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Rule2021-27735

Managing Transmission Line Ratings

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Published

January 13, 2022

Effective

March 14, 2022

Issuing agencies

Energy DepartmentFederal Energy Regulatory Commission

Abstract

The Federal Energy Regulatory Commission (Commission) is revising 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 electric transmission line ratings. Specifically, the Commission is requiring: Public utility transmission providers to implement ambient-adjusted ratings on the transmission lines over which they provide transmission service; regional transmission organizations (RTO) and independent system operators (ISO) to establish and implement the systems and procedures necessary to allow transmission owners to electronically update transmission line ratings at least hourly; public utility transmission providers to use uniquely determined emergency ratings; public utility transmission owners to share transmission line ratings and transmission line rating methodologies with their respective transmission provider(s) and with market monitors in RTOs/ISOs; and public utility transmission providers to maintain a database of transmission owners' transmission line ratings and transmission line rating methodologies on the transmission provider's Open Access Same-Time Information System site or other password-protected website.

Full Text

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[Federal Register Volume 87, Number 9 (Thursday, January 13, 2022)]
[Rules and Regulations]
[Pages 2244-2307]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2021-27735]

[[Page 2243]]

Vol. 87

Thursday,

No. 9

January 13, 2022

Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Managing Transmission Line Ratings; Final Rule

Federal Register / Vol. 87, No. 9 / Thursday, January 13, 2022 /
Rules and Regulations

[[Page 2244]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM20-16-000; Order No. 881]

Managing Transmission Line Ratings

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
revising 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 electric transmission line ratings.
Specifically, the Commission is requiring: Public utility transmission
providers to implement ambient-adjusted ratings on the transmission
lines over which they provide transmission service; regional
transmission organizations (RTO) and independent system operators (ISO)
to establish and implement the systems and procedures necessary to
allow transmission owners to electronically update transmission line
ratings at least hourly; public utility transmission providers to use
uniquely determined emergency ratings; public utility transmission
owners to share transmission line ratings and transmission line rating
methodologies with their respective transmission provider(s) and with
market monitors in RTOs/ISOs; and public utility transmission providers
to maintain a database of transmission owners' transmission line
ratings and transmission line rating methodologies on the transmission
provider's Open Access Same-Time Information System site or other
password-protected website.

DATES: This rule will become effective March 14, 2022.

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, <a href="/cdn-cgi/l/email-protection#d591bcb9b9babbfbbebab9beb8b4bbbb95b3b0a7b6fbb2baa3">[email&#160;protected]</a>.
Mark Armamentos (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426, (202) 502-8103, <a href="/cdn-cgi/l/email-protection#b7fad6c5dc99d6c5dad6dad2d9c3d8c4f7d1d2c5d499d0d8c1">[email&#160;protected]</a>.
Ryan Stroschein (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426, (202) 502-8099, <a href="/cdn-cgi/l/email-protection#8ddff4ece3a3def9ffe2feeee5e8e4e3cdebe8ffeea3eae2fb">[email&#160;protected]</a>.

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph Numbers

I. Introduction 1
II. Background 13
III. Need for Reform 17
A. NOPR Proposal 17
B. Comments 23
C. Commission Determination 29
IV. Discussion 40
A. Transmission Line Ratings Definition 40
1. NOPR Proposal 40
2. Comments 42
3. Commission Determination 44
B. Ambient-Adjusted Ratings 47
1. AAR Definition and Transmission Provider Obligations 47
2. Specific AAR Implementation Requirements 104
3. Other AAR Implementation Issues 151
C. Seasonal Line Ratings 193
1. Seasonal Line Ratings Requirements 193
2. Seasonal Line Rating Implementation Requirements 204
D. Exceptions and Alternate Ratings 217
1. NOPR Proposal 217
2. Comments 219
3. Commission Determination 227
E. Dynamic Line Ratings 235
1. Dynamic Line Ratings Definition 235
2. DLR Requirements 240
3. Extending to non-RTO/ISO Transmission Providers the
Requirement To Allow Transmission Owners To Electronically Update
Transmission Line Ratings at Least Hourly 256
4. DLR Studies 259
5. Advanced Transmission Technology Cost Recovery 265
F. Emergency Ratings 267
1. NOPR Request for Comments 267
2. Emergency Ratings Definition and Implementation Requirements
269
3. Equipment for Which Emergency Ratings Must Be Calculated 304
G. Transparency 306
1. NOPR Proposal 306
2. Comments 309
3. Commission Determination 330
H. Other Miscellaneous Issues 344
1. Comments 344
2. Commission Determination 346
I. Compliance 348
1. NOPR Proposal 348
2. Comments 351
3. Commission Determination 360
V. Information Collection Statement 364
VI. Environmental Analysis 383
VII. Regulatory Flexibility Act 384
VIII. Document Availability 399
IX. Effective Date and Congressional Notification 402
Appendix A: Abbreviated Names of Commenters
Appendix B: Pro Forma Open Access Transmission Tariff

I. Introduction

1. In this final rule, the Federal Energy Regulatory Commission
(Commission) is adopting reforms, pursuant to section 206 of the
Federal Power Act (FPA),\1\ to the pro forma Open Access Transmission
Tariff (OATT) and the Commission's regulations to improve the accuracy
and transparency of electric transmission line ratings used by
transmission providers.\2\ As discussed below, we adopt the
Commission's proposal in the Notice of Proposed Rulemaking (NOPR) to
define a transmission line rating as ``the maximum transfer capability
of a transmission line, computed in accordance with a written
transmission line rating methodology and consistent with Good Utility
Practice,\3\ considering the technical limitations on conductors and
relevant transmission equipment (such as thermal flow limits), as well
as technical limitations of the Transmission System (such as system
voltage and stability limits).'' \4\
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\1\ 16 U.S.C. 824e.
\2\ In this final rule, we use transmission provider to mean any
public utility that owns, operates, or controls facilities used for
the transmission of electric energy in interstate commerce. 18 CFR
37.3 (2021). Therefore, unless otherwise noted, ``transmission
provider'' refers only to public utility transmission providers.
Furthermore, the term ``public utility'' as found in section 201(e)
of the FPA means ``any person who owns or operates facilities
subject to the jurisdiction of the Commission under this subchapter
. . .'' 16 U.S.C. 824(e).
\3\ The Commission's pro forma OATT defines Good Utility
Practice as: ``[a]ny of the practices, methods and acts engaged in
or approved by a significant portion of the electric utility
industry during the relevant time period, or any of the practices,
methods and acts which, in the exercise of reasonable judgment in
light of the facts known at the time the decision was made, could
have been expected to accomplish the desired result at a reasonable
cost consistent with good business practices, reliability, safety
and expedition. Good Utility Practice is not intended to be limited
to the optimum practice, method, or act to the exclusion of all
others, but rather to be acceptable practices, methods, or acts
generally accepted in the region, including those practices required
by Federal Power Act section 215(a)(4).'' Pro forma OATT section
1.15.
\4\ The definition also states, ``Relevant transmission
equipment may include, but is not limited to, circuit breakers, line
traps, and transformers.'' Managing Transmission Line Ratings,
Notice of Proposed Rulemaking, 86 FR 6420 (Jan. 21, 2021), 173 FERC
] 61,165, at P 85 (2020) (NOPR).
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2. The transfer capability of a transmission line can change with
ambient weather conditions. Thus, a transmission line rating can be
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. Conductor temperatures are impacted by a variety of
factors,

[[Page 2245]]

including ambient air temperatures. Increases in ambient air
temperatures tend to increase a transmission line's operating
temperature and lower a transmission line's rating, while lower ambient
air temperatures tend to lower a transmission line's operating
temperature and increase the transmission line's rating.
3. Many transmission line ratings are currently calculated based on
assumptions about ambient conditions that are not regularly adjusted
and therefore do not accurately reflect the near-term transfer
capability of the transmission system.\5\ For example, when seasonal or
static temperature assumptions exceed actual ambient air temperatures,
transmission line ratings may understate the near-term transfer
capability that the transmission system can actually provide, leading
to unnecessarily restricted flows and potentially increased congestion
costs. Alternatively, when ambient air temperatures exceed seasonal or
static temperature assumptions, transmission line ratings may overstate
the near-term transfer capability of the system, creating potential
reliability and safety problems. In either case, the continued use of
seasonal and static temperature assumptions may result in transmission
line ratings that do not accurately represent the transfer capability
of the transmission system. We 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; thus, we find that inaccurate transmission line ratings
result in Commission-jurisdictional rates that are unjust and
unreasonable.
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\5\ Federal Energy Regulatory Commission, Staff Paper, Managing
Transmission Line Ratings, Docket No. AD19-15-000 (Aug. 2019)
(Commission Staff Paper), <a href="https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf">https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf</a>.
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4. To address these issues with respect to transmission service in
the near term, we adopt, with certain modifications, the NOPR
proposal's definition of an ambient-adjusted rating (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; (3)
reflects the absence of solar heating during nighttime periods where
the local sunrise/sunset times used to determine daytime and nighttime
periods are updated at least monthly, if not more frequently; and (4)
is calculated at least each hour, if not more frequently.\6\
Additionally, we adopt two requirements for greater use of AARs. First,
we require that transmission providers--including RTOs/ISOs for
transmission service at their seams \7\--use AARs as the basis for
evaluation of transmission service requests that will end within 10
days of the request. Second, we require that transmission providers--
including RTOs/ISOs for transmission service at their seams--use AARs
as the basis for their determination of the necessity of certain
curtailment, interruption, or redispatch of transmission service
anticipated to occur within those 10 days.
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\6\ 18 CFR 35.28(b)(10) (2021); Pro Forma OATT attach. M, AAR
Definition.
\7\ The term ``seam'' is commonly used by the industry to
indicate the border between two transmission provider's service
territories. Service at the seam can take different forms, such as
point-to-point service or market-to-market service.
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5. To address these issues with respect to transmission service in
the longer term, we require that transmission providers use seasonal
line ratings as the basis for evaluation of transmission service
requests ending more than 10 days from the date of the request. We also
require that transmission providers use seasonal line ratings as the
basis for the determination of the necessity of curtailment,
interruption, or redispatch of transmission service that is anticipated
to occur more than 10 days in the future.\8\
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\8\ The use of seasonal 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 discussed below, we adopt certain reforms to
change seasonal line rating implementation.
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6. For both longer term and shorter term transmission service, we
adopt exceptions to the AAR and seasonal line rating requirements to
accommodate instances in which the transmission line rating of a
transmission line is not affected by ambient air temperature and
instances in which a transmission provider reasonably determines,
consistent with good utility practice, that the use of a temporary
alternate rating is necessary to ensure the safety and reliability of
the transmission system.\9\
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\9\ Because the new requirements related to AARs and seasonal
line ratings are implemented through the new pro forma OATT
Attachment M, these requirements are placed upon transmission
providers. However, we recognize that transmission owners (not
transmission providers) determine transmission line ratings. In many
instances, the transmission provider and transmission owner are the
same entity. However, below in Section IV.B.2.b, we discuss
compliance within RTOs/ISOs, where the transmission provider and
transmission owner are separate entities.
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7. In certain situations, using transmission line ratings that are
based on factors beyond forecasted ambient air temperatures and the
presence or absence of solar heating may lead to greater accuracy. For
example, the use of dynamic line ratings (DLRs) presents opportunities
for transmission line ratings that may be more accurate than those
established with AARs. Unlike AARs, DLRs are based not only on
forecasted ambient air temperatures and the presence or absence of
solar heating, but also on other weather conditions such as (but not
limited to) wind, cloud cover, solar heating intensity (instead of mere
daytime/nighttime distinctions used in AARs), and precipitation, and/or
on transmission line conditions such as tension or sag. As discussed
below, we adopt the NOPR's proposed definition of DLR as a transmission
line rating that: (1) Applies to a time period of not greater than one
hour; and (2) reflects up-to-date forecasts of inputs such as (but not
limited to) ambient air temperature, wind, solar heating intensity,
transmission line tension, or transmission line sag.
8. Although some transmission owners have adopted the use of DLRs
for individual transmission lines, there is not currently widespread
use of DLRs. While DLRs can represent more accurate transmission line
ratings than AARs, based on the record in this proceeding, we decline
to mandate DLR implementation in this final rule. We instead
incorporate the record in this proceeding on DLRs into new Docket No.
AD22-5-000, which we open to further explore DLR implementation.
9. One factor that may contribute to the limited deployment of DLRs
by transmission owners is that the RTOs/ISOs that operate a large
portion of the transmission system in the United States 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. Although the record does not
support a mandate for DLR implementation at this time, we require RTOs/
ISOs to establish and maintain the systems and procedures necessary to
allow transmission owners in their regions to electronically update
transmission line ratings on at least an hourly basis.
10. In addition to reforms to improve the accuracy of transmission
line ratings used during normal (pre-contingency) operations,\10\ we
revise the pro forma

[[Page 2246]]

OATT to require transmission providers to use uniquely determined
emergency ratings for contingency analysis in the operations horizon
and in post-contingency simulations of constraints.\11\ Such uniquely
determined emergency ratings must also incorporate an adjustment for
ambient air temperature and daytime/nighttime solar heating, consistent
with our AAR requirements for normal ratings. Most transmission
equipment can withstand high currents for short periods of time without
sustaining damage. Emergency ratings reflect this technical capability,
defining the specific additional current that a transmission line can
withstand and for what duration the transmission line can withstand
that additional current without sustaining damage. Because emergency
ratings reflect this capability, uniquely determined emergency ratings
will ensure more accurate transmission line ratings.
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\10\ The North American Electric Reliability Corporation (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 28,
2021), <a href="https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf">https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf</a>.
\11\ As discussed below in Section IV.F.2.b, uniquely determined
means the ratings are determined based on assumptions that reflect
the specific, finite duration of emergency ratings, as opposed to
using assumptions used to calculate normal ratings.
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11. Finally, we adopt four requirements to enhance transparency.
First, we require public utility transmission owners to share
transmission line ratings and methodologies with their transmission
provider(s) and with market monitors in RTOs/ISOs. Second, we require
transmission providers to share their transmission owners' transmission
line ratings and methodologies with any transmission provider(s) upon
request. Third, we require transmission providers to maintain a
database of their transmission owners' transmission line ratings and
methodologies on the transmission provider's Open Access Same-Time
Information System (OASIS) site or another password-protected website.
Fourth, we require transmission providers to post on OASIS or another
password-protected website any uses of exceptions or temporary
alternate ratings. Availability of this additional information on
transmission line ratings and their methodologies will facilitate more
cost-effective decisions by transmission customers and more accurate
transmission line ratings. We find that these transparency reforms will
ensure that prices reflect the true cost of the wholesale service being
provided and thereby are necessary to ensure just and reasonable
wholesale rates.
12. We require each transmission provider to submit a compliance
filing within 120 days of the effective date of this final rule
revising their OATT to incorporate pro forma OATT Attachment M. We
further require that all requirements adopted herein be fully
implemented no later than three years from the compliance filing due
date.

II. Background

13. In August 2019, Commission staff issued a paper entitled
``Managing Transmission Line Ratings,'' which drew upon 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.\12\
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\12\ Commission Staff Paper, <a href="https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf">https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf</a>.
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14. 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.\13\
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\13\ Supplemental Notice of Technical Conference, Docket No.
AD19-15-000 (Sep. 4, 2019).
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15. In October 2019, the Commission requested comments on questions
that arose from the September 2019 Technical Conference.\14\ In
response, commenters addressed issues related to AARs and DLRs,
emergency ratings, and transparency, as discussed below.
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\14\ Notice Inviting Post-Technical Conference Comments, Docket
No. AD19-15-000 (Oct. 2, 2019).
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16. On November 19, 2020, the Commission issued the NOPR in this
proceeding, proposing to amend the pro forma OATT and its regulations
under the FPA to improve the accuracy and transparency of transmission
line ratings.\15\ Specifically, the Commission proposed a new pro forma
OATT Attachment M ``Transmission Line Ratings'' to require transmission
providers to implement AARs on the transmission lines over which they
provide transmission service. The Commission also proposed revisions to
its regulations to require RTOs/ISOs to establish and implement the
systems and procedures necessary to allow transmission owners to
electronically update transmission line ratings at least hourly and to
require transmission owners to share transmission line ratings and
transmission line rating methodologies with their transmission
provider(s) and, in RTOs/ISOs, with their market monitor(s). The
Commission received comments from 56 entities on the NOPR proposals
from a diverse set of stakeholders.\16\
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\15\ Managing Transmission Line Ratings, Notice of Proposed
Rulemaking, 86 FR 6420 (Jan. 21, 2021), 173 FERC ] 61,165 (2020)
(NOPR).
\16\ See Appendix A for a list of entities that submitted
comments and the shortened names used throughout this final rule to
describe those entities.
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III. Need for Reform

A. NOPR Proposal

17. In the NOPR, the Commission preliminarily found 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. The Commission explained
that, because of the relationship between transmission line ratings and
costs, inaccurate transmission line ratings may result in Commission-
jurisdictional rates that are unjust and unreasonable.\17\
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\17\ NOPR, 173 FERC ] 61,165 at P 38.
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18. The Commission explained that most transmission owners
implement seasonal or static transmission line rating methodologies
based on conservative, worst-case assumptions, such as high
temperatures that are likely to occur over the longer term, but that
often do not reflect the true near-term transfer capability of
transmission facilities. Thus, the Commission reasoned, seasonal and
static line ratings fail to reflect the true cost of delivering
wholesale energy to transmission customers, and incorporating near-term
forecasts of ambient air temperatures in transmission line ratings
would more accurately reflect the actual cost of delivering wholesale
energy to transmission customers.\18\
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\18\ Id. P 39.
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19. Because actual ambient air temperatures are usually not as high
as the ambient air temperatures conservatively assumed in seasonal and
static line ratings, the Commission

