Rule2022-11233
Managing Transmission Line Ratings
Primary source
Metadata and text below are from the Federal Register, a public-domain U.S. government work. Always verify the official published version before relying on it for any legal matter.
Published
May 25, 2022
Effective
March 14, 2022
Issuing agencies
Energy DepartmentFederal Energy Regulatory Commission
Abstract
The Federal Energy Regulatory Commission (Commission) addresses arguments raised on rehearing and clarifies in part Order No. 881, which revised 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.
Full Text
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<title>Federal Register, Volume 87 Issue 101 (Wednesday, May 25, 2022)</title>
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[Federal Register Volume 87, Number 101 (Wednesday, May 25, 2022)]
[Rules and Regulations]
[Pages 31712-31728]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2022-11233]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM20-16-001; Order No. 881-A]
Managing Transmission Line Ratings
AGENCY: Federal Energy Regulatory Commission, Department of Energy.
ACTION: Order addressing arguments raised on rehearing and
clarification.
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SUMMARY: The Federal Energy Regulatory Commission (Commission)
addresses arguments raised on rehearing and clarifies in part Order No.
881, which revised 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.
DATES: As of May 25, 2022 the effective date of the document published
January 13, 2022 at 87 FR 2244 is confirmed as March 14, 2022.
FOR FURTHER INFORMATION CONTACT:
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#194b607877374a6d6b766a7a717c7077597f7c6b7a377e766f"><span class="__cf_email__" data-cfemail="e9bb908887c7ba9d9b869a8a818c8087a98f8c9b8ac78e869f">[email protected]</span></a>.
Dillon Kolkmann (Technical Information), Office of Energy Policy
Innovation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426, (202) 502-8650, <a href="/cdn-cgi/l/email-protection#05416c69696a6b2b4e6a696e68646b6b45636077662b626a73"><span class="__cf_email__" data-cfemail="57133e3b3b3839791c383b3c3a363939173132253479303821">[email protected]</span></a>.
SUPPLEMENTARY INFORMATION:
I. Introduction
1. On December 16, 2021, the Federal Energy Regulatory Commission
(Commission) issued Order No. 881, a final rule that revised both the
pro forma Open Access Transmission Tariff (OATT) and the Commission's
regulations under the Federal Power Act (FPA) \1\ to improve the
accuracy and transparency of electric transmission line ratings.\2\
Specifically, Order No. 881 requires: public utility transmission
providers \3\ to implement ambient-adjusted ratings (AAR) \4\ on the
transmission lines over which they provide transmission service;
regional transmission organizations and independent system operators
(RTO/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
(OASIS) site or other password-protected website.
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\1\ 16 U.S.C. 824e.
\2\ Managing Transmission Line Ratings, Order No. 881, 87 FR
2244 (Jan. 13, 2022, 177 FERC ] 61,179 (2021).
\3\ In this order, 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).
\4\ An ambient-adjusted rating (or AAR) is defined 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. See 18 CFR 35.28(b)(12) (2021); Pro Forma OATT
attach. M, AAR Definition.
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2. On January 18, 2022, several entities filed requests for
rehearing and/or clarification of Order No. 881.\5\
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\5\ The following entities filed requests for rehearing and/or
clarification: American Transmission Company (ATC); Edison Electric
Institute (EEI); ITC Holdings Corp., on behalf of its operating
subsidiaries, International Transmission Company, Michigan Electric
Transmission Company, LLC, ITC Midwest LLC, and ITC Great Plains,
LLC (collectively, ITC); MISO Transmission Owners; and Potomac
Economics, Ltd., acting in its capacity as MISO's independent market
monitor (Potomac Economics).
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3. Pursuant to Allegheny Defense Project v. FERC, \6\ the rehearing
requests filed in this proceeding may be deemed denied by operation of
law. However, as permitted by section 313(a) of the FPA,\7\ we are
modifying the discussion in Order No. 881, granting clarification in
part, and continue to reach the same result in this proceeding, as
discussed below.\8\
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\6\ 964 F.3d 1 (D.C. Cir. 2020) (en banc).
\7\ 16 U.S.C. 825l(a) (``Until the record in a proceeding shall
have been filed in a court of appeals, as provided in subsection
(b), the Commission may at any time, upon reasonable notice and in
such manner as it shall deem proper, modify or set aside, in whole
or in part, any finding or order made or issued by it under the
provisions of this chapter.'').
\8\ Allegheny Def. Project, 964 F.3d at 16-17.
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II. Discussion
4. In this order, we sustain the result of Order No. 881 and
continue to find that, because 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 rates for the transmission of electric energy in interstate
commerce (hereinafter referred to collectively as ``wholesale rates''),
inaccurate transmission line ratings result in Commission-
jurisdictional rates that are unjust and unreasonable.\9\ Below, we
first discuss requests for rehearing and/or clarification related to
the AAR requirements that the Commission adopted in Order No. 881,
specifically: the requirement for transmission providers to implement
AARs on all transmission lines; the impact of the AAR requirements on
transmission line relays; the use of AARs 10 days forward in
transmission service and operations; seasonal line rating floors; the
minimum AAR temperature range and AAR granularity; and solar heating in
AAR calculations. Second, we discuss requests for rehearing related to
the annual recalculation of seasonal line ratings, as required by Order
No. 881. Third, we discuss requests for rehearing and/or clarification
related to the transparency requirements that the Commission adopted in
Order No. 881, including the data sharing burden, OASIS access, and the
role of independent market monitors. Lastly, we address requests for
rehearing and/or clarification related to compliance and other
miscellaneous issues.
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\9\ Order No. 881, 177 FERC ] 61,179 at PP 3, 29.
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A. AAR-Related Requirements of Order No. 881
1. Requirement for Transmission Providers To Implement AARs on All
Transmission Lines
a. Final Rule
5. In Order No. 881, the Commission required transmission providers
to apply the AAR requirements set forth in pro forma OATT Attachment M,
as adopted in the final rule, to all transmission lines,\10\ subject to
certain exceptions.\11\ The Commission adopted
[[Page 31713]]
these AAR requirements to improve the accuracy of transmission line
ratings, which the Commission explained will cause the rates for the
transmission of electric energy in interstate commerce and the sale of
electric energy at wholesale in interstate commerce to more accurately
reflect the cost of the wholesale service being provided (i.e., energy,
capacity, ancillary services, or transmission service), thereby helping
to ensure that those wholesale rates are just and reasonable.\12\
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\10\ Id. P 83.
\11\ Order No. 881 allows exceptions to the AAR and seasonal
line rating requirements in instances where the transmission
provider determines, consistent with good utility practice, that the
transmission line rating of a transmission line is not affected by
ambient air temperatures. Id. P 227.
\12\ Id. P 83.
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6. The Commission chose not to adopt the phased-in implementation
schedule proposed in the Notice of Proposed Rulemaking (NOPR) in which
a transmission provider would initially implement AARs on only
historically congested lines.\13\ The Commission reasoned that applying
the AAR requirements to all transmission lines would both ensure that
wholesale rates remain just and reasonable and strike an appropriate
balance between benefits and challenges of AAR implementation. The
Commission also found that the record indicated that costs are mostly
initial investment costs in energy management system (EMS) improvements
to accommodate AARs, implementation of a ratings database, and review
(and potentially reset) of protective relays settings and that, once
these initial investments are made, adding AARs to additional
transmission lines appears to have a minimal incremental cost.\14\
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\13\ Id. P 84. The Commission had 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].'' Managing Transmission Line
Ratings, 85 FR 6420 (Jan. 21, 2021), 173 FERC ] 61,165, at P 92
(2020) (NOPR.)
\14\ Order No. 881, 177 FERC ] 61,179 at P 85.
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b. Request for Rehearing
7. EEI seeks rehearing of the Commission's decision to require that
transmission providers implement AARs on all transmission lines on
which they provide transmission service rather than prioritize
implementation on historically congested transmission lines as proposed
in the NOPR. EEI argues that Order No. 881 fails to support assertions
that AARs will ensure that wholesale rates more accurately reflect the
cost of wholesale service or that, without AARs, wholesale rates are
not just and reasonable.\15\
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\15\ EEI Request for Rehearing at 4.
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8. EEI asserts that the Commission's primary rationale for
requiring AARs on all transmission lines only supports applying the AAR
requirements to congested lines.\16\ EEI further asserts that the
Commission failed to provide quantified support for applying AARs for
near-term service outside RTOs/ISOs and that the examples the
Commission relied upon to support its actions, e.g., the potential for
avoiding overloads, are hypothetical or anecdotal when applied
broadly.\17\
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\16\ Id. at 5.
\17\ Id.
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9. EEI also argues that the Commission must weigh the benefits of
AARs against the costs that will be incurred by requiring AAR adoption
on all transmission lines (subject to a few exceptions). EEI further
suggests that Order No. 881 cursorily addresses reliability concerns
raised by commenters regarding this requirement without sufficiently
explaining why the requirement to impose AARs on all transmission lines
addresses those concerns.\18\
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\18\ Id. (citing Order No. 881, 177 FERC ] 61,179 at PP 128-
133).
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10. EEI also argues that the final rule does not reconcile its
requirement for AARs on all transmission lines with Order No. 890,\19\
which requires transmission providers ``to use data and modeling
assumptions for the short- and long-term ATC calculations that are
consistent with that used for the planning of operations and system
planning, respectively, to the maximum extent practicable.'' EEI
contends that the Commission's failure to reconcile Order No. 881 and
Order No. 890 reinforces limiting the applicability of the AAR
requirements to only congested transmission lines and in real-time
operations or day-ahead markets.\20\
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\19\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007),
118 FERC ] 61,119, 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).
\20\ EEI Request for Rehearing at 6 (quoting Order No. 890, 118
FERC ] 61,119 at P 292).
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11. Finally, EEI contends that, while the exceptions to the AAR
requirements are needed, they highlight why AARs should not be required
on all transmission lines. For example, EEI states that Order No. 881
allows the ``temporary use of a transmission line rating different than
would otherwise be required under pro forma OATT Attachment M [if it]
is necessary to ensure safety and reliability.'' \21\ EEI argues that
``reliable operation should not be addressed by exception'' and that
transmission owners and transmission providers ``should be allowed the
flexibility to implement AARs in a reliable manner on the specific
circuits where congestion/transfer capability benefits are derived.''
\22\
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\21\ Id. at 6-7 (citing Order No. 881, 177 FERC ] 61,179 at P
232).
\22\ Id.
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c. Commission Determination
12. Having considered EEI's request for rehearing on this matter,
we continue to find that requiring transmission providers to apply the
AAR requirements set forth in pro forma OATT Attachment M to all
transmission lines on which they provide transmission service, subject
to certain exceptions, is just and reasonable.
13. First, in response to EEI's statement that ``the Commission
assumes, without support, that AARs will ensure that wholesale rates
more accurately reflect the cost of the wholesale service being
provided,'' \23\ we disagree. In Order No. 881, to conclude that the
AAR requirements will ensure that wholesale rates are just and
reasonable, the Commission relied on the ``inextricabl[e] link[ ]''
between transmission line ratings and wholesale rates.\24\ That
inextricable link reflects the basic economics of the transmission
system; that is, the relationship between the physical system and
economic fundamentals, a relationship described in detail by the
Commission.\25\ Consistent with those economics, the Commission
explained how inaccurate transmission line ratings--both the
understating of transmission capability and the overstating of
transmission capability--can affect congestion and resulting wholesale
rates.\26\ These economic fundamentals apply to all transmission lines,
not only those that have historically been congested. The Commission
explained the benefit of applying the AAR requirements to all
transmission lines particularly ``[g]iven the difficulty in predicting
unexpected congestion before it happens.'' \27\ Changes in the
transmission flow will arise due to short-term and long-term changes in
the physical transmission system (e.g., outages and transmission line
upgrades),\28\ due to changes to the location and amount of generation
and load, or due to unexpected events, such as extreme weather. Because
such
[[Page 31714]]
changes may affect all transmission lines, the economic logic
underlying the AAR requirements applies to all transmission lines. By
establishing and relying on the basic economic logic underlying the
relationship between more accurate transmission line ratings and
wholesale rates,\29\ the Commission had ample support to conclude that
applying the AAR requirements to all transmission lines will lead to
just and reasonable wholesale rates.\30\
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\23\ Id. at 4.
\24\ Order No. 881, 177 FERC ] 61,179 at P 30.
\25\ Id.
\26\ Id. PP 34-35.
\27\ Id. P 94.
\28\ Id. (stating ``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.'').
\29\ Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520, 531
(D.C. Cir. 2010) (recognizing that it is ``perfectly legitimate for
the Commission to base its findings . . . on basic economic
theory''); Assoc. Gas Distributors v. FERC, 824 F.2d 981, 1008 (D.C.
Cir. 1987) (``Agencies do not need to conduct experiments in order
to rely on the prediction that an unsupported stone will fall.'').
\30\ Order No. 881, 177 FERC ] 61,179 at P 29.
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14. As for the decision to apply the AAR requirements to all
transmission lines, EEI is correct that the Commission must weigh the
benefits against the burdens of applying the AAR requirements to all
transmission lines. The Commission did just that. As explained in Order
No. 881, the incremental cost to implement AARs on additional
transmission lines--beyond those that are historically congested--once
the initial costs have been incurred, is minimal.\31\ EEI does not
dispute this fact. By contrast, as the Commission explained in Order
No. 881, extending the AAR requirements to apply to those additional
transmission lines is expected to have significant value. As the
Commission explained in Order No. 881 and we reiterate here, we expect
that, over time, the additional congestion costs that will be
alleviated through AAR implementation on all transmission lines
(compared to only on historically congested transmission lines) will
exceed the additional, primarily one-time, costs to implement AARs on
those additional transmission lines.\32\
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\31\ Id. P 85 (citing Exelon Corporation (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 181:4-9).
