[Federal Register Volume 80, Number 210 (Friday, October 30, 2015)]
[Rules and Regulations]
[Pages 67056-67123]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-26908]



[[Page 67055]]

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  

[[Page 67056]]


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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, (202) 502-6479.

Carol Johnson (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE., Washington, 
DC 20426, (202) 502-8521.


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
 


[[Page 67057]]

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

[[Page 67058]]

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

[[Page 67059]]

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

[[Page 67060]]

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

    \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

[[Page 67061]]

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

[[Page 67062]]

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

[[Page 67063]]

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

[[Page 67064]]

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\
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    \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

[[Page 67065]]

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

    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.
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    \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

[[Page 67066]]

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

[[Page 67067]]

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.
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    \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)).
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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.

[[Page 67068]]

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,

[[Page 67069]]

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

    \110\ Broehm/Taylor at 6.
---------------------------------------------------------------------------

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

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

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

    \113\ SoCal Edison at 15.
---------------------------------------------------------------------------

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

    \114\ NextEra at 7.
    \115\ EEI at 11.
---------------------------------------------------------------------------

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

    \116\ FirstEnergy at 7.
    \117\ Id. at 8.
    \118\ Idaho Power at 3.
    \119\ Broehm/Taylor at 7-8.
---------------------------------------------------------------------------

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

    \120\ SoCal Edison at 15.
    \121\ EPSA at 6-7.
    \122\ E.ON at 5.
    \123\ EEI at 11.
    \124\ NextEra at 6.
---------------------------------------------------------------------------

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

[[Page 67070]]

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

    \125\ E.ON at 5.
---------------------------------------------------------------------------

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

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

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

    \128\ Id. P 344.
---------------------------------------------------------------------------

    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

[[Page 67071]]

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

    \129\ Id. P 38.
    \130\ See Order No. 697-B, FERC Stats. & Regs. ] 31,285 at PP 
99-101.
    \131\ NOPR, FERC Stats. & Regs. ] 32,702 at P 73 (citing Order 
No. 697-B, FERC Stats. & Regs. ] 31,285 at PP 99-101).
---------------------------------------------------------------------------

    109. In the NOPR, the Commission noted that the limited reporting 
of long-term firm purchases may create errors or misleading results in 
the indicative screens submitted by some sellers including incorrectly-
sized markets and negative market shares for franchised public 
utilities and inconsistencies between the SIL values reported in the 
screens and the SIL values calculated for the relevant market or 
balancing authority area. The Commission noted instances where neither 
the seller nor the purchaser under a long-term firm power sale is 
attributed with the generation capacity that is used to make the sale 
because the seller deducted the capacity committed under the long-term 
firm power sale from its uncommitted capacity while the purchaser 
followed existing Commission policy and, because it did not ``control'' 
this capacity, did not include it as part of its uncommitted capacity.
    110. The Commission proposed in the NOPR to modify the policy with 
respect to the reporting of long-term firm purchases in the indicative 
screens. Specifically, the Commission proposed to require applicants 
\132\ under the market-based rate program to report all of their long-
term firm purchases of capacity and/or energy in their indicative 
screens and asset appendices, where the purchaser has an associated 
long-term firm transmission reservation, regardless of whether the 
seller has operational control over the generation capacity supplying 
the purchased power.\133\ The Commission proposed that if the long-term 
firm purchase involves the sale of energy and does not identify an 
associated capacity amount, the purchaser must convert the amount of 
energy to which it is entitled into an amount of generation capacity 
for purposes of its indicative screens and asset appendices, i.e., 
include the amount of the capacity as long-term firm purchases in rows 
B (Long-Term Firm Purchases (from inside the study area)) or B1 (Long-
Term Firm Purchases (from outside the study area)) of the proposed 
revised indicative screens and include it in its asset appendix. The 
Commission proposed that a seller under that firm power purchase 
agreement must continue this approach the next time it submits a 
market-based rate triennial or change in status filing with the 
Commission, i.e., convert the energy into capacity and include the 
amount of capacity as a long-term firm sale in row C (Long-Term Firm 
Sales).\134\ The Commission proposed that, when making these filings, 
both the purchaser and the seller must show how they made the energy-
to-capacity conversion. Although the Commission proposed this 
attribution of capacity as a general policy, the Commission noted that 
applicants or intervenors may raise fact-specific circumstances that 
they believe may support a different attribution of capacity.
---------------------------------------------------------------------------

    \132\ Although we generally use the term ``sellers'' elsewhere 
in the Final Rule when referring to market-based rate sellers and 
applicants, in this section, we refer to such sellers as 
``applicants'' to avoid confusion when discussing market-based rate 
sellers who are purchasers under long-term firm power purchase 
agreements.
    \133\ NOPR, FERC Stats. & Regs. ] 32,702 at P 79. In Vantage 
Wind, LLC, 139 FERC ] 61,063 (2012) (Vantage Wind), the Commission 
directed the purchasers to report all long-term firm purchases if 
the purchase had long-term firm transmission rights associated with 
those resources. In the NOPR, the Commission assumed for purposes of 
the proposal that all long-term firm purchases necessarily have 
long-term firm transmission rights associated with them. If that is 
not the case, the Commission stated that applicants or intervenors 
are free to raise fact-specific circumstances that they believe may 
support a different attribution of capacity. NOPR, FERC Stats. & 
Regs. ] 32,702 at P 79 n.97.
    \134\ In the NOPR, the Commission stated that many power 
purchase agreements for firm energy specify an associated capacity 
commitment from the seller. In cases where capacity commitments are 
not specified in the power purchase agreement, we propose that 
applicants use the following formula to convert energy to capacity 
(on a one-year basis): [Energy (MWh)/8,760]/capacity factor = 
capacity (MW).
    Where energy (MWh) is the total amount of energy purchased under 
the power purchase agreement over the calendar year; 8,760 is the 
total hours of a calendar year (use 8,784 in a leap year); capacity 
factor is actual capacity factor achieved by the unit(s) supplying 
the energy during the calendar year and is a measure of a generating 
unit's actual output over a specified period of time compared to its 
potential or maximum output over that same period. For example, if 
700,000 MWh is the amount of firm energy purchased under a power 
purchase agreement during a calendar year, and the capacity factor 
of the generator supplying the energy is 0.8 or 80 percent, then the 
700,000 MWh of energy would be converted into approximate 100 MW of 
capacity. That is: (700,000 MWh/8,760)/0.8 = 100 MW. NOPR, FERC 
Stats. & Regs. ] 32,702 at P 79 n.98.
---------------------------------------------------------------------------

    111. The Commission stated that the intent of the proposed reform 
is to have an applicant report all long-term firm purchases that it 
makes where the selling entity has a legal obligation to provide the 
purchaser with an energy supply that cannot be interrupted for economic 
reasons or at the seller's discretion. If the purchaser has contractual 
rights to receive the output of a long-term firm energy purchase, the 
Commission proposed that the amount of the capacity supplying that 
purchase must be reported in the purchaser's screens.
    112. In the NOPR, the Commission stated that the proposal to 
require applicants to report all of their long-term firm purchases of 
capacity and/or energy in their indicative screens and asset appendices 
is supported based on several considerations. First, it will size the 
market correctly and therefore improve the accuracy of the indicative 
screens, especially for franchised public utilities, whose indicative 
screens are used by the non-transmission owning sellers to prepare 
their own indicative screens. Currently, applicants often do not report 
some or all of their long-term firm purchases because they do not 
control these resources. Including all long-term firm purchases in the 
indicative screens will properly size the market and eliminate the 
unrealistic results (e.g., negative market shares) caused by the under-
reporting of generation noted above.
    113. Second, the Commission stated that this proposed change will 
establish consistent treatment of long-term firm sales and long-term 
firm purchases in the indicative screens. The Commission noted that 
applicants typically deduct long-term firm sales without making a 
determination as to whether those sales confer operational control to 
the purchaser. The Commission explained that, in Order No. 697, it did 
not require that sellers make such a determination before deducting the 
capacity supporting long-term firm sales: ``Uncommitted capacity is 
determined

[[Page 67072]]

by adding the total nameplate or seasonal capacity of generation owned 
or controlled through contract and firm purchases, less operating 
reserves, native load commitments and long-term firm sales.'' \135\ In 
Order No. 697, the Commission stated that ``[s]ellers may deduct 
generation associated with their long-term firm requirements sales, 
unless the Commission disallows such deductions based on extraordinary 
circumstances.'' \136\
---------------------------------------------------------------------------

    \135\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 38 
(footnotes omitted).
    \136\ Id. P 38 n.18.
---------------------------------------------------------------------------

    114. In the NOPR, the Commission explained that it is only on the 
``buy'' side of long-term firm purchases that the Commission has 
considered the issue of control in reporting capacity in the 
screens.\137\ The Commission stated that the result is that some 
generation capacity sold under long-term power purchase agreements 
``disappears'' from the market because neither the seller nor the 
purchaser includes the capacity as part of its uncommitted capacity 
(i.e., the seller subtracts the amount sold under the long-term power 
purchase agreement from its capacity for purposes of its screens, but 
sometimes the purchaser does not add the corresponding amount to its 
capacity for purposes of its screens). The Commission stated that it is 
inevitable that some generation capacity will be excluded from the 
indicative screens, with resulting errors in market shares and overall 
market size, when differing standards are applied to long-term firm 
purchases and long-term firm sales with respect to the allocation of 
such capacity. The Commission stated that the NOPR proposal will make 
those standards consistent, reducing such errors.
---------------------------------------------------------------------------

    \137\ Order No. 697-B, FERC Stats. & Regs. ] 31,285 at PP 99, 
100.
---------------------------------------------------------------------------

    115. Third, requiring the reporting of all long-term firm power 
purchases also will ensure consistent treatment of owned or installed 
capacity and long-term firm purchases in the indicative screens. The 
Commission stated that the horizontal market power analysis implicitly 
assumes that applicants control all of their owned or installed 
capacity listed in their indicative screens but this is not necessarily 
the case.\138\ For example, in situations where an applicant is a 
minority owner of a jointly-owned generating unit, it is quite possible 
that the applicant will not have operational control (i.e., commitment 
and dispatch authority) over the unit.\139\ However, applicants 
typically include all of their owned or controlled generation capacity 
in the indicative screens regardless of whether they actually control 
the commitment and dispatch of this capacity. Accordingly, the 
Commission proposed that an applicant with long-term firm purchases 
treat such contracted-for capacity in a similar manner to an applicant 
that owns capacity; that is, such purchases should be included in the 
applicant's portfolio of generation for the indicative screens.
---------------------------------------------------------------------------

    \138\ As the Commission explained in the NOPR, in Order No. 697, 
the Commission noted that its historical approach has been that the 
owner of a facility is presumed to have control of the facility 
unless such control has been transferred to another party by virtue 
of a contractual agreement. The Commission stated in Order No. 697 
that it would continue its practice of assigning control to the 
owner absent a contractual agreement transferring such control. 
Order No. 697, FERC Stats. & Regs. ] 31,252 at P 183.
    \139\ Another example is when a generator confers operational 
control to a third party through a long-term tolling agreement. See, 
e.g., Shell Energy North America (US), L.P., 135 FERC ] 61,090, at P 
3 (2011).
---------------------------------------------------------------------------

    116. Further, the Commission stated in the NOPR that for those 
applicants incorrectly reporting long-term firm power purchases in the 
wrong row of the indicative screens,\140\ uniform reporting of these 
purchases will also help to ensure consistency between the SIL values 
reported in the screens and the Commission's accepted SIL values for 
the relevant market or balancing authority area. In the NOPR, the 
Commission stated that improperly classifying long-term firm purchases 
(or imports of remotely-owned installed capacity) as Imported Power in 
the existing screens (row D of the pivotal supplier screen and row E of 
the market share screen) may lead to an overstatement of the market's 
SIL values.\141\ The Commission explained in the NOPR that this is 
because the sum of the values in the existing pivotal supplier screen 
for Seller and Affiliate Imported Power shown in row D and Non-
Affiliate Imported Power shown in row H should be less than or equal to 
the Commission-accepted SIL values. All Commission-accepted SIL values 
account for (i.e., subtract) long-term transmission reservations into 
the study area, so that they reflect the transmission capability 
available to competing sellers after accounting for the capability that 
the local utility has reserved for its own use to import power from 
remote resources. Thus, the Commission explained that classifying long-
term firm purchases as Imported Power effectively ``double counts'' 
import capability in the screens because it adds back the import 
capability associated with long-term firm purchases and assumes that 
this capability is available to potential competitors. The Commission 
stated that this problem does not arise if long-term firm purchases 
(and imports of remotely-owned installed capacity) are properly 
classified in the indicative screens as Long-Term Firm Purchases (rows 
B1 and F1 in the proposed screen format for the pivotal screen) and 
Remote Capacity (rows A1 and E1 in the proposed screen format for the 
pivotal screen), respectively. The Commission stated that this proposal 
is intended to help clarify how to classify imports of firm power and 
remotely-owned capacity. The Commission also proposed these changes to 
the screen format for the market-share screen.
---------------------------------------------------------------------------

    \140\ The NOPR stated that ``[a]s the Commission noted in 
Vantage Wind, improperly classifying long-term firm purchases (or 
imports of remotely-owned installed capacity) as Imported Power in 
the existing screens . . . may lead to an overstatement of the 
market's SIL values.'' NOPR, FERC Stats. & Regs. ] 32,702 at P 85 
(citing Vantage Wind, 139 FERC ] 61,063).
    \141\ The Commission noted Vantage Wind, 139 FERC ] 61,063 at P 
16 (``In its updated market power analysis, Puget accounted for both 
its remote generation from its Colstrip plant located in Montana and 
its firm power purchase agreements from Bonneville Power 
Administration as Imported Power (Line D of the market share screen 
and the pivotal supplier screen) rather than as Installed Capacity 
(Line A of the market share screen and the pivotal supplier screen) 
or a Long-term Firm Purchase (Line B of the market share screen and 
the pivotal supplier screen), respectively. Consequently, the total 
SIL shown in Puget's screens exceeded the net SIL value for the 
Puget balancing authority area as accepted by the Commission in 
[Puget, 135 FERC ] 61,254]. When Vantage Wind applied the 
Commission-approved SIL values to its analysis without making any 
other adjustments to Puget's screens, Vantage Wind appeared to fail 
the screens because Puget's capacity was underreported.'').
---------------------------------------------------------------------------

b. Comments
    117. Commenters mostly disagree with the proposal, either 
supporting the Commission's existing ``control test'' or expressing 
concerns that the Commission's proposal does not actually make the 
reporting more accurate.\142\ SoCal Edison states that the Commission's 
identified flaws in the control test and the current reporting of long-
term purchases are not well supported and do not merit abandonment of 
the control test.\143\ In particular, SoCal Edison disputes the 
``disappearing capacity'' concern raised in the NOPR, asserting that 
generation capacity associated with long-term firm sales is reflected 
in some manner in the screens.\144\ SoCal Edison also contends that the 
Commission's assertion that a long-term firm purchase is just like 
ownership with regard to the ability to

[[Page 67073]]

get energy to the market is demonstrably false in some cases.\145\
---------------------------------------------------------------------------

    \142\ EPSA at 10; APPA/NRECA at 21-24; SoCal Edison at 3-11; 
Solomon/Arenchild at 8-10; Avista at 2-4; NextEra at 8; TAPS at 2.
    \143\ SoCal Edison at 3.
    \144\ Id. at 5.
    \145\ Id. at 11.
---------------------------------------------------------------------------

    118. E.ON and FirstEnergy agree with the Commission's 
proposal.\146\ FirstEnergy states that ``attribution of all such 
capacity to the purchaser, as proposed by the FERC, will recognize 
appropriately the rights of the purchaser in the purchased resource and 
will help to improve the consistency of market power studies.'' \147\ 
E.ON requests clarification that sellers of long-term capacity in RTO 
markets would not be required to submit indicative screens solely 
because the purchaser was required to do so.\148\
---------------------------------------------------------------------------

    \146\ E.ON at 6; FirstEnergy at 8.
    \147\ FirstEnergy at 8-9.
    \148\ E.ON at 7.
---------------------------------------------------------------------------

    119. EEI urges the Commission to engage in further dialogue, noting 
that some EEI members have concerns, and some agree with at least some 
elements of the proposal. EEI states that some members were concerned 
that they would lose flexibility to reflect actual ownership and 
control of assets in indicative screens and asset appendices, and 
whether they would need to report the long-term contracts in the asset 
appendix.\149\
---------------------------------------------------------------------------

    \149\ EEI at 12.
---------------------------------------------------------------------------

    120. Avista/Puget state that the Commission's proposed solution 
goes too far and that the Commission instead should retain its current 
treatment of purchased capacity and/or energy based on the concept of 
operational control established in Order No. 697, with certain 
modifications to ensure that the capacity does not disappear from 
reports of the market.\150\ To prevent generation capacity from 
disappearing in the indicative screens, Avista/Puget propose that the 
Commission modify its current policy with regard to the seller's 
treatment of sold energy such that it is the mirror image of the 
purchaser's treatment. Under Avista/Puget's proposal, generating 
capacity associated with a long-term sale would be assigned to the 
seller, for purposes of conducting the indicative screen computations, 
if the contract does not convey control of the capacity to the 
purchaser.\151\
---------------------------------------------------------------------------

    \150\ Avista Corp. and Puget Sound Energy, Inc. (Avista/Puget) 
at 2.
    \151\ Id. at 4.
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    121. TAPS expresses concerns that the proposed change may well 
result in inaccurate reporting and mask the market power of large 
sellers where they retain control over the resource(s).\152\ APPA/NRECA 
concede that this may fix some administrative problems, but worry that 
the resulting indicative screens will not accurately reflect actual 
market shares or pivotal supplier conditions.\153\
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    \152\ TAPS at 2.
    \153\ APPA/NRECA at 21-24.
---------------------------------------------------------------------------

    122. Indicated Utilities state that if the Commission adopts this 
rule, it should exempt from this requirement the capacity and/or energy 
associated with power purchase agreements from inherently intermittent 
qualifying small power production facilities entered into under 18 CFR 
part 292, subpart C, namely solar and wind qualifying facilities.\154\ 
Indicated Utilities state that power purchase agreements with 
intermittent resource qualifying facilities are often fundamentally 
different from other power purchase agreements and thus warrant 
different treatment from that proposed in the NOPR.\155\ For that 
reason Indicated Utilities urge the Commission to retain for such power 
purchase agreements its existing policy of attributing capacity and/or 
energy to the entity that ``controls'' the qualifying facilities, as 
that term has been used in Order No. 697.\156\
---------------------------------------------------------------------------

    \154\ Indicated Utilities at 2.
    \155\ Id. at 5.
    \156\ IWU at 7.
---------------------------------------------------------------------------

    123. EPSA questions the utility of this proposal and seeks 
clarification of how this requirement would differ from the reporting 
required in EQRs. EPSA states that it appears that the information 
required to be reported by this proposal would duplicate the 
information provided by sellers contained in the EQRs, which are 
required to be filed under current Commission regulations. EPSA 
suggests that if the Commission is seeking this information, then the 
Commission should not adopt the proposed revision but just refer to the 
EQR data.\157\
---------------------------------------------------------------------------

    \157\ EPSA at 9-10.
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    124. EPSA requests clarification that in evaluating long-term 
contracts for the indicative screens, sellers are still permitted to 
make conservative assumptions in their initial application and 
triennial updated market power analyses.\158\
---------------------------------------------------------------------------

    \158\ Id. at 10.
---------------------------------------------------------------------------

    125. Indicated Utilities state that the Commission should clarify 
that this proposed change--whether for intermittent qualifying small 
power production facilities power purchase agreements or other power 
purchase agreements--applies only to the indicative screens and asset 
appendices, and does not apply to any DPT analyses submitted to rebut a 
presumption of market power brought about by failure of one or both of 
the screens. Indicated Utilities contend that it would be consistent 
with the Commission's post-Order No. 697 approach for the proposed 
policy to apply only to the indicative screens while maintaining the 
current ``control-based'' approach to DPT analyses. Indicated Utilities 
state that the indicative screens are designed to be screens, while the 
DPT, on the other hand, is more granular and a more accurate means of 
assessing horizontal market power.\159\
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    \159\ Indicated Utilities at 8-9.
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    126. SoCal Edison states that it does not generally object to the 
Commission collecting data on all long-term firm purchases through the 
asset appendix, but SoCal Edison asks the Commission to clarify that 
inclusion of a long-term firm purchase in an asset appendix does not 
constitute a concession that a purchase should appear in a market power 
screen analysis. SoCal Edison states that a seller should be permitted 
to rebut the presumption that any particular long-term firm purchase 
should be counted if the applicant is seeking to exclude the long-term 
firm purchase from a market power analysis. SoCal Edison further 
submits that if the applicant has no obligation to submit such screens, 
it need not rebut the presumption, but reserves the right to do so if 
ever requested to submit a screen analysis.\160\
---------------------------------------------------------------------------

    \160\ SoCal Edison at 12.
---------------------------------------------------------------------------

    127. Several commenters request clarification of various aspects of 
the proposal. SoCal Edison requests that the Commission explain how the 
buyer is to obtain the capacity factor information, which may not 
exist, in order to convert energy-only transactions.\161\ Solomon/
Arenchild state that converting an energy-only contract to MW-
equivalents rather than the full amount of capacity may create 
confusion. Solomon/Arenchild ask whether the determining characteristic 
is whether a capacity payment is part of the long-term contract.\162\ 
NextEra expresses concerns with the formula proposed for converting 
long-term energy purchases to a capacity value.\163\ NextEra suggests 
that rather than requiring the actual energy supplied during a calendar 
year in the capacity calculation, a purchaser/seller should be allowed 
to rely on EIA regional data for energy-limited resources. NextEra 
states that otherwise there could be a significant overstatement of the 
capacity value submitted in triennial market power updates or notices 
of change in status.\164\ APPA/NRECA state that the proposed 
conversation mechanism in

[[Page 67074]]

footnote 98 of the NOPR calculates capacity as an average annual 
number, whereas the peak capacity purchased during a shorter interval 
in the study period would be the most relevant number.
---------------------------------------------------------------------------

    \161\ Id. at 17.
    \162\ Solomon/Arenchild at 10-11.
    \163\ NextEra at 9.
    \164\ Id. at 10.
---------------------------------------------------------------------------

    128. SoCal Edison states that although the NOPR proposes reporting 
of long-term firm purchases where the purchase has an associated long-
term firm transmission reservation, the concept of a long-term firm 
transmission reservation does not exist within the California 
Independent System Operator Corporation (CAISO) market. Therefore, 
SoCal Edison states that the Commission should clarify for CAISO and 
any other region that has eliminated long-term firm reservations, how 
this standard should be applied.\165\
---------------------------------------------------------------------------

    \165\ SoCal Edison at 13.
---------------------------------------------------------------------------

    129. Solomon/Arenchild ask for clarification on the treatment of 
jointly-owned facilities. They state that although the NOPR proposal 
abandons the need to determine the party that controls capacity under 
long-term contracts, the need for letter of concurrence seems to 
remain. They state that because the letter of concurrence previously 
was tied to the issue of the degree to which each party controls a 
facility, and control is no longer a factor, it is difficult to 
understand when letters of concurrence are appropriate.\166\
---------------------------------------------------------------------------

    \166\ Solomon/Arenchild at 11.
---------------------------------------------------------------------------

c. Commission Determination
    130. We adopt the proposal to report long-term firm purchases in 
the indicative screens, with modification and clarifications as 
discussed below. We believe that requiring applicants under the market-
based rate program to report all of their long-term firm purchases of 
energy and/or capacity, regardless of whether the applicant has 
operational control of the generation capacity supplying the purchased 
power, will improve the accuracy of the indicative screens.
    131. Some commenters contend that the proposed change will not make 
the screens more accurate because it may understate the market power of 
entities selling long-term firm capacity and/or energy.\167\ However, 
this argument overlooks the fact that sellers in most cases already are 
deducting capacity sold pursuant to long-term firm contracts. The 
differing standards applied to purchasers and sellers with respect to 
control are the basis for the ``disappearing capacity'' problem 
described in the NOPR. Furthermore, as explained below, the Commission 
believes that it is more appropriate to attribute such capacity to the 
purchaser rather than the seller.
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    \167\ APPA/NRECA at 24; TAPS at 2.
---------------------------------------------------------------------------

    132. We are not persuaded by SoCal Edison's arguments disputing the 
existence of a ``disappearing capacity'' problem under the current 
policy. For example, SoCal Edison claims that even if an applicant does 
not attribute a long-term firm energy and/or capacity purchase to 
itself, the associated capacity will show up in the screens as non-
affiliate capacity.\168\ This is potentially true only if the purchased 
capacity is located in the same balancing authority area or market as 
the purchaser because the non-affiliated capacity included in the 
indicative screens only includes capacity located in the study 
area.\169\ Many of the long-term purchases reported in certain regions 
cross balancing authority areas, i.e., the purchase is made from a 
resource external to the purchaser's home market. Therefore, capacity 
associated with long-term purchases often is not included in the 
indicative screens. Moreover, not reporting a long-term firm purchase 
from an external generation resource would make the screens 
inconsistent with the SILs, which account for long-term transmission 
reservations. Long-term firm purchases usually have an associated long-
term firm transmission reservation. SoCal Edison's arguments also 
ignore the problems that can arise when an applicant's long-term firm 
purchases are recorded in an incorrect line of the indicative screens, 
which the Commission noted in Vantage Wind \170\ and explained in the 
NOPR.
---------------------------------------------------------------------------

    \168\ SoCal Edison at 5.
    \169\ The indicative screens include rows for long-term firm 
sales and purchases made by non-affiliated sellers. However, the 
existence of these rows does not support SoCal Edison's argument 
because a long-term firm purchase made by SoCal Edison from a seller 
external to SoCal Edison's market (CAISO) would not show up as a 
long-term firm purchase made by a non-affiliated seller in CAISO. 
Thus, the capacity associated with the long-term firm purchase that 
SoCal Edison did not report would not show up in its indicative 
screens for the CAISO market.
    \170\ Vantage Wind, 139 FERC ] 61,063 at P 16.
---------------------------------------------------------------------------

    133. Avista/Puget proposes to fix the ``disappearing capacity'' 
problem by allowing sellers of long-term firm energy and/or capacity to 
only deduct such capacity in their indicative screens if they 
relinquish operational control over the capacity.\171\ While this 
proposal would solve the ``disappearing capacity'' problem, we find 
that it is more appropriate to attribute capacity from a long-term firm 
power purchase agreement accompanied by a long-term firm transmission 
reservation to a purchaser/load serving entity, rather than to the 
seller, because the purchaser can use that contract to meet its 
capacity requirements. The seller cannot withhold the power from the 
purchaser even though the seller has operational control over the 
generating unit(s) supplying the power. Power purchase agreements may 
give the purchaser significant economic control over the power; e.g., 
the purchaser can bid the energy into centralized spot markets (if 
present).
---------------------------------------------------------------------------

    \171\ Avista at 4.
---------------------------------------------------------------------------

    134. Moreover, applying the control test to the seller would 
largely negate the Commission's policy with respect to fully committed 
generation capacity, as described elsewhere in this Final Rule. Under 
this policy, in order to satisfy the Commission's market-based rate 
requirements regarding horizontal market power, sellers may explain 
that their generation capacity is fully committed in lieu of including 
indicative screens. Today, new generating units, many of which are wind 
and solar units, often represent that they are fully committed under 
long-term power purchase agreements and deduct all of their capacity in 
the indicative screens or do not provide screens at all. Under Avista/
Puget's proposal to assign the control test to the seller of long-term 
firm capacity, such sellers would only be able to deduct their capacity 
if they demonstrated that the purchaser had operational control of the 
generating unit. These sellers either would have to demonstrate that 
they no longer have control of their generation capacity or, if that 
was not the case, submit indicative screens. What currently are routine 
filings requesting market-based rate authority for new fully committed 
generators could in some cases become complicated.
    135. We reject Indicated Utilities' proposal to exempt applicants 
from reporting long-term firm purchases backed by intermittent or 
energy-limited qualifying facility resources.\172\ We believe that 
there is no reason to ignore such long-term firm purchases in the 
indicative screens and that Indicated Utilities' position confuses the 
operational characteristics of such resources with operational control. 
The fact that a solar or wind unit will not produce energy at certain 
times is equally true whether an applicant owns a solar or wind unit or 
purchases energy from a solar or wind unit through a long-term firm 
power purchase agreement. We clarify, however, that consistent with our 
direction elsewhere in this Final Rule, long-term firm purchases backed 
by energy-limited resources may be de-rated based on a

[[Page 67075]]

five-year average capacity factor based either on the unit's operating 
history or the EIA regional average. Providing this capacity rating 
option to applicants will yield consistent treatment of such resources 
in the indicative screens, whether owned or purchased.\173\ This 
capacity rating option also addresses NextEra's concern regarding the 
potential overstatement of capacity associated with long-term firm 
power purchase agreements in the indicative screens.
---------------------------------------------------------------------------

    \172\ IWU at 7.
    \173\ See supra Section IV.A.6.
---------------------------------------------------------------------------

    136. Regarding SoCal Edison's argument concerning the distinctions 
between owning and purchasing generation, we reiterate that, for the 
purpose of horizontal market power analyses, long-term firm power 
purchase agreements convey rights to generation capacity that are 
similar (though not identical) to ownership because they provide the 
purchaser with a resource that the purchaser can rely on to serve its 
load. The common definition of a ``firm'' purchase is a service or 
product that is not interruptible for economic reasons.\174\ This was 
the Commission's primary reason for concluding in the NOPR that a long-
term firm purchase was comparable to ownership. Such purchases provide 
a resource that a load-serving entity can count towards its capacity 
requirement. The variable nature of energy-limited resources is the 
primary reason given by SoCal Edison for disputing the NOPR's 
contention that long-term firm energy agreements provide the purchaser 
with energy that only can be interrupted for limited and specified 
reasons.\175\ However, as discussed above, the variable nature of 
certain energy-limited generators is a separate issue, and we will 
allow applicants to de-rate long-term firm power purchase agreements 
backed by energy-limited resources according to a five-year average 
capacity factor as discussed below. This will permit equivalent 
treatment of energy-limited resources in the indicative screens whether 
owned or purchased under long-term firm power purchase agreements.
---------------------------------------------------------------------------

    \174\ The EQR Data Dictionary uses this definition as well.
    \175\ SoCal Edison at 11.
---------------------------------------------------------------------------

    137. With regard to EPSA's contention that reporting of long-term 
firm power purchase agreements in the indicative screens is duplicative 
of reporting such transactions in EQRs, the indicative screens and EQRs 
perform separate functions. The former is an ex ante analysis of a 
seller's potential market power while the latter enables an ex post 
analysis of its sales. Information on long-term firm purchases and 
sales is required to complete the indicative screens. The need to 
provide this information is not ``waived'' because it also is reported 
after-the-fact in EQRs or other forms. Therefore, we affirm the need 
for applicants to report long-term firm purchases in the indicative 
screens.
    138. With respect to questions raised regarding the treatment of 
long-term firm purchases in DPT analyses, we clarify that applicants 
must attribute long-term firm power purchase agreements to the 
purchaser when the power purchase agreement has an associated long-term 
transmission reservation. An applicant that includes long-term firm 
power purchase agreements in its screens should include the same power 
purchase agreements in any DPT analyses filed to rebut the presumption 
of market power resulting from a screen failure. The fact that DPTs are 
more detailed, granular market power analyses does not negate the need 
to attribute long-term firm purchases to purchasers. We recognize that 
this may lead to inconsistencies in the treatment of long-term 
purchases between DPT analyses submitted in section 203 filings and 
those submitted in section 205 filings, but there already are several 
differences between DPT analyses filed in section 203 and 205 
proceedings (e.g., the section 203 analysis is a forward-looking 
analysis whereas the section 205 analysis is historical).
    139. We confirm that long-term firm power purchase agreements that 
are reported in the indicative screens also should be reported in the 
asset appendix, appendix B, as proposed in the NOPR. However, we agree 
with commenters that the existing appendix B is not designed to report 
long-term firm purchases, particularly those that are not backed by 
specific generating units. Therefore, the Commission is creating a 
separate sheet in appendix B specifically for applicants to report all 
long-term firm purchases included in their indicative screens. This new 
sheet to the asset appendix is described in the discussion of the asset 
appendix below.\176\
---------------------------------------------------------------------------

