[Federal Register Volume 77, Number 197 (Thursday, October 11, 2012)]
[Rules and Regulations]
[Pages 61895-61936]
[FR Doc No: 2012-23746]

Vol. 77

Thursday,

No. 197

October 11, 2012

Part III

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Electricity Market Transparency Provisions of Section 220 of the
Federal Power Act; Final Rule

Federal Register / Vol. 77 , No. 197 / Thursday, October 11, 2012 /
Rules and Regulations

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM10-12-000; Order No. 768]

Electricity Market Transparency Provisions of Section 220 of the
Federal Power Act

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: The Commission is revising its regulations pursuant to section
220 of the Federal Power Act (FPA), as enacted by section 1281 of the
Energy Policy Act of 2005 (EPAct 2005), to facilitate price
transparency in markets for the sale and transmission of electric
energy in interstate commerce. In doing so, the Commission revises its
regulations to require market participants that are excluded from the
Commission's jurisdiction under FPA section 205 and have more than a de
minimis market presence to file Electric Quarterly Reports (EQR) with
the Commission.
    In addition, the Commission revises the existing EQR filing
requirements applicable to market participants in the interstate
wholesale electric markets by adding new fields for: reporting the
trade date and the type of rate; identifying the exchange used for a
sales transaction, if applicable; reporting whether a broker was used
to consummate a transaction; reporting electronic tag (e-Tag) ID data;
and reporting standardized prices and quantities for energy, capacity
and booked out power transactions. The Commission also requires EQR
filers to indicate in the existing ID data section whether they report
their sales transactions to an index publisher and, if so, to which
index publisher(s), and, if applicable, identify which types of
transactions are reported. The Commission also eliminates the time zone
from the contract section and the Data Universal Numbering System
(DUNS) data requirement. These refinements to the existing EQR filing
requirements reflect the evolving nature of interstate wholesale
electric markets, will increase market transparency for the Commission
and the public, and will allow market participants to file the
information in the most efficient manner possible.

DATES: Effective Date: This rule will become effective December 10,
2012.

FOR FURTHER INFORMATION CONTACT:

Maria Vouras, Office of Enforcement, Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426,<PHONE_NUMBER>,
<EMAIL_ADDRESS>Steven Reich, Office of Enforcement, Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426,<PHONE_NUMBER>,
<EMAIL_ADDRESS>Christina Switzer, Office of the General Counsel, Federal Energy
Regulatory Commission, 888 First Street NE., Washington, DC 20426,
(202) 502-6379<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Order No. 768

Final Rule

Table of Contents

                                                               Paragraph
                                                                  No.

I. Introduction.............................................           5
    A. Order No. 2001.......................................           5
    B. EPAct 2005...........................................           7
    C. Procedural History...................................           9
II. Discussion..............................................          10
    A. Extending the EQR Filing Requirements to Non-Public            10
     Utilities..............................................
        1. Need for Information from Non-Public Utilities             10
         and Commission's Legal Authority...................
            a. Value of Information from Non-Public                   10
             Utilities......................................
                i. NOPR.....................................          10
                ii. Comments................................          12
                iii. Commission Determination...............          19
            b. Existing Sources of Information..............          28
                i. NOPR.....................................          28
                ii. Comments................................          29
                iii. Commission Determination...............          35
            c. De Minimis Threshold.........................          40
                i. NOPR.....................................          40
                ii. Comments................................          41
                 (a) Setting the Threshold..................          41
                 (b) Applying the Threshold.................          47
                iii. Commission Determination...............          54
        2. Filing Requirements for Non-Public Utilities.....          59
            a. Scope of EQR Filing Requirements for Non-              59
             Public Utilities...............................
                i. NOPR.....................................          59
                ii. Comments................................          60
                iii. Commission Determination...............          73
            b. Burden.......................................          76
                i. NOPR.....................................          76
                ii. Comments................................          77
                iii. Commission Determination...............          82
    B. Refinements to the Existing EQR Requirements.........          86
        1. General Refinements..............................          86
            a. Trade Date & Time and Type of Rate...........          86
                i. NOPR.....................................          86
                ii. Comments................................          87
                 (a) Trade Date.............................          88
                 (1) Commission Determination...............          90
                 (b) Time of Trade..........................          96
                 (1) Commission Determination...............         102

                 (c) Type of Rate...........................         103
                 (1) Commission Determination...............         105
            b. Resale of Financial Transmission Rights in            109
             Secondary Markets..............................
                i. NOPR.....................................         109
                ii. Comments................................         110
                iii. Commission Determination...............         111
            c. Standardizing the Unit for Reporting Energy           112
             and Capacity Transactions......................
                i. NOPR.....................................         112
                ii. Comments................................         113
                iii. Commission Determination...............         116
            d. Omitting the Time Zone from the Contract              119
             Section of the EQR.............................
                i. NOPR.....................................         119
                ii. Comments................................         120
                iii. Commission Determination...............         121
        2. Additional EQR Enhancements......................         122
            a. Identify Transactions Reported to Index               122
             Publishers.....................................
                i. NOPR.....................................         122
                ii. Comments................................         123
                iii. Commission Determination...............         127
            b. Identify the Exchange/Broker Used To                  132
             Consummate a Transaction.......................
                i. NOPR.....................................         132
                ii. Comments................................         133
                iii. Commission Determination...............         137
            c. Collection of e-Tag ID Data..................         143
                i. NOPR.....................................         143
                ii. Comments................................         144
                 (a) Burdens................................         145
                 (b) Implementation Issues..................         146
                iii. Commission Determination...............         156
            d. Eliminating the DUNS Number Requirement......         168
                i. NOPR.....................................         168
                ii. Comments................................         169
                iii. Commission Determination...............         171
            e. Other Issues.................................         172
                i. Comments.................................         172
                ii. Commission Determination................         173
III. Information Collection Statement.......................         176
    A. Comments.............................................         176
    B. Commission Determination.............................         178
IV. Environmental Analysis..................................         185
V. Regulatory Flexibility Act...............................         186
VI. Document Availability...................................         192
VII. Effective Date and Congressional Notification..........         195
Attachment A: Revisions to the EQR Data Dictionary Clean
 Version
Attachment B: List of Commenters on the NOPR

Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller,
John R. Norris, Cheryl A. LaFleur, and Tony T. Clark.

Final Rule

Issued September 21, 2012.
    1. To facilitate price transparency in markets for the sale and
transmission of electric energy in interstate commerce, the Federal
Energy Regulatory Commission (Commission) pursuant to section 220 of
the Federal Power Act (FPA) \1\ revises its regulations to require
market participants that are excluded from the Commission's
jurisdiction under section 205 of the FPA \2\ and have more than a de
minimis market presence to file Electric Quarterly Reports (EQR) with
the Commission.\3\ After consideration of the comments filed in
response to the Notice of Proposed Rulemaking (NOPR),\4\ the Commission
concludes that the requirements in this Final Rule will allow the
Commission and the public to gain a more complete picture of interstate
wholesale electric power and transmission markets by providing
additional information concerning price formation and market
concentration in these electric markets. Public access to additional
sales and transmission-related information in the EQR improves market
participants' ability to assess supply and demand fundamentals and to
price interstate wholesale electric market transactions. It also
strengthens the Commission's ability to identify potential exercises of
market power or manipulation and to

better evaluate the competitiveness of interstate wholesale electric
markets.
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    \1\ EPAct 2005, Public Law 109-58, 119 Stat. 594 (2005).
    \2\ 16 U.S.C. 824d.
    \3\ This Final Rule refers to market participants that are not
public utilities under section 201(f) of the FPA as ``non-public
utilities.'' FPA section 201(f) provides: No provision in this Part
shall apply to, or be deemed to include, the United States, a State
or any political subdivision of a State, an electric cooperative
that receives financing under the Rural Electrification Act of 1936
(7 U.S.C. 901 et seq.) or that sells less than 4,000,000 megawatt
hours of electricity per year, or any agency, authority, or
instrumentality of any one or more of the foregoing, or any
corporation which is wholly owned, directly or indirectly, by any
one or more of the foregoing, or any officer, agent, employee of any
of the foregoing acting as such in the course of his official duty,
unless such provision makes specific reference thereto. 16 U.S.C.
824(f). In the NOPR, the Commission proposed to amend Part 35 to add
a definition of ``non-public utility,'' and incorrectly referenced
16 U.S.C. 824f. In this Final Rule, we have corrected the reference,
which now refers to 16 U.S.C. 824(f).
    \4\ Electricity Market Transparency Provisions of Section 220 of
the Federal Power Act, Notice of Proposed Rule Making, FERC Stats. &
Regs. ] 32,676 (2011) (NOPR).
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    2. In adopting the requirements in this Final Rule, the Commission
has balanced the need to increase transparency with the burden on non-
public utilities associated with filing the EQR by revising some of the
proposals in the NOPR. As explained below, the Commission uniformly
adopts a 4,000,000 MWh de minimis threshold for all non-public
utilities, including for non-public utilities that are Balancing
Authorities. The Commission also will not require non-public utilities
to report the following types of wholesale sales: (1) Sales by a non-
public utility, such as a cooperative or joint action agency, to its
members; and (2) sales by a non-public utility under a long-term, cost-
based agreement required to be made to certain customers under a
Federal or state statute.
    3. In addition, the Commission revises the existing EQR filing
requirements applicable to market participants in the interstate
wholesale electric markets. The Commission revises the EQRs currently
filed by public utilities under FPA section 205(c) and that will be
filed by non-public utility filers under FPA section 220. These
revisions include the addition of new fields for: (1) Reporting the
trade date and the type of rate; (2) identifying the exchange used for
a sales transaction, if applicable; (3) reporting whether a broker was
used to consummate a transaction; (4) reporting electronic tag (e-Tag)
ID data; and (5) reporting standardized prices and quantities for
energy, capacity, and booked out power transactions. The Commission
also requires EQR filers to indicate in the existing ID data section
whether they report their sales transactions to an index publisher and,
if so, to which index publisher(s) and, if applicable, which types of
transactions are reported. The Commission also eliminates the time zone
from the contract section and the Data Universal Numbering System
(DUNS) data requirement. These refinements to the existing EQR filing
requirements reflect the evolving nature of interstate wholesale
electric markets, will increase market transparency for the Commission
and the public, and will allow market participants to file the
information in the most efficient manner possible.\5\
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    \5\ The Commission has proposed to change the process for filing
EQRs. Specifically, the Commission has proposed to replace the
Visual FoxPro-based EQR software with two new filing options. See
Revisions to Electric Quarterly Report Filing Process, 139 FERC ]
61,234 (2012).
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    4. The requirement for certain non-public utilities to file EQRs
will be implemented at the same time as the requirement for all EQR
filers (both public utilities and non-public utilities) to report the
data fields discussed in this rule, i.e., beginning the third quarter
of 2013.