[[Page 2247]]

observed that updating transmission line ratings used in near-term
transmission service to reflect actual ambient air temperatures usually
results in increased system transfer capability and, in turn, lower
costs for consumers. However, the Commission also observed that
seasonal and static line ratings can at times assume temperatures that
are lower than the actual ambient air temperatures in the short term.
In doing so, the Commission noted that seasonal or static transmission
line rating methodologies can at times result in transmission line
ratings that reflect more transfer capability than physically exists.
The Commission observed that this overstatement of transmission line
ratings similarly results in wholesale energy rates that fail to
reflect the actual cost of delivering wholesale energy to transmission
customers, and may also create reliability and safety problems, risk
damage to equipment, and prevent occurrences of rates for scarcity
pricing or transmission constraint penalty factors.\19\
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\19\ Id. P 42.
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20. Regarding DLR implementation, the Commission observed that some
RTOs/ISOs may rely on software and systems that cannot accommodate
transmission line ratings that frequently change, such as DLRs, and
that, without reflecting such frequent changes to transmission line
ratings, such software may serve as a barrier that prevents
transmission owners in RTOs/ISOs from implementing DLRs, which can
better reflect the actual transfer capability of the transmission
system. The Commission explained that, in addition to ambient air
temperature, DLRs incorporate additional inputs, including wind, cloud
cover, solar heating, and precipitation, as well as transmission line
conditions such as tension and sag. DLRs 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 than relying on AARs. However, the Commission explained that
the potential inability of RTOs/ISOs to automatically accept and use
DLRs provided by transmission owners may prevent RTO/ISO markets from
benefiting from the more accurate representation of current RTO/ISO
system conditions. In turn, by ensuring RTO/ISO market models can
incorporate more accurate representations of system conditions when
transmission owners use DLRs, RTO/ISO markets would produce prices that
more accurately reflect the costs of delivering wholesale energy to
transmission customers. For this reason, the Commission also
preliminarily found in the NOPR 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.\20\
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\20\ Id. P 43.
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21. Regarding emergency ratings, the Commission found that current
transmission line rating practices may fail to use emergency ratings,
and in failing to do so, may result in transmission line ratings that
do not accurately reflect the near-term transfer capability of the
system. This, in turn, may result in rates that do not reflect actual
costs of delivering wholesale energy to transmission customers. In
support, the Commission stated that transmission owners often develop
two sets of transmission line 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. Because emergency ratings are a
more accurate representation of the flow limits over shorter
timeframes, the Commission preliminarily found that their use in models
of post-contingency flows may produce prices that more accurately
reflect actual costs of delivering wholesale energy to transmission
customers.\21\
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\21\ Id. PP 44-46.
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22. Finally, in the NOPR, the Commission preliminarily found that,
by preventing transmission providers and, in RTO/ISOs, market monitors
from having the opportunity to validate transmission line ratings in
situations where a transmission provider serves any transmission owners
that are not itself, current levels of transparency into transmission
line ratings and transmission line rating methodologies may result in
unjust and unreasonable rates. The Commission observed that a
consequence of a lack of transparency could be inaccurate near-term
transmission line ratings, which may result in rates that do not
accurately reflect congestion and reserve costs on the system. As one
example, the Commission stated that, without knowing the basis for a
given transmission line rating that frequently binds and elevates
prices, a transmission provider and/or market monitor cannot determine
whether the transmission line rating is accurately calculated and
therefore whether unjust and unreasonable wholesale rates are being
created through use of inaccurate transmission line ratings.\22\
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\22\ Id. P 47.
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B. Comments

23. Commenters overwhelmingly agree with the Commission's
preliminary finding 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.\23\
Commenters also agree with the Commission's preliminary finding that,
because of the relationship between transmission line ratings and
wholesale energy costs, inaccurate transmission line ratings may result
in Commission-jurisdictional rates that are unjust and
unreasonable.\24\
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\23\ AEP Comments at 3; Ohio FEA Comments at 6; New England
State Agencies Comments at 8; OMS Comments at 6; Potomac Economics
Comments at 5; CAISO DMM Comments at 4; SPP MMU Comments at 1-2; R
Street Institute Comments at 2; Industrial Customer Organizations
Comments at 11-12; TAPS Comments at 5-6; WATT Comments at 3-5;
Certain TDU Comments at 4-5; Clean Energy Parties Comments at 2-3;
EDFR Comments at 3.
\24\ SPP MMU Comments at 1-2; Potomac Economics Comments at 5;
CAISO DMM Comments at 4; Industrial Customer Organizations Comments
at 11-12; TAPS Comments at 5-6; Certain TDU Comments at 4-5; Clean
Energy Parties Comments at 2-3.
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24. The majority of commenters representing state agencies support
the Commission's basis for reform. New England State Agencies explain
that, because transmission lines are used to control the amount of
energy on electric power systems, transmission line ratings affect the
price of electric power as well as the reliability of the electric
grid.\25\ OMS also agrees with the Commission's preliminary finding
that transmission line ratings directly affect wholesale energy costs
and artificially limit transfers within and between regions, stating
that such a conclusion is obvious and correct.\26\ OMS further contends
that the slow pace of action on this issue by RTOs/ISOs and
transmission owners makes the issue ripe for Commission action.\27\
Ohio FEA maintains that transmission line ratings have a direct and
significant influence on wholesale energy and capacity markets and,
therefore, must be accurate. Ohio FEA further argues that inaccurate
transmission line ratings may also cause Locational Deliverability
Areas (LDAs) to unnecessarily constrain in the

[[Page 2248]]

capacity market, resulting in higher capacity prices.\28\
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\25\ New England State Agencies Comments at 8.
\26\ OMS Comments at 6.
\27\ OMS Reply Comments at 2-3.
\28\ Ohio FEA Comments at 6.
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25. Each of the commenting market monitors supports the
Commission's basis for reform. For example, Potomac Economics agrees
with the Commission's finding that inaccurate transmission line ratings
may result in rates that are not just and reasonable and notes that
facility ratings are used in virtually every aspect of electricity
markets and system operations. Potomac Economics further avers that
transmission line ratings determine the transmission limits input into
market models, which, in turn, determine the commitment and dispatch
needed to satisfy load and manage congestion. Potomac Economics further
explains that underestimated transmission line ratings cause
inefficient operations, higher congestion, reduced transmission
availability, higher costs, higher renewable energy curtailments, and a
greater perceived need for new transmission facilities.\29\ The SPP MMU
also agrees with the Commission's assertion that transmission line
ratings can directly affect the cost of producing wholesale energy,
capacity, and ancillary services, as well as the cost of delivering
such products. The SPP MMU explains that the cost of congestion is
directly impacted by transmission line ratings and that inaccurate
transmission line ratings cause price distortions, which may result in
unjust and unreasonable rates.\30\ The CAISO DMM also agrees with the
Commission's assessment that transmission line ratings and the rules by
which they are established directly impact the cost of wholesale energy
delivery and related services, explaining that static or seasonal line
ratings can lead to increased costs when their assumptions are not
realized, which may be inefficient and can result in excess cost paid
by load.\31\
---------------------------------------------------------------------------

\29\ Potomac Economics Comments at 5.
\30\ SPP MMU Comments at 1-2.
\31\ CAISO DMM Comments at 4.
---------------------------------------------------------------------------

26. Other commenters also support the Commission's basis for
reform. R Street Institute states that the Commission's problem
statement is sound, explaining that transmission line ratings are
chronically understated because they do not reflect current weather
conditions, and as a result, according to R Street Institute, fail to
allow for significant cost savings.\32\ Industrial Customer
Organizations state that transmission line ratings and associated rules
directly affect the cost of wholesale energy, capacity, and ancillary
services, and the cost of delivering wholesale energy to transmission
customers, and the rulemaking is therefore consistent with the
Commission's authority and obligations under the FPA.\33\ TAPS states
that reliance on static or seasonal line ratings inflicts unnecessary
costs on consumers and that AAR deployment can provide significant
benefits to consumers.\34\ WATT explains that accurate transmission
line ratings lower costs for consumers.\35\ Certain TDUs assert that
enhanced transmission line ratings, including AARs and DLRs, are tools
that maximize the efficiency of the existing transmission system and
lower costs for consumers.\36\
---------------------------------------------------------------------------

\32\ R Street Institute Comments at 2.
\33\ Industrial Customer Organizations Comments at 11-12.
\34\ TAPS Comments at 5-6.
\35\ WATT Comments at 3-5.
\36\ Certain TDUs Comments at 4.
---------------------------------------------------------------------------

27. Finally, clean energy and generator representatives also
support the Commission's basis for reform.\37\ For example, Clean
Energy Parties conclude that, due to the impact that transmission line
ratings have on wholesale rates requirements, accurate transmission
line ratings are consistent with the Commission's mandate under
sections 205 and 206 of the FPA.\38\
---------------------------------------------------------------------------

\37\ Clean Energy Parties Comments at 2-3; EDFR Comments at 3.
\38\ Clean Energy Parties Comments at 2-3.
---------------------------------------------------------------------------

28. However, NYTOs question the Commission's legal standing to
regulate transmission line ratings, noting that the U.S. Court of
Appeals for the District of Columbia Circuit (D.C. Circuit) found that
there are limits to the Commission's FPA section 206 jurisdiction over
``practices'' and that the term may not include all utility
operations.\39\ NYTOs note that the Commission's authority to regulate
transmission planning was upheld on appeal but that Order No. 1000 \40\
is not prescriptive; therefore, NYTOs request that the Commission
similarly allow utilities to make their own decisions related to
advanced line rating technologies.\41\
---------------------------------------------------------------------------

\39\ NYTOs Comments at 9 (referencing Cal. Indep. Sys. Operator
Corp. v. FERC, 372 F.3d 395, 402 (D.C. Cir. 2004)).
\40\ Transmission Planning and Cost Allocation by Transmission
Owning and Operating Public Utilities, Order No. 1000, 77 FR 32184
(May 31, 2012), 136 FERC ] 61,051 (2011), order on reh'g, Order No.
1000-A, 139 FERC ] 61,132, order on reh'g and clarification, Order
No. 1000-B, 141 FERC ] 61,044 (2012), aff'd sub nom. S.C. Pub. Serv.
Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014).
\41\ NYTOs Comments at 9-10.
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C. Commission Determination

29. We find that transmission line ratings, and the rules by which
they are established, are practices that directly affect the rates for
the transmission of electric energy in interstate commerce and the sale
of electric energy at wholesale in interstate commerce (hereinafter
referred to collectively as ``wholesale rates''). Thus, the Commission
has jurisdiction over transmission line ratings.\42\ We further find
that, because of the relationship between transmission line ratings and
wholesale rates, inaccurate transmission line ratings result in
wholesale rates that are unjust and unreasonable. Accordingly, pursuant
to FPA section 206,\43\ we conclude that certain revisions to the pro
forma OATT and the Commission's regulations are necessary to ensure
just and reasonable wholesale rates. We adopt most of the reforms
proposed in the NOPR, with certain clarifications, as discussed further
herein, and revisions to the proposed pro forma OATT Attachment M and
to the Commission's regulations.
---------------------------------------------------------------------------

\42\ 16 U.S.C. 824(b)(1), 824d.
\43\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

30. We find that transmission line ratings directly affect
wholesale rates because transmission line ratings and wholesale rates
are inextricably linked. As explained above, transmission line ratings
represent the maximum transfer capability of each transmission line.
That transfer capability determines the quantity of energy that can be
transmitted from suppliers to load in any given moment. Supply and
demand fundamentals dictate that less transfer capability (i.e., less
supply) will result in higher rates, all else being equal. Inaccurate
transmission line ratings can result in underutilization (or
overutilization) of existing transmission facilities, thereby sending a
signal that there is less (or more) transfer capability than is truly
available. This signal impacts the wholesale rates charged for
providing energy and other ancillary services. For example, if the
system operator believes there is less transfer capability than is
truly available, it may dispatch more expensive generators to serve
load, when less expensive generators (which would have resulted in
lower congestion costs) could have been used to reliably serve the same
load. Alternatively, inaccurate transmission line ratings can result in
oversubscription of existing transmission facilities, thereby sending
the opposite signal--that there is more transfer capability than is
truly available--which may risk damage to equipment, may fail to
accurately price congestion costs, and may fail to signal to the market
that more generation and/or transmission investment may be needed in
the long term. We therefore find that transmission line ratings

[[Page 2249]]

directly affect wholesale rates and, concomitantly, that inaccurate
transmission line ratings result in unjust and unreasonable wholesale
rates.\44\
---------------------------------------------------------------------------

\44\ SPP MMU Comments at 1-2; Potomac Economics Comments at 5;
CAISO DMM Comments at 4; Industrial Customer Organizations Comments
at 11-12; TAPS Comments at 5-6; Certain TDU Comments at 4-5; Clean
Energy Parties Comments at 2-3.
---------------------------------------------------------------------------

31. Most commenters, except NYTOs, agree with the Commission's
preliminary conclusion that transmission line ratings directly affect
wholesale rates.\45\ NYTOs caution that the D.C. Circuit found there
are limits to the Commission's FPA section 206 jurisdiction over
``practices'' and that the term may not include all utility
operations.\46\ But, the inextricable link between transmission line
ratings and wholesale rates places transmission line ratings within the
Commission's FPA section 206 jurisdiction.
---------------------------------------------------------------------------

\45\ AEP Comments at 3; Ohio FEA Comments at 6; New England
State Agencies Comments at 8; OMS Comments at 6; Potomac Economics
Comments at 5; CAISO DMM Comments at 4; SPP MMU Comments at 1-2; R
Street Institute Comments at 2; Industrial Customer Organizations
Comments at 11-12; TAPS Comments at 5-6; WATT Comments at 3-5;
Certain TDU Comments at 4-5; Clean Energy Parties Comments at 2-3;
EDFR Comments at 3.
\46\ NYTOs Comments at 9-10.
---------------------------------------------------------------------------

32. Some commenters, in response to the preliminary finding that
accurate transmission line ratings are necessary for just and
reasonable wholesale rates, argue that transmission line ratings are
fundamentally a reliability tool.\47\ We agree that system safety and
reliability are paramount to the proposed requirements for transmission
line ratings. But we disagree with the suggestion that because
transmission line ratings are critical to reliability, economic
considerations are an inappropriate basis for requiring a certain type
of transmission line ratings. Instead, we find that commenters present
a false choice; economic considerations and reliability considerations
are inextricably linked as reliability constraints bound the potential
economic transactions of market participants. In the case of
transmission line ratings, transmission owners calculate the maximum
transfer capability of a transmission line. Transmission providers, in
order to maintain reliable system operations, incorporate those ratings
and other constraints into operations, and the results determine
dispatch and commitment instructions and wholesale rates. Even though
transmission line ratings can be seen as a reliability tool, that does
not obviate the need to ensure that the wholesale rates resulting from
such reliability tools are just and reasonable.
---------------------------------------------------------------------------

\47\ See, e.g., Dominion Comments at 13; Exelon Comments at 6;
PJM Indicated Transmission Owners Comments at 2; EEI Comments at 5.
---------------------------------------------------------------------------

33. Regarding that incorporation of transmission line ratings into
operations and resulting wholesale rates, as the Commission explained
in the NOPR, most transmission owners implement seasonal or static line
ratings. Such seasonal or static line ratings are based on
conservative, worst-case assumptions about long-term conditions, such
as the expected high temperatures that are likely to occur over the
longer term. 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 and, when used in near-
term operations, produce unjust and unreasonable wholesale rates.
34. As explained in the NOPR, incorporating near-term forecasts of
ambient air temperatures in transmission line ratings can more
accurately reflect the true near-term transfer capability of
transmission facilities than continuing to rely on seasonal or static
line ratings. Because actual ambient air temperatures are usually not
as high as the ambient air temperatures conservatively assumed in
seasonal and static line ratings, updating the transmission line
ratings used in near-term transmission service to reflect actual
ambient air 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
serve load with less expensive resources from what were previously
constrained areas. For example, Potomac Economics has found that AAR
implementation by those not already using AARs in MISO alone would have
produced approximately $66.5 million and $49 million in reduced
congestion costs in 2019 and in 2020, respectively.\48\ Such congestion
cost changes and related overall price changes will more accurately
reflect the actual congestion on the system, leading to wholesale rates
that more accurately reflect the cost of the wholesale service being
provided. 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.
---------------------------------------------------------------------------

\48\ Potomac Economics Comments at 8.
---------------------------------------------------------------------------

35. Moreover, while current transmission line rating practices
usually understate transfer capability, they can also overstate
transfer capability and, in doing so, place transmission lines at risk
of inadvertent overload. While actual ambient air temperatures are
usually not as high as the assumed seasonal or static line rating
temperature input, in some instances actual ambient air temperatures
exceed those assumed temperatures. In those instances, seasonal or
static line ratings might reflect more transfer capability than
physically exists, and therefore such transmission line ratings might
allow access to some electric power supplies and/or demand that would
not be available if transmission line ratings reflected the true
transfer capability. Overstating transfer capability, like understating
transfer capability, can result in wholesale rates that fail to reflect
the cost of the wholesale service being provided, though, in the case
of overstated transfer capability, through inaccurately low congestion
pricing and failing to signal to the market that more generation and/or
transmission investment may be needed in the long term.
36. Regarding DLRs, in addition to ambient air temperatures and the
presence or absence of solar heating, other weather conditions such as
(but not limited to) wind, cloud cover, solar heating intensity, and
precipitation, and transmission line conditions such as tension and
sag, can affect the 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 limits than AARs. However, as noted above and
explained in greater detail in Section IV.E below, based on the record
in this proceeding, we decline to mandate DLR implementation in this
final rule. We instead incorporate the record in this proceeding on
DLRs into new Docket No. AD22-5-000, which we open to further explore
DLR implementation.
37. While we believe additional record is needed regarding DLR
implementation, we can determine based on the record that current
transmission line rating practices in RTOs/ISOs that do not permit the
acceptance of DLRs from transmission owners that use DLRs are
contributing to unjust and unreasonable wholesale rates by acting as a
barrier to accurate transmission line ratings. Therefore, as part of
remedying inaccurate transmission line ratings that result in unjust
and unreasonable wholesale rates, we require RTOs/ISOs to establish and
maintain the systems and

[[Page 2250]]

procedures necessary to permit the acceptance of DLRs from transmission
owners that use them. As the Commission explained in the NOPR, some
RTOs/ISOs rely on software that cannot accommodate transmission line
ratings that frequently change, such as DLRs.\49\ Without reflecting
such frequent changes to transmission line ratings, such software
serves as a barrier that prevents transmission owners in RTOs/ISOs from
implementing DLRs and better reflecting the actual transfer capability
of the transmission system. The result is that, even if a transmission
owner sought to implement DLRs, the RTO's/ISO's energy management
system (EMS) may not be able to accept and use the resulting
transmission line rating. The potential inability of RTOs/ISOs to
accept and use a DLR prevents RTO/ISO markets from benefiting from the
more accurate representation of current system conditions. Therefore,
we require RTOs/ISOs to establish and maintain the systems and
procedures necessary to permit the acceptance of DLRs from transmission
owners that use them.
---------------------------------------------------------------------------

