168 FERC ¶ 61,040

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM19-2-000; Order No. 861]

Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional 

Transmission Organization and Independent System Operator Markets

(Issued July 18, 2019)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

SUMMARY: The Federal Energy Regulatory Commission (Commission) is modifying 

its regulations regarding the horizontal market power analysis required for market-based 

rate sellers that study certain Regional Transmission Organization (RTO) or Independent 

System Operator (ISO) markets and submarkets therein. This modification relieves such 

sellers of the obligation to submit indicative screens to the Commission in order to obtain 

or retain authority to sell energy, ancillary services and capacity at market-based rates. 

The Commission’s regulations continue to require market-based rate sellers that study an 

RTO, ISO, or submarket therein, to submit indicative screens for authorization to make 

capacity sales at market-based rates in any RTO/ISO market that lacks an RTO/ISOadministered capacity market subject to Commission-approved RTO/ISO monitoring and 

mitigation. For those RTOs and ISOs that do not have an RTO/ISO-administered 

capacity market, Commission-approved RTO/ISO monitoring and mitigation is no longer 

presumed sufficient to address any horizontal market power concerns for capacity sales 
Docket No. RM19-2-000 ii

where there are indicative screen failures. Sellers studying RTO/ISO markets that do not 

have an RTO/ISO-administered capacity market would be relieved of the requirement to 

submit indicative screens to the Commission if they sought market-based rate authority 

limited to sales of energy and/or ancillary services in those markets.

DATES: This rule will become effective [Insert_Date 60 days after date of publication 

in the FEDERAL REGISTER]

FOR FURTHER INFORMATION CONTACT:

Ashley Dougherty (Technical Information)

Office of Energy Market Regulation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8851

Mary Ellen Stefanou (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE 

Washington, DC 20426

(202) 502-8989

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Neil Chatterjee, Chairman;

 Cheryl A. LaFleur, Richard Glick,

 and Bernard L. McNamee.

Refinements to Horizontal Market Power Analysis for 

Sellers in Certain Regional Transmission Organization 

and Independent System Operator Markets

 Docket No. RM19-2-000

ORDER NO. 861

FINAL RULE

(Issued July 18, 2019)

TABLE OF CONTENTS

Paragraph Numbers

I. Introduction ..................................................................................................................... 1.

II. Background .................................................................................................................... 5.

III. Discussion..................................................................................................................... 9.

A. Assurance of Just and Reasonable Rates .................................................................. 9.

1. Availability of Data Necessary for Effective Review of Seller Market Power... 10.

2. No Sub-delegation of Statutory Responsibility................................................... 28.

B. Retention of Screens for Capacity Sellers in CAISO and SPP ............................... 32.

1. CAISO ................................................................................................................. 32.

2. SPP....................................................................................................................... 43.

C. Clarifications for Capacity Sellers in CAISO and SPP........................................... 49.

D. Retention of Screens for EIM ................................................................................. 53.

1. Comments............................................................................................................ 53.

2. Commission Determination................................................................................. 56.

E. Bilateral Sales.......................................................................................................... 57.

1. Comments............................................................................................................ 57.

2. Commission Determination................................................................................. 59.

F. Current Status and Effectiveness of RTO/ISO Monitoring and Mitigation ............ 63.

1. Comments............................................................................................................ 63.

2. Commission Determination................................................................................. 65.

G. Other Issues Raised By Commenters...................................................................... 67.
Docket No. RM19-2-000 - 2 -

1. Change in Status and Triennial Updates.............................................................. 67.

2. Rights of Market Monitors.................................................................................. 73.

3. Corporate Character Reporting............................................................................ 77.

4. Data Collection NOPR and Market Power NOI.................................................. 79.

I. Information Collection Statement................................................................................. 81.

V. Environmental Analysis .............................................................................................. 89.

VI. Regulatory Flexibility Act.......................................................................................... 90.

VII. Document Availability.............................................................................................. 97.

VIII. Effective Date and Congressional Notification..................................................... 100.
Docket No. RM19-2-000 - 3 -

I. Introduction

1. On December 20, 2018, the Federal Energy Regulatory Commission 

(Commission) issued a notice of proposed rulemaking (NOPR)1 proposing to modify

§ 35.37(c) of its regulations regarding the horizontal market power analysis for marketbased rate sellers2 studying certain Regional Transmission Organization (RTO) and 

Independent System Operator (ISO) markets.3

 The proposed modification would relieve 

Sellers of the requirement to submit indicative screens to the Commission in order to 

obtain or retain authority to sell energy, ancillary services and capacity at market-based 

rates when studying RTO/ISO markets with RTO/ISO-administered energy, ancillary 

services, and capacity markets that are subject to Commission-approved RTO/ISO 

monitoring and mitigation. Under the proposal, the Commission did not propose to 

relieve Sellers studying RTOs or ISOs that do not have an RTO/ISO-administered 

capacity market from submitting indicative screens to sell capacity in those markets at 

market-based rates. However, under the proposal Sellers studying such markets would be 

 1 Refinements to Horizontal Market Power Analysis for Sellers in Certain 

Regional Transmission Organization and Independent System Operator Markets, 

165 FERC ¶ 61,268 (2018) (NOPR).

2 The term “Seller” is defined as any person that has authorization to or seeks 

authorization to engage in sales for resale of electric energy, capacity or ancillary services 

at market-based rates. 18 CFR 35.36(a)(1).

3 The term “RTO/ISO markets” in this final rule includes any submarkets therein.

(continued ...)
Docket No. RM19-2-000 - 4 -

relieved of the requirement to submit indicative screens to the Commission if they sought 

market-based rate authority limited to sales of energy and/or ancillary services in those 

markets.

4

2. The Commission also proposed to eliminate the rebuttable presumption that 

Commission-approved RTO/ISO market monitoring and mitigation is sufficient to 

address any horizontal market power concerns regarding sales of capacity in RTOs/ISOs 

that do not have an RTO/ISO-administered capacity market.

3. The Commission received 18 comments in response to the NOPR.5 A list of 

commenters and the abbreviated names used in this final rule is attached as Appendix A.

4. In this final rule, we adopt the proposal from the NOPR and provide clarification,

as discussed below.

II. Background

5. The Commission allows power sales at market-based rates if the Seller and its 

affiliates do not have, or have adequately mitigated, horizontal and vertical market 

power.6

 Section 35.37 of the Commission’s regulations requires market-based rate 

 4 At this time, California Independent System Operator Corporation (CAISO) and 

Southwest Power Pool, Inc. (SPP) do not have Commission-approved RTO/ISO capacity 

markets that include Commission-approved market monitoring and mitigation.

5 Although the Commission did not request reply comments, several commenters 

nonetheless submitted reply comments. The Commission rejects such reply comments.

6 Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and 

Ancillary Services by Public Utilities, Order No. 697, 119 FERC ¶ 61,295, at PP 62, 399, 

408, 440, clarified, 121 FERC ¶ 61,260 (2007), order on reh’g, Order No. 697-A, 

123 FERC ¶ 61,055, clarified, 124 FERC ¶ 61,055, order on reh’g, Order No. 697-B, 

(continued ...)
Docket No. RM19-2-000 - 5 -

Sellers to submit indicative screens as part of a market power analysis: (1) when seeking 

market-based rate authority; (2) every three years for Category 2 Sellers;

7 and (3) at any 

other time the Commission requests a Seller to submit an analysis.

6. In Order No. 697, the Commission adopted two indicative screens for assessing 

horizontal market power: the pivotal supplier screen and the wholesale market share 

screen.8

 The Commission has stated that passing both screens establishes a rebuttable 

presumption that the Seller does not possess horizontal market power, while failing either 

screen creates a rebuttable presumption that the Seller has horizontal market power.9

 

Generally, Sellers that are located in and are members of an RTO/ISO may consider the 

geographic area under the control of the RTO/ISO as the default relevant geographic 

 

125 FERC ¶ 61,326 (2008), order on reh’g, Order No. 697-C, 127 FERC ¶ 61,284 

(2009), order on reh’g, Order No. 697-D, 130 FERC ¶ 61,206 (2010), aff’d sub nom. 

Mont. Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011), cert. denied, sub nom. 

Public Citizen, Inc. v. FERC, 567 U.S. 934 (2012).

7 Category 1 Seller means a Seller that: (1) is either a wholesale power marketer 

or wholesale power producer that owns, controls or is affiliated with 500 MW or less of 

generation in aggregate per region; (2) does not own, operate, or control transmission 

facilities other than limited equipment necessary to connect individual generation 

facilities to the transmission grid (or has been granted waiver of the requirements of 

Order No. 888); (3) is not affiliated with anyone that owns, operates, or controls 

transmission facilities in the same region as the Seller’s generation assets; (4) is not 

affiliated with a franchised public utility in the same region as the Seller’s generation 

assets; and (5) does not raise other vertical market power issues. Sellers that are not 

Category 1 are designated as Category 2 Sellers and are required to file updated market 

power analyses. 18 CFR 35.36(a)(2).

8 Order No. 697, 119 FERC ¶ 61,295 at P 62.

9 Id. PP 33, 62-63.

(continued ...)
Docket No. RM19-2-000 - 6 -

market for purposes of the indicative screens.10 In Order No. 697-A, the Commission 

adopted a rebuttable presumption that existing RTO/ISO mitigation is sufficient to 

address any market power concerns created by indicative screen failures in an 

RTO/ISO.

11

7. On July 19, 2014, in a NOPR that culminated in the issuance of Order No. 816,

12

the Commission proposed certain changes and clarifications in order to streamline and 

improve the market-based rate program’s processes and procedures.13 Specifically, as 

relevant for the purposes of the instant rulemaking, the Commission proposed in the 

Order No. 816 NOPR to allow Sellers in RTO/ISO markets to address horizontal market 

power issues in a streamlined manner that would not involve the submission of indicative 

screens if the Seller relies on Commission-approved monitoring and mitigation to prevent 

 10 Where the Commission has made a specific finding that there is a submarket 

within an RTO/ISO, that submarket becomes a default relevant geographic market for 

Sellers located within the submarket for purposes of the horizontal market power 

analysis. See id. PP 15, 231.

11 Order No. 697-A, 123 FERC ¶ 61,055 at P 111.

12 Refinements to Policies and Procedures for Market-Based Rates for Wholesale 

Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order 

No. 816, 153 FERC ¶ 61,065 (2015), order on reh’g Order No. 816-A, 155 FERC 

¶ 61,188 (2016).

13 Refinements to Policies and Procedures for Market-Based Rates for Wholesale 

Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 147 FERC 

¶ 61,232, at P 10 (2014) (Order No. 816 NOPR).

