[Federal Register Volume 80, Number 210 (Friday, October 30, 2015)]
[Rules and Regulations]
[Pages 67055-67123]
[FR Doc No: 2015-26908]

Vol. 80

Friday,

No. 210

October 30, 2015

Part IV

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Refinements to Policies and Procedures for Market-Based Rates for
Wholesale Sales of Electric Energy, Capacity and Ancillary Services by
Public Utilities; Final Rule

Federal Register / Vol. 80 , No. 210 / Friday, October 30, 2015 /
Rules and Regulations

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM14-14-000; Order No. 816]

Refinements to Policies and Procedures for Market-Based Rates for
Wholesale Sales of Electric Energy, Capacity and Ancillary Services by
Public Utilities

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
amending its regulations that govern market-based rate authorizations
for wholesale sales of electric energy, capacity, and ancillary
services by public utilities pursuant to the Federal Power Act. This
order represents another step in the Commission's efforts to modify,
clarify and streamline certain aspects of its market-based rate
program. The Commission is eliminating or refining certain existing
filing requirements for market-based rate sellers as well as providing
clarification regarding several issues. The specific components of this
rule, in conjunction with other regulatory activities, are designed to
ensure that the market-based rates charged by public utilities are just
and reasonable.

DATES: Effective Date: This rule will become effective January 28,
2016.

FOR FURTHER INFORMATION CONTACT:

Greg Basheda (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426,<PHONE_NUMBER>.

Carol Johnson (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

Order No. 816

Final Rule

Table of Contents

                                                         Paragraph Nos.

I. Introduction......................................                  1
II. Background.......................................                  4
III. Overview of Final Rule..........................                 12
IV. Discussion.......................................                 24
    A. Horizontal Market Power.......................                 24
        1. Sellers in RTOs/ISOs......................                 24
        2. Sellers With Fully Committed Long-Term                     29
         Generation Capacity.........................
        3. Relevant Geographic Market for Certain                     45
         Sellers in Generation-Only Balancing
         Authority Areas.............................
        4. Reporting Format for the Indicative                        72
         Screens and SIL Submittals 1 and 2..........
        5. Competing Imports.........................                 84
        6. Capacity Ratings..........................                 87
        7. Reporting of Long-Term Firm Purchases.....                108
        8. Clarification of Commission Language in                   146
         Performing SIL Studies......................
    B. Vertical Market Power--Land Acquisition                       200
     Reporting.......................................
        1. Commission Proposal.......................                200
        2. Comments..................................                202
        3. Commission Determination..................                207
    C. Notices of Change in Status...................                213
        1. Geographic Focus..........................                213
        2. New Affiliation and Behind-the-Meter                      241
         Generation..................................
        3. Reporting of Long-Term Firm Purchases.....                256
    D. Asset Appendix................................                259
        1. Changes to the Existing Columns...........                260
        2. Reporting Power Purchase Agreements.......                268
        3. Clarifications Regarding the Existing                     272
         Columns.....................................
        4. Changes Regarding OATT Waiver and                         295
         Citations in Transmission Asset List........
        5. Electronic Format.........................                301
        6. Database..................................                308
    E. Category 1 and Category 2 Sellers.............                314
        1. Commission Proposal.......................                314
        2. Comments..................................                319
        3. Commission Determination..................                320
    F. Corporate Families............................                323
        1. Corporate Organizational Charts...........                323
        2. Single Corporate Tariff...................                336
    G. Part 101 and 141 Waivers......................                339
        1. Commission Proposal.......................                339
        2. Comments..................................                342
        3. Commission Determination..................                345
    H. Miscellaneous Issues..........................                351
        1. Regional Reporting Schedule...............                351
        2. Affirmative Statement.....................                354
        3. Comments of Barrick.......................                357
V. Section-by-Section Analysis of Regulations........                360
VI. Information Collection Statement.................                370
VII. Environmental Analysis..........................                380
VIII. Regulatory Flexibility Act.....................                381
IX. Document Availability............................                384
X. Effective Date and Congressional Notification.....                387
Appendix C to the Final Rule: Regional Reporting
 Schedule
Appendix D to the Final Rule: Generalized Map of
 Geographic Regions
Appendix E to the Final Rule: Summary Tables for SIL
 Calculation
Appendix F to the Final Rule: List of Commenters and
 Acronyms

Order No. 816

Final Rule

(Issued October 16, 2015)

I. Introduction

    1. On June 19, 2014, the Commission issued a Notice of Proposed
Rulemaking (NOPR), pursuant to sections 205 and 206 of the Federal
Power Act (FPA),\1\ in which the Commission proposed to revise its
current standards for market-based rates for sales of electric energy,
capacity, and ancillary services.\2\ The Commission proposed to modify
and streamline certain aspects of the Commission's filing requirements
to reduce the administrative burden on market-based rate sellers \3\
and the Commission.
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    \1\ 16 U.S.C. 824d, 824e.
    \2\ Refinements to Policies and Procedures for Market-Based
Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary
Services by Public Utilities, FERC Stats. & Regs. ] 32,702 (2014)
(NOPR).
    \3\ The term ``seller'' as used in this Final Rule includes
sellers that have already been granted market-based rate authority
as well as applicants for market-based rate authority, unless
otherwise noted.
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    2. This Final Rule represents another step in the Commission's
efforts to modify, clarify and streamline certain aspects of its
market-based rate program. Some aspects of this Final Rule eliminate or
refine existing filing requirements, while other aspects of the Final
Rule require submission of additional information from market-based
rate sellers. For example, this Final Rule redefines the default
relevant geographic market for an independent power producer (IPP) with
generation capacity located in a generation-only balancing authority
and requires sellers to report all long-term firm purchases that have
an associated long-term firm transmission reservation in their
indicative screens and asset appendices. The Final Rule provides
clarification on issues including capacity ratings and preparation of
simultaneous transmission import limit (SIL) studies. Streamlining is
accomplished through, for example, elimination of the land acquisition
reporting requirement, reduction in the number of notice of change in
status filings due to establishment of a 100 megawatt (MW) threshold
for reporting new affiliations, and clarification that sellers need not
report behind-the-meter generation in the indicative screens and asset
appendices. The specific components of this rule, in conjunction with
other regulatory activities, are designed to ensure that the market-
based rates charged by public utilities are just and reasonable.
    3. Pursuant to sections 205 and 206 of the FPA, the Commission is
amending its regulations to revise subpart H to part 35 of title 18 of
the Code of Federal Regulations (CFR), which governs market-based rate
authorizations for wholesale sales of electric energy, capacity, and
ancillary services by public utilities.

II. Background

    4. In 1988, the Commission began considering proposals for market-
based pricing of wholesale power sales. The Commission acted on market-
based rate proposals filed by various wholesale suppliers on a case-by-
case basis. Over the years, the Commission developed a four-prong
analysis to assess whether a seller should be granted market-based rate
authority: (1) Whether the seller and its affiliates lack, or have
adequately mitigated, market power in generation; (2) whether the
seller and its affiliates lack, or have adequately mitigated, market
power in transmission; (3) whether the seller or its affiliates can
erect other barriers to entry; and (4) whether there is evidence
involving the seller or its affiliates that relates to affiliate abuse
or reciprocal dealing.
    5. In 2006, the Commission issued a notice of proposed rulemaking,
which led to the issuance in 2007 of Order No. 697, which clarified and
codified the Commission's market-based rate policy and generally
retained the four prong analyses.\4\ As to the first prong, the
Commission adopted two indicative screens for assessing horizontal
market power: The pivotal supplier screen and the wholesale market
share screen (with a 20 percent threshold). Each of these uses a
``snapshot in time'' approach based on historical data \5\ and serves
as a cross check on the other to determine whether sellers may have
horizontal market power and should be further examined.\6\ The
Commission stated that passage of both indicative screens establishes a
rebuttable presumption that the seller does not possess horizontal
market power. Sellers that fail either indicative screen are rebuttably
presumed to have market power and are given the opportunity to present
evidence such as a delivered price test (DPT) analysis or historical
sales and transmission data to demonstrate that, despite a screen
failure, they do not have market power.\7\ The Commission specified
that in traditional markets (outside regional transmission
organization/independent system operator (RTO/ISO) markets), the
default relevant geographic market for purposes of the indicative
screens is first, the balancing authority area(s) where the seller is
physically located, and second, the markets directly interconnected to
the seller's balancing authority area (first-tier balancing authority
areas).\8\ Generally, sellers that are located in and are members of
the RTO/ISO may consider the geographic region under the control of the
RTO/ISO as the default relevant geographic market for purposes of the
indicative screens.\9\
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    \4\ Market-Based Rates for Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by Public Utilities, Order No. 697,
FERC Stats. & Regs. ] 31,252, clarified, 121 FERC ] 61,260 (2007)
(Clarifying Order), order on reh'g, Order No. 697-A, FERC Stats. &
Regs. ] 31,268, clarified, 124 FERC ] 61,055, order on reh'g, Order
No. 697-B, FERC Stats. & Regs. ] 31,285 (2008), order on reh'g,
Order No. 697-C, FERC Stats. & Regs. ] 31,291 (2009), order on
reh'g, Order No. 697-D, FERC Stats. & Regs. ] 31,305 (2010), aff'd
sub nom. Mont. Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir.
2011), cert. denied, 133 S. Ct. 26 (2012).
    \5\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 17.
    \6\ Id. PP 62, 75.
    \7\ Id. P 13; 18 CFR 35.37(c)(3).
    \8\ The Commission also noted that ``[w]here a generator is
interconnecting to a non-affiliate owned or controlled transmission
system, there is only one relevant market (i.e., the balancing
authority area in which the generator is located).'' Order No. 697,
FERC Stats. & Regs. ] 31,252 at P 232 n.217.
    \9\ 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 market-based rate analysis. See Id. PP 15, 231.
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    6. With respect to the vertical market power analysis, in cases
where a public utility or any of its affiliates owns, operates, or
controls transmission facilities, the Commission requires that there be
a Commission-approved Open Access Transmission Tariff (OATT) on file,
or that the seller or its applicable affiliate has received waiver of
the OATT requirement, before granting a seller market-based rate
authorization.\10\ The Commission also considers a seller's ability to
erect other barriers to entry as part of the vertical market power
analysis.\11\ As such, the Commission requires a seller to provide a
description of its ownership or control of, or affiliation with an
entity that owns or controls, intrastate natural gas transportation,
storage or distribution facilities; sites for generation capacity
development; and physical coal supply sources and ownership of or
control over who may access transportation of coal supplies
(collectively, inputs to electric power production).\12\ In Order No.
697-C, the Commission revised the change in status reporting
requirement

