
[Federal Register Volume 76, Number 83 (Friday, April 29, 2011)]
[Proposed Rules]
[Pages 24188-24211]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-10113]



[[Page 24187]]

Vol. 76

Friday,

No. 83

April 29, 2011

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; Proposed Rule

  Federal Register / Vol. 76 , No. 83 / Friday, April 29, 2011 / 
Proposed Rules  

[[Page 24188]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM10-12-000]


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

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Commission proposes to amend 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 proposes 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 proposes to refine the existing EQR 
filing requirements by directing all filers to: report the transaction 
date and time, as well as the type of rate by which the price in the 
transaction or contract was set (i.e., fixed price, formula, index, 
regional transmission organization/independent system operator (RTO/
ISO) price, or index); indicate whether the transaction was reported to 
an index publisher; identify the broker or exchange used for a 
transaction, if applicable; and report electronic tag (e-Tag) ID data 
in EQRs. The Commission also proposes to: Standardize the unit for 
reporting energy and capacity transactions; omit the time zone from the 
contract section; and eliminate the Data Universal Numbering System 
(DUNS) data requirement. These refinements to the existing EQR filing 
requirements reflect the evolving nature of electricity markets and 
promote greater price transparency and confidence in electricity 
markets.

DATES: Comments are due June 28, 2011.

ADDRESSES: You may submit comments, identified by docket number by any 
of the following methods:
     Agency Web Site: http://ferc.gov. Documents created 
electronically using word processing software should be filed in native 
applications or print-to-PDF format and not in a scanned format.
     Mail/Hand Delivery: Commenters unable to file comments 
electronically must mail or hand-deliver an original and 14 copies of 
their comments to: Federal Energy Regulatory Commission, Secretary of 
the Commission, 888 First Street, NE., Washington, DC 20426.

FOR FURTHER INFORMATION CONTACT:
Maria Vouras, Office of Enforcement, Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-
8062, Maria.Vouras@ferc.gov.
Christina Switzer, Office of General Counsel, Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-
6379, Christina.Switzer@ferc.gov.
William Sauer, Office of Enforcement, Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-
6639, William. Sauer@ferc.gov.

SUPPLEMENTARY INFORMATION: 

Table of Contents

 
                                                               Paragraph
                                                                numbers
 
I. Background...............................................           3
    A. Order No. 2001.......................................           3
    B. EPAct 2005...........................................           5
    C. Notice of Inquiry....................................           8
II. Discussion..............................................           9
    A. Extending the EQR Filing Requirements to Non-Public             9
     Utilities..............................................
        1. Background.......................................           9
        2. Commission Authority.............................          14
        3. Proposed Filing Requirements for Non-Public                32
         Utilities..........................................
    B. Refinements to the Existing EQR Requirements.........          78
        1. Background.......................................          78
        2. General Refinements..............................          81
        3. Additional EQR Enhancements......................         107
III. Information Collection Statement.......................         123
IV. Environmental Analysis..................................         131
V. Regulatory Flexibility Act Certification.................         132
VI. Comment Procedures......................................         136
VII. Document Availability..................................         140
Appendix A: List of Commenters
Appendix B: Proposed Refinements to the Existing EQR
 

Notice of Proposed Rulemaking--April 21, 2011

    1. To facilitate price transparency in markets for the sale and 
transmission of electric energy in interstate commerce, the Federal 
Energy Regulatory Commission (Commission) proposes to revise its 
regulations to require market participants that are excluded from the 
Commission's jurisdiction under section 205 of the Federal Power Act 
(FPA) \1\ and have more than a de minimis market presence to file 
Electric Quarterly Reports (EQR) with the Commission.\2\ In doing so, 
the Commission proposes to exercise its

[[Page 24189]]

authority under section 220 of the FPA,\3\ as adopted in the Energy 
Policy Act of 2005 (EPAct 2005).\4\ This proposal would allow the 
Commission and the public to gain a more complete picture of wholesale 
power and transmission markets in interstate commerce by providing 
additional information concerning price formation and market 
concentration in these markets. Public access to additional sales and 
transmission-related information in the EQR would improve market 
participants' ability to assess supply and demand fundamentals and to 
price interstate wholesale market transactions. It also would 
strengthen the Commission's ability to identify potential exercises of 
market power or manipulation and to better evaluate the competitiveness 
of the interstate wholesale markets.
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    \1\ 16 U.S.C. 824d. For ease of reference, this Notice of 
Proposed Rulemaking (NOPR) 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).
    \2\ These proposed requirements would not apply to a transaction 
for the purchase or sale of wholesale electric energy or 
transmission services within the Electric Reliability Council of 
Texas (ERCOT), consistent with the exclusion set forth in FPA 
section 220(f). 16 U.S.C. 824t(f).
    \3\ 16 U.S.C. 824t.
    \4\ EPAct 2005, Pub. L. 109-58, 119 Stat. 594 (2005).
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    2. In addition, the Commission proposes to make certain revisions 
to the existing EQR filing requirements and apply those revisions to 
all market participants filing EQRs. The Commission proposes to revise 
the EQRs currently filed by public utilities under FPA section 205(c) 
and that will be filed by non-public utilities under FPA section 220. 
These revisions include the addition of new fields for: (1) Reporting 
the transaction date and time, as well as the type of rate; (2) 
indicating whether the sales transaction was reported to an index 
publisher; (3) identifying the broker or exchange used for a sales 
transaction, if applicable; and (4) reporting electronic tag (e-Tag) ID 
data. The Commission also proposes to eliminate the time zone from the 
contract section and the Data Universal Numbering System (DUNS) data 
requirement. Further, the Commission proposes to standardize the unit 
for reporting energy and capacity transactions. These refinements to 
the existing EQR filing requirements reflect the evolving nature of 
electricity markets, would increase market transparency for the 
Commission and the public, and would allow market participants to file 
the information in the most efficient manner possible.\5\
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    \5\ The Commission also is reviewing the software currently used 
to file EQRs.
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I. Background

A. Order No. 2001

    3. 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,\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. P 13-14.
    \9\ 16 U.S.C. 824d(c).
    \10\ Order No. 2001, FERC Stats. & Regs.] 31,127 at P 31.
    \11\ Id. P 31.
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    4. 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 reassignment to be reported in the EQR.\14\ The 
refinements to the existing EQR requirements that we are proposing in 
this NOPR 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 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 (March 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

    5. 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 provisions in the 
Natural Gas Act.\20\
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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\ 16 U.S.C. 824t(a)(2).
    \18\ Id. 824t(a)(3)(A).
    \19\ Id. 824t(d).
    \20\ 15 U.S.C. 717t-2.
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    6. In 2006, Commission staff conducted an extensive outreach effort 
to formulate options for implementing EPAct 2005's transparency 
provisions for wholesale natural gas and electricity markets. As a 
result, the Commission used its new transparency authority to adopt 
additional filing and posting requirements for the sale or 
transportation of physical natural gas in interstate commerce in Orders 
No. 704 and 720. Order No. 704 requires buyers and sellers of more than 
a de minimis volume of natural gas to report aggregate volumes of 
relevant transactions in an

[[Page 24190]]

annual filing.\21\ In Order No. 720, the Commission required major non-
interstate pipelines to post daily scheduled volume and other data for 
certain receipt and delivery points.\22\ Order No. 720 also requires 
interstate pipelines to post information regarding no-notice 
service.\23\
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    \21\ Transparency Provisions of Section 23 of the Natural Gas 
Act, Order No. 704, 73 FR 1014 (Jan. 4, 2008), FERC Stats. & Regs. ] 
31,260, at P 32 (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, at P 3 
(2008), order on reh'g, Order No. 720-A, 73 FR 73494 (Dec. 2, 2008), 
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).
    \22\ Order No. 720, FERC Stats. & Regs. ] 31,283 at P 1.
    \23\ Id.
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    7. The Commission declined to extend such requirements to wholesale 
electricity markets because, at the time of the Natural Gas 
Transparency Notice of Proposed Rulemaking, the Commission was 
considering other reforms to its regulation of electricity markets.\24\ 
In particular, the Commission was undertaking open access transmission 
service reforms and the more general review of competition in wholesale 
electricity markets.\25\ 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].'' \26\ 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.'' \27\ Although these final rules improved 
transparency in wholesale markets in a number of ways, the Commission 
believes the revisions proposed in this order are necessary to 
facilitate price transparency in wholesale electricity markets.
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    \24\ 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 P 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.'').
    \25\  Id.
    \26\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 40.
    \27\ 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. Notice of Inquiry

    8. On January 21, 2010, the Commission issued a Notice of Inquiry 
\28\ 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. In response to the Transparency NOI, the Commission 
received 40 comments. Of those comments, twenty-eight discuss extending 
the EQR filings to non-public utilities; five discuss EQR refinements; 
and six discuss both. We have considered these comments in drafting the 
proposals in this NOPR, and we invite further comments on these 
proposals.
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    \28\ 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).
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II. Discussion

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

1. Background
a. Need for Information from Non-Public Utilities
    9. Currently, market participants that fall within the Commission's 
jurisdiction under FPA section 205(c) \29\ must file EQRs summarizing 
contractual terms and conditions in their agreements for jurisdictional 
services, including market-based rate sales, cost-based sales, 
transmission service, and transmission capacity reassignments. In 
addition, EQR filers must provide detailed transactional information 
for power sales and transmission capacity reassignments made during the 
most recent calendar quarter.
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    \29\ FPA section 205(c) requires public utilities to file all 
rates and charges for any transmission or sale subject to the 
Commission's jurisdiction in a convenient form and place for public 
inspection. 16 U.S.C. 824d(c).
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    10. 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. 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. Applying the EQR 
filing requirements to the 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. As the Commission explained in 
implementing the transparency provisions under section 23 of the 
Natural Gas Act:

    The Commission's market-oriented policies for the wholesale 
natural gas industry require that interested persons have broad 
confidence that reported market prices accurately reflect the 
interplay of legitimate market forces. Without confidence in the 
fairness of price formation, the true value of transactions is very 
difficult to determine. Further, price transparency makes it easier 
for us to ensure that jurisdictional prices are ``just and 
reasonable.'' \30\
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    \30\ Order No. 704-A, 124 FERC ] 61,269 at P 3; see also Order 
No. 704, FERC Stats. & Regs. ] 31,260 at P 7.

    11. Based on the most recent data available in the 2009 U.S. Energy 
Information Administration's (EIA) 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).\31\ In particular, about 29 percent of those 
wholesale sales are made by non-public utilities. Non-public utilities 
make a significant portion of sales in certain regional wholesale 
markets within the United States. The 2009 EIA Form 861 data indicates 
that non-public utilities account for 60 and 70 percent of wholesale 
sales within the Western Electric Coordinating Council (WECC) and SERC 
Reliability Corporation (SERC) regions, respectively. Similarly, non-
public utilities make up about 80 percent of all wholesale sales that 
occur within the Florida Reliability Coordinating Council (FRCC). Given 
non-public utilities' significant presence in national and regional 
wholesale electricity markets, 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

[[Page 24191]]

and the Commission to detect and address the potential exercise of 
market power and manipulation.
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    \31\ See U.S. Energy Information Administration, Form EIA-861, 
Annual Electric Power Industry Report (April 2010), available at 
http://www.eia.doe.gov/cneaf/electricity/page/eia861.html.
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    12. Among the refinements this NOPR proposes to the EQR filing 
requirements is a requirement that all market participants provide 
information about the index publishers, if any, to which they report 
their transactions and any broker or exchange they use. This 
information would provide greater transparency regarding electricity 
index prices and how well those index prices reflect market forces, 
thus creating greater confidence in the electricity market. In 
addition, this NOPR proposes several refinements to the EQR filing 
requirements, including requiring all filers to report: (1) The 
transaction date and time; (2) the type of rate by which the price in 
the transaction or contract was set (i.e., fixed price, formula, index, 
or RTO/ISO price); and (3) e-Tag ID data. The Commission also proposes 
to: (1) Standardize the unit for reporting energy and capacity 
transactions; (2) omit the time zone from the contract section; and (3) 
eliminate the DUNS number requirement.
    13. Section 220(a)(4) of the FPA requires the Commission to 
``consider the degree of price transparency provided by existing price 
publishers and providers of trade processing services, and * * * rely 
on such publishers and services to the maximum extent possible.'' As 
discussed below, we have reviewed existing publications and we believe 
that the additional data that would be required under this NOPR is not 
available through existing sources and is necessary to provide a 
complete picture of price formation in wholesale power markets.
b. Notice of Inquiry Regarding Extending the EQR Filing Requirements
    14. In the Transparency NOI, the Commission sought comments 
regarding whether the Commission should extend the EQR filing 
requirements to non-public utilities. The Commission also sought 
comments on what information the Commission should collect, whether the 
Commission should establish a threshold for reporting, and the burden 
on market participants that would have to adapt their existing systems 
to be able to provide the information. The Commission also asked 
whether extending the filing requirements would impact market 
liquidity.
2. Commission Authority
a. Comments
    15. Several commenters question whether the Commission has the 
authority to extend the EQR filing requirements to non-public 
utilities.\32\ Many of these commenters emphasize that the Commission's 
jurisdiction under section 220 is limited to collecting information 
regarding wholesale electricity and transmission markets. They point to 
section 220(b), which states that ``[t]he Commission may prescribe 
rules * * * [that] provide for the dissemination, on a timely basis, of 
information about the availability and prices of wholesale electric 
energy and transmission service.'' \33\ They argue that non-public 
utilities constitute a small percentage of the wholesale market, and 
therefore information from these market participants will not enhance 
transparency significantly.\34\ In addition, Alaska Power argues that 
utilities in Alaska do not engage in energy and transmission 
transactions in interstate commerce and, therefore, should not be 
required to file EQRs. Many commenters also argue that there is a lack 
of evidence to support imposing the EQR filing requirements on non-
public utilities.\35\ For instance, NRECA and TANC argue that, in the 
Transparency NOI, the Commission overstated the volume of sales that 
would be reported if the Commission extended the filing requirements to 
non-public utilities.\36\ APPA asserts that EIA statistics on non-
public utility sales cited by the Commission in the Transparency NOI 
reflect bundled retail sales to consumers rather than information on 
wholesale sales, which is relevant to the Commission's oversight of 
jurisdictional wholesale markets.\37\ NRECA and TANC claim that the 
Commission should have excluded retail sales from EIA's estimate of 
electric utility sales that are made by entities other than public 
utilities.\38\ TANC also asserts that the Commission should have 
excluded sales from utilities in ERCOT because those utilities are 
outside the Commission's section 220 jurisdiction. APPA asserts that 
the Commission's efforts would be better spent focusing on Regional 
Transmission Organization (RTO) and Independent System Operators (ISO) 
market transparency.
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    \32\ APPA; NRECA; Southwest Transmission; EMCOS; Public Systems; 
East Texas Electric Cooperatives; Cities/M-S-R; TANC; MID; New York 
Public Power; Delaware Municipal; California DWR; Public Power 
Council; Allegheny; Utah Associated Municipal; NCPA; NYMPA/MEUA.
    \33\ 16 U.S.C. 824t(b).
    \34\ APPA; NRECA; EMCOS; Public Systems; East Texas Electric 
Cooperatives; TANC; Delaware Municipal; Utah Associated Municipal; 
NYMPA/MEUA.
    \35\ Southwest Transmission; East Texas Electric Cooperatives; 
TANC; Utah Associated Municipal.
    \36\ NRECA at 11; TANC at 16.
    \37\ APPA at 5-6.
    \38\ NRECA at 11.
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    16. NRECA and TANC further contend that the absence of EQR 
information from non-public utilities has not hampered the Commission's 
ability to approve market-based rates. For example, TANC argues that 
the Commission has been conducting ex ante and ex post analyses of 
public utilities' market power and has been approving and evaluating 
mergers for decades without information from non-jurisdictional 
entities.
    17. Cities/M-S-R state that entities under consideration in this 
proceeding have no statutory obligation to file their energy sales 
agreements with the Commission, nor are their rates subject to 
reasonableness determinations before the Commission. Accordingly, 
Cities/M-S-R argue that there is no need to use the EQR mechanism to 
replace other filing obligations, such as an annual filing with the 
EIA, for entities exempt from section 205 of the FPA.
    18. Other commenters argue that the Commission has the authority 
under the FPA to extend the EQR filing requirements to non-public 
utilities. EEI asserts that section 220 provides the Commission with 
clear authority and responsibility to extend the EQR filing 
requirements. DC Energy notes that section 205 also provides the 
Commission with broad authority to require otherwise exempt entities to 
provide information related to the rates for jurisdictional services.
    19. Several commenters also support the Commission's effort to 
increase transparency in wholesale electricity markets and assert that 
the additional reporting requirements will assist the Commission in 
carrying out its statutory obligations.\39\ The City of Dover states 
that reporting is needed to enable the Commission to understand the 
impact of certain transactions. DC Energy strongly supports the 
Commission's efforts and argues that such reporting will help 
facilitate the detection of market power. In addition, California PUC 
states that the additional filing requirements can help state 
regulatory agencies: (1) Oversee utility procurement; (2) establish 
statewide renewable portfolio standards, energy efficiency initiatives, 
demand response programs, and capacity market activities; and (3) 
further greenhouse gas policies.
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    \39\ See, e.g., City of Dover at 1; DC Energy at 5-6; California 
PUC at 2-3; PG&E at 3; Wisconsin Electric at 2; EEI at 3.

