Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System Operator Markets, 36374-36387 [2019-15716]
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Federal Register / Vol. 84, No. 144 / Friday, July 26, 2019 / Rules and Regulations
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.
Federal Energy Regulatory
Commission.
ACTION: Final rule.
AGENCY:
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.
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I. Introduction ...............................................................................................................................................................................
II. Background ...............................................................................................................................................................................
III. Discussion ...............................................................................................................................................................................
A. Assurance of Just and Reasonable Rates .........................................................................................................................
1. Availability of Data Necessary for Effective Review of Seller Market Power ........................................................
2. No Sub-delegation of Statutory Responsibility ........................................................................................................
B. Retention of Screens for Capacity Sellers in CAISO and SPP .......................................................................................
1. CAISO .........................................................................................................................................................................
2. SPP ..............................................................................................................................................................................
C. Clarifications for Capacity Sellers in CAISO and SPP ...................................................................................................
D. Retention of Screens for EIM ...........................................................................................................................................
1. Comments ...................................................................................................................................................................
2. Commission Determination .......................................................................................................................................
E. Bilateral Sales ....................................................................................................................................................................
1. Comments ...................................................................................................................................................................
2. Commission Determination .......................................................................................................................................
F. Current Status and Effectiveness of RTO/ISO Monitoring and Mitigation ...................................................................
1. Comments ...................................................................................................................................................................
2. Commission Determination .......................................................................................................................................
G. Other Issues Raised By Commenters ...............................................................................................................................
1. Change in Status and Triennial Updates ..................................................................................................................
2. Rights of Market Monitors .........................................................................................................................................
3. Corporate Character Reporting ..................................................................................................................................
4. Data Collection NOPR and Market Power NOI ........................................................................................................
IV. Information Collection Statement ..........................................................................................................................................
V. Environmental Analysis ..........................................................................................................................................................
VI. Regulatory Flexibility Act ......................................................................................................................................................
VII. Document Availability ..........................................................................................................................................................
VIII. Effective Date and Congressional Notification ...................................................................................................................
I. Introduction
proposed rulemaking (NOPR) 1
1. On December 20, 2018, the Federal
Energy Regulatory Commission
(Commission) issued a notice of
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proposing to modify § 35.37(c) of its
regulations regarding the horizontal
market power analysis for market-based
System Operator Markets, 165 FERC ¶ 61,268 (2018)
(NOPR).
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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 Commissionapproved 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
2. The Commission also proposed to
eliminate the rebuttable presumption
that Commission-approved RTO/ISO
market monitoring and mitigation is
sufficient to address any horizontal
market power concerns regarding sales
of capacity in RTOs/ISOs that do not
have an RTO/ISO-administered capacity
market.
3. The Commission received 18
comments in response to the NOPR.5 A
list of commenters and the abbreviated
names used in this final rule is attached
as Appendix A.
4. In this final rule, we adopt the
proposal from the NOPR and provide
clarification, as discussed below.
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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
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 Commissionapproved RTO/ISO capacity markets that include
Commission-approved market monitoring and
mitigation.
5 Although the Commission did not request reply
comments, several commenters nonetheless
submitted reply comments. The Commission rejects
such reply comments.
6 Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
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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.
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
7. On July 19, 2014, in a NOPR that
culminated in the issuance of Order No.
816,12 the Commission proposed certain
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).
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.
12 Refinements to Policies and Procedures for
Market-Based Rates for Wholesale Sales of Electric
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changes and clarifications in order to
streamline and improve the marketbased 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
8. When the Commission issued
Order No. 816, it stated that it was not
prepared at that time to adopt the
proposal regarding RTO/ISO sellers, but
that it would further consider the issues
raised by commenters and transferred
the record on that issue to Docket No.
AD16–8–000 for possible consideration
in the future as the Commission may
deem appropriate.17 The Commission
reviewed and considered that record in
preparing the NOPR proposal.
III. Discussion
A. Assurance of Just and Reasonable
Rates
9. In proposing to relieve RTO/ISO
sellers of the requirement to submit
indicative screens to the Commission in
markets with RTO/ISO-administered
energy, ancillary services, and capacity
markets subject to Commissionapproved monitoring and mitigation,
the Commission emphasized that it
would continue to ensure that marketbased rates are just and reasonable.18
However, commenters raise concerns
that the proposal compromises the
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.
