Managing Transmission Line Ratings

Federal RegisterJan 13, 2022

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

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

Managing Transmission Line Ratings

AGENCY:

Federal Energy Regulatory Commission, Department of Energy.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is revising both the

pro forma

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

DATES:

This rule will become effective March 14, 2022.

FOR FURTHER INFORMATION CONTACT:

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

Dillon.kolkmann@ferc.gov

Mark Armamentos (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202) 502-8103,

Mark.armamentos@ferc.gov

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

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph Numbers

I. Introduction 1

II. Background 13

III. Need for Reform 17

A. NOPR Proposal 17

B. Comments 23

C. Commission Determination 29

IV. Discussion 40

A. Transmission Line Ratings Definition 40

1. NOPR Proposal 40

2. Comments 42

3. Commission Determination 44

B. Ambient-Adjusted Ratings 47

1. AAR Definition and Transmission Provider Obligations 47

2. Specific AAR Implementation Requirements 104

3. Other AAR Implementation Issues 151

C. Seasonal Line Ratings 193

1. Seasonal Line Ratings Requirements 193

2. Seasonal Line Rating Implementation Requirements 204

D. Exceptions and Alternate Ratings 217

1. NOPR Proposal 217

2. Comments 219

3. Commission Determination 227

E. Dynamic Line Ratings 235

1. Dynamic Line Ratings Definition 235

2. DLR Requirements 240

3. Extending to non-RTO/ISO Transmission Providers the Requirement To Allow Transmission Owners To Electronically Update Transmission Line Ratings at Least Hourly 256

4. DLR Studies 259

5. Advanced Transmission Technology Cost Recovery 265

F. Emergency Ratings 267

1. NOPR Request for Comments 267

2. Emergency Ratings Definition and Implementation Requirements 269

3. Equipment for Which Emergency Ratings Must Be Calculated 304

G. Transparency 306

1. NOPR Proposal 306

2. Comments 309

3. Commission Determination 330

H. Other Miscellaneous Issues 344

1. Comments 344

2. Commission Determination 346

I. Compliance 348

1. NOPR Proposal 348

2. Comments 351

3. Commission Determination 360

V. Information Collection Statement 364

VI. Environmental Analysis 383

VII. Regulatory Flexibility Act 384

VIII. Document Availability 399

IX. Effective Date and Congressional Notification 402

Appendix A: Abbreviated Names of Commenters

Appendix B:

Pro Forma

Open Access Transmission Tariff

I. Introduction

1. In this final rule, the Federal Energy Regulatory Commission (Commission) is adopting reforms, pursuant to section 206 of the Federal Power Act (FPA),

to the

pro forma

Open Access Transmission Tariff (OATT) and the Commission's regulations to improve the accuracy and transparency of electric transmission line ratings used by transmission providers.

As discussed below, we adopt the Commission's proposal in the Notice of Proposed Rulemaking (NOPR) to define a transmission line rating as “the maximum transfer capability of a transmission line, computed in accordance with a written transmission line rating methodology and consistent with Good Utility Practice,

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).”

16 U.S.C. 824e.

In this final rule, we use transmission provider to mean any public utility that owns, operates, or controls facilities used for the transmission of electric energy in interstate commerce. 18 CFR 37.3 (2021). Therefore, unless otherwise noted, “transmission provider” refers only to public utility transmission providers. Furthermore, the term “public utility” as found in section 201(e) of the FPA means “any person who owns or operates facilities subject to the jurisdiction of the Commission under this subchapter . . .” 16 U.S.C. 824(e).

The Commission's

pro forma

OATT defines Good Utility Practice as: “[a]ny of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region, including those practices required by Federal Power Act section 215(a)(4).”

Pro forma

OATT section 1.15.

The definition also states, “Relevant transmission equipment may include, but is not limited to, circuit breakers, line traps, and transformers.”

Managing Transmission Line Ratings,

Notice of Proposed Rulemaking, 86 FR 6420 (Jan. 21, 2021), 173 FERC ¶ 61,165, at P 85 (2020) (NOPR).

2. The transfer capability of a transmission line can change with ambient weather conditions. Thus, a transmission line rating can be determined by taking into consideration the physical characteristics of the conductor and making assumptions about ambient weather conditions to determine the maximum amount of power that can flow through a conductor while keeping the conductor under its maximum operating temperature. Conductor temperatures are impacted by a variety of factors,

including ambient air temperatures. Increases in ambient air temperatures tend to increase a transmission line's operating temperature and lower a transmission line's rating, while lower ambient air temperatures tend to lower a transmission line's operating temperature and increase the transmission line's rating.

3. Many transmission line ratings are currently calculated based on assumptions about ambient conditions that are not regularly adjusted and therefore do not accurately reflect the near-term transfer capability of the transmission system.

For example, when seasonal or static temperature assumptions exceed actual ambient air temperatures, transmission line ratings may understate the near-term transfer capability that the transmission system can actually provide, leading to unnecessarily restricted flows and potentially increased congestion costs. Alternatively, when ambient air temperatures exceed seasonal or static temperature assumptions, transmission line ratings may overstate the near-term transfer capability of the system, creating potential reliability and safety problems. In either case, the continued use of seasonal and static temperature assumptions may result in transmission line ratings that do not accurately represent the transfer capability of the transmission system. We find that transmission line ratings and the rules by which they are established are practices that directly affect the cost of wholesale energy, capacity, and ancillary services, as well as the cost of delivering wholesale energy to transmission customers; thus, we find that inaccurate transmission line ratings result in Commission-jurisdictional rates that are unjust and unreasonable.

Federal Energy Regulatory Commission, Staff Paper,

Managing Transmission Line Ratings,

Docket No. AD19-15-000 (Aug. 2019) (Commission Staff Paper),

https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf.

4. To address these issues with respect to transmission service in the near term, we adopt, with certain modifications, the NOPR proposal's definition of an ambient-adjusted rating (AAR) as a transmission line rating that: (1) Applies to a time period of not greater than one hour; (2) reflects an up-to-date forecast of ambient air temperature across the time period to which the rating applies; (3) reflects the absence of solar heating during nighttime periods where the local sunrise/sunset times used to determine daytime and nighttime periods are updated at least monthly, if not more frequently; and (4) is calculated at least each hour, if not more frequently.

Additionally, we adopt two requirements for greater use of AARs. First, we require that transmission providers—including RTOs/ISOs for transmission service at their seams

—use AARs as the basis for evaluation of transmission service requests that will end within 10 days of the request. Second, we require that transmission providers—including RTOs/ISOs for transmission service at their seams—use AARs as the basis for their determination of the necessity of certain curtailment, interruption, or redispatch of transmission service anticipated to occur within those 10 days.

18 CFR 35.28(b)(10) (2021);

Pro Forma

OATT attach. M, AAR Definition.

The term “seam” is commonly used by the industry to indicate the border between two transmission provider's service territories. Service at the seam can take different forms, such as point-to-point service or market-to-market service.

5. To address these issues with respect to transmission service in the longer term, we require that transmission providers use seasonal line ratings as the basis for evaluation of transmission service requests ending more than 10 days from the date of the request. We also require that transmission providers use seasonal line ratings as the basis for the determination of the necessity of curtailment, interruption, or redispatch of transmission service that is anticipated to occur more than 10 days in the future.

The use of seasonal line ratings for long-term requests for transmission service and as the basis for the determination of curtailment, interruption, or redispatch is currently standard practice. However, as discussed below, we adopt certain reforms to change seasonal line rating implementation.

6. For both longer term and shorter term transmission service, we adopt exceptions to the AAR and seasonal line rating requirements to accommodate instances in which the transmission line rating of a transmission line is not affected by ambient air temperature and instances in which a transmission provider reasonably determines, consistent with good utility practice, that the use of a temporary alternate rating is necessary to ensure the safety and reliability of the transmission system.

Because the new requirements related to AARs and seasonal line ratings are implemented through the new

pro forma

OATT Attachment M, these requirements are placed upon

transmission providers.

However, we recognize that

transmission owners

(not transmission providers) determine transmission line ratings. In many instances, the transmission provider and transmission owner are the same entity. However, below in Section IV.B.2.b, we discuss compliance within RTOs/ISOs, where the transmission provider and transmission owner are separate entities.

7. In certain situations, using transmission line ratings that are based on factors beyond forecasted ambient air temperatures and the presence or absence of solar heating may lead to greater accuracy. For example, the use of dynamic line ratings (DLRs) presents opportunities for transmission line ratings that may be more accurate than those established with AARs. Unlike AARs, DLRs are based not only on forecasted ambient air temperatures and the presence or absence of solar heating, but also on other weather conditions such as (but not limited to) wind, cloud cover, solar heating intensity (instead of mere daytime/nighttime distinctions used in AARs), and precipitation, and/or on transmission line conditions such as tension or sag. As discussed below, we adopt the NOPR's proposed definition of DLR as a transmission line rating that: (1) Applies to a time period of not greater than one hour; and (2) reflects up-to-date forecasts of inputs such as (but not limited to) ambient air temperature, wind, solar heating intensity, transmission line tension, or transmission line sag.

8. Although some transmission owners have adopted the use of DLRs for individual transmission lines, there is not currently widespread use of DLRs. While DLRs can represent more accurate transmission line ratings than AARs, based on the record in this proceeding, we decline to mandate DLR implementation in this final rule. We instead incorporate the record in this proceeding on DLRs into new Docket No. AD22-5-000, which we open to further explore DLR implementation.

9. One factor that may contribute to the limited deployment of DLRs by transmission owners is that the RTOs/ISOs that operate a large portion of the transmission system in the United States and oversee organized wholesale electric markets may not be able to automatically incorporate frequently updated transmission line ratings such as DLRs into their operating and market models. Although the record does not support a mandate for DLR implementation at this time, we require RTOs/ISOs to establish and maintain the systems and procedures necessary to allow transmission owners in their regions to electronically update transmission line ratings on at least an hourly basis.

10. In addition to reforms to improve the accuracy of transmission line ratings used during normal (pre-contingency) operations,

we revise the

pro forma

OATT to require transmission providers to use uniquely determined emergency ratings for contingency analysis in the operations horizon and in post-contingency simulations of constraints.

Such uniquely determined emergency ratings must also incorporate an adjustment for ambient air temperature and daytime/nighttime solar heating, consistent with our AAR requirements for normal ratings. Most transmission equipment can withstand high currents for short periods of time without sustaining damage. Emergency ratings reflect this technical capability, defining the specific additional current that a transmission line can withstand and for what duration the transmission line can withstand that additional current without sustaining damage. Because emergency ratings reflect this capability, uniquely determined emergency ratings will ensure more accurate transmission line ratings.

The North American Electric Reliability Corporation (NERC) Glossary defines “normal

rating” as: “[t]he rating as defined by the equipment owner that specifies the level of electrical loading . . . that a system, facility, or element can support or withstand through the daily demand cycles without loss of equipment life.” NERC,

Glossary of Terms Used in NERC Reliability Standards

(June 28, 2021),

https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.

As discussed below in Section IV.F.2.b, uniquely determined means the ratings are determined based on assumptions that reflect the specific, finite duration of emergency ratings, as opposed to using assumptions used to calculate normal ratings.

11. Finally, we adopt four requirements to enhance transparency. First, we require public utility transmission owners to share transmission line ratings and methodologies with their transmission provider(s) and with market monitors in RTOs/ISOs. Second, we require transmission providers to share their transmission owners' transmission line ratings and methodologies with any transmission provider(s) upon request. Third, we require transmission providers to maintain a database of their transmission owners' transmission line ratings and methodologies on the transmission provider's Open Access Same-Time Information System (OASIS) site or another password-protected website. Fourth, we require transmission providers to post on OASIS or another password-protected website any uses of exceptions or temporary alternate ratings. Availability of this additional information on transmission line ratings and their methodologies will facilitate more cost-effective decisions by transmission customers and more accurate transmission line ratings. We find that these transparency reforms will ensure that prices reflect the true cost of the wholesale service being provided and thereby are necessary to ensure just and reasonable wholesale rates.

12. We require each transmission provider to submit a compliance filing within 120 days of the effective date of this final rule revising their OATT to incorporate

pro forma

OATT Attachment M. We further require that all requirements adopted herein be fully implemented no later than three years from the compliance filing due date.

II. Background

13. In August 2019, Commission staff issued a paper entitled “Managing Transmission Line Ratings,” which drew upon Commission staff outreach conducted in spring 2019 with RTOs/ISOs, transmission owners, and trade groups, as well as staff participation in a November 2017 Idaho National Laboratory workshop. The report included background on common transmission line rating approaches, current practices in RTOs/ISOs, a review of pilot projects, and a discussion of potential improvements.

Commission Staff Paper,

https://www.ferc.gov/sites/default/files/2020-05/tran-line-ratings.pdf.

14. On September 10 and 11, 2019, Commission staff convened a technical conference (September 2019 Technical Conference) to discuss what transmission line ratings and related practices might constitute best practices, and what, if any, Commission action in these areas might be appropriate. In particular, the September 2019 Technical Conference covered issues such as: (1) Common transmission line rating methodologies; (2) AAR and DLR implementation benefits and challenges; (3) the ability of RTOs/ISOs to accept and use DLRs; and (4) the transparency of transmission line rating methodologies.

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

15. In October 2019, the Commission requested comments on questions that arose from the September 2019 Technical Conference.

In response, commenters addressed issues related to AARs and DLRs, emergency ratings, and transparency, as discussed below.

Notice Inviting Post-Technical Conference Comments, Docket No. AD19-15-000 (Oct. 2, 2019).

16. On November 19, 2020, the Commission issued the NOPR in this proceeding, proposing to amend the

pro forma

OATT and its regulations under the FPA to improve the accuracy and transparency of transmission line ratings.

Specifically, the Commission proposed a new

pro forma

OATT Attachment M “Transmission Line Ratings” to require transmission providers to implement AARs on the transmission lines over which they provide transmission service. The Commission also proposed revisions to its regulations to require RTOs/ISOs to establish and implement the systems and procedures necessary to allow transmission owners to electronically update transmission line ratings at least hourly and to require transmission owners to share transmission line ratings and transmission line rating methodologies with their transmission provider(s) and, in RTOs/ISOs, with their market monitor(s). The Commission received comments from 56 entities on the NOPR proposals from a diverse set of stakeholders.