    \176\ See infra Section IV.D.
---------------------------------------------------------------------------

    140. With respect to the process for converting long-term firm 
energy-only contracts to MW equivalents, we provide clarification and 
have decided to modify the approach set forth in the NOPR. First, with 
respect to a question raised by Solomon/Arenchild, we clarify that such 
conversions are needed only if a capacity amount (MW) is not specified 
in the contract. Long-term firm power purchase agreements that have a 
capacity amount specified need not be converted, regardless of whether 
the contract includes a separate capacity payment.
    141. Upon consideration of the comments, we will modify the energy-
to-capacity conversion formula proposed in the NOPR. We find there is 
some merit to SoCal Edison's argument that firm energy contracts cannot 
necessarily be linked to specific generating units (although the energy 
comes from a set of generating units that ultimately can be 
identified). Thus, we are adopting an alternative conversion approach 
that is responsive to these concerns; this approach is conceptually 
similar to the approach proposed in the NOPR but uses a different 
factor--load rather than generation--to convert energy into a capacity 
value.\177\
---------------------------------------------------------------------------

    \177\ Although we are adopting an alternative approach in the 
Final Rule, the alternative approach is a logical outgrowth of the 
approach proposed in the NOPR. See Aeronautical Radio, Inc. v. FCC, 
928 F.2d 428, 445-446 (D.C. Cir. 1991) (citing United Steelworkers 
of America v. Marshall, 647 F.2d 1189, 1221 (D.C. Cir.1980), cert. 
denied, 453 U.S. 913, 101 (1981)) (holding that the notice 
requirement of section 553 of the Administrative Procedure Act is 
fulfilled ``so long as the content of the agency's final rule is a 
`logical outgrowth' of its rulemaking proposal.'').
---------------------------------------------------------------------------

    142. In place of the conversion formula set forth in the NOPR, 
applicants should use their actual load factor \178\ in the relevant 
study period to convert a long-term firm energy-only contract to a MW 
equivalent. To determine the MW equivalent, applicants should first 
determine the average MW purchased under the long-term firm energy 
contracts over the study period.\179\ Applicants should then divide the 
average MW purchased by their load factor to obtain the capacity value 
for the contract.
---------------------------------------------------------------------------

    \178\ Load factor is the average load divided by the peak load 
in a specified time period. For example, if during a calendar year a 
franchised public utility has a peak load of 2,000 MW and total 
sales to native load customers of 10,000,000 MWh, its load factor is 
[(10,000,000/8760)/2000] = 0.57 or 57 percent.
    \179\ Average MW equals total MWh purchased during the study 
period divided by the total hours in the study period.
---------------------------------------------------------------------------

    143. Long-term firm energy contracts serve the purchaser's load for 
a term of at least one year, so the purchaser's load factor is a 
reasonable basis to establish the capacity value of a long-term firm 
energy contract. This approach also avoids the need to calculate a 
capacity factor and link the purchase back to a generating unit or set 
of generating units. Applicants have ready access to their load data so 
performing this conversion should not be problematic or burdensome.
    144. Applicants would continue to have the option of proposing a 
different method of attributing capacity based on

[[Page 67076]]

the specific terms and conditions of their power purchase agreement. 
Any alternative attribution method would have to be fully supported and 
justified.
    145. We provide several clarifications to the reporting of long-
term firm power purchase agreements. First, we clarify that an 
applicant should report a long-term firm purchase of capacity and/or 
energy that has an associated long-term firm transmission reservation 
for either point-to-point or network transmission service. In addition, 
we clarify that this requirement applies regardless of whether the 
long-term firm transmission reservation is held by the purchaser or 
seller of the capacity/energy. In response to SoCal Edison's query, we 
clarify that the requirement that applicants only include long-term 
firm power purchase agreements in their indicative screens if they have 
an associated long-term transmission reservation will not apply within 
an RTO/ISO market if that RTO/ISO does not have long-term firm 
transmission reservations or their equivalent. Instead, applicants in 
such RTO/ISO markets will be required to report all long-term firm 
energy and/or capacity purchases from generation capacity located 
within the RTO/ISO market if the generation is a designated as a 
network resource or as a resource with capacity obligations. We further 
clarify that letters of concurrence will not be required to establish 
which party to a long-term firm power purchase agreement has control of 
the underlying generation resource(s).\180\
---------------------------------------------------------------------------

    \180\ However, sellers may need to submit a letter of 
concurrence to support claims that they do not own or control the 
entire capacity of a generation facility. See Order No. 697, FERC 
Stats. & Regs. ] 31,252 at P 187.
---------------------------------------------------------------------------

8. Clarification of Commission Language in Performing SIL Studies
    146. The SIL study is used in both the indicative screens and the 
DPT analysis as the basis for establishing the amount of power that can 
be imported into the relevant geographic market.\181\ In the NOPR, the 
Commission summarized previous Commission SIL guidance to transmission 
operators provided in the April 14 Order, Puget, and Order No. 697. The 
Commission noted that the April 14 Order requires that power flow 
benchmark cases reasonably simulate the historical conditions that were 
present \182\ and requires that sellers consider ``all internal/
external contingency facilities and all monitored/limiting facilities 
that were used historically to approximate area-area transmission 
availability'' and utilize scaling methods according to the same 
methods used historically for non-affiliate resources.\183\
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    \181\ Id. P 19.
    \182\ Historical conditions include ``facility/line deratings 
used to maintain capacity benefit margins (CBM) and transmission 
reliability (TRM/CBM), actual unit dispatch used to fulfill network 
and firm reservation obligation, the actual peak demand, generator 
operating limits opposed on all resources in real time, other 
limits/constraints imposed by the TP [Transmission Provider] during 
the season peaks.'' April 14 Order, 107 FERC ] 61,018 at app. E.
    \183\ NOPR, FERC Stats. & Regs. ] 32,702 at PP 147, 151 (citing 
April 14 Order, 107 FERC ] 61,018 at app. E).
---------------------------------------------------------------------------

    147. In the NOPR, the Commission noted that Puget clarified that 
sellers must ``[p]rovide copies of all Operating Guide descriptions 
that were applied in the scaling section,'' as well as any operating 
guides used to ignore limiting elements in the SIL study results.\184\ 
The Commission also stated that applicants must exclude study area non-
affiliated load from study area native load, and should not include 
first-tier generation serving study area non-affiliated load in net 
area interchange. In addition, the Commission specified that applicants 
must document all instances where the SIL study differs from historical 
practices.\185\
---------------------------------------------------------------------------

    \184\ Id. P 150 (citing Puget, 135 FERC ] 61,254 at app. B, 
Reporting Requirements for Submittals 8, 9).
    \185\ Id. (citing Puget, 135 FERC ] 61,254 at app. B, Reporting 
Requirements for Submittals 10 and 11).
---------------------------------------------------------------------------

    148. In the NOPR, the Commission also noted the Commission's 
finding in Order No. 697 that SIL studies performed by sellers ``should 
not deviate from'' and ``must reasonable[ly] reflect'' the seller's 
Open Access Same-Time Information System (OASIS) operating practices 
and ``techniques used must have [been] historically available to 
customers.'' \186\ The Commission further stated that ``by OASIS 
practices, we mean sellers shall use the same OASIS methods and studies 
used historically by sellers (in determining simultaneous operational 
limits on all transmission lines and monitored facilities) to estimate 
import limits from aggregated first-tier control areas into the study 
area.'' \187\ Furthermore, the Commission stated that Order No. 697 
requires that power flow cases ``represent the transmission provider's 
tariff provisions and firm/network reservations held by seller/
affiliate resources during the most recent seasonal peaks.'' \188\
---------------------------------------------------------------------------

    \186\ Id. P 146 (citing Order No. 697, FERC Stats. & Regs. ] 
31,252 at P 354 (internal citations omitted)).
    \187\ Id. P 146 (citing Order No. 697, FERC Stats. & Regs. ] 
31,252 at P 354 n.361).
    \188\ Id. P 152 (citing Order No. 697, FERC Stats. & Regs. ] 
31,252 at P 354); see also Puget, 135 FERC ] 61,254 at P 15 (``Long-
term firm transmission reservations for applicant/affiliate 
generation resources that serve study area load reduce the amount of 
study are transmission capability available to potential 
competitors.'').
---------------------------------------------------------------------------

    149. The Commission noted that Order No. 697 allows the use of 
simultaneous total transfer capability (simultaneous TTC) values in 
performing SIL studies ``provided that these TTCs are the values that 
are used in operating the transmission system and posting availability 
on OASIS.'' \189\ The Commission requires sellers to provide evidence 
that simultaneous TTC values account for simultaneity, internal and 
first-tier external transmission limitations, and transmission 
reliability margins.\190\
---------------------------------------------------------------------------

    \189\ NOPR, FERC Stats. & Regs. ] 32,702 at P 155 (quoting Order 
No. 697, FERC Stats. & Regs. ] 31,252 at P 364).
    \190\ Id.; see also Order No. 697-A, FERC Stats. & Regs. ] 
31,268 at P 142 (clarifying that ``the use of simultaneous TTC 
values in the SIL study must properly account for all firm 
transmission reservations, transmission reliability margin, and 
capacity benefit margin.'').
---------------------------------------------------------------------------

    150. In the NOPR, the Commission proposed to clarify several issues 
about how to perform SIL studies and the associated Submittals 1 and 2 
found on the Commission's Web site.\191\ In particular, the Commission 
proposed to clarify issues relating to what is included in OASIS 
practices, how to deal with conflicts between OASIS practices and the 
Commission directions provided in Appendix B of Puget, and the correct 
load value to use in the SIL study.
---------------------------------------------------------------------------

    \191\ 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.''
---------------------------------------------------------------------------

    151. The Commission stated that the purpose of the SIL study is to 
calculate the total simultaneous import capability available to first-
tier uncommitted generation resources, while also considering system 
limitations and existing resource commitments (i.e., long-term firm 
transmission reservations).\192\ Therefore, the methodology a 
transmission provider uses to calculate simultaneous TTC values \193\ 
must be consistent with the methodology it uses for calculating and 
posting available transfer capability (ATC) \194\ and for evaluating 
firm transmission service requests, consistent with Commission policy 
and precedent.\195\ The Commission stated that import capability 
available to a transmission provider during real-time operations should 
not be included in

[[Page 67077]]

the transmission provider's SIL value if such transmission import 
capability is not available to non-affiliated uncommitted generation 
resources requesting long-term firm transmission service.\196\
---------------------------------------------------------------------------

    \192\ NOPR, FERC Stats. & Regs. ] 32,702 at P 158.
    \193\ See row 4 of proposed Submittal 1 (Total Simultaneous 
Transfer Capability).
    \194\ In the NOPR, FERC Stats. & Regs. ] 32,702 at P 25, ATC was 
inadvertently defined as ``available transmission capability''; it 
should have been ``available transfer capability.'' See Order No. 
697-A, FERC Stats. & Regs. ] 31,268 at P 57.
    \195\ NOPR, FERC Stats. & Regs. ] 32,702 at P 158.
    \196\ Id.
---------------------------------------------------------------------------

a. OASIS Practices
i. Commission Proposal
    152. In the NOPR, the Commission proposed to clarify that the term 
``OASIS practices'' refers specifically to the seasonal benchmark power 
flow case modeling assumptions, study solution criteria,\197\ and 
operating practices historically used by the first-tier and study area 
transmission providers \198\ to calculate and post ATC and to evaluate 
requests for firm transmission service.\199\
---------------------------------------------------------------------------

    \197\ Study solution criteria may include but are not limited to 
distribution factor thresholds, transformer tap adjustments, 
reactive power limits, transmission equipment ratings, and model 
solution settings. Id. P 159 n.169.
    \198\ We reiterate that, while entities may not be familiar with 
all of the OASIS practices of transmission providers in first-tier 
balancing authority areas, they should at least be familiar with 
major constraints, path limits, and delivery problems in neighboring 
transmission systems. Id. P 159 n.170 (citing Order No. 697, FERC 
Stats. & Regs ] 31,252 at P 354 n.361).
    \199\ The interruptible nature of non-firm transmission service 
makes using these practices an inappropriate means of calculating 
the study area's SIL value. Id. P 161 n.171.
---------------------------------------------------------------------------

    153. The Commission also proposed to clarify that in performing a 
SIL study, the transmission provider must utilize its OASIS practices 
consistent with the administration of its tariff. The seasonal 
benchmark power flow cases submitted with a SIL study should represent 
historical operating practices only to the extent that such practices 
are available to customers requesting firm transmission service. For 
example, if the transmission provider does not allow the use of an 
operating guide when evaluating firm transmission service requests, the 
transmission provider should not use the operating guide when 
calculating SIL values.\200\
---------------------------------------------------------------------------

    \200\ By ``operating guide'' we generally refer to the North 
American Electric Reliability Corp. (NERC)-defined term ``Operating 
Procedure,'' which is defined as ``a document that identifies 
specific steps or tasks that should be taken by one or more specific 
operating positions to achieve specific operating goal(s).'' See 
NERC, Glossary of Terms Used in NERC Reliability Standards 53 
(2014), http://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf. In the SIL study context, this may include 
switching procedures, special protection systems, load throw-over 
schemes, temporary transmission line rating changes, and other 
actions that are not typically represented in the seasonal benchmark 
power flow models. NOPR, FERC Stats. & Regs. ] 32,702 at P 161 
n.172.
---------------------------------------------------------------------------

ii. Commission Determination
    154. There were no comments on the above proposals. Therefore, we 
adopt the proposals as set forth in the NOPR to clarify that the term 
``OASIS practices'' refers specifically to the seasonal benchmark power 
flow case modeling assumptions, study solution criteria, and operating 
practices historically used by the first-tier and study area 
transmission providers to calculate and post ATC and to evaluate 
requests for firm transmission service, and to clarify that in 
performing a SIL study, the transmission provider must utilize its 
OASIS practices consistent with the administration of its tariff. We 
believe these clarifications will improve consistency between the 
methodology a transmission provider uses to calculate SIL values and 
the methodology it uses for calculating and posting ATC and for 
evaluating transmission service requests.
b. SIL Studies and OASIS Practices
i. Conflicts Between OASIS Practices and Puget
(a) Commission Proposal
    155. In the NOPR, the Commission proposed several clarifications 
for instances when the methodology a transmission provider uses to 
calculate SIL values is inconsistent with the methodology the 
transmission provider uses for calculating and posting ATC and for 
evaluating transmission service requests. The Commission proposed to 
clarify that where there is a conflict between OASIS practices and the 
Commission directions provided in Appendix B of Puget, sellers should 
follow OASIS practices except as noted in the NOPR. The Commission 
reminded sellers that, in instances where actual OASIS practices differ 
from the SIL direction provided in Puget, sellers should use actual 
OASIS practices and provide documentation specifically identifying such 
practices.\201\ The Commission also proposed to clarify that, to the 
extent that a seller's SIL study departs from actual OASIS 
practices,\202\ such departures are only permitted where use of actual 
OASIS practices is incompatible with an analysis of import capability 
from an aggregated first-tier area.\203\ The Commission invited 
comments identifying potential areas where actual OASIS practices may 
be incompatible with the performance of SIL studies.
---------------------------------------------------------------------------

    \201\ NOPR, FERC Stats. & Regs. ] 32,702 at P 162 n.173 (citing 
Order No. 697, FERC Stats. & Regs. ] 31,252 at P 356).
    \202\ See Puget, 135 FERC ] 61,254 at app. B.
    \203\ NOPR, FERC Stats. & Regs. ] 32,702 at P 162.
---------------------------------------------------------------------------

    156. The Commission also reminded sellers that the calculated SIL 
value should account for any limits defined in the tariff, such as 
stability or voltage.\204\ For example, if a seller utilizes a direct 
current analysis when performing a SIL study, but an alternating 
current analysis when evaluating transmission service requests, the 
seller must validate the total aggregate transfer level value, 
consistent with the transmission provider's OASIS practices, if modeled 
using an alternating current load flow model.\205\
---------------------------------------------------------------------------

    \204\ Id. P 163 n.175 (citing Order No. 697, FERC Stats. & Regs. 
] 31,252 at P 346).
    \205\ Id. P 163 n.176 (citing Pinnacle West Capital Corporation, 
117 FERC ] 61,316, at P 11 n.19 (2006) (``The resulting loading and 
voltages for the limiting cases, if derived from DC (direct current) 
load flow analysis would have been verified by AC (alternating 
current) load flow analysis and demonstrated to be within the 
applicable system operating limits as dictated by thermal, voltage 
or stability considerations to ensure system reliability. The 
Commission requires that such comparisons be included in the 
applicant's working papers that are submitted to the Commission.'').
---------------------------------------------------------------------------

    157. The Commission also reiterated that sellers may use a load 
shift methodology to perform a SIL study if they use a load shift 
methodology in their OASIS practices, ``provided they submit adequate 
support and justification for the scaling factor used in their load 
shift methodology and how the resulting SIL number compares had the 
company used a generation shift methodology.'' \206\
---------------------------------------------------------------------------

    \206\ Id. P 164 n.177 (quoting Order No. 697-A, FERC Stats. & 
Regs. ] 31,268 at P 145).
---------------------------------------------------------------------------

    158. Regarding accounting for long-term firm transmission 
reservations for generation resources that serve study area load, the 
Commission proposed to clarify that sellers must reduce the 
simultaneous TTC value \207\ by subtracting all long-term firm import 
transmission reservations, including reservations held by non-
affiliated sellers.\208\ The Commission noted that it has already 
provided guidance with respect to accounting for long-term firm 
transmission reservations into the study area from affiliated 
generation resources located outside the study area.\209\ The 
Commission stated that proposed revised appendix A--Standard Screen 
Format accounts for all long-term firm

[[Page 67078]]

import transmission reservations into the study area.\210\ The 
Commission also proposed revisions to Submittal 2 to account for these 
non-affiliate long-term firm transmission reservations to ensure that 
the determination of the SIL value is consistent with the method used 
to allocate this value to uncommitted generation capacity in the 
aggregated first-tier area for the indicative screens.\211\
---------------------------------------------------------------------------

    \207\ The revised Standard Screen Format (e.g., rows B1 and M1 
in the market share screen (Long-Term Firm Purchases (from outside 
the study area))) must reflect the long-term firm reservations from 
Submittal 1, Table 1, row 5 of Puget. Puget, 135 FERC ] 61,254 at 
app. B.
    \208\ See NOPR, FERC Stats. & Regs. ] 32,702 at P 165 n.179 
(citing revised app. E, Submittal 1, row 5).
    \209\ Id. P 165 n.180 (citing Puget, 135 FERC ] 61,254 at P 15).
    \210\ Id. P 165 & n.182 (citing to revised app. A, Standard 
Screen Format, specifically rows A1, B1, E1 and F1 in the market 
share screen and rows A1, B1, L1, and M1 in the pivotal supplier 
screen).
    \211\ Id. P 165.
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(b) Comments
    159. Solomon/Arenchild agree with the Commission's proposal to 
continue the requirement that SIL studies follow OASIS practices. 
Southeast Transmission Owners, however, state they are concerned that 
the Commission's proposal to require sellers to ``subtract all long-
term firm import transmission reservations, including reservations held 
by non-affiliated sellers, from the simultaneous TTC value'' could 
yield a misleading conclusion regarding market activity within a given 
area. According to Southeast Transmission Owners, the possession by a 
non-affiliate of a long-term transmission reservation across a seller's 
interface that sinks in the seller's home balancing authority area is 
an indicator of an open market, representing a decision by a competitor 
and the ability of that competitor to compete for load in the 
particular balancing authority area. Southeast Transmission Owners 
assert that, while the components of the screen inclusive of the SIL 
may yield a mathematically accurate result, the tabular depiction of 
the availability of transmission capacity for use by non-affiliates, as 
proposed in the NOPR, becomes complicated and misleading and results in 
the market appearing more constrained than it really is. Southeast 
Transmission Owners urge the Commission to forego adoption of this 
proposal and not require deduction of long-term reservations held by 
non-affiliates of the seller. Instead, Southeast Transmission Owners 
ask that the Commission adopt an approach that appropriately reflects 
marketplace activity and the availability of transmission capacity to 
non-affiliates. However, if the Commission proceeds with this proposal, 
then Southeast Transmission Owners urge that the Commission recognize 
the ability of sellers, when performing a SIL study and the associated 
screens, to rebut the results through companion sensitivities and other 
data that show how the utilization of import capability by non-
affiliates is indicative of a competitive marketplace.\212\
---------------------------------------------------------------------------

    \212\ Duke Energy Carolinas, LLC, Duke Energy Progress, Inc., 
Louisville Gas and Electric Co., Kentucky Utilities Co., South 
Carolina Electric and Gas Co., and Southern Companies Services, 
Inc., acting as agent for Alabama Power Co., Georgia Power Co., Gulf 
Power Co., and Mississippi Power Co. (Southern Companies) 
(collectively, Southeast Transmission Owners) at 3.
---------------------------------------------------------------------------

(c) Commission Determination
    160. We clarify that, where there is a conflict between the 
transmission provider's tariff or OASIS practices and the Commission 
directions specified in Puget for performing SIL studies, sellers, 
except as noted below, should follow OASIS practices and provide 
documentation specifically identifying such practices.\213\
---------------------------------------------------------------------------

    \213\ See Order No. 697, FERC States. & Regs. ] 31,252 at P 356.
---------------------------------------------------------------------------

    161. We adopt the proposal that, to the extent that a seller's SIL 
study departs from actual OASIS practices, such departures are only 
permitted where use of actual OASIS practices is incompatible with an 
analysis of import capability from an aggregated first-tier area. The 
calculated SIL value should account for any limits defined in the 
tariff, such as stability and voltage.\214\ Sellers may use a load 
shift methodology to perform a SIL study if they use a load shift 
methodology in their OASIS practices, provided they submit adequate 
support and justification for the scaling factor used in their load 
shift methodology and show how the resulting SIL values compare to 
those that would be obtained if the seller used a generation shift 
methodology.\215\
---------------------------------------------------------------------------

    \214\ Id. P 346.
    \215\ Order No. 697-A, FERC States. & Regs. ] 31,268 at P 145.
---------------------------------------------------------------------------

    162. We also adopt the proposal to direct sellers to subtract all 
long-term firm import transmission reservations (including those held 
by non-affiliated sellers) from the simultaneous TTC and historical 
peak load values. Finally, we adopt the proposed revisions to Submittal 
2 to account for these non-affiliate long-term firm transmission 
reservations. We note that the adopted Submittals 1 and 2 spreadsheet 
has an additional row in Submittal 2 for each non-affiliated long-term 
firm transmission reservation to more clearly illustrate that each 
transaction should be reported separately. There is also an additional 
row in the adopted spreadsheet in Submittal 2 for each power purchase 
agreement for the same reason.\216\
---------------------------------------------------------------------------

    \216\ Though the spreadsheet published in the NOPR did not 
contain these additional rows, the original instructions for 
Submittal 2 published in Appendix B of Puget and the proposed 
spreadsheet posted on the Commission's Web site each had the 
instruction to insert ``as many rows as necessary'' to report each 
power purchase agreement. Finally, the descriptive text in rows 2 
and 6 of Submittal 2 has been changed to ``Power Purchase 
Agreement'' instead of ``Purchased Power Agreement'' to be 
consistent with this nomenclature as used elsewhere in this Final 
Rule.
---------------------------------------------------------------------------

    163. In response to Southeast Transmission Owners, we find that 
reducing the simultaneous TTC value and historical peak load value by 
long-term firm transmission reservations held by both affiliates and 
non-affiliates properly accounts for all import capability used to 
serve affiliated and non-affiliated load in the study area. This 
provides an accurate measure of the study area's load and import 
capability that is not available to uncommitted generation capacity in 
the first-tier area. We note that such reservations are properly 
accounted for in the indicative screens and that treating all long-term 
firm transmission reservations in a consistent manner should reduce 
confusion rather than increase it. With respect to Southeast 
Transmission Owners' request that the Commission recognize the ability 
of sellers to rebut SIL study results through companion sensitivities, 
we note that sellers ``[m]ay submit additional sensitivity studies, 
including a more thorough import study as part of the DPT. We reaffirm, 
however, that any such sensitivity studies must be filed in addition 
to, and not in lieu of, a SIL study.'' \217\
---------------------------------------------------------------------------

    \217\ Order No. 697-A, FERC States. & Regs. ] 31,268 at P 146.
---------------------------------------------------------------------------

ii. Wheel-Through Transactions
(a) Commission Proposal
    164. The Commission proposed to clarify that sellers must account 
for wheel-through transactions where such transactions are used to 
serve a non-affiliated load that is embedded within a study area. 
Specifically, the Commission proposed that the seller reduce the 
simultaneous TTC value by subtracting the value of all wheel-through 
transactions. The Commission observed that while wheel-through 
transactions are not used to serve study area load, they reduce the 
amount of transmission capability available to first-tier generators 
competing to serve study area load. Thus, the Commission proposed that 
these transactions be accounted for as long-term firm import 
transmission reservations and reported

[[Page 67079]]

in Submittal 2 and proposed corresponding changes to Submittal 2.
(b) Comments
    165. Solomon/Arenchild state they do not understand the rationale 
and intent of the proposal to include wheel-through transactions as a 
deduction to the amount of transmission capability available to first-
tier generators to serve study area load. According to Solomon/
Arenchild, wheel-through reservations generally do not reduce overall 
import capability because the import schedule nets out against the 
subsequent export schedule and that such reservations are not used to 
serve load in the balancing authority area. Southeast Transmission 
Owners voice similar concerns about the Commission's proposal regarding 
wheel through transactions.\218\ According to Southeast Transmission 
Owners, this proposal results in an inequitable reduction of a seller's 
SIL that is not indicative of actual marketplace activity. Further, 
Southeast Transmission Owners state that, in their experience, 
transmission operators use the term wheel through transaction to 
describe transactions that are imported into, and then exported out of, 
their particular areas of operation, thereby not serving load in that 
study area. Southeast Transmission Owners are unclear what transactions 
the NOPR would purport to capture by this new requirement and whether a 
wheel through transaction under the NOPR must in fact be supported by a 
long-term firm reservation.
---------------------------------------------------------------------------

    \218\ Southeast Transmission Owners at 4 (citing NOPR, FERC 
Stats. & Regs. ] 32,702 at P 166).
---------------------------------------------------------------------------

    166. Southeast Transmission Owners are concerned that the proposal 
may cause confusion among sellers, result in the capture of 
transactions that are beyond the intended scope, and contribute to less 
reliable SIL values. Given these concerns over the Commission's 
proposal, Southeast Transmission Owners request that the Commission (1) 
clarify or elaborate what it means by wheel through transactions 
sinking in the seller's area, and (2) limit this new requirement to 
this category of transactions that are supported by long-term firm 
reservations held by the seller and its affiliates.
(c) Commission Determination
    167. We agree with commenters' interpretation of the term wheel-
through to mean long-term firm transmission reservations that enter and 
exit a study area, but do not serve load in that study area. While a 
wheel-through transaction is still considered to be reserved capability 
on transmission lines similar to other long-term firm transmission 
reservations, a traditional wheel-through does not serve a study area's 
Historical Peak Load and, as such, should not be recognized as a long-
term firm transmission reservation for the purposes of the SIL study. 
Accordingly, we clarify that the NOPR should have instead used the 
terminology ``wheel-into,'' which refers to a long-term firm 
transmission reservation that enters a study area and serves non-
affiliated load embedded in that study area. Thus, we make this 
distinction to clarify these terms in the Final Rule, and to adopt the 
NOPR proposal to apply to wheel-into transactions rather than to wheel-
through transactions.
    168. Further, we clarify that wheel-into or other similarly related 
import transactions supported by first-tier, long-term firm 
transmission reservations used to serve non-affiliated load embedded 
within the study area are to be accounted for in a consistent manner, 
and the seller should reduce the simultaneous TTC value and historical 
peak load value by subtracting the value of all these 
transactions.\219\
---------------------------------------------------------------------------

    \219\ In Submittal 1, Long-Term Firm Transmission Reservations 
(row 5) are deducted from Total Simultaneous Transfer Capability 
(row 4) to yield the Calculated SIL Value (row 6). The Calculated 
SIL Value is compared to Adjusted Historical Peak Load (row 8) and 
Uncommitted First-Tier Generation (row 9) to determine the SIL Study 
Value (row 10), which is limited by those two values.
---------------------------------------------------------------------------

    169. Additionally, while import and export transactions may net out 
for the purpose of calculating net area interchange, the Commission 
does not net out such long-term firm transmission reservations that are 
used to serve non-affiliated load embedded within the study area. 
Finally, we refine our proposed language in row 3 and row 7 in 
Submittal 2 to remove any potential confusion with the use of the term 
``wheel-through'' to read, ``Transaction to serve non-affiliated, load 
embedded in the study area using external generation.''
iii. Preferred Approach for Treating Controllable Tie Lines
(a) Proposal
    170. The Commission proposed to clarify that, where a first-tier 
market or balancing authority area is directly interconnected to the 
study area only by controllable tie lines \220\ and is not 
interconnected to any other first-tier market or balancing authority 
area, sellers should follow their OASIS practices regarding calculation 
and posting of ATC for such areas. If sellers' OASIS practices are 
incompatible with the SIL study (e.g., ATC is based on tie line 
rating), sellers may use an alternative process to account for import 
capability for such tie lines.\221\ The Commission also proposed to 
clarify that, in such circumstances, it will be presumed reasonable to 
model a controllable tie line as a single equivalent first-tier 
generator connected to the study area by a radial line. The Commission 
stated that sellers should document any instances where modeling of 
controllable tie lines deviates from OASIS practices, and explain such 
deviations, including: how tie line flow is accounted for in the net 
area interchange calculations; how tie line flow is scaled or otherwise 
controlled when calculating simultaneous incremental transfer 
capability; and how long-term firm transmission reservations are 
accounted for over controllable tie lines.\222\
---------------------------------------------------------------------------

    \220\ Controllable tie lines include direct current (DC) 
transmission facilities and alternating current (AC) transmission 
facilities with the ability to control the magnitude and direction 
of power flows through equipment such as converters, phase shifting 
transformers, variable frequency transformers, etc.
    \221\ NOPR, FERC Stats. & Regs. ] 32,702 at P 167.
    \222\ Id.
---------------------------------------------------------------------------

(b) Comments
    171. Solomon/Arenchild seek clarification of the preferred approach 
for treating controllable tie lines. According to Solomon/Arenchild, 
there are two reasonable options for treating such lines with regard to 
the Commission's proposal that SIL studies for markets ``directly 
connected to the study area [first-tier] only by controllable tie 
lines'' should follow OASIS practices regarding calculation and posting 
of ATC.\223\ Using a market that has an high-voltage direct current 
(HVDC) tie of 200 MW as an example, Solomon/Arenchild state that one 
option for treating such lines is that the SIL study could include a 
200 MW generator inside the balancing authority area being analyzed, 
assigning any share of the generation to the holder of long-term 
reservations on the HVDC tie, if any. Another option is that the SIL 
study could treat the HVDC tie as a 200 MW generator outside of the 
balancing authority area being analyzed but include it as part of the 
aggregated generation in the first-tier area.
---------------------------------------------------------------------------

    \223\ Solomon/Arenchild at 12 (quoting NOPR, FERC Stats. & Regs. 
] 32,702 at P 167).
---------------------------------------------------------------------------

(c) Commission Determination
    172. We clarify that, for purposes of performing market power 
studies for market-based rate authorization, where a first-tier market 
or balancing authority area is directly interconnected to the