17 Order No. 816, 153 FERC ¶ 61,065 at P 27.
18 NOPR, 165 FERC ¶ 61,268 at PP 61–70.
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Commission’s ability to ensure just and
reasonable rates because, they argue, it
eliminates data necessary for detecting
the presence of market power, and it
results in an improper sub-delegation of
the Commission’s statutory
responsibility to the RTO/ISO.19 We
have carefully considered these
arguments, but disagree for the reasons
discussed below. Accordingly, we adopt
the changes to § 35.37(c) of the
Commission’s regulations, as proposed
in the NOPR.
1. Availability of Data Necessary for
Effective Review of Seller Market Power
a. Comments
10. Opponents of the NOPR raise
concerns that the proposal would
deprive the Commission and
intervenors/complainants of data that is
necessary for assessing market power.
They add that the proposal is contrary
to the Commission’s statement in Order
No. 697–A that, even where RTO/ISO
monitoring and mitigation is in place,
the indicative screens provide ‘‘critical
information regarding the potential
market power of Sellers in the
market.’’ 20
11. TAPS and AAI/APPA/NRECA
both state that the courts have relied on
ex ante market power screening in
upholding the Commission’s use of
market-based rates, and both argue that
the indicative screens play an essential
role in the Commission’s ex ante market
power analysis, which ‘‘consists of a
finding that the applicant lacks market
power (or has taken sufficient steps to
mitigate market power).’’ 21 TAPS
argues that the ‘‘rigorous screening
process to detect market power’’ and
collection of seller-specific data were
critical to the court’s upholding of the
Commission’s market-based rate
program in Order No. 697.22 Similarly,
AAI/APPA/NRECA argue that courts
have specifically relied on the existence
of seller-specific, ex ante market power
screening in upholding the
Commission’s use of market-based
rates.23
12. TAPS and AAI/APPA/NRECA
argue that the efficacy of the other
existing market-based rate requirements
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19 TAPS
at 20–21; AAI/APPA/NRECA at 29.
20 AAI/APPA/NRECA at 15 (citing Order No.
697–A, 123 FERC ¶ 61,055 at P 109); TAPS at 7
(citing same).
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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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
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
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
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
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24 TAPS
at 13.
25 AAI/APPA/NRECA
at 17.
at 26.
27 TAPS at 22.
28 Id. at 8.
29 16 U.S.C. 824d.
30 Public Citizen at 3.
31 AAI/APPA/NRECA at 16.
26 Id.
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not obligated to collect and report
individual entity market shares and
market concentration data.
16. TAPS asserts that the lack of
indicative screen information will
hinder the ability of affected parties and
the Commission to meet the evidentiary
burden required to challenge marketbased 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 marketbased 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 marketbased rate authority would be required
to demonstrate, as a threshold matter,
that the Seller has market power.33
b. Commission Determination
17. At the outset, we note that the
Commission’s prior decision in Order
No. 697–A to retain the indicative
screens for Sellers in RTO/ISO markets
is not controlling here. The Commission
may evaluate the continuing
reasonableness of a prior policy or
determination and subsequently reach a
different conclusion.34 We reach a
different conclusion here in part based
on our finding that the proposal does
not eliminate data necessary for the
effective review of a Seller’s market
power.
18. We also disagree with TAPS and
AAI/APPA/NRECA’s assertion that the
courts, in upholding the Commission’s
ability to approve market-based rates,
have found that indicative screens play
an essential role in the Commission’s ex
ante analysis. While the courts have
found that an ex ante finding of the
absence of market power, coupled with
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
32 TAPS
at 13.
33 AAI/APPA/NRECA
at 28.
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).
34 New
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it.35 The use of indicative screens is not
the only permissible approach the
Commission may employ to assess
market power before authorizing
market-based rates, nor are indicative
screens essential to the Commission’s
determination of whether market power
is mitigated.
19. Contrary to AAI/APPA/NRECA’s
assertion, the Commission is not
‘‘distancing itself’’ from oversight of
competitive issues arising in wholesale
markets. Sellers continue to be required
to submit notices of change in status
and market power analyses, which
include a demonstration regarding
vertical market power, affiliate
information, and an asset appendix.
