Rm14-14 Nopr

RM14-14-000 NOPR.pdf

FERC-919, (RM14-14 Final Rule) Refinements to Policies and Procedures for Market Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities

RM14-14 NOPR

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147 FERC ¶ 61,232
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
(Issued June 19, 2014)
AGENCY: Federal Energy Regulatory Commission.
ACTION: Notice of Proposed Rulemaking.
SUMMARY: The Federal Energy Regulatory Commission (Commission) is proposing
to amend its regulations to revise Subpart H to Part 35 of Title 18 of the Code of Federal
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 [INSERT DATE 60 days after publication in the FEDERAL
REGISTER].
ADDRESSES: Comments, identified by docket number, may be filed in the following
ways:

Docket No. RM14-14-000

 Electronic Filing through http://www.ferc.gov. Documents created electronically
using word processing software should be filed in native applications or print-toPDF 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
202-502-8876
Carol Johnson (Legal Information)
Office of the General Counsel
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
202-502-8521
SUPPLEMENTARY INFORMATION:

Docket No. RM14-14-000
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION

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

Docket No. RM14-14-000

NOTICE OF PROPOSED RULEMAKING
TABLE OF CONTENTS
Paragraph Numbers
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
Authority Areas ......................................................................................................... 47
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

Docket No. RM14-14-000
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

Docket No. RM14-14-000
147 FERC ¶ 61,232
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Refinements to Policies and Procedures for MarketBased Rates for Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by Public Utilities

Docket No. RM14-14-000

NOTICE OF PROPOSED RULEMAKING
(Issued June 19, 2014)
I.

Introduction

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.
II.

Background

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 marketbased 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

16 U.S.C. 824d, 824e (2012).

Docket No. RM14-14-000

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
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

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).

Docket No. RM14-14-000

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
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

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 62.

Id. P 13; 18 CFR 35.37(c)(3).

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 17.

We will use the term “RTO” when referring to either an RTO or ISO for easier
readability.

Docket No. RM14-14-000

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
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

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.
10

Id. P 408.

Id. P 440.

Docket No. RM14-14-000

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 § 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
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

Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 176.

Order No. 697-C, FERC Stats. & Regs. ¶ 31,291 at P 18; 18 CFR 35.42(d).

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 446; 18 CFR 35.37(c).

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 447.

Docket No. RM14-14-000

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
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

18 CFR 35.39.

18 CFR 35.10b.

18 CFR 35.42.

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 3; 18 CFR 35.37(a)(1).

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 848.

Docket No. RM14-14-000

waiver of the requirements of Order No. 88821); that are not affiliated with anyone that
owns, operates, or controls transmission facilities in the same region as the seller’s
generation assets; that are not affiliated with a franchised public utility in the same region
as the seller’s generation assets; and that do not raise other vertical market power
issues.22 Category 1 sellers are not required to file regularly scheduled updated market
power analyses. Sellers that do not fall into Category 1 are designated as Category 2
sellers and are required to file updated market power analyses.23 However, the
Commission may require an updated market power analysis from any market-based rate
seller at any time, including those sellers that fall within Category 1.24
9.

In Order No. 697, the Commission further stated that through its ongoing

oversight of market-based rate authorizations and market conditions, the Commission
may take steps to address seller market power or modify rates. For example, based on its

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.

Id. P 853.

Docket No. RM14-14-000

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
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.
25

Id. P 5.

Docket No. RM14-14-000

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 generationonly 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

Docket No. RM14-14-000

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.
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
26

Puget Sound Energy, Inc., 135 FERC ¶ 61,254, Appendix B (2011) (Puget).

Docket No. RM14-14-000

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.

Docket No. RM14-14-000
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

Docket No. RM14-14-000

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

Docket No. RM14-14-000

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.

Docket No. RM14-14-000
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 generationshift methodology. We also instruct sellers to subtract all long-term firm import

Docket No. RM14-14-000

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

Docket No. RM14-14-000

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 §§ 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-

Docket No. RM14-14-000

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 §§ 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.

31.

Current Policy

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

Docket No. RM14-14-000

seek to obtain or retain market-based rate authority by relying on Commission-approved
RTO monitoring and mitigation.27
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
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

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.”
28
29

AEP Power Marketing, Inc., 97 FERC ¶ 61,219, at 61,970 (2001).

AEP Power Marketing, Inc., 107 FERC ¶ 61,018, at P 186 (April 14, 2004
Order), order on reh’g, 108 FERC ¶ 61,026 (2004).

Docket No. RM14-14-000

from all sellers, including those in [RTO] markets.”30 In Order No. 697-A, the
Commission denied requests to reconsider its decision stating that
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]
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
30

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 290.

Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 110.

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

(continued…)

Docket No. RM14-14-000

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
b.
35.

Proposal

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

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.

Docket No. RM14-14-000

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.
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 Commissionapproved 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

April 14 Order, 107 FERC ¶ 61,018 at P 189.

Docket No. RM14-14-000

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.
37.

Thus, we propose to add a paragraph to the end of § 35.37(c) (regarding horizontal

market power), making it paragraph (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 Commissionapproved 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:
The existing [change in status] reporting requirement provides the
Commission a sufficient tool to allow it to assess whether there is a
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.
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.”).

Docket No. RM14-14-000

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]
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.

41.

Current Policy

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

Id. P 505 (emphasis added).

Docket No. RM14-14-000

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]
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
38

Id. P 41.

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 noninterruptible for economic reasons and states that contracts with durations of one year or
greater are long-term.

Docket No. RM14-14-000

perform indicative screens when they can demonstrate that all of their capacity is
committed under long-term contract.
b.
43.

Proposal

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

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.”).

Docket No. RM14-14-000

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.
44.

We propose that sellers claiming that all of their relevant capacity42 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 longterm contract, the expiration date of the contract, and a representation that the contract is
for firm sales for one year or longer. In order to qualify as fully committed, the
commitment of the generation capacity cannot be limited during that 12-month
consecutive period in any way, such as limited to certain seasons, market conditions, or
any other limiting factor. 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).
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

“Relevant” capacity refers to seller and affiliated capacity in the study area,
including the first tier.
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).

Docket No. RM14-14-000
46.

We seek comment on these proposals.
3.

Relevant Geographic Market for Certain Sellers in GenerationOnly Balancing Authority Areas
a.

47.

Current Policy

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 (firsttier 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

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 37.

Id. P 232.

Id. n.217.

Id. P 231 n.215.

Docket No. RM14-14-000
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
49

Id. P 251.

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.

Docket No. RM14-14-000
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.

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
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).
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.”

Docket No. RM14-14-000

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.
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.

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.

Docket No. RM14-14-000
b.
52.

32
Proposal

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.
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.

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.

Docket No. RM14-14-000
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

Docket No. RM14-14-000

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 firsttier markets, just as would be the case if it were a generator located within the
transmission provider’s home balancing authority area.57
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

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.

Docket No. RM14-14-000

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
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.

Docket No. RM14-14-000

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.
57.

We seek comment on these proposals.
4.

Reporting Format for the Indicative Screens
a.

58.

Current Policy

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. 69761 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.

See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 305-306.

See Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 17 n.6, Appendix A.

Docket No. RM14-14-000
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

Puget, 135 FERC ¶ 61,254 at Appendix B.

Id. P 20.

Id. at Appendix B.

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.”).

Docket No. RM14-14-000
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

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.”).

Docket No. RM14-14-000

power purchase agreements that serve load in the study area; both values are components
of the SIL value used in the screens.
b.
62.

Proposal

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.

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.

Docket No. RM14-14-000
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 a horizontal market power analysisthe 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 screensform.
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.

“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.
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/docsfiling/elibrary/accept-file-formats.asp.

Docket No. RM14-14-000
64.

We also propose to add a paragraph to the end of § 35.37(c), making it paragraph

(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
site72 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.
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
65.

We seek comment on these proposals.

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.”
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.

Docket No. RM14-14-000
5.

Competing Imports
a.

66.

Current Policy

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
b.
67.

Proposal

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 Order76 and other Commission orders.77 We further clarify that the seller must still

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.

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
(continued…)

Docket No. RM14-14-000

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.
6.

Capacity Ratings
a.

68.

Current Policy

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

areas, the applicant need not include such imports.” (emphasis added) (footnote
omitted)).
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).

Docket No. RM14-14-000

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
b.
69.

Proposal

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 fiveyear 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 fiveyear 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

79
80

Id. P 344.

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).

Docket No. RM14-14-000

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.
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
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.

Docket No. RM14-14-000

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
83

See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 343.

Docket No. RM14-14-000

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.
72.

We seek comment on these proposals.
7.

Reporting of Long-Term Firm Purchases
a.

73.

Current Policy

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

Docket No. RM14-14-000

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 applicants87 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

Id. P 38.

Id. P 157.

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.

Docket No. RM14-14-000

firm capacity purchases when assessing their cumulative generation capacity only if such
purchases confer control of such capacity to the applicant purchaser.89
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

Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at PP 99-101.

Id.

Id. P 99.

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.

Docket No. RM14-14-000

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.
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 sale93 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
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).

Docket No. RM14-14-000

agreements many times “disappearing” from the market, with neither counterparty
reflecting the capacity in their screens.
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.
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
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/.

Docket No. RM14-14-000

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

Vantage Wind, 139 FERC ¶ 61,063 at P 21.

Id.

Docket No. RM14-14-000

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.
b.
79.

Proposal

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 purchases97 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
97

The Commission in Vantage Wind directed the purchasers to report all longterm 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 factspecific circumstances that they believe may support a different attribution of capacity.

Docket No. RM14-14-000

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.

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.

Docket No. RM14-14-000
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 nontransmission 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.

Docket No. RM14-14-000
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
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

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 38 (footnotes omitted).

100

Id. n.18.

101

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

Docket No. RM14-14-000

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.
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
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).

Docket No. RM14-14-000

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.
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
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.”).

Docket No. RM14-14-000

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.
86.

We seek comment on this proposal.
B.

Vertical Market Power – Land Acquisition Reporting
1.

87.

Current Policy

All market-based rate sellers are currently required, pursuant to § 35.42(d) of the

Commission’s regulations and Order Nos. 697-C and 697-D, to file notices of change in

Docket No. RM14-14-000

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.
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

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.
106

18 CFR 35.37(e).

Docket No. RM14-14-000

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
2.
89.

Proposal

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
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

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.

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.

Docket No. RM14-14-000

generation capacity development may be creating a barrier to entry, the Commission can
request additional information from the seller at any time.110
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, § 35.42(d)-(e) and § 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, § 35.42(b) would read as
follows:
Any change in status subject to paragraph (a) of this section, 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
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.”).

Docket No. RM14-14-000

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.

93.

Notices of Change in Status

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:
(1) ownership or control of generation capacity results in net increases of 100 MW
or more;[112] or
(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]
1.

Geographic Focus
a.

94.

Current Policy

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

111

18 CFR 35.42(a).

112

18 CFR 35.42(a)(1).

113

18 CFR 35.42(a)(2).

Docket No. RM14-14-000

of the horizontal market power analysis on which the Commission relied in granting the
seller market-based rate authority.”114
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
b.
96.

Proposal

We propose to clarify that the 100 MW reporting threshold in § 35.42(a)(1) is not

limited only to markets previously studied. That is, if a seller acquires generation that
would cause a cumulative net increase of 100 MW or more in any relevant geographic
market (including generation in both the relevant geographic market itself and any firsttier/interconnected market with the potential to import into that market) since the seller’s
most recent triennial updated market power analysis or change in status filing, the seller
must make a change in status filing. This would include cumulative increases of

114
115

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

Id. We note that the original text in Order No. 697-A stated “the increase in
generation is less than 50 MW in each generation market.” However, it should have
stated “the increase in generation is less than 100 MW in each generation market.”

Docket No. RM14-14-000

100 MW or more in a new market that has not previously been studied because, once the
seller has generation in that market, it is a relevant geographic market for that seller. We
clarify that a net increase measures the difference between increases and decreases in
affiliated generation. We further clarify that the example cited above from Order
No. 697-A described a situation where the geographic market on which the Commission
relied was not first-tier to the geographic market in which the seller acquired an
additional 50 MW. Thus, we propose to clarify that the 100 MW threshold applies to the
cumulative capacity added in any relevant geographic market, including what can be
imported from first-tier markets, but does not cover situations where a seller acquires less
than 100 MW in one market and less than 100 MW in another market, as long as those
two markets are not first-tier to each other. We further propose to require that the
100 MW threshold requirement for change in status filings be calculated based on a
generator’s nameplate capacity rating because it is a single value, it exists for all types of
generators, it is generally a more conservative value than a seasonal or five-year average
rating would be, and it allows for uniform measurements across different types of
generators.
97.

Therefore, we propose to revise the regulatory text in § 35.42(a)(1) of the

Commission’s regulations to provide greater clarity and direction on this topic as follows:
Ownership or control of generation capacity that results in cumulative net
increases (i.e., the difference between increases and decreases in affiliated
generation capacity) of 100 MW or more of nameplate capacity in any relevant
geographic market (including generation in the relevant geographic market and
generation in any markets that are first tier to the relevant geographic market), or

Docket No. RM14-14-000

of inputs to electric power production, or ownership, operation or control of
transmission facilities, or
98.

We seek comment on these proposals.
2.

Long-Term Contracts
a.

99.

Current Policy

As noted above, sellers are currently required to report ownership or control of

generation capacity that results in net increases of 100 MW or more but are not required
to report contracts that do not convey ownership or control of generation capacity. 116
b.
100.