in section 35.42 of the Commission's regulations to require a market-
based rate seller to report the acquisition of control of sites for new
generation capacity development on a quarterly basis instead of within
30 days of the acquisition.\13\ The Commission adopted a rebuttable
presumption that the ownership or control of, or affiliation with any
entity that owns or controls, inputs to electric power production does
not allow a seller to raise entry barriers but will allow intervenors
to demonstrate otherwise.\14\ Finally, as part of the vertical market
power analysis, the Commission also requires a seller to make an
affirmative statement that it has not erected barriers to entry into
the relevant market and will not erect barriers to entry into the
relevant market.\15\
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    \10\ Id. P 408.
    \11\ Id. P 440.
    \12\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 176.
    \13\ Order No. 697-C, FERC Stats. & Regs. ] 31,291 at P 18; 18
CFR 35.42(d).
    \14\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 446; 18
CFR 35.37(c).
    \15\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 447
(clarifying that the obligation in this regard applies to both the
seller and its affiliates but is limited to the geographic market(s)
in which the seller is located).
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    7. If a seller is granted market-based rate authority, the
authorization is conditioned on: (1) Compliance with affiliate
restrictions governing transactions and conduct between power sales
affiliates where one or more of those affiliates has captive customers;
\16\ (2) a requirement to file post-transaction electric quarterly
reports (EQR) with the Commission containing: (a) A summary of the
contractual terms and conditions in every effective service agreement
for market-based power sales; and (b) transaction information for
effective short-term (less than one year) and long-term (one year or
longer) market-based power sales during the most recent calendar
quarter; \17\ (3) a requirement to file any change in status that would
reflect a departure from the characteristics the Commission relied upon
in granting market-based rate authority; \18\ and (4) a requirement for
large sellers to file updated market power analyses every three
years.\19\
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    \16\ 18 CFR 35.39.
    \17\ 18 CFR 35.10b.
    \18\ 18 CFR 35.42.
    \19\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 3; 18 CFR
35.37(a)(1).
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    8. In Order No. 697, the Commission created two categories of
sellers.\20\ Category 1 sellers are wholesale power marketers and
wholesale power producers that own or control 500 MW or less of
generation in aggregate per region; that do not own, operate, or
control transmission facilities other than limited equipment necessary
to connect individual generation facilities to the transmission grid
(or have been granted waiver of the requirements of Order No. 888
\21\); that are not affiliated with anyone that owns, operates, or
controls transmission facilities in the same region as the seller's
generation assets; that are not affiliated with a franchised public
utility in the same region as the seller's generation assets; and that
do not raise other vertical market power issues.\22\ Category 1 sellers
are not required to file regularly scheduled updated market power
analyses. Sellers that do not fall into Category 1 are designated as
Category 2 sellers and are required to file updated market power
analyses.\23\ However, the Commission may require an updated market
power analysis from any market-based rate seller at any time, including
those sellers that fall within Category 1.\24\
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    \20\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 848.
    \21\ 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), order on reh'g,
Order No. 888-A, FERC Stats. & Regs. ] 31,048, 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).
    \22\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 849
n.1000; 18 CFR 35.36(a).
    \23\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 850.
    \24\ Id. P 853.
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    9. In Order No. 697, the Commission further stated that through its
ongoing oversight of market-based rate authorizations and market
conditions, the Commission may take steps to address seller market
power or modify rates. For example, based on its review of updated
market power analyses, EQR filings, or notices of change in status, the
Commission may institute a proceeding under section 206 of the FPA to
revoke a seller's market-based rate authorization if it determines that
the seller may have gained market power since its original market-based
rate authorization. The Commission also may, based on its review of EQR
filings or daily market price information, investigate a specific
utility or anomalous market circumstance to determine whether there has
been a violation of RTO/ISO market rules or Commission orders or
tariffs, or any prohibited market manipulation, and take steps to
remedy any violations.\25\
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    \25\ Id. P 5.
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    10. After more than six years of experience with the implementation
of Order No. 697, the Commission proposed a number of changes to the
market-based rate program which, taken as a whole, it believed would
simplify and streamline certain aspects of the market-based rate
program and reduce the burden on industry and the Commission, while
continuing to ensure that the standards for market-based rate sales of
electric energy, capacity and ancillary services result in sales that
are just and reasonable. The Commission also proposed a number of
changes to improve transparency in the market-based rate program, some
of which represent increases in information collected from market-based
rate sellers.
    11. The Commission received 23 comments in response to the NOPR. A
list of commenters is attached as Appendix F.\26\
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    \26\ Although the Commission did not request reply comments,
several commenters nonetheless submitted reply comments. The
Commission will reject such reply comments.
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III. Overview of Final Rule

    12. In this Final Rule, we adopt in many respects the proposals
contained in the NOPR with further modifications and clarifications and
decline to adopt others. Our findings are summarized below.
    13. First, with respect to the Commission's horizontal market power
analysis, we are not, at this time, adopting the proposal to relieve
market-based rate sellers in RTO/ISO markets of the obligation to
submit indicative screens. However, we are confirming clarifications
and adopting many of the other proposed modifications to the horizontal
market power analysis. For example, we clarify that sellers may explain
that their generation capacity in the relevant geographic market
(including first-tier markets) is fully committed in lieu of submitting
indicative screens as part of their horizontal market power analysis.
We also clarify that, when the current Commission-accepted SIL values
into the relevant market are zero for all four seasons and the seller's
and its affiliates' generation capacity in the relevant market is fully
committed, the seller does not need to submit indicative screens. In
addition, we adopt the NOPR proposal regarding reporting of long-term
firm purchases.
    14. We adopt the proposal to define the default relevant geographic
market for an IPP located in a generation-only balancing authority area
as the balancing authority area(s) of each transmission provider to
which the IPP's generation-only balancing authority area is directly
interconnected. We explain that an IPP should study all of its
uncommitted

generation capacity from the generation-only balancing authority area
in the balancing authority area(s) of each transmission provider to
which it is directly connected, and we provide examples and
clarification of this policy.
    15. We amend the indicative screen reporting format and require
that the horizontal market power indicative screens and SIL Submittals
1 and 2 be filed in workable electronic spreadsheets. We find that
solar photovoltaic and solar thermal facilities are energy limited.
However, we determine that, due to their unique characteristics, solar
photovoltaic facilities, unlike other energy-limited facilities, must
use nameplate capacity and may not use historical five-year average
capacity factors.
    16. We adopt the proposal to require a market-based rate seller to
report in its indicative screens and asset appendix all of its long-
term firm purchases of capacity and/or energy that have an associated
long-term firm transmission reservation regardless of whether the
market-based rate seller has control over the generation capacity
supplying the purchased power. We also adopt a modified formula for
converting energy to capacity, and make corresponding changes to the
change in status reporting requirements.
    17. We confirm most of the clarifications proposed in the NOPR
regarding the SIL studies and provide some additional clarifications in
response to comments.
    18. With respect to the Commission's vertical market power
analysis, we adopt the proposal to eliminate the requirement that
market-based rate sellers file quarterly land acquisition reports and
provide information on sites for generation capacity development in
market-based rate applications and triennial updated market power
analyses. With respect to other change in status proposals, we clarify
that the 100 MW threshold does not include generation capacity that can
be imported from first-tier markets. Similarly, we find that applicants
and sellers are not limited to nameplate ratings when determining the
100 MW threshold. We have reconsidered the proposed clarification that
market-based rate sellers must account for behind-the-meter generation
in their indicative screens and asset appendices and find that behind-
the-meter generation need not be accounted for in the indicative
screens and asset appendices and will not count towards the 100 MW
change in status threshold or the 500 MW Category 1 seller threshold.
    19. We also adopt a 100 MW change in status threshold for reporting
new affiliations to align with the existing 100 MW threshold for
reporting net increases in generation capacity.
    20. We adopt changes to the asset appendix that sellers must submit
with most market-based rate filings, and will also require that the
asset appendix be submitted in an electronic format that can be
searched, sorted, and otherwise accessed using electronic tools. In
addition, based on comments received, we will add two additional
worksheets to the asset appendix, one for end notes and another for
long-term firm purchases. We provide some additional clarifications on
the asset appendix as well.
    21. We adopt the NOPR proposal to require a seller filing an
initial application for market-based rate authority, an updated market
power analysis, or a notice of change in status reporting new
affiliations to include a corporate organizational chart. However, we
clarify that the organizational chart need only to include the seller's
affiliates as defined in section 35.36(a)(9) of the Commission's
regulations rather than all upstream owners, ``energy subsidiaries''
and ``energy affiliates.''
    22. We adopt the NOPR proposal and clarify that granting waiver of
18 CFR part 101 under market-based rate authority does not waive the
requirements under Part I of the FPA for hydropower licensees. In
addition, we clarify how hydropower licensees that only make sales at
market-based rates may satisfy the requirements in part 101 of the
Commission's regulations (Uniform System of Accounts), and confirm that
hydropower licensees that have Commission-approved cost-based rates are
required to comply with the full requirements of the Uniform System of
Accounts.
    23. We also provide clarifications in the Final Rule with regard to
simplifying assumptions, the criteria for determining seller category
status, how to file a single corporate tariff, the regional reporting
schedule, and the vertical affirmative statement obligation.

IV. Discussion

A. Horizontal Market Power

1. Sellers in RTOs/ISOs
a. Commission Proposal
    24. Section 35.37 of the Commission's regulations requires market-
based rate sellers to submit market power analyses: (1) When seeking
market-based rate authority; (2) every three years for Category 2
sellers; and (3) at any other time the Commission requests a seller to
submit an analysis. A market power analysis must address a seller's
potential to exercise horizontal and vertical market power. If an RTO/
ISO seller \27\ fails the indicative screens for the RTO/ISO, it can
seek to obtain or retain market-based rate authority by relying on
Commission-approved RTO/ISO monitoring and mitigation.\28\
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    \27\ RTO/ISO sellers are sellers that study an RTO, ISO, and
submarkets therein as a relevant geographic market.
    \28\ In Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 111,
the Commission stated that ``to the extent a seller seeking to
obtain or retain market-based rate authority is relying on existing
Commission-approved [RTO/ISO] market monitoring and mitigation, we
adopt a rebuttable presumption that the existing mitigation is
sufficient to address any market power concerns.''
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    25. The Commission proposed to not require sellers in RTO/ISO
markets to submit indicative screens as part of their horizontal market
power analyses if they rely on Commission-approved monitoring and
mitigation to prevent the exercise of market power. Under the proposal,
RTO/ISO sellers instead would simply state that they are relying on
such mitigation to address any potential market power they might have,
and describe their generation and transmission assets and provide an
asset appendix with a list of generation assets and entities with
market-based rate authority (generation list) and a list of
transmission assets and natural gas intrastate pipelines and gas
storage facilities (transmission list). Under this proposal, all RTO/
ISO sellers seeking market-based rate authority in an RTO/ISO market
would make an initial filing, consistent with current practice, and
those sellers required to file updated market power analyses every
three years (i.e., Category 2 sellers) would continue to make their
scheduled filings. The Commission noted that it would retain the
ability to require an updated market power analysis, including
indicative screens, from any market-based rate seller at any time.
b. Comments
    26. Some commenters support the Commission's proposal to allow
market-based rate sellers in RTO/ISO markets with Commission-approved
monitoring and mitigation to not file indicative screens when
submitting initial applications requesting market-based rate authority
and updated market power analyses.\29\ Some commenters

