Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 43535-43572 [2014-16002]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 79, Number 143 (Friday, July 25, 2014)]
[Proposed Rules]
[Pages 43535-43572]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2014-16002]



[[Page 43535]]

Vol. 79

Friday,

No. 143

July 25, 2014

Part II





Department of Energy





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Federal Energy Regulatory Commission





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18 CFR Part 35





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

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

[[Page 43536]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM14-14-000]


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

AGENCY:  Federal Energy Regulatory Commission.

ACTION:  Notice of proposed rulemaking.

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

DATES:  Comments are due September 23, 2014.

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

FOR FURTHER INFORMATION CONTACT:
Joseph Cholka (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, 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: 

Table of Contents


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



[[Page 43537]]

I. Introduction

    1. Pursuant to sections 205 and 206 of the Federal Power Act 
(FPA),\1\ the Commission is proposing to amend its regulations to 
revise Subpart H to Part 35 of Title 18 of the Code of Federal 
Regulations (CFR), which governs market-based rate authorizations for 
wholesale sales of electric energy, capacity, and ancillary services by 
public utilities.
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    \1\ 16 U.S.C. 824d, 824e (2012).
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II. Background

    2. In 1988, the Commission began considering proposals for market-
based pricing of wholesale power sales. The Commission acted on market-
based rate proposals filed by various wholesale suppliers on a case-by-
case basis. Over the years, the Commission developed a four-prong 
analysis to assess whether a seller should be granted market-based rate 
authority: (1) Whether the seller and its affiliates lack, or have 
adequately mitigated, market power in generation; (2) whether the 
seller and its affiliates lack, or have adequately mitigated, market 
power in transmission; (3) whether the seller or its affiliates can 
erect other barriers to entry; and (4) whether there is evidence 
involving the seller or its affiliates that relates to affiliate abuse 
or reciprocal dealing.
    3. In April 2004, the Commission initiated a rulemaking proceeding 
to consider the adequacy of its market-based rate analysis and whether 
and how it should be modified to assure that prices for electric power 
being sold under market-based rates are just and reasonable under the 
FPA.\2\ At that time, the Commission noted that much had changed in the 
industry since its analysis was first developed and posed a number of 
questions that would be explored through a series of technical 
conferences. Following the technical conferences, the Commission issued 
a notice of proposed rulemaking that led to the issuance in 2007 of 
Order No. 697, which clarified and codified the Commission's market-
based rate policy.\3\
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    \2\ Market-Based Rates for Public Utilities, 107 FERC ] 61,019, 
at P 1 (2004) (initiating rulemaking proceeding).
    \3\ Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities, Order No. 697, 
FERC Stats. & Regs. ] 31,252, clarified, 121 FERC ] 61,260 (2007) 
(Clarifying Order), order on reh'g, Order No. 697-A, FERC Stats. & 
Regs. ] 31,268, clarified, 124 FERC ] 61,055, order on reh'g, Order 
No. 697-B, FERC Stats. & Regs. ] 31,285 (2008), order on reh'g, 
Order No. 697-C, FERC Stats. & Regs. ] 31,291 (2009), order on 
reh'g, Order No. 697-D, FERC Stats. & Regs. ] 31,305 (2010), aff'd 
sub nom. Mont. Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 
2011), cert. denied, 133 S. Ct. 26 (2012).
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    4. In Order No. 697, the Commission adopted two indicative screens 
for assessing horizontal market power: The pivotal supplier screen and 
the wholesale market share screen (with a 20 percent threshold), each 
of which serves as a cross check on the other to determine whether 
sellers may have market power and should be further examined.\4\ The 
Commission stated that passage of both indicative screens establishes a 
rebuttable presumption that the seller does not possess horizontal 
market power. Sellers that fail either indicative screen are rebuttably 
presumed to have market power and are given the opportunity to present 
evidence through a delivered price test (DPT) analysis demonstrating 
that, despite a screen failure, they do not have market power.\5\ The 
Commission uses a ``snapshot in time'' approach based on historical 
data for both the indicative screens and the DPT analysis.\6\
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    \4\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 62.
    \5\ Id. P 13; 18 CFR 35.37(c)(3).
    \6\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 17.
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    5. With respect to the horizontal market power analysis, in 
traditional markets (outside regional transmission organization/
independent system operator (RTO/ISO) markets),\7\ the default relevant 
geographic market for purposes of the indicative screens is first, the 
balancing authority area(s) where the seller is physically located, and 
second, the markets directly interconnected to the seller's balancing 
authority area (first-tier balancing authority areas).\8\ Generally, 
sellers that are located in and are members of the RTO may consider the 
geographic region under the control of the RTO as the default relevant 
geographic market for purposes of the indicative screens.\9\
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    \7\ We will use the term ``RTO'' when referring to either an RTO 
or ISO for easier readability.
    \8\ The Commission also noted that ``[w]here a generator is 
interconnecting to a non-affiliate owned or controlled transmission 
system, there is only one relevant market (i.e., the balancing 
authority area in which the generator is located).'' Order No. 697, 
FERC Stats. & Regs. ] 31,252 at P 232 n.217.
    \9\ Where the Commission has made a specific finding that there 
is a submarket within an RTO, that submarket becomes a default 
relevant geographic market for sellers located within the submarket 
for purposes of the market-based rate analysis. See id. PP 15, 231.
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    6. With respect to the vertical market power analysis, in cases 
where a public utility or any of its affiliates owns, operates, or 
controls transmission facilities, the Commission requires that there be 
a Commission-approved Open Access Transmission Tariff (OATT) on file, 
or that the seller or its applicable affiliate has received waiver of 
the OATT requirement, before granting a seller market-based rate 
authorization.\10\ The Commission also considers a seller's ability to 
erect other barriers to entry as part of the vertical market power 
analysis.\11\ As such, the Commission requires a seller to provide a 
description of its ownership or control of, or affiliation with an 
entity that owns or controls, intrastate natural gas transportation, 
storage or distribution facilities; sites for generation capacity 
development; and physical coal supply sources and ownership of or 
control over who may access transportation of coal supplies 
(collectively, inputs to electric power production).\12\ In Order No. 
697-C, the Commission revised the change in status reporting 
requirement in Sec.  35.42 of the Commission's regulations to require 
market-based rate sellers to report the acquisition of control of sites 
for new generation capacity development on a quarterly basis instead of 
within 30 days of the acquisition.\13\ The Commission adopted a 
rebuttable presumption that the ownership or control of, or affiliation 
with any entity that owns or controls, inputs to electric power 
production does not allow a seller to raise entry barriers but will 
allow intervenors to demonstrate otherwise.\14\ Finally, as part of the 
vertical market power analysis, the Commission also requires sellers to 
make an affirmative statement that they have not erected barriers to 
entry into the relevant market and will not erect barriers to entry 
into the relevant market. The Commission clarified that the obligation 
in this regard applies to both the seller and its affiliates but is 
limited to the geographic market(s) in which the seller is located.\15\
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    \10\ Id. P 408.
    \11\ Id. P 440.
    \12\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 176.
    \13\ Order No. 697-C, FERC Stats. & Regs. ] 31,291 at P 18; 18 
CFR 35.42(d).
    \14\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 446; 18 
CFR 35.37(c).
    \15\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 447.
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    7. If a seller is granted market-based rate authority, the 
authorization is conditioned on: (1) Compliance with affiliate 
restrictions governing transactions and conduct between power sales 
affiliates where one or more of those affiliates has captive customers; 
\16\ (2) a requirement to file post-transaction electric quarterly 
reports (EQR) with the Commission containing: (a) A summary of the 
contractual terms and conditions in

[[Page 43538]]

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

Summary of Proposals

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

[[Page 43539]]

propose to include solar technologies as energy-limited generation 
resources. We further propose that sellers with energy-limited 
resources that do not have five years of historical data may use 
regional capacity factor estimates appropriate to the specific 
technology as derived by the United States Energy Information 
Administration (EIA) to determine the capacity for those resources. We 
also propose to clarify that a seller must use the same capacity rating 
methodology for similar generation assets throughout a particular 
filing.
    16. The Commission has stated that a seller's uncommitted capacity 
is determined by adding the nameplate or seasonal capacity of 
generation owned or controlled through contract and long-term firm 
capacity purchases, less operating reserves, native load commitments, 
and long-term firm sales. Therefore, sellers have been reporting their 
long-term firm purchases as part of their capacity if the purchase 
granted them control of that capacity. We propose to require sellers to 
report all of their long-term firm purchases of capacity and/or energy 
in their indicative screens and asset appendices, regardless of whether 
the seller has operational control over the generation capacity 
supplying the purchased power. This approach will help size the market 
correctly and will establish consistent treatment of long-term firm 
sales and long-term firm purchases.
    17. The Commission's vertical market power analysis examines 
affiliation, ownership or control of inputs to electric power 
production, including sites for generation capacity development. In 
this Notice of Proposed Rulemaking (NOPR), we propose to eliminate the 
requirement that sellers provide information on sites for generation 
capacity development in their market-based rate applications and 
triennial updated market power analyses and to similarly relieve 
sellers of their obligation to file quarterly land acquisition reports.
    18. The Commission requires that sellers report to the Commission 
any change in status that would reflect a departure from the 
characteristics the Commission relied upon in granting market-based 
rate authority. We propose to revise the regulations to clarify that 
the 100 MW reporting threshold for filing a notice of change in status 
is not limited to markets previously studied; thus if a seller acquires 
generation that causes a cumulative net increase of 100 MW or more in 
any relevant geographic market, the seller must file a notice of change 
in status. We also propose to revise the regulations to include long-
term firm purchases of capacity and/or energy in calculating the 100 MW 
change in status threshold. Although there currently is no threshold 
for reporting a change in status that results in a new affiliation, we 
propose to revise the regulations to include a 100 MW threshold for 
reporting new affiliations.
    19. The Commission requires that sellers include with each new 
application, market power analysis, and relevant change in status 
notification an asset appendix that lists all affiliates that have 
market-based rate authority and identifies assets owned or controlled 
by the seller and its affiliates. We propose to revise the asset 
appendix by revising the headings of several columns to be more clear 
and consistent. We also propose several clarifications to the asset 
appendix requirements. In particular: (1) A seller must enter the 
entire amount of a generator's capacity, even if the seller only owns 
part of the generator; (2) a seller must list one of three specified 
uses for assets in the asset list containing electric transmission and 
intrastate gas assets; and (3) sellers should not list assets in which 
passive ownership interests have been claimed. We also propose to 
modify the asset appendix to add a new column in the list of 
transmission assets for the citation to the Commission order accepting 
the OATT or granting waiver of the OATT requirement. We further propose 
to require that sellers submit the asset lists in an electronic 
spreadsheet format that can be searched, sorted, and accessed using 
electronic tools. We also seek comment on whether it would be useful to 
develop a comprehensive searchable public database of the information 
contained in the asset appendix, which sellers could access to update 
their asset appendices.
    20. There are two categories of market-based rate sellers. Category 
1 sellers are exempt from the requirement to automatically submit 
updated market power analyses every three years. Market-based rate 
Category 2 sellers are required to submit an updated market power 
analysis every three years according to a regional schedule. We include 
an updated schedule and region map as part of this NOPR.
    21. One of the criteria that must be satisfied to be a Category 1 
seller in a region is that the seller and its affiliates must own or 
control 500 MW or less of generation in aggregate in that region. We 
propose to codify in the Commission's regulations a distinction in 
determining seller category status for power marketers and power 
producers. For each region, a power marketer should include all 
affiliated generation in that region, while a power producer would only 
need to include affiliated generation capacity that is located in the 
same region as the power producer's generation asset(s). We propose 
this difference in treatment based on the fact that a power marketer is 
assumed to have no home market, while it is assumed that a majority of 
a power producer's sales will be in market(s) in which it owns 
generation assets.
    22. While sellers have been required to describe their affiliates 
and upstream owners when filing initial applications, updated market 
power analyses and notices of change in status involving new 
affiliations, we propose to add a requirement in the regulations that 
sellers provide an organizational chart as well. We propose that the 
organizational chart be similar to that which we require from FPA 
section 203 applicants.
    23. Although we have previously explained that joint filers are 
permitted to designate one market-based rate seller to file a single, 
joint master corporate market-based rate tariff for inclusion in the 
Commission's eTariff database that reflects the joint tariff for all 
affiliated sellers, many sellers have not taken advantage of the option 
to file a joint master corporate market-based rate tariff. We propose 
to clarify on the Commission's Web site how a corporate family that 
chooses to submit a joint master corporate tariff should identify its 
designated filer and what each of the other filers should submit into 
their respective eTariff databases.
    24. We also propose to provide clarification regarding several 
issues related to how to perform SIL studies and regarding the 
associated Submittals 1 and 2. In particular, we propose to clarify 
issues relating to what is meant by Open Access Same-Time Information 
System (OASIS) practices, how to deal with conflicts between OASIS 
practices and Commission direction provided in Appendix B of Puget, and 
what is the correct load value to use in the SIL study.
    25. The Commission has previously stated that the methodology a 
transmission provider uses to calculate SIL values must be consistent 
with the methodology it uses for calculating and posting available 
transmission capability (ATC) and for evaluation of firm transmission 
service requests. We propose to clarify that ``OASIS practices'' refers 
to the seasonal benchmark power flow case modeling assumptions, study 
solution criteria, and operating practices historically used by the 
first-tier and study area transmission providers to calculate and post 
ATC and to evaluate requests for