Managing Transmission Line Ratings,

Notice of Proposed Rulemaking, 86 FR 6420 (Jan. 21, 2021), 173 FERC ¶ 61,165 (2020) (NOPR).

See

Appendix A for a list of entities that submitted comments and the shortened names used throughout this final rule to describe those entities.

III. Need for Reform

A. NOPR Proposal

17. In the NOPR, the Commission preliminarily found that transmission line ratings and the rules by which they are established are practices that directly affect the cost of wholesale energy, capacity, and ancillary services, as well as the cost of delivering wholesale energy to transmission customers. The Commission explained that, because of the relationship between transmission line ratings and costs, inaccurate transmission line ratings may result in Commission-jurisdictional rates that are unjust and unreasonable.

NOPR, 173 FERC ¶ 61,165 at P 38.

18. The Commission explained that most transmission owners implement seasonal or static transmission line rating methodologies based on conservative, worst-case assumptions, such as high temperatures that are likely to occur over the longer term, but that often do not reflect the true near-term transfer capability of transmission facilities. Thus, the Commission reasoned, seasonal and static line ratings fail to reflect the true cost of delivering wholesale energy to transmission customers, and incorporating near-term forecasts of ambient air temperatures in transmission line ratings would more accurately reflect the actual cost of delivering wholesale energy to transmission customers.

Id.

P 39.

19. Because actual ambient air temperatures are usually not as high as the ambient air temperatures conservatively assumed in seasonal and static line ratings, the Commission

observed that updating transmission line ratings used in near-term transmission service to reflect actual ambient air temperatures usually results in increased system transfer capability and, in turn, lower costs for consumers. However, the Commission also observed that seasonal and static line ratings can at times assume temperatures that are lower than the actual ambient air temperatures in the short term. In doing so, the Commission noted that seasonal or static transmission line rating methodologies can at times result in transmission line ratings that reflect more transfer capability than physically exists. The Commission observed that this overstatement of transmission line ratings similarly results in wholesale energy rates that fail to reflect the actual cost of delivering wholesale energy to transmission customers, and may also create reliability and safety problems, risk damage to equipment, and prevent occurrences of rates for scarcity pricing or transmission constraint penalty factors.

Id.

P 42.

20. Regarding DLR implementation, the Commission observed that some RTOs/ISOs may rely on software and systems that cannot accommodate transmission line ratings that frequently change, such as DLRs, and that, without reflecting such frequent changes to transmission line ratings, such software may serve as a barrier that prevents transmission owners in RTOs/ISOs from implementing DLRs, which can better reflect the actual transfer capability of the transmission system. The Commission explained that, in addition to ambient air temperature, DLRs incorporate additional inputs, including wind, cloud cover, solar heating, and precipitation, as well as transmission line conditions such as tension and sag. DLRs thereby provide transmission line ratings that are closer to the true thermal transmission line limit than AARs, which can result in rates that even more accurately reflect the costs of delivering wholesale energy to transmission customers than relying on AARs. However, the Commission explained that the potential inability of RTOs/ISOs to automatically accept and use DLRs provided by transmission owners may prevent RTO/ISO markets from benefiting from the more accurate representation of current RTO/ISO system conditions. In turn, by ensuring RTO/ISO market models can incorporate more accurate representations of system conditions when transmission owners use DLRs, RTO/ISO markets would produce prices that more accurately reflect the costs of delivering wholesale energy to transmission customers. For this reason, the Commission also preliminarily found in the NOPR that current transmission line rating practices in RTOs/ISOs that do not permit the acceptance of DLRs from transmission owners may result in rates that do not reflect the actual costs of delivering wholesale energy to transmission customers.

Id.

P 43.

21. Regarding emergency ratings, the Commission found that current transmission line rating practices may fail to use emergency ratings, and in failing to do so, may result in transmission line ratings that do not accurately reflect the near-term transfer capability of the system. This, in turn, may result in rates that do not reflect actual costs of delivering wholesale energy to transmission customers. In support, the Commission stated that transmission owners often develop two sets of transmission line ratings for most facilities: Normal ratings that can be safely used continuously, and emergency ratings that can be used for a specified shorter period of time, typically during post-contingency operations. Because emergency ratings are a more accurate representation of the flow limits over shorter timeframes, the Commission preliminarily found that their use in models of post-contingency flows may produce prices that more accurately reflect actual costs of delivering wholesale energy to transmission customers.

Id.

PP 44-46.

22. Finally, in the NOPR, the Commission preliminarily found that, by preventing transmission providers and, in RTO/ISOs, market monitors from having the opportunity to validate transmission line ratings in situations where a transmission provider serves any transmission owners that are not itself, current levels of transparency into transmission line ratings and transmission line rating methodologies may result in unjust and unreasonable rates. The Commission observed that a consequence of a lack of transparency could be inaccurate near-term transmission line ratings, which may result in rates that do not accurately reflect congestion and reserve costs on the system. As one example, the Commission stated that, without knowing the basis for a given transmission line rating that frequently binds and elevates prices, a transmission provider and/or market monitor cannot determine whether the transmission line rating is accurately calculated and therefore whether unjust and unreasonable wholesale rates are being created through use of inaccurate transmission line ratings.

Id.

P 47.

B. Comments

23. Commenters overwhelmingly agree with the Commission's preliminary finding that transmission line ratings and the rules by which they are established are practices that directly affect the cost of wholesale energy, capacity, and ancillary services, as well as the cost of delivering wholesale energy to transmission customers.

Commenters also agree with the Commission's preliminary finding that, because of the relationship between transmission line ratings and wholesale energy costs, inaccurate transmission line ratings may result in Commission-jurisdictional rates that are unjust and unreasonable.

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.

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

24. The majority of commenters representing state agencies support the Commission's basis for reform. New England State Agencies explain that, because transmission lines are used to control the amount of energy on electric power systems, transmission line ratings affect the price of electric power as well as the reliability of the electric grid.

OMS also agrees with the Commission's preliminary finding that transmission line ratings directly affect wholesale energy costs and artificially limit transfers within and between regions, stating that such a conclusion is obvious and correct.

OMS further contends that the slow pace of action on this issue by RTOs/ISOs and transmission owners makes the issue ripe for Commission action.

Ohio FEA maintains that transmission line ratings have a direct and significant influence on wholesale energy and capacity markets and, therefore, must be accurate. Ohio FEA further argues that inaccurate transmission line ratings may also cause Locational Deliverability Areas (LDAs) to unnecessarily constrain in the

capacity market, resulting in higher capacity prices.

New England State Agencies Comments at 8.

OMS Comments at 6.

OMS Reply Comments at 2-3.

Ohio FEA Comments at 6.

25. Each of the commenting market monitors supports the Commission's basis for reform. For example, Potomac Economics agrees with the Commission's finding that inaccurate transmission line ratings may result in rates that are not just and reasonable and notes that facility ratings are used in virtually every aspect of electricity markets and system operations. Potomac Economics further avers that transmission line ratings determine the transmission limits input into market models, which, in turn, determine the commitment and dispatch needed to satisfy load and manage congestion. Potomac Economics further explains that underestimated transmission line ratings cause inefficient operations, higher congestion, reduced transmission availability, higher costs, higher renewable energy curtailments, and a greater perceived need for new transmission facilities.

The SPP MMU also agrees with the Commission's assertion that transmission line ratings can directly affect the cost of producing wholesale energy, capacity, and ancillary services, as well as the cost of delivering such products. The SPP MMU explains that the cost of congestion is directly impacted by transmission line ratings and that inaccurate transmission line ratings cause price distortions, which may result in unjust and unreasonable rates.

The CAISO DMM also agrees with the Commission's assessment that transmission line ratings and the rules by which they are established directly impact the cost of wholesale energy delivery and related services, explaining that static or seasonal line ratings can lead to increased costs when their assumptions are not realized, which may be inefficient and can result in excess cost paid by load.

Potomac Economics Comments at 5.

SPP MMU Comments at 1-2.

CAISO DMM Comments at 4.

26. Other commenters also support the Commission's basis for reform. R Street Institute states that the Commission's problem statement is sound, explaining that transmission line ratings are chronically understated because they do not reflect current weather conditions, and as a result, according to R Street Institute, fail to allow for significant cost savings.

Industrial Customer Organizations state that transmission line ratings and associated rules directly affect the cost of wholesale energy, capacity, and ancillary services, and the cost of delivering wholesale energy to transmission customers, and the rulemaking is therefore consistent with the Commission's authority and obligations under the FPA.

TAPS states that reliance on static or seasonal line ratings inflicts unnecessary costs on consumers and that AAR deployment can provide significant benefits to consumers.

WATT explains that accurate transmission line ratings lower costs for consumers.

Certain TDUs assert that enhanced transmission line ratings, including AARs and DLRs, are tools that maximize the efficiency of the existing transmission system and lower costs for consumers.

R Street Institute Comments at 2.

Industrial Customer Organizations Comments at 11-12.

TAPS Comments at 5-6.

WATT Comments at 3-5.

Certain TDUs Comments at 4.

27. Finally, clean energy and generator representatives also support the Commission's basis for reform.

For example, Clean Energy Parties conclude that, due to the impact that transmission line ratings have on wholesale rates requirements, accurate transmission line ratings are consistent with the Commission's mandate under sections 205 and 206 of the FPA.

Clean Energy Parties Comments at 2-3; EDFR Comments at 3.

Clean Energy Parties Comments at 2-3.

28. However, NYTOs question the Commission's legal standing to regulate transmission line ratings, noting that the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) found that there are limits to the Commission's FPA section 206 jurisdiction over “practices” and that the term may not include all utility operations.

NYTOs note that the Commission's authority to regulate transmission planning was upheld on appeal but that Order No. 1000

is not prescriptive; therefore, NYTOs request that the Commission similarly allow utilities to make their own decisions related to advanced line rating technologies.

NYTOs Comments at 9 (referencing

Cal. Indep. Sys. Operator Corp.

FERC,

372 F.3d 395, 402 (D.C. Cir. 2004)).

Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities,

Order No. 1000, 77 FR 32184 (May 31, 2012), 136 FERC ¶ 61,051 (2011),

order on reh'g,

Order No. 1000-A, 139 FERC ¶ 61,132,

order on reh'g and clarification,

Order No. 1000-B, 141 FERC ¶ 61,044 (2012),

aff'd sub nom. S.C. Pub. Serv. Auth.

FERC,

762 F.3d 41 (D.C. Cir. 2014).

NYTOs Comments at 9-10.

C. Commission Determination

29. We find that transmission line ratings, and the rules by which they are established, are practices that directly affect the rates for the transmission of electric energy in interstate commerce and the sale of electric energy at wholesale in interstate commerce (hereinafter referred to collectively as “wholesale rates”). Thus, the Commission has jurisdiction over transmission line ratings.

We further find that, because of the relationship between transmission line ratings and wholesale rates, inaccurate transmission line ratings result in wholesale rates that are unjust and unreasonable. Accordingly, pursuant to FPA section 206,

we conclude that certain revisions to the

pro forma

OATT and the Commission's regulations are necessary to ensure just and reasonable wholesale rates. We adopt most of the reforms proposed in the NOPR, with certain clarifications, as discussed further herein, and revisions to the proposed

pro forma

OATT Attachment M and to the Commission's regulations.

16 U.S.C. 824(b)(1), 824d.

16 U.S.C. 824e.

30. We find that transmission line ratings directly affect wholesale rates because transmission line ratings and wholesale rates are inextricably linked. As explained above, transmission line ratings represent the maximum transfer capability of each transmission line. That transfer capability determines the quantity of energy that can be transmitted from suppliers to load in any given moment. Supply and demand fundamentals dictate that less transfer capability (

i.e.,

less supply) will result in higher rates, all else being equal. Inaccurate transmission line ratings can result in underutilization (or overutilization) of existing transmission facilities, thereby sending a signal that there is less (or more) transfer capability than is truly available. This signal impacts the wholesale rates charged for providing energy and other ancillary services. For example, if the system operator believes there is less transfer capability than is truly available, it may dispatch more expensive generators to serve load, when less expensive generators (which would have resulted in lower congestion costs) could have been used to reliably serve the same load. Alternatively, inaccurate transmission line ratings can result in oversubscription of existing transmission facilities, thereby sending the opposite signal—that there is more transfer capability than is truly available—which may risk damage to equipment, may fail to accurately price congestion costs, and may fail to signal to the market that more generation and/or transmission investment may be needed in the long term. We therefore find that transmission line ratings

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

31. Most commenters, except NYTOs, agree with the Commission's preliminary conclusion that transmission line ratings directly affect wholesale rates.

NYTOs caution that the D.C. Circuit found there are limits to the Commission's FPA section 206 jurisdiction over “practices” and that the term may not include all utility operations.

But, the inextricable link between transmission line ratings and wholesale rates places transmission line ratings within the Commission's FPA section 206 jurisdiction.

NYTOs Comments at 9-10.

32. Some commenters, in response to the preliminary finding that accurate transmission line ratings are necessary for just and reasonable wholesale rates, argue that transmission line ratings are fundamentally a reliability tool.

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

See, e.g.,

Dominion Comments at 13; Exelon Comments at 6; PJM Indicated Transmission Owners Comments at 2; EEI Comments at 5.

33. Regarding that incorporation of transmission line ratings into operations and resulting wholesale rates, as the Commission explained in the NOPR, most transmission owners implement seasonal or static line ratings. Such seasonal or static line ratings are based on conservative, worst-case assumptions about long-term conditions, such as the expected high temperatures that are likely to occur over the longer term. While such long-term assumptions may be appropriate in various planning contexts, they often do not reflect the true near-term transfer capability of transmission facilities and, when used in near-term operations, produce unjust and unreasonable wholesale rates.

34. As explained in the NOPR, incorporating near-term forecasts of ambient air temperatures in transmission line ratings can more accurately reflect the true near-term transfer capability of transmission facilities than continuing to rely on seasonal or static line ratings. Because actual ambient air temperatures are usually not as high as the ambient air temperatures conservatively assumed in seasonal and static line ratings, updating the transmission line ratings used in near-term transmission service to reflect actual ambient air temperatures usually results in increased system transfer capability. By increasing transfer capability, congestion costs will, on average, decline because transmission providers will be able to serve load with less expensive resources from what were previously constrained areas. For example, Potomac Economics has found that AAR implementation by those not already using AARs in MISO alone would have produced approximately $66.5 million and $49 million in reduced congestion costs in 2019 and in 2020, respectively.