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[[Page 24192]]

b. Discussion
    20. The market transparency provisions in section 220 of the FPA 
direct the Commission to ``facilitate price transparency'' in markets 
for the sale and transmission of electric energy in interstate 
commerce.\40\ The transparency provisions 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.'' \41\ These provisions expand the Commission's authority to 
collect such information, not only from public utilities, but ``from 
any market participant'' \42\ with more than a de minimis market 
presence.\43\ The Commission proposes, in this NOPR, 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 outlined in the next 
section.
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    \40\ 16 U.S.C. 824t(a)(1).
    \41\ Id. at 824t(a)(2).
    \42\ Id. at 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).
    \43\ Id. at 824t(d).
---------------------------------------------------------------------------

    21. Currently, market participants that fall within the 
Commission's jurisdiction under FPA section 205 must file EQRs. Section 
201(f) of the FPA exempts certain entities (i.e., Federal entities, 
municipalities, and certain cooperatives with Rural Electrification Act 
financing and that sell less than 4,000,000 MWh of electricity per 
year) from the Commission's section 205 jurisdiction.\44\ However, the 
transparency provisions in FPA section 220 specifically permit the 
Commission to obtain price and availability information from ``any 
market participant.'' 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.
---------------------------------------------------------------------------

    \44\ Id. at 824(f).
---------------------------------------------------------------------------

    22. We interpret ``any market participant'' to include non-public 
utilities that fall under FPA section 201(f).\45\ 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, in EPAct 2005, Congress amended section 201(b)(2) of the 
FPA \46\ 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, 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.
---------------------------------------------------------------------------

    \45\ See id. at 824t(a)(3)(A).
    \46\ FPA section 201(b)(2) states that: Notwithstanding section 
201(f), the provisions of sections * * * 220 * * * shall apply to 
the entities described in such provisions, and such entities shall 
be subject to the jurisdiction of the Commission for purposes of 
carrying out such provisions and for purposes of applying the 
enforcement authorities of this Act with respect to such provisions. 
Id. at 824(b)(2).
---------------------------------------------------------------------------

    23. We disagree with certain commenters' assertions that 
information about wholesale sales made by non-public utilities will not 
significantly enhance price transparency because non-public utilities 
are a small percentage of the wholesale market. As noted above, based 
on 2009 EIA Form 861 data, non-public utility sales account for 
approximately 29 percent of wholesale sales in the 48 contiguous states 
(excluding ERCOT),\47\ while non-public utilities account for 60 and 70 
percent of wholesale sales within the WECC and SERC regions, 
respectively. Similarly, non-public utilities make up about 80 percent 
of all wholesale sales that occur within FRCC. Given non-public 
utilities' significant presence in national and regional wholesale 
electricity markets, obtaining information about their sales 
transactions is essential to understanding how prices are formed in 
electricity markets.
---------------------------------------------------------------------------

    \47\ The Commission has excluded ERCOT from its calculations 
consistent with FPA section 220(f), which states that section 220 
does not apply to wholesale sales of electric energy or transmission 
services within ERCOT. Id. at 824t(f). However, ERCOT members would 
need to report wholesale power sale contract and transaction 
information in EQR to the extent they make interstate sales outside 
of ERCOT.
---------------------------------------------------------------------------

    24. Certain commenters dispute the accuracy of the 29 percent 
figure cited in the Transparency NOI \48\ as the percentage of 
wholesale sales made by non-public utilities, arguing that the 
Commission incorrectly relied on EIA statistics pertaining to non-
public utility bundled sales instead of wholesale sales. In particular, 
NRECA, APPA, and TANC argue that the Transparency NOI calculated the 29 
percent figure based on EIA's figures for retail electric utility 
sales, labeled ``Sales to Ultimate Consumers.'' In fact, however, the 
Commission arrived at the 29 percent figure in the Transparency NOI by 
using the 2007 EIA Form 861 wholesale sales data classified by EIA as 
``Sales for Resale,'' and not ``Sales to Ultimate Consumers.'' \49\ 
This 29 percent figure remains the same using the most recently 
available date (i.e. 2009) from EIA Form 861.\50\ Thus, the percentages 
of wholesale sales made by non-public utilities cited in the 
Transparency NOI and this NOPR are accurate.
---------------------------------------------------------------------------

    \48\ Specifically, the Transparency NOI stated that EIA's 
Electric Power Industry Overview 2007 estimated that 29 percent of 
electric utility sales are made by publicly-owned electric utilities 
(municipals, public utility districts or public power districts, 
state authorities, irrigation districts, and joint municipal action 
agencies, consumer-owned rural electric cooperatives, and Federal 
electric utilities). See Transparency NOI, FERC Stats. & Regs. ] 
35,565 at P 9 & n. 21 (citing Energy Information Administration, 
Electric Power Industry Overview 2007 (March 2009) available at 
http://www.eia.doe.gov/cneaf/electricity/page/prim2/toc2.html).
    \49\ See Annual Electric Power Industry Report Instructions, 
available at http://www.eia.doe.gov/cneaf/electricity/forms/eia861.pdf.
    \50\ At the time that the Commission issued the Transparency 
NOI, EIA had not yet released the data for 2009.
---------------------------------------------------------------------------

    25. With respect to APPA's comments that the Commission should 
focus on increasing market transparency in RTOs/ISOs instead of 
increasing market transparency by requiring non-public utilities to 
file EQRs, we agree that transparency in the organized markets is 
important. In fact, the RTOs/ISOs already make available a significant 
amount of information about the availability and prices for wholesale 
sales and transmission service within their markets. For example, in 
Order No. 719, the Commission further promoted transparency in RTO/ISO 
markets by directing RTOs/ISOs to reduce the lag time for the release 
of offer and bid data and requiring RTOs/ISOs to justify in compliance 
filings their policy regarding the aggregation of offer data and cost 
data, discussing how the policy avoids participant harm and the 
possibility of collusion, while fostering market transparency.\51\ 
However, notwithstanding the high value the Commission places on market 
transparency in RTO/ISO markets, we continue to believe that increasing 
transparency broadly across all markets subject to the Commission's 
jurisdiction by requiring all market participants,

[[Page 24193]]

including non-public utilities with more than a de minimis presence in 
those markets, to provide information through EQRs is equally 
important.
---------------------------------------------------------------------------

    \51\ See 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 (Jul. 29, 2009), FERC Stats. & Regs. ] 31,292, order on 
reh'g, Order No. 719-B, 129 FERC ] 61,252 (2009).
---------------------------------------------------------------------------

    26. NRECA's and TANC's arguments that the Commission should not 
require non-public utilities to report information in the EQR because 
the Commission has been approving market-based rates and evaluating 
mergers for decades without such information miss the mark. 
Disseminating information through the EQR about wholesale sales made by 
non-public utilities would benefit the Commission, market participants 
and the public in several different ways in addition to improving the 
Commission's ability to evaluate jurisdictional sellers' market-based 
rate authorizations and proposed mergers and acquisitions. Information 
about non-public utility sales would provide a more complete view of 
the prices and volumes that underlie price formation in the wholesale 
power markets. Information on all sales, rather than sales made only by 
public utilities, would allow market participants to value their 
transactions more accurately and increase confidence that market prices 
reflect all relevant supply and demand forces. Such information, in 
combination with other information tools, would also allow the 
Commission to better monitor for indications of market power and 
manipulation at major trading hubs and on electricity indices. For 
example, without the inclusion of non-public utility transactions in 
the EQR, the Commission may incorrectly conclude that substantial 
market price deviations, or other indicators, at major trading hubs or 
on electricity indices are attributable to the exercise of market power 
or manipulation by a public utility, when in fact, those price 
deviations reflect legitimate market forces caused by significant 
volumes being transacted by non-public utilities.
    27. In addition, as the Commission explained in the Transparency 
NOI, 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.\52\ 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 excessive market share since it was granted 
authorization to transact at market-based rates or since the last 
review of such rates.\53\ One tool used in some cases to conduct an ex 
ante analysis of whether to grant market-based rate authority to a 
seller is the delivered price test (DPT). The DPT defines the relevant 
market by identifying potential suppliers based on market prices, input 
costs, and transmission availability, and then calculates each 
supplier's economic capacity and available economic capacity for each 
season/load condition.\54\ Rather than relying on a DPT analysis for 
analyzing a market-based rate seller's authority that is based on proxy 
prices and published price indices for sales by non-public utilities, 
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. 
The DPT also is used by the Commission to evaluate the effect on 
competition with respect to proposed mergers and acquisitions under FPA 
section 203. Therefore, obtaining more complete price and volume 
information would provide a better basis for considering whether to 
approve merger and acquisition proposals.
---------------------------------------------------------------------------

    \52\  See Transparency NOI, 130 FERC ] 61,039 at P 10-12.
    \53\ The Ninth Circuit Court of Appeals upheld the Commission's 
market-based rate regulatory scheme 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) (Lockyer).
    \54\  See Market-Based Rates for Wholesale Sales of Electric 
Energy, Capacity and Ancillary Services by Public Utilities, Order 
No. 697, 72 FR 39904 (July 20, 2007), FERC Stats. & Regs. ] 31,252, 
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, 
clarified, 124 FERC ] 61,055, 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), order on reh'g, Order No. 697-D, 75 FR 14342 
(March 25, 2010), FERC Stats. & Regs. ] 31,305 (2010). The 
Commission requires the DPT if a seller fails one of the indicative 
screens. The indicative screens analyze the number of megawatts of 
capacity an applicant owns or controls, rather than analyzing actual 
price data. However, ``sellers that do not pass the indicative 
screens are allowed to provide additional analysis for Commission 
consideration,'' including price data. Order No. 697, FERC Stats. & 
Regs ] 31,252 at P 62.
---------------------------------------------------------------------------

    28. Such information from non-public utilities would also provide 
the Commission with important actual sales information for performing 
ex post analysis of whether a jurisdictional seller with market-based 
rate authority has gained an excessive market share since the original 
authorization to transact at market-based rates or since the 
Commission's last review of such rates. Information about sales by non-
public utility market participants will allow the Commission to compare 
prices for power sold by jurisdictional sellers with those of non-
public utility sellers in the same market.
    29. Cities/M-S-R argues that the EQR mechanism should not replace 
other filings made by non-public utilities, such as an annual filing 
with the EIA, because non-public utilities have no statutory obligation 
to file sales agreements with the Commission and their rates are not 
subject to the Commission's reasonableness determinations. Although 
non-public utilities are not subject to the same filing requirements 
and rate determinations under FPA sections 205 and 206 as public 
utilities are, we propose that reporting in the EQR is the proper 
mechanism for non-public utilities to make information about their 
wholesale sales and transmission available to the public. As we note 
below, existing sources of information about non-public utility 
wholesale sales are insufficient to facilitate price transparency. The 
EQR is an established public reporting process that already provides 
substantial transparency into public utility sales. Furthermore, by 
requiring non-public utilities to file information in the EQR in the 
format used by public utilities, we can help ensure the consistency and 
comparability of the information. Consistency and comparability between 
filers is important because wholesale markets do not distinguish 
between sellers that are subject to the Commission's FPA section 205 
jurisdiction or the Commission's regulations and sellers that are 
typically exempt from such Commission's jurisdiction. Expanding the 
applicability of the Commission's EQR filing requirements allows the 
Commission and the public to equally evaluate all transactions in the 
market.
    30. With respect to Cities/M-S-R's arguments that they do not file 
sales agreements or need reasonableness determinations from the 
Commission on their rates, so they should not be required to file EQRs, 
we note that our jurisdiction under FPA section 220's transparency 
provisions is limited to the dissemination of information that will aid 
in market transparency for the public and the Commission. Section 220 
gives the Commission no jurisdiction related to, nor do our proposed 
regulations govern, the rates, terms, and conditions of service of 
market

[[Page 24194]]

participants that are excluded from the Commission's FPA section 205 
jurisdiction. The Commission is requiring only the posting of 
information important to ensuring market transparency and is not 
engaging in traditional regulation of rates, terms and conditions of 
service for non-public utilities.
    31. In response to Alaska Power, we propose to exempt utilities 
located entirely in Alaska from the EQR filing requirements because 
they are electrically isolated from the contiguous United States. In 
addition, we propose to apply this exemption to utilities located 
entirely in Hawaii.
3. Proposed Filing Requirements for Non-Public Utilities
a. Existing Sources of Information
i. Comments
    32. California DWR, NRECA, New York Public Power, City of 
Fayetteville, and SWP argue that section 220 of the FPA requires the 
Commission to determine that existing price publications are 
insufficient before establishing any new reporting requirements. 
Commenters also urge the Commission to consider whether new reporting 
requirements would be duplicative of existing sources, such as EIA 
reports, ISO/RTO data, and private index publishers.\55\ Public Systems 
claim that the Commission may not impose EQR filing requirements on 
market participants in New England because RTOs in New England already 
provide the public with extensive data regarding price and the 
availability of wholesale electric energy. SWP also suggests that the 
Commission could combine data from multiple sources, such as the 
California Independent System Operator (CAISO), existing EQRs, and 
pricing publications, to conduct ex ante or ex post market analyses.
---------------------------------------------------------------------------