[[Page 67080]]

study area only by controllable tie lines and is not interconnected to 
any other first-tier market or balancing authority area, sellers should 
follow their OASIS practices for calculation and posting of ATC for 
such areas.\224\ However, if a seller's OASIS practices are 
incompatible with the SIL study (e.g., ATC is based on tie line 
rating), the seller may use an alternative process to account for 
import capability for such tie lines.
---------------------------------------------------------------------------

    \224\ Controllable tie lines are transmission facilities with 
associated equipment enabling control of the magnitude and direction 
of power flows over the facility. One example of a controllable tie 
line is the Cross Sound Cable, which connects the New England and 
New York markets.
---------------------------------------------------------------------------

    173. In such circumstances where a seller's OASIS practices are 
incompatible with the SIL study, sellers shall not model a controllable 
tie line as a radial line connected to an equivalent study area 
generator, as proposed by Solomon/Arenchild, as this leads to potential 
SIL study errors when scaling generation. However, for purposes of 
calculating the SIL value and consistent with the NOPR proposal, where 
a first-tier market or balancing authority area is directly 
interconnected to the study area only by controllable tie lines, each 
controllable tie line shall be modeled as a radial line connecting the 
study area to a first-tier area generator located in the first-tier 
area, and may be scaled as first-tier area generation. For the purposes 
of allocating SIL values to aggregate uncommitted first-tier generation 
capacity, sellers must consider actual uncommitted generation capacity 
in each first-tier area, rather than the capability of the controllable 
tie line.
iv. Treatment of Controllable Merchant Lines
(a) Commission Proposal
    174. The Commission stated that in the NOPR that, to the extent 
that the study area is directly interconnected to first-tier areas by 
controllable merchant transmission lines (e.g., Linden VFT), sellers 
should properly account for capacity rights on such lines. If sellers 
hold long-term capacity rights on such lines, these rights should be 
accounted for as long-term firm transmission reservations. If sellers 
lack sufficient knowledge regarding the existence and attributes of 
capacity rights on controllable merchant lines, sellers shall assume 
the full capacity of such lines is held by sellers with long-term firm 
transmission reservations.\225\
---------------------------------------------------------------------------

    \225\ NOPR, FERC Stats. & Regs. ] 32,702 at P 168.
---------------------------------------------------------------------------

(b) Comments
    175. Solomon/Arenchild note their confusion as to controllable 
merchant lines and the Commission's statement that, ``[i]f sellers lack 
sufficient knowledge regarding the existence and attributes of capacity 
rights on controllable merchant lines, they shall assume the full 
capacity of such lines is held by sellers with long-term firm 
transmission reservations.'' \226\ Solomon/Arenchild ask why these 
long-term firm transmission rights should be treated any differently 
than any other transmission reservations. Additionally, they ask 
whether the reference to ``sellers'' with long-term firm transmission 
rights really is a reference to transmission right holders as opposed 
to the ``sellers'' filing the screens. Further, Solomon/Arenchild seek 
clarification that the Commission's intent is to reflect the full 
amount of the controllable merchant line capacity in determining the 
total size of the market.\227\
---------------------------------------------------------------------------

    \226\ Solomon/Arenchild at 12; NOPR, FERC Stats. & Regs. ] 
32,702 at P 168.
    \227\ Solomon/Arenchild at 12-13.
---------------------------------------------------------------------------

(c) Commission Determination
    176. We clarify in response to the question asked by Solomon/
Arenchild that the reference to ``sellers'' was intended to be a 
generic reference to transmission right holders and not to apply to the 
seller submitting the study.
    177. SIL values are net of long-term firm transmission reservation. 
We find that capacity rights on controllable merchant lines are 
comparable to long-term firm transmission reservations and should be 
deducted from the Total Simultaneous Transfer Capability value and 
Historical Peak Load value. Capacity rights on controllable merchant 
lines represent import capability that is only available to a specific 
transmission customer pursuant to the Commission's policies for 
merchant transmission, and is therefore not generally available to any 
uncommitted generator in the first-tier area. In the past, some sellers 
have treated controllable merchant transmission lines as if such lines 
were available to import generation into the study area. Such treatment 
is inconsistent with the merchant transmission model. However, sellers 
should be able to determine whether merchant transmission lines are 
subscribed given the requirement that merchant transmission developers 
disclose the results of their capacity allocation process.\228\ 
However, where the seller is unaware of the terms and conditions for 
third-party capacity rights on controllable merchant lines, the seller 
must make a conservative assumption and subtract from the Total 
Simultaneous Transfer Capability and Historical Peak Load values the 
full capacity of the controllable merchant line as a long-term firm 
transmission reservation. We find this to be a reasonable assumption as 
the capacity on controllable merchant lines typically is fully 
subscribed.\229\ This approach ensures that such capacity rights on 
controllable merchant transmission lines are treated in a comparable 
manner to long-term firm transmission reservations.
---------------------------------------------------------------------------

    \228\ See Allocation of Capacity on New Merchant Transmission 
Projects and New Cost-Based, Participant-Funded Transmission 
Projects Priority Rights to New Participant-Funded Transmission, 142 
FERC ] 61,038 (2013).
    \229\ This assumes that the capacity of the merchant tie line is 
included in the net area interchange value as well, such that the 
net impact on the SIL value is zero.
---------------------------------------------------------------------------

v. Inclusion of All Load Data
(a) Commission Proposal
    178. In the NOPR, the Commission proposed to require sellers to 
include all load associated with balancing authority area(s) within the 
study area. The Commission stated that the SIL study is ``intended to 
provide a reasonable simulation of historical conditions'' and is not 
``a theoretical maximum import capability or best import case 
scenario.'' \230\ The Commission noted that the SIL study ``is a study 
to determine how much competitive supply from remote resources can 
serve load in the study area.'' \231\ In the NOPR, the Commission noted 
the clarification in Puget that sellers should not report study area 
non-affiliated load as study area native load, and should adjust 
modeled net area interchange by the same amount.\232\ The Commission 
stated that the exclusion of all study area non-affiliated load may 
result in SIL values that are inconsistent with the intent of the 
indicative screens. Furthermore, in the event the SIL value is limited 
by study area load, restricting study area load to affiliated load 
fails to account for import capability that may be used to serve 
wholesale load customers. The Commission stated that sellers should 
only adjust the reported value for modeled net area interchange to 
account for first-tier generation serving load associated with a first-
tier balancing authority area that is modeled

[[Page 67081]]

as part of the study area.\233\ To ensure Submittal 1 is consistent 
with these requirements, the Commission proposed to revise row 8 to 
read ``Adjusted Historical Peak Load'' (instead of ``Study area 
adjusted native load'').
---------------------------------------------------------------------------

    \230\ NOPR, FERC Stats. & Regs. ] 32,702 at P 169 (quoting Order 
No. 697, FERC Stats. & Regs. ] 31,252 at P 354).
    \231\ Id. (quoting Order No. 697, FERC Stats. & Regs. ] 31,252 
at P 361).
    \232\ Id. (citing Puget, 135 FERC ] 61,254 at app. B).
    \233\ Id. (citing Order No. 697, FERC Stats. & Regs. ] 31,252 at 
P 169 n.186 (``If the load is modeled as part of another area, i.e., 
as a non-area load attached to an area bus, and the net area 
interchange calculation includes both tie lines and non-area loads 
attached to area buses, net area interchange associated with service 
to such load should be approximately zero, and no adjustment will be 
necessary.'')).
---------------------------------------------------------------------------

(b) Comments
    179. Solomon/Arenchild and Southeast Transmission Owners agree with 
the Commission's proposal that sellers include in SIL studies all load 
associated with balancing authority area(s) within the study area, with 
sellers' specific load obligations accounted for in the indicative 
screen analysis. However, Idaho Power contends that the Commission's 
proposal prevents an accurate accounting for a fraction of non-
affiliate load that is served by non-affiliate generation when both are 
located in the study area. Further, Idaho Power argues that the 
proposal to include both affiliate and all non-affiliate load in the 
definition of Historical Peak Load means that any remaining amount of 
non-affiliate load not served by non-affiliate generation in the study 
area would be included in long-term firm transmission reservations, 
which would reduce the simultaneous TTC value by this fraction of non-
affiliate load. According to Idaho Power, this would lead to the 
fraction of the non-affiliate load served by internal non-affiliate 
generation incorrectly appearing as affiliate load.\234\
---------------------------------------------------------------------------

    \234\ Idaho Power at 4-5.
---------------------------------------------------------------------------

(c) Commission Determination
    180. We adopt the proposal to require sellers to include in the SIL 
studies all load associated with balancing authority area(s) within the 
study area. With regard to Idaho Power's argument regarding 
consideration of study area non-affiliate load served by non-affiliate 
generation, we first note that study area non-affiliate load not served 
by study area non-affiliate generation would only appear as a long-term 
firm transmission reservation when served by first-tier generation 
capacity. Furthermore, as the Commission noted in the NOPR, Adjusted 
Historical Peak Load includes both affiliate and non-affiliate native 
load, as well as wholesale load. This ensures the SIL value, when 
limited by Adjusted Historical Peak Load, remains consistent with the 
load values in the indicative screens and also does not provide biased 
SIL values when they are limited by load. This clarification is not 
intended to re-categorize study area non-affiliated load as study area 
affiliate load, but rather clarify that they together are available to 
be served by competitors in the first-tier market and from available 
non-affiliate generators within the study area. However, we agree with 
Idaho Power that non-affiliate load served by internal non-affiliate 
generation with a firm commitment should not be represented as being 
available to be served by competitors. Therefore, we clarify that when 
a non-affiliate generator has a firm commitment to serve a non-
affiliate load and both are located within the study area, then this 
non-affiliate generator should not be scaled and the value of this non-
affiliate load should not be included in the study area Historical Peak 
Load as reported on row 7 of Submittal 1.
vi. Sources of Load Data
(a) Commission Proposal
    181. The Commission stated in the NOPR that it is also looking for 
consistent, reported load values for all sellers to use in preparing 
SIL studies, noting that Puget requires that sellers use FERC Form No. 
714 load values or explain the source of the data used.\235\ The 
Commission noted that some sellers have stated that the load values in 
their models differ from FERC Form No. 714 data and have sought to rely 
on data from sources other than FERC Form No. 714. The Commission 
sought industry comment on what sources other than FERC Form No. 714 
may be appropriate sources to rely on in determining historical peak 
load.
---------------------------------------------------------------------------

    \235\ NOPR, FERC Stats. & Regs. ] 32,702 at P 170 (citing Puget, 
135 FERC ] 61,254 at app. B, Submittal 1, n.iv).
---------------------------------------------------------------------------

(b) Comments
    182. Idaho Power believes that, with the other adjustments in the 
NOPR, use of FERC Form No. 714 data, which includes the balancing 
authority area load, is appropriate. However, Solomon/Arenchild state 
that, in their experience, the load included in seasonal benchmark 
power flow models often does not precisely match loads reported in FERC 
Form No. 714 and typically used in the indicative screens. Solomon/
Arenchild recommend that the Commission allow sellers to use the load 
data underlying the transmission models for purposes of row 7 of 
Submittal 1.
    183. Southeast Transmission Owners believe that, regardless of its 
source, the load data must incorporate all data in the market under 
study. Southeast Transmission Owners use Southern Companies as an 
example to demonstrate that FERC Form No. 714 may not always reflect 
aggregated balancing authority area information necessary to determine 
the historical peak load for the SIL study because the FERC Form No. 
714 data reflects load data of the Southern Companies and not the load 
of all other load-serving entities operating inside the Southern 
Companies balancing authority area. Therefore, Southeast Transmission 
Owners argue that, in order to perform a SIL study consistent with the 
Commission's existing requirements, entities like Southern Companies 
use archived load data from their energy management systems in order to 
provide the requisite balancing authority area information needed for 
the study. Southeast Transmission Owners assert that, while there may 
be other FERC Form No. 714 alternatives, archived energy management 
systems data serves as a reliable, cost-effective means for satisfying 
the Commission's requirements and ensuring that the appropriate inputs 
to the SIL have been obtained in order to yield accurate results.
(c) Commission Determination
    184. We do not find it necessary for the load used in the seasonal 
benchmark case model to exactly match FERC Form No. 714 data. However, 
the Historical Peak Load reported in row 7 of Submittal 1 should be 
consistent with the load used in the seasonal benchmark case model. We 
clarify that entities are permitted to deviate from reported FERC Form 
No. 714 load values where such values fail to account for all load 
within the study area, but sellers must explain and document their 
reasons for using an alternative data source and any adjustments made 
to the data. In addition, we find it acceptable for sellers to use 
energy management systems data to represent Historical Peak Load 
values, so long as sellers attest that such data is unmodified and 
accurate, and includes all study area affiliate and non-affiliate load.
vii. Submittals 1 and 2
(a) Commission Proposal
    185. The Commission clarified in the NOPR that the values provided 
in Submittal 1 should generally be supported by the submitted seasonal 
benchmark power flow models.\236\ In particular, the Commission 
explained

[[Page 67082]]

that row 1 (Simultaneous Incremental Transfer Capability), row 2 
(Modeled Net Area Interchange), and row 4 (Total Simultaneous Transfer 
Capability) should agree with the corresponding values from the 
seasonal benchmark power flow models. Any differences should be 
explained by the seller. The Commission proposed to update Submittal 1, 
as reflected in Appendix E to the NOPR, to provide additional clarity 
on the expected values for certain rows.\237\ As addressed above in the 
discussion of wheel-through transactions, the Commission also proposed 
revisions to Submittal 2. Revised versions of Submittals 1 and 2 were 
posted on the Commission's Web site.
---------------------------------------------------------------------------

    \236\ Id. P 171.
    \237\ See Revised app. E, Submittal 1.
---------------------------------------------------------------------------

(b) Commission Determination
    186. We adopt the proposal to clarify that the values provided in 
Submittal 1 should generally be supported by the submitted benchmark 
power flow models. Any differences should be explained by the seller. 
We will also adopt the proposal to update Submittal 1, as reflected in 
Appendix E of the NOPR, to provide additional clarity on the expected 
values for certain rows. We will post the revised versions of 
Submittals 1 and 2 on the Commission's Web site and direct sellers to 
begin using the revised versions no later than the effective date of 
this Final Rule.
c. Simultaneous TTC Method
i. Commission Proposal
    187. The Commission proposed in the NOPR to define the following 
standard guidance for data submittals and representations that sellers 
using the simultaneous TTC method must provide to the Commission. 
First, the Commission stated that sellers must provide historical data 
of actual, hourly, real-time TTC values used for operating the 
transmission system and posting transmission capacity availability on 
OASIS. Sellers should identify the date and hour from which 
simultaneous TTC values were calculated. Sellers may use the maximum 
sum of TTC values for any day and time during each season, so long as 
they also demonstrate that these TTC values are simultaneously 
feasible. Sellers may demonstrate that TTC values are simultaneously 
feasible by performing a power flow study that verifies that the 
declared simultaneous TTC value is simultaneously feasible while 
accounting for all internal and external transmission limitations 
identified in Appendix E of the NOPR and Puget.\238\ Sellers may also 
provide expert testimony explaining how the specific criteria and 
procedures used to calculate posted TTC values result in TTC values 
that are simultaneously feasible.
---------------------------------------------------------------------------

    \238\ NOPR, FERC Stats. & Regs. ] 32,702 at P 172.
---------------------------------------------------------------------------

    188. The Commission reiterated that, in the event there are limited 
interconnections between first-tier markets, the Commission will review 
evidence that potential loop flow between first-tier areas is properly 
accounted for in the underlying SIL values on a case-by-case 
basis.\239\ However, the Commission clarified that simply attesting 
that first-tier markets or balancing authority areas are not directly 
interconnected is not sufficient evidence that TTC values posted on 
OASIS are simultaneous, as this does not preclude internal transmission 
limitations from limiting the simultaneous TTC below the sum of 
individual path TTC values.
---------------------------------------------------------------------------

    \239\ Id. P 173 (citing Atlantic Renewables Projects II, 135 
FERC ] 61,227, at P 9 (2011)).
---------------------------------------------------------------------------

ii. Commission Determination
    189. There were no comments addressing this proposal. Thus, we 
adopt the standard guidance for data submittals and representations 
that sellers using the simultaneous TTC method must provide to the 
Commission.
d. Other Issues
i. Comments
    190. Solomon/Arenchild seek several clarifications relating to the 
determination of the SIL and its application in the indicative screens 
versus a DPT analysis. First, they state that the SIL value for the 
indicative screens is calculated for four seasonal peaks (Winter, 
Spring, Summer, and Fall), whereas the DPT analysis typically evaluates 
a ``Shoulder'' season that combines Spring and Fall. Solomon/Arenchild 
seek that the Commission clarify that the DPT analysis of a 
``Shoulder'' season should use the average of the Spring and Fall 
values, unless it can be demonstrated that facts exist to support use 
of either Spring or Fall values alone for the Shoulder season.
    191. Second, Solomon/Arenchild state that, in their experience, the 
SIL values used in the DPT and those reported in the SIL submittals may 
legitimately differ as a direct result of underlying differences 
between the DPT and the indicative screens related to the treatment of 
long-term transmission reservations. Solomon/Arenchild ask that the 
Commission clarify that it is appropriate when calculating the SIL 
values used in the DPT analysis not to deduct any associated long-term 
transmission for a remote generating facility during a period when such 
generation is not fully available or not economic (or, alternatively, 
to increase the SIL to reflect additional import capacity).
    192. Finally, Solomon/Arenchild seek clarification of the 
definition of ``long-term firm transmission contracts.'' According to 
Solomon/Arenchild, the Commission's current regulations define 
transmission contracts with a term of 28 days or more as ``long-term'' 
and direct that such contracts be reflected in the SIL analysis. 
However, Solomon/Arenchild assert that such contracts may be excluded 
in the indicative screen analysis and/or the DPT because they do not 
meet the definition of ``long-term'' as being one year or longer, as 
used for analyzing energy markets. While they recognize that both the 
SILs and the indicative screens are intended to depict an accurate 
historical representation of markets, Solomon/Arenchild contend that 
including only transmission reservations with durations of one year or 
longer provides a more robust analysis. Accordingly, Solomon/Arenchild 
suggest that the Commission clarify that only long-term contracts, 
including seasonal contracts, that are one year or longer be included 
in both the SIL study and the indicative screen and/or DPT 
analyses.\240\
---------------------------------------------------------------------------

    \240\ Solomon/Arenchild at 14-15.
---------------------------------------------------------------------------

    193. EEI states it is concerned with the volume of clarifications 
in the Commission's proposal regarding SIL studies. EEI encourages the 
Commission to engage in further dialogue with the regulated community 
about the proposed changes, to ensure that the changes are reasonable, 
clear, accurate, and easy to implement. Additionally, EEI expresses 
concern that some of its members are already being required to make 
changes in their SIL analyses.\241\
---------------------------------------------------------------------------

    \241\ EEI at 21.
---------------------------------------------------------------------------

    194. Southeast Transmission Owners support EEI's request for the 
Commission to further caucus with industry regarding SIL studies. Given 
the complexities underlying the market-based rate program and the fact 
that industry's most recent round of triennial updated market power 
analysis filings will continue until June 2016, Southeast Transmission 
Owners state that the Commission does not need to rush action with 
regard to these proposals.\242\ Further, Southeast Transmission Owners 
are concerned that the Commission's proposals may cause confusion among 
sellers, rather than the

[[Page 67083]]

intended goal of streamlining the market-based rate program, and may 
result in less reliable SIL values.
---------------------------------------------------------------------------

    \242\ Southeast Transmission Owners at 6-7 (citing NOPR, FERC 
Stats. & Regs. ] 32,702 at app. C).
---------------------------------------------------------------------------

    195. SoCal Edison recommends that the Commission require each RTO/
ISO, and the CAISO in particular, to perform a SIL study for common 
use.
ii. Commission Determination
    196. We find Solomon/Arenchild's request for clarification 
regarding which Spring and Fall SIL values to use for the DPT analysis 
to be beyond the scope of this rulemaking proceeding. We also find 
their request for clarification regarding calculation of the SIL values 
used in the DPT analysis to be beyond the scope of this rulemaking 
proceeding.
    197. Additionally, we decline Solomon/Arenchild's request to 
redefine the applicable duration of long-term firm transmission 
reservations, currently defined as 28 days or longer, for purposes of 
the SIL study as this would inflate the amount of import capability 
available on a long-term basis. Solomon/Arenchild have not demonstrated 
why the Commission should change the definition for purposes of the SIL 
study. Indeed, the power flow cases utilized for SIL studies are a 
reflection of seasonal peaks such that a ``monthly'' designation for 
such reservations appropriately captures this designation.
    198. With regard to concerns about the volume and complexity of 
changes, we remind commenters that the proposed rule is primarily a 
clarification of existing policy and that the need for this 
clarification was based in part on a lack of specificity resulting in 
confusion with the SIL study process. To the extent sellers remain 
confused about any aspect of the Commission's instructions regarding 
SIL studies, Commission staff will continue to be available to discuss 
these issues prior to an applicant submitting its filing.
    199. In response to SoCal Edison's request for the Commission to 
require each RTO/ISO to perform a SIL study for common use, the RTOs/
ISOs do not have market-based rate tariffs on file; thus, we will not 
require SIL studies from RTOs/ISOs.

B. Vertical Market Power--Land Acquisition Reporting

1. Commission Proposal
    200. In the NOPR, the Commission noted that all market-based rate 
sellers currently are required to provide, as part of their vertical 
market power analysis, a description of their ownership or control of, 
or affiliation with an entity that owns or controls, sites for 
generation capacity development \243\ and to file notices of change in 
status on a quarterly basis when they acquire sites for new generation 
capacity development.\244\ The Commission noted that in the more than 
six years since issuance of Order No. 697, not a single protest had 
been filed in response to disclosures regarding sites for new 
generation capacity development and it proposed 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 (land acquisition reporting requirements) 
because the burden of such reporting outweighs the benefits.\245\ The 
Commission noted that, if there is a concern that a particular seller's 
sites for generation capacity development may be creating a barrier to 
entry, the Commission can request additional information from the 
seller at any time.\246\
---------------------------------------------------------------------------

    \243\ 18 CFR 35.37(e)(2).
    \244\ 18 CFR 35.42(d).
    \245\ For example, the Commission received, from the second 
quarter in 2012 to the fourth quarter in 2013, approximately 90 
filings from 1,380 filers. This is a reporting burden on sellers and 
an inefficient use of Commission resources for information that has 
yet to produce an actionable item or elicit a single comment in 
almost five years.
    \246\ See Order No. 697-D, FERC Stats. & Regs. ] 31,305 at P 23 
(``[I]f there is a concern that a particular seller may be acquiring 
land for the purpose of preventing new generation capacity from 
being developed on that land, the Commission can request additional 
information from the seller at any time.'').
---------------------------------------------------------------------------

    201. Thus, the Commission proposed to revise the regulations at 18 
CFR 35.42 relating to change in status reporting requirements to remove 
paragraph (d). This proposed revision would remove the requirement that 
sellers report the acquisition of control of a site or sites for new 
generation capacity development for which site control has been 
demonstrated. Likewise, the Commission proposed to revise the 
regulations at 18 CFR 35.42 to remove paragraph (e), which pertains to 
the definition of site control for purposes of paragraph (d). In 
addition, the Commission proposed to revise 18 CFR 35.42 at paragraph 
(b) to remove the reference to the reporting of acquisition of control 
of a site or sites for new generation capacity development. The 
Commission also proposed to revise the market power analysis 
regulations at 18 CFR 35.37 to remove paragraph (e)(2), which requires 
sellers to provide information regarding sites for generation capacity 
development to demonstrate a lack of vertical market power.
2. Comments
    202. Several commenters support the Commission's proposal to 
eliminate the land acquisition reporting requirements.\247\ These 
commenters contend that the reporting obligation is unnecessary and 
unduly burdensome, with little benefit, particularly given that in the 
last six years intervenors have not challenged whether sites for new 
generation capacity development created a barrier to entry.\248\
---------------------------------------------------------------------------

    \247\ See, e.g., AEP at 5-7; E.ON at 7-8; EEI at 13; EPSA at 7; 
FirstEnergy at 9; NRG Companies at 7-8; NextEra at 10.
    \248\ See E.ON at 7-8; EEI at 13; FirstEnergy at 9; NextEra at 
10.
---------------------------------------------------------------------------

    203. EPSA and NRG Companies note that the purpose of the initial 
applications, triennial updates, and notices of change in status, is to 
identify for the Commission material facts and changes relevant to a 
seller's qualification for market-based rate authority. EPSA and NRG 
Companies state that requirements that sellers file quarterly land 
acquisition reports fail to further the purpose of the triennial 
updates and notices of change in status filings.\249\ NRG Companies add 
that there is no reason to think that these reports would ever provide 
information that would call into question the validity of ``the 
rebuttable presumption that sellers cannot erect barriers to entry with 
regard to the ownership or control of, or affiliation with any entity 
that owns or controls . . . sites for generation capacity development . 
. . .'' \250\ As such, EPSA states that the Commission's proposal 
furthers the Commission's stated goal of reducing the regulatory 
burdens on market-based rate sellers.\251\
---------------------------------------------------------------------------

    \249\ EPSA at 7; NRG Companies at 7-8.
    \250\ NRG Companies at 7-8 (quoting Order No. 697, FERC Stats. & 
Regs. ] 31,252 at P 446).
    \251\ EPSA at 7.
---------------------------------------------------------------------------

    204. NextEra asserts that, in addition to being burdensome, the 
reports have limited value because the land acquisition reporting 
requirements do not allow the netting of generation in the 
interconnection queue when a market-based rate seller withdraws a 
proposed project from the interconnection queue or places a new project 
in-service. According to NextEra, as a result, the information on file 
with the Commission does not accurately reflect actual site control in 
the interconnection process and the quarterly reports provide little 
useful information to the Commission or the public.\252\
---------------------------------------------------------------------------

    \252\ NextEra at 10.

---------------------------------------------------------------------------

[[Page 67084]]

    205. On the other hand, other commenters oppose removing the land 
acquisition reporting requirements.\253\ They argue that the fact that 
in the last six years intervenors have not challenged whether sites for 
new generation capacity development created a barrier to entry is not a 
reason for the Commission to ignore the issue in the future. AAI argues 
that, due to the relative scarcity of land suitable for renewable 
energy development, incumbents can erect barriers to entry through 
strategic generation site acquisitions, i.e., accumulate renewable 
energy sites with the aim of preventing rivals from developing them. 
Further, AAI states that the composition of generation in the United 
States may be on the cusp of radical restructuring, pointing to state 
enacted Renewable Portfolio Standards and the United States 
Environmental Protection Agency's rulemaking to reduce greenhouse gas 
emissions from new and existing power plants.\254\ According to AAI, 
for the intended change in the generation fleet to occur, barriers to 
entry, including access to generation sites, must be minimized. AAI 
states that the Commission should continue to collect data on the 
acquisition of generation sites and recommends using a comprehensive 
database, as opposed to relying on complaints of affected parties, to 
monitor this issue in a systematic fashion. Lastly, AAI states that, 
given the anticipated high growth in renewable energy, revising land 
acquisition and generation capacity development reporting rules would 
be premature.
---------------------------------------------------------------------------

    \253\ AAI at 10-12; APPA/NRECA at 26-27; TAPS at 2.
    \254\ AAI at 11-12 (citing U.S. Energy Info. Admin., Most States 
Have Renewable Portfolio Standards, Feb. 3, 2012, available at 
http://www.eia.gov/todayinenergy/detail.cfm?id=4850; Carbon 
Pollution Emission Guidelines for Existing Stationary Sources: 
Electric Utility Generating Units, 79 FR 34830 (proposed June 18, 
2014) (to be codified at 40 CFR part 60)).
---------------------------------------------------------------------------

    206. Similarly, APPA/NRECA states that a number of economic, 
technological, and regulatory factors are inducing the retirement of 
substantial coal generation and the construction of substantial new 
gas-fired and renewable generation in the coming years. APPA/NRECA 
asserts that where this new generation will be located will be an 
important issue because most of the new generation will be location-
constrained renewable resources. Further, APPA/NRECA asserts that, 
because of constraints on gas pipeline capacity, the location of gas-
fired generation sites relative to existing and proposed gas pipelines 
is also critical. Lastly, APPA/NRECA asserts that the retirement of 
coal generation can change the economic and reliability factors that 
will determine where new generation may be located. APPA/NRECA warns 
that, because the location of new generation build-out may have 
important economic consequences, the Commission should not ignore the 
barriers to entry created by the acquisition of new generation 
sites.\255\ TAPS supports APPA/NRECA's comments with respect to land 
acquisition reporting. TAPS opposes the proposed elimination of the 
land acquisition reporting requirement given the current dramatic 
changes in generation resource mixes, and in particular, the potential 
importance of access to gas pipeline facilities.\256\
---------------------------------------------------------------------------

    \255\ APPA/NRECA at 26-27.
    \256\ TAPS at 2.
---------------------------------------------------------------------------

3. Commission Determination
    207. We adopt the NOPR proposal to eliminate the land acquisition 
reporting requirements.
    208. We continue to find that the current land acquisition 
reporting is of limited value in assessing barriers to entry. The 
existing land acquisition reports include: (1) The number of sites 
acquired; (2) the relevant geographic market in which the sites are 
located; and (3) the maximum potential number of megawatts that are 
reasonably commercially feasible on the sites reported.\257\ Thus, the 
reports identify relevant geographic market/balancing authority areas, 
but such reports do not indicate specific locations or whether the 
sites are adjacent to the existing transmission grid or natural gas 
pipelines. Moreover, the reports do not include any metrics or analyses 
to indicate whether the seller's land acquisitions provide it with 
control over a sufficient amount of sites to create a potential barrier 
to entry within a geographic market.
---------------------------------------------------------------------------

    \257\ 18 CFR 35.42(d).
---------------------------------------------------------------------------

    209. As noted above, the land acquisition reporting requirements 
are burdensome for sellers and yield little, if any, offsetting 
benefit. Out of 58 filings of land acquisition reports from the fourth 
quarter in 2013 to the first quarter in 2015, none has been contested 
or has provided sellers and the Commission with useful information 
regarding barriers to entry.\258\ No one has used the information in a 
land acquisition report in a comment or protest challenging the market-
based rate authority of any seller.
---------------------------------------------------------------------------

    \258\ NOPR, FERC Stats. & Regs. ] 32,702 at P 89 n.109.
---------------------------------------------------------------------------

    210. In response to the concerns raised by AAI and APPA/NRECA, we 
clarify that intervenors are free to challenge an applicant's claims 
that it has not erected barriers to entry. We also reiterate that the 
Commission retains the right to request additional information on such 
potential barriers to entry from the seller at any time if it has 
reason to believe that a seller's acquisition of land has created a 
barrier to entry or otherwise been used to exercise vertical market 
power.\259\ Furthermore, the Commission will continue to require 
market-based rate sellers to affirmatively state that they and their 
affiliates have not and will not raise any barriers to entry in the 
relevant market, including of land acquisitions, as part of the 
Commission's vertical market power analysis required in initial 
applications, triennials, and notices of change in status that affect 
the vertical market power analysis.
---------------------------------------------------------------------------

    \259\ See Order No. 697-D, FERC Stats. & Regs. ] 31,305 at P 23 
(``[I]f there is a concern that a particular seller may be acquiring 
land for the purpose of preventing new generation capacity from 
being developed on that land, the Commission can request additional 
information from the seller at any time.'').
---------------------------------------------------------------------------

    211. Finally, AAI suggests that the Commission utilize a 
comprehensive database to monitor the acquisition of generation sites 
in a systematic fashion. However, the Commission did not propose any 
refinements to the information collected in land acquisition reports 
but rather the elimination of the requirement. The comprehensive 
database recommended by AAI would be a major undertaking with uncertain 
benefits, for the reasons stated above, and is beyond the scope of this 
rulemaking. For these reasons, we reject this request.
    212. We adopt the NOPR proposal to revise the regulations at 18 CFR 
35.42 relating to the change in status reporting requirements to remove 
paragraph (d), the requirement that sellers report the acquisition of 
control of a site or sites for new generation capacity development for 
which site control has been demonstrated. We will also remove paragraph 
(e), which pertains to the definition of site control for purposes of 
paragraph (d), and revise paragraph (b) to remove the reference to the 
reporting of acquisition of control of a site or sites for new 
generation capacity development. Further, we adopt the NOPR proposal to 
revise the market power analysis regulations at 18 CFR 35.37 to remove 
paragraph (e)(2), which requires sellers to provide information 
regarding sites for generation capacity development to demonstrate a 
lack of vertical market power.

