Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 67055-67123 [2015-26908]
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Vol. 80
Friday,
No. 210
October 30, 2015
Part IV
Department of Energy
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Federal Energy Regulatory Commission
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
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Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
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
Federal Energy Regulatory
Commission, DOE.
ACTION: Final rule.
AGENCY:
The Federal Energy
Regulatory Commission (Commission) is
amending its regulations that govern
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SUMMARY:
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 marketbased 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
I. Introduction ...............................................................................................................................................................................
II. Background ...............................................................................................................................................................................
III. Overview of Final Rule ..........................................................................................................................................................
IV. Discussion ...............................................................................................................................................................................
A. Horizontal Market Power .................................................................................................................................................
1. Sellers in RTOs/ISOs .................................................................................................................................................
2. Sellers With Fully Committed Long-Term Generation Capacity ............................................................................
3. Relevant Geographic Market for Certain Sellers in Generation-Only Balancing Authority Areas .......................
4. Reporting Format for the Indicative Screens and SIL Submittals 1 and 2 ............................................................
5. Competing Imports ....................................................................................................................................................
6. Capacity Ratings .........................................................................................................................................................
7. Reporting of Long-Term Firm Purchases ..................................................................................................................
8. Clarification of Commission Language in Performing SIL Studies ........................................................................
B. Vertical Market Power—Land Acquisition Reporting ....................................................................................................
1. Commission Proposal ................................................................................................................................................
2. Comments ...................................................................................................................................................................
3. Commission Determination .......................................................................................................................................
C. Notices of Change in Status .............................................................................................................................................
1. Geographic Focus .......................................................................................................................................................
2. New Affiliation and Behind-the-Meter Generation .................................................................................................
3. Reporting of Long-Term Firm Purchases ..................................................................................................................
D. Asset Appendix ................................................................................................................................................................
1. Changes to the Existing Columns .............................................................................................................................
2. Reporting Power Purchase Agreements ....................................................................................................................
3. Clarifications Regarding the Existing Columns ........................................................................................................
4. Changes Regarding OATT Waiver and Citations in Transmission Asset List .......................................................
5. Electronic Format .......................................................................................................................................................
6. Database ......................................................................................................................................................................
E. Category 1 and Category 2 Sellers ...................................................................................................................................
1. Commission Proposal ................................................................................................................................................
2. Comments ...................................................................................................................................................................
3. Commission Determination .......................................................................................................................................
F. Corporate Families ............................................................................................................................................................
1. Corporate Organizational Charts ...............................................................................................................................
2. Single Corporate Tariff ..............................................................................................................................................
G. Part 101 and 141 Waivers ................................................................................................................................................
1. Commission Proposal ................................................................................................................................................
2. Comments ...................................................................................................................................................................
3. Commission Determination .......................................................................................................................................
H. Miscellaneous Issues ........................................................................................................................................................
1. Regional Reporting Schedule ....................................................................................................................................
2. Affirmative Statement ................................................................................................................................................
3. Comments of Barrick .................................................................................................................................................
V. Section-by-Section Analysis of Regulations ...........................................................................................................................
VI. Information Collection Statement ..........................................................................................................................................
VII. Environmental Analysis ........................................................................................................................................................
VIII. Regulatory Flexibility Act ...................................................................................................................................................
IX. Document Availability ...........................................................................................................................................................
X. Effective Date and Congressional Notification .......................................................................................................................
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
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Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
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 marketbased 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.
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 marketbased 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.
1 16
U.S.C. 824d, 824e.
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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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
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
7 Id.
P 13; 18 CFR 35.37(c)(3).
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.
10 Id. P 408.
11 Id. P 440.
12 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 176.
8 The
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.
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Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
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
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 longterm (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
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
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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).
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).
20 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
P 848.
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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
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
10. After more than six years of
experience with the implementation of
Order No. 697, the Commission
proposed a number of changes to the
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.
25 Id. P 5.
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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 marketbased 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
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 marketbased 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 longterm 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
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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Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
generation capacity from the generationonly 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-themeter 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.
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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
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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
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 marketbased 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
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 marketbased 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.’’
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
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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 Commissionapproved RTO/ISO monitoring and
mitigation in the event that such sellers
fail the indicative screens for the RTO/
ISO markets.36
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
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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
2. Sellers With Fully Committed LongTerm Generation Capacity
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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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.
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
36 See Order No. 697–A, FERC Stats. & Regs. ¶
31,268 at P 11.
37 See id. P 41.
38 ‘‘Relevant’’ generation capacity refers to seller
and affiliated capacity in the study area, including
the first tier.
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counterparties, the length of the longterm 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).
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
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 longterm basis lacks the ability to exercise
horizontal market power by withholding
such capacity from the market.43
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
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).
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.
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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 firsttier market in which its affiliates have
uncommitted capacity.44
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
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 longterm 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
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
44 NRG
Companies at 10–11.
45 NextEra at 4.
46 EPSA at 5.
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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
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
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
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
47 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 43
(emphasis added).
48 Solomon/Arenchild at 2–3.
49 Id. at 3.
50 NextEra at 4–5 (citing https://www.ferc.gov/
docs-filing/eqr/order770/data-dictionary.pdf).
51 Id. at 5.
52 EEI at 8.
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67061
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 longterm 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 marketpower 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.
41. We do not adopt the suggestion
from Solomon/Arenchild to only
consider first-tier supply that has longterm firm transmission rights into the
relevant market. First-tier generation
capacity without long-term firm
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.
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transmission rights still can be imported
into the relevant market as long as the
SIL value is not zero; albeit on a nonfirm, pro rata basis.54 The SIL values
used in the Commission’s horizontal
market power analysis are net of longterm 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.
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.
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 marketbased 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
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 firsttier 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.
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.
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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
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
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).
60 Id. P 51.
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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 generationonly 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.
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
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 generationonly balancing authority area is directly
interconnected with, then the IPP would
provide indicative screens for that
transmission provider’s balancing
authority area.62
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
61 Id.
P 49 n.50.
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.
62 The
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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
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
63 See Order No. 697, FERC Stats. & Regs.
¶ 31,252 at P 232 n.217.
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serve load in a balancing authority area,
but there is no longer any material load
present in the balancing authority
area.64
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
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
64 Solomon/Arenchild
at 15.
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).
67 Id. at 17.
65 The
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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
55. Solomon/Arenchild state that the
proposal could have significant marketdistortive 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 marketbased 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
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
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).
69 Id. at 18.
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area, and hence, allow market-based rate
sales at the hubs.70
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 onlybalancing 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
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
70 Id.
73 Id.
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
74 EPSA
71 Broehm/Taylor
72 Id.
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
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 marketbased 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
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
at 6.
Companies at 12–13 (citing Order No. 697,
FERC Stats. & Regs. ¶ 31,252 at P 817).
76 EEI at 9.
at 3.
75 NRG
at 3–5.
at 5–6.
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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
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 generationonly 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 generationonly balancing authority areas of the
Gila River Power Company LLC and
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).
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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
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.
65. We appreciate the concerns of
Solomon/Arenchild that this
requirement is overly burdensome, but
think the proposal achieves an
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.
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.
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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 marketbased 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
82 Mitigated
sellers are allowed to make marketbased 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.
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67065
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
68. We find Broehm/Taylor’s request
that the Commission require all marketbased 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 firsttier 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
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 Commissionapproved tariff that may also, depending on the
facts, violate the Commission’s market
manipulation regulations. See id. P 831.
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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
4. Reporting Format for the Indicative
Screens and SIL Submittals 1 and 2
a. Commission Proposal
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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
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.’’).
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).
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row 10 of Submittal 1 used to report SIL
study results.
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.
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 preprogrammed spreadsheet as an example
that sellers may use to submit their
indicative screens.89
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
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 nonaffiliate uncommitted capacity able to be imported
from the first tier.
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.
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the Commission’s Web site 90 and
submit their information, as instructed,
in workable electronic spreadsheets.
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
77. EEI requests that the Commission
specify that it simply wants marketbased 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 marketbased rate program, to ensure that all are
reasonable, clear, accurate, easy to use,
and most cost-effective.93
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
79. El Paso commends the proposal to
add new rows to clearly identify LongTerm 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 firsttier balancing authority areas. El Paso
states that the Commission’s proposed
modifications to the standard screen
90 The sample spreadsheets for Submittals 1 and
2 are found at the Commission’s Web site at
https://www.ferc.gov/industries/electric/gen-info/
mbr/authorization.asp under ‘‘Quick Links.’’
91 APPA/NRECA at 4; Golden Spread at 7.
92 EEI at 9.
93 Id. at 9–10.
94 Solomon/Arenchild at 11–12.
95 El Paso at 2–3.
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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
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
96 Id.
at 3–4.
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
97 It
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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 ‘‘LongTerm 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
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: https://www.ferc.gov/
docs-filing/elibrary/accept-file-formats.asp.
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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.
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
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.
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.
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).
100 EEI at 10; APPA/NRECA at 4; Golden Spread
at 7.
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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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
103 See EIA, Annual Energy Outlook (May 2014),
available at https://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.
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generation capacity ratings from EIA’s
Annual Energy Outlook in their filing.
89. In addition, the Commission
sought industry input in identifying
additional technologies that are energylimited 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 energylimited generation resource, it must use
the five-year average for all energylimited 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
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technologies as energy-limited
generation resources.105
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 fiveyear 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.
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,
105 See, e.g., E.ON at 4; NextEra at 6; EEI at 11;
SunEdison, Inc. (SunEdison) at 1.
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).
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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
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
iii. Identifying Other Energy-Limited
Resources
96. In response to the Commission’s
request for industry input in identifying
additional technologies that are energylimited 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
iv. Require Same Rating Methodology
for All Resources of the Same
Technology
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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
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
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 energylimited resources can provide energy in
daylight hours and not necessarily only
in peak-defined hours. E.ON asks that if
114 NextEra
110 Broehm/Taylor
at 6.
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.
113 SoCal Edison at 15.
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at 7.
at 11.
116 FirstEnergy at 7.
117 Id. at 8.
118 Idaho Power at 3.
119 Broehm/Taylor at 7–8.
120 SoCal Edison at 15.
121 EPSA at 6–7.
115 EEI
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67069
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 fiveyear average capacity factor or EIA
regional data.124
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 fiveyear 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
122 E.ON
at 5.
at 11.
124 NextEra at 6.
123 EEI
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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
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
125 E.ON
at 5.
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.
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which it is unable to obtain five years
of operating history.127
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 energylimited 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 energylimited 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
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
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.