    \55\ See, e.g., East Texas Electric Cooperatives at 2-3; New 
York Public Power at 3-4; NRECA at 6-8; Cities/M-S-R at 10-11; DEMEC 
at 3-4; Public Systems at 11-15; TANC at 10-11, 14-15; SWP at 8.
---------------------------------------------------------------------------

    33. According to APPA, before expanding EQR requirements to non-
public utilities, the Commission should look closely at the amount and 
type of wholesale sales these utilities actually make and consider 
other sources of available information on such sales, such as EIA 
publications and forms, to determine whether the additional information 
supplied through their EQR filings would help in achieving the 
Transparency NOI's stated goals. NRECA and Cities/M-S-R state that 
cooperatives and other electric utilities annually file form EIA-861, 
``Annual Electric Power Industry Report,'' with the EIA. They explain 
that this form includes information such as peak load, generation, 
electric purchases, sales and revenues. Moreover, NRECA states that EIA 
provides access to the daily volumes, high and low prices, and weighted 
average prices from hubs around the country. In addition, NRECA states 
that cooperatives that receive Rural Utilities Service (RUS) financing 
are required to file RUS Form 12, which includes such information as 
electric purchases, sales, and revenues and is publicly available 
through a database purchased from Ventyx.\56\ NRECA also states that 
the Energy Management Institute provides results of a daily survey of 
wholesale transactions that they conduct in all the major trading 
regions of the country. Furthermore, TANC and NRECA note that forward 
market prices are available through the New York Mercantile Exchange 
and the IntercontinentalExchange. Finally, Sam Rayburn Municipal 
believes that any additional reporting requirement would be duplicative 
because its power supply structure is simple and reported in detail in 
its formal financing, accounting and engineering documents.\57\
---------------------------------------------------------------------------

    \56\ Ventyx is a commercial provider that offers Velocity Suite, 
an application that includes data from generation and transmission 
cooperatives, distribution cooperatives, municipal utilities, and 
other market participants exempt from the Commission's FPA section 
205 jurisdiction.
    \57\ Sam Rayburn Municipal at 2.
---------------------------------------------------------------------------

ii. Discussion
    34. In carrying out Congress' directive to facilitate price 
transparency in wholesale sales and transmission markets, FPA section 
220 requires that the Commission consider the degree of price 
transparency provided by existing price publishers and trade processing 
services, and rely on such publishers and services to the maximum 
extent possible.\58\ As pointed out by commenters, there are already a 
number of sources of publicly available information about wholesale 
markets, including EIA and RUS forms, RTOs/ISOs, electric index 
publishers, and commercial data providers that provide varying degrees 
of price transparency. However, the Commission believes the degree of 
price transparency provided by existing sources is insufficient for 
facilitating price transparency.
---------------------------------------------------------------------------

    \58\ See 16 U.S.C. 824t(a)(4).
---------------------------------------------------------------------------

    35. The two most significant publicly available forms that capture 
information about non-public utility power sales are the EIA Form 861 
and the RUS Form 12. EIA Form 861 reports total volume (MWh) and 
revenue associated with a filer's wholesale power sales for an entire 
year.\59\ However, Form EIA Form 861 does not detail individual 
wholesale transactions, including the counterparty, location, price, 
and delivery timeframe as well as other transaction details contained 
in EQR. Rather, EIA Form 861 filers report their aggregated annual 
volume of sales for resale and corresponding revenues. RUS Form 12 
provides accounting details for power transaction by entities that fall 
under 7 U.S.C. 901 authority.\60\ RUS Form 12 provides considerably 
more detail than EIA Form 861 through the inclusion of the energy 
purchaser and other contract details for individual energy sales.\61\ 
However, RUS Form 12 provides only limited price transparency because 
the form does not contain information on delivery location and time. 
Delivery location and time are critical for gaining insight into price 
formation.\62\ Without transaction-specific delivery location and time 
information, Form EIA 861 and RUS Form 12 do not provide sufficient 
price transparency into wholesale electricity markets. Therefore, 
expanding EQR filing requirements to non-public utilities would provide 
price transparency that is not available through EIA Form 861 or RUS 
Form 12.
---------------------------------------------------------------------------

    \59\ On line 12 of Schedule 2, Part B, EIA Form 861 collects 
information on electricity ``Sales for Resale.'' http://www.eia.doe.gov/cneaf/electricity/forms/eia861.pdf.
    \60\ RUS Form 12b SE itemizes sales of electricity while RUS 
Form 12b PP itemizes purchases of electricity. http://www.usda.gov/rus/dcs/electric-forms/form12-2006.pdf, http://www.usda.gov/rus/dcs/downloads/form12/1717b-3.pdf.
    \61\ RUS Form 12b SE data field ``Statistical Classification 
(b)'' provides detail on whether the sale is for requirements 
service, long-term firm service or intermediate-term firm service, 
among other classifications. http://www.usda.gov/rus/dcs/downloads/form12/1717b-3.pdf.
    \62\ For example, one would expect power sold in a load-
constrained area during on-peak hours to be priced very differently 
from power sold in a generation-rich area during off-peak hours.
---------------------------------------------------------------------------

    36. RTOs/ISOs post extensive information about RTO/ISO wholesale 
market prices and market participant bid/offer data that provide 
valuable transparency for spot wholesale power markets run by RTOs/
ISOs. These postings contain detailed location, market and product 
information. However, these postings are limited to the wholesale 
electricity markets that are administered by RTOs and ISOs. In 
addition, publicly posted RTO/ISO data does not provide price 
transparency into the bilateral transactions entered into by market 
participants within the RTO/ISO balancing authority area that can 
impact RTO/ISO market price formation. These bilateral transactions are 
frequently

[[Page 24195]]

scheduled into the RTO/ISO market.\63\ The terms of bilateral 
transactions are often not reported to RTO/ISO markets and not included 
in publicly posted price and bid/offer data. While some bilateral 
transactions are already reported in the EQR, expanding the EQR filing 
requirements to include non-public utilities would give the Commission 
and the public a better view into bilateral transactions. This data 
would also enhance the RTO/ISO market monitoring units' ability to 
monitor RTO/ISO markets. Thus, expanding EQR filing requirements to 
non-public utilities would provide valuable price transparency into 
bilateral wholesale electricity markets that is not currently captured 
in publicly posted data from RTOs/ISOs.
---------------------------------------------------------------------------

    \63\ For example, NYISO estimates that approximately 50 percent 
of the energy scheduled in their markets was transacted bilaterally. 
See http://www.nyiso.com/public/about_nyiso/understanding_the_markets/energy_market/index.jsp.
---------------------------------------------------------------------------

    37. Existing daily index publications provide a degree of price 
transparency into spot wholesale electricity markets by capturing 
certain transactions. However, this price transparency is limited 
because these index publications do not capture longer-term 
transactions. Expanding EQR filing requirements to non-public utilities 
would provide price transparency for longer-term transactions not 
included in daily index publications.
    38. Organized exchanges, such as the Intercontinental Exchange, 
also provide valuable price information, but that information is 
limited only to prices for particular power products at standardized 
locations. Finally, commercial data providers, like Ventyx, provide a 
valuable service by collecting and packaging existing publicly 
available data. However, their products are limited by the availability 
of existing information, and therefore do not, in themselves, increase 
price transparency.
    39. In addition, information about non-public utility transmission 
service and reassigned transmission capacity sales may be available in 
the Open Access Same-Time Information System (OASIS). However, 
information on OASIS is not readily accessible to the public. Thus, 
requiring information about non-public utility transmission service and 
reassigned transmission capacity sales to be made publicly available 
through the EQR will facilitate price transparency in the transmission 
markets and aid the public and the Commission in detecting and 
addressing possible market power and manipulation in these markets.
b. Scope of Proposed EQR Filing Requirements for Non-Public Utilities
i. Comments
    40. BPA and Cities/M-S-R question whether the Commission needs all 
of the information included in the EQR and whether quarterly filings 
are necessary. In particular, BPA believes that the critical 
information that the Commission needs to measure the size of the 
relevant market is contained in the transaction section, Field Numbers 
46-67, and that the information in the contract section would not be 
necessary or helpful to the Commission. In addition, APPA and Salt 
River note that the Commission may need to customize the EQR filing 
forms to reflect the types of information applicable to public power 
entities.\64\ However, EEI states that if particular reporting 
requirements do not apply to a given filer, it can simply indicate 
``not applicable.''
---------------------------------------------------------------------------

    \64\ Salt River at 4-5.
---------------------------------------------------------------------------

    41. In addition, BPA asserts that the burden would be greatly 
reduced if the Commission were to limit the filing requirements for BPA 
to wholesale power sales at market-based rates. Thus, BPA supports 
excluding the cost-based sales to consumer-owned utilities, direct 
services industries, and inter-business line transmission services 
transactions.
    42. APPA asserts that sales by joint action agencies, state 
agencies, and power or water districts to their own members should not 
be reported.\65\ APPA argues that if the Commission expands EQR filing 
requirements to public power utilities, these agencies and districts 
should only be required to file EQR information on their excess power 
sales (i.e., sales to entities other than their member utilities or 
long-term distribution customers). TAPS and Public Power argue that 
joint-action agencies should not be required to report transactional 
information on long-term, wholesale sales of power to their member 
utilities. In addition, TAPS argues that generation and transmission 
(G&T) cooperatives' sales to their members should not be included. TAPS 
explains that although technically at wholesale, such sales are 
analogous to a vertically integrated utility's internal supply of its 
retail sales unit and subsequent retail sale, neither of which is 
reported through public utilities' EQRs.\66\
---------------------------------------------------------------------------

    \65\ APPA at 5.
    \66\ TAPS at 2, 12.
---------------------------------------------------------------------------

    43. LPPC and Salt River argue that the Commission should avoid 
requirements for reporting on long-term power supply arrangements that 
are solely between non-jurisdictional entities. For instance, LPPC 
argues that the power sold under long-term arrangements between non-
jurisdictional entities is not a factor to market participants when 
considering competitive purchases or sales nor is it relevant to the 
Commission's market manipulation oversight. Thus, such power 
arrangements do not factor into the market over which the Commission 
has oversight.\67\
---------------------------------------------------------------------------

    \67\ LPPC at 3.
---------------------------------------------------------------------------

    44. By contrast, PG&E, Wisconsin Electric, and EEI believe that 
market participants that are excluded from the Commission's section 205 
jurisdiction should file the same data elements that jurisdictional 
entities are required to file under the EQR Data Dictionary.
ii. Commission Proposal
    45. The Commission proposes to apply the same EQR requirements to 
non-public utilities that it currently requires from public utilities, 
with some adjustments, as discussed below. In particular, the 
Commission proposes that non-public utilities be required to report the 
same information about wholesale sales, transmission service, and 
transmission capacity reassignments that are currently reported by 
public utilities. 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 market participants 
and the public 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 that 
jurisdictional prices are ``just and reasonable.''
    46. In their comments, several market participants suggest that 
non-public utilities should not be required to file certain sales in 
the EQR, such as certain cost-based sales. BPA, for instance, suggested 
that cost-based sales to consumer-owned utilities, inter-business line 
transmission services transactions and sales to direct services 
industries, which are developed based on cost-based rates, should not 
be filed.\68\ Other commenters suggest that joint action agencies 
should not be required to report transactional information on the long-
term, wholesale sales of power to their member utilities.
---------------------------------------------------------------------------

    \68\ Cities/M-S-R at 9.
---------------------------------------------------------------------------

    47. The Commission proposes that all wholesale sales, including 
cost-based and market-based sales, be included in EQR filings from non-
public utilities with more than a de minimis market

[[Page 24196]]

presence. Although several commenters argue that certain sales, such as 
sales by joint action agencies, state agencies, and power or water 
districts to their own members, should not be reported, we conclude 
that excluding these wholesale sales in the EQR adversely impacts price 
transparency in wholesale electricity markets. Specifically, these 
sales can impact market prices regardless of whether or not they are 
made by entities that fall under the Commission's FPA section 205 
jurisdiction. For instance, if the agencies and districts did not 
supply their members, then the members would have to purchase supply 
from other sources in the market. Also, depending on these agency and 
district rules, the members may be able to sell excess power into the 
market. In either case, these sales would have an effect on the 
formation of prevailing market prices. Sales transactions by non-public 
utilities, whether cost-based or market-based, can influence wholesale 
electricity markets. Excluding certain segments of wholesale sales 
would result in an incomplete picture of wholesale price formation and 
would hamper the ability of the public and Commission to detect and 
address the potential exercise of market power and manipulation.
    48. Furthermore, we agree with TAPS that a vertically integrated 
utility that internally supplies its retail sales unit would not need 
to report that supply in the EQR because there is no wholesale sale in 
this situation. However, in the case of a G&T cooperative selling to 
its member cooperatives to meet the members' load obligations, this 
would constitute a wholesale sale that must be reported in the EQR. 
Such reporting is consistent with how jurisdictional cooperatives 
report their sales in the EQR. Any subsequent sale by a member 
cooperative to its retail customers would be a retail sale that is not 
reported in the EQR.
    49. We believe that certain data fields in the EQR may not be 
applicable to filings made by non-public utilities. For example, 
contract data Field Number 19 (FERC Tariff Reference) and transaction 
data Field Number 50 (FERC Tariff Reference) require filers to insert a 
``FERC Tariff Reference.'' Non-public utilities may not possess an 
appropriate FERC Tariff Reference (Fields 19 and 50) for certain 
wholesale contracts and transactions. In cases where a FERC Tariff 
Reference is not applicable, the Commission proposes to require that a 
filer state that the appropriate FERC Tariff Reference is ``Not 
Required,'' or ``n/r,'' in their EQR filing. However, if the sale 
relates to a previously filed reciprocal open access transmission 
tariff (OATT), the Commission proposes that the appropriate reference 
to the reciprocal OATT be included in the EQR. In addition, non-public 
utilities can mark as ``Not Required,'' or ``n/r,'' for the ``Product 
Type Information'' captured in Field Number 30, which relates to 
whether the transaction is ``cost-based,'' ``capacity reassignment,'' 
``market-based,'' or ``other,'' because the values for Field Number 30 
are defined based on types of FERC-approved tariffs.
    50. In its comments, BPA noted that the information necessary for 
the Commission to measure the size of a relevant market for merger 
analysis can be found in the transaction section (Field Numbers 46 
through 67) of the EQR, but that the contract section (Field Numbers 14 
through 45) does not appear to be necessary or helpful for merger 
analysis. The Commission agrees with BPA's assessment that the 
transaction section would be the relevant data fields in the EQR to use 
in determining the size of a wholesale energy market. However, the 
EQR's function is not limited to merger analysis, as discussed above.
    51. Furthermore, limiting EQR data to only transactions data would 
significantly detract from the Commission's efforts to facilitate price 
transparency under FPA section 220. The contract section of the EQR 
provides critical price transparency information in several ways. 
First, the contract section provides information and valuable context 
on when rates were established and the terms of the rates. Without 
contextual information, such as when and how a rate was agreed upon, 
the sales price that is reported in the transaction section (Field 
Number 64) might appear anomalous compared to other prices reported in 
the transaction section. Second, there are a number of products and 
agreements that are reported solely on the contract section of the EQR, 
such as emergency energy, interconnection agreements, membership 
agreements, and must run agreements.\69\ These products and agreements 
can impact a market participant's ability to make sales and access 
transmission, which are aspects of price formation. Therefore, 
excluding them would limit the price transparency impact associated 
with expanding the EQR to non-public utilities.
---------------------------------------------------------------------------