Additionally, Sellers continue to be
required to submit Electric Quarterly
Reports (EQR). EQR reporting is a vital
tool for determining whether Sellers
may be exercising market power
because it shows the volumes and prices
at which Sellers are transacting; as such,
it can be used to determine a Seller’s
market share of sales and relative prices.
20. We are not aware of an instance
to date where an intervenor or
complainant has used indicative screen
data as part of a challenge to the market
power of an RTO/ISO seller.
Nevertheless, even without the screen
data, the information that continues to
be required under § 35.37 is useful to
those seeking to challenge a Seller’s
market-based rate authority. We
disagree with TAPS’s suggestion that
this information is of limited value
without the indicative screens. The
asset appendices also provide detailed
information on a Seller’s generation
portfolio, including affiliated generation
and long-term power purchase
agreements. Through the triennial
update process,36 a potential intervenor
can review contemporaneous
information on a Seller’s generation
portfolio and can aggregate this
information to get an indication of an
individual Seller’s size relevant to the
market. Moreover, data on total market
size is available from other public
sources such as reports from the U.S.
Energy Information Administration.
35 See Lockyer, 383 F.3d at 1013; Blumenthal, 552
F.3d at 882; Mont. Consumer Counsel, 659 F.3d at
916.
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.
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 [marketbased rate] authority is granted, [the
Commission] is unlikely to take it
away,’’ the standard for obtaining and
retaining market-based rate authority is
the same. The Commission can and does
institute FPA section 206 proceedings
when potential market power concerns
arise.40
23. In addition, the Commission
conducts independent, ex post analyses
using public and non-public data to
assess market behavior in RTO/ISO
markets. The Commission can examine
transaction level data (e.g., resource
supply offers) using data provided
pursuant to Order No. 760 to conduct
such oversight.41
24. Regarding concerns that the
market monitors’ reports are not
‘‘uniform,’’ we note that the RTOs/ISOs
themselves are not uniform and that a
‘‘one size fits all’’ report format is
Citizen at 3.
U.S.C. 824e.
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).
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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38 16
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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 marketbased 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
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
42 Order
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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
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
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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 Commissionapproved 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
43 Public
Citizen at 4–5 (also noting that the
market monitors do not have corporate control
protections to safeguard the public interest).
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)).
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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.
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,
46 ISO New England Inc., 166 FERC ¶ 61,060, at
P 8 (2019).
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).
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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
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 marketbased sales of capacity in CAISO if it
demonstrates that the sale of capacity
results from a competitive solicitation
that meets the guidelines articulated in
Order No. 784 (transparency, definition,
evaluation, oversight, and
competitiveness).
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
48 Calpine
at 7.
49 Competitive
Suppliers at 6.
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).
51 SoCal Edison at 4.
52 Id. at 5.
50 Third-Party
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indicative screens for capacity sales in
CAISO, it recommends a technical
conference to consider how CAISO’s
market monitoring and mitigation of
capacity sales can be modified such that
the requirement to submit indicative
screens can be eliminated prior to the
submission of the next triennial for the
Southwest region due in December
2021, or how the indicative screens can
be modified to reflect the Resource
Adequacy reserve margin obligations
and capacity procurement in CAISO.53
36. Other commenters support the
proposal to retain the requirement that
Sellers submit indicative screens for
capacity sales in CAISO.54 CAISO DMM
‘‘strongly 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
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
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
53 Id.
at 7.
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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.
57 TAPS at 19–20.
58 Id.
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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
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 caseby-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
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.
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).
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36379
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.
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 Commissionapproved market monitoring and
mitigation.
2. SPP
a. Comments
43. Certain commenters request
extending the proposal to grant relief
from submitting the indicative screens
to capacity sellers in the SPP market.63
44. Evergy/Xcel assert that SPP’s lack
of an RTO-administered capacity market
does not mean that capacity sellers in
SPP can exercise market power. Evergy/
Xcel state that other safeguards exist in
SPP, such as transparent energy pricing,
comprehensive 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
45. Evergy/Xcel state that the
Commission rejected proposed
62 SoCal
Edison at 7.
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.