request that the Commission clarify aspects of its proposal \30\ or
extend the proposal to additional circumstances.\31\ Some commenters
oppose the Commission's proposal, raising issues regarding the
Commission's legal authority to eliminate the indicative screens \32\
or the effectiveness of RTO/ISO monitoring and mitigation.\33\ For
example, Potomac Economics agrees with the general principal underlying
the Commission's proposal, but states that in some cases, participants
selling into RTO markets may be exempt from certain market power
mitigation measures or the mitigation measures may not be fully
effective and that the Commission's proposal may allow some
participants with potential market power to sell at market-based rates
without this market power being fully addressed.\34\ APPA/NRECA contend
that the proposal is a fundamental departure from the market-based rate
scheme that the courts have previously upheld.\35\
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    \29\ American Electric Power Service Corporation (AEP) at 4-5;
Electric Power Supply Association (EPSA) at 3-4; FirstEnergy Service
Company (FirstEnergy) at 4-5; Golden Spread Electric Cooperative,
Inc. (Golden Spread) at 6; NextEra Energy, Inc. (NextEra) at 2;
Subsidiaries of NRG Energy, Inc. (NRG Companies) at 8-9.
    \30\ See, e.g., E.ON Climate & Renewables North America LLC
(E.ON) at 3-4; Southern California Edison Company (SoCal Edison) at
16; Julie Solomon and Matthew Arenchild (Solomon/Arenchild) at 2;
Edison Electric Institute (EEI) at 6.
    \31\ See, e.g., FirstEnergy at 10; AEP at 6; EEI at 7.
    \32\ American Antitrust Institute (AAI) at 3-7; American Public
Power Association and National Rural Electric Cooperative
Association (APPA/NRECA) at 6-21; Transmission Access Policy Study
Group (TAPS) at 1-2, 5-9, 17-18.
    \33\ Potomac Economics at 3-4.
    \34\ Potomac Economics at 2.
    \35\ APPA/NRECA at 8-10 (citing Mont. Consumer Counsel v. FERC,
659 F.3d 910; California ex rel. Lockyer v. FERC, 383 F.3d 1006 (9th
Cir. 2004) (Lockyer); Blumentha v. FERC, 552 F.3d 875,882 (D.C. Cir.
2009) (Blumenthal)).
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c. Commission Determination
    27. The Commission received 15 comments on this issue from a wide
variety of market participants. Indeed, this was one of the most widely
commented upon aspects of the Commission's NOPR. The comments included
those who fully support the Commission's proposal, those who favor only
portions of it, those who seek clarification of it and those who oppose
it. And among those who oppose it, there are various reasons for their
opposition, which include legal, economic, and implementation issues.
While the Commission considers further the issues that were raised in
these comments, we are not prepared to adopt at this time the proposal
in the NOPR and will continue with our current practice of requiring
that sellers in RTO/ISO markets submit the indicative screens when
submitting initial applications requesting market-based rate authority
and updated market power analyses and relying on the Commission-
approved market monitoring and mitigation. We will transfer the record
on this aspect of the NOPR to Docket No. AD16-8-000 for possible
consideration in the future as the Commission may deem appropriate.
    28. Because we continue to value the information obtained through
the indicative screens and are not prepared at this time to adopt the
proposal, market-based rate sellers in RTO/ISO markets must continue to
submit the indicative screens as part of their horizontal market power
analysis unless the seller and its affiliates do not own or control
generation capacity or all of their capacity is fully committed. We
will continue to allow sellers to seek to obtain or retain market-based
rate authority by relying on Commission-approved RTO/ISO monitoring and
mitigation in the event that such sellers fail the indicative screens
for the RTO/ISO markets.\36\
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    \36\ See Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 11.
---------------------------------------------------------------------------

2. Sellers With Fully Committed Long-Term Generation Capacity
a. Commission Proposal
    29. The Commission has found that, if generation is committed to be
sold on a long-term firm basis to one or more buyers and cannot be
withheld by a seller, it is appropriate for a seller to deduct such
capacity when performing the indicative screens.\37\ In the NOPR, the
Commission clarified that where all generation owned or controlled by a
seller and its affiliates in the relevant balancing authority areas or
markets including first-tier balancing authority areas or markets is
fully committed, sellers may satisfy the Commission's market-based rate
requirements regarding horizontal market power by explaining that their
capacity is fully committed in lieu of including indicative screens in
their filings. The Commission proposed to clarify that, in order to
qualify as ``fully committed,'' a seller must commit the generation
capacity so that none of it is available to the seller or its
affiliates for one year or longer.
---------------------------------------------------------------------------

    \37\ See id. P 41.
---------------------------------------------------------------------------

    30. The Commission proposed that sellers claiming that all of their
relevant generation capacity \38\ is fully committed would have to
include the following information: the amount of generation capacity
that is fully committed, the names of the counterparties, the length of
the long-term contract, the expiration date of the contract, and a
representation that the contract is for firm sales for one year or
longer. The Commission stated that in order to qualify as fully
committed, the commitment of the generation capacity cannot be limited
during that 12-month consecutive period in any way, such as limited to
certain seasons, market conditions, or any other limiting factor.
Furthermore, the Commission stated that a seller's generation would not
qualify as fully committed if, for example, the seller has generation
necessary to serve native load, provider of last resort obligations, or
a contract that could allow the seller to reclaim, recall, or otherwise
use the capacity and/or energy or regain control of the generation
under certain circumstances (such as transmission availability
clauses).
---------------------------------------------------------------------------

    \38\ ``Relevant'' generation capacity refers to seller and
affiliated capacity in the study area, including the first tier.
---------------------------------------------------------------------------

    31. Additionally, the Commission stated that, consistent with the
existing regulations, a change in status filing will be required when a
long-term firm sales agreement expires if it results in a net increase
of 100 MW or more.\39\
---------------------------------------------------------------------------

    \39\ The Commission noted that such a change would be a
departure from the characteristics the Commission relied upon in
granting market-based rate authority. See 18 CFR 35.42(a).
---------------------------------------------------------------------------

b. Comments
    32. Many commenters support the Commission's proposal.\40\ For
example, EPSA agrees with the Commission's assessment that the study of
uncommitted generation in indicative screens becomes a purely
mathematical task and provides no significant additional information
when sellers' fully-committed long-term capacity is deducted from the
indicative screens.\41\ NextEra, also agreeing with the Commission's
proposal, states that where all generation owned or controlled by
sellers and their affiliates is fully committed to purchasers not
affiliated with the seller, the ability to exercise market power is
severely limited or non-existent.\42\ FirstEnergy states that it
supports the proposal because a seller whose generation capacity is
fully committed on a long-term basis lacks the ability to exercise
horizontal market power by withholding such capacity from the
market.\43\
---------------------------------------------------------------------------

    \40\ EPSA at 4; Solomon/Arenchild at 2; NextEra at 3; EEI at 8;
FirstEnergy at 7; NRG Companies at 10.
    \41\ EPSA at 5.
    \42\ NextEra at 3.
    \43\ FirstEnergy at 7.
---------------------------------------------------------------------------

    33. NRG Companies also support the proposal and request that the
Commission clarify that even if the seller and/or its affiliates have
uncommitted capacity in one or more

first-tier markets, no indicative screens will be required if all of
their generation capacity in the relevant market is fully committed
under long-term contracts and (1) the simultaneous import limitation
for the relevant market is zero, indicating that no capacity can be
imported from affiliates in first-tier markets, or (2) neither the
seller nor its affiliates have firm transmission rights into the
relevant market from any first-tier market in which its affiliates have
uncommitted capacity.\44\
---------------------------------------------------------------------------

    \44\ NRG Companies at 10-11.
---------------------------------------------------------------------------

    34. NextEra states that there is no need to provide screens in
balancing authority areas where all generation owned or controlled by
sellers and their affiliates is fully committed to purchasers not
affiliated with the seller and further requests that the Commission not
require screens if there is uncommitted capacity in any first-tier
market when 100 percent of the seller's generation capacity in the
relevant market is fully committed.\45\
---------------------------------------------------------------------------

    \45\ NextEra at 4.
---------------------------------------------------------------------------

    35. EPSA requests clarification that the proposed term ``fully
committed'' would also apply to circumstances where a seller retains
the right to sell capacity to a second buyer, but only when the first
buyer under the long-term contract waives the right to purchase. EPSA
explains that if the buyer under a long-term contract has the right to
call on the full output of the seller's generation, and the seller may
only offer the capacity to a second buyer when the first buyer foregoes
its purchase right, then that capacity should be considered fully
committed and thus, excluded from the indicative screens.\46\
---------------------------------------------------------------------------

    \46\ EPSA at 5.
---------------------------------------------------------------------------

    36. Solomon/Arenchild state that the Commission's proposal that the
exemption from the submittal of screens depends, in part, on whether
the seller has uncommitted capacity in first-tier markets is
inconsistent with its general approach in defining geographic markets
and when screens are required. They recommend that the Commission's
proposal be amended. In the NOPR, the Commission stated that ``where
all generation owned or controlled by a seller and its affiliates in
the relevant balancing authority areas or markets including first-tier
balancing authority areas or markets is fully committed, sellers may
explain that their capacity is fully committed in lieu of including
indicative screens in their filings in order to satisfy the
Commission's market-based rate requirements regarding horizontal market
power.'' \47\ Solomon/Arenchild propose that the language ``including
first-tier balancing authority areas or markets'' be excluded.\48\
Alternatively, they state that the definition could be modified to only
include first-tier supply that has a corresponding long-term firm
transmission agreement into the relevant balancing authority area.\49\
---------------------------------------------------------------------------

    \47\ NOPR, FERC Stats. & Regs. ] 32,702 at P 43 (emphasis
added).
    \48\ Solomon/Arenchild at 2-3.
    \49\ Id. at 3.
---------------------------------------------------------------------------

    37. With regard to the information a seller must provide, NextEra
seeks clarification on the phrase ``firm sales for one year or
longer.'' NextEra requests that the Commission clarify that the term
``firm'' has the same meaning as in the Commission's EQR Data
Dictionary, where it is defined as ``a service or product that is not
interruptible for economic reasons.'' \50\
---------------------------------------------------------------------------

    \50\ NextEra at 4-5 (citing http://www.ferc.gov/docs-filing/eqr/order770/data-dictionary.pdf).
---------------------------------------------------------------------------

    38. NextEra does not oppose the Commission's proposal to require
that sellers provide the expiration date of the contract in updated
market power analyses, but NextEra states that it does not agree with
requiring this information in initial market-based rate applications.
NextEra states that, more often than not, at the time a seller files
for market-based rate authority, the expiration date is unknown.\51\
EEI does not support requiring the expiration date and notes that the
expiration date is reported separately in EQR filings.\52\
---------------------------------------------------------------------------

    \51\ Id. at 5.
    \52\ EEI at 8.
---------------------------------------------------------------------------

c. Commission Determination
    39. Consistent with the NOPR, the Commission clarifies here that
when all of a seller's generation capacity is sold on a long-term firm
basis to one or more buyers, the seller has no uncommitted capacity and
in such cases will not be required to file the indicative screens.
Sellers may explain that their generation capacity is fully committed
in lieu of including indicative screens in their filings in order to
satisfy the Commission's market-based rate requirements regarding
horizontal market power in instances where all generation owned or
controlled by a seller and its affiliates in the relevant balancing
authority areas or markets, including first-tier balancing authority
areas or markets, is fully committed. We clarify that to qualify as
fully committed, a seller must commit the capacity to a non-affiliated
buyer so that none of it is available to the seller or its affiliates
for one year or longer. We also adopt the proposal that for those
sellers claiming that all of their relevant capacity is fully committed
they must include the following information: The amount of generation
capacity that is fully committed, the names of the counterparties, the
length of the long-term contract, the expiration date of the contract,
and a representation that the contract is for firm sales for one year
or longer. In order to qualify as fully committed, the commitment of
the generation capacity cannot be limited during that 12-month
consecutive period in any way, such as limited to certain seasons,
market conditions, or any other limiting factor. As stated in the NOPR,
a seller's generation would not qualify as fully committed if, for
example, that generation is needed for the seller to meet its native
load or provider of last resort obligations, or the power sales
contract in question could allow the seller to reclaim, recall, or
otherwise use the generation capacity and/or energy or regain rights to
the generation under certain circumstances (such as transmission
availability clauses). Additionally, a change in status filing will be
required when a long-term firm sales agreement expires if it results in
a net increase of 100 MW or more.
    40. We do not adopt the suggestions by NRG Companies, NextEra, and
Solomon/Arenchild regarding capacity in first-tier markets. We will not
implement NRG Companies' and NextEra's proposals that the Commission
not require sellers to submit indicative screens even if they have
uncommitted capacity in one or more first-tier markets as long as all
of the seller's capacity in the relevant market is fully committed. A
seller may fail an indicative screen in a market where it does not have
any uncommitted capacity due to its imports into the study area.\53\
However, when the current Commission-accepted SIL values into the
relevant market are zero for all four seasons, the seller does not have
to consider imports in its market-power studies. Therefore, we clarify
that if the seller's capacity in the relevant market is fully committed
and all the SIL values into the relevant market are zero, the seller
does not need to submit the indicative screens.
---------------------------------------------------------------------------

    \53\ For example, this can occur when a seller is relatively
large and the study area is relatively small and relies
significantly on imports to meet its load obligations.
---------------------------------------------------------------------------