Such congestion cost changes and related overall price changes will more accurately reflect the actual congestion on the system, leading to wholesale rates that more accurately reflect the cost of the wholesale service being provided. Likewise, the ability to increase transmission flows into load pockets may reduce transmission provider reliance on local reserves inside load pockets, which may reduce local reserve requirements and the costs to maintain that required level of reserves.

Potomac Economics Comments at 8.

35. Moreover, while current transmission line rating practices usually understate transfer capability, they can also overstate transfer capability and, in doing so, place transmission lines at risk of inadvertent overload. While actual ambient air temperatures are usually not as high as the assumed seasonal or static line rating temperature input, in some instances actual ambient air temperatures exceed those assumed temperatures. In those instances, seasonal or static line ratings might reflect more transfer capability than physically exists, and therefore such transmission line ratings might allow access to some electric power supplies and/or demand that would not be available if transmission line ratings reflected the true transfer capability. Overstating transfer capability, like understating transfer capability, can result in wholesale rates that fail to reflect the cost of the wholesale service being provided, though, in the case of overstated transfer capability, through inaccurately low congestion pricing and failing to signal to the market that more generation and/or transmission investment may be needed in the long term.

36. Regarding DLRs, in addition to ambient air temperatures and the presence or absence of solar heating, other weather conditions such as (but not limited to) wind, cloud cover, solar heating intensity, and precipitation, and transmission line conditions such as tension and sag, can affect the amount of transfer capability of a given transmission facility. DLRs incorporate these additional inputs and thereby provide transmission line ratings that are closer to the true thermal transmission line limits than AARs. However, as noted above and explained in greater detail in Section IV.E below, based on the record in this proceeding, we decline to mandate DLR implementation in this final rule. We instead incorporate the record in this proceeding on DLRs into new Docket No. AD22-5-000, which we open to further explore DLR implementation.

37. While we believe additional record is needed regarding DLR implementation, we can determine based on the record that current transmission line rating practices in RTOs/ISOs that do not permit the acceptance of DLRs from transmission owners that use DLRs are contributing to unjust and unreasonable wholesale rates by acting as a barrier to accurate transmission line ratings. Therefore, as part of remedying inaccurate transmission line ratings that result in unjust and unreasonable wholesale rates, we require RTOs/ISOs to establish and maintain the systems and

procedures necessary to permit the acceptance of DLRs from transmission owners that use them. As the Commission explained in the NOPR, some RTOs/ISOs rely on software that cannot accommodate transmission line ratings that frequently change, such as DLRs.

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

NOPR, 173 FERC ¶ 61,165 at P 43.

38. Regarding emergency ratings, we find that many transmission owners' current transmission line rating practices fail to use emergency ratings, and in failing to do so, lead to transmission line ratings that do not accurately reflect the near-term transfer capability of the transmission system, and therefore result in wholesale rates that do not reflect costs of the wholesale service being provided. As the Commission explained in the NOPR, transmission owners often develop two sets of transmission line ratings for most facilities: Normal ratings that can be safely used continuously, and emergency ratings that can be used for a specified shorter period of time, typically during post-contingency operations. Transmission providers generally calculate resource dispatch and commitments to ensure that all facilities are within applicable facility ratings both during normal operations and following any modeled contingency (

e.g.,

following the loss of a transmission line). In ensuring that the system is stable and reliable following a contingency, transmission providers often allow post-contingency flows on transmission lines to exceed normal ratings for short periods of time, as long as those flows do not exceed the applicable emergency rating for the corresponding timeframe. Because these emergency ratings are a more accurate representation of the flow limits over those shorter timeframes, their use in models of post-contingency flows produces wholesale rates that more accurately reflect the costs of the wholesale service being provided and therefore is necessary to ensure just and reasonable wholesale rates. For this reason, as described below, we require that transmission providers implement uniquely determined emergency ratings. Additionally, we require that transmission providers use uniquely determined emergency ratings for contingency analysis in the operations horizon and in post-contingency simulations of constraints. Such uniquely determined emergency ratings must also include separate AAR calculations for each emergency rating duration used.

39. Finally, we find that the current level of transparency into transmission line ratings and methodologies may result in unjust and unreasonable wholesale rates. In some regions, where the transmission owner and transmission provider are not the same entity, such as RTOs/ISOs, current transparency levels prevent the transmission provider and market monitor(s) from having the opportunity to assess the accuracy of transmission line ratings. For example, as the Commission described in the NOPR, without knowing the basis for a given transmission line rating that frequently binds and elevates prices, a transmission provider and/or market monitor cannot determine whether the transmission line rating is accurately calculated.

Moreover, we find that, absent additional information to market participants on transmission line ratings and their methodologies, the status quo does not provide market participants with information important to making cost-effective decisions and, thereby, impedes such decisions. For example, without accurate transmission line rating information, market participants operate without information that is important in making accurate economic decisions regarding where to build generation or where to site load. Further, this lack of transparency could allow transmission owners to submit inaccurate near-term transmission line ratings, which, in turn, would result in wholesale rates that do not accurately reflect the cost of the wholesale service being provided, as discussed above. For these reasons, we require: (1) Public utility transmission owners to share transmission line ratings and methodologies with their transmission provider(s) and with market monitors in RTOs/ISOs; (2) transmission providers to share their transmission owners' transmission line ratings and methodologies with any transmission provider(s) upon request; (3) transmission providers to maintain a database of their transmission owners' transmission line ratings and methodologies on the transmission provider's OASIS site or another password-protected website; and (4) transmission providers to post on OASIS or another password-protected website any uses of exceptions or temporary alternate ratings.

Id.

P 47.

IV. Discussion

A. Transmission Line Ratings Definition

1. NOPR Proposal

40. In the NOPR, the Commission proposed to define a transmission line rating in

pro forma

OATT Attachment M as the maximum transfer capability of a transmission line, computed in accordance with a written transmission line rating methodology and consistent with good utility practice, considering the technical limitations on conductors and relevant transmission equipment (such as thermal flow limits), as well as technical limitations of the transmission system (such as system voltage and stability limits). Relevant transmission equipment may include, but is not limited to, circuit breakers, line traps, and transformers.

NOPR, 173 FERC ¶ 61,165 at P 85.

41. Under the “Obligations of Transmission Provider” section in

pro forma

OATT Attachment M, the Commission further proposed to require that the transmission provider must use either AARs or seasonal line ratings, as appropriate, as the relevant transmission line ratings. Similarly, and as described in more detail in Section IV.D.3, the Commission proposed exceptions to the AAR and seasonal line rating requirements for certain transmission line ratings.

2. Comments

42. Some commenters support the proposed definition of transmission line rating, while others request clarity or modifications be made, specifically around the list of relevant transmission equipment. AEP supports the Commission's proposed transmission line rating definition, explaining that the Commission's proposed definition reflects the fact that transmission line ratings incorporate a set of electrical equipment that collectively operate as a single bulk electric system element (

e.g.,

transformers, relay protective devices, terminal equipment, and series and shunt compensation devices) and that the most limiting component from that

set determines the transmission line rating.

Similarly, Indicated PJM Transmission Owners address the NOPR's proposed AAR requirements set forth in

pro forma

OATT Attachment M under “Obligations of Transmission Provider” (hereinafter referred to as “the proposed AAR requirements”) as ambient-adjusted and seasonal line ratings, consistent with NERC's definition of facility rating,

and describe Indicated PJM Transmission Owners' implementation of AARs, consistent with NERC's definition of facility ratings.

PJM also describes the implementation of AARs for each of its transmission facilities.

AEP Comments at 2-3.

The NERC Glossary defines a “Facility Rating” as: “[t]he maximum or minimum voltage, current, frequency, or real or reactive power flow through a facility that does not violate the applicable equipment rating of any equipment comprising the facility.” NERC,

Glossary of Terms Used in NERC Reliability Standards

(June 28, 2021),

https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.

Indicated PJM Transmission Owners Comments at 1-2, 6-7.

PJM Comments at 2-3.

43. Entergy explains that overhead conductor ratings and ratings for “ancillary equipment,” or equipment that does not include a primary element, like conductors and transformers, can be temperature adjusted. According to Entergy, examples of “ancillary equipment” include breakers, switches, traps, busses, jumpers, current transformers, potential transformers, and relay equipment. Entergy further asserts, however, that shunt reactors, series capacitors, relays, current transformers, static VAR compensators, circuit breakers, autotransformers, copper weld (“CW”) buses, conductors, risers or jumpers, and, subject to limited exceptions, customer equipment have ratings that cannot be temperature adjusted.

Eversource states that the ratings for relays and other equipment, such as splices, switches, and terminal equipment, are not impacted by ambient air temperatures.

NYISO states that the majority of the bulk electric system equipment ratings in New York are able to be rated using AARs or DLRs,

while NYTOs note that transmission line ratings may be based on non-conductor components which are not affected by ambient air temperatures.

EEI and MISO Transmission Owners request clarity on the definition of transmission line rating and its specific applicability, stating that the AAR requirements should not apply to power transformers, but instead, under certain circumstances, to other types of transformers, including current transformers.

EEI further explains that ratings for power transformers are generally the result of the efficiency of the heat transfer process, not ambient air temperatures directly, and thus requests that the Commission clarify that the references to transformers apply only to transformers that limit or impact transmission line ratings and not power transformers generally.

Entergy similarly notes that transformer and relay ratings do not change with ambient conditions.

ITC states that AARs cannot be applied to voltage or stability limits and therefore recommends that “transmission line rating” reflect the concepts of equipment and facility rating as defined by NERC in order to avoid confusion with a system operating limit.

APS states that transmission lines with limitations associated with substation equipment or series capacitors, among other equipment in which the transmission line is not the limiting factor, may not experience changes to their transfer capabilities.

MISO contends that the list could include potential relay trip limits and maximum power transfer limits.

Entergy Comments at 5-6.

Eversource Comments at 3.

NYISO Comments at 3-4.

NYTOs Comments at 8.

EEI Comments at 17-18; MISO Transmission Owners Comments at 39-40.

EEI Comments at 17-18.

Entergy Comments at 9-10.

ITC Comments at 11-12. The NERC Glossary defines an “Equipment Rating” as: “[t]he maximum and minimum voltage, current, frequency, real and reactive power flows on individual equipment under steady state, short-circuit and transient conditions, as permitted or assigned by the equipment owner.” It defines a “System Operating Limit” as: “[t]he value (such as MW, Mvar, amperes, frequency or volts) that satisfies the most limiting of the prescribed operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria. System Operating Limits are based upon certain operating criteria. These include, but are not limited to: Facility Ratings (applicable pre- and post-Contingency Equipment Ratings or Facility Ratings); transient stability ratings (applicable pre- and post-Contingency stability limits); voltage stability ratings (applicable pre- and post-Contingency voltage stability); and system voltage limits (applicable pre- and post-Contingency voltage limits).” NERC,

Glossary of Terms Used in NERC Reliability Standards

(June 28, 2021),

https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.

APS Comments at 3.

MISO Comments at 34.

3. Commission Determination

44. In this final rule, we adopt the definition of transmission line rating proposed in the NOPR. Specifically, we adopt the proposed definition that a transmission line rating means the maximum transfer capability of a transmission line, computed in accordance with a written transmission line rating methodology and consistent with good utility practice, considering the technical limitations on conductors and relevant transmission equipment (such as thermal flow limits), as well as technical limitations of the transmission system (such as system voltage and stability limits). Relevant transmission equipment may include, but is not limited to, circuit breakers, line traps, and transformers. As the Commission stated in the NOPR, system safety and reliability are paramount to the proposed requirements for transmission line ratings. We agree with AEP that the definition adopted herein reflects the fact that transmission line ratings must incorporate a set of electrical equipment ratings that collectively operate as a single bulk electric system element (

e.g.,

transformers, relay protective devices, terminal equipment, and series and shunt compensation devices) and that the most limiting component from that set determines the transmission line rating.

AEP Comments at 2-3.

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

46. Finally, in response to requests for clarification from EEI and MISO Transmission Owners regarding the applicability of the proposed AAR requirements to power transformers, we decline to provide a generic exception from the AAR requirement for power transformers. The operating limits of a power transformer are bounded by the

ambient air temperature, the average winding temperature, and the maximum winding hottest-spot temperature.

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

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

B. Ambient-Adjusted Ratings

1. AAR Definition and Transmission Provider Obligations

a. NOPR Proposal

47. In the NOPR, the Commission proposed to define an AAR in

pro forma

OATT Attachment M and in the Commission's regulations as a transmission line rating that: (1) Applies to a time period of not greater than one hour; (2) reflects an up-to-date forecast of ambient air temperature across the time period to which the rating applies; and (3) is calculated at least each hour, if not more frequently. As obligations of the transmission provider set forth in

pro forma

OATT Attachment M, the Commission proposed to require that transmission providers use AARs as the applicable line rating: (1) For requests for near-term point-to-point transmission service ending within 10 days of the request date, as defined in

pro forma

OATT Attachment M; (2) for determining the necessity of near-term curtailment or interruption of near-term point-to-point transmission service anticipated to occur (start and end) within the next 10 days; and (3) for determining the necessity of near-term interruption or redispatch of network transmission service anticipated to occur (start and end) within the next 10 days. The Commission proposed to require transmission providers to implement the use of AARs and seasonal line ratings on all historically congested transmission lines

within one year after the compliance filing due date and on all other transmission lines within two years after the compliance filing due date.

For RTOs/ISOs, for which the Commission has approved variations from the

pro forma

OATT to manage congestion and initiate curtailments and/or redispatch of transmission service within their footprints (although generally not at their borders), the Commission proposed two requirements. First, the Commission proposed requirements for RTOs/ISOs to implement AARs in both the day-ahead and real-time markets and any intra-day reliability unit commitment. Second, the Commission proposed to require AARs as the relevant transmission line rating for any near-term point-to-point transmission service offered (

e.g.,

at the RTO's/ISO's borders).

