[Federal Register Volume 79, Number 143 (Friday, July 25, 2014)]
[Proposed Rules]
[Pages 43535-43572]
[FR Doc No: 2014-16002]

Vol. 79

Friday,

No. 143

July 25, 2014

Part II

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; Proposed Rules

Federal Register / Vol. 79 , No. 143 / Friday, July 25, 2014 /
Proposed Rules

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM14-14-000]

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.

ACTION:  Notice of proposed rulemaking.

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SUMMARY:  The Federal Energy Regulatory Commission (Commission) is
proposing to amend its regulations governing market-based rates for
public utilities pursuant to the Federal Power Act (FPA). The
Commission is proposing to revise its current standards for market-
based rates for sales of electric energy, capacity, and ancillary
services to streamline certain aspects of its filing requirements to
reduce the administrative burden on applicants and the Commission. The
Commission seeks comment on the proposed revisions. In addition, the
Commission provides some clarification regarding the standards for
obtaining and retaining market-based rate authority.

DATES:  Comments are due September 23, 2014.

ADDRESSES:  Comments, identified by docket number, may be filed in the
following ways:
     Electronic Filing through http://www.ferc.gov. Documents
created electronically using word processing software should be filed
in native applications or print-to-PDF format and not in a scanned
format.
     Mail/Hand Delivery: Those unable to file electronically
may mail or hand-deliver comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE.,
Washington, DC 20426.
    Instructions: For detailed instructions on submitting comments and
additional information on the rulemaking process, see the Comment
Procedures Section of this document.

FOR FURTHER INFORMATION CONTACT:
Joseph Cholka (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426,<PHONE_NUMBER>.
Carol Johnson (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

Table of Contents

                                        Paragraph Nos.

I. Introduction..............................................................................                  1
II. Background...............................................................................                  2
III. Discussion..............................................................................                 31
    A. Horizontal Market Power...............................................................                 31
        1. Sellers in RTOs...................................................................                 31
        2. Sellers With Fully-Committed Long-Term Generation Capacity........................                 41
        3. Relevant Geographic Market for Certain Sellers in Generation-Only Balancing                        47
         Authority Areas.....................................................................
        4. Reporting Format for the Indicative Screens.......................................                 58
        5. Competing Imports.................................................................                 66
        6. Capacity Ratings..................................................................                 68
        7. Reporting of Long-Term Firm Purchases.............................................                 73
    B. Vertical Market Power--Land Acquisition Reporting.....................................                 87
        1. Current Policy....................................................................                 87
        2. Proposal..........................................................................                 89
    C. Notices of Change in Status...........................................................                 93
        1. Geographic Focus..................................................................                 94
        2. Long-Term Contracts...............................................................                 99
        3. New Affiliation and Behind-the-Meter Generation...................................                102
    D. Asset Appendix........................................................................                110
        1. Current Policy....................................................................                110
        2. Proposal..........................................................................                111
    E. Category 1 and Category 2 Sellers.....................................................                128
        1. Current Policy....................................................................                128
        2. Proposal..........................................................................                130
    F. Corporate Families....................................................................                135
        1. Corporate Organizational Charts...................................................                135
        2. Single Corporate Tariff...........................................................                141
    G. Clarification of Commission Language in Performing SIL Studies........................                144
        1. Current Policy....................................................................                144
        2. Proposal..........................................................................                157
    H. Parts 101 and Part 141 Waivers........................................................                175
        1. Current Policy....................................................................                175
        2. Proposal..........................................................................                176
    I. Miscellaneous.........................................................................                179
        1. Regional Reporting Schedule.......................................................                179
        2. Affirmative Statement.............................................................                181
IV. Information Collection Statement.........................................................                182
V. Environmental Analysis....................................................................                193
VI. Regulatory Flexibility Act...............................................................                194
VII. Comment Procedures......................................................................                204
VIII. Document Availability..................................................................                208

I. Introduction

    1. Pursuant to sections 205 and 206 of the Federal Power Act
(FPA),\1\ the Commission is proposing to amend 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.
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    \1\ 16 U.S.C. 824d, 824e (2012).
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II. Background

    2. 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.
    3. In April 2004, the Commission initiated a rulemaking proceeding
to consider the adequacy of its market-based rate analysis and whether
and how it should be modified to assure that prices for electric power
being sold under market-based rates are just and reasonable under the
FPA.\2\ At that time, the Commission noted that much had changed in the
industry since its analysis was first developed and posed a number of
questions that would be explored through a series of technical
conferences. Following the technical conferences, the Commission issued
a notice of proposed rulemaking that led to the issuance in 2007 of
Order No. 697, which clarified and codified the Commission's market-
based rate policy.\3\
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    \2\ Market-Based Rates for Public Utilities, 107 FERC ] 61,019,
at P 1 (2004) (initiating rulemaking proceeding).
    \3\ 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).
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    4. In Order No. 697, the Commission adopted two indicative screens
for assessing horizontal market power: The pivotal supplier screen and
the wholesale market share screen (with a 20 percent threshold), each
of which serves as a cross check on the other to determine whether
sellers may have market power and should be further examined.\4\ 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 through a delivered price test (DPT) analysis demonstrating
that, despite a screen failure, they do not have market power.\5\ The
Commission uses a ``snapshot in time'' approach based on historical
data for both the indicative screens and the DPT analysis.\6\
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    \4\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 62.
    \5\ Id. P 13; 18 CFR 35.37(c)(3).
    \6\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 17.
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    5. With respect to the horizontal market power analysis, in
traditional markets (outside regional transmission organization/
independent system operator (RTO/ISO) markets),\7\ 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 may consider the
geographic region under the control of the RTO as the default relevant
geographic market for purposes of the indicative screens.\9\
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    \7\ We will use the term ``RTO'' when referring to either an RTO
or ISO for easier readability.
    \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, that submarket becomes a default
relevant geographic market for sellers located within the submarket
for purposes of the market-based rate analysis. See id. PP 15, 231.
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    6. With respect to the vertical market power analysis, in cases
where a public utility or any of its affiliates owns, operates, or
controls transmission facilities, the Commission requires that there be
a Commission-approved Open Access Transmission Tariff (OATT) on file,
or that the seller or its applicable affiliate has received waiver of
the OATT requirement, before granting a seller market-based rate
authorization.\10\ The Commission also considers a seller's ability to
erect other barriers to entry as part of the vertical market power
analysis.\11\ As such, the Commission requires a seller to provide a
description of its ownership or control of, or affiliation with an
entity that owns or controls, intrastate natural gas transportation,
storage or distribution facilities; sites for generation capacity
development; and physical coal supply sources and ownership of or
control over who may access transportation of coal supplies
(collectively, inputs to electric power production).\12\ In Order No.
697-C, the Commission revised the change in status reporting
requirement in Sec.  35.42 of the Commission's regulations to require
market-based rate sellers 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 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 clarified 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.\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.
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    7. If a seller is granted market-based rate authority, the
authorization is conditioned on: (1) Compliance with affiliate
restrictions governing transactions and conduct between power sales
affiliates where one or more of those affiliates has captive customers;
\16\ (2) a requirement to file post-transaction electric quarterly
reports (EQR) with the Commission containing: (a) A summary of the
contractual terms and conditions in

every effective service agreement for market-based power sales; and (b)
transaction information for effective short-term (less than one year)
and long-term (one year or longer) market-based power sales during the
most recent calendar quarter; \17\ (3) a requirement to file any change
in status that would reflect a departure from the characteristics the
Commission relied upon in granting market-based rate authority; \18\
and (4) a requirement for large sellers to file updated market power
analyses every three years.\19\
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    \16\ 18 CFR 35.39.
    \17\ 18 CFR 35.10b.
    \18\ 18 CFR 35.42.
    \19\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 3; 18 CFR
35.37(a)(1).
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    8. In Order No. 697, the Commission created two categories of
sellers.\20\ Category 1 sellers are wholesale power marketers and
wholesale power producers that own or control 500 megawatts (MW) or
less of generation in aggregate per region; that do not own, operate,
or control transmission facilities other than limited equipment
necessary to connect individual generation facilities to the
transmission grid (or have been granted waiver of the requirements of
Order No. 888 \21\); that are not affiliated with anyone that owns,
operates, or controls transmission facilities in the same region as the
seller's generation assets; that are not affiliated with a franchised
public utility in the same region as the seller's generation assets;
and that do not raise other vertical market power issues.\22\ Category
1 sellers are not required to file regularly scheduled updated market
power analyses. Sellers that do not fall into Category 1 are designated
as Category 2 sellers and are required to file updated market power
analyses.\23\ However, the Commission may require an updated market
power analysis from any market-based rate seller at any time, including
those sellers that fall within Category 1.\24\
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    \20\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 848.
    \21\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996), order on reh'g,
Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on reh'g, Order
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C,
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom.
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C.
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
    \22\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 849
n.1000; 18 CFR 35.36(a).
    \23\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 850.
    \24\ Id. P 853.
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    9. In Order No. 697, the Commission further stated that through its
ongoing oversight of market-based rate authorizations and market
conditions, the Commission may take steps to address seller market
power or modify rates. For example, based on its review of updated
market power analyses, EQR filings, or notices of change in status, the
Commission may institute a proceeding under section 206 of the FPA to
revoke a seller's market-based rate authorization if it determines that
the seller may have gained market power since its original market-based
rate authorization. The Commission also may, based on its review of EQR
filings or daily market price information, investigate a specific
utility or anomalous market circumstance to determine whether there has
been a violation of RTO market rules or Commission orders or tariffs,
or any prohibited market manipulation, and take steps to remedy any
violations.\25\
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    \25\ Id. P 5.
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    10. As discussed below, after over six years of experience with the
implementation of Order No. 697, we propose certain changes and
clarifications in order to streamline and simplify the market-based
rate program, and to enhance and improve the program's processes and
procedures. Based on our experience, we have found that the burdens
associated with certain of our requirements may outweigh the benefits
in certain circumstances. For these reasons, we propose a number of
changes to the market-based rate program which, taken as a whole, will
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. We also include several specifications and propose a
number of minor changes that will add clarity to, and improve
transparency in, the market-based rate program.