    \69\ For a detailed list, please refer to Appendix B in the 
Electric Quarterly Report Data Dictionary, Version 1.1, available at 
http://www.ferc.gov/docs-filing/eqr/soft-tools/eqrdatadictionary.pdf.
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c. Burden
i. Comments
    52. EEI believes that the burden on non-public utilities would be 
no greater than the burden on jurisdictional entities, once systems are 
in place to collect and compile the information. However, several 
commenters state that complying with any additional reporting 
requirements would be a significant burden for municipals and 
cooperatives. Public Power Council states that the EQR requirements are 
burdensome and the value of the information that the Commission would 
collect from most Northwest public power entities does not justify the 
cost that would be expended by non-public utilities to produce the 
information. Further, Utah Associated Municipal states that filing EQRs 
to report those sales made every hour of every day to nearly every 
member utility would give the Commission no useful information relevant 
to its purposes.
    53. Cities/M-S-R argue that it is unnecessarily burdensome for the 
Commission to collect transaction data for market transparency purposes 
on a quarterly basis and state that the Commission has created annual, 
not quarterly, reporting requirements under the natural gas 
transparency provisions. Cities/M-S-R also assert that the data 
required on Form 552 for natural gas transactions is less involved than 
EQR data fields and creates a more limited burden on responding 
parties. Further, Cities/M-S-R state that the scope of the EQR 
information is broader than necessary and the frequency is too great 
for the limited purpose of obtaining information to improve the 
Commission's delivered price test analysis.
    54. According to APPA, a number of its members estimated that they 
would require from two weeks to nine months for the initial setup, and 
one to three days to compile, verify, and file the EQR each quarter. 
The City of Fayetteville states that it has not done a detailed cost/
time analysis, but believes that it would fall in the upper quartile of 
the time estimates reported in the APPA comments. Allegheny estimates 
that significant computer system changes and additional ongoing 
personnel resources may be required, the costs of which would need to 
be passed along to the cooperative's customers. Salt River estimates 
that it would need at least six months to develop an internal EQR 
filing program. In addition, Salt River encourages the Commission to 
provide guidance through workshops or training sessions and to provide 
opportunities for interaction with staff while

[[Page 24197]]

preparing initial filings, and to allow sufficient time to ensure 
completeness and accuracy of the filings. Based on its own experience, 
DC Energy states that, while the burden will vary depending on the 
scope and amount of activities, there would be an upfront time 
investment of 2-4 person-weeks to design and implement an EQR tracking/
reporting system, and an ongoing reporting burden of 2-3 person-days 
per quarter. It states that this estimate is based on a ``self-build 
model'' and believes there also are off-the-shelf products that will 
automatically generate these reports for an entity, resulting in less 
of a burden.
    55. BPA states that the burden would be greatly reduced if the 
Commission were to limit the filing requirements for BPA to wholesale 
power sales at market-based rates (thereby excluding inter-business 
line transmission services transactions, and the statutorily-mandated 
cost-based sales to consumer-owned utilities and direct services 
industries\70\) and eliminate the fields associated with contract data. 
BPA also argues that it should not be required to report transmission 
services sales made by BPA's functionally separated Power Services 
section to its Transmission Services section because these inter-
business line transactions are not discretionary, open market 
transactions that would aid the Commission in evaluating market power 
issues.
---------------------------------------------------------------------------

    \70\ BPA notes that direct services industries are generally a 
defined set of aluminum companies and large industries in the 
Pacific Northwest. BPA at 1.
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ii. Discussion
    56. We acknowledge that enhancing price transparency by extending 
the EQR filing requirements to non-public utility market participants 
will impose a new burden on those market participants. However, we 
believe that, on balance, the benefit of increased price transparency 
stemming from the filing of such information will outweigh the burden 
on these market participants above the de minimis threshold. We assume 
that most non-public utilities already capture transaction-specific 
information for accounting and record-keeping purposes. Therefore, we 
believe the burden imposed will relate primarily to the required format 
for submitting that information. In addition, we believe that the 
amount of burden created by requiring non-public utilities to file EQRs 
will depend on how many transactions the non-public utility makes. 
Accordingly, entities with a relatively small number of wholesale sales 
will face less of a burden.
    57. Cities/M-S-R contend that the data collected under the natural 
gas market transparency provisions is less burdensome because it is 
collected annually, not quarterly, and contains less detail than the 
EQR data. We note that the Commission has promulgated two rules under 
the natural gas market transparency provisions in section 23 of the 
NGA,\71\ Order Nos. 704 and 720. Order No. 704 requires certain 
purchasers and sellers of natural gas to file an annual report about 
specified physical natural gas transactions. Order No. 720 requires 
major non-interstate pipelines to file certain receipt and delivery 
information on a daily basis. Therefore, Order No. 720 requires data to 
be provided more frequently than the EQR. In addition, Order No. 720 
requires non-interstate pipelines to post detailed information, 
including the transportation service provider's name, posting data, 
posting time, nomination cycle, location name, additional locational 
information if needed to distinguish between points, location purpose 
description, posted capacity, scheduled volume, available capacity, and 
measurement unit for each receipt or delivery point that meets certain 
criteria.\72\ Although the level of detail in the EQR may be greater 
than that required under Order Nos. 704 and 720, this difference 
reflects variations between transactions made in the natural gas and 
electricity markets.
---------------------------------------------------------------------------

    \71\ 15 U.S.C. 717t-2.
    \72\ See 18 CFR 284.14.
---------------------------------------------------------------------------

    58. We disagree with Cities/M-S-R's suggestion that the Commission 
seeks to obtain EQR information from non-public utilities solely to 
improve the Commission's DPT. As discussed above, the Commission 
proposes to require non-public utilities to file EQRs to fulfill 
Congress's directive in FPA section 220 to facilitate price 
transparency in markets for the sale and transmission of electric 
energy in interstate commerce. The information in these EQRs will 
provide valuable information that serves a number of purposes. This 
information will provide a more complete picture of price formation in 
wholesale electricity markets for the Commission and the public. In 
addition, obtaining sales price and volume information in EQRs from 
non-public utilities will increase the Commission's ability to monitor 
utilities' power sales for indications of market power and 
manipulation. Also, as explained in the Transparency NOI,\73\ and 
discussed above, collecting EQR information from non-public utilities 
would improve the quality of the DPT results and assist the Commission 
in determinations concerning a seller's ability to exercise market 
power and provide a better basis for considering whether to approve 
merger/acquisition proposals under FPA section 203.
---------------------------------------------------------------------------

    \73\  See Transparency NOI, FERC Stats. & Regs. ] 35,565 at P 9-
12.
---------------------------------------------------------------------------

    59. We believe that the EQR compliance burden on non-public 
utilities above the de minimis threshold would be greatest during the 
initial set-up phase, when data is mapped into the new required format. 
However, to the extent a filer uses the same format for each EQR, once 
the filer's system is mapped to the interim and final formats, the 
burden will be significantly reduced. The Commission invites comment 
from non-public utilities and public utilities on how their existing 
data capture processes have been or can be mapped to facilitate EQR 
filing in its current and proposed formats.
    60. We recognize that the initial implementation and ongoing 
reporting associated with the proposed EQR filing requirements will 
result in additional costs and burden on non-public utilities. However, 
the Commission has tried to balance the need for data with efforts to 
minimize the burden on filers. To help alleviate the burden of filing 
EQRs, the Commission has designed a system that allows EQRs to be filed 
using the Internet so that all filers submit EQRs to the Commission 
electronically. In addition, the Commission is only requiring those 
non-public utilities that fall above the de minimis threshold test to 
file EQRs. We also agree with Salt River that workshops or training 
sessions to provide guidance may be helpful and we will make every 
effort to provide technical assistance prior to the implementation of 
the EQR filing requirements for non-public utilities.
d. De Minimis Threshold
i. Comments
    61. Commenters propose a wide range of de minimis market presence 
thresholds for non-public utility exemptions from the EQR filing 
requirements, from 8 million MWh to 100 MWh of annual sales. In favor 
of the 8 million MWh threshold, two commenters \74\ point to FPA 
section 206(e), which gives the Commission refund authority over 
certain sales made by non-jurisdictional entities except for an entity 
that sells less than 8 million MWh of electricity per year.\75\ Cities/
M-S-R also argue that a threshold of at least 8 million MWh per year is 
appropriate because of the growth in the electricity market, as 
evidenced by the

[[Page 24198]]

reported wholesale sales, which have nearly tripled between 1997 and 
2008.\76\
---------------------------------------------------------------------------

    \74\ Cities/M-S-R at 14; Imperial at 6.
    \75\ 16 U.S.C. 206(e).
    \76\ Cities/M-S-R at 14.
---------------------------------------------------------------------------

    62. Other commenters recommend a threshold level of 4 million MWh, 
based on either annual wholesale sales \77\ or annual total sales.\78\ 
In support of a 4 million MWh threshold, many commenters refer to 
section 201(f) of the FPA, which specifically excludes from the 
Commission's jurisdiction electric cooperatives that sell less than 4 
million MWh of electricity per year.\79\ They also cite to the 
definition of a small utility under the Regulatory Flexibility Act and 
Small Business Act, which define a utility as small if its total annual 
output (i.e., wholesale and/or retail) does not exceed 4 million 
MWh.\80\ APPA states that a threshold of 4 million MWh annual wholesale 
sales would capture approximately 70 percent of public power utilities' 
wholesale sales, and 82 percent of wholesale sales made by cooperative, 
Federal, and public power utilities combined. APPA argues that using 
annual wholesale sales will eliminate the potential for double-counting 
some public power wholesale sales in RTO regions, such as joint action 
agency sales to their members. APPA also argues that the use of EIA 
data to determine which utilities are above the de minimis threshold 
for reporting purposes will eliminate the potential for double-counting 
some public power wholesale sales in RTO regions. For example, notes 
APPA, joint action agencies situated in RTO regions are often required 
to sell their wholesale power into their RTO's market at the point of 
generation, buy it back at their members' load nodes, and then sell the 
same energy to their members. Using EIA data would eliminate potential 
double-counting of these joint action agency sales to members as sales 
to an RTO as well. Additionally, the City of Fayetteville argues that, 
in promoting wholesale market transparency, retail sales to ultimate 
consumers should not be counted toward the cutoff, because such sales 
do not bear on whether a section 201(f) entity's wholesale market 
presence is de minimis.
---------------------------------------------------------------------------

    \77\ See, e.g., APPA at 9; NRECA at 26; New York Public Power at 
6; Delaware Municipal at 5; City of Fayetteville at 7; Southwest 
Transmission at 3; Alaska Power at 2.
    \78\ See, e.g., City of Dover at 2; Northwest Utility at 2; TANC 
at 20.
    \79\ In particular, FPA section 201(f) provides, in part, that 
``[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).
    \80\ The Regulatory Flexibility Act (RFA) definition of a 
``small entity'' refers to a definition provided in the Small 
Business Act, which defines a ``small business concern'' as a 
business that is independently owned and operated and that is not 
dominant in its field of operation. See 15 U.S.C. 632. According to 
the Small Business Act, a small electric utility is one that has a 
total electric output of less than 4 million MWh in the preceding 
year. 15 U.S.C. 631.
---------------------------------------------------------------------------

    63. EMCOS believes that 4 million MWh based on total annual sales 
is appropriate, but that both inter-affiliate sales by consumer-owned 
utilities and must-offer sales into Day 2 markets should be excluded to 
avoid over-reporting. NRECA and Allegheny argue that the Commission 
also should not consider sales by G&T cooperatives to their members as 
wholesale sales for purposes of the de minimis 4 million MWh sales 
threshold. NRECA states that when a G&T cooperative makes sales to its 
member cooperatives under long-term wholesale power contracts, it is 
essentially acting as the functional equivalent of a generation 
division of a vertically integrated public utility. NRECA also argues 
that if the Commission does not exclude sales by G&T cooperatives to 
their member cooperatives, then it should establish a rebuttable 
presumption that non-public utility cooperatives that sell less than 4 
million MWh of power to third parties other than their member 
cooperatives are exempt from the filing requirement as having a de 
minimis impact on wholesale markets if such sales constitute less than 
2 percent of wholesale sales in the region.
    64. LPPC asks the Commission to exempt non-jurisdictional entities 
from having to report long-term sales agreements (of greater than one 
year) between non-jurisdictional entities. LPPC also asks the 
Commission to provide a mechanism for requests for waiver sought by 
parties on the ground that specific transactions or categories of 
transactions are not of a nature that their reporting is relevant to 
the Commission's oversight of the wholesale marketplace. LPPC states 
that examples of typical long-term agreements between non-
jurisdictional entities are the thirty-year sales agreements between 
municipal utilities and MEAG Power, which was formed by the Georgia 
Assembly for the purpose of generating power to be sold under long-term 
agreements to municipal utility participants. LPPC states that the 
power sold under these agreements does not factor into the market over 
which the Commission has oversight.
    65. Some commenters further note that the Commission has used a 4 
million MWh of total sales threshold in several contexts. For instance, 
TANC states that the Commission has used this threshold in granting 
waivers of standards of conduct for transmission providers under Order 
Nos. 888,\81\ 889,\82\ and 890,\83\ and with respect to the requirement 
that RTOs/ISOs accept demand response bids by aggregators of retail 
customers.\84\ Furthermore, some commenters, such as LPPC, argue that a 
utility that sells 4 million MWh or less of energy per year is too 
small to affect the electricity markets, so excluding it from the EQR 
requirements would still provide the Commission with information on the 
large majority of wholesale transactions by non-jurisdictional 
entities.
---------------------------------------------------------------------------

    \81\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 
31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12274 (Mar. 
14, 1997), FERC Stats. & Regs. ] 31,048, order on reh'g, Order No. 
888-B, 62 FR 64688 (Dec. 9, 1997), 81 FERC ] 61,248 (1997), order on 
reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant 
part sub nom. Transmission Access Policy Study Group v. FERC, 225 
F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 
1 (2002).
    \82\  Open Access Same-Time Information System and Standards of 
Conduct, Order No. 889, 61 FR 21737 (May 10, 1996), FERC Stats. & 
Regs. ] 31,035 (1996), order on reh'g, Order No. 889-A, 62 FR 12484 
(March 14, 1997), FERC Stats & Regs. ] 31,049, reh'g denied, Order 
No. 889-B, 81 FERC ] 61,253 (1997).
    \83\ Order No. 890, FERC Stats. & Regs. ] 31,241.
    \84\ TANC at 19-20 (citing Wolverine Power Supply Coop., Inc., 
127 FERC ] 61,159, at P 15 (2009); Order No. 719, FERC Stats. & 
Regs. ] 31,218).
---------------------------------------------------------------------------