The Commission proposed to define a historically congested transmission line as “a transmission line that was congested at any time in the five years prior to the effective date of [this final rule].” NOPR, 173 FERC ¶ 61,165 at P 92.

Id.

P 131.

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

Id.

PP 93-94.

49. As justification for requiring AARs, the Commission preliminarily found that AAR requirements strike an appropriate balance between benefits and challenges. First, the Commission observed that, while there are differences across transmission systems, simply accounting for ambient air temperatures in transmission line ratings can reliably increase power transfer capability and significantly lower production costs at a manageable implementation cost. The Commission next explained that, according to Potomac Economics' estimates, the benefits to AAR implementation by those not already implementing AARs in MISO alone would have produced approximately $94 million and $78 million in reduced congestion costs in 2017 and in 2018, respectively. The Commission further explained that, while several entities noted implementation costs as a barrier to AAR implementation, the costs identified were mostly initial investments in upgraded OASIS and/or EMS and ratings databases and that once these systems are upgraded, adding AARs to additional transmission lines appears to have a minimal incremental cost.

Id.

P 99.

b. Comments

50. In response to the proposed AAR requirements, RTO/ISO comments are mixed, with most requesting flexibility to accommodate regional or market differences,

while market monitors are generally supportive of the NOPR proposal.

Transmission owners are conceptually supportive of AAR implementation but request flexibility in response to what they generally describe as an overly broad requirement.

The PJM transmission owners that submitted comments are generally supportive of the proposed AAR requirements in

pro forma

OATT Attachment M, explaining that they have experience using AARs.

Other commenters, including state governments, generation, load, renewable energy advocates, and other technical experts, are generally supportive of the proposed AAR requirements.

See, e.g.,

MISO Comments at 7, 9, 14-16; NYISO Comments at 9-11; ISO-NE Comments at 9.

Potomac Economics Comments at 3-4; CAISO DMM Comments at 2-4; SPP MMU Comments at 1, 4.

MISO Transmission Owners Comments at 8-9; PacifiCorp Comments at 2; EEI Comments at 2-5; NRECA/LPPC Comments at 2-3; Entergy Comments at 1-2; BPA Comments at 2-4; WAPA Comments at 4-5; APS Comments at 2-4; Southern Company Comments at 2-3; NYTOs Comments at 2-3; Duke Energy Comments at 1-2; PG&E Comments at 3; SCE Comments at 1-2; SDG&E Comments at 1-2; LADWP Comments at 2-3; IID Comments at 4-6; ITC Comments at 1-3; Sunflower Comments at 2; Eversource Comments at 5-7.

Exelon Comments at 1-2; AEP Comments at 5-6; Dominion Comments at 3-4; Indicated PJM Transmission Owner Comments at 1-4.

New England State Agencies Comments at 10; OMS Comments at 2; Ohio FEA Comments at 2; R Street Institute Comments at 1-2; WATT Comments at 1-2; DC Energy Comments at 1-2; ACORE Comments at 1; Clean Energy Parties Comments at 2, 4-6; ENEL Comments at 1; EDFR Comments at 1-2; Vistra Comments at 1-2; EPSA Comments at 2; Industrial Customers Comments at 1-2; TAPS Comments at 1-2; Certain TDU Comments at 1.

51. Several transmission owners explain that they currently use AARs on all or parts of their transmission lines and support the Commission's NOPR proposal to implement widespread AAR use. AEP notes that it has used AARs in real-time operations for decades and that AARs have provided both reliability and financial benefits.

AEP notes that the use of AARs is common in PJM and that it similarly implements AARs for its facilities in SPP and the Electric Reliability Council of Texas (ERCOT).

Exelon states that it

considers AARs to be a best practice, explaining that all of its six utilities have implemented AARs on their transmission systems, without any adverse reliability or safety impacts, and have found the practice to be a cost-effective tool to enhance grid reliability.

Dominion states that, because PJM has implemented AARs for transmission service and for use in its day-ahead and real-time markets, Dominion Energy Virginia has adopted and uses PJM's AAR methodology on all its transmission lines, while Dominion Energy South Carolina uses AARs on only a portion of its transmission system.

Indicated PJM Transmission Owners support efforts to enhance transmission utilization by requiring AAR and seasonal line rating implementation, explaining that such practices improve efficiency; they also state that transmission line ratings are fundamentally a reliability tool.

While generally supportive of the NOPR proposal, Dominion, AEP, and Indicated PJM Transmission Owners all request flexibility to accommodate PJM's current AAR implementation and ask that the Commission not require hourly updates to AARs.

AEP Comments at 3.

Id.

at 3-4.

Exelon Comments at 1-2.

Dominion Comments at 6.

Indicated PJM Transmission Owners Comments at 1-2.

Dominion Comments at 3; AEP Comments at 6-7; Indicated PJM Transmission Owners Comments at 5.

52. Both ITC and Sunflower state that they are generally supportive of AAR implementation, but urge flexibility for transmission providers to implement AARs.

MISO Transmission Owners, explaining that they have initiated a process to implement AARs, state that they support certain aspects of the NOPR, but also state that other aspects are overly broad and will not yield sufficient benefits to justify the costs.

MISO Transmission Owners urge the Commission to allow for regional flexibility in any requirements and state that AAR deployment should focus on where it is expected to provide benefits by “freeing up” additional transfer capability.

MISO Transmission Owners state that, over the past five years, congestion arose on only 10% of the nearly 10,000 transmission facilities under MISO's functional control and that there would be no benefit to implementing AARs on non-congested lines.

MISO Transmission Owners also state that there are several necessary steps to implement AARs, which can be costly and time consuming.

Additionally, MISO Transmission Owners state that the Commission should not rely upon Potomac Economics' estimates of AAR benefits, explaining that Potomac Economics inaccurately assumed that: (1) All transmission lines are ambient adjustable; (2) all transmission owners are using worst-case assumptions; and (3) congestion caused by transient outages existed even though it has since been alleviated by recent upgrades.

ITC Comments at 1-3; Sunflower Comments at 2.

MISO Transmission Owners Comments at 3-4.

Id.

at 13.

Id.

at 28.

Id.

at 22.

Id.

at 43-45.

53. NYTOs, Eversource, and Southern Company request that the Commission refrain from adopting blanket AAR requirements for all transmission lines and instead require transmission providers to adopt a process for determining whether to apply AARs or DLRs to certain transmission facilities.

Southern Company suggests that such a process could be similar to the Commission's available transfer capability (ATC) requirements, whereby a public utility could include the metrics and criteria for determining when to use AAR or DLR in its OATT and implementation details in its guidelines or business practices.

Southern Company states that, while broader use of AARs and DLRs may provide cost savings to customers, the Commission's proposed approach in the NOPR is overly prescriptive and may therefore create unnecessary implementation complications and limit the deployment of other grid-enhancing technologies.

Southern Company and NRECA/LPPC also argue that non-RTO/ISO regions are characterized by long-term transmission commitments and that incremental short-term transfer capability is less relevant and less likely to result in cost savings.

Eversource contends that it applies AARs where it is beneficial, but states that the benefits of AARs will depend on specific circumstances within a region, noting that there is little congestion in ISO-NE.

Southern Company Comments at 1-2; Eversource Comments at 6; NYTOs Comments at 10.

Southern Company Comments at 1-2.

Id.

at 2.

Id.

at 4-5; NRECA/LPPC Comments at 19.

Eversource Comments at 4-5.

54. Southern Company states that reliability issues may arise as a result of the NOPR proposal because AARs may create difficulties in identifying the most limiting element, which may change as the temperature changes, and similar difficulties may arise in complying with Reliability Standard PRC-023-4's transmission relay loadability requirements that depend on maximum published ratings.

EEI states that, to ensure compliance with Reliability Standard PRC-023-4, significant amounts of field engineering time could be required to install and test new settings for thousands of relays.

NYTOs state that implementing the AAR requirements will require significant time and resources and would divert scarce resources from ongoing efforts to meet the goals of New York's Climate Leadership and Community Protection Act.

NERC contends that the Commission should keep in mind considerations for implementing AARs across long transmission lines that span multiple climates.

Southern Company Comments at 6.

EEI Comments at 5-6.

NYTOs Comments at 6-7.

NERC Comments at 7.

55. Duke Energy states that it already employs AARs in real-time operations and supports the Commission's proposed requirements for transmission providers to implement AARs in real-time operations.

However, Duke Energy also argues that, because incorporating AARs into ATC calculations would require fundamental software changes that may take several million dollars and multiple years to complete, the benefits may not outweigh the costs.

Duke Energy suggests that the Commission should instead require transmission providers to submit a compliance filing in which they may propose a process to identify the transmission facilities for which the implementation of AARs and seasonal line ratings will provide the most benefits to customers.

100

Duke Energy Comments at 5.

Id.

at 10.

100

Id.

at 5.

56. EEI states that its experience with AARs is that their use can provide benefits on a subset of transmission lines

101

and requests flexibility for transmission owners and transmission providers to implement transmission line rating solutions that best suit their needs.

102

EEI recommends a staggered AAR approach whereby AARs would first be implemented on priority designated facilities, using established and studied criteria, and any subsequent AAR implementation would occur following further studies of potential benefits.

103

Similarly, Entergy states that AARs allow for more flexibility in real-time operations than static/thermal values for real-time contingency studies,

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

104

101

EEI Comments at 5.

102

Id.

at 2-4.

103

Id.

104

Entergy Comments at 8.

57. NRECA/LPPC, Sunflower, and WAPA contend that the promised benefits, costs, and risks of AARs are not evenly distributed nationwide and that blanket application of the proposed AAR requirements poses difficult operating challenges.

105

NRECA/LPPC argue that the Commission should maintain a focus on safety and reliability and limit the scope of any final rule by applying the AAR requirements to transmission lines: (1) Rated 100 kV and above; (2) that are historically congested due to conductor limitations only; and (3) that are under RTO/ISO control. In addition, NRECA/LPPC argue that AAR requirements should be limited to transmission service used for near-term wholesale transactions, which in the RTOs/ISOs would be the day-head and real-time markets, and outside of the RTOs/ISOs, if applied, would be daily and hourly ATC, curtailment, and redispatch.

106

NRECA/LPPC and Sunflower further contend that, due to challenges in implementing AARs, utilities should have the flexibility to choose the AAR methodology best suited to their needs and should provide a waiver mechanism for particular circuits on which AAR implementation is difficult.

107

105

NRECA/LPPC Comments at 15-16, 19; Sunflower Comments at 5; WAPA Comments at 5.

106

NRECA/LPPC Comments at 2-3.

107

Id.

at 3; Sunflower Comments at 5.

58. Several Western Interconnection, non-CAISO transmission owners, including PacifiCorp, BPA, WAPA, and APS, broadly support the adoption of AARs due to the associated reduction in congestion, increase in transfer capability, and reliability improvements. However, these transmission owners request additional flexibility in how transmission owners apply AARs and urge the Commission to not adopt blanket AAR requirements for all transmission lines given differences in terrain, line lengths, and scarcity of temperature data for such lines.

108

In explaining the drawbacks to blanket AAR implementation, APS explains that non-congested transmission lines, transmission lines that are substation equipment-limited, and transmission lines that are voltage- and stability-limited will not benefit from AAR implementation.

109

WAPA further identifies additional AAR implementation challenges, including the installation of new devices, communication equipment, and cybersecurity challenges. To reduce implementation burdens, WAPA recommends that the Commission examine real-time Total Transfer Capability (TTC) calculations.

110

WAPA further cautions that it would have to pass the costs of AAR implementation on to all customers, even though only some customers would benefit.

111

BPA states that if it uses AARs as proposed, it would need to make its wind assumptions more conservative, de-rating transmission, to mitigate the risk of operating near the conductor limit.

112

108

PacifiCorp Comments at 2; BPA Comments at 2-4; WAPA Comments at 4-5; APS Comments at 2-4.

109

APS Comments at 2-4.

110

WAPA Comments at 7-9.

111

Id.

at 4-5.

112

BPA Comments at 4-5.

59. PacifiCorp, BPA, EEI, and IID further explain additional difficulties they would face implementing the proposed requirements to incorporate AARs into ATC that could render AAR implementation infeasible.

113

IID explains that, in the Western Interconnection, path limits are the result of multiple limits in series and in parallel. TTC calculations involve adjusting a base case with an associated series of activities, and failures in base case studies have to be evaluated manually, such that a generic equation would be insufficient in calculating transmission line ratings.

114

BPA and PacifiCorp explain that most congested parts on their transmission systems are lines that are operated in parallel as part of a rated transmission path,

115

that such rated paths have interactions with other paths, which result in operating nomograms,

116

and that the NOPR proposal may be more appropriate for a flow-based transmission system.

117

According to PacifiCorp and BPA, it may be infeasible to implement AARs as it would substantially increase the time to compute the constraints that they use to calculate TTC.

118

CAISO also describes the TTC calculation process using rated paths and states that using hourly AARs would exponentially increase the complexity of such calculations and would necessitate further automation.

119

Similarly describing the challenges of incorporating AARs into ATC, EEI explains that, in some areas, TTC values are determined annually, or even less frequently.

120

113

Id.

at 3-4; PacifiCorp Comments at 2; IID Comments at 5-6; EEI Comments at 10-11.

114

IID Comments at 5.

115

BPA Comments at 3; PacifiCorp Comments at 2.

116

Nomograms are operating constraints related to the flow on multiple paths that generally result from the simultaneous interaction between those paths.

117

BPA Comments at 3; PacifiCorp Comments at 2.

118

BPA Comments at 3; PacifiCorp Comments at 2.

119

CAISO Comments at 10.

120

EEI Comments at 11.

60. California transmission owners urge more targeted AAR implementation.

121

PG&E recommends requiring transmission owners to determine which lines would realize net benefits for customers if AARs were deployed, noting that deployment of AARs across all transmission lines could result in a negative return on investment and an increased risk profile for the transmission system.

122

PG&E notes that most of its weather stations are currently located in “High Fire Threat Districts” and contends that AAR implementation on 500 kV lines will require planning for additional weather station equipment to ensure that accurate weather data is available.

123

SCE advocates for phased AAR implementation in which transmission owners identify priority facilities, and, after implementation, study their implementation in a report filed with the Commission.

