a decade and that 
it monitors temperature zones in its regions and retrieves real-time 
temperature data for every state estimation process run. AEP states 
that AARs using real-time and next day forecasted regional temperatures 
can benefit customers and bring flexibility to transmission 
operations.\64\
---------------------------------------------------------------------------

    \64\ AEP Comments at 2.
---------------------------------------------------------------------------

    52. Dominion explains that requiring the use of AARs, rather than a 
default temperature assumption that is ``too conservative,'' will allow 
transmission line ratings to better reflect forecasted conditions. 
Dominion cautions, however, against AARs that make overly aggressive 
assumptions, which would also result in the transmission system being 
operated ``less conservatively'' and a degradation of grid 
reliability.\65\
---------------------------------------------------------------------------

    \65\ Dominion Comments at 3-4.
---------------------------------------------------------------------------

    53. Similarly, Exelon states that it would not oppose a properly 
structured requirement to implement AARs in both real-time and day-
ahead markets. Exelon explains that AARs represent a best practice and 
a cost-effective way to enhance transmission use to the benefit of 
customers.\66\ As background, Exelon explains that PJM requires its 
transmission owners to provide ambient temperature-dependent ratings 
for both daytime and nighttime periods (which account for the presence 
or lack of solar irradiance heating), and for normal, long-term 
emergency, short-term emergency, and load dump conditions.\67\ Exelon 
explains that implementing AARs results in more accurate transmission 
line ratings, reducing the likelihood of overloading a line and thus 
creating reliability benefits. Exelon reiterates its comments from the 
conference that, while implementing AARs requires initial investments, 
AARs are a cost-effective way to reduce congestion and enhance 
reliability.\68\
---------------------------------------------------------------------------

    \66\ Exelon Comments at 1.
    \67\ Id. at 25-26.
    \68\ Id. at 1, 9.
---------------------------------------------------------------------------

    54. While generally supporting a requirement to implement AARs, 
AEP, Dominion, and Exelon express caution and request flexibility 
regarding AAR implementation. Dominion explains that it would not 
support a requirement for AAR implementation to be fully automated.\69\ 
Dominion and Exelon warn that AAR implementation will not eliminate 
congestion.\70\ Exelon further cautions that an AAR requirement should 
only apply to transmission facility ratings sensitive to temperature 
changes,\71\ that transmission owners should have flexibility to 
determine appropriate temperature granularity,\72\ and that it may not 
be appropriate to apply AARs to certain degraded or older assets.\73\ 
AEP cautions that entities that have not implemented AARs before will 
incur some up-front costs, including internal process development and 
documentation costs, weather data subscriptions, software changes, and 
training, but explains that these costs should be manageable.\74\ 
Exelon and AEP both also caution that AAR implementation should be 
applied only to real-time and day-ahead markets and should not be 
considered permanent solutions to address thermal constraints 
identified in long-term transmission planning reliability 
assessments.\75\
---------------------------------------------------------------------------

    \69\ Dominion Comments at 5-6.
    \70\ Exelon Comments at 10; Dominion Comments at 11.
    \71\ Exelon Comments at 22-23.
    \72\ Id. at 24.
    \73\ Id. at 23.
    \74\ AEP Comments at 2-3.
    \75\ Exelon Comments at 5; AEP Comments at 3.
---------------------------------------------------------------------------

    55. Both Potomac Economics and Monitoring Analytics support a 
requirement for transmission owners to implement AARs that must be 
updated hourly.\76\ Monitoring Analytics states that the ``failure to 
use AARs means that line ratings in actual use are wrong much of the 
time,'' which they argue is not acceptable.\77\ Potomac Economics 
estimates that adoption of AARs in MISO by those not already doing so 
would have produced approximately $78 million and $94 million in annual 
benefits in 2017 and 2018, respectively. Potomac Economics further 
estimates the savings derived from Entergy and another unnamed MISO 
transmission owner's current AAR implementation to have been $51.3 
million over 2017 and 2018.\78\ Potomac Economics explains that an AAR 
requirement would enhance reliability by increasing operational and 
situational awareness, by ensuring transmission line ratings are more 
accurate, and by ensuring that transmission providers have a better 
understanding of the capabilities of transmission facilities.\79\
---------------------------------------------------------------------------

    \76\ Potomac Economics Comments at 2-3; Monitoring Analytics 
Comments at 5.
    \77\ Monitoring Analytics Comments at 5.
    \78\ Potomac Economics Comments at 6-7. Potomac Economics 
explains that estimates of benefits will necessarily be conservative 
given that the shadow price would increase if the market was 
controlling to a lower rating.
    \79\ Id. at 8.
---------------------------------------------------------------------------

    56. DTE, TAPS, Industrial Customers, and OMS each make supportive 
comments. Citing Entergy's presentation from the September 2019 
Technical Conference, DTE explains that using AARs can increase 
transmission line ratings by up to 25% for lower-voltage facilities and 
by 5% on higher-voltage facilities, and its ongoing implementation 
requires only ``one full-time engineer to maintain the associated in-
house database, perform modeling updates, and liaison with real-time 
system operations personnel and IT resources to support automation of 
the calculations.'' \80\ DTE therefore submits that AARs can be 
implemented without causing any undue burden.\81\ DTE states that 
transmission owners are obligated to implement the most cost-effective 
solution, and given the experience of other transmission owners that 
have successfully implemented AARs, DTE contends that transmission 
owners should be required to implement AARs because they are the most 
cost-effective solution.\82\
---------------------------------------------------------------------------

    \80\ DTE Comments at 2.
    \81\ Id.
    \82\ Id. at 3.
---------------------------------------------------------------------------

    57. TAPS agrees with September 2019 Technical Conference 
participants, such as AEP, who contended that the Commission should 
issue a rulemaking requiring AAR implementation, assuming appropriate 
safeguards.\83\ TAPS encourages a requirement for AAR implementation to 
be part of an effort to ensure more accurate transmission line ratings, 
as part of good utility practice, and focusing AAR application where 
congestion reductions might be most meaningful.\84\ To identify 
locations where AAR application would be beneficial, TAPS explains that 
RTOs/ISOs should have backstop authority to identify transmission 
facility candidates following a transparent process where the RTO/ISO 
is directed to independently evaluate the grid for beneficial AAR 
candidates.\85\ Noting the importance for transmission line ratings to 
be both accurate and applied in a non-discriminatory manner, as well as 
the challenges of ensuring accuracy and preventing discrimination in 
the absence of an independent entity facilitating AAR implementation, 
TAPS explains that the Commission should give serious examination to 
AAR application in non-RTO/ISO regions.\86\
---------------------------------------------------------------------------

    \83\ TAPS Comments at 4-5.
    \84\ Id. at 9.
    \85\ Id. at 10.
    \86\ Id. at 11.
---------------------------------------------------------------------------

    58. Industrial Customers similarly argue that the Commission, at a 
minimum, should require transmission owners to implement AARs on the 
most congested transmission lines and facilities.\87\ Industrial 
Customers explain that AARs provide a more

[[Page 6429]]

accurate representation of ATC and contend that using AARs is good 
utility practice by allowing transmission operators to better optimize 
existing circuits and reduce electric prices.\88\ For these reasons, 
Industrial Customers contend the Commission should require the 
implementation of AARs, but, noting the possibility that a cost-benefit 
comparison may change at a very granular level, only on such facilities 
where AAR implementation is truly cost-effective.\89\
---------------------------------------------------------------------------

    \87\ Industrial Customers Comments at 15.
    \88\ Id. at 14-15.
    \89\ Id. at 14-16.
---------------------------------------------------------------------------

    59. PJM explains that it has derived significant operational value 
in the adoption of AARs, explaining that its use of AARs has allowed it 
to take advantage of additional transfer capability that promotes a 
more reliable system dispatch.\90\
---------------------------------------------------------------------------

    \90\ PJM Comments at 2-3.
---------------------------------------------------------------------------

    60. Other entities, while not outright supporting a requirement for 
AAR implementation, offer a more nuanced view. MISO states that if the 
Commission does require AAR implementation, that requirement should not 
solely focus on congested facilities. MISO explains that any 
transmission facility could become the next most limiting element as 
the system changes, and that therefore AARs should be applied to any 
facility where temperature is a determining factor.\91\
---------------------------------------------------------------------------

    \91\ MISO Comments at 2-3.
---------------------------------------------------------------------------

    61. IEEE and NERC offer limited support for AAR implementation. 
According to IEEE, AARs provide safer transmission line ratings during 
periods of unexpected extreme ambient conditions exceeding the 
assumptions that are the basis for static ratings, provide better use 
of transmission assets, and reduce the need for additional 
infrastructure investment to service anticipated demand.\92\ However, 
IEEE also highlights disadvantages to AAR implementation. These include 
necessary upgrades to EMSs, assurances that a utility's EMS is 
protected from sabotage and cyber tampering, and robust analysis 
protocols needed to convert changing temperatures into updated 
transmission line ratings, as well as additional work needed to 
document AAR protocols in a transmission line rating methodology.\93\ 
NERC cautions that AAR implementation may not increase the reliability 
of transmission lines if implementation is not properly coordinated to 
avoid real-time operational confusion,\94\ citing an example from 
during the 2003 blackout of a transmission line rating discrepancy 
between the transmission owner, transmission operator, and reliability 
coordinator where each had separate transmission line ratings for the 
same facility.\95\
---------------------------------------------------------------------------

    \92\ IEEE Comments at 1.
    \93\ Id. at 2-4.
    \94\ NERC Comments at 3.
    \95\ Technical Conference, Day 1 Tr. at 91.
---------------------------------------------------------------------------

    62. Opposition to a requirement to implement AARs comes primarily 
from MISO Transmission Owners, ITC, EEI, NRECA, WATT, and AWEA. 
Generally, MISO Transmission Owners and ITC state that the industry is 
not ready to support full implementation of AARs or DLRs.\96\ MISO 
Transmission Owners and ITC state that the Commission should allow 
industry to continue to explore the use primarily of AARs and 
secondarily of DLRs through industry groups or pilot programs.\97\ MISO 
Transmission Owners further argue that the Commission should recognize 
that preserving and protecting transmission system reliability is of 
paramount importance, and that tying development and implementation of 
AARs and DLRs to financial incentives or other economic criteria 
without fully understanding and taking into account the impact on 
reliability or safety could be contrary to the reliable and safe 
operation of the transmission grid and create unreasonable risk.\98\ 
One specific cause for concern, according to the MISO Transmission 
Owners and ITC, is that implementation of AARs can reduce some of the 
``margin'' between what the transmission system can actually handle and 
how it is operated.\99\ Moreover, according to MISO Transmission 
Owners, if real-time ambient temperatures are higher or wind is lower 
than forecasted day-ahead rating assumptions, AARs could lower ratings 
near peak load conditions, which could in turn lead to congestion and 
generation redispatch.\100\ Citing safety concerns and the importance 
of ratings to reliability, ITC also warns that the Commission should 
not take any action that conflicts with a transmission owner's NERC's 
obligations.\101\
---------------------------------------------------------------------------

    \96\ MISO Transmission Owners Comments at 1-2; ITC Comments at 
2-3.
    \97\ MISO Transmission Owners Comments at 1-2; ITC Comments at 
2-3.
    \98\ MISO Transmission Owners Comments at 2.
    \99\ Id. at 6; ITC Comments at 3-4.
    \100\ MISO Transmission Owners Comments at 13.
    \101\ ITC Comments at 1.
---------------------------------------------------------------------------

    63. MISO Transmission Owners also contend that the Commission 
should recognize that the benefits that would be realized from the 
adoption of AARs or DLRs will vary by system, and may even vary within 
an RTO/ISO region or within a transmission system.\102\ MISO 
Transmission Owners state that AARs and DLRs may only be cost-effective 
on a subset of transmission lines, and notes that transmission systems 
that are constrained by voltage, stability, or certain substation 
limitations may not benefit from AAR or DLR implementation.\103\ MISO 
Transmission Owners further state that factors such as topology, 
congestion, and localized climate conditions can affect the benefits of 
and need for AARs.\104\ MISO Transmission Owners add that implementing 
and maintaining the necessary sensors and making the other investments 
necessary to implement AARs can be costly, and make the cost of AAR 
implementation similar to that of DLRs implementation.\105\
---------------------------------------------------------------------------

    \102\ MISO Transmission Owners Comments at 14.
    \103\ Id. at 8-9 (citing Commission Staff Paper at 8-9).
    \104\ Id. at 7.
    \105\ Id.
---------------------------------------------------------------------------