(continued ...)
Docket No. RM19-2-000 - 7 -

the exercise of market power.14 Under that proposal, RTO/ISO sellers15 would state that 

they are relying on such monitoring and mitigation to address the potential for market 

power issues that they might have, provide an asset appendix, and describe their 

generation and transmission assets. The Commission would retain its ability to require a 

market power analysis, including indicative screens, from any Seller at any time.16

8. When the Commission issued Order No. 816, it stated that it was not prepared at 

that time to adopt the proposal regarding RTO/ISO sellers, but that it would further 

consider the issues raised by commenters and transferred the record on that issue to 

Docket No. AD16-8-000 for possible consideration in the future as the Commission may 

deem appropriate.17 The Commission reviewed and considered that record in preparing 

the NOPR proposal.

III. Discussion

A. Assurance of Just and Reasonable Rates

9. In proposing to relieve RTO/ISO sellers of the requirement to submit indicative 

screens to the Commission in markets with RTO/ISO-administered energy, ancillary 

services, and capacity markets subject to Commission-approved monitoring and 

 14 See id. PP 35-36.

15 RTO/ISO sellers are Sellers that have an RTO/ISO market as a relevant 

geographic market.

16 Order No. 816 NOPR, 147 FERC ¶ 61,232 at P 36.

17 Order No. 816, 153 FERC ¶ 61,065 at P 27.

(continued ...)
Docket No. RM19-2-000 - 8 -

mitigation, the Commission emphasized that it would continue to ensure that marketbased rates are just and reasonable.18 However, commenters raise concerns that the 

proposal compromises the Commission’s ability to ensure just and reasonable rates 

because, they argue, it eliminates data necessary for detecting the presence of market 

power, and it results in an improper sub-delegation of the Commission’s statutory

responsibility to the RTO/ISO.19 We have carefully considered these arguments, but 

disagree for the reasons discussed below. Accordingly, we adopt the changes to 

§ 35.37(c) of the Commission’s regulations, as proposed in the NOPR.

1. Availability of Data Necessary for Effective Review of Seller 

Market Power

a. Comments

10. Opponents of the NOPR raise concerns that the proposal would deprive the 

Commission and intervenors/complainants of data that is necessary for assessing market 

power. They add that the proposal is contrary to the Commission’s statement in Order 

No. 697-A that, even where RTO/ISO monitoring and mitigation is in place, the 

indicative screens provide “critical information regarding the potential market power of 

Sellers in the market.”20

 18 NOPR, 165 FERC ¶ 61,268 at PP 61-70.

19 TAPS at 20-21; AAI/APPA/NRECA at 29.

20 AAI/APPA/NRECA at 15 (citing Order No. 697-A, 123 FERC ¶ 61,055 

at P 109); TAPS at 7 (citing same).

(continued ...)
Docket No. RM19-2-000 - 9 -

11. TAPS and AAI/APPA/NRECA both state that the courts have relied on ex ante

market power screening in upholding the Commission’s use of market-based rates, and 

both argue that the indicative screens play an essential role in the Commission’s ex ante

market power analysis, which “consists of a finding that the applicant lacks market power 

(or has taken sufficient steps to mitigate market power).”21 TAPS argues that the 

“rigorous screening process to detect market power” and collection of seller-specific data 

were critical to the court’s upholding of the Commission’s market-based rate program in 

Order No. 697.22 Similarly, AAI/APPA/NRECA argue that courts have specifically 

relied on the existence of seller-specific, ex ante market power screening in upholding the 

Commission’s use of market-based rates.23

12. TAPS and AAI/APPA/NRECA argue that the efficacy of the other existing 

market-based rate requirements and procedural avenues would be undermined by the 

elimination of the indicative screens. For example, TAPS notes that the Commission and 

others may always scrutinize a Seller’s asset appendix, but the indicative screens enable 

them to better understand this information in the context of particular markets.24 

 21 AAI/APPA/NRECA at 7; TAPS at 5 (quoting Cal. ex rel. Lockyer v. FERC, 

383 F.3d 1006, 1013 (9th Cir. 2004) (Lockyer).

22 TAPS at 5 (citing Mont. Consumer Counsel v. FERC, 659 F.3d 910, 917 

(9th Cir. 2011) (Mont. Consumer Counsel).

23 AAI/APPA/NRECA at 7 (citing Blumenthal v. FERC, 552 F.3d 875, 882 

(D.C. Cir. 2009) (Blumenthal).

24 TAPS at 13.

(continued ...)
Docket No. RM19-2-000 - 10 -

Similarly, AAI/APPA/NRECA note that a Seller’s asset appendix and affiliate 

information offer “a ballpark idea of the share of generation capacity owned or controlled 

by a [S]eller and its affiliates” but is “divorced from any analytical framework designed 

to identify a [S]eller’s ability to exercise market power.”25 AAI/APPA/NRECA also 

state that the proposal would deprive the Commission of important data and analysis that 

is complementary to the Commission’s merger analysis, transmission policy, and policies 

relating to certification of natural gas pipelines that also have interests in generation 

assets.26

13. AAI/APPA/NRECA and TAPS argue that the Commission should retain its caseby-case approach for determining whether market power mitigation is sufficient to 

address market power concerns.27 TAPS explains that “[e]ven in those instances where, 

based on RTO monitoring and mitigation, the Commission has ultimately granted 

[market-based rate] authority despite screen failures, it nevertheless has done so with at 

least an initial understanding of the degree of potential market power the particular 

[S]eller may have.”28

 25 AAI/APPA/NRECA at 17.

26 Id. at 26.

27 TAPS at 22.

28 Id. at 8.

(continued ...)
Docket No. RM19-2-000 - 11 -

14. Public Citizen believes that the NOPR interferes with the public’s right to inspect, 

comment, and protest Federal Power Act (FPA) section 20529 rate filings such that “at the 

time of a [s]ection 205 [market-based rate] application, any member of the public with 

concerns about market power wielded by the applicant would now be required to lodge 

their challenge with the relevant RTO tariff in a completely different proceeding.”30

15. While recognizing that market monitors are required under Order No. 719 to 

submit annual and quarterly reports, AAI/APPA/NRECA state that the reporting 

requirements are not uniform and are left to the discretion of the RTO/ISO monitor.31 In 

particular, they note that the market monitors are not obligated to collect and report 

individual entity market shares and market concentration data. 

16. TAPS asserts that the lack of indicative screen information will hinder the ability 

of affected parties and the Commission to meet the evidentiary burden required to 

challenge market-based rate filings.32 AAI/APPA/NRECA share this concern and 

believe that the NOPR increases the burden for entities seeking to challenge a Seller’s 

market-based rate authority. They note that under the current framework, the sufficiency 

of RTO/ISO market monitoring and mitigation is only placed at issue after a Seller fails 

 29 16 U.S.C. 824d.

30 Public Citizen at 3.

31 AAI/APPA/NRECA at 16.

32 TAPS at 13.

(continued ...)
Docket No. RM19-2-000 - 12 -

one or both of the indicative screens, resulting in a presumption that the Seller has market 

power. In contrast, under the proposal, a party challenging market-based rate authority 

would be required to demonstrate, as a threshold matter, that the Seller has market 

power.33

b. Commission Determination

17. At the outset, we note that the Commission’s prior decision in Order No. 697-A to 

retain the indicative screens for Sellers in RTO/ISO markets is not controlling here. The 

Commission may evaluate the continuing reasonableness of a prior policy or 

determination and subsequently reach a different conclusion.34 We reach a different

conclusion here in part based on our finding that the proposal does not eliminate data 

necessary for the effective review of a Seller’s market power.

18. We also disagree with TAPS and AAI/APPA/NRECA’s assertion that the courts, 

in upholding the Commission’s ability to approve market-based rates, have found that

indicative screens play an essential role in the Commission’s ex ante analysis. While the 

courts have found that an ex ante finding of the absence of market power, coupled with 

 33 AAI/APPA/NRECA at 28.

34 New Jersey Bd. of Pub. Utils. v. FERC, 744 F.3d 74, 100 (3rd Cir. 2014) (noting 

that “[c]ourts have repeatedly held that an agency may alter its policies despite the 

absence of a change in circumstances.” (citing Motor Vehicle Mfrs. Ass’n of United 

States, Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 57 (1983)); Tennessee Gas 

Pipeline Co., 105 FERC ¶ 61,120, at P 35 (2003) (the Commission’s prior acceptance of 

tariff provisions does not preclude the Commission from reconsidering its policies), aff’d 

Tennessee Gas Pipeline Co. v. FERC, 400 F.3d 23 (D.C. Cir. 2005).

(continued ...)
Docket No. RM19-2-000 - 13 -

sufficient post-approval reporting requirements, ensures that market-based rates are just 

and reasonable, the courts have recognized that the Commission’s market-based rate 

analysis looks at whether a seller lacks market power or has taken sufficient steps to 

mitigate it.

35 The use of indicative screens is not the only permissible approach the 

Commission may employ to assess market power before authorizing market-based rates, 

nor are indicative screens essential to the Commission’s determination of whether market 

power is mitigated.

19. Contrary to AAI/APPA/NRECA’s assertion, the Commission is not “distancing 

itself” from oversight of competitive issues arising in wholesale markets. Sellers 

continue to be required to submit notices of change in status and market power analyses, 

which include a demonstration regarding vertical market power, affiliate information, and

an asset appendix. Additionally, Sellers continue to be required to submit Electric 

Quarterly Reports (EQR). EQR reporting is a vital tool for determining whether Sellers 

may be exercising market power because it shows the volumes and prices at which 

Sellers are transacting; as such, it can be used to determine a Seller’s market share of 

sales and relative prices.

20. We are not aware of an instance to date where an intervenor or complainant has 

used indicative screen data as part of a challenge to the market power of an RTO/ISO 

seller. Nevertheless, even without the screen data, the information that continues to be 

 35 See Lockyer, 383 F.3d at 1013; Blumenthal, 552 F.3d at 882; Mont. Consumer 

Counsel, 659 F.3d at 916. 
Docket No. RM19-2-000 - 14 -

required under § 35.37 is useful to those seeking to challenge a Seller’s market-based rate 

authority. We disagree with TAPS’s suggestion that this information is of limited value 

without the indicative screens. The asset appendices also provide detailed information on 

a Seller’s generation portfolio, including affiliated generation and long-term power 

purchase agreements. Through the triennial update process,36 a potential intervenor can 

review contemporaneous information on a Seller’s generation portfolio and can aggregate 

this information to get an indication of an individual Seller’s size relevant to the market. 

Moreover, data on total market size is available from other public sources such as reports 

from the U.S. Energy Information Administration.