128 Id. P 344.
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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 energylimited 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 derate 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 energylimited 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
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capacity of generation owned or
controlled through contract and longterm 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 longterm firm energy purchase would allow
the purchaser to control generation
capacity.131
109. In the NOPR, the Commission
noted that the limited reporting of longterm 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
129 Id.
P 38.
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).
132 Although we generally use the term ‘‘sellers’’
elsewhere in the Final Rule when referring to
market-based rate sellers and applicants, in this
130 See
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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
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 factspecific 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
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67071
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 factspecific circumstances that they believe
may support a different attribution of
capacity.
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 longterm 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
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.
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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
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.
115. Third, requiring the reporting of
all long-term firm power purchases also
will ensure consistent treatment of
owned or installed capacity and longterm 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
135 Order No. 697, FERC Stats. & Regs. ¶ 31,252
at P 38 (footnotes omitted).
136 Id. P 38 n.18.
137 Order No. 697–B, FERC Stats. & Regs. ¶ 31,285
at PP 99, 100.
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.
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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.
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 longterm 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.
139 Another example is when a generator confers
operational control to a third party through a longterm tolling agreement. See, e.g., Shell Energy North
America (US), L.P., 135 FERC ¶ 61,090, at P 3
(2011).
140 The NOPR stated that ‘‘[a]s the Commission
noted in Vantage Wind, improperly classifying
long-term firm purchases (or imports of remotelyowned 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
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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
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.
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get energy to the market is demonstrably
false in some cases.145
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
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
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
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
tkelley on DSK3SPTVN1PROD with RULES2
145 Id.
at 11.
at 6; FirstEnergy at 8.
147 FirstEnergy at 8–9.
148 E.ON at 7.
149 EEI at 12.
150 Avista Corp. and Puget Sound Energy, Inc.
(Avista/Puget) at 2.
151 Id. at 4.
152 TAPS at 2.
146 E.ON
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market shares or pivotal supplier
conditions.153
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
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
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
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 postat 21–24.
Utilities at 2.
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
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
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
153 APPA/NRECA
159 Indicated
154 Indicated
160 SoCal
155 Id.
at 5.
at 7.
157 EPSA at 9–10.
158 Id. at 10.
156 IWU
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Utilities at 8–9.
Edison at 12.
161 Id. at 17.
162 Solomon/Arenchild at 10–11.
163 NextEra at 9.
164 Id. at 10.
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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.
128. SoCal Edison states that although
the NOPR proposes reporting of longterm 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
129. Solomon/Arenchild ask for
clarification on the treatment of jointlyowned 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
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
165 SoCal
Edison at 13.
166 Solomon/Arenchild
167 APPA/NRECA
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attribute such capacity to the purchaser
rather than the seller.
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 longterm 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 longterm 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 longterm 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.
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
168 SoCal
Edison at 5.
indicative screens include rows for longterm firm sales and purchases made by nonaffiliated 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 longterm 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.
171 Avista at 4.
169 The
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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).
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
172 IWU
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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.
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 longterm 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 longterm 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 energylimited resources in the indicative
screens whether owned or purchased
under long-term firm power purchase
agreements.
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
173 See
174 The
supra Section IV.A.6.
EQR Data Dictionary uses this definition
as well.
175 SoCal Edison at 11.
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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 forwardlooking 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
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
176 See
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67075
converted, regardless of whether the
contract includes a separate capacity
payment.
141. Upon consideration of the
comments, we will modify the energyto-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
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 longterm 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.
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
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.’’).
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.
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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 longterm 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
tkelley on DSK3SPTVN1PROD with RULES2
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
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.
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
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consider ‘‘all internal/external
contingency facilities and all
monitored/limiting facilities that were
used historically to approximate areaarea transmission availability’’ and
utilize scaling methods according to the
same methods used historically for nonaffiliate resources.183
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
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 SameTime 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
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).
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).
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
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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
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.
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
amount of study are transmission capability
available to potential competitors.’’).
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.’’).
191 The sample spreadsheets for Submittals 1 and
2 are found at the Commission’s Web site at
https://www.ferc.gov/industries/electric/gen-info/
mbr/authorization.asp under ‘‘Quick Links.’’
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.
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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
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 firsttier and study area transmission
providers 198 to calculate and post ATC
and to evaluate requests for firm
transmission service.199
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
tkelley on DSK3SPTVN1PROD with RULES2
196 Id.
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.
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),
https://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.
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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
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.
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67077
incompatible with the performance of
SIL studies.
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
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
158. Regarding accounting for longterm 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
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.’’).
206 Id. P 164 n.177 (quoting Order No. 697–A,
FERC Stats. & Regs. ¶ 31,268 at P 145).
207 The revised Standard Screen Format (e.g.,
rows B1 and M1 in the market share screen (LongTerm 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).
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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
tkelley on DSK3SPTVN1PROD with RULES2
(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 longterm 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 nonaffiliates. 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
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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sensitivities and other data that show
how the utilization of import capability
by non-affiliates is indicative of a
competitive marketplace.212
(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
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
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 nonaffiliate 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
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.
213 See Order No. 697, FERC States. & Regs.
¶ 31,252 at P 356.
214 Id. P 346.
215 Order No. 697–A, FERC States. & Regs.
¶ 31,268 at P 145.
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power purchase agreement for the same
reason.216
163. In response to Southeast
Transmission Owners, we find that
reducing the simultaneous TTC value
and historical peak load value by longterm 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
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 nonaffiliated 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 wheelthrough 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
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.
217 Order No. 697–A, FERC States. & Regs.
¶ 31,268 at P 146.
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in Submittal 2 and proposed
corresponding changes to Submittal 2.
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(b) Comments
165. Solomon/Arenchild state they do
not understand the rationale and intent
of the proposal to include wheelthrough 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.
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 longterm 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
218 Southeast Transmission Owners at 4 (citing
NOPR, FERC Stats. & Regs. ¶ 32,702 at P 166).
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to other long-term firm transmission
reservations, a traditional wheelthrough 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 ‘‘wheelinto,’’ 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 wheelthrough transactions.
168. Further, we clarify that wheelinto 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
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
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.
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.
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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
(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 longterm 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.
(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
221 NOPR,
FERC Stats. & Regs. ¶ 32,702 at P 167.
222 Id.
223 Solomon/Arenchild at 12 (quoting NOPR,
FERC Stats. & Regs. ¶ 32,702 at P 167).
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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.
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 firsttier 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
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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
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.
225 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 168.
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(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 longterm 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
(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 longterm 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
226 Solomon/Arenchild at 12; NOPR, FERC Stats.
& Regs. ¶ 32,702 at P 168.
227 Solomon/Arenchild at 12–13.
228 See Allocation of Capacity on New Merchant
Transmission Projects and New Cost-Based,
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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.
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
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.
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).
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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’’).
(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 nonaffiliate 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
(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
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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.’’)).
234 Idaho Power at 4–5.
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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 nonaffiliate 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.
(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
235 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 170
(citing Puget, 135 FERC ¶ 61,254 at app. B,
Submittal 1, n.iv).
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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
236 Id.
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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.
(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.
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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.
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.
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 ‘‘longterm 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 ‘‘longterm’’ 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
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
194. Southeast Transmission Owners
support EEI’s request for the
Commission to further caucus with
industry regarding SIL studies. Given
the complexities underlying the marketbased 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
240 Solomon/Arenchild
at 14–15.
at 21.
242 Southeast Transmission Owners at 6–7 (citing
NOPR, FERC Stats. & Regs. ¶ 32,702 at app. C).
241 EEI
237 See
Revised app. E, Submittal 1.
FERC Stats. & Regs. ¶ 32,702 at P 172.
238 NOPR,
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239 Id. P 173 (citing Atlantic Renewables Projects
II, 135 FERC ¶ 61,227, at P 9 (2011)).
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intended goal of streamlining the
market-based rate program, and may
result in less reliable SIL values.
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 longterm 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
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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
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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
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
243 18
CFR 35.37(e)(2).
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.’’).
244 18
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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
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
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
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.
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.
252 NextEra at 10.
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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.
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/
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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 https://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)).
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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
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.
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.
255 APPA/NRECA
at 26–27.
256 TAPS
at 2.
CFR 35.42(d).
258 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 89
n.109.
257 18
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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.
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.
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.’’).
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C. Notices of Change in Status
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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.
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 marketbased 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
260 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 512.
261 Id.
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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 firsttier to each other.
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
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
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
265 Solomon/Arenchild
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).
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266 Solomon/Arenchild
267 EEI
at 4; NextEra at 11.
at 5.
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.
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tkelley on DSK3SPTVN1PROD with RULES2
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
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, fiveyear 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
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
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.
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.
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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
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
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
224. E.ON requests that the
Commission clarify that a notice of
283 E.ON
284 Id.
at 13.
E.ON’s proposed change is illustrated in
italics.
285 Idaho Power at 3–4.
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.
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 marketbased rate seller has already told the Commission,
namely, that the market-based rate seller is relying
on RTO mitigation).
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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
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
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
291 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).
293 NextEra at 11.
294 Id.
295 Id. at 12.
296 EEI at 16.
292 Id.
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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
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 marketbased 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.
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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
297 EPSA
at 11–12.
298 Id.
299 NextEra
at 11; Solomon/Arenchild at 4.
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there is a long-term firm transmission
reservation to import the 100 MW.
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
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.
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.
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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.
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.
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
302 AEP
at 3; E.ON at 8–9.
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.
305 Cal. ex rel. Harris v. FERC., 784 F.3d 1267,
1276 (9th Cir. 2015) (‘‘When we approved marketbased 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)).
306 EEI at 16.
303 AEP
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threshold was not proposed in the
NOPR; thus, the proposal is outside the
scope of this rulemaking.
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.
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
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
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.
308 E.ON at 11 (arguing that an initial marketbased rate application of the new affiliate should
suffice to address all other relevant, affiliated
market-based sellers).
309 NextEra at 11.
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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.
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
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).
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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.
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-themeter 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.
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
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 inservice 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.
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.
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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
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
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
313 EEI
at 16.
314 FirstEnergy
315 Id.
at 11.
at 12.
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316 Id.
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
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add that such generation may involve
net metering, which they state does not
involve wholesale sales or transmission
implicating the Commission’s
jurisdiction.320
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
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)).
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 netmetered 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).
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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
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-themeter 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
326 El
Paso at 4.
327 Id.
328 Id.
329 EPSA
330 SoCal
at 11.
Edison at 19 (emphasis in original).
331 Id.
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generation assets.332 SoCal Edison
argues that such aggregation should be
permitted to relieve the burden that
otherwise would be imposed.333
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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.
252. However, we do not adopt the
NOPR proposal to count behind-themeter 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.