Summary of Proposals

    11. Although we intend to retain the horizontal indicative screens,
we propose certain modifications to our horizontal market power
analysis. First, we propose to allow sellers in RTO markets to address
horizontal market power issues in a streamlined manner that would not
involve the submission of indicative screens if the seller relies on
Commission-approved monitoring and mitigation to prevent the exercise
of market power. We also propose to clarify that where all generation
capacity owned or controlled by a seller and its affiliates in the
relevant balancing authority areas (including first-tier balancing
authority areas or markets) is fully committed, sellers may explain
that their capacity is fully committed in lieu of submitting indicative
screens as part of their horizontal market power analysis.
    12. While we are retaining the definition of the default geographic
market for the vast majority of sellers, we are proposing a redefined
default relevant geographic market for an independent power producer
(IPP) with generation capacity located in a generation-only balancing
authority area. We propose that, instead of the default geographic
market being the generation-only balancing authority area where its
generation is located, the IPP's default geographic market(s) will be
the balancing authority area(s) of each transmission provider to which
the generation-only balancing authority area is directly
interconnected.
    13. In Order No. 697, the Commission adopted standard indicative
screen formats for submitting a horizontal market power analysis. We
propose to add rows to the indicative screen format for sellers to
specify Simultaneous Transmission Import Limit (SIL) Values, Long-Term
Firm Purchases (from outside the study area), and Remote Capacity (from
outside the study area), as well as modifications to the descriptive
text of the rows to make them more consistent. We further propose to
revise the regulations to require that sellers file the indicative
screens in a workable electronic spreadsheet format. We also propose to
revise the Commission's regulations to codify the requirement, first
discussed in Puget Sound Energy, Inc.,\26\ that sellers submitting SIL
studies adhere to the direction and required format for Submittals 1
and 2 found on the Commission's Web site and that sellers submit
Submittals 1 and 2 in a workable electronic spreadsheet format.
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    \26\ Puget Sound Energy, Inc., 135 FERC ] 61,254, Appendix B
(2011) (Puget).
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    14. The Commission previously stated that sellers could make
simplifying assumptions such as ``performing the indicative screens
assuming no import capacity.'' We clarify that ``assuming no import
capacity'' means a seller may assume that there is no competing import
capacity from the first-tier balancing authority areas or markets.
    15. The Commission generally permits sellers submitting indicative
screens to rate their generation facilities using either nameplate or
seasonal capacity ratings. In addition, the Commission allows sellers
with energy-limited resources, such as hydroelectric and wind
generation facilities, to use a five-year average capacity factor. We

propose to include solar technologies as energy-limited generation
resources. We further propose that sellers with energy-limited
resources that do not have five years of historical data may use
regional capacity factor estimates appropriate to the specific
technology as derived by the United States Energy Information
Administration (EIA) to determine the capacity for those resources. We
also propose to clarify that a seller must use the same capacity rating
methodology for similar generation assets throughout a particular
filing.
    16. The Commission has stated that a seller's uncommitted capacity
is determined by adding the nameplate or seasonal capacity of
generation owned or controlled through contract and long-term firm
capacity purchases, less operating reserves, native load commitments,
and long-term firm sales. Therefore, sellers have been reporting their
long-term firm purchases as part of their capacity if the purchase
granted them control of that capacity. We propose to require sellers to
report 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. This approach will help size the market
correctly and will establish consistent treatment of long-term firm
sales and long-term firm purchases.
    17. The Commission's vertical market power analysis examines
affiliation, ownership or control of inputs to electric power
production, including sites for generation capacity development. In
this Notice of Proposed Rulemaking (NOPR), we propose to eliminate the
requirement that sellers provide information on sites for generation
capacity development in their market-based rate applications and
triennial updated market power analyses and to similarly relieve
sellers of their obligation to file quarterly land acquisition reports.
    18. The Commission requires that sellers report to the Commission
any change in status that would reflect a departure from the
characteristics the Commission relied upon in granting market-based
rate authority. We propose to revise the regulations to clarify that
the 100 MW reporting threshold for filing a notice of change in status
is not limited to markets previously studied; thus if a seller acquires
generation that causes a cumulative net increase of 100 MW or more in
any relevant geographic market, the seller must file a notice of change
in status. We also propose to revise the regulations to include long-
term firm purchases of capacity and/or energy in calculating the 100 MW
change in status threshold. Although there currently is no threshold
for reporting a change in status that results in a new affiliation, we
propose to revise the regulations to include a 100 MW threshold for
reporting new affiliations.
    19. The Commission requires that sellers include with each new
application, market power analysis, and relevant change in status
notification an asset appendix that lists all affiliates that have
market-based rate authority and identifies assets owned or controlled
by the seller and its affiliates. We propose to revise the asset
appendix by revising the headings of several columns to be more clear
and consistent. We also propose several clarifications to the asset
appendix requirements. In particular: (1) A seller must enter the
entire amount of a generator's capacity, even if the seller only owns
part of the generator; (2) a seller must list one of three specified
uses for assets in the asset list containing electric transmission and
intrastate gas assets; and (3) sellers should not list assets in which
passive ownership interests have been claimed. We also propose to
modify the asset appendix to add a new column in the list of
transmission assets for the citation to the Commission order accepting
the OATT or granting waiver of the OATT requirement. We further propose
to require that sellers submit the asset lists in an electronic
spreadsheet format that can be searched, sorted, and accessed using
electronic tools. We also seek comment on whether it would be useful to
develop a comprehensive searchable public database of the information
contained in the asset appendix, which sellers could access to update
their asset appendices.
    20. There are two categories of market-based rate sellers. Category
1 sellers are exempt from the requirement to automatically submit
updated market power analyses every three years. Market-based rate
Category 2 sellers are required to submit an updated market power
analysis every three years according to a regional schedule. We include
an updated schedule and region map as part of this NOPR.
    21. One of the criteria that must be satisfied to be a Category 1
seller in a region is that the seller and its affiliates must own or
control 500 MW or less of generation in aggregate in that region. We
propose to codify in the Commission's regulations a distinction in
determining seller category status for power marketers and power
producers. For each region, a power marketer should include all
affiliated generation in that region, while a power producer would only
need to include affiliated generation capacity that is located in the
same region as the power producer's generation asset(s). We propose
this difference in treatment based on the fact that a power marketer is
assumed to have no home market, while it is assumed that a majority of
a power producer's sales will be in market(s) in which it owns
generation assets.
    22. While sellers have been required to describe their affiliates
and upstream owners when filing initial applications, updated market
power analyses and notices of change in status involving new
affiliations, we propose to add a requirement in the regulations that
sellers provide an organizational chart as well. We propose that the
organizational chart be similar to that which we require from FPA
section 203 applicants.
    23. Although we have previously explained that joint filers are
permitted to designate one market-based rate seller to file a single,
joint master corporate market-based rate tariff for inclusion in the
Commission's eTariff database that reflects the joint tariff for all
affiliated sellers, many sellers have not taken advantage of the option
to file a joint master corporate market-based rate tariff. We propose
to clarify on the Commission's 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.
    24. We also propose to provide clarification regarding several
issues related to how to perform SIL studies and regarding the
associated Submittals 1 and 2. In particular, we propose to clarify
issues relating to what is meant by Open Access Same-Time Information
System (OASIS) practices, how to deal with conflicts between OASIS
practices and Commission direction provided in Appendix B of Puget, and
what is the correct load value to use in the SIL study.
    25. The Commission has previously stated that the methodology a
transmission provider uses to calculate SIL values must be consistent
with the methodology it uses for calculating and posting available
transmission capability (ATC) and for evaluation of firm transmission
service requests. We propose to clarify that ``OASIS practices'' refers
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. We further propose to clarify that in
performing a SIL study, the transmission provider must follow its OASIS
practices consistent with the administration of its tariff. Thus, 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. We clarify that where there is a conflict between the
transmission provider's tariff or OASIS practices and the Commission's
directions in Puget, sellers should follow OASIS practices except where
use of actual OASIS practices is incompatible with an analysis of
import capability from an aggregated first-tier area. We also remind
sellers that the calculated SIL value should account for any limits
defined in the tariff, such as stability or voltage. We reiterate that
sellers may use load scaling to perform a SIL study if they use load
scaling in their OASIS practices as long as they submit adequate
support and justification for the scaling factor used and how the
resulting SIL value compares had the seller used a generation-shift
methodology. We also instruct sellers to subtract all long-term firm
import transmission reservations, including reservations held by non-
affiliated sellers, from the simultaneous total transfer capability
(simultaneous TTC) value. Finally, we clarify that the seller should
reduce the simultaneous TTC value by subtracting all wheel through
transactions used to serve non-affiliated load embedded in the study
area using first-tier area generation. These transactions should be
accounted for as long-term firm transmission reservations and reported
in Submittal 2.
    26. We propose to amend Submittal 1 to revise Row 8 to read
``Adjusted Historical Peak Load'' and propose to direct sellers to
include all load associated with the balancing authority area(s) within
the study area, including non-affiliated load. Submittal 1 requires
sellers to use FERC Form No. 714 load values or explain the source of
the data used. We seek comment on the appropriate source of historical
peak load data.
    27. We propose to clarify that where a first-tier market or
balancing authority area is directly connected to the study area only
by controllable tie lines and is not connected to any other first-tier
market or balancing authority area, sellers should follow their OASIS
practice regarding calculation and posting of ATC for such areas. If
the seller's OASIS practices are incompatible with the SIL study,
entities may use an alternative process to account for import
capability for such tie lines.
    28. We propose to provide standard guidance for data submittals and
representations that sellers using the simultaneous TTC must provide,
including historical data of actual, hourly, real-time TTC values used
for operating the transmission system and posting availability on OASIS
for each interface during each seasonal study period. We propose to
clarify that sellers may use the maximum sum of TTC values for any day
and time during each season as long as they demonstrate that these TTC
values are simultaneously feasible. Finally, we reiterate that, if
there are limited interconnections between first-tier markets, we will
review evidence that potential loop flow between first-tier areas is
properly accounted for in the underlying SIL values and we clarify 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.
    29. We note that there are certain waivers that the Commission has
granted to certain sellers with market-based rate authority, e.g.,
power marketers and independent or affiliated power producers, such as
waiver of the Uniform System of Accounts requirements, specifically
waiver of Parts 41, 101, and 141 of the Commission's regulations except
Sec. Sec.  141.14 and 141.15. We clarify that any waiver of Part 101
granted to a market-based rate seller is limited such that waiver of
the provisions of Part 101 that apply to hydropower licensees is not
granted with respect to licensed hydropower projects. The Commission
further directs that, to the extent that a 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 be granted with respect to licensed hydropower projects. Similarly,
hydropower licensees that have been granted waiver of Part 141 as part
of their market-based rate authority should ensure that the limitations
and exemptions section of their market-based rate tariffs specify that
waiver of Part 141 has been granted, with the exception of Sec. Sec.
141.14 and 141.15.
    30. The Commission's regulations require as part of the vertical
market power analysis that sellers 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. We propose
to revise the regulations to make it clear that the obligation to make
the affirmative statement applies to both the seller and its
affiliates.