\49\ NOPR, 173 FERC ] 61,165 at P 43.
---------------------------------------------------------------------------

38. Regarding emergency ratings, we find that many transmission
owners' current transmission line rating practices fail to use
emergency ratings, and in failing to do so, lead to transmission line
ratings that do not accurately reflect the near-term transfer
capability of the transmission system, and therefore result in
wholesale rates that do not reflect costs of the wholesale service
being provided. As the Commission explained in the NOPR, transmission
owners often develop two sets of transmission line 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. Transmission
providers generally calculate resource dispatch and commitments to
ensure that all facilities are 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, transmission providers
often allow post-contingency flows on transmission lines to exceed
normal ratings for short periods of time, as long as those 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 produces wholesale rates that more accurately
reflect the costs of the wholesale service being provided and therefore
is necessary to ensure just and reasonable wholesale rates. For this
reason, as described below, we require that transmission providers
implement uniquely determined emergency ratings. Additionally, we
require that transmission providers use uniquely determined emergency
ratings for contingency analysis in the operations horizon and in post-
contingency simulations of constraints. Such uniquely determined
emergency ratings must also include separate AAR calculations for each
emergency rating duration used.
39. Finally, we find that the current level of transparency into
transmission line ratings and methodologies may result in unjust and
unreasonable wholesale rates. In some regions, where the transmission
owner and transmission provider are not the same entity, such as RTOs/
ISOs, current transparency levels prevent the transmission provider and
market monitor(s) from having the opportunity to assess the accuracy of
transmission line ratings. For example, as the Commission described in
the NOPR, without knowing the basis for a given transmission line
rating that frequently binds and elevates prices, a transmission
provider and/or market monitor cannot determine whether the
transmission line rating is accurately calculated.\50\ Moreover, we
find that, absent additional information to market participants on
transmission line ratings and their methodologies, the status quo does
not provide market participants with information important to making
cost-effective decisions and, thereby, impedes such decisions. For
example, without accurate transmission line rating information, market
participants operate without information that is important in making
accurate economic decisions regarding where to build generation or
where to site load. Further, this lack of transparency could allow
transmission owners to submit inaccurate near-term transmission line
ratings, which, in turn, would result in wholesale rates that do not
accurately reflect the cost of the wholesale service being provided, as
discussed above. For these reasons, we require: (1) Public utility
transmission owners to share transmission line ratings and
methodologies with their transmission provider(s) and with market
monitors in RTOs/ISOs; (2) transmission providers to share their
transmission owners' transmission line ratings and methodologies with
any transmission provider(s) upon request; (3) transmission providers
to maintain a database of their transmission owners' transmission line
ratings and methodologies on the transmission provider's OASIS site or
another password-protected website; and (4) transmission providers to
post on OASIS or another password-protected website any uses of
exceptions or temporary alternate ratings.
---------------------------------------------------------------------------

\50\ Id. P 47.
---------------------------------------------------------------------------

IV. Discussion

A. Transmission Line Ratings Definition

1. NOPR Proposal
40. In the NOPR, the Commission proposed to define a transmission
line rating in pro forma OATT Attachment M as the maximum transfer
capability of a transmission line, computed in accordance with a
written transmission line rating methodology and consistent with good
utility practice, considering the technical limitations on conductors
and relevant transmission equipment (such as thermal flow limits), 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.\51\
---------------------------------------------------------------------------

\51\ NOPR, 173 FERC ] 61,165 at P 85.
---------------------------------------------------------------------------

41. Under the ``Obligations of Transmission Provider'' section in
pro forma OATT Attachment M, the Commission further proposed to require
that the transmission provider must use either AARs or seasonal line
ratings, as appropriate, as the relevant transmission line ratings.
Similarly, and as described in more detail in Section IV.D.3, the
Commission proposed exceptions to the AAR and seasonal line rating
requirements for certain transmission line ratings.
2. Comments
42. Some commenters support the proposed definition of transmission
line rating, while others request clarity or modifications be made,
specifically around the list of relevant transmission equipment. AEP
supports the Commission's proposed transmission line rating definition,
explaining that the Commission's proposed definition reflects the fact
that transmission line ratings incorporate a set of electrical
equipment that collectively operate as a single bulk electric system
element (e.g., transformers, relay protective devices, terminal
equipment, and series and shunt compensation devices) and that the most
limiting component from that

[[Page 2251]]

set determines the transmission line rating.\52\ Similarly, Indicated
PJM Transmission Owners address the NOPR's proposed AAR requirements
set forth in pro forma OATT Attachment M under ``Obligations of
Transmission Provider'' (hereinafter referred to as ``the proposed AAR
requirements'') as ambient-adjusted and seasonal line ratings,
consistent with NERC's definition of facility rating,\53\ and describe
Indicated PJM Transmission Owners' implementation of AARs, consistent
with NERC's definition of facility ratings.\54\ PJM also describes the
implementation of AARs for each of its transmission facilities.\55\
---------------------------------------------------------------------------

\52\ AEP Comments at 2-3.
\53\ The NERC Glossary defines a ``Facility Rating'' as: ``[t]he
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 28,
2021), <a href="https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf">https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf</a>.
\54\ Indicated PJM Transmission Owners Comments at 1-2, 6-7.
\55\ PJM Comments at 2-3.
---------------------------------------------------------------------------

43. Entergy explains that overhead conductor ratings and ratings
for ``ancillary equipment,'' or equipment that does not include a
primary element, like conductors and transformers, can be temperature
adjusted. According to Entergy, examples of ``ancillary equipment''
include breakers, switches, traps, busses, jumpers, current
transformers, potential transformers, and relay equipment. Entergy
further asserts, however, that shunt reactors, series capacitors,
relays, current transformers, static VAR compensators, circuit
breakers, autotransformers, copper weld (``CW'') buses, conductors,
risers or jumpers, and, subject to limited exceptions, customer
equipment have ratings that cannot be temperature adjusted.\56\
Eversource states that the ratings for relays and other equipment, such
as splices, switches, and terminal equipment, are not impacted by
ambient air temperatures.\57\ NYISO states that the majority of the
bulk electric system equipment ratings in New York are able to be rated
using AARs or DLRs,\58\ while NYTOs note that transmission line ratings
may be based on non-conductor components which are not affected by
ambient air temperatures.\59\ EEI and MISO Transmission Owners request
clarity on the definition of transmission line rating and its specific
applicability, stating that the AAR requirements should not apply to
power transformers, but instead, under certain circumstances, to other
types of transformers, including current transformers.\60\ EEI further
explains that ratings for power transformers are generally the result
of the efficiency of the heat transfer process, not ambient air
temperatures directly, and thus requests that the Commission clarify
that the references to transformers apply only to transformers that
limit or impact transmission line ratings and not power transformers
generally.\61\ Entergy similarly notes that transformer and relay
ratings do not change with ambient conditions.\62\ ITC states that AARs
cannot be applied to voltage or stability limits and therefore
recommends that ``transmission line rating'' reflect the concepts of
equipment and facility rating as defined by NERC in order to avoid
confusion with a system operating limit.\63\ APS states that
transmission lines with limitations associated with substation
equipment or series capacitors, among other equipment in which the
transmission line is not the limiting factor, may not experience
changes to their transfer capabilities.\64\ MISO contends that the list
could include potential relay trip limits and maximum power transfer
limits.\65\
---------------------------------------------------------------------------

\56\ Entergy Comments at 5-6.
\57\ Eversource Comments at 3.
\58\ NYISO Comments at 3-4.
\59\ NYTOs Comments at 8.
\60\ EEI Comments at 17-18; MISO Transmission Owners Comments at
39-40.
\61\ EEI Comments at 17-18.
\62\ Entergy Comments at 9-10.
\63\ ITC Comments at 11-12. The NERC Glossary defines an
``Equipment Rating'' as: ``[t]he maximum and minimum voltage,
current, frequency, real and reactive power flows on individual
equipment under steady state, short-circuit and transient
conditions, as permitted or assigned by the equipment owner.'' It
defines a ``System Operating Limit'' as: ``[t]he value (such as MW,
Mvar, amperes, frequency or volts) that satisfies the most limiting
of the prescribed operating criteria for a specified system
configuration to ensure operation within acceptable reliability
criteria. System Operating Limits are based upon certain operating
criteria. These include, but are not limited to: Facility Ratings
(applicable pre- and post-Contingency Equipment Ratings or Facility
Ratings); transient stability ratings (applicable pre- and post-
Contingency stability limits); voltage stability ratings (applicable
pre- and post-Contingency voltage stability); and system voltage
limits (applicable pre- and post-Contingency voltage limits).''
NERC, Glossary of Terms Used in NERC Reliability Standards (June 28,
2021), <a href="https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf">https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf</a>.
\64\ APS Comments at 3.
\65\ MISO Comments at 34.
---------------------------------------------------------------------------

3. Commission Determination
44. In this final rule, we adopt the definition of transmission
line rating proposed in the NOPR. Specifically, we adopt the proposed
definition that a transmission line rating means the maximum transfer
capability of a transmission line, computed in accordance with a
written transmission line rating methodology and consistent with good
utility practice, considering the technical limitations on conductors
and relevant transmission equipment (such as thermal flow limits), 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. As the Commission stated in the NOPR, system safety and
reliability are paramount to the proposed requirements for transmission
line ratings. We agree with AEP that the definition adopted herein
reflects the fact that transmission line ratings must incorporate a set
of electrical equipment ratings that collectively operate as a single
bulk electric system element (e.g., transformers, relay protective
devices, terminal equipment, and series and shunt compensation devices)
and that the most limiting component from that set determines the
transmission line rating.\66\
---------------------------------------------------------------------------

\66\ AEP Comments at 2-3.
---------------------------------------------------------------------------

45. In response to comments about the definition's inclusion of the
technical limitations (such as thermal flow limits) on conductors and
relevant transmission equipment, we clarify that the definition of
transmission line rating encompasses transmission line ratings for
electric system equipment that includes more than just overhead
conductors. For example, it includes ratings for electric system
equipment such as circuit breakers, line traps, and transformers.
Additionally, as described in more detail below in Section IV.D.3, we
adopt the list of proposed exceptions from the NOPR. Consequently, we
do not require transmission line ratings that are not affected by
ambient air temperatures to be rated using forecasts of ambient air
temperatures. That said, we decline to define in this final rule which
electric system equipment ratings are (or are not) affected by ambient
air temperatures. Instead, we allow flexibility for individual
transmission owners and transmission providers to apply good utility
practice to determine which specific electric system equipment has
ratings that are (or are not) affected by ambient air temperatures.
46. Finally, in response to requests for clarification from EEI and
MISO Transmission Owners regarding the applicability of the proposed
AAR requirements to power transformers, we decline to provide a generic
exception from the AAR requirement for power transformers. The
operating limits of a power transformer are bounded by the

[[Page 2252]]

ambient air temperature, the average winding temperature, and the
maximum winding hottest-spot temperature.\67\ However, we reiterate the
exceptions adopted herein and discussed further below, which provide
that any rating not affected by ambient air temperatures would not be
required to incorporate forecasts of ambient air temperatures into the
rating. Thus, if a transmission provider determines, consistent with
good utility practice, that a specific power transformer's rating is
not affected by ambient air temperature, then that power transformer
would fall within the scope of such exceptions to the AAR requirement.
---------------------------------------------------------------------------

\67\ Institute of Electrical and Electronics Engineers, IEEE
Standard for General Requirements for Liquid-Immersed Distribution,
Power, and Regulating Transformers, IEEE Std C57.91.00-2021.
---------------------------------------------------------------------------

B. Ambient-Adjusted Ratings

1. AAR Definition and Transmission Provider Obligations
a. NOPR Proposal
47. In the NOPR, the Commission proposed to define an AAR in pro
forma OATT Attachment M and in the Commission's regulations 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. As
obligations of the transmission provider set forth in pro forma OATT
Attachment M, the Commission proposed to require that transmission
providers use AARs as the applicable line rating: (1) For requests for
near-term point-to-point transmission service ending within 10 days of
the request date, as defined in pro forma OATT Attachment M; (2) for
determining the necessity of near-term curtailment or interruption of
near-term point-to-point transmission service anticipated to occur
(start and end) within the next 10 days; and (3) for determining the
necessity of near-term interruption or redispatch of network
transmission service anticipated to occur (start and end) within the
next 10 days. The Commission proposed to require transmission providers
to implement the use of AARs and seasonal line ratings on all
historically congested transmission lines \68\ within one year after
the compliance filing due date and on all other transmission lines
within two years after the compliance filing due date.\69\ For RTOs/
ISOs, for which the Commission has 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), the Commission proposed two
requirements. First, the Commission proposed requirements for RTOs/ISOs
to implement AARs in both the day-ahead and real-time markets and any
intra-day reliability unit commitment. Second, the Commission proposed
to require AARs as the relevant transmission line rating for any near-
term point-to-point transmission service offered (e.g., at the RTO's/
ISO's borders).
---------------------------------------------------------------------------

\68\ The Commission proposed to define a historically congested
transmission line as ``a transmission line that was congested at any
time in the five years prior to the effective date of [this final
rule].'' NOPR, 173 FERC ] 61,165 at P 92.
\69\ Id. P 131.
---------------------------------------------------------------------------

48. As justification for the NOPR proposal to require AAR
implementation on all transmission lines and not only on historically
congested lines, the Commission noted that any facility can become the
most limiting element as the transmission system changes, and in
certain circumstances flows may change considerably from normal
operations. Therefore, the Commission proposed to require AARs be
implemented on all transmission lines but recognized that a staggered
implementation schedule would allow transmission providers and
transmission owners to focus initial implementation where it would have
the most impact.\70\
---------------------------------------------------------------------------

\70\ Id. PP 93-94.
---------------------------------------------------------------------------

49. As justification for requiring AARs, the Commission
preliminarily found that AAR requirements strike an appropriate balance
between benefits and challenges. First, the Commission observed that,
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. The Commission
next explained that, according to Potomac Economics' estimates, the
benefits to AAR implementation by those not already implementing AARs
in MISO alone would have produced approximately $94 million and $78
million in reduced congestion costs in 2017 and in 2018, respectively.
The Commission further explained that, while several entities noted
implementation costs as a barrier to AAR implementation, the costs
identified were mostly initial investments in upgraded OASIS and/or EMS
and ratings databases and that once these systems are upgraded, adding
AARs to additional transmission lines appears to have a minimal
incremental cost.\71\
---------------------------------------------------------------------------

\71\ Id. P 99.
---------------------------------------------------------------------------

b. Comments
50. In response to the proposed AAR requirements, RTO/ISO comments
are mixed, with most requesting flexibility to accommodate regional or
market differences,\72\ while market monitors are generally supportive
of the NOPR proposal.\73\ Transmission owners are conceptually
supportive of AAR implementation but request flexibility in response to
what they generally describe as an overly broad requirement.\74\ The
PJM transmission owners that submitted comments are generally
supportive of the proposed AAR requirements in pro forma OATT
Attachment M, explaining that they have experience using AARs.\75\
Other commenters, including state governments, generation, load,
renewable energy advocates, and other technical experts, are generally
supportive of the proposed AAR requirements.\76\
---------------------------------------------------------------------------

\72\ See, e.g., MISO Comments at 7, 9, 14-16; NYISO Comments at
9-11; ISO-NE Comments at 9.
\73\ Potomac Economics Comments at 3-4; CAISO DMM Comments at 2-
4; SPP MMU Comments at 1, 4.
\74\ MISO Transmission Owners Comments at 8-9; PacifiCorp
Comments at 2; EEI Comments at 2-5; NRECA/LPPC Comments at 2-3;
Entergy Comments at 1-2; BPA Comments at 2-4; WAPA Comments at 4-5;
APS Comments at 2-4; Southern Company Comments at 2-3; NYTOs
Comments at 2-3; Duke Energy Comments at 1-2; PG&E Comments at 3;
SCE Comments at 1-2; SDG&E Comments at 1-2; LADWP Comments at 2-3;
IID Comments at 4-6; ITC Comments at 1-3; Sunflower Comments at 2;
Eversource Comments at 5-7.
\75\ Exelon Comments at 1-2; AEP Comments at 5-6; Dominion
Comments at 3-4; Indicated PJM Transmission Owner Comments at 1-4.
\76\ New England State Agencies Comments at 10; OMS Comments at
2; Ohio FEA Comments at 2; R Street Institute Comments at 1-2; WATT
Comments at 1-2; DC Energy Comments at 1-2; ACORE Comments at 1;
Clean Energy Parties Comments at 2, 4-6; ENEL Comments at 1; EDFR
Comments at 1-2; Vistra Comments at 1-2; EPSA Comments at 2;
Industrial Customers Comments at 1-2; TAPS Comments at 1-2; Certain
TDU Comments at 1.
---------------------------------------------------------------------------

51. Several transmission owners explain that they currently use
AARs on all or parts of their transmission lines and support the
Commission's NOPR proposal to implement widespread AAR use. AEP notes
that it has used AARs in real-time operations for decades and that AARs
have provided both reliability and financial benefits.\77\ AEP notes
that the use of AARs is common in PJM and that it similarly implements
AARs for its facilities in SPP and the Electric Reliability Council of
Texas (ERCOT).\78\ Exelon states that it

[[Page 2253]]

considers AARs to be a best practice, explaining that all of its six
utilities have implemented AARs on their transmission systems, without
any adverse reliability or safety impacts, and have found the practice
to be a cost-effective tool to enhance grid reliability.\79\ Dominion
states that, because PJM has implemented AARs for transmission service
and for use in its day-ahead and real-time markets, Dominion Energy
Virginia has adopted and uses PJM's AAR methodology on all its
transmission lines, while Dominion Energy South Carolina uses AARs on
only a portion of its transmission system.\80\ Indicated PJM
Transmission Owners support efforts to enhance transmission utilization
by requiring AAR and seasonal line rating implementation, explaining
that such practices improve efficiency; they also state that
transmission line ratings are fundamentally a reliability tool.\81\
While generally supportive of the NOPR proposal, Dominion, AEP, and
Indicated PJM Transmission Owners all request flexibility to
accommodate PJM's current AAR implementation and ask that the
Commission not require hourly updates to AARs.\82\
---------------------------------------------------------------------------

\77\ AEP Comments at 3.
\78\ Id. at 3-4.
\79\ Exelon Comments at 1-2.
\80\ Dominion Comments at 6.
\81\ Indicated PJM Transmission Owners Comments at 1-2.
\82\ Dominion Comments at 3; AEP Comments at 6-7; Indicated PJM
Transmission Owners Comments at 5.
---------------------------------------------------------------------------