21. Public Citizen is mistaken in its view that challengers to a market-based rate filing 

would have to lodge their objections with the relevant RTO/ISO tariff in a different 

proceeding.37 Any objections to a Seller’s market-based rate authority can and should 

occur as a direct response to an initial application, a change in status filing, a triennial 

update, or in a proceeding instituted under FPA section 206.38 The Commission will 

consider all relevant information in the record when determining whether the Seller can 

 36 Only Category 2 Sellers are required to submit triennial updated market power 

analyses. 18 CFR 35.37(a)(1). Category 2 Sellers likely will have more of a presence in 

the market than Category 1 Sellers and are considered more likely to either fail one or 

more of the indicative screens or pass by a smaller margin than those that will qualify as 

Category 1 Sellers, or may present circumstances that could pose vertical market power 

issues. Order No. 697, 119 FERC ¶ 61,295 at P 852; 18 CFR 35.36(a)(2), (a)(3).

37 Public Citizen at 3.

38 16 U.S.C. 824e.

(continued ...)
Docket No. RM19-2-000 - 15 -

obtain or retain market-based rate authority. This will continue to occur notwithstanding 

the existence of Commission-approved monitoring and mitigation.

22. The public and the Commission will continue to have access to a Seller’s 

ownership information, vertical market power analysis, asset appendix, and EQRs, as 

well as to the market monitors’ reports. For example, PJM IMM notes that its quarterly 

State of the Market reports contain a comprehensive listing of market power concerns.39 

Anyone may use this information in support of a challenge to a Seller’s market-based rate 

authority. The Commission would then consider this and other information to determine

whether the Seller may obtain or retain market-based rate authority. In addition, contrary 

to Public Citizen’s argument that “once [market-based rate] authority is granted, [the 

Commission] is unlikely to take it away,” the standard for obtaining and retaining 

market-based rate authority is the same. The Commission can and does institute FPA 

section 206 proceedings when potential market power concerns arise.40 

23. In addition, the Commission conducts independent, ex post analyses using public 

and non-public data to assess market behavior in RTO/ISO markets. The Commission 

 39 PJM IMM at 4-5.

40 See, e.g., Nevada Power Co., 155 FERC ¶ 61,249 (2016); FortisUS Energy 

Corp., 150 FERC ¶ 61,153 (2015); Alabama Power Co., 151 FERC ¶ 61,071 (2015); 

Duke Power, 109 FERC ¶ 61,270 (2004).
Docket No. RM19-2-000 - 16 -

can examine transaction level data (e.g., resource supply offers) using data provided 

pursuant to Order No. 760 to conduct such oversight.41

24. Regarding concerns that the market monitors’ reports are not “uniform,” we note 

that the RTOs/ISOs themselves are not uniform and that a “one size fits all” report format 

is unnecessary. The more relevant question is whether the reports contain a 

comprehensive review of market performance. To the extent intervenors/complainants 

identify relevant information the reports are lacking, they can raise such concerns as part 

of a challenge to a Seller’s market-based rate authority and request that the Commission 

require the Seller to submit indicative screens.

25. We acknowledge that, under the proposal that we adopt herein, a successful 

challenge to Seller’s market-based rate authority will involve two demonstrations: 

(1) that the Seller has market power and (2) that such market power is not addressed by 

existing Commission-approved RTO/ISO market monitoring and mitigation.

26. Regarding the second demonstration, a challenge to existing Commissionapproved RTO/ISO market monitoring and mitigation would be no different than what 

the Commission articulated in Order No. 697-A, where it established the rebuttable 

presumption that Commission-approved market monitoring and mitigation was sufficient 

to address market power concerns. There, the Commission explicitly recognized that 

“intervenors may challenge that presumption. Depending on the nature of the evidence 

 41 Enhancement of Electricity Market Surveillance and Analysis through Ongoing 

Electronic Delivery of Data from Regional Transmission Organizations and Independent 

System Operators, Order No. 760, 139 FERC ¶ 61,053 (2012).

(continued ...)
Docket No. RM19-2-000 - 17 -

submitted by an intervenor, the Commission will consider whether to institute a separate 

FPA section 206 proceeding to investigate whether the existing RTO/ISO mitigation 

continues to be just and reasonable.”42

27. With respect to the first demonstration as to whether a Seller has market power, 

we are sympathetic to the concern that, to the extent intervenors/complainants 

successfully rebut the presumption as to the sufficiency of market monitoring and 

mitigation, they will not have indicative screen information which would otherwise have 

established a presumption of market power one way or the other. In this situation, the 

Commission retains authority to require the Seller to submit indicative screens or other 

evidence to help evaluate whether the Seller has market power.

2. No Sub-delegation of Statutory Responsibility

a. Comments

28. Opponents of the proposal renew many of the legal arguments raised in the Order 

No. 816 proceeding. AAI/APPA/NRECA argue that RTOs/ISOs cannot lawfully 

substitute for the Commission’s regulation of wholesale electricity markets required by 

the FPA. They assert the RTOs/ISOs are not public agencies or regulators and cannot 

serve as the Commission’s surrogate. Similarly, Public Citizen contends that the 

proposal weakens oversight by transferring regulatory control to private consulting firms 

(referring specifically to the market monitors).43

 42 Order No. 697-A, 123 FERC ¶ 61,055 at P 5.

43 Public Citizen at 4-5 (also noting that the market monitors do not have corporate 

control protections to safeguard the public interest).
Docket No. RM19-2-000 - 18 -

29. AAI/APPA/NRECA point to a recent Court of Appeals for the District of 

Columbia Circuit (D.C. Circuit) opinion where the court “emphasized the distinction 

between the PJM IMM, which ‘is not a creature of statute and operates under no 

affirmative duty imposed by public law,’ and a public regulator such as the 

Commission.”44 AAI/APPA/NRECA also point to the D.C. Circuit’s opinion in Exelon 

Corp. v. FERC, issued eight days after the NOPR, and its holding “that only the 

Commission—not the ISO or its market monitor—had authority to evaluate whether a 

capacity Seller’s offer was just and reasonable under the FPA or instead constituted 

unlawful physical withholding and should be subject to mitigation.”45

b. Commission Determination

30. We agree that it is the Commission, and not the market monitors or the 

RTOs/ISOs, that bears responsibility for ensuring that rates are just and reasonable under 

the FPA. Under the proposal, which we adopt in this final rule, it is the Commission—

and not the RTO/ISO or its associated market monitor—that determines whether an entity 

can obtain or retain market-based rate authority. In performing mitigation, the RTO/ISO 

or market monitor does not usurp the Commission’s role or act as its surrogate but rather 

implements Commission-approved tariff provisions. Thus, the Commission is the entity

 44 AAI/APPA/NRECA at 19 (citing Old Dominion Elec. Coop. v. FERC, 892 F.3d 

1223, 1234 (D.C. Cir. 2018)).

45 Id. at 19-20 (citing Exelon Corp. v. FERC, 911 F.3d 1236 (D.C. Cir. 2018) 

(Exelon)).
Docket No. RM19-2-000 - 19 -

determining whether granting a Seller market-based rate authority would result in just 

and reasonable rates. 

31. The Exelon case relied on by AAI/APPA/NRECA is inapposite to this rulemaking. 

That proceeding involved a disputed tariff provision under which the ISO New England 

Inc. market monitor would review a capacity supplier’s retirement bid and, if it 

determined that the bid was unsupported, would substitute a “mitigated” bid that would 

then be submitted to the Commission for approval under FPA section 205. On remand 

from the D.C. Circuit, the Commission explained that its review of an FPA section 205 

filing would consider the entirety of the record and that it would accept the capacity 

supplier’s bid so long as the capacity supplier persuades the Commission that its bid is 

just and reasonable, despite contrary assertions by the market monitor.46 Nothing in 

Exelon calls into question the Commission’s ability to rely on Commission-approved 

RTO/ISO monitoring and mitigation market rules to address market power concerns. 

The Commission will continue to review a Seller’s filing under FPA section 205 based on 

the entirety of the record and will grant market-based rate authority if the Seller 

demonstrates that it lacks the ability to exercise market power.

 46 ISO New England Inc., 166 FERC ¶ 61,060, at P 8 (2019).
Docket No. RM19-2-000 - 20 -

B. Retention of Screens for Capacity Sellers in CAISO and SPP

1. CAISO

a. Comments

32. Several commenters request extending the proposal to grant relief from submitting 

the indicative screens to capacity Sellers in the CAISO market, while other commenters 

support the Commission’s proposal to retain the requirement that Sellers submit 

indicative screens for capacity sales in CAISO. 

33. Calpine, EEI, Indicated Generation Investors, PG&E, Competitive Suppliers, and 

SoCal Edison urge the Commission to extend the proposal to grant relief from submitting 

the indicative screens to capacity sellers in CAISO.47 Calpine identifies “structural 

safeguards” in California that protect against the exercise of horizontal market power in 

the sale of capacity. Calpine explains that these safeguards are provided through the 

combination of the California Public Utilities Commission (CPUC)-administered 

Resource Adequacy program, CAISO Tariff requirements imposed on sellers of Resource 

Adequacy capacity and, ultimately, on CAISO-administered backstop capacity 

procurement programs, including the Capacity Procurement Mechanism and Reliability 

 47 Calpine at 4-5 (identifying structural safeguards in California that protect 

against the exercise of horizontal market power in the sale of capacity); EEI at 5-6 

(mitigation methods exist in CAISO’s Capacity Procurement Mechanism which address 

market power in the capacity sales); Indicated Generation Investors at 9-10 (“There is no 

credible case to be made that the presence or absence of a particular type of forward 

capacity market itself defines whether exercises of market power are prevented.”); PG&E 

at 3-4; Competitive Suppliers at 5-7; SoCal Edison at 3-6 (CAISO’s Resource Adequacy 

framework provides similar monitoring and mitigation measures found in centralized 

capacity markets).

(continued ...)
Docket No. RM19-2-000 - 21 -

Must-Run Agreements. Calpine argues that the Commission-approved settlement for the 

bid cap in the capacity backstop market establishes “presumptively just and reasonable 

price caps for capacity, even in a competitive market.”48

34. Competitive Suppliers maintain that “[b]etween [Capacity Procurement 

Mechanism] to address capacity deficiency issues when they arise, and the [Reliability 

Must-Run] process to mandate service from units that would otherwise retire, CAISO has 

backstop mechanisms that cap prices – initially at a representation of going forward fixed 

costs in the case of [Capacity Procurement Mechanism], and ultimately at full cost-ofservice with [Reliability Must-Run].”49 Competitive Suppliers also suggest that the 

Commission could extend its ruling in Order No. 784,

50 which permits a Seller to make 

market-based sales of certain ancillary services if the sale results from a competitive 

solicitation, to sales of capacity in CAISO. Competitive Suppliers propose, consistent 

with the process specified in Order No. 784, that a Seller be allowed to make marketbased sales of capacity in CAISO if it demonstrates that the sale of capacity results from 

a competitive solicitation that meets the guidelines articulated in Order No. 784 

(transparency, definition, evaluation, oversight, and competitiveness).