    41. We do not adopt the suggestion from Solomon/Arenchild to only
consider first-tier supply that has long-term firm transmission rights
into the relevant market. First-tier generation capacity without long-
term firm

transmission rights still can be imported into the relevant market as
long as the SIL value is not zero; albeit on a non-firm, pro rata
basis.\54\ The SIL values used in the Commission's horizontal market
power analysis are net of long-term firm transmission reservations.
While a seller's pro rata share of the SIL value or transmission
capacity that may be used to import generation capacity from the first-
tier ultimately may be small, it should not be ignored.
---------------------------------------------------------------------------

    \54\ Stated another way, if the SIL value is not zero, and the
seller has uncommitted generation capacity in a first-tier market,
that uncommitted capacity is capable of reaching the study area and
will affect the market power analysis. However, a seller's first-
tier uncommitted capacity has to compete with non-affiliated first-
tier uncommitted capacity to enter the study area, so the Commission
allows sellers to allocate to themselves a portion of the SIL value
based on the percentage of uncommitted generation capacity they and
their affiliates own in the aggregated first-tier area in relation
to the total amount of uncommitted generation capacity in this area.
See Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 373-375.
---------------------------------------------------------------------------

    42. We also decline to adopt EPSA's request that we clarify that a
seller's generation capacity is fully committed where the seller
retains the right to sell capacity to a second buyer.\55\ We are
concerned that permitting a more flexible definition of fully committed
could create the potential for sellers to claim that their contracts
meet the standard for fully committed even where it is not clear that
the capacity's output is fully committed. Moreover, the contract-
specific analysis could create inconsistencies in the way data is
reported.
---------------------------------------------------------------------------

    \55\ Here we are referring to a situation in which the seller
retains rights to sell the same generation capacity to a second
buyer. We are not referring to a contractual arrangement whereby
capacity is fully committed but is sold to multiple buyers; e.g.,
500 MW of a 1,000 MW unit is sold to buyer A, while the remaining
500 MW of the unit is sold to buyer B, with A and B having exclusive
rights to their respective shares of the unit.
---------------------------------------------------------------------------

    43. With regard to NextEra's request that the Commission clarify
that ``firm'' has the same meaning as in the Commission's EQR Data
Dictionary, we clarify here that the term ``firm'' means a ``service or
product that is not interruptible for economic reasons,'' as it is
defined in the Commission's EQR Data Dictionary.
    44. We believe that NextEra raises a valid point concerning unknown
expiration dates. Therefore, we clarify here that if a contract
expiration date is unknown at the time of the market-based rate filing,
the seller must follow up with an informational filing, in the docket
in which the seller was granted market-based rate authorization, to
inform the Commission of the contract expiration date, within 30 days
of the date becoming known. In response to EEI's argument that the
expiration date is reported separately in EQR filings, we note many
contracts reported in EQR filings do not include expiration dates.
Further, there can be a time gap between when a seller receives market-
based authority and when it submits its EQR. This time gap may be as
large as 120 days, and would not meet the need for this information.
Therefore, we will require expiration date information to show that
generation capacity is fully committed.
3. Relevant Geographic Market for Certain Sellers in Generation-Only
Balancing Authority Areas
a. Commission Proposal
    45. In the NOPR, the Commission noted that ``the horizontal market
power analysis centers on and examines the balancing authority area
where the seller's generation is physically located'' \56\ and that the
default relevant geographic market under both indicative screens ``will
be first, the balancing authority area where the seller is physically
located [the seller's home balancing authority area] and second, the
markets directly interconnected to the seller's balancing authority
area (first-tier balancing authority area markets).'' \57\ However, the
Commission noted that ``[w]here a generator is interconnecting to a
non-affiliate owned or controlled transmission system, there is only
one relevant market (i.e., the balancing authority area in which the
generator is located).'' \58\ Similarly, the Commission noted that RTO/
ISO sellers are required ``to consider, as part of the relevant market,
only the relevant [RTO/ISO] market and not first-tier markets to the
[RTO/ISO].'' \59\
---------------------------------------------------------------------------

    \56\ NOPR, FERC Stats. & Regs. ] 32,702 at P 47 (quoting Order
No. 697, FERC Stats. & Regs. ] 31,252 at P 37).
    \57\ Id. (quoting Order No. 697, FERC Stats. & Regs. ] 31,252 at
P 232).
    \58\ Id. (quoting Order No. 697, FERC Stats. & Regs. ] 31,252 at
P 232 n.217).
    \59\ Id. (quoting Order No. 697, FERC Stats. & Regs. ] 31,252 at
P 231 n.215).
---------------------------------------------------------------------------

    46. The Commission noted that Order No. 697 stated that a
``balancing authority area means the collection of generation,
transmission, and loads within the metered boundaries of a balancing
authority, and the balancing authority maintains load/resource balance
within this area.'' \60\ The Commission further noted that, given that
generation-only balancing authority areas do not have any load, these
balancing authority areas do not appear to meet the Commission
definition of a default relevant geographic market. In light of the
unusual and complex circumstances that are associated with defining the
relevant geographic market of an IPP located in a generation-only
balancing authority area, and in light of the fact that a generation-
only balancing authority area is not a market, the Commission proposed
in the NOPR that the default relevant geographic market(s) for such a
seller would be the balancing authority areas of each transmission
provider to which its generation-only balancing authority area is
directly interconnected. The Commission proposed that such IPP seller
study all of its uncommitted generation capacity from the generation-
only balancing authority area in the balancing authority area(s) of
each transmission provider to which it is directly interconnected,
since all such uncommitted capacity could potentially be sold into any
of the markets that are directly interconnected to the IPP's
generation-only balancing authority area, even if the IPP has not sold
into that market.
---------------------------------------------------------------------------

    \60\ Id. P 51.
---------------------------------------------------------------------------

    47. In the NOPR, the Commission stated that ``[f]or purposes of
market power analyses for market-based rate authority, we propose to
define an IPP as a generation resource that has power production as its
primary purpose, does not have any native load obligation, is not
affiliated with any transmission owner located in the first-tier
markets in which the IPP is competing and does not have an affiliate
with a franchised service territory. This IPP could also have an OATT
waiver on file with the Commission.'' \61\
---------------------------------------------------------------------------

    \61\ Id. P 49 n.50.
---------------------------------------------------------------------------

    48. To illustrate the NOPR proposal, the Commission explained that
if an IPP is located in a generation-only balancing authority area that
is embedded within a transmission provider's balancing authority area,
and that balancing authority area is the only balancing authority area
that the IPP's generation-only balancing authority area is directly
interconnected with, then the IPP would provide indicative screens for
that transmission provider's balancing authority area.\62\
---------------------------------------------------------------------------

    \62\ The Commission proposed that an IPP in this situation would
not need to study the transmission provider's balancing authority
first-tier markets, just as would be the case if that generator were
similarly located in the transmission provider's balancing authority
area.
---------------------------------------------------------------------------

    49. The Commission provided another example for an IPP located in a
generation-only balancing authority area in a remote area such as the
desert southwest. In that case, the IPP would have to provide
indicative screens for the balancing authority area(s) of the
transmission provider(s) to which its generation-only balancing
authority area

is directly interconnected. The IPP would assume that all of its
uncommitted capacity could compete in each balancing authority area of
the transmission provider(s) to which its generation-only balancing
authority area is directly interconnected, since all such uncommitted
capacity could potentially be sold in each market to which there is a
direct interconnection, even if the IPP has not sold into that market
in the past. An IPP in this situation would not need to study any
first-tier markets.\63\
---------------------------------------------------------------------------

    \63\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 232
n.217.
---------------------------------------------------------------------------

    50. For an IPP in a generation-only balancing authority area
directly interconnected to a transmission provider at an energy trading
hub, the Commission proposed that the IPP would provide indicative
screens that study itself in the balancing authority area of each
transmission provider that is directly interconnected at the trading
hub. Thus, the balancing authority areas that are directly
interconnected at the hub would each be relevant geographic markets for
that IPP, and the IPP would provide indicative screens that study the
IPP in each of those transmission providers' balancing authority areas.
The Commission proposed that the IPP would provide indicative screens
that assume that all of its uncommitted capacity may compete in each of
the balancing authority areas that are directly interconnected at that
trading hub, since all such uncommitted capacity could potentially be
sold in each market to which there is a direct interconnection, even if
the IPP has not sold into that market in the past. The IPP in this
situation would not need to provide indicative screens that study
itself in any markets that are first-tier to the various balancing
authority areas that are directly interconnected at the trading hub.
b. Comments
    51. Solomon/Arenchild agree in principal with the Commission's
proposal to define relevant geographic market(s) for sellers located in
generation-only balancing area as the balancing authority areas of each
transmission provider to which the generation-only balancing authority
area is directly interconnected. Solomon/Arenchild suggest that the
Commission confirm that the proposal also applies to quasi-generation-
only balancing authority areas, such as Ohio Valley Electric
Corporation and Alcoa Power Generating, Inc.--Yadkin Division.
According to Solomon/Arenchild, in these quasi-generation-only
balancing authority areas, generation was built to serve load in a
balancing authority area, but there is no longer any material load
present in the balancing authority area.\64\
---------------------------------------------------------------------------

    \64\ Solomon/Arenchild at 15.
---------------------------------------------------------------------------

    52. However, Solomon/Arenchild voice concerns with the Commission's
proposal to have an IPP provide screens that study the IPP in the
balancing authority area of each transmission provider that is directly
interconnected at the trading hub. Citing the example in the NOPR
regarding IPPs interconnected to the Hassayampa switchyard, Solomon/
Arenchild state that, as proposed, the solution is overly burdensome
and likely to have unintended consequences.\65\ They explain that the
Commission's proposal, as they understand it, would require New
Harquahala Generating Company, LLC (Harquahala) and Arlington Valley,
LLC (Arlington Valley) to each perform indicative screens for all
Arizona Nuclear Power Project switchyard participants. They state that
this would be at least six balancing authority areas and perhaps more,
resulting in a ``significant increase in the scope of the analysis and
the burden.'' \66\
---------------------------------------------------------------------------

    \65\ The Commission explained in the NOPR that if an IPP in a
generation-only balancing authority area in the Arizona desert is
directly interconnected to a transmission provider at the Palo Verde
trading hub at the Palo Verde and Hassayampa switchyards, then it
would provide screens that study all of its uncommitted capacity in
each balancing authority area that is directly interconnected at the
switchyard. NOPR, FERC Stats. & Regs. ] 32,702 at P 56.
    \66\ Solomon/Arenchild at 15-17 (citing NOPR, FERC Stats. &
Regs. ] 32,702 at P 56).
---------------------------------------------------------------------------

    53. Solomon/Arenchild also argue that the proposal does not clarify
many of the steps that must be considered. They state that a seller has
to determine if each of the analyses require a presumption that 100
percent of the output of each of the relevant merchant generators can
be ``imported'' into each of the six or more balancing authority areas.
They further state that the SIL studies done by the transmission owners
in the region would have to be aligned with the analyses and they
question whether that means that each of the balancing authority areas
would be required to conduct two SIL studies--one that assumes each of
the potentially relevant generators reside ``within'' their balancing
authority areas and one that does not. Solomon/Arenchild also question
whether Harquahala and Arlington Valley should be singled out from
their other counterparts who are also interconnected at Hassayampa,
merely because they reside in a generation-only balancing authority
area.\67\
---------------------------------------------------------------------------

    \67\ Id. at 17.
---------------------------------------------------------------------------

    54. Solomon/Arenchild state that the proposal to conduct indicative
screens for multiple interconnected balancing authority areas appears
to merely create multiple opportunities for the generator in a
generation-only balancing authority area to fail an indicative screen.
Solomon/Arenchild further state that in proposing that each generator
consider multiple relevant balancing authority areas, it seems that the
Commission is acknowledging the highly interconnected nature of the
region (a key reason for the existence of a ``hub''), while still
rejecting the proposition that a ``hub'' itself can be a relevant
market. Solomon/Arenchild explain that it is worth noting that in the
Western Interconnection (unlike in the Eastern Interconnection), load
flow models such as those underlying the SIL analyses are based not on
individual balancing authority areas, but on ``areas'' that more
closely approximate real world conditions.\68\
---------------------------------------------------------------------------

