31712 Federal Register / Vol. 87, No. 101 / Wednesday, May 25, 2022 / Rules and Regulations 

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). 

4An 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. 

5The 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). 

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.’’). 

8Allegheny Def. Project, 964 F.3d at 16–17. 

9Order No. 881, 177 FERC ¶ 61,179 at PP 3, 29. 

10 Id. P 83. 

11Order 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. 

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. 

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, Ryan.Stroschein@

ferc.gov. 

Dillon Kolkmann (Technical 

Information), Office of Energy Policy 

Innovation, Federal Energy Regulatory 

Commission, 888 First Street NE, 

Washington, DC 20426, (202) 502–8650, 

Dillon.Kolkmann@ferc.gov. 

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 ambientadjusted 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 passwordprotected website. 

2. On January 18, 2022, several 

entities filed requests for rehearing and/ 

or clarification of Order No. 881.5

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

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. 

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 


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12 Id. P 83. 

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.) 

14Order No. 881, 177 FERC ¶ 61,179 at P 85. 

15EEI Request for Rehearing at 4. 

16 Id. at 5. 

17 Id. 

18 Id. (citing Order No. 881, 177 FERC ¶ 61,179 at 

PP 128–133). 

19Preventing 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). 

20EEI Request for Rehearing at 6 (quoting Order 

No. 890, 118 FERC ¶ 61,119 at P 292). 

21 Id. at 6–7 (citing Order No. 881, 177 FERC 

¶ 61,179 at P 232). 

22 Id. 

23 Id. at 4. 

24Order 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.’’). 

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

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

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

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

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

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

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

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 


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29Sacramento 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.’’). 

30Order No. 881, 177 FERC ¶ 61,179 at P 29. 

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. 

33 Id. P 95. 

34 Id. 

35See, 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. 

36Order 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-weatheroutages-texas-and-south-central-united-states-fercnerc-and. 

37EEI Request for Rehearing at 5. 

38Order No. 881, 177 FERC ¶ 61,179 at PP 29–34. 

39See supra note 31. 

40Order 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). 

41EEI Request for Rehearing at 5–6. 

42Order No. 881, 177 FERC ¶ 61,179 at P 228. 

43 Id. 

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

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

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

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. 

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

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

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 


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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. 

47See 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. 

49Order No. 890, 118 FERC ¶ 61,119. 

50EEI Request for Rehearing at 6 (citing Order No. 

890, 118 FERC ¶ 61,119 at P 292). 

51Order No. 881, 177 FERC ¶ 61,179 at P 131. 

52Order No. 890, 118 FERC ¶ 61,119 at P 292 

(emphasis added). 

53 Id. P 347. 

54Order No. 881, 177 FERC ¶ 61,179 at P 48. 

55 Id. P 99. 

56EEI Request for Rehearing at 12–13. 

57 Id. 

58 Id. at 13 (emphasis added). 

59NERC 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. 

that Attachment M is insufficient to 

protect safety and reliability. 

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 longterm 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

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 longterm 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

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

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

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 


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60Order No. 881, 177 FERC ¶ 61,179 at PP 227– 

228. 61We 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.). 

62As 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. 

63 Id. P 99. 

64 Id. 

65 Id. 

66 Id. P 104. 

67 Id. P 121. 

68MISO Transmission Owners Request for 

Rehearing at 15–16. 

69 Id. at 17 & n.53. 

70 Id. at 13–14. 

71 Id. at 13. 

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-orminus a margin of 10 degrees 

Fahrenheit,62 and thus already have 

relay settings evaluated or reevaluated 

for compliance with Order No. 881. 

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

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: 

(1) the additional benefits gained by adopting 

a threshold that permits weekly point-topoint 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

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 decisionmaking.’’ 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

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 


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72Order No. 881, 177 FERC ¶ 61,179 at P 126. 

73 Id. PP 127–128. 

74 Id. PP 122–123. 

75 Id. P 127. 

76 Id. P 129. 

77 Id. P 125. 

78 Id. 

79 Id. P 134. 

80 Id.; see also id. P 106. 

81MISO Transmission Owners Request for 

Rehearing at 17 n.53. 

82See 18 CFR 385.713(c) (2021). 

83Order No. 881, 177 FERC ¶ 61,179 at P 123. 

84See NOAA, National Blend of Models—NBM 

Versions, https://vlab.noaa.gov/web/mdl/nbmversions (last visited April 21, 2022). 

85Order No. 881, 177 FERC ¶ 61,179 at P 122. 

86 Id. P 123. 

87 Id. 

88 Id. PP 121–122. 

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

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

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. 

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-topoint 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

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 underreport 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

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. 