 48 Calpine at 7.

49 Competitive Suppliers at 6.

50 Third-Party Provision of Ancillary Services; Accounting and Financial 

Reporting for New Electric Storage Technologies, Order No. 784, 144 FERC ¶ 61,056 

(2013), order on clarification, Order No. 784-A, 146 FERC ¶ 61,114 (2014).

(continued ...)
Docket No. RM19-2-000 - 22 -

35. SoCal Edison states that while CAISO does not have a centralized capacity 

market, the CPUC and CAISO together have designed and implemented a Resource 

Adequacy framework, which provides similar monitoring and mitigation measures found 

in centralized capacity markets.51 SoCal Edison argues that although CAISO is currently 

evaluating its Reliability Must-Run and Capacity Procurement Mechanism processes, 

such changes should not be viewed as an indication that the current processes are inferior 

to the Commission’s horizontal market power screens.52 SoCal Edison states that if the 

Commission does not eliminate the requirement for Sellers to submit indicative screens 

for capacity sales in CAISO, it recommends a technical conference to consider how 

CAISO’s market monitoring and mitigation of capacity sales can be modified such that 

the requirement to submit indicative screens can be eliminated prior to the submission of 

the next triennial for the Southwest region due in December 2021, or how the indicative 

screens can be modified to reflect the Resource Adequacy reserve margin obligations and 

capacity procurement in CAISO.53

36. Other commenters support the proposal to retain the requirement that Sellers 

submit indicative screens for capacity sales in CAISO.54 CAISO DMM “strongly 

 51 SoCal Edison at 4.

52 Id. at 5.

53 Id. at 7.

54 CAISO DMM at 10-11; TAPS at 19-20 (noting that the indicative screens are 

especially important for capacity sales in RTOs that do not administer a capacity market); 

(continued ...)
Docket No. RM19-2-000 - 23 -

supports the NOPR’s provisions relating to capacity market sales in the CAISO”55 and 

notes that a bilateral capacity sales market that supports resource adequacy is overseen by 

the CPUC, but it is not directly subject to Commission-approved RTO/ISO monitoring. 

CAISO DMM explains that CAISO’s backstop procurement processes help to set a 

ceiling on resources’ bilateral capacity contract compensation, similar to the way systemwide offer caps set ceilings in ISO-administered capacity markets; “[h]owever, these 

backstop procurement processes do not mitigate market power like the Commissionapproved market power mitigation in those capacity markets.”56

37. TAPS comments that the indicative screens are especially important for capacity 

sales in RTOs that do not administer a capacity market because “there is no basis for 

presuming the sufficiency of monitoring and mitigation absent Commission-approval of 

particular measures for the specific market.”57 TAPS also supports the proposal to 

eliminate the rebuttable presumption that RTO market monitoring and mitigation is 

sufficient with respect to capacity sales where there is no RTO/ISO administered capacity 

markets.58

 

see also ELCON at 7-8 (“capacity markets present a fundamental challenge to horizontal 

market power detection and mitigation”).

55 CAISO DMM at 10.

56 Id. at 11.

57 TAPS at 19-20.

58 Id.
Docket No. RM19-2-000 - 24 -

b. Commission Determination

38. We adopt the NOPR proposals to require capacity sellers in CAISO to continue to 

submit indicative screens and to eliminate the rebuttable presumption that Commissionapproved RTO/ISO market monitoring and mitigation is sufficient to address any 

horizontal market power concerns regarding sales of capacity in CAISO.

39. Although the majority of capacity sales within CAISO are made through the 

Resource Adequacy program, we note that these sales are not reviewed, approved, or 

monitored by CAISO. The CPUC reviews and approves capacity purchases by load 

serving entities via the Resource Adequacy program pursuant to resource requirements 

established by the CPUC, but these purchases are not necessarily the result of competitive 

solicitations. There is no transparent market price determined under Commissionapproved rules for capacity in CAISO comparable to the market price for capacity 

established by RTOs/ISOs with centralized capacity markets.59

40. With regard to the soft offer cap for the Capacity Procurement Mechanism cited 

by Calpine and other commenters, we note that the soft offer cap is an estimate of the 

cost of new entry and does not necessarily reflect a mitigated, “going forward” cost of 

any existing generator and does not address concerns regarding local market power. 

 59 Capacity sales in CAISO are reported in EQRs but that data, on its own, does 

not provide a meaningful market price given the different vintage, length, product 

characteristics, and terms and conditions of the contracts under which capacity is sold in 

CAISO.
Docket No. RM19-2-000 - 25 -

Although the soft offer cap is helpful, it does not provide mitigation comparable to the 

mitigation applied in the RTO/ISO administered capacity markets.

41. We disagree with Competitive Suppliers’ comment that a Seller be allowed to 

make market-based rate sales of capacity in CAISO if it demonstrates that the sale of 

capacity results from a competitive solicitation that meets the guidelines articulated in 

Order No. 784 ((1) transparency; (2) definition; (3) evaluation; (4) oversight; and 

(5) competitiveness) as a meaningful alternative to the requirement to submit screens. 

Order No. 784 describes an auction process that, if satisfied, would enable a Seller to 

sell certain ancillary services at market-based rates on a case-by-case basis.60 

The first four guidelines comprise the Edgar-Allegheny61 guidelines that must be 

adequately addressed for Commission acceptance of an affiliate sale. Order No. 784 

established an additional criteria—competitiveness. To meet the competitiveness criteria, 

sellers are required to submit evidence showing the absence of market power in the 

ancillary service market. Therefore, were the Order No. 784 guidelines applied here, a

Seller would be obligated to submit screens, a comparable study, or other evidence that 

demonstrates a lack of market power in the capacity market to comply with the 

competitiveness guideline. 

 60 Third-Party Provision of Ancillary Services; Accounting and Financial 

Reporting for New Electric Storage Technologies, Order No. 784, 144 FERC ¶ 61,056,

at P 95 (2013), order on clarification, Order No. 784-A 146 FERC ¶ 61,114 (2014).

61 Boston Edison Co. Re: Edgar Electric Energy Company, 55 FERC ¶ 61,382 

(1991); Allegheny Energy Supply Company, LLC, 108 FERC ¶ 61,082 (2004) (EdgarAllegheny).
Docket No. RM19-2-000 - 26 -

42. Lastly, we do not think it is necessary to hold a technical conference to consider 

how CAISO’s market monitoring and mitigation of capacity sales can be modified such 

that the requirement to submit indicative screens can be eliminated prior to the next 

triennial for the Southwest region due in December 2021, or how the indicative screens 

can be modified to reflect the Resource Adequacy reserve margin obligations and 

capacity procurement in CAISO.62 We note that relief from the requirement to submit 

screens may be extended to capacity sellers in CAISO in the future, if CAISO develops 

an ISO-administered capacity market that is subject to Commission-approved market 

monitoring and mitigation.

2. SPP

a. Comments

43. Certain commenters request extending the proposal to grant relief from submitting 

the indicative screens to capacity sellers in the SPP market.

63

44. Evergy/Xcel assert that SPP’s lack of an RTO-administered capacity market does 

not mean that capacity sellers in SPP can exercise market power. Evergy/Xcel state that 

other safeguards exist in SPP, such as transparent energy pricing, comprehensive mustoffer requirements, vigorous independent market monitoring, and Commission-accepted 

 62 SoCal Edison at 7.

63 Evergy/Xcel at 7-12; EEI at 5-6. Indicated Generation Investors do not 

specifically reference SPP in their comments but state (at 8-9) that markets “in addition to 

the named Northeastern market” should be included in the relief that the NOPR proposes.

(continued ...)
Docket No. RM19-2-000 - 27 -

mitigation measures.64 Evergy/Xcel also point to other safeguards, such as state 

regulators’ oversight and review of capacity sales in retail rate cases, the Commission’s 

authority to require the submission of indicative screens, the continued submission of 

EQRs, and the continued ability to file complaints under FPA section 206.65

45. Evergy/Xcel state that the Commission rejected proposed mitigation in MISO, 

finding that the Minimum Offer Price Rule that would mitigate against the potential 

exercise of market power by buyers of capacity was unnecessary because of the 

predominance of vertically-integrated utilities and bilateral contracting and minimal use 

of the voluntary MISO capacity market. Evergy/Xcel maintain that these same factors 

apply to SPP, as it “mostly consists of vertically-integrated utilities with a small number 

of independent generators.” According to Evergy/Xcel, while “‘most’ capacity is 

transacted bilaterally or self-supplied in MISO, all capacity in SPP is transacted 

bilaterally or self-supplied. Thus ‘most’ capacity transactions in MISO are not subject to 

direct monitoring or mitigation, just as in SPP.”66

b. Commission Determination

46. We adopt the NOPR proposals to require capacity sellers in SPP to continue to 

submit indicative screens and to eliminate the rebuttable presumption that Commission-

 64 Evergy/Xcel at 8.

65 Id. at 9-10.

66 Id. at 11-12.
Docket No. RM19-2-000 - 28 -

approved RTO/ISO market monitoring and mitigation is sufficient to address any 

horizontal market power concerns regarding sales of capacity in SPP.

47. We disagree with Evergy/Xcel that certain safeguards present in SPP justify 

removal of the requirement to submit screens for capacity sales. While these safeguards 

are important, they do not fully allay the concerns about the lack of an RTO-administered 

capacity market with Commission-approved monitoring and mitigation. For example, the 

must-offer requirement as a safeguard is not relevant here because it applies to energy 

sales, not capacity sales. Furthermore, as discussed in the NOPR, while we acknowledge 

state review67 of SPP capacity sales, we conclude that it is not sufficient oversight to 

extend relief to capacity sellers that would otherwise study the SPP market. As we found 

above with respect to CAISO, there is no transparent market price determined under 

Commission-approved rules for capacity in SPP comparable to the market price for 

capacity established by RTOs/ISOs with centralized capacity markets.

48. We acknowledge that SPP is similar to MISO in that it mostly consists of 

vertically-integrated utilities with a small number of independent generators. However, 

MISO conducts annual capacity auctions subject to Commission-approved monitoring 

and mitigation, thereby disciplining the price of bilateral capacity sales and providing 

capacity buyers with protections that are not available in SPP. The SPP market lacks a 

transparent market price for capacity and SPP does not review or mitigate capacity prices.

