Document ID: FERC-2019-0870-0001
Agency: ferc
Document Type: Rule
Title: Refinements to Horizontal Market Power Analysis for Sellers in Certain RegionalTransmission Organization and Independent System Operator Markets
Posted Date: 2019-07-26T04:00Z

[Federal Register Volume 84, Number 144 (Friday, July 26, 2019)]
[Rules and Regulations]
[Pages 36374-36387]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2019-15716]

[[Page 36373]]

Vol. 84

Friday,

No. 144

July 26, 2019

Part IV

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Refinements to Horizontal Market Power Analysis for Sellers in Certain 
Regional Transmission Organization and Independent System Operator 
Markets; Final Rule

  Federal Register / Vol. 84 , No. 144 / Friday, July 26, 2019 / Rules 
and Regulations  

[[Page 36374]]

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DEPARTMENT OF ENERGY

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.

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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/ISO-administered 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 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 September 24, 2019.

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 Nos.
 
I. Introduction......................................                  1
II. Background.......................................                  5
III. Discussion......................................                  9
    A. Assurance of Just and Reasonable Rates........                  9
        1. Availability of Data Necessary for                         10
         Effective Review of Seller Market Power.....
        2. No Sub-delegation of Statutory                             28
         Responsibility..............................
    B. Retention of Screens for Capacity Sellers in                   32
     CAISO and SPP...................................
        1. CAISO.....................................                 32
        2. SPP.......................................                 43
    C. Clarifications for Capacity Sellers in CAISO                   49
     and SPP.........................................
    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                    63
     Monitoring and Mitigation.......................
        1. Comments..................................                 63
        2. Commission Determination..................                 65
    G. Other Issues Raised By Commenters.............                 67
        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
IV. Information Collection Statement.................                 81
V. Environmental Analysis............................                 89
VI. Regulatory Flexibility Act.......................                 90
VII. Document Availability...........................                 97
VIII. Effective Date and Congressional Notification..                100
 

I. Introduction

    1. On December 20, 2018, the Federal Energy Regulatory Commission 
(Commission) issued a notice of proposed rulemaking (NOPR) \1\ 
proposing to modify Sec.  35.37(c) of its regulations regarding the 
horizontal market power analysis for market-based

[[Page 36375]]

rate sellers \2\ 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 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\
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    \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.
    \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.
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    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.
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    \5\ Although the Commission did not request reply comments, 
several commenters nonetheless submitted reply comments. The 
Commission rejects such reply comments.
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    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 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.
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    \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, 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).
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    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 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\
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    \8\ Order No. 697, 119 FERC ] 61,295 at P 62.
    \9\ Id. PP 33, 62-63.
    \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.
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    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 the exercise 
of market power.\14\ Under that proposal, RTO/ISO sellers \15\ 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\
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    \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).
    \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.
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    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.
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    \17\ Order No. 816, 153 FERC ] 61,065 at P 27.
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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 mitigation, the Commission 
emphasized that it would continue to ensure that market-based rates are 
just and reasonable.\18\ However, commenters raise concerns that the 
proposal compromises the

[[Page 36376]]

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 Sec.  35.37(c) of 
the Commission's regulations, as proposed in the NOPR.
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    \18\ NOPR, 165 FERC ] 61,268 at PP 61-70.
    \19\ TAPS at 20-21; AAI/APPA/NRECA at 29.
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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\
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    \20\ AAI/APPA/NRECA at 15 (citing Order No. 697-A, 123 FERC ] 
61,055 at P 109); TAPS at 7 (citing same).
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    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\
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    \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).
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    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\ 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\
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    \24\ TAPS at 13.
    \25\ AAI/APPA/NRECA at 17.
    \26\ Id. at 26.
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    13. AAI/APPA/NRECA and TAPS argue that the Commission should retain 
its case-by-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\
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    \27\ TAPS at 22.
    \28\ Id. at 8.
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    14. Public Citizen believes that the NOPR interferes with the 
public's right to inspect, comment, and protest Federal Power Act (FPA) 
section 205 \29\ 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\
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    \29\ 16 U.S.C. 824d.
    \30\ Public Citizen at 3.
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    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.
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    \31\ AAI/APPA/NRECA at 16.
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    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 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\
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    \32\ TAPS at 13.
    \33\ AAI/APPA/NRECA at 28.
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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.
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    \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).
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    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 
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