I. Introduction

A. Order No. 2001

    5. The Commission set forth the EQR filing requirements in Order
No. 2001.\6\ Order No. 2001 requires public utilities to electronically
file EQRs summarizing transaction information for short-term and long-
term cost-based sales and market-based rate sales and the contractual
terms and conditions in their agreements for all jurisdictional
services.\7\ The Commission established the EQR reporting requirements
to help ensure the collection of information needed to perform its
regulatory functions over transmission and sales of electric energy,\8\
while making data more useful to the public and allowing public
utilities to better fulfill their responsibility under FPA section
205(c) \9\ to have rates on file in a convenient form and place.\10\ As
noted in Order No. 2001, the EQR data is designed to ``provide greater
price transparency, promote competition, enhance confidence in the
fairness of the markets, and provide a better means to detect and
discourage discriminatory practices.'' \11\
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    \6\ Revised Public Utility Filing Requirements, Order No. 2001,
67 FR 31043 (May 8, 2002), FERC Stats. & Regs. ] 31,127, reh'g
denied, Order No. 2001-A, 100 FERC ] 61,074, reh'g denied, Order No.
2001-B, 100 FERC ] 61,342, order directing filing, Order No. 2001-C,
101 FERC ] 61,314 (2002), order directing filing, Order No. 2001-D,
102 FERC ] 61,334, order refining filing requirements, Order No.
2001-E, 105 FERC ] 61,352 (2003), order on clarification, Order No.
2001-F, 106 FERC ] 61,060 (2004), order revising filing
requirements, Order No. 2001-G, 72 FR 56735 (Oct. 4, 2007), 120 FERC
] 61,270, order on reh'g and clarification, Order No. 2001-H, 73 FR
1876 (Jan. 10, 2008), 121 FERC ] 61,289 (2007), order revising
filing requirements, Order No. 2001-I, 73 FR 65526 (Nov. 4, 2008),
125 FERC ] 61,103 (2008).
    \7\ Order No. 2001, FERC Stats. & Regs. ] 31,127.
    \8\ Id. PP 13-14.
    \9\ 16 U.S.C. 824d(c).
    \10\ Order No. 2001, FERC Stats. & Regs. ] 31,127 at P 31.
    \11\ Id.
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    6. Since issuing Order No. 2001, the Commission has provided
guidance and refined the reporting requirements, as necessary, to
simplify the filing requirements and to reflect changes in the
Commission's rules and regulations.\12\ For instance, in 2007 the
Commission adopted an Electric Quarterly Report Data Dictionary, which
provides in one document the definitions of certain terms and values
used in filing EQR data.\13\ Moreover, in 2007, the Commission required
transmission capacity reassignments to be reported in the EQR.\14\ The
refinements to the existing EQR requirements that we are adopting in
this Final Rule build upon the Commission's prior improvements to the
reporting requirements and further enhance the goals of providing
greater price transparency, promoting competition, instilling
confidence in the fairness of the markets, and providing a better means
to detect and discourage anti-competitive, discriminatory, and
manipulative practices.
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    \12\ See, e.g., Revised Public Utility Filing Requirements for
Electric Quarterly Reports, 124 FERC ] 61,244 (2008) (providing
guidance on the filing of information on transmission capacity
reassignments in EQRs); Notice of Electric Quarterly Reports
Technical Conference, 73 FR 2477 (Jan. 15, 2008) (announcing a
technical conference to discuss changes associated with the EQR Data
Dictionary).
    \13\ Order No. 2001-G, 120 FERC ] 61,270.
    \14\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007),
FERC Stats. & Regs. ] 31,241, at P 817, order on reh'g, Order No.
890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ] 31,261
(2007), order on reh'g and clarification, Order No. 890-B, 73 FR
39092 (July 8, 2008), 123 FERC ] 61,299 (2008), order on reh'g,
Order No. 890-C, 74 FR 12540 (Mar. 25, 2009), 126 FERC ] 61,228
(2009), order on clarification, Order No. 890-D, 74 FR 61511 (Nov.
25, 2009), 129 FERC ] 61,126.
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B. EPAct 2005

    7. In EPAct 2005, Congress added section 220 to the FPA,\15\
directing the Commission to ``facilitate price transparency in markets
for the sale and transmission of electric energy in interstate
commerce'' with ``due regard for the public interest, the integrity of
those markets, fair competition, and the protection of consumers.''
\16\ FPA section 220 grants the Commission authority to obtain and
disseminate ``information about the availability and prices of
wholesale electric energy and transmission service to the Commission,
State commissions, buyers and sellers of wholesale electric energy,
users of transmission services, and the public.'' \17\ The statute
specifies that the Commission may obtain this information from ``any
market participant,'' \18\ except for entities with a de minimis market
presence.\19\ EPAct

2005 added a similar transparency provision in the Natural Gas Act,\20\
which led to additional filing and posting requirements for the sale or
transportation of physical natural gas in interstate commerce in Order
Nos. 704 and 720.\21\
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    \15\ 16 U.S.C. 824t.
    \16\ In addition, FPA section 220(b)(1-2) directs the Commission
to exempt from disclosure information that is ``detrimental to the
operation of an effective market or [that would] jeopardize system
security,'' and ``to ensure that consumers and competitive markets
are protected from the adverse effects of potential collusion or
other anticompetitive behaviors that can be facilitated by untimely
public disclosure of proprietary trading information.'' 16 U.S.C.
824t(b)(1-2).
    \17\ Id. 824t(a)(2).
    \18\ Id. 824t(a)(3)(A).
    \19\ Id. 824t(d).
    \20\ 15 U.S.C. 717t-2.
    \21\ See Transparency Provisions of Section 23 of the Natural
Gas Act, Order No. 704, 73 FR 1014 (Jan. 4, 2008), FERC Stats. &
Regs. ] 31,260 (2007), order on reh'g, Order No. 704-A, 73 FR 55726
(Sept. 26, 2008), FERC Stats. & Regs. ] 31,275, order dismissing
reh'g and clarification, Order No. 704-B, 125 FERC ] 61,302 (2008),
order granting clarification, Order No. 704-C, 75 FR 35632 (June 23,
2010), 131 FERC ] 61,246 (2010); see also, Pipeline Posting
Requirements under Section 23 of the Natural Gas Act, Order No. 720,
73 FR 73494 (Dec. 2, 2008), FERC Stats. & Regs. ] 31,283 (2008),
order on reh'g, Order No. 720-A,75 FR 5178 (Jan. 21, 2010), FERC
Stats. & Regs. ] 31,302, order on reh'g and clarification, Order No.
720-B, 75 FR 44893 (July 30, 2010), FERC Stats. & Regs. ] 31,314
(2010), vacated, Texas Pipeline Ass'n v. FERC, 661 F.3d 258 (2011).
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    8. The Commission did not previously extend transparency
requirements under FPA section 220 to wholesale electricity markets
because the Commission was considering other reforms to its regulation
of electricity markets.\22\ In particular, the Commission was
undertaking open access transmission service reforms and the more
general review of competition in wholesale electricity markets.\23\ As
a result of these efforts, the Commission issued two final rules. In
Order No. 890, the Commission exercised its remedial authority ``to
limit further opportunities for undue discrimination, by minimizing
areas of discretion, addressing ambiguities and clarifying various
aspects of the pro forma [Open Access Transmission Tariff].'' \24\
Moreover, in Order No. 719, the Commission made reforms ``to improve
the operation [and competitiveness] of organized wholesale electric
power markets'' in connection with ``fulfilling its statutory mandate
to ensure supplies of electric energy at just, reasonable and not
unduly discriminatory or preferential rates.'' \25\ Although these
final rules improved transparency in wholesale markets in a number of
ways, the Commission believes the revisions required in this Final Rule
are necessary to facilitate price transparency in wholesale electricity
markets.
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    \22\ See Transparency Provisions of Section 23 of the Natural
Gas Act; Transparency Provisions of the Energy Policy Act, Notice of
Proposed Rulemaking, 72 FR 20791 (April 26, 2007), FERC Stats. &
Regs. ] 32,614, at PP 9-11 (2007) (Natural Gas Transparency NOPR)
(``The Commission does not propose action with respect to electric
markets at this time. The Commission has recently addressed and is
currently addressing electric market transparency in other
proceedings.'').
    \23\ Id.
    \24\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 40.
    \25\ Wholesale Competition in Regions with Organized Electric
Markets, Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC Stats. &
Regs. ] 31,281 (2008), order on reh'g, Order No. 719-A, 74 FR 37776
(July 29, 2009), FERC Stats. & Regs. ] 31,292, order on reh'g and
clarification, Order No. 719-B, 129 FERC ] 61,252 (2009).
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C. Procedural History

    9. On January 21, 2010, the Commission issued a Notice of Inquiry
\26\ seeking comments on whether the Commission should apply the EQR
filing requirements to non-public utilities and whether the Commission
should consider other refinements to the existing EQR filing
requirements. Based on comments received in response to the
Transparency NOI, the Commission drafted the proposals in the NOPR. The
Commission issued the NOPR in this proceeding on April 21, 2011. In
response, the Commission received 28 comments.\27\
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    \26\ Electricity Market Transparency Provisions of Section 220
of the Federal Power Act, Notice of Inquiry, 75 FR 4805 (Jan. 29,
2010), FERC Stats. & Regs. ] 35,565 (2010) (Transparency NOI).
    \27\ See Attachment B for a list of commenters and their
abbreviated names as used here.
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II. Discussion

A. Extending the EQR Filing Requirements to Non-Public Utilities

1. Need for Information From Non-Public Utilities and Commission's
Legal Authority
a. Value of Information From Non-Public Utilities
i. NOPR
    10. In the NOPR, the Commission stated that the market transparency
provisions in section 220 of the FPA authorize the Commission to
``prescribe such rules as the Commission determines necessary and
appropriate'' for the dissemination of ``information about the
availability and prices of wholesale electric energy and transmission
service.'' \28\ The Commission explained that the transparency
provisions expand the Commission's authority to collect such
information not only from jurisdictional utilities, but also ``from any
market participant'' \29\ with more than a de minimis market
presence.\30\ The Commission also stated that the phrase ``any market
participant'' is not defined in section 220 and is not limited to
public utilities subject to the Commission's jurisdiction under section
205 of the FPA. The Commission interpreted ``any market participant''
to include non-public utilities that fall under FPA section 201(f).\31\
The Commission stated that such an interpretation of ``any market
participant'' is consistent with the broad mandate in section 220 to
``facilitate price transparency in the markets for the sale and
transmission of electric energy in interstate commerce, having due
regard for the public interest, the integrity of those markets, fair
competition, and the protection of consumers.'' Furthermore, the
Commission stated that, in EPAct 2005, Congress amended section
201(b)(2) of the FPA to provide that, ``[n]otwithstanding section
201(f),'' the entities described in section 201(f) shall be subject to
the Commission's jurisdiction for purposes of carrying out certain
provisions, including FPA section 220. Thus, the Commission concluded
that reading FPA section 201(b)(2) in conjunction with section 220,
EPAct 2005 granted the Commission authority to collect information
concerning the availability and prices of wholesale electric energy and
transmission service from entities that are not public utilities.
Accordingly, the Commission proposed to fulfill its responsibility
under section 220 of the FPA by requiring non-public utilities with
more than a de minimis market presence in wholesale markets to comply
with the EQR filing requirements.
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    \28\ 16 U.S.C. 824t(a)(2).
    \29\ Id. 824t(a)(3). This section states, in relevant part, that
``[t]he Commission may obtain the information described in paragraph
(2) from any market participant.'' Id. (emphasis added).
    \30\ Id. 824t(d).
    \31\ See id. at 824t(a)(3)(A).
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    11. As part of its justification for its proposals in the NOPR, the
Commission explained that applying the EQR filing requirements to non-
public utilities that fall above the de minimis threshold will increase
price transparency to the public and the Commission and aid the
Commission in its oversight of wholesale power and transmission
markets. The Commission stated that non-public utilities have a
significant presence in national and regional wholesale electricity
markets \32\ so that obtaining information about their sales
transactions is important to unmasking