332 Id.
at 23.
333 Id.
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.
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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-themeter 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 marketbased rate authority and the capacity of
these facilities should be reported in the
screens, asset appendix and in
determining the 100 MW threshold.
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
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 longterm 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
335 See
18 CFR 292.601(c)(1).
Stats. & Regs. ¶ 32,702 at P 100.
337 SoCal Edison at 23.
c. Commission Determination
258. The requirement to report longterm 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 longterm 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.
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
336 NOPR,
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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
339 See,
e.g., Solomon/Arenchild at 7; EEI at 17.
at 7 & Attachment 1
(illustrating their proposed additional column to
the asset appendix).
340 Solomon/Arenchild
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geographic regions without advance
notice and opportunity for comment by
market participants in those regions.341
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
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
341 EEI
at 17.
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.
342 See,
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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
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 FiveYear 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, 5yr (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,
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].’’
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].
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while maintaining the ability to tie asset
appendix ratings to those used in a
market power analysis.
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
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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.
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
352 NOPR,
FERC Stats. & Regs. ¶ 32,702 at PP 16,
79.
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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 fiveyear average capacity rating.355
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 longterm 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.
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 nonaffiliated 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 longterm firm PPA, it should use the same
rating methodology for that facility in its
353 SoCal
Edison at 21.
at 23.
355 NextEra at 13–14.
356 SoCal Edison at 21.
357 As discussed above, the Commission will not
permit de-rating of solar photovoltaic facilities. See
supra Section IV.A.6.c.i.
354 Id.
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market power study that it is using for
other generation facilities utilizing that
technology.
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.
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
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
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.
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)).
360 See Order No. 697, FERC Stats. & Regs.
¶ 31,252 at P 187.
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screens. However, the entire capacity of
the facility should be reflected in the list
of generation assets in the appendix.
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.
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
361 See
supra Section IV.C.2.c.
term ‘‘company registration database’’
here refers to ‘‘FERC’s Online Company Registration
application’’ (see https://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)).
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362 The
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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).
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(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.
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 longdistance 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
(b) Commission Determination
281. We disagree with SoCal Edison
that reporting the mileage of
368 See
supra Section IV.D.1.c.
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).
369 Transmission
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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
iii. Passive Ownership
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(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
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
370 NOPR,
FERC Stats. & Regs. ¶ 32,702 at P 118.
e.g., EEI at 17; AAI at 7–9.
372 EEI at 17.
373 Id.
374 AAI at 7–8.
375 Id. at 7–9
371 See,
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(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.
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
376 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 116
n.130 (citing AES Creative, 129 FERC ¶ 61,239).
377 Solomon/Arenchild at 7–8.
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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
(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
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).
380 Order No. 697, FERC Stats. & Regs. ¶ 31,252
at P 301.
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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.
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
381 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at PP 124–130.
382 Id. P 130.
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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
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.
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
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
386 APPA/NRECA
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.
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.
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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.
390 See, e.g., AEP at 9; EEI at 17; and FirstEnergy
at 13.
391 FirstEnergy at 13.
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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
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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.
392 Id.
at 14.
at 9.
394 Id.; EEI at 17.
395 AEP at 9; see also EEI at 17.
393 AEP
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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
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
303. An example of the electronic
spreadsheet for the asset appendix with
the proposed new columns and column
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).
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
https://www.ferc.gov/docs-filing/elibrary/accept-fileformats.asp.
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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 predefined 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
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
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.
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
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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.
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
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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
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
https://www.ferc.gov/docs-filing/elibrary/acceptfileformats.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.
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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
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 nonjurisdictional 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
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 marketbased 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.
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.
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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
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
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
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 welldesigned 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.
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
414 NextEra
415 EPSA
at 15.
at 14.
416 Id.
417 Id.
418 AEP
at 9.
419 APPA/NRECA
at 5; Golden Spread at 7; E.ON
at 14; Solomon/Arenchild at 6–7.
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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
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
420 Order No. 697, FERC Stats. & Regs. ¶ 31,252
at PP 853–863; see also 18 CFR 35.36(a)(2).
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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
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
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
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.
422 EEI at 19.
423 Id.
424 Id.
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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.
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.
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
425 Order No. 697, FERC Stats. & Regs. ¶ 31,252
at PP 864–868.
426 Id. P 864.
427 Id. P 865; Order No. 697–A, FERC Stats. &
Regs. ¶ 31,268 at P 360.
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).
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ownership, for initial applications for
market-based rate authority, updated
market power analyses and notices of
change in status reporting new
affiliations.
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 posttransaction 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 marketbased 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
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).
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minimal as most sellers have this
organizational chart available.
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 marketbased 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
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
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
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.
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.
437 Id. at 15–16.
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67099
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 marketbased 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
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
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
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.
440 E.ON at 15; EPSA at 16.
441 E.ON at 15.
442 EPSA at 16.
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.
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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 Commissionapproved 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
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
c. Commission Determination
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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 marketbased 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.
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).
448 NRG Companies at 5; AEP at 10.
449 NRG Companies at 5.
450 AEP at 10.
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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
335. Consistent with our clarifications
above, we will revise the regulatory text
in § 35.37(a)(2) to clarify that the
organizational chart must include
affiliates, without any further reference
to ‘‘upstream owners,’’ ‘‘energy
451 Tonopah Solar Energy, LLC, 151 FERC ¶
61,203, at PP 11–12 (2015).
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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
https://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
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
452 EEI
at 20.
453 Id.
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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.
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
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).
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respect to licensed hydropower projects.
Similarly, to the extent that a
hydropower licensee has been granted
waiver of part 141 as part of its marketbased 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
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 marketbased 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
456 See Domtar Maine, LLC, 133 FERC ¶ 61,207,
at P 23 (2010).
457 EPSA at 17–18; NHA at 2–10; EEI at 21–22.
But see APPA/NRECA at 5; Golden Spread at 7.
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67101
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.
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
458 See, e.g., EPSA at 18 (citing Order No. 697,
FERC Stats. & Regs. ¶ 31,252 at P 985).
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)).
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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
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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
462 EEI
at 22; EPSA at 18; NHA at 8–9.
at 22; EPSA at 18; NHA at 8–9.
464 EEI at 22; NHA at 8–9.
465 EEI at 22: NHA at 9.
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).
463 EEI
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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.
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.
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
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).
471 18 CFR part 101 (General Instruction No. 16).
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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.
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 marketbased 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 marketbased 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
472 See
Domtar Maine, LLC, 133 FERC ¶ 61,207 at
P 23.
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market-based rate seller requesting
waivers of parts 101 and/or 141 should
include these limitations in its marketbased 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 marketbased rate seller is not a licensee, these
limitations should not have any effect as
they only deny waiver of certain
provisions affecting licensees.
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
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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 https://
www.ferc.gov/industries/electric/geninfo/mbr/triennial/when.asp.
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
473 The NOPR also included an updated region
map in Appendix D.
474 EEI at 22.
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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
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.
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
475 Id.
at 23.
regional reporting schedule and region
map can be found on the Commission’s Web site
at https://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.
476 The
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67103
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.
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
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
477 See Order No. 697, FERC Stats. & Regs.
¶ 31,252 at P 447.
478 APPA/NRECA at 5; Golden Spread at 7.
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.
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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
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.
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).
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.
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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
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
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.
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 fiveminute 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).
488 Additionally, reply comments were filed in
response to Barrick’s comments but they are not
permitted in this proceeding.
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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
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amend the language of paragraph (e)(3)
to clarify that the affirmative statement
must be made on behalf of the seller and
its affiliates.
owners and energy subsidiaries, and
requires only that the organizational
charts indicate all 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
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.
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.
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4. Miscellaneous
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
Commission Determination
373. We revise the Information
Collection Statement estimates
contained in the NOPR because the
489 5
CFR 1320.11(b) (2015).
U.S.C. 3507(d) (2012).
491 EEI at 10.
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 Commissionapproved 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.
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
490 44
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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 behindthe-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 preprogrammed 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)
Number of
respondents
Annual number
of responses
per respondent
Total number
of responses
Average
burden & cost
per response 493
Total annual
burden hours
& total annual cost
Cost per
respondent
($)
(1)
(2)
(1)*(2) = (3)
(4)
(3)*(4) = (5)
(5) ÷ (1)
New Applications
for MarketBased Rates (18
CFR 35.37 ........
213
1
213
494 250
$21,268
53,250
$4,529,998
$21,268
Triennial Market
Power Analysis
in Category 2
Seller Updates
(18 CFR 35.37)
83
1
83
250
$21,268
20,750
$1,765,203
$21,268
Quarterly Land Acquisition Reports
[18 CFR
35.42(d)] ...........
0
0
0
0
$0
0
$0
$0
Change in Status
Reports [18
CFR 35.42(a)],
With Screens ....
27
1
27
250
$21,268
6,750
$574,222
$21,268
Change in Status
reports [18 CFR
35.42(a)], No
Screens ............
186
1
186
20
$1,701
3,720
$316,460
84,470
$7,185,883
$1,701
Total ..............
509
tkelley on DSK3SPTVN1PROD with RULES2
After implementation of the proposed
changes,the total estimated annual cost
493 The
Commission estimates this figure based
on the Bureau of Labor Statistics data (for the
Utilities sector, at https://www.bls.gov/oes/current/
naics2_22.htm, plus benefits information at https://
www.bls.gov/news.release/ecec.nr0.htm). The
salaries (plus benefits) for the three occupational
categories are:
• Economist: $67.75/hour
VerDate Sep<11>2014
18:00 Oct 29, 2015
Jkt 238001
of burden to respondents is
• 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.
PO 00000
Frm 00052
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$14,118
$7,185,882.90 [84,470 hours ×
$85.07 495) = $7,185,882.90].
495 The Commission estimates this figure based
on the Bureau of Labor Statistics data (for the
Utilities sector, at https://www.bls.gov/oes/current/
naics2_22.htm, plus benefits information at https://
www.bls.gov/news.release/ecec.nr0.htm). The
salaries (plus benefits) for the three occupational
categories are:
• Economist: $67.75/hour
E:\FR\FM\30OCR2.SGM
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tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
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
• Electric Engineer: $59.62/hour
• Lawyer: $128.02/hour
($67.57 + $59.62 + $128.02)/3 = $85.07
VerDate Sep<11>2014
18:00 Oct 29, 2015
Jkt 238001
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:
DataClearance@ferc.gov, 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 oira_
submission@omb.eop.gov. 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.