 67 In the SPP region, capacity costs are recovered in the rate bases of franchised 

public utilities and, therefore, are subject to state regulatory review.
Docket No. RM19-2-000 - 29 -

C. Clarifications for Capacity Sellers in CAISO and SPP

a. Comments

49. Calpine asks that the Commission make the following clarification in Paragraph 

51 of the NOPR “that, in the event of indicative screen failures, the CAISO (or SPP) 

Seller’s evidentiary burden is limited to demonstrating that it lacks market power in 

capacity markets, or to propose satisfactory mitigation for capacity sales, but that the 

CAISO (or SPP) Seller may still rely on a rebuttable presumption that it lacks market 

power in energy and ancillary services markets as a result of Commission-approved 

market monitoring and mitigation provisions in the CAISO (or SPP) Tariff.”68

50. Powerex states that the NOPR introduces an ambiguity about which markets a 

Seller would be required to evaluate for purposes of making capacity sales. Specifically, 

Paragraph 49 of the NOPR states that the Commission proposes “to require any Seller 

seeking to sell capacity at the market-based rates in CAISO or SPP, either as a bundled or 

unbundled product or on a short-term or long-term basis, to submit the indicative 

screens.”69 Powerex asserts that “[r]ead literally, the foregoing statement would require 

all [market-based rate] sellers wishing to sell capacity in CAISO or SPP to study these 

markets as a relevant market and to submit the indicative screens, even though many 

[market-based rate] sellers making sales in CAISO and SPP do not presently submit 

indicative screens for those markets because they do not own or control generation in 

 68 Calpine at 9 (emphasis in original).

69 NOPR, 165 FERC ¶ 61,268 at P 49.
Docket No. RM19-2-000 - 30 -

those markets and because those markets are not first-tier markets.” As such, Powerex 

believes Paragraph 49’s “expansive language requiring ‘any seller’ seeking to sell 

capacity in CAISO or SPP to submit indicative screens is ambiguous and potentially 

over-broad.”70

b. Commission Determination

51. We agree with Calpine that the addition of “capacity” appropriately clarifies 

Paragraph 51 of the NOPR. Therefore, we clarify that in the event of indicative screen 

failures, the CAISO (or SPP) Seller’s evidentiary burden is limited to demonstrating that 

it lacks market power in capacity markets, or to proposing a satisfactory mitigation plan 

that is specific to capacity sales. Additionally, we note that the CAISO (or SPP) Seller 

may still rely on the rebuttable presumption that it lacks market power in energy and 

ancillary services markets as a result of Commission-approved market monitoring and 

mitigation.

52. We agree with Powerex that Paragraph 49’s language requiring “any seller” 

seeking to sell capacity in CAISO or SPP to submit indicative screens is unclear. We 

clarify that the proposal adopted in the final rule requires that any RTO/ISO seller that 

would normally study CAISO or SPP as a relevant market, and that seeks to offer 

capacity at market-based rates in those markets, either as a bundled or unbundled product 

or on a short-term or long-term basis, must submit the indicative screens to demonstrate 

that it will not have market power in capacity sales.

 70 Powerex at 5.
Docket No. RM19-2-000 - 31 -

D. Retention of Screens for EIM

1. Comments

53. While the Commission did not include in its proposal any changes for Sellers that 

study the Western Energy Imbalance Market (EIM), CAISO DMM and EIM Entities 

submitted comments in which they seek clarification that the proposal will apply to 

participants in the EIM and advocate for this result.71 Specifically, EIM Entities argue 

that because the EIM is part of CAISO’s real-time energy market and is subject to 

Commission-approved market monitoring and mitigation, indicative screens should not 

be required for purposes of obtaining or retaining market-based rate authority in the 

EIM.72

54. EIM Entities state that the EIM has become an increasingly liquid market that 

offers competitive supply from a significant number of participants. They argue that the 

EIM is structurally competitive, asserting that “[t]he DMM has presented analysis and the 

Commission has affirmed in multiple EIM orders that the EIM is structurally competitive 

due to absence of pivotal suppliers and low frequency of price separation,” and in those 

intervals where potential structural market power could exist, it would be mitigated by 

CAISO’s real-time bid mitigation procedures.73 EIM Entities also argue that the 

 71 EIM Entities at 1; CAISO DMM at 8; see also EEI at 2 (requesting extension of 

relief to Sellers in the EIM).

72 EIM Entities at 7.

73 Id. at 7-8.

(continued ...)
Docket No. RM19-2-000 - 32 -

requirement to perform indicative screens, as well as congestion and price separation 

analysis, on five-minute dispatch intervals in the EIM is “complex and financially 

burdensome to EIM entities.”74 Finally, EIM Entities note that CAISO has implemented 

improvements to the accuracy of its mitigation regime that serve to reduce instances of 

either over or under-mitigation.75

55. CAISO DMM states that, unlike the local market power mitigation procedures 

applied within the CAISO, the automated market power mitigation procedures applied to 

each EIM balancing authority area provide effective market power mitigation on a 

system-wide level across each individual EIM balancing area.76 Therefore, CAISO 

DMM believes that the EIM should be treated as an energy market that is subject to 

Commission-approved market monitoring and mitigation.

2. Commission Determination

56. We will not extend the relief proposed in the NOPR to Sellers in the EIM at this 

time. While the Commission has accepted the use of CAISO’s real-time local market 

power mitigation process in the EIM,

77 the Commission has not held that market 

monitoring and mitigation in the EIM is sufficient to address market power concerns, and 

 74 Id. at 10.

75 Id. at 12-13.

76 CAISO DMM at 8-9.

77 See Cal. Indep. Sys. Operator Corp., 147 FERC ¶ 61,231, order on reh’g, 

clarification, and compliance, 149 FERC ¶ 61,058 (2014).

(continued ...)
Docket No. RM19-2-000 - 33 -

the NOPR did not propose to expand the relief from the requirement to submit screens in 

the EIM or seek comment on the sufficiency of the mitigation.

E. Bilateral Sales

1. Comments

57. Several commenters assert that monitoring and mitigation does not ensure just and 

reasonable rates for bilateral sales of electricity in RTO/ISO markets.78 

AAI/APPA/NRECA argue that “[t]he NOPR provides no factual or legal support for its 

claims that private monitoring and mitigation of RTO/ISO markets will indirectly ensure 

just and reasonable rates in non-RTO/ISO markets” and “no prior Commission order or 

court decision supports this proposition.”79 AAI/APPA/NRECA argue that the NOPR’s 

claim that RTO/ISO markets will discipline market power in long-term bilateral markets 

is “unsubstantiated and illogical.”80 AAI/APPA/NRECA state that purchases from 

RTO/ISO-run capacity auctions are not a substitute for self-supply arrangements and 

long-term bilateral capacity purchases needed by a load-serving entity seeking to provide 

rate stability for its retail customers.81

58. TAPS asserts that there is no basis for assuming that voluntary RTO/ISO capacity 

markets are substitutes for bilateral transactions, especially for load-serving entities that 

 78 APPA/AAI/NRECA at 23; TAPS at 19.

79 AAI/APPA/NRECA at 24.

80 Id. at 25.

81 Id.

(continued ...)
Docket No. RM19-2-000 - 34 -

rely heavily on bilateral transactions to meet their resource requirements.82 According to 

TAPS, spot markets and one-year capacity products do not provide a sufficient 

benchmark against which to compare prices in bilateral markets, given the nonsubstitutable nature of these products.83 TAPS asserts that the one-year product sold on 

mandatory capacity markets is not an adequate substitute for long-term bilateral contracts

and the NOPR makes no claims to the contrary.84 According to TAPS, just as a night at 

an Airbnb is not a substitute for the purchase of a home, the price of a night at an Airbnb 

does not provide a benchmark against which to compare the price of purchasing a 

home.85 TAPS also criticizes the NOPR’s finding that bilateral markets for energy and 

capacity should be competitive so long as RTO/ISO energy and capacity markets are 

competitive, and monitoring and mitigation sufficiently protects against the exercise of 

market power in these markets. TAPS argues that the Commission makes no showing 

that RTO/ISO energy and capacity markets are competitive.86 TAPS argues that even if 

one were to credit the NOPR’s contention that competitive auction prices discipline 

bilateral sales (to some unspecified degree), this reasoning runs “directly afoul” of the 

 82 TAPS at 15-16.

83 Id.

84 Id. at 16.

85 Id.

86 Id.

(continued ...)
Docket No. RM19-2-000 - 35 -

court precedent stating that the Commission cannot rely upon market forces as a basis for 

approving market-based rate transactions.87

2. Commission Determination 

59. We find that Commission-approved RTO/ISO monitoring and mitigation will 

enable the Commission to retain sufficient oversight of bilateral sales in RTO/ISO 

markets. We disagree with AAI/APPA/NRECA and TAPS’s suggestion that the 

Commission’s statement that RTO/ISO mitigation can effectively discipline bilateral 

transactions is “unsubstantiated.” In the NOPR, the Commission acknowledged that 

purchases in short-term RTO/ISO energy and capacity markets are not necessarily perfect 

substitutes for long-term bilateral purchases of energy and/or capacity. However, 

AAI/APPA/NRECA and TAPS make an unsupported logical leap in suggesting that these 

products are not substitutable at all, and therefore prices in the RTO/ISO-administered 

energy and capacity markets do not discipline or provide a useful benchmark against 

which to compare prices offered in bilateral markets within RTOs/ISOs. These products 

may be imperfect substitutes but that does not mean that there is no relationship between 

prices in RTO/ISO-administered markets and bilateral markets. As the Commission 

found in Order No. 697-A, “[i]n RTO/ISOs, buyers have access to centralized, bid-based 

short-term markets which will discipline a seller’s attempt to exercise market power in 

 87 Id. at 18 (citing Lockyer, 383 F.3d at 1013).

(continued ...)
Docket No. RM19-2-000 - 36 -

long-term contracts because the would-be buyer can always purchase from the short-term 

market if a seller tries to charge an excessive price.”88

60. RTO/ISO-administered capacity auctions establish prices for prospective 

deliveries of capacity—the firm supply needed by load-serving entities. PJM’s capacity 

auctions, for example, establish prices for capacity to be delivered in three years. We 

find that such prices, along with RTO/ISO-administered energy prices and other liquid 

and frequently traded products, such as standardized forward contracts, provide a 

benchmark against which to compare prices offered in the market for long-term bilateral 

contracts.89

61. We also note that the Commission has consistently found that long-term markets 

for energy and capacity are competitive in the absence of barriers to entry.90 TAPS does 

not provide any evidence that RTO/ISO markets suffer from barriers to entry. 