how prices are formed in electricity markets. The lack of information
from non-public utilities results in an incomplete picture of these
markets, and hampers the ability of the public and the Commission to
detect and address the potential exercise of market power and
manipulation.
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    \32\ In the NOPR, the Commission stated that, based on the most
recent data available in the 2009 U.S. Energy Information
Administration's (EIA's) Form 861, non-public utilities account for
significant volumes of the 3.2 billion MWh of total annual wholesale
electricity sales made within the 48 contiguous states (excluding
ERCOT). The Commission noted that about 29 percent of those
wholesale sales were made by non-public utilities, with non-public
utilities accounting for 60 and 70 percent of wholesale sales within
the Western Electric Coordinating Council (WECC) and SERC
Reliability Corporation (SERC) regions, respectively, and about 80
percent of all wholesale sales that occur within the Florida
Reliability Coordinating Council (FRCC). See NOPR, FERC Stats. &
Regs. ] 32,676 at P 23.
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ii. Comments
    12. Several commenters argue that extending the EQR filing
requirements to non-public utilities will not increase transparency in
wholesale electric markets regulated by the Commission.\33\ NYMPA/MEUA
argue that, contrary to the Commission's contention in the NOPR,
reporting information about the limited wholesale sales made by
municipal utilities will add little to the Commission's oversight of
the markets it regulates.\34\ Southwestern Power Administration states
that it makes cost-based sales pursuant to statute; therefore, its
sales play no role in price formation in wholesale markets and do not
materially affect wholesale prices or rates paid to jurisdictional
entities.\35\ NRECA states that the majority of wholesale sales by non-
public utilities are sales to their members pursuant to long-term
bilateral contracts, which do not take place within wholesale
electricity markets and have no impact on wholesale market prices.
APPA, Public Systems, and TAPS argue that requiring Regional
Transmission Operators (RTOs) and Independent System Operators (ISO) to
make bid information publicly available with a shorter time lag is the
most effective way to improve market transparency and oversight of RTO
and ISO markets.\36\
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    \33\ See, e.g., California DWR at 1-2; NRECA at 4; NYMPA/MEUA at
3; Southwestern Power Administration at 3.
    \34\ NYMPA/MEUA at 3.
    \35\ Southwestern Power Administration at 3.
    \36\ APPA at 4; Public Systems at 2; TAPS at 17-20.
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    13. APPA, supported by NRECA, asserts that the Commission's
estimate of sales by non-public utilities overstates the percentage of
sales made by non-public utilities.\37\ For instance, APPA argues that
not all wholesale sales are reported in EIA Form 861, and that
wholesale power sales in Alaska, Hawaii, and ERCOT cannot be excluded
from the percentage of nationwide wholesale sales made by non-public
utilities because EIA data are not reported in sufficient detail to
accurately determine which sales should be excluded.\38\ In particular,
APPA states that its analysis of EIA data indicates that non-public
utilities accounted for only 19.4 percent of wholesale sales in the
United States in 2009 rather than 29 percent, as stated in the NOPR. In
addition, APPA argues that the NOPR's estimates of non-public utility
wholesale sales by region, i.e., 80 percent in FRCC, 70 percent in
SERC, and 60 percent in WECC, are overstated because EIA reports a
power marketer's sales as being from a single region even though it may
make sales in several regions. APPA also argues that the EQR data
supports its contention that the Commission overstated in the NOPR the
percentage of wholesale sales attributable to non-public utilities.\39\
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    \37\ APPA at 9-10; NRECA at 8.
    \38\ APPA at 8-9.
    \39\ Id. at 10. For example, APPA states that Morgan Stanley
Capital Group's 2009 wholesale sales reported on EIA Form 861 are
assigned to the ReliabilityFirst Corporation (RFC) region of North
American Electric Reliability Corporation (NERC), but that the
company's fourth quarter 2009 EQR shows that not all of those sales
were in the RFC region. Morgan Stanley reported energy sales and
bookouts of 27.5 million MWhs in WECC and 5.1 million MWhs in SERC.
APPA concludes that for that quarter, ``Morgan Stanley sold more in
the WECC region than any public power utility or cooperative sold in
WECC for all of 2009, but the Morgan Stanley sales were not part of
FERC's analysis of the WECC region.'' APPA makes a similar
observation regarding sales by Constellation Energy Commodities
Group for fourth quarter 2009 and notes that Calpine Energy Services
and Dynegy Power Marketing both report large amounts of wholesale
sales on the 2009 EIA Form 861, but leave the NERC region blank.
EQRs for the fourth quarter show that Calpine sold 22.2 million MWhs
in WECC, 3.1 million MWhs in SERC, and 136,000 MWhs in FRCC; Dynegy
sold 1.1 million MWhs in WECC. APPA claims that regional
calculations based on EIA Form 861 data would not include those
sales in the appropriate regions, thus overstating the percentage of
non-public utilities' sales in those regions.
---------------------------------------------------------------------------

    14. NRECA also argues that the NOPR overestimated the number of
wholesale sales made by non-public utilities in regional markets
because the EIA data used to calculate those numbers do not distinguish
between non-public utility sales made to members and non-members and
appear to omit certain large power marketers as they do not report
sales by NERC Reliability Region.\40\ In particular, NRECA states that
the percentage of non-public utility wholesale sales in FRCC was less
than 80 percent of all wholesale sales in FRCC, with only two non-
public utilities in FRCC selling above 4,000,000 MWh of wholesale
energy in 2009, primarily to their own members. NRECA contends that the
Commission made a similar mistake in its analyses of non-public utility
sales in the Western Electricity Coordinating Council.\41\
---------------------------------------------------------------------------

    \40\ NRECA at 7-8.
    \41\ Id.
---------------------------------------------------------------------------

    15. Other commenters, such as EEI and Joint Market Monitors, not
only argue that the Commission has the authority to require non-public
utilities to submit EQRs, but also that this information will increase
transparency. Moreover, Joint Market Monitors argue that the
Commission's jurisdiction over market manipulation constitutes a
standalone basis for requiring all market participants to file EQRs.
Joint Market Monitors state that the Commission's market-based rate
program is based on a theory of regulation through competition, which
relies on a lack of market power or adequate mitigation to ensure just
and reasonable pricing.\42\
---------------------------------------------------------------------------

    \42\ Joint Market Monitors at 3.
---------------------------------------------------------------------------

    16. Moreover, certain commenters agree with the Commission that
information from non-public utilities will increase transparency in
interstate wholesale electric power and transmission markets.\43\ Joint
Market Monitors assert that the jurisdictional status of a market
participant has no bearing on the impact of its participation and
conduct on electricity markets. Furthermore, Joint Market Monitors
agree that the Commission must have an understanding of what transpires
in a market as a whole to fully understand any particular part of it.
Given that all market participants participate in price formation,
Joint Market Monitors argue that all market participants should be
required to provide data adequate to ensure that the Commission is able
to fulfill its basic regulatory duties.\44\
---------------------------------------------------------------------------

    \43\ See, e.g., DC Energy at 3; EEI at 3-6; Joint Market
Monitors at 3; NYMPA/MEUA at 3; Pacific Northwest IOUs at 2;
Pennsylvania Commission at 6; Powerex at 4; Ronald Rattey at 10;
Shell Energy at 2.
    \44\ Joint Market Monitors at 3-4.
---------------------------------------------------------------------------

    17. Pennsylvania Commission states that cooperatives and
municipalities play a significant role in serving Pennsylvania
residents; thus, expanding EQR requirements to include them will
strengthen the Commission's ability to monitor wholesale markets and
Pennsylvania Commission's ability to monitor its retail markets for
anti-competitive and manipulative behavior.\45\
---------------------------------------------------------------------------

    \45\ Pennsylvania Commission at 7.
---------------------------------------------------------------------------

    18. EEI states that public utilities would benefit from access to
EQR information from non-public utilities in undertaking analyses used
for market-based rate applications.\46\ In contrast, LPPC asserts that
information regarding long-term agreements would not assist the
Commission in conducting a delivered price test (DPT) for market-based
rate authorizations and mergers. LPPC asserts that the delivered price
test measures concentration in short-term markets and focuses on the
ability

of suppliers to deliver energy to relevant markets as measured by their
short-term variable costs. LPPC therefore contends that disclosure of
the prices reflected in long-term wholesale contracts between non-
public utilities would do nothing to improve the accuracy of
determining either short-term destination market prices or the short-
term variable costs of potential suppliers.\47\
---------------------------------------------------------------------------

    \46\ EEI at 3-4.
    \47\ LPPC at 9-10.
---------------------------------------------------------------------------

iii. Commission Determination
    19. We conclude that FPA section 201(b)(2), read in conjunction
with section 220, grants the Commission authority to collect
information about the availability and prices of wholesale electric
energy and transmission service from non-public utilities
notwithstanding section 201(f) .\48\ We further conclude, for the
reasons discussed in the NOPR and based on our review of the record,
that it is appropriate to adopt the NOPR proposal to extend EQR filing
requirements to non-public utilities above the de minimis threshold
under FPA section 220 with the following modifications. In the NOPR,
the Commission proposed to require non-public utilities above the de
minimis threshold to report all of their wholesale sales in the EQR to
increase price transparency to the public and the Commission. The
Commission modifies its NOPR proposal by excluding the following types
of wholesale sales from the EQR reporting requirement for non-public
utilities above the de minimis threshold: (1) Sales by a non-public
utility, such as a cooperative or joint action agency, to its members;
and (2) sales by a non-public utility under a long-term, cost-based
agreement required to be made to certain customers under a Federal or
state statute.
---------------------------------------------------------------------------

    \48\ FPA section 201(b)(2) explicitly applies certain FPA
provisions, including the transparency provision under FPA section
220, to entities covered by FPA section 201(f). This contrasts with
the Natural Gas Act (NGA), which does not contain a similar
provision setting forth the applicability of the transparency
provision under NGA section 23 to natural gas pipelines that are
exempted from the Commission's NGA jurisdiction under NGA section
1(b). On appeal of Order Nos. 720 and 720-A, whereby the Commission
required major intrastate natural gas pipelines to post certain
information under NGA section 23, the Fifth Circuit Court of Appeals
concluded that the Commission's authority under NGA section 23 does
not extend to intrastate pipelines because they are exempted from
the Commission's NGA jurisdiction by NGA section 1(b). See Texas
Pipeline Ass'n v. FERC, 661 F.3d at 262.
---------------------------------------------------------------------------

    20. The NOPR explained that transactions made by both public
utility and non-public utility market participants provide critical
pricing information that market participants can use to make better-
informed decisions about, among other things, sales, purchases, and
infrastructure investments. Moreover, access to reliable data reduces
differences in available information among various market participants,
results in greater market confidence, lowers transaction costs, and
ultimately supports competitive markets, which helps lower electricity
costs for consumers.
    21. The NOPR also pointed out that non-public utilities have a
significant presence in national and regional wholesale electric
markets so that obtaining information about their sales transactions is
important to unmasking how prices are formed in electric markets.
Therefore, the lack of information from non-public utilities results in
an incomplete picture of these markets, and hampers the ability of the
public and the Commission to detect and address the potential exercise
of market power and manipulation.\49\
---------------------------------------------------------------------------

    \49\ NOPR, FERC Stats. & Regs. ] 32,676 at P 11.
---------------------------------------------------------------------------

    22. In addition, as stated in the NOPR, obtaining EQR information
from non-public utilities would strengthen the Commission's oversight
of its market-based rate program under FPA section 205 and provide a
better basis for considering whether to approve merger and acquisition
proposals under FPA section 203.\50\ The Commission's market-based rate
program is grounded in an ex ante analysis of whether to grant a seller
market-based rate authority and an ex post analysis of whether a seller
with market-based rate authority has obtained the ability to exercise
market power since it was granted authorization to transact at market-
based rates or since its last updated market power analysis.\51\ As
stated in the NOPR, one tool used to conduct an ex ante analysis is the
DPT, which is used if a seller fails one of the indicative screens of
market power. The NOPR stated that obtaining more complete price and
volume information for sales of electricity by non-public utilities
would more accurately reflect market prices, improve the quality of the
DPT results and assist the Commission in identifying whether sellers
can exercise market power.\52\ After consideration of various comments
and careful balancing of the need to facilitate price transparency
against the burden on non-public utilities associated with filing the
EQR, the Commission modifies its NOPR proposal, as discussed above, by
excluding certain non-public utility wholesale sales from the EQR
reporting requirement. In particular, the Commission modifies its NOPR
proposal by excluding the following types of wholesale sales from the
EQR reporting requirement for non-public utilities above the de minimis
threshold: (1) Sales by a non-public utility, such as a cooperative or
joint action agency, to its members; and (2) sales by a non-public
utility under a long-term, cost-based agreement required to be made to
certain customers under a Federal or state statute. For purposes of
this rulemaking, the Commission refers to non-public utility wholesale
sales not subject to either of these two exclusions as ``surplus''
market sales. The Commission finds that information about a non-public
utility's sales to its members, or by a non-public utility under a
long-term, cost-based agreement required to be made to certain
customers under statute, will not materially contribute to additional
price transparency. These types of sales do not significantly impact
wholesale price formation in electric markets because these sales
generally take place between a non-public utility and a pre-determined
customer without arm's-length negotiations. In addition, the benefit of
obtaining information about such sales by non-public utilities may not
outweigh the burden imposed on the non-public utilities that would need
to report such sales in the EQR.
---------------------------------------------------------------------------

    \50\ Id. P 27.
    \51\ The Ninth Circuit Court of Appeals has upheld the
Commission's market-based rate program because it relies on a
``system [that] consists of a finding that the applicant lacks
market power (or has taken sufficient steps to mitigate market
power), coupled with strict reporting requirements to ensure that
the rate is `just and reasonable' and that markets are not subject
to manipulation.'' State of California, ex rel. Bill Lockyer v.
FERC, 383 F.3d 1006, 1013 (9th Cir. 2004), cert. denied (S. Ct. Nos.
06-888 and 06-1100, June 18, 2007)).
    \52\ NOPR, FERC Stats. & Regs. ] 32,676 at P 27.
---------------------------------------------------------------------------