64 Evergy/Xcel at 8.
65 Id. at 9–10.
63 Evergy/Xcel
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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 verticallyintegrated utilities with a small number
of independent generators.’’ According
to Evergy/Xcel, while ‘‘‘most’ capacity is
transacted bilaterally or self-supplied in
MISO, all capacity in SPP is transacted
bilaterally or self-supplied. Thus ‘most’
capacity transactions in MISO are not
subject to direct monitoring or
mitigation, just as in SPP.’’ 66
b. Commission Determination
46. We adopt the NOPR proposals to
require capacity sellers in SPP to
continue to submit indicative screens
and to eliminate the rebuttable
presumption that Commission-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 mustoffer 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 Commissionapproved rules for capacity in SPP
comparable to the market price for
capacity established by RTOs/ISOs with
centralized capacity markets.
48. We acknowledge that SPP is
similar to MISO in that it mostly
consists of vertically-integrated utilities
with a small number of independent
generators. However, MISO conducts
annual capacity auctions subject to
Commission-approved monitoring and
mitigation, thereby disciplining the
price of bilateral capacity sales and
providing capacity buyers with
protections that are not available in SPP.
The SPP market lacks a transparent
market price for capacity and SPP does
not review or mitigate capacity prices.
C. Clarifications for Capacity Sellers in
CAISO and SPP
a. Comments
49. Calpine asks that the Commission
make the following clarification in
Paragraph 51 of the NOPR ‘‘that, in the
event of indicative screen failures, the
CAISO (or SPP) Seller’s evidentiary
burden is limited to demonstrating that
it lacks market power in capacity
markets, or to propose satisfactory
mitigation for capacity sales, but that
the CAISO (or SPP) Seller may still rely
on a rebuttable presumption that it lacks
market power in energy and ancillary
services markets as a result of
Commission-approved market
monitoring and mitigation provisions in
the CAISO (or SPP) Tariff.’’ 68
50. Powerex states that the NOPR
introduces an ambiguity about which
markets a Seller would be required to
evaluate for purposes of making
capacity sales. Specifically, Paragraph
49 of the NOPR states that the
Commission proposes ‘‘to require any
Seller seeking to sell capacity at the
market-based rates in CAISO or SPP,
either as a bundled or unbundled
product or on a short-term or long-term
basis, to submit the indicative
screens.’’ 69 Powerex asserts that ‘‘[r]ead
literally, the foregoing statement would
require all [market-based rate] sellers
wishing to sell capacity in CAISO or
SPP to study these markets as a relevant
market and to submit the indicative
screens, even though many [marketbased 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 overbroad.’’ 70
b. Commission Determination
51. We agree with Calpine that the
addition of ‘‘capacity’’ appropriately
clarifies Paragraph 51 of the NOPR.
Therefore, we clarify that in the event of
indicative screen failures, the CAISO (or
SPP) Seller’s evidentiary burden is
66 Id.
at 11–12.
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.
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68 Calpine
at 9 (emphasis in original).
165 FERC ¶ 61,268 at P 49.
70 Powerex at 5.
69 NOPR,
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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 realtime energy market and is subject to
Commission-approved market
monitoring and mitigation, indicative
screens should not be required for
purposes of obtaining or retaining
market-based rate authority in the
EIM.72
54. EIM Entities state that the EIM has
become an increasingly liquid market
that offers competitive supply from a
significant number of participants. They
argue that the EIM is structurally
competitive, asserting that ‘‘[t]he DMM
has presented analysis and the
Commission has affirmed in multiple
EIM orders that the EIM is structurally
competitive due to absence of pivotal
suppliers and low frequency of price
separation,’’ and in those intervals
where potential structural market power
could exist, it would be mitigated by
CAISO’s real-time bid mitigation
procedures.73 EIM Entities also argue
that the requirement to perform
71 EIM Entities at 1; CAISO DMM at 8; see also
EEI at 2 (requesting extension of relief to Sellers in
the EIM).
72 EIM Entities at 7.
73 Id. at 7–8.
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indicative screens, as well as congestion
and price separation analysis, on fiveminute 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 undermitigation.75
55. CAISO DMM states that, unlike
the local market power mitigation
procedures applied within the CAISO,
the automated market power mitigation
procedures applied to each EIM
balancing authority area provide
effective market power mitigation on a
system-wide level across each
individual EIM balancing area.76
Therefore, CAISO DMM believes that
the EIM should be treated as an energy
market that is subject to Commissionapproved market monitoring and
mitigation.