    64. MISO Transmission Owners argue that there are additional 
indirect costs to AAR implementation. According to MISO Transmission 
Owners, these indirect costs are primarily liability-related, including 
market liability, safety liability, and reliability liability, and 
these costs would be complex, if not incalculable, to determine.\106\ 
MISO Transmission Owners also argue that, should the Commission require 
AAR implementation, the Commission should not require AARs be used in 
the day-ahead markets.\107\ According to MISO Transmission Owners, 
implementation of AARs in the day-ahead markets would increase 
potential liability and potentially cause congestion. Specifically, 
MISO Transmission Owners imply that liabilities could result from 
adjustments to transmission line ratings in real-time should a 
transmission line rating be determined based on an inaccurate day-ahead 
forecast and cause real-time congestion and generation re-
dispatch.\108\ Therefore, because there are no universal benefits to 
AAR or DLR implementation and because of the resulting direct and 
indirect costs, MISO Transmission Owners argue that no universal 
solution is appropriate.\109\
---------------------------------------------------------------------------

    \106\ Id.
    \107\ Id. at 12-13.
    \108\ Id. at 12-14.
    \109\ Id. at 7.
---------------------------------------------------------------------------

    65. EEI echoes many of MISO Transmission Owners' arguments in its 
opposition to an AAR requirement. EEI explains that because of the 
initial investment costs, and because the benefits to AAR 
implementation would vary considerably, a one-size-fits-all requirement 
to implement AARs would

[[Page 6430]]

not be appropriate.\110\ EEI further states that, by requiring 
transmission owners to consider ambient conditions in transmission line 
ratings, NERC Reliability Standard FAC-008-3 creates a meaningful 
incentive for transmission owners to implement AARs. Specifically, EEI 
argues that transmission owners are required to consider ambient 
temperatures under FAC-008-3, and are also required rate their lines 
using technically sound principles, and therefore, any further 
requirement to implement AARs is unnecessary.\111\ EEI emphasizes that 
AARs and DLRs are only appropriate for real-time and near-real-time 
operations and are not appropriate to use in system planning.\112\
---------------------------------------------------------------------------

    \110\ EEI Comments at 5-7.
    \111\ Id. at 7-8.
    \112\ Id. at 9-10.
---------------------------------------------------------------------------

    NRECA states that while it would support a reasoned approach to 
implementing transmission line rating changes, it does not support a 
Commission mandate to implement either AARs or DLRs.\113\ NRECA does 
not oppose the use of AARs or DLRs in operations if there are consumer 
benefits to be gained, but contends that safety and reliability should 
remain the foremost considerations. Further, NRECA agrees with 
September 2019 Technical Conference participants who recommended 
against ``one-size-fit-all'' requirements for transmission ratings and 
ratings methodologies and, citing the September 2019 Technical 
Conference, explained that it would not be cost-effective to implement 
AARs or DLRs on all transmission lines.\114\ For these reasons, NRECA 
emphasizes the need for flexibility to balance the cost and benefits of 
implementing these rating methods. Moreover, NRECA explains that a one-
size fits-all approach poses a distinct risk to Western states and 
NRECA members in particular, since an AAR or DLR mandate would increase 
transmission costs disproportionately for rural consumers.\115\
---------------------------------------------------------------------------

    \113\ NRECA Comments at 2-5.
    \114\ Id. at 4 (citing the opening statements of Dennis D. 
Kramer on behalf of the MISO Transmission Owners and Rikin Shah on 
behalf of PacifiCorp, located in Technical Conference, Day 1 Tr. at 
147 and 163-65, respectively).
    \115\ Id. at 5-6.
---------------------------------------------------------------------------

    66. WATT asserts that transmission owners should not be required to 
implement AARs everywhere because, according to WATT, AARs are not 
sufficiently conservative.\116\ WATT argues that at times, AAR 
implementation may not be conservative enough because AAR 
implementation can assume too much wind, causing transmission line 
ratings to be too high, and possibly result in safety violations.\117\ 
Specifically, WATT explains that wind speeds assumed by IEEE and the 
International Council on Large Electric Systems studies may be too high 
at certain temperatures and result in transmission line ratings that 
exceed what a transmission line can safely handle.\118\
---------------------------------------------------------------------------

    \116\ WATT Comments at 2.
    \117\ Id. at 2-5.
    \118\ Id. at 2-4.
---------------------------------------------------------------------------

    67. Finally, rather than recommend Commission action to require 
AARs, AWEA recommends a process whereby transmission owners should be 
required to disclose transmission line ratings and, for lines whose 
limiting element is an overhead conductor, perform a cost-benefit study 
of the deployment of DLR or other congestion mitigation 
technologies.\119\ AWEA further contends that for lines that are not 
conductor-limited, transmission owners should be required to perform a 
cost-benefit study of the upgrade of the terminal equipment or other 
congestion mitigation technologies.\120\ However, in the absence or 
delay of DLR implementation, AWEA adds that AARs also present benefits 
and should be considered for implementation.\121\
---------------------------------------------------------------------------

    \119\ AWEA Comments at 2.
    \120\ Id.
    \121\ Id.
---------------------------------------------------------------------------

b. Dynamic Line Ratings
    68. WATT states that DLRs are more accurate than AARs, and that 
DLRs reduce uncertainty relative to AARs by providing accurate 
information about sag, clearances, and conductor temperatures.\122\ 
WATT recommends transmission owners be required to, for each line that 
is or is forecast to become heavily congested, disclose nominal ratings 
and perform a cost-benefit study of the deployment of DLRs, other 
congestion mitigation technologies, and/or upgrading the terminal 
equipment, as appropriate.\123\ WATT concedes that security can be a 
concern, but should not be used as a red herring to avoid improvements 
to the grid's reliability and efficiency.\124\
---------------------------------------------------------------------------

    \122\ WATT Comments at 5.
    \123\ Id. at 2-5.
    \124\ WATT Reply Comments at 4.
---------------------------------------------------------------------------

    69. Some commenters recommend pilot programs, a limited or staged 
implementation of DLRs, and/or requirements to ensure transmission 
operators can accept and use DLRs, noting these would be helpful in 
overcoming the challenges related to DLR implementation. Monitoring 
Analytics recommends that the Commission direct all transmission owners 
in PJM to start DLR pilot programs.\125\ PJM also supports DLR pilot 
projects, and notes that DLR pilot projects have already taken place on 
its system.\126\ Dominion states that it has partnered with LineVision 
and EPRI in pilot projects focused on evaluating DLR sensor 
installations and validating the sensors' data, and contends that more 
pilot programs could facilitate the adoption of DLRs.\127\ Potomac 
Economics and MISO state that they do not oppose DLR implementation, 
but contend that AAR implementation should be prioritized.\128\ In 
considering where to begin DLR implementation, WATT contends that the 
Commission could consider factors such as whether a line is thermally 
limited, congested, or the average wind speed or other weather 
parameters would have a strong bearing on the line's rating. WATT also 
contends that DLRs should be made available at a customer's 
request.\129\
---------------------------------------------------------------------------

    \125\ Monitoring Analytics Comments at 5-6.
    \126\ PJM Comments at 1, 4-6.
    \127\ Dominion Comments at 8-9.
    \128\ MISO Comments at 3, 6; Potomac Economics Comments at 13.
    \129\ WATT Reply Comments at 3.
---------------------------------------------------------------------------

    70. Although some commenters highlight the benefits of DLRs, others 
stress the challenges associated with DLR implementation. For example, 
Dominion cautions that DLRs provide only marginal benefits compared to 
AAR implementation in real-time operations, but also include additional 
challenges, increased operational burdens, and likely higher 
uncertainty.\130\ MISO, PJM, and MISO Transmission Owners caution that 
data verification would be necessary when implementing DLRs to protect 
against intrusion and corruption.\131\ MISO Transmission Owners further 
caution that implementation of DLRs is likely to be complex, resource-
intensive, and costly.\132\ EEI and Exelon note that implementing DLRs 
includes additional challenges, such as placing sensors in remote 
locations, ensuring the cyber security of sensors, and various 
additional costs.\133\ Other commenters urge the Commission to exercise 
caution regarding further DLR requirements, including ITC, MISO, and 
PJM,\134\ which explain that DLR is a technology still under 
development and therefore further pilot projects to evaluate the 
appropriateness of DLR requirements

[[Page 6431]]

are needed \135\ and also that, since AAR implementation is more cost-
effective, DLR cost-effectiveness should be reevaluated in light of any 
AAR requirement.\136\
---------------------------------------------------------------------------

    \130\ Dominion Comments at 8-11.
    \131\ MISO Comments at 8-9; PJM Comments at 8; MISO Transmission 
Owners Comments at 25.
    \132\ MISO Transmission Owners Comments at 15-16, 25.
    \133\ EEI Comments at 8-10; Exelon Comments at 11-13.
    \134\ ITC Comments at 3-4; MISO Comments at 5-6; PJM Comments at 
4-6.
    \135\ PJM Comments at 5-6; ITC Comments at 3-4.
    \136\ MISO Comments at 6.
---------------------------------------------------------------------------

    71. Comments indicate that the ability to incorporate DLRs is 
uneven. Dominion states that its EMS cannot incorporate DLRs, and that, 
while PJM's EMS can accept DLRs, that capability is unused. Dominion 
states that relative to AAR implementation, EMS upgrades are typically 
needed to support DLRs, which would require fundamental data schema 
updates. Dominion notes that most ``off-the-shelf'' EMSs can 
accommodate AARs because they have alternative line ratings sets that 
can be switched on or off according to ambient temperature.\137\
---------------------------------------------------------------------------

    \137\ Dominion Comments at 8.
---------------------------------------------------------------------------

    72. MISO contends that it can accept DLRs, but not the information 
necessary to calculate the rating itself.\138\ MISO Transmission Owners 
state that some RTOs/ISOs may have the capability now to change 
transmission line ratings ``on-the-fly'' through their EMSs, while 
other RTOs/ISOs and their transmission owners would have to update and 
revise multiple systems to use DLRs in real-time and day-ahead 
markets.\139\ WATT concurs, explaining that RTOs/ISOs and transmission 
operators currently vary in their ability to incorporate DLRs based on 
various factors.\140\
---------------------------------------------------------------------------

    \138\ MISO Comments at 5.
    \139\ MISO Transmission Owners Comments at 16.
    \140\ WATT Comments at 7.
---------------------------------------------------------------------------

    73. The idea of requiring studies on the cost-effectiveness of DLRs 
was generally supported, but commenters disagreed on study details and 
on whom should conduct the study. WATT and Industrial Customers 
recommend that RTOs/ISOs study the benefits and effectiveness of DLR on 
the most congested, thermally limited lines.\141\ Dominion states that 
it is open to studying its most congested lines to determine DLR's 
cost-effectiveness, but argues that PJM is better suited to assess the 
costs and congestion relief associated with DLR adoption.\142\
---------------------------------------------------------------------------

    \141\ Id.; Industrial Customers Comments at 16.
    \142\ Dominion Comments at 10-11.
---------------------------------------------------------------------------

    74. MISO Transmission Owners suggest that there may be no single 
metric for determining which congested lines to target.\143\ Exelon 
states that a DLR cost-effectiveness study could duplicate existing 
processes, noting that in PJM, transmission owners are able to propose 
advanced technologies as possible transmission solutions.\144\
---------------------------------------------------------------------------

    \143\ MISO Transmission Owners Comments at 16-17.
    \144\ Exelon Comments at 29-30.
---------------------------------------------------------------------------

c. Emergency Ratings
    75. At the September 2019 Technical Conference, Entergy stated that 
it uses short-term emergency ratings on less than 10% of its 
facilities.\145\ In explaining its reluctance to implement emergency 
ratings, Entergy stated that the use of emergency ratings carries a 
high degree of risk based on its potential to degrade the applicable 
transmission facility, and that the risk and trade-offs must be very 
carefully balanced.\146\ Moreover, given the reliability risks, Entergy 
further contended that emergency ratings should not be used for 
economic purposes.\147\
---------------------------------------------------------------------------

    \145\ Technical Conference, Day 1 Tr. at 159.
    \146\ Id.
    \147\ Id. at 293-94.
---------------------------------------------------------------------------

    76. While most post-September 2019 Technical Conference comments 
focused on normal ratings, some commenters also described the current 
implementation and availability of emergency ratings, typically used 
for specific durations post-contingency. Commenters discussing 
emergency ratings include Exelon, PJM, Dominion, Industrial Customers, 
Potomac Economics, and Monitoring Analytics.
    77. Exelon and Monitoring Analytics note that, in addition to 
normal transmission line ratings, PJM transmission owners are required 
to provide short-term emergency transmission line ratings, long-term 
emergency transmission line ratings, and load-dump transmission line 
ratings.\148\ Exelon states that, like AARs, emergency ratings also may 
not be sensitive to changes in ambient air temperatures if the 
equipment rating is not sensitive to ambient air temperatures or if the 
transmission facility is not thermally limited.\149\ Monitoring 
Analytics explains that while PJM typically uses the long-term four-
hour emergency rating in SCED/SCUC modeled contingencies, there is no 
requirement that the ratings differ for these operating 
conditions.\150\
---------------------------------------------------------------------------