52. Both ITC and Sunflower state that they are generally supportive
of AAR implementation, but urge flexibility for transmission providers
to implement AARs.\83\ MISO Transmission Owners, explaining that they
have initiated a process to implement AARs, state that they support
certain aspects of the NOPR, but also state that other aspects are
overly broad and will not yield sufficient benefits to justify the
costs.\84\ MISO Transmission Owners urge the Commission to allow for
regional flexibility in any requirements and state that AAR deployment
should focus on where it is expected to provide benefits by ``freeing
up'' additional transfer capability.\85\ MISO Transmission Owners state
that, over the past five years, congestion arose on only 10% of the
nearly 10,000 transmission facilities under MISO's functional control
and that there would be no benefit to implementing AARs on non-
congested lines.\86\ MISO Transmission Owners also state that there are
several necessary steps to implement AARs, which can be costly and time
consuming.\87\ Additionally, MISO Transmission Owners state that the
Commission should not rely upon Potomac Economics' estimates of AAR
benefits, explaining that Potomac Economics inaccurately assumed that:
(1) All transmission lines are ambient adjustable; (2) all transmission
owners are using worst-case assumptions; and (3) congestion caused by
transient outages existed even though it has since been alleviated by
recent upgrades.\88\
---------------------------------------------------------------------------

\83\ ITC Comments at 1-3; Sunflower Comments at 2.
\84\ MISO Transmission Owners Comments at 3-4.
\85\ Id. at 13.
\86\ Id. at 28.
\87\ Id. at 22.
\88\ Id. at 43-45.
---------------------------------------------------------------------------

53. NYTOs, Eversource, and Southern Company request that the
Commission refrain from adopting blanket AAR requirements for all
transmission lines and instead require transmission providers to adopt
a process for determining whether to apply AARs or DLRs to certain
transmission facilities.\89\ Southern Company suggests that such a
process could be similar to the Commission's available transfer
capability (ATC) requirements, whereby a public utility could include
the metrics and criteria for determining when to use AAR or DLR in its
OATT and implementation details in its guidelines or business
practices.\90\ Southern Company states that, while broader use of AARs
and DLRs may provide cost savings to customers, the Commission's
proposed approach in the NOPR is overly prescriptive and may therefore
create unnecessary implementation complications and limit the
deployment of other grid-enhancing technologies.\91\ Southern Company
and NRECA/LPPC also argue that non-RTO/ISO regions are characterized by
long-term transmission commitments and that incremental short-term
transfer capability is less relevant and less likely to result in cost
savings.\92\ Eversource contends that it applies AARs where it is
beneficial, but states that the benefits of AARs will depend on
specific circumstances within a region, noting that there is little
congestion in ISO-NE.\93\
---------------------------------------------------------------------------

\89\ Southern Company Comments at 1-2; Eversource Comments at 6;
NYTOs Comments at 10.
\90\ Southern Company Comments at 1-2.
\91\ Id. at 2.
\92\ Id. at 4-5; NRECA/LPPC Comments at 19.
\93\ Eversource Comments at 4-5.
---------------------------------------------------------------------------

54. Southern Company states that reliability issues may arise as a
result of the NOPR proposal because AARs may create difficulties in
identifying the most limiting element, which may change as the
temperature changes, and similar difficulties may arise in complying
with Reliability Standard PRC-023-4's transmission relay loadability
requirements that depend on maximum published ratings.\94\ EEI states
that, to ensure compliance with Reliability Standard PRC-023-4,
significant amounts of field engineering time could be required to
install and test new settings for thousands of relays.\95\ NYTOs state
that implementing the AAR requirements will require significant time
and resources and would divert scarce resources from ongoing efforts to
meet the goals of New York's Climate Leadership and Community
Protection Act.\96\ NERC contends that the Commission should keep in
mind considerations for implementing AARs across long transmission
lines that span multiple climates.\97\
---------------------------------------------------------------------------

\94\ Southern Company Comments at 6.
\95\ EEI Comments at 5-6.
\96\ NYTOs Comments at 6-7.
\97\ NERC Comments at 7.
---------------------------------------------------------------------------

55. Duke Energy states that it already employs AARs in real-time
operations and supports the Commission's proposed requirements for
transmission providers to implement AARs in real-time operations.\98\
However, Duke Energy also argues that, because incorporating AARs into
ATC calculations would require fundamental software changes that may
take several million dollars and multiple years to complete, the
benefits may not outweigh the costs.\99\ Duke Energy suggests that the
Commission should instead require transmission providers to submit a
compliance filing in which they may propose a process to identify the
transmission facilities for which the implementation of AARs and
seasonal line ratings will provide the most benefits to customers.\100\
---------------------------------------------------------------------------

\98\ Duke Energy Comments at 5.
\99\ Id. at 10.
\100\ Id. at 5.
---------------------------------------------------------------------------

56. EEI states that its experience with AARs is that their use can
provide benefits on a subset of transmission lines \101\ and requests
flexibility for transmission owners and transmission providers to
implement transmission line rating solutions that best suit their
needs.\102\ EEI recommends a staggered AAR approach whereby AARs would
first be implemented on priority designated facilities, using
established and studied criteria, and any subsequent AAR implementation
would occur following further studies of potential benefits.\103\
Similarly, Entergy states that AARs allow for more flexibility in real-
time operations than static/thermal values for real-time contingency
studies,

[[Page 2254]]

but contends that the use of AARs should follow a scientific
application of factors that can reasonably result in an adjustment of
facility ratings to those facilities for which an adjustment would be
reasonably expected to provide benefits that exceed costs.\104\
---------------------------------------------------------------------------

\101\ EEI Comments at 5.
\102\ Id. at 2-4.
\103\ Id.
\104\ Entergy Comments at 8.
---------------------------------------------------------------------------

57. NRECA/LPPC, Sunflower, and WAPA contend that the promised
benefits, costs, and risks of AARs are not evenly distributed
nationwide and that blanket application of the proposed AAR
requirements poses difficult operating challenges.\105\ NRECA/LPPC
argue that the Commission should maintain a focus on safety and
reliability and limit the scope of any final rule by applying the AAR
requirements to transmission lines: (1) Rated 100 kV and above; (2)
that are historically congested due to conductor limitations only; and
(3) that are under RTO/ISO control. In addition, NRECA/LPPC argue that
AAR requirements should be limited to transmission service used for
near-term wholesale transactions, which in the RTOs/ISOs would be the
day-head and real-time markets, and outside of the RTOs/ISOs, if
applied, would be daily and hourly ATC, curtailment, and
redispatch.\106\ NRECA/LPPC and Sunflower further contend that, due to
challenges in implementing AARs, utilities should have the flexibility
to choose the AAR methodology best suited to their needs and should
provide a waiver mechanism for particular circuits on which AAR
implementation is difficult.\107\
---------------------------------------------------------------------------

\105\ NRECA/LPPC Comments at 15-16, 19; Sunflower Comments at 5;
WAPA Comments at 5.
\106\ NRECA/LPPC Comments at 2-3.
\107\ Id. at 3; Sunflower Comments at 5.
---------------------------------------------------------------------------

58. Several Western Interconnection, non-CAISO transmission owners,
including PacifiCorp, BPA, WAPA, and APS, broadly support the adoption
of AARs due to the associated reduction in congestion, increase in
transfer capability, and reliability improvements. However, these
transmission owners request additional flexibility in how transmission
owners apply AARs and urge the Commission to not adopt blanket AAR
requirements for all transmission lines given differences in terrain,
line lengths, and scarcity of temperature data for such lines.\108\ In
explaining the drawbacks to blanket AAR implementation, APS explains
that non-congested transmission lines, transmission lines that are
substation equipment-limited, and transmission lines that are voltage-
and stability-limited will not benefit from AAR implementation.\109\
WAPA further identifies additional AAR implementation challenges,
including the installation of new devices, communication equipment, and
cybersecurity challenges. To reduce implementation burdens, WAPA
recommends that the Commission examine real-time Total Transfer
Capability (TTC) calculations.\110\ WAPA further cautions that it would
have to pass the costs of AAR implementation on to all customers, even
though only some customers would benefit.\111\ BPA states that if it
uses AARs as proposed, it would need to make its wind assumptions more
conservative, de-rating transmission, to mitigate the risk of operating
near the conductor limit.\112\
---------------------------------------------------------------------------

\108\ PacifiCorp Comments at 2; BPA Comments at 2-4; WAPA
Comments at 4-5; APS Comments at 2-4.
\109\ APS Comments at 2-4.
\110\ WAPA Comments at 7-9.
\111\ Id. at 4-5.
\112\ BPA Comments at 4-5.
---------------------------------------------------------------------------

59. PacifiCorp, BPA, EEI, and IID further explain additional
difficulties they would face implementing the proposed requirements to
incorporate AARs into ATC that could render AAR implementation
infeasible.\113\ IID explains that, in the Western Interconnection,
path limits are the result of multiple limits in series and in
parallel. TTC calculations involve adjusting a base case with an
associated series of activities, and failures in base case studies have
to be evaluated manually, such that a generic equation would be
insufficient in calculating transmission line ratings.\114\ BPA and
PacifiCorp explain that most congested parts on their transmission
systems are lines that are operated in parallel as part of a rated
transmission path,\115\ that such rated paths have interactions with
other paths, which result in operating nomograms,\116\ and that the
NOPR proposal may be more appropriate for a flow-based transmission
system.\117\ According to PacifiCorp and BPA, it may be infeasible to
implement AARs as it would substantially increase the time to compute
the constraints that they use to calculate TTC.\118\ CAISO also
describes the TTC calculation process using rated paths and states that
using hourly AARs would exponentially increase the complexity of such
calculations and would necessitate further automation.\119\ Similarly
describing the challenges of incorporating AARs into ATC, EEI explains
that, in some areas, TTC values are determined annually, or even less
frequently.\120\
---------------------------------------------------------------------------

\113\ Id. at 3-4; PacifiCorp Comments at 2; IID Comments at 5-6;
EEI Comments at 10-11.
\114\ IID Comments at 5.
\115\ BPA Comments at 3; PacifiCorp Comments at 2.
\116\ Nomograms are operating constraints related to the flow on
multiple paths that generally result from the simultaneous
interaction between those paths.
\117\ BPA Comments at 3; PacifiCorp Comments at 2.
\118\ BPA Comments at 3; PacifiCorp Comments at 2.
\119\ CAISO Comments at 10.
\120\ EEI Comments at 11.
---------------------------------------------------------------------------

60. California transmission owners urge more targeted AAR
implementation.\121\ PG&E recommends requiring transmission owners to
determine which lines would realize net benefits for customers if AARs
were deployed, noting that deployment of AARs across all transmission
lines could result in a negative return on investment and an increased
risk profile for the transmission system.\122\ PG&E notes that most of
its weather stations are currently located in ``High Fire Threat
Districts'' and contends that AAR implementation on 500 kV lines will
require planning for additional weather station equipment to ensure
that accurate weather data is available.\123\ SCE advocates for phased
AAR implementation in which transmission owners identify priority
facilities, and, after implementation, study their implementation in a
report filed with the Commission.\124\ SDG&E contends that settings for
all relays will have to be studied and installed in the field, causing
a significant cost burden unaccounted for in the Commission's
analysis.\125\ IID contends that the Commission should not take a one-
size-fits-all approach and, in addition to the challenges of AAR
implementation, encourages the Commission to consider the costs of
software, equipment, and staffing in comparison to the benefits of AARs
providing congestion relief.\126\
---------------------------------------------------------------------------

\121\ PG&E Comments at 3; SCE Comments at 1-2; SDG&E Comments at
1-2; LADWP Comments at 2-3.
\122\ PG&E Comments at 3.
\123\ Id. at 9-10.
\124\ SCE Comments at 3-4.
\125\ SDG&E Comments at 4.
\126\ IID Comments at 5.
---------------------------------------------------------------------------

61. LADWP states that Southern California loads peak in the summer
when temperatures are already high and may not allow AARs to expand
transfer capability. Conversely, according to LADWP, there is already
abundant transfer capability in the winter months.\127\ Describing AAR
implementation challenges, LADWP notes that, due to the diversity in
terrain and microclimates that western transmission lines traverse,
weather forecasts can vary significantly during volatile weather
seasons and present

[[Page 2255]]

challenges in identifying the most constraining ambient conditions for
a given transmission line.\128\ LADWP therefore contends that the
Commission should consider offering regional exceptions from the AAR
requirements or prescribing AARs only in areas where significant
benefits are expected.\129\
---------------------------------------------------------------------------

\127\ LADWP Comments at 3-4.
\128\ Id. at 5-6.
\129\ Id. at 4-5.
---------------------------------------------------------------------------

62. PJM generally supports the adoption of AARs by transmission
providers. PJM states that it already employs AARs in its operations
and day-ahead and real-time markets and that the use of AARs is
commonplace among the overwhelming majority of transmission owners in
the PJM region. PJM states that transmission owners' utilization of
AARs increases operational flexibility, promotes a more efficient use
of the transmission system, and results in more reliable system
dispatch and cost-effective market operations.\130\
---------------------------------------------------------------------------

\130\ PJM Comments at 2.
---------------------------------------------------------------------------

63. CAISO states that it currently uses seasonal line ratings,
emergency ratings, and AARs. However, CAISO notes that AARs are used on
relatively few facilities and involve a manual process to update
transmission line ratings for an applicable period. CAISO states that,
while AARs provide a more accurate understanding of the transfer
capability of the transmission system, CAISO recommends that the
Commission allow transmission owners and transmission providers to
justify when they use AARs.\131\
---------------------------------------------------------------------------

\131\ CAISO Comments at 2.
---------------------------------------------------------------------------

64. MISO states that AAR and DLR deployment can support the
efficient use of existing transmission infrastructure but is not a
long-term solution to meet emerging system needs. MISO states that the
Commission should not mandate the use of AARs where the burden of that
deployment is greater than the benefits to be expected. MISO contends
that the Commission should explore options for a more targeted
application of identifying facilities that are good candidates for AARs
based on objective criteria and documented methodologies.\132\ MISO
notes that it and MISO Transmission Owners have already commenced an
effort to identify a prioritized list of candidate transmission
facilities for deployment of real-time AARs in MISO.\133\
---------------------------------------------------------------------------

\132\ MISO Comments at 9.
\133\ MISO Comments at 14.
---------------------------------------------------------------------------

65. NYISO does not support a uniform approach to managing
transmission line ratings and instead requests that each RTO/ISO work
with the Commission to set objectives for its markets.\134\ NYISO
contends that AAR use would not provide benefits everywhere.\135\ NYISO
explains that using AARs to modify day-ahead transmission line ratings
would overly complicate the day-ahead market solution and would reduce
efficiency.\136\ NYISO requests flexibility for regional variation with
transmission line ratings given regional differences, such as
transmission scheduling and market rules.\137\ NYISO states that it
could work with stakeholders to develop a proposal to implement three
to four sets of seasonal line ratings that would be easier to implement
and still achieve many of the NOPR objectives.\138\
---------------------------------------------------------------------------

\134\ NYISO Comments at 1.
\135\ Id. at 2.
\136\ Id. at 1-2.
\137\ Id. at 2.
\138\ Id. at 20.
---------------------------------------------------------------------------

66. Neither ISO-NE nor SPP explicitly takes a position on the NOPR
proposal to implement AARs. However, ISO-NE states that most of the
congestion that occurs on its system is due to voltage or stability
limitations, and thus AAR benefits may be limited.\139\ ISO-NE
estimates that the implementation of AARs could result in the lowering
of thermal congestion costs by, at most, approximately $5-10 million
per year.\140\ ISO-NE also contends, however, that AAR implementation
may expose other binding system limitations without appreciably
increasing transfer capability or reducing congestion.\141\
---------------------------------------------------------------------------

\139\ ISO-NE Comments at 4-6.
\140\ Id. at 5 (basing estimates on 2019 data contained in IMM
and EMM Reports and the Commission's estimates of potential savings
from AARs in other RTO/ISO regions).
\141\ Id. at 6.
---------------------------------------------------------------------------

67. Market monitors are mostly supportive of the proposed AAR
requirements.\142\ The SPP MMU supports the proposed reforms to improve
the accuracy and transparency of transmission line ratings used by
transmission providers. The SPP MMU notes that numerous SPP
transmission lines are not rated according to SPP Planning
Criteria.\143\ The SPP MMU states that it supports the use of DLRs for
all transmission lines.\144\ According to the SPP MMU, when
transmission line ratings underestimate the actual transfer capability
of the transmission system, this can result in restricted flows on
certain paths while overloading others and can create a potential for
de facto physical withholding of the available transfer capability by
transmission owners.\145\ The SPP MMU argues that more accurate
transmission line ratings will improve the robustness of price
formation, particularly in congested areas.\146\
---------------------------------------------------------------------------

\142\ Potomac Economics Comments at 3-4; CAISO DMM Comments at
2-4; SPP MMU Comments at 1, 4.
\143\ SPP MMU Comments at 4.
\144\ Id. at 1, 4.
\145\ Id. at 7.
\146\ Id. at 9.
---------------------------------------------------------------------------

68. Potomac Economics states that only 8% of the transmission line
ratings in MISO are adjusted for changes in ambient air temperatures.
Potomac Economics indicates that it conservatively estimates that the
benefits of using AARs and emergency ratings in 2019 and 2020 would
have been between 9% and 13% of the real-time congestion value, or $98
million and $114 million per year.\147\ Potomac Economics notes that
transmission owners have little or no economic incentive to provide
temperature-adjusted ratings and that transmission operators \148\
rarely verify or validate transmission line rating methodologies or
transmission line rating calculations.\149\ Potomac Economics contends
that it would be unreasonable to require AARs on all transmission
facilities, and instead argues that it would be more reasonable to
require that processes be established to allow for additional AARs to
be deployed quickly when new constraints begin to bind or other studies
indicate it may be appropriate.\150\ Potomac Economics cautions,
however, against requiring any cost-benefit analysis, noting that the
incremental cost of initiating AARs on new constraints is near zero so
such analysis is unnecessary.\151\ Finally, Potomac Economics contends
that using AARs and emergency ratings will not create reliability
concerns as the NOPR proposal only requires that decisions to not
implement AARs or emergency ratings be based on reliability and not a
preference or policy decision.\152\ CAISO DMM supports the proposed
requirements to implement hourly AARs as a way to improve both the
accuracy of congestion costs and transmission system efficiency.\153\
---------------------------------------------------------------------------

\147\ Potomac Economics Comments at 7-9; see also Potomac
Economics Reply Comments at 2-6.
\148\ The NERC Glossary defines a ``Transmission Operator'' as:
``[t]he entity responsible for the reliability of its `local'
transmission system, and that operates or directs the operations of
the transmission Facilities.'' NERC, Glossary of Terms Used in NERC
Reliability Standards (June 28, 2021), <a href="https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf">https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf</a>.
\149\ Potomac Economics Comments at 9-10; see also Potomac
Economics Reply Comments at 6-7.
\150\ Potomac Economics Comments at 20; see also Potomac
Economics Reply Comments at 9.
\151\ Potomac Economics Reply Comments at 7.
\152\ Id. at 11.
\153\ CAISO DMM Comments at 2, 4.