2. Commission Determination
56. We will not extend the relief
proposed in the NOPR to Sellers in the
EIM at this time. While the Commission
has accepted the use of CAISO’s realtime 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.
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
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74 Id.
at 10.
at 12–13.
76 CAISO DMM at 8–9.
77 See Cal. Indep. Sys. Operator Corp., 147 FERC
¶ 61,231, order on reh’g, clarification, and
compliance, 149 FERC ¶ 61,058 (2014).
78 APPA/AAI/NRECA at 23; TAPS at 19.
79 AAI/APPA/NRECA at 24.
80 Id. at 25.
RTO/ISO-run capacity auctions are not
a substitute for self-supply arrangements
and long-term bilateral capacity
purchases needed by a load-serving
entity seeking to provide rate stability
for its retail customers.81
58. TAPS asserts that there is no basis
for assuming that voluntary RTO/ISO
capacity markets are substitutes for
bilateral transactions, especially for
load-serving entities that 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
2. Commission Determination
59. We find that Commissionapproved 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
75 Id.
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81 Id.
82 TAPS
at 15–16.
83 Id.
84 Id.
at 16.
85 Id.
86 Id.
87 Id.
NOPR, the Commission acknowledged
that purchases in short-term RTO/ISO
energy and capacity markets are not
necessarily perfect substitutes for longterm 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, bidbased 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
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 longterm bilateral contracts.89
61. We also note that the Commission
has consistently found that long-term
markets for energy and capacity are
competitive in the absence of barriers to
entry.90 TAPS does not provide any
88 Order
No. 697–A, 123 FERC ¶ 61,055 at P 285.
periodically calculate the cost of
new entry or ‘‘CONE’’ to provide a benchmark price
for new capacity. CONE is a measure of the revenue
needed to recover the cost of a new generating unit,
typically a gas-fired combustion turbine or
combined cycle unit, net of energy revenues. While
this is an administratively determined cost, it
provides another useful benchmark that buyers can
use to assess prices offered in the long-term
bilateral market.
90 Order No. 697, 119 FERC ¶ 61,295 at P 114; see
also Order No. 697–A, 123 FERC ¶ 61,055 at P 279;
Promoting Wholesale Competition Through Open
Access 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) (crossreferenced 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
89 RTOs/ISOs
at 18 (citing Lockyer, 383 F.3d at 1013).
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evidence that RTO/ISO markets suffer
from barriers to entry.
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 postapproval 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.
F. Current Status and Effectiveness of
RTO/ISO Monitoring and Mitigation
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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
(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).
91 See Lockyer, 383 F.3d at 1014.
92 Id.
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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
64. In contrast, Competitive Suppliers
urge the Commission to avoid holding
market power mitigation to an
‘‘unreasonable standard,’’ noting that
existing market power mitigation
protocols are better suited to prevent the
exercise of market power than static
indicative screens and that market
power mitigation protocols will
necessarily evolve with experience and
changes in market fundamentals.
Competitive Suppliers argue that the
Commission should not delay
implementing its proposal to relieve
Sellers of the burden to file indicative
screens while it waits for the mitigation
protocols to cross the ‘‘elusive finish
line represented by the standard that
market power mitigation is
‘complete.’ ’’ 97
2. Commission Determination
65. We disagree with ELCON that it is
necessary to initiate a formal review of
the effectiveness of RTO/ISO monitoring
and mitigation practices concurrent
with this final rule. The Commission
has previously accepted each RTO/ISO’s
market monitoring and 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
PO 00000
93 ELCON
94 Id.
at 3.
at 10.
95 Id.
96 Id.
97 Competitive
98 NOPR,
Suppliers at 3–4.
165 FERC ¶ 61,269 at P 28.
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contrast, RTO/ISO mitigation uses
interval-specific market and operational
data to identify, in real-time, binding
transmission constraints that create
conditions that could result in the
emergence of local market power.
Removing the indicative screens does
not affect the RTOs/ISOs’ application of
the market power monitoring and
mitigation provisions in their markets.
66. Moreover, nothing in this final
rule precludes an RTO/ISO from filing
to amend the existing market power
mitigation provisions if improvement is
needed. Indeed, in recent years,
improvements have been made to
market monitoring and mitigation
protocols in all RTO/ISO markets.99 The
Commission will continue to scrutinize
RTO/ISO market monitoring and
mitigation provisions and take
necessary action, as appropriate, should
any issues arise.