    \148\ Exelon Comments at 25; Monitoring Analytics Comments at 3.
    \149\ Exelon Comments at 10.
    \150\ Monitoring Analytics Comments at 3.
---------------------------------------------------------------------------

    78. PJM points out that any permitted use of emergency ratings is 
documented within PJM manuals.\151\ Dominion explains that the 
implementation of emergency ratings, if used, typically assumes first 
or second contingency conditions, and that the development and usage of 
emergency ratings should be documented in each transmission owner's 
transmission line rating methodology.\152\ Finally, Industrial 
Customers clarify that PJM's tariff allows certain flowgate 
calculations to use emergency ratings.\153\
---------------------------------------------------------------------------

    \151\ PJM Comments at 7.
    \152\ Dominion Comments at 15.
    \153\ Industrial Customers Comments at 17.
---------------------------------------------------------------------------

    79. Potomac Economics explains that because most binding real-time 
constraints are based on contingencies, operators model the additional 
flows that would occur on a monitored facility post-contingency, and 
MISO must be prepared to return flows below normal ratings within the 
prescribed time period. Thus, Potomac Economics states that unique 
emergency ratings may enable operating at higher levels for longer 
post-contingency.\154\ Potomac Economics and Industrial Customers \155\ 
explain that the MISO Transmission Owners Agreement calls for 
transmission owners to provide emergency ratings, which can reliably 
accommodate flow for two to four hours, for all contingency 
constraints.\156\ However, Potomac Economics notes that 63% of all 
post-contingency ratings used by MISO are actually the normal 
ratings.\157\ Had unique emergency ratings been used in MISO, Potomac 
Economics contends, the market cost savings would have been 
approximately $62 and $68 million in 2017 and 2018, respectively.\158\
---------------------------------------------------------------------------

    \154\ Potomac Economics Comments at 4.
    \155\ Industrial Customers Comments at 12 (citing MISO, MISO 
Rate Schedules, Transmission Owner Agreement, Appendix B, Section V 
(30.0.0)).
    \156\ Potomac Economics Comments at 4.
    \157\ Id. at 5.
    \158\ Id. at 6.
---------------------------------------------------------------------------

2. Proposal
    80. To remedy potentially unjust and unreasonable rates, we make 
several proposals related to AARs, DLRs and emergency ratings. We 
propose to require all transmission providers to implement AARs on the 
transmission lines over which they provide transmission service. We 
propose a staggered approach to the proposed AAR requirement that would 
prioritize implementation on congested lines (within one year from the 
date of the compliance filing for implementation of the proposed 
reforms to become effective), and propose to require a less aggressive 
implementation of AARs on all other lines (within two years from the 
date of the compliance filing for implementation of the proposed 
reforms to become effective).
    81. In addition, we propose to require all RTOs/ISOs to implement 
the systems and procedures necessary to allow transmission owners to 
electronically update transmission line ratings at least

[[Page 6432]]

hourly. We also seek comment on whether to apply this requirement to 
transmission providers located outside of RTO/ISO markets.
    82. Finally, with regard to emergency ratings, we seek comment on 
whether to require transmission providers to use unique emergency 
ratings.
a. Ambient-Adjusted Line Ratings and Seasonal Line Ratings
i. Proposed Requirements
    83. Having preliminarily found that the use of transmission line 
ratings that are based on long-term assumptions is not just and 
reasonable, we propose, pursuant to section 206 of the FPA to revise 
the pro forma OATT to require all transmission providers to implement 
AARs and seasonal line ratings on the transmission lines over which 
they provide transmission service, under certain circumstances. This 
requirement would ensure that transmission line ratings accurately 
reflect the availability of transmission in real-time.
    84. In proposing to require the implementation of AARs and seasonal 
transmission line ratings, we propose to define transmission line 
ratings as the maximum transfer capability of a transmission line, 
computed in accordance with a written line rating methodology and 
consistent with Good Utility Practice, considering the technical 
limitations (such as thermal flow limits) on conductors and relevant 
transmission equipment, as well as technical limitations of the 
Transmission System (such as system voltage and stability limits). 
Relevant transmission equipment may include, but is not limited to, 
circuit breakers, line traps, and transformers.
    85. We propose to implement these requirements through a new 
Attachment M to the pro forma OATT titled Transmission Line Ratings. 
Within the proposed Attachment M, different line rating requirements 
would apply in the context of different types of transmission service, 
as discussed below.
(a) Point-to-Point Transmission Service
    86. The first proposed AAR requirement applies to the availability 
of and requests for ``near-term point-to-point transmission service,'' 
(under section 15, section 17, and section 18 of the pro forma OATT) 
which we propose to define as point-to-point transmission service 
ending within 10 days of the date of the request. We propose to require 
transmission providers to use AARs as the relevant transmission line 
ratings when (1) evaluating requests for near-term point-to-point 
transmission service, (2) responding to requests for information on the 
availability of potential near-term point-to-point transmission service 
(including requests for ATC or other information related to potential 
service), and (3) posting ATC or other information related to near-term 
point-to-point transmission service to the their OASIS site. Through 
the definition of ``near-term point-to-point transmission service,'' we 
propose to limit the AAR requirement to requests for transmission 
service ending within 10 days of the date of the request. We propose 
this 10-day limit both because it appears to be a reasonable cut-off 
beyond which forecasts may not be accurate enough for AARs to provide 
significant value, and because we believe such a limit would reasonably 
accommodate requests for weekly point-to-point transmission service. 
However, we seek comment on the appropriateness of this 10-day limit.
    87. For other (longer-term) point-to-point transmission service 
requests, we propose to require transmission providers to use seasonal 
line ratings as the relevant transmission line ratings when (1) 
evaluating requests for such service, (2) responding to requests for 
information on the availability of such service (including requests for 
ATC or other information related to such potential service), and (3) 
posting ATC or other information related to such service to their OASIS 
site. In proposing to require seasonal ratings, however, we propose to 
limit the duration of a season to three months. We do not propose to 
require the use of AARs for evaluations of longer-term service because 
we expect that ambient air temperature forecasts for such future 
periods have more uncertainty than near-term forecasts, and thus tend 
to converge to the longer-term ambient air temperature forecasts used 
in seasonal line ratings.
    88. We also propose to require that transmission providers use AARs 
as the relevant transmission line ratings when determining whether to 
curtail or interrupt point-to-point transmission service (under section 
14.7 of the pro forma OATT) if such curtailment or interruption is both 
necessary because of a reduction in transmission capability anticipated 
to occur (start and end) within the next 10 days. For determining the 
necessity of curtailment or interruption of point-to-point transmission 
service in other (beyond 10 days) situations, we propose to require 
transmission providers to use seasonal line ratings as the relevant 
transmission line ratings.
(b) Network Transmission Service
    89. For network transmission service, we propose to require 
transmission providers to evaluate requests to designate network 
resources (under section 30 of the pro forma OATT) or network load 
(under section 31 of the pro forma OATT) based on seasonal line 
ratings, because such designations are generally long-term requests and 
seasonal line ratings better reflect conditions over a longer-term than 
AARs. In proposing to require seasonal ratings for evaluation of 
network service requests, however, we propose to limit the duration of 
a season to three months. Additionally, we propose to require that 
transmission providers use AARs as the relevant transmission line 
ratings when determining whether to curtail network service or 
secondary network service (under section 33 of the pro forma OATT) or 
redispatch network service or secondary network service (under sections 
30.5 and/or 33 of the pro forma OATT), if such curtailment or 
redispatch is both necessary because of issues related to flow limits 
on transmission lines and anticipated to occur (start and end) within 
10 days of such determination. For determining the necessity of 
curtailment or redispatch of network service or secondary network 
service in other (beyond 10 days) situations, we propose to require 
transmission providers to use seasonal line ratings as the relevant 
transmission line ratings.
(c) RTOs/ISOs
    90. With respect to RTOs/ISOs, we recognize that such entities have 
Commission-approved variations from the pro forma OATT to manage 
congestion and initiate curtailments and/or redispatch of transmission 
service within their footprints (although generally not at their 
borders) through mechanisms such as SCED and SCUC. To accommodate these 
variations, we propose that RTOs/ISOs comply with the proposed 
requirements by revising their tariffs to require implementation of 
AARs within their SCED and SCUC models (and in any relevant related 
models) in both the day-ahead and real-time markets and any intra-day 
reliability unit commitment or reliability assessment commitment. For 
the real-time market, we propose that RTOs/ISOs update the AARs at 
least hourly. For any point-to-point transmission service offered by 
RTOs/ISOs (e.g., at their borders), we propose that the AAR 
requirements discussed above for point-to-point service would apply.

[[Page 6433]]

(d) Implementation Timeline
    91. We propose to apply the proposed requirements for AARs and 
seasonal line ratings to all transmission lines, rather than targeting 
only congested transmission lines, as suggested by some commenters. 
However, we propose to prioritize the implementation of AARs and 
seasonal line ratings on historically congested transmission lines. 
Specifically, we propose to require that AARs and seasonal line ratings 
be implemented on historically congested lines within one year from the 
date of the compliance filing for implementation of any final rule, and 
on all other lines within two years from the date of the compliance 
filing for implementation of any final rule. For purposes of this 
proceeding, we propose that the term ``historically congested line'' 
mean a transmission line that was congested at any time in the five 
years prior to the effective date of any final rule.\159\
---------------------------------------------------------------------------

    \159\ Congestion is a characteristic of the transmission system 
produced by a binding transmission constraint such that the rates 
for wholesale electric energy, exclusive of losses, at different 
locations of the transmission system are not equal.
---------------------------------------------------------------------------

    92. We propose to require implementation of AARs on all 
transmission lines and not only on congested lines, because any 
transmission facility, whether or not historically congested, could 
become the most limiting element as the system changes, a point argued 
by MISO.\160\ The 2019 FERC NERC Staff Report on the January 2018 South 
Central cold weather event illustrates this point.\161\ As shown in 
that event, during times of emergency or system stress, flows may 
change considerably from normal operations and the increased 
transmission capability provided through AARs may prove valuable even 
on lines not typically congested.
---------------------------------------------------------------------------

    \160\ MISO Comments at 2-3.
    \161\ 2019 FERC and NERC Staff Report, The South Central United 
States Cold Weather Bulk Electric System Event of January 17, 2018, 
at 96 (July 2019) (FERC and NERC Staff Report), https://www.ferc.gov/sites/default/files/2020-05/07-18-19-ferc-nerc-report_0.pdf.
---------------------------------------------------------------------------

    93. Nevertheless, we recognize that a staggered implementation 
schedule would allow RTOs/ISOs and transmission owners to focus 
implementation on transmission lines where AAR implementation is likely 
to provide the most benefits and gain operational experience with the 
new AAR requirements prior to full implementation.
(e) Implementation Considerations
    94. As a practical matter, the proposed requirements related to 
AARs and seasonal line ratings would entail specific implementation and 
on-going obligations on the part of the transmission provider. First, 
the proposed AAR requirement would necessitate that transmission 
providers implement an automated system that can take as an input a 10-
day forecast of ambient air temperatures at locations across its 
service area, and calculate up-to-date AAR values for each of the 240 
hours in the next 10 days and for each of their transmission lines. 
Under the proposed requirement, for an AAR value to be ``up-to-date,'' 
a transmission provider must update AAR values at least every hour. We 
propose that transmission providers use such AAR values when evaluating 
requests for transmission service (or developing ATC or other 
information related to potential transmission service) that will occur 
within the next 10 days by determining (among other things) whether the 
transmission provider can accommodate the requested service request 
without violating the AAR in any hour.
    95. Under the proposed AAR requirement, transmission providers 
would also need to arrange to have the appropriate forecasts available 
to support the AAR determinations discussed above. Based on information 
from the 2017 Idaho National Laboratory conference on DLRs, we 
understand that existing users of advanced line ratings such as AARs or 
DLRs use a variety of approaches to produce those ratings and the 
forecasts that underly them. Such approaches range from using vendors 
to handle most of the tasks related to developing forecasts and related 
line ratings, to performing much or most of those tasks in-house based 
on developed expertise and a subscription to a weather data service, 
with various approaches in between. We do not propose to stipulate the 
approach that transmission providers take to develop AAR values under 
our proposed requirements, as long as they execute these 
responsibilities consistent with good utility practice.
    96. The proposed seasonal line rating requirement, as defined in 
proposed Attachment M, would require similar implementation obligations 
as for the proposed AAR requirement discussed above, although for 
seasonal line ratings the transmission provider would be (1) 
calculating line ratings for future years (instead of calculating 
ratings for all hours within the next 10 days for AARs), and (2) 
running the seasonal rating system and calculating seasonal ratings 
every month (instead of calculating AARs at least every hour).
    97. System safety and reliability are paramount to the proposed 
requirements for transmission line ratings. The proposed tariff 
language requires the transmission provider to develop transmission 
line ratings (including the forecasts that underpin AARs and seasonal 
line ratings) consistent with good utility practice, and the definition 
of ``Good Utility Practice'' in section 1.15 of the pro forma OATT 
requires consistency with safety and reliability, among other things. 
While we expect the nature of our proposed requirements to provide 
transmission providers with the latitude (and obligation) to develop 
accurate, safe, and reliable line ratings in the first instance, we 
also propose, in an abundance of caution, to make explicit in the 
tariff language proposed herein that if a transmission provider 
determines, consistent with good utility practice, that it must 
temporarily use a rating different than otherwise required by the 
tariff in order to ensure the safety or reliability of the transmission 
system, it may do so. While we expect that such alternate line rating 
authority would be needed infrequently, if ever, we provide the 
clarification related to such temporary ratings to resolve any instance 
where a transmission provider reasonably believes that the tariff 
requirements for transmission line ratings conflict with system safety 
or reliability.
ii. Justification and Response to Comments
    98. While there are differences across transmission systems, simply 
accounting for ambient air temperatures in transmission line ratings 
can reliably increase power transfer capability and significantly lower 
production costs at a manageable implementation cost.\162\ For example, 
as noted above, Potomac Economics estimates that the benefits to AAR 
implementation in MISO alone would have produced approximately $94 
million and $78 million in reduced congestion costs in 2017 and in 
2018, respectively.\163\ While several entities note implementation 
costs as a barrier, these costs are mostly initial investments in 
upgraded OASIS and/or EMS and ratings databases.\164\ Once