\32\ Id. PP 93-95.
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15. As the Commission explained in Order No. 881, AARs can help
alleviate congestion costs. While the greatest initial benefit may come
from implementing AARs on historically congested transmission lines,
limiting implementation to such lines, would likely fail to alleviate
considerable congestion costs. Generally, patterns of congestion across
different transmission lines are difficult to predict. This difficulty
is particularly notable during unanticipated system events, such as
sudden forced outages and extreme weather, when flows may change
considerably from normal operations. During such events, any increased
transfer capability provided through AARs may prove valuable even on
transmission lines that have not been historically congested.\33\
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\33\ Id. P 95.
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16. Additionally, AAR implementation itself will affect congestion
patterns, as changes to transmission line ratings may change generation
dispatch patterns and, by extension, congestion patterns.\34\ Moreover,
as the generation mix continues to evolve and new generation comes
online in new locations, congestion patterns will also evolve.\35\ By
design, limiting AARs to only historically congested transmission lines
would not address evolving transmission congestion patterns until after
potentially costly congestion occurs on previously uncongested lines.
For the above reasons, applying the AAR requirements to only
historically congested transmission lines would not strike the right
balance between the benefits and burdens of AAR implementation.
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\34\ Id.
\35\ See, e.g., American Clean Power Association (ACPA) and
Solar Energy Industries Association (SEIA) Joint Comments at 8, 11;
Electric Power Supply Association (EPSA) Comments at 4; New England
State Agencies Comments at 6.
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17. Indeed, the Commission provided the example in Order No. 881 of
congestion costs during extreme events as compared to potential
congestion cost savings due to AAR implementation. During certain
single extreme events, the congestion cost savings of AAR
implementation would have been substantial enough from that event alone
to justify applying the AAR requirements to all transmission lines,
instead of just to historically congested transmission lines. For
example, in the February 2021 cold weather event, MISO, which primarily
implements seasonal and static line ratings, experienced unprecedented
east-to-west flows throughout its service footprint and accrued $773
million in congestion charges in just a few days, significantly in
congestion patterns that were neither predicted nor typical in
MISO.\36\
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\36\ Order No. 881, 177 FERC ] 61,179 at P 95; Organization of
MISO States, Inc. (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>.
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18. With respect to EEI's claim that the Commission provided
inadequate support for applying the AAR requirements for near-term
transmission service outside RTOs/ISOs,\37\ we disagree. As explained
above, Order No. 881 established a clear linkage between transmission
line ratings and wholesale rates.\38\ The Commission's reasoning
applies equally in both RTOs/ISOs and non-RTO/ISO regions. While EEI
criticizes the Commission's support for its determination as ``largely
hypothetical,'' we note that EEI offers no additional arguments or
evidence on rehearing that suggests the Commission's use of basic
economic theory to support its conclusions was not reasonable.\39\
Moreover, despite EEI's characterization of the supporting evidence as
``anecdotal'' and lacking ``quantified support,'' the Commission based
its conclusions on substantial evidence in the record that transmission
line ratings, not transmission line ratings in RTOs/ISOs, are practices
that directly affect wholesale rates.\40\
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\37\ EEI Request for Rehearing at 5.
\38\ Order No. 881, 177 FERC ] 61,179 at PP 29-34.
\39\ See supra note 31.
\40\ Order No. 881, 177 FERC ] 61,179 at P 31 (citing 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).
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19. We also disagree with EEI's assertion that Order No. 881 was
arbitrary and capricious because it addressed reliability concerns in
only a ``cursory manner,'' and that it provided for reliability ``by
exception.'' \41\ In Order No. 881, the Commission adopted the System
Reliability section of pro forma OATT Attachment M, which permits a
transmission provider to use a temporary alternate rating (in place of
what would be otherwise required in Attachment M) if the transmission
provider reasonably determines such an alternate rating is necessary to
ensure the safety and reliability of the transmission system.\42\
Contrary to arguments from EEI, the Commission carefully considered the
impacts of the AAR requirements and established the necessary
mechanisms to provide transmission owners with the flexibility to
ensure safety and reliability.\43\ While EEI may have preferred that
the Commission adopt a more limited application of the AAR
requirements, nothing in its rehearing request suggests
[[Page 31715]]
that Attachment M is insufficient to protect safety and reliability.
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\41\ EEI Request for Rehearing at 5-6.
\42\ Order No. 881, 177 FERC ] 61,179 at P 228.
\43\ Id.
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20. In making its determination in Order No. 881, the Commission
relied on the record to find that accounting for ambient air
temperatures in transmission line ratings can result ``in significant
reliability, operational, and economic benefits'' by, for example,
increasing transmission line ratings and thereby affording transmission
providers more options to manage load.\44\ AARs correct existing
occasional overestimations of transmission line ratings during periods
when the actual ambient air temperature is greater than the temperature
assumed when the rating was calculated.\45\ As a result, implementation
of AARs will lower transmission line ratings when extreme high
temperature events occur, reducing the likelihood of inadvertently
overloading a transmission line.\46\ Moreover, consistent with PJM's
and Potomac Economics' post-technical conference comments, the
Commission explained that, because AARs typically increase transmission
line ratings when actual temperatures are lower than long-term
assumptions, the resulting increased transmission capability will
provide operators additional flexibility during many hours, which
promotes reliability.\47\ Specifically, by increasing the ATC, system
operators would have more options available to manage congestion, and
potentially ameliorate system conditions during an emergency. This is
consistent with the 2019 FERC and North American Electric Reliability
Corporation (NERC) Staff Report on the January 2018 South Central cold
weather event, which recommended adoption of transmission line ratings
that better consider ambient temperature conditions.\48\
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\44\ Id. P 85 (emphasis added).
\45\ Id. P 35.
\46\ Id.; NOPR, 173 FERC ] 61,165 at P 106; Exelon Post-
Technical Conference Comments at 9.
\47\ See PJM Post-Technical Conference Comments at 2; Potomac
Economics Post-Technical Conference Comments at 8.
\48\ 2019 FERC and NERC Staff Report, The South Central United
States Cold Weather Bulk Electric System Event of January 17, 2018,
at 96-97 (July 2019) (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>.
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21. Finally, we disagree with EEI's contention that Order No. 881
failed to reconcile the requirements outlined in pro forma OATT
Attachment M with the provisions adopted in Order No. 890 \49\ that
require transmission providers ``to use data and modeling assumptions
for the short- and long-term ATC calculations that are consistent with
that used for the planning of operations and system planning,
respectively, to the maximum extent practicable.'' \50\ In Order No.
881, the Commission acknowledged that AARs used in near-term operations
will deviate from those transmission line ratings used in various
planning functions.\51\ However, Order No. 890 found that requirements
for consistency would ``remedy the potential for undue discrimination
by eliminating discretion and ensuring comparability in the manner in
which a transmission provider operates and plans its system to serve
native load and the manner in which it calculates ATC for service to
third parties.'' \52\ Since Order No. 881 imposes requirements to
change the calculation of ATC by all transmission providers on all
transmission lines, any resulting deviation between near-term ATC
calculations and those used in modeling assumptions for various
``planning of operation and system expansion'' does not create the
potential for undue discrimination and therefore does not conflict with
the requirements of Order No. 890. In any event, we note that the
requirement in Order No. 890 for consistent assumptions was ``to the
maximum extent practicable,'' and clarify that none of the requirements
in Order No. 881 require revisions to the assumptions used in the
transmission planning and development contexts.\53\
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\49\ Order No. 890, 118 FERC ] 61,119.
\50\ EEI Request for Rehearing at 6 (citing Order No. 890, 118
FERC ] 61,119 at P 292).
\51\ Order No. 881, 177 FERC ] 61,179 at P 131.
\52\ Order No. 890, 118 FERC ] 61,119 at P 292 (emphasis added).
\53\ Id. P 347.
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2. Transmission Line Relays
a. Final Rule
22. In Order No. 881, when discussing its decision to apply the AAR
requirements to all transmission 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.'' \54\ The Commission further
noted that 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.\55\
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\54\ Order No. 881, 177 FERC ] 61,179 at P 48.
\55\ Id. P 99.
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b. Request for Clarification
23. EEI requests clarification that compliance with the AAR
requirements of Order No. 881 will require all transmission owners and
transmission providers to evaluate or reevaluate all their transmission
protective relay settings to ensure these new worst-case transmission
line ratings will not limit transmission loadability under Reliability
Standard PRC-023-4 and, wherever necessary, develop and apply new
protective relay settings.\56\ Specifically, EEI explains that the AAR
requirements adopted in Order No. 881 are beyond PJM's current
practice, despite the Commission's reliance on PJM as an example, and
will require companies to conduct considerable analysis of new maximum
transmission line ratings. According to EEI, that analysis of new
maximum transmission line ratings, in turn, will require companies to
evaluate or reevaluate all of their transmission protective relay
settings to ensure compliance with Reliability Standard PRC-023-4.\57\
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\56\ EEI Request for Rehearing at 12-13.
\57\ Id.
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c. Commission Determination
24. We clarify two aspects of the AAR requirements related to
transmission providers' transmission protection relay settings. First,
if a transmission provider establishes higher transmission line
ratings, it will have to evaluate or reevaluate its applicable
protection systems for that facility. Second, we clarify that in a
majority of situations the relay setting should exceed AAR values.
25. As an initial matter, we disagree with EEI that Order No. 881
requires transmission providers to evaluate or reevaluate ``all
transmission protective relay settings to ensure worse case line
ratings will not limit transmission loadability under Reliability
Standard PRC-023-4.'' \58\ Rather, because compliance with Reliability
Standard PRC-023-4 is only applicable to a subset of protection
systems, i.e., phase protection systems,\59\ not all transmission
protection relay settings will be implicated by the requirements
adopted in Order No. 881. Additionally, some transmission line ratings
will qualify for an exception to the AAR
[[Page 31716]]
requirements,\60\ and some transmission lines may already have
implemented the AAR requirements.\61\ Finally, some transmission
providers have already calculated and implemented AARs for the range of
local historical temperatures (over the entire period for which records
are available) plus-or-minus a margin of 10 degrees Fahrenheit,\62\ and
thus already have relay settings evaluated or reevaluated for
compliance with Order No. 881.
---------------------------------------------------------------------------
\58\ Id. at 13 (emphasis added).
\59\ NERC Reliability Standard PRC-023-4 only applies to
transmission owners, generator owners, and distribution providers,
with load-responsive phase protection systems as described in
Attachment A of the Reliability Standard, for certain transmission
lines and transformers (i.e., those with low-voltage terminals
operated or connected at 200 kV and above and between 100 kV and 200
kV as identified by the planning coordinator as critical to the
reliability of the bulk electric system (BES)). Reliability Standard
PRC-023-4, at 1-2, <a href="https://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-023-4.pdf">https://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-023-4.pdf</a>.
\60\ Order No. 881, 177 FERC ] 61,179 at PP 227-228.
\61\ We note that, while Order No. 881 requires more AAR
calculations than are currently implemented in the PJM look-up
tables, there remains the possibility that many of the transmission
owners may have calculated transmission line ratings, and calibrated
relay settings accordingly, for a wider range of ambient air
temperatures. For example, Entergy calculates AARs for every degree
of temperature change. See September 2019 Technical Conference,
Docket No. AD19-15, Day One Tr. 157:7-15 (filed Oct. 8, 2019)
(September 2019 Technical Conference, Day 1 Tr.).
\62\ As described in Order No. 881, transmission facilities in
this case includes overhead conductors and other transmission
equipment. Specifically, the Commission defined a transmission line
rating in the 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.'' Order No. 881, 177 FERC ] 61,179 at P 44.
---------------------------------------------------------------------------
26. That said, outside the circumstances identified above, we
clarify that, if, as a result of favorable ambient conditions, a
transmission provider establishes a higher transfer capability than the
currently determined maximum facility ratings, the transmission
provider must evaluate its applicable protection systems for that
facility in order to comply with Reliability Standard PRC-023-4 and
prevent protection settings from limiting transmission loadability. In
those instances, some relay settings might require changes to maintain
reliability and to accommodate the additional power transfer capability
based on AARs. However, relays are set to operate during abnormal
conditions such as fault conditions that result in currents that are
many factors higher than the maximum continuous facility rating,
without limiting power/current flow under any system configuration or
interfering with system operators' ability to take remedial action to
protect system reliability and thus are not expected to conflict with
AARs. As the Commission explained in Order No. 881, relays are set
based on practical limitations (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).\63\ While 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 defines minimum relay
settings, because relays are set to detect abnormal conditions such as
fault currents that are many factors higher than the maximum rating of
the facility and include a margin to account for minor system changes,
transmission providers generally set relay settings above the minimum
requirement. Therefore, relay settings should already exceed the
minimum requirements even when accounting for new AAR values and thus,
in those circumstances, should not merit new protection settings.
However, we note that, in Order No. 881, the Commission inadvertently
stated that relay settings ``in the majority of cases should not exceed
AAR values.'' \64\ We clarify that this was in error. On the contrary,
relay settings in the majority of cases should exceed AAR values,
meaning, as explained above, that the requirements adopted in Order No.
881 will only require new protective settings of existing relay
settings where the transmission line rating increases on compliance
with the final rule and that increase results in the relay setting
dropping below the minimum required by Reliability Standard PRC-023-
4.\65\
---------------------------------------------------------------------------
\63\ Id. P 99.