VIII. Regulatory Flexibility Act
67107
the 2,002 entities are small entities
affected by this Final Rule.500
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 (https://
www.ferc.gov) and in the Commission’s
Public Reference Room during normal
business hours (8:30 a.m. to 5:00 p.m.
Eastern time) at 888 First Street NE.,
Room 2A, Washington, DC 20426.
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 ferconlinesupport@ferc.gov,
or the Public Reference Room at (202)
502–8371, TTY (202) 502–8659. Email
the Public Reference Room at
public.referenceroom@ferc.gov.
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
X. Effective Date and Congressional
additional burden on responsible
Notification
entities, as described below.
387. This Final Rule is effective
382. The final rule in RM14–14–000
January 28, 2016. The Commission has
is expected to impose an additional
burden on 2,002 entities. Comparison of
500 The Small Business Administration sets the
the applicable entities with FERC’s
threshold for what constitutes a small business.
small business data indicates that
Public utilities may fall under one of several
approximately 1,634, or 82 percent 499 of different categories, each with a size threshold
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).
498 5 U.S.C. 601–612 (2012).
499 81.6 percent.
PO 00000
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Fmt 4701
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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).
E:\FR\FM\30OCR2.SGM
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67108
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
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.
§ 35.37
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
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.
2. Amend § 35.36 by revising
paragraph (a)(2) to read as follows:
■
tkelley on DSK3SPTVN1PROD with RULES2
§ 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.
*
*
*
*
*
■ 3. Amend § 35.37 as follows:
VerDate Sep<11>2014
18:00 Oct 29, 2015
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’’.
■ b. Revise paragraphs (a)(2) and (c)(4).
■ c. Add paragraph (c)(5).
■ d. Remove paragraph (e)(2) and
redesignate paragraphs (e)(3) and (4) as
paragraphs (e)(2) and (3), respectively.
■ e. Remove the period at the end of
newly redesignated paragraph (e)(2) and
add ‘‘; and’’ in its place.
■ f. Revise newly redesignated
paragraph (e)(3).
The revisions and additions read as
follows:
■
Jkt 238001
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.
*
*
*
*
*
■ 4. Amend § 35.42 as follows:
■ a. Revise paragraphs (a)(1) and (2) and
(c).
■ b. In paragraph (b), remove the phrase
‘‘, other than a change in status
submitted to report the acquisition of
PO 00000
Frm 00054
Fmt 4701
Sfmt 4700
control of a site or sites for new
generation capacity development,’’.
■ c. Remove paragraphs (d) and (e).
The revisions read as follows:
§ 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 marketbased 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 marketbased 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.
■ 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
E:\FR\FM\30OCR2.SGM
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Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
67109
Appendix A: Standard Screen Format (Data provided for illustrative purposes only)
Part 1- Pivotal Supplier Analysis
Staff Notes:
The file differs from the file published in the NOPR:
1. All entered values must be positive (no parenthesis/negative numbers)
2. The formulas (and the text in the row description) have been changed to reflect number 1.
3. The text in row 13 "Date of Filing" has been replaced with "Data Year''
4. Instruction: Enter all numeric values as positive numbers (blue values)
I
Don't enter values into an outlined cell (black values)
I
Applicant-> Company X, LLC (TO)
Market -> Company X BAA
Data Year-> Dec 2011-Nov 2012
Row
Generation
Seller and Affiliate Capacity (owned or controlled)
Reference
1,500
200
A
A1
8
81
C
D
Installed Capacity (from inside the study area)
Remote Capacity (from outside the study area)
Long-Tenm Finm Purchases (from inside the study area)
Long-Tenm Finm Purchases (from outside the study area)
Long-Tenm Finm Sales (in and outside the study area)
Uncommitted Capacity Imports
E
E1
F
F1
G
H
Non-Affiliate Capacity (owned or controlled)
Installed Capacity (from inside the study area)
Remote Capacity (from outside the study area)
Long-Tenm Finm Purchases (from inside the study area)
Long-Tenm Finm Purchases (from outside the study area)
Long-Tenm Finm Sales (in and outside the study area)
Uncommitted Capacity Imports
I
J
Study Area Reserve Requirement
Amount of Line I Attributable to Seller, if any
K
Total Uncommitted Supply (A+A1+8+81+D+E+E1+F+F1+H-C-G-I-M)
worksheet
worksheet
worksheet
worksheet
worksheet
worksheet
70
200
500
0
X
X
X
X
X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
300
50
40
40
60
2,500
300
200
2,a4o
X
worksheet X
I
Load
1,500
1,200
L Balancing Authority Area Annual Peak Load
M Average Daily Peak Native Load in Peak Month
N Amount of Line M Attributable to Seller, if any
900
0 Wholesale Load (L-M)
P
worksheet X
worksheet X
worksheet X
300
2,540
Net Uncommitted Supply (K-0)
370
Q Seller's Uncommitted Capacity (A+A1+B+B1+D-C-J-N)
Result of Pivotal Supplier Screen (Pass if Line Q < Line P)
Pass
(Fail if Line Q > Line P)
Total Imports (Sum D,H), as filed by Seller->
% of SIL for Selle~s imported capacity->
% of SIL for Othe~s imported capacity -> L------'-'=
VerDate Sep<11>2014
18:00 Oct 29, 2015
Jkt 238001
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Sfmt 4725
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC15.000</GPH>
tkelley on DSK3SPTVN1PROD with RULES2
SIL wlue• ->
2,500
Do Total Imports exceed the SIL wlue? ->I
No
I
• Transmission owners filing triennials should use the SIL wlues from their Submittal1, Row 10 (see Puget Sound Energy, Inc., 135 FERC 'II 61,254 (2011)).
Other sellers should use Commission-accepted SIL wlues, if they exist for the study area and study period. If these wlues do not exist, sellers should
use SIL wlues that ha1.e been filed but not accepted.
67110
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
Appendix A: Standard Screen Format (Data provided for illustrative purposes only)
Part II- Market Share Analysis
Staff Notes:
The file differs from the file published in the NO PR:
1. All entered values must be positive (no parenthesis/negative numbers)
2. The formulas (and the text in the row description) have been changed to reflect number 1.
3. Instruction: Enter all numeric values as positive numbers (blue values)
Don't enter values into an outlined cell (black values)
I
Applicant-> Company X, LLC (TO)
Study Area -> Company X BAA
Data Year-> Dec 2011-Nov 2012
As filed by the Applicant/Seller
Winter
Spring
Summer
Row
(MW)
A
A1
B
81
C
D
E
Seller and Affiliate Capacity (owned, controlled or under L T contract)
Installed Capacity (inside the study area)
1,000
400
Remote Capacity (from outside the study area)
Long-Temn Fimn Purchases (inside the study area)
60
Long-Temn Fimn Purchases (from outside the study area)
200
Long-Temn Fimn Sales (in and outside the study area)
500
Seasonal Average Planned Outages
150
Uncommitted Capacity Imports
0
F
G
H
I
J
K
Capacity Deductions
Average Peak Native Load in the Season
Amount of Line F Attributable to Seller, if any
Amount of Line F Attributable to Non-Affiliates, if any
Study Area Reserve Requirement
Amount of Line I Attributable to Seller, if any
Amount of Line I Attributable to Non-Affiliates, if any
L
L1
M
M1
N
0
P
(MW)
Non-Affiliate Capacity (owned, controlled or under L T contract)
Installed Capacity (inside the study area)
250
Remote Capacity (from outside the study area)
50
Long-Temn Fimn Purchases (inside the study area)
30
Long-Temn Fimn Purchases (from outside the study area)
40
Long-Temn Fimn Sales (in and outside the study area)
50
Seasonal Average Planned Outages
10
Uncommitted Capacity Imports
2,000
(MW)
900
300
40
200
500
50
0
1,000
200
30
200
500
100
0
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
900
1,000
1,500
200
70
200
500
80
0
1,200
800
worksheet X
worksheet X
700
900
600
.-----=-70='0:-------=-::7------=-':-=-----:.o~
I
200
300
2oo
.___---=.30"'0=------==-=-----==----==:....~
200
200
300
100
100
200
80
.------'-1O='O:------....C::7----=.:-::----~
100
100
20
'--------'-10"'0=-----...:..:-=------'-'=----:.::...J
I
200
50
30
30
30
20
1,500
300
50
30
40
60
10
2,500
150
50
30
20
50
20
1,300
1,910
210
2,120
1,460
90
1,550
2,450
290
2,740
5.8%
Pass
10.6%
Pass
10.6%
Pass
T
Seller's Market Share (R+S)
Results (Pass if< 20% and Fail if<: 20%)
u
Total Imports, as filed by Seller (E+P)
SIL value*
2,ooo
2,000
Do Total Imports exceed SIL value? (is U<=V)
No
I
1,5oo
1,500
I
No
2,5oo
2,500
No
I
tkelley on DSK3SPTVN1PROD with RULES2
Other sellers should use Commission-accepted SIL values, if they exist for the study area and study period.
use SIL values that ha;e been filed but not accepted.
18:00 Oct 29, 2015
Jkt 238001
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~these
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
1,300
1,300
No
• Transmission owners filing triennials should use the SIL values from their Submittal1, Row 10 (see Puget Sound Energy, Inc., 135 FERC
VerDate Sep<11>2014
worksheet X
worksheet X
1,260
150
1,410
9.9%
Pass
Supply Calculation
Q Total Competing Supply (L +L 1+M+M1 +P-H-K-N-0)
R Seller's Uncommitted Capacity (A+A 1+B+B 1+E-C-D-G-J)
s Total Seasonal Uncommitted Capacity (Q+R)
v
Reference
Fall
(MW)
~
61,254 (2011)).
values do not exist, sellers should
E:\FR\FM\30OCR2.SGM
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I
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
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
■
§-""-l<ti"'th."""'. . . . .
Tille
[l
[
~
67111
&ot""""tiooFonnat
Filing Entity and its EnBgyAffiliates
Free Form Text
Docket II where MBR authority was
Text in the form: IIIIXX-XXX-XXX where "1111"
granted
is either "ER" or
~
Name of the Filing Entity and its Afli liates. Please use the exact
name as in the Company Registration database if possible.
·w and ·r is a digit
If ap11licable, Docket Number where MBR or QF status was
originallygranted. can be an ER, EL or QF Docket
Unit Name or if all units in a plant are reasonably similar, a plant
Generation Name (Plant or Unit
Free Form Text
Name)
name. Use EIA-860 or industry standard names to the extent
possible.
Name of the Entity owning the generation unit or 11lant Please
[D
Owned By
use the same name as in the Company Registration database if
Free Form Text
possible.
Name of the Entity that controls the output of the generation unit
Controlled By
Free Form Text
or plant Please use the same name as in the Company
Registration database if possible.