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[[Page 2256]]

69. State government agencies are also mostly supportive of the
proposed AAR requirements.\154\ New England State Agencies state that
they strongly support the Commission's proposed AAR requirements.\155\
New England State Agencies state that the transmission system was built
on behalf of and paid for by ratepayers, and argue that the Commission
should take all reasonable steps to protect those ratepayers from
excessive costs. New England State Agencies contend that the use of
AARs can be an important tool in this regard.\156\ New England State
Agencies state that a transmission system operated using AARs may
provide benefits by possibly: (1) Obviating the need for new
transmission lines, thus deferring capital costs; \157\ (2) reducing
reliance on higher cost local reserves which will reduce costs and
local reserve requirements resulting from an increased ability to flow
power into load pockets; \158\ and (3) helping with the integration of
new clean energy resources.\159\ Finally, New England State Agencies
argue that, because parts of MISO as well as most of ERCOT are already
employing AARs, there can be no serious argument that AARs are too
difficult or costly to implement as was suggested by some transmission
owners.\160\
---------------------------------------------------------------------------

\154\ New England State Agencies Comments at 10; OMS Comments at
2; Ohio FEA Comments at 2.
\155\ New England State Agencies Comments at 10.
\156\ Id.
\157\ Id. at 10-11.
\158\ Id. at 12.
\159\ Id.
\160\ Id.
---------------------------------------------------------------------------

70. OMS states that it supports the NOPR proposal that AAR
requirements generally apply to all transmission lines and not just
those with historical congestion.\161\ OMS notes that the most
expensive energy prices typically occur after unforeseen outages or
weather events and are not the result of chronic, well understood
scenarios. However, OMS also states that it does not support requiring
AARs on those facilities where it is uneconomical or unreliable to do
so.\162\ OMS contends that the Commission should require RTOs/ISOs to
develop a process whereby transmission owners transparently work with
the RTOs/ISOs and market monitors to demonstrate why any exceptions
from the requirements are justified.\163\
---------------------------------------------------------------------------

\161\ OMS Comments at 8-10; see also OMS Reply Comments at 7,
10.
\162\ OMS Comments at 9.
\163\ Id.
---------------------------------------------------------------------------

71. Ohio FEA also supports the AAR NOPR proposal, stating that AARs
help ratepayers to realize the full benefits of their transmission
system investment. Ohio FEA explains that the four Ohio transmission
owners have already recognized the benefits of AARs, as a way of moving
away from static ratings.\164\ However, UDPU contends that the AAR NOPR
proposal should be limited to certain historically congested facilities
until the Commission has better information to assess the costs and
benefits of broad AAR implementation.\165\
---------------------------------------------------------------------------

\164\ Ohio FEA Comments at 2-4.
\165\ UDPU Comments at 1-3.
---------------------------------------------------------------------------

72. CEA encourages the Commission to further consider the costs
associated with the proposed changes, as a broader use of AARs may
over-estimate the benefit to cost ratio. CEA contends that the use of
AARs presents a significant cost challenge considering the number of
upgrades required.\166\
---------------------------------------------------------------------------

\166\ CEA Comments at 2.
---------------------------------------------------------------------------

73. Other technical experts are also supportive of more accurate
transmission line ratings.\167\ R Street Institute states that
understated transmission line ratings can result in increased
congestion costs and underutilization of generation in export-
constrained locales, which is disproportionately zero-emission
generation.\168\ R Street Institute contends that the Commission should
require DLRs by default and permit exceptions where justified by a
cost-benefit analysis.\169\
---------------------------------------------------------------------------

\167\ R Street Institute Comments at 1; WATT Comments at 1-2;
LineVision Comments at 1-2.
\168\ R Street Institute Comments at 1.
\169\ Id. at 3, 5-7.
---------------------------------------------------------------------------

74. WATT supports the direction the Commission is taking with the
NOPR's AAR requirements, but explains that additional factors that
affect transmission line ratings but are not incorporated into AARs are
very knowable.\170\ WATT contends that the Commission should require
the use of DLRs when certain criteria are met.\171\ LineVision supports
WATT's comments and states that DLR implementation will also result in
additional accuracy and situational awareness.\172\
---------------------------------------------------------------------------

\170\ WATT Comments at 1-2.
\171\ Id. at 10-12.
\172\ LineVision Comments at 1-2.
---------------------------------------------------------------------------

75. Renewable energy advocates are also generally supportive of the
AAR NOPR proposal, but urge the Commission to take further measures to
spur the implementation of DLRs.\173\ For example, ACORE commends the
Commission for issuing the NOPR, but recommends the Commission take
further steps to encourage DLR deployment by incenting its deployment
through transmission incentives and incorporating its assessment into
transmission planning processes.\174\ Similarly, Clean Energy Parties
contend that AARs are easy to implement and a modest improvement over
static line ratings.\175\ However, Clean Energy Parties argue that DLR
is superior to AAR, though Clean Energy Parties do not contend a
blanket DLR mandate is appropriate.\176\ ACPA/SEIA support accurate
transmission line ratings, and contend that the Commission should
require all transmission owners and transmission providers to study the
costs and benefits of implementing DLRs on persistently congested
transmission lines and require implementation where warranted.\177\
ACPA/SEIA and Clean Energy Parties both argue that the Commission
should alter its NOPR proposal to prioritize transmission lines that
are expected to be congested, persistently congested, or likely to be
congested in the future.\178\
---------------------------------------------------------------------------

\173\ ACORE Comments at 1; Clean Energy Parties Comments at 2,
4-6.
\174\ ACORE Comments at 1.
\175\ Clean Energy Parties Comments at 4-5.
\176\ Id. at 5, 8.
\177\ ACPA/SEIA Comments at 5-7.
\178\ Id. at 8-9; Clean Energy Parties Comments at 8, 10.
---------------------------------------------------------------------------

76. Generator owners and representatives are also generally
supportive of the proposed AAR requirements.\179\ EDFR argues that
getting the transmission line rating policy right is important due to
the urgency of addressing the climate crisis and President Biden's
carbon emissions reduction goals. EDFR contends that a lack of adequate
transfer capability can cripple clean energy generation.\180\ EDFR
further explains that, under many offtake agreements in RTO/ISO
markets, the developer is paid a fixed price for energy at a market hub
and if congestion limits the project's ability to deliver power to the
hub, then the developer bears the risk (known as basis risk). EDFR
argues that congestion is difficult to hedge in an effective way
because system topology and conditions change unexpectedly over time,
but states that more accurate transmission line ratings will decrease
basis risk and hedging difficulties.\181\ EDFR contends that
prioritization should not only consider historical congestion, but
should consider future congestion based on transmission planning,
interconnection, and transmission service studies for purposes of
prioritizing implementation.\182\
---------------------------------------------------------------------------

\179\ ENEL Comments at 1; EDFR Comments at 1-2; Vistra Comments
at 1-2; EPSA Comments at 2.
\180\ EDFR Comments at 2.
\181\ Id.
\182\ Id. at 4.

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[[Page 2257]]

77. EPSA contends that the Commission should encourage the use of
technological advances that improve transmission operators' ability to
track and optimize transmission line ratings and usage where feasible
and cost effective. EPSA states that PJM's adoption of AAR requirements
has shown clear benefits.\183\ Vistra is supportive of the Commission's
NOPR proposal, stating that it is imperative that the Commission act
now to make best use of existing infrastructure and that AARs and DLRs
are the best way to do that.\184\
---------------------------------------------------------------------------

\183\ EPSA Comments at 2.
\184\ Vistra Comments at 1-2.
---------------------------------------------------------------------------

78. Industrial Customer Organizations, TAPS, and Certain TDUs are
also broadly supportive of the AAR NOPR proposal.\185\ Certain TDUs
state that they support the proposed rule and encourage the Commission
to mandate improvements to the accuracy and transparency of
transmission line ratings because not all transmission owners have
shown a willingness to make these improvements voluntarily.\186\
Certain TDUs state that they support the use of AARs as a way to better
utilize the existing transmission system, noting that it will become
imperative that the existing transmission system is utilized to the
greatest extent possible as additional renewable resources come
online.\187\
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\185\ Industrial Customer Organizations Comments at 1-2; TAPS
Comments at 1-2; Certain TDU Comments at 1.
\186\ Certain TDUs Comments at 4.
\187\ Id. at 4-5.
---------------------------------------------------------------------------

79. Industrial Customer Organizations state that they generally
support the proposed rules, but assert that these rules should be
implemented as soon as practicable.\188\ Industrial Customer
Organizations argue that, if prioritization is needed, congested
circuits should be prioritized.\189\ Industrial Customer Organizations
explain that understated transmission line ratings increase congestion
and may lead to curtailments. Industrial Customer Organizations contend
that transmission owners that understate transmission line ratings may
create an illusory need for transmission upgrades. Further, Industrial
Customer Organizations contend that some transmission line ratings may
be deliberately understated because transmission owners may have a
profit incentive to calculate understated transmission line ratings in
order to benefit local generation.\190\
---------------------------------------------------------------------------

\188\ Industrial Customer Organizations Comments at 15-18.
\189\ Id. at 18-19.
\190\ Id. at 4.
---------------------------------------------------------------------------

80. TAPS states that it supports the proposed broad application of
AARs because it reduces the likelihood that AARs will be implemented in
a discriminatory manner.\191\ Similarly, Clean Energy Parties cite
Order No. 888,\192\ in which the Commission stated that ``[d]enials of
access [to transmission services] (whether they are blatant or subtle),
and the potential for future denials of access [to transmission
services], require the Commission to revisit and reform its regulation
of transmission in interstate commerce.'' \193\ According to Clean
Energy Parties, Order No. 888 supports the assertion that a lack of
consistency and transparency in transmission line ratings creates the
potential for future denials of access to transmission service, as
inaccurate transmission line ratings are used to provide discriminatory
transmission service to preferential customers.\194\
---------------------------------------------------------------------------

\191\ TAPS Comments at 7.
\192\ 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 21540 (May 10, 1996), FERC Stats. & Regs. ]
31,036 (1996) (cross-referenced at 75 FERC ] 61,080), order on
reh'g, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. &
Regs. ] 31,048 (cross-referenced at 78 FERC ] 61,220), order on
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g,
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub
nom. Transmission Access 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).
\193\ Id. at 31,652.
\194\ Clean Energy Parties Comments at 2-3.
---------------------------------------------------------------------------

81. Additionally, TAPS notes that the NOPR proposal would require
the use of AARs when evaluating requests for near-term point-to-point
transmission service and contends that the Commission should also apply
the requirements to requests for near-term secondary service requests
and near-term network resource designations. TAPS explains that
secondary service comes ahead of non-firm point-to-point transmission
service in curtailment priority, and the NOPR proposal flips this
priority.\195\
---------------------------------------------------------------------------

\195\ TAPS Comments at 20.
---------------------------------------------------------------------------

82. Prysmian discourages mandatory AAR implementation without
consideration of other variables and without a holistic evaluation of
all transmission line rating inputs to determine whether an overall
transmission line rating methodology is conservative or not. Prysmian
states that AARs can also lead to situations in which near-term
transfer capability is overstated.\196\
---------------------------------------------------------------------------

\196\ Prysmian Comments at 1.
---------------------------------------------------------------------------

c. Commission Determination
83. In this final rule, we adopt with certain modifications the
NOPR proposal to require transmission providers to apply the AAR
requirements set forth in pro forma OATT Attachment M to all
transmission lines, subject to the exceptions described below in
Section IV.D.3.\197\ As discussed above, the AAR requirements will
ensure that transmission line ratings are more accurate. In turn, more
accurate transmission line ratings will ensure wholesale rates more
accurately reflect the cost of the wholesale service being provided
(i.e., energy, capacity, ancillary services, or transmission service)
and, thus, that those wholesale rates are just and reasonable. We
further describe, below, the requirements and the modifications to the
NOPR proposal adopted herein.
---------------------------------------------------------------------------

\197\ NOPR, 173 FERC ] 61,165 at PP 92, 102.
---------------------------------------------------------------------------

84. First, we adopt the proposal to apply the AAR requirements as
set forth under ``Obligations of Transmission Provider'' in pro forma
OATT Attachment M to all transmission lines subject to the exceptions
described below in Section IV.D.3. We find that applying the AAR
requirements to all transmission lines will both ensure that wholesale
rates remain just and reasonable and strike an appropriate balance
between benefits and challenges of AAR implementation. For this reason,
we do not adopt the phased-in implementation schedule proposed in the
NOPR in which a transmission provider would initially implement AARs on
only historically congested lines.
85. As the Commission preliminarily found in the NOPR \198\ and as
the record demonstrates, despite differences across transmission
systems, simply accounting for ambient air temperatures in transmission
line ratings can reliably increase power transfer capability, resulting
in significant reliability, operational, and economic benefits.
Numerous commenters describe these benefits.\199\ For example, Potomac
Economics estimates that the benefits to AAR implementation in MISO
alone would have produced approximately $67 million and $49 million in
reduced congestion costs in 2019 and in 2020,

[[Page 2258]]

respectively.\200\ Exelon describes AARs as a best practice that cost-
effectively enhances transmission utilization, benefiting customers,
without adverse safety and reliability impacts.\201\ EEI acknowledges
that experience with AARs shows that their use can provide benefits on
certain subsets of transmission facilities.\202\ PJM states that, in
its experience, AARs increase operational flexibility, promote a more
efficient use of the transmission system, and result in more reliable
system dispatch and cost-effective market operations.\203\ New England
State Agencies argue that the Commission should take all reasonable
steps to protect ratepayers from excessive costs and that the use of
AARs, by permitting more power to flow than a system operated using
static or seasonal line ratings, can be an important tool in this
regard.\204\ Similarly, TAPS explains that reliance on static and
seasonal line ratings inflicts unnecessary costs on consumers and
contends that deployment of AARs using commercial temperature forecasts
can produce significant benefits to consumers at low cost.\205\ While
several entities note implementation costs as a barrier, these costs
are mostly initial investment costs in EMS improvements to accommodate
AARs, implementation of a ratings database, and review (and potentially
reset) of protective relays settings.\206\ Once these initial
investments are made, adding AARs to additional transmission lines
appears to have a minimal incremental cost.\207\
---------------------------------------------------------------------------

\198\ Id. P 99.
\199\ MISO Transmission Owners Comments at 8-9; PacifiCorp
Comments at 2; EEI Comments at 4-5; Entergy Comments at 1-2; BPA
Comments at 2-4; NYTOs Comments at 2-3, 5; Duke Energy Comments at
6-7; PG&E Comments at 1; LADWP Comments at 2-3; ITC Comments at 1-3;
Sunflower Comments at 2; Exelon Comments at 1-2; AEP Comments at 3;
Indicated PJM Transmission Owner Comments at 2; PJM Comments at 2;
PJM Comments at 2; New England State Agencies Comments at 7; TAPS
Comments at 5.
\200\ Potomac Economics Comments at 7-8.
\201\ Exelon Comments at 1.
\202\ EEI Comments at 5.
\203\ PJM Comments at 2.
\204\ New England State Agencies Comments at 5-6, 10-11.
\205\ TAPS Comments at 5.
\206\ Indicated PJM Transmission Owner Comments at 5-6; Exelon
Comments at 14; AEP AD19-15 Post Technical Conference Comments at 3.
\207\ Exelon Comments at 8; Indicated PJM Transmission Owner
Comments at 5-6; AEP Post-Technical Conference Comments at 2-3;
September 2019 Technical Conference, Day 1 Tr. at 180-181.
---------------------------------------------------------------------------

86. Second, in this final rule we adopt a requirement for
transmission providers to use AARs when evaluating the availability of
and requests for near-term transmission service (under sections 15, 17,
18, and 29 of the pro forma OATT).\208\ For purposes of this
requirement, we define ``requests for near-term transmission service''
to include not only requests for near-term point-to-point transmission
service, but also network resource designations and secondary service
where the start and end date of the designation/request is within the
next 10 days. Specifically, we require transmission providers to use
AARs as the relevant transmission line ratings when: (1) Evaluating
requests for near-term transmission service, defined as transmission
service ending within 10 days of the date of the request; (2)
responding to requests for information on the availability of potential
near-term transmission service (including requests for ATC or other
information related to potential service); and (3) posting ATC or other
information related to near-term transmission service to their OASIS
site. As discussed further below, in response to comments, we modify
this requirement from the NOPR proposal to include near-term network
and near-term secondary service, as well as the near-term point-to-
point transmission service proposed in the NOPR.\209\
---------------------------------------------------------------------------

\208\ NOPR, 173 FERC ] 61,165 at P 87.
\209\ Although requests for network transmission service are
typically long-term requests, meriting their evaluation using
seasonal line ratings, we note the Commission's finding in Order No.
890 that the minimum term for network transmission service should be
the same as the minimum time period used for firm point-to-point
transmission service (i.e., daily). See Preventing Undue
Discrimination and Preference in Transmission Service, Order No.
890, 72 FR 12266 (Mar. 15, 2007), 118 FERC ] 61,119, at P 1505,
order on reh'g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), 121
FERC ] 61,297 (2007), order on reh'g, Order No. 890-B, 123 FERC ]
61,299 (2008), order on reh'g, Order No. 890-C, 74 FR 12540 (Mar.
25, 2009), 126 FERC ] 61,228, order on clarification, Order No. 890-
D, 129 FERC ] 61,126 (2009). As such, any requests for transmission
service that fall within the near-term threshold defined herein
would qualify as near-term network transmission service.
---------------------------------------------------------------------------

87. Third, we adopt the Commission's proposal in the NOPR to
require that transmission providers use AARs as the relevant
transmission line rating when determining whether to curtail or
interrupt near-term point-to-point transmission service (under sections
13.6 and/or 14.7 of the pro forma OATT) \210\ 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.\211\
---------------------------------------------------------------------------

\210\ Additionally, we add references to interruption or
curtailment of near-term point-to-point transmission service
occurring pursuant to 13.6 of the pro forma OATT to Attachment M in
order to ensure consistent treatment of firm and non-firm point-to-
point transmission service.
\211\ NOPR, 173 FERC ] 61,165 at P 89.
---------------------------------------------------------------------------

88. Fourth, we adopt the proposal in the NOPR \212\ to require that
transmission providers use AARs as the relevant transmission line
ratings when determining whether to curtail network or secondary
service (under section 33 of the pro forma OATT) or redispatch network
or secondary 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.
---------------------------------------------------------------------------

\212\ Id. P 90.
---------------------------------------------------------------------------