\64\ Id.
\65\ Id.
---------------------------------------------------------------------------
3. Use of AARs 10-Days Forward in Transmission Service and Operations
a. Final Rule
27. In Order No. 881, the Commission required transmission
providers to use AARs as the relevant transmission line rating for
transmission service that starts or ends within 10 days of the date of
the request, for the curtailment or interruption of point-to-point
transmission service anticipated to occur (start and end) within the
next 10 days, and for 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.\66\ The Commission justified this requirement based on:
---------------------------------------------------------------------------
\66\ Id. P 104.
(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 . . . 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.\67\
---------------------------------------------------------------------------
\67\ Id. P 121.
---------------------------------------------------------------------------
b. Request for Rehearing
28. MISO Transmission Owners contend that the Commission ignored or
failed to meaningfully respond to MISO Transmission Owners' arguments
that requiring the use of AARs for a 10-day forward period could
adversely impact reliability and request rehearing on this point.
29. MISO Transmission Owners argue that transmission system
reliability could be jeopardized in situations where actual ambient air
temperatures are higher than forecast and that, as forecasts approach
10 days, the accuracy of forecasts decreases, which in turn increases
the uncertainty and accompanying risk. Specifically, MISO Transmission
Owners contend that, due to the imprecise nature of weather
forecasting, requiring the use of AARs for a 10-day forward period will
result in RTOs/ISOs granting near-term transmission service based on
inaccurate calculations of transfer capability, resulting in less
accurate calculations of ATC.\68\ For support, MISO Transmission Owners
cite evidence from the American Meteorological Society website on the
accuracy of medium range forecasts.\69\ Finally, MISO Transmission
Owners suggest that, by adopting this provision, the Commission
``fail[ed] the requirements of reasoned decision-making.'' \70\ They
contend that, when coupled with the 10-degree temperature margin
requirement and the hourly AAR update requirement, this provision will
be burdensome, requiring transmission owners to develop millions of
data points and ratings across their systems and incorporate voluminous
data into all of their market and transmission processes.\71\
---------------------------------------------------------------------------
\68\ MISO Transmission Owners Request for Rehearing at 15-16.
\69\ Id. at 17 & n.53.
\70\ Id. at 13-14.
\71\ Id. at 13.
---------------------------------------------------------------------------
c. Commission Determination
30. We sustain the determination in Order No. 881 to require the
use of AARs for a 10-day forward period. As the Commission acknowledged
in Order No. 881, relying on ambient air temperature forecasts
necessitates
[[Page 31717]]
accepting some degree of forecast error; however, we disagree that this
error will jeopardize system reliability. First, recognizing that
ambient air temperature forecast error exists, the Commission required
in Order No. 881 that, no matter how accurate the forecast temperatures
that underlie transmission providers' calculations of AARs,
transmission providers must implement forecast margins to ensure
sufficient confidence that actual temperatures will not be greater than
the forecast temperatures.\72\ Next, the Commission further established
that transmission providers should re-evaluate and adjust such forecast
margins if they turn out to be insufficiently or overly
conservative.\73\ Finally, we disagree that the potential error in
temperature estimates is significant. A published analysis of the
National Oceanic and Atmospheric Administration (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.\74\
---------------------------------------------------------------------------
\72\ Order No. 881, 177 FERC ] 61,179 at P 126.
\73\ Id. PP 127-128.
\74\ Id. PP 122-123.
---------------------------------------------------------------------------
31. Because transmission providers must implement forecast margins,
we disagree with MISO Transmission Owners that inaccurate ambient air
temperature forecasts will create reliability concerns. Specifically,
by incorporating forecast margins and reevaluating overly conservative
forecast margins into their AAR calculations, transmission providers
will account for any such forecast inaccuracies in a manner necessary
to maintain system reliability. Thus, because transmission providers
must use forecast margins that will account for potential inaccurate
forecasts, inaccurate forecasts will not, as MISO Transmission Owners
suggest, cause excessive real-time service curtailments. Indeed, the
Commission found in Order No. 881--and we reiterate here--that although
transmission providers will continue to curtail transmission at times
due to unrealized ambient air temperature assumptions (just as they do
today), the need for such curtailments should be decreased as a result
of the new AAR requirements.\75\
---------------------------------------------------------------------------
\75\ Id. P 127.
---------------------------------------------------------------------------
32. Moreover, as the Commission acknowledged in Order No. 881, next
day and further forward transmission scheduling already rely heavily
upon weather forecasts to inform next-day load and intermittent
generation availability.\76\ Transmission providers have the tools to
manage any congestion or potential reliability events that could arise
from errors in weather forecasts. These include the ability to curtail
or interrupt point-to-point transmission service under sections 13.6
and 14.7 of the pro forma OATT, the ability to curtail network service
under section 33 of the pro forma OATT, and the ability to redispatch
network service under sections 30.5 and 33 of the pro forma OATT.
---------------------------------------------------------------------------
\76\ Id. P 129.
---------------------------------------------------------------------------
33. We also disagree with MISO Transmission Owners' argument that
the 10-day threshold for AARs is unduly burdensome. As the Commission
found in Order No. 881, and we continue to find here, 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.\77\ As this process will likely be largely automated, we do not
anticipate that the cost and implementation burden of the 10-day
threshold, as opposed to a shorter threshold, will be significantly
higher.\78\ Additionally, we reiterate that, for RTOs/ISOs, the 10-day
threshold applies only to the movement of electricity into/out of their
service territories, which is generally point-to-point transmission
service. As stated in Order No. 881, because energy transactions in
RTOs/ISOs take place within the real-time and day-ahead markets, the
10-day threshold will provide very little additional benefits within
existing RTO/ISO markets. Accordingly, Order No. 881 stated that the
10-day threshold does not apply to internal transactions or internal
flows associated with through-and-out transactions in RTOs/ISOs.\79\
Instead, the 10-day threshold requirement applies only to RTOs/ISOs'
evaluation or determination of availability of transmission service at
the seams of RTO/ISO service territories.\80\
---------------------------------------------------------------------------
\77\ Id. P 125.
\78\ Id.
\79\ Id. P 134.
\80\ Id.; see also id. P 106.
---------------------------------------------------------------------------
34. Turning to MISO Transmission Owners' citation to information on
the American Meteorological Society website about the accuracy of
forecasts beyond eight days,\81\ we reject the introduction of such new
evidence as out of time.\82\ In any event, we find such evidence
unpersuasive. First, we note that the statement regarding the accuracy
of medium range forecasts cited by MISO Transmission Owners was
approved by the American Meteorological Association in 2015. As the
Commission noted in Order No. 881, one type of forecast that
transmission providers might use to comply with the AAR requirement is
the NBM forecast provided by NOAA.\83\ The NBM forecast did not even
exist in 2015, and has gone through at least four complete iterations
since its introduction in 2016 (from Version 1.0 to Version 4.0).\84\
The Commission noted in Order No. 881 the tendency for weather forecast
accuracy to steadily improve.\85\ As such, statements about weather
forecast accuracy from 2015 are likely to under-report accuracy of
forecasts in 2025 (when implementation of AARs is required).
Furthermore, the Commission in Order No. 881 found that available data
on 10-day ambient air temperature forecast accuracy indicated that such
forecasts were not so inaccurate that they cannot provide any benefits
when used as part of AARs, even when adjusted with appropriate forecast
margins.\86\ Indeed, the Commission found that the reported 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.\87\
---------------------------------------------------------------------------
\81\ MISO Transmission Owners Request for Rehearing at 17 n.53.
\82\ See 18 CFR 385.713(c) (2021).
\83\ Order No. 881, 177 FERC ] 61,179 at P 123.
\84\ See NOAA, National Blend of Models--NBM Versions, <a href="https://vlab.noaa.gov/web/mdl/nbm-versions">https://vlab.noaa.gov/web/mdl/nbm-versions</a> (last visited April 21, 2022).
\85\ Order No. 881, 177 FERC ] 61,179 at P 122.
\86\ Id. P 123.
\87\ Id.
---------------------------------------------------------------------------
35. The Commission also noted that the adoption of a 10-day forward
AAR provided other benefits, beyond any direct benefits of additional
transmission line capacity due to ambient air temperature
considerations. Specifically, the Commission found that the adopted 10-
day threshold would permit weekly point-to-point transmission service
requests to be evaluated using AARs, and would provide additional
benefits in forward nighttime hours where the newly required AARs would
consider the lack of solar heating in those hours.\88\ We continue to
find that these additional benefits will accrue, even in the unlikely
event that the use of AARs 10 days forward results in no hours where
daytime AARs are greater than seasonal line ratings.
---------------------------------------------------------------------------
\88\ Id. PP 121-122.
---------------------------------------------------------------------------
[[Page 31718]]
4. Seasonal Line Rating Floors
a. Final Rule
36. In Order No. 881, the Commission declined to require the use of
a transmission line rating ``floor'' whereby no AAR would fall below
the lowest seasonal line rating. In doing so, the Commission reasoned
that, while seasonal line ratings are generally already calculated to
reflect worst-case weather conditions, to the extent that a
transmission provider experiences extreme temperatures that exceed
seasonal assumptions, the resulting transmission line ratings will be
more accurate than seasonal line ratings and will send important price
signals to market participants. The Commission concluded that, in such
circumstances, transmission providers should be able to plan for such
extreme temperatures given current temperature forecasting
capabilities.\89\
---------------------------------------------------------------------------
\89\ Id. P 125.
---------------------------------------------------------------------------
b. Request for Clarification
37. MISO Transmission Owners request that the Commission clarify
that individual transmission owners and transmission providers may use
a seasonal line rating ``floor'' (which would ensure that no AAR falls
below the lowest seasonal line rating) if they reasonably determine,
consistent with good utility practice, that use of such a floor is
appropriate.\90\ ITC makes a similar request and, to the extent the
Commission denies clarification on this point, ITC seeks rehearing.\91\
---------------------------------------------------------------------------
\90\ MISO Transmission Owners Request for Rehearing at 18.
\91\ ITC Request for Rehearing at 3 n.4, 11.
---------------------------------------------------------------------------
38. MISO Transmission Owners contend that many transmission owners
have developed seasonal line ratings using a combination of assumptions
that include ambient air temperature, wind speed, and other variables,
that take into consideration the relationship between them as each
variable changes. MISO Transmission Owners further suggest that this is
contrary to the Commission's suggestion that transmission owners use
``worst case'' assumptions in their transmission line ratings. MISO
Transmission Owners argue that denying transmission owners the ability
to use a floor when justified would compel transmission owners to use
ratings that are inconsistent with their planning criteria.\92\
---------------------------------------------------------------------------
\92\ MISO Transmission Owners Request for Rehearing at 18-19.
---------------------------------------------------------------------------
39. ITC states that its transmission line ratings do not represent
worst-case conditions but rather use a combination of assumptions that
include ambient air temperature, wind speed, wind direction, and solar
irradiation and that their transmission line ratings take into
consideration the relationship between the variables as each variable
changes. ITC suggests that implementation of AARs across the range of
historically observed temperatures, plus-or-minus a 10-degree margin,
presumes less risk, which could cause divergence in the transmission
line ratings used for planning and operational purposes. ITC contends
that allowing for the use of a seasonal line ratings floor would help
mitigate operational risk and reliability planning risk, which should
be of paramount importance given how infrequently AARs are likely to
exceed the long-term planning assumptions used to establish the lowest
seasonal line rating.\93\
---------------------------------------------------------------------------
\93\ ITC Request for Rehearing at 10.
---------------------------------------------------------------------------
c. Commission Determination
40. We deny the requested clarification and rehearing on this
issue. In Order No. 881, the Commission adopted the AAR requirements in
order to ensure that transmission line ratings are more accurate and,
therefore, that wholesale rates are just and reasonable.\94\ In
contrast, imposing a seasonal line rating floor would fail to produce
transmission line ratings that reflect the actual capabilities of the
transmission lines. A transmission line rating limited by a seasonal
line rating floor could result in wholesale rates that do not
accurately reflect costs and could result in overloaded conductors or
equipment. We recognize that not imposing a seasonal line rating floor
means that there will be times in which transmission line ratings fall
below the seasonal line rating, for example, because extreme weather
events may result in ambient air temperatures above even those used to
calculate the seasonal line ratings. However, in such situations, the
lower AARs as required by this rule would be the more accurate ratings.
The transmission line ratings resulting from a seasonal line rating
floor would be inaccurate and thus would not reflect true system
limitations and could create reliability concerns.
---------------------------------------------------------------------------
\94\ Order No. 881, 177 FERC ] 61,179 at P 83.
---------------------------------------------------------------------------
5. Minimum AAR Temperature Range and AAR Granularity
a. Final Rule
41. In Order No. 881, the Commission required that any methods used
to determine AARs be valid for at least the range of local historical
temperatures (over the entire period for which records are available)
plus-or-minus a margin of 10 degrees Fahrenheit (10-degree margin
requirement). The Commission further required that, where a
transmission provider uses pre-calculated AARs within a look-up table
or similar database, such values must be calculated for all
temperatures within such a valid range. Similarly, where a transmission
provider uses a formula or computer program to calculate AARs based on
forecasted temperatures, such a formula/program must be accurate across
such a valid range. The Commission also required transmission providers
to have procedures in place to handle a situation where forecast
temperatures fall outside of the valid range of temperatures, to ensure
that safe and reliable transmission line ratings are used. The
Commission required transmission providers to revise their look-up
tables or similar databases or formulas/programs in the event that
actual temperatures set new high or low records to maintain the 10-
degree Fahrenheit margin.\95\
---------------------------------------------------------------------------
\95\ Id. P 185.