G. Other Issues Raised By Commenters
1. Change in Status and Triennial
Updates
a. Comments
67. EEI requests that the Commission
eliminate the requirement for change in
status reporting and reconsider the
continued need for the triennial market
power update for all Sellers relying on
Commission-approved market
monitoring and mitigation.100 EEI asks
the Commission to clarify the
characteristics it relies upon in granting
market-based rate authority. To the
extent information is not relied upon by
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-ofmarket and to resources that self-schedule in realtime); Sw. Power Pool, Inc., 165 FERC ¶ 61,242
(2018) (streamlining the process by which
Frequently Constrained Areas are designated); N.Y.
Indep. Sys. Operator, Inc., Docket No. ER18–1168–
000 (May 14, 2018) (delegated order) (revising the
market power mitigation provisions to address
cases where Sellers submit inaccurate fuel type or
fuel price information in fuel cost adjustments).
100 EEI at 8–9.
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the Commission in its initial grant of
market-based rate authorization, EEI
contends that it also is not relevant to
changes in status and Sellers should not
be required to submit it.101
68. EEI points to how the Commission
currently requires that change in status
reporting and triennial market power
updates include information on any
new affiliations with entities that own,
operate, or control transmission
facilities. EEI argues that ‘‘[s]o 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 Commissionapproved market monitoring and
mitigation, thereby addressing any
market power concerns.’’ 103
69. Similarly, SoCal Edison argues
that RTO/ISO sellers who are exempt
from submitting screens under the
proposal should also be relieved of the
requirement to file a change in status for
any net increases of generation in their
portfolios. In SoCal Edison’s view, an
increase in generation would not affect
the characteristics the Commission
relied upon in granting the Seller
market-based rate authority because,
under the proposal, the Commission is
no longer relying on any particular
amount of generating capacity when
granting market-based rate authority.104
70. Contrary to these comments, AAI/
APPA/NRECA urge the Commission to
gather more information from Sellers
and advocate for removing the current
stay of the requirement in 18 CFR
35.37(a)(2) that Sellers submit an
organizational chart. AAI/APPA/NRECA
contend that the organizational chart
requirement should be reinstituted
regardless of whether the Commission
adopts the NOPR, but particularly if the
Commission eliminates the indicative
screen requirement based in part on
‘‘the availability of other data regarding
horizontal market power.’’ 105
b. Commission Determination
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71. We reject, as beyond the scope of
this proceeding, EEI’s and SoCal
101 Id.
at 9.
at 10–11.
103 Id. at 11.
104 SoCal Edison at 9–10.
105 AAI/APPA/NRECA at 18 (citing NOPR, 165
FERC ¶ 61,268 at P 27).
102 Id.
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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
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.
2. Rights of Market Monitors
3. Corporate Character Reporting
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-based
rates.108
74. PJM IMM also asserts that
adequate market power monitoring and
mitigation ‘‘requires that market
monitors have equal standing with the
RTO and its membership to file tariff
revisions to the market monitoring and
mitigation sections of the tariff.’’ 109 PJM
IMM suggests that the Commission
could achieve equal standing by
requiring that all filings to change
monitoring and mitigation fall under
FPA section 206, as opposed to the
current practice of allowing RTOs/ISOs
to file changes under FPA section 205.
PJM IMM states that the FPA section
206 approach ‘‘would allow the
Commission to choose the most
effective monitoring and mitigation
practices, ensuring that markets remain
competitive and ensuring that market
based rates are justified.’’ 110
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
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).
107 OPSI at 4–5.
108 PJM IMM at 7.
109 Id. at 6.
110 Id.
PO 00000
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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
111 Public
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Federal Register / Vol. 84, No. 144 / Friday, July 26, 2019 / Rules and Regulations
information requirements and analyses
are sufficient.112
b. Commission Determination
80. We are not persuaded by, and
therefore reject AAI/APPA/NRECA’s
assertion that the Commission should
first act on the Data Collection NOPR
and Market Power NOI proceedings
before acting on the instant NOPR. We
see no reason why the Commission
must first act in those proceedings
before taking action to remove the
screen requirement as proposed in the
NOPR. Any actions taken in the Data
Collection NOPR and Market Power NOI
will not impact the implementation of
the removal of the screen requirement.