    23. The Commission adopts the NOPR proposal to exempt utilities
located entirely in Alaska and Hawaii from the EQR filing requirements
because they are electrically isolated from the contiguous United
States. In addition, this Final Rule does not apply to a transaction
for the purchase or sale of wholesale electric energy or transmission
services within ERCOT as it is described in section 212(k)(2)(A) of the
FPA.\53\
---------------------------------------------------------------------------

    \53\ 16 U.S.C. 824t(f).
---------------------------------------------------------------------------

    24. APPA and NRECA argue that the NOPR overestimated the amount of
nationwide wholesale sales made by non-public utilities. APPA contends
that its calculations indicate that non-public utilities account for
19.4 percent of nationwide wholesale sales rather than 29 percent, as
stated in the NOPR. APPA also points out that its calculation of non-
public utility sales does not exclude certain sales in Alaska, Hawaii

and ERCOT due to the lack of sufficient detail in EIA data.\54\ Even if
non-public utilities account for approximately 19.4 percent of
nationwide wholesale sales, as APPA contends, the Commission finds this
percentage of sales in the nationwide wholesale electricity market to
be significant. APPA and NRECA also argue that the Commission's
analysis using EIA Form 861 data overstated the number of non-public
utility wholesale sales in regional markets. Although EIA data is not
sufficiently detailed to provide a complete and precise estimate of
wholesale sales made by non-public utilities, the Commission's market
analysis using EIA data nevertheless indicates that non-public
utilities account for a significant portion of sales in certain
regional markets. The lack of publicly available data regarding non-
public utility sales challenges the ability of the public and the
Commission to rely on existing information sources to form an accurate
picture of wholesale electricity markets and does not provide the level
of price transparency that this Final Rule seeks to achieve.
---------------------------------------------------------------------------

    \54\ APPA at 8-9.
---------------------------------------------------------------------------

    25. As noted in the NOPR, the Commission believes its effort to
increase transparency broadly across all wholesale markets subject to
the Commission's jurisdiction by requiring additional information in
the EQR is just as important as efforts the Commission has taken to
improve transparency in RTO and ISO markets.\55\ Obtaining information
about sales in markets outside of RTO and ISO regions will enable the
Commission and the public to better understand non-public utilities'
effect on market dynamics. For example, in the Pacific Northwest, the
supply of power from non-public utilities ebbs and flows with the water
levels powering hydroelectric facilities. During times of high flows,
power prices may fall and public utilities' fossil fuel and wind-fired
generation can become less competitive. During times of drought or dry
seasons, power prices may rise.
---------------------------------------------------------------------------

    \55\ See NOPR, FERC Stats. & Regs. ] 32,676 at P 25.
---------------------------------------------------------------------------

    26. With respect to the suggestion by certain commenters that the
Commission should require shorter time lags for RTO and ISO postings of
bid and offer data, we note that the Commission has previously
addressed the time lag for such data and we will not address that issue
again here. Specifically, in Order No. 719, the Commission shortened
the release period for bid and offer data and provided RTOs and ISOs
with the flexibility to propose a different lag period.\56\
Furthermore, the EQR provides a level of transparency that RTO or ISO
postings of bid and offer data do not, because it informs the public
which market participants are involved across markets and at what
level.
---------------------------------------------------------------------------

    \56\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 421, order
on reh'g, Order No. 719-A, FERC Stats. & Regs. ] 31,292 at P 156.
---------------------------------------------------------------------------

    27. We disagree with LPPC's statements that information about long-
term agreements between non-public utilities would not assist the
Commission in conducting a DPT analysis for market-based rate
authorizations and mergers. The DPT measures market concentration by
identifying the sellers that could compete to sell electricity in a
relevant market. In defining the relevant market, the DPT identifies
potential suppliers based on market prices, input costs, and
transmission availability, and calculates each supplier's economic
capacity and available economic capacity for each season/load
condition.\57\ A supplier's economic capacity measures the amount of
generating capacity owned or controlled by a potential supplier with
variable costs low enough that energy from such capacity could be
economically delivered to the destination market.\58\ To determine the
total supply in the relevant market, the DPT adds the total amount of
economic or available economic capacity located in the relevant market
(including capacity owned by the seller and competing suppliers) with
that of economic or available economic capacity that can be imported
into the relevant market.\59\ Economic capacity is based on total
nameplate or seasonal capacity of generation owned or controlled
through contract and firm purchases, reduced by operating reserves, and
long-term firm sales. Available economic capacity is calculated by
deducting long-term obligations including native load obligations from
the economic capacity value. Therefore, information about long-term
sales agreements between non-public utilities can be used to help
determine the total supply in the relevant market. In addition,
information about sales made by non-public utilities, including under
long-term agreements, can assist the Commission in performing ex post
analyses to determine whether a seller with market-based rate authority
has obtained the ability to exercise market power since the original
authorization to transact at market-based rates or since its last
updated market power analysis.
---------------------------------------------------------------------------

    \57\ See Market-Based Rates for Wholesale Sales of Electric
Energy, Capacity and Ancillary Services by Public Utilities, Order
No. 697, FERC Stats. & Regs. ] 31,252, at P 106, clarified, 121 FERC
] 61,260 (2007), order on reh'g, Order No. 697-A, 73 FR 25832 (May
7, 2008), FERC Stats. & Regs. ] 31,268, order on reh'g, Order No.
697-B, 73 FR 79610 (Dec. 30, 2008), FERC Stats. & Regs. ] 31,285
(2008), order on reh'g, Order No. 697-C, 74 FR 30924 (June 29,
2009), FERC Stats. & Regs. ] 31,291 (2009), aff'd sub nom. Montana
Consumer Counsel v. FERC, No. 08-71827, 2011 U.S. App. LEXIS 20724
(9th Cir. Oct. 13, 2011).
    \58\ See id. P 96.
    \59\ See id. P 37.
---------------------------------------------------------------------------

b. Existing Sources of Information
i. NOPR
    28. In the NOPR, the Commission concluded that existing sources of
information regarding non-public utility wholesale electricity market
transactions did not provide sufficient price transparency. The
Commission considered the information made publicly available by the
Energy Information Administration (EIA) Form 861, Rural Utilities
Service (RUS) Form 12, RTO or ISO postings related to wholesale market
prices and market participant bid/offer data, daily index publications,
organized exchanges, commercial data providers, and through the Open
Access Same-Time Information System (OASIS). Thus, the Commission
proposed to expand EQR filing requirements to non-public utilities to
provide price transparency that is not available through these existing
sources of information.
ii. Comments
    29. Certain commenters agree with the Commission that information
available from existing price publishers and trade processing services
is incomplete and, thus, inadequate.\60\ However, other commenters
argue that the Commission's NOPR is overly broad and proposes to
collect duplicative information.\61\ They further argue that the
Commission must tailor its request to collect information that it
currently lacks. California DWR asserts that the Paperwork Reduction
Act requires the Commission to certify that a new reporting requirement
such as this one is not unnecessarily duplicative of information
otherwise reasonably accessible to the Commission. In addition,
California DWR asserts that FPA section 220(a)(4) similarly requires
that, before additional reporting to ensure price transparency in
electric markets may be ordered, the Commission must make a
determination

that existing data sources are insufficient. California DWR states that
in this respect, the NOPR disregards redundant requirements, and
requires governmental entities to reformat and re-report already
existing data.\62\
---------------------------------------------------------------------------

    \60\ See, e.g., DC Energy at 3; EEI at 3-6; Joint Market
Monitors at 3; NYMPA/MEUA at 3; Pacific Northwest IOUs at 2;
Pennsylvania Commission at 6; Powerex at 4; Ronald Rattey at 10;
Shell Energy at 2.
    \61\ California DWR at 3-5; NRECA at 4-5; Public Systems at 13-
16.
    \62\ California DWR at 3, 5-6.
---------------------------------------------------------------------------

    30. Numerous commenters argue that sufficient information is
already publicly available to meet the objectives of FPA section 220 to
``ensure that consumers and competitive markets are protected from the
adverse effects of potential collusion or other anticompetitive
behaviors'' without requiring non-public utilities to file EQRs.\63\
NRECA argues that the additional information that would be available in
the EQR does not justify the increased burden on non-public
utilities.\64\ For instance, NRECA states that, as recognized in the
NOPR, non-public utilities annually file Form EIA-861 ``Annual Electric
Power Industry Report'' and that cooperatives receiving RUS financing
also are required to file RUS Form 12.\65\ California DWR adds that the
NOPR concedes that data is available from EIA as well as from RTOs and
ISOs.\66\
---------------------------------------------------------------------------

    \63\ See, e.g. California DWR at 4-5; NRECA at 2, 5;
Transmission Dependent Utility Systems at 3.
    \64\ NRECA at 5-6. Allegheny, Associated Electric Cooperative,
and South Mississippi Electric each support NRECA's comments.
    \65\ NRECA at 4-6 (``This form [EIA-861] includes information
regarding peak load, generation, electric purchases, sales,
revenues, customer counts and demand-side management programs, green
pricing and net metering programs, and distributed generation
capacity.'' RUS Form 12 ``includes information regarding electric
purchases, sales and revenues.'').
    \66\ California DWR at 3.
---------------------------------------------------------------------------

    31. NRECA states that a substantial amount of information is
available from these sources and others. For example, it asserts that
EIA provides access to the daily volumes, high and low prices, and
weighted average prices from hubs around the country and that Energy
Management Institute provides results of a daily survey of wholesale
transactions that it conducts in all the major trading regions of the
country. NRECA further submits that forward market prices are available
through the New York Mercantile Exchange and the Intercontinental
Exchange (ICE). NRECA argues that it is inappropriate to increase
reporting burdens on consumer-owned entities merely to avoid some
effort on the part of the government to collect this information from
various sources. NRECA concludes that the increased burden on non-
public utilities that would be imposed by the EQR filing requirement is
not justified by the information that would be obtained.\67\
---------------------------------------------------------------------------

    \67\ NRECA at 5.
---------------------------------------------------------------------------

    32. California DWR, Public Systems, and TAPS also note that
significant amounts of data also are available from RTOs and ISOs.\68\
California DWR states that most of the desired information may be
obtained from existing sources such as RTOs, ISOs or Commission-
jurisdictional counterparties of governmental entities.\69\ EEI and
Public Systems argue that the Commission should collect EQR information
directly from RTOs and ISOs because, as the Commission recognized in
the NOPR, RTOs, and ISOs already make information publicly
available.\70\ Public Systems state that ISO-NE., the Commission, and
others publish reams of data that facilitate price transparency in the
New England markets. They note that ISO-NE's ``Markets'' page provides
links to numerous data compilations and descriptions, including a real-
time ``LMP Price Ticker'' and a link to its real-time ``LMP Map.'' \71\
Public Systems further state that the NOPR would require non-public
utilities to repackage the voluminous market-settlement data that they
receive from the RTO and to file that data in EQRs.
---------------------------------------------------------------------------

    \68\ California DWR at 3; Public Systems at 14; TAPS at 18.
    \69\ California DWR at 2-3.
    \70\ EEI at 21; Public Systems at 13.
    \71\ Public Systems at 14-15. Public Systems explains that the
``LMP Map'' shows: (1) Day-ahead market locational marginal prices
(LMP) for the current hour, by load zone, along with the relevant
binding constraints; (2) corresponding LMPs and constraints for the
real-time energy market; and (3) real-time reserve-market clearing
prices and regulation prices.
---------------------------------------------------------------------------

    33. Public Systems state that the NOPR does not rely on data that
RTOs already publish ``to the maximum extent possible'' under FPA
section 220. Rather, argues Public Systems, the NOPR identifies certain
information gaps in existing sources, such as information about
bilateral transactions in the RTO market or sales outside of the RTO
markets, and then uses those gaps to justify requiring non-public
utilities to file EQRs covering all of their wholesale transactions,
including those settled in the RTO markets. Public Systems state that,
as a result, the NOPR would require a non-public utility with more than
a de minimis presence in organized markets to file data about bilateral
transactions and sales outside the RTO markets in its EQR along with
voluminous market-settlement data that they receive from the RTO.\72\
---------------------------------------------------------------------------

    \72\ Id. at 15.
---------------------------------------------------------------------------