III. Discussion

A. Horizontal Market Power

1. Sellers in RTOs
a. Current Policy
    31. 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 a seller
studying an RTO as a relevant geographic market (RTO seller) fails the
indicative screens for the RTO, it can seek to obtain or retain market-
based rate authority by relying on Commission-approved RTO monitoring
and mitigation.\27\
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    \27\ 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] 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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    32. In 2001, the Commission originally proposed that all sales,
including bilateral sales, into an RTO with Commission-approved market
monitoring and mitigation would be exempt from the generation market
power analysis in effect at that time (the Supply Margin Assessment
test) and, instead, would be governed by the specific thresholds and
mitigation provisions approved for the particular market.\28\ However,
the Commission subsequently concluded that it would no longer exempt
sellers located in markets with Commission-approved market monitoring
and mitigation from providing generation market power analyses, on the
basis that requiring sellers located in such markets to submit
indicative screens provides an additional check on the potential for
market power.\29\
---------------------------------------------------------------------------

    \28\ AEP Power Marketing, Inc., 97 FERC ] 61,219, at 61,970
(2001).
    \29\ AEP Power Marketing, Inc., 107 FERC ] 61,018, at P 186
(April 14, 2004 Order), order on reh'g, 108 FERC ] 61,026 (2004).

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

    33. In Order No. 697, the Commission declined the request that it
reinstate the prior RTO exemption, stating it ``will continue to
require generation market power analyses from all sellers, including
those in [RTO] markets.'' \30\ In Order No. 697-A, the Commission
denied requests to reconsider its decision stating that
---------------------------------------------------------------------------

    \30\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 290.

the dual protections of individual market power analyses and
mitigation rules of the [RTOs] provide the Commission with better
ability to discern and protect against potential market power.
While, as discussed below, mitigation rules for the individual
[RTOs] in most cases should be sufficient to guard against the
exercises of market power, we are not comfortable at this time with
dispensing of the requirement for sellers in [RTOs] to provide us
with horizontal market power analyses. Any administrative burden of
submitting such analyses is outweighed by the additional information
gleaned with respect to a specific seller's market power.[\31\]
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    \31\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 110.

    34. Since the issuance of Order No. 697, it has been the
Commission's practice to grant sellers market-based rate authority or
allow them to retain market-based rate authority where they have failed
indicative screens in an RTO but have relied on Commission-approved
monitoring and mitigation.\32\ RTO sellers are sellers that study an
RTO as a relevant geographic market, including those that sell
bilaterally. While the burdens of preparing the indicative screens are
not necessarily greater for RTO sellers than for sellers in other
markets, the submission of indicative screens yields little practical
benefit since it has been the Commission's practice to allow RTO
sellers that fail the indicative screens to rely on RTO monitoring and
mitigation. Thus, for sellers in RTOs, the burden of submitting
indicative screens may not be ``outweighed by the additional
information gleaned with respect to a specific seller's market power.''
\33\
---------------------------------------------------------------------------

    \32\ See, e.g., Niagara Mohawk Power Corp., 123 FERC ] 61,175,
at P 28 (2008) (failures in the New York City and Long Island
submarkets of the New York Independent System Operator, Inc.);
Dominion Energy Marketing, Inc., 125 FERC ] 61,070, at PP 26-27
(2008) (failures in the Connecticut submarket of ISO New England,
Inc.); PSEG Energy Resources & Trade LLC, 125 FERC ] 61,073, at PP
31-32 (2008) (failures in the PJM-East submarket). There are also
numerous delegated letter orders granting a seller market-based rate
authority where the seller relies on Commission-approved monitoring
and mitigation in RTO markets. See, e.g., TransCanada Energy
Marketing ULC, Docket No. ER07-1274-001 (Jan. 23, 2009) (delegated
letter order). Finally, the Commission has not initiated any
investigations pursuant to section 206 of the FPA for any RTO
sellers failing indicative screens since the issuance of Order No.
697; in all cases where RTO sellers failed, the Commission relied on
the Commission-approved monitoring and mitigation to prevent the
seller's ability to exercise any potential market power.
    \33\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 110.
---------------------------------------------------------------------------

b. Proposal
    35. We propose to modify the approach taken in Order No. 697 to
reflect current practice and reduce the burden on these sellers.
Specifically, we propose to allow market-based rate sellers in RTO
markets with Commission-approved monitoring and mitigation to address
horizontal market power issues in a streamlined manner when submitting
initial applications requesting market-based rate authority and updated
market power analyses. We note that this proposal includes RTO sellers
who may have bilateral contracts not subject to the Commission-approved
monitoring and mitigation. We find that the existence of monitoring and
mitigation in an organized market generally results in a market where
prices are transparent.\34\ This disciplines forward and bilateral
markets by revealing a benchmark price and keeping offers competitive.
For example, if a seller offers what a buyer perceives as a non-
competitive price in the bilateral market, that buyer can opt to
purchase in the spot market. This provides a strong incentive for the
seller to offer at a competitive price in the forward and bilateral
markets.
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    \34\ April 14 Order, 107 FERC ] 61,018 at P 189.
---------------------------------------------------------------------------