[[Page 6434]]

these systems are upgraded, adding AARs to additional lines appears to 
have a minimal incremental cost.\165\
---------------------------------------------------------------------------

    \162\ AEP Comments at 3.
    \163\ Potomac Economics Comments at 6-7.
    \164\ While most commenters only mention the need for software 
changes (AEP Comments at 3) or mention the need for EMS upgrades and 
ratings databases to ensure AARs are implemented in near-term 
transmission service (Exelon Comments at 5-6), we also note that 
OASIS and/or related systems might also need to be upgraded in order 
to ensure ATC postings for near-term point-to-point transmission 
service transmission service requests also reflect AARs. For this 
reason, we describe initial costs to include OASIS and/or EMS 
upgrade costs.
    \165\ AEP Comments at 2-3.
---------------------------------------------------------------------------

    99. Between the two possible approaches to increasing transmission 
line rating accuracy, AARs and DLRs, our proposal to require 
transmission providers to implement AARs in near-term transmission 
service is based on our preliminary finding that an AAR requirement 
strikes a more appropriate balance between benefits and challenges. 
While DLRs can represent more accurate transmission line ratings than 
AARs, DLRs also present additional costs and challenges that AARs do 
not present. Relative to AARs, these additional costs and challenges 
include placing sensors in remote locations, ensuring the cyber 
security of sensors, and various additional costs.\166\ However, we 
seek comment on whether to require transmission providers to implement 
DLRs across their systems or on certain transmission lines that have 
the most to benefit from a dynamic rating.
---------------------------------------------------------------------------

    \166\ EEI Comments at 8-10; Exelon Comments at 11-13.
---------------------------------------------------------------------------

    100. In response to comments from OMS and Potomac Economics that 
suggest the Commission focus on the most heavily congested lines,\167\ 
we note that our proposal, as discussed above, is to prioritize the 
implementation of AARs on historically congested transmission lines 
first.
---------------------------------------------------------------------------

    \167\ OMS Comments at 2; Potomac Economics Comments at 9-10.
---------------------------------------------------------------------------

    101. In response to concerns articulated by MISO Transmission 
Owners that day-ahead forecasts could be inaccurate, causing 
differences between day-ahead and real-time transmission line ratings 
and therefore uplift,\168\ we observe that day-ahead markets already 
rely upon forecasts for weather to inform next-day load and 
intermittent generation availability. Instead, we agree with PJM that 
temperatures can be forecast within a reasonable degree of 
certainty,\169\ and we note that within our proposal transmission 
providers can (consistent with good utility practice) determine the 
needed degree of certainty when constructing their forecasts of ambient 
air temperature. We also preliminarily agree with MISO that, because 
one of the goals of the day-ahead market is to align prices with those 
eventually determined in the real-time market, maintaining policy 
consistency between the day-ahead and real-time markets, where 
practical, is desirable.\170\
---------------------------------------------------------------------------

    \168\ MISO Transmission Owners Comments at 7.
    \169\ PJM Comments at 3.
    \170\ MISO Comments at 3.
---------------------------------------------------------------------------

    102. We agree with some commenters that not all transmission line 
ratings are affected by ambient air temperature, either because the 
technical transfer capability of the limiting conductors and/or 
limiting transmission equipment is not dependent on ambient air 
temperature, or because the transmission line's transfer capability is 
limited by a transmission system limit (such as a system voltage or 
stability limit) which is not dependent on ambient air 
temperature.\171\ Our proposed pro forma OATT language accommodates 
such transmission lines without requiring unwarranted calculations or 
updates. Specifically, our proposed pro forma OATT language provides 
that where the transmission provider determines that the rating of a 
transmission line is not affected by ambient air temperature, the 
transmission provider may use a transmission line rating for that line 
that is not an AAR or seasonal line rating.
---------------------------------------------------------------------------

    \171\ Dominion Comments at 3; Exelon Comments at 10, 22-23; 
September 2019 Technical Conference, Day 1 Tr. at 141 (AEP opening 
statement to Panel Three).
---------------------------------------------------------------------------

    103. Finally, in response to Exelon's comments that AARs should not 
be implemented in transmission planning, we agree and reiterate that we 
are only proposing to require AAR implementation for certain aspects of 
near-term transmission service.\172\
---------------------------------------------------------------------------

    \172\ Exelon Comments at 4-5.
---------------------------------------------------------------------------

    104. Some entities argue that requiring AAR implementation would 
lead to operational and reliability concerns. MISO Transmission Owners 
caution that any AAR requirement could make operational or safety 
incidents more likely by reducing some of the margin between what a set 
of transmission facilities can safely handle at that point in time and 
the current operating levels.\173\ ITC and NRECA raise similar 
reliability questions.\174\ WATT contends that at times, AAR 
implementation may not be conservative enough because AAR 
implementation can assume too much wind. We do not find these concerns 
persuasive. We note that the ``safety margin'' cited by commenters is 
not dependable--it exists only during periods where the ambient air 
temperature happens to be lower than the temperature assumed when the 
static or seasonal line rating was calculated. We further note that the 
margin is lowest precisely during the hottest periods, which represent 
periods of high system stress when a dependable reliability margin 
would be most valuable. Furthermore, transmission providers that find 
they need a reliability margin have existing Commission-approved 
mechanisms, such as the transmission reliability margin (TRM) component 
of ATC, for establishing such a margin on a consistent and transparent 
basis. With respect to assumptions about ambient conditions, under our 
proposal, transmission owners have latitude, consistent with good 
utility practice, to develop assumptions about ambient conditions that 
result in transmission line ratings that reflect what transmission 
flows the system can safely and reliably accommodate.
---------------------------------------------------------------------------

    \173\ MISO Transmission Owners Comments at 6.
    \174\ ITC Comments at 3-4; NRECA Comments at 3.
---------------------------------------------------------------------------

    105. Moreover, as Exelon points out, AARs would correct the 
existing occasional overestimations of transmission line ratings during 
periods where the actual ambient air temperature is greater than the 
temperature assumed when the rating was calculated. As a result, we 
believe that implementation of AARs will reduce transmission line 
ratings when extreme high temperature events occur, reducing the 
likelihood of inadvertently overloading a transmission line.\175\ 
Moreover, consistent with PJM's and Potomac Economics' comments, we 
believe that because AARs will typically increase transmission line 
ratings when actual temperatures are lower than long-term assumptions, 
the resulting increased transmission capability will provide operators 
additional flexibility, which promotes reliability.\176\ Specifically, 
by increasing the available transmission capability, system operators 
would be provided more options to manage congestion, and potentially 
ameliorate system conditions during an emergency. This is consistent 
with the 2019 FERC NERC Staff Report on the January 2018 South Central 
cold weather event, which, for example, identified and recommended 
adoption of transmission line ratings that better consider ambient 
temperature conditions. In this instance, implementing AARs would have 
been one way to potentially introduce additional transmission 
capability, which would have provided operators additional flexibility 
to transfer additional power to an area experiencing a potential 
reliability event, and thereby preventing the need for possible 
generator redispatch (reducing available contingency reserves), 
transmission reconfiguration,

[[Page 6435]]

and/or transmission loading relief,\177\ and helping mitigate future 
cold weather reliability events.\178\ Implementing AARs may also 
improve the ability to schedule and perform planned equipment outages 
for maintenance purposes and project upgrades.\179\
---------------------------------------------------------------------------

    \175\ See Exelon Comments at 9.
    \176\ See PJM Comments at 2; Potomac Economics Comments at 8.
    \177\ FERC and NERC Staff Report at 56-57.
    \178\ Id. at 96.
    \179\ Commission Staff Paper at 12 (describing outreach 
discussions that noted that the increased transfer capability, which 
typically results from ad hoc transmission line rating uprates (but 
would also result from AAR implementation) provides RTOs/ISOs 
additional options to manage challenges due to maintenance outages).
---------------------------------------------------------------------------

    106. Additionally, RTOs/ISOs already periodically request ad hoc 
transmission line rating changes based on differences between actual 
and assumed ambient temperatures.\180\ These requests are typically 
needed to either manage congestion or support reliable grid operations, 
but further demonstrate the benefits of AAR implementation. Our 
proposed AAR requirements would help ensure all market participants are 
consistently able to access the benefits of such transmission line 
rating changes.
---------------------------------------------------------------------------

    \180\ Id. at 10 and 21.
---------------------------------------------------------------------------

b. RTO/ISO Capability To Allow Electronic Updates to Line Ratings
    107. Having preliminary found above that the use of transmission 
line ratings that are based on long-term assumptions may not be just 
and reasonable, we propose, pursuant to section 206 of the FPA, to 
revise the Commission's regulations to require RTOs/ISOs to establish 
and implement the systems and procedures necessary to allow 
transmission owners to electronically update transmission line ratings 
(for each period for which transmission line ratings are calculated) at 
least hourly. We propose to require that such data be submitted by 
transmission owners directly into an RTO's/ISO's EMS through 
Supervisory Control and Data Acquisition (SCADA) or related 
systems.\181\ Absent these capabilities, the voluntary implementation 
of DLRs by transmission owners in some RTOs/ISOs would be of limited 
value, as their more dynamic ratings would not be incorporated into 
RTO/ISO markets.
---------------------------------------------------------------------------

    \181\ The NERC Glossary defines ``Supervisory Control and Data 
Acquisition'' as: ``A system of remote control and telemetry used to 
monitor and control the transmission system.'' NERC, Glossary of 
Terms Used in NERC Reliability Standards (June 2, 2020), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
---------------------------------------------------------------------------

    108. We expect that many of the systems and procedures RTOs/ISOs 
would need to develop under this proposal are likely to already be 
required as part of compliance with the requirement proposed in the 
previous section for transmission providers to adopt AAR. Nonetheless, 
we seek comment on the additional costs, if any, needed to comply with 
this proposed requirement that RTOs/ISOs also be able to accommodate 
frequently updated transmission line ratings from transmission owners. 
We also seek comment on whether there is any need to extend this same 
requirement to transmission providers that operate outside of an RTO/
ISO.
    109. Finally, we seek comment on whether to require RTOs/ISOs to 
conduct a one-time study of the cost effectiveness of DLR 
implementation, and if so, what details/format any such study should 
include.
c. Emergency Ratings
    110. We seek comment on whether to require transmission providers 
to use unique emergency ratings. As discussed above, we expect that 
such ratings would not be arbitrarily set equal to the normal ratings, 
but rather developed from the appropriate, unique technical 
inputs.\182\ We understand that many RTOs/ISOs already have 
requirements in place for transmission owners to provide emergency 
ratings. However, we also understand that many of the emergency ratings 
provided to RTOs/ISOs by transmission owners may be the same as the 
normal (pre-contingency) ratings. While Potomac Economics explains that 
63% of all post-contingency ratings used by MISO are the same as their 
normal ratings,\183\ we do not have comparable information from other 
RTO/ISO regions or information regarding whether non-RTO/ISO regions 
tend to use unique emergency ratings. For this reason, we seek comment 
on the degree to which other transmission providers use or are provided 
with unique emergency ratings and the emergency rating durations that 
are commonly used.
---------------------------------------------------------------------------