---------------------------------------------------------------------------
42. The Commission, in Order No. 881, also required transmission
providers to implement AARs that update at least with every five-degree
Fahrenheit increment of temperature change (five-degree requirement),
in order to meet the pro forma OATT Attachment M requirement that an
AAR reflect an up-to-date forecast of ambient air temperature. The
Commission explained that greater temperature increments might
introduce inaccuracies into transmission line ratings, resulting in
wholesale rates that are unjust and unreasonable, and that a minimum
amount of AAR temperature granularity is necessary to ensure that
transmission line ratings sufficiently reflect changes in ambient air
temperatures.\96\
---------------------------------------------------------------------------
\96\ Id. P 187.
---------------------------------------------------------------------------
b. Request for Rehearing
43. MISO Transmission Owners contend that the Commission failed to
satisfy its burden of supporting the five-degree requirement as just
and reasonable and request rehearing on this point. MISO Transmission
Owners state that the specific use of five-degree Fahrenheit increments
was not discussed or proposed in the NOPR, which inhibited parties'
opportunity to comment.\97\
---------------------------------------------------------------------------
\97\ MISO Transmission Owners Request for Rehearing at 11.
---------------------------------------------------------------------------
44. MISO Transmission Owners contend that the Commission's only
evidentiary support for the five-degree requirement is that the
Electric Reliability Council of Texas (ERCOT) uses this increment.
According to MISO
[[Page 31719]]
Transmission Owners, the Commission fails to demonstrate how this
provision might be appropriate in a multi-state region like MISO.\98\
MISO Transmission Owners also argue that the Commission supplied no
evidence to support its conclusion that transmission line rating
increments of greater than five degrees might introduce inaccuracies
into transmission line ratings, resulting in wholesale rates that are
unjust and unreasonable.\99\
---------------------------------------------------------------------------
\98\ Id. at 12.
\99\ Id. at 13.
---------------------------------------------------------------------------
45. MISO Transmission Owners further contend that the Commission
failed to take into account the compliance burdens that the five-degree
requirement will impose, especially when coupled with the 10-degree
margin requirement and the requirement to update AARs hourly for every
hour over the course of a rolling 10-day period.\100\ EEI claims that
requiring entities to use a five-degree Fahrenheit temperature
increment will be a significant and costly effort that will not yield
improvements to the ATC of affected transmission lines.\101\ ITC
asserts that the extensive increase in the volume of transmission line
ratings calculations required by Order No. 881 was not contemplated in
the NOPR \102\ and requests that the Commission provide transmission
owners and transmission providers greater flexibility regarding the
implementation of additional data points to support AAR
calculations.\103\ MISO Transmission Owners and ITC contend that, at
least partially due to the plus-or-minus 10-degree range and five
degree maximum increment requirements, transmission owners will be
required to develop or maintain millions of data points and
transmission line ratings across their systems.\104\ ITC further argues
that the Commission has not shown that the benefits of maintaining
these records or the potential use of this data will outweigh the
associated burdens.\105\ MISO Transmission Owners and ITC contend that,
by failing to take this balancing into account, the Commission's
decision to impose this requirement fails to constitute reasoned
decision-making.\106\
---------------------------------------------------------------------------
\100\ Id.
\101\ EEI Request for Rehearing at 11.
\102\ ITC Request for Rehearing at 6.
\103\ Id. at 7.
\104\ Id. at 8; MISO Transmission Owners Request for Rehearing
at 13.
\105\ ITC Request for Rehearing at 8.
\106\ Id.; MISO Transmission Owners Request for Rehearing at 14.
---------------------------------------------------------------------------
46. MISO Transmission Owners also argue that, because the
Commission acknowledged in Order No. 881 that the mean absolute error
for continental United States surface temperature forecasts was
approximately four to six degrees Fahrenheit in July to November of
2016,\107\ it belies any Commission conclusion that the use of five-
degree increments, which are within this margin of error, is just and
reasonable. MISO Transmission Owners suggest that this demonstrates
that the use of a five-degree increment is likely to produce inaccurate
ATC determinations and that Order No. 881 is internally inconsistent
and contrary to the record.\108\
---------------------------------------------------------------------------
\107\ MISO Transmission Owners Request for Rehearing at 14
(citing Order No. 881, 177 FERC ] 61,179 at P 123).
\108\ Id.
---------------------------------------------------------------------------
47. EEI contends that Order No. 881 fails to consider the
significant weather differences between various regions of the country
and lacks substantial evidence to support the five-degree requirement
when slightly larger increments would have no meaningful impact on
ratings of affected transmission lines.\109\ EEI therefore requests
that the Commission allow flexibility for governing entities to
determine what temperature increments might work best in their
region.\110\ Similarly, MISO Transmission Owners argue that, if the
Commission determines that a temperature increment is necessary, the
Commission should allow transmission owners and transmission providers
to work collaboratively to develop appropriate temperature increments
for AARs that are tailored to their regions, climates, and transmission
systems, consistent with good utility practice and reasonable deference
to engineering judgment.\111\
---------------------------------------------------------------------------
\109\ EEI Request for Rehearing at 11.
\110\ Id. at 11-12.
\111\ MISO Transmission Owners Request for Rehearing at 14-15.
---------------------------------------------------------------------------
c. Commission Determination
48. On rehearing, MISO Transmission Owners, EEI, and ITC argue that
the Commission failed to support the five-degree requirement, to
appropriately balance the burdens of the five-degree requirement
(particularly combined with other requirements adopted in the final
rule) with the benefits, and to consider the considerable weather
differences across the country. For the reasons explained below, we
disagree. We continue to find that the five-degree requirement is just
and reasonable and will result in more accurate transmission line
ratings, and, in turn, just and reasonable wholesale rates, by ensuring
that AARs reflect up-to-date forecasts of ambient air temperatures.
49. As an initial matter, in Order No. 881, the Commission reasoned
that remedying inaccurate transmission line ratings requires a minimum
amount of AAR temperature granularity.\112\ We disagree that the
Commission failed to adequately support its finding that five degrees
is the appropriate increment for such granularity. In its comments,
Vistra Corp. (Vistra) argued that absent some guidance on the maximum
increment of ambient air temperature change beyond which AARs must be
updated, a transmission provider would be able to use temperature
increments so large that it would undermine the Commission's AAR
requirement.\113\ The Commission agreed, explaining that, absent
guidance, some implementations of AARs may not result in an AAR change
despite substantial changes in forecasted temperature and therefore
could not be considered an ``up-to-date forecast of ambient air
temperature.'' \114\
---------------------------------------------------------------------------
\112\ Order No. 881, 177 FERC ] 61,179 at P 187.
\113\ Vistra Comments at 6.
\114\ Order No. 881, 177 FERC ] 61,179 at P 187.
---------------------------------------------------------------------------
50. Having established that a minimum amount of temperature
granularity was needed for the AAR requirements adopted in Order No.
881 to yield just and reasonable wholesale rates, the Commission took
the step of establishing a five-degree Fahrenheit maximum increment--
the five-degree requirement.\115\ The Commission reasoned that an
increment greater than five degrees might introduce inaccuracies into
transmission line ratings that would result in wholesale rates that are
unjust and unreasonable.\116\ The Commission also found that the five-
degree requirement was a necessary corollary of the requirement that an
AAR reflect an up-to-date forecast of ambient air temperature.\117\
---------------------------------------------------------------------------
\115\ Id.
\116\ Id.
\117\ Id.
---------------------------------------------------------------------------
51. Contrary to the claim that the Commission reached this
conclusion without evidence--or based only on the example of ERCOT--the
Commission considered, as reference points, a range of AAR
implementation examples, including PJM, ERCOT, and Entergy Services,
LLC (Entergy). PJM provides updated AARs every nine degrees Fahrenheit;
\118\ ERCOT provides updated AARs every five degrees Fahrenheit; \119\
and Entergy calculates AARs for every one degree Fahrenheit of
temperature change.\120\ Based on this
[[Page 31720]]
record evidence, the Commission adopted a requirement that balances the
need for accuracy, and the benefits thereof, with the burdens imposed
by a more onerous requirement, such as the one Entergy voluntarily uses
for its own AAR calculations. MISO Transmission Owners are correct
that, in adopting the five-degree requirement, the Commission partially
based its finding on ERCOT's experience. But the Commission did so with
good reason: ERCOT has successfully implemented AARs since 2005,\121\
and attests to have benefited considerably from its AAR implementation,
which specifically includes the five-degree increment.\122\ We are not
persuaded by MISO Transmission Owners' claim that because ERCOT is a
single-state transmission operator, the Commission inappropriately
relied on ERCOT's practices to support imposing requirements on RTOs
such as MISO. It is unclear what relevance the number of states within
a transmission provider's territory has on the probative value of its
experience implementing AARs. To the extent the argument is related to
the range of potential temperatures experienced within a transmission
provider's territory, and whether that should justify different AAR
requirements, we address similar assertions below.
---------------------------------------------------------------------------
\118\ Id. P 138.
\119\ Id. P 187.
\120\ September 2019 Technical Conference, Day One Tr. at 157:7-
15.
\121\ Id. at 79:6-10.
\122\ Id. at 80:9-19.
---------------------------------------------------------------------------
52. In addition to basing its findings on actual AAR implementation
by several transmission providers, the Commission relied on statistics
describing the value of transmission line rating changes with each
degree of temperature change. Specifically, the record from the
September 2019 technical conference demonstrates that the difference in
transmission line rating accuracy between the five-degree requirement
adopted in the final rule and larger temperature increments, e.g.,
PJM's nine-degree increment, is meaningful. A change in temperature of
1 degree Celsius (1.8 degrees Fahrenheit) can change transmission
capacity by 1%.\123\ Given the sensitivity of wholesale rates to
changes in transmission line ratings, as the Commission explained in
Order No. 881,\124\ we believe that even a 1% increase in transmission
capacity could present considerable savings for ratepayers. In other
words, the Commission had substantial evidence to support the five-
degree requirement, both from transmission providers' experience
implementing AARs and statistics on the value of additional accuracy of
transmission line ratings.
---------------------------------------------------------------------------
\123\ See id. at 52:4-9 (Hudson Gilmer, Line Vision, Inc.) (The
benefit of AARs is generally ``1% additional capacity for each
degree Celsius of reduced temperature below the static
assumption.''); September 2019 Technical Conference, Speaker
Comments--Jake Gentle (Forecasts for Dynamic Line Rating), Docket
No. AD19-15-000, at slide 14 (Sept. 10, 2019).
\124\ Order No. 881, 177 FERC ] 61,179 at PP 30, 34, 35.
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53. The Commission balanced the evidence of the benefits of this
granularity in AAR calculations with the burdens imposed by increasing
precision. Specifically, the Commission considered record evidence that
AAR implementation will likely be primarily automated and that
implementation costs will primarily be one-time expenses.\125\
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\125\ See Order No. 881, 177 FERC ] 61,179 at PP 94, 125;
September 2019 Technical Conference, Day One Tr. at 154:25-157:15;
September 2019 Technical Conference, Day One Tr. at 142:14-18;
September 2019 Technical Conference, Day Two Tr. at 295:4-7.
---------------------------------------------------------------------------
54. We acknowledge that the AAR requirements, including the five-
degree requirement, will impose implementation costs on every
transmission provider, including those that already implement AARs. But
we sustain the Commission's finding that the benefits of the
requirements adopted in Order No. 881, on balance, outweigh the
burdens. For those transmission providers that already implement AARs,
we note that they will be required to revise their transmission line
rating look-up tables or similar databases to implement AARs as
required by Order No. 881 (including expanding the range of
temperatures included in such look-up tables or similar databases to at
least the range of local historical temperatures plus-or-minus a margin
of 10 degrees Fahrenheit), regardless of whether their temperature
increment is five degrees or another increment. In other words, we find
that the burden of requiring a five-degree temperature increment versus
the burden of requiring a larger than five-degree temperature increment
is likely minimal.
55. In response to MISO Transmission Owners' and ITC's contention
that the five-degree requirement, particularly when combined with the
10-degree temperature margin requirement, imposes an undue data
reporting burden, we disagree. These requirements will materially
affect the size of the look-up tables or similar databases from which
transmission line ratings will be looked-up each hour (for transmission
providers that voluntarily use such look-up tables or similar
databases), but such requirements will not have any effect on the
amount of data that must be stored in the line ratings database under
the adopted recordkeeping requirements. This is because, as discussed
further below, we expect the total data storage in such look-up tables
or similar databases to remain small, that transmission line ratings,
once recalculated to comply with Order No. 881, will change only
infrequently, the expectation that implementation will be automated,
and that there is no requirement for transmission providers to
implement look-up tables at all. Specifically, with respect to the
effect on the size of the look-up tables or similar databases, we
expect that the five-degree requirement and the 10-degree margin
requirement may increase by three to five times the amount of data in
such databases/tables for some transmission providers that currently
use look-up tables or similar databases with narrow temperature ranges
or large temperature step-sizes, but that such databases/tables will
nonetheless continue to store a very small amount of data,\126\ and
that for any particular transmission line such data would usually
remain unchanged for months or years. Given that computers will mainly
generate and interact with such look-up tables or similar databases,
the burden associated with any such increase in the amount of data is
not significant. Furthermore, we reiterate that there is no requirement
that transmission providers implement such look-up tables or similar
databases at all. Transmission providers are free to implement formulas
or computer programs that will compute line ratings, rather than
implementing a line ratings approach that requires looking-up ratings
from a database/table.\127\
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\126\ For example, for a transmission line for which the range
of historically observed local temperatures was -25 to +115 degrees
Fahrenheit, and which had four types of ratings (one normal and
three emergency ratings), a look-up table or similar database would
need to contain at least 264 data points for each transmission line
(33 data points for each of the four rating types, computed for both
daytime and nighttime). For comparison, PJM's current transmission
line rating database computes 64 data points for each transmission
line (eight data points for each of four data types, computed for
both daytime and nighttime). PJM Ratings Information, <a href="https://www.pjm.com/markets-and-operations/etools/oasis/system-information/ratings-information">https://www.pjm.com/markets-and-operations/etools/oasis/system-information/ratings-information</a>.