 88 Order No. 697-A, 123 FERC ¶ 61,055 at P 285.

89 RTOs/ISOs periodically calculate the cost of new entry or “CONE” to provide a 

benchmark price for new capacity. CONE is a measure of the revenue needed to recover 

the cost of a new generating unit, typically a gas-fired combustion turbine or combined 

cycle unit, net of energy revenues. While this is an administratively determined cost, it 

provides another useful benchmark that buyers can use to assess prices offered in the 

long-term bilateral market.

90 Order No. 697, 119 FERC ¶ 61,295 at P 114; see also Order No. 697-A, 123 

FERC ¶ 61,055 at P 279; Promoting Wholesale Competition Through Open Access NonDiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by 

Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 

(1996) (cross-referenced at 77 FERC ¶ 61,080), order on reh’g, Order No. 888-A, 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 

(continued ...)
Docket No. RM19-2-000 - 37 -

62. Contrary to TAPS’s contention, eliminating the requirement for Sellers to submit 

screens in certain RTOs/ISOs is not inconsistent with Lockyer because the Commission is 

not “relying on market forces alone” to ensure that these bilateral sales result in just and 

reasonable rates. In addition to RTO/ISO mitigation measures, RTO/ISO sellers engaged 

in these bilateral sales remain subject to EQR reporting requirements, which comprise 

part of the post-approval reporting requirements that reassured the court that the 

Commission was not relying on market forces alone.91 As the U. S. Court of Appeals for 

the Ninth Circuit recognized, the Commission conducts ongoing analysis of ex post

transactional EQR and other market data to detect indications of market power in the 

wholesale electricity markets “to determine whether rates were ‘just and reasonable’ and 

whether market forces were truly determining the price.”92 Additionally, as is currently 

the case, in the event someone is aware of a situation where a Seller is exercising market 

power in a bilateral transaction in an RTO/ISO geographic area, evidence of that exercise 

of market power, for example an analysis of EQR data, could serve as the basis of a 

 

v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 

(2002); Preventing Undue Discrimination and Preference in Transmission Service, Order 

No. 890, 118 FERC ¶ 61,119, order on reh’g, Order No. 890-A, 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, 126 FERC ¶ 61,228, order on clarification, Order No. 890-D, 129 

FERC ¶ 61,126 (2009).

91 See Lockyer, 383 F.3d at 1014.

92 Id.
Docket No. RM19-2-000 - 38 -

complaint or a protest. The Commission is not aware of any such challenges since the 

issuance of Order No. 697.

F. Current Status and Effectiveness of RTO/ISO Monitoring and 

Mitigation

1. Comments

63. ELCON tentatively supports the proposal in the NOPR but questions the 

effectiveness of RTO/ISO monitoring and mitigation and suggests that the Commission 

could do more to elucidate the impact of horizontal market power on price formation in 

the RTOs/ISOs. Specifically, ELCON conditionally supports the NOPR, but only if the 

Commission explicitly and fully retains its authority to take direct action to prevent 

potential exercise of horizontal market power and simultaneously initiates a review of the 

effectiveness of RTO/ISO market monitoring and mitigation practices when issuing the 

final rule.

93 ELCON argues that ultimately it would be more productive if, instead of 

focusing on the indicative screens, Commission staff resources were redirected toward 

robust examination of dynamic horizontal market power, monitoring, and mitigation in 

the RTOs/ISOs.94 ELCON states that the Commission should bolster RTO/ISO and 

Commission reporting to provide more transparency and analytic insights on the 

influence of horizontal market power in price formation, which includes more refined 

 93 ELCON at 3.

94 Id. at 10.

(continued ...)
Docket No. RM19-2-000 - 39 -

markup estimates and the aggregate and localized cost to load effects.95 ELCON 

suggests that the Commission could initiate this process with a notice of inquiry and 

technical conference, before proceeding to the RTO/ISO specific determinations that 

would be necessary to achieve such action.96

64. In contrast, Competitive Suppliers urge the Commission to avoid holding market 

power mitigation to an “unreasonable standard,” noting that existing market power 

mitigation protocols are better suited to prevent the exercise of market power than static 

indicative screens and that market power mitigation protocols will necessarily evolve 

with experience and changes in market fundamentals. Competitive Suppliers argue that 

the Commission should not delay implementing its proposal to relieve Sellers of the 

burden to file indicative screens while it waits for the mitigation protocols to cross the 

“elusive finish line represented by the standard that market power mitigation is 

‘complete.’”97

2. Commission Determination

65. We disagree with ELCON that it is necessary to initiate a formal review of the 

effectiveness of RTO/ISO monitoring and mitigation practices concurrent with this final 

rule. The Commission has previously accepted each RTO/ISO’s market monitoring and 

 95 Id.

96 Id.

97 Competitive Suppliers at 3-4.

(continued ...)
Docket No. RM19-2-000 - 40 -

mitigation provisions as just and reasonable. Moreover, as discussed in the NOPR, 

market power mitigation in RTOs/ISOs uses more granular data than the indicative 

screens.98 The indicative screens use static data from a historical study year to evaluate a 

Seller’s ability to exercise market power in the relevant market (i.e. at the balancing 

authority area/market, or submarket, level). In contrast, RTO/ISO mitigation uses 

interval-specific market and operational data to identify, in real-time, binding 

transmission constraints that create conditions that could result in the emergence of local 

market power. Removing the indicative screens does not affect the RTOs/ISOs’ 

application of the market power monitoring and mitigation provisions in their markets. 

66. Moreover, nothing in this final rule precludes an RTO/ISO from filing to amend 

the existing market power mitigation provisions if improvement is needed. Indeed, in 

recent years, improvements have been made to market monitoring and mitigation 

protocols in all RTO/ISO markets.

99 The Commission will continue to scrutinize

 98 NOPR, 165 FERC ¶ 61,269 at P 28.

99 See, e.g., Cal. Indep. Sys. Operator Corp., 157 FERC ¶ 61,091 (2016) (adding a 

new mitigation run for each five-minute real-time dispatch interval to address the 

potential for under-mitigation); Cal. Indep. Sys. Operator Corp., 143 FERC ¶ 61,078 

(2013) (replacing a static competitive path assessment with a dynamic competitive path 

assessment in the hour-ahead scheduling process and the real-time market to better 

evaluate whether transmission constraints are competitive); Midcontinent Indep. Sys. 

Operator, Inc., 161 FERC ¶ 61,268 (2017) (establishing Dynamic Narrow Constrained 

Areas); ISO New England, Inc., 155 FERC ¶ 61,029 (2016) (addressing the potential 

exercise of market power associated with the retirement of existing resources); PJM 

Interconnection, L.L.C., 158 FERC ¶ 61,133 (2017) (revising the market power 

mitigation methodology for resources committed in the day-ahead market to update their 

offers in real-time, for the purposes of mitigation, electing to use the offer that results in 

the lowest cost to the PJM system); PJM Interconnection, L.L.C., Docket No. ER18-252-

(continued ...)
Docket No. RM19-2-000 - 41 -

RTO/ISO market monitoring and mitigation provisions and take necessary action, as 

appropriate, should any issues arise.

G. Other Issues Raised By Commenters

1. Change in Status and Triennial Updates

a. Comments

67. EEI requests that the Commission eliminate the requirement for change in status 

reporting and reconsider the continued need for the triennial market power update for all 

Sellers relying on Commission-approved market monitoring and mitigation.100 EEI asks 

the Commission to clarify the characteristics it relies upon in granting market-based rate 

authority. To the extent information is not relied upon by the Commission in its initial 

grant of market-based rate authorization, EEI contends that it also is not relevant to 

changes in status and Sellers should not be required to submit it.101

68. EEI points to how the Commission currently requires that change in status 

reporting and triennial market power updates include information on any new affiliations 

with entities that own, operate, or control transmission facilities. EEI argues that “[s]o 

 

000 (Dec. 18, 2017) (delegated order) (applying market power tests to resources that are 

committed out-of-market and to resources that self-schedule in real-time); Sw. Power 

Pool, Inc., 165 FERC ¶ 61,242 (2018) (streamlining the process by which Frequently 

Constrained Areas are designated); N.Y. Indep. Sys. Operator, Inc., Docket No. ER18-

1168-000 (May 14, 2018) (delegated order) (revising the market power mitigation 

provisions to address cases where Sellers submit inaccurate fuel type or fuel price 

information in fuel cost adjustments).

100 EEI at 8-9.

101 Id. at 9.

(continued ...)
Docket No. RM19-2-000 - 42 -

long as the affiliated transmission facilities are turned over to the operational control of 

an RTO/ISO, subject to an Open Access Transmission Tariff (OATT) or have received a 

waiver of the OATT requirement, [market-based rate] sellers should not be required to 

report such information as changes in status.”102 EEI adds that the same principles justify 

eliminating reporting of inputs to power production. According to EEI, “[s]uch inputs 

would comprise part of the price that is controlled by the Commission-approved market 

monitoring and mitigation, thereby addressing any market power concerns.”103

69. Similarly, SoCal Edison argues that RTO/ISO sellers who are exempt from 

submitting screens under the proposal should also be relieved of the requirement to file a 

change in status for any net increases of generation in their portfolios. In SoCal Edison’s 

view, an increase in generation would not affect the characteristics the Commission relied 

upon in granting the Seller market-based rate authority because, under the proposal, the 

Commission is no longer relying on any particular amount of generating capacity when 

granting market-based rate authority.104

70. Contrary to these comments, AAI/APPA/NRECA urge the Commission to gather 

more information from Sellers and advocate for removing the current stay of the 

requirement in 18 CFR 35.37(a)(2) that Sellers submit an organizational chart. 

 102 Id. at 10-11.

103 Id. at 11.

104 SoCal Edison at 9-10.

(continued ...)
Docket No. RM19-2-000 - 43 -

AAI/APPA/NRECA contend that the organizational chart requirement should be 

reinstituted regardless of whether the Commission adopts the NOPR, but particularly if 

the Commission eliminates the indicative screen requirement based in part on “the 

availability of other data regarding horizontal market power.”105

b. Commission Determination

71. We reject, as beyond the scope of this proceeding, EEI’s and SoCal Edison’s 

requests to eliminate the requirement for change in status reporting and to reconsider the 

continued need for the triennial market power updates. The Commission did not propose 

to eliminate or change the triennial or change in status requirements and did not request

comment on such a proposal.