    36. Under this streamlined approach, RTO sellers would not have 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. Rather, to address horizontal
market power effects, RTO sellers instead would simply state that they
are relying on such mitigation to address any potential market power
they might have, and provide an asset appendix and describe their
generation and transmission assets. Under this proposal, all RTO
sellers seeking market-based rate authority in an RTO 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. To
address horizontal market power effects, both the initial applications
for market-based rate authorization and the updated market power
analyses would include: (1) A statement that the seller is relying on
RTO mitigation to address any potential market power it might have; (2)
identification and description of generation and transmission assets;
and (3) an asset appendix.\35\ In all scenarios, the Commission would
retain the ability to require an updated market power analysis,
including indicative screens, from any market-based rate seller at any
time.
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    \35\ Applicants making these filings would continue to be
required to provide the following information that is related to the
non-horizontal market power issues: (1) A standard vertical market
power analysis; (2) category status representations; (3) a
demonstration that sellers continue to lack captive customers in
order to support obtaining or retaining a waiver of the affiliate
restrictions, if requested; and (4) any other information that is
required for that particular filing.
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    37. Thus, we propose to add a paragraph to the end of Sec.
35.37(c) (regarding horizontal market power), making it paragraph
(c)(6) under this subsection, to read as follows: In lieu of submitting
the indicative screens, Sellers in regional transmission organization
and independent system operator markets with Commission-approved market
monitoring and mitigation must include a statement that they are
relying on such mitigation to address any potential horizontal market
power concerns.
    38. In addition, we note that market-based rate sellers are not
required by Order No. 697 or the regulations to provide indicative
screens in their horizontal market power analyses when submitting
change in status filings.\36\ In Order No. 697-A, the Commission
stated:
---------------------------------------------------------------------------

    \36\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 506
(``[W]e will not require entities to automatically file an updated
market power analysis with their change in status filings. . . .
Furthermore, regardless of the seller's representation, if the
Commission has concerns with a change in status filing (for example,
market shares are below 20 percent, but are relatively high
nonetheless), the Commission retains the right to require an updated
market power analysis at any time.'').

    The existing [change in status] reporting requirement provides
the Commission a sufficient tool to allow it to assess whether there
is a potential market power concern and, if so, the Commission
reserves the right to require the seller to submit a market power
study. In addition, the seller is required to provide an affirmative
statement as to what effect, if any, the added generation has on its
market power. For a seller to make such an affirmative statement, it
must determine what effect the added generation has on the market
power analysis. To the extent the seller makes an affirmative
statement that there is no effect on its market power, it is bound
to that statement and faces remedial action, including civil
penalties, if it has misrepresented the effect.\37\
---------------------------------------------------------------------------

    \37\ Id. P 505 (emphasis added).

    39. Historically, when a change in status filing has created the
likelihood that a seller would fail an indicative screen, the seller
has often voluntarily

submitted indicative screens in order to determine the effect of the
change on its market power. We clarify that, with this proposed
streamlined approach, an RTO seller need not submit indicative screens
with its change in status filing even where it may have market power.
Instead, the seller may state that it is relying on Commission-approved
monitoring and mitigation to mitigate any potential market power it may
have. However, the Commission still reserves the right to require an
updated market power analysis at any time.
    40. We seek comment on this proposal.
2. Sellers With Fully-Committed Long-Term Generation Capacity
a. Current Policy
    41. 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. In Order No. 697-A,
the Commission stated:

once capacity is committed long-term, regardless of how that
capacity is priced (e.g., whether linked to spot prices or not), the
ability of the firm to use that capacity to exercise market power in
the spot market is severely limited or non-existent. The ability to
collude will be determined by the remaining uncommitted capacity in
the spot market, not the capacity that is already committed under
long-term contracts. Therefore, we conclude that it is appropriate
to subtract capacity committed under long-term contracts when
calculating a seller's uncommitted capacity for purposes of
performing the indicative screens.[\38\]

    \38\ Id. P 41.
---------------------------------------------------------------------------

    42. Thus, the capacity dedicated to long-term firm power sales
should be deducted from seller and affiliate capacity in Row C (Long-
Term Firm Sales) of the standard screen format provided in Appendix A
to Subpart H of Part 35 for submitting the indicative screens.\39\
However, some sellers have filed indicative screens in which they did
not deduct their fully-committed capacity or incorrectly reported
capacity as fully committed when it was only committed for some
seasons, for less than one year, or under certain market
conditions.\40\ Moreover, some sellers have argued that there is no
need to perform indicative screens when they can demonstrate that all
of their capacity is committed under long-term contract.
---------------------------------------------------------------------------

    \39\ 18 CFR 35.37(c)(4). We note 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. See Order No. 697-A, FERC Stats.
& Regs. ] 31,268 at n.6. We propose to amend Appendix A to Subpart H
of Part 35 to add the market share screen that was inadvertently
removed and to make proposed changes to both indicative screens as
discussed herein.
    \40\ The EQR data dictionary defines firm power sales as sales
that are non-interruptible for economic reasons and states that
contracts with durations of one year or greater are long-term.
---------------------------------------------------------------------------

b. Proposal
    43. It is the Commission's policy to study uncommitted generation
capacity in the indicative screens.\41\ Currently, the seller's owned
or controlled capacity in megawatts is entered into the indicative
screens and the fully-committed long-term (one year or longer) capacity
is then deducted. If all of the seller and its affiliates' capacity in
the relevant balancing authority areas or markets including first-tier
balancing authority areas or markets is fully committed, this exercise
results in a purely mathematical task (netting to zero uncommitted
capacity), thus providing no significant additional information.
Therefore, we clarify 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. The Commission proposes to clarify
that, in order to qualify as ``fully committed,'' a seller must commit
the capacity so that none of the excluded capacity is available to the
seller or its affiliates for one year or longer.
---------------------------------------------------------------------------

    \41\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 37-38;
April 14, 2004 Order, 107 FERC ] 61,018 at P 71 (``We will adopt an
uncommitted pivotal supplier analysis that will evaluate the
potential of an applicant (including its affiliates) to exercise
market power based on the control area market's annual peak demand.
We will also adopt an uncommitted market share analysis that will
seasonally evaluate the market share of the uncommitted capacity of
an applicant and its affiliates.'').
---------------------------------------------------------------------------

    44. We propose that sellers claiming that all of their relevant
capacity \42\ 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. 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, 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).
---------------------------------------------------------------------------

    \42\ ``Relevant'' capacity refers to seller and affiliated
capacity in the study area, including the first tier.
---------------------------------------------------------------------------

    45. Finally, 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.\43\
---------------------------------------------------------------------------

    \43\ 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).
---------------------------------------------------------------------------

    46. We seek comment on these proposals.
3. Relevant Geographic Market for Certain Sellers in Generation-Only
Balancing Authority Areas
a. Current Policy
    47. The Commission stated in Order No. 697 that ``the horizontal
market power analysis centers on and examines the balancing authority
area where the seller's generation is physically located'' \44\ and
that the default relevant geographic market (default 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).'' \45\ However, 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).'' \46\
Similarly, the Commission continued to require RTO sellers ``to
consider, as part of the relevant market, only the relevant [RTO]
market and not first-tier markets to the [RTO].'' \47\
---------------------------------------------------------------------------

    \44\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 37.
    \45\ Id. P 232.
    \46\ Id. n.217.
    \47\ Id. P 231 n.215.
---------------------------------------------------------------------------

    48. The Commission further stated in Order No. 697 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.''
\48\ Order No. 697 rejected the concept of a ``hub'' as a relevant
geographic market, noting that for purposes of evaluating market power,
``trading hub data alone does not provide a foundation for the
Commission to analyze transmission limitations and other transfers of
energy.'' \49\ However, Order No. 697 did not specifically address the
default market for a seller located in a balancing authority area that
has generation capacity but no load or customers (a generation-only
balancing authority area). As discussed below, the Commission is
concerned that the default market definition from Order No. 697 does
not accurately reflect the market for all sellers, particularly in the
Western Electricity Coordinating Council (WECC), which has several
generation-only balancing authority areas with generation that is not
sited close to load.
---------------------------------------------------------------------------