[[Page 67085]]

C. Notices of Change in Status

1. Geographic Focus
a. Commission Proposal
    213. In Order No. 697-A, the Commission clarified that sellers must 
report a change in status when they acquire 100 MW or more in the 
``geographic market that was the subject of the horizontal market power 
analysis on which the Commission relied in granting the seller market-
based rate authority.'' \260\ In the NOPR, the Commission proposed to 
clarify that the 100 MW reporting threshold in section 35.42(a)(1) is 
not limited only to markets previously studied. The Commission proposed 
that, if a seller acquires generation that would cause a cumulative net 
increase of 100 MW or more in any relevant geographic market (including 
generation in both the relevant geographic market itself and any first-
tier/interconnected market with the potential to import into that 
market) since the seller's most recent triennial updated market power 
analysis or change in status filing, the seller must make a change in 
status filing. This would include cumulative increases of 100 MW or 
more in a new market that has not previously been studied because, once 
the seller has generation in that market, it is a relevant geographic 
market for that seller. The Commission clarified that a net increase 
measures the difference between increases and decreases in affiliated 
generation.
---------------------------------------------------------------------------

    \260\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 512.
---------------------------------------------------------------------------

    214. In Order No. 697-A, the Commission also provided the following 
example, ``if a seller has a net increase of 50 MW in the geographic 
market on which the Commission relied in granting the seller market-
based rate authority and 50 MW increase in a different geographic 
market that is in the same region . . . , the 100 MW or more threshold 
would not be met because the increase in generation capacity is less 
than [100] MW in each generation market and, accordingly, a change in 
status filing would not be required.'' \261\ In the NOPR, the 
Commission clarified that this example described a situation where the 
geographic market on which the Commission relied in granting market-
based rate authority was not first-tier to the geographic market in 
which the seller acquired an additional 50 MW. Thus, the Commission 
proposed to clarify that the 100 MW threshold applies to the cumulative 
capacity added in any relevant geographic market, including what can be 
imported from first-tier markets, but does not cover situations where a 
seller acquires less than 100 MW in one market and less than 100 MW in 
another market, as long as those two markets are not first-tier to each 
other.
---------------------------------------------------------------------------

    \261\ Id.
---------------------------------------------------------------------------

    215. The Commission further proposed to require that the 100 MW 
threshold requirement for change in status filings be calculated based 
on a generator's nameplate capacity rating because it is a single 
value, it exists for all types of generators, it is generally a more 
conservative value than a seasonal or five-year average rating would 
be, and it allows for uniform measurements across different types of 
generators.
    216. The Commission proposed to revise the regulatory text in 
section 35.42(a)(1) of the Commission's regulations to provide greater 
clarity and direction on this topic.
b. Comments
    217. Several commenters object to the Commission's proposal to 
consider cumulative net increases of 100 MW or more of nameplate 
capacity in any relevant geographic market as well as any first-tier/
interconnected market with the potential to import into that market 
when determining whether to report a change in status.\262\ Solomon/
Arenchild and NextEra argue that the proposed change significantly 
broadens the market definition captured in the metric of what 
constitutes a net 100 MW change in generation capacity.\263\ Solomon/
Arenchild and NextEra contend that the current proposal implies that a 
megawatt outside of the market is equivalent to a megawatt inside of 
the market, which is not the case.\264\ Solomon/Arenchild and NextEra 
further argue that the Commission's proposal reinstates the ``hub and 
spoke'' methodology, which attributed all capacity controlled by the 
seller and its affiliates in the relevant and first-tier markets to the 
seller, and was properly disposed of by the Commission because 
megawatts added in first-tier markets cannot necessarily be imported, 
unless there is a firm transmission reservation, which is a distinction 
the proposal fails to address.\265\ Solomon/Arenchild propose 
corresponding revisions to the Commission's proposed regulatory 
text.\266\
---------------------------------------------------------------------------

    \262\ See, e.g., Solomon/Arenchild at 4; NextEra at 11; E.ON at 
10; EEI at 14. But see APPA/NRECA (supporting the Commission's 
proposal); Golden Spread at 7 (supporting the eleven Commission 
proposals that APPA/NRECA supports, which are listed on pages 4-5 of 
the APPA/NRECA joint comments).
    \263\ Solomon/Arenchild at 4; NextEra at 11.
    \264\ Solomon/Arenchild at 4; NextEra at 11 (stating that the 
proposal appears to assume that 100 MW (or even one megawatt) added 
to a first-tier market should be treated no differently than 100 MW 
added in the relevant geographic market).
    \265\ Solomon/Arenchild at 4; NextEra at 11.
    \266\ Solomon/Arenchild at 5.
---------------------------------------------------------------------------

    218. EEI contends that the Commission should not attribute changes 
in generation in one market to another market, even if the markets are 
first-tier to one another.\267\ EEI explains that the 100 MW threshold 
should be measured for each market separately, without adding changes 
in first-tier markets, for two reasons.\268\ First, the focus of the 
Commission's market power analyses has always been on the default 
balancing authority area or other market in which market-based rate 
authorization is sought, informed by transmission capability to import 
generation into that market, but not by generation ownership in 
adjacent markets.\269\ EEI argues that there seems to be little reason 
to expand the change in status reporting requirement to mix changes in 
generation ownership in the relevant geographic market and the adjacent 
first-tier markets, which would be the subject of a separate study if 
market-based rate authorization is sought in those markets.\270\ 
Second, EEI is concerned that the expansion of the change in status 
reporting requirement for generation ownership to account for 
generation in the first-tier markets would create confusion.\271\ EEI 
states that this would complicate the tracking of generation and the 
application of the 100 MW threshold in the various markets and will not 
produce commensurate benefits.\272\ EEI therefore proposes that each 
market should be treated independently for the purpose of change in 
status reporting.\273\ EPSA adds that any increase in megawatts in a 
first-tier market would already be reflected in the analysis of that 
particular first-tier market and argues that amending the current 
regulations to require sellers to account for such increases separately 
would be redundant and serve to substantially increase the burden on 
such sellers.\274\
---------------------------------------------------------------------------

    \267\ EEI at 14.
    \268\ Id.
    \269\ Id.
    \270\ Id.
    \271\ Id.
    \272\ Id.
    \273\ Id. at 15. EPSA also argues that the proposal would 
complicate the tracking of generation and similarly recommends that 
the Commission to treat each market separately. EPSA at 8.
    \274\ EPSA at 9.
---------------------------------------------------------------------------

    219. E.ON notes that the Commission proposes to require a seller to 
notify the Commission when it becomes affiliated with ``100 MW or more 
in any relevant

[[Page 67086]]

geographic market'' \275\ and requests the Commission clarify that the 
``any relevant market'' language is limited to the applicable 
geographic region and applicable first-tier markets.\276\ E.ON further 
notes that the Commission states in the NOPR that this notification 
requirement would extend to ``cumulative increases of 100 MW or more in 
a new market that has not previously been studied because, once the 
seller has generation in that market, it is a relevant geographic 
market for that seller'' \277\ and states that it struggles to 
understand the benefit of this extended notification requirement and 
the Commission's definition of a new ``relevant'' market.\278\
---------------------------------------------------------------------------

    \275\ E.ON at 10 (citing NOPR, FERC Stats. & Regs. ] 32,702 at P 
96) (emphasis added by E.ON).
    \276\ Id. at 10. E.ON uses the following example: If a seller 
owns or controls a generation facility in PJM and obtained market-
based rate authorization, the fact that a new affiliate may own or 
control 100 MW or more of new generation in the CAISO market has no 
relevance to whether the seller in PJM lacks horizontal market 
power.
    \277\ Id. (citing NOPR, FERC Stats. & Regs. ] 32,702 at P 96).
    \278\ Id.
---------------------------------------------------------------------------

    220. Several commenters oppose the Commission's proposal to use 
nameplate capacity to calculate the 100 MW change in status 
threshold.\279\ Solomon/Arenchild argue that the proposal creates a 
disconnect between the asset appendix capacity ratings and indicative 
screens capacity ratings because most indicative screens are based on 
seasonal (summer/winter), not nameplate, ratings, and many sellers 
report summer ratings only in their asset appendix.\280\ Solomon/
Arenchild therefore propose that the Commission allow sellers to use 
either nameplate or seasonal ratings and, if applicable, five-year 
averages, for determining the 100 MW threshold for the notice of change 
in status.\281\ Solomon/Arenchild and EEI argue that the Commission 
should allow energy-limited resources, in particular, to report five-
year averages.\282\
---------------------------------------------------------------------------

    \279\ See, e.g., Solomon/Arenchild at 3; EEI at 15; EPSA at 8-9; 
E.ON at 13; Idaho Power at 3-4.
    \280\ Solomon/Arenchild at 3.
    \281\ Id.
    \282\ Id.; EEI at 15.
---------------------------------------------------------------------------

    221. Similarly, E.ON states that, if an affiliate of a market-based 
rate seller acquires an interest in or builds 100 MW or more of energy-
limited generation, the Commission may already have on file five years 
of historical average capacity ratings or EIA-derived data for the 
energy-limited generation and argues that it would be a ``mismatch'' to 
apply nameplate rating to the energy-limited generation for the 
purposes of triggering any notice of change in status filing 
requirement.\283\ Therefore, E.ON requests that, to the extent the 100 
MW threshold remains, the Commission revise its regulations in section 
35.42(a)(1) to provide that a market-based rate seller submit a notice 
of change in status where there are ``cumulative net increases . . . of 
100 MW or more of nameplate capacity or as otherwise has been reported 
to the Commission.'' \284\ Idaho Power adds that while using nameplate 
ratings across all generation types may provide consistency, it does 
not provide a proper basis for evaluation when comparing, for example, 
variable generation (i.e., wind, solar) with thermal generation (i.e., 
natural gas).\285\
---------------------------------------------------------------------------

    \283\ E.ON at 13.
    \284\ Id. E.ON's proposed change is illustrated in italics.
    \285\ Idaho Power at 3-4.
---------------------------------------------------------------------------

    222. Other commenters argue that notices of change in status need 
not be filed in certain circumstances.\286\ FirstEnergy argues that the 
Commission's approval of a transaction under section 203 of the FPA 
should obviate the need for a subsequent change in status report and 
further Commission review under section 205 of the FPA.\287\ 
FirstEnergy states that it is unaware of any instance in which the 
Commission authorized a merger of generation facilities under section 
203 of the FPA and later found that the merged entity fails the 
standard for selling electricity at market-based rates in any relevant 
geographic market.\288\ FirstEnergy further claims that its 
recommendation will reduce the regulatory burden on sellers without 
adversely affecting the Commission's ability to protect consumers.\289\
---------------------------------------------------------------------------

    \286\ See, e.g., FirstEnergy at 10, 11; AEP at 6; E.ON at 8-9, 
11.
    \287\ FirstEnergy at 10.
    \288\ Id.
    \289\ Id. at 11.
---------------------------------------------------------------------------

    223. Additionally, AEP and E.ON argue that the Commission should 
eliminate altogether the notice of change in status requirement for 
sellers within RTOs. AEP explains that, to the extent market power 
concerns are implicated by a market-based rate seller's acquisition or 
new affiliation, the extensive Commission-approved RTO market 
monitoring and mitigation rules adequately prevent the exercise of 
market power without the need for the seller to file an additional 
report.\290\
---------------------------------------------------------------------------

    \290\ AEP at 6. E.ON makes similar arguments. See E.ON at 8-9 
(emphasizing that the notice of change in status would simply repeat 
what the market-based rate seller has already told the Commission, 
namely, that the market-based rate seller is relying on RTO 
mitigation).
---------------------------------------------------------------------------

    224. E.ON requests that the Commission clarify that a notice of 
change in status filing is not necessary where an affiliate of a 
market-based rate seller is granted market-based rate 
authorization.\291\ E.ON also recommends that the Commission revise its 
policies so that only one substantive filing is submitted to the 
Commission.\292\
---------------------------------------------------------------------------

    \291\ E.ON at 11.
    \292\ Id. (arguing that an initial market-based rate application 
of the new affiliate should suffice to address all other relevant, 
affiliated market-based sellers).
---------------------------------------------------------------------------

    225. NextEra claims that this notice of change in status proposal 
is confusing in light of another NOPR proposal to eliminate the 
requirement to provide indicative screens where all of a seller's and 
its affiliates' generation in the relevant market is committed under 
long-term power purchase agreements.\293\ NextEra states that the 
proposed revised text of section 35.42(a)(1) of the Commission's 
regulations provides only a bright line test for notices of change in 
status based on nameplate capacity in the relevant geographic market 
and first-tier markets, thus ignoring the long-term power purchase 
agreements.\294\ NextEra suggests that, if the Commission adopts this 
new requirement, it should explain how section 35.42(a) of the 
Commission's regulation should be interpreted when generation is 
subject to a long-term power purchase agreement.\295\ EEI encourages 
the Commission to find additional ways to streamline the change in 
status reporting requirements. EEI offers two examples: (1) The 
Commission should indicate that minor changes in organization or other 
information covered by the change in status reporting requirements need 
not be reported individually but can be cumulated to include with a 
next change in status filing, and (2) the Commission should consider 
providing additional relief from change in status reporting to 
companies based on the Commission's experience with the change in 
status requirements over the past decade (e.g., the Commission should 
consider increasing the 100 MW thresholds).\296\
---------------------------------------------------------------------------

    \293\ NextEra at 11.
    \294\ Id.
    \295\ Id. at 12.
    \296\ EEI at 16.
---------------------------------------------------------------------------

    226. EPSA notes that sellers are required to report a change in 
status when an additional 100 MW in a relevant geographic market is 
attained, but states that it is unclear whether the change in status 
reporting requirement is then ``reset'' and a notice of change in 
status is necessary when another 100 MW of controlled generation is

[[Page 67087]]

obtained, or once the 100 MW threshold is attained, if all new 
controlled generation in excess of 100 MW must be reported.\297\ EPSA 
seeks clarification that a notice of change in status must be submitted 
each time a seller attains a cumulative 100 MW of controlled 
generation.\298\
---------------------------------------------------------------------------

    \297\ EPSA at 11-12.
    \298\ Id.
---------------------------------------------------------------------------

    227. FirstEnergy recommends that, in addition to the proposal to 
relieve RTO/ISO sellers from the obligation to file the indicative 
screens, the Commission should relieve RTO/ISO sellers from the 
obligation to submit notices of change in status relating to increases 
in generation capacity. Similarly, AEP recommends that the Commission 
relieve RTO/ISO sellers from the obligation to submit notices of change 
in status altogether. EEI encourages the Commission to consider 
providing broader relief from change in status reporting to utilities 
with FERC-approved market power mitigation measures to reduce the 
burden associated with the market-based rate program. EEI states that 
the same principles underlying the proposed exemption of sellers with 
FERC-approved market power mitigation from providing the indicative 
horizontal market screens in their market power updates could apply 
equally to the overall change in status reporting requirements.
c. Commission Determination
    228. We adopt the NOPR proposal with certain modifications and 
clarifications. In the NOPR, the Commission proposed to apply the 100 
MW threshold to a seller's and/or its affiliates' generation capacity 
in each relevant market and first tier market(s), and to also apply the 
100 MW threshold to each new relevant market (not previously studied) 
in which a seller and/or its affiliates acquire a cumulative net 
increase of 100 MW. The NOPR also proposed to require that the 100 MW 
threshold for change in status filings be calculated based solely on a 
generator's nameplate capacity rating.
    229. We believe that the Solomon/Arenchild and NextEra comments 
with respect to the calculation of the 100 MW threshold have merit 
\299\ and that generation capacity in the first tier markets should not 
be treated the same as capacity located in the seller's relevant 
geographic market/study area. We recognize that 100 MW located outside 
of the study area is only equivalent to 100 MW inside when there is a 
long-term firm transmission reservation to import the 100 MW.
---------------------------------------------------------------------------

    \299\ NextEra at 11; Solomon/Arenchild at 4.
---------------------------------------------------------------------------

    230. Therefore, we will modify the proposal set forth in the NOPR. 
The 100 MW threshold for reporting a change in status will apply to a 
seller's and/or its affiliates' net generation capacity additions in 
each individual market, but will exclude markets and balancing 
authority areas that are first-tier to the seller's study area. This 
means a seller need not consider its and its affiliates new generation, 
including generation from long-term purchase agreements, in first-tier 
areas in determining whether it has reached the 100 MW threshold.
    231. However, we confirm that, consistent with the NOPR, the 100 MW 
threshold applies to each new relevant market (not previously studied) 
in which a seller and/or its affiliates acquire a cumulative net 
increase of 100 MW. To find otherwise would allow a loophole where an 
applicant could request and be granted market-based rate authority with 
a small amount of generation in one market, qualify as a Category 1 
seller, and then accumulate large amounts of generation in other 
markets in the same region such that the seller could become Category 2 
in the region without notifying the Commission. In addition, applying 
the 100 MW threshold to each new relevant market ensures that sellers 
study the generation acquired in any additional market that meets or 
exceeds this threshold.
    232. Further, we believe that the comments opposing the 
Commission's proposal to require use of nameplate capacity to calculate 
the 100 MW change in status threshold have merit.\300\ Therefore, we 
will revise the NOPR proposal and permit sellers to use nameplate or 
seasonal capacity ratings for the 100 MW threshold for most generation 
and allow energy-limited generation to use either nameplate or a five-
year average capacity factor.\301\
---------------------------------------------------------------------------

    \300\ E.g., E.ON at 13 ; EEI at 15; Idaho Power at 3-4; Solomon/
Arenchild at 3.
    \301\ However, consistent with our finding in this Final Rule 
regarding use of nameplate capacity for solar photovoltaic 
facilities, for change in status threshold purposes, sellers should 
use nameplate capacity for such facilities. NOPR, FERC Stats. & 
Regs. ] 32,702 at P 104.
---------------------------------------------------------------------------

    233. We disagree with FirstEnergy's contention that section 203 
approvals should obviate the need for subsequent change in status 
filings for further Commission review under section 205. The 
Commission's analyses under sections 203 and 205 consider different 
criteria for approving transactions; therefore, it is not a given that 
a seller that passes a section 203 analysis will pass a section 205 
analysis. Furthermore, the data required for the Commission's analyses 
under FPA sections 203 and 205 differ; section 203 filings are 
prospective, with studies based on projected data, whereas the change 
in status filings under section 205 require studies based on historical 
data.
    234. Additionally, we reject AEP's, E.ON's, FirstEnergy's, AEP's, 
and EEI's requests that the Commission eliminate the change in status 
requirements for sellers located in RTOs/ISOs.\302\ AEP states that the 
Commission-approved market monitoring and mitigation rules adequately 
prevent the exercise of market power without the need for the seller to 
file an additional report.\303\ As explained above, we are not prepared 
at this time to adopt the NOPR proposal to relieve sellers in RTO/ISO 
markets of the obligation to file indicative screens.\304\ Therefore, 
we will not relieve sellers in RTO/ISO markets of their obligation to 
file notices of change in status.
---------------------------------------------------------------------------

    \302\ AEP at 3; E.ON at 8-9.
    \303\ AEP at 6.
    \304\ Moreover, we note that the NOPR did not propose to 
completely eliminate the requirement for RTO sellers to file 
triennial updated market power analyses but instead proposed to 
eliminate the need to file indicative screens with their triennials.
---------------------------------------------------------------------------

    235. We reject EEI's request to report minor changes in 
organization or other information covered by the change in status 
requirements cumulatively with another change in status filing instead 
of in separate change in status filings. Any change in other 
information covered by the change in status requirements must be 
reported within 30 days of the change. We interpret EEI's request to be 
that ``minor change'' be permitted to be filed more than 30 days after 
the change, i.e., at the time of the next change in status filing. 
Timely notice of reportable changes in status are part of the 
Commission's ex post analysis; \305\ it is not appropriate to exempt 
any changes from being reported within 30 days, particularly given that 
it is unclear when, if at all, those changes would ever be reported.
---------------------------------------------------------------------------

    \305\ Cal. ex rel. Harris v. FERC., 784 F.3d 1267, 1276 (9th 
Cir. 2015) (``When we approved market-based ratemaking in Lockyer, 
we repeatedly emphasized the importance of the `dual requirement of 
an ex ante finding of the absence of market power and sufficient 
post-approval reporting requirements.' '' (citing Cal. ex rel. 
Lockyer v. FERC, 383 F.3d 1006, 1013 (9th Cir. 2004)).
---------------------------------------------------------------------------

    236. Additionally, we reject EEI's proposal to increase the 100 MW 
change in status reporting threshold.\306\ We believe that the 100 MW 
threshold is reasonable, particularly given the trend towards building 
smaller units. Further, changing the value of the megawatt

[[Page 67088]]

threshold was not proposed in the NOPR; thus, the proposal is outside 
the scope of this rulemaking.
---------------------------------------------------------------------------

    \306\ EEI at 16.
---------------------------------------------------------------------------

    237. With regard to E.ON's request that the Commission clarify that 
the ``any relevant market'' language is limited to the applicable 
geographic region and applicable first-tier markets,\307\ we clarify 
that any relevant market refers to a market in which a seller already 
has generation located and acquires an additional 100 MW or a new 
market that the seller had not studied previously.
---------------------------------------------------------------------------

    \307\ E.ON at 10. E.ON uses the following example: If a seller 
owns or controls a generation facility in the PJM market and 
obtained market-based rate authorization, the fact that a new 
affiliate may own or control 100 MW or more of new generation in the 
CAISO market has no relevance to whether the seller in the PJM 
market lacks horizontal market power.
---------------------------------------------------------------------------

    238. Additionally, in response to E.ON's requests that the 
Commission clarify if a seller needs to submit a change in status if it 
acquires generation in an RTO market where it sells energy products, 
and clarify whether a seller has to file a change in status when an 
affiliate is granted market-based rate authority, we clarify as 
follows. A seller should submit a change in status when it acquires 
generation in any market, including an RTO market where it sells 
electric products. Further, if a seller's affiliate is granted market-
based rate authority, and that results in 100 MW or more of new 
generation capacity in a market, then the seller will have to file a 
corresponding change in status. Therefore, we reject E.ON's 
recommendation to revise the change in status policy so that only one 
substantive filing is submitted to the Commission.\308\
---------------------------------------------------------------------------

    \308\ E.ON at 11 (arguing that an initial market-based rate 
application of the new affiliate should suffice to address all other 
relevant, affiliated market-based sellers).
---------------------------------------------------------------------------

    239. In response to NextEra's contention that the notice of change 
in status proposal is confusing because it conflicts with the NOPR 
proposal to eliminate the requirement to provide indicative screens 
where all of a seller's and its affiliates' generation in the relevant 
market is committed under long-term power purchase agreements, we 
clarify as follows.\309\ For purposes of the change in status 
requirement in section 35.42(a)(1), long-term firm purchases should be 
treated as seller or affiliate-owned or controlled generation capacity 
in the determination of the 100 MW threshold. Thus, a seller need not 
make a change in status filing every time it enters into a new long-
term firm purchase agreement, but would need to submit a change is 
status when its overall cumulative increase in generation is 100 MW. 
The seller would need to revise its asset appendix to include the long-
term purchase agreement(s). In addition, we clarify that a market-based 
rate seller that adds new generation capacity that is fully committed 
to a non-affiliated buyer need not count that capacity toward the 100 
MW threshold.
---------------------------------------------------------------------------

    \309\ NextEra at 11.
---------------------------------------------------------------------------

    240. We clarify in response to EPSA that if a seller acquires more 
than 100 MW, it should report all of the newly acquired generation to 
ensure that the net change in generation capacity is reported in a 
timely manner. Furthermore, once a seller files a change in status for 
a net increase of 100 MW or more of generation capacity, the threshold 
is effectively reset such that the seller must file a change in status 
each time it acquires an additional 100 MW or more of generation 
capacity.
2. New Affiliation and Behind-the-Meter Generation
a. Commission Proposal
    241. Market-based rate sellers are required to make a change in 
status filing when, among other requirements in section 35.42 of the 
Commission's regulations, they become affiliated with entities that: 
(1) Own or control generation; (2) own or control inputs to electric 
power production; (3) own, operate, or control transmission facilities; 
or (4) have a franchised service territory. There currently is no 100 
MW threshold for reporting new affiliations (but there is a 100 MW 
threshold for net increases for a seller's owned or controlled 
generation facilities). In the NOPR, the Commission proposed to revise 
the change in status regulations to include a 100 MW threshold for 
reporting new affiliations. That is, a market-based rate seller that 
has a new affiliation would not be required to file a change in status 
for an affiliation with an entity with generation assets until its new 
affiliations result in a cumulative net increase of 100 MW or more of 
nameplate capacity in any relevant geographic market. The Commission 
noted that the 100 MW threshold for reporting new generation strikes 
the proper balance between the Commission's duty to ensure that market-
based rates are just and reasonable and the Commission's desire not to 
impose an undue regulatory burden on market-based rate sellers.\310\ 
Similarly, the Commission stated that applying the 100 MW threshold to 
new affiliations might ease the reporting burden on sellers without 
diminishing the Commission's ability to identify possible market power. 
Therefore, the Commission proposed to revise section 35.42(a)(2) of the 
Commission's regulations to add a 100 MW threshold for reporting 
certain new affiliations.
---------------------------------------------------------------------------

    \310\ Reporting Requirement for Changes in Status for Public 
Utilities with Market-Based Rate Authority, Order No. 652, FERC 
Stats. & Regs. ] 31,175, at P 68, order on reh'g, 111 FERC ] 61,413 
(2005).
---------------------------------------------------------------------------

    242. The Commission also clarified that the requirement to submit a 
notice of change in status to report affiliation with new generation, 
transmission, or intrastate gas pipelines includes reporting that asset 
in the seller's asset appendix. The Commission proposed to amend 
section 35.42(c) to clarify that sellers must include all new 
affiliates and any assets owned or controlled by the new affiliates in 
the asset appendix.
    243. The Commission further proposed in the NOPR that ``all 
assets'' include behind-the-meter generation and qualifying 
facilities.\311\ However, the Commission proposed to allow sellers to 
aggregate their behind-the-meter generation by balancing authority area 
or market into one line on the list of generation assets. Similarly, 
the Commission proposed to allow sellers to aggregate their qualifying 
facilities under 20 MW by balancing authority area or market into one 
line on the list of generation assets.
---------------------------------------------------------------------------

    \311\ Accordingly, the appendix must list all generation assets 
owned (clearly identifying which affiliate owns which asset) or 
controlled (clearly identifying which affiliate controls which 
asset) by the corporate family by balancing authority area, and by 
geographic region, and provide the in-service date and nameplate or 
seasonal ratings by unit. As a general rule, any generation assets 
included in a seller's market power study should be listed in the 
asset appendix. Order No. 697, FERC Stats. & Regs. ] 31,252 at P 
895.
---------------------------------------------------------------------------

    244. The Commission also proposed that sellers should include these 
assets in their indicative screens, as well as in their asset appendix 
and that sellers should include this generation when calculating the 
100 MW change in status threshold and the 500 MW Category 1 threshold.
b. Comments
    245. Commenters generally support the Commission's proposal to 
revise the change in status regulations to include a 100 MW threshold 
for reporting new affiliations.\312\ Specifically, EEI supports the 
Commission's proposal and adds that the Commission should consider 
allowing a seller the option to file an

[[Page 67089]]

addendum to its appendix B asset list with the change in status filing, 
instead of a complete new list, to show the specific changes in 
generation.\313\ FirstEnergy also supports the Commission's proposal, 
but argues that, if the new affiliation has previously been reviewed by 
the Commission pursuant to its authority under section 203 of the FPA, 
the Commission will derive no significant benefit by requiring the 
seller to submit a notice of change in status relating to such 
affiliation and recommends that the reporting requirement be further 
limited.\314\
---------------------------------------------------------------------------

    \312\ See, e.g., EEI at 15-16; FirstEnergy at 11-12; SunEdison 
at 9 (noting that this proposal is especially important to a company 
like SunEdison that routinely acquires or becomes affiliated with 
new entities that own small amounts of capacity); NRG Companies at 
11-12; APPA/NRECA at 4; Golden Spread at 7.
    \313\ EEI at 16.
    \314\ FirstEnergy at 11.
---------------------------------------------------------------------------

    246. FirstEnergy supports the proposal to require generating 
capacity associated with qualifying facilities and behind-the-meter 
generation to be considered when determining the applicability of the 
Commission's rules for filing notices of change in status and updated 
market power analyses.\315\ FirstEnergy contends that, to the extent 
qualifying facilities may be owned by or affiliated with entities 
owning other generation resources, there is no valid reason why owners 
of qualifying facilities and/or behind-the-meter generation resources 
should not be subject to the same rules as those applicable to other 
market participants.\316\
---------------------------------------------------------------------------

    \315\ Id. at 12.
    \316\ Id.
---------------------------------------------------------------------------

    247. Several commenters oppose the Commission's proposal to include 
behind-the-meter generation as part of the 100 MW change in status 
threshold.\317\ NRG Companies and NextEra argue that requiring the 
inclusion of behind-the-meter generation in asset appendices and market 
power analyses would impose a substantial burden on sellers.\318\ NRG 
Companies and NextEra also argue that no useful purpose will be served 
by the inclusion of behind-the-meter generation that is committed to 
on-site consumption and not available to the grid.\319\ NRG Companies 
and NextEra add that such generation may involve net metering, which 
they state does not involve wholesale sales or transmission implicating 
the Commission's jurisdiction.\320\
---------------------------------------------------------------------------

    \317\ See, e.g., NextEra at 12; NRG Companies at 2-3 (stating, 
however, that the proposal makes sense as to qualifying facilities); 
SunEdison 5-8.
    \318\ NRG Companies at 3 (stating that distributed generation 
projects can be developed and installed in very short time periods 
and tracking these projects with the frequency required to maintain 
accurate asset appendices would be burdensome on any entity whose 
affiliates are active in this area); NextEra at 12 (stating that the 
burden to include behind-the-meter generation will increase 
significantly, if there are numerous facilities within a corporate 
family).
    \319\ NextEra at 12-13 (stating that, because of their small 
size, such facilities are unlikely to affect meaningfully any 
evaluation of market power in the indicative screens and adding that 
there would be little or no value to the Commission in submitting a 
notice of change in status in addition to the initial applications 
and market power updates); NRG Companies at 2-3.
    \320\ NextEra at 13; NRG Companies at 2-3 (citing Sun Edison 
LLC, 129 FERC ] 61,146, at P 18 (2009) (Sun Edison)).
---------------------------------------------------------------------------

    248. NRG Companies, NextEra, and SunEdison argue that behind-the-
meter generation does not contribute to market power and should be 
excluded from the asset appendix.\321\ SunEdison argues that it is 
inconsistent to require listing of assets that are not engaged in 
wholesale power sales in the interstate power market and therefore 
cannot and do not contribute to the seller's market share or market 
power.\322\ SunEdison argues that, because the purpose of an asset 
appendix is to provide data to be used in the Commission's assessment 
of a seller's and its affiliates' market power in jurisdictional 
wholesale markets, the Commission should find that assets that do not 
participate in wholesale markets should not be included in the asset 
appendix.\323\ SunEdison further contends that, since behind-the-meter 
facilities are not physically capable of engaging in coordinated 
interactions or arrangements with generation that sells power in 
jurisdictional markets, there is no need to include them in a seller's 
asset appendix.\324\ SunEdison requests that, if the Commission 
determines it necessary to report behind-the-meter generation in the 
asset appendix, it should exempt from this requirement facilities with 
a net capacity of one MW or less.\325\
---------------------------------------------------------------------------