Proposal

As discussed above, we propose to require sellers to report all long-term firm

purchases of capacity and/or energy in their indicative screens, regardless of whether the
seller has acquired control over the generation capacity supplying the power. The change
in status reporting requirement in § 35.42 seeks to provide a timely report of “any change
in status that would reflect a departure from the characteristics the Commission relied
upon in granting market-based rate authority.”117 We propose above to require reporting
of long-term firm purchases in the indicative screens; such purchases will be relied upon
in granting market-based rate authority. Therefore, in addition to the revisions proposed
above, we propose to include such contracts when determining the 100 MW threshold

116

See 18 CFR 35.42(a)(1).

117

18 CFR 35.42(a).

Docket No. RM14-14-000

and propose to revise the beginning of § 35.42(a)(1) of the Commission’s regulations as
follows:
Ownership or control of generation capacity or long-term firm purchases of
capacity and/or energy that results in net increases…[118]
101.

We seek comment on this proposal.
3.

New Affiliation and Behind-the-Meter Generation
a.

102.

Current Policy

Market-based rate sellers are required to make a change in status filing when they

become affiliated with entities that: (1) own or control generation; (2) own or control
inputs to electric power production (e.g., intrastate natural gas transportation, storage, or
distribution facilities); (3) own, operate or control transmission facilities; or (4) have a
franchised service territory.119 Currently, the 100 MW threshold for reporting increases
in generation contained in § 35.42(a)(1) of the Commission’s regulations does not apply
to the requirement to report a new affiliation found in § 35.42(a)(2) of the Commission’s
118

When the changes to § 35.42(a)(1) as proposed here are combined with the
changes to § 35.42(a)(1) proposed above, the revised § 35.42(a)(1) would read as
follows:
Ownership or control of generation capacity or long-term firm purchases of
capacity and/or energy that results in cumulative net increases (i.e., the difference
between increases and decreases in affiliated generation capacity) of 100 MW or
more of nameplate capacity in any relevant geographic market (including
generation in the relevant geographic market(s) and generation in any markets that
are first tier to the relevant geographic market(s)), or of inputs to electric power
production, or ownership, operation or control of transmission facilities, or
119

18 CFR 35.42(a)(2).

Docket No. RM14-14-000

regulations because the existing language in § 35.42(a)(2) does not reference the
100 MW threshold. As a result, § 35.42(a)(2) requires a change in status filing for any
new affiliation, regardless of the amount of generation owned or controlled by the new
affiliate.
103.

In addition, the regulatory text states that a change in status filing is required for

any new affiliate that owns or controls generation facilities, without regard to the size,
type or characteristics of those facilities.120 The Commission’s experience is that some
sellers are unsure if they should report new affiliates that own certain facilities such as
qualifying facilities that are exempt from FPA section 205121 and behind-the-meter
facilities.
104.

Finally, the Commission’s experience is that some sellers report the new

acquisition or new affiliation in the text of their change in status filings but do not include
the generation in the asset appendix, especially when it is behind-the-meter generation.
b.
105.

Proposal

We propose to revise the change in status regulations to include a 100 MW

threshold for reporting new affiliations. That is, a market-based rate seller that has a new
affiliation would not be required to file a change in status until its new affiliations result

120
121

See id.

Sales of energy or capacity made by qualifying facilities 20 MW or smaller are
exempt from section 205. Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 525;
18 CFR 292.601(c)(1).

Docket No. RM14-14-000

in a cumulative net increase of 100 MW or more of nameplate capacity in any relevant
geographic market (including generation in both the relevant geographic market itself and
any first-tier/interconnected market). As noted above, the Commission adopted a
100 MW threshold for reporting new generation, finding that a minimum reporting
threshold strikes the proper balance between the Commission’s duty to ensure that
market-based rates are just and reasonable and the Commission’s desire not to impose an
undue regulatory burden on market-based rate sellers.122 Similarly, we believe that
applying the 100 MW threshold to new affiliations would ease the reporting burden on
sellers without diminishing the Commission’s ability to identify possible market power.
Therefore, we propose to revise § 35.42(a)(2) of the Commission’s regulations to read as
follows:
Affiliation with any entity not disclosed in the application for market-based rate
authority that:
(i) oOwns or controls generation facilities or has long-term firm purchases of
capacity and/or energy that results in cumulative net increases (i.e., the difference
between increases and decreases in affiliated generation capacity) of 100 MW or
more of nameplate capacity in any relevant geographic market (including
generation in the relevant geographic market(s) and generation in any markets that
are first tier to the relevant geographic market(s));
(ii) Owns or controls inputs to electric power production;,
(iii) affiliation with any entity not disclosed in the application for market-based
rate authority that oOwns, operates or controls transmission facilities;, or
(iv) affiliation with any entity that hHas a franchised service area.
122

Reporting Requirement for Changes in Status for Public Utilities with MarketBased Rate Authority, Order No. 652, FERC Stats. & Regs. ¶ 31,175, at P 68, order on
reh’g, 111 FERC ¶ 61,413 (2005).

Docket No. RM14-14-000
106.

We further clarify that the requirement to submit a notice of change in status to

report affiliation with new generation, transmission, or intrastate gas pipelines includes
reporting that asset in the seller’s appendix. We propose to amend the regulation to
clarify that sellers must include all new affiliates and any assets owned or controlled by
the new affiliates in the asset appendix. We propose to revise § 35.42(c) of the
Commission’s regulations as follows:
When submitting a change in status notification regarding a change that impacts
the pertinent assets held by a Seller or its affiliates with market-based rate
authorization, a Seller must include an appendix of all assets, including the new
assets and/or affiliates reported in the change in status, in the form provided in
Appendix B of this subpart.
107.

We further clarify that “all assets” include behind-the-meter generation and

qualifying facilities.123 However, we propose to allow sellers to aggregate their behindthe-meter generation by balancing authority area or market into one line on the list of
generation assets. Similarly, we propose to allow sellers to aggregate their qualifying
facilities under 20 MW by balancing authority area or market into one line on the list of
generation assets.
108.

We also clarify that sellers should include these assets in their indicative screens,

as well as in their asset appendix. Sellers should also include this generation when
123

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

Docket No. RM14-14-000

calculating the 100 MW change in status threshold and the 500 MW Category 1
threshold.
109.

We seek comment on these proposals.
D.

Asset Appendix
1.

110.

Current Policy

Order No. 697 requires that market-based rate 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 any
assets owned or controlled by the seller and any such affiliate.124 The asset appendix
includes two lists of assets. One list contains market-based rate affiliates and generation
assets and the other list contains electric transmission and intrastate natural gas assets.
The appendix must list all generation assets owned or controlled by the corporate family,
and each asset’s balancing authority area (clearly identifying which affiliate owns or
controls which asset), geographic region, in-service date, and nameplate and/or seasonal
ratings.125 The transmission list of assets must reflect all electric transmission and natural
gas intrastate pipelines and/or gas storage facilities owned or controlled by the corporate
family and the location of such facilities.126 The Commission requires the appendix of

124

Id. P 894.

125

Id. P 895.

126

Id.

Docket No. RM14-14-000

assets to be included in the form provided in Appendix B to Subpart H of Part 35 of the
Commission’s regulations, and provides an example of the required appendix on its Web
site.127
2.
111.

Proposal

As detailed below, we propose clarifications and revisions to the required

appendix that contains the lists of assets.
a.
112.

Changes to the Existing Columns

We propose to make three changes to the existing columns in the asset appendix.

We propose to change the column headings on both lists of assets from “Balancing
Authority Area” to “Market/Balancing Authority Area” to reflect the correct location for
assets in organized markets as well as in balancing authority areas. The second proposal
is to change the column headings on both lists of assets from “Geographic Region (per
Appendix D)” to “Geographic Region” because there have been changes to some sellers’
regions since the Commission originally published the region map in Appendix D of
Order No. 697. Finally, we propose to change the heading for the “Nameplate and/or
Seasonal Rating” column to “Capacity Rating (MW): Nameplate, Seasonal, or Five-Year
Average” to clarify that this column requires capacity ratings in megawatts and to reflect
that each submission of the asset appendix should use either “nameplate,” “seasonal,” or
five-year average rating to reflect the rating used throughout the filing for a particular
127

The sample asset appendix can be found on the Commission’s Web site at
http://www.ferc.gov/industries/electric/gen-info/mbr/appendix.pdf.

Docket No. RM14-14-000

generation technology. These proposed changes will ensure consistency across filings
and allow the industry and Commission staff to better utilize the information contained in
the lists of assets.
113.

Thus, we propose to modify the example of the required appendix found in

Appendix B to Subpart H of Part 35 of the Commission’s regulations to incorporate these
changes.128
114.

We seek comment on these proposed changes.
b.

115.

Clarifications Regarding the Existing Columns

The Commission’s post-Order No. 697 experience has been that, with respect to

the currently labeled “Nameplate and/or Seasonal Rating” column in the list of generation
assets, some sellers report only the portion of the capacity that they own,129 whereas other
sellers report the entire capacity of the facility. Additionally, some sellers include in their
asset lists generation facilities in which they have claimed a familial relationship through
only passive, non-controlling interests.
116.

We propose to clarify that, for the list of assets: (1) a seller must enter the entire

amount of a generator’s capacity (in MWs) in the “Capacity Rating (MW): Nameplate,
128
129

See Appendix B herein for an example of the proposed revised appendix.

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

Docket No. RM14-14-000

Seasonal, or Five-Year Average” column even if the seller only owns part of a facility;
(2) a seller should list only one of the following as a “Use” in the “Asset Name and Use”
column: transmission, intrastate natural gas storage, intrastate natural gas transportation,
or intrastate natural gas distribution; (3) entities and generation assets in which passive
ownership interests have been claimed should not be included in the horizontal market
power indicative screens or reported in the appendix.130 If a seller does not believe that
the entire capacity of a generation facility should be included in its indicative screens, it
may explain its position in the transmittal letter filed with its horizontal market power
screens, including letters of concurrence where appropriate,131 and thus account for only
its portion of that particular generation facility in the indicative screens. However, the
entire capacity of the facility should be reflected in the list of generation assets in the
appendix. We note that generating units within a single plant may be aggregated in a
single row if the information in the other columns is the same for all units, but separate
plants cannot be aggregated in a single row, except for behind-the-meter generation, and
qualifying facilities less than 20 MW, as proposed above. We further clarify that each
asset should be listed only once; if it is owned by more than one affiliate, all affiliate
names should be included in the “Owned By” column. If a company or an affiliate is

130

We note that sellers must demonstrate why such ownership interests should be
deemed passive. See AES Creative Resources, L.P., 129 FERC ¶ 61,239 (2009).
131

See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 187.

Docket No. RM14-14-000

registered in the Commission’s company registration database,132 we propose to clarify
that the name in the asset appendix for that company must appear exactly the same as in
the registration database.
117.

With respect to the “Date Control Transferred” column in both the generation and

transmission asset lists, we clarify that the “Date Control Transferred” column should
identify the date on which a contract that transfers control over a facility becomes
effective. Where appropriate, companies may enter “N/A” in this field to indicate that it
is not applicable to their asset(s).
118.

With respect to the “Size” column in the list of transmission assets, we propose to

clarify that the “Size” refers to both the length of the transmission line (i.e., feet or miles)
and the capability of the line in voltage (kV). We note that companies can aggregate
their transmission assets by voltage. For instance, a utility that owns a transmission
system with several hundred transmission lines might include two rows in the
transmission asset list; one row with 200 miles of 138 kV lines listed in the “Size”
column and another row with 100 miles of 230 kV lines listed in the “Size” column as
long as all the other columns (e.g., owned by, controlled by, balancing authority area,
132

The term “company registration database” here refers to “FERC’s Online
Company Registration application” (see http://www.ferc.gov/docsfiling/etariff/implementation-guide.pdf). However, Commission orders have referred to
this database as we have also issued orders referring to it as “Company Registration,”
(see Filing Via the Internet, Revisions to Company Registration and Establishing
Technical Conference, 142 FERC ¶ 61,097 (2013)) or “Company Registration system”
(see Order Updating Electric Quarterly Report Data Dictionary, 146 FERC ¶ 61,169
(2014)).

Docket No. RM14-14-000

geographic region, etc.) remain the same for all assets aggregated in that row. The name
for such aggregated facilities should describe the lines that are being aggregated, e.g.,
“230 kV transmission lines.”
119.

We seek comment on these proposals.
c.

120.

Changes Regarding OATT Waiver and Citations in
Transmission Assets

The Commission has stated that even if a seller has been granted waiver of the

requirement to file an OATT, those transmission facilities should be reported in its asset
appendix,133 and we believe that this should be reiterated and clarified going forward.
Therefore, we propose to require any seller that has been granted waiver of the
requirement to file an OATT for its facilities134 to report in its list of transmission assets
the citation to the Commission order granting the OATT waiver for those facilities. We
propose to modify the example of the asset appendix found in Appendix B to Subpart H
of Part 35 of the Commission’s regulations to add a new column in the list of
transmission assets for the citation to the Commission order accepting the OATT or
granting waiver of the OATT requirement. This will make the list of transmission assets
consistent with the list of generation assets, which already contains a column for the
133

“We clarify that the transmission facilities that we require to be included in that
asset appendix are limited to those the ownership or control of which would require an
entity to have an OATT on file with the Commission (even if the Commission has
waived the OATT requirement for a particular seller).” Order No. 697-A, FERC Stats.
& Regs. ¶ 31,268 at P 378.
134

See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 408.

Docket No. RM14-14-000

docket number in which market-based rate authority was granted, and will provide a
more complete list of transmission assets to the Commission and the public. Providing
the citation to the Commission order accepting the OATT or granting waiver of the
OATT requirement in the list of transmission assets will facilitate the Commission’s and
market participants’ verification that sellers were granted the appropriate authorizations.
121.