As noted above, the Commission will
continue to monitor RTO/ISO mitigation
provisions on an ongoing basis and take
necessary action, as appropriate. In
addition, we note that a final rule in
Docket No. RM16–17–000 is being
issued concurrently with this final
rule.113
IV. Information Collection Statement
81. The Paperwork Reduction Act
(PRA) 114 requires each federal agency to
seek and obtain Office of Management
and Budget (OMB) approval before
undertaking a collection of information
directed to ten or more persons or
contained in a rule of general
applicability. OMB’s 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.
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
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/ISOadministered energy, ancillary services,
and capacity markets subject to
Commission-approved RTO/ISO
monitoring and mitigation. In any RTO/
ISO market that does not have an RTO/
ISO-administered capacity market
subject to Commission-approved RTO/
ISO monitoring and mitigation, Sellers
would continue to be required to submit
indicative screens for authorization to
make capacity sales. Eliminating the
requirement to file indicative screens in
certain markets will reduce the burden
of filing a horizontal market power
analysis for a large portion of Sellers
when filing triennial updated market
power analyses, initial applications for
market-based rate authority, and notices
of change in status.
85. Burden Estimate: The estimated
burden and cost for the requirements are
as follows.
BURDEN REDUCTIONS IN FINAL RULE, RM19–2–000 120
Requirement
Number of
respondents
Annual
number of
responses per
respondent
Total number
of responses
Average burden & cost
per response
Total annual burden
hours & cost
Annual cost
per
respondent
($)
(1)
(2)
(1) * (2) = (3)
(4)
(3) * (4) = (5)
(5) ÷ (1)
Market Power Analysis in New Applications for Market-based Rates
for RTO/ISO Sellers.
Triennial Market Power Analysis
Updates for RTO/ISO Sellers.
72
1
72
¥230 hrs. ¥$21,620 .........
¥16,560 hrs. ¥$1,556,640
¥$21,620
33
1
33
¥230 hrs. ¥$21,620 .........
¥7,590 hrs. ¥$713,460 ....
¥$21,620
Total .........................................
........................
........................
105
.............................................
¥24,150 hrs. ¥$2,270,100
86. After implementation of the
proposed changes, the total estimated
annual reduction in cost burden to
112 AAI/APPA/NRECA
Comments at 30.
No. 860, 168 FERC ¶ 61,039.
114 44 U.S.C. 3507(d).
115 5 CFR 1320.
116 See 5 CFR 1320.12.
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.
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113 Order
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respondents is $2,270,100 [24,150 hours
* $94 = $2,270,100].121
Title: FERC–919, Market Based Rates
for Wholesale Sales of Electric Energy,
U.S.C. 3507(d).
CFR 35.37.
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
PO 00000
118 44
119 18
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Capacity and Ancillary Services by
Public Utilities.
Action: Revision of Currently
Approved Collection of Information.
Statistics for the Utilities sector (available at https://
www.bls.gov/oes/current/naics2_22.htm) and
updated March 2019 for benefits information (at
https://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.
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Federal Register / Vol. 84, No. 144 / Friday, July 26, 2019 / Rules and Regulations
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
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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.
VI. Regulatory Flexibility Act
90. The Regulatory Flexibility Act of
1980 (RFA) 126 generally requires a
description and analysis of final rules
that will have significant economic
impact on a substantial number of small
entities. The RFA mandates
consideration of regulatory alternatives
that accomplish the stated objectives of
a final rule and minimize any
significant economic impact on a
substantial number of small entities. In
lieu of preparing a regulatory flexibility
analysis, an agency may certify that a
final rule will not have a significant
economic impact on a substantial
number of small entities.
91. The Small Business
Administration’s (SBA) Office of Size
Standards develops the numerical
122 Regulations Implementing the National
Environmental Policy Act of 1969, Order No. 486,
FERC Stats. & Regs., ¶ 30,783 (1987) (crossreferenced 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).
126 5 U.S.C. 601–612.
PO 00000
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36385
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
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 marketbased 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
127 13
CFR 121.101.
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).
131 Order No. 697, 119 FERC ¶ 61,295 at PP 1126–
1129.
128 Id.
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Federal Register / Vol. 84, No. 144 / Friday, July 26, 2019 / Rules and Regulations
submitting their horizontal market
power analysis.