\127\ Order No. 881, 177 FERC ] 61,179 at P 185.
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56. As for arguments for regional flexibility, we are not persuaded
that significant weather differences across the country justify the use
of different temperature increments for calculating AARs in different
regions. The Commission adopted the five-degree requirement as a
minimum accuracy threshold that the Commission believes--and we
sustain--is necessary to ensure just and reasonable wholesale
[[Page 31721]]
rates. While we agree that certain transmission provider regions, such
as MISO's, cover a large geographic area and may experience
considerable temperature differences as compared to other regions, it
is unclear why these differences should merit different transmission
line rating accuracy requirements. In other words, we have no reason to
conclude that a larger or smaller geographic footprint or wider or
narrower range of temperatures across a year justify treating
transmission providers disparately with regard to the AAR requirements.
57. We also disagree with MISO Transmission Owners' suggestion that
the NOPR gave commenters inadequate notice of the final rule's five-
degree requirement. In the NOPR, the Commission proposed AAR
requirements that would ensure that transmission line ratings ``reflect
an up-to-date forecast of ambient temperature,'' \128\ which reasonably
includes consideration of what minimum degree of granularity might be
required to meet this standard.
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\128\ NOPR, 173 FERC ] 61,165 at P 3 n.3.
---------------------------------------------------------------------------
58. As explained above, different transmission providers that have
voluntarily implemented AARs use look-up tables or similar databases
with different temperature increments as a means of ensuring the AARs
reflect an up-to-date forecast of ambient temperature. In response to
the NOPR, Vistra argued that, absent some guidance on the maximum
increment of ambient air temperature change beyond which AARs must be
updated, a transmission provider would be able to use temperature
increments so large as to undermine the effectiveness of the
Commission's AAR requirements.\129\ In Order No. 881, the Commission
refined its proposal based on stakeholder comments, which is the very
purpose of the notice and comment requirements under the Administrative
Procedures Act.\130\ The courts have made clear that an ``agency `is
not required to adopt a final rule that is identical to the proposed
rule.' On the contrary, `[a]gencies are free--indeed, they are
encouraged--to modify proposed rules as a result of the comments they
receive.' '' \131\ That is exactly what the Commission did. The fact
that commenters in response to the NOPR raised this issue and asked the
Commission to address it reinforces this fact.
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\129\ Vistra Comments at 6-7.
\130\ 5 U.S.C. 553.
\131\ Earthworks v. U.S. Dept. of the Interior, 496 F. Supp. 3d
472, 498-99 (D.D.C. 2020) (quoting Ne. Md. Waste Disposal Auth. v.
EPA, 358 F.3d 936, 951 (D.C. Cir. 2004) (per curiam)); see also id.
(citing Int'l Union, United Mine Workers of Am. v. Mine Safety &
Health Admin., 407 F.3d 1250, 1259 (D.C. Cir. 2005)) (``Public input
is, after all, one of the purposes of the APA's notice-and-comment
scheme.'').
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59. As for MISO Transmission Owners' contention that the mean
absolute error of 10-day temperature forecasts being approximately four
to six degrees suggests that the five-degree requirement is
inappropriate, we find no merit to the argument. The mean absolute
error of a particular forecast and the maximum temperature increment
for updating AARs are wholly separate concepts. The mean absolute error
of a forecast represents the historical average difference between
forecasted value and actual value. By contrast, the maximum temperature
increment for updating AARs represents the maximum temperature degree
change which might occur before necessitating different AAR values. As
such, we find that no inaccuracies or internal inconsistencies are
introduced if a maximum temperature increment is smaller than a
forecast's mean absolute error.
60. We also further clarify the relationship between the five-
degree granularity requirement and the requirement to recalculate AARs
hourly. In Order No. 881, the Commission responded to Vistra's comments
discussed above that, absent certain minimum requirements for the
method to calculate AARs hourly, the Commission's AAR requirements
could be undermined. To address this concern, the Commission clarified
that ``a transmission provider must implement AARs that update at least
with every five-degree Fahrenheit increment of temperature change, in
order to meet the pro forma OATT Attachment M requirement that an AAR
reflect an up-to-date forecast of ambient air temperature,'' \132\
which is the five-degree granularity requirement. The five-degree
granularity requirement does not affect the required timing of a
transmission provider's recalculation of AARs. We reiterate that a
transmission provider must recalculate AARs at least every hour.\133\
When the transmission provider undertakes that hourly calculation, it
must do so using a method that incorporates the five-degree granularity
requirement. That method may be based on a formula or a look-up table
or similar database which contains pre-calculated AARs as a function of
temperature (e.g., from -10 to 110 degrees Fahrenheit). To the extent a
transmission provider uses the latter method such look-up table or
similar database must have no more than five degrees between
temperature ``steps.''
---------------------------------------------------------------------------
\132\ Order No. 881, 177 FERC ] 61,179 at P 187.
\133\ Id. PP 47, 162.
---------------------------------------------------------------------------
6. Solar Heating in AAR Calculations
a. Final Rule
61. Order No. 881 requires transmission providers to incorporate
solar heating into AARs by implementing separate AARs for daytime and
nighttime periods.\134\ It further requires transmission providers to
update the sunrise and sunset times used to calculate their AARs at
least monthly, if not more frequently.\135\ The Commission found that
this requirement will produce benefits in forward nighttime hours that
would not be realized if the AAR requirements were imposed over a
timeframe shorter than 10 days forward and that the accuracy benefits
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.\136\
---------------------------------------------------------------------------
\134\ Id. P 147.
\135\ Id. P 149.
\136\ Id. P 122.
---------------------------------------------------------------------------
b. Requests for Rehearing
62. Both EEI and ITC request rehearing on the daytime/nighttime
ratings requirement and argue that this requirement constitutes a
substantial departure from the proposal contained in the NOPR. EEI
asserts that the scope of benefits that flow from this daytime/
nighttime ratings requirement is unclear, particularly given that
transmission providers will still rely on industry standards to
maintain compliance.\137\ ITC adds that the Commission did not
demonstrate that any potential market efficiencies that flow from this
and other requirements outweigh the burden on transmission owners to
gather the significant amount of data required to calculate AARs for
the average system.\138\
---------------------------------------------------------------------------
\137\ EEI Request for Rehearing at 10.
\138\ ITC Request for Rehearing at 5.
---------------------------------------------------------------------------
c. Commission Determination
63. We sustain the result of Order No. 881 regarding the
Commission's requirement that transmission providers incorporate solar
heating into AARs by implementing separate AARs for daytime and
nighttime periods, and to update the sunrise and sunset times used to
calculate their AARs at least monthly, if not more frequently (daytime/
nighttime ratings requirement).
64. In Order No. 881, the Commission required implementation of
daytime/nighttime ratings based on evidence in the record that such a
requirement
[[Page 31722]]
would enhance the accuracy of transmission line ratings, and therefore
result in just and reasonable wholesale rates.\139\ None of the
arguments contained in the requests for rehearing persuade us to alter
that view.
---------------------------------------------------------------------------
\139\ For example, the Commission cited to comments from R
Street Institute, Pacific Gas and Electric (PG&E), Indicated PJM
Transmission Owners, Dominion Energy Services, Inc. (Dominion),
Potomac Economics, and Vistra. Order No. 881, 177 FERC ] 61,179 at
PP 147-48.
---------------------------------------------------------------------------
65. In response to the NOPR, several commenters supported
incorporating predictable daytime/nighttime ratings into AARs.\140\ As
the Commission explained in Order No. 881, solar heating is an
important input consideration for calculating thermal transmission line
ratings.\141\ By removing solar heating assumptions from transmission
line ratings during nighttime periods, transmission providers increase
the accuracy of transmission line ratings and thereby enable wholesale
rates to better reflect the true cost to serve load. According to
several commenters, incorporating daytime/nighttime ratings, subject to
the exceptions adopted in Order No. 881,\142\ will provide important
increases in transfer capability. This, in turn, will lower wholesale
rates. Specifically, commenters explained that daytime/nighttime
ratings would, on average, increase nighttime transfer capability by
anywhere from 5% to 14%.\143\ Potomac Economics found that such
transfer capability increase would decrease wholesale rates in MISO by
approximately $30 million per year.\144\ Importantly, such increases in
transfer capability due to calculating transmission line ratings for
nighttime periods can support operators during potentially challenging
intervals, such as before sunrise during the morning ramp or after
sunset during the evening ramp. Contrary to EEI's assertions, this
evidence demonstrates the significant economic benefits of the daytime/
nighttime ratings requirement.
---------------------------------------------------------------------------
\140\ R Street Institute Comments at 3; PG&E Comments at 11-12;
Indicated PJM Transmission Owner Comments at 8-9; Dominion Comments
at 8; Potomac Economics Comments at 14-15; Vistra Comments at 4-5.
\141\ Order No. 881, 177 FERC ] 61,179 at PP 147-149; PG&E
Comments at 11-12; Vistra Comments at 4-5; Potomac Economics
Comments at 15.
\142\ Order No. 881, 177 FERC ] 61,179 at PP 227-28.
\143\ PG&E Comments at 11; Entergy Comments at 8; Potomac
Economics Comments at 15.
\144\ Potomac Economics Comments at 15.
---------------------------------------------------------------------------
66. Further, we continue to find that the daytime/nighttime
requirement can yield these benefits at minimal cost,\145\ contrary to
ITC's contention. Incorporating daytime/nighttime ratings into AAR
calculations can be done at minimal costs, as explained by several
commenters.\146\ As noted earlier, we expect the costs to implement
daytime/nighttime ratings to primarily be one-time automation costs.
Once automated, we do not expect the addition of daytime/nighttime
ratings to materially increase the cost and complexity of implementing
the AAR requirements.
---------------------------------------------------------------------------
\145\ Order No. 881, 177 FERC ] 61,179 at P 148.
\146\ Potomac Economics Comments at 15; Vistra Comments at 4-5.
---------------------------------------------------------------------------
67. Finally, we disagree that stakeholders lacked adequate notice.
In the NOPR, the Commission noted that AARs could incorporate other
forecasted inputs and, as an example, pointed to PJM's implementation
of ``day and night ambient air temperature tables, where the night
ambient air temperature table assumes zero solar irradiance.'' \147\
Further, the Commission sought comment on whether to require the
implementation of dynamic line ratings,\148\ which the Commission
expressly defined as a transmission line rating that reflects inputs
including solar irradiance forecasts and of which daytime/nighttime
ratings are the most basic and obvious example.\149\ Moreover, the
objective of the NOPR--and the final rule--was to improve the accuracy
of transmission line ratings, with solar irradiance forecasts
repeatedly discussed as one tool for doing so, including multiple
mentions of PJM's use of daytime/nighttime AARs.\150\ Finally, several
commenters in response to the NOPR either noted the benefits of, or
voiced support for, incorporating predictable daytime/nighttime solar
irradiance forecasts into AARs.\151\
---------------------------------------------------------------------------
\147\ Order No. 881, 177 FERC ] 61,179 at P 144 (citing NOPR,
173 FERC ] 61,165 at P 23).
\148\ NOPR, 173 FERC ] 61,165 at P 100.
\149\ Id. P 5 n.5.
\150\ Id. P 23 n.40.
\151\ See, e.g., Small Refiner Lead Phase-Down Task Force v.
EPA, 705 F.2d 506, 549 (D.C. Cir. 1983) (finding that a final
provision is permitted if an entity participating in a rulemaking
``ex ante, should have anticipated that such a requirement might be
imposed.'').
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B. Seasonal Line Ratings--Annual Recalculation Requirement
1. Final Rule
68. In Order No. 881, the Commission required that seasonal line
ratings be calculated at least annually, if not more frequently.\152\
While the NOPR proposed requiring seasonal line ratings to be updated
on a monthly basis, the final rule revised that requirement in response
to stakeholder comments. Specifically, the Commission acknowledged that
calculating monthly updates to seasonal line ratings would be
burdensome and that the weather assumptions underlying seasonal line
ratings are unlikely to change on a month-to-month basis.\153\
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\152\ Order No. 881, 177 FERC ] 61,179 at P 215.
\153\ Id.
---------------------------------------------------------------------------
2. Request for Rehearing
69. ITC seeks rehearing of the annual update requirement for
seasonal line ratings; it requests greater flexibility for transmission
owners and transmission providers to update seasonal line ratings as
warranted, consistent with good utility practice.\154\ ITC asserts that
it used recognized industry technical standards to support a multi-year
study of its transmission system, which included the collection and
analysis of a number of different data sets related to weather,
temperature, conductor parameters, and historical inputs, among other
things. ITC contends that its use of a multi-year study increases the
accuracy of seasonal line ratings and meets the intent of Order No.
881.\155\
---------------------------------------------------------------------------
\154\ ITC Request for Rehearing at 9.
\155\ Id.