    \182\ See supra note 7, at P6 and note 58 at P 46.
    \183\ Potomac Economics Comments at 5.
---------------------------------------------------------------------------

    111. We recognize that there may be tradeoffs in requiring 
transmission owners to implement unique emergency ratings and therefore 
seek comment on the costs and benefits of such a requirement. On one 
hand, as Potomac Economics explains, emergency ratings result in 
additional capability being made available in shorter timeframes.\184\ 
Because the transmission system is operated to withstand contingencies, 
the use of unique emergency ratings, where appropriate, allows for 
greater flows during normal conditions as well.\185\ Such additional 
transmission capability can provide significant cost savings and afford 
transmission providers additional flexibility in how to respond to 
unforeseen events.
---------------------------------------------------------------------------

    \184\ Id. at 4.
    \185\ See supra P 31.
---------------------------------------------------------------------------

    112. On the other hand, we recognize that there are concerns that 
the use of emergency ratings could impact reliability. As Entergy 
explained in the September 2019 Technical Conference, the use of 
emergency ratings may degrade affected transmission facilities and 
ultimately reduce the equipment's useful life.\186\ Therefore, we 
request comment on whether and how a requirement to implement unique 
emergency rating would impact the useful life of transmission equipment 
as well as on the feasibility of calculating emergency ratings on 
transmission equipment other than conductors and transformers.
---------------------------------------------------------------------------

    \186\ September 2019 Technical Conference, Day 2 Tr. at 293-294.
---------------------------------------------------------------------------

B. Transparency

    113. While some transmission owners and/or operators make both 
their transmission line ratings and/or ratings methodologies public, 
many do not. While NERC Regional Entities are responsible for auditing 
line ratings for compliance with Reliability Standards, FAC-008-3 R8 
allows other entities, including other Transmission Service Providers, 
Planning Coordinators, Reliability Coordinators, or Transmission 
Operators, to request facility ratings up to 13 months later for 
internal examination.\187\ Such data requests remain non-public. 
However, NERC has proposed retiring FAC-008-3 R8, which would end the 
option of non-public facility rating requests.\188\
---------------------------------------------------------------------------

    \187\ NERC Standard MOD-001-1a--Available Transmission System 
Capability, R9.
    \188\ NERC, Petition of the North American Electric Reliability 
Corporation for Approval of Revised and Retired Reliability 
Standards Under the NERC Standards Efficiency Review, Docket No. 
RM19-16-000 (filed June 7, 2019). In the SER NOPR, the Commission 
sought further information on NERC's proposed retirement of FAC-008 
R7 and R8 inquiring how such requirements are redundant.
---------------------------------------------------------------------------

1. Comments
    114. During the September 2019 Technical Conference, some 
participants expressed a desire for additional transmission line rating 
transparency. Potomac Economics stated that additional transparency 
regarding rating methodologies was ``essential'' for administering an 
AAR requirement.\189\ WATT noted that transmission owners may have an 
incentive to be overly conservative with

[[Page 6436]]

their transmission line rating methodologies, and that increasing 
transparency around these methodologies could improve efficiency.\190\ 
Conversely, many transmission owners at the September 2019 Technical 
Conference stated that they did not believe additional transparency 
requirements should be required.\191\
---------------------------------------------------------------------------

    \189\ Michael Chiasson, Potomac Economics, FERC Technical 
Conference on Managing Line Ratings: AD19-15 Panel 5--Transparency 
of Transmission Line Rating Methodologies (Sept. 11, 2019).
    \190\ September 2019 Technical Conference, Day 1 Tr. at 23 and 
25.
    \191\ Id. at 281-82.
---------------------------------------------------------------------------

    115. Arguing in favor of further transparency, Potomac Economics 
presented data showing a large variation in transmission line ratings 
for similar lines. In addition, Potomac Economics pointed to instances 
when the same ratings were used for a given transmission line in both 
summer and winter, and instances in which the same ratings were used 
for both emergency and normal operations. Potomac Economics explained 
that, in MISO, 30% of lines use the same ratings for summer as they do 
for winter. Potomac Economics further noted that, at least during the 
winter, 63% of lines use emergency ratings that are equal to their 
normal ratings.\192\
---------------------------------------------------------------------------

    \192\ September 2019 Technical Conference, Day 2 Tr. at 311-12.
---------------------------------------------------------------------------

    116. However, some panelists argued that current transparency 
levels were adequate. For example, AEP stated that it has shared 
details of its facility rating methodology and assumptions in past 
technical industry publications and noted that review of facility 
rating parameters and assumptions is common in competitive transmission 
development.\193\ MISO Transmission Owners stated that FERC Form No. 
715 data in many cases describe the rating methodology.\194\ Similarly, 
the Exelon representative stated that their NERC Regional Entity, 
ReliabilityFirst, validates some of Exelon's ratings against the 
ratings methodology Exelon provides. Exelon stated that PJM publishes 
ratings and guidelines for transmission owners on facility ratings, and 
that Exelon tries to make their methodology closely conform to PJM's 
guidelines.\195\ NYISO noted that it publishes seasonal rating sets as 
part of its operating studies, making them available to all interested 
parties. NYISO also stated that it makes the transmission line ratings 
to which it secures the system available on a limited basis to all 
interested parties.\196\
---------------------------------------------------------------------------

    \193\ AEP Comments at 5.
    \194\ September 2019 Technical Conference, Day 2 Tr. at at 322.
    \195\ Id. at 297.
    \196\ Id. at 243.
---------------------------------------------------------------------------

    117. Regarding RTO/ISO audits of transmission line ratings, MISO 
indicated that their audit process was more of a ``sanity check'' 
rather than a comprehensive validation of line ratings.\197\ Similarly, 
SPP described its use of ``reasonability limits'' that gets the 
transmission owner to ``sign-off'' on upper and lower bounds to cap the 
amount by which transmission line ratings can change and thereby ``get 
rid of possible erroneous data or anything else that shouldn't be 
used.'' \198\
---------------------------------------------------------------------------

    \197\ Id. at 264.
    \198\ Id. at 247.
---------------------------------------------------------------------------

    118. Following the September 2019 Technical Conference, the 
Commission requested comments on a variety of issues involving 
transparency. Specifically, the Commission asked whether transmission 
owners' transmission line rating methodologies and transmission line 
ratings should be made more transparent, and, if so, how and to what 
extent. The Commission requested comment on who should have access to 
this information. The Commission also requested comment on whether 
transmission owners or other entities, such as NERC Regional Entities 
or RTOs/ISOs, should be required to develop a database to document each 
transmission facility's most limiting element, what burdens would be 
associated with reporting and maintaining such a database, and who 
should have access to such a database and what levels of 
confidentiality protections would need to exist for such a limiting 
elements database. Finally, the Commission asked whether requests from 
transmission system operators to transmission owners to allow an ad hoc 
increase in transmission line ratings above seasonal or static ratings 
should be publicly posted.
    119. Commenters were divided over the extent to which the 
Commission should require further transparency with regard to 
transmission line ratings and transmission line rating changes. 
Commenters in support of greater transmission line rating methodology 
transparency include Potomac Economics and Monitoring Analytics, which 
argue that transmission line rating methodologies should be fully 
transparent and public.\199\ Potomac Economics contends that, should 
AARs be required, additional transparency regarding rating 
methodologies and independent oversight is ``essential.'' Potomac 
Economics states that very little information is shared with MISO on 
transmission owner rating methodologies or calculations, and that the 
ability to validate transmission line rating methodologies and 
calculations by RTOs/ISOs and other transmission providers would 
enhance reliability by increasing operational and situational awareness 
and identifying incorrect ratings.\200\
---------------------------------------------------------------------------

    \199\ Potomac Economics Comments at 15; Monitoring Analytics 
Comments at 4.
    \200\ Potomac Economics Comments at 14-16.
---------------------------------------------------------------------------

    120. OMS agrees that rating methodologies should be as transparent 
as possible and suggests incorporating the transparency model applied 
to load forecasting methodologies.\201\ Industrial Customers also 
support methodology transparency, suggesting that the Commission enable 
market monitors, customers, and other stakeholders (such as state 
commissions) to have broad access to transmission line rating 
methodologies, assumptions, and values.\202\ PJM supports a requirement 
for additional transmission line rating transparency, explaining that 
it currently posts ratings on the PJM website every 15 minutes, 
including ad hoc changes.\203\ DTE states that transmission owners 
currently have a monopoly on all transmission line rating information, 
and suggests that enhanced transmission line rating transparency could 
help identify more cost-effective congestion management solutions.\204\ 
TAPS agrees that greater transmission line rating transparency is 
essential,\205\ encouraging the Commission to enforce greater 
transmission line rating accuracy through FPA section 206 authority 
regarding non-discriminatory open access instead of through FPA section 
215 authority over reliability.\206\ Finally, WATT also suggests that 
additional transmission line rating transparency is appropriate.\207\ 
WATT contends that transmission owners should face no additional 
litigations risk if they post and follow their transmission line rating 
methodologies and are subject to audit by an independent entity. 
Instead, WATT suggests that more accurate transmission line ratings 
should reduce litigation risks.\208\
---------------------------------------------------------------------------

    \201\ OMS Comments at 3-4.
    \202\ Industrial Customers Comments at 13.
    \203\ PJM Comments at 6-7.
    \204\ DTE Comments at 4.
    \205\ TAPS Comments at 8.
    \206\ Id. at 11-12.
    \207\ WATT Comments at 8-9.
    \208\ WATT Reply Comments at 3.
---------------------------------------------------------------------------

    121. Other commenters, while not fully opposed, were less 
supportive of increased rating methodology transparency, citing reasons 
such as lack of need and concerns that their ratings will be challenged 
and subject to increased litigation. Dominion, EEI, Exelon, MISO 
Transmission Owners, and AEP all generally contend that the

[[Page 6437]]

current transparency provisions are satisfactory and expressed concerns 
about challenges or litigation upon publication of transmission line 
rating methodologies.\209\ For example, while Exelon does not oppose 
posting transmission line ratings, it states that the PJM transparency 
method is sufficient, suggesting that no further transmission line 
rating transparency requirements is necessary.\210\ MISO Transmission 
Owners do not believe that increased transparency will improve 
reliability, adding that information on transmission line rating 
methodologies is already provided through FERC Form No. 715.\211\ MISO 
Transmission Owners contend that transmission line ratings should not 
be reviewed or challenged by market participants because such parties 
do not bear reliability obligations and that justifying transmission 
owner ratings to market participants would be costly.\212\ Similarly, 
while AEP states that it would support any rule that required the 
publication of transmission line rating methodologies, AEP also 
suggests it is unnecessary and requests protection from 
litigation.\213\ Finally, NERC states that it does not see a 
reliability benefit to increasing the transparency of rating 
methodologies, noting that it ended its own requirements for sharing 
rating methodologies in 2013,\214\ and that it already audits for 
compliance with the NERC Reliability Standards.\215\
---------------------------------------------------------------------------

    \209\ AEP Comments at 5; Dominion Comments at 13; EEI Comments 
at 11-12; Exelon Comments at 33; MISO Transmission Owners Comments 
at 18-19.
    \210\ Exelon Comments at 14-15.
    \211\ MISO Transmission Owners Reply Comments at 9 (citing FERC 
Form No. 715, at part IV(D)).
    \212\ MISO Transmission Owners Comments at 19-20.
    \213\ AEP Comments at 4-5.
    \214\ NERC Comments at 4 (citing Electric Reliability 
Organization Proposal to Retire Requirements in Reliability 
Standards, Order No. 788, 145 FERC ] 61,147 (2013) (retiring NERC 
Reliability Standard FAC-008, R4 and R5)).
    \215\ Id. at 5-6.
---------------------------------------------------------------------------

    122. Regarding the transparency of ad hoc line transmission line 
ratings changes specifically, commenters against further transparency 
include ITC and MISO. ITC contends they should not be posted because 
change requests may not be granted,\216\ and MISO argues that publicly 
posting ad hoc ratings would be unduly burdensome with no commensurate 
benefit.\217\
---------------------------------------------------------------------------

    \216\ ITC Comments at 6.
    \217\ MISO Comments at 8.
---------------------------------------------------------------------------