[[Page 43540]]

firm transmission service. We further propose to clarify that in 
performing a SIL study, the transmission provider must follow its OASIS 
practices consistent with the administration of its tariff. Thus, the 
seasonal benchmark power flow cases submitted with a SIL study should 
represent historical operating practices only to the extent that such 
practices are available to customers requesting firm transmission 
service. We clarify that where there is a conflict between the 
transmission provider's tariff or OASIS practices and the Commission's 
directions in Puget, sellers should follow OASIS practices except where 
use of actual OASIS practices is incompatible with an analysis of 
import capability from an aggregated first-tier area. We also remind 
sellers that the calculated SIL value should account for any limits 
defined in the tariff, such as stability or voltage. We reiterate that 
sellers may use load scaling to perform a SIL study if they use load 
scaling in their OASIS practices as long as they submit adequate 
support and justification for the scaling factor used and how the 
resulting SIL value compares had the seller used a generation-shift 
methodology. We also instruct sellers to subtract all long-term firm 
import transmission reservations, including reservations held by non-
affiliated sellers, from the simultaneous total transfer capability 
(simultaneous TTC) value. Finally, we clarify that the seller should 
reduce the simultaneous TTC value by subtracting all wheel through 
transactions used to serve non-affiliated load embedded in the study 
area using first-tier area generation. These transactions should be 
accounted for as long-term firm transmission reservations and reported 
in Submittal 2.
    26. We propose to amend Submittal 1 to revise Row 8 to read 
``Adjusted Historical Peak Load'' and propose to direct sellers to 
include all load associated with the balancing authority area(s) within 
the study area, including non-affiliated load. Submittal 1 requires 
sellers to use FERC Form No. 714 load values or explain the source of 
the data used. We seek comment on the appropriate source of historical 
peak load data.
    27. We propose to clarify that where a first-tier market or 
balancing authority area is directly connected to the study area only 
by controllable tie lines and is not connected to any other first-tier 
market or balancing authority area, sellers should follow their OASIS 
practice regarding calculation and posting of ATC for such areas. If 
the seller's OASIS practices are incompatible with the SIL study, 
entities may use an alternative process to account for import 
capability for such tie lines.
    28. We propose to provide standard guidance for data submittals and 
representations that sellers using the simultaneous TTC must provide, 
including historical data of actual, hourly, real-time TTC values used 
for operating the transmission system and posting availability on OASIS 
for each interface during each seasonal study period. We propose to 
clarify that sellers may use the maximum sum of TTC values for any day 
and time during each season as long as they demonstrate that these TTC 
values are simultaneously feasible. Finally, we reiterate that, if 
there are limited interconnections between first-tier markets, we will 
review evidence that potential loop flow between first-tier areas is 
properly accounted for in the underlying SIL values and we clarify that 
simply attesting that first-tier markets or balancing authority areas 
are not directly interconnected is not sufficient evidence that TTC 
values posted on OASIS are simultaneous.
    29. We note that there are certain waivers that the Commission has 
granted to certain sellers with market-based rate authority, e.g., 
power marketers and independent or affiliated power producers, such as 
waiver of the Uniform System of Accounts requirements, specifically 
waiver of Parts 41, 101, and 141 of the Commission's regulations except 
Sec. Sec.  141.14 and 141.15. We clarify that any waiver of Part 101 
granted to a market-based rate seller is limited such that waiver of 
the provisions of Part 101 that apply to hydropower licensees is not 
granted with respect to licensed hydropower projects. The Commission 
further directs that, to the extent that a hydropower licensee has been 
granted waiver of Part 101 as part of its market-based rate authority, 
the licensee's market-based rate tariff limitations and exemptions 
section should be revised to provide that the seller has been granted 
waiver of Part 101 of the Commission's regulations with the exception 
that waiver of the provisions that apply to hydropower licensees has 
not be granted with respect to licensed hydropower projects. Similarly, 
hydropower licensees that have been granted waiver of Part 141 as part 
of their market-based rate authority should ensure that the limitations 
and exemptions section of their market-based rate tariffs specify that 
waiver of Part 141 has been granted, with the exception of Sec. Sec.  
141.14 and 141.15.
    30. The Commission's regulations require as part of the vertical 
market power analysis that sellers make an affirmative statement that 
they have not erected barriers to entry into the relevant market and 
will not erect barriers to entry into the relevant market. We propose 
to revise the regulations to make it clear that the obligation to make 
the affirmative statement applies to both the seller and its 
affiliates.

III. Discussion

A. Horizontal Market Power

1. Sellers in RTOs
a. Current Policy
    31. Section 35.37 of the Commission's regulations requires market-
based rate sellers to submit market power analyses: (1) When seeking 
market-based rate authority; (2) every three years for Category 2 
sellers; and (3) at any other time the Commission requests a seller to 
submit an analysis. A market power analysis must address a seller's 
potential to exercise horizontal and vertical market power. If a seller 
studying an RTO as a relevant geographic market (RTO seller) fails the 
indicative screens for the RTO, it can seek to obtain or retain market-
based rate authority by relying on Commission-approved RTO monitoring 
and mitigation.\27\
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    \27\ In Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 111, 
the Commission stated that ``to the extent a seller seeking to 
obtain or retain market-based rate authority is relying on existing 
Commission-approved [RTO] market monitoring and mitigation, we adopt 
a rebuttable presumption that the existing mitigation is sufficient 
to address any market power concerns.''
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    32. In 2001, the Commission originally proposed that all sales, 
including bilateral sales, into an RTO with Commission-approved market 
monitoring and mitigation would be exempt from the generation market 
power analysis in effect at that time (the Supply Margin Assessment 
test) and, instead, would be governed by the specific thresholds and 
mitigation provisions approved for the particular market.\28\ However, 
the Commission subsequently concluded that it would no longer exempt 
sellers located in markets with Commission-approved market monitoring 
and mitigation from providing generation market power analyses, on the 
basis that requiring sellers located in such markets to submit 
indicative screens provides an additional check on the potential for 
market power.\29\
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    \28\ AEP Power Marketing, Inc., 97 FERC ] 61,219, at 61,970 
(2001).
    \29\ AEP Power Marketing, Inc., 107 FERC ] 61,018, at P 186 
(April 14, 2004 Order), order on reh'g, 108 FERC ] 61,026 (2004).

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[[Page 43541]]

    33. In Order No. 697, the Commission declined the request that it 
reinstate the prior RTO exemption, stating it ``will continue to 
require generation market power analyses from all sellers, including 
those in [RTO] markets.'' \30\ In Order No. 697-A, the Commission 
denied requests to reconsider its decision stating that
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    \30\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 290.

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

    34. Since the issuance of Order No. 697, it has been the 
Commission's practice to grant sellers market-based rate authority or 
allow them to retain market-based rate authority where they have failed 
indicative screens in an RTO but have relied on Commission-approved 
monitoring and mitigation.\32\ RTO sellers are sellers that study an 
RTO as a relevant geographic market, including those that sell 
bilaterally. While the burdens of preparing the indicative screens are 
not necessarily greater for RTO sellers than for sellers in other 
markets, the submission of indicative screens yields little practical 
benefit since it has been the Commission's practice to allow RTO 
sellers that fail the indicative screens to rely on RTO monitoring and 
mitigation. Thus, for sellers in RTOs, the burden of submitting 
indicative screens may not be ``outweighed by the additional 
information gleaned with respect to a specific seller's market power.'' 
\33\
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    \32\ See, e.g., Niagara Mohawk Power Corp., 123 FERC ] 61,175, 
at P 28 (2008) (failures in the New York City and Long Island 
submarkets of the New York Independent System Operator, Inc.); 
Dominion Energy Marketing, Inc., 125 FERC ] 61,070, at PP 26-27 
(2008) (failures in the Connecticut submarket of ISO New England, 
Inc.); PSEG Energy Resources & Trade LLC, 125 FERC ] 61,073, at PP 
31-32 (2008) (failures in the PJM-East submarket). There are also 
numerous delegated letter orders granting a seller market-based rate 
authority where the seller relies on Commission-approved monitoring 
and mitigation in RTO markets. See, e.g., TransCanada Energy 
Marketing ULC, Docket No. ER07-1274-001 (Jan. 23, 2009) (delegated 
letter order). Finally, the Commission has not initiated any 
investigations pursuant to section 206 of the FPA for any RTO 
sellers failing indicative screens since the issuance of Order No. 
697; in all cases where RTO sellers failed, the Commission relied on 
the Commission-approved monitoring and mitigation to prevent the 
seller's ability to exercise any potential market power.
    \33\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 110.
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b. Proposal
    35. We propose to modify the approach taken in Order No. 697 to 
reflect current practice and reduce the burden on these sellers. 
Specifically, we propose to allow market-based rate sellers in RTO 
markets with Commission-approved monitoring and mitigation to address 
horizontal market power issues in a streamlined manner when submitting 
initial applications requesting market-based rate authority and updated 
market power analyses. We note that this proposal includes RTO sellers 
who may have bilateral contracts not subject to the Commission-approved 
monitoring and mitigation. We find that the existence of monitoring and 
mitigation in an organized market generally results in a market where 
prices are transparent.\34\ This disciplines forward and bilateral 
markets by revealing a benchmark price and keeping offers competitive. 
For example, if a seller offers what a buyer perceives as a non-
competitive price in the bilateral market, that buyer can opt to 
purchase in the spot market. This provides a strong incentive for the 
seller to offer at a competitive price in the forward and bilateral 
markets.
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    \34\ April 14 Order, 107 FERC ] 61,018 at P 189.
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    36. Under this streamlined approach, RTO sellers would not have to 
submit indicative screens as part of their horizontal market power 
analyses if they rely on Commission-approved monitoring and mitigation 
to prevent the exercise of market power. Rather, to address horizontal 
market power effects, RTO sellers instead would simply state that they 
are relying on such mitigation to address any potential market power 
they might have, and provide an asset appendix and describe their 
generation and transmission assets. Under this proposal, all RTO 
sellers seeking market-based rate authority in an RTO market would make 
an initial filing, consistent with current practice, and those sellers 
required to file updated market power analyses every three years (i.e., 
Category 2 sellers) would continue to make their scheduled filings. To 
address horizontal market power effects, both the initial applications 
for market-based rate authorization and the updated market power 
analyses would include: (1) A statement that the seller is relying on 
RTO mitigation to address any potential market power it might have; (2) 
identification and description of generation and transmission assets; 
and (3) an asset appendix.\35\ In all scenarios, the Commission would 
retain the ability to require an updated market power analysis, 
including indicative screens, from any market-based rate seller at any 
time.
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    \35\ Applicants making these filings would continue to be 
required to provide the following information that is related to the 
non-horizontal market power issues: (1) A standard vertical market 
power analysis; (2) category status representations; (3) a 
demonstration that sellers continue to lack captive customers in 
order to support obtaining or retaining a waiver of the affiliate 
restrictions, if requested; and (4) any other information that is 
required for that particular filing.
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    37. Thus, we propose to add a paragraph to the end of Sec.  
35.37(c) (regarding horizontal market power), making it paragraph 
(c)(6) under this subsection, to read as follows: In lieu of submitting 
the indicative screens, Sellers in regional transmission organization 
and independent system operator markets with Commission-approved market 
monitoring and mitigation must include a statement that they are 
relying on such mitigation to address any potential horizontal market 
power concerns.
    38. In addition, we note that market-based rate sellers are not 
required by Order No. 697 or the regulations to provide indicative 
screens in their horizontal market power analyses when submitting 
change in status filings.\36\ In Order No. 697-A, the Commission 
stated:
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    \36\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 506 
(``[W]e will not require entities to automatically file an updated 
market power analysis with their change in status filings. . . . 
Furthermore, regardless of the seller's representation, if the 
Commission has concerns with a change in status filing (for example, 
market shares are below 20 percent, but are relatively high 
nonetheless), the Commission retains the right to require an updated 
market power analysis at any time.'').