    66. By contrast, EEI and DC Energy recommend adopting relatively 
low thresholds. EEI states that the Commission could apply one of the 
following thresholds: (1) 100 MWh of sales for resale per year used by 
the Commission in the context of FERC Forms 1 and 1-F between major and 
non-major utilities; or (2) 114,000 MWh of sales per year, based on 
what a qualifying facility (QF) exempted from FPA section 205 (20 MW or 
smaller) could produce in a year.\85\
---------------------------------------------------------------------------

    \85\ EEI at 4.
---------------------------------------------------------------------------

    67. Sam Rayburn Municipal believes that a threshold exemption 
should exist where there is no retail competition or the relative size 
or amount of power transactions is insignificant by size or substance.
ii. Discussion
    68. FPA section 220(c)(2)(d) specifies that the Commission shall 
not require entities with a de minimis market presence to comply with 
the reporting requirements of FPA section 220. At present, the 
Commission collects data regarding cost-based sales, market-based rate 
sales, transmission service, and transmission capacity reassignments 
from entities subject to section 205 of the FPA. Data regarding sales,

[[Page 24199]]

transmission service, and transmission capacity reassignments provided 
by non-public utilities is not readily available. Without this data, 
the public is unable to observe a significant number of trades and is 
unable to develop a more complete view of wholesale power and 
transmission markets. As discussed above, a more complete view of price 
formation in the markets will provide the public with greater price 
transparency to evaluate the concentration of market participants in a 
market and the market participant's ability to unduly influence the 
market, and will assist the public and the Commission in detecting and 
addressing the potential exercise of market power and manipulation.
    69. The Commission proposes that a non-public utility would be 
exempt under the de minimis market presence threshold from filing EQRs 
if it makes 4 million 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 \86\ 
that makes 1 million MWh or more of annual wholesale sales (based on an 
average of wholesale sales it made in the preceding three years). As 
requested by some commenters, the Commission proposes to calculate the 
de minimis market presence threshold on the amount of annual wholesale 
sales made by the non-public utility rather than total (i.e. wholesale 
and retail) sales. The transparency provisions in FPA section 220 focus 
on the Commission requiring information concerning the availability and 
prices of ``wholesale electric energy and transmission service.'' \87\ 
Therefore, the Commission proposes to use only the wholesale 
electricity sales made by non-public utilities for purposes of 
calculating the de minimis market presence threshold.
---------------------------------------------------------------------------

    \86\ As defined in the North American Electric Reliability 
Corporation's (NERC) Glossary of Terms Used in Reliability 
Standards, a Balancing Authority is the ``responsible entity that 
integrates resource plans ahead of time, maintains load-interchange-
generation balancing within a Balancing Authority Area, and supports 
Interconnection frequency in real time.'' See http://www.nerc.com/files/Glossary_of_Terms_2011Mar15.pdf.
    \87\ See 16 U.S.C. 824t(a)(2).
---------------------------------------------------------------------------

    70. To reduce the filing burden and promote clear compliance 
requirements, the Commission proposes that non-public utilities use the 
annual wholesale sales volumes they currently report to EIA to 
calculate whether they meet the de minimis threshold.\88\ The 
Commission proposes that the threshold be calculated using the ``Sales 
for Resale'' data published in EIA Form 861.\89\ ``Sales for Resale'' 
as reported in EIA Form 861 does not include retail sales, as addressed 
above.
---------------------------------------------------------------------------

    \88\ This proposal is consistent with APPA's suggestion to use 
EIA data when calculating the de minimis threshold. See APPA at 9-
10.
    \89\ ``Sales for Resale'' figures can be found on Line 12 in 
``Schedule 2, Part B. Energy Sources and Disposition.'' See http://www.eia.doe.gov/cneaf/electricity/forms/eia861/eia861instr.pdf.
---------------------------------------------------------------------------

    71. The Commission believes that establishing a 4 million MWh 
annual wholesale sales threshold for non-public utilities that are not 
Balancing Authorities will allow the Commission and the public to 
access information from market participants whose transactions could 
have an impact on wholesale market prices and thereby increase price 
transparency for the markets and aid in the Commission's oversight of 
wholesale electricity markets,\90\ while alleviating the reporting 
burden for smaller entities.
---------------------------------------------------------------------------

    \90\ It is important to note that electricity markets can be 
comprised of markets that are regional, local, and even nodal. For 
example, exerting market power does not necessarily involve a large 
volume of physical sales. In fact, small volumes of power sales can 
influence market pricing, particularly when transmission limitations 
and other dynamics exist.
---------------------------------------------------------------------------

    72. With respect to non-public utilities that are Balancing 
Authorities, the Commission believes requiring them to file EQRs if 
they make 1 million MWh or more of annual wholesale sales will provide 
a more complete picture of prices within the balancing authority area 
markets that are operated by non-public utilities and thereby assist 
market participants and the Commission, particularly with respect to 
conducting market-based rate analyses for jurisdictional market-based 
rate sellers. For traditional (non-RTO/ISO) markets, the Commission 
uses the balancing authority area as the default relevant geographic 
market for its market-based rate analysis.\91\ For example, Order No. 
697 noted that if a transmission-owning Federal power marketing agency 
is the home or first-tier market to a seller located outside of an RTO/
ISO, then that seller must treat that Federal power marketing agency's 
balancing authority area as a relevant geographic market and file a 
market power analysis on it just as it would any other relevant 
market.\92\ Obtaining sales information from non-public utility 
Balancing Authorities that operate that balancing authority area would 
greatly assist the Commission in determining whether to grant a seller 
market-based rate authority (ex ante analysis) and allow a more 
effective after-the-fact examination of market-based rate 
authorizations (ex post analysis). The Ninth Circuit Court of Appeals 
upheld the Commission's market-based rate program based on the dual 
requirement of an ex ante finding of the absence of market power and 
post-approval reporting requirements through the EQR. Specifically, the 
Ninth Circuit held that ``FERC's system 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.'' \93\
---------------------------------------------------------------------------

    \91\  See Order No. 697, FERC Stats. & Regs ] 31,252 at P 232.
    \92\ See id.
    \93\ Lockyer, 383 F.3d 1013.
---------------------------------------------------------------------------

    73. APPA expresses concern about double counting of wholesale sales 
by joint action agencies situated in RTO/ISO markets. APPA notes that 
joint action agencies in RTO/ISO regions are often required to sell 
their wholesale power into the RTO/ISO market at the point of 
generation, buy it back at their members' load nodes and then sell the 
same energy to their members. APPA suggests that using EIA data would 
eliminate double counting of these joint action agency-to-member 
transactions as sales to an RTO/ISO. As noted above, the Commission 
proposes that non-public utilities use EIA data to determine whether 
they meet the de minimis threshold. However, the Commission is 
concerned with capturing all wholesale power sales as they occur (no 
matter how many times the power changes hands). Therefore, in the 
example provided by APPA, the Commission agrees that EIA data should be 
used by the joint action agency to determine whether it meets the de 
minimis threshold for filing EQRs. However, if the joint action agency, 
or other non-public utility, determines that it falls above the de 
minimis threshold based on the EIA data, then the Commission would 
expect the joint action agency or other non-public utility to report 
all wholesale sales in a manner that is consistent with existing EQR 
reporting standards.
    74. Some commenters argue that the Commission should not consider 
sales such as inter-affiliate sales by consumer-owned utilities or 
sales by G&T cooperatives to their members for purposes of the de 
minimis threshold. For ease of reference, we shall refer to the 
transactions raised by NRECA, and others as ``inter-familial 
transactions''. We disagree with commenters' assertions that wholesale 
inter-familial transactions should not be considered sales for purposes 
of the de minimis annual wholesale sales threshold. Rather, the 
Commission believes that

[[Page 24200]]

any sale of wholesale electricity should count towards the threshold, 
regardless of the type of transaction from which the sale originated 
(e.g., G&T cooperative sales to its members captured under long-term 
wholesale power agreements). Moreover, reporting of wholesale inter-
familial transactions will assist the Commission and the public in 
monitoring price formation and understanding electricity prices, 
quantities, and market trends, particularly in bilateral markets.
    75. We further note that the Commission will not propose the 
rebuttable presumption suggested by NRECA that non-public utility 
cooperatives that sell less than 4 million MWh of power to third 
parties other than their member cooperatives are exempt from the EQR 
filing requirements as having a de minimis impact on wholesale markets 
if such sales constitute less than 2 percent of wholesale sales in the 
region. We also do not propose a mechanism for requesting waiver of the 
EQR reporting requirements on the basis that the nature of specific 
transactions or categories of transactions are not relevant to the 
Commission's oversight of wholesale markets. Under the proposed de 
minimis threshold, a non-public utility that makes 4 million MWh or 
less of annual wholesale sales would be exempt from filing EQRs unless 
the non-public utility is a Balancing Authority making 1 million MWh or 
more of annual wholesale sales. Because entities with a de minimis 
market presence are thereby exempted from the EQR filing requirement, 
the Commission does not believe it is necessary to establish a 
rebuttable presumption or waiver procedures. In addition, as explained 
above, we believe that it is necessary to capture a G&T cooperative's 
sales to its members for transparency purposes, and therefore will not 
propose the rebuttable presumption approach as suggested by NRECA.
    76. Sam Rayburn Municipal believes that a threshold exemption 
should exist where there is no retail competition or the relative size 
or amount of power transactions is insignificant by size or substance 
under this effort. We agree with Sam Rayburn Municipal's comments about 
a threshold exemption, but we disagree with its comment on an exemption 
where retail competition does not exist. In states where retail 
competition is not present there are still wholesale transactions that 
are of interest to the Commission and public. These transactions are 
part of wholesale electricity price formation even in regions where 
retail competition does not exist. Additionally, it is the Commission's 
duty to ensure market transparency and obtain reporting from a 
sufficient number of market participants to accurately understand the 
physical electricity market as a whole.
    77. EMCOS believes that must-offer sales into a ``Day-2'' RTO/ISO 
market should be excluded because they involve output committed under 
contracts.\94\ In particular, EMCOS commented that must-offer sales 
into ``Day-2'' central security-constrained dispatch/central unit 
commitment markets should be excluded from the calculation of the de 
minimis threshold, because such sales reflect only the application of a 
tariff requirement for bidding both load and the output of resources 
already contractually committed to serving that load in order to 
facilitate bid-based pricing, and do not provide useful information 
about the exchange of commercial consideration leading to price 
formation. The Commission believes that resources committed under 
contract do impact price formation and should be included in the de 
minimis threshold calculation. Must-offer provisions often do not 
dictate the price at which a unit may offer its supply into the market. 
Even if a must-offer unit is a price taker through self-scheduling, the 
unit is impacting price formation through its supply into RTO/ISO 
markets.
---------------------------------------------------------------------------

    \94\ EMCOS at 12.
---------------------------------------------------------------------------

B. Refinements to the Existing EQR Requirements

1. Background
    78. In addition to seeking comments on whether the Commission 
should extend the EQR reporting requirements to non-public utilities, 
the Commission also sought comments regarding certain refinements to 
the EQR reporting requirements. Specifically, the Commission sought 
guidance on whether to: (1) Require the reporting of the trade date, 
type of rate, and resales of financial transmission rights in secondary 
markets; (2) use a standard unit for reporting energy and capacity 
transactions; and (3) omit the time zone from the contract section.
    79. As discussed above, the Commission has determined that it 
should consider whether substantial reforms to the EQR reporting 
requirements are needed. After considering comments received in 
response to the Transparency NOI, the Commission is proposing in this 
NOPR to make the following refinements to the EQR: (1) Reporting of the 
transaction date; (2) reporting of the type of rate by which the price 
was set (i.e., fixed price, formula, index, or RTO/ISO price); (3) 
standardizing the unit for reporting energy and capacity transactions 
(i.e., $/MWh, $/MW-month); and (4) omitting the time zone from the 
contract section. The Commission is also proposing not to require the 
reporting of resales of financial transmission rights in secondary 
markets.
    80. In addition, the Commission proposes other refinements that 
were not included in the Transparency NOI. In particular, the 
Commission proposes to require EQR filers to: (1) Report the time that 
the transaction took place; (2) identify the broker or exchange used 
for a sales transaction, if applicable; (3) indicate whether the 
transaction was reported to an index publisher; and (4) report certain 
e-Tag data. The Commission also proposes to eliminate the DUNS number 
requirement.
2. General Refinements
    81. In combination with the broader effort to improve the 
Commission's access to information about the availability and prices of 
wholesale sales of electricity, the Transparency NOI considered other 
refinements to the existing EQR filing requirements. As discussed 
above, these refinements included: (1) Reporting the trade date (i.e., 
the date on which a transaction price is set) and the type of rate 
(i.e., fixed price, a formula, an index, or an RTO/ISO price); (2) 
reporting resales of financial transmission rights in secondary 
markets; (3) standardizing the unit for reporting energy and capacity 
transactions (i.e., $/MWh and $/MW-month); and (4) omitting the time 
zone from the contract section of the EQR. The proposals described 
above are detailed in Appendix B.
a. Trade Date & Time and Type of Rate
i. Comments
    82. DC Energy agrees that the EQR reporting requirement should 
include the contract date, and states that master agreements or 
evergreen contracts do not preclude an entity from specifying when the 
agreement to transact was executed.\95\ California PUC also supports 
the addition of requirements to report the trading date information and 
to specify whether the reported rate is a fixed price, a formula, or an 
index. It states that prices without trading dates are less informative 
because prices change over time.\96\
---------------------------------------------------------------------------

    \95\ DC Energy at 10.
    \96\ California PUC at 3-4.
---------------------------------------------------------------------------

    83. EEI, EPSA, and Duke Energy argue that the burden of collecting 
the trade

[[Page 24201]]

date and type of rate from all filers likely will require system 
changes and thus outweighs the value of such information.\97\ In 
addition, EPSA suggests that there are several problems with adding the 
trade date, such as it being subject to multiple interpretations and 
creating major software problems in the Commission's EQR program.\98\
---------------------------------------------------------------------------

    \97\ EEI at 6-7; EPSA at 2-3; Duke Energy supports the comments 
filed by EEI at 2.
    \98\ EPSA at 4.
---------------------------------------------------------------------------