124

SDG&E contends that settings for all relays will have to be studied and installed in the field, causing a significant cost burden unaccounted for in the Commission's analysis.

125

IID contends that the Commission should not take a one-size-fits-all approach and, in addition to the challenges of AAR implementation, encourages the Commission to consider the costs of software, equipment, and staffing in comparison to the benefits of AARs providing congestion relief.

126

121

PG&E Comments at 3; SCE Comments at 1-2; SDG&E Comments at 1-2; LADWP Comments at 2-3.

122

PG&E Comments at 3.

123

Id.

at 9-10.

124

SCE Comments at 3-4.

125

SDG&E Comments at 4.

126

IID Comments at 5.

61. LADWP states that Southern California loads peak in the summer when temperatures are already high and may not allow AARs to expand transfer capability. Conversely, according to LADWP, there is already abundant transfer capability in the winter months.

127

Describing AAR implementation challenges, LADWP notes that, due to the diversity in terrain and microclimates that western transmission lines traverse, weather forecasts can vary significantly during volatile weather seasons and present

challenges in identifying the most constraining ambient conditions for a given transmission line.

128

LADWP therefore contends that the Commission should consider offering regional exceptions from the AAR requirements or prescribing AARs only in areas where significant benefits are expected.

129

127

LADWP Comments at 3-4.

128

Id.

at 5-6.

129

Id.

at 4-5.

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

130

PJM Comments at 2.

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

131

CAISO Comments at 2.

64. MISO states that AAR and DLR deployment can support the efficient use of existing transmission infrastructure but is not a long-term solution to meet emerging system needs. MISO states that the Commission should not mandate the use of AARs where the burden of that deployment is greater than the benefits to be expected. MISO contends that the Commission should explore options for a more targeted application of identifying facilities that are good candidates for AARs based on objective criteria and documented methodologies.

132

MISO notes that it and MISO Transmission Owners have already commenced an effort to identify a prioritized list of candidate transmission facilities for deployment of real-time AARs in MISO.

133

132

MISO Comments at 9.

133

MISO Comments at 14.

65. NYISO does not support a uniform approach to managing transmission line ratings and instead requests that each RTO/ISO work with the Commission to set objectives for its markets.

134

NYISO contends that AAR use would not provide benefits everywhere.

135

NYISO explains that using AARs to modify day-ahead transmission line ratings would overly complicate the day-ahead market solution and would reduce efficiency.

136

NYISO requests flexibility for regional variation with transmission line ratings given regional differences, such as transmission scheduling and market rules.

137

NYISO states that it could work with stakeholders to develop a proposal to implement three to four sets of seasonal line ratings that would be easier to implement and still achieve many of the NOPR objectives.

138

134

NYISO Comments at 1.

135

Id.

at 2.

136

Id.

at 1-2.

137

Id.

at 2.

138

Id.

at 20.

66. Neither ISO-NE nor SPP explicitly takes a position on the NOPR proposal to implement AARs. However, ISO-NE states that most of the congestion that occurs on its system is due to voltage or stability limitations, and thus AAR benefits may be limited.

139

ISO-NE estimates that the implementation of AARs could result in the lowering of thermal congestion costs by, at most, approximately $5-10 million per year.

140

ISO-NE also contends, however, that AAR implementation may expose other binding system limitations without appreciably increasing transfer capability or reducing congestion.

141

139

ISO-NE Comments at 4-6.

140

Id.

at 5 (basing estimates on 2019 data contained in IMM and EMM Reports and the Commission's estimates of potential savings from AARs in other RTO/ISO regions).

141

Id.

at 6.

67. Market monitors are mostly supportive of the proposed AAR requirements.

142

The SPP MMU supports the proposed reforms to improve the accuracy and transparency of transmission line ratings used by transmission providers. The SPP MMU notes that numerous SPP transmission lines are not rated according to SPP Planning Criteria.

143

The SPP MMU states that it supports the use of DLRs for all transmission lines.

144

According to the SPP MMU, when transmission line ratings underestimate the actual transfer capability of the transmission system, this can result in restricted flows on certain paths while overloading others and can create a potential for de facto physical withholding of the available transfer capability by transmission owners.

145

The SPP MMU argues that more accurate transmission line ratings will improve the robustness of price formation, particularly in congested areas.

146

142

Potomac Economics Comments at 3-4; CAISO DMM Comments at 2-4; SPP MMU Comments at 1, 4.

143

SPP MMU Comments at 4.

144

Id.

at 1, 4.

145

Id.

at 7.

146

Id.

at 9.

68. Potomac Economics states that only 8% of the transmission line ratings in MISO are adjusted for changes in ambient air temperatures. Potomac Economics indicates that it conservatively estimates that the benefits of using AARs and emergency ratings in 2019 and 2020 would have been between 9% and 13% of the real-time congestion value, or $98 million and $114 million per year.

147

Potomac Economics notes that transmission owners have little or no economic incentive to provide temperature-adjusted ratings and that transmission operators

148

rarely verify or validate transmission line rating methodologies or transmission line rating calculations.

149

Potomac Economics contends that it would be unreasonable to require AARs on all transmission facilities, and instead argues that it would be more reasonable to require that processes be established to allow for additional AARs to be deployed quickly when new constraints begin to bind or other studies indicate it may be appropriate.

150

Potomac Economics cautions, however, against requiring any cost-benefit analysis, noting that the incremental cost of initiating AARs on new constraints is near zero so such analysis is unnecessary.

151

Finally, Potomac Economics contends that using AARs and emergency ratings will not create reliability concerns as the NOPR proposal only requires that decisions to not implement AARs or emergency ratings be based on reliability and not a preference or policy decision.

152

CAISO DMM supports the proposed requirements to implement hourly AARs as a way to improve both the accuracy of congestion costs and transmission system efficiency.

153

147

Potomac Economics Comments at 7-9;

see also

Potomac Economics Reply Comments at 2-6.

148

The NERC Glossary defines a “Transmission Operator” as: “[t]he entity responsible for the reliability of its `local' transmission system, and that operates or directs the operations of the transmission Facilities.” NERC,

Glossary of Terms Used in NERC Reliability Standards

(June 28, 2021),

https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.

149

Potomac Economics Comments at 9-10;

see also

Potomac Economics Reply Comments at 6-7.

150

Potomac Economics Comments at 20;

see also

Potomac Economics Reply Comments at 9.

151

Potomac Economics Reply Comments at 7.

152

Id.

at 11.

153

CAISO DMM Comments at 2, 4.

69. State government agencies are also mostly supportive of the proposed AAR requirements.

154

New England State Agencies state that they strongly support the Commission's proposed AAR requirements.

155

New England State Agencies state that the transmission system was built on behalf of and paid for by ratepayers, and argue that the Commission should take all reasonable steps to protect those ratepayers from excessive costs. New England State Agencies contend that the use of AARs can be an important tool in this regard.

156

New England State Agencies state that a transmission system operated using AARs may provide benefits by possibly: (1) Obviating the need for new transmission lines, thus deferring capital costs;

157

(2) reducing reliance on higher cost local reserves which will reduce costs and local reserve requirements resulting from an increased ability to flow power into load pockets;

158

and (3) helping with the integration of new clean energy resources.

159

Finally, New England State Agencies argue that, because parts of MISO as well as most of ERCOT are already employing AARs, there can be no serious argument that AARs are too difficult or costly to implement as was suggested by some transmission owners.

160

154

New England State Agencies Comments at 10; OMS Comments at 2; Ohio FEA Comments at 2.

155

New England State Agencies Comments at 10.

156

Id.

157

Id.

at 10-11.

158

Id.

at 12.

159

Id.

160

Id.

70. OMS states that it supports the NOPR proposal that AAR requirements generally apply to all transmission lines and not just those with historical congestion.

161

OMS notes that the most expensive energy prices typically occur after unforeseen outages or weather events and are not the result of chronic, well understood scenarios. However, OMS also states that it does not support requiring AARs on those facilities where it is uneconomical or unreliable to do so.

162

OMS contends that the Commission should require RTOs/ISOs to develop a process whereby transmission owners transparently work with the RTOs/ISOs and market monitors to demonstrate why any exceptions from the requirements are justified.

163

161

OMS Comments at 8-10;

see also

OMS Reply Comments at 7, 10.

162

OMS Comments at 9.

163

Id.

71. Ohio FEA also supports the AAR NOPR proposal, stating that AARs help ratepayers to realize the full benefits of their transmission system investment. Ohio FEA explains that the four Ohio transmission owners have already recognized the benefits of AARs, as a way of moving away from static ratings.

164

However, UDPU contends that the AAR NOPR proposal should be limited to certain historically congested facilities until the Commission has better information to assess the costs and benefits of broad AAR implementation.

165

164

Ohio FEA Comments at 2-4.

165

UDPU Comments at 1-3.

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

166

CEA Comments at 2.

73. Other technical experts are also supportive of more accurate transmission line ratings.

167

R Street Institute states that understated transmission line ratings can result in increased congestion costs and underutilization of generation in export-constrained locales, which is disproportionately zero-emission generation.

168

R Street Institute contends that the Commission should require DLRs by default and permit exceptions where justified by a cost-benefit analysis.

169

167

R Street Institute Comments at 1; WATT Comments at 1-2; LineVision Comments at 1-2.

168

R Street Institute Comments at 1.

169

Id.

at 3, 5-7.

74. WATT supports the direction the Commission is taking with the NOPR's AAR requirements, but explains that additional factors that affect transmission line ratings but are not incorporated into AARs are very knowable.

170

WATT contends that the Commission should require the use of DLRs when certain criteria are met.

171

LineVision supports WATT's comments and states that DLR implementation will also result in additional accuracy and situational awareness.

172

170

WATT Comments at 1-2.

171

Id.

at 10-12.

172

LineVision Comments at 1-2.

75. Renewable energy advocates are also generally supportive of the AAR NOPR proposal, but urge the Commission to take further measures to spur the implementation of DLRs.

173

For example, ACORE commends the Commission for issuing the NOPR, but recommends the Commission take further steps to encourage DLR deployment by incenting its deployment through transmission incentives and incorporating its assessment into transmission planning processes.

174

Similarly, Clean Energy Parties contend that AARs are easy to implement and a modest improvement over static line ratings.

175

However, Clean Energy Parties argue that DLR is superior to AAR, though Clean Energy Parties do not contend a blanket DLR mandate is appropriate.

176

ACPA/SEIA support accurate transmission line ratings, and contend that the Commission should require

all

transmission owners and transmission providers to study the costs and benefits of implementing DLRs on persistently congested transmission lines and require implementation where warranted.

177

ACPA/SEIA and Clean Energy Parties both argue that the Commission should alter its NOPR proposal to prioritize transmission lines that are expected to be congested, persistently congested, or likely to be congested in the future.

178

173

ACORE Comments at 1; Clean Energy Parties Comments at 2, 4-6.

174

ACORE Comments at 1.

175

Clean Energy Parties Comments at 4-5.

176

Id.

at 5, 8.

177

ACPA/SEIA Comments at 5-7.

178

Id.

at 8-9; Clean Energy Parties Comments at 8, 10.

76. Generator owners and representatives are also generally supportive of the proposed AAR requirements.

179

EDFR argues that getting the transmission line rating policy right is important due to the urgency of addressing the climate crisis and President Biden's carbon emissions reduction goals. EDFR contends that a lack of adequate transfer capability can cripple clean energy generation.

180

EDFR further explains that, under many offtake agreements in RTO/ISO markets, the developer is paid a fixed price for energy at a market hub and if congestion limits the project's ability to deliver power to the hub, then the developer bears the risk (known as basis risk). EDFR argues that congestion is difficult to hedge in an effective way because system topology and conditions change unexpectedly over time, but states that more accurate transmission line ratings will decrease basis risk and hedging difficulties.

181

EDFR contends that prioritization should not only consider historical congestion, but should consider future congestion based on transmission planning, interconnection, and transmission service studies for purposes of prioritizing implementation.

182

179

ENEL Comments at 1; EDFR Comments at 1-2; Vistra Comments at 1-2; EPSA Comments at 2.

180

EDFR Comments at 2.

181

Id.

182

Id.

at 4.

77. EPSA contends that the Commission should encourage the use of technological advances that improve transmission operators' ability to track and optimize transmission line ratings and usage where feasible and cost effective. EPSA states that PJM's adoption of AAR requirements has shown clear benefits.

183

Vistra is supportive of the Commission's NOPR proposal, stating that it is imperative that the Commission act now to make best use of existing infrastructure and that AARs and DLRs are the best way to do that.

184

183

EPSA Comments at 2.

184

Vistra Comments at 1-2.

78. Industrial Customer Organizations, TAPS, and Certain TDUs are also broadly supportive of the AAR NOPR proposal.

185

Certain TDUs state that they support the proposed rule and encourage the Commission to mandate improvements to the accuracy and transparency of transmission line ratings because not all transmission owners have shown a willingness to make these improvements voluntarily.

186

Certain TDUs state that they support the use of AARs as a way to better utilize the existing transmission system, noting that it will become imperative that the existing transmission system is utilized to the greatest extent possible as additional renewable resources come online.

187

185

Industrial Customer Organizations Comments at 1-2; TAPS Comments at 1-2; Certain TDU Comments at 1.

186

Certain TDUs Comments at 4.

187

Id.

at 4-5.

79. Industrial Customer Organizations state that they generally support the proposed rules, but assert that these rules should be implemented as soon as practicable.

188

Industrial Customer Organizations argue that, if prioritization is needed, congested circuits should be prioritized.

189

Industrial Customer Organizations explain that understated transmission line ratings increase congestion and may lead to curtailments. Industrial Customer Organizations contend that transmission owners that understate transmission line ratings may create an illusory need for transmission upgrades. Further, Industrial Customer Organizations contend that some transmission line ratings may be deliberately understated because transmission owners may have a profit incentive to calculate understated transmission line ratings in order to benefit local generation.

190

188

Industrial Customer Organizations Comments at 15-18.

189

Id.

at 18-19.

190

Id.

at 4.

80. TAPS states that it supports the proposed broad application of AARs because it reduces the likelihood that AARs will be implemented in a discriminatory manner.

191

Similarly, Clean Energy Parties cite Order No. 888,

192

in which the Commission stated that “[d]enials of access [to transmission services] (whether they are blatant or subtle), and the potential for future denials of access [to transmission services], require the Commission to revisit and reform its regulation of transmission in interstate commerce.”