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

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

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

[[Page 43542]]

submitted indicative screens in order to determine the effect of the 
change on its market power. We clarify that, with this proposed 
streamlined approach, an RTO seller need not submit indicative screens 
with its change in status filing even where it may have market power. 
Instead, the seller may state that it is relying on Commission-approved 
monitoring and mitigation to mitigate any potential market power it may 
have. However, the Commission still reserves the right to require an 
updated market power analysis at any time.
    40. We seek comment on this proposal.
2. Sellers With Fully-Committed Long-Term Generation Capacity
a. Current Policy
    41. The Commission has found that, if generation is committed to be 
sold on a long-term firm basis to one or more buyers and cannot be 
withheld by a seller, it is appropriate for a seller to deduct such 
capacity when performing the indicative screens. In Order No. 697-A, 
the Commission stated:

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

    \38\ Id. P 41.
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    42. Thus, the capacity dedicated to long-term firm power sales 
should be deducted from seller and affiliate capacity in Row C (Long-
Term Firm Sales) of the standard screen format provided in Appendix A 
to Subpart H of Part 35 for submitting the indicative screens.\39\ 
However, some sellers have filed indicative screens in which they did 
not deduct their fully-committed capacity or incorrectly reported 
capacity as fully committed when it was only committed for some 
seasons, for less than one year, or under certain market 
conditions.\40\ Moreover, some sellers have argued that there is no 
need to perform indicative screens when they can demonstrate that all 
of their capacity is committed under long-term contract.
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    \39\ 18 CFR 35.37(c)(4). We note that the market share screen 
was inadvertently deleted from Appendix A to Subpart H of Part 35 at 
the time that the Commission made a correction to the pivotal 
supplier screen in Order No. 697-A. See Order No. 697-A, FERC Stats. 
& Regs. ] 31,268 at n.6. We propose to amend Appendix A to Subpart H 
of Part 35 to add the market share screen that was inadvertently 
removed and to make proposed changes to both indicative screens as 
discussed herein.
    \40\ The EQR data dictionary defines firm power sales as sales 
that are non-interruptible for economic reasons and states that 
contracts with durations of one year or greater are long-term.
---------------------------------------------------------------------------

b. Proposal
    43. It is the Commission's policy to study uncommitted generation 
capacity in the indicative screens.\41\ Currently, the seller's owned 
or controlled capacity in megawatts is entered into the indicative 
screens and the fully-committed long-term (one year or longer) capacity 
is then deducted. If all of the seller and its affiliates' capacity in 
the relevant balancing authority areas or markets including first-tier 
balancing authority areas or markets is fully committed, this exercise 
results in a purely mathematical task (netting to zero uncommitted 
capacity), thus providing no significant additional information. 
Therefore, we clarify that where all generation owned or controlled by 
a seller and its affiliates in the relevant balancing authority areas 
or markets including first-tier balancing authority areas or markets is 
fully committed, sellers may explain that their capacity is fully 
committed in lieu of including indicative screens in their filings in 
order to satisfy the Commission's market-based rate requirements 
regarding horizontal market power. The Commission proposes to clarify 
that, in order to qualify as ``fully committed,'' a seller must commit 
the capacity so that none of the excluded capacity is available to the 
seller or its affiliates for one year or longer.
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    \41\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 37-38; 
April 14, 2004 Order, 107 FERC ] 61,018 at P 71 (``We will adopt an 
uncommitted pivotal supplier analysis that will evaluate the 
potential of an applicant (including its affiliates) to exercise 
market power based on the control area market's annual peak demand. 
We will also adopt an uncommitted market share analysis that will 
seasonally evaluate the market share of the uncommitted capacity of 
an applicant and its affiliates.'').
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    44. We propose that sellers claiming that all of their relevant 
capacity \42\ is ``fully committed'' would have to include the 
following information: The amount of generation capacity that is fully 
committed, the names of the counterparties, the length of the long-term 
contract, the expiration date of the contract, and a representation 
that the contract is for firm sales for one year or longer. In order to 
qualify as fully committed, the commitment of the generation capacity 
cannot be limited during that 12-month consecutive period in any way, 
such as limited to certain seasons, market conditions, or any other 
limiting factor. Furthermore, a seller's generation would not qualify 
as ``fully committed'' if, for example, the seller has generation 
necessary to serve native load, provider of last resort obligations, or 
a contract that could allow the seller to reclaim, recall, or otherwise 
use the capacity and/or energy or regain control of the generation 
under certain circumstances (such as transmission availability 
clauses).
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    \42\ ``Relevant'' capacity refers to seller and affiliated 
capacity in the study area, including the first tier.
---------------------------------------------------------------------------

    45. Finally, consistent with the existing regulations, a change in 
status filing will be required when a long-term firm sales agreement 
expires if it results in a net increase of 100 MW or more.\43\
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    \43\ Such a change would be a departure from the characteristics 
the Commission relied upon in granting market-based rate authority. 
See 18 CFR 35.42(a).
---------------------------------------------------------------------------

    46. We seek comment on these proposals.
3. Relevant Geographic Market for Certain Sellers in Generation-Only 
Balancing Authority Areas
a. Current Policy
    47. The Commission stated in Order No. 697 that ``the horizontal 
market power analysis centers on and examines the balancing authority 
area where the seller's generation is physically located'' \44\ and 
that the default relevant geographic market (default market) under both 
indicative screens ``will be first, the balancing authority area where 
the seller is physically located [the seller's home balancing authority 
area], and second, the markets directly interconnected to the seller's 
balancing authority area (first-tier balancing authority area 
markets).'' \45\ However, the Commission also noted that ``[w]here a 
generator is interconnecting to a non-affiliate owned or controlled 
transmission system, there is only one relevant market (i.e., the 
balancing authority area in which the generator is located).'' \46\ 
Similarly, the Commission continued to require RTO sellers ``to 
consider, as part of the relevant market, only the relevant [RTO] 
market and not first-tier markets to the [RTO].'' \47\
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    \44\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 37.
    \45\ Id. P 232.
    \46\ Id. n.217.
    \47\ Id. P 231 n.215.
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    48. The Commission further stated in Order No. 697 that a 
``balancing authority area means the collection of generation, 
transmission, and loads

[[Page 43543]]

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.
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    \48\ Id. P 251.
    \49\ Id. P 275. We note that a number of hubs (e.g., Palo Verde, 
Four Corners, and Mead, etc.) are located at the intersections of 
clearly-defined balancing authority areas. Historically, identifying 
the market for generation located at the hub was not important 
because vertically-integrated utilities used their own generation to 
meet their load. As the markets have evolved, many hubs have become 
trading centers and some IPPs have built generation near hubs. The 
Commission has defined a trading hub as ``a representative location 
at which multiple sellers buy and sell power and ownership changes 
hands, typically with trading of financial and physical products.'' 
Id.
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    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.
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    \50\ For purposes of market power analyses for market-based rate 
authority, we propose to define an IPP as a generation resource that 
has power production as its primary purpose, does not have a native 
load obligation, is not affiliated with any transmission owner 
located in the first-tier markets in which the IPP is competing and 
does not have an affiliate with a franchised service territory. This 
IPP could also have an OATT waiver on file.
    \51\ See, e.g., Sundevil Power Holdings, LLC, Docket No. ER10-
1777-000 (Sept. 15, 2010) (delegated letter order).
---------------------------------------------------------------------------

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

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

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

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

b. Proposal
    52. In light of the unusual and complex circumstances identified 
above that are associated with defining the relevant geographic market 
of an IPP located in a generation-only balancing authority area, and in 
light of the fact that a generation-only balancing authority area is 
not a market, we propose that the default relevant geographic market(s) 
for such a seller would be the balancing authority areas of each 
transmission provider to which its generation-only balancing authority 
area is directly interconnected.\55\ Thus, if an IPP's generation-only 
balancing authority area is directly interconnected with one or more 
balancing authority areas, the IPP would provide indicative screens for 
each of those balancing authority areas.
---------------------------------------------------------------------------

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

    53. We further propose that such IPP seller study all of its 
uncommitted generation capacity from the generation-only balancing 
authority area in the balancing authority area(s) of each transmission 
provider to which it is directly interconnected, since all such 
uncommitted capacity could potentially be sold in each market that is 
directly interconnected to the IPP's generation-only balancing 
authority area, even if the IPP has not sold into that market in the 
past.
    54. To illustrate how this proposal would work, if an IPP is 
located in a generation-only balancing authority area that is embedded 
within a transmission provider's balancing authority area, and that 
balancing authority area is the only balancing authority area that the 
IPP's generation-only balancing authority area is directly 
interconnected with, then the IPP will provide indicative screens for 
that transmission provider's balancing authority area. An IPP in this 
situation would not need to study the transmission provider's balancing 
authority first-tier markets, just as would be the case if that 
generator were similarly located in the transmission provider's 
balancing authority area. An example of this situation is NaturEner 
Power Watch, LLC (NaturEner), which has a generation-only balancing 
authority area that is located within the NorthWestern Energy balancing 
authority area. Thus, NaturEner would provide indicative screens that 
examine all of its uncommitted capacity in the NorthWestern Energy 
balancing authority area. NaturEner would not need to study itself in 
any other balancing authority areas unless its generation-only 
balancing authority area is directly interconnected to other balancing 
authority areas.
    55. Similarly, if an IPP is located in a generation-only balancing 
authority area in a remote area such as the desert

[[Page 43544]]