    \68\ Id. at 17-18 (noting that Western Electricity Coordinating
Council transmission models used an ``Area 14,'' which covers the
Arizona ``region'' as the basis for SIL studies rather than the
individual balancing authority areas).
---------------------------------------------------------------------------

    55. Solomon/Arenchild state that the proposal could have
significant market-distortive effects. Solomon/Arenchild postulate that
if a generator fails an indicative screen in the Salt River Project
balancing authority area, but not in the Arizona Public Service
balancing authority area, the Salt River Project balancing authority
area may lose opportunities to purchase at market-based rates, and
generators may lose opportunities to sell at market-based rates.
Solomon/Arenchild contend that this would not occur if somewhat broader
markets are considered. Solomon/Arenchild conclude that, in the absence
of creating broader markets for generation-only balancing authority
areas like those at Hassayampa, the Commission should not change its
current practice. That is, sellers in generation-only balancing
authority areas should use as the default relevant market, the directly
interconnected balancing authority areas and that the scope of such
definitions be evaluated on a case-by-case basis.\69\
---------------------------------------------------------------------------

    \69\ Id. at 18.
---------------------------------------------------------------------------

    56. Lastly, Solomon/Arenchild request that the Commission clarify
that, to the extent that a seller fails the indicative screens in the
balancing authority area(s) to which it is directly interconnected,
sales at the ``hubs'' be treated as ``at the metered boundary'' of a
seller's mitigated balancing authority

area, and hence, allow market-based rate sales at the hubs.\70\
---------------------------------------------------------------------------

    \70\ Id.
---------------------------------------------------------------------------

    57. Romkaew Broehm and Gerald A. Taylor (Broehm/Taylor) agree with
the Commission's logic in proposing to define relevant markets as the
balancing authority areas that are directly interconnected to the
generation only-balancing authority area. However, Broehm/Taylor
encourage the Commission to look beyond its default market rule when
defining a proper relevant geographic market for a market power
analysis for all sellers. Broehm/Taylor question whether a seller's
home balancing authority area and its first-tier balancing authority
area would be adequate for determining relevant default markets.
According to Broehm/Taylor, during the 2000-2001 Western power crisis
experience, suppliers with generation more than two wheels away could
easily reach the California buyers and became pivotal sellers, simply
by having firm transmission rights at the key interfaces.\71\ Broehm/
Taylor explain that if the Commission were to require sellers to report
all of their transmission reservation data, a seller with reservations
on a path from a first-tier to a second-tier balancing authority area
would need to perform a market power analysis for the second-tier
balancing authority area.\72\ Broehm/Taylor state that this suggests
that the Commission should expand its review to consider other
information, such as sellers' transmission reservation data. Broehm/
Taylor therefore recommend that the Commission require all sellers to
summarize their historical short-term trade patterns outside their home
balancing authority area and report their firm transmission service
reservations of one month or longer as part of their triennial updated
market power analysis filing. Broehm/Taylor state that sellers are
required to report this information to the Commission via EQRs and that
this information can be used to determine whether or not the default
geographic markets as defined by the Commission are adequate for
purposes of market power analyses.\73\
---------------------------------------------------------------------------

    \71\ Broehm/Taylor at 3.
    \72\ Id. at 3-5.
    \73\ Id. at 5-6.
---------------------------------------------------------------------------

    58. EPSA generally supports the proposal, but suggests consistent
treatment in the Commission's evaluation of nested balancing authority
areas. It requests that the Commission clarify that it will implement
the proposal in such a manner to ensure that as long as there is
network deliverability from the nested balancing authority areas
through the interconnected balancing authority areas and to the first-
tier balancing authority areas, those first-tier balancing authority
areas should be included in the indicative screens of sellers in the
generation-only balancing authority areas. According to EPSA, this
approach would more accurately reflect the geographic area in which the
energy from the nested balancing authority area is available and with
which it can compete. They also state that this approach would be
consistent with the analysis for an IPP's balancing authority area that
is connected to a trading hub.\74\
---------------------------------------------------------------------------

    \74\ EPSA at 6.
---------------------------------------------------------------------------

    59. NRG Companies request that the Commission clarify that if a
seller in a generation-only balancing authority area fails the
indicative market power screens and surrenders or loses market-based
rate authorization to sell in one or more of the markets connected to
the trading hub, the seller will still be allowed to make market-based
rate sales at the trading hub, as long as it retains market-based rate
authorization in at least one of the balancing authority areas
interconnected to the trading hub. NRG Companies state that such
clarification is consistent with the Commission's holding in Order No.
697 that a seller that has lost market-based rate authorization and is
making sales subject to cost-based mitigation may continue to ``make
market-based rate sales at the metered boundary between a mitigated
balancing authority area and a balancing authority in which the seller
has market-based rate authority.'' \75\
---------------------------------------------------------------------------

    \75\ NRG Companies at 12-13 (citing Order No. 697, FERC Stats. &
Regs. ] 31,252 at P 817).
---------------------------------------------------------------------------

    60. EEI encourages the Commission to clarify that IPPs connected to
a hub would need to perform the market power analyses only for the home
market of each transmission provider connected to the hub, not the
transmission provider's first-tier adjacent markets, and that the IPPs
could conduct a single analysis, not separate ones for each provider's
market. EEI also requests the Commission consider whether a similar
approach could be used for entities that are not IPPs and for entities
that have a de minimis amount of load in their balancing authority
areas.\76\
---------------------------------------------------------------------------

    \76\ EEI at 9.
---------------------------------------------------------------------------

c. Commission Determination
    61. We adopt the NOPR proposal to define the default relevant
geographic market(s) for an IPP located in a generation-only balancing
authority area as the balancing authority areas of each transmission
provider to which the IPP's generation-only balancing authority area is
directly interconnected. For purposes of this provision, we define an
eligible IPP as a generation resource that has power production as its
primary purpose, does not have any native load obligation, is not
affiliated with any transmission owner located in the target or first-
tier markets in which the IPP is competing and does not have an
affiliate with a franchised service territory.\77\
---------------------------------------------------------------------------

    \77\ NOPR, FERC Stats. & Regs. ] 32,702 at P 49 n.50. This IPP
could also have an OATT waiver on file with the Commission or
qualify for a blanket waiver under 18 CFR 35.28(d).
---------------------------------------------------------------------------

    62. We also adopt the proposal for such an IPP to study all of its
uncommitted generation capacity from the generation-only balancing
authority area in the balancing authority area(s) of each transmission
provider to which it is directly interconnected. We clarify that we do
not consider other generation-only balancing authority areas to which
an IPP may be interconnected to be balancing authority areas of
transmission providers. If an IPP is located in a generation-only
balancing authority area that is embedded within a transmission
provider's balancing authority area, and that balancing authority area
is the only balancing authority that the IPP's generation-only
balancing authority area is directly interconnected with, then the IPP
only needs to study that transmission provider's balancing authority
area. An IPP in this situation would not need to study the transmission
provider's first-tier markets. An example of this situation is
NaturEner Power Watch, LLC (NaturEner), which has a generation-only
balancing authority area that is located within the NorthWestern Energy
balancing authority area. NaturEner would provide indicative screens
that examine all of its uncommitted capacity in the NorthWestern Energy
balancing authority area. NaturEner would not need to study itself in
any other balancing authority areas unless its generation-only
balancing authority area is directly interconnected to other balancing
authority areas.
    63. Similarly, if the IPP is located in a generation-only balancing
authority area and is not embedded within a single transmission
provider's balancing authority area, the IPP would need to provide
indicative screens for the balancing authority area(s) of the
transmission provider(s) to which its generation-only balancing
authority area is directly interconnected. For example, if it were the
case that the generation-only balancing authority areas of the Gila
River Power Company LLC and

Sundevil generation plants are each directly interconnected with the
balancing authority area operated by Arizona Public Service Co. (APS),
then each of those IPPs would study themselves in the APS balancing
authority area, and each would treat all other competing generators
from generation-only balancing authority areas directly interconnected
with the APS balancing authority area as being in the APS balancing
authority area. The IPPs in generation-only balancing authority areas
would also study themselves in the same manner in any other balancing
authority areas to which their generation-only balancing authority area
is directly interconnected.\78\ An IPP in this situation would not need
to study any of the transmission providers' first-tier markets, just as
would be the case if it were a generator located within the
transmission provider's home balancing authority area.\79\
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    \78\ However, the transmission provider, in all cases, would
consider the IPP generation capacity as first-tier generation when
conducting its SIL studies and indicative screens.
    \79\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 232
n.217.
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    64. Finally, we adopt the proposal to require an IPP in a
generation-only balancing authority area that is directly
interconnected to a transmission provider at a trading hub to provide
indicative screens that study itself in the balancing authority area of
each transmission provider that is directly interconnected at the
trading hub \80\ and to assume that all of its uncommitted capacity may
compete in each of those balancing authority areas.\81\ If the
uncommitted capacity of an IPP studying a balancing area authority
directly interconnected to a trading hub exceeds the transmission
provider's SIL, then the capacity assumed available to compete in that
balancing authority area will be equal to the SIL.
---------------------------------------------------------------------------

    \80\ As noted in the NOPR, when we state that the transmission
providers' balancing authority areas are directly interconnected at
the hub we are assuming that all such balancing authority areas are
directly interconnected with each other. NOPR, FERC Stats. & Regs. ]
32,702 at P 56 n.58.
    \81\ For example, if an IPP in a generation-only balancing
authority area in the desert southwest is directly interconnected to
a transmission provider at the Palo Verde trading hub at the Palo
Verde and Hassayampa switchyards, then the IPP would provide screens
that study all of its uncommitted capacity in each balancing
authority area that is directly interconnected at the trading hub.
An IPP in this situation would not need to study any markets that
are first-tier to the various balancing authority areas that are
directly interconnected at the trading hub.
---------------------------------------------------------------------------

    65. We appreciate the concerns of Solomon/Arenchild that this
requirement is overly burdensome, but think the proposal achieves an
appropriate balance. Historically, these sellers frequently failed the
indicative screens for their home markets since they often own or
control the majority of installed capacity, but have no associated load
from which to reduce their market shares. The Commission's approach in
this Final Rule likely will obviate the need to submit a DPT to rebut
the presumption of market power that results from failure of the
indicative screens, which typically is more burdensome and expensive
than preparing indicative screens for multiple markets. In addition,
the obligation to submit screens for all balancing authority areas
directly interconnected to a trading hub would apply to a limited
number of market-based rate sellers and these sellers could rely on
previously-accepted studies to complete their indicative screen
analyses. We believe that this approach helps sellers by providing
explicit guidance on the definition of the default market for their
specific situation.
    66. In response to Solomon/Arenchild's concern that a transmission
provider would need to conduct two SIL studies, we clarify that SIL
studies should consider the IPP's generation capacity as first-tier
generation to each balancing authority area studied. There would be no
need to conduct a second SIL study that assumes that the IPP is located
within a transmission provider's balancing authority area. However, if
an IPP has a long-term firm transmission reservation into a particular
transmission provider's balancing authority area for all or a portion
of its output, then the SIL study would have to reflect the fact that
the IPP's generation capacity associated with the transmission
reservation would be a firm import to that specific transmission
provider. However, multiple SIL studies would not need to be performed;
in this case, the IPP's generation capacity associated with the
transmission reservation would be modeled as a firm import to the
relevant transmission provider's balancing authority area.
    67. With regard to requests that the Commission clarify that, to
the extent a seller fails the indicative screen in the balancing
authority area(s) it is directly interconnected to, sales at hubs are
treated as ``at the metered boundary'' \82\ of a seller's mitigated
balancing authority area, and hence, market-based rate sales at hubs
are allowed, we clarify as follows. An IPP would be allowed to make
market-based rate sales at a trading hub if it loses market-based rate
authority in one of the markets connected to the trading hub, so long
as the hub is not located within the market in which the IPP is
prohibited from selling.\83\
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    \82\ Mitigated sellers are allowed to make market-based rate
sales for export at the metered boundary between a mitigated
balancing authority area and a balancing authority area in which the
seller has market-based rate authority. See Order No. 697, FERC
Stats. & Regs. ] 31,252 at PP 819-821.
    \83\ Resale of any sort by an affiliate of the mitigated seller
into the seller's mitigated balancing authority area(s) (i.e., by
looping power through adjacent markets) are violations of a
Commission-approved tariff that may also, depending on the facts,
violate the Commission's market manipulation regulations. See id. P
831.
---------------------------------------------------------------------------