The date the unit came under the control of the Entity listed in
Date Control Transferred
•[E] Controlled By." Often it is the date the generation was
MM/Y'{YY or DD/MM/Y'f
acquired or bui It
Free Form Text For Markets or
submarkets please use one of the
[G)
Market I Balancing Authority Area
abbreviations or names in the next
column. For BAAs please use the NERC
defined name
[t
Oneofthesix RTO/ISOs(I50-NE, NYISO, PJM, MISO,SPP,CAISOor
their designated submarkets {PJM-East, 5004/5005, APsouth,
Connecticut, Southwest Connecticut, New York City, Long Island) or
a NERCdefined Balancing Authority Area name.
One of the six MBR regions: Northeast, Southeast, Central, SPP,
Geographic Region
Specific Text
n-Se!vice Date
MM/Y'{YY or MM/DD/YY
The date the unit first came into service.
capacity Rating: Nameplate IMWI
Numeric. Either an integerorfixed
The nameplate capacity rating of the unit, usually provided by the
Southeast, Southwest; or •NfA"
width numeric with one decimal
Thecapacityratingofthe unit{s), in MWs, used in this filing for
width numeric with one decimal
capacity Rating: Used in Filing IMWI
manufacturer, in MWs..
Numeric. Either an integer or fixed
that unit{sj
capacity Rating: Methodology Used in
A single capitalletter(either•N•, -s·;u•;E", or "A") to designate
;~l:~iNjameplate,{S)easonal, 5-yr
the rating methodology of the unit's capacity used in this filing.
lit, 5-yr lEliA, (A)Itemative
The number of the explanatory note in •End Notes" worksheet
that refers to this entry. The numbers should be ascending
[MJ
End Note Number {Enter text in End
Note Tab)
integers throughout the append ill lfthere are three notes in the
Integer
Generation worksheet tab, then the first end note in the
Transmission tab should be •tour" (please do not start over with
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67112
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
Name of the Entity that is selling the energy or capacity.
Contracted amount of MW of the PPA. If the contract is for the entire
output of a specific generation facility, you may de-rate the facility
Numeric. Either an integer or fixed width
[D]
[E]
Amount of PPA (MW)
numeric with one decimal
rated please explain in the end notes section. Energy only contracts
must be converted from MwH to MW and only report contracts one
Free Form Text. For Markets or
submarkets please use one of the
abbreviations or names in the next
Market I Balancing Authority Area
using the same de-rating methodology that is used for generators of
the same technology elsewhere in the appendix. If this amount is de-
column. For BAAs please use the NERC
he RT0/150, RT0/150 submarket, or NERC defined balancing
authority area where the generation or capacity is physically located.
mmission cite to the order accepting the Filing Entity's or its
order approving the transfer of
En~ Affil iates•
transmission facilities to an RTO or
ansmission facilities to an RTO/ISO.
Lega I name of the faci I ity and brief description of the type of
Free Form Text
current OATT~ or the order transferring control of
lity (i.e. transmission line "'gas pipeline).
Desai ption of the size in faci I ity in the measures relevant to the
pecific type of facility. Fm example, fm Electric •size• refers to
the Length and kV rating of the transmission line; fm Gas
pipeline "Size.. refers to the length and Diameter of the pipeline;
for Gas Storage ..Size" refers to the capacity of the facility
Free Fmm Text
Same instruction as the Generation Assets Tab
Instructions for completing the Asset Appendix list: End Notes
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Explanatory Nate
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"PPA.. or *Transmission.. lists
Thewmds "Generation•, "PPA•,m
Indicates which asset list the end note is located
"Transmission"
ext providing the clarification or explanatory note_
Free Form Text
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List (Generation, PPA "'Transmission)
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~
Should match an End Note number in the •Generation Assets",
Integer
End Nate Number
67113
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
Asset Appendix: Generation Assets
ilhis is an example of the required appendix listing the filing entity and all its energy affiliates and their associall!d assets which should be submi!ll!d with all market-based rate filings_
[B)
[AI
[C)
[F)
[E]
[D)
[G)
[H]
[K]
[JJ
[I)
ILl
Location
()od[etlf
Generation
Filing
Market/
Date
Entity and whereMBR
Name
OWned Controlled
Balancing
Control
By
Authority
its Energy authority was (Plant or
By
Transferred
Affiliates
granted
Unit Name)
Area
I
Geographk
Region
I
capacity
Rating:
Nameplate
(MW)
[GI
[HI
[II
Start Date
End Date
End Note Number (Enter
(mo/da/yr)
(mo/da/yr)
text in End Note Tab)
ln-Sel'vke
Date
I
t=J
capacity Rating:
EndNote
Methodology
Number
capacity
Usedin[K):
(Enter
Rating: Used
(N)ameplate,
text in
in Filing (MW) (S)easonal, ~yr
EndNote
(U}nit, ~yr (E}IA,
Tab)
!Alltemative
I
Asset Appendix: Long-Term Purchased Power Agreements (PPA)
~IDMW
[A)
[C)
[BI
[DI
[E]
[F)
Docket lfwhet-e
MBR authority
Affiliates
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Filing Entity
and its Energy
WiiS granted
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Amount
Geographk
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Market/
Balancing
(MW)
Seller Name
Authority Area
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Location
67114
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
I
I
Asset Appendix: Transmission Assets I Natural Gas Assets
I
This is an example of the required appendix listing the filing entity and all its energy affiliates and their associated assets which must be submitted with some market-based rate filings.
I
[B]
[AI
I
I
I
I
I
Location
Cite to order
accepting OATT
or order
approving the
lransfet' of
transmission
facilities to an
RTOoriSO
Filing Entity and
its Enetgy
Affiliates
I
Electric Transmission Assets and/or Natural Gas Intrastate Pipe6nes and/or Gas Storage Facirmes
[E)
[F)
[C]
[D]
[G)
[HI
Ill
Asset Name
and Use
OWned By
COntrolled
By
Market/
Date
Balancing Geographk: Region
COntrol
Authority
Transferred
[JJ
Size
Size: [length
andkV)
Area
End Note Number
{Entel" text in End
NoteTabl
Asset Appendix: End Notes
I
I
This is an example of the required appendix listing the filing entity and all its energy affiliates and their associated assets which must be submitted with some market-based rate filings
End Notes for Entries in the Generation, Long-term PPA and Transmission Lists
[A]
End Note Number
[B]
List
(Genemion,
[C]
Explanatmy Note
PPAor
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TraiiSlllissionl
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
Note: The following appendices will not be
published in the Code of Federal Regulations.
67115
Appendix C to the Final Rule: Regional
Reporting Schedule
Appendix C
Schedule for Transmission Owning Utilities with Market-based Rate Authority that are
Designated as Category 2 Sellers in the Region
Entities Required to File
Study Period
Filing Period
(anytime during
this month)
December: 2013
June: 2014
December: 2014
June: 2015
December: 2015
June: 2016
20 11
20 11
20 12
20 12
20 13
20 13
to
to
to
to
to
to
November
November
November
November
November
November
2012
2012
2013
2013
2014
2014
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
December
December
December
December
December
December
20 14
20 14
2015
2015
2016
2016
to
to
to
to
to
to
November
November
November
November
November
November
2015 December: 2016
2015
June: 2017
2016 December: 2017
2016
June: 2018
2017 December: 2018
2017
June: 2019
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
December
December
December
December
December
December
2017
2017
2018
2018
2019
2019
to
to
to
to
to
to
November
November
November
November
November
November
2018 December: 2019
2018
June: 2020
2019 December: 2020
2019
June: 2021
2020 December: 2021
2020
June: 2022
Northeast
Southeast
Central
SPP
Southwest
Northwest
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
December
December
December
December
December
December
2020
2020
2021
2021
2022
2022
to
to
to
to
to
to
November
November
November
November
November
November
2021 December: 2022
2021
June: 2023
2022 December: 2023
2022
June:2024
2023 December: 2024
2023
June: 2025
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December
December
December
December
December
December
Northeast
Southeast
Central
SPP
Southwest
Northwest
VerDate Sep<11>2014
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Northeast
Southeast
Central
SPP
Southwest
Northwest
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Northeast
Southeast
Central
SPP
Southwest
Northwest
67116
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
Appendix Cl
Schedule for Non-Transmission Owning Utilities with Market-based Rate Authority that are
Designated as Category 2 Sellers in the Region
Entities Required to File
Study Period
Filing Period
(anytime during
this month)
December: 20 13
June: 2014
December: 20 14
June: 2015
December: 20 15
June: 2016
December
December
December
December
December
December
2010
2011
2011
2012
2012
2013
to
to
to
to
to
to
November
November
November
November
November
November
2011
2012
2012
2013
2013
2014
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
December
December
December
December
December
December
2013
2014
2014
2015
2015
2016
to
to
to
to
to
to
November
November
November
November
November
November
2014 December: 20 16
2015
June: 2017
2015 December: 20 17
2016
June: 2018
2016 December: 20 18
2017
June: 2019
Northwest
Northeast
Southeast
Central
SPP
Southwest
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
December
December
December
December
December
December
2016
2017
2017
2018
2018
2019
to
to
to
to
to
to
November
November
November
November
November
November
2017 December: 20 19
2018
June: 2020
2018 December: 2020
2019
June: 2021
2019 December: 2021
2020
June:2022
Northwest
Northeast
Southeast
Central
SPP
Southwest
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
December
December
December
December
December
December
2019
2020
2020
2021
2021
2022
to
to
to
to
to
to
November
November
November
November
November
November
2020 December: 2022
2021
June: 2023
2021 December: 2023
2022
June:2024
2022 December: 2024
2023
June: 2025
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Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Northwest
Northeast
Southeast
Central
SPP
Southwest
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Northwest
Northeast
Southeast
Central
SPP
Southwest
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
67117
Appendix D to the Final Rule: Generalized Map of Geographic Regions
II Northeast (ISO-NE, NYISO, PJM)
II Southeast (SERC and FRCC NERC Regions, excluding for PJM and MISO
members)
II Central (Midcontinent Independent System Operator (MISO) and members of the
Midwest Reliability Organization (MRO) that are not part of another R TO)
Southwest Power Pool (SPP NERC Region, excluding MISO members)
II Southwest (Arizona, most of California, part ofNevada and the portions ofNew
Mexico and Texas within the Western Interconnection)
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II Northwest (The remainder of the Western Interconnection)
67118
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
Appendix E to the Final Rule: Summary Tables for SIL Calculation
[Required Reporting for Simultaneous' Import Limit (SIL} Studies, with Numerical Examples
Submittal1: Summary Table of the Components Used to Calculate SIL Values
I
I
Table 1: SIL Computation
Instructions:
1 Delete the text XX in the heading 'Study Period' and enter the last two digits ofthe years in the study period.
2 Delete the text 'Name of Home BAA/Market' and enter the name ofthe study area.
I
3 If you are studying more than one first-tier area, copy the relevant columns of Table 1 to empty columns
I
on the right ofthis spreadsheet for each ofthe first-tier areas studied.