193

According to Clean Energy Parties, Order No. 888 supports the assertion that a lack of consistency and transparency in transmission line ratings creates the potential for future denials of access to transmission service, as inaccurate transmission line ratings are used to provide discriminatory transmission service to preferential customers.

194

191

TAPS Comments at 7.

192

Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities,

Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996) (cross-referenced at 75 FERC ¶ 61,080),

order on reh'g,

Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220),

order on reh'g,

Order No. 888-B, 81 FERC ¶ 61,248 (1997),

order on reh'g,

Order No. 888-C, 82 FERC ¶ 61,046 (1998),

aff'd in relevant part sub nom. Transmission Access Policy Study Group

FERC,

225 F.3d 667 (D.C. Cir. 2000),

aff'd sub nom. New York

FERC,

535 U.S. 1 (2002).

193

Id.

at 31,652.

194

Clean Energy Parties Comments at 2-3.

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

195

TAPS Comments at 20.

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

196

Prysmian Comments at 1.

c. Commission Determination

83. In this final rule, we adopt with certain modifications the NOPR proposal to require transmission providers to apply the AAR requirements set forth in

pro forma

OATT Attachment M to all transmission lines, subject to the exceptions described below in Section IV.D.3.

197

As discussed above, the AAR requirements will ensure that transmission line ratings are more accurate. In turn, more accurate transmission line ratings will ensure wholesale rates more accurately reflect the cost of the wholesale service being provided (

i.e.,

energy, capacity, ancillary services, or transmission service) and, thus, that those wholesale rates are just and reasonable. We further describe, below, the requirements and the modifications to the NOPR proposal adopted herein.

197

NOPR, 173 FERC ¶ 61,165 at PP 92, 102.

84. First, we adopt the proposal to apply the AAR requirements as set forth under “Obligations of Transmission Provider” in

pro forma

OATT Attachment M to all transmission lines subject to the exceptions described below in Section IV.D.3. We find that applying the AAR requirements to all transmission lines will both ensure that wholesale rates remain just and reasonable and strike an appropriate balance between benefits and challenges of AAR implementation. For this reason, we do not adopt the phased-in implementation schedule proposed in the NOPR in which a transmission provider would initially implement AARs on only historically congested lines.

85. As the Commission preliminarily found in the NOPR

198

and as the record demonstrates, despite differences across transmission systems, simply accounting for ambient air temperatures in transmission line ratings can reliably increase power transfer capability, resulting in significant reliability, operational, and economic benefits. Numerous commenters describe these benefits.

199

For example, Potomac Economics estimates that the benefits to AAR implementation in MISO alone would have produced approximately $67 million and $49 million in reduced congestion costs in 2019 and in 2020,

respectively.

200

Exelon describes AARs as a best practice that cost-effectively enhances transmission utilization, benefiting customers, without adverse safety and reliability impacts.

201

EEI acknowledges that experience with AARs shows that their use can provide benefits on certain subsets of transmission facilities.

202

PJM states that, in its experience, AARs increase operational flexibility, promote a more efficient use of the transmission system, and result in more reliable system dispatch and cost-effective market operations.

203

New England State Agencies argue that the Commission should take all reasonable steps to protect ratepayers from excessive costs and that the use of AARs, by permitting more power to flow than a system operated using static or seasonal line ratings, can be an important tool in this regard.

204

Similarly, TAPS explains that reliance on static and seasonal line ratings inflicts unnecessary costs on consumers and contends that deployment of AARs using commercial temperature forecasts can produce significant benefits to consumers at low cost.

205

While several entities note implementation costs as a barrier, these costs are mostly initial investment costs in EMS improvements to accommodate AARs, implementation of a ratings database, and review (and potentially reset) of protective relays settings.

206

Once these initial investments are made, adding AARs to additional transmission lines appears to have a minimal incremental cost.

207

198

Id.

P 99.

199

MISO Transmission Owners Comments at 8-9; PacifiCorp Comments at 2; EEI Comments at 4-5; Entergy Comments at 1-2; BPA Comments at 2-4; NYTOs Comments at 2-3, 5; Duke Energy Comments at 6-7; PG&E Comments at 1; LADWP Comments at 2-3; ITC Comments at 1-3; Sunflower Comments at 2; Exelon Comments at 1-2; AEP Comments at 3; Indicated PJM Transmission Owner Comments at 2; PJM Comments at 2; PJM Comments at 2; New England State Agencies Comments at 7; TAPS Comments at 5.

200

Potomac Economics Comments at 7-8.

201

Exelon Comments at 1.

202

EEI Comments at 5.

203

PJM Comments at 2.

204

New England State Agencies Comments at 5-6, 10-11.

205

TAPS Comments at 5.

206

Indicated PJM Transmission Owner Comments at 5-6; Exelon Comments at 14; AEP AD19-15 Post Technical Conference Comments at 3.

207

Exelon Comments at 8; Indicated PJM Transmission Owner Comments at 5-6; AEP Post-Technical Conference Comments at 2-3; September 2019 Technical Conference, Day 1 Tr. at 180-181.

86. Second, in this final rule we adopt a requirement for transmission providers to use AARs when evaluating the availability of and requests for near-term transmission service (under sections 15, 17, 18, and 29 of the

pro forma

OATT).

208

For purposes of this requirement, we define “requests for near-term transmission service” to include not only requests for near-term point-to-point transmission service, but also network resource designations and secondary service where the start and end date of the designation/request is within the next 10 days. Specifically, we require transmission providers to use AARs as the relevant transmission line ratings when: (1) Evaluating requests for near-term transmission service, defined as transmission service ending within 10 days of the date of the request; (2) responding to requests for information on the availability of potential near-term transmission service (including requests for ATC or other information related to potential service); and (3) posting ATC or other information related to near-term transmission service to their OASIS site. As discussed further below, in response to comments, we modify this requirement from the NOPR proposal to include near-term network and near-term secondary service, as well as the near-term point-to-point transmission service proposed in the NOPR.

209

208

NOPR, 173 FERC ¶ 61,165 at P 87.

209

Although requests for network transmission service are typically long-term requests, meriting their evaluation using seasonal line ratings, we note the Commission's finding in Order No. 890 that the minimum term for network transmission service should be the same as the minimum time period used for firm point-to-point transmission service (

i.e.,

daily).

See Preventing Undue Discrimination and Preference in Transmission Service,

Order No. 890, 72 FR 12266 (Mar. 15, 2007), 118 FERC ¶ 61,119, at P 1505,

order on reh'g,

Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), 121 FERC ¶ 61,297 (2007),

order on reh'g,

Order No. 890-B, 123 FERC ¶ 61,299 (2008),

order on reh'g,

Order No. 890-C, 74 FR 12540 (Mar. 25, 2009), 126 FERC ¶ 61,228,

order on clarification,

Order No. 890-D, 129 FERC ¶ 61,126 (2009). As such, any requests for transmission service that fall within the near-term threshold defined herein would qualify as near-term network transmission service.

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

pro forma

OATT)

210

if such curtailment or interruption is both necessary because of issues related to flow limits on transmission lines and anticipated to occur (start and end) within the next 10 days.

211

210

Additionally, we add references to interruption or curtailment of near-term point-to-point transmission service occurring pursuant to 13.6 of the

pro forma

OATT to Attachment M in order to ensure consistent treatment of firm and non-firm point-to-point transmission service.

211

NOPR, 173 FERC ¶ 61,165 at P 89.

88. Fourth, we adopt the proposal in the NOPR

212

to require that transmission providers use AARs as the relevant transmission line ratings when determining whether to curtail network or secondary service (under section 33 of the

pro forma

OATT) or redispatch network or secondary service (under sections 30.5 and/or 33 of the

pro forma

OATT), if such curtailment or redispatch is both necessary because of issues related to flow limits on transmission lines and anticipated to occur (start and end) within 10 days of such determination.

212

Id.

P 90.

89. Fifth, we adopt and modify the proposal in the NOPR to allow RTOs/ISOs to comply with the final rule's AAR requirements by revising their OATTs to require implementation of AARs within their security constrained economic dispatch (SCED) and security constrained unit commitment (SCUC) models (and in any relevant related models) in both the day-ahead and real-time markets and reliability unit commitment (RUC) processes,

213

and any other intra-day RUC processes.

214

As the Commission recognized in the NOPR, such entities have Commission-approved variations from the

pro forma

OATT to manage congestion and initiate curtailments and/or redispatch of transmission service within their footprints (although generally not at their borders) through mechanisms such as SCED and SCUC. As discussed in Section IV.B.3.b, we adopt the Commission's NOPR proposal to require that transmission providers—including RTOs/ISOs—update their AARs at least hourly. As discussed in Sections IV.B.3.b and IV.B.3.c, for any seams-based transmission service offered by RTOs/ISOs, we adopt the Commission's NOPR proposal to implement the near-term transmission service requirements for inclusion of up-to-date hourly AAR calculations in ATC.

213

After the day-ahead market process takes place, RTOs/ISOs typically perform one or more residual unit commitment processes, or what we refer to here as RUC, to address remaining resource gaps and reliability issues or to manage uncertainty and the potential for real-time operational issues. The exact names, definitions, and market processes implementing what we refer here to as RUC processes differ across RTOs/ISOs. For example, CAISO refers to its process as residual unit commitment, SPP uses reliability unit commitment, and MISO uses reliability assessment commitment. For simplicity, however, this final rule uses the term RUC to refer to all of these relevant processes in all of the RTO/ISO markets interchangeably.

214

NOPR, 173 FERC ¶ 61,165 at P 91. The statement “(and in any relevant related models)” was intended to encompass all RUC processes within the timeframe. In the interest of clarity, we modify the NOPR proposal here to make that more explicit.

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

extent that commenters were arguing for a narrower application than what we adopt in this final rule, below we explain the basis for application of the AAR requirements to all transmission lines.

91. Finally, we alter the proposed compliance schedule. Specifically, we require each transmission provider to submit a compliance filing within 120 days of the effective date of this final rule to incorporate into its OATT the changes adopted herein consistent with

pro forma

OATT Attachment M and the changes to the Commission's regulations set forth below. Additionally, we further require that all requirements adopted herein be fully implemented no later than three years from the compliance filing due date established by this final rule.

92. In response to comments received in response to the NOPR, we modify the NOPR proposal's defined term “near-term point-to-point transmission service” to instead be “near-term transmission service.” As a result, the AAR requirements will apply to requests for near-term network transmission service, near-term secondary service, and near-term point-to-point transmission service, provided that such service meets the 10-day threshold defined in the near-term transmission service definition. We agree with TAPS that it would be inappropriate to apply the AAR requirements only to requests for near-term point-to-point transmission service and not to requests for near-term network and near-term secondary service because secondary service comes before non-firm point-to-point transmission service in curtailment priority.

215

More generally, we find that a requirement to use AARs on all types of near-term transmission service will better ensure that transmission line ratings are accurate and that wholesale rates are just and reasonable.

215

TAPS Comments at 18-20.

93. Although commenters broadly raise concerns with adopting transmission line ratings that may fluctuate widely or contend that implementing AARs on certain transmission lines may not yield benefits, we do not find that these concerns and arguments overcome the need to improve the accuracy of transmission line ratings through applying the AAR requirements to all transmission lines. Specifically, we decline to accommodate requests for more targeted AAR requirements in which transmission providers would either have flexibility to identify candidate transmission lines or the Commission would require AAR implementation on only priority transmission lines, such as only on historically congested lines.

94. We recognize commenters' concerns, such as those from NRECA/LPPC, that the promised benefits, costs, and risks of implementing AARs may not be evenly distributed nationwide.

216

Nevertheless, we find that with the broad AAR requirements adopted herein, the overall benefits via savings to load and lower congestion charges to generators will on balance outweigh the costs. Moreover, we acknowledge the difficulty of knowing in advance all the locations and situations in which the benefits of AAR implementation will outweigh the costs. Given the difficulty in predicting unexpected congestion before it happens, narrowing the scope of the AAR requirements would limit the ability of these reforms to ensure just and reasonable wholesale rates. In particular, we find that the AAR requirements adopted in this final rule are beneficial in mitigating the impact of transient congestion,

i.e.,

temporary or short-term congestion that does not occur on a regular basis, such as congestion caused by unexpected equipment outages or other unusual conditions. Furthermore, given the increasing occurrence of extreme weather events, we expect that assessing the benefits of broader AAR implementation based on historical congestion likely understates the potential savings associated with implementation of the AAR requirements adopted in this final rule. By contrast, the record demonstrates that AAR implementation costs are predominantly one-time investment costs in EMS improvements to accommodate AARs, implementation of a ratings database, and review (and potentially reset) of protective relays settings.

217

Once these costs have been incurred, the incremental cost of applying AARs to additional transmission facilities is minimal.

218

216

NRECA/LPPC Comments at 15.

217

Exelon Comments at 8-9.

218

Id.

at 8; Indicated PJM Transmission Owner Comments at 5-6; AEP Post-Technical Conference Comments at 2-3; September 2019 Technical Conference, Day 1 Tr. at 180-181.

95. Attempts to anticipate the situations in which AARs will not be cost beneficial (

e.g.,

attempts to forecast locations and situations in which there will be future congestion and deploy AARs in only those anticipated situations) will necessarily be imperfect and complex, especially during infrequent but consequential events. Additionally, since many emergencies may come and go before new AARs can be developed and implemented for newly congested transmission lines, a more targeted AAR requirement advocated by some commenters may not accurately represent system transfer capability in such critical situations. As the Commission recognized in the NOPR, congestion is difficult to predict, particularly during emergency conditions.

219

The 2019 FERC and NERC Staff Report on the January 2018 South Central cold weather event illustrates this point.

220

As shown by that event, during times of emergency or system stress, flows may change considerably from normal operations and the increased transfer capability provided through AARs may prove valuable even on transmission lines that are not typically congested.

221

In addition, in the February 2021 cold weather event, MISO experienced unprecedented east-to-west flows throughout the footprint and accrued $773 million in congestion charges in just a few days.