    68. We find Broehm/Taylor's request that the Commission require all
market-based rate sellers to report their historical sales and
transmission reservation data and to use such data to define the
relevant geographic market, including markets beyond the first-tier, to
be outside the scope of this rulemaking. This aspect of the NOPR
proposal is limited to the relevant geographic market for IPPs in
generation-only balancing authority areas.
    69. We interpret EPSA's reference to nested balancing authority
areas to mean generation-only balancing authority areas that are
embedded within a transmission provider's balancing authority area.
With regard to EPSA's request to require IPPs in generation-only
balancing authority areas to provide indicative screens for first-tier
balancing authority areas when there is network deliverability from the
embedded balancing authority area through the interconnected balancing
authority area to the first-tier balancing authority areas, we
reiterate that an IPP in this situation would not need to study the
transmission provider's first-tier markets, even if there is available
transmission capacity. As noted above, if an IPP is located in a
generation-only balancing authority area that is embedded within a
transmission provider's balancing authority area, and that balancing
authority area is the only balancing authority that the IPP's
generation-only balancing authority area is directly interconnected
with, then the IPP only needs to study that transmission provider's
balancing authority area.
    70. We clarify, in response to the request from Solomon/Arenchild,
that the Commission's proposal also is meant to apply to quasi-
generation-only balancing authority areas such as Ohio Valley Electric
Corporation, Alcoa Power Generating, Inc.-Yadkin Division and Electric
Energy Inc. We interpret EEI's request for the Commission to consider
applying the proposal to entities that are not IPPs and entities that
have a de minimis amount of load

in their balancing authority areas to also be referring to quasi-
generation-only balancing authority areas.
    71. In response to EEI's request, we clarify that an IPP in a
generation-only balancing authority area that is directly
interconnected to a hub would need to perform the market power analyses
only for the home market of each transmission provider connected to the
hub, not the transmission provider's first-tier adjacent markets.
However, we decline to grant EEI's request to allow IPPs to provide a
single analysis for all balancing authority areas interconnected to the
trading hub and Solomon/Arenchild's similar request for broader markets
to be considered. Preparing a single analysis for all balancing
authority areas interconnected to a trading hub would require that
these areas be combined into a single, consolidated market. We believe
that such a request is beyond the scope of this proceeding.\84\
---------------------------------------------------------------------------

    \84\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 268
(``[a]ny proposal to use an alternative geographic market (i.e., a
market other than the default geographic market) must include a
demonstration regarding whether there are frequently binding
transmission constraints . . . that prevent competing supply from
reaching customers within the proposed alternative geographic
market.'').
---------------------------------------------------------------------------

4. Reporting Format for the Indicative Screens and SIL Submittals 1 and
2
a. Commission Proposal
    72. When submitting indicative screens as part of a horizontal
market power analysis, sellers are required to use the standard screen
formats adopted by the Commission in Order Nos. 697 and 697-A, which
are provided in appendix A to subpart H of part 35.\85\ Although
sellers currently submit their indicative screens using the standard
formats, they perform their own mathematical calculations. In the NOPR,
the Commission noted that in Puget Sound Energy, Inc.\86\ the
Commission adopted standardized formats for reporting SIL study
results, which includes Submittal 1, a spreadsheet that calculates the
SIL values to be used in the indicative screens. However, the
Commission noted in the NOPR that the current standard screen formats
for indicative screens does not have a row for SIL values even though
the Uncommitted Capacity Import values are constrained by the SIL
values from row 10 of Submittal 1 used to report SIL study results.
---------------------------------------------------------------------------

    \85\ The Commission noted in the NOPR that the market share
screen was inadvertently deleted from appendix A to subpart H of
part 35 at the time that the Commission made a correction to the
pivotal supplier screen in Order No. 697-A. NOPR, FERC Stats. &
Regs. ] 32,702 at P 42 n.39.
    \86\ 135 FERC ] 61,254 (2011) (Puget).
---------------------------------------------------------------------------

    73. Thus, the Commission proposed to amend the indicative screen
reporting formats in appendix A of subpart H of part 35. The Commission
proposed that appendix A include new rows for SIL Values, Long-Term
Firm Purchases (from outside the study area), and Remote Capacity (from
outside the study area) in both the pivotal supplier and market share
screen reporting formats. The Commission stated that including a row in
the indicative screens for SIL Values will help reinforce the
relationship between affiliated and non-affiliated generation capacity
imports and the SIL value. The Commission also proposed to modify the
descriptive text of the rows in the indicative screens for Installed
Capacity, Long-Term Firm Purchases, Long-Term Firm Sales, and
Uncommitted Capacity Imports.\87\ The Commission stated that the new
rows and their descriptions will clarify whether the resources are
either inside or outside the study area for Installed Capacity and
Long-Term Firm Purchases. Furthermore, the description for Uncommitted
Capacity Imports will now be consistent across both indicative screens.
The Commission provided an example of the proposed new indicative
screens reporting formats in appendix A of the NOPR.
---------------------------------------------------------------------------

    \87\ The Commission proposed to change the phrase ``Imported
Power'' in Rows D and H of the pivotal supplier screen to
``Uncommitted Capacity Imports.'' The Commission also proposed to
make the same change to Row E of the Market Share Screen. Thus,
under this proposal, all four rows in the indicative screens will
have the same text for this field, which represents affiliate and
non-affiliate uncommitted capacity able to be imported from the
first tier.
---------------------------------------------------------------------------

    74. The Commission proposed to revise the regulations at 18 CFR
35.37(c)(4) to require sellers to file the indicative screens in a
workable electronic spreadsheet format.\88\ The Commission also
proposed to post on the Commission's Web site a pre-programmed
spreadsheet as an example that sellers may use to submit their
indicative screens.\89\
---------------------------------------------------------------------------

    \88\ ``Workable electronic spreadsheet'' refers to a machine
readable file with intact, working formulas as opposed to a scanned
document such as an Adobe PDF file.
    \89\ The Commission explained in the NOPR that if a seller
chooses to create its own workable electronic spreadsheet, the file
it submits must have the same format as the sample spreadsheet on
the Commission Web site.
---------------------------------------------------------------------------

    75. Next, the Commission proposed to add a paragraph to the end of
section 35.37(c), making it paragraph (5), to codify the Commission's
requirement that sellers submitting SIL studies adhere to the direction
and required format for Submittals 1 and 2 found on the Commission's
Web site \90\ and submit their information, as instructed, in workable
electronic spreadsheets.
---------------------------------------------------------------------------

    \90\ The sample spreadsheets for Submittals 1 and 2 are found at
the Commission's Web site at http://www.ferc.gov/industries/electric/gen-info/mbr/authorization.asp under ``Quick Links.''
---------------------------------------------------------------------------

b. Comments
    76. APPA/NRECA and Golden Spread state that they support requiring
sellers to file the indicative screens in a workable, electronic
spreadsheet format.\91\ EEI states that to the extent that the
Commission's proposal simply reflects the Commission's current
requirements for conducting the indicative screens and Puget submittal
analyses, the changes are appropriate and reasonable.\92\
---------------------------------------------------------------------------

    \91\ APPA/NRECA at 4; Golden Spread at 7.
    \92\ EEI at 9.
---------------------------------------------------------------------------

    77. EEI requests that the Commission specify that it simply wants
market-based rate sellers to file the information electronically using
standard formats such as Adobe, Excel, or Word. EEI adds that if the
Commission has something more complex in mind, it should explain the
need for a more complex approach and should work with the regulated
community in developing the new formats that will be posted on the FERC
Web site, and in preparing other such guidance, information, and
requirements related to the market-based rate program, to ensure that
all are reasonable, clear, accurate, easy to use, and most cost-
effective.\93\
---------------------------------------------------------------------------

    \93\ Id. at 9-10.
---------------------------------------------------------------------------

    78. Solomon/Arenchild state that the proposal to require sellers to
provide a summary spreadsheet of the SIL components used to calculate
the SIL values in the electronic spreadsheet format provided on the
Commission's Web site is potentially helpful but seek clarification as
to whether only Line 10 of Submittal 1 is required to be filed
publicly.\94\
---------------------------------------------------------------------------

    \94\ Solomon/Arenchild at 11-12.
---------------------------------------------------------------------------

    79. El Paso commends the proposal to add new rows to clearly
identify Long-Term Firm Purchases and Remote Capacity from outside the
study area. It states that these reporting modifications will not only
provide clarity and transparency for the Commission's review, but will
also correctly recognize traditional entities, like El Paso, which have
invested in remote generation capacity to serve their native load
customers.\95\ El Paso states that the Commission should extend its
proposal further and apply it to the study of first-tier balancing
authority areas. El Paso states that the Commission's proposed
modifications to the standard screen

formats in appendix A do not consider when a seller with remote
generation performs the analysis for the balancing authority areas
market where its remote generation is located. El Paso recommends that
the Commission extend its proposal to modify the horizontal screen
formats to add the following rows to the screen formats in appendix A:
(i) ``Seller Native Load outside the study area'' as a separate line in
row K of the Market Share Analysis and (ii) ``Amount of Seller Load
outside the study area attributable to Seller Capacity inside the study
area, if any'' as a separate line in row N of the Pivotal Supplier
Analysis.\96\
---------------------------------------------------------------------------

    \95\ El Paso at 2-3.
    \96\ Id. at 3-4.
---------------------------------------------------------------------------

c. Commission Determination
    80. We adopt the NOPR proposal to amend the indicative screen
reporting formats in appendix A of subpart H of part 35 to include new
rows for SIL Values, Long-Term Firm Purchases (from outside the study
area), and Remote Capacity (from outside the study area) in both the
pivotal supplier and market share screen reporting formats. We also
adopt the NOPR proposal to revise the regulations at 18 CFR 35.37, as
proposed in the NOPR, to require sellers to file the indicative screens
in a workable electronic spreadsheet format and to codify the
requirement that sellers submitting SIL studies adhere to the direction
and required formats for SIL Submittals 1 and 2 found on the
Commission's Web site and submit their information in workable
electronic spreadsheets. The adopted indicative screen reporting
formats for appendix A to subpart H is provided in appendix A of this
Final Rule.
    81. In response to EEI's request that the Commission specify that
it simply wants market-based rate sellers to file the information
electronically using standard formats such as Adobe, Excel, or Word, we
clarify that Excel or another spreadsheet format will be acceptable but
an Adobe PDF file will not be acceptable. As the Commission stated in
the NOPR, a ``workable electronic spreadsheet'' refers to a machine
readable file with intact, working formulas as opposed to a scanned
document such as an Adobe PDF file. If a seller chooses to create its
own workable electronic spreadsheet, the file it submits must have the
same format as the sample spreadsheet on the Commission Web site.\97\
---------------------------------------------------------------------------