We seek comment on these proposed changes.
d.

122.

Electronic Format

Currently, virtually all of the asset lists are submitted to the Commission using

PDF format. Staff is unable to perform calculations on PDF files, or to search, or sort the
data contained in the lists of assets. Staff therefore frequently transfers the information
included in the lists of assets into spreadsheets for sorting, comparison purposes, and
internal calculations, and has found numerous submission errors from sellers. If the
Commission provided a sample electronic spreadsheet and required sellers to submit the
lists of assets in an electronic spreadsheet, it would reduce filing burdens, improve
accuracy, decrease the number of staff inquiries to sellers regarding submission errors,
and result in a more efficient use of resources.
123.

Therefore, we propose to require market-based rate sellers to submit the

Appendix B asset lists in an electronic spreadsheet format that can be searched, sorted,
and otherwise accessed using electronic tools. We propose to post on the Commission’s
Web site sample lists of assets in formatted electronic spreadsheets and to require sellers

Docket No. RM14-14-000

to submit all required appendices in the form and format of the sample electronic
spreadsheets.135
124.

We further propose to clarify that the lists of assets should not contain any

information other than what is required in the respective columns. For instance, sellers
frequently include footnotes in their appendices that cause the appendices to become
unwieldy and difficult to read or understand. Sellers sometimes explain in these
footnotes that some facilities are partially owned, that some affiliates included in their
lists may not actually be affiliates but are included out of an abundance of caution, or that
a facility is expected to come on-line or off-line at some future date. We discourage any
such footnotes and direct that any such representations be made in the filing transmittal
letter.

125.

An example of the electronic spreadsheet for the appendix with the new columns

and column headings is included as Appendix B herein.
e.
126.

Database

As noted above, we propose to require market-based rate sellers to submit their

lists of assets in an electronic spreadsheet that can be searched, sorted, and otherwise
accessed using electronic tools. In addition, we seek comment whether in the future it
135

If a seller chooses to create its own workable electronic spreadsheet, the file it
submits must have the same format as the sample spreadsheet on the Commission Web
site. Specifically, it must have the same exact columns and descriptive text as the sample
spreadsheet. The 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.

Docket No. RM14-14-000

would be beneficial to develop a comprehensive searchable public database of the
information contained in the asset appendices, which would eventually replace the
pre-formatted spreadsheet. Such an approach would allow market-based rate sellers to
update their asset appendices when circumstances change. We seek input regarding
whether such a database would be useful, how the database might be created,
standardized and maintained, and the frequency with which it should be updated. We
further seek input on the usefulness of including unique identifiers for the affiliate
companies and generation assets in such a database, e.g., the Company Registration
database and the EIA Power Plant Code and Generator ID, respectively, where those IDs
exist. We also seek input on the difficulty of reporting and the usefulness of including in
such a database the percentage each affiliate owns of each of its assets.

127.

We seek comment on these proposals.
E.

Category 1 and Category 2 Sellers
1.

128.

Current Policy

In Order No. 697, the Commission created a category of market-based rate sellers

(Category 1 sellers) that are exempt from the requirement to automatically submit
updated market power analyses. Category 1 sellers include wholesale power marketers
and wholesale power producers that own or control 500 MW or less of generation in
aggregate per region;136 that do not own, operate or control transmission facilities other

136

In Order No. 697, the Commission adopted a regional schedule for the
submission of updated market power analyses based on the balancing authority area in
(continued…)

Docket No. RM14-14-000

than limited equipment necessary to connect individual generating facilities to the
transmission grid (or have been granted waiver of the requirements of Order No. 888);
that are not affiliated with anyone that owns, operates or controls transmission facilities
in the same region as the seller’s generation assets; that are not affiliated with a
franchised public utility in the same region as the seller’s generation assets; and that do
not raise other vertical market power issues.137 Category 2 sellers (those market-based
rate sellers that do not qualify as Category 1 sellers) are required to file regularly
scheduled updated market power analyses.138
129.

In practice, the criteria for Category 1 seller status have been applied differently in

the case of power marketers (i.e., a seller that does not own generation or transmission)
and power producers (i.e., a seller with generation assets).139 The seller category status
for a power marketer is determined by considering all affiliated generation and

which the seller owns or controls generation. The Commission established the following
six geographic regions: Northeast, Southeast, Central, Southwest Power Pool,
Southwest, and Northwest. Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
Appendix D. We provide an updated region map as Appendix D of this NOPR.
137

See id. PP 848-849 n.1000; see also 18 CFR 35.36(a)(2), 35.37(a)(1).

138

18 CFR 35.36(a)(3), 35.37(a)(1).

139

The distinction between the category status of power marketers and power
producers was previously articulated in the March 2010 market-based rate technical
conference. FERC, Technical Conference on Preparation of Market-Based Rate Filings
Quarterly Reports by Public Utilities, Docket No. AD10-4-000 (2010), available at
https://www.ferc.gov/EventCalendar/EventDetails.aspx?ID=5089&CalType=%20&Cale
ndarID=116&Date=03/03/2010&View=Listview).

Docket No. RM14-14-000

transmission, while power producers owning generation or transmission assets only have
to consider affiliated generation if it is located in the same region as the power producer’s
generation assets.
2.
130.

Proposal

We propose to clarify the distinction in determining the seller category status of

power marketers and power producers.140 For purposes of determining seller category
status for each region, a power marketer should include all affiliated generation capacity
in that region. Power producers only need to include affiliated generation that is located
in the same region as the power producer’s generation assets. The reason behind this
distinction is that a power marketer with no generation assets in the ground is assumed to
have no home market; it is thus assumed to be equally likely to make sales in any region.
However, although a power producer has authorization to make sales in other regions, it
is assumed that the majority of its sales will be in the region(s) in which it owns
generation assets.

140

The Commission regulations define Category 1 sellers as “wholesale power
marketers and wholesale power producers that own or control 500 MW or less of
generation in aggregate per region; that do not own, operate or control transmission
facilities other than limited equipment necessary to connect individual generating
facilities to the transmission grid (or have been granted waiver of the requirements of
Order No. 888, FERC Stats. & Regs. ¶ 31,036); 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.”
18 CFR 35.36(a)(2).

Docket No. RM14-14-000
131.

Thus, we propose to clarify that a power marketer with no generation assets may

qualify as a Category 1 seller in any region where: (1) its affiliates own or control, in
aggregate, 500 MW or less of generation capacity; (2) it is not affiliated with anyone that
owns, operates or controls transmission facilities; (3) it is not affiliated with a franchised
public utility; and (4) it does not raise other vertical market power issues. In addition, for
any region where the power marketer’s affiliates are designated as Category 2 sellers, it is
Commission practice that the power marketer is also a Category 2 seller. We note that
the above is consistent with the way in which the Commission has viewed power
marketers since the issuance of Order No. 697.
132.

We also propose to clarify that a power producer may qualify as a Category 1

seller in any region in which the power producer itself owns generation and the power
producer and its affiliates own or control, in aggregate, 500 MW of generation capacity
or less, as long as the power producer is not affiliated with anyone that owns, operates or
controls transmission facilities in that region, is not affiliated with a franchised public
utility in that region, and does not raise other vertical market power issues. In addition,
unlike power marketers, a power producer may qualify as a Category 1 seller in a region
where the power producer itself does not own or control any generation or transmission
assets but where it has affiliates that are Category 2 sellers.141

141

We note that a mitigated seller cannot use an affiliated power producer in
another region as a conduit to sell in a mitigated balancing authority area because all
affiliates of a mitigated seller are prohibited from selling at market-based rates in any
(continued…)

Docket No. RM14-14-000
133.

Therefore, we propose to revise the regulations to clarify that to qualify for

Category 1 status, a seller must meet all of the requirements. Failure to satisfy any of
these requirements results in a Category 2 designation. The proposed change of the text
of 18 CFR 35.36(a)(2) is:
A Category 1 Seller means a Seller that:
(i) Is either a wholesale power marketers that controls or is affiliated with
500 MW or less of generation in aggregate per region or a wholesale power
producers that owns, or controls or is affiliated with 500 MW or less of generation
in aggregate in the same region as its generation assets;
(ii) that do Does not own, operate or control transmission facilities other than
limited equipment necessary to connect individual generating facilities to the
transmission grid (or has have been granted waiver of the requirements of Order
No. 888, FERC Stats. & Regs. ¶ 31,036);
(iii) that are Is not affiliated with anyone that owns, operates or controls
transmission facilities in the same region as the Seller's generation assets;
(iv) that are Is not affiliated with a franchised public utility in the same region as
the Sseller's generation assets; and
(v) that do Does not raise other vertical market power issues.
134.

We seek comment on this proposal.
F.

Corporate Families
1.

Corporate Organizational Charts
a.

135.

Current Policy

The Commission currently requires new and existing market-based rate sellers to

provide written descriptions of their affiliates and corporate structure or upstream
ownership for initial applications for market-based rate authority, updated market power

balancing authority area or market where the seller is mitigated. Order No. 697-A, FERC
Stats. & Regs. ¶ 31,268 at P 335.

Docket No. RM14-14-000

analyses and notices of change in status as a result of new affiliations. In Order No. 697A, the Commission stated:
A seller seeking market-based rate authority must provide information
regarding its affiliates and its corporate structure or upstream ownership.
To the extent that a seller’s owners are themselves owned by others, the
seller seeking to obtain or retain market-based rate authority must identify
those upstream owners. Sellers must trace upstream ownership until all
upstream owners are identified. Sellers must also identify all affiliates.
Finally, an entity seeking market-based rate authority must describe the
business activities of its owners, stating whether they are in any way
involved in the energy industry.[142]
b.
136.

Proposal

We propose to require sellers to provide an organizational chart, in addition to

written descriptions of their affiliates and corporate structure or upstream ownership, for
initial applications for market-based rate authority, updated market power analyses and
notices of change in status reporting new affiliations.
137.

The Commission has seen increasingly complex organizational structures as

private equity funds and other financial institutions take ownership positions in
generation and utilities. The Commission believes that requiring the filing of an
organizational chart for initial applications for market-based rate authority, updated
market power analyses and notices of change in status reporting new affiliations would
make reviewing market-based rate filings more efficient, increase transparency, and
synchronize information about corporate structure that the Commission receives from

142

Id. P 181 n.258.

Docket No. RM14-14-000

sellers with market-based rate authority with similar information that the Commission
receives under section 203 of the FPA.143 We propose to require from market-based rate
sellers an organizational chart similar to that which the Commission requires from section
203 applicants. Specifically, § 33.2(c)(3) of the Commission’s regulations144 provides
that section 203 applicants must include: a description of the applicant, including, among
other things, “[o]rganizational charts depicting the applicant’s current and proposed posttransaction corporate structures (including any pending authorized but not implemented
changes) indicating all parent companies, energy subsidiaries and energy affiliates unless
the applicant demonstrates that the proposed transaction does not affect the corporate
structure of any party to the transaction.” We propose that market-based rate sellers be
required to provide written descriptions of their affiliates and corporate structure or
upstream ownership and an organizational chart depicting the market-based rate seller’s
current corporate structures (including any pending authorized but not implemented
changes) indicating all upstream owners, energy subsidiaries and energy affiliates. We
believe that the increased burden on market-based rate sellers is minimal as most sellers
have this organizational chart available.
138.

Thus, we propose to revise the regulatory text in § 35.37(a)(2) of the

Commission’s regulations as follows:

143

16 U.S.C. 824b.

144

See 18 CFR 33.2(c)(3).

Docket No. RM14-14-000

When submitting a market power analysis, whether as part of an initial application
or an update, a Seller must include an appendix of assets, in the form provided in
Appendix B of this subpart, written descriptions of their affiliates and corporate
structure or upstream ownership, and an organizational chart. The organizational
chart must depict the Seller’s current corporate structure indicating all upstream
owners, energy subsidiaries and energy affiliates.
139.

We also propose that such organizational chart be required for any notice of

change in status involving a change in the ownership structure that was in place the last
time the seller made a market-based rate filing with the Commission. Therefore, we
propose to revise the regulatory text in § 35.42(c) of the Commission’s regulations as
follows:
When submitting a change in status notification regarding a change that impacts
the pertinent assets held by a Seller or its affiliates with market-based rate
authorization, a Seller must include an appendix of assets in the form provided in
Appendix B of this subpart, written descriptions of their affiliates and corporate
structure or upstream ownership, and an organizational chart. The organizational
chart must depict the Seller’s prior and new corporate structures indicating all
upstream owners, energy subsidiaries and energy affiliates unless the Seller
demonstrates that the change in status does not affect the corporate structure and
the Seller’s affiliations.[145]
145

When the changes to § 35.42(c) as proposed here are combined with the
changes to § 35.42(c) proposed above, the revised § 35.42(c) would read as follows:
When submitting a change in status notification regarding a change that impacts
the pertinent assets held by a Seller or its affiliates with market-based rate
authorization, a Seller must include an appendix of all assets, including the new
assets and/or affiliates reported in the change in status, in the form provided in
Appendix B of this subpart, written descriptions of their affiliates and corporate
structure or upstream ownership, and an organizational chart. The organizational
chart must depict the Seller’s prior and new corporate structures indicating all
upstream owners, energy subsidiaries and energy affiliates unless the Seller
demonstrates that the change in status does not affect the corporate structure and
the Seller’s affiliations.

Docket No. RM14-14-000

140.

We seek comment on these proposals.
2.

Single Corporate Tariff
a.

141.