72. Similarly, we deny as beyond the scope of this proceeding, AAI/APPA/NRECA’s 

request that the Commission remove the current stay of the requirement in 18 CFR 

35.37(a)(2) that Sellers submit an organizational chart.106

2. Rights of Market Monitors

a. Comments

73. Both OPSI and PJM IMM request that the Commission definitively state that 

independent market monitors have the right to file FPA section 206 complaints, including 

 105 AAI/APPA/NRECA at 18 (citing NOPR, 165 FERC ¶ 61,268 at P 27).

106 We note that the Commission is concurrently issuing a final rule in Docket 

No. RM16-17-000 that eliminates the requirement that Sellers submit an organizational 

chart. Data Collection for Analytics and Surveillance and Market-Based Rate Purposes, 

Order No. 860, 168 FERC ¶ 61,039 (2019).

(continued ...)
Docket No. RM19-2-000 - 44 -

complaints against an RTO/ISO for the independent market monitor’s relevant region. 

OPSI states that the right to file FPA section 206 complaints is needed “to ensure 

effective and comprehensive market power mitigation and public confidence in the 

markets.”107 PJM IMM emphasizes that market monitors’ ability to initiate an FPA 

section 206 proceeding when markets are not competitive is a critical part of the NOPR’s 

reliance on effective market monitoring to support market‐based rates.108

74. PJM IMM also asserts that adequate market power monitoring and mitigation 

“requires that market monitors have equal standing with the RTO and its membership to 

file tariff revisions to the market monitoring and mitigation sections of the tariff.”109 

PJM IMM suggests that the Commission could achieve equal standing by requiring that 

all filings to change monitoring and mitigation fall under FPA section 206, as opposed to 

the current practice of allowing RTOs/ISOs to file changes under FPA section 205. PJM 

IMM states that the FPA section 206 approach “would allow the Commission to choose 

the most effective monitoring and mitigation practices, ensuring that markets remain 

competitive and ensuring that market based rates are justified.”110

 107 OPSI at 4-5.

108 PJM IMM at 7.

109 Id. at 6.

110 Id.
Docket No. RM19-2-000 - 45 -

b. Commission Determination

75. We find that OPSI and the PJM IMM’s request that the Commission definitively 

state that independent market monitors have the right to file FPA section 206 complaints 

is beyond the scope of this proceeding. The Commission did not make, or request 

comment on, such a proposal.

76. We similarly find PJM IMM’s suggestion that all filings to change monitoring 

and mitigation fall under FPA section 206 to be beyond the scope of this rulemaking, as 

the Commission did not make, or request comment on, such a proposal.

3. Corporate Character Reporting

a. Comments

77. Public Citizen asserts that the Commission should establish corporate character 

reporting standards for market-based rate applications. Public Citizen states that under 

the Commission’s current regulations, there is no requirement that an applicant disclose 

adjudications, criminal convictions, or adverse legal or regulatory rulings against it. 

Public Citizen maintains that the lack of corporate character reporting requirements 

“leaves the Commission vulnerable to approving market-based rate authority to an entity 

that may have a demonstrated track record of frequent and serious legal violations.”111

b. Commission Determination

78. We find that Public Citizen’s request for establishing corporate character reporting 

requirements for market-based rate applications to be beyond the scope of this 

 111 Public Citizen Comments at 5.
Docket No. RM19-2-000 - 46 -

proceeding. The Commission did not propose to establish corporate character reporting 

requirements or request comment on such a proposal.

4. Data Collection NOPR and Market Power NOI

a. Comments

79. AAI/APPA/NRECA argue that the Commission should not act on this NOPR 

before it has acted on a related pending rulemaking in Docket No. RM16-17-000 (Data 

Collection NOPR) and a notice of inquiry in Docket No. RM16-21-000 (Market Power 

NOI). AAI/APPA/NRECA argue that the NOPR, if adopted, would reduce the 

information available to the Commission for assessing and monitoring the ability of 

Sellers to exercise market power at the same time the Commission is evaluating whether 

the Commission’s existing market power information requirements and analyses are 

sufficient.112

b. Commission Determination

80. We are not persuaded by, and therefore reject AAI/APPA/NRECA’s assertion that 

the Commission should first act on the Data Collection NOPR and Market Power NOI 

proceedings before acting on the instant NOPR. We see no reason why the Commission 

must first act in those proceedings before taking action to remove the screen requirement 

as proposed in the NOPR. Any actions taken in the Data Collection NOPR and Market

Power NOI will not impact the implementation of the removal of the screen requirement. 

As noted above, the Commission will continue to monitor RTO/ISO mitigation 

 112 AAI/APPA/NRECA Comments at 30.
Docket No. RM19-2-000 - 47 -

provisions on an ongoing basis and take necessary action, as appropriate. In addition, we 

note that a final rule in Docket No. RM16-17-000 is being issued concurrently with this 

final rule.113

IV. Information Collection Statement

81. The Paperwork Reduction Act (PRA)114 requires each federal agency to seek and 

obtain Office of Management and Budget (OMB) approval before undertaking a 

collection of information directed to ten or more persons or contained in a rule of general 

applicability. OMB’s regulations115 require approval of certain information collection 

requirements contained in final rules published in the Federal Register.

116 Upon 

approval of a collection of information, OMB will assign an OMB control number and an 

expiration date. Respondents subject to the filing requirements of an agency rule will not 

be penalized for failing to respond to the collection of information unless the collection of 

information display a valid OMB control number.

82. The final rule revises the requirements for Sellers seeking to obtain or retain 

market-based rate authority that study certain RTOs, ISOs, or submarkets therein, as 

discussed above. The Commission anticipates that the revisions, once effective, would 

 113 Order No. 860, 168 FERC ¶ 61,039.

114 44 U.S.C. 3507(d).

115 5 CFR 1320.

116 See 5 CFR 1320.12.

(continued ...)
Docket No. RM19-2-000 - 48 -

reduce regulatory burdens.117 The Commission will submit the reporting requirements to 

OMB for its review and approval under section 3507(d) of the PRA.118

83. While the Commission expects that the revisions adopted in this final rule will 

reduce the burdens on affected entities, the Commission nonetheless solicited public 

comments regarding the Commission’s need for this information, whether the 

information will have practical utility, the accuracy of the burden estimates, ways to 

enhance the quality, utility, and clarity of the information to be collected or retained, and 

any suggested methods for minimizing respondents’ burden, including the use of 

automated information techniques. Specifically, the Commission asked that any revised 

burden or cost estimates submitted by commenters be supported by sufficient detail to 

understand how the estimates are generated. The Commission did not receive any 

comments concerning its burden or cost estimates.

84. Section 35.37 of the Commission’s regulations currently requires Sellers to submit 

a horizontal market power analysis when seeking to obtain or retain market-based rate 

authority.119 The final rule will implement a streamlined procedure that will eliminate 

the requirement for Sellers to file the indicative screens as part of a horizontal market 

 117 “Burden” is the total time, effort, or financial resources expended by persons to 

generate, maintain, retain, or disclose or provide information to or for a Federal agency. 

For further explanation of what is included in the information collection burden, refer to 

5 CFR 1320.3.

118 44 U.S.C. 3507(d).

119 18 CFR 35.37.
Docket No. RM19-2-000 - 49 -

power analysis for RTO/ISO markets with RTO/ISO-administered energy, ancillary 

services, and capacity markets subject to Commission-approved RTO/ISO monitoring 

and mitigation. In any RTO/ISO market that does not have an RTO/ISO-administered 

capacity market subject to Commission-approved RTO/ISO monitoring and mitigation,

Sellers would continue to be required to submit indicative screens for authorization to 

make capacity sales. Eliminating the requirement to file indicative screens in certain 

markets will reduce the burden of filing a horizontal market power analysis for a large 

portion of Sellers when filing triennial updated market power analyses, initial 

applications for market-based rate authority, and notices of change in status.

85. Burden Estimate: The estimated burden and cost for the requirements are as

follows.
Docket No. RM19-2-000 - 50 -

Burden Reductions in Final Rule, RM19-2-000120

Requirement

Number of 

Respondents

(1)

Annual 

Number of 

Responses 

per 

Respondent

(2)

Total 

Number of 

Responses

(1)*(2)=(3)

Average 

Burden & 

Cost Per 

Response

(4)

Total 

Annual 

Burden 

Hours & 

Cost

(3)*(4)=(5)

Annual 

Cost per 

Respondent 

($)

(5)÷(1)

Market 

Power 

Analysis in 

New 

Applications 

for Marketbased Rates 

for RTO/ISO 

Sellers 72 1 72

-230 hrs.

-$21,620

-16,560 hrs.

-$1,556,640 -$21,620

Triennial 

Market 

Power 

Analysis 

Updates for 

RTO/ISO 

Sellers 33 1 33

-230 hrs.

-$21,620

-7,590 hrs.

-$713,460 -$21,620

Total 105

-24,150 hrs.

-$2,270,100

 120 Although some Sellers may include the indicative screens when submitting a 

change in status filing, this is not required by the Commission’s regulations. Thus, we 

estimate that the change in burden for change in status filings is de minimis. See 18 CFR 

35.42.
Docket No. RM19-2-000 - 51 -

86. After implementation of the proposed changes, the total estimated annual 

reduction in cost burden to respondents is $2,270,100 [24,150 hours * $94 = 

$2,270,100].121

Title: FERC-919, Market Based Rates for Wholesale Sales of Electric Energy, Capacity 

and Ancillary Services by Public Utilities.

Action: Revision of Currently Approved Collection of Information.

OMB Control No.: 1902-0234

Respondents: Public utilities, wholesale electricity sellers, businesses, or other for profit 

and/or nonprofit institutions.

Frequency of Responses: 

Initial Applications: On occasion.

Updated Market Power Analyses: Updated market power analyses are filed every 

three years by Category 2 Sellers seeking to retain market-based rate authority.

Change in Status Reports: On occasion.

 121 The estimated hourly cost (salary plus benefits) provided in this section are 

based on the figures for May 2018 posted by the Bureau of Labor Statistics for the 

Utilities sector (available at http://www.bls.gov/oes/current/naics2_22.htm) and updated 

March 2019 for benefits information (at http://www.bls.gov/news.release/ecec.nr0.htm). 

The hourly estimates for salary plus benefits are: 

Economist: $70.83/hour

Electrical Engineer: $68.17/hour

Lawyer: $142.86/hour

The average hourly cost of the three categories is $93.95 [($70.83+$68.17+$142.86)/3].

The Commission rounds it up to $94.00/hour.
Docket No. RM19-2-000 - 52 -

Necessity of the Information: 

Initial Applications: In order to obtain market-based rate authority, the Commission must 

first evaluate whether a Seller has the ability to exercise market power. Initial 

applications help inform the Commission as to whether an entity seeking market-based 

rate authority lacks market power or has adequately mitigated any market power, and 

whether sales by that entity will be just and reasonable.