    84. EPSA's other major concern with this reporting requirement is 
timing. Any reporting requirement would have to be prospective only, as 
``trade date'' is not currently a reporting requirement. Thus, there 
may be major software problems created with the Commission's EQR 
program. EPSA states that, if implemented by the Commission without 
grandfathering preexisting transactions, there would be no way for 
reporting entities to differentiate new deals from old, and the old 
deals will not have a reported trade date. Thus, any analysis done with 
this newly reported data would have a field precluded from historical 
data. Any adjustments made to prior quarters' data presumably would 
need to include this information, which may be impossible to gather for 
preexisting transactions. EPSA is concerned that the Commission's EQR 
software would generate error messages for leaving the field blank. The 
Transparency NOI provides no discussion of these problems and EPSA 
states that the Commission should seriously consider these concerns 
before requiring that transaction dates be reported.
    85. In addition, EPSA states there is an overlap issue. If a deal 
is concluded in one quarter but goes to delivery in another quarter (or 
quarters), will it have to be reported in the quarter the transaction 
was concluded as well as the quarter(s) of delivery? What about any 
intervening quarters--will the entity have to report deals in some form 
of abeyance between conclusion and delivery?
    86. Also, EPSA states that some of its member companies have 
reported that they do not track how the price was set and therefore 
could not currently comply with a requirement to report the type of 
rate. Thus, if this proposal is adopted, market participants would need 
to make major system changes to be able to capture and report this 
data. If the Commission proceeds down this route, EPSA contends that 
the Commission should allow a significant period of time for 
implementation before this aspect of a rule change became mandatory so 
that reporting parties could hire the necessary contractors, and have 
time to reconfigure data capture and reporting systems to collect this 
new data.
    87. However, if the Commission decides to require filers to include 
the trade date and type of rate, then EEI and EPSA propose several 
revisions. EEI suggests that the Commission clarify that ``trade date'' 
includes only the date and not the time of day when a transaction price 
was set and only include it in the transactions section, not the 
contract section.\99\ Also, EEI proposes that ``the date the price was 
agreed to'' should refer to the date the trade was finally 
executed.\100\ According to EPSA, its members have reported that 
through custom and usage in the trading industry, the term ``Trade 
Date'' has developed the broadly understood meaning of ``the date upon 
which the parties agree upon the terms of, and enter, a transaction.'' 
EPSA argues that the Commission should give the term ``Trade Date'' the 
same meaning it generally has in the industry.\101\ In addition, EEI 
suggests that if the Commission decides to include the type of rate, 
then the options should be modified to ``fixed,'' ``formula without 
index,'' and ``formula with index.'' EEI also requests that the 
Commission clearly define these rate types and give examples to ensure 
that industry applies the terms consistently.\102\
---------------------------------------------------------------------------

    \99\ EEI at 6-7.
    \100\ Id. at 6.
    \101\ EPSA at 4.
    \102\ EEI at 7.
---------------------------------------------------------------------------

    88. FirstEnergy asserts that the EQR Contract Data already captures 
the trade date via the Contract Execution Date in Field 21, which 
provides for the date the contract was signed. According to 
FirstEnergy, typically the rate for the transaction will be agreed upon 
on this date. FirstEnergy also states that the Commencement Date is 
reported in the Contract Terms in Field 22, which provides for the date 
that the terms in the contract are effective. Further, FirstEnergy 
explains that Fields 43 and 44 provide the first and last dates for the 
sale of the product at the specified rate. In addition, FirstEnergy 
states that the Commission's proposed field to describe the type of 
rate for each transaction is already reported under field 37, Rate 
Description. According to FirstEnergy, this field currently requires 
that the filing company either cite the FERC accession number for the 
relevant FERC tariff or provide the entire rate algorithm.\103\ 
Similarly, EPSA argues that the ``type of rate'' information is already 
captured in the ``contract'' field and that creating a new field would 
be a significant burden.\104\
---------------------------------------------------------------------------

    \103\ FirstEnergy at 2-3.
    \104\ EPSA at 5.
---------------------------------------------------------------------------

ii. Discussion
    89. The current Commission EQR reporting requirements include, 
among other things, the Contract Execution Date (Field Number 21), the 
Contract Commencement Date (Field Number 22), Rate Description (Field 
Number 37), Begin Date (Field Number 43), and End Date (Field Number 
44).\105\ These contract fields were not intended to capture trade-
specific details related to each specific transaction, but rather to 
capture contractual terms and conditions under which two entities 
transact for all jurisdictional services.
---------------------------------------------------------------------------

    \105\ These fields are outlined in more detail in the Electronic 
Quarterly Report Data Dictionary, Version 1.1, available at http://www.ferc.gov/docs-filing/eqr/soft-tools/eqrdatadictionary.pdf.
---------------------------------------------------------------------------

    90. We agree with the points made by DC Energy and the California 
PUC. Master agreements and evergreen contracts do not preclude an 
entity from specifying when an agreement to transact was executed. 
Prices without trading dates are less informative because prices change 
over time.
    91. Presently, the trade date and type of rate by which the price 
was set are not provided or collected publicly. The trade date is 
essential to assessing the significance of prices in relation to market 
conditions in effect at that time.\106\ Many of the prices reported in 
the EQR are the result of confirmation made under master agreements. 
Because the prices are not set in the contracts themselves, the 
Commission is unable to determine from EQR data when the price was set. 
Additionally, the Commission is unable to conclude whether the price 
was based on a fixed price, a formula, an index, or an RTO/ISO price.
---------------------------------------------------------------------------

    \106\ Currently, the EQR collects only the start and end date of 
physical transactions. Trades entered into months before the 
transaction dates are reported in the same manner as trades entered 
into minutes before the transaction occurs, making it difficult to 
differentiate between trades made under different circumstances.
---------------------------------------------------------------------------

    92. Therefore, to improve market transparency, the Commission 
proposes to require market participants to report the date on which 
parties to a reported transaction agreed upon a price (trade date) and, 
additionally, require the type of rate by which the price was set 
(i.e., fixed price, formula, index, or RTO/ISO price) in its respective 
EQR filings. The date and type of rate are to accompany each specific 
sales transaction and be reported in the EQR transaction section only 
in the quarter the sale occurs.
    93. We propose to clarify the term ``trade date'' as ``the date 
upon which the

[[Page 24202]]

parties agree upon the price of a transaction.'' As discussed below, we 
also propose tracking the time of the transaction. Further, EEI 
suggests that the Commission clarify how to specify the type of rate 
and provide examples to ensure that industry applies the terms 
consistently. As a result, the options for the type of rate that the 
Commission is proposing will be ``fixed,'' ``formula,'' ``index,'' and 
``RTO/ISO price.'' A ``fixed'' rate will be defined as a fixed charge 
per unit of consumption. An example is an agreement for the sale of 30 
MWh during every on-peak hour during 2012 for an agreed upon rate in 
advance of delivery. A ``formula'' rate will be defined as a 
calculation of a rate based upon a formula that does not contain an 
index component. An example is a cost-of-service rate. An ``index'' 
rate will be defined as a calculation of a rate based upon an index or 
a formula that contains an index component. An example is an options 
agreement where power is sold at a published index price (or at a 
percentage of that published index price). An ``RTO/ISO price'' will be 
defined as a rate that is based on an RTO/ISO published price or a 
formula that contains an RTO/ISO price component. An example is a 
generator's sale to into a RTO/ISO day-ahead market.
    94. This proposal would impose additional reporting requirements on 
any market participant that is required to file an EQR with the 
Commission. The Commission will ensure its EQR software can accommodate 
such requirements before the first EQR filings containing the trade 
date and type of rate must be submitted. Reporting of the trade date 
and type of rate would occur prospectively from the time the 
requirements are implemented. Accordingly, market participants would 
not have to re-file prior EQR filings with the proposed time and date 
information and would not have to adjust a prior quarter's information 
on already executed transactions. However, if the Final Rule requires 
EQR filers to report the trade date and type of rate of their 
transactions, we would expect market participants to include the trade 
date and type of rate for transactions taking place from the date of 
the Final Rule's implementation. Any re-filings and adjustments to EQR 
filings made prior to the date of effectiveness of such a rule would 
follow the EQR filing requirements imposed at the time of the original 
filing.
    95. Although not raised in the Transparency NOI, the Commission now 
proposes to require market participants to also report the time of 
trade. We propose to clarify the term ``time of trade'' as ``the time 
upon which the parties agree upon the price of a transaction.'' The 
Commission recognizes that not only the date, but also the time of 
trade, is essential in identifying some forms of market manipulation 
that may be designed to target daily index price creation for the 
purpose of benefiting financial swap settlements. Without knowing what 
time a trade occurred, customers and the Commission would have 
difficulty identifying these out-of-market, or anti-competitive, 
transactions from those that followed the ebbs and flows of the daily 
market. This is due to the fact that competitive market pricing is 
often fluid to reflect changes in supply and demand fundamentals. For 
example, market pricing for next-day power on the morning before 
delivery may be entirely different than pricing that afternoon as 
outage, forecast and other information continually changes. It is 
possible for market participants to attempt to ``direct'' physical 
market pricing throughout the day in an effort to impact settlement 
pricing for other positions. This behavior may involve trading large 
volumes at the beginning of the trading day in order to ``direct'' 
pricing in subsequent hours or other strategies that concentrate 
trading in a narrow time window.
b. Resales of Financial Transmission Rights in Secondary Markets
    96. In the Transparency NOI, staff sought comments as to whether 
the Commission should collect information about the resale of financial 
transmission rights in secondary markets through reporting to the EQR. 
Specifically, the Transparency NOI asked whether market participants 
perceive that collecting this information would enhance market 
transparency and, if so, to designate what current EQR filing 
requirements should be imposed on resales of financial transmission 
rights in secondary markets. In addition, comments were sought to 
identify other filing requirements that may be applicable to the resale 
of financial transmission rights in secondary markets that are not 
current EQR filing requirements and explain whether and, if so, how 
collection of the information would improve market transparency.
i. Comments
    97. California PUC and SDG&E support reporting sales of financial 
transmission rights to increase transparency of financial transmission 
right trading by both transmission and non-transmission owners and to 
reveal whether sales in the secondary market result in market 
concentration or increased liquidity. SDG&E also supports requiring 
transaction-specific information for financial transmission right 
secondary transactions as is required for all other transactions. APPA, 
Duke Energy, EEI and Morgan Stanley question the need for information 
concerning resale of financial transmission rights and assert that the 
burden of collecting financial transmission right resale information 
may outweigh the minimal value of such information. EPSA believes that 
the Commission should not collect financial transmission right data as 
part of this transparency effort because it would be unnecessary, 
duplicative and not provide any useful information.\107\ APPA and EPSA 
state that secondary financial transmission right markets are 
relatively illiquid and Morgan Stanley states that the Commission has 
recognized that financial transmission right markets are thinly traded 
at this time.\108\ FirstEnergy argues that this filing requirement 
would be duplicative because RTO market monitors may have the 
responsibility for reviewing the secondary bilateral financial 
transmission right markets.\109\ DC Energy also believes that reporting 
requirements for secondary market financial transmission right sales 
should be the province of the ISOs/RTOs.\110\ APPA also sees the task 
of assuring transparency of financial transmission right transactions 
as a responsibility of the RTOs.\111\ Morgan Stanley similarly 
recommends that the Commission monitor secondary market financial 
transmission right transactions by requesting each RTO to provide 
quarterly or annual data on such transactions arising in their 
markets.\112\ In addition, PJM observes that, as a threshold question, 
the Commission should first determine whether it has any jurisdiction 
over this type of transaction before deciding whether to compel 
participant reporting.\113\ PJM also states that its bulletin board on 
the PJM eFTR system may provide a means to access secondary market 
financial transmission right transaction information, making increased 
participant reporting unnecessary.\114\
---------------------------------------------------------------------------

    \107\ EPSA at 5-6.
    \108\ Morgan Stanley at 2.
    \109\ FirstEnergy at 3-4.
    \110\ DC Energy at 10-11.
    \111\ APPA at 13.
    \112\ Morgan Stanley at 2-3.
    \113\ PJM at 4-5.
    \114\ Id. at 2-4.

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[[Page 24203]]

ii. Discussion
    98. We agree with certain commenters that RTOs/ISOs collect and 
publish some financial transmission right data and that RTOs/ISOs are 
the proper entities for reporting information about financial 
transmission rights. We believe that requiring financial transmission 
right data to be reported by market participants in the EQR, in 
addition to the information already provided by RTOs/ISOs, would not 
significantly improve price transparency in these markets. Therefore, 
we do not propose to require entities to report information about 
financial transmission rights in the EQR at this time.
c. Standardizing the Unit for Reporting Energy and Capacity 
Transactions
i. Comments
    99. California PUC, DC Energy, and PG&E support standardizing EQR 
data on capacity and energy across all filers to help the Commission 
and other market participants compare prices.\115\ PG&E further states 
that $/MWh is an appropriate unit for energy transactions and $/MW is 
an appropriate unit for capacity transactions because these units are 
commonly used in organized electricity markets, including the markets 
operated by CAISO.\116\
---------------------------------------------------------------------------

    \115\ California PUC at 4; DC Energy at 11; and PG&E at 3.
    \116\ PG&E at 3.
---------------------------------------------------------------------------

    100. EEI states that having common units for reporting energy and 
capacity transactions (i.e., $/MWh and $ per MW-month) would simplify 
interpretation of the data, but that the Commission should clarify that 
this change requires the conversion only of KWh to MWh and KW to MW 
(i.e., utilities can still report transactions in MW/Month, MW/Day, 
KVA, MVAR, etc.). In addition, EEI notes that if the Commission makes 
this change, then it will likely have to increase the number of digits 
allowed in the Rate field--particularly if the units being reported are 
MWhs.\117\
---------------------------------------------------------------------------

    \117\ EEI at 8.
---------------------------------------------------------------------------

    101. EPSA does not advocate standardizing units for reporting 
transactions. EPSA states that capacity may be sold on a $/MW-Day, $/
MW-Week, $/KW-Day, $/KW-Week, $/KW-Month, or $/KW-Year basis, and 
argues that the parties should report those trades in accordance with 
the way the products were measured, priced and sold under each 
transaction. According to EPSA, this will reduce the possibility of 
errors in translating one unit to another.\118\
---------------------------------------------------------------------------

    \118\ EPSA at 6.
---------------------------------------------------------------------------

ii. Discussion
    102. We propose to insert an additional field to the EQR 
transaction section to standardize the units for reporting energy and 
capacity within the EQR. We agree with several commenters that the 
usefulness of the additional field will simplify interpretation of the 
data and aid the Commission and other market participants in comparing 
prices. The additional field will provide a consistent rate for 
comparison purposes and allow the Commission to develop internal checks 
in the EQR software on the accuracy of a filing.
    103. Today, the EQR filing requirements include, among other 
things, the Transaction Rate Units (Field Number 65). This field 
requires a market participant to report the measure for the appropriate 
price of the product sold.\119\ To avoid possible confusion, we clarify 
that the additional field we are proposing to add would not remove or 
replace any current EQR filing requirement. It would simply add a new 
field to capture a common unit for reporting energy and capacity 
transactions.
---------------------------------------------------------------------------

    \119\ Valid values include: $/KVA, $/KW, $/KW-DAY, $/KW-MO, $/
KW-WK, $/KW-YR, $/KWH, $/MVAR-YR, $/MW, $/MW-DAY, $/MW-MO, $/MW-WK, 
$/MW-YR, $/MWH, $/RKVA, CENTS, CENTS/KVR, CENTS/KWH, and FLAT RATE. 
Rate units should match product names.
---------------------------------------------------------------------------