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89 Id. P 125. 

90MISO Transmission Owners Request for 

Rehearing at 18. 

91 ITC Request for Rehearing at 3 n.4, 11. 

92MISO Transmission Owners Request for 

Rehearing at 18–19. 

93 ITC Request for Rehearing at 10. 94Order No. 881, 177 FERC ¶ 61,179 at P 83. 

95 Id. P 185. 

96 Id. P 187. 

97MISO Transmission Owners Request for 

Rehearing at 11. 

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

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

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

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

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. 

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

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

b. Request for Rehearing 

43. MISO Transmission Owners 

contend that the Commission failed to 

satisfy its burden of supporting the fivedegree 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

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 


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98 Id. at 12. 

99 Id. at 13. 

100 Id. 

101EEI 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. 

107MISO Transmission Owners Request for 

Rehearing at 14 (citing Order No. 881, 177 FERC 

¶ 61,179 at P 123). 

108 Id. 

109EEI Request for Rehearing at 11. 

110 Id. at 11–12. 

111MISO Transmission Owners Request for 

Rehearing at 14–15. 

112Order No. 881, 177 FERC ¶ 61,179 at P 187. 

113 Vistra Comments at 6. 

114Order No. 881, 177 FERC ¶ 61,179 at P 187. 

115 Id. 

116 Id. 

117 Id. 

118 Id. P 138. 

119 Id. P 187. 

120September 2019 Technical Conference, Day 

One Tr. at 157:7–15. 

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

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 plusor-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

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 fivedegree increment is likely to produce 

inaccurate ATC determinations and that 

Order No. 881 is internally inconsistent 

and contrary to the record.108

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

c. Commission Determination 

48. On rehearing, MISO Transmission 

Owners, EEI, and ITC argue that the 

Commission failed to support the fivedegree 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

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 upto-date forecast of ambient air 

temperature.117

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 


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121 Id. at 79:6–10. 122 Id. at 80:9–19. 123See 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). 124Order No. 881, 177 FERC ¶ 61,179 at PP 30, 

34, 35. 

125See 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. 

126For 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/marketsand-operations/etools/oasis/system-information/ 

ratings-information. 

127Order No. 881, 177 FERC ¶ 61,179 at P 185. 

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. 

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. 

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

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 lookup 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

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 


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128NOPR, 173 FERC ¶ 61,165 at P 3 n.3. 129 Vistra Comments at 6–7. 130 5 U.S.C. 553. 131Earthworks 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.’’). 

132Order No. 881, 177 FERC ¶ 61,179 at P 187. 

133 Id. PP 47, 162. 

134 Id. P 147. 

135 Id. P 149. 

136 Id. P 122. 

137EEI Request for Rehearing at 10. 

138 ITC Request for Rehearing at 5. 

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 upto-date forecast of ambient 

temperature,’’ 128 which reasonably 

includes consideration of what 

minimum degree of granularity might be 

required to meet this standard. 

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. 

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 fivedegree 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.’’ 

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

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

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 


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139For 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. 

140R 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. 

141Order 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. 

142Order No. 881, 177 FERC ¶ 61,179 at PP 227– 

28. 

143PG&E Comments at 11; Entergy Comments at 

8; Potomac Economics Comments at 15. 

144Potomac Economics Comments at 15. 

145Order No. 881, 177 FERC ¶ 61,179 at P 148. 

146Potomac Economics Comments at 15; Vistra 

Comments at 4–5. 

147Order No. 881, 177 FERC ¶ 61,179 at P 144 

(citing NOPR, 173 FERC ¶ 61,165 at P 23). 

148NOPR, 173 FERC ¶ 61,165 at P 100. 

149 Id. P 5 n.5. 

150 Id. P 23 n.40. 

151See, 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.’’). 

152Order No. 881, 177 FERC ¶ 61,179 at P 215. 

153 Id. 

154 ITC Request for Rehearing at 9. 

155 Id. 

156 Id. 

157Order 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 

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. 

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. 

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 onetime 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. 

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

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

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

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

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 


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System: The Second Installment of the QER, at 4– 

2 (Jan. 2017). 

158Order No. 881, 177 FERC ¶ 61,179 at P 215; 

MISO Comments at 21. 

159Order No. 881, 177 FERC ¶ 61,179 at P 215. 

160 Id. P 330. 

161 Id. 

162 Id. P 339. 

163 Id. P 339 n.819. 

164 Id. P 339 n.820. 

165EEI Request for Rehearing at 3. 166 ITC Request for Rehearing at 5. 167 Id. at 8; EEI Request for Rehearing at 10. 168EEI Request for Rehearing at 9–10. 169 ITC Request for Rehearing at 8. 170EEI Request for Rehearing at 10–11. 171 Id. at 9–11. 172 Id. at 11. 