    \48\ Id. P 251.
    \49\ Id. P 275. We note that a number of hubs (e.g., Palo Verde,
Four Corners, and Mead, etc.) are located at the intersections of
clearly-defined balancing authority areas. Historically, identifying
the market for generation located at the hub was not important
because vertically-integrated utilities used their own generation to
meet their load. As the markets have evolved, many hubs have become
trading centers and some IPPs have built generation near hubs. The
Commission has defined a trading hub as ``a representative location
at which multiple sellers buy and sell power and ownership changes
hands, typically with trading of financial and physical products.''
Id.
---------------------------------------------------------------------------

    49. The issue of what constitutes an appropriate market for an IPP
in a generation-only balancing authority area has arisen because there
is often no clear nexus between the default market, the generation
resources an IPP competes with, and the customers an IPP actually
serves.\50\ Since the implementation of Order No. 697, we have observed
several instances in which the default market may not be appropriately
defined for some IPPs in generation-only balancing authority areas.\51\
Moreover, the issue of proposing an appropriate geographic market for
IPPs in generation-only balancing authority areas that do not serve
load in the default market (i.e., their home balancing authority area)
is further complicated when the IPP makes sales to a trading hub (e.g.,
Palo Verde). The following factors illustrate some differences between
IPPs and franchised public utilities in terms of identifying the
appropriate geographic markets.
---------------------------------------------------------------------------

    \50\ For 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 a 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.
    \51\ See, e.g., Sundevil Power Holdings, LLC, Docket No. ER10-
1777-000 (Sept. 15, 2010) (delegated letter order).
---------------------------------------------------------------------------

    50. Franchised public utilities typically have a geographically-
defined franchised service territory and an obligation under state law
to serve retail customers residing within that service territory.\52\
Thus, the home balancing authority area reflects the primary market in
which a franchised public utility sells electricity, because this is
where its customers are located. In addition, a franchised public
utility's generation capacity is usually dedicated primarily to serving
load in its franchised service territory even though it may sell at
least some wholesale power outside of its service territory. Therefore,
the default market (home and first-tier balancing authority areas) is
appropriate for franchised public utilities because there is a clear
nexus between the physical location of a franchised public utility's
generation and the load served by that generation.
---------------------------------------------------------------------------

    \52\ See 18 CFR 35.36(a)(5). A franchised public utility's
obligation to serve is modified, but not entirely eliminated, in
states that have implemented ``retail choice.''
---------------------------------------------------------------------------

    51. In contrast, an IPP does not have a franchised service
territory, or an obligation to serve retail customers.\53\ Moreover,
generation-only balancing authority areas do not have any load;
therefore, these balancing authority areas do not appear to meet the
Commission definition of a default market as they do not, by
definition, ``maintain[] load/resource balance with the area.'' \54\
IPPs may directly interconnect to transmission providers at energy
trading hubs to facilitate sales to one or more markets within the
broader region.
---------------------------------------------------------------------------

    \53\ Thus, the Commission's policy is to use the balancing
authority area(s) (or RTO) where an IPP's generation is physically
located as the relevant geographic market(s). Order No. 697, FERC
Stats. & Regs. ] 31,252 at P 232 n.217.
    \54\ Id. P 251; see also NERC Glossary of Terms Used in NERC
Reliability Standards 10 (2014) (``The collection of generation,
transmission, and loads within the metered boundaries of the
Balancing Authority. The Balancing Authority maintains load-resource
balance within this area.''), http://www.nerc.com/files/glossary_of_terms.pdf.
---------------------------------------------------------------------------

b. Proposal
    52. In light of the unusual and complex circumstances identified
above 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, we propose 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.\55\ Thus, if an IPP's generation-only
balancing authority area is directly interconnected with one or more
balancing authority areas, the IPP would provide indicative screens for
each of those balancing authority areas.
---------------------------------------------------------------------------

    \55\ Consistent with the Commission's proposal above in the
section dealing with proposed new filing requirements for sellers in
RTOs, the IPP would not need to study itself in any RTO market to
which its generation-only balancing authority area is directly
interconnected. Instead, the IPP must include a statement that it is
relying on Commission-approved market monitoring and mitigation to
address any potential horizontal market power concerns.
---------------------------------------------------------------------------

    53. We further propose 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 in each market that is
directly interconnected to the IPP's generation-only balancing
authority area, even if the IPP has not sold into that market in the
past.
    54. To illustrate how this proposal would work, 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 will provide indicative screens for
that transmission provider's balancing authority area. 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. 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. Thus, 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.
    55. Similarly, if an IPP is located in a generation-only balancing
authority area in a remote area such as the desert

Southwest, then the Commission proposes that the IPP would have to
provide indicative screens for the balancing authority area(s) of the
transmission provider(s) to which its generation-only balancing
authority area is directly interconnected. We further propose that an
IPP assume that all of its uncommitted capacity may compete in each
balancing authority area to which its generation-only balancing
authority area is directly interconnected, since, as noted above, 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. Thus, for example, if it were the case
that the generation-only balancing authority areas of the Gila River
Power Company LLC and Sundevil generating 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 include
all other competing generators from generation-only balancing authority
areas directly interconnected with the APS balancing authority area in
that study as well. These 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.\56\ Consistent with what is
proposed above, an IPP in this situation would not need to study any
first-tier markets, just as would be the case if it were a generator
located within the transmission provider's home balancing authority
area.\57\
---------------------------------------------------------------------------

    \56\ 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.
    \57\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 232
n.217.
---------------------------------------------------------------------------

    56. If an IPP in a generation-only balancing authority area is
directly interconnected to a transmission provider at an energy trading
hub, we propose that the IPP would provide 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
screens that study the IPP in each of those transmission providers'
balancing authority areas.\58\ Consistent with what is proposed above,
we propose that the IPP should 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.\59\ Thus, for
example, 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,\60\ then it would provide screens that study all of its
uncommitted capacity in each balancing authority area that is directly
interconnected at the switchyard. Also, consistent with what is
proposed above, an IPP in this situation would not need to provide
screens that study itself in any markets that are first tier to the
various balancing authority areas that are directly interconnected at
the switchyard.
---------------------------------------------------------------------------

    \58\ 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.
    \59\ When providing screens for the directly interconnected
balancing authority areas, the IPP would also include the
uncommitted capacity of any other generation-only balancing
authority area also interconnected to the same transmission
providers at that hub. However, the transmission providers, in all
cases, would consider the IPP generation capacity as first-tier
generation when conducting their SIL studies and indicative screens.
    \60\ A generator interconnected to a transmission provider at a
location where the transmission provider is directly interconnected
to other transmission providers would also be directly
interconnected to those other transmission providers.
---------------------------------------------------------------------------

    57. We seek comment on these proposals.
4. Reporting Format for the Indicative Screens
a. Current Policy
    58. When submitting a horizontal market power analysis, sellers are
required to use the standard screen format provided in Appendix A to
Subpart H of Part 35 for submitting their indicative screens. Although
sellers submit their indicative screens based on the formats provided
in Appendix A to Subpart H of Part 35 and in Commission Order Nos. 697
\61\ and 697-A,\62\ they currently perform their own mathematical
calculations. The Commission does not currently provide pre-programmed
spreadsheets that allow for automated mathematical calculations for
sellers' indicative screens. When preparing their screens, certain
sellers also perform SIL studies, which produce data (e.g., SIL values)
applicable to the indicative screens.
---------------------------------------------------------------------------

    \61\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 305-
306.
    \62\ See Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 17
n.6, Appendix A.
---------------------------------------------------------------------------

    59. In Puget,\63\ the Commission adopted a standardized format for
reporting SIL study results in order to help ensure greater efficiency.
The Commission directed sellers to refer to the guidance, directions,
and reporting format provided in Appendix B of Puget when preparing and
submitting SIL studies.\64\ Appendix B of Puget discusses various
submittals, including ``Submittal 1,'' which is a spreadsheet that
calculates the SIL values to be used in the indicative screens.
Submittal 1 is a summary spreadsheet of the SIL components used to
calculate the SIL values and is currently posted on the Commission's
Web site. The last line of Submittal 1 (Row 10) contains the SIL values
that sellers should use in preparing their screens.\65\ Currently, the
screen reporting format in Appendix A of Subpart H, which is discussed
in Order Nos. 697 and 697-A, does not have a row for SIL values even
though the Uncommitted Capacity Import values in the indicative screens
are constrained by the SIL value from Row 10 of Submittal 1, i.e., the
sum of the affiliated and non-affiliated Uncommitted Capacity Import
values cannot exceed the SIL value.\66\
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    \63\ Puget, 135 FERC ] 61,254 at Appendix B.
    \64\ Id. P 20.
    \65\ Id. at Appendix B.
    \66\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 361
(explaining that a SIL study determines ``how much competitive
supply from remote resources can serve load in the study area.'').
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    60. Appendix B of Puget also discusses ``Submittal 2,'' which is a
spreadsheet that identifies long-term firm transmission reservations
used to import power from seller and affiliate generating resources in
the first-tier area to serve native load in the study area. The
calculations performed in Submittal 2 provide detailed data summed to
produce the total value of long-term firm transmission reservations,
which are included in Row 5 of Submittal 1.
    61. The Commission provided additional direction on the completion
of the indicative screens in Vantage Wind Energy, LLC.\67\ In
particular, the Commission provided direction on how to account for
both remote generation resources and long-term firm power purchases
from generation resources located outside a seller's home balancing
authority area when

performing the indicative screens.\68\ Currently, the indicative screen
reporting formats in Appendix A of Subpart H and Order Nos. 697 and
697-A do not have separate rows for the value of installed capacity of
remote generation resources or the capacity of resources that are
external to the study area that support long-term firm power purchase
agreements that serve load in the study area; both values are
components of the SIL value used in the screens.
---------------------------------------------------------------------------