I
4 If you are studying first-tier areas, replace the text 'Name of First-Trer BAA/Market' with the name ofthe first-tier area(s).
5 Do not enter data in the white-background cells as these contain formulas which compute the cell values,
I
enter all megawatt values as non-negative integers in rows 1 through 3, 1 and 9 (the blue-shaded cells).
I
6 Note that row 5 In Table 1 Is the sum of the seasonal columns lium row 9 of Table 2.
I
I
1 Include an electronic copy of this spreadsheet, or a workable electronic spreadsheet with the same format and formulas
as the sample spmadsheet on the Commission Web site, with your filing.
I
I
8 The SIL Study Values (i.e., row 10 of Table 1) must be filed as part of a public document. (see note below)*
NOTE: See the footnotes below for further instruction and m19renc es to prior Cornm ission
dimction on the component or calculation in that row.
I
I
Study Period: December 1, 20XX to November 30, 20XX
I
Description of Component
Simultaneous Incremental Transfer
Capability
The most limiting First Contingency Incremental
1
Trans19r Capability (FCITC), Normal Incremental
Trans19r Capability (NITC) or equivalent values.
Note i
Modeled Net Area Interchange (NAI}
2 Enter a positive value and indicate the direction
of flow in row 3 below. Note ii
Interchange Direction
3 Indicate whether the Study Area NAI is export or
import.
Name of Home BAA/Market
Winter Spring Summe1
Fall
(MW)
(MW)
(MW)
(MW)
Name of First-Tier BAA/Market
Winter Spring Summer
Fall
(MW)
(MW)
(MW)
(MW)
1,700
1,800
1,900
2,000
3,000
3,200
3,400
3,600
500
600
100
800
200
300
400
500
Import
4 Total Simultaneous Transfer Capability
(row 4 = row 1 +/-row 2). Note iii
Import
Import
Import
Export
Export
Export
Export
2,200
2,400
2,600
2,800
2,800
2,900
3,000
3,100
620
300
620
300
460
360
460
360
1,580
2,100
1,980
2,500
2,340
2,540
2,540
2,740
1,400
1,900
2,500
2,000
1,400
1,900
2,500
2,000
780
1,600
1,880
1,700
940
1,540
2,040
1,640
13,580
12,800
14,500
12,800
13,580
12,800
14,500
12,800
780
1,600
1,880
1,700
2,040
1,640
Long-Term Firm Transmission Reservations
5 Sum ofthe long-term firm transmission
reservations from Table 2. Note iv
6 Calculated SIL Value
(row 6 = row 4 - row 5). Note v
Historical Peak Load
1 (Identify source if not lium FERC Form No. 714).
Note vi
8 Adjusted Historical Peak Load
(row 8 = row 1 - row 5). Note vii
~
*To the extent a filer intends to request privileged treatment for any portion of Submittals 1 or 2, such tiling 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)
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Uncommitted First-Tier Generation
9 Amount of uncommitted generation modeled in
the first-tier area. Note viii
SIL Study Value
(row 10 • the minimum ofthe values entered in
10 rows 6, 8 and 9 for each season). Use these SIL
Study Values in the Market Share Screens.
Note ix
67119
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
Winter
(MW)
Description of Component
Affiliates
1 MW Sham of Remote Plant #1
100
1a MW Sham of Remote Plant #2
1b MW Sham of Remote Plant #3
Power Purchase Agreement where the energy is
2 imported into the study area with long-tenn firm
reservations
Power Purchase Agreement where the energy is
a imported into the study area with long-tenn firm
50
50
45
50
80
80
80
80
150
230
180
230
180
50
50
50
50
50
100
75
75
75
75
25
25
25
25
3 Transaction to seoo non-alliliated load embedded
in the study area using external generation
10
0
10
0
Transaction to seoo non-alliliated load embedded
a in the study area using external generation
5
0
5
0
310
150
310
4 Sum of affiliated long-term finn reservations
Non-Affiliates
5 MW Sham of Remote Plant #1
100
50
100
50
60
Power Purchase Agreement where the energy is
6 imported into the study area with long-tenn firm
reservations
Power Purchase Agreement where the energy is
a imported into the study area with long-tenn firm
50
60
50
50
80
80
80
80
150
230
180
230
180
300
460
360
460
360
50
50
50
50
25
25
25
25
7 Transaction to seoo non-affiliated load embedded
in the study area using external generation
15
15
15
15
Transaction to seoo non-alliliated load embedded
a in the study area using external generation
10
10
10
10
310
150
310
620
300
620
8 Sum of no!N311i!iated long-tenn finn reservations
Sum of alliliated and non-iilliliated long-term finn
9 reservations (enter value in row 5ofTable 1
above)
* To the extent a filer intends to request privileged treatment for any portion of Submittals 1 or 2, such filing must
comply with 18 CFR 388.112, including the justification for privileged treatment, i.e., why the infonnation is exempt from
disclosure under the mandatory public disclosure requirements of the Freedom of lnfonnation Act, 6 U.S.C. 662 (2012}
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100
67120
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
Endnotes for Table 1:
See generally AEP Service Corp., 131 FERC ~ 61,146, at P 5 (20 10) (AEP)
("FCITC is calculated in the power flow model and represents the additional power that
can flow into a study area by increasing available uncommitted generation in the first-tier
area while simultaneously decreasing generation in the study area.").
Enter an integer value for the FCITC or incremental SIL value. A negative FCITC or
incremental SIL value may indicate a serious modeling error such as an N-0 or N-1 base
case overload and must be addressed or explained.
ii
See generally AEP, 131 FERC ~ 61,146 at P 5 ("The net area interchange is also
determined in the seasonal power flow model and represents 'the sum of a study area's
scheduled energy transactions' already flowing into and out of the study area at the
seasonal peak that is modeled." (citing CP&L, 128 FERC ~ 61,039 at P 9)).
Enter a non-negative integer value for Net Area Interchange. Different sellers apparently
use different nomenclature to represent net imports into a study area. Here, the direction
of the interchange, either export from or import into the study area, is explicitly declared
in the text in row 3 and the direction is not indicated by the sign of the interchange value.
See generally AEP, 131 FERC ~ 61,146 at P 14 ("The Commission previously has given
guidance on how to combine the FCITC and net area interchange values in calculating
the SIL. However, this guidance was based on the assumption that the industry standard
was to report a study area exporting power as a positive value (a positive net area
interchange). SPP, however, used the reverse notation, causing some SPP Transmission
Owners to subtract net area interchange from the FCITC value when they should have
added." (footnote omitted)).
iii
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See generally AEP, 131 FERC ~ 61,146 at P 14 ("For a study area whose net area
interchange represents net exports from the study area, the SIL value is equal to FCITC
minus net exports. Therefore, net exports from a study area reduce the SIL value.
Conversely, for a study area whose net area interchange represents net imports into the
study area, the SIL value is equal to FCITC plus net imports. Therefore, net imports into
a study area increase the SIL value."); CP&L Clarification Order, 129 FERC ~ 61,152 at
P 23 n.15.
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
67121
iv
See generally Order No. 697, FERC Stats. & Regs.~ 31,252 at P 368 ("[T]he
Commission will require sellers to account for firm and network transmission
reservations having a duration oflonger than 28 days."); id. P 368 n.375 ("The
simultaneous import limit study must account for short-term firm transmission rights
including point-to-point on-peak/off-peak transmission reservations (firm or network
transmission commitments) which have been stacked, or successively arranged, into an
aggregated point-to-point transmission reservation longer than 28 days."); id. P 369
("[W]e clarify that the seller's firm, network, and grandfathered transmission reservations
longer than 28 days, including reservations for designated resources to serve retail load,
shall be fully accounted for in the simultaneous import limit study."); Order No. 697-A,
FERC Stats. & Regs. ~ 31,268 at P 142 ("[W]e clarify that the use of simultaneous TTC
in the SIL study must properly account for all firm transmission reservations,
transmission reliability margin, and capacity benefit margin.").
See generally Order No. 697 -A, FERC Stats. & Regs. ~ 31,268 at P 144
("Therefore, we will require applicants to allocate their seasonal and longer transmission
reservations to themselves from the calculated SIL, where seasonal reservations are
greater than one month and less than 365 consecutive days in duration, as defined in the
Commission's EQR Data Dictionary."); Order No. 697-B, FERC Stats. & Regs.~ 31,285
at P 6 "[T]he Commission clarifies and reaffirms that it will require applicants to allocate
their seasonal and longer transmission reservations to themselves from the calculated
simultaneous transmission import limit only up to the uncommitted first-tier generation
capacity owned, operated or controlled by the seller and its affiliates.").
v
vi
See generally CP&L Clarification Order, 129 FERC ~ 61,152 at P 26 ("We clarify
that seasonal, historical peak load is one limitation on the SIL values reported in the
indicative screens and the Delivered Price Test. This SIL value limitation applies to both
scaling methodologies when conducting a SIL study (load-shift and generation-shift
methodologies)." (footnote omitted)); id. P 26 n.16 ("The other two limitations are: (1)
when transmission equipment reaches an operating limit during the energy transfer
calculation portion of the SIL study (these are 'the real-life physical limitations of firsttier balancing authority areas that impede power flowing from remote first-tier resources
into the seller's study area'; and (2) when the available uncommitted generation in the
first-tier area is exhausted and no transmission equipment has reached an operating limit
during the scaling process." (citations omitted)).
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Here, enter the highest hourly net energy for load value for each season from FERC Form
No. 714 or equivalent and identify the source of the data if not FERC Form No. 714. Do
not enter the average seasonal peak load value used in the wholesale market share screen
because it is not the single, highest hourly load recorded for each season.