    34. California DWR states its wholesale transactions already are
captured in EIA reports and California ISO postings, with the exception
of non-California ISO bilateral transactions that California DWR may
engage in. Thus, argues California DWR, the NOPR would require
extensive duplication through a full EQR filing to collect a relatively
small amount of data. California DWR states that in this respect, the
NOPR disregards redundant requirements, and requires governmental
entities to reformat and re-report already existing data.\73\
Similarly, EEI also encourages the Commission to ensure that the EQR
only requires reporting of information that is truly necessary, though
it states that it agrees with the Commission that available information
from existing price publishers and trade processing services is
incomplete and thus inadequate.\74\
---------------------------------------------------------------------------

    \73\ California DWR at 4-5.
    \74\ EEI at 6.
---------------------------------------------------------------------------

iii. Commission Determination
    35. The Commission finds that the degree of price transparency
provided by existing sources of information about wholesale markets is
insufficient for the Commission to fulfill Congress' directive in FPA
section 220 to facilitate price transparency in interstate markets for
the sale and transmission of electric energy. As discussed in the
NOPR,\75\ the Commission has considered the degree of price
transparency provided by a number of sources of publicly available
information, including EIA Form 861 and RUS Form 12,\76\ RTO and ISO
postings, index publications, organized exchanges, commercial data
providers, and through OASIS, and concludes that the degree of price
transparency provided by these existing information sources is not
sufficient to help ensure an adequate level of transparency in
jurisdictional markets.
---------------------------------------------------------------------------

    \75\ NOPR, FERC Stats. & Regs. ] 32,676 at PP 34-39.
    \76\ RUS Form 12 was recently renamed the RUS Financial and
Operating Report Electric Power Supply.
---------------------------------------------------------------------------

    36. In general, the Commission and the public need a more compete
picture of markets across the country, including smaller markets, even
if a significant part of those markets is served by non-public
utilities. Market dynamics, including markets dominated by non-public
utilities, can change throughout the year through a host of factors
including weather conditions, outages, and contract expirations.
    37. Annual data collections from two of the most significant
publicly available forms that capture information about non-public
utility power sales, the EIA Form 861 and the RUS Form 12, do not
provide sufficiently detailed or

timely information to assess those market dynamics. As stated in the
NOPR, EIA Form 861 does not detail individual wholesale transactions,
including the counterparty, location, price, and delivery timeframe as
well as other transaction details combined in the EQR.\77\ Instead, EIA
Form 861 filers report their aggregated annual volume of sales for
resale and corresponding revenues. In addition, cooperatives that fall
under 7 U.S.C. 901 provide accounting details, including the energy
purchaser and other contract details for individual energy sales in RUS
Form 12. However, as stated in the NOPR, RUS Form 12 provides only
limited price transparency because the form does not contain
information on delivery location and timing, which are critical
elements for gaining insight into price formation.\78\
---------------------------------------------------------------------------

    \77\ See NOPR, FERC Stats. & Regs. ] 32,676 at P 35.
    \78\ Id.
---------------------------------------------------------------------------

    38. As recognized by certain commenters, and in the NOPR,\79\ RTOs,
and ISOs make available a significant amount of information about the
availability and prices for wholesale sales and transmission service
within these markets. However, as stated in the NOPR, the Commission
believes that it is equally important to increase transparency broadly
across all markets subject to the Commission's jurisdiction by
requiring market participants, including non-public utilities with more
than a de minimis presence in those markets, to provide information
through EQRs.\80\ The Commission finds that this information should
include not only non-public utilities' bilateral transactions in an RTO
or ISO market or sales outside of the RTO or ISO markets, but also
sales made by non-public utilities to the RTO or ISO markets. The EQR
provides a level of transparency that RTO or ISO postings do not
because it informs the public which market participants were involved
across markets and at what level. Obtaining information about such
sales will improve transparency by providing the public and the
Commission with the ability to view a broader universe of non-public
utility sales. Specifically, the EQR provides a greater level of
transparency by providing information in one place about a filer's
wholesale transactions, including the counterparty, delivery location,
price, and delivery timeframe as well as other transaction details.
Furthermore, in response to Public Systems' concern that non-public
utilities would be required to repackage voluminous market-settlement
data that they receive from the RTO and to file that data in EQRs, we
note that Order No. 2001 permitted RTOs and ISOs to file power sales
transaction information on behalf of members or market participants as
an agent, if authorized to do so by the member or market
participant.\81\ The Commission has also encouraged efforts that allow
market participants to request EQR-ready settlement reports from RTOs
and ISOs and will continue to do so.\82\
---------------------------------------------------------------------------

    \79\ Id. P 25.
    \80\ Id.
    \81\ Order No. 2001, FERC Stats. & Regs. ] 31,127 at P 336.
    \82\ Order No. 2001-E, 105 FERC ] 61,352 at P 12.
---------------------------------------------------------------------------

    39. Moreover, the Commission finds that the information collected
through the EQR filing requirements in this Final Rule will not result
in unnecessary duplication of information accessible to the Commission
and the public. Market transparency is not served if market
participants are required to piece together various sources with
disparate, inconsistent, or potentially incomplete data. The EQR will
facilitate price transparency by providing a uniform electronic
information system with filers timely reporting data under a consistent
set of rules for a specific period of time.
c. De Minimis Threshold
i. NOPR
    40. In the NOPR, the Commission proposed that a non-public utility
would be exempt under the de minimis market presence threshold from
filing EQRs if it makes 4,000,000 MWh or less of annual wholesale sales
(based on an average of the wholesale sales it made in the preceding
three years), unless the non-public utility is a Balancing Authority
that makes 1,000,000 MWh or more of annual wholesale sales (based on an
average of wholesale sales it made in the preceding three years).
Furthermore, the Commission concluded that FPA section 220 focuses on
the availability and prices of ``wholesale electric energy and
transmission service,'' and therefore proposed to use only the
wholesale electricity sales made by non-public utilities for purposes
of calculating the de minimis market presence threshold. The Commission
proposed that a non-public utility use the annual wholesale sales
volume it currently reports to EIA as ``Sales for Resale'' to calculate
whether it meets the de minimis threshold.
ii. Comments
(a) Setting the Threshold
    41. Many commenters support the Commission's proposal in the NOPR
to set a de minimis threshold of 4,000,000 MWh of annual wholesale
sales for non-public utilities.\83\ LPPC asserts that EQR information
from non-public utilities with relatively small roles in the
marketplace would be of minimal value to the Commission and the public,
and contribute little to transparency goals.\84\
---------------------------------------------------------------------------

    \83\ See, e.g., Allegheny at 4; APPA at 4; Cities/M-S-R at 8-9;
LPPC at 3; NRECA at 2; NYMPA/MEUSA at 1; Pennsylvania Commission at
8; Powerex at 3; Public Systems at 7; TAPS at 4.
    \84\ LPPC at 1.
---------------------------------------------------------------------------

    42. However, other commenters suggest lowering the de minimis
threshold to 1,000,000 MWh for all non-public utilities.\85\ EEI and
Pacific Northwest IOUs state that this would more accurately and fairly
honor the statutory exception for de minimis participants, and would
provide a clearer picture of transactions occurring in the nation's
electricity markets and the operation of those markets.\86\ DC Energy
states that the threshold should be lowered to 1,000,000 MWh to ensure
that all entities that may have an impact on wholesale market prices
are required to submit EQR data and to provide for complete price
transparency across the wholesale electricity markets.\87\
---------------------------------------------------------------------------

    \85\ See, e.g., DC Energy at 5; EEI at 7; Pacific Northwest IOUs
at 2.
    \86\ EEI at 7; Pacific Northwest IOUs at 2.
    \87\ DC Energy at 5.
---------------------------------------------------------------------------

    43. EEI submits that setting the threshold at 4,000,000 MWh would
still leave a significant portion of the market unreported. EEI states
that by setting the threshold at 1,000,000 MWh, the Commission would
gain substantial additional information while inconveniencing a modest
number of non-public utilities. EEI explains that, according to the
EIA, of the 3,265 entities (including both public and non-public
utilities) that filed the Form EIA-861 in 2009, 138 had sales over
4,000,000 MWh representing 91.8 percent of total U.S. wholesale sales,
whereas 254 had sales over 1,000,000 MWh representing 98.7 percent of
total U.S. wholesale sales. Of the 116 entities with sales between
1,000,000 and 4,000,000 MWh, EEI asserts that 67 were public power
agencies and cooperatives representing approximately 3.9 percent of
total U.S. wholesale sales, and the remaining 49 were investor-owned
utilities and private power marketers representing 3.0 percent of such
sales.\88\ EEI further states that according to the

NOPR's burden statement, only five non-public utility Balancing
Authorities are picked up if the threshold for Balancing Authorities is
reduced from 4,000,000 to 1,000,000 MWh.\89\
---------------------------------------------------------------------------

    \88\ EEI at 8 (citing NOPR, FERC Stats. & Regs. ] 32,676 at P
125).
    \89\ Id.
---------------------------------------------------------------------------

    44. Conversely, other commenters suggest that the Commission should
increase the 1,000,000 MWh annual wholesale sale threshold for
Balancing Authorities to 4,000,000 MWh or less.\90\ NRECA suggests that
a threshold of at least 4,000,000 MWh annual wholesale sales, akin to
that used for non-Balancing Authorities, would still capture sales by
non-public utility Balancing Authorities with a significant market
presence without exposing small Balancing Authorities to a reporting
requirement that would place a significant burden on them with no
corresponding benefit to the Commission or to the market. NRECA states
that the proposed 1,000,000 MWh threshold reflects an approximately 114
MW baseload energy sale, which is too small to have more than a de
minimis impact on any market. Therefore, NRECA asserts that the
requirement places the burden of filing EQRs on Balancing Authorities
that do not have more than a de minimis market presence.\91\
---------------------------------------------------------------------------

    \90\ See, e.g., NRECA at 16; TAPS at 6.
    \91\ NRECA at 16-17.
---------------------------------------------------------------------------

    45. Similarly, TAPS requests that the Commission apply the
4,000,000 MWh wholesale sales de minimis threshold uniformly,
regardless of whether the non-public utility is a Balancing Authority.
TAPS asserts that applying a lower de minimis threshold to non-public
utilities that are Balancing Authorities is insufficiently explained,
unduly discriminatory, and inconsistent with the statute. TAPS argues
that the Commission's authority to require reporting by non-public
utilities turns on whether the non-public utility at issue has a de
minimis market presence. TAPS states that being a Balancing Authority
does not magnify the market impact of a non-public utility's sales.
TAPS states that nothing in the NOPR justifies a finding that a
Balancing Authority that sells 1,000,000 MWh at wholesale annually has
more than a de minimis market presence, and that there is nothing about
being a Balancing Authority that should lead to such a conclusion.\92\
---------------------------------------------------------------------------

    \92\ TAPS at 6.
---------------------------------------------------------------------------

    46. Finally, Shell Energy supports adopting a de minimis level
below which specific transactions would not be required to be reported
in the EQRs. Shell Energy states that a minimum threshold for reporting
by all EQR filers could be either a volume cut-off or a capacity cut-
off, and that a reasonable threshold would be transactions below 10 MWh
or under $1,000. Alternatively, Shell Energy asserts that the
Commission should exclude from EQR reporting any transactions that are
under 10 MWh or $1000 and are undertaken simply for balancing energy
with an RTO or ISO. Shell Energy explains that it is involved in large
numbers of such balancing transactions, each of a very small volume and
the reporting of such transactions is onerous while not providing very
helpful information to the Commission.\93\
---------------------------------------------------------------------------

    \93\ Shell at 12.
---------------------------------------------------------------------------

    (b) Applying the Threshold
    47. Several commenters suggest that the Commission should exclude
intra-familial sales by non-public utilities for purposes of the annual
sales threshold.\94\ NRECA notes that FPA section 220(d) provides that,
``[t]he Commission shall not require entities who have a de minimis
market presence to comply with the reporting requirement of this
section.''\95\ Allegheny, NRECA, and Public Systems state that intra-
familial sales transactions do not result in any ``market presence''
because they take place entirely outside of the markets.\96\ NRECA
argues, as such, intra-familial sales are outside the scope of
transactions in section 220 of the FPA.\97\
---------------------------------------------------------------------------

    \94\ See, e.g., Allegheny at 4; Associated Electric Cooperative
at 3; NRECA at 10; Public Systems at 2; Transmission Dependent
Utility Systems at 3.
    \95\ NRECA at 12.
    \96\ Additionally, TAPS states that the fact that joint action
agencies and G&T cooperatives cost-based inter-familial sales are
not market sales justify excluding those transactions. TAPS at 10.
    \97\ NRECA at 12.
---------------------------------------------------------------------------