89. Fifth, we adopt and modify the proposal in the NOPR to allow
RTOs/ISOs to comply with the final rule's AAR requirements by revising
their OATTs to require implementation of AARs within their security
constrained economic dispatch (SCED) and security constrained unit
commitment (SCUC) models (and in any relevant related models) in both
the day-ahead and real-time markets and reliability unit commitment
(RUC) processes,\213\ and any other intra-day RUC processes.\214\ As
the Commission recognized in the NOPR, 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. As discussed in Section IV.B.3.b, we
adopt the Commission's NOPR proposal to require that transmission
providers--including RTOs/ISOs--update their AARs at least hourly. As
discussed in Sections IV.B.3.b and IV.B.3.c, for any seams-based
transmission service offered by RTOs/ISOs, we adopt the Commission's
NOPR proposal to implement the near-term transmission service
requirements for inclusion of up-to-date hourly AAR calculations in
ATC.
---------------------------------------------------------------------------

\213\ After the day-ahead market process takes place, RTOs/ISOs
typically perform one or more residual unit commitment processes, or
what we refer to here as RUC, to address remaining resource gaps and
reliability issues or to manage uncertainty and the potential for
real-time operational issues. The exact names, definitions, and
market processes implementing what we refer here to as RUC processes
differ across RTOs/ISOs. For example, CAISO refers to its process as
residual unit commitment, SPP uses reliability unit commitment, and
MISO uses reliability assessment commitment. For simplicity,
however, this final rule uses the term RUC to refer to all of these
relevant processes in all of the RTO/ISO markets interchangeably.
\214\ NOPR, 173 FERC ] 61,165 at P 91. The statement ``(and in
any relevant related models)'' was intended to encompass all RUC
processes within the timeframe. In the interest of clarity, we
modify the NOPR proposal here to make that more explicit.
---------------------------------------------------------------------------

90. We do not adopt the NOPR proposal to establish a definition of
historically congested transmission lines. Accordingly, since we are
not adopting the NOPR's proposed definition of historically congested
transmission line, and instead apply the AAR requirements adopted
herein to all transmission lines, we do not address comments related to
the NOPR's proposed definition of historically congested transmission
line. To the

[[Page 2259]]

extent that commenters were arguing for a narrower application than
what we adopt in this final rule, below we explain the basis for
application of the AAR requirements to all transmission lines.
91. Finally, we alter the proposed compliance schedule.
Specifically, we require each transmission provider to submit a
compliance filing within 120 days of the effective date of this final
rule to incorporate into its OATT the changes adopted herein consistent
with pro forma OATT Attachment M and the changes to the Commission's
regulations set forth below. Additionally, we further require that all
requirements adopted herein be fully implemented no later than three
years from the compliance filing due date established by this final
rule.
92. In response to comments received in response to the NOPR, we
modify the NOPR proposal's defined term ``near-term point-to-point
transmission service'' to instead be ``near-term transmission
service.'' As a result, the AAR requirements will apply to requests for
near-term network transmission service, near-term secondary service,
and near-term point-to-point transmission service, provided that such
service meets the 10-day threshold defined in the near-term
transmission service definition. We agree with TAPS that it would be
inappropriate to apply the AAR requirements only to requests for near-
term point-to-point transmission service and not to requests for near-
term network and near-term secondary service because secondary service
comes before non-firm point-to-point transmission service in
curtailment priority.\215\ More generally, we find that a requirement
to use AARs on all types of near-term transmission service will better
ensure that transmission line ratings are accurate and that wholesale
rates are just and reasonable.
---------------------------------------------------------------------------

\215\ TAPS Comments at 18-20.
---------------------------------------------------------------------------

93. Although commenters broadly raise concerns with adopting
transmission line ratings that may fluctuate widely or contend that
implementing AARs on certain transmission lines may not yield benefits,
we do not find that these concerns and arguments overcome the need to
improve the accuracy of transmission line ratings through applying the
AAR requirements to all transmission lines. Specifically, we decline to
accommodate requests for more targeted AAR requirements in which
transmission providers would either have flexibility to identify
candidate transmission lines or the Commission would require AAR
implementation on only priority transmission lines, such as only on
historically congested lines.
94. We recognize commenters' concerns, such as those from NRECA/
LPPC, that the promised benefits, costs, and risks of implementing AARs
may not be evenly distributed nationwide.\216\ Nevertheless, we find
that with the broad AAR requirements adopted herein, the overall
benefits via savings to load and lower congestion charges to generators
will on balance outweigh the costs. Moreover, we acknowledge the
difficulty of knowing in advance all the locations and situations in
which the benefits of AAR implementation will outweigh the costs. Given
the difficulty in predicting unexpected congestion before it happens,
narrowing the scope of the AAR requirements would limit the ability of
these reforms to ensure just and reasonable wholesale rates. In
particular, we find that the AAR requirements adopted in this final
rule are beneficial in mitigating the impact of transient congestion,
i.e., temporary or short-term congestion that does not occur on a
regular basis, such as congestion caused by unexpected equipment
outages or other unusual conditions. Furthermore, given the increasing
occurrence of extreme weather events, we expect that assessing the
benefits of broader AAR implementation based on historical congestion
likely understates the potential savings associated with implementation
of the AAR requirements adopted in this final rule. By contrast, the
record demonstrates that AAR implementation costs are predominantly
one-time investment costs in EMS improvements to accommodate AARs,
implementation of a ratings database, and review (and potentially
reset) of protective relays settings.\217\ Once these costs have been
incurred, the incremental cost of applying AARs to additional
transmission facilities is minimal.\218\
---------------------------------------------------------------------------

\216\ NRECA/LPPC Comments at 15.
\217\ Exelon Comments at 8-9.
\218\ Id. at 8; Indicated PJM Transmission Owner Comments at 5-
6; AEP Post-Technical Conference Comments at 2-3; September 2019
Technical Conference, Day 1 Tr. at 180-181.
---------------------------------------------------------------------------

95. Attempts to anticipate the situations in which AARs will not be
cost beneficial (e.g., attempts to forecast locations and situations in
which there will be future congestion and deploy AARs in only those
anticipated situations) will necessarily be imperfect and complex,
especially during infrequent but consequential events. Additionally,
since many emergencies may come and go before new AARs can be developed
and implemented for newly congested transmission lines, a more targeted
AAR requirement advocated by some commenters may not accurately
represent system transfer capability in such critical situations. As
the Commission recognized in the NOPR, congestion is difficult to
predict, particularly during emergency conditions.\219\ The 2019 FERC
and NERC Staff Report on the January 2018 South Central cold weather
event illustrates this point.\220\ As shown by that event, during times
of emergency or system stress, flows may change considerably from
normal operations and the increased transfer capability provided
through AARs may prove valuable even on transmission lines that are not
typically congested.\221\ In addition, in the February 2021 cold
weather event, MISO experienced unprecedented east-to-west flows
throughout the footprint and accrued $773 million in congestion charges
in just a few days.\222\ We note that with broad AAR implementation,
given Potomac Economics' finding that AAR implementation consistently
results in savings of approximately 5% to 8% of total congestion,\223\
congestion cost savings from this single event might have exceeded the
total costs of AAR implementation in the region. Moreover, many argue
that the changing generation mix makes congestion prediction even more
difficult.\224\ Additionally, AAR implementation itself will have
secondary consequences for congestion patterns, as changes to
transmission line ratings may change generation dispatch patterns and,
by extension, congestion patterns. Such secondary congestion
consequences may only be able to be promptly addressed by a broad AAR
requirement that applies to all transmission lines.
---------------------------------------------------------------------------

\219\ NOPR, 173 FERC ] 61,165 at P 93.
\220\ 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), <a href="https://www.ferc.gov/sites/default/files/2020-05/07-18-19-ferc-nerc-report_0.pdf">https://www.ferc.gov/sites/default/files/2020-05/07-18-19-ferc-nerc-report_0.pdf</a>.
\221\ NOPR, 173 FERC ] 61,165 at P 93.
\222\ OMS Comments at 10; OMS Reply Comments at 7; see FERC,
NERC and Regional Entity Staff Report, The February 2021 Cold
Weather Outages in Texas and the South Central United States (Nov.
16, 2021), <a href="https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and">https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and</a>.
\223\ Potomac Economics Comments at 8; Potomac Economics Post-
Technical Conference Comments at 5-6.
\224\ ACPA/SEIA Comments at 8, 11; EPSA Comments at 4; New
England State Agencies Comments at 6.
---------------------------------------------------------------------------

96. Beyond congestion costs, during times of stressed system
conditions, operators in RTOs/ISOs might have to

[[Page 2260]]

spend limited time requesting AARs from transmission owners on an ad
hoc basis.\225\ AAR implementation on all transmission lines will help
ensure transmission providers have sufficient transfer capability and
flexibility to manage emergency conditions. Delayed access to AARs
could force transmission operators to spend precious time reaching out
to transmission owners for AARs, rather than using such time to manage
emergency conditions. Instead, AAR implementation on all transmission
lines will alleviate the need for transmission providers to spend time
requesting AARs when there may be no time to waste.
---------------------------------------------------------------------------

\225\ OMS Reply Comments at 7; see also FERC and NERC Staff
Report at 56-59; ISO-NE, Cold Weather Operations: December 24,
2017--January 8, 2018, at 41 (Jan. 16, 2019), <a href="https://www.iso-ne.com/static-assets/documents/2018/01/20180112_cold_weather_ops_npc.pdf">https://www.iso-ne.com/static-assets/documents/2018/01/20180112_cold_weather_ops_npc.pdf</a>.
---------------------------------------------------------------------------

97. Further, arguments that the benefits of broad AAR
implementation will not outweigh the costs are inconsistent with the
ERCOT and PJM transmission owners' actual AAR implementation
experience. AEP has been implementing AARs for decades and has realized
both reliability and financial benefits for its customers.\226\ As
Indicated PJM Transmission Owners state, transmission owners in PJM
provide AARs for each of their facility ratings.\227\ PJM further
states that the use of AARs is commonplace among the overwhelming
majority of transmission owners in PJM.\228\ As New England State
Agencies observe, the broad experience implementing AARs does not
support the argument that AARs are too difficult or costly to
implement.\229\
---------------------------------------------------------------------------

\226\ AEP Comments at 3.
\227\ Indicated PJM Transmission Owners Comments at 6-7.
\228\ PJM Comments at 2.
\229\ New England State Agencies Comments at 11-12.
---------------------------------------------------------------------------

98. In response to MISO Transmission Owners' argument that the
Commission should not rely on Potomac Economics' estimates of the
benefits of AARs, our rationale for the AAR requirements adopted in
this final rule is not solely based on Potomac Economics' analysis.
Rather, our rationale is based on the finding that AARs on all
transmission lines will ensure that wholesale rates more accurately
reflect the cost of the wholesale service being provided, and, thus
that those wholesale rates are just and reasonable. This finding is
further informed by the widespread benefits experienced by commenters
implementing AARs broadly in PJM and ERCOT, the expectation that the
benefits of AAR implementation will be greatest on transmission lines
that are frequently congested, along with the understanding of the
difficulty of predicting congestion and the low incremental cost to
implement AARs. However, in response to MISO Transmission Owners'
critique that Potomac Economics' analysis erroneously assumes that all
transmission lines in MISO are ambient adjustable, we note that, in
response to MISO Transmission Owners' comments, Potomac Economics
states that its analysis does not assume that all transmission lines
are able to be rated using AARs and instead removes from the analysis
all transmission lines that currently have summer ratings equal to
winter ratings.\230\ With respect to MISO Transmission Owners' argument
that Potomac Economics' analysis erroneously assumes that all
transmission lines in MISO are currently using worst-case ambient air
temperature assumptions, we note that Potomac Economics does not
uniformly assume worst-case 104 degrees Fahrenheit as the basis for
adjusting AARs, but instead infers unique transmission owner base
assumptions using maximum historical temperatures in each transmission
owner service territory.\231\ Finally, we disagree with MISO
Transmission Owners' assertion that the benefits in Potomac Economics'
analysis are inflated because of certain transmission outages or
upgrades assumptions. As Potomac Economics explains, there are many
generalized and localized factors that might increase or decrease
congestion in an individual year and, given the highly complex nature
of the electric system, incorporating all of these factors is not
possible.\232\ Despite certain generalizations, which we believe are
likely to render Potomac Economics' analysis conservative, Potomac
Economics has consistently found that AARs and emergency ratings will
reduce congestion by 10% to 15% annually.\233\
---------------------------------------------------------------------------

\230\ Potomac Economics Reply Comments at 3-5.
\231\ Id. at 2-3.
\232\ Id. at 5-6.
\233\ Id. at 5.
---------------------------------------------------------------------------

99. We disagree with arguments from Southern Company, EEI, and
other commenters that reliability issues may arise because AARs may
create difficulties in identifying the most limiting element and
similar difficulties and costs associated with complying with
Reliability Standard PRC-023-4's transmission relay loadability
requirements that depend on maximum published ratings. Reliability
Standard PRC-023-4 requires setting transmission line relays at values
at or above 115 to 170% of various maximum values for current or power
carrying capability, e.g., 115% of the highest seasonal 15-minute
Facility Rating of a circuit or 150% of the highest seasonal four-hour
Facility Rating of a circuit. We do not agree that this final rule will
result in PRC-023-4 related relay setting changes to ``thousands''
\234\ of relays, since the relay settings are currently calculated
based on practical limitations which in the majority of cases should
not exceed AAR values. In addition, PJM has long implemented AARs and,
rather than describing reliability challenges, contends that AAR
implementation creates reliability benefits.\235\ For example, PJM
states that the adoption of AARs increases operational flexibility,
promotes a more efficient use of the transmission system, and results
in more reliable system dispatch and cost-effective market
operations.\236\ Transmission owners in PJM have implemented AARs
despite the initial cost incurred to update relay settings. Likewise,
AEP submits that it has implemented AARs for decades and that AAR
implementation presents reliability benefits.\237\
---------------------------------------------------------------------------

\234\ EEI Comments at 5-6.
\235\ PJM Comments at 7.
\236\ Id. at 2.
\237\ AEP Comments at 3.
---------------------------------------------------------------------------

100. In response to concerns about the additional challenges
associated with incorporating AARs into ATC, as raised by Duke Energy,
EEI, and several non-RTO/ISO transmission owners with service
territories in the Western Interconnection, we note that such TTC
calculation practices, and in turn ATC practices, particularly those
which only update TTC values annually,\238\ will need to be updated in
order to comply with this final rule's AAR requirements. In fact, such
practices may already be out of compliance with the Commission's
existing ATC calculation rules. For example, while Order No. 890
provides transmission providers with significant flexibility in what
approach they take to determine ATC in their transmission paths, it
also requires that ATC values (regardless of the approach used to
calculate them) be ``updated and benchmarked to actual events.'' \239\
Furthermore, in May 2021, the Commission issued Order No. 676-J,\240\
in which the Commission (among other things) codified the
``fundamentals of Order No. 890 requirements for calculating ATC'' in
the Commission's regulations.\241\ Specifically, Order No.

[[Page 2261]]

676-J revised section 37.6(b)(2)(i) of the Commission's regulations to
codify that ATC calculations must be ``conducted in a manner that is .
. . consistent with anticipated system conditions and outages for the
relevant timeframe.'' \242\ We find that transmission line ratings
represent one such ``system condition'' with which ATC calculations
must be consistent.
---------------------------------------------------------------------------

\238\ EEI Comments at 11.
\239\ Order No. 890, 118 FERC ] 61,119 at P 290.
\240\ Standards for Business Practices and Communication
Protocols for Public Utilities, Order No. 676-J, 86 FR 29491 (June
2, 2021), 175 FERC ] 61,139 (2021).
\241\ Id. P 38.
\242\ Id.
---------------------------------------------------------------------------

101. In response to specific concerns from PacifiCorp and BPA about
nomogram constraints, we note that nomogram constraints are typically
used to represent transfer capability on facilities with stability or
voltage limitations. The AAR requirements adopted in pro forma OATT
Attachment M exempt transmission lines whose ratings are not affected
by ambient air temperature.
102. In response to comments from NERC requesting further
consideration of AAR implementation on long transmission lines, and
from LADWP, and other, primarily western transmission owners, which
describe AAR implementation challenges due to the diversity in terrain
and microclimates that western transmission lines traverse, we agree
that longer transmission lines can and will experience differing
weather conditions across the length of those transmission lines. To
maintain reliable system operations, we expect transmission providers
to implement the transmission line rating calculated based on the most
limiting element under the prevailing weather conditions (actual or
anticipated) at the relevant point on the transmission line. In the
case of transmission conductors, which might be exposed to different
weather conditions along the length of the transmission line,
transmission providers must rate such elements using the most limiting
weather conditions, in accordance with good utility practice. However,
this requirement does not require the installation of field devices or
sensors, as some transmission owners suggest.\243\ Rather, as proposed
in the NOPR, the AAR requirements can be met through the use of a
weather data service.\244\
---------------------------------------------------------------------------

\243\ WAPA Comments at 7-9; PG&E Comments at 9-10.
\244\ NOPR, 173 FERC ] 61,165 at P 95.
---------------------------------------------------------------------------

103. Similarly, in response to comments from BPA that if BPA uses
AARs as proposed, it would need to make its current liberal wind
assumptions (and therefore, the resultant transmission line ratings)
more conservative to mitigate the risk of operating near the conductor
limit,\245\ we reiterate that the AAR requirements will ensure more
accurate transmission line ratings, not necessarily higher transmission
line ratings. We further clarify that there is no requirement to change
wind speed assumptions. Utilities have operated reliably for decades
with AARs.\246\ However, if any transmission owner finds it necessary
to change its wind speed assumptions consistent with good utility
practice, we clarify that nothing in this rulemaking prevents it from
doing so.
---------------------------------------------------------------------------

\245\ BPA Comments at 4.
\246\ AEP Comments at 3.
---------------------------------------------------------------------------

2. Specific AAR Implementation Requirements
a. Use of AARs 10-Days Forward in Transmission Service and Operations
i. NOPR Proposal
104. In the NOPR, within the context of the AAR requirements
described and adopted above in Section IV.B.1, the Commission proposed
to apply the AAR requirements to transmission service that starts/ends
within 10 days, to the curtailment or interruption of point-to-point
transmission service anticipated to occur (start and end) within the
next 10 days, and to the curtailment of network transmission service or
secondary service or redispatch network transmission service or
secondary transmission service anticipated to occur (start and end)
within 10 days (hereinafter referred to as the ``10-day threshold'').
105. The Commission justified the proposed 10-day threshold as a
reasonable cut-off beyond which forecasts may not be accurate enough
for AARs to provide significant value, and by stating that the
Commission believed that such a limit would reasonably accommodate
requests for weekly point-to-point transmission service. The Commission
further noted that ambient air temperature forecasts for intervals
beyond the proposed 10-day threshold tend to converge to the longer-
term ambient air temperature forecasts used in seasonal line
ratings.\247\ Finally, the Commission noted that its proposal allowed
transmission providers to determine (consistent with good utility
practice) the needed degree of certainty when constructing their
forecasts of ambient air temperature.\248\
---------------------------------------------------------------------------