95. The final rule will relieve Sellers
in certain RTO/ISO markets of the
requirement to submit indicative
screens and will reduce the burden on
those Sellers, including small entities.
The changes to the Commission’s
regulations are estimated to cause a
reduction of 41 percent in total annual
burden to Sellers when filing triennial
market power analyses and market
power analyses in new applications for
market-based rates, including small
entities.
96. Accordingly, pursuant to section
605(b) of the RFA, the Commission
certifies that this final rule will not have
a significant economic impact on a
substantial number of small entities.
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 (https://
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.
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
1. The authority citation for part 35
continues to read as follows:
■
Authority: 16 U.S.C. 791a–825r, 2601–
2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.
§ 35.37
■
a. Redesignate paragraph (c)(5) as
(c)(7); and
■ b. Add new paragraph (c)(5) and
paragraph (c)(6).
The additions read as follows:
■
§ 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/ISOadministered 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
[Amended]
2. Amend § 35.37 as follows:
List of Commenters and Acronyms
jbell on DSK3GLQ082PROD with RULES2
Commenter
Short name/acronym
American Antitrust Institute, American Public Power Association, and National Rural Electric Cooperative Association.
California Independent System Operator—Department of Market Monitoring ..........................................................
Calpine Corporation ...................................................................................................................................................
EDF Renewables, Inc ................................................................................................................................................
Edison Electric Institute ..............................................................................................................................................
EIM Entities (Arizona Public Service Company, Avista Corporation, Idaho Power Company, NV Energy, Inc.,
PacifiCorp, and Portland General Electric Company).
Electric Power Supply Association and Independent Energy Producers Association ..............................................
Electricity Consumers Resource Council ...................................................................................................................
Evergy Companies (Westar Energy, Inc., Kansas City Power & Light Company, and KCP&L Greater Missouri
Operations Company) and Xcel Energy Services Inc.
FirstEnergy Service Company ...................................................................................................................................
Indicated Generation Investors (Southwest Generation Operating Company, LLC, Ares EIF Management, LLC,
Northern Star Generation Services Company LLC, Astoria Energy LLC and Astoria Energy II LLC, and Coronal Management, LLC).
Monitoring Analytics, LLC ..........................................................................................................................................
Organization of PJM States, Inc ................................................................................................................................
Pacific Gas and Electric Company ............................................................................................................................
Powerex Corp ............................................................................................................................................................
132 5
U.S.C. 804(2).
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AAI/APPA/NRECA.
CAISO DMM.
Calpine.
EDF Renewables.
EEI.
EIM Entities.
Competitive Suppliers.
ELCON.
Evergy/Xcel.
FirstEnergy.
Indicated Generation Investors.
PJM IMM.
OPSI.
PG&E.
Powerex.
Federal Register / Vol. 84, No. 144 / Friday, July 26, 2019 / Rules and Regulations
Commenter
Short name/acronym
Public Citizen .............................................................................................................................................................
Southern California Edison Company ........................................................................................................................
Transmission Access Policy Study Group .................................................................................................................
[FR Doc. 2019–15716 Filed 7–25–19; 8:45 am]
jbell on DSK3GLQ082PROD with RULES2
BILLING CODE 6717–01–P
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Public Citizen.
SoCal Edison.
TAPS.
]]>Agencies
[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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\35\ See Lockyer, 383 F.3d at 1013; Blumenthal, 552 F.3d at 882;
Mont. Consumer Counsel, 659 F.3d at 916.
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\43\ Public Citizen at 4-5 (also noting that the market monitors
do not have corporate control protections to safeguard the public
interest).
---------------------------------------------------------------------------
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.
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\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.
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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\
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\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\
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\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.
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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
https://www.bls.gov/oes/current/naics2_22.htm) and updated March 2019
for benefits information (at https://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.
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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: [email protected],
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:
[email protected]. 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.
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\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).
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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.
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\126\ 5 U.S.C. 601-612.
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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\
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\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).
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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.
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\131\ Order No. 697, 119 FERC ] 61,295 at PP 1126-1129.
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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 (https://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
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
[email protected].
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.
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\132\ 5 U.S.C. 804(2).
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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.
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[FR Doc. 2019-15716 Filed 7-25-19; 8:45 am]
BILLING CODE 6717-01-P