Current Policy

Joint tariffs may be used when a corporate family has more than one affiliated

seller with market-based rate authority.146 Joint tariffs allow corporate families to more
clearly organize their tariff records and simplify their tariff filings. The Commission
explained in Order No. 714 that joint filers are permitted to designate one market-based
rate seller (the designated filer) to file a single tariff (joint master corporate tariff) for
inclusion in the Commission’s eTariff database that reflects the joint tariff for itself and
all affiliated sellers.147 The Commission further explained that all affiliated sellers (i.e.,
the non-designated joint filers) would include in their respective tariff filings a tariff
section consisting of a single page or section that would provide the appropriate name of
the tariff and the identity of the designated filer for the joint tariff. In this way, nondesignated filers incorporate by reference the joint master corporate tariff submitted by
the designated filer, and staff and the general public are able to find quickly the
appropriate joint master corporate market-based rate tariff in the Commission’s eTariff
database.

146

Electronic Tariff Filings, Order No. 714, FERC Stats. & Regs. ¶ 31,276, at
P 60 (2008).
147

See id. P 63.

Docket No. RM14-14-000
142.

Several corporate families have successfully submitted a joint master corporate

market-based rate tariff; however, others have experienced technical and non-technical
difficulties when filing their tariff records into the Commission’s electronic tariff
database. Other corporate families continue to maintain their market-based rate tariffs
separately. Having a joint master corporate market-based rate tariff eases the regulatory
burden on corporate families because only the designated filer is required to submit tariff
revisions, such as when mitigation is changed for the entire corporate family or when
Commission-approved or required language in the tariff needs updating, and results in a
more efficient use of seller and agency resources.
b.
143.

Proposal

We 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. That information
can be found on the Commission’s Web site at
http://www.ferc.gov/industries/electric/gen-info/mbr/tariff/joint.asp.
G.

Clarification of Commission Language in Performing SIL Studies
1.

Current Policy
a.

144.

OASIS Practices

The Commission adopted the requirement that the SIL study be used in both the

indicative screens and the DPT analysis as the basis for establishing the amount of power

Docket No. RM14-14-000

that can be imported into the relevant geographic market.148 The Commission also stated
that the SIL study shown in Appendix E of the April 14, 2004 Order is the only study that
meets this requirement.149
145.

The Commission’s OASIS requirements are intended to ensure that potential

transmission customers receive access to information that will enable them to obtain
transmission service on a non-discriminatory basis from any transmission provider. The
transmission provider’s OASIS provides, among other things, information by electronic
means about ATC for point-to-point service and provides a process for requesting
transmission service.150
b.
146.

SIL Studies and OASIS Practices

In Order No. 697, the Commission found that SIL studies performed by sellers

“should not deviate from” and “must reasonably reflect” the seller’s OASIS operating
practices and “techniques used must have been historically available to customers.”151
Order No. 697 also stated that
148

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 19.

149

Id. (citing April 14, 2004 Order, 107 FERC ¶ 61,018 at Appendix E). The
April 14, 2004 Order predates Order No. 697. However, Order No. 697 largely adopts
the requirements of the April 14, 2004 Order. Id. PP 19, 354-362.
150
151

18 CFR 37.2, 37.6(b).

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354 (citing Market-Based
Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public
Utilities, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,602, at PP 77, 78
(2006)).

Docket No. RM14-14-000

[b]y OASIS practices, we mean sellers shall use the same
OASIS methods and studies used historically by sellers (in
determining simultaneous operational limits on all
transmission lines and monitored facilities) to estimate import
limits from aggregated first-tier control areas into the study
area.152
147.

Furthermore, the April 14, 2004 Order requires that the seller consider “all

internal/external contingency facilities and all monitored/limiting facilities that were used
historically to approximate area-area transmission availability” and utilize scaling
methods “according to the same methods used historically in assessing available
transmission for non-affiliate resources.”153
148.

Similarly, in Pinnacle West,154 the Commission found that “simultaneous

transmission import capability used in the market screens should account for how
transmission is actually provided by the applicant,” explaining that “simultaneous
transmission import capability calculations should be based on actual historic
conditions.”155

152

Id. n.361.

153

April 14 Order, 107 FERC ¶ 61,018 at Appendix E.

154

Pinnacle West Capital Corp., 109 FERC ¶ 61,295 (2004), clarified, 110 FERC
¶ 61,127 (2005) (Pinnacle West). Pinnacle West predates Order No. 697. However,
Order No. 697 largely affirms statements made in Pinnacle West. Order No. 697, FERC
Stats. & Regs. ¶ 31,252 at PP 354-362.
155

Pinnacle West, 110 FERC ¶ 61,127 at P 8.

Docket No. RM14-14-000
149.

Additionally, in Carolina Power & Light, the Commission clarified footnote 361

of Order No. 697, stating that “in performing SIL studies, applicants should follow
OASIS practices historically used by the study area and aggregated first-tier balancing
authority areas.”156
150.

In Puget, the Commission largely reiterated and consolidated direction previously

provided in Order No. 697, the April 14, 2004 Order, Pinnacle West, and Carolina Power
& Light. The Commission clarified that sellers must “[p]rovide copies of all Operating
Guide descriptions that were applied in the Scaling section,” as well as any operating
guides used to ignore limiting elements in the SIL study results.157 In addition, the
Commission stated that applicants must exclude study area non-affiliated load from study
area native load, and should not include first-tier generation serving study area nonaffiliated load in net area interchange.158 Finally, the Commission required that
applicants document all instances where the SIL study differs from historical practices.159

156

Carolina Power & Light Co., 128 FERC ¶ 61,039, at P 7 (Carolina Power
& Light), clarified, 129 FERC ¶ 61,152 (2009).
157

Puget, 135 FERC ¶ 61,254 at Appendix B, Reporting Requirements for
Submittals 8, 9.
158

Id. at Reporting Requirements for Submittal 10.

159

Id. at Reporting Requirements for Submittal 11.

Docket No. RM14-14-000
151.

The April 14, 2004 Order further requires that power flow benchmark cases

should represent “operational practices historically used” and “reasonably simulate the
historical conditions that were present.”160 Historical conditions include
facility/line deratings used to maintain capacity benefit
margins (CBM) and transmission reliability (TRM/CBM),
actual unit dispatch used to fulfill network and firm
reservation obligation, the actual peak demand, generator
operating limits opposed on all resources in real time, other
limits/constraints imposed by the [Transmission Provider] TP
during the season peaks.[161]
152.

In addition, Order No. 697 requires that power flow cases “represent the

transmission provider’s tariff provisions and firm/network reservations held by
seller/affiliate resources during the most recent seasonal peaks.”162
153.

In Puget, the Commission stated that “[l]ong-term firm transmission reservations

for applicant/affiliate generation resources that serve study area load reduce the amount
of study area transmission capability available to potential competitors” and that
“[f]ailing to properly account for such reservations is inconsistent with the Commission’s
methodology for calculating SIL values.”163

160

April 14, 2004 Order, 107 FERC ¶ 61,018 at Appendix E.

161

Id.

162

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354.

163

Puget, 135 FERC ¶ 61,254 at P 15.

Docket No. RM14-14-000
154.

In addition, the Commission stated that the transmission capability associated with

study area long-term firm import transmission reservations also must be subtracted from
the study area’s native load to accurately represent the amount of study area native load
available to be served by first-tier area generation.164 This direction is reflected in Row 8
of Submittal 1 found in Appendix B of Puget.165
c.
155.

Simultaneous TTC

Order No. 697 allows the use of simultaneous TTC values in performing SIL

studies. The Commission stated that this was permissible “provided that these TTCs are
the values that are used in operating the transmission system and posting availability on
OASIS.” The Commission required sellers to provide evidence that simultaneous TTC
values account for simultaneity, internal and first-tier external transmission limitations,
and transmission reliability margins; and are used in operating the transmission system
and posting availability on OASIS.166
156.

In Order No. 697-A, the Commission clarified that “the use of simultaneous TTC

values in the SIL study must properly account for all firm transmission reservations,
transmission reliability margin, and capacity benefit margin.”167

164

Id. P 16.

165

Id. at Appendix B.

166

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 364.

167

Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 142.

Docket No. RM14-14-000
2.
157.

Proposal

We propose to provide clarification regarding several issues that have arisen

regarding the proper way to perform SIL studies. In particular, the we propose
clarification on issues relating to what is included in “OASIS practices,” how to deal with
conflicts between OASIS practices and the Commission directions provided in
Appendix B of Puget, and the correct load value to use in the SIL study.
158.

The purpose of the SIL study is to calculate the total simultaneous import

capability available to first-tier uncommitted generation resources, while also considering
system limitations and existing resource commitments (i.e., long-term firm transmission
reservations). Therefore, the methodology a transmission provider uses to calculate
simultaneous TTC values168 must be consistent with the methodology used for
calculating and posting ATC and for evaluation of firm transmission service requests,
consistent with Commission policy and precedent. Import capability available to a
transmission provider during real-time operations should not be included in the
transmission provider’s SIL value if such import capability is not available to nonaffiliated uncommitted generation resources requesting long-term firm transmission
service. The following clarifications are therefore proposed.

168

See Row 4 of proposed Submittal 1 (Total Simultaneous Transfer Capability).

Docket No. RM14-14-000
a.
159.

95
OASIS Practices

As discussed above, the methodology a transmission provider uses to calculate

SIL values must be consistent with the methodology it uses for calculating and posting
ATC169 and for evaluating transmission service requests. We propose the following
clarifications:
160.

We propose to clarify that the term “OASIS practices” refers specifically to the

seasonal benchmark power flow case modeling assumptions, study solution criteria,170
and operating practices historically used by the first-tier and study area transmission
providers171 to calculate and post ATC and to evaluate requests for firm transmission
service.172

169

Section 15.2 (Determination of Available Transfer Capability) of the pro forma
OATT states “[i]n the event sufficient transfer capability may not exist to accommodate a
service request, the Transmission Provider will respond by performing a System Impact
Study.” See Preventing Undue Discrimination and Preference in Transmission Service,
Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, FERC
Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299
(2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228 (2009), order on
clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).
170

Study solution criteria may include but are not limited to distribution factor
thresholds, transformer tap adjustments, reactive power limits, transmission equipment
ratings, and model solution settings.
171

We reiterate that, while entities may not be familiar with all of the OASIS
practices of transmission providers in first-tier balancing authority areas, they should at
least be familiar with major constraints, path limits, and delivery problems in neighboring
transmission systems. See Order No. 697, FERC Stats. & Regs ¶ 31,252 at P 354 n.361.
172

While the OASIS practices associated with non-firm transmission service may
result in a higher SIL value, the interruptible nature of such service makes it
(continued…)

Docket No. RM14-14-000
161.

Second, we propose to clarify that in performing a SIL study the transmission

provider must utilize its OASIS practices consistent with the administration of its tariff.
The seasonal benchmark power flow cases submitted with a SIL study should represent
historical operating practices only to the extent that such practices are available to
customers requesting firm transmission service. For example, if the transmission
provider does not allow the use of an operating guide when evaluating firm transmission
service requests, the transmission provider should not be allowed to use the operating
guide when calculating SIL values.173
b.
162.

SIL Studies and OASIS Practices

Where there is a conflict between the transmission provider’s tariff or OASIS

practices and the directions specified in the Puget order for performing SIL studies, we
propose to clarify that sellers should follow OASIS practices except as noted below.
Sellers are reminded that, in instances where actual OASIS practices differ from the SIL
direction provided in Puget, sellers should both use actual OASIS practices and provide
inappropriate as a measure of uncommitted generation capacity in the first-tier available
to compete in the study area.
173

By “operating guide” we are generally referring to the NERC defined term
“Operating Procedure,” which is defined as “a document that identifies specific steps or
tasks that should be taken by one or more specific operating positions to achieve specific
operating goal(s).” See NERC, Glossary of Terms Used in NERC Reliability Standards
53 (2014),
http://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf. In
the SIL study context, this may include switching procedures, special protection systems,
load throw-over schemes, temporary transmission line rating changes, and other actions
that are not typically represented in the seasonal benchmark power flow models.

Docket No. RM14-14-000

documentation specifically identifying such practices.174 We propose to clarify that to the
extent that a seller’s SIL study departs from actual OASIS practices,175 such departures
are only permitted where use of actual OASIS practices is incompatible with an analysis
of import capability from an aggregated first- tier area. We invite comments identifying
potential areas where actual OASIS practices may be incompatible with the performance
of SIL studies.
163.

Further, we remind sellers that the calculated SIL value should account for any

limits defined in the tariff, such as stability or voltage.176 If a seller utilizes a direct
current analysis when performing a SIL study, but an alternating current analysis when
evaluating transmission service requests, the seller must validate the total aggregate
transfer level value, consistent with the transmission provider’s OASIS practices, if
modeled using an alternating current load flow model.177

174

See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 356.

175

See Puget, 135 FERC ¶ 61,254 at Appendix B.

176

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 346.

177

See Pinnacle West Capital Corporation, 117 FERC ¶ 61,316, at P 11 n.19
(2006) (“The resulting loading and voltages for the limiting cases, if derived from DC
(direct current) load flow analysis would have been verified by AC (alternating current)
load flow analysis and demonstrated to be within the applicable system operating limits
as dictated by thermal, voltage or stability considerations to ensure system reliability.
The Commission requires that such comparisons be included in the applicant’s working
papers that are submitted to the Commission.”).

Docket No. RM14-14-000
164.

We also reiterate that sellers may use load scaling to perform a SIL study if they

use load scaling in their OASIS practices, “provided they submit adequate support and
justification for the scaling factor used in their load shift methodology and how the
resulting SIL number compares had the company used a generation shift
methodology.”178
165.