[[Page 36377]]

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.
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    \35\ See Lockyer, 383 F.3d at 1013; Blumenthal, 552 F.3d at 882; 
Mont. Consumer Counsel, 659 F.3d at 916.
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    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 required under Sec.  
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.
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    \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).
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    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 obtain or retain market-
based rate authority. This will continue to occur notwithstanding the 
existence of Commission-approved monitoring and mitigation.
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    \37\ Public Citizen at 3.
    \38\ 16 U.S.C. 824e.
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    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\
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    \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).
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    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 can examine transaction level data 
(e.g., resource supply offers) using data provided pursuant to Order 
No. 760 to conduct such oversight.\41\
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    \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).
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    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 
Commission-approved 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 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\
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    \42\ Order No. 697-A, 123 FERC ] 61,055 at P 5.
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    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

[[Page 36378]]

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\
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    \43\ Public Citizen at 4-5 (also noting that the market monitors 
do not have corporate control protections to safeguard the public 
interest).
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    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\
---------------------------------------------------------------------------

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

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 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).
---------------------------------------------------------------------------

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

    \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).
    \48\ Calpine at 7.
---------------------------------------------------------------------------

    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-of-service 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 market-based 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).
---------------------------------------------------------------------------

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

    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

[[Page 36379]]

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

    \51\ SoCal Edison at 4.
    \52\ Id. at 5.
    \53\ Id. at 7.
---------------------------------------------------------------------------

    36. Other commenters support the proposal to retain the requirement 
that Sellers submit indicative screens for capacity sales in CAISO.\54\ 
CAISO DMM ``strongly 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 system-wide offer caps set 
ceilings in ISO-administered capacity markets; ``[h]owever, these 
backstop procurement processes do not mitigate market power like the 
Commission-approved market power mitigation in those capacity 
markets.'' \56\
---------------------------------------------------------------------------

    \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); 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.
---------------------------------------------------------------------------

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

    \57\ TAPS at 19-20.
    \58\ Id.
---------------------------------------------------------------------------

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 Commission-approved 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 
Commission-approved rules for capacity in CAISO comparable to the 
market price for capacity established by RTOs/ISOs with centralized 
capacity markets.\59\
---------------------------------------------------------------------------

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

    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. 
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-Allegheny \61\ 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) (Edgar-Allegheny).
---------------------------------------------------------------------------

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

    \62\ SoCal Edison at 7.
---------------------------------------------------------------------------

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

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

    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 must-offer 
requirements, vigorous independent market monitoring, and Commission-
accepted 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\
---------------------------------------------------------------------------

    \64\ Evergy/Xcel at 8.
    \65\ Id. at 9-10.
---------------------------------------------------------------------------

    45. Evergy/Xcel state that the Commission rejected proposed

[[Page 36380]]

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

    \66\ Id. at 11-12.
---------------------------------------------------------------------------

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-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 review \67\ 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.
---------------------------------------------------------------------------

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

    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.

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

    \68\ Calpine at 9 (emphasis in original).
---------------------------------------------------------------------------

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

    \69\ NOPR, 165 FERC ] 61,268 at P 49.
    \70\ Powerex at 5.
---------------------------------------------------------------------------

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.