    \321\ SunEdison at 4 (stating that the requirement will be 
``unduly burdensome'' for a company that owns ``hundreds of small 
behind-the-meter solar projects'' and whose business plan is for it 
and its affiliates to develop and acquire ``thousands of additional 
similar projects'' and citing Commission precedent where the 
Commission held that net-metered sales do not represent 
jurisdictional wholesale sales or transmission). SunEdison also 
references the White House and U.S. Department of Energy initiative 
to streamline the permitting, installation, and interconnection 
processes and states that reducing unnecessary administrative 
burdens on companies that develop solar energy projects is one way 
to help achieve this goal. Id. at 4-5.
    \322\ Id. at 5.
    \323\ Id. at 7.
    \324\ Id.
    \325\ Id. at 9 (citing Revisions to Form, Procedures, and 
Criteria for Certification of Qualifying Facility Status for a Small 
Power Production or Cogeneration Facility, Order No. 732, 75 FR 
15950 (Mar. 30, 2010), FERC Stats. & Regs. ] 31,306, at P 34 (2010) 
and comparing its argument for why behind-the-meter generation 
should not be included in a seller's asset appendix to the 
Commission's reasoning in Order No. 732 to exempt small facilities 
from the Commission's Qualifying Facility status filing 
requirement).
---------------------------------------------------------------------------

    249. El Paso recognizes the increasing role of behind-the-meter 
generators in wholesale power markets and does not oppose the 
Commission's inclusion of behind-the-meter generation in the indicative 
screens.\326\ However, El Paso cautions the Commission to recognize 
that for some systems, the output of these generators will have already 
been reflected in the net load reported in the FERC Form No. 714 
(Annual Electric Control and Planning Area Report), thus resulting in 
double-counting a utility's capacity and, consequently, overestimating 
its supply.\327\ El Paso requests that the Commission further refine 
its reporting directive to instruct sellers to include behind-the-meter 
generation in their indicative screens to the extent such generation is 
not already netted against load for purposes of their FERC Form No. 714 
reporting.\328\
---------------------------------------------------------------------------

    \326\ El Paso at 4.
    \327\ Id.
    \328\ Id.
---------------------------------------------------------------------------

    250. Other commenters seek clarification of the Commission's 
proposed changes to the change in status reporting requirements, as 
they relate to behind-the-meter generation. Specifically, EPSA argues 
that, if a seller has behind-the-meter generation that is used solely 
to operate equipment for production (such as an oil or gas operation 
that uses behind-the-meter generation to produce oil or gas), such 
behind-the-meter generation should not be counted towards the 100 MW 
threshold because that generation is never offered or sold into the 
market. EPSA recommends the Commission clarify that any such behind-
the-meter generation that is wholly self-consumed would not count 
towards the 100 MW threshold.\329\ SoCal Edison requests the Commission 
clarify whether behind-the-meter generation includes generation not 
synchronized to the grid (i.e., generation that cannot be used for 
wholesale power sales), since all generation is typically behind some 
meter.\330\ SoCal Edison does not believe, for example, that a back-up 
generator used to power a control center in the event of a power outage 
needs to be included in a seller's asset appendix and seeks 
confirmation to that effect.\331\ SoCal Edison also requests that the 
Commission clarify whether it will permit sellers to aggregate long-
term firm purchases from small generators (such as qualifying 
facilities under 20 MW) by balancing authority area or market into one 
line on the list of

[[Page 67090]]

generation assets.\332\ SoCal Edison argues that such aggregation 
should be permitted to relieve the burden that otherwise would be 
imposed.\333\
---------------------------------------------------------------------------

    \329\ EPSA at 11.
    \330\ SoCal Edison at 19 (emphasis in original).
    \331\ Id.
    \332\ Id. at 23.
    \333\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    251. We adopt the NOPR proposal to establish a 100 MW threshold for 
reporting new affiliations in change of status filings. A market-based 
rate seller that has a new affiliation will not be required to file a 
change in status for an affiliation with an entity with generation 
assets until its new affiliations result in a cumulative net increase 
of 100 MW of capacity in a relevant geographic market.\334\ The 100 MW 
threshold for new affiliations will be determined in exactly the same 
manner as the 100 MW threshold is determined for other notices of 
change in status. As explained above, the 100 MW threshold will be 
determined for each relevant geographic market but will not consider 
generation capacity additions in first-tier markets. We believe the 100 
MW threshold strikes a reasonable balance between reducing reporting 
burden on sellers while keeping the Commission informed about potential 
market power concerns. We clarify that the 100 MW reporting threshold 
for new affiliations is not separate nor distinct from the 100 MW 
thresholds for reporting power purchase agreements or owned generation 
as discussed elsewhere in this Final Rule. In other words, if a seller 
becomes newly affiliated with 50 MW of generation in a balancing 
authority area or market and experiences an increase of 50 MW of owned 
generation in that same balancing authority area or market, the 100 MW 
reporting threshold would be triggered. Similarly, a seller with a 
newly acquired 50 MW power purchase agreement in that same balancing 
authority area of market would also trigger the reporting threshold.
---------------------------------------------------------------------------

    \334\ However, if a seller files a notice of change in status 
for another reason, e.g., to report the entrance into a power 
purchase agreement of more than 100 MW, the seller should note that 
it has a new affiliate with market-based rate authority and include 
that new affiliate and any related assets in the seller's asset 
appendix.
---------------------------------------------------------------------------

    252. However, we do not adopt the NOPR proposal to count behind-
the-meter generation in the 100 MW change in status threshold and 500 
MW Category 1 seller status threshold and to include such generation in 
the asset appendices and indicative screens.
    253. We agree with El Paso that the output of behind-the-meter 
generation should be reflected in the load data reported in the FERC 
Form No. 714. That is, the load reported in FERC Form No. 714 reflects 
the fact that the load is lower than it otherwise would be if a portion 
of the load were not served by behind-the-meter generation. 
Additionally, since behind-the-meter generation is netted out of the 
load data, requiring sellers to count behind-the-meter generation as 
installed capacity could result in double-counting a portion of the 
seller's generation capacity. Moreover, we clarify that behind-the-
meter generation that is consumed on-site by the host load and not sold 
into the wholesale market, or is not synchronized to the transmission 
grid, is not relevant to the Commission's horizontal market power 
analysis.
    254. Given our decision not to require sellers to include behind-
the-meter generation in their asset appendices, indicative screens, and 
for purposes of calculating the 100 MW change in status threshold and 
500 MW Category 1 threshold, we will not address the remaining requests 
for clarifications made by NRG Companies, NextEra, SunEdison, EPSA, and 
SoCal Edison.
    255. Finally, we clarify that qualifying facilities that are exempt 
from FPA section 205 \335\ and facilities that are behind-the-meter 
facilities do not need to be reported in the asset appendix or 
indicative screens. However, many qualifying facilities do have market-
based rate authority and the capacity of these facilities should be 
reported in the screens, asset appendix and in determining the 100 MW 
threshold.
---------------------------------------------------------------------------

    \335\ See 18 CFR 292.601(c)(1).
---------------------------------------------------------------------------

3. Reporting of Long-Term Firm Purchases
a. Commission Proposal
    256. As discussed elsewhere in this Final Rule, the Commission 
proposed to require reporting of long-term firm purchases in the 
indicative screens and also proposed to include such contracts when 
determining the 100 MW threshold for change in status filings.\336\
---------------------------------------------------------------------------

    \336\ NOPR, Stats. & Regs. ] 32,702 at P 100.
---------------------------------------------------------------------------

b. Comments
    257. The comments addressed in the discussion on treatment of long-
term contracts generally encompass the issues in this section. However, 
SoCal Edison states that the Commission should clarify that it will 
permit long-term firm purchase aggregation from small generators, such 
as qualifying facilities under 20 MW. SoCal Edison requests that such 
aggregation be permitted to relieve the burden that otherwise would be 
imposed.\337\
---------------------------------------------------------------------------

    \337\ SoCal Edison at 23.
---------------------------------------------------------------------------

c. Commission Determination
    258. The requirement to report long-term firm purchases in the 
asset appendix and indicative screens and to require that such 
contracts be counted towards the 100 MW threshold is discussed 
elsewhere in this Final Rule.\338\ With respect to SoCal Edison's 
request regarding aggregation of long-term firm purchase agreements, we 
clarify that aggregation of such agreements will be permitted in the 
asset appendix if certain conditions are met. Specifically, we will 
allow aggregation of long-term firm purchase agreements from small 
generators only if the information in these columns in the asset 
appendix is identical for all agreements: ``[E] Market/Balancing 
Authority Area,'' ``[F] Geographic Region,'' ``[G] Start Date (mo/da/
yr),'' and ``[H] End Date (mo/da/yr).'' Aggregating agreements with 
different start dates or end dates or agreements in different Market/
Balancing Authority Areas would defeat the usefulness of collecting 
such information. We also clarify that a seller that meets these 
criteria can aggregate such agreements but would need to use column 
``[I] End Note'' to report different docket numbers and/or names of the 
filing entities and seller(s) in the End Note list of the asset 
appendix.
---------------------------------------------------------------------------

    \338\ See supra Section IV.C.1.
---------------------------------------------------------------------------

D. Asset Appendix

    259. The Commission proposed clarifications and revisions to the 
required appendix that contains the lists of generation and 
transmission assets.
1. Changes to the Existing Columns
a. Commission Proposal
    260. The Commission proposed to make three changes to the existing 
columns in the asset appendix. The Commission proposed to change a 
column heading on both assets lists from ``Balancing Authority Area'' 
to ``Market/Balancing Authority Area'' to reflect the correct location 
for assets in organized markets as well as in balancing authority 
areas. The second proposal was to change a column heading on both asset 
lists from ``Geographic Region (per Appendix D)'' to ``Geographic 
Region'' because there have been changes to some regions since the 
Commission originally published the region map in Appendix D of Order 
No. 697. Finally, the Commission proposed to change the heading for the 
``Nameplate and/or Seasonal Rating'' column of the generation list to 
``Capacity Rating (MW): Nameplate, Seasonal, or Five-Year Average'' to

[[Page 67091]]

clarify that this column requires capacity ratings in megawatts and to 
reflect that each submission in the asset appendix should use either 
``nameplate,'' ``seasonal,'' or ``five-year average'' ratings to 
reflect the rating used throughout the filing for a particular 
generation technology. The Commission indicated that these proposed 
changes would ensure consistency across filings and allow the industry 
and Commission staff to better utilize the information contained in the 
asset lists.
    261. The Commission further proposed to clarify that the asset 
lists should not contain any information other than what is required in 
the respective columns. For instance, sellers frequently include 
footnotes in their appendices that cause the appendices to become 
unwieldy and difficult to read or understand. Sellers sometimes explain 
in these footnotes that some facilities are partially owned, that some 
affiliates included in their asset lists may not actually be affiliates 
but are included out of an abundance of caution, or that a facility is 
expected to come on-line or off-line at some future date. The 
Commission discouraged any such footnotes and directed that any such 
representations be made in the filing transmittal letter.
    262. Thus, the Commission proposed to modify the example of the 
required appendix found in appendix B to subpart H of part 35 of the 
Commission's regulations to incorporate these changes.
b. Comments
    263. Few commenters express concern about the Commission's proposed 
changes to the existing columns in the asset appendix.\339\ Solomon/
Arenchild are concerned that the proposal to change the heading for 
capacity ratings column from ``Nameplate and/or Seasonal Rating'' to 
``Capacity Rating (MW): Nameplate, Seasonal, or Five-Year Average'' may 
introduce ``another potential source of inconsistency across filings'' 
and therefore suggest that the Commission add another column to the 
asset appendix to allow a seller to report nameplate or seasonal 
ratings, as well as the five-year average rating, if the seller elects 
to use five-year average ratings.\340\ EEI states that the Commission's 
proposed changes to existing columns seem appropriate, but would 
encourage the Commission not to change the geographic regions without 
advance notice and opportunity for comment by market participants in 
those regions.\341\
---------------------------------------------------------------------------

    \339\ See, e.g., Solomon/Arenchild at 7; EEI at 17.
    \340\ Solomon/Arenchild at 7 & Attachment 1 (illustrating their 
proposed additional column to the asset appendix).
    \341\ EEI at 17.
---------------------------------------------------------------------------

    264. Several commenters oppose the Commission's proposal to clarify 
that asset lists should not contain any information other than what is 
required in the respective columns.\342\ EPSA notes that the reason 
sellers include footnotes and other ``extraneous information'' is to 
avoid allegations that the sellers have misled the Commission.\343\ 
EPSA requests that the Commission add a separate column to the asset 
appendix for explanatory notes and clarifications, instead of 
prohibiting the use of footnotes.\344\ NRG Companies echo EPSA's 
concerns and state that sellers include explanatory notes to avoid 
misleading the Commission about matters that are too complex to be 
depicted fully and accurately in the prescribed fields.\345\ NRG 
Companies add that providing the explanatory notes in the transmittal 
letter will not be an adequate substitute for appropriate notes in the 
asset appendix itself.\346\ El Paso argues that discouraging sellers 
from adding footnotes to their asset appendices could cause confusion 
amongst industry particularly if the Commission creates a searchable 
public database from these asset appendices because sellers may 
unintentionally provide misleading information.\347\ EEI notes that 
this clarification seems unnecessary and could inhibit sellers from 
including helpful information in the asset appendix.\348\
---------------------------------------------------------------------------

    \342\ See, e.g., EEI at 18; El Paso at 5; EPSA at 13; NRG 
Companies at 6.
    \343\ EPSA at 13.
    \344\ Id.
    \345\ NRG Companies at 6.
    \346\ Id. at 7.
    \347\ El Paso at 5 (arguing that members of the public may not 
take the time to search the original transmittal letter that would 
explain a seller's ownership).
    \348\ EEI at 18.
---------------------------------------------------------------------------

c. Commission Determination
    265. We adopt the proposed changes to the existing columns in the 
asset appendix on both asset lists from ``Balancing Authority Area'' to 
``Market/Balancing Authority Area'' to reflect the correct location for 
assets in organized markets, as well as in balancing authority areas. 
We also adopt the proposed column heading change from ``Geographic 
Region (per Appendix D)'' to ``Geographic Region'' because there have 
been changes to some regions since the Commission originally published 
the region map in Appendix D of Order No. 697. We note, with regard to 
EEI's comment, that removing the reference to Appendix D removes an 
outdated reference to the Appendix in Order No. 697. Further, to aid in 
identification of similarly named columns in the asset lists, we are 
adding an alphabetic label to each column in the asset lists in the new 
Asset Appendix.\349\
---------------------------------------------------------------------------

    \349\ For example, the first column in the generation asset list 
is ``Filing Entity and its Energy Affiliates.'' We have labeled that 
column, above the column heading, as Column ``[A].''
---------------------------------------------------------------------------

    266. We do not adopt the proposal to change the heading for the 
``Nameplate and/or Seasonal Rating'' column of the generation list to 
``Capacity Rating (MW): Nameplate, Seasonal, or Five-Year Average.'' 
Instead, in response to the Solomon/Arenchild comments, we will modify 
the generation asset list to clearly distinguish between the nameplate 
rating and an alternative rating of a generation facility. 
Specifically, we are removing the ``Nameplate and/or Seasonal Rating'' 
column and replacing it with three new Columns [J], [K], and [L], 
entitled ``Capacity Rating: Nameplate (MW)'', ``Capacity Rating: Used 
in Filing (MW)'', and ``Capacity Rating: Methodology Used in [K]: 
(N)ampelate, (S)easonal, 5-yr (U)nit, 5-yr (E)IA, (A)lternative,'' 
respectively.\350\ Sellers will populate Column [J] with the nameplate 
capacity rating of their facilities, Column [K] with the capacity 
rating attributed to that facility in the filing and any associated 
market power study, and Column [L] with the appropriate letter to 
indicate which rating methodology was used to derive the capacity 
rating used in Column [K].\351\ Sellers will need to populate every 
column for all facilities in the generation asset list, even facilities 
that are not discussed in a given filing. If the instant filing does 
not contain a market power study, or a particular generation asset is 
not included in a market power study in that filing, sellers should 
include in the generation asset list the rating that it used the last 
time the asset was included in a market power study. We believe this 
format addresses Solomon/Arenchild's concern about consistency of the 
rating methodology across filings,

[[Page 67092]]

while maintaining the ability to tie asset appendix ratings to those 
used in a market power analysis.
---------------------------------------------------------------------------

    \350\ As discussed in this Final Rule, sellers are allowed to 
use alternative rating methodologies for different generation 
technologies in their market power studies. The ``Capacity Rating: 
Used in Filing (MW)'' column is where sellers should report the 
actual value they used in the market power analysis. If a seller 
uses nameplate ratings, the values in Column [J] ``Capacity rating 
nameplate (MW)'' and Column [K] ``Capacity rating: used in filing 
(MW)'' will be the same.
    \351\ For example, for a seller that has decided to use 
nameplate ratings for all wind facilities in its market power 
studies and owns a 100 MW (nameplate) wind facility, the seller will 
place ``100'' in Column [J], ``100'' in Column [K], and ``N'' in 
Column [L].
---------------------------------------------------------------------------

    267. Finally, we adopt the NOPR proposal to prohibit footnotes from 
the asset appendices. However, in response to commenters' concerns 
about loss of clarity and information, we adopt EPSA's suggestion and 
add a separate column to the asset appendix for explanatory notes and 
clarifications. We are adding a column entitled ``End Note Number 
(Enter text in End Note Tab)'' as the final column in the generation 
list (Column [M]), transmission list (Column [J]), and, as discussed 
below, the new long-term firm power purchase agreement list (Column 
[I]), and creating an additional end notes list. The end notes list 
will have three columns: Column [A] ``End Note Number;'' Column [B] 
``List (Generation, PPA, or Transmission);'' and Column [C] 
``Explanatory Note.'' When a seller wants to provide more information 
about a particular facility in an asset appendix list, the seller will 
place a number in the appropriate end note column of the row listing 
that facility. Furthermore, the seller will then enter that number in 
Column [A] of the end notes list, specify in Column [B] which asset 
list this end note refers to, and finally, enter in Column [C] the 
explanatory text.
2. Reporting Power Purchase Agreements
a. Commission Proposal
    268. The Commission also proposed to require sellers to include all 
of their long-term firm purchases of capacity and/or energy in their 
indicative screens and asset appendices, regardless of whether the 
seller has operational control over the generation capacity supplying 
the purchased power. The Commission stated that this approach will help 
size the market correctly and will establish consistent treatment of 
long-term firm sales and long-term firm purchases.\352\ Other sections 
of this Final Rule discuss the conversion of a power purchase agreement 
measured in MWh into MW values that will be entered into the asset 
appendix and indicative screens.
---------------------------------------------------------------------------

    \352\ NOPR, FERC Stats. & Regs. ] 32,702 at PP 16, 79.
---------------------------------------------------------------------------

b. Comments
    269. Several commenters requested clarification regarding how to 
account for long-term firm purchases in the asset appendix. For 
example, SoCal Edison states that it will not be possible to fill out 
the asset appendix as currently proposed where a long-term firm 
purchase is not tied to a physical generating asset and suggests 
separating the appendix into two appendices--one for seller's/
applicant's generation and one for seller's/applicant's long-term firm 
purchases.\353\ SoCal Edison states that if the Commission does not 
change the asset appendix headings as requested, the Commission should 
hold a technical conference to address questions raised by the change 
in policy regarding the reporting of long-term firm purchases.\354\ 
NextEra opposes the reporting of long-term power purchase agreements in 
the asset appendix but states that if the Commission decides to require 
this reporting it should allow the use of EIA regional data for 
facilities that do not yet have seasonal or a five-year average 
capacity rating.\355\
---------------------------------------------------------------------------

    \353\ SoCal Edison at 21.
    \354\ Id. at 23.
    \355\ NextEra at 13-14.
---------------------------------------------------------------------------

c. Commission Determination
    270. We do not find the comments opposed to reporting of long-term 
firm purchases in the asset appendix to be persuasive and adopt the 
NOPR proposal to require sellers to report all of their long-term firm 
purchases of capacity and/or energy in their indicative screens and 
asset appendices. However, we agree with commenters that the format of 
the generation asset list is not well suited for reporting long-term 
purchases. Therefore, we are implementing SoCal Edison's recommendation 
to create a separate list for a seller's long-term firm purchases.\356\ 
The new long-term purchases list has columns similar to the generation 
list, but removes several inapplicable columns (Generation Name, Owned 
By, Controlled By, and Date Control Transferred), and adds ``Start Date 
(mo/da/yr)'' and ``End Date (mo/da/yr)'' columns.
---------------------------------------------------------------------------

    \356\ SoCal Edison at 21.
---------------------------------------------------------------------------

    271. NextEra requests that purchasers under a long-term firm power 
purchase agreement be allowed to use EIA regional data. As discussed 
above in the section on capacity ratings, we permit use of EIA regional 
data but only for energy-limited facilities that lack five years of 
operating data or for non-affiliated energy-limited facilities for 
which the seller cannot obtain operating data.\357\ We also will 
require that sellers de-rate all generators using the same technology 
in a consistent manner. Thus, if a purchaser can identify which 
generation units are fulfilling a long-term firm PPA, it should use the 
same rating methodology for that facility in its market power study 
that it is using for other generation facilities utilizing that 
technology.
---------------------------------------------------------------------------

    \357\ As discussed above, the Commission will not permit de-
rating of solar photovoltaic facilities. See supra Section 
IV.A.6.c.i.
---------------------------------------------------------------------------

3. Clarifications Regarding the Existing Columns
a. Commission Proposal
    272. The Commission noted that its post-Order No. 697 experience 
has been that, with respect to the column in the list of generation 
assets that is currently labeled ``Nameplate and/or Seasonal Rating,'' 
some sellers report only the portion of the capacity that they 
own,\358\ whereas other sellers report the entire capacity of the 
facility. Additionally, some sellers include in their generation asset 
lists facilities in which they have claimed a relationship through only 
passive, non-controlling interests.
---------------------------------------------------------------------------

    \358\ The Commission noted that it has not permitted market-
based rate sellers to dilute the ownership share of generation 
attributed to the seller or its affiliates based on multiplying 
successive shares of partial ownership in a company. See Kansas 
Energy LLC, Trademark Merchant Energy, LLC, 138 FERC ] 61,107, at P 
28 (2012). Instead, sellers must account for generation capacity 
owned or controlled by the seller and its affiliates for purposes of 
analyzing horizontal market power. See id. P 37.
---------------------------------------------------------------------------

    273. The Commission proposed the following clarifications with 
respect to the asset appendix: (1) A seller must enter the entire 
amount of a generator's capacity (in MWs) in the ``Capacity Rating 
(MW): Nameplate, Seasonal, or Five-Year Average'' column of the 
generation list even if the seller only owns part of a facility; (2) a 
seller should list only one of the following as a ``use'' in the 
``Asset Name and Use'' column of the transmission list: Transmission, 
intrastate natural gas storage, intrastate natural gas transportation, 
or intrastate natural gas distribution; and (3) entities and generation 
assets in which passive ownership interests have been claimed should 
not be included in the horizontal market power indicative screens or 
reported in the appendix.\359\
---------------------------------------------------------------------------

    \359\ The Commission noted that sellers must demonstrate why 
such ownership interests should be deemed passive. NOPR, FERC Stats. 
& Regs. ] 32,702 at P 116 n.129 (citing AES Creative Resources, L.P. 
et al., 129 FERC ] 61,239 (2009) (AES Creative)).
---------------------------------------------------------------------------

    274. The Commission explained that if a seller does not believe 
that the entire capacity of a generation facility should be included in 
its indicative screens, it may explain its position in the transmittal 
letter filed with its horizontal market power screens, including 
letters of concurrence where appropriate,\360\ and thus account for 
only its portion of that particular generation facility in the 
indicative

[[Page 67093]]

screens. However, the entire capacity of the facility should be 
reflected in the list of generation assets in the appendix.
---------------------------------------------------------------------------

    \360\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 187.
---------------------------------------------------------------------------

    275. The Commission noted that generating units within a single 
plant may be aggregated in a single row of the generation list if the 
information in the other columns is the same for all units, but 
separate plants cannot be aggregated into a single row. As discussed 
and adopted elsewhere in this Final Rule,\361\ the Commission proposed 
that qualifying facilities less than 20 MW may be aggregated by 
balancing authority area or market into one line in the generation 
asset list. The Commission further clarified that each asset should be 
listed only once; if it is owned by more than one affiliate, all 
affiliate names should be included in the ``Owned By'' column. If a 
company or an affiliate is registered in the Commission's company 
registration database,\362\ the Commission proposed to clarify that the 
name in the asset appendix for that company must appear exactly the 
same as in the registration database.
---------------------------------------------------------------------------

    \361\ See supra Section IV.C.2.c.
    \362\ The term ``company registration database'' here refers to 
``FERC's Online Company Registration application'' (see http://www.ferc.gov/docs-filing/etariff/implementation-guide.pdf). However, 
Commission orders have referred to this database as we have also 
issued orders referring to it as ``Company Registration,'' (see 
Filing Via the Internet, Revisions to Company Registration and 
Establishing Technical Conference, 142 FERC ] 61,097 (2013)) or 
``Company Registration system'' (see Filing Requirements for El. 
Utility S.A., Order Updating Electric Quarterly Report Data 
Dictionary, 146 FERC ] 61,169 (2014)).
---------------------------------------------------------------------------

    276. With respect to the ``Date Control Transferred'' column in 
both the generation and transmission asset lists, the Commission 
proposed to clarify that the ``Date Control Transferred'' column should 
identify the date on which a contract or other transaction that 
transfers control over a facility became effective. The Commission 
noted that where appropriate, sellers may enter ``N/A'' in this field 
to indicate that it is not applicable to their asset(s) and explain why 
in the end note list.
    277. With respect to the ``Size'' column in the list of 
transmission assets, the Commission proposed to clarify that the 
``Size'' refers to both the length of the transmission line (i.e., feet 
or miles) and the capability of the line in voltage (kV). The 
Commission noted that sellers may aggregate their transmission assets 
by voltage. For instance, a seller that owns a transmission system with 
several hundred transmission lines might include two rows in the 
transmission asset list; one row with 200 miles of 138 kV lines listed 
in the ``Size'' column and another row with 100 miles of 230 kV lines 
listed in the ``Size'' column as long as all the other columns (e.g., 
owned by, controlled by, balancing authority area, geographic region, 
etc.) remain the same for all assets aggregated in that row. The name 
for such aggregated facilities should describe the lines that are being 
aggregated, e.g., ``230 kV transmission lines.''
i. Entire Amount of Generator's Capacity in Asset Appendix
(a) Comments
    278. Several commenters express concern over the Commission's 
proposal to require a seller to include the entire amount of a 
generator's capacity in its asset appendix, even if the seller only 
owns part of a facility.\363\ Idaho Power, EEI, and FirstEnergy argue 
that this proposal may lead to double counting many generation 
facilities, or would otherwise lead to confusion.\364\ FirstEnergy also 
argues that the proposal will result in the amount of generation 
capacity reported by a seller in its asset appendix to differ from the 
amount of generation capacity reflected in its indicative screens, 
which may cause confusion over the amount of generation capacity 
controlled by the reporting entity.\365\ NextEra adds that the 
information in the asset appendix may not match the information in the 
transmittal letter, which only includes a seller's ownership interest 
in the generation facility where it has demonstrated its partial 
ownership (or lack of control over).\366\ Idaho Power, NextEra, and El 
Paso suggest that, if the Commission adopts this requirement, it should 
add a column to the asset appendix to allow a seller to declare the 
percentage of the generation facility it owns or controls.\367\
---------------------------------------------------------------------------

    \363\ See, e.g., Idaho Power at 2, 4; EEI at 17; FirstEnergy at 
12-13; NextEra at 14-15; El Paso at 4-5.
    \364\ Idaho Power at 2, 4 (explaining that, if a seller enters 
the entire amount of the generator's capacity when it owns just a 
share of the generating asset, it is unclear how the Commission 
would ensure that the generation capacity is not being counted 
twice); EEI at 17 (explaining that, if multiple sellers have an 
interest in an asset, and each lists the asset's entire generation, 
the seller may over count the facility's capacity); FirstEnergy at 
12-13 (explaining that each joint owner including the entire 
generating capacity of a jointly owned facility may result in 
double-counting).
    \365\ FirstEnergy at 12-13.
    \366\ NextEra at 14.
    \367\ Idaho Power at 2, 4; NextEra at 15 (expressing concern 
over the public having to search for the seller's transmittal letter 
in which the seller declares its partial interest); El Paso at 4-5 
(recommending that the Commission add a ``Percentage of Ownership/
Control'' column to the asset appendix that would allow a seller to 
identify the percentage of a generation facility that the seller 
owns or controls).
---------------------------------------------------------------------------

(b) Commission Determination
    279. We adopt the NOPR's proposed clarification that a seller must 
enter the entire amount of a generator's capacity in the generation 
asset list. In response to commenters' concerns that the NOPR proposal 
could result in double counting, confusion, or other inconsistencies, 
we believe we have addressed those concerns through the addition of 
capacity rating and end notes columns discussed above. Specifically, as 
discussed more fully above, we are adopting Solomon/Arenchild's 
proposal to add a new end notes column where sellers will be able to 
place explanatory notes.\368\ To the extent a seller is attributing to 
itself less than a facility's full capacity rating, the seller can 
explain that in the end notes column.
---------------------------------------------------------------------------

    \368\ See supra Section IV.D.1.c.
---------------------------------------------------------------------------

ii. Size Column in Transmission Asset List
(a) Comments
    280. SoCal Edison questions the continued need for mileage of 
transmission assets as required in the asset appendix for entities that 
own integrated transmission networks rather than number of 
interconnection customer's interconnection facilities. SoCal Edison 
argues that the total length in miles of a utility's integrated network 
transmission assets has no meaningful relationship to the ability to 
exercise vertical market power. SoCal Edison further argues that one of 
the aims of the distributed generation movement is to slow transmission 
growth, such that a lack of transmission system growth could merely 
reflect state preference for distributed generation over long-distance 
transmission. Finally, SoCal Edison argues that FERC Form No. 1 
provides the Commission an annual update of the transmission mileage 
for major utilities and should prove sufficient for analysis. SoCal 
Edison recommends that the Commission explain the need to track mileage 
of transmission lines in service and how it relates to vertical market 
power, particularly in light of third parties' ability to build new 
transmission additions under Order No. 1000.\369\
---------------------------------------------------------------------------

    \369\ Transmission Planning and Cost Allocation by Transmission 
Owning and Operating Public Utilities, Order No. 1000, FERC Stats. & 
Regs. ] 31,323 (2011), order on reh'g, Order No. 1000-A, 139 FERC ] 
61,132, order on reh'g, Order No. 1000-B, 141 FERC ] 61,044 (2012), 
aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 
2014).
---------------------------------------------------------------------------

(b) Commission Determination
    281. We disagree with SoCal Edison that reporting the mileage of

[[Page 67094]]

transmission assets as required in the asset appendix for entities that 
own integrated transmission networks is unnecessary for a transmission 
market power analysis. While we agree that the total length in miles of 
a utility's integrated network transmission assets has no direct 
relationship to the ability to exercise vertical market power, the 
asset appendix is not intended to provide a detailed study of a 
transmission owner's system. Instead, the transmission asset list, like 
the generation asset list, provides a comprehensive list of the assets 
owned or controlled by a market-based rate seller and identifies the 
relevant transmission assets of sellers in wholesale power markets. 
Collecting this information adds transparency to the market and allows 
the public the opportunity to provide comments on a seller's 
transmission assets. However, as noted in the NOPR, sellers are 
permitted to aggregate similar assets in a balancing authority area, 
which will reduce the burden associated with preparing the asset 
lists.\370\
---------------------------------------------------------------------------