Updated Market Power Analyses: Triennial updated market power analyses allow the 

Commission to monitor market-based rate authority to detect changes in market power or 

potential abuses of market power. The updated market power analysis permits the 

Commission to determine that continued market-based rate authority will still yield rates 

that are just and reasonable.

Change in Status Reports: The change in status requirement permits the Commission to 

ensure that rates and terms of service offered by market-based rate Sellers remain just and 

reasonable.

Internal Review: The Commission has reviewed the reporting requirements and made a 

determination that revising the reporting requirements will ensure the Commission has 

the necessary data to carry out its statutory mandates, while eliminating unnecessary 

burden on industry. The Commission has assured itself, by means of its internal review, 

that there is specific, objective support for the burden estimate associated with the 

information requirements.

87. Interested persons may obtain information on the reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, 
Docket No. RM19-2-000 - 53 -

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, 

e-mail: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873].

88. Comments concerning the collection of information and the associated burden 

estimates may also be sent to: Office of Information and Regulatory Affairs, Office of 

Management and Budget, 725 17th Street NW, Washington, DC 20503 [Attention: Desk 

Officer for the Federal Energy Regulatory Commission]. Due to security concerns,

comments should be sent electronically to the following email address: 

oira_submission@omb.eop.gov. Comments submitted to OMB should refer to FERC919 (OMB Control No. 1902-0234).

V. Environmental Analysis

89. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.122 The Commission has categorically excluded certain 

Docket Number RM19-2-000 actions from this requirement as not having a significant 

effect on the human environment.123 The actions proposed here fall within the 

categorical exclusions in the Commission’s regulations for rules that are clarifying, 

corrective, or procedural, or do not substantially change the effect of legislation or 

 122 Regulations Implementing the National Environmental Policy Act of 1969, 

Order No. 486, FERC Stats. & Regs., ¶ 30,783 (1987) (cross-referenced at 41 FERC 

¶ 61,284).

123 18 CFR 380.4.

(continued ...)
Docket No. RM19-2-000 - 54 -

regulations being amended.124 In addition, this final rule is categorically excluded as an 

electric rate filing submitted by a public utility under Federal Power Act sections 205 and 

206.125 As explained above, this final rule, which addresses the issue of electric rate 

filings submitted by public utilities for market-based rate authority, is clarifying in nature. 

Accordingly, no environmental assessment is necessary and none has been prepared in 

this final rule.

VI. Regulatory Flexibility Act

90. The Regulatory Flexibility Act of 1980 (RFA)126 generally requires a description 

and analysis of final rules that will have significant economic impact on a substantial 

number of small entities. The RFA mandates consideration of regulatory alternatives that 

accomplish the stated objectives of a final rule and minimize any significant economic 

impact on a substantial number of small entities. In lieu of preparing a regulatory 

flexibility analysis, an agency may certify that a final rule will not have a significant 

economic impact on a substantial number of small entities. 

91. The Small Business Administration’s (SBA) Office of Size Standards develops the 

numerical definition of a small business.127 The SBA size standard for electric utilities is 

 124 18 CFR 380.4(a)(2)(ii).

125 18 CFR 380.4(a)(15).

126 5 U.S.C. 601-612.

127 13 CFR 121.101.

(continued ...)
Docket No. RM19-2-000 - 55 -

based on the number of employees, including affiliates.128 Under SBA’s current size 

standards, an electric utility (one that falls under NAICS codes 221122 [electric power 

distribution], 221121 [electric bulk power transmission and control], or 221118 [other 

electric power generation])129 are small if it, including its affiliates, employs 1,000 or 

fewer people.130 

92. Out of the 2,500 market-based rate Sellers who are potential respondents subject 

to the requirements proposed by this final rule, the Commission estimates approximately 

74 percent of the affected entities (or approximately 1,850) are small entities. We 

estimate that none of the 1,850 small entities to whom the final rule apply will incur 

additional cost because these small entities will no longer be required to file indicative 

screens causing a reduction in burden, not an increase. 

93. The final rule will eliminate some requirements and reduce burden on entities of 

all sizes (public utilities seeking and currently possessing market-based rate authority). 

Implementation of the final rule is expected to reduce total annual burden by 

24,150 hours per year or 9.66 hours per entity with a related reduced cost of 

 128 Id. 121.201.

129 The North American Industry Classification System (NAICS) is an industry 

classification system that Federal statistical agencies use to categorize businesses for the 

purpose of collecting, analyzing, and publishing statistical data related to the U.S. 

economy. United States Census Bureau, North American Industry Classification System, 

https://www.census.gov/eos/www/naics/.

130 13 CFR 121.201 (Sector 22 - Utilities).

(continued ...)
Docket No. RM19-2-000 - 56 -

$2,270,100 per year or $908.04 per entity to the industry when filing triennial market 

power analyses and market power analyses in new applications for market-based rates, 

and will further reduce burden when filing notices of change in status.

94. As discussed in Order No. 697,131 current regulations regarding market-based rate 

Sellers under Subpart H to Part 35 of Title 18 of the Code of Federal Regulations exempt 

many small entities from significant filing requirements by designating them as Category 

1 Sellers. Category 1 Sellers are exempt from triennial updates and may use simplifying 

assumptions, such as Sellers with fully-committed generation may submit an explanation 

that their generation is fully committed in lieu of submitting indicative screens, that the 

Commission allows Sellers to utilize in submitting their horizontal market power 

analysis.

95. The final rule will relieve Sellers in certain RTO/ISO markets of the requirement 

to submit indicative screens and will reduce the burden on those Sellers, including small 

entities. The changes to the Commission’s regulations are estimated to cause a reduction 

of 41 percent in total annual burden to Sellers when filing triennial market power 

analyses and market power analyses in new applications for market-based rates, including 

small entities.

96. Accordingly, pursuant to section 605(b) of the RFA, the Commission certifies that 

this final rule will not have a significant economic impact on a substantial number of 

small entities. 

 131 Order No. 697, 119 FERC ¶ 61,295 at PP 1126-1129.
Docket No. RM19-2-000 - 57 -

VII. Document Availability

97. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission’s Home Page 

(http://www.ferc.gov) and in the Commission’s Public Reference Room during normal 

business hours (8:30 a.m. to 5:00 p.m. Eastern Time) at 888 First Street, NE, Room 2A, 

Washington, DC 20426.

98. From the Commission’s Home Page on the Internet, this information is available 

on eLibrary. The full text of this document is available on eLibrary in PDF and 

Microsoft Word format for viewing, printing, and/or downloading. To access this 

document in eLibrary, type the docket number excluding the last three digits of this 

document in the docket number field.

99. User assistance is available for eLibrary and the Commission’s website during 

normal business hours from FERC Online Support at (202) 502-6652 (Toll-free at 1-866-

208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at 

(202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.

VIII. Effective Date and Congressional Notification

100. This final rule is effective [INSERT DATE 60 DAYS AFTER DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. The Commission has determined, 

with the concurrence of the Administrator of the Office of Information and Regulatory 

Affairs of OMB, that this rule is not a major rule as defined in section 351 of the Small 
Docket No. RM19-2-000 - 58 -

Business Regulatory Enforcement Fairness Act of 1996.132 This rule is being submitted 

to the Senate, House, Government Accountability Office, and Small Business 

Administration.

List of subjects in 18 CFR Part 35

Electric power rates, Electric utilities, Reporting and recordkeeping requirements.

By the Commission.

( S E A L )

Kimberly D. Bose,

 Secretary.

 132 5 U.S.C. 804(2).
Docket No. RM19-2-000 - 59 -

In consideration of the foregoing, the Commission proposes to amend Part 35, 

Chapter I, Title 18, Code of Federal Regulations, as follows:

PART 35 – FILING OF RATE SCHEDULES AND TARIFFS

1. The authority citation for Part 35 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-

7352.

§35.37 [Amended]

2. Amend § 35.37 as follows:

a. Redesignate paragraph (c)(5) as (c)(7).

b. Add new paragraphs (c)(5) and (c)(6) to read as follows:

§35.37 Market power analysis required.

* * * * *

(5) In lieu of submitting the indicative market power screens, Sellers studying 

regional transmission organization (RTO) or independent system operator (ISO) markets 

that operate RTO/ISO-administered energy, ancillary services, and capacity markets may 

state that they are relying on Commission-approved market monitoring and mitigation to 

address potential horizontal market power Sellers may have in those markets.

(6) In lieu of submitting the indicative market power screens, Sellers studying 

RTO or ISO markets that operate RTO/ISO-administered energy and ancillary services 

markets, but not capacity markets, may state that they are relying on Commissionapproved market monitoring and mitigation to address potential horizontal market power 

that Sellers may have in energy and ancillary services. However, Sellers studying such 
Docket No. RM19-2-000 - 60 -

RTOs/ISOs would need to submit indicative market power screens if they wish to obtain 

market-based rate authority for wholesale sales of capacity in these markets.

* * * * *
Docket No. RM19-2-000 - 61 -

Note: The following appendix will not be published in the Code of Federal 

Regulations.

Appendix A

List of Commenters and Acronyms

Commenter Short Name/Acronym

American Antitrust Institute, 

American Public Power Association, 

and National Rural Electric 

Cooperative Association AAI/APPA/NRECA

California Independent System 

Operator - Department of Market 

Monitoring CAISO DMM

Calpine Corporation Calpine

EDF Renewables, Inc. EDF Renewables

Edison Electric Institute EEI

EIM Entities (Arizona Public 

Service Company, Avista 

Corporation, Idaho Power

Company, NV Energy, Inc., 

PacifiCorp, and Portland General

Electric Company) EIM Entities

Electric Power Supply Association 

and Independent Energy Producers 

Association Competitive Suppliers

Electricity Consumers Resource 

Council ELCON

Evergy Companies (Westar Energy, 

Inc., Kansas City Power & Light 

Company, and KCP&L Greater Evergy/Xcel
Docket No. RM19-2-000 - 62 -

Missouri Operations Company) and 

Xcel Energy Services Inc.

FirstEnergy Service Company FirstEnergy

Indicated Generation Investors 

(Southwest Generation Operating 

Company, LLC, Ares EIF 

Management,

LLC, Northern Star Generation 

Services Company LLC, Astoria 

Energy LLC and Astoria Energy II 

LLC, and

Coronal Management, LLC) Indicated Generation Investors

Monitoring Analytics, LLC PJM IMM

Organization of PJM States, Inc. OPSI

Pacific Gas and Electric Company PG&E

Powerex Corp. Powerex

Public Citizen Public Citizen

Southern California Edison 

Company SoCal Edison

Transmission Access Policy Study 

Group TAPS