Southwest, then the Commission proposes that the IPP would have to 
provide indicative screens for the balancing authority area(s) of the 
transmission provider(s) to which its generation-only balancing 
authority area is directly interconnected. We further propose that an 
IPP assume that all of its uncommitted capacity may compete in each 
balancing authority area to which its generation-only balancing 
authority area is directly interconnected, since, as noted above, all 
such uncommitted capacity could potentially be sold in each market to 
which there is a direct interconnection, even if the IPP has not sold 
into that market in the past. Thus, for example, if it were the case 
that the generation-only balancing authority areas of the Gila River 
Power Company LLC and Sundevil generating plants are each directly 
interconnected with the balancing authority area operated by Arizona 
Public Service Co. (APS), then each of those IPPs would study 
themselves in the APS balancing authority area, and each would include 
all other competing generators from generation-only balancing authority 
areas directly interconnected with the APS balancing authority area in 
that study as well. These IPPs in generation-only balancing authority 
areas would also study themselves in the same manner in any other 
balancing authority areas to which their generation-only balancing 
authority area is directly interconnected.\56\ Consistent with what is 
proposed above, an IPP in this situation would not need to study any 
first-tier markets, just as would be the case if it were a generator 
located within the transmission provider's home balancing authority 
area.\57\
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    \56\ However, the transmission provider, in all cases, would 
consider the IPP generation capacity as first-tier generation when 
conducting its SIL studies and indicative screens.
    \57\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 232 
n.217.
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    56. If an IPP in a generation-only balancing authority area is 
directly interconnected to a transmission provider at an energy trading 
hub, we propose that the IPP would provide screens that study itself in 
the balancing authority area of each transmission provider that is 
directly interconnected at the trading hub. Thus, the balancing 
authority areas that are directly interconnected at the hub would each 
be relevant geographic markets for that IPP, and the IPP would provide 
screens that study the IPP in each of those transmission providers' 
balancing authority areas.\58\ Consistent with what is proposed above, 
we propose that the IPP should provide indicative screens that assume 
that all of its uncommitted capacity may compete in each of the 
balancing authority areas that are directly interconnected at that 
trading hub, since all such uncommitted capacity could potentially be 
sold in each market to which there is a direct interconnection, even if 
the IPP has not sold into that market in the past.\59\ Thus, for 
example, if an IPP in a generation-only balancing authority area in the 
Arizona desert is directly interconnected to a transmission provider at 
the Palo Verde trading hub at the Palo Verde and Hassayampa 
switchyards,\60\ then it would provide screens that study all of its 
uncommitted capacity in each balancing authority area that is directly 
interconnected at the switchyard. Also, consistent with what is 
proposed above, an IPP in this situation would not need to provide 
screens that study itself in any markets that are first tier to the 
various balancing authority areas that are directly interconnected at 
the switchyard.
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    \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.
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    57. We seek comment on these proposals.
4. Reporting Format for the Indicative Screens
a. Current Policy
    58. When submitting a horizontal market power analysis, sellers are 
required to use the standard screen format provided in Appendix A to 
Subpart H of Part 35 for submitting their indicative screens. Although 
sellers submit their indicative screens based on the formats provided 
in Appendix A to Subpart H of Part 35 and in Commission Order Nos. 697 
\61\ and 697-A,\62\ they currently perform their own mathematical 
calculations. The Commission does not currently provide pre-programmed 
spreadsheets that allow for automated mathematical calculations for 
sellers' indicative screens. When preparing their screens, certain 
sellers also perform SIL studies, which produce data (e.g., SIL values) 
applicable to the indicative screens.
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    \61\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 305-
306.
    \62\ See Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 17 
n.6, Appendix A.
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    59. In Puget,\63\ the Commission adopted a standardized format for 
reporting SIL study results in order to help ensure greater efficiency. 
The Commission directed sellers to refer to the guidance, directions, 
and reporting format provided in Appendix B of Puget when preparing and 
submitting SIL studies.\64\ Appendix B of Puget discusses various 
submittals, including ``Submittal 1,'' which is a spreadsheet that 
calculates the SIL values to be used in the indicative screens. 
Submittal 1 is a summary spreadsheet of the SIL components used to 
calculate the SIL values and is currently posted on the Commission's 
Web site. The last line of Submittal 1 (Row 10) contains the SIL values 
that sellers should use in preparing their screens.\65\ Currently, the 
screen reporting format in Appendix A of Subpart H, which is discussed 
in Order Nos. 697 and 697-A, does not have a row for SIL values even 
though the Uncommitted Capacity Import values in the indicative screens 
are constrained by the SIL value from Row 10 of Submittal 1, i.e., the 
sum of the affiliated and non-affiliated Uncommitted Capacity Import 
values cannot exceed the SIL value.\66\
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    \63\ Puget, 135 FERC ] 61,254 at Appendix B.
    \64\ Id. P 20.
    \65\ Id. at Appendix B.
    \66\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 361 
(explaining that a SIL study determines ``how much competitive 
supply from remote resources can serve load in the study area.'').
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    60. Appendix B of Puget also discusses ``Submittal 2,'' which is a 
spreadsheet that identifies long-term firm transmission reservations 
used to import power from seller and affiliate generating resources in 
the first-tier area to serve native load in the study area. The 
calculations performed in Submittal 2 provide detailed data summed to 
produce the total value of long-term firm transmission reservations, 
which are included in Row 5 of Submittal 1.
    61. The Commission provided additional direction on the completion 
of the indicative screens in Vantage Wind Energy, LLC.\67\ In 
particular, the Commission provided direction on how to account for 
both remote generation resources and long-term firm power purchases 
from generation resources located outside a seller's home balancing 
authority area when

[[Page 43545]]

performing the indicative screens.\68\ Currently, the indicative screen 
reporting formats in Appendix A of Subpart H and Order Nos. 697 and 
697-A do not have separate rows for the value of installed capacity of 
remote generation resources or the capacity of resources that are 
external to the study area that support long-term firm power purchase 
agreements that serve load in the study area; both values are 
components of the SIL value used in the screens.
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    \67\ Vantage Wind Energy, LLC, 139 FERC ] 61,063, at P 21 (2012) 
(Vantage Wind).
    \68\ Id. (``[L]oad serving entities should add their share of 
remote generation to Installed Capacity (Line A of the market share 
screen and the pivotal market share screen) and the amount of any 
long-term firm purchases in `Long-term Firm Purchases' (Line B of 
the market share screen and the pivotal supplier screen) of the 
indicative screens, when load-serving entities have long-term firm 
transmission rights associated with those resources.'').
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b. Proposal
    62. We propose to amend the indicative screen reporting format in 
Appendix A of Subpart H. We propose that Appendix A include both the 
pivotal supplier and market share screen reporting formats with new 
rows for SIL values, Long-Term Firm Purchases (from outside the study 
area), and Remote Capacity (from outside the study area). Including a 
row in the indicative screens for SIL value will help reinforce the 
relationship between the values for affiliated and non-affiliated 
capacity imports and the SIL value. For purposes of clarification, we 
also propose to modify the descriptive text of the rows in the 
indicative screens for Installed Capacity, Long-Term Firm Purchases, 
Long-Term Firm Sales, and Uncommitted Capacity Imports.\69\ As 
discussed below, the new rows and their descriptions will clarify that 
the resources are either inside or outside the study area for Installed 
Capacity and Long-Term Firm Purchases. Furthermore, the description for 
Uncommitted Capacity Imports will now be consistent across both 
indicative screens. An example of the proposed new indicative screen 
reporting formats for Appendix A to Subpart H is provided in Appendix A 
of this NOPR.
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    \69\ We propose to change the phrase ``Imported Power'' in Rows 
D and H of the pivotal supplier screen to ``Uncommitted Capacity 
Imports.'' We also propose to make the same change to Row E of the 
Market Share Screen. Thus, all four rows in the indicative screens 
will have the same text for this field, which represents affiliate 
and non-affiliate uncommitted capacity able to be imported from the 
first tier.
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    63. Additionally, we propose to revise the regulations at 18 CFR 
35.37(c)(4) to require sellers to file the indicative screens in a 
workable electronic spreadsheet format.\70\ The proposed new language 
is as follows: When submitting (proposing to delete) [a horizontal 
market power analysis]the indicative screens, a Seller must use the 
format provided in Appendix A of this subpart and file the indicative 
screens in an electronic spreadsheet format. A Seller must include all 
supporting materials referenced in the indicative screens (proposing to 
delete) [form].
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    \70\ ``Workable electronic spreadsheet'' refers to a machine 
readable file with intact, working formulas as opposed to a scanned 
document such as an Adobe PDF file.
---------------------------------------------------------------------------

    We propose to post on the Commission's Web site a pre-programmed 
spreadsheet as an example that sellers may use to submit their 
indicative screens.\71\ The example spreadsheet contains pre-programmed 
cells that allow for summations and data comparisons, as well as cells 
that restrict entries to negative or positive values where appropriate. 
We believe that these proposed changes to the indicative screens, as 
reflected in Appendix A to this NOPR, will aid sellers when preparing 
screens and minimize the need for follow up inquiries from staff and 
amended filings.
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    \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 https://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
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    64. We also propose to add a paragraph to the end of Sec.  
35.37(c), making it paragraph (c)(5), to codify the requirement in 
Puget that sellers submitting SIL studies adhere to the direction and 
required format for Submittals 1 and 2 found on the Commission's Web 
site \72\ and submit their information, as instructed, in workable 
electronic spreadsheets. The proposed new language is as follows: 
Sellers submitting simultaneous transmission import limit studies must 
file Submittal 1, and, if applicable, Submittal 2, in the electronic 
spreadsheet format provided on the Commission's Web site.
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    \72\ The sample spreadsheets for Submittals 1 and 2 are found at 
the Commission's Web site at https://www.ferc.gov/industries/electric/gen-info/mbr/authorization.asp under ``Quick Links.''
---------------------------------------------------------------------------

    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\
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    \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 https://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
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    65. We seek comment on these proposals.
5. Competing Imports
a. Current Policy
    66. The Commission permits sellers to make simplifying assumptions, 
where appropriate, and to submit streamlined horizontal market power 
analyses.\74\ In Order No. 697, the Commission stated that ``a seller, 
where appropriate, can make simplifying assumptions, such as performing 
the indicative screens assuming no import capacity or treating the host 
balancing authority area utility as the only other competitor.'' \75\
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    \74\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 308, 
321; April 14, 2004 Order, 107 FERC ] 61,018 at P 38.
    \75\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 321.
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b. Proposal
    67. We clarify that the phrase ``assuming no import capacity'' 
means that a seller may assume ``no competing import capacity'' from 
the first-tier markets (i.e., adjacent balancing authority areas or 
markets). This clarification is consistent with the April 14, 2004 
Order \76\ and other Commission orders.\77\ We further clarify that the 
seller must still include any uncommitted capacity that it and its 
affiliates can import into the study area. We believe that this 
clarification will aid sellers when preparing screens and minimize the 
need for follow up

[[Page 43546]]

inquiries from staff and amended filings.
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    \76\ April 14, 2004 Order, 107 FERC ] 61,018 at P 38 (``Where 
appropriate, the screens allow the applicant to submit streamlined 
applications or to forego the generation market power analysis 
entirely and, in the alternative, go directly to mitigation. For 
example, if an applicant would pass the screens without considering 
competing supplies from adjacent control areas, the applicant need 
not include such imports in its studies.'' (emphasis added)).
    \77\ See, e.g., Acadia Power Partners, LLC, 107 FERC ] 61,168, 
at P 12 (2004) (``We remind applicants that they may provide 
streamlined applications, where appropriate, to show that they pass 
both screens. For example, if an applicant would pass both screens 
without considering competing supplies imported from adjacent 
control areas, the applicant need not include such imports.'' 
(emphasis added) (footnote omitted)).
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6. Capacity Ratings
a. Current Policy
    68. The Commission allows sellers submitting indicative screens to 
rate their generation facilities using either nameplate or seasonal 
capacity ratings.\78\ With regard to sellers with energy-limited 
resources, such as hydroelectric and wind generation facilities, in 
lieu of using nameplate or seasonal capacity ratings in their 
submissions, the Commission stated in Order No. 697 that it would allow 
such sellers to provide an analysis based on historical capacity 
factors reflecting the use of a five-year average capacity factor, 
including a sensitivity test using the lowest and highest capacity 
factors for the previous five years.\79\ Since the issuance of Order 
No. 697, the Commission has recognized that sellers with newly-built 
energy-limited generation facilities may not have five years of 
historical data for use in their analyses. To address this situation, 
the Commission has allowed the use of the five most recent years of 
regional average capacity factors from the EIA to determine capacity 
factors for those resources.\80\
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    \78\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 343 
(``We will adopt the NOPR proposal that allows sellers to use 
seasonal capacity. We clarify that each seller must be consistent in 
its choice and thus must choose either seasonal or nameplate 
capacity and use it consistently throughout the analysis. In 
addition, a seller using seasonal capacity must identify in its 
submittal from what source the data was obtained.''). The Commission 
adopted the EIA definition of seasonal capacity as reported on Form 
EIA-860, Schedule 3, Part B, Line 2, which provides that seasonal 
capacity is the ```net summer or winter capacity''' and EIA 
instructions that ```net capacity should reflect a reduction in 
capacity due to electricity use for station service or 
auxiliaries.''' Id. (footnotes omitted).
    \79\ Id. P 344.
    \80\ See Golden Spread Electric Coop., Inc., 138 FERC ] 61,208, 
at P 16 (2012) (Golden Spread) (finding that a five-year average 
wind capacity factor derived from EIA data represents an appropriate 
analysis).
---------------------------------------------------------------------------

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

    \81\ See EIA, Annual Energy Outlook (May 2014), available at 
https://www.eia.gov/forecasts/aeo/source_renewable.cfm. In Table 58 
through Table 58.9 ``Renewable Energy Generation by Fuel--(by 
Area),'' EIA provides data for the total generating capacity, and 
actual (or estimated) electricity generated by renewable type for 22 
``electricity market module regions'' covering the lower 48 states. 
After converting the inputs into matching units, sellers can divide 
actual (or estimated) electricity generated by installed capacity to 
find the capacity factor.
    \82\ Sellers should use either nameplate, a five-year average of 
historical data, or EIA-derived five-year average regional capacity 
factors instead of seasonal capacity factors for energy-limited 
resources. The Commission found that a five-year average wind 
capacity factor derived from EIA regional data was an appropriate 
proxy for wind generators that do not have five years of historical 
data. See Golden Spread, 138 FERC ] 61,208 at P 16.
---------------------------------------------------------------------------