    \370\ NOPR, FERC Stats. & Regs. ] 32,702 at P 118.
---------------------------------------------------------------------------

iii. Passive Ownership
(a) Comments
    282. Some commenters took issue with the Commission's proposal to 
clarify that entities and generation assets in which passive ownership 
interests have been claimed should not be reported in the asset 
appendix.\371\ EEI states that the clarification seems appropriate, but 
vague.\372\ EEI asks whether partial passive ownership by anyone is 
enough to exclude the asset from the asset appendix, or whether passive 
ownership as the seller's only interest in the asset is what is 
required for that seller to exclude the asset from its asset 
appendix.\373\
---------------------------------------------------------------------------

    \371\ See, e.g., EEI at 17; AAI at 7-9.
    \372\ EEI at 17.
    \373\ Id.
---------------------------------------------------------------------------

    283. However, AAI cautions the Commission against eliminating the 
passive ownership interests reporting requirement. AAI argues that a 
passive interest can still affect competitive dynamics in the market 
because control is not the sole factor to determine whether an entity 
exercises market power.\374\ AAI further argues that eliminating the 
reporting requirement could encourage generation owners to acquire 
undisclosed passive interests that enhance their incentive to engage in 
generation withholding and other abusive market behavior.\375\
---------------------------------------------------------------------------

    \374\ AAI at 7-8.
    \375\ Id. at 7-9
---------------------------------------------------------------------------

(b) Commission Determination
    284. We clarify that sellers should not include in their asset 
appendices entities and facilities for which they have claimed, and 
demonstrated to the Commission, that the only relationship is through 
passive, non-controlling interests consistent with AES Creative (i.e., 
where the seller has a strictly passive ownership interest in another 
entity, or another entity has a strictly passive ownership interest in 
the seller). This is consistent with current Commission practice. As 
noted in the NOPR, sellers must demonstrate why such a relationship 
should be deemed passive.\376\ We are not persuaded by AAI's concerns 
that eliminating this reporting requirement could encourage generation 
owners to acquire undisclosed passive interests. We stress that we are 
not eliminating the requirement to demonstrate passivity; we are merely 
articulating our existing expectations. As noted above, we will 
continue to require that any seller that claims certain interests are 
passive or non-controlling must meet the standards set out in AES 
Creative.
---------------------------------------------------------------------------

    \376\ NOPR, FERC Stats. & Regs. ] 32,702 at P 116 n.130 (citing 
AES Creative, 129 FERC ] 61,239).
---------------------------------------------------------------------------

iv. Other Issues
    285. The Commission proposed clarifications regarding: Populating 
the ``Use'' column in the transmission asset list; listing each asset 
once in an asset list; matching seller and affiliate names in the asset 
lists with the name registered in the Commission's company registration 
database where possible; and the use of the ``Date Control 
Transferred'' column in the transmission asset list.
(a) Comments
    286. We did not receive any comments directly related to the 
aforementioned proposals. However, Solomon/Arenchild raised a concern 
related to clarifications regarding existing columns in the asset 
appendix. Solomon/Arenchild note that the proposed reporting of 
capacity values in generation asset list in the asset appendix may be 
inconsistent with the indicative screens. Specifically, Solomon/
Arenchild state that there is a disconnect between the time period 
covered in the asset appendix and the time period covered in the 
indicative screens.\377\ Solomon/Arenchild also state that the 
indicative screens cannot rely solely on the ratings reported in the 
asset appendix because both summer and winter seasonal ratings 
typically are used in the indicative screens while the current asset 
appendix only allows sellers to report one rating per generation 
unit.\378\ Accordingly, Solomon/Arenchild recommend that the Commission 
specify that any generation sold or contracts terminated following the 
relevant study period be excluded from the historical study period of 
the triennial filing, and that any generation acquired or contracts 
begun since the historical study period be included in the indicative 
screens and asset appendix.\379\
---------------------------------------------------------------------------

    \377\ Solomon/Arenchild at 7-8.
    \378\ Id.
    \379\ Id. at Attachment 1 (noting that their recommendation 
conforms the indicative screens with the asset appendix that is part 
of the triennial filing, creates a ``baseline'' for any future 
notice of change in status filings, and more properly aligns the 
determination of when a change in status should be filed in the 
context of the 100 MW net change in capacity ownership for those 
entities that have sold generation or terminated contracts).
---------------------------------------------------------------------------

(b) Commission Determination
    287. We adopt the proposed clarifications regarding: Populating the 
``Use'' column in the transmission asset list; listing each asset once 
in an asset list; matching seller and affiliate names in the asset 
lists with the name registered in the Commission's company registration 
database where possible; and to the use of the ``Date Control 
Transferred'' column in the transmission asset list.
    288. In regard to the ``Date Control Transferred'' column, we 
further clarify that sellers should identify the date on which a 
contract or other transaction that transfers control over a facility 
becomes effective. Where appropriate, companies may enter ``N/A'' in 
this field to indicate that it is not applicable to their asset(s) and 
provide any further explanation in the new end notes column.
    289. We do not adopt Solomon/Arenchild's recommendation to modify 
the data in the market power analysis to match the data required for 
the asset appendix. In Order No. 697, the Commission stated ``that when 
the Commission evaluates an application for market-based rate 
authority, the Commission's focus is on whether the seller passes both 
of the indicative screens based on unadjusted historical data. 
Likewise, when a seller fails one or both of the screens and the 
Commission evaluates whether that seller passes the DPT, the 
Commission's focus is on whether the seller passes the DPT based on 
unadjusted historical data'' \380\ We will continue to require that a 
seller's market power analysis rely on unadjusted historical data. To 
the extent that a seller's generation

[[Page 67095]]

assets have changed between the historical time period used in the 
market power analysis and the current time period of the asset 
appendix, the seller should explain and reconcile any differences in 
its application. Sellers may also provide sensitivity runs along with 
the required historical studies to show whether changed circumstances 
since the end of the study period justify a different conclusion than 
what the data from the study period indicates.\381\ The Commission has 
addressed the data disconnect issue by noting previously that the 
Commission will consider, on a case-by-case basis, clear and compelling 
evidence that seeks to demonstrate that certain changes in the market 
should be taken into account as part of the market power analysis in a 
particular case.\382\ However, we provide the following guidance for 
preparing the studies and asset appendices for filings that commonly 
contain both asset appendices and market-power studies.
---------------------------------------------------------------------------

    \380\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 301.
    \381\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at PP 124-
130.
    \382\ Id. P 130.
---------------------------------------------------------------------------

    290. For initial applications where the seller has acquired an 
existing facility, sellers should prepare or rely on a study with 
historical data that transfers the MW values of the acquired generation 
from the Non-Affiliate Capacity rows to the Seller and Affiliate 
Capacity rows of their indicative screens and enter the information for 
the acquired facility in the generation asset list.
    291. For initial applications where the seller has newly built 
generation, sellers should submit a study that increases the total 
capacity value of the market/balancing authority area in which the 
seller is physically located by the seller's newly built generation 
capacity. To accomplish this, the seller should use a previously 
approved study and add the value of their newly built generation to the 
total capacity value of the market/balancing authority area. Sellers 
must report this newly built generation in the generation asset list.
    292. In triennials, there are occasions when a seller's generation 
fleet at the time of filing has changed since the close of the relevant 
study period. In these instances, sellers should explain the changes in 
the text of their filing, the end notes of the asset appendix if 
applicable, and if the changes are significant, the seller should 
provide a sensitivity analysis reflecting those changes.
    293. Notices of change in status generally do not require 
indicative screens. However, sometimes a seller provides screens for 
changes that the seller considers significant enough to merit the 
submission of screens to show that it would not fail the indicative 
screens with these new assets. In this case, we clarify that any 
studies submitted by a seller should use the most recently available 
historical data for the market, but include the seller's current 
generation portfolio, imports, and load and reserve obligations (if 
any).
    294. We understand Solomon/Arenchild's concern that the indicative 
screens cannot solely rely on the ratings reported in the asset 
appendix. Based on our experience, sellers that use seasonal ratings 
for thermal generation in their indicative screens are likely to use 
either summer or winter ratings in their asset appendix. However, in 
some cases sellers that use seasonal ratings in their screens use 
nameplate ratings in their asset appendix. Therefore, we clarify that 
when sellers use seasonal ratings in their indicative screens, their 
asset appendix should include the capacity rating used for each 
generation unit in their pivotal supplier screen(s). Requiring sellers 
to report the capacity rating used in their pivotal supplier screen 
eliminates this inconsistency and allows us to maintain the simplicity 
of the asset appendix. In addition, this ensures that the generation 
asset list displays the seasonal rating of each generation unit at the 
time of peak demand, when capacity is most needed.\383\
---------------------------------------------------------------------------

    \383\ As previously noted, if a filing does not contain a market 
power study, or a particular generation asset is not included in a 
market power study, sellers should include in the asset appendix the 
rating that it used the last time the asset was included in a market 
power study.
---------------------------------------------------------------------------

4. Changes Regarding OATT Waiver and Citations in Transmission Asset 
List
a. Commission Proposal
    295. The Commission has stated that even if a seller has been 
granted waiver of the requirement to file an OATT, those transmission 
facilities should be reported in its asset appendix,\384\ and the 
Commission stated in the NOPR that this should be reiterated and 
clarified going forward. Therefore, the Commission proposed to require 
any seller that has been granted waiver of the requirement to file an 
OATT for its facilities \385\ to report in its transmission asset list 
the citation to the Commission order granting the OATT waiver for those 
facilities. The Commission proposed to modify the example of the asset 
appendix found in appendix B to subpart H of part 35 of the 
Commission's regulations to add a new column in the transmission asset 
list for the citation to the Commission order accepting the OATT or 
granting waiver of the OATT requirement. Providing the citation to the 
Commission order accepting the OATT or granting waiver of the OATT 
requirement in the list of transmission assets was intended to 
facilitate the Commission's and market participants' verification that 
sellers were granted the appropriate authorizations or waivers.
---------------------------------------------------------------------------

    \384\ ``We clarify that the transmission facilities that we 
require to be included in that asset appendix are limited to those 
the ownership or control of which would require an entity to have an 
OATT on file with the Commission (even if the Commission has waived 
the OATT requirement for a particular seller).'' Order No. 697-A, 
FERC Stats. & Regs. ] 31,268 at P 378.
    \385\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 408.
---------------------------------------------------------------------------

b. Comments
    296. While APPA/NRECA support the Commission's proposal to require 
a seller that has been granted waiver of the requirement to file an 
OATT for its facilities to cite the Commission order granting that 
waiver in its list of transmission assets in the asset appendix,\386\ 
other commenters oppose it. Some commenters note that the Commission's 
proposal may be at odds with the Interconnection Customer 
Interconnection Facility (ICIF) rulemaking in Docket No. RM14-11-000 
that was pending at the Commission at the time the comments were 
submitted.\387\ SoCal Edison requests that the Commission reject this 
proposal because the new column will not provide useful information, in 
light of the proposed ICIF rulemaking, and may cause confusion.\388\ 
NextEra suggests that the Commission synthesize the OATT waiver 
provisions in both pending rulemakings.\389\
---------------------------------------------------------------------------

    \386\ APPA/NRECA at 5; see also Golden Spread at 7.
    \387\ SoCal Edison at 25 (explaining that the Commission is 
proposing a blanket waiver of all OATT, OASIS, and Standards of 
Conduct requirements to any public utility that is subject to such 
requirements solely because it owns, controls, or operates 
interconnection customer interconnection facilities and citing Open 
Access and Priority Rights on Interconnection Customer's 
Interconnection Facilities, 147 FERC ] 61,123, at P 35 (2014)); 
NextEra at 15; EEI at 17-18.
    \388\ SoCal Edison at 25.
    \389\ NextEra at 15.
---------------------------------------------------------------------------

    297. Other commenters argue that the proposal is unnecessary and 
unclear.\390\ Specifically, FirstEnergy states that, if the citation to 
the OATT or OATT waiver is in the transmittal letter, including the 
citation in the asset appendix is redundant and unnecessary.\391\ 
FirstEnergy further states that, if a company transferred operational 
control of its facilities to an

[[Page 67096]]

RTO, a citation to the order authorizing the transfer should 
suffice.\392\ AEP argues that the proposal to provide a citation to the 
OATT waiver is an extra imposition on sellers that is inconsistent with 
the stated purpose of the NOPR.\393\ AEP and EEI state that OATTs are 
readily publicly available and therefore do not need to be included in 
the transmission asset list.\394\ AEP further argues that it is unclear 
which OATT waiver citation a company like AEP would list because its 
filings are frequently revised and updated.\395\
---------------------------------------------------------------------------

    \390\ See, e.g., AEP at 9; EEI at 17; and FirstEnergy at 13.
    \391\ FirstEnergy at 13.
    \392\ Id. at 14.
    \393\ AEP at 9.
    \394\ Id.; EEI at 17.
    \395\ AEP at 9; see also EEI at 17.
---------------------------------------------------------------------------

c. Commission Determination
    298. We adopt the proposal to require sellers to add a citation to 
the order accepting a seller's OATT. Further, we agree with 
FirstEnergy's suggestion that if a seller has transferred operational 
control of its facilities to an RTO/ISO, this cite should be to the 
order authorizing the transfer. Therefore, we have changed the text to 
the proposed column (Column [B]) of the transmission asset list from 
``Cite to Order Accepting OATT or granting OATT waiver'' to ``Cite to 
order accepting OATT or order approving the transfer of transmission 
facilities to an RTO or ISO.'' The change to remove ``granting OATT 
waiver'' is discussed below.
    299. We do not agree with AEP's assertion that this requirement is 
an extra imposition upon sellers. Further, in regard to AEP and EEI's 
comments, we understand that OATT information is already publicly 
available. However, sellers are already required to supply this 
information as part of their demonstration that they meet the 
Commission's vertical market power requirements. The new column 
provides a convenient location for sellers to provide the information 
and for the Commission or third-parties to find the information. We 
clarify that sellers are not expected to change the citation every time 
they revise or update their OATTs. Similar to Column [B] ``Docket # 
where market-based rate authority was granted'' in the generation asset 
list, we expect sellers to provide citation to the initial order 
accepting a seller's OATT or accepting the seller's transfer of 
transmission facilities to an RTO/ISO in Column [B] of the transmission 
asset list. This will minimize any burden associated with including 
this information in the transmission asset list.
    300. However, we do not adopt the NOPR proposal to require sellers 
to add a citation to orders granting the seller waiver of the OATT 
requirements. We agree with SoCal Edison that this requirement will not 
provide useful information, in light of the Final Rule in the ICIF 
proceeding.\396\
---------------------------------------------------------------------------

    \396\ See Open Access and Priority Rights on Interconnection 
Customer's Interconnection Facilities, Order No. 807, FERC Stats. & 
Regs. ] 31,367 (2015) (amending Commission regulations to waive the 
OATT requirements of section 35.28, the OASIS requirements of part 
37, and the Standards of Conduct requirements of part 358, under 
certain conditions, for entities that own interconnection 
facilities).
---------------------------------------------------------------------------

5. Electronic Format
a. Commission Proposal
    301. Currently, virtually all of the asset appendices are submitted 
to the Commission using PDF format. Staff is unable to perform 
calculations on PDF files, or to search, or sort the data contained in 
the asset lists. Staff therefore frequently transfers the information 
included in the asset lists into spreadsheets for sorting, comparison 
purposes, and internal calculations, and in doing so has found numerous 
submission errors from sellers. In the NOPR, the Commission stated that 
if it provided a sample electronic spreadsheet and required sellers to 
submit the assets lists in an electronic spreadsheet, it would reduce 
filing burdens, improve accuracy, decrease the number of staff 
inquiries to sellers regarding submission errors, and result in a more 
efficient use of resources.
    302. Therefore, the Commission proposed to require market-based 
rate sellers to submit the appendix B asset lists in an electronic 
spreadsheet format that can be searched, sorted, and otherwise accessed 
using electronic tools. The Commission proposed to post on the 
Commission's Web site sample asset lists in formatted electronic 
spreadsheets and to require sellers to submit the asset appendix in the 
form and format of the sample electronic asset list spreadsheets.\397\
---------------------------------------------------------------------------

    \397\ The Commission proposed 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. Specifically, it must have the same exact columns and 
descriptive text as the sample spreadsheet. The Commission further 
proposed that the file must be submitted in one of the spreadsheet 
file formats accepted by the Commission for electronic filing. NOPR, 
FERC Stats. & Regs. ] 32,702 at P 63 n.71. See FERC, Acceptable File 
Formats (January 2012), available at http://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
---------------------------------------------------------------------------

    303. An example of the electronic spreadsheet for the asset 
appendix with the proposed new columns and column headings was included 
as appendix B to the NOPR.
b. Comments
    304. Commenters generally support the Commission's proposal to 
require sellers to submit the asset appendix in an electronic 
spreadsheet format; however, several commenters request clarification 
or modification of the proposal.\398\ EPSA requests clarification on 
the specific fields that would be required in the electronic format, 
and the methodology that should be used to submit the electronic 
forms.\399\ E.ON urges the Commission to thoroughly vet the process to 
ensure ease of use and submission by market participants, which may 
require a public test period.\400\ EEI states that, ``if the Commission 
simply intends to require market-based rate applicants and sellers to 
file the information in standard electronic formats, such as Adobe, 
Excel, and Word, that would be fine. Such straightforward electronic 
filing will simply mirror the current FERC eFiling process, which has 
eased the burden of filing documents at FERC. If, however, the 
Commission has in mind that market-based rate applicants and sellers 
must provide the information using rigid new formats, e.g. with pre-
defined rows and columns using XML data, EEI asks the Commission to 
engage in further dialogue with the regulated community first, to 
ensure that the format changes are reasonable, clear, and workable.'' 
\401\
---------------------------------------------------------------------------

    \398\ See, e.g., APPA/NRECA at 5 (supporting the Commission's 
proposal and requesting no clarifications or modifications); 
Solomon/Arenchild at 6-7; EPSA at 12; E.ON at 13, 14.
    \399\ EPSA at 12.
    \400\ E.ON at 13.
    \401\ EEI at 18.
---------------------------------------------------------------------------

c. Commission Determination
    305. We adopt the NOPR proposal to require sellers to submit the 
asset appendix in an electronic spreadsheet format.
    306. EEI apparently misconstrued this proposal and we clarify here 
that the electronic format requirement for the asset appendix is 
specifically designed to stop the submission of asset appendices in 
Word or PDF format and instead require that these be submitted in a 
workable electronic file format such as Excel. We adopt the NOPR 
requirements of a ``workable electronic spreadsheet,'' \402\ provide an 
example on

[[Page 67097]]

our Web site, and provide the electronic filing requirements for such a 
filing.\403\ Furthermore, we clarify that this requirement is not 
dependent upon any particular technology such as Extensible Markup 
Language (XML), and instead can use any one of a number of Commission 
accepted spreadsheet formats.\404\ In response to EPSA, we clarify that 
the entire asset appendix (including all relevant lists) should be 
submitted in the electronic format. Sellers should submit the 
electronic asset appendix as an attachment to their filings, following 
the Commission's electronic filing requirements described above.
---------------------------------------------------------------------------

    \402\ `` `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.'' NOPR, FERC Stats. & Regs. ] 
32,702 at P 63 n.70. Additionally:
    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. Specifically, 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. Finally, the file must be submitted in one of 
the spreadsheet file formats accepted by the Commission for 
electronic filing. See FERC, Acceptable File Formats (Jan. 2012), 
available at http://www.ferc.gov/docs-filing/elibrary/accept-fileformats.asp. NOPR, FERC Stats. & Regs. ] 32,702 at P 63 n.71.
    \403\ Id. P 123 n.135.
    \404\ Id. P 65 n.73; see also supra Section IV.A.4.c.
---------------------------------------------------------------------------

    307. Finally, we replace the example appendix found in appendix B 
to subpart H of part 35 of the Commission's regulations with the 
appendix B in this Final Rule.
6. Database
a. Commission Proposal
    308. The Commission sought comment regarding whether in the future 
it would be beneficial to develop a comprehensive searchable public 
database of the information contained in the asset appendix, which 
would eventually replace the pre-formatted spreadsheet. The Commission 
noted that such an approach would allow market-based rate sellers to 
update their asset appendices when circumstances change. The Commission 
sought comments regarding whether such a database would be useful, how 
the database might be created, standardized and maintained, and the 
frequency with which it should be updated. The Commission further 
sought input on the usefulness of including unique identifiers for the 
affiliate companies and generation assets in such a database, e.g., the 
company registration database and the EIA Power Plant Code and 
Generator ID, respectively, where those identifiers exist. The 
Commission also sought comment on the difficulty of reporting and the 
usefulness of including in such a database the percentage each 
affiliate owns of each of its assets.
b. Comments
    309. While APPA/NRECA, Golden Spread, and E.ON support the 
Commission's proposal to develop a comprehensive, searchable public 
database of the information contained in the asset appendix,\405\ 
several other commenters expressed concern.\406\ SoCal Edison and EEI 
argue that including contract data in the database would raise concerns 
about confidentiality.\407\ EEI states that the database would need to 
be designed in close coordination with the regulated community to 
ensure a useful result, minimize the regulatory burden, and address 
confidentiality and critical energy infrastructure information (CEII) 
concerns.\408\ Idaho Power states that, in some cases, proprietary 
information of a generator's capacity would be masked in a public 
database, impacting the usefulness of the database.\409\
---------------------------------------------------------------------------

    \405\ APPA/NRECA at 5; Golden Spread at 7; E.ON at 14 (stating 
that a database would be particularly useful if the Commission 
ultimately adopts its proposal to redefine relevant markets for 
generation-only balancing authority areas, and it would provide 
market participants and market-based rate sellers with access to 
megawatt generation data needed for horizontal market power 
analyses).
    \406\ See, e.g., SoCal Edison at 26; EEI at 18; Idaho Power at 
2-3.
    \407\ SoCal Edison at 26; EEI at 18 (adding that including 
contract data in the database would create additional information 
collection burdens and would also raise concerns about the 
disclosure of Critical Energy Infrastructure Information (CEII)).
    \408\ EEI at 18.
    \409\ Idaho Power at 2-3.
---------------------------------------------------------------------------

    310. Other commenters raise issues related to maintaining the 
database's integrity.\410\ SoCal Edison, EEI, and AEP state that the 
database could omit qualifying facilities' generation and non-
jurisdictional entities' generation.\411\ SoCal Edison also argues that 
it would be difficult to assemble information from the asset appendix 
about long-term firm purchases into a meaningful database.\412\ 
Solomon/Arenchild support the database, in theory, but state that the 
database would require continual, time-consuming, and cumbersome 
maintenance to maintain its integrity.\413\ They further state that for 
such a database to provide meaningful information, one would need to be 
able to readily identify duplicates, overlaps etc., or the utility of 
the database will be undermined. NextEra echoes Solomon/Arenchild's 
concern and state that the burdens associated with maintaining such a 
database would outweigh the benefits.\414\ EPSA expresses concern over 
whether the industry or the Commission will be responsible for updating 
the database and how the accuracy of the information will be 
ensured.\415\
---------------------------------------------------------------------------

    \410\ See, e.g., SoCal Edison at 26; EEI at 18; AEP at 10; 
Solomon/Arenchild at 6-7; NextEra at 15; EPSA at 14.
    \411\ SoCal Edison at 26 (adding also that the data may not be 
particularly useful due to joint ownership issues); EEI at 18; AEP 
at 10.
    \412\ SoCal Ed. at 26.
    \413\ Solomon/Arenchild at 6-7.
    \414\ NextEra at 15.
    \415\ EPSA at 14.
---------------------------------------------------------------------------

    311. EPSA also seeks clarification on whether the database would 
eventually replace the asset appendix, or if both a database and an 
asset appendix would be required.\416\ EPSA states that, if both a 
database and an asset appendix will be required of all market-based 
rate sellers, then such requirements would run counter to the 
Commission's stated intentions to streamline the information required 
and reduce the regulatory burden on market-based rate sellers. EPSA 
suggests that, if sellers will be required to use the database for 
documentation of assets, the seller should be responsible for updating 
and maintaining its data on the database.\417\
---------------------------------------------------------------------------

    \416\ Id.
    \417\ Id.
---------------------------------------------------------------------------

    312. AEP does not see the need for the Commission to host a 
comprehensive searchable public database, stating that the information 
is available through other means and creating the database would impose 
another reporting obligation on sellers.\418\
---------------------------------------------------------------------------

    \418\ AEP at 9.
---------------------------------------------------------------------------

c. Commission Determination
    313. We will not direct the creation of a comprehensive public 
database as part of this rulemaking. In the NOPR, we sought industry 
comment on the usefulness of a potential database and for input on how 
the database might be created and maintained. While some commenters 
raise valid concerns about the structure, confidentiality, burden and 
maintenance of the database, others recognize the potential utility of 
a well-designed and properly administered database.\419\ Similarly, we 
continue to recognize the potential value of the database and may 
consider the creation of a database in the future.
---------------------------------------------------------------------------

    \419\ APPA/NRECA at 5; Golden Spread at 7; E.ON at 14; Solomon/
Arenchild at 6-7.
---------------------------------------------------------------------------

E. Category 1 and Category 2 Sellers

1. Commission Proposal
    314. In Order No. 697, the Commission created a category of market-
based rate sellers, Category 1 sellers, that are exempt from the 
requirement to periodically submit

[[Page 67098]]

updated market power analyses in accordance with the regional reporting 
schedule. Category 1 sellers include 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 generating facilities to the transmission grid (or 
have been granted waiver of the requirements of Order No. 888); 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 concerns.\420\
---------------------------------------------------------------------------

    \420\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 853-863; 
see also 18 CFR 35.36(a)(2).
---------------------------------------------------------------------------

    315. In the NOPR, the Commission proposed to clarify the 
distinction in determining the seller category status of power 
marketers and power producers. For purposes of determining seller 
category status for each region, a power marketer should include all 
affiliated generation capacity in that region. Power producers only 
need to include affiliated generation that is located in the same 
region as the power producer's generation assets. The Commission 
explained that the reason behind this distinction is that a power 
marketer with no generation assets in the ground is assumed to have no 
home market; it is thus assumed to be equally likely to make sales in 
any region. In contrast, although a power producer has authorization to 
make sales in other regions, it is assumed that the majority of its 
sales will be in the region(s) in which it owns generation assets.
    316. Thus, the Commission proposed to clarify that a power marketer 
with no generation assets may qualify as a Category 1 seller in any 
region where: (1) Its affiliates own or control, in aggregate, 500 MW 
or less of generation capacity; (2) it is not affiliated with anyone 
that owns, operates or controls transmission facilities; (3) it is not 
affiliated with a franchised public utility; and (4) it does not raise 
other vertical market power issues. The Commission noted that the above 
is consistent with the Commission's treatment of power marketers since 
the issuance of Order No. 697.
    317. The Commission also proposed to clarify that a power producer 
may qualify as a Category 1 seller in any region in which the power 
producer itself owns generation and the power producer and its 
affiliates own or control, in aggregate, 500 MW of generation capacity 
or less, as long as the power producer is not affiliated with anyone 
that owns, operates or controls transmission facilities in that region, 
is not affiliated with a franchised public utility in that region, and 
does not raise other vertical market power issues. In addition, unlike 
power marketers, a power producer may qualify as a Category 1 seller in 
a region where the power producer itself does not own or control any 
generation or transmission assets but where it has affiliates that are 
Category 2 sellers.\421\
---------------------------------------------------------------------------

    \421\ The Commission noted that a mitigated seller cannot use an 
affiliated power producer in another region as a conduit to sell in 
a mitigated balancing authority area because all affiliates of a 
mitigated seller are prohibited from selling at market-based rates 
in any balancing authority area or market where the seller is 
mitigated. Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 335.
---------------------------------------------------------------------------

    318. Therefore, the Commission proposed to revise the regulation at 
18 CFR 35.36(a)(2) and clarify that in order to qualify for Category 1 
status, a seller must meet all of the requirements. Failure to satisfy 
any of these requirements results in a Category 2 designation.
2. Comments
    319. EEI recommends that the Commission modify its proposed 
clarifications regarding Category 1 and Category 2 sellers. EEI 
encourages the Commission to allow power marketers to demonstrate that 
their sales from particular capacity are confined to particular regions 
and thus should be counted accordingly in determining their category 
status.\422\ EEI adds that the Commission should modify the definition 
of a Category 1 seller from ``no more than 500 MW generation ownership 
and/or control'' to ``no more than 500 MW of uncommitted resources 
owned and/or controlled.'' \423\ EEI contends that some companies have 
always had negative uncommitted resources because they are net buyers, 
and so should not be required to make updated market power analysis 
filings or change in status filings.\424\
---------------------------------------------------------------------------

    \422\ EEI at 19.
    \423\ Id.
    \424\ Id.
---------------------------------------------------------------------------

3. Commission Determination
    320. We adopt the proposed clarifications regarding Category 1 and 
Category 2 sellers and the corresponding regulatory changes to 18 CFR 
35.36(a)(2) as proposed in the NOPR.
    321. In response to EEI's comment to allow power marketers to 
demonstrate that sales from particular capacity are confined to a 
particular region, the Commission has found that category seller status 
is based on the region in which generation capacity is owned or 
controlled by the seller and its affiliates in aggregate rather than 
where sales are made in an effort to keep the definition and 
demonstration of a seller's category status simple and 
straightforward.\425\ Since sales change frequently, we believe basing 
the category seller status definition on sales could create an 
additional burden on sellers to demonstrate that their and their 
affiliates' sales are confined to a particular region. However, we note 
that to the extent that any seller wishes to limit its market-based 
rate authority to a particular region or set of regions in its tariff, 
it is free to do so. If a seller does not have market-based rate 
authority in a particular region, it will not have an obligation to 
file regular updated market-power analyses for that region.
---------------------------------------------------------------------------

    \425\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 864-868.
---------------------------------------------------------------------------

    322. EEI also proposed that the category seller status designation 
be based on whether a seller owns or controls uncommitted resources in 
a region. We reject this proposal as beyond the scope of what was 
proposed in the NOPR. Moreover, the test for category seller status was 
intended to be a bright line test that would be easy to 
administer.\426\ The Commission has previously found that ``aggregate 
capacity in a given region best meets our goal of ensuring that we do 
not create regulatory barriers to small sellers seeking to compete in 
the market while maintaining an ample degree of monitoring and 
oversight that such sellers do not obtain market power.'' \427\ We do 
not believe that a seller with over 500 MW of capacity is the type of 
seller that the Commission intended to exclude from periodic updated 
market power analyses, regardless of whether the seller's capacity 
happens to be committed at a particular point in time.
---------------------------------------------------------------------------

    \426\ Id. P 864.
    \427\ Id. P 865; Order No. 697-A, FERC Stats. & Regs. ] 31,268 
at P 360.
---------------------------------------------------------------------------

F. Corporate Families

1. Corporate Organizational Charts
a. Commission Proposal
    323. In the NOPR, the Commission proposed to require sellers to 
provide an organizational chart, in addition to the existing 
requirement \428\ to provide written descriptions of their affiliates 
and corporate structure or upstream

[[Page 67099]]

ownership, for initial applications for market-based rate authority, 
updated market power analyses and notices of change in status reporting 
new affiliations.
---------------------------------------------------------------------------

    \428\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 181, 
n.258 (also requiring sellers seeking market-based rate authority to 
describe the business activities of their owners, stating whether 
they are in any way involved in the energy industry).
---------------------------------------------------------------------------