222

We note that with broad AAR implementation, given Potomac Economics' finding that AAR implementation consistently results in savings of approximately 5% to 8% of total congestion,

223

congestion cost savings from this single event might have exceeded the total costs of AAR implementation in the region. Moreover, many argue that the changing generation mix makes congestion prediction even more difficult.

224

Additionally, AAR implementation itself will have secondary consequences for congestion patterns, as changes to transmission line ratings may change generation dispatch patterns and, by extension, congestion patterns. Such secondary congestion consequences may only be able to be promptly addressed by a broad AAR requirement that applies to all transmission lines.

219

NOPR, 173 FERC ¶ 61,165 at P 93.

220

2019 FERC and NERC Staff Report,

The South Central United States Cold Weather Bulk Electric System Event of January 17, 2018,

at 96 (July 2019) (FERC and NERC Staff Report),

https://www.ferc.gov/sites/default/files/2020-05/07-18-19-ferc-nerc-report_0.pdf.

221

NOPR, 173 FERC ¶ 61,165 at P 93.

222

OMS Comments at 10; OMS Reply Comments at 7;

see

FERC, NERC and Regional Entity Staff Report,

The February 2021 Cold Weather Outages in Texas and the South Central United States

(Nov. 16, 2021),

https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and.

223

Potomac Economics Comments at 8; Potomac Economics Post-Technical Conference Comments at 5-6.

224

ACPA/SEIA Comments at 8, 11; EPSA Comments at 4; New England State Agencies Comments at 6.

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

spend limited time requesting AARs from transmission owners on an

ad hoc

basis.

225

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

225

OMS Reply Comments at 7;

see also

FERC and NERC Staff Report at 56-59; ISO-NE,

Cold Weather Operations: December 24, 2017—January 8, 2018,

at 41 (Jan. 16, 2019),

https://www.iso-ne.com/static-assets/documents/2018/01/20180112_cold_weather_ops_npc.pdf.

97. Further, arguments that the benefits of broad AAR implementation will not outweigh the costs are inconsistent with the ERCOT and PJM transmission owners' actual AAR implementation experience. AEP has been implementing AARs for decades and has realized both reliability and financial benefits for its customers.

226

As Indicated PJM Transmission Owners state, transmission owners in PJM provide AARs for each of their facility ratings.

227

PJM further states that the use of AARs is commonplace among the overwhelming majority of transmission owners in PJM.

228

As New England State Agencies observe, the broad experience implementing AARs does not support the argument that AARs are too difficult or costly to implement.

229

226

AEP Comments at 3.

227

Indicated PJM Transmission Owners Comments at 6-7.

228

PJM Comments at 2.

229

New England State Agencies Comments at 11-12.

98. In response to MISO Transmission Owners' argument that the Commission should not rely on Potomac Economics' estimates of the benefits of AARs, our rationale for the AAR requirements adopted in this final rule is not solely based on Potomac Economics' analysis. Rather, our rationale is based on the finding that AARs on all transmission lines will ensure that wholesale rates more accurately reflect the cost of the wholesale service being provided, and, thus that those wholesale rates are just and reasonable. This finding is further informed by the widespread benefits experienced by commenters implementing AARs broadly in PJM and ERCOT, the expectation that the benefits of AAR implementation will be greatest on transmission lines that are frequently congested, along with the understanding of the difficulty of predicting congestion and the low incremental cost to implement AARs. However, in response to MISO Transmission Owners' critique that Potomac Economics' analysis erroneously assumes that all transmission lines in MISO are ambient adjustable, we note that, in response to MISO Transmission Owners' comments, Potomac Economics states that its analysis does not assume that all transmission lines are able to be rated using AARs and instead removes from the analysis all transmission lines that currently have summer ratings equal to winter ratings.

230

With respect to MISO Transmission Owners' argument that Potomac Economics' analysis erroneously assumes that all transmission lines in MISO are currently using worst-case ambient air temperature assumptions, we note that Potomac Economics does not uniformly assume worst-case 104 degrees Fahrenheit as the basis for adjusting AARs, but instead infers unique transmission owner base assumptions using maximum historical temperatures in each transmission owner service territory.

231

Finally, we disagree with MISO Transmission Owners' assertion that the benefits in Potomac Economics' analysis are inflated because of certain transmission outages or upgrades assumptions. As Potomac Economics explains, there are many generalized and localized factors that might increase or decrease congestion in an individual year and, given the highly complex nature of the electric system, incorporating all of these factors is not possible.

232

Despite certain generalizations, which we believe are likely to render Potomac Economics' analysis conservative, Potomac Economics has consistently found that AARs and emergency ratings will reduce congestion by 10% to 15% annually.

233

230

Potomac Economics Reply Comments at 3-5.

231

Id.

at 2-3.

232

Id.

at 5-6.

233

Id.

at 5.

99. We disagree with arguments from Southern Company, EEI, and other commenters that reliability issues may arise because AARs may create difficulties in identifying the most limiting element and similar difficulties and costs associated with complying with Reliability Standard PRC-023-4's transmission relay loadability requirements that depend on maximum published ratings. Reliability Standard PRC-023-4 requires setting transmission line relays at values at or above 115 to 170% of various maximum values for current or power carrying capability,

e.g.,

115% of the highest seasonal 15-minute Facility Rating of a circuit or 150% of the highest seasonal four-hour Facility Rating of a circuit. We do not agree that this final rule will result in PRC-023-4 related relay setting changes to “thousands”

234

of relays, since the relay settings are currently calculated based on practical limitations which in the majority of cases should not exceed AAR values. In addition, PJM has long implemented AARs and, rather than describing reliability challenges, contends that AAR implementation creates reliability benefits.

235

For example, PJM states that the adoption of AARs increases operational flexibility, promotes a more efficient use of the transmission system, and results in more reliable system dispatch and cost-effective market operations.

236

Transmission owners in PJM have implemented AARs despite the initial cost incurred to update relay settings. Likewise, AEP submits that it has implemented AARs for decades and that AAR implementation presents reliability benefits.

237

234

EEI Comments at 5-6.

235

PJM Comments at 7.

236

Id.

at 2.

237

AEP Comments at 3.

100. In response to concerns about the additional challenges associated with incorporating AARs into ATC, as raised by Duke Energy, EEI, and several non-RTO/ISO transmission owners with service territories in the Western Interconnection, we note that such TTC calculation practices, and in turn ATC practices, particularly those which only update TTC values annually,

238

will need to be updated in order to comply with this final rule's AAR requirements. In fact, such practices may already be out of compliance with the Commission's

existing

ATC calculation rules. For example, while Order No. 890 provides transmission providers with significant flexibility in what approach they take to determine ATC in their transmission paths, it also requires that ATC values (regardless of the approach used to calculate them) be “updated and benchmarked to actual events.”

239

Furthermore, in May 2021, the Commission issued Order No. 676-J,

240

in which the Commission (among other things) codified the “fundamentals of Order No. 890 requirements for calculating ATC” in the Commission's regulations.

241

Specifically, Order No.

676-J revised section 37.6(b)(2)(i) of the Commission's regulations to codify that ATC calculations must be “conducted in a manner that is . . . consistent with anticipated system conditions and outages for the relevant timeframe.”

242

We find that transmission line ratings represent one such “system condition” with which ATC calculations must be consistent.

238

EEI Comments at 11.

239

Order No. 890, 118 FERC ¶ 61,119 at P 290.

240

Standards for Business Practices and Communication Protocols for Public Utilities,

Order No. 676-J, 86 FR 29491 (June 2, 2021), 175 FERC ¶ 61,139 (2021).

241

Id.

P 38.

242

Id.

101. In response to specific concerns from PacifiCorp and BPA about nomogram constraints, we note that nomogram constraints are typically used to represent transfer capability on facilities with stability or voltage limitations. The AAR requirements adopted in

pro forma

OATT Attachment M exempt transmission lines whose ratings are not affected by ambient air temperature.

102. In response to comments from NERC requesting further consideration of AAR implementation on long transmission lines, and from LADWP, and other, primarily western transmission owners, which describe AAR implementation challenges due to the diversity in terrain and microclimates that western transmission lines traverse, we agree that longer transmission lines can and will experience differing weather conditions across the length of those transmission lines. To maintain reliable system operations, we expect transmission providers to implement the transmission line rating calculated based on the most limiting element under the prevailing weather conditions (actual or anticipated) at the relevant point on the transmission line. In the case of transmission conductors, which might be exposed to different weather conditions along the length of the transmission line, transmission providers must rate such elements using the most limiting weather conditions, in accordance with good utility practice. However, this requirement does not require the installation of field devices or sensors, as some transmission owners suggest.

243

Rather, as proposed in the NOPR, the AAR requirements can be met through the use of a weather data service.

244

243

WAPA Comments at 7-9; PG&E Comments at 9-10.

244

NOPR, 173 FERC ¶ 61,165 at P 95.

103. Similarly, in response to comments from BPA that if BPA uses AARs as proposed, it would need to make its current liberal wind assumptions (and therefore, the resultant transmission line ratings) more conservative to mitigate the risk of operating near the conductor limit,

245

we reiterate that the AAR requirements will ensure more accurate transmission line ratings, not necessarily higher transmission line ratings. We further clarify that there is no requirement to change wind speed assumptions. Utilities have operated reliably for decades with AARs.

246

However, if any transmission owner finds it necessary to change its wind speed assumptions consistent with good utility practice, we clarify that nothing in this rulemaking prevents it from doing so.

245

BPA Comments at 4.

246

AEP Comments at 3.

2. Specific AAR Implementation Requirements

a. Use of AARs 10-Days Forward in Transmission Service and Operations

i. NOPR Proposal

104. In the NOPR, within the context of the AAR requirements described and adopted above in Section IV.B.1, the Commission proposed to apply the AAR requirements to transmission service that starts/ends within 10 days, to the curtailment or interruption of point-to-point transmission service anticipated to occur (start and end) within the next 10 days, and to the curtailment of network transmission service or secondary service or redispatch network transmission service or secondary transmission service anticipated to occur (start and end) within 10 days (hereinafter referred to as the “10-day threshold”).

105. The Commission justified the proposed 10-day threshold as a reasonable cut-off beyond which forecasts may not be accurate enough for AARs to provide significant value, and by stating that the Commission believed that such a limit would reasonably accommodate requests for weekly point-to-point transmission service. The Commission further noted that ambient air temperature forecasts for intervals beyond the proposed 10-day threshold tend to converge to the longer-term ambient air temperature forecasts used in seasonal line ratings.

247

Finally, the Commission noted that its proposal allowed transmission providers to determine (consistent with good utility practice) the needed degree of certainty when constructing their forecasts of ambient air temperature.

248

247

NOPR, 173 FERC ¶ 61,165 at PP 87-88.

248

Id.

P 102.

106. With respect to RTOs/ISOs, the Commission proposed to require AARs as the relevant transmission line rating for any point-to-point transmission service offered (

e.g.,

at their borders). However, the Commission also recognized that RTOs/ISOs have Commission-approved variations from the

pro forma

OATT to manage internal congestion and initiate curtailments and/or redispatch of transmission service within their footprints through mechanisms such as SCED and SCUC. To accommodate these variations, the Commission proposed that RTOs/ISOs comply with the proposed requirements by revising their OATTs to require implementation of AARs within their SCED and SCUC models (and in any relevant related models) in both the day-ahead and real-time markets and any intra-day RUC processes. For real-time markets, the Commission proposed that RTOs/ISOs update their AARs at least hourly. For any point-to-point transmission service offered by RTOs/ISOs (

e.g.,

at their borders), the Commission proposed that the AAR requirements discussed above for point-to-point transmission service would apply. As justification, the Commission explained that day-ahead markets already rely upon forecasts of weather to inform next-day load and intermittent generation availability. The Commission preliminarily agreed with PJM that temperatures can be forecast with a reasonable degree of certainty in day-ahead markets.

249

The Commission further stated that, within its NOPR proposal, transmission providers could (consistent with good utility practice) determine the needed degree of certainty when constructing their forecasts of ambient air temperature, and that, because one of the goals of the day-ahead market is to align prices with those eventually determined in the real-time market, maintaining policy consistency between the day-ahead and real-time markets, where practical, is desirable.

250

249

PJM Post-Technical Conference Comments at 3.

250

NOPR, 173 FERC ¶ 61,165 at P 102.

ii. Comments

107. Many commenters generally support the Commission's proposed AAR requirements without specifically discussing the 10-day threshold.

251

Industrial Customer Organizations specifically agree with the Commission that implementing AARs in near-term transmission service will more accurately reflect the cost of delivering

energy to load.

252

CEA states that using AARs to calculate transmission line ratings for service requests up to 10 days has proven to be reliable and to provide benefits to effective and reliable transmission operations.

253

EDFR contends that the distinction between AARs and seasonal line ratings depending on the applicable time frame appears sensible.

254

ACPA/SEIA state that they support the Commission's proposed requirements for near-term point-to-point transmission service and curtailments expected to occur within the next 10 days.

255

The Ohio FEA does not take a firm position, but states that implementing AARs for the next 10 days is reasonable.

256

OMS states that the weather data required to implement AARs is already widely available through public sources and used for load and resource forecasting.

257

251

EPSA Comments at 2; Clean Energy Parties Comments at 2-3; R Street Institute Comments at 2-3; TAPS Comments at 1-3; ACORE Comments at 3; OMS Comments at 2; New England State Agencies Comments at 10; Vistra Comments at 2-3.

252

Industrial Customer Organizations Comments at 4-6.

253

CEA Comments at 2.

254

EDFR Comments at 7.

255

ACPA/SEIA Comments at 16-17.

256

Ohio FEA Comments at 5.

257

OMS Comments at 11.

108. While not supporting or opposing the proposed 10-day threshold, EPRI recommends an independent assessment that documents the accuracy and risk associated with weather forecast data, explaining that not all weather forecast data will be appropriate for transmission line ratings and that some limiting spans run through microclimates. EPRI further explains that inaccurate forecast risks can be mitigated by identifying and implementing corrective factors to allow forecasts to be used consistent with good utility practice. EPRI suggests utility-specific rating studies would be required to assess and mitigate forecast risk,

258

to update and revise weather condition assumptions, and possibly to adjust transmission reliability margins.

259

EPRI contends that further studies are needed to determine a technical basis for updated wind speed assumptions and that such studies may take between one and two years.