---------------------------------------------------------------------------
70. ITC also claims that there is no technical or market-driven
justification to require ITC to update its seasonal line ratings
annually. Rather, ITC contends that, given its reliance on its multi-
year study, it would not be possible for ITC to update its seasonal
line ratings annually and that this provision would result in a
continuous weather study operation that would be burdensome and
unnecessary. Finally, because transmission planning processes partially
rely on seasonal line ratings, ITC asserts that changing these ratings
on an annual basis would unnecessarily inject complexity and
uncertainty into the multi-year transmission planning processes.\156\
---------------------------------------------------------------------------
\156\ Id.
---------------------------------------------------------------------------
3. Commission Determination
71. Regarding ITC's request for rehearing on the annual update
requirement for seasonal line ratings, we sustain the result in Order
No. 881. We disagree with ITC that there is no justification for the
annual update requirement for seasonal line ratings. On the contrary,
transmission system conditions, including relevant climate and weather
data, are frequently changing, especially as extreme weather events are
increasing in frequency and duration.\157\ To the extent that a
[[Page 31723]]
transmission provider continues to implement seasonal line ratings for
years without reviewing and updating those ratings, transmission system
conditions are likely to have changed to such a degree as to render the
ratings inaccurate and associated wholesale rates unjust and
unreasonable. As the Commission stated in Order No. 881, seasonal line
ratings, once established, should be reviewed when equipment changes
are made, climate or weather data necessitates, or when otherwise
prudent.\158\ While the Commission proposed in the NOPR to require such
recalculations on a monthly basis, the Commission concluded in Order
No. 881 that an annual update requirement for seasonal line ratings
strikes an appropriate balance between ensuring accurate seasonal line
ratings as weather patterns continue to change and the costs associated
with updating such transmission line ratings on a regular basis.\159\
We continue to believe that the Commission struck the proper balance.
---------------------------------------------------------------------------
\157\ Order No. 881, 177 FERC ] 61,179 at P 215 (citing ACPA/
SEIA Comments at 8, 11; EPSA Comments at 4; New England State
Agencies Comments at 6); NOAA, National Centers for Environmental
Information, U.S. Billion-Dollar Weather and Climate Disasters
(2021), <a href="https://www.ncdc.noaa.gov/billions/">https://www.ncdc.noaa.gov/billions/</a>; Quadrennial Energy
Review, Transforming the Nation's Electricity System: The Second
Installment of the QER, at 4-2 (Jan. 2017).
\158\ Order No. 881, 177 FERC ] 61,179 at P 215; MISO Comments
at 21.
\159\ Order No. 881, 177 FERC ] 61,179 at P 215.
---------------------------------------------------------------------------
72. Nevertheless, we clarify that the Commission did not prescribe
the procedure for recalculating seasonal line ratings, including
determining which inputs have changed in a year. For instance, a
transmission provider could comply with the annual update requirement
for seasonal line ratings by recalculating its seasonal line ratings
annually to adjust seasonable temperature assumptions, but then also
perform a more detailed recalculation every few years using multi-year
temperature data to consider temperature patterns that are harder to
identify with only a single year of new temperature data.
73. Moreover, we clarify that the requirement to engage in an
annual recalculation does not require transmission owners to undertake
unnecessary change from year to year. To the extent that relevant
inputs have not changed from one year to the next, the annual
recalculation may simply result in continuing to use transmission
owner's existing facility ratings.
C. Transparency
1. Data Sharing Burden
a. Final Rule
74. In Order No. 881, the Commission required each transmission
provider to maintain a database of its transmission line ratings and
methodologies on the transmission provider's OASIS site or other
password-protected website.\160\ The Commission required that this
database be in such a form that can be accessed by all parties with
OASIS access or access to the password-protected website. The
Commission stated that the database should archive and allow for
querying of all current transmission line ratings and all transmission
line ratings used in the past five years.\161\
---------------------------------------------------------------------------
\160\ Id. P 330.
\161\ Id.
---------------------------------------------------------------------------
75. The Commission further required that transmission line ratings
stored in the required database must include a full record of all
transmission line ratings, both as used in real-time operations, and as
used for all future market periods for which transmission service is
offered.\162\ The Commission provided a specific example of the
implications of the final rule for data storage requirements. Further,
while the Commission did not require implementation of DLRs when
issuing Order No. 881, it noted that if a transmission provider
implements DLRs on any of its transmission lines, then under this
requirement it would document the DLRs on such transmission lines in
the same way that it documents its AARs. The Commission noted that
transmission providers may determine that a variety of approaches to
storing this data may be acceptable as long as users of the database
can readily identify which such ratings (including for the operational
hour and any forward hours) were in effect for which transmission lines
at which times.\163\ The Commission did not specify exactly how records
of seasonal or static line ratings should be stored in the transmission
line rating database. However, the Commission explained that such
longer-term transmission line ratings do not necessarily need to be
stored on an hourly basis, so long as users of the database can readily
identify which ratings were in effect for which transmission lines at
which times. The Commission noted that some transmission lines may not
have any AARs at all, where permitted under pro forma OATT Attachment
M, and so may only have ratings such as seasonal or static line
ratings.\164\
---------------------------------------------------------------------------
\162\ Id. P 339.
\163\ Id. P 339 n.819.
\164\ Id. P 339 n.820.
---------------------------------------------------------------------------
b. Requests for Rehearing
76. EEI and ITC request rehearing of the data requirements of Order
No. 881. EEI argues that the Commission erred in requiring transmission
owners to store in the required database a full record of all
transmission line ratings, both as used in real-time operations and as
used for all future market periods for which transmission service is
offered, without a showing of substantial need.\165\ ITC similarly
asserts that the Commission erred by requiring transmission owners to
comply with unduly burdensome data storage and maintenance
requirements.\166\
---------------------------------------------------------------------------
\165\ EEI Request for Rehearing at 3.
\166\ ITC Request for Rehearing at 5.
---------------------------------------------------------------------------
77. EEI and ITC allege that the data requirements impose a
significant burden on transmission owners for which the Commission has
failed to articulate corresponding and substantially greater
benefits.\167\ EEI reports that one member utility estimates that it
will send several million transmission line ratings per hour to its
transmission provider.\168\ ITC calculates that implementing Order No.
881's requirements on its own transmission system would result in 3.4
million ratings calculated and stored every hour and that the total
number of ratings calculated and stored would ``quickly become
astronomical.'' \169\ EEI notes that even its member utilities who have
been using AARs for years do not maintain the kind of data required by
Order No. 881.\170\ Rather, EEI states that member utilities using AARs
commonly embed algorithms into the transmission owner's EMS that allow
power flow analyses to make use of AAR curves for each circuit. EEI
also contends that the volume of data required is a significant
departure from the NOPR and significantly more burdensome.\171\ EEI
alleges that ``[t]he requirements in the Final Rule are significantly
more burdensome than providing data upon request'' and that the
Commission's decision to impose such requirements is ``arbitrary and
capricious.'' \172\
---------------------------------------------------------------------------
\167\ Id. at 8; EEI Request for Rehearing at 10.
\168\ EEI Request for Rehearing at 9-10.
\169\ ITC Request for Rehearing at 8.
\170\ EEI Request for Rehearing at 10-11.
\171\ Id. at 9-11.
\172\ Id. at 11.
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c. Commission Determination
78. In response to requests for rehearing regarding the data
storage and sharing requirements of Order No. 881, we continue to find
that the benefits outweigh the burdens and that these requirements will
help ensure just and reasonable wholesale rates. As the Commission
found in Order No. 881, making transmission line ratings and
methodologies available to a broader range of stakeholders will amplify
the expected benefits of the proposal included in the NOPR, further
facilitate more accurate transmission line ratings,
[[Page 31724]]
and facilitate more cost-effective decisions by market participants and
state agencies.\173\ For example, these requirements will help
potential interconnection customers more easily identify optimal
interconnection locations and understand or reproduce congestion
analyses.\174\ These requirements will also enable transmission
customers to better understand what is driving the prices that they are
required to pay.\175\ In addition, as noted in Order No. 881,\176\
transparency with transmission line ratings and methodologies will be
particularly beneficial to wholesale market participants trying to
manage uncertainty. With respect to FTR market participants, for
example, because FTR payouts are based on congestion costs that change
with transmission line ratings, sharing transmission line ratings and
methodologies with a wider range of stakeholders will help establish
efficient FTR market price discovery by improving FTR market
participants' understanding of certain drivers of congestion, and allow
such market participants to build such understanding into their FTR
bids and offers.\177\ Commenters also suggest that these requirements
may assist transmission providers in considering public policy driven
transmission needs as part of their regional transmission planning
processes.\178\ We reiterate the Commission's finding in Order No. 881
that the benefits of increased transparency, such as those just
described, are likely to outweigh the burden on transmission
providers.\179\
---------------------------------------------------------------------------
\173\ Order No. 881, 177 FERC ] 61,179 at P 336.
\174\ See, e.g., ACPA/SEIA Comments at 18-20.
\175\ See, e.g., TAPS Comments at 24.
\176\ Order No. 881, 177 FERC ] 61,179 at P 337.
\177\ DC Energy Comments at 3. While different RTOs/ISOs have
different names for these financial products, such as financial
transmission rights, transmission congestion rights, congestion
revenue rights, etc., for simplicity here we will use FTRs to refer
to any such financial product in the RTOs/ISOs.
\178\ See, e.g., New England State Agencies Comments at 20.
\179\ Order No. 881, 177 FERC ] 61,179 at P 336.
---------------------------------------------------------------------------
79. We also find that these requirements reasonably follow from the
NOPR, which proposed to require transmission owners to share
transmission line ratings for each period for which transmission line
ratings are calculated and emphasized the value of such transparency to
verify the resulting transmission line ratings and to identify
potential errors.\180\ The NOPR then explicitly sought comment on
``whether to require transmission owners to make their transmission
line ratings and rating methodologies available to other interested
stakeholders, including posting information on their OASIS pages or
other password protected online forum.'' \181\ Commenters extensively
discussed the benefits and burdens of the proposed transparency
requirements, including responding to this request for comment.\182\ In
addition to the explicit language in the NOPR, storing transmission
line ratings and methodologies on OASIS or a similar website should be
an expected means of achieving the data-sharing contemplated by the
NOPR. In fact, the Commission has similarly required the use of OASIS
or a similar website to ensure transparency in other contexts.\183\
---------------------------------------------------------------------------
\180\ NOPR, 173 FERC ] 61,165 at PP 125-130.
\181\ Id. P 129.
\182\ See Order No. 881, 177 FERC ] 61,179 at PP 316-320, 336-
340 (summarizing relevant comments).
\183\ See, e.g., Reform of Generator Interconnection Procedures
and Agreements, Order No. 845, 83 FR 21342 (May 9, 2018), 163 FERC ]
61,043 at PP 236-238 (2018), errata notice, 167 FERC ] 61,123, order
on reh'g, Order No. 845-A, 84 FR 8156 (Mar. 6, 2019), 166 FERC ]
61,137 (2019), errata notice, 167 FERC ] 61,124, order on reh'g,
Order No. 845-B, 168 FERC ] 61,092 (2019).
---------------------------------------------------------------------------
80. Further, we continue to find that Order No. 881's requirements
follow from existing regulations surrounding transmission line rating
data sharing and retention. As noted in Order No. 881,\184\ the
requirement that transmission providers must archive the data for five
years of history follows reasonably from the Commission's regulations
for document retention periods that apply to OASIS postings.\185\ In
addition, as noted in Order No. 881,\186\ Sec. 37.6 of the
Commission's regulations already requires transmission providers, upon
customer request, to make all data used to calculate ATC for any
constrained posted path publicly available on OASIS. This includes the
limiting elements and the cause of the limit (e.g., thermal, voltage,
stability), as well as load forecast assumptions.\187\ Similarly, Sec.
37.7of the Commission's regulations also requires historical data to be
available for 90 days or, upon request, five years. We note again that
the durations for document retention in Order No. 881 are consistent
with these existing requirements.
---------------------------------------------------------------------------
\184\ Order No. 881, 177 FERC ] 61,179 at P 340.
\185\ 18 CFR 37.7 (2021) (Information to be posted on the
OASIS).
\186\ Order No. 881, 177 FERC ] 61,179 at P 338.
\187\ See 18 CFR 37.6 (2021).
---------------------------------------------------------------------------
81. Finally, we also find unpersuasive arguments that the
transparency requirements are unduly burdensome. In response to
comments that the total number of transmission line ratings required to
be stored would ``quickly become astronomical,'' \188\ we find the
implementation and operation of a database of this type to be well
within the normal business scope of a data-intensive entity like a
transmission provider. For example, the 3.4 million transmission line
rating records that ITC explains it would have to calculate and store
every hour would total only about 1.8 terabytes over the entire five-
year line rating retention period required in Order No. 881,\189\
although the overall storage requirements would be several times that,
considering memory for back-ups and data management. As a pure matter
of quantity of data stored (i.e., ``hard drive size''), this is a de
minimis amount of storage. We note that ITC might be arguing that this
is a significant number of individual records to store, even if they
require a small data storage footprint. While we recognize that there
will be significant numbers of line rating records, we have also
explained that we expect that transmission providers will use automated
processes to calculate these line ratings,\190\ and we similarly expect
that transmission providers will use automated processes to populate
the ratings databases. As such, we disagree that the storage of the
line rating data will have a meaningful burden.
---------------------------------------------------------------------------
\188\ ITC Request for Rehearing at 8.