Further, we propose to clarify that when properly accounting for long-term firm

transmission reservations for generation resources that serve study area load, sellers must
reduce the simultaneous TTC value179 by subtracting all long-term firm import
transmission reservations.180 The Commission has already provided guidance with
respect to accounting for long-term firm transmission reservations into the study area
from affiliated generation resources located outside the study area.181 The proposed
revised Appendix A Standard Screen Format accounts for all long-term firm import
transmission reservations into the study area.182 Therefore, we propose to direct
178

Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 145.

179

The revised Standard Screen Format (e.g., Rows B1 and M1 in the market
share screen (Long-Term Firm Purchases (from outside the study area))) must reflect
the long-term firm reservations from Submittal 1, Table 1, Row 5 of Puget. Puget,
135 FERC ¶ 61,254 at Appendix B.
180

See Revised Appendix E, Submittal 1, Row 5.

181

Puget, 135 FERC ¶ 61,254 at P 15.

182

See Revised Appendix A, Standard Screen Format, specifically Rows A1, B1,
E1 and F1 in the market share screen and Rows A1, B1, L1 and M1 in the pivotal
supplier screen.

Docket No. RM14-14-000

applicants to subtract all long-term firm import transmission reservations, including
reservations held by non-affiliated sellers, from the simultaneous TTC value. We
propose revisions to Submittal 2 to account for these non-affiliate long-term firm
reservations. Accounting for all long-term firm reservations ensures that the
determination of the SIL study value is consistent with the method used to allocate this
value to uncommitted generation capacity in the aggregated first-tier area for the
indicative screens. Sellers should refer to Submittal 1 for further information.
166.

Finally, we propose to clarify that sellers must account for wheel through

transactions where such transactions are used to serve a non-affiliated load that is
embedded within a study area. Specifically, the seller should reduce the simultaneous
TTC value by subtracting the value of all wheel-through transactions. These transactions
should be accounted for as long-term firm import transmission reservations, and reported
in Submittal 2. We propose revisions to Submittal 2 to account for wheel-through
transactions. While such generation is not used to serve study area load, it still reduces
the amount of transmission capability available to first-tier generators competing to serve
study area load.
167.

We propose to clarify that, where a first-tier market or balancing authority area is

directly interconnected to the study area only by controllable tie lines183 and is not
183

Controllable tie lines include DC transmission facilities and AC transmission
facilities with the ability to control the magnitude and direction of power flows through

(continued…)

Docket No. RM14-14-000

100

interconnected to any other first-tier market or balancing authority area, sellers should
follow their OASIS practices regarding calculation and posting of ATC for such areas. If
sellers’ OASIS practices are incompatible with the SIL study (e.g., ATC is based on tie
line rating), sellers may use an alternative process to account for import capability for
such tie lines. We propose to further clarify that, in such circumstances, it will be
presumed reasonable to model a controllable tie line as a single equivalent first-tier
generator connected to the study area by a radial line with a rating equal to the rating of
the controllable tie line. Sellers should document any instances where modeling of
controllable tie lines deviates from OASIS practices, and explain such deviations,
including: how tie line flow is accounted for in net area interchange; how tie line flow is
scaled or otherwise controlled when calculating simultaneous incremental transfer
capability; and how to account for long-term firm transmission reservations over
controllable tie lines.
168.

To the extent that the study area is directly interconnected to first-tier areas by

controllable merchant transmission lines (e.g., Linden VFT), sellers should properly
account for capacity rights on such lines. If sellers hold long-term capacity rights on such
lines, these rights should be accounted for as long-term firm transmission reservations. If
sellers lack sufficient knowledge regarding the existence and attributes of capacity rights

equipment such as converters, phase shifting transformers, variable frequency
transformers, etc.

Docket No. RM14-14-000

101

on controllable merchant lines, they shall assume the full capacity of such lines is held by
sellers with long-term firm transmission reservations.
169.

As an initial matter, we reiterate that the SIL study is “intended to provide a

reasonable simulation of historical conditions” and is not “a theoretical maximum import
capability or best import case scenario.”184 Order No. 697 stated that the SIL study “is a
study to determine how much competitive supply from remote resources can serve load
in the study area.”185 The Commission clarified in Puget that sellers should not report
study area non-affiliated load as study area native load, and should adjust modeled net
area interchange by the same amount.186 However, the exclusion of all study area nonaffiliated load may result in SIL values that are inconsistent with the intent of the
indicative screens. Furthermore, in the event the SIL value is limited by study area load,
restricting study area load to affiliated load fails to account for import capability that may
be used to serve wholesale load customers. Therefore, we propose to require sellers to
include all load associated with balancing authority area(s) within the study area. Sellers
should only adjust the reported value for modeled net area interchange to account for
first-tier generation serving load associated with a first-tier balancing authority area that
184

Id. P 361.

186

Puget, 135 FERC ¶ 61,254 at Appendix B.

Docket No. RM14-14-000

102

is modeled as part of the study area.187 To ensure Submittal 1 is consistent with these
requirements, we propose to revise Row 8 to read “Adjusted Historical Peak Load”
(instead of “Study area adjusted native load”).
170.

We are also looking for consistent, reported load values for all sellers to use in

preparing SIL studies. Puget, Appendix B, Submittal 1 requires sellers to use FERC
Form No. 714 load values or explain the source of the data used. Some sellers have
commented that the load values in their models differ from Form No. 714 data and have
sought to rely on data from sources other than FERC Form No. 714. We seek industry
comment on what sources other than FERC Form No. 714 may be appropriate sources to
rely on in determining historical peak load.
171.

We clarify that the values provided in Submittal 1 should generally be supported

by the submitted seasonal benchmark power flow models. In particular, we expect that
Row 1 (Simultaneous Incremental Transfer Capability), Row 2 (Modeled Net Area
Interchange), and Row 4 (Total Simultaneous Transfer Capability) should agree with the
corresponding values from the seasonal benchmark power flow models. Any differences
should be explained by the seller. We propose to update Submittal 1, as reflected in

187

If the load is modeled as part of another area, i.e., as a non-area load attached to
an area bus, and the net area interchange calculation includes both tie lines and non-area
loads attached to area buses, net area interchange associated with service to such load
should be approximately zero, and no adjustment will be necessary.

Docket No. RM14-14-000

103

Appendix E to this NOPR, to provide additional clarity on the expected values for certain
rows.188 We propose to post a new version of Submittal 1 on the Commission’s Web site.
c.
172.

Simultaneous TTC

We propose to define standard guidance for data submittals and representations

that sellers using the simultaneous TTC method must provide to the Commission. First,
sellers must provide 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. Sellers should identify the date and hour from which
simultaneous TTC values were calculated. Sellers may use the maximum sum of TTC
values for any day and time during each season, so long as they also demonstrate that
these TTC values are simultaneously feasible. Sellers may demonstrate that simultaneous
TTC values are simultaneously feasible by performing a power flow study that verifies
that the declared simultaneous TTC value is simultaneously feasible while accounting for
all internal and external transmission limitations supplied in Appendix E and Puget.
Sellers may also provide expert testimony explaining how the specific criteria and
procedures used to calculate posted TTC values result in TTC values that are
simultaneously feasible.

173.

We reiterate that, in the event there are limited interconnections between first-tier

markets, the Commission will review evidence that potential loop flow between first-tier

188

See Revised Appendix E, Submittal 1.

Docket No. RM14-14-000

104

areas is properly accounted for in the underlying SIL values on a case-by-case basis.189
However, 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, as this does not preclude internal transmission limitations from
limiting the simultaneous TTC below the sum of individual path TTC values.
174.

We seek comment on these proposals.
H.

Parts 101 and Part 141 Waivers
1.

175.

Current Policy

As noted in Order No. 697, the Commission has granted certain entities with

market-based rate authority, such as power marketers and independent or affiliated power
producers, waiver of the Commission’s Uniform System of Accounts requirements,
specifically waiver of Parts 41, 101, and 141 of the Commission’s regulations, except
§§ 141.14 and 141.15.190 The Commission found that the costs of complying with the
Uniform System of Accounts requirements, and specifically Parts 41, 101, and 141 of the
Commission’s regulations, outweigh any incremental benefits of such compliance where
the seller only transacts at market-based rates.191 However, the Commission typically

189

Atlantic Renewables Projects II, 135 FERC ¶ 61,227, at P 9 (2011).

190

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 976, 984.

191

Id. P 985 (noting that the Commission has “previously stated that Parts 41, 101
and 141 prescribe certain accounting and reporting requirements that focus on the assets
that a utility owns, and waiver of these requirements is appropriate where the utility ‘will
not own any such assets, its jurisdictional facilities will be only corporate and
(continued…)

Docket No. RM14-14-000

105

does not grant market-based rate sellers waiver of §§ 141.14 and 141.15 of the
Commission’s regulations, which address certain reporting requirements applicable to
hydropower licensees.192
2.
176.

Proposal

We clarify here that any waiver of Part 101 granted to a market-based rate seller is

limited such that the waiver of the provisions of Part 101 that apply to hydropower
licensees is not granted with respect to licensed hydropower projects. Hydropower
licensees are required to comply with the requirements of the Uniform System of
Accounts pursuant to 18 CFR Part 101 to the extent necessary to carry out their
responsibilities under Part I of the FPA, particularly sections 4(b), 10(d) and 14 of the
FPA.193 We further note that a licensee’s status as a market-based rate seller under Part II

documentary, its costs will be determined by utilities that sell power to it, and its earnings
will not be defined and regulated in terms of an authorized return on invested capital’”).
192

See Electron Hydro, LLC, 144 FERC ¶ 61,161, at P 23 (2013).

193

In Trafalgar Power Inc., 87 FERC ¶ 61,207, at 61,798 n.46 (1999) (Trafalgar
Power), the Commission stated:
Under [s]ection 14 of the FPA, the Federal government may take over a project
upon expiration of the project’s licensee, conditioned upon the government’s
payment to the licensee of the ‘net investment of the licensee in the project or
projects taken.’ Section 4(b) requires licensees to file a statement showing the
‘actual legitimate original cost of construction of such project’ to enable the
Commission to determine ‘the actual legitimate cost of and the net investment in’
the project. Section 10(d) requires licensees to establish an amortization reserve
account that will reflect excess or surplus earnings of their licensed project if such
earnings have accumulated in excess of a reasonable rate of return upon the ‘net
investment’ in the project during a period beginning after the first twenty years of
(continued…)

Docket No. RM14-14-000

106

of the FPA does not exempt it from accounting responsibilities as a licensee under Part I
of the FPA.194 Thus, hydropower licensees that received waiver of Part 101 of the
Commission’s regulations as part of their market-based rate applications under Part II of
the FPA are cautioned that such waivers do not relieve them of their obligations to
comply with the Uniform System of Accounts to the extent necessary to carry out their
responsibilities under Part I of the FPA with respect to their licensed projects.
177.

We further direct market-based rate sellers that own licensed hydropower projects

to ensure that their market-based rate tariffs reflect appropriate limitations on any waivers
that previously have been granted. Specifically, to the extent that the hydropower
licensee has been granted waiver of Part 101 as part of its market-based rate authority, the
licensee’s market-based rate tariff limitations and exemptions section should be revised
to provide that the seller has been granted waiver of Part 101 of the Commission’s
regulations with the exception that waiver of the provisions that apply to hydropower
licensees has not been granted with respect to licensed hydropower projects. Similarly,
to the extent that a hydropower licensee has been granted waiver of Part 141 as part of its
market-based rate authority, it should ensure that the limitation and exemptions section of
operations. Pursuant to [s]ection 10 (d) of the FPA the amount transferred to the
amortization reserve may be used to reduce a licensee’s net investment in the
project, and if, after expiration of the license, the government takes over the
project under [s]ection 14, it will be required to compensate the licensee for its net
investment in the project, reduced by the amortization reserve for the project.
194

See Seneca Gen., LLC, 145 FERC ¶ 61,096, at P 23 n.20 (2013) (citing
Trafalgar Power, 87 FERC ¶ 61,207, at 61,798).

Docket No. RM14-14-000

107

its market-based rate tariff specifies that waiver of Part 141 has been granted, with the
exception of §§ 141.14 and 141.15 (which pertain to the filing by hydropower licensees
of Form No. 80, Licensed Hydropower Development Recreation Report, and the Annual
Conveyance Report).195
178.

These market-based rate tariff compliance filings are to be made the next time the

hydropower licensee proposes a change to its market-based rate tariff, files a notice of
change in status pursuant to 18 CFR 35.42, or submits an updated market power analysis
in accordance with 18 CFR 35.37. In addition, going forward, any market-based rate
seller requesting waivers of Parts 101 and/or 141 should include these limitations in their
market-based rate tariffs, regardless of whether they own any licensed hydropower
projects. This will ensure that hydropower licensees understand the limitations on Parts
101 and 141 waivers. To the extent that the market-based rate seller is not a licensee,
these limitations should not have any effect as they only deny waiver of certain
provisions affecting licensees. If a market-based rate seller becomes a hydro licensee
after it receives market-based rate authority, it must file revisions to its market-based rate
tariff to reflect the limitations in its Parts 101 and 141 waivers within 30 days of the
effective date of its license.

195

See Domtar Maine, LLC, 133 FERC ¶ 61,207, at P 23 (2010).

Docket No. RM14-14-000
I.

Miscellaneous
1.

179.