    70. While we are proposing this treatment for solar capacity, we 
acknowledge that photovoltaic solar facilities will effectively 
function with zero capacity during nighttime hours or during heavy 
overcast conditions, as the sun does not provide much, if any, solar 
energy from photovoltaic solar facilities during such conditions. Thus, 
we are seeking comment on whether it may make more sense to assign 
different capacity factors to solar generation as compared to other 
generation based on these operating characteristics. In particular, we 
seek comment on whether we should allow such sellers to use either 
nameplate capacity or five-year historical average capacity ratings 
during peak hours to determine the capacity rating for their solar 
technology generation resources, and, as noted above, sellers may use 
EIA regional average capacity factors over peak hours for the previous 
five years to determine capacity for those resources. In other words, 
we seek comment on whether using peak hours will provide a better 
measure of capacity for photovoltaic solar, as compared to all hours, 
which would necessarily include hours in which we can predict that 
output will be zero.
    71. Finally, consistent with Order No. 697, we propose to clarify 
that, within each filing, a seller must use the same capacity rating 
methodology for similar generation assets.\83\ Specifically, if a 
seller chooses in a particular filing to use seasonal ratings for one 
of its thermal units, it must use seasonal ratings for all of its 
thermal units in that filing. Likewise, if the seller chooses to use an 
alternative rating methodology, such as the five-year average for any 
energy-limited generation resource, it must use the five-year average 
for all energy-limited generation resources in that filing, for which 
five years of historical data is available; otherwise it must use the 
EIA-derived capacity factors for those resources for which the seller 
does not have five years of data. The seller must specify in the 
filing's transmittal letter or accompanying testimony, and in the 
generation asset appendix, which rating methodologies it is using. The 
seller must use the specified rating methodologies consistently 
throughout its entire filing, including in its transmittal letter, 
asset appendix, and indicative screens. This proposal does not preclude 
the seller from using a different capacity rating methodology for each 
type of generation facility (thermal or energy-limited) in subsequent 
filings (e.g., in its initial filing a seller may use nameplate ratings 
for its thermal units, then in its next filing choose to use seasonal 
ratings for its thermal units). We believe that when a seller 
consistently uses the same rating methodology within a filing, it will 
improve the accuracy of the horizontal market power analysis by linking 
the capacity values in the transmittal letter, accompanying testimony, 
generation asset appendix, and the indicative screens.
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    \83\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 343.
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    72. We seek comment on these proposals.

[[Page 43547]]

7. Reporting of Long-Term Firm Purchases
a. Current Policy
    73. In Order No. 697, the Commission stated that a seller's 
uncommitted capacity, as calculated in the indicative screens, is 
determined by adding the total nameplate or seasonal capacity of 
generation owned or controlled through contract and long-term firm 
capacity purchases, less operating reserves, native load commitments, 
and long-term firm sales.\84\ The Commission specified that capacity 
associated with contracts that confer operational control of a given 
facility to an entity other than the owner must be assigned to the 
entity exercising control over that facility, rather than to the entity 
that is the legal owner of the facility.\85\ Order No. 697 stated that 
if a market-based rate applicant has control over certain capacity, 
such that that applicant can affect the ability of the capacity to 
reach the market, then that capacity should be attributed to that 
applicant when performing the indicative screens.\86\ As a result, in 
their initial and triennial market-based rate filings, market-based 
rate applicants \87\ have been required to report long-term firm 
purchases in Row B of the indicative screens (Long-Term Firm Purchases) 
only if the purchase granted them control of the capacity.\88\ 
Similarly, for purposes of reporting a change in status, market-based 
rate applicants have been required to report long-term firm capacity 
purchases when assessing their cumulative generation capacity only if 
such purchases confer control of such capacity to the applicant 
purchaser.\89\
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    \84\ Id. P 38.
    \85\ Id. P 157.
    \86\ Id. P 174. The Commission found that determination of 
control is based on a review of the totality of circumstances on a 
fact-specific basis. Id.
    \87\ Although we generally use the term ``market-based rate 
sellers'' elsewhere in this NOPR, in this section we refer to such 
sellers as ``market-based rate applicants'' to avoid confusion when 
discussing sellers who are purchasers under long-term firm power 
purchase agreements.
    \88\ Reflecting this capacity in Row B has the effect of 
attributing the capacity to the market-based rate applicant.
    \89\ Order No. 697-B, FERC Stats. & Regs. ] 31,285 at PP 99-101.
---------------------------------------------------------------------------

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

    \90\ Id.
    \91\ Id. P 99.
    \92\ Id. P 101. In Integrys Energy Group, Inc., 123 FERC ] 
61,034 (2008), the Commission found that the sale of a ``Firm (LD)'' 
product, as defined in the EEI Master Power Purchase & Sale 
Agreement, by itself gives the purchaser only a right to receive 
energy and thus no rights that would allow the purchaser to control 
generation capacity. In reaching this determination, the Commission 
relied on the fact that the purchaser under a Firm (LD) product 
cannot force the seller to back down the output of any generator and 
the fact that if the purchaser refused to receive delivery, that 
refusal does not keep the power from entering the market because the 
seller has the right to resell the Firm (LD) product, as well as to 
receive damages from the purchaser.
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    75. As explained below, we have determined, after two complete 
rounds of regional reviews, that the limited reporting of long-term 
firm purchases may create errors or misleading results in the 
indicative screens submitted by some sellers. These errors include 
incorrectly-sized markets and negative market shares for franchised 
public utilities and inconsistencies between the SIL values reported in 
the screens and the SIL values calculated for the relevant market or 
balancing authority area. Specifically, on numerous occasions the 
Commission has encountered situations where neither the seller nor the 
purchaser under a long-term firm power sale is being attributed with 
the generation capacity that is used to make that sale. This is because 
the seller, consistent with Commission policy, has deducted the 
capacity committed under the long-term firm power sale \93\ for 
purposes of calculating that seller's uncommitted capacity, while the 
purchaser has used our policies (and underlying assumptions) outlined 
above to assume that it is also not responsible for this capacity and 
therefore has not included this capacity as part of the purchaser's 
uncommitted capacity. The combination of these actions by sellers and 
purchasers results in capacity under long-term firm power purchase 
agreements many times ``disappearing'' from the market, with neither 
counterparty reflecting the capacity in their screens.
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    \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).
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    76. One result of this practice is that it leads to the anomalous 
result in the indicative screens of some franchised public utility 
sellers appearing to be net short; that is, appearing to lack 
sufficient generation resources (both owned and purchased) to serve 
their peak load. In reality, franchised public utilities are required 
by state regulators to have sufficient generation resources (owned 
capacity and firm purchases) to serve their projected peak load and an 
additional ``planning reserve margin'' on top of that.\94\ Although it 
is unrealistic for franchised public utilities to rely extensively on 
spot market purchases to serve statutory load obligations, that is what 
is implied in some of the indicative screens that have been submitted 
by franchised public utilities that do not include long-term firm 
purchases in their indicative screens.
---------------------------------------------------------------------------

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

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

[[Page 43548]]

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

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

b. Proposal
    79. For the reasons stated above, we propose to modify the policy 
with respect to the reporting of long-term firm purchases in the 
indicative screens. Specifically, we propose to require applicants 
under the market-based rate program to report all of their long-term 
firm purchases \97\ of capacity and/or energy in their indicative 
screens and asset appendices, where the purchaser has an associated 
long-term firm transmission reservation, regardless of whether the 
seller has operational control over the generation capacity supplying 
the purchased power. If the long-term firm purchase involves the sale 
of energy, then the purchaser must convert the amount of energy to 
which it is entitled into an amount of generation capacity for purposes 
of its indicative screens and asset appendices, i.e., include the 
amount of the capacity as long-term firm purchases in Rows B (Long-Term 
Firm Purchases (from inside the study area)) or B1 (Long-Term Firm 
Purchases (from outside the study area)) of the proposed revised 
indicative screens and include it in its asset appendix. The seller 
under that power purchase agreement must do the same the next time it 
submits a market-based rate triennial or change of status filing with 
the Commission, i.e., convert the energy into capacity and include the 
amount of capacity as a long-term firm sale in Row C (Long-Term Firm 
Sales).\98\ When making these filings, we propose that both the 
purchaser and the seller must show how they made the energy-to-capacity 
conversion. Although this attribution of capacity is the default 
approach that we propose as a general policy, applicants or intervenors 
are free to raise fact-specific circumstances that they believe may 
support a different attribution of capacity.
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    \97\ The Commission in Vantage Wind directed the purchasers to 
report all long-term firm purchases if the purchase had long-term 
firm transmission rights associated with those resources. Id. We 
assume for purposes of our proposal here that all long-term firm 
purchases necessarily have long-term firm transmission rights 
associated with them. If that is not the case, as noted above, 
applicants or intervenors are free to raise fact-specific 
circumstances that they believe may support a different attribution 
of capacity.
    \98\ Our understanding is that many power purchase agreements 
for firm energy specify an associated capacity commitment from the 
seller. In cases where capacity commitments are not specified in the 
power purchase agreement, we propose that applicants use the 
following formula to convert energy to capacity (on a one-year 
basis): [energy (MWh)/8,760]/capacity factor = capacity (MW).
    Where energy (MWh) is the total amount of energy purchased under 
the power purchase agreement over the calendar year; 8,760 is the 
total hours of a calendar year (use 8,784 in a leap year); capacity 
factor is actual capacity factor achieved by the unit(s) supplying 
the energy during the calendar year and is a measure of a generating 
unit's actual output over a specified period of time compared to its 
potential or maximum output over that same period. For example, if 
700,000 MWh is the amount of firm energy purchased under a power 
purchase agreement during a calendar year, and the capacity factor 
of the generator supplying the energy is 0.8 or 80 percent, then the 
700,000 MWh of energy would be converted into approximate 100 MW of 
capacity. That is: (700,000 MWh/8,760)/0.8 = 100 MW.
---------------------------------------------------------------------------

    80. The intent of our proposed reform is to have an entity with 
market-based rate authority report all long-term firm purchases that it 
makes where the selling entity has a legal obligation to provide the 
purchaser with an energy supply that cannot be interrupted for economic 
reasons or at the seller's discretion. If the purchaser has contractual 
rights to receive the output of a long-term firm energy purchase, we 
propose that the amount of the capacity supplying that purchase must be 
reported in the purchaser's screens. We also propose to require that 
all such long-term firm purchases should be reported in Rows B (Long-
Term Firm Purchases (from inside the study area)) or B1 (Long-Term Firm 
Purchases (from outside the study area)) of the proposed revised 
indicative screens, depending on whether the generation resource(s) 
supplying the sale are located inside or outside the seller's balancing 
authority area, as explained earlier in this proposed rule.
    81. The proposal to require applicants under the market-based rate 
program to report all of their long-term firm purchases of capacity 
and/or energy in their indicative screens and asset appendices is 
supported based on the following considerations. First, it will size 
the market correctly and therefore improve the accuracy of the 
indicative screens, especially for franchised public utilities, whose 
indicative screens are used by the non-transmission owning sellers to 
prepare their own indicative screens. Currently, sellers often do not 
report some or all of their long-term firm purchases because they do 
not control these resources. Including all long-term firm purchases in 
the indicative screens will properly size the market and eliminate the 
unrealistic results (e.g., negative market shares) caused by the under-
reporting of generation noted above.
    82. Second, this proposed change will establish consistent 
treatment of long-term firm sales and long-term firm purchases in the 
indicative screens. Market-based rate applicants typically deduct long-
term firm sales without making a determination as to whether those 
sales confer operational control to the purchaser. The Commission, in 
Order No. 697, did not require that sellers make such a determination 
before deducting the capacity supporting long-term firm sales: 
``Uncommitted capacity is determined by adding the total nameplate or 
seasonal capacity of generation owned or controlled through contract 
and firm purchases, less operating reserves, native load commitments 
and long-term firm sales.'' \99\ The Commission clarified that 
``[s]ellers may deduct generation associated with their long-term firm 
requirements sales, unless the Commission disallows such deductions 
based on extraordinary circumstances.'' \100\
---------------------------------------------------------------------------

    \99\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 38 
(footnotes omitted).
    \100\ Id. n.18.
---------------------------------------------------------------------------

    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-

[[Page 43549]]

term power purchase agreements ``disappears'' from the market because 
neither the seller nor the purchaser includes the capacity as part of 
its uncommitted capacity (i.e., the seller subtracts the amount sold 
under the long-term power purchase agreement from its capacity for 
purposes of its screens, but sometimes the purchaser does not add the 
corresponding amount to its capacity for purposes of its screens). It 
is inevitable that some generation capacity will be excluded from the 
indicative screens, with resulting errors in market shares and overall 
market size, when differing standards are applied to long-term firm 
purchases and long-term firm sales with respect to the allocation of 
such capacity. This proposal will make those standards consistent, 
reducing such errors.
---------------------------------------------------------------------------

