Document ID: FERC-2022-0639-0001
Agency: ferc
Document Type: Rule
Title: Managing Transmission Line Ratings
Posted Date: 2022-05-25T04:00Z

[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 [www.gpo.gov]
[FR Doc No: 2022-11233]

[[Page 31712]]

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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, [email protected].
    Dillon Kolkmann (Technical Information), Office of Energy Policy 
Innovation, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426, (202) 502-8650, [email protected].

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), https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and.
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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), https://www.ferc.gov/sites/default/files/2020-05/07-18-19-ferc-nerc-report_0.pdf.
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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.
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    \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, https://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-023-4.pdf.
    \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, https://vlab.noaa.gov/web/mdl/nbm-versions (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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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, https://www.pjm.com/markets-and-operations/etools/oasis/system-information/ratings-information.
    \127\ Order No. 881, 177 FERC ] 61,179 at P 185.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    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.'').
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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), https://www.ncdc.noaa.gov/billions/; 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.
---------------------------------------------------------------------------

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 (http://www.ferc.gov) 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 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
[email protected].

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