\247\ NOPR, 173 FERC ] 61,165 at PP 87-88.
\248\ Id. P 102.
---------------------------------------------------------------------------

106. With respect to RTOs/ISOs, the Commission proposed to require
AARs as the relevant transmission line rating for any point-to-point
transmission service offered (e.g., at their borders). However, the
Commission also recognized that RTOs/ISOs have Commission-approved
variations from the pro forma OATT to manage internal congestion and
initiate curtailments and/or redispatch of transmission service within
their footprints through mechanisms such as SCED and SCUC. To
accommodate these variations, the Commission proposed that RTOs/ISOs
comply with the proposed requirements by revising their OATTs 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 RUC processes. For real-time markets, the
Commission proposed that RTOs/ISOs update their AARs at least hourly.
For any point-to-point transmission service offered by RTOs/ISOs (e.g.,
at their borders), the Commission proposed that the AAR requirements
discussed above for point-to-point transmission service would apply. As
justification, the Commission explained that day-ahead markets already
rely upon forecasts of weather to inform next-day load and intermittent
generation availability. The Commission preliminarily agreed with PJM
that temperatures can be forecast with a reasonable degree of certainty
in day-ahead markets.\249\ The Commission further stated that, within
its NOPR proposal, transmission providers could (consistent with good
utility practice) determine the needed degree of certainty when
constructing their forecasts of ambient air temperature, and 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.\250\
---------------------------------------------------------------------------

\249\ PJM Post-Technical Conference Comments at 3.
\250\ NOPR, 173 FERC ] 61,165 at P 102.
---------------------------------------------------------------------------

ii. Comments
107. Many commenters generally support the Commission's proposed
AAR requirements without specifically discussing the 10-day
threshold.\251\ Industrial Customer Organizations specifically agree
with the Commission that implementing AARs in near-term transmission
service will more accurately reflect the cost of delivering

[[Page 2262]]

energy to load.\252\ CEA states that using AARs to calculate
transmission line ratings for service requests up to 10 days has proven
to be reliable and to provide benefits to effective and reliable
transmission operations.\253\ EDFR contends that the distinction
between AARs and seasonal line ratings depending on the applicable time
frame appears sensible.\254\ ACPA/SEIA state that they support the
Commission's proposed requirements for near-term point-to-point
transmission service and curtailments expected to occur within the next
10 days.\255\ The Ohio FEA does not take a firm position, but states
that implementing AARs for the next 10 days is reasonable.\256\ OMS
states that the weather data required to implement AARs is already
widely available through public sources and used for load and resource
forecasting.\257\
---------------------------------------------------------------------------

\251\ EPSA Comments at 2; Clean Energy Parties Comments at 2-3;
R Street Institute Comments at 2-3; TAPS Comments at 1-3; ACORE
Comments at 3; OMS Comments at 2; New England State Agencies
Comments at 10; Vistra Comments at 2-3.
\252\ Industrial Customer Organizations Comments at 4-6.
\253\ CEA Comments at 2.
\254\ EDFR Comments at 7.
\255\ ACPA/SEIA Comments at 16-17.
\256\ Ohio FEA Comments at 5.
\257\ OMS Comments at 11.
---------------------------------------------------------------------------

108. While not supporting or opposing the proposed 10-day
threshold, EPRI recommends an independent assessment that documents the
accuracy and risk associated with weather forecast data, explaining
that not all weather forecast data will be appropriate for transmission
line ratings and that some limiting spans run through microclimates.
EPRI further explains that inaccurate forecast risks can be mitigated
by identifying and implementing corrective factors to allow forecasts
to be used consistent with good utility practice. EPRI suggests
utility-specific rating studies would be required to assess and
mitigate forecast risk,\258\ to update and revise weather condition
assumptions, and possibly to adjust transmission reliability
margins.\259\ EPRI contends that further studies are needed to
determine a technical basis for updated wind speed assumptions and that
such studies may take between one and two years.\260\ Similarly, NERC
asserts that the Commission should consider how variations in the
temperature and load forecast should be addressed, what temperature
sets should be used when considering requests to grant firm
transmission service, and whether additional AAR calculation
information should be incorporated into transmission line rating
methodologies.\261\
---------------------------------------------------------------------------

\258\ EPRI Comments at 10-11.
\259\ Id. at 12. Transmission reliability margin, or TRM, means
the amount of TTC necessary to provide reasonable assurance that the
interconnected transmission network will be secure, or such
definition as contained in Commission-approved Reliability
Standards. 18 CFR 37.6(b)(1)(viii) (2021)..
\260\ EPRI Comments at 12.
\261\ NERC Comments at 7.
---------------------------------------------------------------------------

109. Other commenters also discuss risk management for forecasted
ambient air temperatures. For example, Entergy states that forecasted
ambient air temperatures should include appropriate safety margins to
account for historical forecast uncertainty.\262\ Similarly, the SPP
MMU states that, ideally, congestion costs should, to some extent,
represent the risk assumed to serve the load.\263\ Finally, the CAISO
DMM argues that AAR requirements should allow leeway for RTOs/ISOs to
adjust modeled transmission limits for reliability reasons, as CAISO
does in the case of flowgates and nomograms whose modeled flows
frequently differ from actual flows.\264\ The CAISO DMM asserts that
lower or more conservative transmission limits might be needed for
temporally distant intervals to ensure commitments made in an advisory
interval horizon are feasible in the binding market interval and at the
time of power flow. The CAISO DMM further asserts that lower day-ahead
transmission limits could promote the feasibility of day-ahead
commitments in real time.\265\
---------------------------------------------------------------------------

\262\ Entergy Comments at 11.
\263\ SPP MMU Comments at 1.
\264\ CAISO DMM Comments at 3, 4-5, 7.
\265\ Id. at 3.
---------------------------------------------------------------------------

110. Many RTOs/ISOs, however, oppose or urge caution on the
proposed 10-day threshold, with many advocating instead for a 48-hour
threshold.\266\ PJM does not support use of AARs in ATC calculations
beyond 48 hours, arguing that it would require significant system
changes and increase the compliance burden.\267\ PJM proposes AARs for
48 hours, and a more conservative approach for hours 48-240 to avoid
potential volatility and over-selling.\268\ Both NYISO and ISO-NE argue
that the transmission service offered in their respective regions
differs from that contemplated by the pro forma OATT, and request
flexibility in implementing any transmission line rating
requirements.\269\
---------------------------------------------------------------------------

\266\ PJM Comments at 7-8; ISO-NE Comments at 10; MISO Comments
at 10, 16-17; NYISO Comments at 13-14.
\267\ PJM Comments at 7-8.
\268\ Id.
\269\ ISO-NE Comments at 10; NYISO Comments at 9.
---------------------------------------------------------------------------

111. NYISO does not support extending the AAR requirements or DLRs
into the day-ahead market, or for use up to 10 days into the future,
contending that such a requirement could result in costly and
unnecessary uplift payments, which could lead to significant cost
increases to customers, and could present reliability concerns if
transmission line ratings decline in real time from the day-ahead
schedule, forcing NYISO to rapidly reduce the schedules of certain
generators while quickly ramping up other generators.\270\ NYISO also
states that it would consider designating a portion of transfer
capability to be able to respond to the operational and cost volatility
that would come with DLR use, although such a process would limit
overall efficiency and increase production costs.\271\
---------------------------------------------------------------------------

\270\ NYISO Comments at 13-14.
\271\ Id.
---------------------------------------------------------------------------

112. Without taking a position on the proposed 10-day threshold,
CAISO explains that the NOPR proposal would significantly increase the
complexity of its day-ahead market and introduce possible variances
between real-time and day-ahead schedules.\272\ Also without taking a
position on the proposed 10-day threshold, SPP states that, to use AARs
to evaluate transmission service requests that end within 10 days or as
the basis for curtailment, SPP would have to make several technical and
process upgrades and align its operating horizon and planning
horizon.\273\
---------------------------------------------------------------------------

\272\ CAISO Comments at 9-11.
\273\ SPP Comments at 5-7, 9.
---------------------------------------------------------------------------

113. MISO argues that the vast majority of the benefit from AARs is
in addressing real-time congestion, and that implementing AARs in
MISO's day-ahead market would be difficult to do in less than three
years, while offering comparatively little benefit. MISO further claims
that requiring hourly AARs 10 days in advance will provide little to no
benefit because the accuracy of temperature forecasts diminishes
considerably beyond 48 hours, and precipitously by the five to seven
day mark.\274\ MISO urges the Commission to limit AAR implementation to
48 hours from the start of the operating day.\275\ Similarly, Potomac
Economics recommends that the Commission require that AARs be used in
the day-ahead and real-time markets, stating that this will allow the
RTOs/ISOs to focus their resources on improving the transmission line
ratings that will generate almost all of the savings.
---------------------------------------------------------------------------

\274\ MISO Comments at 18.
\275\ Id. at 19.
---------------------------------------------------------------------------

114. Similar to RTOs/ISOs, transmission owners also urge caution
on, or oppose, the proposed 10-day threshold.\276\ Those transmission

[[Page 2263]]

owners generally argue that there is too much risk forecasting 10 days
forward and generally support more limited forecasting of either 24
\277\ or 48 hours.\278\ For example, Indicated PJM Transmission Owners
contend that forecasting AARs beyond two or three days in advance
provides little benefit because weather conditions beyond that are too
difficult to predict.\279\ Dominion similarly argues there is no
benefit to extending the AAR requirements beyond three to five days
because forecasts beyond five days tend to reflect seasonal
averages.\280\ Entergy contends that forecasts should be limited to
three days and include appropriate safety margins for historical
forecast uncertainty and geographic variability.\281\
---------------------------------------------------------------------------

\276\ BPA Comments at 7; Indicated PJM Transmission Owners
Comments at 2; Dominion Comments at 8-9; Duke Energy Comments at 8-
9; SDG&E Comments at 2-3; Southern Company Comments at 5-6; MISO
Transmission Owners Comments at 15-16; EEI Comments at 10-11; APS
Comments at 8; NYTOs Comments at 5-6; AEP Comments at 6-7; NRECA/
LPPC Comments at 19-20; SDG&E Comments at 2-3; LADWP Comments at 7;
ITC Comments at 7-9.
\277\ BPA Comments at 7; Duke Energy Comments at 8-9; Southern
Company Comments at 5-6; MISO Transmission Owners Comments at 15-16;
EEI Comments at 10-11; APS Comments at 8; NYTOs Comments at 5-6.
\278\ AEP Comments at 6-7; NRECA/LPPC Comments at 19-20; SDG&E
Comments at 2-3; LADWP Comments at 7.
\279\ Indicated PJM Transmission Owners Comments at 2.
\280\ Dominion Comments at 9.
\281\ Entergy Comments at 11.
---------------------------------------------------------------------------

115. Several commenters argue that requiring AARs 10 days in
advance presents the potential problem of selling transmission service
based on a given ambient air temperature forecast only for the
temperature to be higher in real time, causing curtailments or safety
and reliability risks.\282\ BPA argues that it could result in an
inefficient use of the transmission system because transmission could
be sold, curtailed, and then available again, all prior to the
transmission service window.\283\ NYTOs note that, because there is
generally less flexibility in real time, if operators do not have
sufficient resources to restore flow to a lower limit within the
required time, they may need to shed load or damage equipment.\284\
---------------------------------------------------------------------------

\282\ MISO Transmission Owners Comments at 15-16; Duke Energy
Comments at 8-9; Southern Company Comments at 5-6; NYTOs Comments at
5.
\283\ BPA Comments at 7.
\284\ NYTOs Comments at 5-6.
---------------------------------------------------------------------------

116. Arguing that the Commission should not extend the AAR
requirements beyond the operating day, MISO Transmission Owners state
that using AARs any further forward than in real time introduces
uncertainty and error. MISO Transmission Owners acknowledge that these
risks exist today, but argue that AARs introduce further complexity and
explain that lowering transmission line ratings in real time would
compound the problems.\285\ Similarly, Duke Energy presents an example
of transmission sold based on a 60 degree Fahrenheit temperature
forecast four days forward and, on the operating day having the
transmission system oversubscribed, with greater pressure on operators
to curtail transmission schedules to avoid safety and reliability
risks, because the actual temperature was 75 degrees Fahrenheit.\286\
Southern Company states that AARs have the potential to create
reliability concerns if transmission service is oversold due to
inaccurate weather forecasts, especially for transmission service that
is scheduled 10 days ahead.\287\ Southern Company also states that
reliability issues may arise because AARs may create difficulties in
identifying the most limiting element, which may change as the
temperature changes, for the purpose of complying with Reliability
Standard FAC-008-5, and similar difficulties in complying with
Reliability Standard PRC-023 relay loadability requirements that depend
on maximum published ratings.\288\
---------------------------------------------------------------------------

\285\ MISO Transmission Owners Comments at 15-16.
\286\ Duke Energy Comments at 8-9.
\287\ Southern Company Comments at 5-6.
\288\ Id. at 6.
---------------------------------------------------------------------------

117. NRECA/LPPC contend that such a requirement is unduly
burdensome because most of the benefits of using AARs are for real-time
and day-ahead transactions. NRECA/LPPC add that hourly weather
forecasts and the resulting hourly transmission line ratings are
unlikely to be accurate for more than a very few days.\289\ IID
explains that the Commission should provide flexibility in the forward
AAR application period, noting that weather patterns may not be stable
everywhere. IID contends that the Commission should consider
implementation challenges associated with looking 10 days ahead,
calculating what could be several hundred transmission line ratings per
year.\290\
---------------------------------------------------------------------------

\289\ NRECA/LPPC Comments at 19-20.
\290\ IID Comments at 4-6.
---------------------------------------------------------------------------

118. EEI and APS contend that AARs should only be implemented in
real-time operations.\291\ EEI contends that such AAR values should not
extend to the day-ahead or intra-day unit commitment values and that
hourly ATC for up to 10 days would introduce uncertainty and ATC
fluctuations that result in curtailment of sold service and resale of
previously curtailed service. EEI further explains that the Commission
has previously recognized the reliability harm associated with
overestimated ATC and explains that the harm may result from using
hourly AARs for transmission service available for up to 10 days. EEI
also states that the NOPR proposal for hourly ATC for every hour in the
next 10 days is complex, with a burden that may outweigh the benefits
since the NOPR proposal fundamentally requires a TTC determination.
However, EEI states that TTC is path dependent and is based on many
transmission line ratings, contingencies, and power flow assumptions.
Because of this complexity, some transmission owners only determine TTC
annually or less frequently and, for these transmission owners, the
NOPR proposal for transmission providers to recalculate TTC every hour,
and perform 240 calculations every hour, is infeasible.\292\ NERC
contends that the Commission should consider how entities should
reconcile AARs used for planning and operations functions. NERC also
argues that there is potential confusion regarding transmission line
ratings used in transmission operator operations and planning system
operating limits and interconnection reliability operating limits, but
believes the confusion can be avoided through the timing of Commission
action to retire the NERC Modeling, Data, and Analysis (MOD) A
Reliability Standards.\293\
---------------------------------------------------------------------------

\291\ APS Comments at 8; EEI Comments at 10-12.
\292\ EEI Comments at 10-12.
\293\ NERC Comments at 7-8.
---------------------------------------------------------------------------

119. NYTOs explain that requiring AARs for up to 10 days forward,
even for a subset of the transmission system, would be a significant
change requiring major software buildout and corresponding market
design changes, which would create a significant burden on NYISO and
its associated utilities. NYTOs assert that this burden would be
further complicated by the fact that vendor availability for such a
buildout is unknown.\294\ NYTOs also explain that implementing AARs 10
days forward has the potential to create reliability concerns through
disconnects between forecasted and real-time conditions \295\ and that
extending the AAR requirements to the day-ahead market would make
security analysis more difficult.\296\ LADWP contends that the
Commission should align any final rule requirements with NERC
Reliability Standards and asserts that the proposed 10-day threshold
would conflict with

[[Page 2264]]

the requirements specified in Reliability Standard MOD-001-1a that ATC
be calculated hourly for the next 48 hours.\297\ Moreover, recognizing
the variability in weather, LADWP asks that system operators be
afforded the flexibility to recall transfer capability awarded during
moderate conditions at least 24 hours in advance.\298\
---------------------------------------------------------------------------

\294\ NYTOs Comments at 5-6.
\295\ Id.
\296\ Id. at 7.
\297\ LADWP Comments at 7.
\298\ Id. at 6.
---------------------------------------------------------------------------

iii. Commission Determination
120. We adopt the NOPR proposal to require transmission providers
to use AARs when evaluating the availability of and requests for near-
term transmission service (under sections 15, 17, 18, and 29 of the pro
forma OATT) \299\ as set forth under ``Obligations of Transmission
Provider'' in the pro forma OATT Attachment M adopted in this final
rule. We further adopt the Commission's proposal in the NOPR to require
transmission providers to use AARs as the relevant transmission line
rating when determining whether to curtail or interrupt point-to-point
transmission service (under sections 13.6 and/or 14.7 of the pro forma
OATT) 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. Additionally, we adopt
the Commission's proposal in the NOPR to require transmission providers
to use AARs as the relevant transmission line rating when determining
whether to curtail network or secondary service (under section 33 of
the pro forma OATT) or redispatch network or secondary 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 (i.e., the 10-day threshold). Finally,
consistent with the NOPR, we clarify that AARs must be calculated using
the temperature at which there is sufficient confidence that the actual
temperature will not be greater than that temperature (i.e., expected
temperature plus an appropriate forecast margin).\300\
---------------------------------------------------------------------------

\299\ See supra P 85.
\300\ See NOPR, 173 FERC ] 61,165 at PP 97, 102.
---------------------------------------------------------------------------