108

Regional Reporting Schedule

Section 35.37(a)(1) of the Commission’s regulations requires Category 2 sellers to

submit a market power analysis “every three years, according to the schedule contained
in Order No. 697.”196 The Commission stated in Order No. 697 that Category 2 sellers
“will be required to file an updated market power analysis based on the schedule in
Appendix D.”197 Concurrent with the issuance of this NOPR, we will post on the
Commission’s Web site an updated version of the schedule. Additionally, we propose to
revise § 35.37(a)(1) as follows:
In addition to other requirements in subparts A and B, a Seller must submit a
market power analysis in the following circumstances: when seeking market-based
rate authority; for Category 2 Sellers, every three years, according to the schedule
contained in Order No. 697, FERC Stats. & Regs. ¶ 31,252posted on the
Commission’s Web site; or any other time the Commission directs a Seller to
submit one. Failure to timely file an updated market power analysis will constitute
a violation of Seller's market-based rate tariff.
180.

We also include an updated region map in Appendix D of this NOPR.
2.

181.

Affirmative Statement

In Order No. 697, as part of the vertical market power analysis, the Commission

stated that it would require sellers to make an affirmative statement that they have not
erected barriers to entry into the relevant market and will not erect barriers to entry into

196

18 CFR 35.37(a)(1).

197

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 850.

Docket No. RM14-14-000

109

the relevant market.198 This requirement is codified at § 35.37(e)(4): “In addition, a
Seller is required to make an affirmative statement that it has not erected barriers to entry
into the relevant market and will not erect barriers to entry into the relevant market.”199
In Order No. 697, the Commission stated that the obligation applies both to the seller and
its affiliates, but is limited to the geographic market(s) in which the seller is located.200
However, many sellers have not mentioned their affiliates when making their affirmative
statements. Therefore, we propose to revise § 35.37(e)(4) (which is proposed elsewhere
in this NOPR to be renumbered as § 35.37(e)(3)), as follows to make clear that the
affirmative statement requirement applies to the seller and its affiliates:
A Seller must ensure that this information is included in the record of each new
application for market-based rates and each updated market power analysis. In
addition, a Seller is required to make an affirmative statement that it and its
affiliates have has not erected barriers to entry into the relevant market and will
not erect barriers to entry into the relevant market.
IV.

Information Collection Statement

182.

The information collection requirements contained in this proposed rule are

subject to review by the Office of Management and Budget (OMB) under section 3507(d)
of the Paperwork Reduction Act of 1995 (PRA).201 The OMB regulations require

198

Id. P 447.

199

18 CFR 35.37(e)(4).

200

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 447.

201

44 U.S.C. 3507(d) (2012).

Docket No. RM14-14-000

110

approval of certain reporting and recordkeeping requirements (collections of information)
imposed by agency rules.202 Upon approval of a collection of information, OMB will
assign an OMB control number and expiration date. Respondents subject to the filing
requirements of this rule will not be penalized for failing to respond to this collection of
information unless the collection of information displays a valid OMB control number.
183.

Comments are solicited on the Commission’s need for this information, whether

the information will have practical utility, the accuracy of the provided burden estimate,
ways to enhance the quality, utility, and clarity of the information to be collected, and any
suggested methods for minimizing the respondent’s burden,203 including the use of
automated information techniques.
Calculated Burden

184.

We propose to clarify and streamline the Commission’s regulations, and to reduce

the burden on entities seeking to obtain or retain market-based rate authority by revising
existing market-based rate requirements under Subpart H to Part 35 of Title 18 of the
Code of Federal Regulations. Specifically, as discussed below, three significant filing
burdens will be reduced or eliminated by the proposed rule due to (1) eliminating the
requirement for sellers in an RTO to file indicative screens; (2) creating a threshold for
202
203

5 CFR 1320.11.

The Commission defines burden as the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or provide information to
or for a Federal agency. For further explanation of what is included in the information
collection burden, reference 5 CFR 1320.3.

Docket No. RM14-14-000

111

reporting new affiliations only if they result in a 100 MW or more cumulative change in
generation capacity; and (3) discontinuing land acquisition reporting requirements for
market-based rate sellers. As discussed below, other amendments in the proposed rule
also are expected to reduce the filing burden on market-based rate sellers, but to a lesser
extent.
185.

Section 35.37 of the Commission’s regulations currently requires market-based

rate sellers to submit a horizontal market power analysis when seeking to obtain or retain
market-based rate authority.204 We propose to implement a streamlined procedure that
will eliminate the requirement to file the indicative screens as part of a horizontal market
power analysis for any seller in an RTO if the seller is relying on Commission-approved
monitoring and mitigation to mitigate any potential market power it may have.
Eliminating the requirement for RTO sellers to file indicative screens will reduce the
burden of filing a horizontal market power analysis for a large portion of market-based
rate sellers when filing updated market power analyses, initial applications for marketbased rate authority, and notices of change in status.
186.

We propose to further reduce the filing burden on market-based rate sellers by

adopting a reporting threshold of a 100 MW cumulative net change in generation
capacity for reporting changes in status regarding new affiliations. This change applies
the 100 MW reporting threshold for new generation in 18 CFR 35.42(a)(1) to the
204

18 CFR 35.37.

Docket No. RM14-14-000

112

reporting requirement for new affiliations in 18 CFR 35.42(a)(2). Under this proposed
change, we expect that market-based rate sellers will file fewer changes in status, instead
of reporting multiple acquisitions of small newly-affiliated generators in one filing.
Given that a change in status filing typically includes a transmittal letter and a revised
asset appendix and may also include indicative screens, we expect this change to reduce
burdens on market-based rate sellers.
187.

Section 35.42(d) of the Commission’s regulations currently requires that all

market-based rate sellers report on a quarterly basis the acquisition of site(s) that have the
potential to be developed for new generation capacity of 100 MWs or more.205 The
Commission proposes to eliminate the burden on all market-based rate sellers by
discontinuing the quarterly land acquisition reporting requirement in § 35.42(d). The
Commission also proposes to eliminate the provision in § 35.37(e)(2) requiring reporting
of sites for generation capacity development as part of the vertical market power analysis.
Other Changes in Burden
188.

In addition to the elimination of significant burdens to market-based rate sellers

discussed above, we propose to revise a number of current market-based rate
requirements in 18 CFR Part 35 to provide greater clarity to entities seeking to acquire
and retain market-based rate authority. These revisions are expected to: (1) reduce the
need for clarification phone calls from market-based rate sellers and subsequent follow205

18 CFR 35.42(d).

Docket No. RM14-14-000

113

up phone calls from staff; (2) reduce amendments filed to correct errors and the related
processing delays; and (3) streamline existing requirements, thereby reducing the burden
in future filings. We estimate that such measures will typically reduce burdens on
market-based rate sellers. Some simplifications to the existing market-based rate
requirements may create an initial, minimal one-time implementation burden for marketbased rate sellers when the filing is first submitted.
189.

The Commission is also making a few minor additions to the current requirements.

These proposed additions include: (a) providing organization charts (for initial
applications for market-based rate authority, updated market power analyses and notices
of change in status reporting new affiliations); (b) splitting some entries in Appendix A to
provide more detail;206 (c) citing the Order accepting the OATT in Appendix B; and (d)
amendments to Submittal 2 to account for non-affiliate long-term firm reservations and
wheel-through transactions.
190.

However, any increases in burden (for the initial filing, such as downloading the

new proposed spreadsheets, as well as ongoing additions) are expected to be greatly
outweighed by the reduction in burden.

206

For example, we propose to split Row A (Installed Capacity) in the existing
pivotal supplier screen into Row A (Installed Capacity (from inside the study area)) and
Row A1 (Remote Capacity (from outside the study area)), with similar changes being
made to currently defined Rows B, E, and F. Similar changes are proposed for the same
rows in the market share screen.

Docket No. RM14-14-000

114

Public Reporting Burden: The Commission recently issued notices on the burden
estimate for FERC-919.207 The estimated total annual burden of 85,444 hours includes:
 Market power analysis in new applications for market-based Rates [18 CFR
35.37(a)], 53,250 hours;
 Triennial market power analysis in Category 2 seller updates [18 CFR 35.37(a)],
20,750 hours;
 Quarterly land acquisition reports [18 CFR 35.42(d)], 3,208 hours; and
 Change in status reports [18 CFR 35.42(a)], 8,236 hours.
191.

In comparison, the total burden estimate for all market-based rate sellers after the

Proposed Rule goes into effect is expected to be significantly lower. The total cost for
market-based rate sellers after revising the market-based rate requirements is expected to
be as follows:208

FERC-919, burden after implementation of proposals in NOPR in Docket No.
RM14-14

207

The Commission issued notices requesting comment in Docket No. IC14-2000. See 78 FR 62,006 (Oct. 11, 2013); 79 FR 818 (Jan. 7, 2014). The FERC-919 and
related burden estimates were approved by OMB on February 27, 2014.
208

Order No. 697 included the burden for Appendix A Parts I and II. The burden
was not modified when Appendix A Part II was inadvertently omitted in Order
No. 697-A; the burden related to Appendix A Part II continues to be included in the
FERC-919.

Docket No. RM14-14-000

New applications
for market-based
rates [18 CFR
35.37], With
Screens
New applications
for market-based
rates [18 CFR
35.37], No
Screens
Triennial market
power analysis in
Category 2 seller
updates [18 CFR
35.37], With
Screens
Triennial market
power analysis in
Category 2 seller
updates [18 CFR
35.37], No
Screens
Quarterly land
acquisition reports
[18 CFR 35.42(d)]
Change in status
reports [18 CFR
35.42(a)], With
Screens
Change in status
reports [18 CFR
35.42(a)], No
Screens
TOTAL

115

Number of
Respondents
(A)

Number of
Responses
Per
Respondent
(B)

Total
Number
of
Responses
(A) x (B)
=(C)

Average Estimated
Burden
Total
Hours
Annual
per
Burden
Response
Hours
(D)
(C)x(D)

107

250

26,750

106

120

12,720

250

10,500

120

4,920

250

3,250

224

4,480
62,620

Docket No. RM14-14-000
192.

116

After implementation of the proposed changes, the total estimated annual cost

burden to respondents is $5,497,409.80 [62,620 hours * $87.79209) = $5,497,409.80].
This represents a reduction in total annual burden for FERC-919 of 22,824 hours210 (to
62,620 hours from 85,444 hours) or a 27 percent reduction.
Title: Proposed Revisions to Market Based Rates for Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by Public Utilities (FERC-919).
Action: Revision of Currently Approved Collection of Information.
OMB Control No.: 1902-0234
Respondents for this Rulemaking: Public utilities, wholesale electricity sellers,
businesses, or other for profit and/or not for profit institutions.
Frequency of Responses:
Initial Applications: On occasion.

209

The Commission estimates this figure based on the Bureau of Labor Statistics
data (for the Utilities sector, at http://www.bls.gov/oes/current/naics2_22.htm, plus
benefits information at http://www.bls.gov/news.release/ecec.nr0.htm). The salaries
(plus benefits) for the three occupational categories are:
•
•
•

Economist: $74.29/hour
Electrical Engineer: $60.70/hour
Lawyer: $128.39/hour

The average hourly cost of the three categories is $87.79
[($74.29+$60.70+$128.39)/3].
210

This includes reductions for: new applications for market-based rates of
13,780 hours; triennial market power analysis of 5,330 hours; quarterly land acquisition
reports of 3,208 hours; and change in status reports of 506 hours.

Docket No. RM14-14-000

117

Updated Market Power Analyses: Updated market power analyses are filed every
three years by Category 2 sellers seeking to retain market-based rate authority.
Land Acquisitions: We propose to eliminate this requirement under the proposed rule.
Change in Status Reports: On occasion.
Necessity of the Information:
Initial Applications: In order to retain market-based rate authority, the Commission must
first evaluate whether a seller has the ability to exercise market power. Initial
applications help inform the Commission as to whether an entity seeking market-based
rate authority lacks market power, and whether sales by that entity will be just and
reasonable.
Updated Market Power Analyses: Triennial updated market power analyses allow the
Commission to monitor market-based rate authority to detect changes in market power or
potential abuses of market power. The updated market power analysis permits the
Commission to determine that continued market-based rate authority will still yield rates
that are just and reasonable.
Change in Status Reports: The change in status requirement permits the Commission to
ensure that rates and terms of service offered by market-based rate sellers remain just and
reasonable.
Internal Review: The Commission has reviewed the reporting requirements and made a
determination that revising the reporting requirements will ensure the Commission has
the necessary data to carry out its statutory mandates, while eliminating unnecessary

Docket No. RM14-14-000

118

burden on industry. The Commission has assured itself, by means of its internal review,
that there is specific, objective support for the burden estimate associated with the
information requirements.
Interested persons may obtain information on the reporting requirements by contacting
the following: Federal Energy Regulatory Commission, 888 First Street, NE,
Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director,
e-mail: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873]. Please
send comments concerning the collection of information and the associated burden
estimates to the Commission, and to the Office of Management and Budget, Office of
Information and Regulatory Affairs, Washington, DC 20503 [Attention: Desk Officer
for the Federal Energy Regulatory Commission, phone: (202) 395-4638, fax: (202) 3957285]. For security reasons, comments to OMB should be submitted by e-mail to:
oira_submission@omb.eop.gov. Comments submitted to OMB should include Docket
Number RM14-14, FERC-919, and OMB Control Number 1902-0234.
V.

Environmental Analysis

193.

The Commission is required to prepare an Environmental Assessment or an

Environmental Impact Statement for any action that may have a significant adverse effect
on the human environment.211 The Commission has categorically excluded certain

211

Regulations Implementing the National Environmental Policy Act of 1969,
Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations
Preambles 1986-1990 ¶ 30,783 (1987).

Docket No. RM14-14-000

119

actions from this requirement as not having a significant effect on the human
environment.212 The actions proposed here fall within the categorical exclusions in the
Commission’s regulations for rules that are clarifying, corrective, or procedural, or do not
substantially change the effect of legislation or regulations being amended.213 In addition,
the proposed rule is categorically excluded as an electric rate filing submitted by a public
utility under sections 205 and 206 of the FPA.214 As explained above, this proposed rule,
which addresses the issue of electric rate filings submitted by public utilities for marketbased rate authority, is clarifying in nature. Accordingly, no environmental assessment is
necessary and none has been prepared in this NOPR.
VI.