\189\ We estimated this storage space requirement based on the
following assumptions: First, we assume that the 3.4 million hourly
line ratings reflect each of the 240 forecasted line ratings for
each of the relevant transmission lines and transmission line rating
types (normal and emergency), as required by Order No. 881. Second,
we assume the rating records are stored in a table with each row
having line ID, rating day and hour, rating type, 240 forecast
ratings and 240 forecast hours, and 2 extra variable character
columns in case of other information requirements. Thereby, the 3.4
million hourly line ratings is reduced to 14,167 hourly records
(that is, (3.4 million hourly line ratings)/(240 forecasted
ratings)). The hourly storage requirements are then estimated to be
41 megabytes/hour. That is, (2,998 bytes per row) * (14,167 rows/
hour)/(1,048,576 bytes/megabyte). We estimate the bytes per row to
be 2,998 bytes as follows: (8 bytes for line ID) + (8 bytes for
rating day and hour) + (2 bytes for rating type) + (4 bytes per
forecast rating * 240 forecast ratings) + (8 bytes per forecast
rating hour * 240 forecast hours) + (50 bytes each for the 2
variable character columns). The entire five years of transmission
line ratings data that are required to be stored is then calculated
as (41 megabytes/hour) * (24 hours/day) * (365 days/year) * (5
years)/(1,000,000 megabytes/terabyte) = 1.8 terabytes.
\190\ Order No. 881, 177 FERC ] 61,179 at PP 125, 149, 163, 169,
362.
---------------------------------------------------------------------------
2. OASIS Access
a. Final Rule
82. In Order No. 881, the Commission required each transmission
provider to maintain a database of its transmission owners'
transmission line ratings and methodologies on the password-protected
section of the transmission provider's OASIS site or other
[[Page 31725]]
password-protected website. The Commission found that allowing other
entities (beyond transmission providers and market monitors) to access
the password-protected section of the transmission provider's OASIS
site or other password-protected website containing the database of
transmission line ratings and methodologies will further facilitate
more accurate transmission line ratings and more cost-effective
decisions by market participants.\191\
---------------------------------------------------------------------------
\191\ Id. P 336.
---------------------------------------------------------------------------
b. Request for Clarification
83. EEI requests that the Commission clarify that those seeking to
access the data on their OASIS site be required to show a ``business
need'' for the information.\192\ EEI further suggests that the
requirements in Order No. 881 might not be sufficient to maintain
confidentiality.\193\ EEI characterizes the requirements of Order No.
881 as mandating that transmission owners share information on their
transmission line rating methodology with market participants that may
not have signed non-disclosure agreements, which EEI claims
significantly deviates from past practice and infringes on the rights
of transmission providers to rate their own equipment. EEI requests
that the Commission clarify that the transmission owner may limit
access to those with a business need and may require execution of non-
disclosure agreements prior to accessing the information.\194\
---------------------------------------------------------------------------
\192\ EEI Request for Rehearing at 4.
\193\ Id. at 15.
\194\ Id.
---------------------------------------------------------------------------
84. EEI also requests that the Commission clarify that the data
might be subject to protections for Critical Energy Infrastructure
Information (CEII). EEI claims that the use of AARs will, in many
instances, establish the maximum limiting factor for transmission lines
and that such information might be argued to constitute CEII.\195\
---------------------------------------------------------------------------
\195\ Id.
---------------------------------------------------------------------------
c. Commission Determination
85. As a preliminary matter, we clarify that, contrary to
statements in EEI's request for clarification,\196\ Order No. 881
requires transmission providers to post transmission line ratings and
methodologies-related data to a password-protected section of their
OASIS site or another password-protected website. Therefore,
transmission providers have the discretion to post the required data to
their OASIS site or an alternative password-protected website. We note,
however, that the data posted to either a transmission provider's
website or OASIS must be maintained such that users can view, download,
and query data in standard formats, using standard protocols.\197\ If
the transmission provider chooses to post the data to its own website
instead of OASIS, we clarify that users must be able to access the data
in a manner that is comparable to if it were posted to OASIS and
subject to OASIS access requirements.\198\
---------------------------------------------------------------------------
\196\ Id.
\197\ See 18 CFR 35.28(b)(12); Pro Forma OATT, attach. M, AAR
Definition; see also Pro Forma OATT, attach. M, Obligations of the
Transmission Provider (``Postings to OASIS or another password-
protected website: The Transmission Provider must maintain on the
password-protected section of its OASIS page or on another password-
protected website a database of Transmission Line Ratings and
Transmission Line Rating methodologies. . . . The database must be
maintained such that users can view, download, and query data in
standard formats, using standard protocols.'').
\198\ Open Access Same-Time Information System and Standards of
Conduct, Order No. 889, 61 FR 21737 (May 10, 1996), FERC Stats. &
Regs. ] 31,035, at attach. Sec. V.3 ``Information Access
Requirements (1996) (cross-referenced at 75 FERC ] 61,078), order on
reh'g, Order No. 889-A, 61 FR 21737 (Mar. 14, 1997), FERC Stats &
Regs. ] 31,049 (cross-referenced at 78 FERC ] 61,221), reh'g denied,
Order No. 889-B, 81 FERC ] 61,253 (1997), aff'd in relevant part sub
nom. Transmission Access Policy Study Grp. v. FERC, 225 F.3d 667 (DC
Cir. 2000).
---------------------------------------------------------------------------
86. Consistent with these clarifications, we decline to establish
further requirements regarding access to OASIS or to a password-
protected website the transmission provider uses for compliance with
Order No. 881 that would require demonstration of a business need or
signing of a non-disclosure agreement. EEI has not explained why
transmission providers should be able to restrict access to
transmission line ratings and methodology data only to parties who have
a ``business need'' and have executed a non-disclosure agreement. EEI's
support for such restrictions is only a vague assertion that Order No.
881's requirements might not ``be sufficient to maintain
confidentiality.'' \199\ We find this vague assertion inadequate for
imposing the restrictions EEI describes, particularly since accessing
much of the other transmission-related information on OASIS requires no
such demonstration or signing of a non-disclosure agreement under the
Commission's rules governing OASIS.
---------------------------------------------------------------------------
\199\ EEI Comments at 15.
---------------------------------------------------------------------------
87. Conversely, we find that avoiding such restrictions maintains
the benefits of transparency into transmission line ratings and
methodologies that the Commission articulated in Order No. 881 and
elsewhere in this order. In other words, we are not persuaded that any
confidentiality benefits that would come from allowing the kind of
restrictions EEI requests would outweigh the loss of transparency
benefits gained by the Commission's requirements. Thus, we uphold Order
No. 881's finding that requiring transmission line ratings and
methodologies to be shared via OASIS or other password-protected
website creates a measure of transparency needed to ensure just and
reasonable wholesale rates.\200\
---------------------------------------------------------------------------
\200\ See, e.g., Order No. 881, 177 FERC ] 61,179 at PP 11
(finding that the transparency reforms adopted in Order No. 881
``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''), 39 (finding existing wholesale rates
unjust and unreasonable due to lack of transparency, specifically
the failure to ``provide market participants information important
to making cost-effective decisions'' and the possibility for
``transmission owners to submit inaccurate near-term transmission
line ratings'' that ``do not accurately reflect the cost of the
wholesale service being provided'').
---------------------------------------------------------------------------
88. We deny EEI's request for clarification that transmission line
ratings and methodologies constitute CEII, and clarify that Order No.
881 did not revise the Commission's existing CEII requirements.\201\
The Commission's CEII regulations govern only ``the procedures for
submitting, designating, handling, sharing, and disseminating [CEII]
submitted to or generated by the Commission.'' \202\ Because the
transmission line ratings and methodologies are neither generated by
the Commission nor filed with the Commission--either under current
rules or under the requirements of Order No. 881--such information
would not be considered CEII under the Commission's CEII regulations.
---------------------------------------------------------------------------
\201\ Under the Commission's CEII regulations, an entity may
submit information to the Commission requesting that it be treated
as CEII. 18 CFR 388.113 (2021).
\202\ Id. (emphasis added).
---------------------------------------------------------------------------
3. The Role of Independent Market Monitors
a. Final Rule
89. In Order No. 881, the Commission required transmission owners
to share their transmission line ratings for each period for which they
are calculated and transmission line rating methodologies with their
transmission providers and with market monitors in RTOs/ISOs.\203\ The
Commission found that requiring transmission owners to share
transmission line ratings and methodologies with their transmission
providers and, in RTOs/ISOs, market monitors, will help remedy unjust
and unreasonable wholesale rates caused by
[[Page 31726]]
inaccurate transmission line ratings.\204\ The Commission reiterated
that it will continue to conduct reviews of transmission line ratings
as a component of broader tariff compliance audits and that Order No.
881 does not change the auditing requirements or authorities of any
entity.\205\ The Commission noted that many commenters used the term
``audit'' to describe activities by market monitors and other entities
that the Commission's rules do not define as auditing and noted that
the Commission retains its authority to formally audit for compliance
with OATTs and other Commission-jurisdictional rules.\206\
---------------------------------------------------------------------------
\203\ Order No. 881, 177 FERC ] 61,179 at P 330.
\204\ Id. P 331.
\205\ Id. P 334.
\206\ Id. P 334 n.813.
---------------------------------------------------------------------------
b. Request for Clarification
90. EEI requests that the Commission clarify that the role of the
independent market monitor is not to ``second guess'' the information
provided by the transmission provider.\207\ EEI requests clarification
that any review of transmission line ratings and/or methodologies does
not expand the market monitor's audit authority over this information
provided by the transmission owner.\208\ EEI requests clarification
that the market monitor's role is limited to ``verifying the accurate
mechanical implementation of transmission line ratings calculations
(e.g., detecting corrupt data) and not related to the line ratings
formulations or inputs thereto.'' \209\ EEI claims that the role of
market monitors is to identify noncompetitive outcomes resulting from
market power or manipulative behavior. EEI argues that the market
monitor should be independent of interests in market outcomes, should
not interfere with market participants' management of their assets, and
should not interfere with RTOs/ISOs' and transmission owners'
operations of the bulk electric system.\210\ EEI requests that the
Commission clarify that the market monitor has no audit or enforcement
authority related to the use of transmission line ratings and any
impacts on reliable operations or market outcomes.\211\
---------------------------------------------------------------------------
\207\ EEI Request for Rehearing at 3.
\208\ Id. at 14.
\209\ Id.
\210\ Id.
\211\ Id. at 14-15.
---------------------------------------------------------------------------
c. Commission Determination
91. We grant EEI's request for clarification in part and deny in
part. We clarify that nothing in Order No. 881 changes or expands the
role or authority of market monitors or the auditing responsibilities
of any entity.\212\ However, we deny EEI's request for clarification on
other matters. We expect that market monitors may use the transmission
line rating information available to them in furtherance of their
existing responsibilities, which are set forth in the Commission's
regulations and the relevant tariffs of each RTO/ISO.\213\
---------------------------------------------------------------------------
\212\ Order No. 881, 177 FERC ] 61,179 at PP 333-34.
\213\ 18 CFR 35.28(g)(3).
---------------------------------------------------------------------------
D. Compliance
1. Final Rule
92. In Order No. 881, the Commission adopted a modified
implementation schedule from that proposed in the NOPR. In particular,
in the NOPR, the Commission proposed requiring AAR implementation on
congested transmission lines within one year from the date of the
compliance filing and, for all other transmission lines, implementation
within two years from the date of the compliance filing.\214\ In the
final rule, the Commission required implementation of the requirements
adopted in Order No. 881 no later than three years from the compliance
filing due date. Based on comments submitted in response to the NOPR,
\215\ the Commission found that three years is consistent with the
implementation schedule most commonly suggested by transmission owners
for AAR implementation on priority transmission lines, and that three
years should be sufficient time for transmission owners and
transmission providers to implement changes to their processes and
systems to comply with the requirements of Order No 881.\216\
---------------------------------------------------------------------------
\214\ NOPR, 173 FERC ] 61,165 at P 81.
\215\ Order No. 881, 177 FERC ] 61,179 at P 361 n.870.
\216\ Id. PP 360-361.
---------------------------------------------------------------------------
2. Request for Rehearing
93. EEI seeks rehearing, arguing that the implementation schedule
set forth in Order No. 881 was made without any evaluation of the
number and types of transmission lines that would be implicated by the
final rule.\217\ EEI claims that, while some commenters may have opined
that three years would be a sufficient amount of time to implement
AARs, these comments were based on the NOPR proposal that would have
required that AARs be implemented on historically congested
transmission lines, not on all transmission lines.\218\ EEI argues that
the three-year implementation period does not consider the substantial
increase in the number of transmission line ratings that the final rule
requires transmission providers to compute as compared to the NOPR. In
addition, EEI argues that the implementation timeframe does not
consider or provide information on whether third-party vendors have the
database infrastructure or the ability to develop the database
infrastructure necessary to support the data requirements in the final
rule. EEI contends that a longer implementation period would provide
additional time for coordination, which would benefit transmission
owners that have facilities in multiple states.\219\
---------------------------------------------------------------------------
\217\ EEI Request for Rehearing at 7-8.
\218\ Id. at 8.
\219\ Id.
---------------------------------------------------------------------------
94. Potomac Economics also requests rehearing, but argues that the
Commission should require implementation of AARs and emergency ratings
as soon as practicable rather than permitting transmission providers
and transmission owners to wait three years to comply with these
requirements.\220\ Specifically, Potomac Economics contends that the
Commission made a well-reasoned finding that failing to adjust
transmission line ratings for changes in ambient air temperature and
failing to utilize emergency ratings can lead to wholesale rates that
are unjust and unreasonable, and should only be done if it were
infeasible to require AARs more quickly than the three-year deadline
established in the final rule. In particular, Potomac Economics
requests that the Commission modify its proposed implementation
schedule to require that AARs be implemented within one year of the
final rule on a designated number of the most congested constraints
that are not currently being adjusted.\221\
---------------------------------------------------------------------------
\220\ Potomac Economics Request for Rehearing at 5.