    \67\ Vantage Wind Energy, LLC, 139 FERC ] 61,063, at P 21 (2012)
(Vantage Wind).
    \68\ Id. (``[L]oad serving entities should add their share of
remote generation to Installed Capacity (Line A of the market share
screen and the pivotal market share screen) and the amount of any
long-term firm purchases in `Long-term Firm Purchases' (Line B of
the market share screen and the pivotal supplier screen) of the
indicative screens, when load-serving entities have long-term firm
transmission rights associated with those resources.'').
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b. Proposal
    62. We propose to amend the indicative screen reporting format in
Appendix A of Subpart H. We propose that Appendix A include both the
pivotal supplier and market share screen reporting formats with new
rows for SIL values, Long-Term Firm Purchases (from outside the study
area), and Remote Capacity (from outside the study area). Including a
row in the indicative screens for SIL value will help reinforce the
relationship between the values for affiliated and non-affiliated
capacity imports and the SIL value. For purposes of clarification, we
also propose 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.\69\ As
discussed below, the new rows and their descriptions will clarify that
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. An example of the proposed new indicative screen
reporting formats for Appendix A to Subpart H is provided in Appendix A
of this NOPR.
---------------------------------------------------------------------------

    \69\ We propose to change the phrase ``Imported Power'' in Rows
D and H of the pivotal supplier screen to ``Uncommitted Capacity
Imports.'' We also propose to make the same change to Row E of the
Market Share Screen. Thus, 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.
---------------------------------------------------------------------------

    63. Additionally, we propose 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.\70\ The proposed new language
is as follows: When submitting (proposing to delete) [a horizontal
market power analysis]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 (proposing to
delete) [form].
---------------------------------------------------------------------------

    \70\ ``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.
---------------------------------------------------------------------------

    We propose to post on the Commission's Web site a pre-programmed
spreadsheet as an example that sellers may use to submit their
indicative screens.\71\ The example spreadsheet contains pre-programmed
cells that allow for summations and data comparisons, as well as cells
that restrict entries to negative or positive values where appropriate.
We believe that these proposed changes to the indicative screens, as
reflected in Appendix A to this NOPR, will aid sellers when preparing
screens and minimize the need for follow up inquiries from staff and
amended filings.
---------------------------------------------------------------------------

    \71\ If a seller chooses to create its own workable electronic
spreadsheet, the file it submits must have the same format as the
sample spreadsheet on the Commission Web site. Specifically, it must
have one worksheet for each of the indicative screens and each
screen must have the same exact rows, columns, and descriptive text
as the sample worksheets. Cells requiring negative values must be
pre-programmed to only allow negative values. Likewise, cells with
calculated values must contain a working formula that calculates the
value for that cell. Finally, the file must be submitted in one of
the spreadsheet file formats accepted by the Commission for
electronic filing. See FERC, Acceptable File Formats (Jan. 2012),
available at http://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
---------------------------------------------------------------------------

    64. We also propose to add a paragraph to the end of Sec.
35.37(c), making it paragraph (c)(5), to codify the requirement in
Puget that sellers submitting SIL studies adhere to the direction and
required format for Submittals 1 and 2 found on the Commission's Web
site \72\ and submit their information, as instructed, in workable
electronic spreadsheets. The proposed new language is as follows:
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.
---------------------------------------------------------------------------

    \72\ The sample spreadsheets for Submittals 1 and 2 are found at
the Commission's Web site at http://www.ferc.gov/industries/electric/gen-info/mbr/authorization.asp under ``Quick Links.''
---------------------------------------------------------------------------

    Revising the regulations to reflect this requirement will help
ensure that sellers are aware of the requirement to include Submittals
1 and 2 in workable electronic spreadsheets as well.\73\
---------------------------------------------------------------------------

    \73\ Here, as with the indicative screens, 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 rows,
columns, and descriptive text as the sample spreadsheet. Likewise,
cells with calculated values must contain working formulas that
calculate 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
(January 2012), available at http://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
---------------------------------------------------------------------------

    65. We seek comment on these proposals.
5. Competing Imports
a. Current Policy
    66. The Commission permits sellers to make simplifying assumptions,
where appropriate, and to submit streamlined horizontal market power
analyses.\74\ In Order No. 697, the Commission stated 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.'' \75\
---------------------------------------------------------------------------

    \74\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 308,
321; April 14, 2004 Order, 107 FERC ] 61,018 at P 38.
    \75\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 321.
---------------------------------------------------------------------------

b. Proposal
    67. We clarify that the phrase ``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 \76\ and other Commission orders.\77\ We further clarify that the
seller must still include any uncommitted capacity that it and its
affiliates can import into the study area. We believe that this
clarification will aid sellers when preparing screens and minimize the
need for follow up

inquiries from staff and amended filings.
---------------------------------------------------------------------------

    \76\ April 14, 2004 Order, 107 FERC ] 61,018 at P 38 (``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)).
    \77\ See, e.g., Acadia Power Partners, LLC, 107 FERC ] 61,168,
at P 12 (2004) (``We remind applicants that they may provide
streamlined applications, where appropriate, to show that they pass
both screens. For example, if an applicant would pass both screens
without considering competing supplies imported from adjacent
control areas, the applicant need not include such imports.''
(emphasis added) (footnote omitted)).
---------------------------------------------------------------------------

6. Capacity Ratings
a. Current Policy
    68. The Commission allows sellers submitting indicative screens to
rate their generation facilities using either nameplate or seasonal
capacity ratings.\78\ With regard to sellers with energy-limited
resources, such as hydroelectric and wind generation facilities, in
lieu of using nameplate or seasonal capacity ratings in their
submissions, the Commission stated in Order No. 697 that it would allow
such sellers 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.\79\ 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 for use in their analyses. To address this situation,
the Commission has allowed the use of the five most recent years of
regional average capacity factors from the EIA to determine capacity
factors for those resources.\80\
---------------------------------------------------------------------------

    \78\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 343
(``We will adopt the NOPR proposal that allows sellers to use
seasonal capacity. We clarify that each seller must be consistent in
its choice and thus must choose either seasonal or nameplate
capacity and use it consistently throughout the analysis. In
addition, a seller using seasonal capacity must identify in its
submittal from what source the data was obtained.''). The Commission
adopted the EIA definition of seasonal capacity as reported on Form
EIA-860, Schedule 3, Part B, Line 2, which provides that seasonal
capacity is the ```net summer or winter capacity''' and EIA
instructions that ```net capacity should reflect a reduction in
capacity due to electricity use for station service or
auxiliaries.''' Id. (footnotes omitted).
    \79\ Id. P 344.
    \80\ See Golden Spread Electric Coop., Inc., 138 FERC ] 61,208,
at P 16 (2012) (Golden Spread) (finding that a five-year average
wind capacity factor derived from EIA data represents an appropriate
analysis).
---------------------------------------------------------------------------

b. Proposal
    69. We recognize that there are energy-limited generation
resources, such as solar photovoltaic and solar thermal facilities
(collectively, solar technologies), which were not identified in Order
No. 697. We propose 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,
and, as noted above, sellers may use EIA regional average capacity
factors for the previous five years to determine capacity for those
resources. Similar to other energy-limited generation resources,
sellers using the five-year historical average must include sensitivity
tests using the lowest and highest capacity factors for the previous
five years. We propose that sellers with energy-limited generation
facilities (including those using solar technology) that do not have
five years of historical data may use the EIA-derived, regional
capacity factor estimates appropriate to their specific technology as
defined in the EIA publication Annual Energy Outlook.\81\ We also
propose to require that sellers without five years of historical data
use either nameplate capacity or the EIA-derived, regional capacity
factor estimates, but not seasonal ratings.\82\ For sellers using EIA-
derived estimates, we propose to require that they 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. In addition, the Commission
seeks industry input in identifying additional technologies that are
energy-limited generation resources, and what capacity factors should
be used to rate them.
---------------------------------------------------------------------------