    104. To ensure that similar sales can be easily compared, the 
Commission is proposing to standardize the units in which energy and 
capacity sales may be filed in the EQR. Therefore, energy transactions 
will be required to be reported as $/MWh and capacity transactions will 
be required to be reported as $/MW-month. Each filing entity will be 
required to make the conversion for any measurement that is not in this 
denomination. Several commenters suggested that requiring transactions 
to be reported using a standardized unit would introduce conversion 
errors into EQR. Converting the quantity and price for energy and 
capacity sales to $/MWh and $/MW-month generally requires routine, 
commonly-used calculations. Commission staff is available to assist 
filers with any filing-related questions, including conversion 
questions. Additionally, the Commission will ensure the appropriate 
number of digits in the EQR software to accommodate the conversion.
d. Omitting the Time Zone From the Contract Section of the EQR
i. Comments
    105. DC Energy and EPSA support eliminating from the contract 
section of the EQR the requirement to report the time zone, so long as 
the Commission maintains the requirement to report the time zone in the 
transaction report.\120\ EEI states that the time zone information in 
the contract section of the EQR is simply unnecessary and that deleting 
this requirement would help to reduce burden.\121\
---------------------------------------------------------------------------

    \120\ DC Energy at 11; EPSA at 6-7.
    \121\ EEI at 8.
---------------------------------------------------------------------------

ii. Discussion
    106. We propose eliminating the Contract Time Zone (Field Number 
45) as currently required in EQR filings. We agree with EEI that time 
zone information in the contract section of the EQR is unnecessary and 
that eliminating it would reduce the burden of filing the EQR. However, 
we clarify that, although we propose to eliminate time zone information 
from the contract section, we will continue to require EQR filers to 
report the time zone where the transaction took place in the 
transaction section (Field Number 55).
3. Additional EQR Enhancements
    107. In the almost nine years since the Commission established EQRs 
under Order No. 2001, large financial markets have emerged and become 
increasingly intertwined with physical wholesale power markets. 
Further, the diversity and complexity of derivatives instruments that 
are linked to physical power prices have grown exponentially. EQR 
reporting requirements have not kept pace with these market evolutions. 
The refinements proposed in this NOPR are intended to allow the 
Commission and market participants to use the EQR to identify behavior 
in physical power markets that may be designed to influence a market 
participant's financial positions linked to physical market pricing 
fundamentals.
    108. The Commission recognizes that there is an incentive to 
manipulate bilateral wholesale spot markets for the purpose of 
influencing financial swap settlements. Although leveraged financial 
positions can provide legitimate hedging capabilities, they can also 
create incentives for companies to alter physical market prices. 
Incentives to manipulate can be especially strong outside of RTO/ISO 
markets, where bilateral transactions are used to determine swap 
settlement values.

[[Page 24204]]

    109. For these reasons, the Commission proposes to require several 
new data fields in the EQR that will enable market participants and the 
Commission to identify physical wholesale transactions that could 
contribute to pricing designed to influence financial swap settlements. 
These additional enhancements were not raised for comment in the 
Transparency NOI, but rather are being proposed in this NOPR as the 
Commission continues to weigh appropriate measures to help facilitate 
greater price transparency and help ensure that a market participant 
does not manipulate wholesale electricity markets for the purpose of 
benefiting its financial positions. Thus, the Commission proposes to 
require EQR filers to report in the transaction section of the EQR the 
following information: (1) The index publisher(s) to which the 
transaction was reported; (2) the exchange on which the transaction was 
consummated or the brokerage firm that arranged the transaction; and 
(3) the time the transaction occurred.
a. Identify Transactions Reported to Index Publishers
    110. The Commission proposes to require all market participants to 
report in the transaction section of EQR the index price publisher to 
which they have reported their sales transactions. The Commission has 
recognized the importance of price indices in energy markets, noting in 
its Policy Statement on Natural Gas and Electric Price Indices:

    Price indices are widely used in bilateral natural gas and 
electric commodity markets to track spot and forward prices. They 
are often referenced in contracts as a price term; they are related 
to futures markets and used when futures contracts go to delivery; * 
* * and state commissions use indices as benchmarks in reviewing the 
prudence of gas or electricity purchases. Since index dependencies 
permeate the energy industry, the indices must be robust and 
accurate and have the confidence of market participants for such 
markets to function property and efficiently.\122\
---------------------------------------------------------------------------

    \122\  See Price Discovery in Natural Gas and Electric Markets, 
Policy Statement on Natural Gas and Electric Price Indices, 104 FERC 
] 61,121, at P 6, clarified, 105 FERC ] 61,282 (2003).

    111. The Commission believes that requiring in the EQR the names of 
index price publishers to which wholesale power sale transactions are 
reported would allow the Commission, market participants and other 
interested parties greater transparency to see how market forces are 
affecting those index prices and the market concentration of the 
companies' sales used to calculate the index prices.
    112. In addition to market participants' significant use of index 
prices with respect to tracking electric spot and forward prices, the 
use of index prices has expanded to form settlement prices for 
financial products. Because bilateral physical spot markets are used to 
settle financial swaps, there is an incentive to manipulate the 
physical markets to benefit larger financial positions. For example, 
linked financial-swap contracts at several hubs traded at volumes many 
times larger than bilateral spot trading at that particular hub. The 
multiple of financial-swaps at such hubs in relation to physical 
transactions indicates that opportunities to profit from physical 
market manipulation strategies involving financial positions already 
exist. For instance, a market participant with fixed price financial-
swap contracts could manipulate the physical index price by transacting 
power at a loss for transactions that contribute to the index price. 
However, the market participant could still profit from such activity 
because any loss from selling power that contributes to the index price 
could be more than offset by financial-swap gains resulting from moving 
the index price. Thus, greater transparency could further our 
understanding of how index prices are formed. This, in turn, could lead 
to more robust indices, enhance public confidence in their accuracy and 
reliability, and improve the Commission's ability to monitor prices for 
exercises of market power and manipulation.
    113. Section 35.41(c) of the Commission's regulations \123\ 
requires market-based rate power sellers to submit a notification to 
the Commission if they report transactions to electric or natural gas 
price index publishers. However, this regulation does not require 
market-based rate sellers to specify the price index publishers to 
which they report their transactions and it applies only to one subset 
of market participants whose transactions are used to form index 
prices, i.e., jurisdictional power sellers with market-based rate 
authorization from the Commission. Obtaining information from all 
market participants about which transactions are reported to which 
index publishers will strengthen the Commission's and interested 
observers' ability to determine whether these index prices reflect 
market forces and provide market participants with greater confidence 
in the accuracy of index prices. Therefore, we propose to require each 
EQR filer to report in the transactions section the particular electric 
or natural gas index publisher to which they report transactions, if 
applicable. To eliminate redundancy between the EQR filings and the 
notification required under 18 CFR 35.41(c) from market-based rate 
sellers, we propose to amend that provision to no longer require 
notifications from these sellers to the Commission stating whether they 
are reporting transactions to electricity or natural gas index 
publishers, or updates of such notifications.
---------------------------------------------------------------------------

    \123\ 18 CFR 35.41(c). Investigation of Terms and Conditions of 
Public Utility Market-Based Rate Authorizations, see Order Amending 
Market-Based Rate Tariffs and Authorizations, 105 FERC ] 61,218, at 
P 116-119 (2003).
---------------------------------------------------------------------------

b. Identify the Exchange/Broker Used To Consummate a Transaction
    114. Exchanges and brokers routinely publish index prices composed 
of wholesale transactions that were consummated on their exchange or 
through their brokerage services. Such index prices are used to track 
electric spot and forward prices and, increasingly, to form settlement 
prices for financial products. We believe that requiring information 
regarding whether exchanges or brokers were used to consummate a 
transaction will promote visibility into index prices and bolster the 
Commission's market monitoring efforts.
c. Collection of e-Tag ID Data
    115. To schedule physical interchange transactions,\124\ market 
participants submit e-Tags to transmission system operators. Generally, 
e-Tags track energy transfers, including where the power is sourced and 
delivered; the responsible parties in the receipt, delivery and 
movement of the power; the timing; and the volumes and specific details 
regarding which transmission paths are used. An e-Tag is reported to 
NERC or WECC, but is not presently reported to the Commission.
---------------------------------------------------------------------------

    \124\ An interchange transaction involves a transfer of energy 
from a seller to a buyer that crosses one or more balancing 
authority area boundaries.
---------------------------------------------------------------------------

    116. The Commission proposes to require EQR filers to submit e-Tag 
IDs for each transaction reported in the EQR in the event an e-Tag is 
used to schedule the transaction. The e-Tag ID is a subset of 
information associated with a full e-Tag and consists of four 
components: (1) Source Balancing Authority Entity Code; \125\ (2) 
Purchasing-Selling Entity Code; \126\ (3) e-Tag Code or Unique

[[Page 24205]]

Transaction Identifier; \127\ and (4) Sink Balancing Authority Entity 
Code.\128\ Requiring e-Tag IDs as part of EQR filings would address a 
major gap in EQR information as it is currently reported: the source 
location of wholesale sales transactions. E-Tag IDs would assist market 
participants and the Commission in identifying chains of transactions 
and transaction paths. Using the information currently reported in the 
EQR, it is difficult to identify linked re-sales or chains of 
transactions between filers. EQRs currently require reporting of the 
Point of Receipt Balancing Authority (Field Number 39) for power sales 
contracts if that information is specified in the contract. In 
practice, however, many EQRs do not contain information related to the 
Point of Receipt Balancing Authority because many contracts do not 
specify source information.
---------------------------------------------------------------------------

    \125\ The Source Balancing Authority is defined as the host 
Balancing Authority in which the generation is located.
    \126\ The Purchasing-Selling Entity is the entity creating and 
submitting the e-Tag request to the authority service, which 
authorizes implementation of interchange schedules between balancing 
authority areas. The Purchasing-Selling Entity also is the entity 
that purchases or sells, and takes title to, energy, capacity and 
interconnected operations services.
    \127\ The e-Tag Code is a unique seven-character transaction 
identifier for each bilateral energy transaction scheduled on the 
transmission network. It is assigned by the e-Tag system when 
transmission service to accommodate the transaction is reserved.
    \128\ The Sink Balancing Authority is defined as the host 
Balancing Authority in which load is located.
---------------------------------------------------------------------------

    117. Accessing e-Tag IDs through the EQR would facilitate price 
transparency by enabling all market participants to ``follow'' 
transactions across markets. In other words, market participants would 
be able to identify that an energy trade from Company A to Company B 
and an energy trade reported by Company B to Company C are, in fact, a 
re-sale of power from Company A to Company C because both sales would 
reflect the same e-Tag ID. Also, the markups observed for these 
``arbitrage'' transactions are a valuable indicator of competitiveness 
in the wholesale market. Specifically, one would expect the arbitrage 
value between differently-priced markets to be closely associated with 
the cost to secure transmission between those markets. Persistent price 
differences between markets that are not consistent with transmission 
costs could indicate that the ability to arbitrage market price 
differences is not fully competitive.
    118. In addition, the Source Balancing Authority information 
contained in the e-Tag ID would provide additional detail on the 
contract path used to schedule a transaction. In analyzing EQR filings, 
the Commission has found that source information related to a power 
sale is a vital component in analyzing transactions for anti-
competitive behavior. Specifically, without some general knowledge of 
where power is being generated, it would be difficult to determine 
whether an interchange transaction is competitively arbitraging price 
separations between markets or behaving anti-competitively. 
Furthermore, the e-Tag IDs will allow the Commission and market 
participants to better monitor interchange transactions and detect 
potential abuses.
    119. In a NOPR in Docket No. RM11-12-000 (e-Tag NOPR), to be issued 
concurrently with this NOPR, the Commission proposes to require the 
Commission-certified Electric Reliability Organization, i.e., NERC, to 
provide Commission staff with non-public access to complete e-Tag data. 
This data will, among other things, help the Commission to monitor 
wholesale markets and prevent market manipulation. In the e-Tag NOPR, 
the Commission explains that accessing e-Tag data through NERC, rather 
than requiring individual market participants to provide such data to 
the Commission, would avoid burdening market participants with 
submitting the complete e-Tags with both NERC and the Commission. In 
addition, it would avoid burdening the Commission with developing and 
maintaining a new system to capture such data from market participants. 
In this NOPR, the Commission is proposing to require individual market 
participants to file, if applicable, a sub-set of e-Tag information, 
specifically e-Tag IDs, as part of the EQR because market participants 
are able to match their e-Tag IDs with the transactions they are 
required to report in the EQR. As explained above, access to this 
information in the EQR will allow the public and the Commission to 
``follow'' transactions across markets.
d. Eliminating the DUNS Number Requirement
i. Comments
    120. Under existing requirements, filers must identify all 
customers and sellers reported in the EQRs using DUNS numbers, a 
numeric identifier assigned by Dun & Bradstreet, Inc. The Commission 
required DUNS numbers in order to distinguish among similarly named, 
but different, service providers.\129\ Although the Transparency NOI 
did not seek comment on whether to continue requiring DUNS numbers in 
EQRs, several commenters urged the Commission to eliminate this 
requirement. EEI argues that DUNS numbers have proven not to be a 
unique way to identify entities and have become a waste of time, 
resources, and money. In addition, EEI and Wisconsin Electric state 
that some market participants have multiple DUNS numbers, while others 
have only one or none at all.\130\ Wisconsin Electric notes that DUNS 
numbers listed in the EQR are often incorrect, and that not all market 
participants subscribe to the proprietary cross-referencing 
service.\131\ EPSA asserts that its members view DUNS numbers as more 
of an administrative burden than a help and that an error message 
occurs even though the Commission has instructed a party to input zero 
when a counterparty does not have a DUNS number. As an alternative to 
DUNS numbers, Wisconsin Electric proposes that the Commission adopt a 
more widely used identification system, such as federal tax IDs. EEI 
proposes using a company's legal name or a new ID developed through the 
FERC eTariff program. EPSA does not advocate a specific identification 
method but did recognize that a uniform nomenclature should be adopted.
---------------------------------------------------------------------------

    \129\ See Order No. 2001, FERC Stats. & Regs. ] 31,127 at P 90.
    \130\ Wisconsin Electric at 2.
    \131\ Id.
---------------------------------------------------------------------------

ii. Proposal
    121. The Commission proposes to eliminate the DUNS number 
requirement from EQR filings. Customer/counterparty identification 
through unique identifier numbers is a significant component of EQRs, 
particularly when identifying sales to individual companies. In the 
EQR, the customer company names are reflected in Field Numbers 16 and 
48 as unrestricted, or free-form, text fields. As a result, the 
customer company names inserted in Field Numbers 16 and 48 are not 
always uniformly reported by different sellers. To help ensure more 
precise identification of counterparties, however, EQRs use DUNS 
numbers in Field Numbers 17 and 49. However, DUNS numbers have proven 
to be an imprecise identification system. As noted by commenters, EQR 
filers can have multiple DUNS numbers, only one DUNS number, or no DUNS 
number at all.
    122. In considering alternatives to the use of DUNS numbers, the 
Commission finds that none of the suggested approaches would provide a 
viable replacement to the current approach and requiring a different 
numbering system would create legacy issues. Therefore, the Commission 
will not

[[Page 24206]]

replace the DUNS number requirement with another approach at this time, 
but rather will continue to rely on the insertion of customer company 
names in the free-form fields, Field Numbers 16 and 48.