    324. The Commission noted that it has seen increasingly complex 
organizational structures as private equity funds and other financial 
institutions take ownership positions in generation and utilities.\429\ 
The Commission stated that requiring the filing of an organizational 
chart would make reviewing market-based rate filings more efficient, 
increase transparency, and synchronize information about corporate 
structure that the Commission receives from sellers with market-based 
rate authority with similar information that the Commission receives 
under section 203 of the FPA.\430\ The Commission proposed to require 
that sellers provide an organizational chart similar to that which the 
Commission requires from section 203 applicants. Specifically, the 
Commission noted that section 33.2(c)(3) of its regulations \431\ 
provides that section 203 applicants must include: A description of the 
applicant, including, among other things, organizational charts 
depicting the applicant's current and proposed post-transaction 
corporate structures (including any pending authorized but not 
implemented changes) indicating all parent companies, energy 
subsidiaries and energy affiliates unless the applicant represents that 
the proposed transaction does not affect the corporate structure of any 
party to the transaction. The Commission proposed that market-based 
rate sellers be required to provide, in addition to the already 
required written descriptions of their affiliates and corporate 
structure or upstream ownership, an organizational chart depicting the 
market-based rate seller's current corporate structures (including any 
pending authorized but not implemented changes) indicating all upstream 
owners, energy subsidiaries and energy affiliates. The Commission 
believed that the increased burden on market-based rate sellers would 
be minimal as most sellers have this organizational chart available.
---------------------------------------------------------------------------

    \429\ We note that the Commission recently issued a NOPR seeking 
comment on a proposal to require each RTO and ISO to electronically 
deliver to the Commission data from market participants that lists 
market participants' ``connected entities,'' including entities that 
have certain ownership, employment, debt or contractual 
relationships to the market participant, and describes the nature of 
such relationships. See Collection of Connected Entity Data from 
Regional Transmission Organizations and Independent System 
Operators, Docket No. RM15-23-000, 80 FR 58382 (Sept. 29, 2015), 152 
FERC ] 61,219 (2015).
    \430\ 16 U.S.C. 824b.
    \431\ See 18 CFR 33.2(c)(3).
---------------------------------------------------------------------------

    325. Thus, the Commission proposed to revise the text in section 
35.37(a)(2) of the Commission's regulations to add this requirement for 
purposes of initial applications and updated market power analyses. The 
Commission also proposed that such organizational chart be required for 
any notice of change in status involving a change in the ownership 
structure that was in place the last time the seller made a market-
based rate filing with the Commission. Therefore, the Commission 
proposed to revise the text in section 35.42(c) accordingly.
b. Comments
    326. Many commenters oppose the Commission's proposal to require 
sellers to provide an organizational chart, in addition to written 
descriptions of their affiliates and corporate structure or upstream 
ownership, for initial applications for market-based rate authority, 
updated market power analyses, and notices of change in status 
reporting new affiliations.\432\ However, APPA/NRECA and Golden Spread 
support the proposal.\433\
---------------------------------------------------------------------------

    \432\ See, e.g., EPSA at 15-17; E.ON at 14-16; NextEra at 16; 
EEI at 19; FirstEnergy at 14-16; NRG Companies at 3-6; AEP at 9.
    \433\ APPA/NRECA at 5; Golden Spread at 7.
---------------------------------------------------------------------------

    327. Several commenters submit that this proposal would impose a 
burden on sellers disproportionate to any benefit received, requiring 
significant investigation into numerous affiliate relationships.\434\ 
EPSA notes that, even if a market-based rate entity already has an 
organizational chart, often those charts are not developed and used for 
the purpose of showing control, but rather to demonstrate how finances 
flow throughout the various companies.\435\ Consequently, EPSA argues 
that the charts would require significant revisions to comply with the 
Commission's proposal.\436\
---------------------------------------------------------------------------

    \434\ See, e.g., EPSA at 15-17 (noting that not all market-based 
rate sellers have these organization charts readily available and 
that many sellers have hundreds of affiliates); E.ON at 14-15; 
NextEra at 16; EEI at 19; NRG Companies at 3-4; AEP at 9.
    \435\ EPSA at 16.
    \436\ Id.
---------------------------------------------------------------------------

    328. EPSA proposes that, if the Commission implements the proposal, 
the Commission should limit the entities depicted in the organizational 
chart to include only public utilities subject to the Commission's 
jurisdiction rather than all affiliates within a seller's corporate 
structure.\437\ Other commenters state that the Commission does not 
need an organizational chart to evaluate market power concerns and that 
an organizational chart does not provide meaningfully different or 
material information to the Commission than is currently required.\438\ 
Specifically, FirstEnergy argues that, because the evaluation of a 
market-based rate application treats the seller and its affiliates as a 
single entity, the complex internal relationships among affiliated 
entities that might be illustrated in an updated organizational chart 
are not relevant to the Commission's evaluation of whether an entity 
should enjoy market-base rate authority.\439\
---------------------------------------------------------------------------

    \437\ Id. at 15-16.
    \438\ See, e.g., E.ON at 15-16; NextEra at 16; EEI at 19; 
FirstEnergy at 14-16; NRG Companies at 5.
    \439\ FirstEnergy at 15.
---------------------------------------------------------------------------

    329. If the Commission adopts this proposal, some commenters 
suggest that the Commission provide further guidance regarding which 
affiliated entities should be included in the organizational 
chart.\440\ E.ON requests that the Commission clarify the meaning of 
``energy affiliate'' and ``energy subsidiary'' and suggests that the 
meaning be limited to affiliates and subsidiaries that (1) own or 
control electric generation or inputs to electric power production in 
the relevant market or balancing authority area; (2) own, operate, or 
control electric transmission facilities in the relevant market or 
balancing authority area; or (3) have a franchised service territory in 
the relevant market or balancing authority area.\441\ EPSA requests 
clarification of how the Commission would treat sellers that are part 
of joint ventures, whether they would be exempt from the organizational 
chart or require particular treatment in the organizational chart.\442\
---------------------------------------------------------------------------

    \440\ E.ON at 15; EPSA at 16.
    \441\ E.ON at 15.
    \442\ EPSA at 16.
---------------------------------------------------------------------------

    330. Some commenters assert that if the Commission adopts this 
proposal, the Commission should allow exemptions for specific 
filers.\443\ AEP notes that Order No. 717 eliminated a similar previous 
requirement for transmission providers to post an organizational chart 
of all affiliates, finding such a requirement to be an ``undue burden 
on transmission providers.'' \444\ AEP also suggests that only filings 
that impact the organizational structure should require an 
organizational chart.\445\ EEI similarly proposes that an 
organizational chart should not be required if ``that applicant

[[Page 67100]]

demonstrates that the proposed transaction does not affect the 
corporate structure of any party to the transaction.'' \446\ 
FirstEnergy suggests that there should be no need for a seller to 
submit an organizational chart (1) if the seller and its affiliates 
operate within an RTO with Commission-approved market monitoring and 
mitigation procedures and rely on such procedures to address horizontal 
market power concerns or (2) if a seller has become affiliated with a 
new entity that owns generation or transmission assets and where the 
transaction has been approved by the Commission pursuant to its 
authority under section 203 of the FPA.\447\
---------------------------------------------------------------------------

    \443\ See, e.g., AEP at 19; EEI at 19; FirstEnergy at 15-16.
    \444\ AEP at 9 (citing Standards of Conduct for Transmission 
Providers, Order No. 717, FERC Stats. & Regs. ] 31,280, at P 243 
(2008)).
    \445\ Id.
    \446\ EEI at 19.
    \447\ FirstEnergy at 15-16 (arguing that the requirement should 
be limited to circumstances in which the information may be useful 
to its review of an application for market-based rate authority).
---------------------------------------------------------------------------

    331. If the Commission adopts the organizational chart proposal, 
some commenters suggest that the Commission allow flexibility for 
meeting this proposal.\448\ The NRG Companies suggest that the 
Commission allow sellers to submit simplified organizational charts 
that omit intermediate holding companies, energy subsidiaries and 
affiliates not relevant to the analysis in the applicable filings. 
\449\ AEP proposes that market-based rate sellers be allowed to provide 
a link to an organizational chart on their Web sites or other 
accessible location.\450\
---------------------------------------------------------------------------

    \448\ NRG Companies at 5; AEP at 10.
    \449\ NRG Companies at 5.
    \450\ AEP at 10.
---------------------------------------------------------------------------

c. Commission Determination
    332. We adopt the corporate organizational chart requirement with 
modifications and clarifications, as discussed below. We disagree with 
commenters' concerns that filing such charts will impose an undue 
burden on sellers. The Commission already requires sellers to file 
organizational charts for filings under FPA section 203, and, as EPSA 
notes, some companies already have organizational charts for other 
purposes. Furthermore, as acknowledged by some commenters, the 
information that the Commission would require in organizational charts 
does not materially differ from what is currently provided in narrative 
form in market-based rate filings. Thus, presenting this same 
information in a graphic format should not be unduly burdensome. 
Similarly, presenting organizational charts in market-based rate 
filings, rather than through links to a corporate Web site as proposed 
by AEP, should not be unduly burdensome.
    333. However, in response to commenters' concerns, we provide 
further guidance regarding the extent to which upstream owners and 
affiliates need to be included in the corporate organizational charts. 
First, we find that the terms ``energy subsidiaries'' and ``energy 
affiliates,'' as used in the FPA section 203 context and as originally 
proposed in the NOPR, are not meaningful in the market-based rate 
context. Instead, we clarify that instead of ``indicating all upstream 
owners, energy subsidiaries, and energy affiliates'' in the 
organizational chart, as proposed in the NOPR, filers should indicate 
all affiliates, as defined under section 35.36(a)(9) of the 
Commission's market-based rate regulations. Second, to minimize burdens 
on filers and to simplify the charts, we clarify that if an entity is 
owned by multiple individual investors, such investors may be grouped 
in the organizational chart as long as they are identified elsewhere in 
the filing.
    334. We caution applicants to examine all upstream ownership 
information to ensure that all affiliates are captured in the chart. 
Applicants should not assume that upstream owners are not affiliates of 
the applicant without looking further up the ownership chain. For 
example, suppose the applicant (Company A) has four upstream owners 
(Companies B, C, D, and E) each of which owns 8 percent of the voting 
shares of A. If Company F owns 100 percent of the voting interests in 
Companies B, C, D, and E, under the Commission's affiliate definition, 
Company F indirectly owns 32 percent of Company A and should be listed 
in the chart as an affiliate of Company A. Furthermore, since Companies 
A, B, C, D, and E are all under the common control of Company F, 
Companies B, C, D, and E also are affiliated with Company A under the 
Commission's definition and should be depicted as such in the 
organizational chart, even though they own less than 10 percent of the 
voting interests in Company A. Further, as the Commission clarified in 
Tonopah Solar Energy, LLC, applicants are not permitted to use a 
derivative share method to calculate ownership interests in downstream 
partially-owned entities for purposes of identifying affiliates.\451\
---------------------------------------------------------------------------

    \451\ Tonopah Solar Energy, LLC, 151 FERC ] 61,203, at PP 11-12 
(2015).
---------------------------------------------------------------------------

    335. Consistent with our clarifications above, we will revise the 
regulatory text in Sec.  35.37(a)(2) to clarify that the organizational 
chart must include affiliates, without any further reference to 
``upstream owners,'' ``energy subsidiaries,'' or ``energy affiliates.'' 
We will also revise the regulatory text in section 35.42(c) of the 
Commission's regulations to require the submission of an organizational 
chart that depicts the seller's prior and new affiliations unless the 
change in status does not affect the seller's affiliations.
2. Single Corporate Tariff
a. Commission Proposal
    336. In the NOPR, the Commission noted that when a corporate family 
has more than one affiliated seller, it may use a joint tariff. The 
Commission committed to clarify on its Web site how a corporate family 
that chooses to submit a joint master corporate tariff should identify 
its designated filer and what each of the other filers should submit 
into their respective eTariff databases. This information can be found 
on the Commission's Web site at http://www.ferc.gov/industries/electric/gen-info/mbr/tariff/joint.asp.
b. Comments
    337. EEI appreciates the Commission's recognition that allowing 
joint filings for corporate families provides economy of effort to 
companies.\452\ EEI encourages the Commission to continue working with 
companies to enable companies to file joint tariffs within their 
corporate families.\453\
---------------------------------------------------------------------------

    \452\ EEI at 20.
    \453\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    338. There is no opposition to the Commission's NOPR clarification. 
We reiterate that when a corporate family has more than one affiliated 
seller, it may use a joint master tariff. Filing instructions for 
entities wishing to use a joint tariff are available on the 
Commission's Web site, as stated above.

G. Part 101 and 141 Waivers

1. Commission Proposal
    339. In the NOPR, the Commission noted that it has granted certain 
entities with market-based rate authority, such as power marketers and 
independent power producers, waiver of the Commission Uniform System of 
Accounts requirements, specifically parts 41, 101, and 141 of the 
Commission's regulations, except sections 141.14 and 141.15. The 
Commission clarified that any waiver of part 101 granted to a market-
based rate seller is limited such that the waiver of the provisions of 
part 101 that apply to hydropower licensees is not granted with respect 
to licensed hydropower

[[Page 67101]]

projects. The Commission stated that hydropower licensees are required 
to comply with the requirements of the Uniform System of Accounts 
pursuant to 18 CFR part 101 to the extent necessary to carry out their 
responsibilities under Part I of the FPA, particularly sections 4(b), 
10(d) and 14 of the FPA.\454\ The Commission further noted that a 
licensee's status as a market-based rate seller under Part II of the 
FPA does not exempt it from accounting responsibilities as a licensee 
under Part I of the FPA.\455\ Thus, hydropower licensees that received 
waiver of Part 101 of the Commission's regulations as part of their 
market-based rate applications under Part II of the FPA are cautioned 
that such waivers do not relieve them of their obligations to comply 
with the Uniform System of Accounts to the extent necessary to carry 
out their responsibilities under Part I of the FPA with respect to 
their licensed projects.
---------------------------------------------------------------------------

    \454\ In Trafalgar Power Inc., 87 FERC ] 61,207, at 61,798 n.46 
(1999) (Trafalgar Power), the Commission stated:
    Under [s]ection 14 of the FPA, the Federal government may take 
over a project upon expiration of the project's licensee, 
conditioned upon the government's payment to the licensee of the 
`net investment of the licensee in the project or projects taken.' 
Section 4(b) requires licensees to file a statement showing the 
`actual legitimate original cost of construction of such project' to 
enable the Commission to determine `the actual legitimate cost of 
and the net investment in' the project. Section 10(d) requires 
licensees to establish an amortization reserve account that will 
reflect excess or surplus earnings of their licensed project if such 
earnings have accumulated in excess of a reasonable rate of return 
upon the `net investment' in the project during a period beginning 
after the first twenty years of operations. Pursuant to [s]ection 
10(d) of the FPA the amount transferred to the amortization reserve 
may be used to reduce a licensee's net investment in the project, 
and if, after expiration of the license, the government takes over 
the project under [s]ection 14, it will be required to compensate 
the licensee for its net investment in the project, reduced by the 
amortization reserve for the project.
    \455\ See Seneca Gen., LLC et al., 145 FERC ] 61,096, at P 23 
n.20 (2013) (Seneca Gen) (citing Trafalgar Power, 87 FERC at 
61,798).
---------------------------------------------------------------------------

    340. The Commission further directed market-based rate sellers that 
own licensed hydropower projects to ensure that their market-based rate 
tariffs reflect appropriate limitations on any waivers that previously 
have been granted. Specifically, to the extent that the hydropower 
licensee has been granted waiver of part 101 as part of its market-
based rate authority, the licensee's market-based rate tariff 
limitations and exemptions section should be revised to provide that 
the seller has been granted waiver of part 101 of the Commission's 
regulations with the exception that waiver of the provisions that apply 
to hydropower licensees has not been granted with respect to licensed 
hydropower projects. Similarly, to the extent that a hydropower 
licensee has been granted waiver of part 141 as part of its market-
based rate authority, it should ensure that the limitation and 
exemptions section of its market-based rate tariff specifies that 
waiver of part 141 has been granted, with the exception of sections 
141.14 and 141.15 (which pertain to the filing by hydropower licensees 
of Form No. 80, Licensed Hydropower Development Recreation Report, and 
the Annual Conveyance Report). \456\
---------------------------------------------------------------------------

    \456\ See Domtar Maine, LLC, 133 FERC ] 61,207, at P 23 (2010).
---------------------------------------------------------------------------

    341. The Commission stated that these market-based rate tariff 
compliance filings are to be made the next time the hydropower licensee 
proposes a change to its market-based rate tariff, files a notice of 
change in status pursuant to 18 CFR 35.42, or submits an updated market 
power analysis in accordance with 18 CFR 35.37. In addition, going 
forward, any market-based rate seller requesting waivers of parts 101 
and/or 141 should include these limitations in their market-based rate 
tariffs, regardless of whether they own any licensed hydropower 
projects. This will ensure that hydropower licensees understand the 
limitations on parts 101 and 141 waivers. To the extent that the 
market-based rate seller is not a licensee, these limitations should 
not have any effect as they only deny waiver of certain provisions 
affecting licensees. If a market-based rate seller becomes a hydropower 
licensee after it receives market-based rate authority, it must file 
revisions to its market-based rate tariff to reflect the limitations in 
its parts 101 and 141 waivers within 30 days of the effective date of 
its license.
2. Comments
    342. Some commenters oppose the Commission's clarification that 
hydropower licensees are required to comply with the requirements of 
the Uniform System of Accounts pursuant to 18 CFR part 101 to the 
extent necessary to carry out their responsibilities under Part I of 
the FPA.\457\ They submit that the Commission in Order No. 697 decided 
against repealing waivers of the accounting requirements given to 
certain market-based rate entities, finding that ``little purpose would 
be served to require compliance with accounting regulations for 
entities that do not sell at cost-based rates and do not have captive 
customers.'' \458\ In addition, they assert that hydropower licensees 
with market-based rate authorizations neither sell at cost-based rates 
nor have captive customers.
---------------------------------------------------------------------------

    \457\ EPSA at 17-18; NHA at 2-10; EEI at 21-22. But see APPA/
NRECA at 5; Golden Spread at 7.
    \458\ See, e.g., EPSA at 18 (citing Order No. 697, FERC Stats. & 
Regs. ] 31,252 at P 985).
---------------------------------------------------------------------------

    343. Further, these commenters contend that requiring licensees to 
bring their accounts into conformance with the Uniform System of 
Accounts is not only unnecessary, but also would be costly and 
burdensome, require substantial work, and impose potential costs 
associated with hiring new accounting personnel, while yielding no 
identified benefit. According to commenters, hydropower licensees can 
already satisfy the statutory requirements in FPA Part I by employing 
Generally Applicable Accounting Principles.
    344. National Hydropower Association (NHA) contends that the 
regulatory burden imposed on hydropower licensees to conform to the 
Uniform System of Accounts is disproportionate to the concern 
underlying the Commission's clarification of hydropower licensees' 
responsibilities, particularly sections 4(b), 10(d), and 14 of the FPA. 
According to NHA, the calculation of net investment and amortization 
reserves only becomes relevant in case of a federal takeover of the 
project under section 14 of the FPA and during relicensing, if the 
project is awarded to a competing applicant.\459\ Further, NHA argues 
that there has not been a federal takeover of a licensed hydroelectric 
project and the Commission has yet to issue a new license to a 
competing applicant since the enactment of the FPA. Accordingly, NHA 
argues that the remote likelihood that a licensee will be paid its 
``net investment'' for a project should allow licensees flexibility 
when complying with the FPA Part I statutory provisions identified in 
the NOPR.\460\ Additionally, NHA argues that, in similar circumstances 
where the Commission addressed the FPA compliance obligations in light 
of an evolving electric industry, the Commission chose to eliminate a 
regulatory burden.\461\ Therefore, NHA asserts that since hydropower 
licensees can rely on Generally Accepted Accounting Principles to 
comply with applicable provisions of FPA Part I, the Commission's 
concerns regarding the FPA Part I provisions would not be implicated by 
allowing hydropower

[[Page 67102]]

licensees to use Generally Accepted Accounting Principles to fulfill 
their statutory obligations. Thus, commenters ask the Commission to 
find that hydropower licensees can meet FPA Part I statutory 
requirements if they follow Generally Accepted Accounting Principles. 
However, if the Commission determines that licensees must comply with 
part 101 in order to fulfill their statutory obligations under FPA Part 
I, then commenters request that the Commission: (1) Provide guidance 
regarding which requirements of part 101 it considers necessary to 
comply with FPA Part I; \462\ (2) only apply this policy prospectively; 
\463\ and (3) delay implementation of this policy for at least one year 
to provide sufficient time to allow affected licensees to bring their 
accounting ledgers into compliance.\464\ Regarding which specific 
accounts the Commission would expect licensees to maintain, NHA and EEI 
state the Commission should limit the number of accounts it deems 
necessary for a hydropower licensee to carry out its responsibilities 
under FPA Part I in order to minimize cost and burden for 
companies.\465\
---------------------------------------------------------------------------

    \459\ NHA at 6 (citing 16 U.S.C. 807(a); 808(a)(1)).
    \460\ Id. at 7-8.
    \461\ Id. at 8 (citing Payment of Dividends From Funds Included 
in Capital Account, 148 FERC ] 61,020 (2014)).
    \462\ EEI at 22; EPSA at 18; NHA at 8-9.
    \463\ EEI at 22; EPSA at 18; NHA at 8-9.
    \464\ EEI at 22; NHA at 8-9.
    \465\ EEI at 22: NHA at 9.
---------------------------------------------------------------------------

3. Commission Determination
    345. We affirm the NOPR clarification that any waiver of part 101 
granted to a market-based rate seller is limited such that the waiver 
of the provisions of part 101 that apply to hydropower licensees is not 
granted with respect to Commission-licensed hydropower projects. We 
recognize that in Order No. 697, the Commission concluded that ``the 
costs of complying with the Commission's [Uniform System of Accounts] 
requirements and, specifically parts 41, 101, and 141 of the 
Commission's regulations, outweigh any incremental benefits of such 
compliance where the seller only transacts at market-based rates.'' 
\466\ However, a licensee's status as a market-based rate seller under 
Part II of the FPA does not exempt it from accounting responsibilities 
as a hydropower licensee under Part I of the FPA.\467\ Thus, while 
hydropower licensees may have received waiver of part 101 of the 
Commission's regulations as part of their market-based rate 
authorizations under Part II of the FPA, that waiver does not relieve 
them of their obligations to comply with the Uniform System of Accounts 
to the extent necessary to carry out their responsibilities under Part 
I of the FPA with respect to their licensed projects. Moreover, we note 
that such responsibilities to maintain the information required for 
compliance with part 101 existed prior to the establishment of the 
Commission's market-based rate program.
---------------------------------------------------------------------------

    \466\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 985.
    \467\ See Seneca Gen., 145 FERC ] 61,096 at P 23 n.20 (citing 
Trafalgar Power, 87 FERC at 61,798).
---------------------------------------------------------------------------

    346. Regarding comments that the Commission's clarification is not 
only unnecessary, but also would be costly and burdensome, require 
substantial work, and impose potential costs associated with hiring new 
accounting personnel, while yielding no identified benefit, we 
disagree. We find that use of Generally Accepted Accounting Principles 
will not satisfy the statutory requirements under FPA sections 
4(b),\468\ 14,\469\ and 10(d).\470\ Further, although NHA contends that 
the chances are remote that the United States federal government would 
take over a hydropower project under FPA section 14, the chance still 
exists. Under part 101 of the Commission's regulations, licensed 
hydropower projects are required to maintain records that may be used 
to calculate net investment in the event that the Commission recommends 
that the United States federal government take over a hydropower 
project under FPA section 14 (or another entity takes over the license 
pursuant to FPA section 15). Thus, there is a need for licensees to 
maintain adequate books and records in case either of those situations 
occur. However, we will attempt to minimize the burden of compliance as 
discussed below.
---------------------------------------------------------------------------

    \468\ 16 U.S.C. 797(b) (relating to determining actual 
legitimate original cost of and net investment in a licensed 
project).
    \469\ 16 U.S.C. 807 (regarding the right of the Federal 
government to take over a project by paying the licensee its net 
investment).
    \470\ 16 U.S.C. 803(d) (relating to surplus accumulated in 
excess of a specified reasonable rate of return and requirement to 
maintain amortization reserves that may be applied from time to time 
to reduce net investment).
---------------------------------------------------------------------------

    347. We find that a hydropower licensee that sells only at market-
based rates may meet its obligations to comply with the Uniform System 
of Accounts by following General Instruction No. 16 under part 101 of 
the Commission's regulations.\471\ Accordingly, we clarify that 
hydropower licensees that make sales only at market-based rates and 
that have been granted Commission waiver of part 101 as part of their 
market-based rate tariffs may satisfy the requirements in part 101 of 
the Commission's regulations by following General Instruction No. 16 
under part 101. We find that doing so will not be unduly burdensome. 
However, we further clarify that hydropower licensees that have a cost-
based rate tariff on file with the Commission are still required to 
comply with the full requirements of FPA sections 4(b), 10(d), and 14 
and the amortization reserve article in their licenses.
---------------------------------------------------------------------------

    \471\ 18 CFR part 101 (General Instruction No. 16).
---------------------------------------------------------------------------

    348. We deny commenters' request that the Commission implement 
these clarifications prospectively and delay the implementation for at 
least one year to provide sufficient time to allow affected licensees 
to bring their accounting ledgers into compliance. We find it is not 
unduly burdensome for a hydropower licensee that sells only at market-
based rates to meet its longstanding obligation to comply with the 
Uniform System of Accounts by following General Instruction No. 16 
under part 101 of the Commission's regulations.
    349. Accordingly, as discussed in the NOPR, we will direct market-
based rate sellers that own licensed hydropower projects to ensure that 
their market-based rate tariffs reflect appropriate limitations on any 
waivers that previously have been granted. Specifically, to the extent 
that the hydropower licensee has been granted waiver of part 101 as 
part of its market-based rate authority, the licensee's market-based 
rate tariff limitations and exemptions section should be revised to 
provide that the seller has been granted waiver of part 101 of the 
Commission's regulations with the exception that waiver of the 
provisions that apply to hydropower licensees has not been granted with 
respect to licensed hydropower projects. Similarly, to the extent that 
a hydropower licensee has been granted waiver of part 141 as part of 
its market-based rate authority, it should ensure that the limitation 
and exemptions section of its market-based rate tariff specifies that 
waiver of part 141 has been granted, with the exception of sections 
141.14 and 141.15 (which pertain to the filing by hydropower licensees 
of Form No. 80, Licensed Hydropower Development Recreation Report, and 
the Annual Conveyance Report).\472\ As explained in the NOPR, these 
market-based rate tariff compliance filings are to be made the next 
time the hydropower licensee proposes a change to its market-based rate 
tariff, files a notice of change in status pursuant to 18 CFR 35.42, or 
submits an updated market power analysis in accordance with 18 CFR 
35.37. In addition, going forward, any

[[Page 67103]]

market-based rate seller requesting waivers of parts 101 and/or 141 
should include these limitations in its market-based rate tariffs, 
regardless of whether it owns any licensed hydropower projects. This 
will ensure that hydropower licensees understand the limitations on 
parts 101 and 141 waivers. To the extent that the market-based rate 
seller is not a licensee, these limitations should not have any effect 
as they only deny waiver of certain provisions affecting licensees.
---------------------------------------------------------------------------

    \472\ See Domtar Maine, LLC, 133 FERC ] 61,207 at P 23.
---------------------------------------------------------------------------

    350. If an existing market-based rate seller becomes a hydropower 
licensee and the Commission previously accepted the seller's market-
based rate tariff with full waivers without the limitations relating to 
hydropower licensees discussed herein, the seller must file revisions 
to its market-based rate tariff to reflect the limitations in its parts 
101 and 141 waivers within 30 days of the effective date of its 
hydropower license.