    \101\ Order No. 697-B, FERC Stats. & Regs. ] 31,285 at PP 99, 
100.
---------------------------------------------------------------------------

    84. Third, requiring the reporting of all long-term firm power 
purchases also will ensure consistent treatment of owned or installed 
capacity and long-term firm purchases in the indicative screens. The 
Commission's horizontal market power analysis implicitly assumes that 
applicants control all of their owned or installed capacity listed in 
their indicative screens but this is not necessarily the case.\102\ For 
example, in situations where an applicant is a minority owner of a 
jointly-owned generating unit, it is quite possible that the applicant 
will not have operational control (i.e., commitment and dispatch 
authority) over the unit.\103\ However, applicants typically include 
all of their owned or controlled generation capacity in the indicative 
screens regardless of whether they actually control the commitment and 
dispatch of this capacity. Accordingly, we propose that an applicant 
with long-term firm purchases treat such contracted-for capacity in a 
similar manner to an applicant that owns capacity; that is, such 
purchases should be included in the applicant's portfolio of generation 
for the indicative screens.
---------------------------------------------------------------------------

    \102\ In Order No. 697, the Commission noted that its historical 
approach has been that the owner of a facility is presumed to have 
control of the facility unless such control has been transferred to 
another party by virtue of a contractual agreement. The Commission 
stated that it would continue its practice of assigning control to 
the owner absent a contractual agreement transferring such control. 
Order No. 697, FERC Stats. & Regs. ] 31,252 at P 183.
    \103\ Another example is when a generator confers operational 
control to a third party through a long-term tolling agreement. See, 
e.g., Shell Energy North America (US), L.P., 135 FERC ] 61,090, at P 
3 (2011).
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    85. Finally, for those applicants incorrectly reporting long-term 
firm power purchases in the wrong row of the indicative screens, 
uniform reporting of these purchases will also help to ensure 
consistency between the SIL values reported in the screens and the 
Commission's accepted SIL values for the relevant market or balancing 
authority area. As the Commission noted in Vantage Wind,\104\ 
improperly classifying long-term firm purchases (or imports of 
remotely-owned installed capacity) as Imported Power in the existing 
screens (Row D of the pivotal supplier screen and Row E of the market 
share screen) may lead to an overstatement of the market's SIL values. 
This is because the sum of the values in the existing pivotal supplier 
screen for Seller and Affiliate Imported Power shown in Row D and Non-
Affiliate Imported Power shown in Row H should be less than or equal to 
the Commission-accepted SIL values. All Commission-accepted SIL values 
account for (i.e., subtract) long-term transmission reservations into 
the study area, so that they reflect the transmission capability 
available to competing sellers after accounting for the capability that 
the local utility has reserved for its own use to import power from 
remote resources. Thus, classifying long-term firm purchases as 
Imported Power effectively ``double counts'' import capability in the 
screens because it adds back the import capability associated with 
long-term firm purchases and assumes that this capability is available 
to potential competitors. This problem does not arise if long-term firm 
purchases (and imports of remotely-owned installed capacity) are 
properly classified in the indicative screens as Long-Term Firm 
Purchases (Rows B1 and F1 in the proposed screen format for the pivotal 
screen) and Remote Capacity (Rows A1 and E1 in the proposed screen 
format for the pivotal screen), respectively. This proposal is intended 
to help clarify how to classify imports of firm power and remotely-
owned capacity. These proposed changes to the pivotal supplier screen 
format are also being proposed for the market-share screen.
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    86. We seek comment on this proposal.

B. Vertical Market Power--Land Acquisition Reporting

1. Current Policy
    87. All market-based rate sellers are currently required, pursuant 
to Sec.  35.42(d) of the Commission's regulations and Order Nos. 697-C 
and 697-D, to file notices of change in status on a quarterly basis 
when they acquire sites for new generation capacity development.\105\ 
To date, not a single protest has been filed in response to these 
copious filings and the Commission has not uncovered any issues 
indicating that a particular seller has erected a barrier to entry as a 
result of its land acquisition. On a number of occasions over the 
years, market-based rate sellers have expressed frustration with this 
reporting requirement and have described it as burdensome.
---------------------------------------------------------------------------

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

    88. In Order No. 697, the Commission stated it would consider a 
seller's ability to erect other barriers to entry as part of the 
vertical market power analysis. Thus, the regulations require that a 
seller provide a description of its ownership or control of, or 
affiliation with an entity that owns or controls, intrastate natural 
gas transportation, intrastate natural gas storage or distribution 
facilities, sites for generation capacity development, and physical 
coal supply sources and ownership or control over who may access 
transportation of coal supplies.\106\ The Commission noted that, to 
date, it had not found such ownership or control to be a potential 
barrier to entry warranting further analysis, but that it did not have 
sufficient evidence to remove these inputs from the analysis entirely. 
Thus, it rebuttably presumed that ownership or control of or 
affiliation with an entity that owns or controls such facilities does 
not allow a seller to raise entry barriers, but would allow intervenors 
to demonstrate otherwise.\107\ In Order No. 697-C, the Commission noted 
that ``[o]ne of the purposes of the change of status reporting 
requirement is to provide interested parties the opportunity to 
intervene and comment if they believe the seller's acquisition of sites 
for new generation capacity

[[Page 43550]]

development creates a barrier to entry.'' \108\
---------------------------------------------------------------------------

    \106\ 18 CFR 35.37(e).
    \107\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 446.
    \108\ Order No. 697-C, FERC Stats. & Regs. ] 31,291 at P 17.
---------------------------------------------------------------------------

2. Proposal
    89. We propose to relieve market-based rate sellers of their 
obligation to file quarterly land acquisition reports and of the 
obligation to provide information on sites for generation capacity 
development in market-based rate applications and triennial updated 
market power analyses because the burden of such reporting outweighs 
the benefits.\109\
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    \109\ For an example of the burden, the Commission received, in 
the most recent seven quarters, 90 filings from 1,380 filers. This 
is a reporting burden on the sellers and an inefficient use of 
Commission resources for information that has yet to produce an 
actionable item or elicit a single comment in almost five years. All 
1,380 filers had to be listed in the notices and in the orders 
accepting the filings. Staff has written and issued seven orders 
accepting these filings, one order for each of the last seven 
quarters.
---------------------------------------------------------------------------

    90. In the more than six years since issuance of Order No. 697, 
intervenors have not challenged whether sites for new generation 
capacity development created a barrier to entry. For this reason, we 
propose to eliminate the requirement to provide such information. We 
note that, if there is a concern that a particular seller's sites for 
generation capacity development may be creating a barrier to entry, the 
Commission can request additional information from the seller at any 
time.\110\
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    91. Thus, we propose to revise the regulations at 18 CFR 35.42 to 
remove paragraph (d). This proposed revision removes the requirement 
that sellers report the acquisition of control of a site or sites for 
new generation capacity development for which site control has been 
demonstrated. Likewise, we propose to revise the regulations at 18 CFR 
35.42 to remove paragraph (e), which pertains to the definition of site 
control for purposes of paragraph (d). We also propose to revise the 
regulations at 18 CFR 35.37 to remove paragraph (e)(2), which requires 
sellers to provide information regarding sites for generation capacity 
development to demonstrate a lack of vertical market power. Therefore, 
under this proposal, Sec.  35.42(d)-(e) and Sec.  35.37(e)(2) would be 
removed entirely. In addition, we propose to revise 18 CFR 35.42 at 
paragraph (b) to remove the reference to the reporting of acquisition 
of control of a site or sites for new generation capacity development. 
Specifically, under this proposal, Sec.  35.42(b) would read as 
follows: Any change in status subject to paragraph (a) of this section, 
(proposing to delete) [other than a change in status submitted to 
report the acquisition of control of a site or sites for new generation 
capacity development], must be filed no later than 30 days after the 
change in status occurs. Power sales contracts with future delivery are 
reportable 30 days after the physical delivery has begun. Failure to 
timely file a change in status report constitutes a tariff violation.
    92. We seek comment on these proposals.

C. Notices of Change in Status

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

    \111\ 18 CFR 35.42(a).

    (1) Ownership or control of generation capacity results in net 
increases of 100 MW or more; [\112\] or
---------------------------------------------------------------------------

    \112\ 18 CFR 35.42(a)(1).
---------------------------------------------------------------------------

    (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\]
---------------------------------------------------------------------------

    \113\ 18 CFR 35.42(a)(2).
---------------------------------------------------------------------------

1. Geographic Focus
a. Current Policy
    94. In Order No. 697-A, the Commission clarified that sellers must 
report a change in status when they acquire 100 MW or more in the 
``geographic market that was the subject of the horizontal market power 
analysis on which the Commission relied in granting the seller market-
based rate authority.'' \114\
---------------------------------------------------------------------------

    \114\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 512.
---------------------------------------------------------------------------

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

    \115\ 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.''
---------------------------------------------------------------------------

b. Proposal
    96. We propose to clarify that the 100 MW reporting threshold in 
Sec.  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 first-tier/interconnected market with the potential to import into 
that market) since the seller's most recent triennial updated market 
power analysis or change in status filing, the seller must make a 
change in status filing. This would include cumulative increases of 100 
MW or more in a new market that has not previously been studied 
because, once the seller has generation in that market, it is a 
relevant geographic market for that seller. 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 Sec.  
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

[[Page 43551]]

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
    98. We seek comment on these proposals.
2. Long-Term Contracts
a. Current Policy
    99. 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\
---------------------------------------------------------------------------

    \116\ See 18 CFR 35.42(a)(1).
---------------------------------------------------------------------------

b. Proposal
    100. 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 Sec.  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 and propose to revise 
the beginning of Sec.  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]\
---------------------------------------------------------------------------

    \117\ 18 CFR 35.42(a).
---------------------------------------------------------------------------

    101. We seek comment on this proposal.
3. New Affiliation and Behind-the-Meter Generation
a. Current Policy
    102. 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.\118\ Currently, 
the 100 MW threshold for reporting increases in generation contained in 
Sec.  35.42(a)(1) of the Commission's regulations does not apply to the 
requirement to report a new affiliation found in Sec.  35.42(a)(2) of 
the Commission's regulations because the existing language in Sec.  
35.42(a)(2) does not reference the 100 MW threshold. As a result, Sec.  
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.
---------------------------------------------------------------------------

    \118\ 18 CFR 35.42(a)(2).
---------------------------------------------------------------------------

    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.\119\ 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 205 \120\ and behind-the-meter facilities.
---------------------------------------------------------------------------

    \119\ See id.
    \120\ 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).
---------------------------------------------------------------------------

    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. Proposal
    105. 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 
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.\121\ 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 Sec.  35.42(a)(2) of the Commission's 
regulations to read as follows:
---------------------------------------------------------------------------

    \121\ Reporting Requirement for Changes in Status for Public 
Utilities with Market-Based Rate Authority, Order No. 652, FERC 
Stats. & Regs. ] 31,175, at P 68, order on reh'g, 111 FERC ] 61,413 
(2005).
---------------------------------------------------------------------------

    Affiliation with any entity not disclosed in the application for 
market-based rate authority that: (i) (proposing to delete)[o]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 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) (proposing to delete)[affiliation 
with any entity not disclosed in the application for market-based rate 
authority that o]Owns, operates or controls transmission facilities;, 
or (iv) (proposing to delete)[affiliation with any entity that h]Has a 
franchised service area.
    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 Sec.  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.\122\

[[Page 43552]]

However, we propose to allow sellers to aggregate their behind-the-
meter generation by balancing authority area or market into one line on 
the list of generation assets. Similarly, 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.
---------------------------------------------------------------------------

    \122\ 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.
---------------------------------------------------------------------------

    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 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. Current Policy
    110. 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.\123\ 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.\124\ 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.\125\ The Commission requires the appendix of 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.\126\
---------------------------------------------------------------------------

    \123\ Id. P 894.
    \124\ Id. P 895.
    \125\ Id.
    \126\ The sample asset appendix can be found on the Commission's 
Web site at https://www.ferc.gov/industries/electric/gen-info/mbr/appendix.pdf.
---------------------------------------------------------------------------

2. Proposal
    111. As detailed below, we propose clarifications and revisions to 
the required appendix that contains the lists of assets.
a. Changes to the Existing Columns
    112. 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 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.\127\
---------------------------------------------------------------------------

    \127\ See Appendix B herein for an example of the proposed 
revised appendix.
---------------------------------------------------------------------------