Regulatory Flexibility Act

194.

The Regulatory Flexibility Act of 1980 (RFA)215 generally requires a description

and analysis of proposed rules that will have significant economic impact on a substantial
number of small entities. The RFA mandates consideration of regulatory alternatives that
accomplish the stated objectives of a proposed rule and that minimize any significant
economic impact on a substantial number of small entities. The Small Business
Administration’s (SBA) Office of Size Standards develops the numerical definition of a

212

18 CFR 380.4.

213

18 CFR 380.4(a)(2)(ii).

214

18 CFR 380.4(a)(15).

215

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

Docket No. RM14-14-000

120

small business.216 The SBA recently revised its size standard for electric utilities
(effective January 22, 2014) to a standard based on the number of employees, including
affiliates (from a standard based on megawatt hours).217 Under SBA’s new size
standards, electric utilities, electric power distribution, and electric bulk power
transmission and control, and power marketers likely come under one of the following
categories and associated size thresholds:218
 Hydroelectric power generation, at 500 employees
 Fossil fuel electric power generation, at 750 employees
 Nuclear electric power generation, at 750 employees
 Other electric power generation (e.g., solar, wind, geothermal, biomass, and
other), at 250 employees
 Electric bulk power transmission and control, at 500 employees
 Electric power distribution, at 1,000 employees.
 Wholesale Trade Agents and Brokers,219 at 100 employees

216

13 CFR 121.101 (2013).

217

SBA Final Rule on “Small Business Size Standards: Utilities,” 78 FR 77343
(Dec. 23, 2013).
218
219

13 CFR 121.201, Sector 22, Utilities.

The NAICS category 425120 (Wholesale Electronic Markets and Agents and
Brokers, within Subsector 425) covers Power Marketers.

Docket No. RM14-14-000
195.

121

Based on U.S. economic census data,220 the approximate percentages of small

firms in these categories vary from 24 percent to 99 percent. However, currently FERC
does not have information on how the economic census data compares with the specific
entities affected by this proposed rule using the new SBA definitions.221 Regardless,
FERC recognizes that the rule will likely impact small electric utilities, electric power
distribution, electric bulk power transmission and control, and power marketers and
estimates the economic impact on each entity below.
196.

The proposed rule will eliminate some requirements, streamline and clarify others,

and add a few minimal requirements, while reducing burden on entities of all sizes
(public utilities seeking and currently possessing market-based rate authority).
Implementation of the proposed rule is expected to reduce total annual burden by
27 percent to the industry. However, the number of filings with the Commission will
decrease only slightly because the only filings that are proposed to be eliminated are the

220

Data and further information are available from SBA at
http://www.sba.gov/advocacy/849/12162.
221

For utilities in the SBA’s subsector 221, the previous SBA definition stated that
“[a] firm is small if, including its affiliates, it is primarily engaged in the generation,
transmission, and/or distribution of electric energy for sale and its total electric output for
the preceding fiscal year did not exceed 4 million megawatt hours.” Using the previous
SBA definition and EQR data from Quarter 3 of 2012 through Quarter 2 of 2013, 678 of
the 1,903 sellers with market-based rate authority potentially affected by the proposed
rule would have qualified as small entities. For this estimate, power marketers are
included with utilities.

Docket No. RM14-14-000

122

Quarterly Land Acquisition Reports, which we estimate account for four percent of the
total annual burden on the industry.
197.

As discussed in Order No. 697,222 current regulations regarding market-based rate

sellers under Subpart H to Part 35 of Title 18 of the Code of Federal Regulations exempt
many small entities (using SBA’s former definition of a small entity not exceeding
4 million megawatt hours) from significant filing requirements by designating them as
Category 1 sellers.223 Category 1 sellers are exempt from triennial updates and may use
simplifying assumptions, such as assuming no competing imports, that the Commission
allows sellers to use in submitting their horizontal market power analysis.
198.

No longer requiring RTO sellers to file indicative screens will reduce the burden

on all sellers in RTOs, including small entities in RTOs. The proposed rule also serves to
clarify existing requirements, such as clarifying that sellers with fully-committed
generation may submit an explanation that their generation is fully committed in lieu of
submitting indicative screens. Such clarification may be particularly helpful to small
entities as many small entities have fully-committed generation.
199.

By adopting a reporting threshold of a 100 MW cumulative change in generation

capacity for reporting changes in status regarding new affiliations, the Commission
222
223

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 1126-1129.

Category 1 Sellers are power marketers and power producers that own or
control 500 MW or less of generating capacity in aggregate and that are not affiliated
with a public utility with a franchised service territory. In addition, Category 1 sellers
must not own or control transmission facilities, and must present no other vertical market
power issues. 18 CFR 35.36(a)(2).

Docket No. RM14-14-000

123

expects a reduction in the frequency of notice of change in status filings, which will
necessarily reduce the burden on market-based rate sellers, including small entities.
200.

The Commission is proposing to discontinue the land acquisition reporting

requirements, which eliminates the need to submit such filings altogether. By so doing,
the reduction in burden will be across all market-based rate sellers, including small
entities.
201.

The additional one-time burden to market-based rate sellers is expected to cause a

minimal increase in burden only during initial implementation, and will decrease future
burdens by allowing a streamlined analysis in subsequent filings. The additional ongoing
requirements (such as providing organization charts, providing details on the components
in Appendix A within and outside the study area, and reporting non-affiliate long-term
reservations and wheel-through transactions in Submittal 2) represent information that is
already available to filers and should result in little additional burden.
202.

The changes to the Commission’s regulations for market-based rate sellers are

estimated to cause a reduction of 27 percent in total annual burden to all sellers, including
small entities.
203.

Accordingly, the Commission certifies that the revised requirements set forth in

this NOPR will not have a significant economic impact on a substantial number of small
entities, and no regulatory flexibility analysis is required. The Commission finds that the
regulations adopted here should not have a significant impact on small businesses.

Docket No. RM14-14-000

124

VII.

Comment Procedures

204.

The Commission invites interested persons to submit comments on the matters and

issues proposed in this notice to be adopted, including any related matters or alternative
proposals that commenters may wish to discuss. Comments are due [INSERT DATE 60
days after publication in the FEDERAL REGISTER]]. Comments must refer to
Docket No. RM14-14-000, and must include the commenter's name, the organization
they represent, if applicable, and their address in their comments.
205.

The Commission encourages comments to be filed electronically via the eFiling

link on the Commission's web site at http://www.ferc.gov. The Commission accepts
most standard word processing formats. Documents created electronically using word
processing software should be filed in native applications or print-to-PDF format and not
in a scanned format. Commenters filing electronically do not need to make a paper
filing.
206.

Commenters that are not able to file comments electronically must send an

original of their comments to: Federal Energy Regulatory Commission, Secretary of the
Commission, 888 First Street NE, Washington, DC 20426.
207.

All comments will be placed in the Commission's public files and may be viewed,

printed, or downloaded remotely as described in the Document Availability section
below. Commenters on this proposal are not required to serve copies of their comments
on other commenters.

Docket No. RM14-14-000

125

VIII. Document Availability
208.

In addition to publishing the full text of this document in the Federal Register, the

Commission provides all interested persons an opportunity to view and/or print the
contents of this document via the Internet through the Commission's Home Page
(http://www.ferc.gov) and in the Commission's Public Reference Room during normal
business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A,
Washington, D.C. 20426.
209.

From the Commission's Home Page on the Internet, this information is available

on eLibrary. The full text of this document is available on eLibrary in PDF and
Microsoft Word format for viewing, printing, and/or downloading. To access this
document in eLibrary, type the docket number excluding the last three digits of this
document in the docket number field.
210.

User assistance is available for eLibrary and the Commission’s Web site during

normal business hours from the Commission’s Online Support at 202-502-6652 (toll free
at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference
Room at (202) 502-8371, TTY (202)502-8659. E-mail the Public Reference Room at
public.referenceroom@ferc.gov.

Docket No. RM14-14-000

126

List of subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and recordkeeping requirements.
By direction of the Commission.
(SEAL)

Nathaniel J. Davis, Sr.,
Deputy Secretary.

Docket No. RM14-14-000

127

In consideration of the foregoing, the Commission proposes to amend part 35, Chapter I,
Title 18, Code of Federal Regulations, as follows:
PART 35 – FILING OF RATE SCHEDULES AND TARIFFS
1.

The authority citation for Part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-

7352.
2.

Amend § 35.36 by revising paragraph (a)(2) to read as follows:

§ 35.36

Generally.

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

Docket No. RM14-14-000

128

Seller's generation assets; and
(v) Does not raise other vertical market power issues.
* * * * *
3.

Amend § 35.37 as follows:
a. In paragraph (a)(1), remove the phrase “contained in Order No. 697, FERC

Stats. & Regs. ¶ 31,252” and add in its place “posted on the Commission’s Web site.”
b. Revise paragraphs (a)(2) and (c)(4).
c. Add paragraphs (c)(5) and (c)(6).
d. Remove paragraph (e)(2) and redesignate paragraphs (e)(3) through (4) as
paragraphs (e)(2) through (3), respectively.
e. Revise redesignated paragraph (e)(3).
The revisions and additions read as follows:
§ 35.37

Market Power analysis required.

(a)(1) * * *
(2)

When submitting a market power analysis, whether as part of an initial

application or an update, a Seller must include an appendix of assets, in the form
provided in Appendix B of this subpart, and an organizational chart. The organizational
chart must depict the Seller’s current corporate structure indicating all upstream owners,
energy subsidiaries and energy affiliates.
* * * * *
(c) * * *

Docket No. RM14-14-000
(4)

129

When submitting the indicative screens, a Seller must use the format

provided in Appendix A of this subpart and file the indicative screens in an electronic
spreadsheet format. A Seller must include all supporting materials referenced in the
indicative screens.
(5)

Sellers submitting simultaneous transmission import limit studies must

file Submittal 1, and, if applicable, Submittal 2, in the electronic spreadsheet format
provided on the Commission’s Web site.
(6)

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.
* * * * *
(e) * * *
(3) A Seller must ensure that this information is included in the record of each
new application for market-based rates and each updated market power analysis. In
addition, a Seller is required to make an affirmative statement that it and its affiliates
have not erected barriers to entry into the relevant market and will not erect barriers to
entry into the relevant market.
* * * * *
4.

Amend § 35.42 as follows:
a. Revise paragraphs (a)(1), (a)(2), and (c).

Docket No. RM14-14-000

130

b. In paragraph (b), remove the phrase “, other than a change in status submitted
to report the acquisition of control of a site or sites for new generation capacity
development,”.
c. Remove paragraphs (d) and (e).
The revisions read as follows:
§ 35.42

Change in status reporting requirement.

(a) * * *
(1)

Ownership or control of generation capacity or long-term firm purchases of

capacity and/or energy that results in cumulative net increases (i.e., the difference
between increases and decreases in affiliated generation capacity) of 100 MW or more of
nameplate capacity in any relevant geographic market (including generation in the
relevant geographic market and generation in any markets that are first tier to the relevant
geographic market), or of inputs to electric power production, or ownership, operation or
control of transmission facilities, or
(2)

Affiliation with any entity not disclosed in the application for market-based

rate authority that:
(i) Owns or controls generation facilities or has long-term firm purchases of
capacity and/or energy that results in cumulative net increases (i.e., the difference
between increases and decreases in affiliated generation capacity) of 100 MW or more of
nameplate capacity in any relevant geographic market (including generation in the

Docket No. RM14-14-000

131

relevant geographic market(s) and generation in any markets that are first tier to the
relevant geographic market(s));
(ii) Owns or controls inputs to electric power production;
(iii) Owns, operates or controls transmission facilities; or
(iv) Has a franchised service area.
* * * * *
(c)

When submitting a change in status notification regarding a change that

impacts the pertinent assets held by a Seller or its affiliates with market-based rate
authorization, a Seller must include an appendix of all assets, including the new assets
and/or affiliates reported in the change in status, in the form provided in Appendix B of
this subpart, and an organizational chart. The organizational chart must depict the
Seller’s prior and new corporate structures indicating all upstream owners, energy
subsidiaries and energy affiliates unless the Seller demonstrates that the change in status
does not affect the corporate structure of the Seller’s affiliations.

Docket No. RM14-14-000
5.