260

Similarly, NERC asserts that the Commission should consider how variations in the temperature and load forecast should be addressed, what temperature sets should be used when considering requests to grant firm transmission service, and whether additional AAR calculation information should be incorporated into transmission line rating methodologies.

261

258

EPRI Comments at 10-11.

259

Id.

at 12. Transmission reliability margin, or TRM, means the amount of TTC necessary to provide reasonable assurance that the interconnected transmission network will be secure, or such definition as contained in Commission-approved Reliability Standards. 18 CFR 37.6(b)(1)(viii) (2021)..

260

EPRI Comments at 12.

261

NERC Comments at 7.

109. Other commenters also discuss risk management for forecasted ambient air temperatures. For example, Entergy states that forecasted ambient air temperatures should include appropriate safety margins to account for historical forecast uncertainty.

262

Similarly, the SPP MMU states that, ideally, congestion costs should, to some extent, represent the risk assumed to serve the load.

263

Finally, the CAISO DMM argues that AAR requirements should allow leeway for RTOs/ISOs to adjust modeled transmission limits for reliability reasons, as CAISO does in the case of flowgates and nomograms whose modeled flows frequently differ from actual flows.

264

The CAISO DMM asserts that lower or more conservative transmission limits might be needed for temporally distant intervals to ensure commitments made in an advisory interval horizon are feasible in the binding market interval and at the time of power flow. The CAISO DMM further asserts that lower day-ahead transmission limits could promote the feasibility of day-ahead commitments in real time.

265

262

Entergy Comments at 11.

263

SPP MMU Comments at 1.

264

CAISO DMM Comments at 3, 4-5, 7.

265

Id.

at 3.

110. Many RTOs/ISOs, however, oppose or urge caution on the proposed 10-day threshold, with many advocating instead for a 48-hour threshold.

266

PJM does not support use of AARs in ATC calculations beyond 48 hours, arguing that it would require significant system changes and increase the compliance burden.

267

PJM proposes AARs for 48 hours, and a more conservative approach for hours 48-240 to avoid potential volatility and over-selling.

268

Both NYISO and ISO-NE argue that the transmission service offered in their respective regions differs from that contemplated by the

pro forma

OATT, and request flexibility in implementing any transmission line rating requirements.

269

266

PJM Comments at 7-8; ISO-NE Comments at 10; MISO Comments at 10, 16-17; NYISO Comments at 13-14.

267

PJM Comments at 7-8.

268

Id.

269

ISO-NE Comments at 10; NYISO Comments at 9.

111. NYISO does not support extending the AAR requirements or DLRs into the day-ahead market, or for use up to 10 days into the future, contending that such a requirement could result in costly and unnecessary uplift payments, which could lead to significant cost increases to customers, and could present reliability concerns if transmission line ratings decline in real time from the day-ahead schedule, forcing NYISO to rapidly reduce the schedules of certain generators while quickly ramping up other generators.

270

NYISO also states that it would consider designating a portion of transfer capability to be able to respond to the operational and cost volatility that would come with DLR use, although such a process would limit overall efficiency and increase production costs.

271

270

NYISO Comments at 13-14.

271

Id.

112. Without taking a position on the proposed 10-day threshold, CAISO explains that the NOPR proposal would significantly increase the complexity of its day-ahead market and introduce possible variances between real-time and day-ahead schedules.

272

Also without taking a position on the proposed 10-day threshold, SPP states that, to use AARs to evaluate transmission service requests that end within 10 days or as the basis for curtailment, SPP would have to make several technical and process upgrades and align its operating horizon and planning horizon.

273

272

CAISO Comments at 9-11.

273

SPP Comments at 5-7, 9.

113. MISO argues that the vast majority of the benefit from AARs is in addressing real-time congestion, and that implementing AARs in MISO's day-ahead market would be difficult to do in less than three years, while offering comparatively little benefit. MISO further claims that requiring hourly AARs 10 days in advance will provide little to no benefit because the accuracy of temperature forecasts diminishes considerably beyond 48 hours, and precipitously by the five to seven day mark.

274

MISO urges the Commission to limit AAR implementation to 48 hours from the start of the operating day.

275

Similarly, Potomac Economics recommends that the Commission require that AARs be used in the day-ahead and real-time markets, stating that this will allow the RTOs/ISOs to focus their resources on improving the transmission line ratings that will generate almost all of the savings.

274

MISO Comments at 18.

275

Id.

at 19.

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

276

Those transmission

owners generally argue that there is too much risk forecasting 10 days forward and generally support more limited forecasting of either 24

277

or 48 hours.

278

For example, Indicated PJM Transmission Owners contend that forecasting AARs beyond two or three days in advance provides little benefit because weather conditions beyond that are too difficult to predict.

279

Dominion similarly argues there is no benefit to extending the AAR requirements beyond three to five days because forecasts beyond five days tend to reflect seasonal averages.

280

Entergy contends that forecasts should be limited to three days and include appropriate safety margins for historical forecast uncertainty and geographic variability.

281

276

BPA Comments at 7; Indicated PJM Transmission Owners Comments at 2; Dominion

Comments at 8-9; Duke Energy Comments at 8-9; SDG&E Comments at 2-3; Southern Company Comments at 5-6; MISO Transmission Owners Comments at 15-16; EEI Comments at 10-11; APS Comments at 8; NYTOs Comments at 5-6; AEP Comments at 6-7; NRECA/LPPC Comments at 19-20; SDG&E Comments at 2-3; LADWP Comments at 7; ITC Comments at 7-9.

277

BPA Comments at 7; Duke Energy Comments at 8-9; Southern Company Comments at 5-6; MISO Transmission Owners Comments at 15-16; EEI Comments at 10-11; APS Comments at 8; NYTOs Comments at 5-6.

278

AEP Comments at 6-7; NRECA/LPPC Comments at 19-20; SDG&E Comments at 2-3; LADWP Comments at 7.

279

Indicated PJM Transmission Owners Comments at 2.

280

Dominion Comments at 9.

281

Entergy Comments at 11.

115. Several commenters argue that requiring AARs 10 days in advance presents the potential problem of selling transmission service based on a given ambient air temperature forecast only for the temperature to be higher in real time, causing curtailments or safety and reliability risks.

282

BPA argues that it could result in an inefficient use of the transmission system because transmission could be sold, curtailed, and then available again, all prior to the transmission service window.

283

NYTOs note that, because there is generally less flexibility in real time, if operators do not have sufficient resources to restore flow to a lower limit within the required time, they may need to shed load or damage equipment.

284

282

MISO Transmission Owners Comments at 15-16; Duke Energy Comments at 8-9; Southern Company Comments at 5-6; NYTOs Comments at 5.

283

BPA Comments at 7.

284

NYTOs Comments at 5-6.

116. Arguing that the Commission should not extend the AAR requirements beyond the operating day, MISO Transmission Owners state that using AARs any further forward than in real time introduces uncertainty and error. MISO Transmission Owners acknowledge that these risks exist today, but argue that AARs introduce further complexity and explain that lowering transmission line ratings in real time would compound the problems.

285

Similarly, Duke Energy presents an example of transmission sold based on a 60 degree Fahrenheit temperature forecast four days forward and, on the operating day having the transmission system oversubscribed, with greater pressure on operators to curtail transmission schedules to avoid safety and reliability risks, because the actual temperature was 75 degrees Fahrenheit.

286

Southern Company states that AARs have the potential to create reliability concerns if transmission service is oversold due to inaccurate weather forecasts, especially for transmission service that is scheduled 10 days ahead.

287

Southern Company also states that reliability issues may arise because AARs may create difficulties in identifying the most limiting element, which may change as the temperature changes, for the purpose of complying with Reliability Standard FAC-008-5, and similar difficulties in complying with Reliability Standard PRC-023 relay loadability requirements that depend on maximum published ratings.

288

285

MISO Transmission Owners Comments at 15-16.

286

Duke Energy Comments at 8-9.

287

Southern Company Comments at 5-6.

288

Id.

at 6.

117. NRECA/LPPC contend that such a requirement is unduly burdensome because most of the benefits of using AARs are for real-time and day-ahead transactions. NRECA/LPPC add that hourly weather forecasts and the resulting hourly transmission line ratings are unlikely to be accurate for more than a very few days.

289

IID explains that the Commission should provide flexibility in the forward AAR application period, noting that weather patterns may not be stable everywhere. IID contends that the Commission should consider implementation challenges associated with looking 10 days ahead, calculating what could be several hundred transmission line ratings per year.

290

289

NRECA/LPPC Comments at 19-20.

290

IID Comments at 4-6.

118. EEI and APS contend that AARs should only be implemented in real-time operations.

291

EEI contends that such AAR values should not extend to the day-ahead or intra-day unit commitment values and that hourly ATC for up to 10 days would introduce uncertainty and ATC fluctuations that result in curtailment of sold service and resale of previously curtailed service. EEI further explains that the Commission has previously recognized the reliability harm associated with overestimated ATC and explains that the harm may result from using hourly AARs for transmission service available for up to 10 days. EEI also states that the NOPR proposal for hourly ATC for every hour in the next 10 days is complex, with a burden that may outweigh the benefits since the NOPR proposal fundamentally requires a TTC determination. However, EEI states that TTC is path dependent and is based on many transmission line ratings, contingencies, and power flow assumptions. Because of this complexity, some transmission owners only determine TTC annually or less frequently and, for these transmission owners, the NOPR proposal for transmission providers to recalculate TTC every hour, and perform 240 calculations every hour, is infeasible.

292

NERC contends that the Commission should consider how entities should reconcile AARs used for planning and operations functions. NERC also argues that there is potential confusion regarding transmission line ratings used in transmission operator operations and planning system operating limits and interconnection reliability operating limits, but believes the confusion can be avoided through the timing of Commission action to retire the NERC Modeling, Data, and Analysis (MOD) A Reliability Standards.

293

291

APS Comments at 8; EEI Comments at 10-12.

292

EEI Comments at 10-12.

293

NERC Comments at 7-8.

119. NYTOs explain that requiring AARs for up to 10 days forward, even for a subset of the transmission system, would be a significant change requiring major software buildout and corresponding market design changes, which would create a significant burden on NYISO and its associated utilities. NYTOs assert that this burden would be further complicated by the fact that vendor availability for such a buildout is unknown.

294

NYTOs also explain that implementing AARs 10 days forward has the potential to create reliability concerns through disconnects between forecasted and real-time conditions

295

and that extending the AAR requirements to the day-ahead market would make security analysis more difficult.

296

LADWP contends that the Commission should align any final rule requirements with NERC Reliability Standards and asserts that the proposed 10-day threshold would conflict with

the requirements specified in Reliability Standard MOD-001-1a that ATC be calculated hourly for the next 48 hours.

297

Moreover, recognizing the variability in weather, LADWP asks that system operators be afforded the flexibility to recall transfer capability awarded during moderate conditions at least 24 hours in advance.

298

294

NYTOs Comments at 5-6.

295

Id.

296

Id.

at 7.

297

LADWP Comments at 7.

298

Id.

at 6.

iii. Commission Determination

120. We adopt the NOPR proposal to require transmission providers to use AARs when evaluating the availability of and requests for near-term transmission service (under sections 15, 17, 18, and 29 of the

pro forma

OATT)

299

as set forth under “Obligations of Transmission Provider” in the

pro forma

OATT Attachment M adopted in this final rule. We further adopt the Commission's proposal in the NOPR to require transmission providers to use AARs as the relevant transmission line rating when determining whether to curtail or interrupt point-to-point transmission service (under sections 13.6 and/or 14.7 of the

pro forma

OATT) if such curtailment or interruption is both necessary because of issues related to flow limits on transmission lines and anticipated to occur (start and end) within the next 10 days. Additionally, we adopt the Commission's proposal in the NOPR to require transmission providers to use AARs as the relevant transmission line rating when determining whether to curtail network or secondary service (under section 33 of the

pro forma

OATT) or redispatch network or secondary service (under sections 30.5 and/or 33 of the

pro forma

i.e.,

the 10-day threshold). Finally, consistent with the NOPR, we clarify that AARs must be calculated using the temperature at which

there is sufficient confidence that the actual temperature will not be greater than that temperature

(

i.e.,

expected temperature plus an appropriate forecast margin).

300

299

See supra

P 85.

300

See

NOPR, 173 FERC ¶ 61,165 at PP 97, 102.

121. We believe that the 10-day threshold is justified by: (1) The additional benefits gained by adopting a threshold that permits weekly point-to-point transmission service requests to be evaluated using AARs; (2) the additional benefits gained by the use of daytime/nighttime ratings (discussed below in Section IV.B.2.c) within the 10-day threshold; (3) the adequate accuracy of ambient air temperature forecasts combined with the ability to implement appropriate forecast margins to alleviate operational concerns associated with persistently decreasing real-time transmission line ratings; and (4) the low relative cost difference between a shorter forward threshold and the proposed 10-day threshold. As the Commission stated in the NOPR, AAR requirements up to 10 days forward will permit weekly point-to-point transmission service to be evaluated using AARs. Because weekly point-to-point transmission service is one of several types of transmission products provided under the Commission's

pro forma

OATT, by adopting the 10-day threshold for AAR implementation rather than a shorter forward duration, weekly point-to-point transmission customers will receive the benefits of AAR implementation rather than only transmission customers taking shorter duration transmission service, thereby not just increasing the expected benefits from the implementation of AARs by improving the accuracy of transmission line ratings for a wider range of transmission services but also for a potentially wider range of transmission customers.

122. We also require AARs to include separate daytime and nighttime ratings. This daytime/nighttime ratings requirement, combined with the addition of weekly point-to-point transmission service, will produce further benefits in forward nighttime hours that would not see such benefits if the AAR requirements were imposed over a timeframe shorter than 10 days forward. These benefits of increased accuracy that result from applying daytime/nighttime ratings to weekly point-to-point transmission service and to shorter duration transmission service up to 10 days forward are significant on their own, even in the unlikely event that the use of ambient air temperature forecasts 10 days forward results in no hours where daytime AARs are greater than seasonal line ratings. In other words, if we were to adopt a shorter threshold for the AAR requirements than 10 days forward, the significant benefits derived from the more accurate transmission line ratings during the additional nighttime hours included in the 10-day threshold would be lost. We further note that

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