    114. We seek comment on these proposed changes.
b. Clarifications Regarding the Existing Columns
    115. 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,\128\ 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.
---------------------------------------------------------------------------

    \128\ 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.
---------------------------------------------------------------------------

    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, 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.\129\ 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,\130\ 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 
registered in the Commission's company registration database,\131\ we 
propose to clarify that the name in the asset appendix for that

[[Page 43553]]

company must appear exactly the same as in the registration database.
---------------------------------------------------------------------------

    \129\ 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).
    \130\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 187.
    \131\ The term ``company registration database'' here refers to 
``FERC's Online Company Registration application'' (see https://www.ferc.gov/docs-filing/etariff/implementation-guide.pdf ). 
However, Commission orders have referred to this database as we have 
also issued orders referring to it as ``Company Registration,'' (see 
Filing Via the Internet, Revisions to Company Registration and 
Establishing Technical Conference, 142 FERC ] 61,097 (2013)) or 
``Company Registration system'' (see Order Updating Electric 
Quarterly Report Data Dictionary, 146 FERC ] 61,169 (2014)).
---------------------------------------------------------------------------

    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, 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. Changes Regarding OATT Waiver and Citations in Transmission Assets
    120. 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,\132\ 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 facilities \133\ 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 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.
---------------------------------------------------------------------------

    \132\ ``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.
    \133\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 408.
---------------------------------------------------------------------------

    121. We seek comment on these proposed changes.
d. Electronic Format
    122. 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 to 
submit all required appendices in the form and format of the sample 
electronic spreadsheets.\134\
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    \134\ 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 https://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
---------------------------------------------------------------------------

    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. Database
    126. 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 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. Current Policy
    128. 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

[[Page 43554]]

region; \135\ that do not own, operate or control transmission 
facilities other than limited equipment necessary to connect individual 
generating facilities to the transmission grid (or have been granted 
waiver of the requirements of Order No. 888); that are not affiliated 
with anyone that owns, operates or controls transmission facilities in 
the same region as the seller's generation assets; that are not 
affiliated with a franchised public utility in the same region as the 
seller's generation assets; and that do not raise other vertical market 
power issues.\136\ 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.\137\
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    \135\ 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 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.
    \136\ See id. PP 848-849 n.1000; see also 18 CFR 35.36(a)(2), 
35.37(a)(1).
    \137\ 18 CFR 35.36(a)(3), 35.37(a)(1).
---------------------------------------------------------------------------

    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).\138\ The seller category 
status for a power marketer is determined by considering all affiliated 
generation and 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.
---------------------------------------------------------------------------

    \138\ 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&CalendarID=116&Date=03/03/2010&View=Listview).
---------------------------------------------------------------------------

2. Proposal
    130. We propose to clarify the distinction in determining the 
seller category status of power marketers and power producers.\139\ 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.
---------------------------------------------------------------------------

    \139\ 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).
---------------------------------------------------------------------------

    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.\140\
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    \140\ 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 
balancing authority area or market where the seller is mitigated. 
Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 335.
---------------------------------------------------------------------------

    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 marketer(proposing to delete)[s] 
that controls or is affiliated with500 MW or less of generation in 
aggregate per region or a wholesale power producers that owns, 
(proposing to delete)[or] controls or is affiliated with 500 MW or less 
of generation in aggregate in the same region as its generation assets;
    (ii) (proposing to delete)[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 (proposing to delete)[have] been granted waiver of the 
requirements of Order No. 888, FERC Stats. & Regs. ] 31,036);
    (iii) (proposing to delete)[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) (proposing to delete)[that are] Is not affiliated with a 
franchised public utility in the same region as the S(proposing to 
delete)[s]eller's generation assets; and
    (v) (proposing to delete)[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. Current Policy
    135. 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 analyses and 
notices of change in status as a result of new affiliations. In Order 
No. 697-A, 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

[[Page 43555]]

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.[ \141\ ]
---------------------------------------------------------------------------

    \141\ Id. P 181 n.258.
---------------------------------------------------------------------------

b. Proposal
    136. 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 sellers with 
market-based rate authority with similar information that the 
Commission receives under section 203 of the FPA.\142\ We propose to 
require from market-based rate sellers an organizational chart similar 
to that which the Commission requires from section 203 applicants. 
Specifically, Sec.  33.2(c)(3) of the Commission's regulations \143\ 
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 post-transaction 
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.
---------------------------------------------------------------------------

    \142\ 16 U.S.C. 824b.
    \143\ See 18 CFR 33.2(c)(3).
---------------------------------------------------------------------------

    138. Thus, we propose to revise the regulatory text in Sec.  
35.37(a)(2) of the Commission's regulations as follows: 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 Sec.  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.[144]
---------------------------------------------------------------------------

    \144\ When the changes to Sec.  35.42(c) as proposed here are 
combined with the changes to Sec.  35.42(c) proposed above, the 
revised Sec.  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.
---------------------------------------------------------------------------

    140. We seek comment on these proposals.
2. Single Corporate Tariff
a. Current Policy
    141. Joint tariffs may be used when a corporate family has more 
than one affiliated seller with market-based rate authority.\145\ 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.\146\ 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, 
non-designated 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.
---------------------------------------------------------------------------

    \145\ Electronic Tariff Filings, Order No. 714, FERC Stats. & 
Regs. ] 31,276, at P 60 (2008).
    \146\ See id. P 63.
---------------------------------------------------------------------------

    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. Proposal
    143. 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 https://

[[Page 43556]]

www.ferc.gov/industries/electric/gen-info/mbr/tariff/joint.asp.

G. Clarification of Commission Language in Performing SIL Studies

1. Current Policy
a. OASIS Practices
    144. 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 that can be imported into the 
relevant geographic market.\147\ 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.\148\
---------------------------------------------------------------------------

    \147\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 19.
    \148\ 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.
---------------------------------------------------------------------------

    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.\149\
---------------------------------------------------------------------------

    \149\ 18 CFR 37.2, 37.6(b).
---------------------------------------------------------------------------

b. SIL Studies and OASIS Practices
    146. 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.'' \150\ Order No. 
697 also stated that
---------------------------------------------------------------------------

    \150\ 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)).

[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.\151\
---------------------------------------------------------------------------

    \151\ Id. n.361.

    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.'' \152\
---------------------------------------------------------------------------

    \152\ April 14 Order, 107 FERC ] 61,018 at Appendix E.
---------------------------------------------------------------------------

    148. Similarly, in Pinnacle West,\153\ 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.'' \154\
---------------------------------------------------------------------------

    \153\ 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.
    \154\ Pinnacle West, 110 FERC ] 61,127 at P 8.
---------------------------------------------------------------------------

    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.'' \155\
---------------------------------------------------------------------------

    \155\ Carolina Power & Light Co., 128 FERC ] 61,039, at P 7 
(Carolina Power & Light), clarified, 129 FERC ] 61,152 (2009).
---------------------------------------------------------------------------

    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.\156\ 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 non-
affiliated load in net area interchange.\157\ Finally, the Commission 
required that applicants document all instances where the SIL study 
differs from historical practices.\158\
---------------------------------------------------------------------------

    \156\ Puget, 135 FERC ] 61,254 at Appendix B, Reporting 
Requirements for Submittals 8, 9.
    \157\ Id. at Reporting Requirements for Submittal 10.
    \158\ Id. at Reporting Requirements for Submittal 11.
---------------------------------------------------------------------------

    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.''\159\ Historical conditions include
---------------------------------------------------------------------------

    \159\ April 14, 2004 Order, 107 FERC ] 61,018 at Appendix E.

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.[\160\]
---------------------------------------------------------------------------

    \160\ Id.

    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.'' \161\
---------------------------------------------------------------------------

    \161\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 354.
---------------------------------------------------------------------------

    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.'' \162\
---------------------------------------------------------------------------

    \162\ Puget, 135 FERC ] 61,254 at P 15.
---------------------------------------------------------------------------

    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.\163\ This 
direction is reflected in Row 8 of Submittal 1 found in Appendix B of 
Puget.\164\
---------------------------------------------------------------------------

    \163\ Id. P 16.
    \164\ Id. at Appendix B.
---------------------------------------------------------------------------

c. Simultaneous TTC
    155. 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.\165\
---------------------------------------------------------------------------

    \165\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 364.

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[[Page 43557]]

    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.'' \166\
---------------------------------------------------------------------------

    \166\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 142.
---------------------------------------------------------------------------

2. Proposal
    157. 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 values \167\ 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 non-
affiliated uncommitted generation resources requesting long-term firm 
transmission service. The following clarifications are therefore 
proposed.
---------------------------------------------------------------------------

    \167\ See Row 4 of proposed Submittal 1 (Total Simultaneous 
Transfer Capability).
---------------------------------------------------------------------------

a. OASIS Practices
    159. 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 ATC \168\ and for evaluating 
transmission service requests. We propose the following clarifications:
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    \168\ 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).
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    160. We propose to clarify that the term ``OASIS practices'' refers 
specifically to the seasonal benchmark power flow case modeling 
assumptions, study solution criteria,\169\ and operating practices 
historically used by the first-tier and study area transmission 
providers \170\ to calculate and post ATC and to evaluate requests for 
firm transmission service.\171\
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    \169\ 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.
    \170\ 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.
    \171\ 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 inappropriate as a 
measure of uncommitted generation capacity in the first-tier 
available to compete in the study area.
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    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.\172\
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    \172\ 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), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf. In the SIL study 
context, this may include switching procedures, special protection 
systems, load throw-over schemes, temporary transmission line rating 
changes, and other actions that are not typically represented in the 
seasonal benchmark power flow models.
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b. SIL Studies and OASIS Practices
    162. 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 documentation specifically identifying such 
practices.\173\ We propose to clarify that to the extent that a 
seller's SIL study departs from actual OASIS practices,\174\ 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.
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    \173\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 356.
    \174\ See Puget, 135 FERC ] 61,254 at Appendix B.
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    163. Further, we remind sellers that the calculated SIL value 
should account for any limits defined in the tariff, such as stability 
or voltage.\175\ 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.\176\
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    \175\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 346.
    \176\ 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.'').
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    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.'' \177\
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    \177\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 145.
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    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 
value \178\ by

[[Page 43558]]

subtracting all long-term firm import transmission reservations.\179\ 
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.\180\ 
The proposed revised Appendix A Standard Screen Format accounts for all 
long-term firm import transmission reservations into the study 
area.\181\ Therefore, we propose to direct 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.
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    \178\ 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.
    \179\ See Revised Appendix E, Submittal 1, Row 5.
    \180\ Puget, 135 FERC ] 61,254 at P 15.
    \181\ 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.
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    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 lines \182\ and is not interconnected to any 
other first-tier market or balancing authority area, sellers should 
follow their OASIS practices regarding calculation and posting of ATC 
for such areas. If sellers' OASIS practices are incompatible with the 
SIL study (e.g., ATC is based on tie line rating), sellers may use an 
alternative process to account for import capability for such tie 
lines. 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.
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    \182\ Controllable tie lines include DC transmission facilities 
and AC transmission facilities with the ability to control the 
magnitude and direction of power flows through equipment such as 
converters, phase shifting transformers, variable frequency 
transformers, etc.
---------------------------------------------------------------------------

    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 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.'' \183\ 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.'' \184\ 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.\185\ However, the exclusion of 
all study area non-affiliated load may result in SIL values that are 
inconsistent with the intent of the indicative screens. Furthermore, in 
the event the SIL value is limited by study area load, restricting 
study area load to affiliated load fails to account for import 
capability that may be used to serve wholesale load customers. 
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 is modeled as part of the study 
area.\186\ 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'').
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    \183\ 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 P 77 (2006)).
    \184\ Id. P 361.
    \185\ Puget, 135 FERC ] 61,254 at Appendix B.
    \186\ If the load is modeled as part of another area, i.e., as a 
non-area load attached to an area bus, and the net area interchange 
calculation includes both tie lines and non-area loads attached to 
area buses, net area interchange associated with service to such 
load should be approximately zero, and no adjustment will be 
necessary.
---------------------------------------------------------------------------

    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 Appendix E to this NOPR, to provide 
additional clarity on the expected values for certain rows.\187\ We 
propose to post a new version of Submittal 1 on the Commission's Web 
site.
---------------------------------------------------------------------------

    \187\ See Revised Appendix E, Submittal 1.
---------------------------------------------------------------------------

c. Simultaneous TTC
    172. 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

[[Page 43559]]