    123. Finally, regarding audits, comments were split on whether 
additional audits are needed. Those that describe the current auditing 
and review procedures as adequate include NRECA, NERC, ITC, EEI, 
Exelon, the MISO Transmission Owners, Dominion, and AEP.\218\ These 
commenters largely believe the current transmission line rating review 
and audit procedures are sufficient,\219\ or that new NERC standards 
are the appropriate path for auditing changes.\220\ Conversely, 
Industrial Customers, Monitoring Analytics, TAPS, DTE, Potomac 
Economics, and WATT contend that additional oversight would be 
beneficial.\221\ These commenters argue that lax line ratings oversight 
is pervasive,\222\ that transmission providers should review all line 
ratings,\223\ that NERC Reliability Standards are not suitable for 
auditing,\224\ and that the Commission should occasionally audit.\225\
---------------------------------------------------------------------------

    \218\ NRECA Comments at 7; NERC Comments at 5-6; ITC Comments at 
6; EEI Comments at 10-11; Exelon Comments at 17-19; MISO 
Transmission Owners Comments at 22-25; Dominion Comments at 16; AEP 
Comments at 4-5.
    \219\ ITC Comments at 6; EEI Comments at 10-11; Exelon Comments 
at 17-19; MISO Transmission Owners Comments at 22-25; Dominion 
Comments at 16; AEP Comments at 4-5.
    \220\ NRECA Comments at 7.
    \221\ Industrial Customer Comments at 10-14; Monitoring 
Analytics Comments at 4-5; TAPS Comments at 12-13; DTE at 6-8; 
Potomac Economics Comments at 18; WATT Comments at 9.
    \222\ Industrial Customer Comments at 13-14.
    \223\ Monitoring Analytics Comments at 4-5; Potomac Economics 
Comments at 18.
    \224\ TAPS Comments at 12-13.
    \225\ WATT Comments at 9.
---------------------------------------------------------------------------

2. Proposal
    124. To remedy any potentially unjust and unreasonable rates caused 
by inaccurate transmission line ratings, we propose, pursuant to 
section 206 of the FPA, to revise the Commission's regulations to 
require transmission owners to share transmission line ratings for each 
period for which transmission line ratings are calculated (with updated 
ratings shared each time ratings are calculated) and transmission line 
rating methodologies with their transmission provider(s) and, in 
regions served by an RTO/ISO, also with the market monitor(s) of that 
RTO/ISO.
    125. We preliminarily find that this proposal will afford 
transmission providers and market monitors more operational and 
situational awareness. Because transmission line ratings and 
transmission line rating methodologies will be shared only with 
transmission providers and, in regions served by an RTO/ISO, also with 
the market monitor(s) of that RTO/ISO rather than with the broader 
public, we believe that this proposal should address confidentiality 
concerns as well as litigation risks and compliance burdens.
    126. We preliminarily find that this proposal to require 
transmission owners to share transmission line ratings and transmission 
line rating methodologies with their transmission provider(s) and, in 
regions served by an RTO/ISO, also with the market monitor(s) of that 
RTO/ISO, will enhance operational and situational awareness by ensuring 
that transmission providers know the effect that changes in ambient 
temperature would have on transmission line ratings within their 
system. This information is critical to transmission providers because 
it allows them to reasonably anticipate increases and decreases in 
transmission capability and coordinate system operations accordingly. 
Moreover, we believe that sharing transmission line rating 
methodologies with transmission providers and, in regions served by an 
RTO/ISO, also with the market monitor(s) of that RTO/ISO will provide 
transmission providers and market monitors the information necessary to 
verify the resulting transmission line ratings and to identify 
potential errors.
    127. We disagree with suggestions that further transparency 
measures are not needed. To the contrary, the proposed requirement 
would provide transmission providers and market monitors, where 
applicable, essential information needed both to validate transmission 
line ratings and to ensure operational and situational awareness. While 
current NERC Reliability Standards provide some transparency regarding 
transmission line ratings and methodologies, current transparency 
levels may be insufficient to ensure accurate transmission line ratings 
and, thereby just and reasonable rates. Moreover, while some commenters 
note that they already provide transmission line rating methodologies 
pursuant to FERC Form No. 715, Form No. 715 collects information that 
relates only to transmission line rating methodologies used in long-
term transmission planning analyses. By contrast, the proposal would 
apply to transmission line ratings and methodologies used in near-term 
transmission service. In addition, while Sec.  37.6 of the Commission's 
regulations requires all data used to calculate ATC, TTC, TRM, and CBM 
for congested paths be made publicly available upon request, such data 
may not necessarily include the transmission line rating methodology 
and may not be well suited for RTOs/ISOs, which typically make ATC 
available only at external seams.
    128. While we propose to limit the sharing of a transmission 
owner's transmission line ratings and transmission line rating 
methodologies

[[Page 6438]]

to only the transmission owner's transmission providers and, in regions 
served by an RTO/ISO, also to the market monitor(s) of that RTO/ISO, we 
acknowledge that sharing such information with other interested parties 
may yield benefits. Sharing transmission line ratings and transmission 
line rating methodologies with other interested parties allows for 
greater transparency, and in the case of transmission providers, may 
aid efforts to manage congestion along mutual seams and may be 
beneficial for the study of affected systems during the interconnection 
process. For this reason, we seek comment on whether to require 
transmission owners to share upon request their transmission line 
ratings and rating methodologies with transmission providers other than 
the transmission owner's own transmission providers. We also seek 
comment on whether to require transmission owners to make their 
transmission line ratings and rating methodologies available to other 
interested stakeholders, including posting information on their OASIS 
pages or other password protected online forum.
    129. In response to arguments that additional auditing of 
transmission line ratings to ensure accuracy is needed, while we 
propose no new auditing requirements, we reiterate that the Commission 
will continue to conduct reviews of line ratings as a component of 
broader tariff compliance audits.

VI. Compliance

    130. We propose that each public utility transmission provider be 
required to submit a compliance filing within 60 days of the effective 
date of any final rule. We note that this compliance deadline would be 
for public utility transmission providers to submit proposed AAR tariff 
changes, RTOs/ISOs to submit proposed tariff changes designed to 
maintain systems and procedures needed to allow for the use of AARs and 
DLRs, and for transmission owners to submit tariff changes implementing 
the proposed transparency reforms or for each entity to otherwise 
comply with any final rule. We understand that implementing the reforms 
required by any final rule in this proceeding may be a complex 
endeavor. However, we preliminarily find that implementation of these 
reforms is important to ensure rates are just and reasonable. 
Therefore, for the AAR reforms, we propose a staggered approach that 
would prioritize implementation on historically congested lines (within 
one year from the date of the compliance filing for implementation to 
any final rule), and propose to require a less aggressive 
implementation of AARs on all other lines (within two years from the 
date to the compliance filing for implementation of any final rule). 
For the DLR reforms, we propose that tariff changes filed in response 
to a final rule in this proceeding must become effective within one 
year from the date of the compliance filing for implementation to any 
final rule. Likewise, for the transparency reforms, we propose that 
tariff changes filed in response to any final rule in this proceeding 
must become effective within one year from the date of the compliance 
filing to any final rule in this proceeding.
    131. Some public utility transmission providers may have provisions 
in their existing pro forma OATTs or other document(s) subject to the 
Commission's jurisdiction that the Commission has deemed to be 
consistent with or superior to the pro forma OATT or are permissible 
under the independent entity variation standard or regional Reliability 
Standard. Where these provisions would be modified by this final rule, 
public utility transmission providers must either comply with this 
proposed requirements or demonstrate that these previously-approved 
variations continue to be consistent with or superior to the pro forma 
OATT as modified by the proposed requirements or continue to be 
permissible under the independent entity variation standard or regional 
Reliability Standard.\226\
---------------------------------------------------------------------------

    \226\ See 18 CFR 35.28(c)(1)(vi).
---------------------------------------------------------------------------

    132. We seek comment on whether 60 days is sufficient time for 
public utility transmission providers to develop new tariff language in 
response to the final rule.
    133. To the extent that any public utility transmission provider 
believes that it already complies with the reforms proposed in this 
proceeding, the public utility transmission provider would be required 
to demonstrate how it complies in the compliance filing required 60 
days after the effective date of any final rule in this proceeding. To 
the extent that any public utility transmission provider believes that 
its existing market rules are consistent with or superior to the 
reforms adopted in any final rule, the Commission will entertain those 
at that time.
    134. As discussed above, we propose the following compliance 
timelines for the proposals in this NOPR:

------------------------------------------------------------------------
 Proposed due date  (from the
   date of the  compliance
filing to any  eventual final        Proposed compliance obligation
            rule)
------------------------------------------------------------------------
1 year.......................  Requirement for Transmission Providers to
                                implement AARs on historically congested
                                transmission lines.
2 years......................  Requirement for Transmission Providers to
                                implement AARs on all other transmission
                                lines.
1 year.......................  Requirement for RTOs/ISOs to establish
                                and implement the systems and procedures
                                necessary to allow transmission owners
                                to electronically update transmission
                                line ratings at least hourly.
1 year.......................  Requirement for transmission owners to
                                share transmission line ratings and
                                transmission line rating methodologies
                                with their respective transmission
                                provider(s) and, in RTOs/ISOs, their
                                respective market monitor(s).
------------------------------------------------------------------------

VII. Information Collection Statement

    135. The information collection requirements contained in this NOPR 
are subject to review by the Office of Management and Budget (OMB) 
under section 3507(d) of the Paperwork Reduction Act of 1995.\227\ 
OMB's regulations require approval of certain information collection 
requirements imposed by agency rules.\228\ Upon approval of a 
collection of information, OMB will assign an OMB control number and 
expiration date. Respondents subject to the filing requirements of this 
rule will not be penalized for failing to respond to these collections 
of information unless the collections of information display a valid 
OMB control number.
---------------------------------------------------------------------------

    \227\ 44 U.S.C. 3507(d).
    \228\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    136. This NOPR would, pursuant to section 206 of the FPA, reform 
the pro forma Open Access Transmission Tariff (OATT) and the 
Commission's regulations to improve the accuracy and transparency of 
transmission line

[[Page 6439]]

ratings used by transmission providers. These provisions would affect 
the following collections of information:
FERC-516H, Pro Forma Open Access Transmission Tariff (Control No. 1902-
0297); and FERC-725A, Mandatory Reliability Standards for the Bulk-
Power System (Control No. 1902-0244).
    137. Interested persons may obtain information on the reporting 
requirements by contacting Ellen Brown, Office of the Executive 
Director, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426 via email ([email protected]) or telephone 
((202) 502-8663).
    138. The Commission solicits comments on the Commission's need for 
this information, whether the information will have practical utility, 
the accuracy of the burden estimates, ways to enhance the quality, 
utility, and clarity of the information to be collected or retained, 
and any suggested methods for minimizing respondents' burden, including 
the use of automated information techniques.
    139. Please send comments concerning the collections of information 
and the associated burden estimates to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, through 
www.reginfo.gov/public/do/PRAMain. Attention: Federal Energy Regulatory 
Commission Desk Officer. Please identify the OMB Control Numbers 1902-
0096 and 1902-0244 in the subject line of your comments. Comments 
should be sent within 60 days of publication of this notice in the 
Federal Register.
    140. Please submit a copy of your comments on the information 
collections to the Commission via the eFiling link on the Commission's 
website at https://www.ferc.gov. Comments on the information collection 
that are sent to FERC should refer to RM20-16-000.
    141. Title: Pro Forma Open Access Transmission Tariff (FERC-516H) 
and Mandatory Reliability Standards for the Bulk-Power System (FERC-
725A).
    142. Action: Proposed revision of collections of information in 
accordance with Docket No. RM20-16-000 and request for comments.
    143. OMB Control Nos.: 1902-0297 (FERC-516H) and 1902-0244 (FERC-
725A).
    144. Respondents: Transmission owners, transmission service 
providers, generation owners, and RTOs/ISOs.
    145. Frequency of Information Collection: One time and annually.
    146. Necessity of Information: The proposed reform to the pro forma 
Open Access Transmission Tariff (OATT) and the Commission's 
regulations, if adopted, would improve the accuracy and transparency of 
transmission line ratings used by transmission providers. Specifically, 
the proposal would require: (1) Transmission providers to implement 
ambient-adjusted ratings on the transmission lines over which they 
provide transmission service; (2) Regional Transmission Organizations 
(RTOs) and Independent System Operators (ISOs) to establish and 
implement the systems and procedures necessary to allow transmission 
owners to electronically update transmission line ratings at least 
hourly; and (3) transmission owners to share transmission line ratings 
and transmission line rating methodologies with their respective 
transmission provider(s) and, in RTOs/ISOs, with their respective 
market monitor(s).
    147. Internal Review: The Commission has reviewed the changes and 
has determined that such changes are necessary. These requirements 
conform to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has specific, objective support for the burden estimates 
associated with the information collection requirements.
    148. Our estimates are based on the NERC Compliance Registry as of 
September 3, 2020, which indicates that 78 transmission service 
providers,\229\ 797 generator owners,\230\ and 289 transmission owners 
are registered within the United States and are subject to this 
proposed rulemaking.\231\ There are also 6 RTOs/ISOs in the United 
States subject to this proposed rulemaking.
---------------------------------------------------------------------------