\221\ Id. at 6-7.
---------------------------------------------------------------------------
95. Potomac Economics also requests rehearing of the Commission's
determination to require the use of emergency ratings on the same
implementation timeframe as AARs. Potomac Economics states that, while
there may be ``challenges'' for resources required to implement AARs,
this is not generally true of emergency ratings, as they can be
provided under most RTOs/ISOs' current systems with no significant
modifications, arguing that emergency ratings are particularly
important because the vast majority of real-time constraints are first-
contingency constraints where emergency ratings are presumptively
appropriate.\222\ Potomac Economics argues that it is unreasonable for
the
[[Page 31727]]
Commission not to require near-term implementation of fixed emergency
ratings pending the implementation of AARs given that: (1) The failure
to utilize emergency ratings on contingency constraints is a major
contributor to unjust and unreasonable wholesale rates; (2) the
information needed to provide unadjusted emergency ratings is readily
available for most constraints; and (3) there are no dependencies
between providing fixed seasonal emergency ratings and later adjusting
such ratings for changes in ambient air temperatures. Potomac Economics
contends that allowing the emergency ratings requirements to be
suspended for up to three years will result in inflated congestion and
curtailments of low-cost generation and is indisputably unreasonable,
is unsupported by the record, and has not been reasonably justified or
explained by the Commission. Potomac Economics requests that the
Commission revise its implementation schedule to require near-term
implementation of reliable emergency ratings in the real-time markets,
day-ahead markets, and forward markets and in planning studies.\223\
---------------------------------------------------------------------------
\222\ Id. at 7-8.
\223\ Id. at 8.
---------------------------------------------------------------------------
3. Commission Determination
96. We sustain the Commission's determinations in Order No. 881 on
this issue. As an initial matter, EEI mischaracterizes the NOPR
proposal as one in which ``AARs would be implemented on congested
lines, not all lines.'' \224\ In fact, the NOPR proposed a staggered
approach that would prioritize implementation on congested transmission
lines (within one year from the date of the compliance filing for
implementation of the proposed reforms to become effective) and require
a longer timeline for implementation of AARs on all other transmission
lines (within two years of the date of the compliance filing for
implementation of the proposed reforms to become effective).\225\ EEI
acknowledged this in comments in response to the NOPR, that it ``agrees
with a staggered approach, similar to the Commission's proposal'' but
suggested that the Commission ``not require that companies deploy AARs
on all transmission facilities.'' \226\
---------------------------------------------------------------------------
\224\ EEI Request for Rehearing at 7.
\225\ NOPR, 173 FERC ] 61,165 at P 81.
\226\ EEI Comments at 6-7.
---------------------------------------------------------------------------
97. EEI suggests that the three-year implementation period does not
consider the ``substantial increase in the number of ratings that the
final rule requires to be computed,'' as compared to the NOPR, nor
whether third-party vendors will be able to support the data
requirements of Order No. 881.\227\ Contrary to EEI's argument, the
Commission did consider the requirements adopted in the final rule--as
opposed to those in the NOPR--in setting the implementation timeline.
The Commission determined that three years was a reasonable
implementation timeline by considering the comments filed in response
to the NOPR. Multiple commenters noted that one of the largest
impediments to the NOPR's proposed two-year implementation timeline was
the time needed to develop necessary software changes, which are
largely one-time upgrades applicable to both congested and non-
congested transmission lines.\228\ In giving transmission providers
more time to implement the requirements adopted in Order No. 881 than
proposed in the NOPR, the Commission responded to commenters'
justification for additional time to develop the software but balanced
that with the fact that once the software is in place, the calculations
are largely automated. Thus, the Commission's determination in setting
the three-year implementation timeline accounted for potential
implementation challenges of the more broadly applicable transmission
line ratings requirements of the final rule.
---------------------------------------------------------------------------
\227\ EEI Request for Rehearing at 8.
\228\ See, e.g., Industrial Customers Comments at 22 (suggesting
an implementation timeline of six months for congested transmission
lines and one year for all others); PG&E Comments at 6 (suggesting a
three-phase, five-year implementation timeline).
---------------------------------------------------------------------------
98. As for third-party vendor availability, the Commission
considered comments that raised these concerns in response to the
NOPR.\229\ Specifically, in the NOPR, the Commission proposed AAR
requirements similar to those adopted in the final rule, and similarly
explained that those requirements would necessitate that transmission
providers implement an automated system in setting the implementation
timeline.\230\ For example, Arizona Public Service Company (APS) argued
that ``adequate time is needed to develop the business requirements for
the software vendors and that APS will have to work with multiple
software vendors to comply'' \231\ and then indicated that it agreed
with EEI's assertion that ``between two to three years'' is needed to
implement AARs on priority transmission lines.\232\ As explained in
Order No. 881 and above, we expect that the implementation burden is
predominantly a one-time investment and that the burden of applying
AARs to additional transmission lines is minimal.\233\ Thus, in
considering comments like APS's, the Commission determined that a
three-year implementation timeline for all transmission lines--as
opposed to just priority transmission lines--balances the need to
implement the requirements adopted in Order No. 881 as soon as
practicable to address unjust and unreasonable wholesale rates with the
burden on transmission providers of complying with those requirements.
In short, EEI fails to support the claims it makes about the potential
for the data storage and sharing requirements to require additional
time due to the need for third-party vendors beyond the extended three-
year timeline adopted in the final rule. Thus, we are not persuaded
that the additional requirements adopted in the final rule, as compared
to the NOPR, necessitate further implementation delay.
---------------------------------------------------------------------------
\229\ Compare Order No. 881, 177 FERC ] 61,179 at P 119
(summarizing NYISO's comments that vendor availability for the
software buildout necessary for calculating AARs for up to 10 days
forward is unknown) with id. P 351 (explaining that NYISO requests
flexibility for implementation and argues that the NOPR proposal
does not give enough time for software changes to be developed).
Compare id. P 354 (summarizing ITC's argument that the NOPR's
proposed implementation timeline does not give enough time for
software development or purchase from a vendor and analysis of the
impact of the requirements on ITC's internal transmission line
ratings database) with id. P 351 (stating that ITC argues that three
years is needed to implement AARs on priority transmission lines).
\230\ NOPR, 173 FERC ] 61,165 at P 95.
\231\ APS Comments at 6.
\232\ Id.; EEI Comments at 8; Order No. 881, 177 FERC ] 61,179
at PP 351, 353.
\233\ Order No. 881, 177 FERC ] 61,179 at P 94.
---------------------------------------------------------------------------
99. Nor are we persuaded to adopt an earlier implementation, as
requested by Potomac Economics. We find that a three-year
implementation schedule provides a reasonable amount of time for
transmission providers to implement the requirements of Order No. 881.
As noted above, commenters raised concerns with the NOPR's proposed
timeline, which was shorter than that adopted in the final rule. For
example, MISO Transmission Owners, EEI, Southern Company, SCE,
PacifiCorp, APS, ITC, and other commenters expressed concerns that it
would be difficult to implement AARs on any transmission line within
one year due to required operating and data system upgrades.\234\ On
the other hand, as the Commission explained in Order No. 881 and as we
note above, three years is consistent with the implementation schedule
most commonly suggested by transmission owners for AAR implementation
on priority
[[Page 31728]]
transmission lines.\235\ Potomac Economics addresses neither these
operational and software concerns, nor the level of support for the
three-year implementation schedule.
---------------------------------------------------------------------------
\234\ Id. PP 351-354.
\235\ Id. P 361 (citing comments in support of a three-year
implementation schedule).
---------------------------------------------------------------------------
100. With regard to Potomac Economics' argument that the Commission
should require implementation of fixed emergency ratings as soon as
practicable, we find that the three-year implementation schedule is
consistent with the implementation schedule most commonly suggested by
transmission owners for AAR implementation on priority transmission
lines,\236\ and both the Commission and commenters explained that the
availability of emergency ratings will need to be factored into ATC
calculations.\237\ Potomac Economics has not demonstrated that the
implementation of emergency ratings on a faster timeline is feasible,
particularly in the non-RTO/ISO regions and particularly in light of
the challenges associated with updating ATC calculations articulated by
commenters.\238\ Moreover, as a matter of policy, there are
administrative efficiencies to requiring implementation of all the
requirements adopted in Order No. 881 on the same timeline.
Specifically, by maintaining a single implementation timeline, the
implementation burdens are lessened in that all transmission line
rating recalculations must only be done once. In contrast, Potomac
Economics' suggestion would require the calculation of seasonal
emergency ratings followed by a separate calculation of emergency
ratings to comply with the AAR requirements for the same transmission
line. Thus, requiring implementation of all the requirements adopted in
Order No. 881 on the same timeline is appropriate given the
interrelationship between the AAR requirements, the emergency ratings
requirements, and the requirement that AARs also be calculated for
``uniquely determined emergency ratings.'' \239\ Therefore, as
explained above, we sustain the findings in the final rule that justify
a three-year implementation timeline for the other requirements of
Order No. 881 and believe it appropriate to include the emergency
ratings requirements in the same timeline.
---------------------------------------------------------------------------
\236\ Id. P 361 (citing EEI Comments at 18; NRECA/LPPC Comments
at 28-29; MISO Transmission Owners Comments at 22-23; SCE Comments
at 2; SDG&E Comments at 1-2; APS Comments at 10; WFEC Comments at 1;
Southern Company Comments at 6-7; ITC Comments at 5; LADWP Comments
at 8-9).
\237\ Id. PP 293, 296.
\238\ Id. P 59 (citing BPA Comments at 3-4; PacifiCorp Comments
at 2; Imperial Irrigation District Comments at 5-6; EEI Comments at
10-11; CAISO Comments at 10).
\239\ Id. P 305.
---------------------------------------------------------------------------
E. Other Issues
101. ATC requests clarification that its current seasonal line
ratings methodology meets the intent of Order No. 881 by providing what
it characterizes as ``four seasons of accurate, science-based weather
parameters'' and that its current AAR approach satisfies the
requirements of Order No. 881.\240\
---------------------------------------------------------------------------
\240\ ATC Request for Clarification at 1.
---------------------------------------------------------------------------
102. In response to ATC's request for clarification, we find that
the appropriate proceeding for the Commission to make such a
determination is through transmission providers' Order No. 881
compliance filings. As explained in Order No. 881, each transmission
provider must submit a compliance filing within 120 days of the
effective date of the final rule revising their OATT to incorporate pro
forma OATT Attachment M.\241\ The Commission acknowledged that ``some
public utility transmission providers may have provisions in their
existing pro forma OATTs or other document(s) subject to the
Commission's jurisdiction that the Commission has deemed to be
consistent with or superior to the pro forma OATT.'' \242\ Where Order
No. 881 modifies these provisions, ``transmission providers must either
comply with the requirements adopted in this final rule or demonstrate
that these previously approved variations continue to be consistent
with or superior to the pro forma OATT, as modified by this final
rule.'' \243\ The compliance filing required by Order No. 881 is the
proper vehicle for presenting this evidence to the Commission.
---------------------------------------------------------------------------
\241\ Order No. 881, 177 FERC ] 61,179 at P 12.
\242\ Id. P 363; see 18 CFR 35.28(c)(1)(vi).
\243\ Order No. 881, 177 FERC ] 61,179 at 363.
---------------------------------------------------------------------------
III. Information Collection Statement
103. The burden estimates have not changed from the final rule.
IV. Regulatory Flexibility Act Certification
104. The Regulatory Flexibility Act of 1980 (RFA) \244\ generally
requires a description and analysis of final rules that will have
significant economic impact on a substantial number of small entities.
Pursuant to section 605(b) of the RFA, we still conclude that the final
rule will not have a significant economic impact on a substantial
number of small entities.
---------------------------------------------------------------------------
\244\ 5 U.S.C. 601-612.
---------------------------------------------------------------------------
V. Document Availability
105. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through FERC's Home Page (<a href="http://www.ferc.gov">http://www.ferc.gov</a>) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5:00
p.m. Eastern time) at 888 First Street NE, Room 2A, Washington DC
20426.
106. From FERC's Home Page on the internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
107. User assistance is available for eLibrary and the FERC's
website during normal business hours from FERC Online Support at 202-
502-6652 (toll free at 1-866-208-3676) or email at
<a href="/cdn-cgi/l/email-protection#fc9a998e9f9392909592998f898c8c938e88bc9a998e9fd29b938a"><span class="__cf_email__" data-cfemail="f89e9d8a9b97969491969d8b8d8888978a8cb89e9d8a9bd69f978e">[email protected]</span></a>, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
<a href="/cdn-cgi/l/email-protection#a6d6d3c4cacfc588d4c3c0c3d4c3c8c5c3d4c9c9cbe6c0c3d4c588c1c9d0"><span class="__cf_email__" data-cfemail="116164737d78723f6374777463747f7274637e7e7c51777463723f767e67">[email protected]</span></a>.
VI. Effective Date
108. The effective date of the document published on January 13,
2022 (87 FR 2244), is confirmed: March 14, 2022.
By the Commission.
Issued: May 19, 2022.
Debbie-Anne A. Reese,
Deputy Secretary.
[FR Doc. 2022-11233 Filed 5-24-22; 8:45 am]
BILLING CODE 6717-01-P
</pre><script data-cfasync="false" src="/cdn-cgi/scripts/5c5dd728/cloudflare-static/email-decode.min.js"></script></body>
</html>Indexed from Federal Register on May 25, 2022.
This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.