67122
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
vii
Puget Sound Energy, Inc., 135 FERC ~ 61,254, at P 16 (2011) ("The transmission
capability associated with these study area import reservations also must be subtracted
from the study area's native load to accurately represent the amount of study area native
load available to being served by first-tier area generation when the study area native load
limits the calculated SIL value. For example, PGE's calculated SIL values exceeded its
peak load in each season, so PGE correctly limited its SIL values to peak load. PGE then
subtracted its affiliated long-term firm transmission reservations from its seasonal peak
load to derive its adjusted or net SIL values, which it used in its updated market power
analysis. PGE's calculation appropriately limited its SIL values to the amount of its
study area load open to competition from non-affiliated, first-tier generators." (footnotes
omitted)).
viii
See generally April14 Order, 107 FERC ~ 61,018 at Appendix E ("[T]he
applicant shall scale up available generation in the exporting (aggregated first tier
areas) .... "); CP&L Clarification Order, 129 FERC ~ 61,152 at P 26 & n.16.
ix
BILLING CODE 6717–01–C
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See generally Public Service Company ofNew Mexico, 133 FERC ~ 61,031 at P
12-13 (accepting SIL values limited by peak load and reduced by amount of transmission
reservations allocated to transmission owners' remote resources brought into the study
area to serve native load); AEP, 131 FERC ~ 61,146 at P 13 ("Because each of the SPP
Transmission Owners was to subtract its own reservations in calculating its final SIL
values, this value should account for the largest quantity of transmission reservations into
the study area, thus providing a reasonable estimate of remaining import capability to use
in the preliminary market power screens."); CP&L Clarification Order, 129 FERC ~
61,152 at P 26 ("The SIL value reported in the indicative screens and the Delivered Price
Test, however, cannot exceed the seasonal historical peak load value.").
Federal Register / Vol. 80, No. 210 / Friday, October 30, 2015 / Rules and Regulations
Appendix F to the Final Rule: List of
Commenters and Acronyms
Commenter
Short name/acronym
American Antitrust Institute ...................................................................................
American Electric Power Service Corporation ......................................................
American Public Power Association and National Rural Electric Cooperative
Association.
Avista Corporation and Puget Sound Energy, Inc ................................................
Barrick Goldstrike Mines .......................................................................................
Romkaew Broehm and Gerald A. Taylor ..............................................................
E.ON Climate & Renewables North America LLC ................................................
Edison Electric Institute .........................................................................................
El Paso Electric Company .....................................................................................
Electric Power Supply Association ........................................................................
FirstEnergy Service Company ...............................................................................
Golden Spread Electric Cooperative, Inc ..............................................................
Idaho Power Company ..........................................................................................
Indicated Western Utilities (Arizona Public Service Company; Idaho Power
Company; NV Energy, Inc.; PacifiCorp; and Portland General Electric Company).
National Hydropower Association .........................................................................
NextEra Energy, Inc ..............................................................................................
Potomac Economics, Ltd .......................................................................................
Southeast Transmission Owners (Duke 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 ...................................................................
Julie R. Solomon and Matthew E. Arenchild ........................................................
SunEdison Inc .......................................................................................................
NRG Companies (over 120 entities wholly or partially owned subsidiaries of
NRG Energy, Inc.).
Transmission Access Policy Study Group ............................................................
AAI
AEP
APPA/NRECA
Avista/Puget
Barrick
Broehm/Taylor
E.ON
EEI
El Paso
EPSA
FirstEnergy
Golden Spread
Idaho Power Company
Indicated Utilities
NHA
NextEra
Potomac Economics
Southeast Transmission Owners
SoCal Edison
Solomon/Arenchild
SunEdison
NRG Companies
TAPS
[FR Doc. 2015–26908 Filed 10–39–15; 8:45 am]
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BILLING CODE 6717–01–P
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]]>Agencies
[Federal Register Volume 80, Number 210 (Friday, October 30, 2015)]
[Rules and Regulations]
[Pages 67055-67123]
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.
-----------------------------------------------------------------------
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.
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\25\ Id. P 5.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\26\ Although the Commission did not request reply comments,
several commenters nonetheless submitted reply comments. The
Commission will reject such reply comments.
---------------------------------------------------------------------------
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\
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\36\ See Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 11.
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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.
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\37\ See id. P 41.
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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).
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\38\ ``Relevant'' generation capacity refers to seller and
affiliated capacity in the study area, including the first tier.
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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\
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\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\
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\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.
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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\
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\44\ NRG Companies at 10-11.
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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\
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\45\ NextEra at 4.
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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\
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\46\ EPSA at 5.
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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\
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\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\
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\50\ NextEra at 4-5 (citing https://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.
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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.
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\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.
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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.
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\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.
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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.
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\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.
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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\
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\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).
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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.
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\60\ Id. P 51.
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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\
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\61\ Id. P 49 n.50.
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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\
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\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.
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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\
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\63\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 232
n.217.
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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\
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\64\ Solomon/Arenchild at 15.
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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\
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\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).
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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.
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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.
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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\
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\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 https://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: https://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
---------------------------------------------------------------------------
82. In response to Solomon/Arenchild's request that the Commission
clarify whether only row 10 of Submittal 1 is required to be filed
publicly, we clarify that the Commission expects that all of Submittal
1, not just row 10, will be filed publicly. Submittal 1 provides
summary numeric data showing how the SIL values were calculated for a
given relevant geographic market and some of this data already is
publicly available. While we discourage submitting any portion of
Submittal 1 as privileged, to the extent a filer intends to request
privileged treatment for any portion of Submittal 1 or any other
portion of its filing, such filing must comply with 18 CFR 388.112,
including the justification for privileged treatment, i.e., why the
information is exempt from disclosure under the mandatory public
disclosure requirements of the Freedom of Information Act, 5 U.S.C. 552
(2012).
83. We believe there is no need to expand the indicative screens as
proposed by El Paso because the scenario El Paso describes can be
addressed within the screens, as amended by this Final Rule. However,
we clarify that a seller with remote generation serving the seller's
home balancing authority area (rather than serving the balancing
authority area where the generation is physically located) should
account for that generation capacity in row C ``Long-Term Firm Sales
(in and outside the study area)'' if that generation is used to serve
load in the seller's home study area by virtue of dynamic scheduling
and/or long-term firm transmission reservations. If the seller's remote
generation is not committed to serving load in the seller's home
balancing authority area, then that generation should be studied as
uncommitted generation in the first-tier balancing authority area where
it is located.
5. Competing Imports
a. Commission Proposal
84. In the NOPR, the Commission noted that it permits sellers to
make simplifying assumptions, where appropriate, and to submit
streamlined horizontal market power analyses. The Commission noted that
Order No. 697 provided that `` `a seller, where appropriate, can make
simplifying assumptions, such as performing the indicative screens
assuming no import capacity or treating the host balancing authority
area utility as the only other competitor.' '' \98\ In the NOPR, the
Commission clarified that the phrase ``assuming no import capacity''
means that a seller may assume ``no competing import capacity'' from
the first-tier area (i.e., directly interconnected balancing authority
areas or markets).\99\ The Commission further clarified that the seller
must still include any uncommitted capacity that it and its affiliates
can import into the study area.
---------------------------------------------------------------------------
\98\ NOPR, FERC Stats. & Regs. ] 32,702 at P 66 (quoting Order
No. 697, FERC Stats. & Regs. ] 31,252 at P 321).
\99\ Id. P 67 (emphasis in original).
---------------------------------------------------------------------------
b. Comments
85. EEI, APPA/NRECA, and Golden Spread support the Commission's
proposed clarifications regarding sellers performing simplified
indicative screens assuming no competing import capacity.\100\
---------------------------------------------------------------------------
\100\ EEI at 10; APPA/NRECA at 4; Golden Spread at 7.
---------------------------------------------------------------------------
c. Commission Determination
86. We confirm the Commission's clarification in the NOPR regarding
competing import capacity. Specifically, ``assuming no import
capacity'' means that a seller may assume ``no competing import
capacity'' from the first-tier markets (i.e., adjacent balancing
authority areas or markets). This clarification is consistent with the
April 14, 2004 Order \101\ and other Commission orders.\102\ The seller
must still include any uncommitted capacity that it and its affiliates
can import into the study area.
---------------------------------------------------------------------------
\101\ AEP Power Marketing, Inc. et al., 107 FERC ] 61,018, at P
38 (April 14 Order), order on reh'g, 108 FERC ] 61,026 (2004)
(``Where appropriate, the screens allow the applicant to submit
streamlined applications or to forego the generation market power
analysis entirely and, in the alternative, go directly to
mitigation. For example, if an applicant would pass the screens
without considering competing supplies from adjacent control areas,
the applicant need not include such imports in its studies.''
(emphasis added)).
\102\ See, e.g., Acadia Power Partners, LLC et al., 107 FERC ]
61,168, at P 12 (2004) (``We remind applicants that they may provide
streamlined applications, where appropriate, to show that they pass
both screens. For example, if an applicant would pass both screens
without considering competing supplies imported from adjacent
control areas, the applicant need not include such imports.''
(emphasis added) (footnote omitted)).
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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.
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\103\ See EIA, Annual Energy Outlook (May 2014), available at
https://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.
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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\
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\105\ See, e.g., E.ON at 4; NextEra at 6; EEI at 11; SunEdison,
Inc. (SunEdison) at 1.
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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.
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\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).
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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\
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\110\ Broehm/Taylor at 6.
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95. Further, Broehm/Taylor state that they ``seek Commission
clarification on whether the availability factors \111\ are required to
be applied only to nameplate capacity ratings of energy limited
resources.'' Broehm/Taylor ask whether the Commission's statement
``that sellers without five years of historical data cannot use
seasonal ratings imply that the availability factors should not be
applied to seasonal ratings.'' Broehm/Taylor state that, if this is the
case, it is appropriate to apply the same availability calculation to
both new and existing units of energy limited resources. Broehm/Taylor
caution that sellers need to be consistent in using capacity ratings
for calculating historical capacity factors and if the capacity ratings
are nameplate in the historical capacity factor calculation, these
capacity factors should be applied to nameplate capacity ratings.\112\
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\111\ Broehm/Taylor use the term ``availability factors''
several times. The Commission has never used availability factors as
a basis for de-rating generation capacity.
\112\ Broehm/Taylor at 7.
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iii. Identifying Other Energy-Limited Resources
96. In response to the Commission's request for industry input in
identifying additional technologies that are energy-limited generation
resources, SoCal Edison identifies the following: Hydro, wind, solar,
biomass, and geothermal resources. It further states that it believes
this list can and should be expanded as appropriate.\113\
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\113\ SoCal Edison at 15.
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iv. Require Same Rating Methodology for All Resources of the Same
Technology
97. NextEra states that it does not support requiring the same
rating methodology for all resources of the same technology. To better
reflect a seller's market power, NextEra urges the Commission to
provide sellers the option in submitting indicative screens to reflect,
if known, the historical capability for resources of the same
technology and, if unknown, to submit EIA regional data for those
specific resources.\114\ EEI echoes these concerns stating that sellers
should be able to use five-year historical data for particular energy-
limited generation resources where the sellers have the information,
even as they may need to use a regional capacity factor for other such
facilities for which they do not have the information.\115\
---------------------------------------------------------------------------
\114\ NextEra at 7.