    \229\ The transmission service provider (TSP) function is a NERC 
registration function which is similar to the transmission provider 
that is referenced in the pro forma OATT. The TSP function is being 
used as a proxy to estimate the number of transmission providers 
that are impacted by this proposed rulemaking.
    \230\ Of the 797 generator owners listed in the September 3, 
2020 NERC Compliance Registry, we estimate that 10% of all NERC 
registered generator owners own facilities between the step-up 
transformer and the point of interconnection. For this reason, we 
estimate that only 80 generator owners are affected.
    \231\ The number of entities listed from the NERC Compliance 
Registry reflects the omission of the Texas RE registered entities.
---------------------------------------------------------------------------

    149. Public Reporting Burden: The burden and cost estimates below 
are based on the need for applicable entities to revise documentation, 
already required by the pro forma OATT and the Commission's regulations 
as well as the NERC Reliability Standard FAC-008-3, Facility 
Ratings.\232\
---------------------------------------------------------------------------

    \232\ The burden associated with Reliability Standard FAC-008-3, 
approved by the Commission under section 215 of the FPA, is included 
in the OMB-approved inventory for FERC-725A. Reliability Standard 
FAC-008-3 has not been revised in this proceeding however the 
requirements proposed in this proposed rulemaking under section 206 
of the FPA affects the burden for three requirements in Reliability 
Standard FAC-008-3.
---------------------------------------------------------------------------

    150. The Commission estimates that the NOPR would affect the burden 
\233\ and cost of FERC-516H and FERC-725A as follows:
---------------------------------------------------------------------------

    \233\ ``Burden'' is the total time, effort, or financial 
resources expended by persons to generate, maintain, retain, or 
disclose or provide information to or for a Federal agency. For 
further explanation of what is included in the information 
collection burden, refer to 5 CFR 1320.3.

                                                   Proposed Changes in NOPR in Docket No. RM20-16-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Annual
                                                             Annual         estimated
                                                            estimated       number of      Average burden  hours &      Total estimated  burden hours &
      Area of modification       Number of  respondents     number of       responses      cost \234\  per response    total estimated cost  (column D x
                                                          responses per    (column B x                                             column E)
                                                           respondent       column C)
A.                               B.....................              C.              D.  E..........................  F.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                      FERC-516H, Pro Forma Open Access Transmission Tariff (Control No. 1902-0297)
--------------------------------------------------------------------------------------------------------------------------------------------------------
For point-to-point transmission  129 (TOs \235\ not in                1             129  1,440 hrs; $120,485........  185,760 hrs; $15,542,539.
 service requests within ten      RTOs/ISOs \236\).
 days, use AARs in determining
 ATC and TTC. (One-Time Burden
 in Year 1).

[[Page 6440]]

 
Where network transmission       160 (to account for                  1             160  1,440 hrs; $120,485........  230,400 hrs; $19,277,568.
 service is provided, use         those TOs in RTOs/
 hourly AARs to determine         ISOs that are not
 curtailment or redispatch of     included in the line
 network service. (One-Time       above).
 Burden in Year 1).
Implement software and systems   78 (TSPs \237\).......               1              78  320 hrs; $26,774...........  24,960 hrs; $2,088,403.
 to communicate the required
 line ratings with relevant
 parties. (One-Time Burden in
 Year 1).
RTOs/ISOs implement software     6 (RTOs/ISOs).........               1               6  320 hrs; $26,774...........  1920 hrs; $160,646.
 with the ability to
 accommodate AARs in both the
 day-ahead and real-time
 markets on an hourly basis.
 (One-Time Burden in Year 1).
Compliance Filings (One-Time     295 (TOs and (RTOs/                  1             295  160 hrs; $13,387...........  47,200 hrs; $3,949,224.
 Burden in Year 1).               ISOs).
Compliance Filings (One-Time     289 (TOs).............               1             289  160 hrs; $13,387...........  46,240 hrs; $3,868,901.
 Burden in Year 2).
RTOs/ISOs establish the systems  6 (RTOs/ISOs).........               1               6  960 hrs; $80,323...........  5,760 hrs; $481,939.
 and procedures necessary to
 allow transmission owners to
 update line ratings on an
 hourly basis directly into an
 EMS. (One-Time Burden in Year
 1).
Transmission owners update       289 (TOs).............               1             289  160 hrs; $13,387...........  46,240 hrs; $3,868,901.
 forecasts and ratings, and
 share transmission line
 ratings and facility ratings
 methodologies w/transmission
 providers and, if applicable,
 RTOs/ISOs & market monitors
 (Year 1 and Ongoing).
                                                                        --------------------------------------------------------------------------------
    Net Subtotal for FERC-516H   ......................  ..............             373  4,800 hrs; $401,616........  542,240 hrs; $45,369,221.
     (Year 1).
                                                                        --------------------------------------------------------------------------------
    Net Subtotal for FERC-516H   ......................  ..............             289  320 hrs; $26,774...........  92,480 hrs; $7,737,802.
     (Year 2).
                                                                        --------------------------------------------------------------------------------
    Net Subtotal for FERC-516H   ......................  ..............             289  160 hrs; $13,387...........  46,240 hrs; $3,868,901.
     (Ongoing).
--------------------------------------------------------------------------------------------------------------------------------------------------------
                          FERC-725A, Mandatory Reliability Standards for the Bulk-Power System--Reliability Standard FAC-008-3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Review and update facility       369 (TO & GO) \238\...               1             369  40 hrs; $3,347.............  14,760 hrs; $1,234,969.
 ratings methodology,
 Requirements R2 and R3. (One-
 Time Burden in Year 1).
Determine facility ratings       369 (TO & GO) \238\...               1             369  8 hrs; $669................  2,952 hrs; $246,994.
 consistent with methodology,
 Requirement R6. (Burden in
 Year 1 and Ongoing).
    Net Subtotal for FERC-725A   ......................  ..............             369  48 hrs; $4,016.............  17,712 hrs; $1,481,963.
     (Year 1).
                                                                        --------------------------------------------------------------------------------
    Net Subtotal for FERC-725A   ......................  ..............             369  8 hrs; $669................  2,952 hrs; $246,994.
     (Ongoing).
--------------------------------------------------------------------------------------------------------------------------------------------------------

    151. For the purposes of estimating burden in this NOPR, we 
conservatively

[[Page 6441]]

estimate these values based on the maximum number of entities and 
burden. As discussed elsewhere in this NOPR, some entities may, for 
example, already use AARs in their existing operations, in which case 
the actual burden associated with specific proposals associated with 
the use of AARs would be lower than the estimate. On the other hand, we 
also acknowledge that changing approaches to facility ratings may 
require extra testing and training for some entities to ensure reliable 
operations and gain familiarity with the approach. We estimate that the 
majority of the additional burden associated with this NOPR occurs in 
the first year, and that, once established, the ongoing burden will 
closely approach the existing burden of operating the transmission 
system. We seek comment on the estimates in the table above and the 
assumptions described here.
---------------------------------------------------------------------------

    \234\ The hourly cost (for salary plus benefits) uses the 
figures from the Bureau of Labor Statistics (BLS) for three 
positions involved in the reporting and recordkeeping requirements. 
These figures include salary (based on BLS data for May 2019, https://bls.gov/oes/current/naics2_22.htm) and benefits (based on BLS data 
for December 2019; issued March 19, 2020, https://www.bls.gov/news.release/ecec.nr0.htm) and are Manager (Code 11-0000 $97.15/
hour), Electrical Engineer (Code 17-2071 $70.19/hour), and File 
Clerk (Code 43-4071 $34.79/hour). The hourly cost for the reporting 
requirements ($83.67) is an average of the cost of a manager and 
engineer. The hourly cost for recordkeeping requirements uses the 
cost of a file clerk.
    \235\ Transmission Owners. While the proposed AAR reforms apply 
to transmission providers, we compute an implementation burden based 
on the number of transmission owners because transmission owners 
typically calculate transmission line ratings and are therefore 
likely to be the entities that update computations to determine the 
effect of changing ambient air temperatures on transmission line 
ratings.
    \236\ Regional Transmission Organizations/Independent System 
Operators.
    \237\ Transmission Service Providers.
    \238\ This number reflects 289 transmission owners and 10% of 
the 797 generator owners estimated to own facilities between the 
step-up transformer and the point of interconnection.
---------------------------------------------------------------------------

VIII. Environmental Analysis

    152. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\239\ We 
conclude that neither an Environmental Assessment nor an Environmental 
Impact Statement is required for this NOPR under Sec.  380.4(a)(15) of 
the Commission's regulations, which provides a categorical exemption 
for approval of actions under sections 205 and 206 of the FPA relating 
to the filing of schedules containing all rates and charges for the 
transmission or sale of electric energy subject to the Commission's 
jurisdiction, plus the classification, practices, contracts, and 
regulations that affect rates, charges, classification, and 
services.\240\
---------------------------------------------------------------------------

    \239\ Regulations Implementing National Environmental Policy Act 
of 1969, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & 
Regs. ] 30,783 (1987).
    \240\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

IX. Regulatory Flexibility Act

    153. The Regulatory Flexibility Act of 1980 \241\ generally 
requires a description and analysis of proposed and final rules that 
will have significant economic impact on a substantial number of small 
entities. The Small Business Administration (SBA) sets the threshold 
for what constitutes a small business. Under SBA's size standards,\242\ 
RTOs/ISOs, planning regions, and transmission owners all fall under the 
category of Electric Bulk Power Transmission and Control (NAICS code 
221121), with a size threshold of 500 employees (including the entity 
and its associates).\243\
---------------------------------------------------------------------------

    \241\ 5 U.S.C. 601-612.
    \242\ 13 CFR 121.201.
    \243\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. The 
Small Business Administrations' regulations at 13 CFR 121.201 define 
the threshold for a small Electric Bulk Power Transmission and 
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C. 
601(3), citing to Section 3 of the Small Business Act, 15 U.S.C. 
632.
---------------------------------------------------------------------------

    154. The six RTOs/ISOs (SPP, MISO, PJM, ISO-NE, NYISO, and CAISO) 
each employ more than 500 employees and are not considered small.
    155. We estimate that 337 transmission owners and six planning 
authorities are also affected by the NOPR. Using the list of 
transmission owners from the NERC Registry (dated September 3, 2020), 
we estimate that approximately 68% of those entities are small 
entities.
    156. We estimate that 80 generation owners own facilities between 
the step-up transformer and the point of interconnection. We estimate 
again that 68% of these are small entities.
    157. We estimate that 78 transmission service providers are 
affected by the NOPR. We estimate again that 68% of these are small 
entities.
    158. We estimate additional one-time costs associated with the NOPR 
(as shown in the table above) of:

--$93,710 for each RTO/ISO (FERC-516H)
--$134,541 for each transmission owner (FERC-516H)
--$3,347 for each transmission owner (FERC-725A)
--$13,387 for each affected generation owner (FERC-516H)
--$3,347 for each generation owner (FERC-725A)
--$26,774 for each transmission service provider (FERC-516H)

    159. Therefore, the estimated additional one-time cost per entity 
ranges from $16,734 to $137,219.
    160. We estimate that the majority of the additional burden 
associated with this NOPR occurs in the first year (as shown in the 
table above), and that, once established, the ongoing burden will 
closely approach the existing burden of operating the transmission 
system.
    161. According to SBA guidance, the determination of significance 
of impact ``should be seen as relative to the size of the business, the 
size of the competitor's business, and the impact the regulation has on 
larger competitors.'' \244\ We do not consider the estimated cost to be 
a significant economic impact. As a result, we certify that the 
proposals in this NOPR will not have a significant economic impact on a 
substantial number of small entities.
---------------------------------------------------------------------------

    \244\ U.S. Small Business Administration, A Guide for Government 
Agencies How to Comply with the Regulatory Flexibility Act, at 18 
(May 2012), https://www.sba.gov/sites/default/files/advocacy/rfaguide_0512_0.pdf.
---------------------------------------------------------------------------

X. Comment Procedures

    162. The Commission invites interested persons to submit comments 
on the matters and issues proposed in this notice to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to discuss. Comments are due January 22, 2021. Comments must 
refer to Docket No. RM20-16-000, and must include the commenter's name, 
the organization they represent, if applicable, and their address in 
their comments.
    163. 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 should 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.
    164. Commenters that are not able to file comments electronically 
must send an original of their comments to: Federal Energy Regulatory 
Commission, Secretary of the Commission, 888 First Street NE, 
Washington, DC, 20426.
    165. 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.