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

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

    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 
requirement to perform

[[Page 36381]]

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

    \73\ Id. at 7-8.
    \74\ Id. at 10.
    \75\ Id. at 12-13.
---------------------------------------------------------------------------

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

    \76\ CAISO DMM at 8-9.
---------------------------------------------------------------------------

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

    \77\ See Cal. Indep. Sys. Operator Corp., 147 FERC ] 61,231, 
order on reh'g, clarification, and compliance, 149 FERC ] 61,058 
(2014).
---------------------------------------------------------------------------

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

    \78\ APPA/AAI/NRECA at 23; TAPS at 19.
    \79\ AAI/APPA/NRECA at 24.
    \80\ Id. at 25.
    \81\ Id.
---------------------------------------------------------------------------

    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 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 non-substitutable 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 court precedent stating that the 
Commission cannot rely upon market forces as a basis for approving 
market-based rate transactions.\87\
---------------------------------------------------------------------------

    \82\ TAPS at 15-16.
    \83\ Id.
    \84\ Id. at 16.
    \85\ Id.
    \86\ Id.
    \87\ Id. at 18 (citing Lockyer, 383 F.3d at 1013).
---------------------------------------------------------------------------

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

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

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

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

    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

[[Page 36382]]

evidence that RTO/ISO markets suffer from barriers to entry.
---------------------------------------------------------------------------

    \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 Non-Discriminatory 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 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).
---------------------------------------------------------------------------

    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 
complaint or a protest. The Commission is not aware of any such 
challenges since the issuance of Order No. 697.
---------------------------------------------------------------------------

    \91\ See Lockyer, 383 F.3d at 1014.
    \92\ Id.
---------------------------------------------------------------------------

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

    \93\ ELCON at 3.
    \94\ Id. at 10.
    \95\ Id.
    \96\ Id.
---------------------------------------------------------------------------

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

    \97\ Competitive Suppliers at 3-4.
---------------------------------------------------------------------------

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

    \98\ NOPR, 165 FERC ] 61,269 at P 28.
---------------------------------------------------------------------------

    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 RTO/ISO market 
monitoring and mitigation provisions and take necessary action, as 
appropriate, should any issues arise.
---------------------------------------------------------------------------

    \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. 
ER18-252-000 (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).
---------------------------------------------------------------------------

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

[[Page 36383]]

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

    \100\ EEI at 8-9.
    \101\ Id. at 9.
---------------------------------------------------------------------------

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

    \102\ Id. at 10-11.
    \103\ Id. at 11.
---------------------------------------------------------------------------

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

    \104\ SoCal Edison at 9-10.
---------------------------------------------------------------------------

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

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

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

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

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 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[hyphen]based 
rates.\108\
---------------------------------------------------------------------------

    \107\ OPSI at 4-5.
    \108\ PJM IMM at 7.
---------------------------------------------------------------------------

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

    \109\ Id. at 6.
    \110\ Id.
---------------------------------------------------------------------------

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

    \111\ Public Citizen Comments at 5.
---------------------------------------------------------------------------

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 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

[[Page 36384]]

information requirements and analyses are sufficient.\112\
---------------------------------------------------------------------------

    \112\ AAI/APPA/NRECA Comments at 30.
---------------------------------------------------------------------------

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

    \113\ Order No. 860, 168 FERC ] 61,039.
---------------------------------------------------------------------------

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 
regulations \115\ 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.
---------------------------------------------------------------------------

    \114\ 44 U.S.C. 3507(d).
    \115\ 5 CFR 1320.
    \116\ See 5 CFR 1320.12.
---------------------------------------------------------------------------