    48. According to NRECA, member cooperatives enter into long-term,
cost-based, pass-through power contracts. NRECA states that the prices
and volumes of such power sales are not influenced by market prices,
and have no influence on market prices because they are established
without regard to wholesale markets.\98\ Allegheny submits that such
sales are essentially the distribution cooperative members supplying
themselves. Allegheny further states that these G&T cooperative sales
are not market sales and do not affect the general marketplace for
electricity because: (1) The sales are available only to the member-
owners; (2) the member-owners are required to purchase the amounts
covered by the contract and therefore they cannot purchase these
amounts in the market; and (3) the G&T cooperatives cannot elect to
sell these resources to third parties instead of to their members.
Therefore, Allegheny asserts that such sales should be excluded from
the 4,000,000 MWh threshold.\99\
---------------------------------------------------------------------------

    \98\ Id. at 10-11.
    \99\ Allegheny at 4-5.
---------------------------------------------------------------------------

    49. Allegheny, NRECA, Public Systems, and Transmission Dependent
Utility Systems submit that intra-familial transactions by non-public
utilities are functionally equivalent to the operation of vertically-
integrated public utilities.\100\ NRECA states that it would be unjust
and unreasonable for the Commission to require non-public utilities to
include intra-familial transactions in calculating the 4,000,000 MWh
sales threshold and in reporting data in EQRs when it does not require
investor-owned utilities to report transfers between their bulk power
and distribution functions, because those contracts do not have any
relationship to markets for the wholesale sale of power.\101\
---------------------------------------------------------------------------

    \100\ NRECA at 11-12; Allegheny at 5; Transmission Dependent
Utility Systems at 5; Public Systems at 11.
    \101\ NRECA at 11-12.
---------------------------------------------------------------------------

    50. NRECA further alleges that the Commission's justification for
including intra-familial transactions in calculating the 4,000,000 MWh
threshold is not valid; the inclusion of such transactions in EQRs will
not assist the Commission or the public in understanding RTO or ISO
market price formation because these transactions do not impact the
market price.\102\ Transmission Dependent Utility Systems suggest that
the Commission should restrict any EQR filing obligations imposed on
G&T cooperatives that are non-public utilities to wholesale sales to
parties other than their distribution cooperative members where those
wholesale sales to third parties equal or exceed the 4,000,000 MWh
threshold.\103\
---------------------------------------------------------------------------

    \102\ Id. at 12.
    \103\ Transmission Dependent Utility Systems at 8.
---------------------------------------------------------------------------

    51. TAPS suggests that if the Commission adopts a final rule
providing that G&T cooperatives' cost-based sales to their members do
not count toward determining where the cooperative has more than a de
minimis wholesale market presence, comparability requires that joint
action agency sales to members be treated in the same fashion.\104\
Associated Electric Cooperative and NRECA comment that if the
Commission does not exclude intra-familial transactions, it should at
least not require both tiers of G&T cooperatives in a three-tier system
to

report their sales on their EQRs, because this would result in double
reporting.\105\
---------------------------------------------------------------------------

    \104\ TAPS at 10.
    \105\ NRECA at 17; Associated Electric Cooperative at 3-4.
---------------------------------------------------------------------------

    52. Cities/M-S-R state that the proposal that EIA data should be
used by the joint action agency to determine whether it meets the de
minimis threshold for filing EQRs is reasonable and should be included
in the final rule. However, Cities/M-S-R request that sales by joint
action agencies to the joint action agencies' members should be
excluded from reporting because the EIA data currently posted from 2009
do not appear to include in the ``Sales for Resale'' figure the sales
from joint action agencies to their members. Accordingly, Cities/M-S-R
state that it is not clear how the Commission plans to compile data
regarding sales by joint action agencies to their own members. If the
Commission does not exclude transactions between joint action agencies
and their members, then Cities/M-S-R request that the Commission
clarify how joint action agencies should determine their volume of
sales for purposes of determining whether or not they exceed the
threshold.\106\
---------------------------------------------------------------------------

    \106\ Cities/M-S-R at 10-11.
---------------------------------------------------------------------------

    53. Southwestern Power Administration states that the Commission's
proposal of a de minimis threshold with no procedure for waiver is
unreasonable for entities largely reliant upon recent weather patterns
to determine sales volumes. Southwestern Power Administration explains
that its annual sales from Corps Hydropower facilities are dependent
upon annual inflows, which vary greatly from year-to-year. Establishing
a threshold based on a one- to three-year timeframe may require
utilities such as Southwestern Power Administration, which are
dependent upon inflow in order to make sales, subject to the filing
requirements simply because of a period of above average rainfall and
may not truly reflect the utility's presence in the region.\107\
---------------------------------------------------------------------------

    \107\ Southwestern Power Administration at 4-5.
---------------------------------------------------------------------------

iii. Commission Determination
    54. The Commission will uniformly adopt a 4,000,000 MWh de minimis
threshold for all non-public utilities, including for non-public
utilities that are Balancing Authorities. Specifically, the Commission
will exempt under the de minimis market presence threshold non-public
utilities that make 4,000,000 MWh or less of annual wholesale sales
(based on an average of the wholesale sales it made in the preceding
three years). To ensure the uniform application of the de minimis
threshold, the Commission will not adopt the NOPR proposal to require a
non-public utility that is a Balancing Authority making 1,000,000 MWh
or more of annual wholesale sales to file EQRs. Instead, the Commission
will apply the 4,000,000 MWh threshold to these non-public utility
Balancing Authorities. As set forth in the NOPR, the Commission will
use wholesale sales, as reported in EIA Form 861, ``Sales for Resale,''
to calculate the de minimis market presence threshold.
    55. In response to commenters that suggest a 1,000,000 MWh de
minimis threshold, we note that the 4,000,000 MWh threshold adopted by
this Final Rule will significantly increase transparency, particularly
in certain markets with large non-public utility concentrations. In
requiring non-public utilities to report EQR information, we must
balance transparency benefits associated with the data collection with
any burdens it may create. EEI comments that EIA Form 861 data
indicates that setting the threshold at 1,000,000 MWh instead of
4,000,000 MWh would capture sales from an additional 67 public power
agencies and cooperatives representing approximately 3.9 percent of the
nation's wholesale sales. However, the Commission finds that the value
of collecting information from non-public utilities making between
1,000,000 and 4,000,000 MWh of annual wholesale sales does not outweigh
the burden that would be imposed on these small non-public utilities.
This determination is consistent with the definition of a small utility
under the Regulatory Flexibility Act \108\ and Small Business Act.\109\
The Small Business Administration's implementing regulations at 13 CFR
121.201 define a utility as 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.'' This
4,000,000 MWh threshold is also consistent with the threshold used in
FPA section 201(f) to exclude certain electric cooperatives from the
Commission's jurisdiction.\110\ Therefore, the Commission will not
lower the de minimis threshold to 1,000,000 MWh of annual wholesale
sales for non-public utilities, as suggested by certain commenters.
---------------------------------------------------------------------------

    \108\ See 5 U.S.C. 601.
    \109\ See 15 U.S.C. 632.
    \110\ FPA section 201(f) provides, in relevant part: ``[n]o
provision in this subchapter shall apply to, or be deemed to include
* * * an electric cooperative that receives financing under the
Rural Electrification Act of 1936 (7 U.S.C. 901 et seq.) or that
sells less than 4,000,000 megawatt hours of electricity per year.''
16 U.S.C. 824(f).
---------------------------------------------------------------------------

    56. We will not adopt Shell Energy's suggestion to establish a de
minimis reporting threshold for EQR filers based on their transactional
volumes or capacity or exclude from reporting certain transactions
undertaken for balancing energy with an RTO or ISO. As set forth in
Order No. 2001, public utilities are required to file information in
the EQR to comply with the requirement under FPA section 205(c) to show
all rates, terms, and conditions of jurisdictional services.\111\ The
Commission has granted waiver of the EQR filing requirements for
certain small public utility entities based on a number of
factors.\112\ Based on the statutory requirement for all public utility
rates, terms and conditions to be on file with the Commission and the
ability for small public utility entities to apply for waiver from the
EQR filing requirement, the Commission concludes it is not necessary to
establish a minimum reporting threshold based on the volume or nature
of transactions undertaken by public utilities. The Commission also
finds that this Final Rule appropriately sets the de minimis threshold
for non-public utility filers based on their annual wholesale sales
rather than on the volume or nature of their transactions.
---------------------------------------------------------------------------

    \111\ Order No. 2001, FERC Stats. & Regs. ] 31,127 at PP 11, 44.
    \112\ See Bridger Valley Elect. Assoc., Inc., 101 FERC ] 61,146
(2002).
---------------------------------------------------------------------------

    57. Consistent with the NOPR proposal, the Commission finds it
appropriate to use the total annual wholesale sales volumes reported as
``Sales for Resale'' in EIA Form 861 for purposes of calculating the de
minimis threshold.\113\ Basing the threshold calculation on the total
annual wholesale sales figure already reported by non-public utilities
in EIA Form 861 will avoid the need for them to make a separate
calculation of annual wholesale sales for EQR purposes and ensure a
consistent method for calculating the threshold. Therefore, in response
to Cities/M-S-R's request for clarification of how joint action
agencies should determine whether they exceed the de minimis threshold,
we clarify that they should use the wholesale sales volumes reported as
their ``Sales for Resale'' figure in EIA Form 861. However, as

explained below, the Commission will not require non-public utilities
to report sales made to members, or intra-familial sales, in the
EQR.\114\ In light of the determination to exclude from the EQR
reporting requirement sales by cooperatives or joint action agencies to
their members, we will not address comments concerning how to report
such member sales.
---------------------------------------------------------------------------

    \113\ EIA Form 861 instructions for Line 12, define ``Sales for
Resale'' as the amount of electricity sold for resale purposes,
including ``sales for resale to power marketers (reported separately
in previous years), full and partial requirements customers, firm
power customers and nonfirm customers.'' See EIA, Annual Electric
Power Industry Report Instructions, available at http://www.eia.gov/survey/form/eia_861/instructions.pdf.
    \114\ We note that while the threshold calculation is based on
total wholesale sales, entities may not have to report all of their
wholesale sales. For additional discussion, see supra Sec.
II.A.1.a. and infra Sec.  II.A.2.a.
---------------------------------------------------------------------------

    58. In response to Southwestern Power Administration's comments
that its annual sales vary greatly from year-to-year due to rainfall
rates, the Commission finds that using a three-year average of total
wholesale sales to calculate an entity's filing status helps moderate
possible fluctuations in an entity's filing status. Moreover,
information capturing fluctuations in wholesale sales can provide
valuable details on the competitiveness of electricity markets.\115\
---------------------------------------------------------------------------

    \115\ See discussion at supra P 18.
---------------------------------------------------------------------------

2. Filing Requirements for Non-Public Utilities
a. Scope of EQR Filing Requirements for Non-Public Utilities
i. NOPR
    59. The Commission proposed to require a non-public utility with
more than a de minimis market presence to report the same contractual
and transactional information about its wholesale sales and
transmission service, including cost-based and market-based sales,
transmission service, and transmission capacity reassignments, that
public utilities currently report. The Commission also proposed to
include sales made by G&T cooperatives, joint action agencies, state
agencies, and power or water districts to their own members. The
Commission proposed to exclude, however, certain fields that it
concluded may not be applicable to filings made by non-public
utilities. As an example, the Commission noted that non-public
utilities may not possess an appropriate FERC Tariff Reference to
include in contract data Field Number 19 (FERC Tariff Reference) and
transaction data Field Number 50 (FERC Tariff Reference) and would mark
``Not Required'' or ``n/r'' in these fields.
ii. Comments
    60. EEI agrees that the Commission should require all parties to
file the same basic EQR information. However, EEI also encourages the
Commission to ensure that the EQR only requires reporting of
information that is necessary and useful for the Commission to collect
and that market participants can provide in the normal course of
business.\116\
---------------------------------------------------------------------------

    \116\ EEI at 6-7.
---------------------------------------------------------------------------