    \97\ It must have one worksheet for each of the indicative
screens and each screen must have the same exact rows, columns, and
descriptive text as the sample worksheets. Cells requiring negative
values must be pre-programmed to only allow negative values.
Likewise, cells with calculated values must contain a working
formula that calculates the value for that cell. The file must be
submitted in one of the spreadsheet file formats accepted by the
Commission for electronic filing. The list of acceptable file
formats can be found at the Commission's Web site: http://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
---------------------------------------------------------------------------

    82. In response to Solomon/Arenchild's request that the Commission
clarify whether only row 10 of Submittal 1 is required to be filed
publicly, we clarify that the Commission expects that all of Submittal
1, not just row 10, will be filed publicly. Submittal 1 provides
summary numeric data showing how the SIL values were calculated for a
given relevant geographic market and some of this data already is
publicly available. While we discourage submitting any portion of
Submittal 1 as privileged, to the extent a filer intends to request
privileged treatment for any portion of Submittal 1 or any other
portion of its filing, such filing must comply with 18 CFR 388.112,
including the justification for privileged treatment, i.e., why the
information is exempt from disclosure under the mandatory public
disclosure requirements of the Freedom of Information Act, 5 U.S.C. 552
(2012).
    83. We believe there is no need to expand the indicative screens as
proposed by El Paso because the scenario El Paso describes can be
addressed within the screens, as amended by this Final Rule. However,
we clarify that a seller with remote generation serving the seller's
home balancing authority area (rather than serving the balancing
authority area where the generation is physically located) should
account for that generation capacity in row C ``Long-Term Firm Sales
(in and outside the study area)'' if that generation is used to serve
load in the seller's home study area by virtue of dynamic scheduling
and/or long-term firm transmission reservations. If the seller's remote
generation is not committed to serving load in the seller's home
balancing authority area, then that generation should be studied as
uncommitted generation in the first-tier balancing authority area where
it is located.
5. Competing Imports
a. Commission Proposal
    84. In the NOPR, the Commission noted that it permits sellers to
make simplifying assumptions, where appropriate, and to submit
streamlined horizontal market power analyses. The Commission noted that
Order No. 697 provided that `` `a seller, where appropriate, can make
simplifying assumptions, such as performing the indicative screens
assuming no import capacity or treating the host balancing authority
area utility as the only other competitor.' '' \98\ In the NOPR, the
Commission clarified that the phrase ``assuming no import capacity''
means that a seller may assume ``no competing import capacity'' from
the first-tier area (i.e., directly interconnected balancing authority
areas or markets).\99\ The Commission further clarified that the seller
must still include any uncommitted capacity that it and its affiliates
can import into the study area.
---------------------------------------------------------------------------

    \98\ NOPR, FERC Stats. & Regs. ] 32,702 at P 66 (quoting Order
No. 697, FERC Stats. & Regs. ] 31,252 at P 321).
    \99\ Id. P 67 (emphasis in original).
---------------------------------------------------------------------------

b. Comments
    85. EEI, APPA/NRECA, and Golden Spread support the Commission's
proposed clarifications regarding sellers performing simplified
indicative screens assuming no competing import capacity.\100\
---------------------------------------------------------------------------

    \100\ EEI at 10; APPA/NRECA at 4; Golden Spread at 7.
---------------------------------------------------------------------------

c. Commission Determination
    86. We confirm the Commission's clarification in the NOPR regarding
competing import capacity. Specifically, ``assuming no import
capacity'' means that a seller may assume ``no competing import
capacity'' from the first-tier markets (i.e., adjacent balancing
authority areas or markets). This clarification is consistent with the
April 14, 2004 Order \101\ and other Commission orders.\102\ The seller
must still include any uncommitted capacity that it and its affiliates
can import into the study area.
---------------------------------------------------------------------------

    \101\ AEP Power Marketing, Inc. et al., 107 FERC ] 61,018, at P
38 (April 14 Order), order on reh'g, 108 FERC ] 61,026 (2004)
(``Where appropriate, the screens allow the applicant to submit
streamlined applications or to forego the generation market power
analysis entirely and, in the alternative, go directly to
mitigation. For example, if an applicant would pass the screens
without considering competing supplies from adjacent control areas,
the applicant need not include such imports in its studies.''
(emphasis added)).
    \102\ See, e.g., Acadia Power Partners, LLC et al., 107 FERC ]
61,168, at P 12 (2004) (``We remind applicants that they may provide
streamlined applications, where appropriate, to show that they pass
both screens. For example, if an applicant would pass both screens
without considering competing supplies imported from adjacent
control areas, the applicant need not include such imports.''
(emphasis added) (footnote omitted)).
---------------------------------------------------------------------------

6. Capacity Ratings
a. Commission Proposal
    87. In the NOPR, the Commission noted that it allows sellers
submitting indicative screens to rate their generation facilities using
either nameplate or seasonal capacity ratings.

The Commission stated that Order No. 697 allows sellers with energy-
limited resources, such as hydroelectric and wind generation
facilities, to provide an analysis based on historical capacity factors
reflecting the use of a five-year average capacity factor, including a
sensitivity test using the lowest and highest capacity factors for the
previous five years. The Commission noted that since the issuance of
Order No. 697, the Commission has recognized that sellers with newly-
built energy-limited generation facilities may not have five years of
historical data and has allowed the use of the five most recent years
of regional average capacity factors from the Energy Information
Administration (EIA) to determine capacity factors for those resources.
    88. In the NOPR, the Commission proposed to identify solar
technologies as energy-limited generation resources and to allow such
sellers to use either nameplate capacity or five-year historical
average capacity ratings to determine the capacity rating for their
solar technology generation resources. The Commission stated that
similar to other energy-limited generation resources, sellers using the
five-year average capacity factor must include sensitivity tests using
the lowest and highest capacity factors for the previous five years.
The Commission proposed that sellers with energy-limited generation
facilities (including solar technologies) that do not have five years
of historical data may use nameplate capacity, or the EIA-derived,
regional capacity factor for the previous five years appropriate to
their specific technology as defined in the EIA publication Annual
Energy Outlook,\103\ but may not use seasonal ratings.\104\ For sellers
using EIA-derived estimates, the Commission proposed to require that
sellers submit their calculation of the regional capacity factor as
well as copies of the appropriate tables of regional generation
capacity ratings from EIA's Annual Energy Outlook in their filing.
---------------------------------------------------------------------------

    \103\ See EIA, Annual Energy Outlook (May 2014), available at
http://www.eia.gov/forecasts/aeo/source_renewable.cfm. In Table 58
through Table 58.9 ``Renewable Energy Generation by Fuel--(by
Area),'' EIA provides data for the total generating capacity, and
actual (or estimated) electricity generated by renewable type for 22
``electricity market module regions'' covering the lower 48 states.
After converting the inputs into matching units, sellers can divide
actual (or estimated) electricity generated by installed capacity to
find the capacity factor.
    \104\ The Commission stated that sellers should use either
nameplate, a five-year average of historical data, or EIA-derived
five-year average regional capacity factors instead of seasonal
capacity factors for energy-limited resources. The Commission noted
that a five-year average wind capacity factor derived from EIA
regional data was an appropriate proxy for wind generators that do
not have five years of historical data.
---------------------------------------------------------------------------

    89. In addition, the Commission sought industry input in
identifying additional technologies that are energy-limited generation
resources, and what capacity factors should be used to rate them. The
Commission acknowledged that solar photovoltaic facilities will
effectively function with zero capacity during nighttime hours or
during heavy overcast conditions, as the sun does not provide much, if
any, solar energy from solar photovoltaic facilities during such
conditions. Thus, the Commission sought comment on whether these
operating characteristics warrant establishing a different method of
setting capacity factors for solar generation as compared to other
generation technologies.
    90. Also in the NOPR, the Commission proposed to clarify that,
within each filing, a seller must use the same capacity rating
methodology for similar generation assets. The Commission stated that
if a seller chooses in a particular filing to use seasonal ratings for
one of its thermal units, it must use seasonal ratings for all of its
thermal units in that filing. Likewise, if the seller chooses to use an
alternative rating methodology, such as the five-year average for any
energy-limited generation resource, it must use the five-year average
for all energy-limited generation resources in that filing for which
five years of historical data is available; otherwise it must use the
EIA-derived capacity factors for those resources for which the seller
does not have five years of data. The Commission stated that the seller
must specify in the filing's transmittal letter or accompanying
testimony, and in the generation asset appendix, which rating
methodologies it is using. The seller must use the specified rating
methodologies consistently throughout its entire filing, including in
its transmittal letter, asset appendix, and indicative screens. The
Commission noted that this proposal does not preclude the seller from
using a different capacity rating methodology for each type of
generation facility (thermal or energy limited) in subsequent filings
(e.g., in its initial filing a seller may use nameplate ratings for its
thermal units, then in its next filing choose to use seasonal ratings
for its thermal units).
b. Comments
i. Identify Solar as Energy Limited
    91. Many commenters support the Commission's proposal to identify
solar technologies as energy-limited generation resources.\105\
---------------------------------------------------------------------------

    \105\ See, e.g., E.ON at 4; NextEra at 6; EEI at 11; SunEdison,
Inc. (SunEdison) at 1.
---------------------------------------------------------------------------

ii. Use of Capacity Factors
    92. E.ON agrees with the Commission's proposal to allow a seller
that owns or controls solar technology generating resources to use
either nameplate capacity or five-year historical average capacity
ratings to determine capacity rating, and to use EIA-derived, regional
capacity factor estimates if the seller does not have five-year
historical capacity data. EEI asks the Commission to consider allowing
a given seller, with or without five years of historical data, to use
an alternative to the EIA regional capacity ratings if the seller can
demonstrate that the alternative is more accurate as to one or more of
the specific solar-generation facilities at issue in the filing, while
allowing use of actual or historical data for other facilities in the
same market.
    93. Many commenters sought clarification on the Commission's
proposals regarding use of capacity factors for energy-limited
resources. E.ON seeks clarification that if the seller relies on EIA-
derived capacity factors for a solar resource, it is not precluded from
using actual historical five-year data to establish capacity factors
for its other energy-limited resources.\106\ SoCal Edison requests
clarification as to the calculation of the five-year average capacity
factor for a given triennial; specifically, what periods do the five
years cover, and what is the average, is it by unit or technology.\107\
SoCal Edison also asks if the EIA-derived capacity factor is used,
whether it is to apply to nameplate capacity or seasonal ratings.\108\
EEI requests that the Commission clarify that companies can use the
average of the data available in the EIA data tables, up to a maximum
of a five-year average.\109\ SoCal Edison strongly supports allowing a
seller to use nameplate capacity ratings anytime a seller is required
to file only an asset appendix.
---------------------------------------------------------------------------

    \106\ E.ON at 5.
    \107\ SoCal Edison at 15-16.
    \108\ Id. at 16.
    \109\ EEI at 12 (noting that some of the EIA tables only cover
2011 forward, so five years of EIA data might not be available).
---------------------------------------------------------------------------