\115\ EEI at 11.
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v. Limiting Capacity Standard to Peak Hours for Solar
98. FirstEnergy states that the Commission properly recognized in
the NOPR that solar photovoltaic facilities will effectively function
with zero capacity during nighttime hours or during heavy overcast
conditions.\116\ FirstEnergy states that in the event that the
Commission permits capacity ratings of solar technologies to be based
on historical generation output rather than on nameplate ratings, such
capacity ratings should be based on the output of such generating
facilities during peak day-light hours only.\117\ Idaho Power believes
that using peak hours for determining solar capacity factors would be
appropriate and would provide better data.\118\ Broehm/Taylor state
that the Commission did not provide the definition of peak hours and
suggests that the Commission give reasonable flexibility to sellers
with regard to the number of peak hours when calculating availability
factors for energy limited technologies as long as sellers justify
their approach.\119\
---------------------------------------------------------------------------
\116\ FirstEnergy at 7.
\117\ Id. at 8.
\118\ Idaho Power at 3.
\119\ Broehm/Taylor at 7-8.
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99. However, SoCal Edison contends that the screens are not
designed for a particular hour or the peak hour for many types of
generation, all hours should be considered when calculating the
capacity rating.\120\ EPSA states that using peak hours will not
provide a better measure of capacity for solar technology generation
resources, and consistent with other intermittent energy resources,
such as wind, a historical average capacity rating during peak hours
would more accurately represent output of the facility incorporating
the variability of output given environmental and weather events that
affect solar generation resources output.\121\ E.ON states that it is
unclear that the use of peak hours is appropriate. It states that these
energy-limited resources can provide energy in daylight hours and not
necessarily only in peak-defined hours. E.ON asks that if the
Commission ultimately adopts some limiting capacity standard, whether
that is peak hours or otherwise, that the Commission clarify that the
solar photovoltaic resource would not be precluded from selling energy
products at market-based rates in any off-peak hours.\122\ EEI states
that the Commission should allow a seller to use an alternative to EIA
regional capacity ratings if they can demonstrate that the alternative
is more accurate as to one or more of the specific solar facilities at
issue in the filing. EEI states that the Commission should give sellers
the option to base solar capacity factors on peak hours rather than all
hours, but should not require them to do so.\123\ NextEra states that
as the horizontal market power indicative screens are intended to study
peak hours, it believes that it may be more consistent to require the
nameplate capacity rating, which for solar technologies largely
correlate to peak load times, rather than the five-year average
capacity factor or EIA regional data.\124\
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\120\ SoCal Edison at 15.
\121\ EPSA at 6-7.
\122\ E.ON at 5.
\123\ EEI at 11.
\124\ NextEra at 6.
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c. Commission Determination
100. We adopt the NOPR proposals with certain modifications and
clarifications. Specifically, we will allow sellers with energy-limited
generation facilities to use capacity factors to de-rate those
facilities in their market power analysis, with certain clarifications
discussed below. We will also identify solar thermal technologies as
energy-limited technologies, but require the use of nameplate capacity
ratings for solar photovoltaic units.
i. Identify Solar as Energy Limited
101. We accept the NOPR proposal to identify solar photovoltaic and
solar thermal facilities as energy-limited generation resources.
However, as discussed below we will continue to require a seller to use
nameplate ratings for its solar photovoltaic facilities. We will allow
a seller to treat solar thermal facilities in the same manner as other
energy-limited resources. If a seller chooses to use a rating based on
a five-year average capacity factor for solar thermal facilities in
their filings, they must follow all of the requirements discussed in
this Final Rule regarding the use of capacity factors. Further, a
seller must use the same rating methodology for non-affiliated solar
thermal facilities, as it does for its own solar thermal facilities.
102. For solar photovoltaic facilities we adopt NextEra's proposal
and
[[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\
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\126\ This is a change from the NOPR proposal to require that if
a seller uses an alternative rating methodology for any energy-
limited resource, it must use an alternative rating for all energy-
limited resources.
\127\ Sellers must use five years of historical data even if
that means using data from multiple EIA reports. We recognize that
this may necessitate sellers including years after the study period.
However, this information is still historical and therefore
consistent with the requirements of Order No. 697, FERC Stats. &
Regs. ] 31,252, at PP 298-301.
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104. A seller must use the same capacity rating method for non-
affiliated energy-limited facilities that it uses to rate the capacity
of its own energy-limited facilities when they are preparing their
market-power analyses. Thus, a seller that uses nameplate ratings for
its own energy-limited facilities should use nameplate ratings for all
other energy-limited facilities included in their horizontal market
power studies. Likewise, a seller that de-rate its own energy-limited
facilities using five-year average capacity factors should de-rate non-
affiliated energy-limited facilities using EIA regional average
capacity factors in its screens and DPTs. Consistent with Order No.
697, we will continue to require a seller that de-rates its energy-
limited facilities to include sensitivity tests using the lowest
capacity factor in the previous five years, and the highest capacity
factor in the previous five years.\128\
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\128\ Id. P 344.
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105. In the NOPR the Commission stated that a seller would be
allowed to use different capacity rating methodologies in subsequent
filings. However, we find here that a seller must use the same rating
methodology in subsequent filings until the next updated triennial
market power analysis. Thus, a seller would not be allowed to change
its rating methodologies until its next updated triennial market power
analysis (e.g., if a seller uses nameplate ratings for nuclear plants
in its triennial, it must use nameplate for nuclear in all filings,
until its subsequent triennial). If a seller is a Category 1 seller
(i.e., not required to file an updated triennial market power
analysis), it would be allowed to change rating methodologies when its
region's transmission owners' updated triennial market power analyses
are due. We reject SoCal Edison's request to allow a seller to switch
rating methods just because it is filing an asset appendix. A seller
must use the same rating methodology for each specific technology in
all filings. We do not see this as more burdensome, because the
capacity rating for most facilities will not change between filings. In
fact, we believe this may be less burdensome because companies will not
have different versions of their asset appendix.
106. We adopt the NOPR proposal to require that a seller submit its
calculations of the regional capacity factor as well as copies of the
appropriate tables of regional generation capacity ratings from EIA's
Annual Energy Outlook in its filing. We also clarify that when using
the EIA tables to calculate a regional average for energy-limited
facilities, a seller should calculate capacity factors using the most
recent five calendar years of data available in the tables. Further,
the capacity factors should be applied per unit, to each generation
facility and applied to the facilities' nameplate ratings. Although we
intend the use of EIA regional capacity factors as a simple and
objective means for a seller to de-rate energy-limited facilities, we
will allow a seller to propose alternative methods of de-rating such
facilities in response to EEI and Broehm/Taylor's comments. A seller
proposing alternative methodologies must provide the data and
calculations used to derive the capacity factors to the Commission in
public, non-privileged files. Further, the seller must also provide the
EIA regional average capacity factor as a comparison and explain why it
believes its methodology provides a more accurate capacity rating than
the EIA regional average. We will decide on a case-by-case basis
whether to accept any such proposed alternative methodology.
iii. Identifying Other Energy-limited Resources
107. In the NOPR, the Commission sought industry input in
identifying additional technologies that are energy-limited generation
resources, and what capacity factors should be used to rate them. As
discussed above, we adopt the proposal to identify solar thermal
technologies as energy limited. However, given that the Commission only
received one comment identifying additional technologies (other than
solar) and the Commission did not receive any comments regarding what
capacity factors should be used to rate additional technologies, we
will not specifically identify any additional technologies as energy
limited at this time.
7. Reporting of Long-Term Firm Purchases
a. Commission Proposal
108. In Order No. 697, the Commission stated that a seller's
uncommitted capacity, as calculated in the indicative screens, is
determined by adding the total nameplate or seasonal
[[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\
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\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).
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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.
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\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.
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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\
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\135\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 38
(footnotes omitted).
\136\ Id. P 38 n.18.
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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.
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\137\ Order No. 697-B, FERC Stats. & Regs. ] 31,285 at PP 99,
100.
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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.
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\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).
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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.
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\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.'').
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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\
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\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.
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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\
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\146\ E.ON at 6; FirstEnergy at 8.
\147\ FirstEnergy at 8-9.
\148\ E.ON at 7.
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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\
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\149\ EEI at 12.
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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\
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\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.
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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\
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\154\ Indicated Utilities at 2.
\155\ Id. at 5.
\156\ IWU at 7.
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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\
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\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\
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\158\ Id. at 10.
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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\
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\160\ SoCal Edison at 12.
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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.
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\161\ Id. at 17.
\162\ Solomon/Arenchild at 10-11.
\163\ NextEra at 9.
\164\ Id. at 10.
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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\
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\165\ SoCal Edison at 13.
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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\
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\166\ Solomon/Arenchild at 11.
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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.
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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.
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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\
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\176\ See infra Section IV.D.
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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\
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\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.'').
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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.
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\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\
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\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.
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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).
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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\
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\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).
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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\
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\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 https://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.
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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\
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\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.
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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\
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\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), https://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.
---------------------------------------------------------------------------
(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'').
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\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.'')).
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(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\
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\234\ Idaho Power at 4-5.
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(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.
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\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.
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(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\
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\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\
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\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\
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\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\
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\252\ NextEra at 10.
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[[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
https://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.
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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.
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\260\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 512.
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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.
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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.
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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\
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\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\
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\326\ El Paso at 4.
\327\ Id.
\328\ Id.
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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\
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\329\ EPSA at 11.
\330\ SoCal Edison at 19 (emphasis in original).
\331\ Id.
\332\ Id. at 23.
\333\ Id.
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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.
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\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.
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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).
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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 https://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 https://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 https://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.
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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 https://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.
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\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).
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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 https://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 https://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 https://www.bls.gov/oes/current/naics2_22.htm, plus benefits information at
https://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 https://www.bls.gov/oes/current/naics2_22.htm, plus benefits information at
https://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
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[[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: DataClearance@ferc.gov, 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
oira_submission@omb.eop.gov. 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.
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\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).
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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.
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\498\ 5 U.S.C. 601-612 (2012).
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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\
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\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).
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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 (https://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
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
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
public.referenceroom@ferc.gov.
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
[GRAPHIC] [TIFF OMITTED] TR30OC15.002
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[[Page 67114]]
[GRAPHIC] [TIFF OMITTED] TR30OC15.005
[[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
[GRAPHIC] [TIFF OMITTED] TR30OC15.006
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[[Page 67117]]
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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