    61. Several commenters argue that the Commission should not require
entities such as joint action agencies, state agencies, power
districts, and G&T cooperatives to report sales made to their own
member utilities or long-term distribution customers under long-term
agreements.\117\ TAPS asserts that requiring joint action agencies and
G&T cooperatives to report their cost-based sales to members is
contrary to FPA section 220 because it imposes reporting requirements
that do not advance the section's objective of enhancing market
transparency. TAPS contends that reporting such sales would provide no
information regarding the rates, terms or conditions under which a
joint action agency would be willing to sell power to a non-member, nor
would it provide information about the alternative rates, terms, and
conditions under which the members could obtain power from other
sources.\118\
---------------------------------------------------------------------------

    \117\ See, e.g., APPA at 4; Cities/M-S-R at 9; Public Systems at
9; TAPS at 11.
    \118\ TAPS at 11.
---------------------------------------------------------------------------

    62. APPA similarly argues that such sales play no role in price
formation. According to APPA, sales by a joint action agency to its
members are cost-based sales under long-term contracts that do not
reflect current commercial conditions or market supply and demand.\119\
Cities/M-S-R state that such sales typically reflect only the cost of
production of the energy and the repayment of bond financing and are
not arm's-length transactions that reflect market conditions; thus,
such transactions should not be reported.\120\
---------------------------------------------------------------------------

    \119\ APPA at 4-5.
    \120\ Cities/M-S-R at 10.
---------------------------------------------------------------------------

    63. While Public Systems agree that such sales are technically
wholesale sales, they argue that such sales are not market sales and
therefore do not reflect the rates, terms, or conditions on which a
joint action agency would be able or willing to sell energy at
wholesale to any other entities.\121\ Transmission Dependent Utility
Systems state that distribution cooperatives form G&T cooperatives to
obtain cost efficiencies and that they enter into long-term contracts
with their members to serve as security to finance generation and
transmission facilities. Transmission Dependent Utility Systems argue
that even though sales by a G&T cooperative to its members are
wholesale sales, these sales are not the type of arm's-length sales
between two wholesale market participants that determine market prices.
Instead, Transmission Dependent Utility Systems argue that the initial
purchase of power by the G&T cooperative is the significant
transaction. According to Transmission Dependent Utility Systems, such
sales are already reported in the EQR by the selling market
participant. Thus, Transmission Dependent Utility Systems argue that
there is no additional price information to be gleaned from the flow-
through of purchased power from a G&T cooperative to its distribution
member cooperative.\122\
---------------------------------------------------------------------------

    \121\ Public Systems at 9.
    \122\ Transmission Dependent Utility Systems at 5-6.
---------------------------------------------------------------------------

    64. A number of commenters argue that joint action agencies and G&T
cooperatives are analogous to vertically-integrated utilities.\123\
APPA states that joint action agencies are virtually vertically
integrated with their member distribution systems, and argues that if
they were literally vertically integrated, then there would be no
wholesale sale to report. APPA argues that the same is true of sales by
state agencies and power districts to neighboring distribution
utilities through full requirement or other types of firm, long-term
contracts.\124\ TAPS argues that transactions involving G&T
cooperatives and joint action agencies are wholesale sales in name
only, and arise only because the individual members were too small to
conduct such activities on their own and had to create a distinct legal
entity to perform them on a joint basis.\125\ Public Systems also
assert that joint action agencies and G&T cooperatives use contracts to
accomplish what vertically-integrated utilities accomplish through
their corporate structure and thus sales to their members should not be
considered wholesale sales.\126\
---------------------------------------------------------------------------

    \123\ See, e.g., APPA at 5; Public Systems at 12; TAPS at 9.
    \124\ APPA at 5.
    \125\ TAPS at 9.
    \126\ Public Systems at 10.
---------------------------------------------------------------------------

    65. Public Systems and TAPS argue that requiring joint action
agencies and G&T cooperatives to report sales to their members is
unduly discriminatory because the Commission does not require other
non-market transactions that affect the amount of demand served through
the market.\127\ For instance, TAPS states that the Commission does not
require a load-serving entity to report when it engages in demand
response, installs energy efficiency

measures, or relies on its own generation to serve its load even though
such activities reduce the load-serving entity's need for market
purchases.\128\
---------------------------------------------------------------------------

    \127\ Public Systems at 12; TAPS at 12.
    \128\ TAPS at 12.
---------------------------------------------------------------------------

    66. TAPS also argues that it may be difficult to fit joint action
agency sales to members into the categories the Commission has
developed to describe other types of transactions. TAPS contends that
this is evidence that such sales are not market transactions and cannot
be compared to them meaningfully.\129\
---------------------------------------------------------------------------

    \129\ Id. 14.
---------------------------------------------------------------------------

    67. Transmission Dependent Utility Systems argue that there is no
potential in the transaction between the G&T cooperative and its member
for exploitation of the kind that the FPA is intended to prevent. In
support, Transmission Dependent Utility Systems state that the
Commission has recognized in a number of orders that affiliate abuse is
not a concern for cooperatives owned by other cooperatives.\130\ APPA
also cites to a Commission order that reasoned that ``sales of power by
G&T cooperatives to their member G&T cooperatives or their member
distribution cooperatives do not constitute marketing functions under
the Standards of Conduct.''\131\ Thus, APPA contends that there is no
need for a joint action agency to report sales to members in its EQR.
---------------------------------------------------------------------------

    \130\ Transmission Dependent Utility Systems at 7-8 (citing
Desert Generation & Transmission, Inc., 115 FERC ] 61,306, at P 14
(2006)).
    \131\ APPA at 5-6 (citing Standards of Conduct for Transmission
Providers, Order No. 717, FERC Stats. & Regs. ] 31,280 (2008), order
on reh'g and clarification, Order No. 717-A, FERC Stats. & Regs. ]
31,297 (2009), order on reh'g and clarification, Order No. 717-B,
129 FERC ] 61,123, order on reh'g and clarification, Order No. 717-
C, 131 FERC ] 61,045, at P 21 (2010)).
---------------------------------------------------------------------------

    68. Cities/M-S-R disagree with the Commission's assertion that if a
joint action agency, state agency, or power or water district did not
supply its members then its members would have to purchase supply from
other sources in the market. Instead, Cities/M-S-R assert that without
the joint action agency, a member would likely develop its own
resource.\132\
---------------------------------------------------------------------------

    \132\ Cities/M-S-R at 9-10.
---------------------------------------------------------------------------

    69. TAPS asserts that if a member makes a sale of excess power into
the market, then it would be required to report that sale in the EQR,
assuming that the selling member had more than a de minimis market
presence. Thus, TAPS argues that a potential resale at wholesale of
power supplied by a joint action agency or G&T cooperative to its
members does not justify requiring joint action agencies and G&T
cooperatives to report sales to their members.\133\
---------------------------------------------------------------------------

    \133\ TAPS at 13.
---------------------------------------------------------------------------

    70. If the Commission does not exclude a G&T cooperative's sales to
its members from reporting requirements, then NRECA argues that the
Commission should not require cooperatives with multiple tiers of G&T
cooperatives to report their sales. For example, NRECA states that
Basin Electric Power Cooperative, a G&T cooperative, sells electric
power and energy at wholesale to its `Class A' members, which are also
G&T cooperatives. NRECA further states that the Class A members, acting
as middlemen, then sell power and energy at wholesale to their
distribution cooperative members at essentially the same price as they
paid. Given that the price is essentially identical, NRECA argues that
the Commission should not require both tiers of these G&T cooperatives
to report; otherwise it will lead to double counting.\134\
---------------------------------------------------------------------------

    \134\ NRECA at 17-18.
---------------------------------------------------------------------------

    71. APPA states that a more reasonable alternative would be for the
Commission to require state agencies and power districts to report such
transactions in their EQRs only to the extent that the applicable firm,
long-term contract expires in less than three years.\135\ Similarly,
LPPC encourages the Commission to exempt from reporting agreements of
longer than three years between non-public utilities.\136\ In support,
LPPC states that much of the power sold pursuant to these long-term
arrangements is not available to private entities purchasing power in
Commission-jurisdictional markets due to Internal Revenue Service Code
restrictions. According to LPPC, these restrictions generally prohibit
non-public utilities from selling more than a minimal amount of
electricity to private entities; power sold in excess of this limit
jeopardizes the nonpublic utility's tax-exempt financing.\137\
---------------------------------------------------------------------------

    \135\ APPA at 7, n.11.
    \136\ LPPC at 4.
    \137\ Id. at 6.
---------------------------------------------------------------------------

    72. In contrast, EEI asserts that non-public utilities should
report transaction and contract information on sales between non-
jurisdictional entities as well as between non-jurisdictional and
jurisdictional entities to provide a more complete picture of energy
markets.\138\
---------------------------------------------------------------------------

    \138\ EEI at 6.
---------------------------------------------------------------------------

iii. Commission Determination
    73. The Commission adopts the NOPR proposal to require non-public
utilities to report the same information about wholesale sales,
transmission service, and transmission capacity reassignments that are
currently reported by public utilities, with modifications. Expanding
the same EQR data elements to non-public utilities will help ensure
comparability and consistency with filings by public utilities, which
will make it easier for the public and the Commission to use the
information. In addition, requiring the same sales and transmission-
related information from non-public utilities will allow the Commission
to better evaluate the performance of wholesale markets as a whole and
make it easier to determine whether jurisdictional prices are just and
reasonable.\139\
---------------------------------------------------------------------------

    \139\ See NOPR, FERC Stats. & Regs. ] 32,676 at P 45.
---------------------------------------------------------------------------

    74. Many commenters argue that the Commission should not require
non-public utilities to report wholesale sales made to their own
members or made under long-term, cost-based agreements. As mentioned
above, the Commission will modify its NOPR proposal to exclude the
following types of wholesale sales from the EQR reporting requirement
for non-public utilities above the de minimis threshold: (1) sales by a
non-public utility, such as a cooperative or joint action agency, to
its members; and (2) sales by a non-public utility under a long-term,
cost-based agreement required to be made to certain customers under
Federal or state statute.\140\ To the extent wholesale sales made by a
non-public utility do not meet either of these criteria, the non-public
utility must report those sales in the EQR.
---------------------------------------------------------------------------

    \140\ See discussion at supra Sec.  II.A.1.a.
---------------------------------------------------------------------------

    75. The Commission recognizes that certain data fields in the EQR
may not be applicable to filings made by non-public utilities. As
stated in the NOPR, non-public utilities may not possess a FERC Tariff
Reference (Field Numbers 19 and 50) for certain wholesale contracts and
transactions. In cases where a FERC Tariff Reference is not applicable,
the Commission will require that a filer mark ``NPU,'' (to indicate
``Non-Public Utility'') in those fields. If a non-public utility has a
previously filed reciprocity open access transmission tariff (OATT), it
should refer to that reciprocity OATT in Field Number 19 under FERC
Tariff Reference. In addition, non-public utilities should mark ``NPU''
with respect to the ``cost-based'' or ``market-based'' options
available under ``Product Type Information'' captured in Field Number
30, because these options are defined based on types of Commission-
approved tariffs. If transmission capacity is reassigned