XI. Document Availability

    166. 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

[[Page 6442]]

Room due to the President's March 13, 2020 proclamation declaring a 
National Emergency concerning the Novel Coronavirus Disease (COVID-19).
    167. From the Commission's Home Page on the internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    168. 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].

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By direction of the Commission.

     Issued: November 19, 2020.
Kimberly D. Bose,
Secretary.

    In consideration of the foregoing, the Commission is proposing to 
amend Part 35, Chapter I, Title 18, Code of Federal Regulations, as 
follows.

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

0
2. Amend Sec.  35.28 as follows:
0
a. In paragraph (b), revise paragraphs (10) and (11) and add paragraphs 
(12) and (13);
0
b. In paragraph (c), add paragraph (5); and
0
c. In paragraph (g), revise the paragraph (g) subject heading, 
paragraph (12) subject heading, and paragraph (12)(i).
    The additions and revisions read as follows:


Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (b) * * *
    (10) Ambient-adjusted line rating means a transmission line rating 
that applies to a time period of not greater than one hour and reflects 
an up-to-date forecast of ambient air temperature across the time 
period to which the rating applies.
    (11) Dynamic line rating means a transmission line rating that 
applies to a time period of not greater than one hour and reflects up-
to-date forecasts of inputs such as (but not limited to) ambient air 
temperature, wind, solar irradiance intensity, transmission line 
tension, or transmission line sag.
    (12) Energy Management System (EMS) means a computer control system 
used by electric utility dispatchers to monitor the real-time 
performance of the various elements of an electric system and to 
dispatch, schedule, and/or control generation and transmission 
facilities.
    (13) Supervisory Control and Data Acquisition (SCADA) means a 
computer system that allows an electric system operator to remotely 
monitor and control elements of an electric system.
    (c) * * *
    (5) Every public utility that owns, controls, or operates 
facilities must have on file a joint pool-wide or system-wide open 
access transmission tariff, which provides for the following to be 
shared with its transmission provider(s) (and its Market Monitoring 
Unit(s), if applicable):
    (i) Transmission line ratings for each period for which 
transmission line ratings are calculated (with updated ratings shared 
each time ratings are calculated); and
    (ii) Written transmission line rating methodologies used to 
calculate the transmission line ratings provided under paragraph 
(c)(5)(i).
* * * * *
    (g) Tariffs and operations of Commission-approved independent 
system operators and regional transmission organizations--
* * * * *
    (12) Transmission line ratings. (i) Each Commission-approved 
independent system operator or regional transmission organization must 
establish and maintain systems and procedures necessary to allow 
transmission owners to electronically update transmission line ratings 
(for each period for which transmission line ratings are calculated) at 
least hourly, with such data submitted by transmission owners directly 
into the independent system operator's or regional transmission 
organization's Energy Management System through Supervisory Control And 
Data Acquisition or related systems.

    Note: The following appendix will not be published in the Code 
of Federal Regulations.

Appendix A: List of Short Names/Acronyms of Commenters

----------------------------------------------------------------------------------------------------------------
             Short name/ acronym                                           Commenter
----------------------------------------------------------------------------------------------------------------
AEP.........................................  American Electric Power Company, Inc.
AWEA........................................  American Wind Energy Association.
CAISO.......................................  California Independent System Operator Corporation.
Dominion....................................  Dominion Energy Services, Inc.
DESC........................................  Dominion Energy South Carolina.
DEV.........................................  Dominion Energy Virginia.
DTE.........................................  DTE Electric Company.
EEI.........................................  Edison Electric Institute.
ELCON.......................................  Electricity Consumers Resource Council.
Entergy.....................................  Entergy Services, LLC.
ERCOT.......................................  Electric Reliability Council of Texas.
Exelon......................................  Exelon Corporation.
IEEE........................................  The Institute of Electrical and Electronics Engineers.
Industrial Customers........................  Includes ELCON, the PJM Industrial Customers Coalition, and the
                                               Coalition of MISO Transmission Customers.
ITC.........................................  International Transmission Company d/b/a ITCTransmission, Michigan
                                               Electric Transmission Company, LLC, ITC Midwest LLC, and ITC
                                               Great Plains, LLC.
MISO........................................  Midcontinent Independent System Operator, Inc.

[[Page 6443]]

 
MISO Transmission Owners....................  The MISO Transmission Owners consists of: Ameren Services Company,
                                               as agent for Union Electric Company d/b/a Ameren Missouri, Ameren
                                               Illinois Company d/b/a Ameren Illinois and Ameren Transmission
                                               Company of Illinois; American Transmission Company LLC; Big
                                               Rivers Electric Corporation; Central Minnesota Municipal Power
                                               Agency; City Water, Light & Power (Springfield, IL); Cleco Power
                                               LLC; Cooperative Energy; Dairyland Power Cooperative; Duke Energy
                                               Business Services, LLC for Duke Energy Indiana, LLC; East Texas
                                               Electric Cooperative; Great River Energy; Hoosier Energy Rural
                                               Electric Cooperative, Inc.; Indiana Municipal Power Agency;
                                               Indianapolis Power & Light Company; International Transmission
                                               Company d/b/a ITCTransmission; ITC Midwest LLC; Lafayette
                                               Utilities System; Michigan Electric Transmission Company, LLC;
                                               MidAmerican Energy Company; Minnesota Power (and its subsidiary
                                               Superior Water, L&P); Missouri River Energy Services;
                                               MontanaDakota Utilities Co.; Northern Indiana Public Service
                                               Company LLC; Northern States Power Company, a Minnesota
                                               corporation, and Northern States Power Company, a Wisconsin
                                               corporation, subsidiaries of Xcel Energy Inc.; Northwestern
                                               Wisconsin Electric Company; Otter Tail Power Company; Prairie
                                               Power Inc.; Southern Illinois Power Cooperative; Southern Indiana
                                               Gas & Electric Company (d/b/a Vectren Energy Delivery of
                                               Indiana); Southern Minnesota Municipal Power Agency; Wabash
                                               Valley Power Association, Inc.; and Wolverine Power Supply
                                               Cooperative, Inc.
NERC........................................  North American Electric Reliability Corporation.
NRECA.......................................  National Rural Electric Cooperative Association.
NYISO.......................................  New York Independent System Operator, Inc.
ISO-NE......................................  ISO New England Inc.
ITC.........................................  ITC Transmission.
OMS.........................................  Organization of MISO States.
PJM.........................................  PJM Interconnection, L.L.C.
SPP.........................................  Southwest Power Pool, Inc.
TAPS........................................  Transmission Access Policy Study Group.
WATT........................................  Working for Advanced Transmission Technologies.
----------------------------------------------------------------------------------------------------------------


    Note: The following appendix will not be published in the Code 
of Federal Regulations.

Appendix B: Pro Forma Open Access Transmission Tariff

ATTACHMENT M

Transmission Line Ratings

General

    The Transmission Provider will implement Ambient-Adjusted 
Ratings and Seasonal Line Ratings on the transmission lines over 
which it provides Transmission Service, as provided below.

Definitions

    The following definitions apply for purposes of this Attachment:
    (1) ``Transmission Line Rating'' means the maximum transfer 
capability of a transmission line, computed in accordance with a 
written line rating methodology and consistent with Good Utility 
Practice, considering the technical limitations (such as thermal 
flow limits) on conductors and relevant transmission equipment, as 
well as technical limitations of the Transmission System (such as 
system voltage and stability limits). Relevant transmission 
equipment may include, but is not limited to, circuit breakers, line 
traps, and transformers.
    (2) ``Ambient-Adjusted Rating'' (AAR) means a Transmission Line 
Rating that:
    (a) Applies to a time period of not greater than one hour.
    (b) Reflects an up-to-date forecast of ambient air temperature 
across the time period to which the rating applies.
    (c) Is calculated at least each hour, if not more frequently.
    (3) ``Seasonal Line Rating'' means a Transmission Line Rating 
that:
    (a) Applies to a specified season, where seasons are defined by 
the Transmission Provider to not include more than three months in 
each season.
    (b) Reflects an up-to-date forecast of ambient air temperature 
across the relevant season over which the rating applies.
    (c) Is calculated monthly, if not more frequently, for each 
season in the future for which Transmission Service can be 
requested.
    (4) ``Near-Term Point-To-Point Transmission Service'' means 
Point-To-Point Transmission Service which ends not more than ten 
days after the Transmission Service request date. When the 
description of obligations below refers to either a request for 
information about the availability of potential Transmission Service 
(including, but not limited to, a request for ATC), or to the 
posting of ATC or other information related to potential service, 
the date that the information is requested or posted will serve as 
the Transmission Service request date.
    (5) ``Historically Congested Transmission Line'' means a 
transmission line that was congested (i.e., whose Transmission Line 
Rating was a binding constraint) at any time on or between [insert 
date five years prior to the effective date of this final rule] and 
[insert the effective date of this final rule].

System Reliability

    If the Transmission Provider reasonably determines, consistent 
with Good Utility Practice, that the temporary use of a Transmission 
Line Rating different than would otherwise be required under the 
Obligations of the Transmission Provider set forth in this 
Attachment is necessary to ensure the safety and reliability of the 
Transmission System, then the Transmission Provider will use such an 
alternate rating.

Obligations of Transmission Provider

    After the relevant dates specified below in the Implementation 
section of this Attachment, the Transmission Provider will have the 
following obligations.
    The Transmission Provider must use AARs as the relevant 
Transmission Line Ratings when performing any of the following 
functions: (1) Evaluating requests for Near-Term Point-To-Point 
Transmission Service, (2) responding to requests for information on 
the availability of potential Near-Term Point-To-Point Transmission 
Service (including requests for ATC or other information related to 
potential service), or (3) posting ATC or other information related 
to Near-Term Point-To-Point Transmission Service to the Transmission 
Provider's OASIS site.
    The Transmission Provider must use AARs as the relevant 
Transmission Line Ratings when determining the necessity of 
curtailment or interruption of Point-To-Point Transmission Service 
(under section 14.7) if such curtailment or interruption is both 
necessary because of issues related to flow limits on transmission 
lines and anticipated to occur (start and end) within the next 10 
days. For determining the necessity of curtailment or interruption 
of Point-To-Point Transmission Service in other situations, the 
Transmission Provider must use Seasonal Line Ratings as the relevant 
Transmission Line Ratings.
    The Transmission Provider must use AARs as the relevant 
Transmission Line Ratings when determining the necessity of 
curtailment (under section 33) or redispatch (under sections 30.5 
and/or 33) of Network Integration Transmission Service or secondary 
service if such curtailment or redispatch is both necessary because 
of issues related to flow limits on transmission lines and 
anticipated to occur (start and end) within the following 10 days. 
For determining the necessity of curtailment or redispatch of 
Network Integration Transmission Service or secondary service in 
other situations, the Transmission Provider must use Seasonal Line 
Ratings as the relevant Transmission Line Ratings.
    The Transmission Provider must use Seasonal Line Ratings as the 
relevant

[[Page 6444]]

Transmission Line Ratings when evaluating requests for any 
Transmission Service not otherwise covered above in this section 
(including, but not limited to, requests for non-Near-Term Point-To-
Point Transmission Service or requests to designate or change the 
designation of Network Resources or Network Load), and when 
developing any ATC or other information posted or provided to 
potential customers related to such services.
    In developing forecasts of ambient air-temperature for AARs and 
Seasonal Line Ratings, the Transmission Provider must develop such 
forecasts consistent with Good Utility Practice and on a non-
discriminatory basis.
    Exception: Where the Transmission Provider determines, 
consistent with Good Utility Practice, that the Transmission Line 
Rating of a transmission line is not affected by ambient air 
temperature, the Transmission Provider may use a Transmission Line 
Rating for that line that is not an AAR or Seasonal Line Rating. 
Examples of such a transmission line include (1) a transmission line 
where the technical transfer capability of the limiting conductors 
and/or limiting transmission equipment is not dependent on ambient 
air temperature, and (2) a transmission line whose transfer 
capability is limited by a Transmission System limit (such as a 
system voltage or stability limit) which is not dependent on ambient 
air temperature.

Implementation

    The Transmission Provider will implement the use of AARs and 
Seasonal Line Ratings as required in this Attachment in accordance 
with the following schedule.
    Prior to these implementation dates, the requirements above will 
not apply.
    (1) Historically Congested Transmission Lines: Transmission 
Provider will complete implementation of AARs and Seasonal Line 
Ratings for Historically Congested Transmission Lines not later than 
[insert date one year after the date of the compliance filing to the 
final rule].
    (2) Other Transmission Lines: Transmission Provider will 
complete implementation of AARs and Seasonal Line Ratings for any 
other transmission lines not later than [insert date two years after 
the date of the compliance filing to the final rule].

[FR Doc. 2020-26107 Filed 1-19-21; 8:45 am]
BILLING CODE 6717-01-P