    94. Broehm/Taylor state that the Commission should require use of
the average historical capacity factor of existing energy limited
resources with the same technologies within the same region instead of
the EIA-derived, regional capacity factor estimates proposed by the
Commission. Broehm/Taylor state that the EIA-derived,

regional capacity factor estimates are an annual average value that
does not reflect seasonality, thereby creating a disconnect with the
Commission's indicative screens, which are required to be performed on
a seasonal basis. Broehm/Taylor further state that generation patterns
for certain energy limited resources such as solar and wind may vary by
months and seasons in certain locations.\110\
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    \110\ Broehm/Taylor at 6.
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    95. Further, Broehm/Taylor state that they ``seek Commission
clarification on whether the availability factors \111\ are required to
be applied only to nameplate capacity ratings of energy limited
resources.'' Broehm/Taylor ask whether the Commission's statement
``that sellers without five years of historical data cannot use
seasonal ratings imply that the availability factors should not be
applied to seasonal ratings.'' Broehm/Taylor state that, if this is the
case, it is appropriate to apply the same availability calculation to
both new and existing units of energy limited resources. Broehm/Taylor
caution that sellers need to be consistent in using capacity ratings
for calculating historical capacity factors and if the capacity ratings
are nameplate in the historical capacity factor calculation, these
capacity factors should be applied to nameplate capacity ratings.\112\
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    \111\ Broehm/Taylor use the term ``availability factors''
several times. The Commission has never used availability factors as
a basis for de-rating generation capacity.
    \112\ Broehm/Taylor at 7.
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iii. Identifying Other Energy-Limited Resources
    96. In response to the Commission's request for industry input in
identifying additional technologies that are energy-limited generation
resources, SoCal Edison identifies the following: Hydro, wind, solar,
biomass, and geothermal resources. It further states that it believes
this list can and should be expanded as appropriate.\113\
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    \113\ SoCal Edison at 15.
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iv. Require Same Rating Methodology for All Resources of the Same
Technology
    97. NextEra states that it does not support requiring the same
rating methodology for all resources of the same technology. To better
reflect a seller's market power, NextEra urges the Commission to
provide sellers the option in submitting indicative screens to reflect,
if known, the historical capability for resources of the same
technology and, if unknown, to submit EIA regional data for those
specific resources.\114\ EEI echoes these concerns stating that sellers
should be able to use five-year historical data for particular energy-
limited generation resources where the sellers have the information,
even as they may need to use a regional capacity factor for other such
facilities for which they do not have the information.\115\
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    \114\ NextEra at 7.
    \115\ EEI at 11.
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v. Limiting Capacity Standard to Peak Hours for Solar
    98. FirstEnergy states that the Commission properly recognized in
the NOPR that solar photovoltaic facilities will effectively function
with zero capacity during nighttime hours or during heavy overcast
conditions.\116\ FirstEnergy states that in the event that the
Commission permits capacity ratings of solar technologies to be based
on historical generation output rather than on nameplate ratings, such
capacity ratings should be based on the output of such generating
facilities during peak day-light hours only.\117\ Idaho Power believes
that using peak hours for determining solar capacity factors would be
appropriate and would provide better data.\118\ Broehm/Taylor state
that the Commission did not provide the definition of peak hours and
suggests that the Commission give reasonable flexibility to sellers
with regard to the number of peak hours when calculating availability
factors for energy limited technologies as long as sellers justify
their approach.\119\
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    \116\ FirstEnergy at 7.
    \117\ Id. at 8.
    \118\ Idaho Power at 3.
    \119\ Broehm/Taylor at 7-8.
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    99. However, SoCal Edison contends that the screens are not
designed for a particular hour or the peak hour for many types of
generation, all hours should be considered when calculating the
capacity rating.\120\ EPSA states that using peak hours will not
provide a better measure of capacity for solar technology generation
resources, and consistent with other intermittent energy resources,
such as wind, a historical average capacity rating during peak hours
would more accurately represent output of the facility incorporating
the variability of output given environmental and weather events that
affect solar generation resources output.\121\ E.ON states that it is
unclear that the use of peak hours is appropriate. It states that these
energy-limited resources can provide energy in daylight hours and not
necessarily only in peak-defined hours. E.ON asks that if the
Commission ultimately adopts some limiting capacity standard, whether
that is peak hours or otherwise, that the Commission clarify that the
solar photovoltaic resource would not be precluded from selling energy
products at market-based rates in any off-peak hours.\122\ EEI states
that the Commission should allow a seller to use an alternative to EIA
regional capacity ratings if they can demonstrate that the alternative
is more accurate as to one or more of the specific solar facilities at
issue in the filing. EEI states that the Commission should give sellers
the option to base solar capacity factors on peak hours rather than all
hours, but should not require them to do so.\123\ NextEra states that
as the horizontal market power indicative screens are intended to study
peak hours, it believes that it may be more consistent to require the
nameplate capacity rating, which for solar technologies largely
correlate to peak load times, rather than the five-year average
capacity factor or EIA regional data.\124\
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    \120\ SoCal Edison at 15.
    \121\ EPSA at 6-7.
    \122\ E.ON at 5.
    \123\ EEI at 11.
    \124\ NextEra at 6.
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c. Commission Determination
    100. We adopt the NOPR proposals with certain modifications and
clarifications. Specifically, we will allow sellers with energy-limited
generation facilities to use capacity factors to de-rate those
facilities in their market power analysis, with certain clarifications
discussed below. We will also identify solar thermal technologies as
energy-limited technologies, but require the use of nameplate capacity
ratings for solar photovoltaic units.
i. Identify Solar as Energy Limited
    101. We accept the NOPR proposal to identify solar photovoltaic and
solar thermal facilities as energy-limited generation resources.
However, as discussed below we will continue to require a seller to use
nameplate ratings for its solar photovoltaic facilities. We will allow
a seller to treat solar thermal facilities in the same manner as other
energy-limited resources. If a seller chooses to use a rating based on
a five-year average capacity factor for solar thermal facilities in
their filings, they must follow all of the requirements discussed in
this Final Rule regarding the use of capacity factors. Further, a
seller must use the same rating methodology for non-affiliated solar
thermal facilities, as it does for its own solar thermal facilities.
    102. For solar photovoltaic facilities we adopt NextEra's proposal
and

require the use of nameplate capacity in the asset appendices and
market power studies. As noted above, there was no consensus among
commenters as to whether to de-rate solar photovoltaic facilities based
on either an annual capacity factor or an on-peak capacity factor.
Given the generation profile of solar photovoltaic facilities (i.e.,
output is highest during peak hours), we believe that use of nameplate
ratings is reasonable for the purposes of the horizontal market power
analysis. In addition, the Commission's experience to date is that
sellers typically use nameplate ratings for solar photovoltaic
facilities in their market power analyses and asset appendices, so this
requirement is consistent with current industry practice. Although we
are requiring the use of nameplate capacity for solar photovoltaic
resources, we clarify that adopting the use of a limiting capacity
factor, such as peak hours, for any generation resource, would not
preclude that resource from selling energy products at market-based
rates in off-peak hours.\125\
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    \125\ E.ON at 5.
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ii. Use of Capacity Factors
    103. We will continue to allow a seller with energy-limited
generation facilities other than solar photovoltaic to use capacity
factors to de-rate those facilities in its market power analysis. For
purposes of this discussion we are excluding solar photovoltaic from
using capacity factors; as discussed above, solar photovoltaic will be
rated on nameplate rating. We clarify that for energy-limited
facilities, a seller may use either the nameplate capacity or a rating
based on a five-year average capacity factor. When a seller chooses to
use a certain rating methodology for an energy-limited resource, it
must consistently use that rating methodology for that specific type of
energy-limited resource in its market-power studies (i.e., its energy-
limited facilities, and non-affiliated energy-limited facilities).\126\
A seller must specify in the filing's transmittal letter or
accompanying testimony, and in the applicable asset appendices, which
rating methodology it is using for each technology. To the extent that
a seller chooses to use a capacity factor, it must use a unit-specific,
historical five-year average for any unit for which it can obtain five
or more years of operating history, and use the EIA-derived regional
capacity factor for any unit for which it is unable to obtain five
years of operating history.\127\
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    \126\ This is a change from the NOPR proposal to require that if
a seller uses an alternative rating methodology for any energy-
limited resource, it must use an alternative rating for all energy-
limited resources.
    \127\ Sellers must use five years of historical data even if
that means using data from multiple EIA reports. We recognize that
this may necessitate sellers including years after the study period.
However, this information is still historical and therefore
consistent with the requirements of Order No. 697, FERC Stats. &
Regs. ] 31,252, at PP 298-301.
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    104. A seller must use the same capacity rating method for non-
affiliated energy-limited facilities that it uses to rate the capacity
of its own energy-limited facilities when they are preparing their
market-power analyses. Thus, a seller that uses nameplate ratings for
its own energy-limited facilities should use nameplate ratings for all
other energy-limited facilities included in their horizontal market
power studies. Likewise, a seller that de-rate its own energy-limited
facilities using five-year average capacity factors should de-rate non-
affiliated energy-limited facilities using EIA regional average
capacity factors in its screens and DPTs. Consistent with Order No.
697, we will continue to require a seller that de-rates its energy-
limited facilities to include sensitivity tests using the lowest
capacity factor in the previous five years, and the highest capacity
factor in the previous five years.\128\
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    \128\ Id. P 344.
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    105. In the NOPR the Commission stated that a seller would be
allowed to use different capacity rating methodologies in subsequent
filings. However, we find here that a seller must use the same rating
methodology in subsequent filings until the next updated triennial
market power analysis. Thus, a seller would not be allowed to change
its rating methodologies until its next updated triennial market power
analysis (e.g., if a seller uses nameplate ratings for nuclear plants
in its triennial, it must use nameplate for nuclear in all filings,
until its subsequent triennial). If a seller is a Category 1 seller
(i.e., not required to file an updated triennial market power
analysis), it would be allowed to change rating methodologies when its
region's transmission owners' updated triennial market power analyses
are due. We reject SoCal Edison's request to allow a seller to switch
rating methods just because it is filing an asset appendix. A seller
must use the same rating methodology for each specific technology in
all filings. We do not see this as more burdensome, because the
capacity rating for most facilities will not change between filings. In
fact, we believe this may be less burdensome because companies will not
have different versions of their asset appendix.
    106. We adopt the NOPR proposal to require that a seller submit its
calculations of the regional capacity factor as well as copies of the
appropriate tables of regional generation capacity ratings from EIA's
Annual Energy Outlook in its filing. We also clarify that when using
the EIA tables to calculate a regional average for energy-limited
facilities, a seller should calculate capacity factors using the most
recent five calendar years of data available in the tables. Further,
the capacity factors should be applied per unit, to each generation
facility and applied to the facilities' nameplate ratings. Although we
intend the use of EIA regional capacity factors as a simple and
objective means for a seller to de-rate energy-limited facilities, we
will allow a seller to propose alternative methods of de-rating such
facilities in response to EEI and Broehm/Taylor's comments. A seller
proposing alternative methodologies must provide the data and
calculations used to derive the capacity factors to the Commission in
public, non-privileged files. Further, the seller must also provide the
EIA regional average capacity factor as a comparison and explain why it
believes its methodology provides a more accurate capacity rating than
the EIA regional average. We will decide on a case-by-case basis
whether to accept any such proposed alternative methodology.
iii. Identifying Other Energy-limited Resources
    107. In the NOPR, the Commission sought industry input in
identifying additional technologies that are energy-limited generation
resources, and what capacity factors should be used to rate them. As
discussed above, we adopt the proposal to identify solar thermal
technologies as energy limited. However, given that the Commission only
received one comment identifying additional technologies (other than
solar) and the Commission did not receive any comments regarding what
capacity factors should be used to rate additional technologies, we
will not specifically identify any additional technologies as energy
limited at this time.
7. Reporting of Long-Term Firm Purchases
a. Commission Proposal
    108. In Order No. 697, the Commission stated that a seller's
uncommitted capacity, as calculated in the indicative screens, is
determined by adding the total nameplate or seasonal

capacity of generation owned or controlled through contract and long-
term firm capacity purchases, minus operating reserves, native load
commitments, and long-term firm sales.\129\ The Commission also stated
that generation capacity associated with contracts that confer
operational control of a given facility to an entity other than the
owner must be assigned to the entity exercising control over that
facility. Therefore, market-based rate sellers have been required to
report long-term firm purchases in row B of the indicative screens
(Long-Term Firm Purchases) only if the purchase granted them control of
the capacity. Similarly, for purposes of reporting a change in status,
sellers have been required to report long-term firm capacity purchases
when assessing their cumulative generation capacity only if such
purchases confer control of such capacity to them.\130\ In the NOPR,
the Commission noted that this requirement applies to long-term firm
energy purchases to the extent that the long-term firm energy purchase
would allow the purchaser to control generation capacity.\131\