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

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

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

    \119\ 18 CFR 35.37.
---------------------------------------------------------------------------

    85. Burden Estimate: The estimated burden and cost for the 
requirements are as follows.

                                                    Burden Reductions in Final Rule, RM19-2-000 \120\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       Annual  number
                                          Number of     of  responses   Total number     Average burden & cost     Total annual burden      Annual cost
             Requirement                 respondents         per        of responses         per response              hours & cost             per
                                                         respondent                                                                       respondent ($)
                                                  (1)             (2)     (1) * (2) =  (4).....................  (3) * (4) = (5)........       (5) / (1)
                                                                                  (3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Market Power Analysis in New                       72               1              72  -230 hrs. -$21,620......  -16,560 hrs. -                 -$21,620
 Applications for Market-based Rates                                                                              $1,556,640.
 for RTO/ISO Sellers.
Triennial Market Power Analysis                    33               1              33  -230 hrs. -$21,620......  -7,590 hrs. -$713,460..        -$21,620
 Updates for RTO/ISO Sellers.
rrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrr
    Total............................  ..............  ..............             105  ........................  -24,150 hrs. -
                                                                                                                  $2,270,100
--------------------------------------------------------------------------------------------------------------------------------------------------------

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

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

    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.

[[Page 36385]]

    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.
    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, Washington, DC 20426 [Attention: Ellen 
Brown, Office of the Executive Director, email: 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 
FERC-919 (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 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.
---------------------------------------------------------------------------

    \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.
    \124\ 18 CFR 380.4(a)(2)(ii).
    \125\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

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

    \126\ 5 U.S.C. 601-612.
---------------------------------------------------------------------------

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

    \127\ 13 CFR 121.101.
    \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).
---------------------------------------------------------------------------

    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 $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

[[Page 36386]]

submitting their horizontal market power analysis.
---------------------------------------------------------------------------

    \131\ Order No. 697, 119 FERC ] 61,295 at PP 1126-1129.
---------------------------------------------------------------------------

    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.

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. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

VIII. Effective Date and Congressional Notification

    100. This final rule is effective September 24, 2019. 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 Business 
Regulatory Enforcement Fairness Act of 1996.\132\ This rule is being 
submitted to the Senate, House, Government Accountability Office, and 
Small Business Administration.
---------------------------------------------------------------------------

    \132\ 5 U.S.C. 804(2).
---------------------------------------------------------------------------

 List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By the Commission.
Kimberly D. Bose,
Secretary.
    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

0
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.

Sec.  35.37  [Amended]

0
2. Amend Sec.  35.37 as follows:
0
a. Redesignate paragraph (c)(5) as (c)(7); and
0
b. Add new paragraph (c)(5) and paragraph (c)(6).
    The additions read as follows:

Sec.  35.37  Market power analysis required.

* * * * *
    (c) * * *
    (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 Commission-approved market monitoring 
and mitigation to address potential horizontal market power that 
Sellers may have in energy and ancillary services. However, Sellers 
studying such 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.
* * * * *

    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        AAI/APPA/NRECA.
 Association, and National Rural Electric Cooperative
 Association.
California Independent System Operator--Department of      CAISO DMM.
 Market Monitoring.
Calpine Corporation......................................  Calpine.
EDF Renewables, Inc......................................  EDF Renewables.
Edison Electric Institute................................  EEI.
EIM Entities (Arizona Public Service Company, Avista       EIM Entities.
 Corporation, Idaho Power Company, NV Energy, Inc.,
 PacifiCorp, and Portland General Electric Company).
Electric Power Supply Association and Independent Energy   Competitive Suppliers.
 Producers Association.
Electricity Consumers Resource Council...................  ELCON.
Evergy Companies (Westar Energy, Inc., Kansas City Power   Evergy/Xcel.
 & Light Company, and KCP&L Greater Missouri Operations
 Company) and Xcel Energy Services Inc.
FirstEnergy Service Company..............................  FirstEnergy.
Indicated Generation Investors (Southwest Generation       Indicated Generation Investors.
 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).
Monitoring Analytics, LLC................................  PJM IMM.
Organization of PJM States, Inc..........................  OPSI.
Pacific Gas and Electric Company.........................  PG&E.
Powerex Corp.............................................  Powerex.

[[Page 36387]]

 
Public Citizen...........................................  Public Citizen.
Southern California Edison Company.......................  SoCal Edison.
Transmission Access Policy Study Group...................  TAPS.
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2019-15716 Filed 7-25-19; 8:45 am]
BILLING CODE 6717-01-P