under a non-public utility's reciprocity OATT, the non-public utility
should follow the existing conventions for transmission providers
reporting transmission capacity reassignments in the EQR.
b. Burden
i. NOPR
    76. In the NOPR, the Commission recognized that extending the EQR
filing requirements to non-public utility market participants will
impose a new burden on those market participants. The Commission agreed
that it would make every effort to provide guidance and technical
assistance prior to implementation of the EQR filing requirements for
non-public utilities.
ii. Comments
    77. Some commenters question whether the Commission has adequately
considered the burden imposed on non-public utilities. For example,
Southwestern Power Administration asserts that section 220 of the FPA
provides the Commission with limited authority to seek information from
certain non-public utilities and requires the Commission to weigh the
value of the information against the regulatory burden it would impose
on those entities. Southwestern Power Administration argues that
requiring it to report information about its sales will serve no useful
purpose that would justify the burden of reporting this information and
that the Commission has not shown otherwise.\141\
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    \141\ Southwestern Power Administration at 2-3.
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    78. California DWR argues that the NOPR fails to comply with
Federal statutes that require the Commission to carefully consider the
costs and benefits of imposing burdens on governmental entities. For
instance, California DWR states that the Paperwork Reduction Act
requires agencies to certify that a new reporting requirement is not
unnecessarily duplicative and that the Unfunded Mandates Reform Act of
1995 requires agencies to prepare a written statement of
intergovernmental mandates that describe the analyses and consultations
on the unfunded mandate.\142\ California DWR also states that Executive
Order 12866 requires agencies to propose or adopt regulations after it
determines that the benefits of the intended regulation justify the
costs and that the Regulatory Right to Know Act requires agencies to
conduct cost-benefit analysis of their regulatory initiatives and
report their findings to the Office of Management and Budget.\143\
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    \142\ California DWR at 6-7 (citing Paperwork Reduction Act, 44
U.S.C. 3506(c)(3) (2006); Unfunded Mandates Reform Act of 1995, 2
U.S.C. 1531, et seq. (2006)).
    \143\ Id. at 5-6 (citing Executive Order 12866, 58 FR 51735
(Oct. 4, 1993); Regulatory Right to Know Act, 31 U.S.C. 1105
(2006)).
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    79. Southwestern Power Administration states that it does not have
the staffing needed to track and report EQR data, and that hiring
additional staff to comply would pose increased costs with no
commensurate benefit to its customers or incremental improvement to
market transparency.\144\ California DWR argues that the NOPR as
written would give non-public utilities an incentive to self-supply to
avoid wholesale power sales in order to reduce reporting burdens, which
appears contrary to business requirements.\145\
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    \144\ Southwestern Power Administration at 4.
    \145\ California DWR at 7.
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    80. If the Commission requires non-public utilities to submit EQRs,
then NRECA argues that the Commission could reduce the burden on non-
public utilities by simplifying the filing requirements as it relates
to billing adjustments. NRECA states that it is common practice for a
cooperative to bill its members under long-term contracts on the basis
of budgets and that these charges are later trued-up to reflect the
actual costs associated with the sale. NRECA states that EQR
regulations require entities to file either revised EQRs or new
transactions with the class name ``Billing Adjustments'' to report
changes in billing data after the initial EQR filing deadlines. NRECA
asserts that it would be very burdensome for cooperatives that use
budget-based billing to submit revised EQRs or Billing Adjustments to
reflect true-ups to actual costs. Thus, NRECA argues that the
Commission should simplify the filing requirements for cooperatives
that use budget-based billing by specifying that true-ups associated
with budget-based billing do not trigger the requirement to submit
revised EQRs or Billing Adjustments.\146\
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    \146\ NRECA at 18-19.
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    81. LPPC encourages the Commission to provide sufficient lead time
to enable non-public utilities to comply, and suggests a period of six
months from the date of the final rule. LPPC also requests that the
Commission have staff assist in training programs that will facilitate
compliance.\147\
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    \147\ LPPC at 10.
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iii. Commission Determination
    82. The Commission has carefully weighed, in developing this Final
Rule, the burden associated with an entity filing the EQR against the
benefits associated with greater transparency in the nation's wholesale
electric markets. The Commission concludes that the burden of reporting
information in the EQR is outweighed by the benefits of greater
transparency provided by the EQR.
    83. The burden of preparing an EQR filing varies, depending on the
complexity of a company's transactions. If a company has a few long-
term contracts of limited complexity, its EQR filing is simple: an
unchanging description of its contracts from quarter to quarter with
monthly or quarterly reports of the transactions under that contract.
As the company's sales activities become more complex, with more
frequent adjustments to price and a greater variety of counterparties
and sales locations, its technological capabilities for tracking its
transactions tend to become more sophisticated. As a result, complex,
detailed EQRs tend to be associated with companies more capable of
generating such a filing. Filers whose participation in the electric
wholesale markets occurs under long-term, cost-based contracts with a
limited number of counterparties will expend relatively little effort
in complying with the EQR filing requirement. In addition, we believe
that excluding from the reporting requirement sales by non-public
utilities under long-term, cost-based agreements required to be made to
certain customers under Federal or state statute will help lessen the
burden on non-public utilities. Therefore, we believe that non-public
utilities would not be encouraged to self-supply to avoid the reporting
requirements, as suggested by California DWR.
    84. In response to NRECA's concern about the difficulty for non-
public utility cooperatives that use budget-based billing to submit
revised EQRs or billing adjustments to reflect true-ups or actual
costs, the Commission will not require true-ups by non-public utility
cooperatives with budget-based billing in the EQR. The Commission's
policy regarding refilings or billing adjustments stems from the
statutory requirement under FPA section 205(c) to have a public
utility's rates on file. Specifically, in recognition of the fact that
public utilities may not have complete, final data for the full quarter
by EQR filing deadlines, the Commission requires that any additions or
changes to an EQR filing must be made by the end of the following
quarter, when the filer is expected to file the best available new
data.\148\ Filers are

required to file material changes, either as a full refiling or as a
transaction with the class name ``Billing Adjustment.'' \149\ It is
worth emphasizing that refiling EQRs, with a billing adjustment to
reflect the receipt of new information, is only necessary if the filer
considers the change to previous EQR totals to be material.\150\ The
Commission has found that this policy balances the need for timely,
accurate EQR data, while reducing the burden on filing entities by
identifying price changes on a transaction-by-transaction basis due to
some after-the-fact billing transaction long after the EQR was
due.\151\ In the case of budget-based billing, non-public utility
cooperatives are not covered by FPA section 205 and the true-up process
will likely have little effect on the market dynamics the Commission is
trying to capture with this Final Rule. For these reasons, the
Commission will exclude true-ups by non-public utility cooperatives
associated with budget-based billing from the EQR's refiling or billing
adjustment policy.
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    \148\ Order No. 2001-E, 105 FERC ] 61,352 at PP 9-10. According
to the EQR Data Dictionary, a Billing Adjustment (BA) designates an
incremental material change to one or more transactions due to a
change in settlement results. BA may be used in a refiling after the
next quarter's filing is due to reflect the receipt of new
information. It may not be used to correct an inaccurate filing. See
Order No. 2001-G, 120 FERC ] 61,270 at P 33.
    \149\ Order No. 2001-E, 105 FERC ] 61,352 at PP 9-10.
    \150\ Order No. 2001-G, 120 FERC ] 61,270 at PP 33-34.
    \151\ Id.
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    85. We agree with LPPC that the Commission should provide
sufficient lead time to enable non-public utilities to comply. Over the
past ten years, the Commission has been proactive in its outreach on
many aspects of the EQR; in issuing this Final Rule, the Commission
acknowledges that new filers will need the opportunity to learn about
the filing. Accordingly, non-public utility filers are required to file
EQRs beginning with the third quarter (Q3) of 2013, covering the period
July through September 2013. The Commission directs staff to assist
filers with compliance. For example, the Commission intends to convene
a staff-led technical conference, to be announced at a future date, to
assist non-public utilities in collecting and filing EQR data.

B. Refinements to the Existing EQR Requirements

1. General Refinements
a. Trade Date & Time and Type of Rate
i. NOPR
    86. In the NOPR, the Commission proposed to require any market
participant that is required to file an EQR to report in the EQR the
date on which parties to a reported transaction agreed upon a price
(trade date) and the type of rate by which the price was set. The
Commission stated in the NOPR that the term ``trade date'' means ``the
date upon which the parties agree upon the price of a transaction.''
The Commission also proposed four types of rates: ``fixed,''
``formula,'' ``index,'' and ``RTO/ISO price.'' A fixed rate would be
defined as a fixed charge per unit of consumption. A formula rate would
be defined as a calculation of a rate based upon a formula that does
not contain an index component. An index rate would be defined as a
calculation of a rate based upon an index or a formula that contains an
index component. An ``RTO/ISO price'' would be defined as a rate that
is based on an RTO/ISO published price or formula that contains an RTO/
ISO price component. The Commission also proposed to require market
participants to report the time of trade, defined as ``the time upon
which the parties agree upon the price of a transaction.''
ii. Comments
    87. DC Energy, Joint Market Monitors, and Pennsylvania Commission
support the Commission's proposal to require the trade date and time
and type of rate in EQR.\152\ However, as discussed further below, many
commenters are opposed to parts of the proposal.
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    \152\ See, e.g., DC Energy at 4-5; Joint Market Monitors at 4-5;
and Pennsylvania Commission at 4.
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(a) Trade Date
    88. With respect to the proposed requirement to report the trade
date, Powerex states it should not be onerous to report such data
because market participants likely already track it.\153\ However, some
commenters question the need for trade data and note some difficulty in
ascertaining the appropriate date to report. EEI questions the need for
trade date information, arguing that contracts negotiated to cover
specific transactions will include trade-specific details so that
transactions can be distinguished based on the associated contract
information in the EQR. In addition, EEI suggests that, if the
Commission requires reporting of trade dates, it should clarify that
the trade date is the effective date of the legally binding agreement
between parties with respect to the transaction. In this vein, EEI
contends that the ``official'' trade date agreed to by market
participants for each transaction and documented in trade capture
systems and related transaction documentation is the appropriate date
to use. EEI states that its members and other market participants
document the ``official'' date in their trade capture systems and
related transaction documentation. EEI also recommends that the
requirement for trade date apply only to transactions entered into
after the Commission adopts a final rule.\154\
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    \153\ Powerex at 14.
    \154\ EEI at 12-13.
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    89. EPSA asks the Commission to clarify whether RTO or ISO sales
are included in the date/time reporting requirement as these
transactions do not meet the Commission's proposed definition of
agreement of the parties upon a price because RTO or ISO mitigation
schemes may alter awarded prices, which are not known to the market
participant and are not received until after the flow data. EPSA notes
that in its NOI comments it expressed concern that the date parties
agree to a price is not synonymous with the transaction date. EPSA adds
that there are several elements apart from price, including volume,
point of delivery, nature of firmness, credit terms, duration, enabling
agreement status, upon which the parties must reach agreement before
they execute that trade. EPSA states that ``[i]f the final rule makes
time and date determinations based on the setting of price there will
be a need to clearly explain how that is done for the many scenarios in
the power business; only with this additional explanation can complying
entities ensure that EQR data is not only transparent but
useful.''\155\ Entergy questions the usefulness of the trade date and
notes examples of situations where the price in effect when the
transaction was entered would not be the rate when the transaction
began.\156\ Entergy adds that, for hourly market sales, a trade date
would be difficult to determine because it may be subject to review and
agreement at a later date.\157\
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    \155\ EPSA at 7.
    \156\ Entergy at 2 (``while a rate may be arranged at the
outset, changes in tariff rates and other circumstances may affect
the rate between the time the transaction was made and the date the
transaction flows'').
    \157\ Id. at 2-3. Entergy provides the example of a price for an
hourly market sale being agreed upon during the day ahead or on an
hourly basis, but the final prices being subject to review and
agreement at a later date. Id. at 3.
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(1) Commission Determination
    90. The Commission adopts, with modification, the NOPR proposal to
require reporting of the trade date in the EQR. The NOPR proposed to
define the trade date as the date on which parties

to a reported transaction agreed upon a price. We will clarify this
definition of trade date, as suggested by EEI, to state that it is
``the date upon which the parties made the legally binding agreement on
the price of the transaction.''
    91. As stated in the NOPR, the trade date for transactions
currently is not provided or collected publicly.\158\ The trade date is
essential to assessing the significance of prices in relation to market
conditions in effect at that time. The EQR only collects the start and
end date of physical transactions as well as other data details for
contracts. In current EQR filings, trades entered into months before
the transaction start and end dates are indistinguishable from trades
entered into minutes before the transaction occurs, making it difficult
to determine whether pricing is appropriate given market conditions. In
addition, many of the prices reported in the EQR result from
confirmation made under master agreements and the prices are not set in
the contracts themselves, so the Commission is not able to determine
from EQR data when the price was set. The Commission concludes that
requiring market participants to report the date on which parties to a
reported transaction agreed upon a price (trade date) is necessary to
improve market transparency. The trade date should be reported in the
EQR transaction section accompanied by each specific sales transaction.
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    \158\ NOPR, FERC Stats. & Regs. ] 32,676 at P 91.
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    92. We further clarify that, in cases where pricing detail is
provided in the contract description, the Contract Execution Date
should be considered the trade date. Where applicable, this
clarification will virtually eliminate any additional burden associated
with this field by allowing the filer to complete the trade date field
for each transaction by using a date (Contract Execution Date in the
contracts section) already provided in the filing. It also will obviate
the need to identify whether this requirement applies to transactions
with trade dates before the initial filing that includes this field. It
is unlikely that a transaction will occur during or after the first
filing under these new rules that both became legally binding before