    \81\ See EIA, Annual Energy Outlook (May 2014), available at
http://www.eia.gov/forecasts/aeo/source_renewable.cfm. In Table 58
through Table 58.9 ``Renewable Energy Generation by Fuel--(by
Area),'' EIA provides data for the total generating capacity, and
actual (or estimated) electricity generated by renewable type for 22
``electricity market module regions'' covering the lower 48 states.
After converting the inputs into matching units, sellers can divide
actual (or estimated) electricity generated by installed capacity to
find the capacity factor.
    \82\ 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 found 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. See Golden Spread, 138 FERC ] 61,208 at P 16.
---------------------------------------------------------------------------

    70. While we are proposing this treatment for solar capacity, we
acknowledge that photovoltaic solar 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 photovoltaic solar facilities during such conditions. Thus,
we are seeking comment on whether it may make more sense to assign
different capacity factors to solar generation as compared to other
generation based on these operating characteristics. In particular, we
seek comment on whether we should allow such sellers to use either
nameplate capacity or five-year historical average capacity ratings
during peak hours to determine the capacity rating for their solar
technology generation resources, and, as noted above, sellers may use
EIA regional average capacity factors over peak hours for the previous
five years to determine capacity for those resources. In other words,
we seek comment on whether using peak hours will provide a better
measure of capacity for photovoltaic solar, as compared to all hours,
which would necessarily include hours in which we can predict that
output will be zero.
    71. Finally, consistent with Order No. 697, we propose to clarify
that, within each filing, a seller must use the same capacity rating
methodology for similar generation assets.\83\ Specifically, 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 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. 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). We believe that when a seller
consistently uses the same rating methodology within a filing, it will
improve the accuracy of the horizontal market power analysis by linking
the capacity values in the transmittal letter, accompanying testimony,
generation asset appendix, and the indicative screens.
---------------------------------------------------------------------------

    \83\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 343.
---------------------------------------------------------------------------

    72. We seek comment on these proposals.

7. Reporting of Long-Term Firm Purchases
a. Current Policy
    73. In Order No. 697, the Commission stated that a seller's
uncommitted capacity, as calculated in the indicative screens, is
determined by adding the total nameplate or seasonal capacity of
generation owned or controlled through contract and long-term firm
capacity purchases, less operating reserves, native load commitments,
and long-term firm sales.\84\ The Commission specified that 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, rather than to the entity
that is the legal owner of the facility.\85\ Order No. 697 stated that
if a market-based rate applicant has control over certain capacity,
such that that applicant can affect the ability of the capacity to
reach the market, then that capacity should be attributed to that
applicant when performing the indicative screens.\86\ As a result, in
their initial and triennial market-based rate filings, market-based
rate applicants \87\ 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.\88\
Similarly, for purposes of reporting a change in status, market-based
rate applicants 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 the applicant
purchaser.\89\
---------------------------------------------------------------------------

    \84\ Id. P 38.
    \85\ Id. P 157.
    \86\ Id. P 174. The Commission found that determination of
control is based on a review of the totality of circumstances on a
fact-specific basis. Id.
    \87\ Although we generally use the term ``market-based rate
sellers'' elsewhere in this NOPR, in this section we refer to such
sellers as ``market-based rate applicants'' to avoid confusion when
discussing sellers who are purchasers under long-term firm power
purchase agreements.
    \88\ Reflecting this capacity in Row B has the effect of
attributing the capacity to the market-based rate applicant.
    \89\ Order No. 697-B, FERC Stats. & Regs. ] 31,285 at PP 99-101.
---------------------------------------------------------------------------

    74. This requirement also 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.\90\ In this regard,
in Order No. 697-B, the Commission stated that if a contract for a
fixed quantity of delivered energy does not confer control, it need not
be reported.\91\ The Commission stated its belief at that time that a
long-term firm energy purchase by itself gives the purchaser only a
right to receive energy and thus no rights that would allow the
purchaser to control generation capacity, and that a determination of
whether a long-term firm energy purchase confers control over
generation capacity must be based on a review of the totality of the
circumstances on a fact-specific basis.\92\ Many applicants under the
market-based rate program, therefore, do not report some or all of
their long-term firm power purchases (including long-term firm energy
purchases) in their indicative screens if they believe these purchases
do not grant them control of the capacity.
---------------------------------------------------------------------------

    \90\ Id.
    \91\ Id. P 99.
    \92\ Id. P 101. In Integrys Energy Group, Inc., 123 FERC ]
61,034 (2008), the Commission found that the sale of a ``Firm (LD)''
product, as defined in the EEI Master Power Purchase & Sale
Agreement, by itself gives the purchaser only a right to receive
energy and thus no rights that would allow the purchaser to control
generation capacity. In reaching this determination, the Commission
relied on the fact that the purchaser under a Firm (LD) product
cannot force the seller to back down the output of any generator and
the fact that if the purchaser refused to receive delivery, that
refusal does not keep the power from entering the market because the
seller has the right to resell the Firm (LD) product, as well as to
receive damages from the purchaser.
---------------------------------------------------------------------------

    75. As explained below, we have determined, after two complete
rounds of regional reviews, that the limited reporting of long-term
firm purchases may create errors or misleading results in the
indicative screens submitted by some sellers. These errors include
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. Specifically, on numerous occasions the
Commission has encountered situations where neither the seller nor the
purchaser under a long-term firm power sale is being attributed with
the generation capacity that is used to make that sale. This is because
the seller, consistent with Commission policy, has deducted the
capacity committed under the long-term firm power sale \93\ for
purposes of calculating that seller's uncommitted capacity, while the
purchaser has used our policies (and underlying assumptions) outlined
above to assume that it is also not responsible for this capacity and
therefore has not included this capacity as part of the purchaser's
uncommitted capacity. The combination of these actions by sellers and
purchasers results in capacity under long-term firm power purchase
agreements many times ``disappearing'' from the market, with neither
counterparty reflecting the capacity in their screens.
---------------------------------------------------------------------------

    \93\ The EQR Data Dictionary defines a firm sale as ``a sale,
service or product that is not interruptible for economic reasons.''
See Filing Requirements for El. Utility S.A., Order Updating
Electric Quarterly Report Data Dictionary, 146 FERC ] 61,169,
Attachment (2014) (``EQR Data Dictionary Transaction Data'' table,
field number 59).
---------------------------------------------------------------------------

    76. One result of this practice is that it leads to the anomalous
result in the indicative screens of some franchised public utility
sellers appearing to be net short; that is, appearing to lack
sufficient generation resources (both owned and purchased) to serve
their peak load. In reality, franchised public utilities are required
by state regulators to have sufficient generation resources (owned
capacity and firm purchases) to serve their projected peak load and an
additional ``planning reserve margin'' on top of that.\94\ Although it
is unrealistic for franchised public utilities to rely extensively on
spot market purchases to serve statutory load obligations, that is what
is implied in some of the indicative screens that have been submitted
by franchised public utilities that do not include long-term firm
purchases in their indicative screens.
---------------------------------------------------------------------------

    \94\ See, e.g., Staff of the California Public Utilities
Commission with the assistance of California Energy Commission
Staff, 2011 Resource Adequacy Report (Feb. 5, 2013), available at
http://www.cpuc.ca.gov/PUC/energy/Procurement/RA/.
---------------------------------------------------------------------------

    77. Moreover, our experience with the horizontal market power
analyses submitted subsequent to the implementation of Order No. 697
has shown us that in the typical situation, the capacity associated
with a long-term firm power purchase agreement should be attributed to
the purchaser, not the seller. This is because long-term firm power
purchase agreements, including long-term firm energy agreements,
provide the purchaser with energy that only can be interrupted for
limited and specified reasons (e.g., force majeure). A firm energy sale
cannot, for example, be interrupted by the seller for economic reasons.
Thus, a seller must have capacity supporting a firm energy sale and
this capacity is now effectively serving the purchaser, much like the
purchaser's owned generation capacity.
    78. As an example of this, the Commission recently addressed
problems associated with the misreporting of long-term firm purchases
in Vantage Wind.\95\ In Vantage Wind, a non-affiliated seller prepared
a horizontal market power study for a balancing authority area based on
the data used by the transmission owner. However, the

transmission owner failed to properly account for its long-term firm
purchases in its indicative screens for its home balancing authority
area. The transmission owner was entitled to receive the output
associated with several long-term firm power purchases, but did not
report the capacity supplying these long-term firm purchases. As a
result, the non-affiliated seller appeared (incorrectly) to fail the
screens because the transmission owner's capacity effectively was
underreported. In Vantage Wind, the Commission corrected for this
underreporting of capacity by directing the load-serving entity
purchasers to report all long-term firm purchases in Row B of the
indicative screens (Long-Term Firm Purchases) if the purchase had long-
term firm transmission rights associated with those resources.\96\ This
direction in the Vantage Wind order resulted in the purchasers having
to include the generation capacity associated with such long-term firm
purchases as part of the purchasers' capacity. Otherwise, this
generation capacity would have ``disappeared'' from being evaluated
under the market-based rate program. We note that in directing this
outcome, the Commission did not consider the issue of who had
operational control of the capacity supplying the long-term firm
purchases; rather, the Commission assigned the capacity to the
purchasers under the long-term firm power purchase agreement.
---------------------------------------------------------------------------