H. Miscellaneous Issues

1. Regional Reporting Schedule
a. Commission Proposal
    351. In the NOPR, the Commission noted that that section 
35.37(a)(1) of the Commission's regulations requires Category 2 sellers 
to submit a market power analysis according to the regional schedule 
contained in Order No. 697. The Commission proposed to revise section 
35.37(a)(1) so that instead of referring to the schedule contained in 
Order No. 697, section 35.37(a)(1) would to refer to an updated 
regional reporting schedule posted on the Commission's Web site.\473\ 
The Commission noted that the revised regional reporting schedule and 
associated map may be found on the Commission's Web site at http://www.ferc.gov/industries/electric/gen-info/mbr/triennial/when.asp.
---------------------------------------------------------------------------

    \473\ The NOPR also included an updated region map in Appendix 
D.
---------------------------------------------------------------------------

b. Comments
    352. EEI encourages the Commission to confer with the regulated 
community before making changes in the schedule and map, to ensure that 
those changes are workable and appropriate.\474\ Additionally, EEI 
states that one significant step that the Commission could undertake to 
reduce the burden on Category 2 sellers would be to extend the time 
frame for submitting updated analyses from every three years to every 
four to five years. EEI states that the Commission would continue to 
receive change in status filings as needed in the interim that would 
alert the Commission of changes occurring in a given market that might 
raise potential market power concerns, and if the Commission is 
concerned about those changes, the Commission already has the right to 
ask for more information or even an updated market power analysis from 
the seller filing the change in status report.\475\
---------------------------------------------------------------------------

    \474\ EEI at 22.
    \475\ Id. at 23.
---------------------------------------------------------------------------

c. Commission Determination
    353. We adopt the NOPR's proposal to revise section 35.37(a)(1) of 
the Commission's regulations with regard to the regional reporting 
schedule. The regional reporting schedule and associated map can be 
found on the Commission's Web site.\476\ In response to EEI's request 
that the Commission confer with the regulated community before making 
changes to the regional reporting schedule, we clarify that we are not 
changing the regional reporting schedule; we simply are changing the 
regulation to refer to the up-to-date schedule posted on the 
Commission's Web site. Our intention is to make the reporting schedule 
more transparent and accessible. We do not adopt EEI's suggestion to 
extend the time frame for submitting updated market power analyses from 
every three years to every four to five years. This suggestion is 
outside the scope of the NOPR. In any event, we believe that three 
years is a reasonable reporting schedule for filing updated market 
power analyses. EEI contends that sellers would submit change in status 
filings in the interim period. But change in status filings, while 
important, often lack the level of detail provided in updated market 
power analyses, such as indicative screens or SIL studies. Finally, in 
response to EEI's request that the Commission confer with the regulated 
community before making changes to the regional reporting schedule, we 
note that the region map is reflective of circumstances (such as 
mergers) that already have taken place. Future changes to the map would 
occur if, for example, a seller moved from an RTO in one region to an 
RTO in another region.
---------------------------------------------------------------------------

    \476\ The regional reporting schedule and region map can be 
found on the Commission's Web site at http://www.ferc.gov/industries/electric/gen-info/mbr/triennial/when.asp. Additionally, 
we include the regional reporting schedule in Appendix C of this 
Final Rule and the region map in Appendix D of this Final Rule.
---------------------------------------------------------------------------

2. Affirmative Statement
a. Commission Proposal
    354. In the NOPR, the Commission noted that in Order No. 697, as 
part of the vertical market power analysis, the Commission stated that 
it would require sellers to make an affirmative statement that they 
have not erected barriers to entry into the relevant market and will 
not erect barriers to entry into the relevant market. The Commission 
further noted that the requirement is codified at section 35.37(e)(4). 
The Commission explained that although the Commission stated in Order 
No. 697 that the obligation applies both to the seller and its 
affiliates,\477\ many sellers have not mentioned their affiliates when 
making their affirmative statements. Therefore, the Commission proposed 
to revise section 35.37(e)(4) (which was proposed elsewhere in the NOPR 
to be renumbered as section 35.37(e)(3)) to make clear that the 
affirmative statement requirement applies to the seller and its 
affiliates.
---------------------------------------------------------------------------

    \477\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 447.
---------------------------------------------------------------------------

b. Comments
    355. APPA/NRECA and Golden Spread support clarifying that an 
applicant for market-based rate authority must affirmatively state, on 
behalf of itself and its affiliates, that they have not and will not 
erect barriers to entry in the relevant market(s).\478\
---------------------------------------------------------------------------

    \478\ APPA/NRECA at 5; Golden Spread at 7.
---------------------------------------------------------------------------

c. Commission Determination
    356. We adopt the proposal in the NOPR concerning the affirmative 
statement. No adverse comments were filed with respect to this 
proposal. As noted above, this obligation already applies both to the 
seller and its affiliates. However, because many sellers have not 
mentioned their affiliates when making their affirmative statements, we 
adopt the proposal to revise the regulations to make it clear that the 
affirmative statement requirement applies to the seller and its 
affiliates. The revised regulation will appear at section 35.37(e)(3).
3. Comments of Barrick
a. Comments
    357. Barrick Goldstrike Mines (Barrick) notes that the Commission 
previously found that ``mitigated sellers and their affiliates are 
prohibited from selling power at market based rates in the balancing 
authority area in which the seller is found, or presumed, to have 
market power.'' \479\ Barrick also notes

[[Page 67104]]

that, in Order No. 697, the Commission recognized that wholesale sales 
made at the metered boundary for export lend themselves to being 
monitored for compliance and concluded to allow mitigated sellers to 
make such sales.\480\ Barrick further notes that in Order No. 697, to 
ensure that the mitigated seller and its directly related companies did 
not sell the same power purchased by a third party at the metered 
boundary back into the balancing authority area where the seller is 
mitigated, the Commission imposed record keeping requirements for these 
sales.\481\ Barrick states that, ``rather than dealing with the 
additional regulatory burdens and risk of non-compliance,'' mitigated 
sellers may instead choose not to make any market-based rate sales at 
the metered boundary and that this is problematic.\482\ Barrick argues 
that permitting affiliates to choose not to sell at a metered boundary 
hinders the development of more robust competition. Barrick also 
represents that Berkshire Hathaway Energy Company's affiliates have 
elected not to sell in a market based on a rebuttable presumption that 
a seller has market power, but have done nothing to rebut or 
substantiate that presumption.\483\ Barrick suggests that the 
Commission reevaluate the mitigation rules and the definition of 
``affiliate'' in certain cases.\484\
---------------------------------------------------------------------------

    \479\ Barrick at 6 (citing Order No. 697-C, FERC Stats. & Regs. 
] 31,291 at P 42) (emphasis added by Barrick). Barrick states that 
``affiliate'' is broadly defined in the market-based rate regulation 
and may need to be refined to be limited to the relationship between 
a franchised public utility with captive customers and its 
associated market-regulated power sales company. Id.
    \480\ Id. at 7 (citing Order No. 697, FERC Stats. & Regs. ] 
31,252 at P 820).
    \481\ Id.
    \482\ Id. (emphasis by Barrick).
    \483\ Id. at 8-9.
    \484\ In particular, where (a) no RTO or ISO exists in the 
region so parties must depend on bilateral contracts; (b) dominant 
utility power suppliers with geographically large balancing 
authority areas and common ownership due to consolidation are 
present; (c) construction of electric generation facilities in these 
geographically large balancing authority areas is dominated by the 
utility power suppliers because they have relatively easy access to 
funding through retail ratepayer funding; and (d) dominant utility 
power suppliers are refusing to sell wholesale power into balancing 
authority areas, even where they have not been found to have market 
power. Id. at 7-8 (arguing that Order No. 697 did not adequately 
anticipate the possibilities brought about by the repeal of PUHCA of 
1938, so now entities, are becoming too big to regulate with 
traditional rules).
---------------------------------------------------------------------------

    358. Barrick further asserts that Order No. 697 should be amended 
in such a way to allow full optimization of imbalance energy across the 
broader footprint of CAISO Energy Imbalance Market \485\ (EIM) and the 
sharing of other resources within the Northwest Power Pool.\486\ 
Barrick states that the mitigation rules adopted in Order No. 697 cause 
imbalance energy across the broader CAISO EIM footprint to not be 
optimized despite the fact that transmission between the entities in 
the EIM is available, resulting in the inefficient implementation of 
the CAISO EIM.\487\
---------------------------------------------------------------------------

    \485\ Id. at 10, 13 (citing Cal. Indep. Sys. Operator Corp., 
Transmittal Letter, Docket No. ER14-1836-000 (filed Feb. 28, 2014) 
and Cal. Indep. Sys. Operator Corp., 147 FERC ] 61,231 (2014)).
    \486\ Id. at 10-13.
    \487\ Id. at 11 (explaining that CAISO and NV Energy will be 
able to purchase and sell five-minute real-time energy under a 
market-driven regime for meeting energy imbalance needs, and CAISO 
and PacifiCorp will be able to purchase and sell five-minute real-
time energy under a market-driven regime for meeting energy 
imbalance needs, but PacifiCorp and NV Energy will not be able to 
purchase and sell five-minute real-time energy under a market-driven 
regime for meeting energy imbalance needs).
---------------------------------------------------------------------------

b. Commission Determination
    359. With respect to Barrick's requests to revisit the Commission's 
findings in Order No. 697 that ``mitigated sellers and their affiliates 
are prohibited from selling power at market-based rates in the 
balancing authority area in which the seller is found, or presumed, to 
have market power'' and the definition of ``affiliate,'' at least in 
certain cases, we find that they are beyond the scope of this 
rulemaking. Accordingly, we will not address Barrick's comments in this 
Final Rule.\488\
---------------------------------------------------------------------------

    \488\ Additionally, reply comments were filed in response to 
Barrick's comments but they are not permitted in this proceeding.
---------------------------------------------------------------------------

V. Section-by-Section Analysis of Regulations

1. Section 35.36 Generally

    360. This section defines certain terms specific to Subpart H and 
explains the applicability of subpart H.
    361. The NOPR proposed to redefine ``Category 1 Seller'' in 
paragraph (a)(2) to clarify the distinction in determining the seller 
category status of power marketers and power producers. Specifically, 
that for purposes of determining category status, a power marketer 
should include all affiliated generation capacity in that region, but 
that a power producer only needs to include affiliated generation that 
is located in the same region as the power producer's generation 
assets.
    362. The Final Rule adopts the regulatory text changes proposed in 
the NOPR regarding the definition of Category 1 Seller in paragraph 
(a)(2).

2. Section 35.37 Market Power Analysis Required

    363. This section describes the market power analysis the 
Commission employs, as discussed in the preamble, and when sellers must 
file one. It is intended to identify the key aspects of the analysis.
    364. The NOPR proposed to change the reference in paragraph (a)(1) 
for the location of the regional reporting schedule from Order No. 697 
to the Commission's Web site. The NOPR proposed to add a requirement in 
paragraph (a)(2) that sellers include as part of their updated market 
power analyses, an organizational chart depicting their current 
corporate structure, indicating all upstream owners, energy 
subsidiaries and energy affiliates. The NOPR proposed to revise 
paragraph (c)(4) to specify that sellers must file their indicative 
screens in an electronic spreadsheet format. The NOPR proposed to add 
paragraph (c)(5) to require that sellers use the format provided in 
appendix A of subpart H of part 35 and, if applicable, file SIL 
Submittals 1 and 2 in the electronic spreadsheet format provided on the 
Commission's Web site. The NOPR also proposed to add paragraph (c)(6) 
to provide that sellers in RTO/ISO markets with Commission-approved 
market monitoring and mitigation may, in lieu of submitting the 
indicative screens, include a statement that they are relying on such 
mitigation to address any potential horizontal market power concerns. 
The NOPR proposed to remove paragraph (e)(2) to remove the requirement 
that sellers address sites for generation capacity development as part 
of their market power analyses and to renumber paragraphs (e)(3) and 
(e)(4) as paragraphs (e)(2) and (e)(3) respectively and to revise new 
paragraph (e)(3) to clarify that the vertical market power affirmative 
statement must be made on behalf of the seller and its affiliates.
    365. The Final Rule adopts the regulatory text changes proposed in 
the NOPR regarding the location of the schedule for updated market 
power filings in paragraph (a)(1). The Final Rule also adopts the NOPR 
proposal to revise the language in paragraph (a)(2) to require an 
organizational chart; however the language varies from that proposed in 
the NOPR to limit the organizational chart to depicting affiliates as 
discussed in the Corporate Families discussion above. The Final Rule 
also adopts the NOPR regulatory text changes to paragraphs (c)(4) and 
(c)(5) regarding submission of the indicative screens and SIL 
Submittals 1 and 2 in electronic spreadsheet formats. Consistent with 
the Horizontal Market Power discussion, the Final Rule does not adopt 
the NOPR proposal to add a new paragraph allowing sellers in RTO/ISO 
markets to rely on market monitoring and mitigation in lieu of 
submitting indicative screens. The Final Rule adopts the NOPR proposal 
to

[[Page 67105]]

amend the language of paragraph (e)(3) to clarify that the affirmative 
statement must be made on behalf of the seller and its affiliates.

3. Section 35.42 Change in Status Reporting Requirement

    366. The NOPR proposed several revisions to the regulation, 
including a change to paragraph (a)(1) to clarify that the 100 MW 
reporting threshold is not limited to market previously studied and 
includes both the relevant market and any first-tier markets. The NOPR 
proposed a change to paragraph (a)(2)(i) to apply a 100 MW threshold 
for reporting new affiliations and to include in that threshold long-
term firm purchases of capacity and/or energy and to included 
cumulative increases in the first-tier markets as well as the relevant 
market. The NOPR also proposed to revise paragraph (c) to require 
sellers to submit organizational chart unless the change in status does 
not affect the seller's structure. In addition, the NOPR proposed 
revisions to paragraph (b) to remove a reference to change in status 
filings to report acquisition of control of sites for new generation 
capacity development and to remove paragraphs (d) and (e), which 
address site control reporting, which is being eliminated as explained 
in the Notices of Change in Status discussion.
    367. The Final Rule adopts the proposed edits to paragraph (a) 
except as discussed herein. In paragraphs (a)(1) and (a)(2)(i), the 
language proposed in the NOPR including first-tier markets is not 
included in accordance with the Notices of Change in Status discussion 
and the requirement is limited to 100 MW or more change in any 
individual relevant geographic market. The Final Rule adopts the NOPR 
proposal to add a 100 MW threshold to the change in status reporting 
requirement and, consistent with the Capacity Ratings discussion, adds 
language in paragraph (a)(2)(i) to specify that energy-limited 
resources may use a five-year capacity rating for purposes of 
calculating the threshold.
    368. Consistent with the Vertical Market Power--Land Acquisition 
Reporting discussion, the Final Rule adopts the proposals to remove 
references to reporting new sites for generation capacity development, 
removing paragraphs (d) and (e) in their entirety and deleting the 
reference to site reporting from paragraph (b).
    369. Finally, the Final Rule adopts the proposed edits to paragraph 
(c) except as discussed herein. Consistent with the Corporate 
Organizational Charts discussion, the Final Rule does not include the 
reference to upstream owners and energy subsidiaries, and requires only 
that the organizational charts indicate all affiliates.

4. Miscellaneous

VI. Information Collection Statement

    370. The Office of Management and Budget (OMB) regulations require 
approval of certain information collection and data retention 
requirements imposed by agency rules.\489\ Upon approval of a 
collection(s) of information, OMB will assign an OMB control number and 
an expiration date. Respondents subject to the filing requirements of a 
rule will not be penalized for failing to respond to these collections 
of information unless the collections of information display a valid 
OMB control number.
---------------------------------------------------------------------------

    \489\ 5 CFR 1320.11(b) (2015).
---------------------------------------------------------------------------

    371. The Commission is submitting the proposed modifications to its 
information collections to OMB for review and approval in accordance 
with section 3507(d) of the Paperwork Reduction Act of 1995.\490\ In 
the NOPR, the Commission solicited comments on the Commission's need 
for this information, whether the information will have practical 
utility, the accuracy of the burden estimates, ways to enhance the 
quality, utility, and clarity of the information to be collected or 
retained, and any suggested methods for minimizing respondents' burden, 
including the use of automated information techniques. The Commission 
included a table that listed the estimated public reporting burdens for 
the proposed reporting requirements, as well as a projection of the 
costs of compliance for the reporting requirements.
---------------------------------------------------------------------------

    \490\ 44 U.S.C. 3507(d) (2012).
---------------------------------------------------------------------------

Comments

    372. In response to the Commission's proposals regarding changes to 
the indicative screen reporting requirements, EEI notes that, if the 
Commission wants sellers to submit the indicative screens in appendix A 
in formats other than the standard formats, such as Adobe, Excel, or 
Word, the Commission should acknowledge that requiring the use of more 
complex formats and new details in appendix A will entail some 
additional burden on sellers filing the information, at least during 
the initial round of using such formats.\491\
---------------------------------------------------------------------------

    \491\ EEI at 10.
---------------------------------------------------------------------------

Commission Determination

    373. We revise the Information Collection Statement estimates 
contained in the NOPR because the Commission has made several changes 
to its NOPR proposal in this Final Rule, which are discussed below.
    374. First, we do not adopt in the Final Rule the NOPR proposal to 
eliminate the requirement in section 35.37 \492\ to file the indicative 
screens as part of a horizontal market power analysis for any seller in 
an RTO if the seller is relying on Commission-approved monitoring and 
mitigation to mitigate any potential market power it may have. The NOPR 
presupposed a decrease in its burden estimate regarding this proposal, 
and we have adjusted the burden estimate in the table below to reflect 
that this burden will not change from current regulations.
---------------------------------------------------------------------------

    \492\ 18 CFR 35.37.
---------------------------------------------------------------------------

    375. Second, we will modify the NOPR's proposal to require sellers 
to file corporate organizational charts including all upstream owners, 
energy subsidiaries, and energy affiliates in initial market-based rate 
applications and related filings. The organizational charts will still 
be required, but they will be limited 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.'' This modification of the NOPR proposal 
constitutes a small burden decrease from the NOPR. Because the 
corporate organizational chart filing is similar to that proposed in 
the NOPR, we are not modifying the estimated public reporting burdens 
for this proposed reporting requirement in the table below. We believe 
that the revised burden estimates below are representative of the 
average burden on filers.
    376. Third, we do not adopt the NOPR proposal to clarify that 
sellers must report behind-the-meter generation in the indicative 
screens and asset appendices, and have such generation count toward 
change in status and category status thresholds. These changes 
represent a small decrease in burden due to the reduction in filings 
from not including behind-the-meter generation as part of the 100 MW 
generation threshold to trigger filing a notice of change in status for 
new affiliations.
    377. Fourth, we modify the NOPR's proposed changes to the asset 
appendix by (1) requiring separate worksheets in the Asset Appendix for 
long-term PPAs and end notes, (2) adding new columns to the generation 
asset list for explanatory end note numbers and information regarding 
capacity ratings, and (3) adding new columns to the

[[Page 67106]]

transmission list for citation to the order accepting the OATT or 
approving transfer of transmission facility to an RTO/ISO and 
explanatory end note numbers. The NOPR presupposed a burden decrease in 
its burden estimate regarding this proposal, and we have adjusted the 
burden estimate in the table below to reflect that, as amended, the 
burden will not change from current regulations. While these changes 
represent a small increase in burden, this burden is counterbalanced by 
the decrease in burden from eliminating the proposed requirements to 
report behind-the-meter generation in indicative screens and for change 
in status and seller category thresholds. Thus, we believe that the 
overall burden will not change when these two changes are averaged 
together.
    378. In response to EEI's comment that the use of more complex 
formats for indicative screens will entail additional burden, 
Commission regulations already require the submission of indicative 
screens, and the Final Rule adopts the NOPR proposal to require these 
screens in electronic format. We view this as a de minimis decrease in 
burden for several reasons. While the new rows in the indicative 
screens may appear to require additional information to complete the 
screens (e.g., rows A1, B1, L1, M, U, and V in the market share 
screen), the information entered in these new rows is simply 
disaggregated information that was previously required, but often 
erroneously aggregated into values in other rows. Requiring sellers to 
explicitly enter this information will reduce computation errors and 
subsequent phone calls from staff to correct problems in the screens. 
Also, these new screens are workable electronic spreadsheets with pre-
programmed formulas in certain cells that compute intermediate and 
final cell values. Embedding these pre-programmed formulas into the 
worksheet will reduce the amount of time that sellers will spend 
creating and calculating the indicative screens, increase the accuracy 
of the values entered (e.g., sellers will now enter only positive 
values and no longer have to enter values surrounded by parentheses to 
indicate a negative value), and eliminate computation errors that 
sellers have frequently made in the past. Thus, we consider the 
electronic format and the additional columns of information in the 
indicative screens to average out to be a de minimis decrease in burden 
for filers and project that the average burden on filers will not 
change from current regulations.

                                                          FERC-919 (Final Rule in RM14-14-000)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Annual number  of                     Average  burden &     Total annual
                                            Number of        responses  per    Total number  of      cost  per       burden hours  &        Cost per
                                           respondents         respondent         responses        response \493\   total annual cost   respondent  ($)
                                                      (1)                (2)      (1)*(2) = (3)                (4)      (3)*(4) = (5)          (5) / (1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
New Applications for Market-Based                     213                  1                213          \494\ 250             53,250            $21,268
 Rates (18 CFR 35.37..................                                                                     $21,268         $4,529,998
Triennial Market Power Analysis in                     83                  1                 83                250             20,750            $21,268
 Category 2 Seller Updates (18 CFR                                                                         $21,268         $1,765,203
 35.37)...............................
Quarterly Land Acquisition Reports [18                  0                  0                  0                  0                  0                 $0
 CFR 35.42(d)]........................                                                                          $0                 $0
Change in Status Reports [18 CFR                       27                  1                 27                250              6,750            $21,268
 35.42(a)], With Screens..............                                                                     $21,268           $574,222
Change in Status reports [18 CFR                      186                  1                186                 20              3,720             $1,701
 35.42(a)], No Screens................                                                                      $1,701           $316,460
    Total.............................                                                      509                                84,470            $14,118
                                                                                                                           $7,185,883
--------------------------------------------------------------------------------------------------------------------------------------------------------

    After implementation of the proposed changes, the total estimated 
annual cost of burden to respondents is $7,185,882.90 [84,470 hours x 
$85.07 \495\) = $7,185,882.90].
---------------------------------------------------------------------------

    \493\ The Commission estimates this figure based on the Bureau 
of Labor Statistics data (for the Utilities sector, at http://www.bls.gov/oes/current/naics2_22.htm, plus benefits information at 
http://www.bls.gov/news.release/ecec.nr0.htm). The salaries (plus 
benefits) for the three occupational categories are:
     Economist: $67.75/hour
     Electric Engineer: $59.62/hour
     Lawyer: $128.02/hour
    ($67.57 + $59.62 + $128.02) / 3 = $85.07
    \494\ The Commission notes that the estimate of 250 hours per 
new application is a conservative estimate and most likely 
overstates burden because some sellers (i.e., power marketers with 
no generation to study and sellers that only have fully committed 
generation) will not have to file indicative screens with their 
initial applications.
    \495\ The Commission estimates this figure based on the Bureau 
of Labor Statistics data (for the Utilities sector, at http://www.bls.gov/oes/current/naics2_22.htm, plus benefits information at 
http://www.bls.gov/news.release/ecec.nr0.htm). The salaries (plus 
benefits) for the three occupational categories are:
     Economist: $67.75/hour
     Electric Engineer: $59.62/hour
     Lawyer: $128.02/hour
    ($67.57 + $59.62 + $128.02)/3 = $85.07

---------------------------------------------------------------------------

[[Page 67107]]

    Title: Proposed Revisions to Market Based Rates for Wholesale Sales 
of Electric Energy, Capacity and Ancillary Services by Public Utilities 
(FERC-919).
    Action: Revision of Currently Approved Collection of Information.
    OMB Control No.: 1902-0234.
    Respondents for this Rulemaking: Public utilities, wholesale 
electricity sellers, businesses, or other for profit and/or not for 
profit institutions.
    Frequency of Responses:
    Initial Applications: On occasion.
    Updated Market Power Analyses: Updated market power analyses are 
filed every three years by Category 2 sellers seeking to retain market-
based rate authority.
    Land Acquisitions: We will eliminate this requirement under the 
Final Rule.
    Change in Status Reports: On occasion.
    Necessity of the Information:
    Initial Applications: In order to receive market-based rate 
authority, the Commission must first evaluate whether a seller has the 
ability to exercise market power. Initial applications help inform the 
Commission as to whether an entity seeking market-based rate authority 
lacks market power, and whether sales by that entity will be just and 
reasonable.
    Updated Market Power Analyses: Triennial updated market power 
analyses allow the Commission to monitor market-based rate sellers to 
detect changes in market power or potential abuses of market power. The 
updated market power analysis permits the Commission to determine that 
continued market-based rate authority will still yield rates that are 
just and reasonable.
    Change in Status Reports: The change in status requirement provides 
the Commission with information regarding changes that could affect 
facts the Commission relied upon in granting market-based rate 
authority and thus permits the Commission to ensure that rates and 
terms of service offered by market-based rate sellers remain just and 
reasonable.
    Internal Review: The Commission has reviewed the reporting 
requirements and made a determination that revising the reporting 
requirements will ensure the Commission has the necessary data to carry 
out its statutory mandates, while eliminating unnecessary burden on 
industry. The Commission has assured itself, by means of its internal 
review, that there is specific, objective support for the burden 
estimate associated with the information requirements.
    379. Interested persons may obtain information on the reporting 
requirements by contacting: Federal Energy Regulatory Commission, 888 
First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office 
of the Executive Director, email: [email protected], phone: (202) 
502-8663, fax: (202) 273-0873]. Comments concerning the requirements of 
this rule may also be sent to the Office of Information and Regulatory 
Affairs, Office of Management and Budget, Washington, DC 20503 
[Attention: Desk Officer for the Federal Energy Regulatory Commission]. 
For security reasons, comments should be sent by email to OMB at 
[email protected]. Comments submitted to OMB should refer to 
FERC-919 and OMB Control Number 1902-0234.

VII. Environmental Analysis

    380. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\496\ The 
Commission has categorically excluded certain actions from this 
requirement as not having a significant effect on the human 
environment. Included in the exclusion are rules that are clarifying, 
corrective, or procedural, or that do not substantially change the 
effect of the regulations being amended.\497\ The actions here fall 
within this categorical exclusion in the Commission's regulations.
---------------------------------------------------------------------------

    \496\ Regulations Implementing the National Environmental Policy 
Act of 1969, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. 
& Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \497\ 18 CFR 380.4(a)(2)(ii).
---------------------------------------------------------------------------

VIII. Regulatory Flexibility Act

    381. The Regulatory Flexibility Act of 1980 (RFA) \498\ generally 
requires a description and analysis of proposed rules that will have 
significant economic impact on a substantial number of small entities. 
Thus, the Commission estimates that the rulemaking will impose only a 
minimal additional burden on responsible entities, as described below.
---------------------------------------------------------------------------

    \498\ 5 U.S.C. 601-612 (2012).
---------------------------------------------------------------------------

    382. The final rule in RM14-14-000 is expected to impose an 
additional burden on 2,002 entities. Comparison of the applicable 
entities with FERC's small business data indicates that approximately 
1,634, or 82 percent \499\ of the 2,002 entities are small entities 
affected by this Final Rule.\500\
---------------------------------------------------------------------------

    \499\ 81.6 percent.
    \500\ The Small Business Administration sets the threshold for 
what constitutes a small business. Public utilities may fall under 
one of several different categories, each with a size threshold 
based on the company's number of employees, including affiliates, 
the parent company, and subsidiaries. For the analysis in this Final 
Rule, we use a 750 employee threshold for each affected entity. Each 
entity is classified as Electric Bulk Power Transmission and Control 
(NAICS code 221121), Fossil Fuel Generation (NAICS code 221112), or 
Nuclear Power Generation (NAICS code 221113).
---------------------------------------------------------------------------

    383. On average, each small entity affected may have a one-time 
cost of $4,207.19, representing 84,470 hours at $67.57/hour (for 
economists), $59.62/hour (for electrical engineers), and $128.02/hour 
(for lawyers). These figures represent the implementation burden of the 
changes to FERC-919 per the RM14-14-000 Final Rule, as explained above 
in the information collection statement. Accordingly, the Commission 
certifies that this rulemaking will not have a significant economic 
impact on a substantial number of small entities. The Commission seeks 
comment on this certification.

IX. Document Availability

    384. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, 
Washington, DC 20426.
    385. From the Commission's Home Page on the Internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    386. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours from the Commission's Online 
Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
[email protected].

X. Effective Date and Congressional Notification

    387. This Final Rule is effective January 28, 2016. The Commission 
has

[[Page 67108]]

determined, with the concurrence of the Administrator of the Office of 
Information and Regulatory Affairs of OMB, that this rule is not a 
``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996. This Final Rule is being 
submitted to the Senate, House, and Government Accountability Office.

List of Subjects in 18 CFR Part 35

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

    By the Commission.

    Issued: October 16, 2015.
Kimberly D. Bose,
Secretary.

    In consideration of the foregoing, the Commission amends part 35, 
chapter I, title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

0
2. Amend Sec.  35.36 by revising paragraph (a)(2) to read as follows:


Sec.  35.36  Generally.

    (a) * * *
    (2) Category 1 Seller means a Seller that:
    (i) Is either a wholesale power marketer that controls or is 
affiliated with 500 MW or less of generation in aggregate per region or 
a wholesale power producer that owns, controls or is affiliated with 
500 MW or less of generation in aggregate in the same region as its 
generation assets;
    (ii) Does not own, operate or control transmission facilities other 
than limited equipment necessary to connect individual generating 
facilities to the transmission grid (or has been granted waiver of the 
requirements of Order No. 888, FERC Stats. & Regs. ] 31,036);
    (iii) Is not affiliated with anyone that owns, operates or controls 
transmission facilities in the same region as the Seller's generation 
assets;
    (iv) Is not affiliated with a franchised public utility in the same 
region as the Seller's generation assets; and
    (v) Does not raise other vertical market power issues.
* * * * *

0
3. Amend Sec.  35.37 as follows:
0
a. In paragraph (a)(1), remove the phrase ``contained in Order No. 697, 
FERC Stats. & Regs. ] 31,252'' and add in its place ``posted on the 
Commission's Web site''.
0
b. Revise paragraphs (a)(2) and (c)(4).
0
c. Add paragraph (c)(5).
0
d. Remove paragraph (e)(2) and redesignate paragraphs (e)(3) and (4) as 
paragraphs (e)(2) and (3), respectively.
0
e. Remove the period at the end of newly redesignated paragraph (e)(2) 
and add ``; and'' in its place.
0
f. Revise newly redesignated paragraph (e)(3).
    The revisions and additions read as follows:


Sec.  35.37  Market power analysis required.

    (a) * * *
    (2) When submitting a market power analysis, whether as part of an 
initial application or an update, a Seller must include an appendix of 
assets, in the form provided in appendix B of this subpart, and an 
organizational chart. The organizational chart must depict the Seller's 
current corporate structure indicating all affiliates.
* * * * *
    (c) * * *
    (4) When submitting the indicative screens, a Seller must use the 
format provided in appendix A of this subpart and file the indicative 
screens in an electronic spreadsheet format. A Seller must include all 
supporting materials referenced in the indicative screens.
    (5) Sellers submitting simultaneous transmission import limit 
studies must file Submittal 1, and, if applicable, Submittal 2, in the 
electronic spreadsheet format provided on the Commission's Web site.
* * * * *
    (e) * * *
    (3) A Seller must ensure that this information is included in the 
record of each new application for market-based rates and each updated 
market power analysis. In addition, a Seller is required to make an 
affirmative statement that it and its affiliates have not erected 
barriers to entry into the relevant market and will not erect barriers 
to entry into the relevant market.
* * * * *

0
4. Amend Sec.  35.42 as follows:
0
a. Revise paragraphs (a)(1) and (2) and (c).
0
b. In paragraph (b), remove the phrase ``, other than a change in 
status submitted to report the acquisition of control of a site or 
sites for new generation capacity development,''.
0
c. Remove paragraphs (d) and (e).
    The revisions read as follows:


Sec.  35.42  Change in status reporting requirement.

    (a) * * *
    (1) Ownership or control of generation capacity or long-term firm 
purchases of capacity and/or energy that results in cumulative net 
increases (i.e., the difference between increases and decreases in 
affiliated generation capacity) of 100 MW or more of nameplate capacity 
in any individual relevant geographic market, or of inputs to electric 
power production, or ownership, operation or control of transmission 
facilities; or
    (2) Affiliation with any entity not disclosed in the application 
for market-based rate authority that:
    (i) Owns or controls generation facilities or has long-term firm 
purchases of capacity and/or energy that results in cumulative net 
increases (i.e., the difference between increases and decreases in 
affiliated generation capacity) of 100 MW or more of capacity based on 
nameplate or seasonal capacity ratings, or, for energy-limited 
resources, five-year average capacity factors, in any individual 
relevant geographic market;
    (ii) Owns or controls inputs to electric power production;
    (iii) Owns, operates or controls transmission facilities; or
    (iv) Has a franchised service area.
* * * * *
    (c) When submitting a change in status notification regarding a 
change that impacts the pertinent assets held by a Seller or its 
affiliates with market-based rate authorization, a Seller must include 
an appendix of all assets, including the new assets and/or affiliates 
reported in the change in status, in the form provided in appendix B of 
this subpart, and an organizational chart. The organizational chart 
must depict the Seller's prior and new corporate structures indicating 
all affiliates unless the Seller demonstrates that the change in status 
does not affect the corporate structure of the Seller's affiliations.

0
5. Revise appendix A to subpart H to read as follows:

Appendix A to Subpart H of Part 35--Standard Screen Format

BILLING CODE 6717-01-P

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0
6. Revise appendix B to subpart H to read as follows:

Appendix B to Subpart H of Part 35--Corporate Entities and Assets 
Sample Appendix
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[[Page 67112]]


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[[Page 67113]]


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[[Page 67114]]


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[[Page 67115]]



    Note: The following appendices will not be published in the Code 
of Federal Regulations.

Appendix C to the Final Rule: Regional Reporting Schedule 
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[[Page 67123]]

Appendix F to the Final Rule: List of Commenters and Acronyms

------------------------------------------------------------------------
                Commenter                        Short name/acronym
------------------------------------------------------------------------
American Antitrust Institute.............  AAI
American Electric Power Service            AEP
 Corporation.
American Public Power Association and      APPA/NRECA
 National Rural Electric Cooperative
 Association.
Avista Corporation and Puget Sound         Avista/Puget
 Energy, Inc.
Barrick Goldstrike Mines.................  Barrick
Romkaew Broehm and Gerald A. Taylor......  Broehm/Taylor
E.ON Climate & Renewables North America    E.ON
 LLC.
Edison Electric Institute................  EEI
El Paso Electric Company.................  El Paso
Electric Power Supply Association........  EPSA
FirstEnergy Service Company..............  FirstEnergy
Golden Spread Electric Cooperative, Inc..  Golden Spread
Idaho Power Company......................  Idaho Power Company
Indicated Western Utilities (Arizona       Indicated Utilities
 Public Service Company; Idaho Power
 Company; NV Energy, Inc.; PacifiCorp;
 and Portland General Electric Company).
National Hydropower Association..........  NHA
NextEra Energy, Inc......................  NextEra
Potomac Economics, Ltd...................  Potomac Economics
Southeast Transmission Owners (Duke        Southeast Transmission Owners
 Energy Carolinas, LLC; Duke Energy
 Progress, Inc.; Louisville Gas and
 Electric Company and Kentucky Utilities
 Company; South Carolina Electric & Gas
 Company; and Southern Company Services,
 Inc., acting as agent for Alabama Power
 Company, Georgia Power Company, Gulf
 Power Company and Mississippi Power
 Company).
Southern California Edison Company.......  SoCal Edison
Julie R. Solomon and Matthew E. Arenchild  Solomon/Arenchild
SunEdison Inc............................  SunEdison
NRG Companies (over 120 entities wholly    NRG Companies
 or partially owned subsidiaries of NRG
 Energy, Inc.).
Transmission Access Policy Study Group...  TAPS
------------------------------------------------------------------------


[FR Doc. 2015-26908 Filed 10-39-15; 8:45 am]
BILLING CODE 6717-01-P