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 areas is properly 
accounted for in the underlying SIL values on a case-by-case 
basis.\188\ 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.
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    \188\ Atlantic Renewables Projects II, 135 FERC ] 61,227, at P 9 
(2011).
---------------------------------------------------------------------------

    174. We seek comment on these proposals.

H. Parts 101 and Part 141 Waivers

1. Current Policy
    175. 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 Sec. Sec.  
141.14 and 141.15.\189\ 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.\190\ However, the Commission 
typically does not grant market-based rate sellers waiver of Sec. Sec.  
141.14 and 141.15 of the Commission's regulations, which address 
certain reporting requirements applicable to hydropower licensees.\191\
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    \189\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 976, 
984.
    \190\ 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 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' '').
    \191\ See Electron Hydro, LLC, 144 FERC ] 61,161, at P 23 
(2013).
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2. Proposal
    176. 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.\192\ We further 
note that a licensee's status as a market-based rate seller under Part 
II of the FPA does not exempt it from accounting responsibilities as a 
licensee under Part I of the FPA.\193\ 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.
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    \192\ In Trafalgar Power Inc., 87 FERC ] 61,207, at 61,798 n.46 
(1999) (Trafalgar Power), the Commission stated:
    Under [s]ection 14 of the FPA, the Federal government may take 
over a project upon expiration of the project's licensee, 
conditioned upon the government's payment to the licensee of the 
`net investment of the licensee in the project or projects taken.' 
Section 4(b) requires licensees to file a statement showing the 
`actual legitimate original cost of construction of such project' to 
enable the Commission to determine `the actual legitimate cost of 
and the net investment in' the project. Section 10(d) requires 
licensees to establish an amortization reserve account that will 
reflect excess or surplus earnings of their licensed project if such 
earnings have accumulated in excess of a reasonable rate of return 
upon the `net investment' in the project during a period beginning 
after the first twenty years of operations. Pursuant to [s]ection 10 
(d) of the FPA the amount transferred to the amortization reserve 
may be used to reduce a licensee's net investment in the project, 
and if, after expiration of the license, the government takes over 
the project under [s]ection 14, it will be required to compensate 
the licensee for its net investment in the project, reduced by the 
amortization reserve for the project.
    \193\ See Seneca Gen., LLC, 145 FERC ] 61,096, at P 23 n.20 
(2013) (citing Trafalgar Power, 87 FERC ] 61,207, at 61,798).
---------------------------------------------------------------------------

    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 its 
market-based rate tariff specifies that waiver of Part 141 has been 
granted, with the exception of Sec. Sec.  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).\194\
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    \194\ See Domtar Maine, LLC, 133 FERC ] 61,207, at P 23 (2010).
---------------------------------------------------------------------------

    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

[[Page 43560]]

and 141 waivers within 30 days of the effective date of its license.

I. Miscellaneous

1. Regional Reporting Schedule
    179. 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.'' \195\ 
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.'' \196\ 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 Sec.  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 (proposing to 
delete)[contained in Order No. 697, FERC Stats. & Regs. ] 31,252] 
posted 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.
---------------------------------------------------------------------------

    \195\ 18 CFR 35.37(a)(1).
    \196\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 850.
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    180. We also include an updated region map in Appendix D of this 
NOPR.
2. Affirmative Statement
    181. In Order No. 697, as part of the vertical market power 
analysis, the Commission stated that it would require sellers to make 
an affirmative statement that they have not erected barriers to entry 
into the relevant market and will not erect barriers to entry into the 
relevant market.\197\ This requirement is codified at Sec.  
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.'' 
\198\ 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.\199\ However, many 
sellers have not mentioned their affiliates when making their 
affirmative statements. Therefore, we propose to revise Sec.  
35.37(e)(4) (which is proposed elsewhere in this NOPR to be renumbered 
as Sec.  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 (proposing to 
delete)[has] not erected barriers to entry into the relevant market and 
will not erect barriers to entry into the relevant market.
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    \197\ Id. P 447.
    \198\ 18 CFR 35.37(e)(4).
    \199\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 447.
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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).\200\ The OMB regulations require approval of certain 
reporting and recordkeeping requirements (collections of information) 
imposed by agency rules.\201\ 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.
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    \200\ 44 U.S.C. 3507(d) (2012).
    \201\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    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,\202\ 
including the use of automated information techniques.
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    \202\ 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.
---------------------------------------------------------------------------

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 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.\203\ 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 market-based rate authority, and notices of 
change in status.
---------------------------------------------------------------------------

    \203\ 18 CFR 35.37.
---------------------------------------------------------------------------

    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 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

[[Page 43561]]

more.\204\ The Commission proposes to eliminate the burden on all 
market-based rate sellers by discontinuing the quarterly land 
acquisition reporting requirement in Sec.  35.42(d). The Commission 
also proposes to eliminate the provision in Sec.  35.37(e)(2) requiring 
reporting of sites for generation capacity development as part of the 
vertical market power analysis.
---------------------------------------------------------------------------

    \204\ 18 CFR 35.42(d).
---------------------------------------------------------------------------

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 follow-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 market-based 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; \205\ (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.
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    \205\ 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.
---------------------------------------------------------------------------

    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.
    Public Reporting Burden: The Commission recently issued notices on 
the burden estimate for FERC-919.\206\ The estimated total annual 
burden of 85,444 hours includes:
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    \206\ The Commission issued notices requesting comment in Docket 
No. IC14-2-000. 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.
---------------------------------------------------------------------------

     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: \207\
---------------------------------------------------------------------------

    \207\ 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.

                                    FERC-919, Burden After Implementation of Proposals in NOPR in Docket No. RM14-14
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                  Number of                           Average burden    Estimated total
                                                               Number of        responses per     Total number of       hours per        annual burden
                                                              respondents         respondent         responses           response            hours
                                                                         (A)                (B)    (A) x (B) = (C)                (D)          (C) x (D)
--------------------------------------------------------------------------------------------------------------------------------------------------------
New applications for market-based rates [18 CFR 35.37],                  107                  1                107                250             26,750
 With Screens............................................
New applications for market-based rates [18 CFR 35.37],                  106                  1                106                120             12,720
 No Screens..............................................
Triennial market power analysis in Category 2 seller                      42                  1                 42                250             10,500
 updates [18 CFR 35.37], With Screens....................
Triennial market power analysis in Category 2 seller                      41                  1                 41                120              4,920
 updates [18 CFR 35.37], No Screens......................
Quarterly land acquisition reports [18 CFR 35.42(d)].....                  0                  0                  0                  0                  0
Change in status reports [18 CFR 35.42(a)], With Screens.                 13                  1                 13                250              3,250
Change in status reports [18 CFR 35.42(a)], No Screens...                224                  1                224                 20              4,480
                                                          ----------------------------------------------------------------------------------------------
    Total................................................  .................  .................  .................  .................             62,620
--------------------------------------------------------------------------------------------------------------------------------------------------------

    192. After implementation of the proposed changes, the total 
estimated annual cost burden to respondents is $5,497,409.80 [62,620 
hours * $87.79 \208\) = $5,497,409.80]. This represents a reduction in 
total annual burden for FERC-919 of 22,824 hours \209\ (to 62,620 hours 
from 85,444 hours) or a 27 percent reduction.
---------------------------------------------------------------------------

    \208\ The Commission estimates this figure based on the Bureau 
of Labor Statistics data (for the Utilities sector, at https://www.bls.gov/oes/current/naics2_22.htm, plus benefits information at 
https://www.bls.gov/news.release/ecec.nr0.htm). The salaries (plus 
benefits) for the three occupational categories are:
    Economist: $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].
    \209\ 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.

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[[Page 43562]]

    Title: Proposed Revisions to Market Based Rates for Wholesale Sales 
of Electric Energy, Capacity and Ancillary Services by Public Utilities 
(FERC-919).
    Action: Revision of Currently Approved Collection of Information.
    OMB Control No.: 1902-0234.
    Respondents for this Rulemaking: Public utilities, wholesale 
electricity sellers, businesses, or other for profit and/or not for 
profit institutions.
    Frequency of Responses:
    Initial Applications: On occasion.
    Updated Market Power Analyses: Updated market power analyses are 
filed every three years by Category 2 sellers seeking to retain market-
based rate authority.
    Land Acquisitions: We 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 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, email: 
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) 395-7285]. For 
security reasons, comments to OMB should be submitted by email 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.\210\ The 
Commission has categorically excluded certain actions from this 
requirement as not having a significant effect on the human 
environment.\211\ 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.\212\ 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.\213\ As explained above, this proposed rule, which addresses 
the issue of electric rate filings submitted by public utilities for 
market-based rate authority, is clarifying in nature. Accordingly, no 
environmental assessment is necessary and none has been prepared in 
this NOPR.
---------------------------------------------------------------------------

    \210\ 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).
    \211\ 18 CFR 380.4.
    \212\ 18 CFR 380.4(a)(2)(ii).
    \213\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act

    194. The Regulatory Flexibility Act of 1980 (RFA) \214\ 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 small business.\215\ 
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).\216\ 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: \217\
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    \214\ 5 U.S.C. 601-612 (2012).
    \215\ 13 CFR 121.101 (2013).
    \216\ SBA Final Rule on ``Small Business Size Standards: 
Utilities,'' 78 FR 77343 (Dec. 23, 2013).
    \217\ 13 CFR 121.201, Sector 22, Utilities.
---------------------------------------------------------------------------

     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,\218\ at 100 employees
---------------------------------------------------------------------------

    \218\ The NAICS category 425120 (Wholesale Electronic Markets 
and Agents and Brokers, within Subsector 425) covers Power 
Marketers.
---------------------------------------------------------------------------

    195. Based on U.S. economic census data,\219\ 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.\220\ 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.
---------------------------------------------------------------------------

    \219\ Data and further information are available from SBA at 
https://www.sba.gov/advocacy/849/12162.
    \220\ 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.

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[[Page 43563]]

    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 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,\221\ 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.\222\ 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.
---------------------------------------------------------------------------

    \221\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 1126-
1129.
    \222\ 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).
---------------------------------------------------------------------------

    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 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.

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 September 23, 2014. 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 https://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.

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 (https://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, 
Washington, DC 20426.
    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. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

List of Subjects in 18 CFR Part 35

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

    By direction of the Commission.

    Issued: June 19, 2014.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    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

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

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

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

[[Page 43564]]

Sec.  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 Seller's generation assets; and
    (v) Does not raise other vertical market power issues.
* * * * *
0
3. Amend Sec.  35.37 as follows:
0
a. In paragraph (a)(1), remove the phrase ``contained in Order No. 697, 
FERC Stats. & Regs. ] 31,252'' and add in its place ``posted on the 
Commission's Web site.''
0
b. Revise paragraphs (a)(2) and (c)(4).
0
c. Add paragraphs (c)C(5) and (c)(6).
0
d. Remove paragraph (e)(2) and redesignate paragraphs (e)(3) and (4) as 
paragraphs (e)(2) and (3), respectively.
0
e. Revise newly redesignated paragraph (e)(3).
    The revisions and additions read as follows:


Sec.  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) * * *
    (4) When submitting the indicative screens, a Seller must use the 
format provided in Appendix A of this subpart and file the indicative 
screens in an electronic spreadsheet format. A Seller must include all 
supporting materials referenced in the indicative screens.
    (5) Sellers submitting simultaneous transmission import limit 
studies must file Submittal 1, and, if applicable, Submittal 2, in the 
electronic spreadsheet format provided on the Commission's Web site.
    (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.
* * * * *
0
4. Amend Sec.  35.42 as follows:
0
a. Revise paragraphs (a)(1), (a)(2), and (c).
0
b. In paragraph (b), remove the phrase ``, other than a change in 
status submitted to report the acquisition of control of a site or 
sites for new generation capacity development,''.
0
c. Remove paragraphs (d) and (e).
    The revisions read as follows:


Sec.  35.42  Change in status reporting requirement.

    (a) * * *
    (1) Ownership or control of generation capacity or long-term firm 
purchases of capacity and/or energy that results in cumulative net 
increases (i.e., the difference between increases and decreases in 
affiliated generation capacity) of 100 MW or more of nameplate capacity 
in any 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 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.
BILLING CODE: 6717-01-P

[[Page 43565]]

0
5. Appendix A of subpart H is revised to read as follows:
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[[Page 43566]]


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[[Page 43567]]


0
6. Appendix B of subpart H is revised to read as follows:
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[[Page 43568]]


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[FR Doc. 2014-16002 Filed 7-24-14; 8:45 am]
BILLING CODE 6717-01-P