    \95\ Vantage Wind, 139 FERC ] 61,063 at P 21.
    \96\ Id.
---------------------------------------------------------------------------

b. Proposal
    79. For the reasons stated above, we propose to modify the policy
with respect to the reporting of long-term firm purchases in the
indicative screens. Specifically, we propose to require applicants
under the market-based rate program to report all of their long-term
firm purchases \97\ 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. If the long-term firm purchase involves the sale
of energy, then 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 seller
under that power purchase agreement must do the same the next time it
submits a market-based rate triennial or change of 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).\98\ When making these filings, we propose that both the
purchaser and the seller must show how they made the energy-to-capacity
conversion. Although this attribution of capacity is the default
approach that we propose as a general policy, applicants or intervenors
are free to raise fact-specific circumstances that they believe may
support a different attribution of capacity.
---------------------------------------------------------------------------

    \97\ The Commission in Vantage Wind directed the purchasers to
report all long-term firm purchases if the purchase had long-term
firm transmission rights associated with those resources. Id. We
assume for purposes of our proposal here that all long-term firm
purchases necessarily have long-term firm transmission rights
associated with them. If that is not the case, as noted above,
applicants or intervenors are free to raise fact-specific
circumstances that they believe may support a different attribution
of capacity.
    \98\ Our understanding is 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.
---------------------------------------------------------------------------

    80. The intent of our proposed reform is to have an entity with
market-based rate authority 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, we
propose that the amount of the capacity supplying that purchase must be
reported in the purchaser's screens. We also propose to require that
all such long-term firm purchases should be reported 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, depending on whether the generation resource(s)
supplying the sale are located inside or outside the seller's balancing
authority area, as explained earlier in this proposed rule.
    81. The proposal to require applicants 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 is
supported based on the following 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, sellers 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.
    82. Second, this proposed change will establish consistent
treatment of long-term firm sales and long-term firm purchases in the
indicative screens. Market-based rate applicants typically deduct long-
term firm sales without making a determination as to whether those
sales confer operational control to the purchaser. The Commission, in
Order No. 697, did not require that sellers make such a determination
before deducting the capacity supporting long-term firm sales:
``Uncommitted capacity is determined 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.'' \99\ The Commission clarified that
``[s]ellers may deduct generation associated with their long-term firm
requirements sales, unless the Commission disallows such deductions
based on extraordinary circumstances.'' \100\
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    \99\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 38
(footnotes omitted).
    \100\ Id. n.18.
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    83. 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.\101\ 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). 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. This proposal will make those standards consistent,
reducing such errors.
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    \101\ Order No. 697-B, FERC Stats. & Regs. ] 31,285 at PP 99,
100.
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    84. 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's 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.\102\ 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.\103\ 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, we propose 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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    \102\ 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 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.
    \103\ 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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    85. Finally, for those applicants incorrectly reporting long-term
firm power purchases in the wrong row of the indicative screens,
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. As the Commission noted in Vantage Wind,\104\
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.
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, 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. 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. This proposal is intended
to help clarify how to classify imports of firm power and remotely-
owned capacity. These proposed changes to the pivotal supplier screen
format are also being proposed for the market-share screen.
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    \104\ 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 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 Sound Energy, Inc., 135 FERC ]
61,254 (2011)]. 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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    86. We seek comment on this proposal.

B. Vertical Market Power--Land Acquisition Reporting

1. Current Policy
    87. All market-based rate sellers are currently required, pursuant
to Sec.  35.42(d) of the Commission's regulations and Order Nos. 697-C
and 697-D, to file notices of change in status on a quarterly basis
when they acquire sites for new generation capacity development.\105\
To date, not a single protest has been filed in response to these
copious filings and the Commission has not uncovered any issues
indicating that a particular seller has erected a barrier to entry as a
result of its land acquisition. On a number of occasions over the
years, market-based rate sellers have expressed frustration with this
reporting requirement and have described it as burdensome.
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    \105\ Order No. 697-C, FERC Stats. & Regs. ] 31,291 at PP 18-19;
Order No. 697-D FERC Stats. & Regs. ] 31,305 at PP 21-23.
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    88. In Order No. 697, the Commission stated it would consider a
seller's ability to erect other barriers to entry as part of the
vertical market power analysis. Thus, the regulations require that a
seller provide a description of its ownership or control of, or
affiliation with an entity that owns or controls, intrastate natural
gas transportation, intrastate natural gas storage or distribution
facilities, sites for generation capacity development, and physical
coal supply sources and ownership or control over who may access
transportation of coal supplies.\106\ The Commission noted that, to
date, it had not found such ownership or control to be a potential
barrier to entry warranting further analysis, but that it did not have
sufficient evidence to remove these inputs from the analysis entirely.
Thus, it rebuttably presumed that ownership or control of or
affiliation with an entity that owns or controls such facilities does
not allow a seller to raise entry barriers, but would allow intervenors
to demonstrate otherwise.\107\ In Order No. 697-C, the Commission noted
that ``[o]ne of the purposes of the change of status reporting
requirement is to provide interested parties the opportunity to
intervene and comment if they believe the seller's acquisition of sites
for new generation capacity

development creates a barrier to entry.'' \108\
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    \106\ 18 CFR 35.37(e).
    \107\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 446.
    \108\ Order No. 697-C, FERC Stats. & Regs. ] 31,291 at P 17.
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2. Proposal
    89. We propose to relieve market-based rate sellers of their
obligation to file quarterly land acquisition reports and of the
obligation to provide information on sites for generation capacity
development in market-based rate applications and triennial updated
market power analyses because the burden of such reporting outweighs
the benefits.\109\
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    \109\ For an example of the burden, the Commission received, in
the most recent seven quarters, 90 filings from 1,380 filers. This
is a reporting burden on the 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. All
1,380 filers had to be listed in the notices and in the orders
accepting the filings. Staff has written and issued seven orders
accepting these filings, one order for each of the last seven
quarters.
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    90. In the more than six years since issuance of Order No. 697,
intervenors have not challenged whether sites for new generation
capacity development created a barrier to entry. For this reason, we
propose to eliminate the requirement to provide such information. We
note 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.\110\
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    \110\ 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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    91. Thus, we propose to revise the regulations at 18 CFR 35.42 to
remove paragraph (d). This proposed revision removes 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, we propose 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). We also propose to revise the
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. Therefore,
under this proposal, Sec.  35.42(d)-(e) and Sec.  35.37(e)(2) would be
removed entirely. In addition, we propose 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.
Specifically, under this proposal, Sec.  35.42(b) would read as
follows: Any change in status subject to paragraph (a) of this section,
(proposing to delete) [other than a change in status submitted to
report the acquisition of control of a site or sites for new generation
capacity development], must be filed no later than 30 days after the
change in status occurs. Power sales contracts with future delivery are
reportable 30 days after the physical delivery has begun. Failure to
timely file a change in status report constitutes a tariff violation.
    92. We seek comment on these proposals.

C. Notices of Change in Status

    93. Section 35.42(a) of the Commission's regulations requires
sellers to report any change in status that would reflect a departure
from the characteristics the Commission relied upon in granting market-
based rate authority.\111\ A change in status filing is required when,
among other things, either of two conditions are met:
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    \111\ 18 CFR 35.42(a).

    (1) Ownership or control of generation capacity results in net
increases of 100 MW or more; [\112\] or
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    \112\ 18 CFR 35.42(a)(1).
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    (2) affiliation with any entity not disclosed in the application
for market-based rate authority that (a) owns or controls generation
facilities or inputs to electric power production, (b) owns,
operates or controls transmission facilities, or (c) has a
franchised service area. [\113\]
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    \113\ 18 CFR 35.42(a)(2).
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1. Geographic Focus
a. Current Policy
    94. 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.'' \114\
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    \114\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 512.
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    95. Order No. 697-A also provided an example of when a seller
should not file a notice of change in status: ``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 a 50 MW
increase in a different geographic market that is in the same region as
defined by Appendix D of Order No. 697, 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.'' \115\
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    \115\ Id. We note that the original text in Order No. 697-A