121. We believe that the 10-day threshold is justified by: (1) The
additional benefits gained by adopting a threshold that permits weekly
point-to-point transmission service requests to be evaluated using
AARs; (2) the additional benefits gained by the use of daytime/
nighttime ratings (discussed below in Section IV.B.2.c) within the 10-
day threshold; (3) the adequate accuracy of ambient air temperature
forecasts combined with the ability to implement appropriate forecast
margins to alleviate operational concerns associated with persistently
decreasing real-time transmission line ratings; and (4) the low
relative cost difference between a shorter forward threshold and the
proposed 10-day threshold. As the Commission stated in the NOPR, AAR
requirements up to 10 days forward will permit weekly point-to-point
transmission service to be evaluated using AARs. Because weekly point-
to-point transmission service is one of several types of transmission
products provided under the Commission's pro forma OATT, by adopting
the 10-day threshold for AAR implementation rather than a shorter
forward duration, weekly point-to-point transmission customers will
receive the benefits of AAR implementation rather than only
transmission customers taking shorter duration transmission service,
thereby not just increasing the expected benefits from the
implementation of AARs by improving the accuracy of transmission line
ratings for a wider range of transmission services but also for a
potentially wider range of transmission customers.
122. We also require AARs to include separate daytime and nighttime
ratings. This daytime/nighttime ratings requirement, combined with the
addition of weekly point-to-point transmission service, will produce
further benefits in forward nighttime hours that would not see such
benefits if the AAR requirements were imposed over a timeframe shorter
than 10 days forward. These benefits of increased accuracy that result
from applying daytime/nighttime ratings to weekly point-to-point
transmission service and to shorter duration transmission service up to
10 days forward are significant on their own, even in the unlikely
event that the use of ambient air temperature forecasts 10 days forward
results in no hours where daytime AARs are greater than seasonal line
ratings. In other words, if we were to adopt a shorter threshold for
the AAR requirements than 10 days forward, the significant benefits
derived from the more accurate transmission line ratings during the
additional nighttime hours included in the 10-day threshold would be
lost. We further note that weather forecast quality is not static, but
rather is steadily improving such that the benefits of the 10-day
threshold requirement are likely to increase over time.\301\
---------------------------------------------------------------------------

\301\ See, e.g., NOAA, Annual WPC Mean Absolute Errors, <a href="https://www.wpc.ncep.noaa.gov/images/hpcvrf/maemaxyr.gif">https://www.wpc.ncep.noaa.gov/images/hpcvrf/maemaxyr.gif</a> (last visited Oct.
28, 2021) (showing NOAA data on the evolving accuracy of their
Weather Prediction Center forecasts of daily high temperature).
---------------------------------------------------------------------------

123. Although we acknowledge that the accuracy of forecasts
decreases the further in advance the forecast is made, we disagree that
ambient air temperature forecasts made 10 days in advance are so
inaccurate that they cannot provide any benefits when used as part of
AARs, even when adjusted with appropriate forecast margins, as
discussed herein. Neither commenters supporting nor opposing the 10-day
threshold provide quantitative evidence related to the accuracy of 10-
day forecasts; however, a published analysis of the NOAA National Blend
of Models (NBM) forecast--one of the publicly available NOAA forecasts
that looks out at least 10 days--indicates that the mean absolute error
for 240 hour (10 day) forward continental United States surface
temperature forecasts was approximately four to six degrees Fahrenheit
in July to November 2016.\302\ We find that such levels of error would
likely allow for a meaningful number of hours in any season where a 10-
day forward AAR would provide benefits relative to the seasonal line
rating. We also note that this finding is consistent with the support
for the 10-day threshold by various commenters.\303\
---------------------------------------------------------------------------

\302\ Tabitha Huntemann, Daniel Plumb, and David Ruth,
Verification of the National Blend of Models (2017), <a href="https://www.weather.gov/media/mdl/AMS2017-NBMVerification.pdf">https://www.weather.gov/media/mdl/AMS2017-NBMVerification.pdf</a>. We note that
this analysis was applicable to the 2016 National Blend of Models
(NBM) Version 2.0 forecast, and that several improved versions of
the NBM forecast have been implemented since that time. The current
NBM Version 4.0 was implemented in September 2020. See NBM: National
Blend of Models, <a href="https://vlab.noaa.gov/web/mdl/nbm">https://vlab.noaa.gov/web/mdl/nbm</a>. While we take
notice of this NBM forecast accuracy data as a point of reference,
we emphasize that the NBM forecasts are just one example of the
types of forecasts that transmission providers might rely on in
complying with this final rule.
\303\ CEA Comments at 2; EDFR Comments at 7; Ohio FEA Comments
at 5; New England State Agencies Comments at 9-10; ACPA/SEIA
Comments at 13.
---------------------------------------------------------------------------

124. We do not find persuasive arguments that the AAR requirements
adopted in this final rule will be unduly burdensome. Contrary to such
assertions, because we expect the increased costs of implementing AARs
under a 10-day threshold (as opposed to a shorter threshold) to be
primarily related to increased forecasting and data storage/hardware
needs, we do not expect such costs to be excessive. Moreover, in
certain situations, especially outside the RTO/ISO context, adopting
the 10-day threshold will

[[Page 2265]]

allow more transfer capability to be made available to customers than
simply adopting seasonal worst-case assumptions. In addition, as CEA
states, using AARs to calculate transmission line ratings for service
requests up to 10 days has proven to be reliable and to provide
benefits to effective and reliable transmission operations.\304\ In
that context, commenters have not provided evidence that the cost to
procure or develop 10-day forward forecasts is materially different
from the cost to procure or develop two- or three-day forward forecasts
and, in any case, that such cost outweighs the added benefits of
extending the forward period from two or three days to 10 days. For
these reasons, we expect the material benefits resulting from adopting
the 10-day threshold to, on balance, outweigh the costs.
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\304\ CEA Comments at 2.
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125. We emphasize that any benefit from the AAR requirements, and
the 10-day threshold in particular, should be compared to the relative
costs of alternatives. And we find that the cost associated with
requiring AARs for additional days forward is essentially the cost of
accessing, storing, and processing the additional forecast data, and
the cost of calculating, storing, and incorporating into transmission
service the additional hours of AARs. As we expect this process will be
largely automated, we do not anticipate that the cost of the 10-day
threshold, as opposed to a shorter threshold, will be significantly
higher. Although the question of where to draw the line in terms of the
time threshold for AAR implementation is not clear cut, we find that 10
days strikes an appropriate balance between the benefits of more
accurate transmission line ratings that result from the AAR
requirements adopted in this final rule, and the likely costs of
implementing those requirements.
126. We note that some commenters may have misunderstood the
Commission's proposal in the NOPR as requiring the use of expected
ambient air temperatures in forecasts of AARs for future periods. That
is, they may have read the Commission's NOPR proposal as requiring that
if the forecasted ambient air temperature at a given transmission line
10 days in advance (without any forecast margin applied, i.e., the
expected temperature) was X degrees, that the transmission provider was
required to use an AAR for that hour 10 days forward that assumed an
air temperature of X degrees. This is not the case. Rather, AARs must
be calculated using the temperature at which there is sufficient
confidence that the actual temperature will not be greater than that
temperature (i.e., expected temperature plus an appropriate forecast
margin).\305\ This approach to calculations is consistent with EPRI's
recommendation and also comments from Entergy and the CAISO DMM, which
suggest margins to account for forecast error.\306\
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\305\ See NOPR, 173 FERC ] 61,165 at PP 97, 102.
\306\ EPRI Comments at 10-12; Entergy Comments at 11; CAISO DMM
Comments at 3.
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127. In response to requests for clarification from BPA, LADWP, and
EEI that transmission providers can curtail transmission sold at least
24 hours in advance, consistent with existing curtailment
prioritization, should temperature forecasts dictate such curtailment,
we confirm that we are not changing the existing curtailment
prioritization. In implementing the 10-day threshold, it may be
necessary in some instances for transmission providers to curtail
transmission sold based on ambient air temperature forecasts (including
forecast margins) that end up being lower than real-time temperatures.
Although transmission providers will continue to curtail transmission
at times due to unrealized ambient air temperature assumptions, the
need for such curtailments should be decreased as a result of the AAR
requirements adopted herein.\307\ We reiterate that under the AAR
requirements that we adopt in this final rule, transmission providers
have the latitude (and obligation) to develop accurate, safe, and
reliable transmission line ratings,\308\ and we do not expect that such
transmission line ratings will necessitate an increase in the need for
curtailments due to inaccurate AARs. If a transmission provider
determines (whether during pre-testing of its AAR methodologies or
during actual operations) that a given level of forecast margins yields
an unreasonable frequency of such curtailment, it should re-evaluate
and adjust its forecast margins.
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\307\ We note, for example, that a typical winter seasonal line
rating temperature assumption today is 32 degrees Fahrenheit--a
temperature assumption which in many parts of the United States is
violated frequently over the current typical six-month ``winter
season'' used in seasonal line ratings. Commission Staff Paper at 7;
see also Midwest Reliability Organization Standards Committee,
Standard Application Guide: FAC-008, Version 1.1, p. 14 (March 21,
2017), <a href="https://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/FAC-008-3%20Standard%20Application%20Guide.pdf">https://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/FAC-008-3%20Standard%20Application%20Guide.pdf</a>. We expect such assumption
violations to be less frequent under our required approach, where
transmission providers will apply reasonable forecast margins when
developing their AARs
\308\ NOPR, 173 FERC ] 61,165 at P 97.
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128. We further acknowledge that, in addition to the concerns of
some commenters related to forecast margins being too low, certain
forecast margins could also prove to be too high. In those instances,
as with the implementation of static transmission line ratings,
transmission line ratings using unreasonably high forecast margins
would also yield inaccurate transmission line ratings and, in turn,
would result in an underutilization of existing transmission
facilities, price signals based on less transfer capability than is
truly available, and wholesale rates that are unjust and unreasonable.
Similar to unreasonably low forecast margins, if a transmission
provider determines (whether during pre-testing of its AAR
methodologies or during actual operations) that a given forecast margin
is unreasonably high, it should re-evaluate and adjust its forecast
margins.
129. Similarly, contrary to comments from CAISO, NYISO, NYTOs, and
EEI that describe the operational risks associated with overestimating
ATC,\309\ we do not expect that the AAR requirements adopted herein
will result in a frequent number of instances when transmission line
ratings used in the real-time market are lower than transmission line
ratings used in the day-ahead market. Some such instances will occur,
but we believe that there is sufficient latitude within our
requirements, as discussed above, for day-ahead transmission line
ratings to be determined with sufficient forecast margins to avoid this
concern. Furthermore, as the Commission stated in the NOPR, day-ahead
markets already rely heavily upon weather forecasts to inform next-day
load and intermittent generation availability. This final rule does not
change reliance upon weather forecasting; instead, the AAR requirements
we adopt herein will improve the accuracy of transmission line ratings
and, if anything, lead to cost savings to consumers and reliability
benefits. Additionally, as PJM's AAR implementation experience
demonstrates, temperatures can be forecast day ahead with a reasonable
degree of certainty.\310\ We also find that operational risks that
might result from the use of transmission line ratings in the real-time
market that are lower than the transmission line ratings used in the
day-ahead market can further be

[[Page 2266]]

managed and mitigated through the use of AARs in the RUC processes,
which will have the benefit of updated temperature forecasts. Finally,
we reiterate that PJM and AEP report reliability benefits from AAR
implementation.
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\309\ NYTOs Comments at 5-6; EEI Comments at 10-12; NYISO
Comments at 13-14; CAISO Comments at 9-11.
\310\ PJM Comments at 3.
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130. In response to comments from EEI and other transmission owners
about the complexities of calculating AARs up to the 10-day threshold,
we find that such complexities are predominately reflected in the
upfront set-up and investment costs \311\ and that these costs will be
primarily related to increased forecasting and data storage/hardware
needs.
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\311\ Exelon Comments at 8; AEP Post-Technical Conference
Comments at 2-3; see also supra Section IV.B.1.c.
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131. In response to NERC's request that the Commission consider how
entities should reconcile AARs used for planning and operations
functions,\312\ we find that AARs used in near-term operations will
deviate from those transmission line ratings used in various planning
functions. As transmission providers progress closer in time to a given
interval, near-term ambient air temperature forecasts will necessarily
be updated. These updates will impact TTC, and, as a result, ATC and
system operating limits. In addition, regarding implementation of this
final rule and currently effective MOD A Reliability Standards,\313\
this final rule does not advocate for operating the transmission system
beyond the system operating limits and established facility ratings.
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\312\ NERC Comments at 6-7.
\313\ Id. at 7.
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132. In response to requests for clarification of the NOPR proposal
from NERC and BPA with respect to temperature variations,\314\
transmission providers must consider the relevant ambient air
temperature forecasts along the transmission line, and determine the
transmission line rating based on the most limiting combination of
equipment limitations and forecasted local ambient air temperature
along the transmission line. We note that NERC additionally requested
that the Commission consider how variations in load forecasts would be
addressed when using values for each of the 240 hours in the next 10
days for each transmission line in granting firm point-to-point
transmission service.\315\ In response, we reiterate that the
requirements adopted herein are designed to ensure accurate
transmission line ratings. We also reiterate that AARs must be
calculated using the temperature at which there is sufficient
confidence that the actual temperature will not be greater than that
temperature (i.e., expected temperature plus an appropriate forecast
margin). We further clarify, in response to NERC, that transmission
line rating methodologies must be updated. In particular, pro forma
OATT Attachment M, as adopted by this final rule, requires transmission
line ratings to be computed in accordance with a written transmission
line rating methodology and consistent with good utility practice.
Moreover, we note that Reliability Standard FAC-008-5 Requirement 3.2
requires transmission line rating methodologies to identify how ambient
conditions are considered.\316\ Thus, transmission line rating
methodologies need to document methods used to calculate AARs.
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\314\ NERC Comments at 6-7; BPA Comments at 2-4.
\315\ NERC Comments at 6-7.
\316\ Reliability Standard FAC-008-5, Requirement R3.2, p.4,
<a href="http://www.nerc.com/pa/Stand/Project%20201803%20Standards%20Efficiency%20Review%20Require/2018-03_FAC-008-5_clean_01192021.pdf">http://www.nerc.com/pa/Stand/Project%20201803%20Standards%20Efficiency%20Review%20Require/2018-03_FAC-008-5_clean_01192021.pdf</a>.
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133. In response to LADWP's argument that the Commission should
align AAR requirements with the NERC Reliability Standards--and that
the proposed 10-day threshold would conflict with the requirement
specified in Reliability Standard MOD-001-1a that ATC be calculated
hourly for the next 48 hours--we note that Reliability Standard MOD-
001-1a requires that ATC be calculated for at least the next 48 hours,
not for only the next 48 hours. Furthermore, the Commission's
regulations require ATC to be calculated and/or posted for periods more
than 48 hours in the future (e.g., when transmission service is
requested or inquired about).
134. Finally, in response to RTO/ISO requests for flexibility, we
clarify the applicability of the 10-day threshold to RTOs/ISOs. The
vast majority of energy transactions in RTOs/ISOs are executed and
financially settled in the day-ahead and real-time energy markets;
thus, we find that requiring AARs for the real-time and day-ahead
energy markets in RTOs/ISOs is necessary to ensure the accuracy of
transmission line ratings and just and reasonable wholesale rates.
Because these transactions take place within a one-day forward
timeframe, the 10-day threshold will provide very little additional
benefits in existing RTO/ISO markets. Accordingly, the 10-day threshold
will not apply to internal transactions or internal flows associated
with through-and-out transactions in RTOs/ISOs. However, given that
RTOs/ISOs generally use the pro forma OATT transmission service model
for movement of electricity into/out of their service territories, the
10-day threshold requirement will apply to RTOs/ISOs' evaluation or
determination of availability of transmission service at the seams of
RTO/ISO service territories, in order to improve the accuracy of
transmission line ratings and ensure just and reasonable wholesale
rates.
b. Role of the Transmission Owner and Transmission Provider in AAR
Implementation
i. NOPR Proposal
135. In proposing AAR implementation in the pro forma OATT, the
Commission proposed for transmission providers--not transmission
owners--to implement AARs because transmission providers--not
transmission owners--must have an OATT.\317\
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\317\ NOPR, 173 FERC ] 61,165 at P 84.
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ii. Comments
136. Several commenters clarify that transmission owners, not
transmission providers, calculate transmission line ratings.\318\ For
example, MISO states that its formational documents reflect, and have
codified, the responsibility of transmission owners to calculate
facility ratings, not MISO.\319\ MISO Transmission Owners explain that
Reliability Standard FAC-008-5 requires transmission owners to have ``a
documented methodology for determining facility ratings of its solely
and jointly owned Facilities'' based on the electrical characteristics
of the transmission equipment or other industry standard.\320\ Southern
Company states that the MOD suite of NERC Reliability Standards
governing TTC/ATC calculations requires transmission line ratings as
provided by transmission owners.\321\ Similarly, ISO-NE explains that
its Transmission Operating Agreement requires its participating
transmission owners to establish transmission line ratings for each
transmission facility.\322\ Additionally, NYISO states that in the New
York Control Area, the transmission owners are responsible for
developing transmission line ratings and providing the element ratings
directly to NYISO. In turn, according to NYISO, NYISO determines the
most limiting element, which sets the applicable facility rating.\323\
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\318\ MISO Comments at 27; Vistra Comments at 3-4; TAPS Comments
at 13-14; Southern Company Comments at 6; EEI Comments at 2-4; MISO
Transmission Owners at 29; EEI Comments at 2-4.
\319\ MISO Comments at 27.
\320\ MISO Transmission Owners at 29.
\321\ Southern Company Comments at 3, 6.
\322\ ISO-NE Comments at 6.
\323\ NYISO Comments at 3.

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[[Page 2267]]

137. Because of these differing transmission owner and transmission
provider roles and responsibilities, these commenters request that the
Commission recognize and make these differing roles explicit in any
final rule.\324\ Some recommend further Commission action to ensure
transmission owners have an obligation to implement the AAR
requirements in proposed pro forma OATT Attachment M. For example,
Vistra encourages the Commission to modify its regulations to create a
compliance obligation for each transmission owner to provide RTOs/ISOs
all information necessary to implement proposed pro forma OATT
Attachment M.\325\ Similarly, TAPS requests that the Commission clarify
that: (1) RTOs/ISOs have the authority to require transmission owners
to provide the information they will need to implement AARs; or (2)
transmission owners within RTOs/ISOs must provide the information RTOs/
ISOs will need to implement AARs to the relevant RTO/ISO.\326\
Additionally, TAPS argues that in order to achieve efficient and
consistent application of AARs, the Commission should direct RTOs/ISOs
to use, or at minimum accommodate the use of, ``look-up tables.'' \327\
TAPS explains that, using the ``look-up table'' approach will limit the
obligation to continuously monitor weather reports to recalculate AARs
and communicate those transmission line ratings to the RTO/ISO on an
hourly basis.\328\
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\324\ MISO Comments at 27; Vistra Comments at 3-4; TAPS Comments
at 13-14; Southern Company Comments at 6; EEI Comments at 2-4.
\325\ Vistra Comments at 3-4.
\326\ TAPS Comments at 14.
\327\ Id. at 8. TAPS states that, for each of their transmission
facilities, transmission owners should be required to provide RTOs/
ISOs with a table showing their temperature-adjusted rating for a
pre-established set of ambient air temperatures.
\328\ Id. at 8-10.
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138. Noting the applicability of the pro forma OATT to transmission
providers and that transmission owners and transmission providers are
different in RTO/ISOs, Exelon comments on the phrasing ``is

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