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. 

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 passwordprotected 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

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

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

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

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, 


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173Order No. 881, 177 FERC ¶ 61,179 at P 336. 

174See, e.g., ACPA/SEIA Comments at 18–20. 

175See, e.g., TAPS Comments at 24. 

176Order 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. 

178See, e.g., New England State Agencies 

Comments at 20. 

179Order No. 881, 177 FERC ¶ 61,179 at P 336. 

180NOPR, 173 FERC ¶ 61,165 at PP 125–130. 

181 Id. P 129. 182See Order No. 881, 177 FERC ¶ 61,179 at PP 

316–320, 336–340 (summarizing relevant 

comments). 183See, 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). 184Order No. 881, 177 FERC ¶ 61,179 at P 340. 185 18 CFR 37.7 (2021) (Information to be posted 

on the OASIS). 186Order No. 881, 177 FERC ¶ 61,179 at P 338. 187See 18 CFR 37.6 (2021). 188 ITC Request for Rehearing at 8. 

189We 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. 

190Order No. 881, 177 FERC ¶ 61,179 at PP 125, 

149, 163, 169, 362. 

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

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

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 § 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, 

§ 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. 

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 dataintensive 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. 

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 passwordprotected section of the transmission 

provider’s OASIS site or other 


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191 Id. P 336. 

192EEI Request for Rehearing at 4. 

193 Id. at 15. 

194 Id. 

195 Id. 

196 Id. 

197See 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 passwordprotected 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.’’). 

198Open 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. § 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). 

199EEI Comments at 15. 

200See, 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’’). 

201Under 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). 

203Order No. 881, 177 FERC ¶ 61,179 at P 330. 

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 costeffective decisions by market 

participants.191

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

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

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 passwordprotected 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

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 nondisclosure 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. 

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

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. 

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 


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204 Id. P 331. 205 Id. P 334. 206 Id. P 334 n.813. 207EEI Request for Rehearing at 3. 208 Id. at 14. 

209 Id. 

210 Id. 

211 Id. at 14–15. 

212Order No. 881, 177 FERC ¶ 61,179 at PP 333– 

34. 

213 18 CFR 35.28(g)(3). 

214NOPR, 173 FERC ¶ 61,165 at P 81. 

215Order No. 881, 177 FERC ¶ 61,179 at P 361 

n.870. 

216 Id. PP 360–361. 

217EEI Request for Rehearing at 7–8. 

218 Id. at 8. 

219 Id. 

220Potomac Economics Request for Rehearing at 

5. 

221 Id. at 6–7. 

222 Id. at 7–8. 

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

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

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

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

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

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

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 firstcontingency constraints where 

emergency ratings are presumptively 

appropriate.222 Potomac Economics 

argues that it is unreasonable for the 


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223 Id. at 8. 

224EEI Request for Rehearing at 7. 

225NOPR, 173 FERC ¶ 61,165 at P 81. 

226EEI Comments at 6–7. 

227EEI Request for Rehearing at 8. 

228See, 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). 

229Compare 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). 

230NOPR, 173 FERC ¶ 61,165 at P 95. 

231APS Comments at 6. 

232 Id.; EEI Comments at 8; Order No. 881, 177 

FERC ¶ 61,179 at PP 351, 353. 

233Order No. 881, 177 FERC ¶ 61,179 at P 94. 

234 Id. PP 351–354. 

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

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

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 onetime 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. 

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 threeyear 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. 

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 


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31728 Federal Register / Vol. 87, No. 101 / Wednesday, May 25, 2022 / Rules and Regulations 

235 Id. P 361 (citing comments in support of a 

three-year implementation schedule). 

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. 

240ATC Request for Clarification at 1. 

241Order No. 881, 177 FERC ¶ 61,179 at P 12. 

242 Id. P 363; see 18 CFR 35.28(c)(1)(vi). 

243Order No. 881, 177 FERC ¶ 61,179 at 363. 

244 5 U.S.C. 601–612. 

transmission lines.235 Potomac 

Economics addresses neither these 

operational and software concerns, nor 

the level of support for the 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. 

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

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. 

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. 

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 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. Email the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

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 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 375 

[Docket No. RM22–15–000; Order No. 883] 

Certification of Uncontested 

Settlements by Settlement Judges 

AGENCY: Federal Energy Regulatory 

Commission. 

ACTION: Final rule. 

SUMMARY: The Federal Energy 

Regulatory Commission (Commission) is 

revising its delegation of authority 

regulations to authorize the Chief 


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