132

Appendix A of subpart H is revised to read as follows:

Appendix A: Standard Screen Format (Data provided for illustrative purposes only)
Part I – Pivotal Supplier Analysis
Applicant-> Company X, LLC (TO)
Market -> Company X BAA
Date of Filing ->
0-Jan-00

Row
Generation
Seller and Affiliate Capacity (owned or controlled)
A
A1
B
B1
C
D

Installed Capacity (from inside the study area)
Remote Capacity (from outside the study area)
Long-Term Firm Purchases (from inside the study area)
Long-Term Firm Purchases (from outside the study area)
Long-Term Firm Sales (in and outside the study area)
Uncommitted Capacity Imports

E
E1
F
F1
G
H

I
J

Study Area Reserve Requirement
Amount of Line I Attributable to Seller, if any

Don't Enter Values (Outlined cell)

Reference

1,500
200
70
200
(500)
0

worksheet X

300
50
40
40
(60)
2,500

worksheet X

(300)
(200)

worksheet X

worksheet X
worksheet X
worksheet X
worksheet X
worksheet X

Non-Affiliate Capacity (owned or controlled)

K Total Uncommitted Supply (Sum A,A1,B,B1,C,D,E,E1,F,F1,G,H,I,M)

worksheet X
worksheet X
worksheet X
worksheet X
worksheet X

2,840

Load
L Balancing Authority Area Annual Peak Load
M Average Daily Peak Native Load in Peak Month
N Amount of Line M Attributable to Seller, if any

1,500
(1,200)
(900)

worksheet X
worksheet X
worksheet X

300

O Wholesale Load (SUM L,M)

2,540

P Net Uncommitted Supply (K-O)
Q Seller's Uncommitted Capacity (Sum A,A1,B,B1,C,D,J,N)
Result of Pivotal Supplier Screen (Pass if Line Q < Line P)
(Fail if Line Q > Line P)
Total Imports (Sum D,H), as filed by Seller ->
% of SIL for Seller's imported capacity ->
% of SIL for Other's imported capacity ->

370
Pass

2,500
0.00
1.00

SIL value* ->
2,500
Do Total Imports exceed the SIL value? ->
No
* Transmission owners filing triennials should use the SIL values from their Submittal 1, Row 10 (see Puget Sound Energy, Inc., 135 FERC ¶ 61,254 (2011)).
Other sellers should use Commission-accepted SIL values, if they exist for the study area and study period. If these values do not exist, sellers should
use SIL values that have been filed but not accepted.

Docket No. RM14-14-000

133

Appendix A: Standard Screen Format (Data provided for illustrative purposes only)
Part II – Market Share Analysis
Applicant-> Company X, LLC (TO)
Study Area -> Company X BAA
Data Year ->
Don't Enter Values (Outlined cell)
As filed by the Applicant/Seller
Row
Winter
Spring
Summer
Fall
Reference
(MW)
(MW)
(MW)
(MW)
Seller and Affiliate Capacity (owned, controlled or under LT contract)
A Installed Capacity (inside the study area)
1,000
900
1,500
1,000
worksheet X
A1 Remote Capacity (from outside the study area)
400
300
200
200
worksheet X
B Long-Term Firm Purchases (inside the study area)
60
40
70
30
worksheet X
B1 Long-Term Firm Purchases (from outside the study area)
200
200
200
200
worksheet X
C Long-Term Firm Sales (in and outside the study area)
(500)
(500)
(500)
(500)
worksheet X
D Seasonal Average Planned Outages
(150)
(50)
(80)
(100)
worksheet X
E Uncommitted Capacity Imports
0
0
0
0
worksheet X

F
G
H
I
J
K

Capacity Deductions
Average Peak Native Load in the Season
Amount of Line F Attributable to Seller, if any
Amount of Line F Attributable to Non-Affiliates, if any
Study Area Reserve Requirement
Amount of Line I Attributable to Seller, if any
Amount of Line I Attributable to Non-Affiliates, if any

(1,000)
(700)
(300)
(200)
(100)
(100)

(900)
(700)
(200)
(200)
(100)
(100)

(1,200)
(900)
(300)
(300)
(200)
(100)

(800)
(600)
(200)
(100)
(80)
(20)

worksheet X
worksheet X

L
L1
M
M1
N
O
P

Non-Affiliate Capacity (owned, controlled or under LT contract)
Installed Capacity (inside the study area)
250
Remote Capacity (from outside the study area)
50
Long-Term Firm Purchases (inside the study area)
30
Long-Term Firm Purchases (from outside the study area)
40
Long-Term Firm Sales (in and outside the study area)
(50)
Seasonal Average Planned Outages
(10)
Uncommitted Capacity Imports
2,000

200
50
30
30
(30)
(20)
1,500

300
50
30
40
(60)
(10)
2,500

150
50
30
20
(50)
(20)
1,300

worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X

1,460
90
1,550

2,450
290
2,740

1,260
150
1,410

Supply Calculation
Q Total Competing Supply (Sum H, K, L,L1,M,M1,N,O,P)
R Seller's Uncommitted Capacity (Sum A,A1,B,B1,C,D,E,G,J)
S Total Seasonal Uncommitted Capacity (Sum Q,R)

1,910
210
2,120

Seller's Market Share (R/S)
Results (Pass if < 20% and Fail if ≥ 20%)

9.9%
Pass

5.8%
Pass

10.6%
Pass

U
V

Total Imports, as filed by Seller (Sum E,P)
SIL value*

2,000
2,000

1,500
1,500

2,500
2,500

1,300
1,300

Do Total Imports exceed SIL value? (is U<=V)

worksheet X
worksheet X

10.6%
Pass

* Transmission owners filing triennials should use the SIL values from their Submittal 1, Row 10 (see Puget Sound Energy, Inc., 135 FERC ¶ 61,254 (2011)).
Other sellers should use Commission-accepted SIL values, if they exist for the study area and study period. If these values do not exist, sellers should
use SIL values that have been filed but not accepted.

Docket No. RM14-14-000
6.

134

Appendix B of subpart H is revised to read as follows:
Appendix B:
Market-Based Rate Authority and Generation Assets

This is an example of the required appendix listing the filing entity and all its energy affiliates and their associated assets which should be submitted with all market-based rate filings.

Market-Based Rate Authority and Generation Assets

Filing Entity and Docket # where
Generation
its Energy
MBR authority
Name
Affiliates
was granted

Owned By

Controlled
By

Location
Date
Market /
Capacity Rating
Control
In-Service Date (MW): Nameplate,
Balancing
Transferred Authority Geographic Region
Seasonal, or FiveArea
Year Average

Electric Transmission Assets and/or Natural Gas Intrastate Pipelines and/or Gas Storage Facilities
Location
Cite to order
Filing Entity and accepting OATT
its Energy
or granting
Affiliates
OATT waiver

Asset Name
and Use

Owned By

Controlled
By

Market /
Date
Balancing Geographic Region
Control
Authority
Transferred
Area

Size (length
and kV)

Docket No. RM14-14-000

135

Note: The following appendices will not be published in the Code of Federal
Regulations.
Appendix C
Schedule for Transmission Owning Utilities with Market-based Rate Authority that are
Designated as Category 2 Sellers in the Region
Entities Required to File

Study Period

Filing Period
(anytime during
this month)
December: 2013
June: 2014
December: 2014
June: 2015
December: 2015
June: 2016

Northeast
Southeast
Central
SPP
Southwest
Northwest

Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities

December
December
December
December
December
December

2011
2011
2012
2012
2013
2013

to
to
to
to
to
to

November
November
November
November
November
November

2012
2012
2013
2013
2014
2014

Northeast
Southeast
Central
SPP
Southwest
Northwest

Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities

December
December
December
December
December
December

2014
2014
2015
2015
2016
2016

to
to
to
to
to
to

November
November
November
November
November
November

2015 December: 2016
2015
June: 2017
2016 December: 2017
2016
June: 2018
2017 December: 2018
2017
June: 2019

Northeast
Southeast
Central
SPP
Southwest
Northwest

Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities

December
December
December
December
December
December

2017
2017
2018
2018
2019
2019

to
to
to
to
to
to

November
November
November
November
November
November

2018 December: 2019
2018
June: 2020
2019 December: 2020
2019
June: 2021
2020 December: 2021
2020
June: 2022

Northeast
Southeast
Central
SPP
Southwest
Northwest

Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities
Transmission Owning Utilities

December
December
December
December
December
December

2020
2020
2021
2021
2022
2022

to
to
to
to
to
to

November
November
November
November
November
November

2021 December: 2022
2021
June: 2023
2022 December: 2023
2022
June: 2024
2023 December: 2024
2023
June: 2025

Docket No. RM14-14-000

136
Appendix C1

Schedule for Non-Transmission Owning Utilities with Market-based Rate Authority that are
Designated as Category 2 Sellers in the Region
Entities Required to File

Study Period

Filing Period
(anytime during
this month)
December: 2013
June: 2014
December: 2014
June: 2015
December: 2015
June: 2016

Northwest
Northeast
Southeast
Central
SPP
Southwest

Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities
Non-Transmission Owning Utilities

December
December
December
December
December
December

2010
2011
2011
2012
2012
2013

to
to
to
to
to
to

November
November
November
November
November
November

2011
2012
2012
2013
2013
2014

Northwest
Northeast
Southeast
Central
SPP
Southwest

December
December
December
December
December
December

2013
2014
2014
2015
2015
2016

to
to
to
to
to
to

November
November
November
November
November
November

2014 December: 2016
2015
June: 2017
2015 December: 2017
2016
June: 2018
2016 December: 2018
2017
June: 2019

Northwest
Northeast
Southeast
Central
SPP
Southwest

December
December
December
December
December
December

2016
2017
2017
2018
2018
2019

to
to
to
to
to
to

November
November
November
November
November
November

2017 December: 2019
2018
June: 2020
2018 December: 2020
2019
June: 2021
2019 December: 2021
2020
June: 2022

Northwest
Northeast
Southeast
Central
SPP
Southwest

December
December
December
December
December
December

2019
2020
2020
2021
2021
2022

to
to
to
to
to
to

November
November
November
November
November
November

2020 December: 2022
2021
June: 2023
2021 December: 2023
2022
June: 2024
2022 December: 2024
2023
June: 2025

Docket No. RM14-14-000

137
Appendix D

Generalized Map of Geographic Regions

Northeast (ISO-NE, NYISO, PJM)
Southeast (SERC and FRCC NERC Regions, excluding for PJM and MISO members)
Central (Midcontinent Independent System Operator (MISO) and members of the Midwest Reliability Organization
(MRO) that are not part of another RTO)
Southwest Power Pool (SPP NERC Region, excluding MISO members)
Southwest (Arizona, most of California, part of Nevada and the portions of New Mexico and Texas within the Western
Interconnection)
Northwest (The remainder of the Western Interconnection)

Docket No. RM14-14-000

138
Appendix E
Submittal 1: Summary Table of the Components Used to Calculate SIL Values
Table 1: SIL Computation

Study Period: December 1, 20XX to November 30, 20XX

Row Description of Component
Simultaneous Incremental Transfer
Capability
The most limiting First Contingency Incremental
1
Transfer Capability (FCITC), Normal Incremental
Transfer Capability (NITC) or equivalent values.
Note i
Modeled Net Area Interchange (NAI)
2 Enter a positive value and indicate the direction
of flow in row 3 below. Note ii
Interchange Direction
3 Indicate whether the Study Area NAI is export or
import.
4

Total Simultaneous Transfer Capability
(row 4 = row 1 +/- row 2). Note iii

Long-Term Firm Transmission Reservations
5 Sum of the long-term firm transmission
reservations from Table 2. Note iv
6

Calculated SIL Value
(row 6 = row 4 - row 5). Note v

Historical Peak Load
7 (Identify source if not from FERC Form No. 714).
Note vi
8

Adjusted Historical Peak Load
(row 8 = row 7 - row 5). Note vii

Uncommitted First-Tier Generation
9 Amount of uncommitted generation modeled in
the first-tier area. Note viii
SIL Study Value
(row 10 = the minimum of the values entered in
10 rows 6, 8 and 9 for each season). Use these SIL
Study Values in the Market Share Screens.
Note ix

Name of Home BAA/Market
Winter Spring Summer Fall
(MW)
(MW)
(MW)
(MW)

Winter
(MW)

Name of First-Tier BAA
Spring Summer
Fall
(MW)
(MW)
(MW)

1,700

1,800

1,900

2,000

3,000

3,200

3,400

3,600

500

600

700

800

200

300

400

500

Import

2,200

620

1,580

1,400

780
13,580

780

Import

2,400

300

2,100

1,900

Import

2,600

620

1,980

2,500

Import

2,800

300

2,500

2,000

1,600

1,880

1,700

12,800

14,500

12,800

1,600

1,880

1,700

Export

2,800

460

2,340

1,400

940

Export

2,900

3,000

360

2,540

1,900

1,540

13,580 12,800

940

1,540

460

2,540

2,500

Export

3,100

360

2,740

2,000

2,040

1,640

14,500

12,800

2,040

1,640

Docket No. RM14-14-000

139

Submittal 2: Identify Long-Term Firm Transmission Reservations Used to Import Power from Generating
Resources in the First-Tier Area to Serve Native Load in the Study Area
Table 2: Long-Term Firm Transmission Reservations
Name of Home BAA/Market
Winter
Description of Remote Resource
Affiliates
1 MW Share of Remote Plant #1

(MW)
100

Spring Summer
(MW)
-

(MW)
100

2 MW Share of Remote Plant #2

3 MW Share of Remote Plant #3
Purchased Power Agreement where the energy
4 is imported into the study area with long-term
firm reservations
Wheel through transactions to serve first-tier area
5 load embedded in the study area using first-tier
generation
6 Sum of affiliated long-term firm reservations

100

310

150

310

Name of First-Tier BAA
Fall

Winter

(MW)

50
-

(MW)

50
100

50
-

100

150

Spring Summer

230

180

Fall
(MW)

50
100

50
80

(MW)

50
-

230

180

Non-Affiliates
7 MW Share of Remote Plant #1

100

8 MW Share of Remote Plant #2

100

310

150

310

150

230

180

230

180

620

300

620

300

460

360

460

360

9 MW Share of Remote Plant #3
Purchased Power Agreement where the energy
10 is imported into the study area with long-term
firm reservations
Wheel through transactions to serve first-tier area
11 load embedded in the study area using first-tier
generation
12 Sum of non-affiliated long-term firm reservations
Sum of affiliated and non-affiliated long-term firm
13 reservations (enter value in row 5 of Table 1
above)

100

50
-

50
100
-

50
-

50
100

50
50

File Type	application/pdf
File Title	RM14-14-000
Subject	Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Ser
Author	FERC
File Modified	2014-06-19
File Created	2014-06-19