III. Information Collection Statement

    123. The Office of Management and Budget (OMB) regulations require 
approval of certain information collection requirements imposed by 
agency rules.\132\ Upon approval of a collection(s) of information, OMB 
will assign an OMB control number and an expiration date. Respondents 
subject to the filing requirements of an agency rule will not be 
penalized for failing to respond to these collections of information 
unless the collections of information display a valid OMB control 
number. The Paperwork Reduction Act (PRA) \133\ requires each federal 
agency to seek and obtain OMB approval before undertaking a collection 
of information directed to ten or more persons or contained in a rule 
of general applicability.\134\
---------------------------------------------------------------------------

    \132\ 5 CFR 1320.8.
    \133\ 44 U.S.C. 3501-3520.
    \134\ OMB's regulations at 5 CFR 1320.3(c)(4)(i) require that 
``Any recordkeeping, reporting, or disclosure requirement contained 
in a rule of general applicability is deemed to involve ten or more 
persons.''
---------------------------------------------------------------------------

    124. The Commission is submitting these reporting and recordkeeping 
requirements to OMB for its review and approval under section 3507(d) 
of the PRA. Comments are solicited on the Commission's need for this 
information, whether the information will have practical utility, the 
accuracy of provided burden estimates, ways to enhance the quality, 
utility, and clarity of the information to be collected, and any 
suggested methods for minimizing the respondent's burden, including the 
use of automated information techniques.
    125. The Commission's estimate of the additional average annual 
Public Reporting Burden and cost \135\ related to the proposed rule in 
Docket RM10-12-000 follow.
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    \135\ For purposes of calculating the annual averages, the 
implementation burden and cost have been averaged, spread over the 
3-year period, and added to the recurring burden and cost.
[GRAPHIC] [TIFF OMITTED] TP29AP11.044

    126. In calculating the number of current respondents filing EQRs, 
the Commission looked at the number of agents responsible for 
submitting the filings of the EQR, which came to 1,291 filers. Out of 
those 1,291 filers, only 831 reported transactions during 2009. 
Therefore, the Commission proposes to use 831 as the number of 
respondents.\136\ Although the Commission estimates the total number of 
current respondents to be 831, this figure overstates the number of 
corporate families filing the EQR because some of the filings were made 
separately by affiliates from the same company. For instance, of the 
831 filer names, 28 began with FPL, 24 began with NRG, 12 began with 
Wheelabrator, and 11 began with Dynegy. This trend was common among 
other filers.
---------------------------------------------------------------------------

    \136\ There were 1,435 unique respondents to the EQR reporting 
for 1,638 unique sellers during the third quarter of 2010. Neither 
the number of respondents nor the number of unique sellers 
accurately reflects the number of entities and affiliated entities 
that respond to the EQR. For instance, respondents will often report 
sales for unique sellers, either individual generation units or 
affiliated entities, separately in the EQR. Similarly, affiliate 
relationships exist for unique respondents. These respondents may 
share EQR filing software and techniques or may even be filed by the 
same staff.
---------------------------------------------------------------------------

    127. For non-public utility filers, the Commission separately 
estimated the burden for non-balancing authorities with more than 4 
million MWh of annual wholesale sales; balancing authorities with more 
than 4 million MWh of annual wholesale and retail sales; and balancing 
authorities with 1 million MWh or more of annual wholesale and retail 
sales. In the RFA Certification section below, the Commission uses the 
SBA definition of a small utility to determine how many small entities 
will be impacted by the proposed rule. The SBA defines a utility as 
small if, including its affiliates, it is primarily engaged in the 
transmission, generation and/or distribution of electric energy for 
sale and its total electric output for the preceding twelve months did 
not exceed four million MWh.\137\ We also used the SBA definition to 
determine the burden on respondents in the table above.
---------------------------------------------------------------------------

    \137\ 13 CFR 121.101.
---------------------------------------------------------------------------

    128. The Commission recognizes that there will be an increased 
burden involved in the initial implementation

[[Page 24207]]

associated with filing EQRs. This burden includes the set-up software 
on a utility's computers, the initial entry of the contract data, and 
the mapping of the transaction data from the utility's internal 
computer systems into the format required by the Commission. For non-
public utility filers, we estimate a burden of 400 hours per year for 
the initial implementation phase. For current EQR filers, we estimate 
that the additional data requirements will involve a burden of 160 
hours. This burden is lower than that for non-public utility filers 
because of current filers' familiarity with EQR reporting.
    129. For the recurring effort involved in filing the EQR each 
subsequent quarter, we anticipate that the burden will be minimal, 
particularly as filing transaction data will be automated for companies 
that have mapped their systems to the required format. Thus, we 
estimate a recurring burden of 24 hours per response (rather than per 
year) for all non-public filers if the requirements of this rulemaking 
are to be implemented. We have estimated that current filers spend 
about 16 hours to meet the existing recurring requirements of filing 
EQRs. With the additional data proposed to be required, we estimate 
that current filers' recurring burden will increase by 8 hours.
    Information Collection Costs: The Commission seeks comments on the 
costs and burden to comply with these requirements.
    Total average annual costs = $8,309,293 ($6,940,157 for public 
utilities plus $1,369,136 for non-public utilities). The Commission 
estimates that the hours to complete the EQR reporting requirements 
will be divided among an entity's accounting, legal and support staff. 
We estimate an average hourly cost of $97.87 (including a senior 
accountant at $50.22/hr., a financial analyst at $67.00/hr., legal 
services at $250/hr., and support staff at $24.25/hr.).\138\
---------------------------------------------------------------------------

    \138\ Hourly average wage is an average and was calculated using 
Bureau of Labor Statistics (BLS), Occupational Employment Statistics 
data for May, 2009 (at http://www.bls.gov/oes/) for the accounting, 
financial, and support staffs. The average hourly figure for legal 
support is a composite from BLS and other resources, taking into 
account the hourly cost for both in-house and contractor 
organizations.
---------------------------------------------------------------------------

    Title: FERC-516, Electric Rate Schedules and Tariff Filings (which 
includes the Electric Quarterly Report [EQR]) \139\
---------------------------------------------------------------------------

    \139\ For administrative purposes, the Commission will consider 
whether to separate the EQR requirements from the remaining 
reporting requirements under FERC-516. If that is done, FERC would 
then request a separate OMB Control No. for EQR.
---------------------------------------------------------------------------

    Action: Proposed Revisions to the EQR.
    OMB Control No: 1902-0096.
    Respondents: Public and non-public utilities.
    Frequency of Responses: Initial implementation and quarterly 
filings.
    Necessity of the Information: The Commission is proposing to enact 
requirements that would facilitate price transparency in wholesale 
markets for the sale and transmission of electric energy in interstate 
commerce by requiring certain non-public utilities to file the EQR. 
This proposal would allow the Commission and the public to gain a more 
complete picture of wholesale power and transmission markets in 
interstate commerce by providing additional information concerning 
price formation and market concentration in these markets. Public 
access to additional sales and transmission-related information in the 
EQR would improve market participants' ability to assess supply and 
demand fundamentals and to price interstate wholesale market 
transactions. It also would strengthen the Commission's ability to 
identify potential exercises of market power or manipulation and to 
better evaluate the competitiveness of the interstate wholesale 
markets. In addition, the Commission proposes to make certain revisions 
to the existing EQR filing requirements and apply those revisions to 
all market participants filing EQRs. These refinements to the existing 
EQR filing requirements reflect the evolving nature of electricity 
markets, would increase market transparency for the Commission and the 
public, and would allow market participants to file the information in 
the most efficient manner possible.
    Internal review: The Commission has reviewed the proposed changes 
and has determined that the changes are necessary. These requirements 
conform to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has assured itself, by means of internal review, that there 
is specific, objective support for the burden estimates associated with 
the information collection requirements.
    130. Interested persons may obtain information on the reporting 
requirements by contacting: Federal Energy Regulatory Commission, 888 
First Street, NE., Washington, DC 20426 [Attention: Ellen Brown, Office 
of the Executive Director, e-mail: DataClearance@ferc.gov, Phone: (202) 
502-8663, fax: (202) 273-0873]. Comments on the requirements of this 
rule may also be sent to the Office of Information and Regulatory 
Affairs, Office of Management and Budget, Washington, DC 20503 
[Attention: Desk Officer for the Federal Energy Regulatory Commission]. 
For security reasons, comments should be sent by e-mail to OMB at 
oira_submission@omb.eop.gov. Please reference OMB Control No. 1902-
0096, FERC-516 and the docket number of this proposed rulemaking in 
your submission.

IV. Environmental Analysis

    131. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\140\ The 
actions taken here fall within categorical exclusions in the 
Commission's regulations for information gathering, analysis, and 
dissemination.\141\ Therefore, an environmental assessment is 
unnecessary and has not been prepared in this rulemaking.
---------------------------------------------------------------------------

    \140\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 486 FR 1750 (Jan. 22, 1988), FERC Stats. & Regs. 
] 30,783 (1987).
    \141\ 18 CFR 380.4(a)(5).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act Certification

    132. The RFA \142\ generally requires a description and analysis of 
final rules that will have significant economic impact on a substantial 
number of small entities. The RFA mandates consideration of regulatory 
alternatives that accomplish the stated objectives of a proposed rule 
and that minimize any significant economic impact on a substantial 
number of small entities. The SBA's Office of Size Standards develops 
the numerical definition of a small business.\143\ The SBA has 
established a size standard for electric utilities, stating that a firm 
is small if, including its affiliates, it is primarily engaged in the 
transmission, generation and/or distribution of electric energy for 
sale and its total electric output for the preceding twelve months did 
not exceed four million MWh.\144\
---------------------------------------------------------------------------

    \142\ 5 U.S.C. 601-612.
    \143\ 13 CFR 121.101.
    \144\ 13 CFR 121.201, Sector 22, Utilities & n.1.
---------------------------------------------------------------------------

    133. As discussed in Order No. 2000,\145\ in making this 
determination,

[[Page 24208]]

the Commission is required to examine only the direct compliance costs 
that a rulemaking imposes upon small businesses. It is not required to 
consider indirect economic consequences, nor is it required to consider 
costs that an entity incurs voluntarily.
---------------------------------------------------------------------------

    \145\  See Regional Transmission Organizations, Order No. 2000, 
65 FR 809 (January 6, 2000), FERC Stats. & Regs. ] 31,089, at 31,237 
& n.754 (1999), order on reh'g, Order No. 2000-A, 65 FR 12,088 (Mar. 
8, 2000), FERC Stats. & Regs. ] 31,092 (2000), aff'd sub nom. Pub. 
Util. Dist. No. 1 of Snohomish, County Washington v. FERC, 272 F.3d 
607, 348 U.S. App. D.C. 205 (D.C. Cir. 2001) (citing Mid-Tex Elec. 
Coop. v. FERC, 773 F.2d 327 (D.C. Cir. 1985) (Commission need only 
consider small entities ``that would be directly regulated''); 
Colorado State Banking Bd. v. RTC, 926 F.2d 931 (10th Cir. 1991) 
(Regulatory Flexibility Act not implicated where regulation simply 
added an option for affected entities and did not impose any 
costs)).
---------------------------------------------------------------------------

    134. Based on EIA Form 861, there are 372 non-public utilities that 
made wholesale sales in 2009.\146\ As discussed above, the Commission 
is proposing to exempt from the EQR filing requirements non-public 
utilities with a de minimis market presence. The Commission estimates 
that 311 of the 372 non-public utilities will be exempt from this 
rulemaking because they make four million MWh or less of annual 
wholesale sales and are not Balancing Authorities. Of the 372, 309 are 
considered small entities because they make four million MWh or less of 
annual wholesale and retail sales. In balancing the need for 
information with the burden on small utilities, the Commission is 
proposing to base the de minimis threshold on wholesale sales and thus 
will exempt a majority of small non-public utilities from this proposed 
rulemaking. In fact, the Commission believes that the proposed rule, if 
finalized, would apply to only five non-public utilities (Balancing 
Authorities) that are considered small entities. The Commission 
believes that the direct, economic impact on these five small non-
public utilities may be significant in terms of initial start-up costs 
(estimated to be $39,148), but that the recurring costs ($2,349 per 
quarterly filing, or $9,396 per year) will likely be small. However, 
the Commission does not consider five non-public utilities to be a 
substantial number of small entities. Using this de minimis threshold, 
the proposed rule will apply to approximately 16 percent of the 372 
non-public utilities with wholesale sales, while capturing 
approximately 85 percent of the total volume of non-jurisdictional 
sales.
---------------------------------------------------------------------------

    \146\ We excluded non-public utilities that are located in 
Alaska, Hawaii, and Texas.
---------------------------------------------------------------------------

    135. This rulemaking also proposes changes to the existing filing 
requirements and thus current EQR filers also will be impacted. Based 
on analysis of EIA Form 861, there are 186 public utilities and, of 
these, 51 make four million MWh or less of annual wholesale and retail 
sales. When considering annual wholesale and retail sales from these 51 
entities together with sales by their affiliates, only 28 combined 
entities had annual wholesale and retail sales of or below four million 
MWh. The Commission does not consider this to be a substantial number 
of small entities. Furthermore, we note that public utilities may 
request, on an individual basis, waiver from the EQR reporting 
requirements.\147\ In addition, the Commission expects that the direct, 
economic cost to comply will be less significant. While public 
utilities will need to modify their systems to capture and report the 
additional data, they already have the system in place. The estimated 
additional costs from the proposed rule are: (1) For implementation of 
the changes, $15,659, and (2) for each quarterly report, $783 (or 
$3,132 annually). Thus, the Commission certifies that this proposed 
rule will not have a significant impact on a substantial number of 
small entities.
---------------------------------------------------------------------------

    \147\ The Commission has granted requests for waiver of the EQR 
filing requirements. See Bridger Valley Elect. Assoc., Inc., 101 
FERC ] 61,146 (2002). Entities with a waiver will continue to have a 
waiver and will not need to file a new request for waiver.
---------------------------------------------------------------------------

VI. Comment Procedures

    136. The Commission invites interested persons to submit comments 
on the matters and issues proposed in this notice to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to discuss. Comments are due 60 days from publication in the 
Federal Register. Comments must refer to Docket No. RM10-12-000, and 
must include the commenter's name, the organization they represent, if 
applicable, and their address in their comments.
    137. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software should be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    138. Commenters that are not able to file comments electronically 
must send an original and 14 copies of their comments to: Federal 
Energy Regulatory Commission, Secretary of the Commission, 888 First 
Street, NE., Washington, DC 20426.
    139. All comments will be placed in the Commission's public files 
and may be viewed, printed, or downloaded remotely as described in the 
Document Availability section below. Commenters on this proposal are 
not required to serve copies of their comments on other commenters.

VII. Document Availability

    140. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. 
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    141. From FERC's Home Page on the Internet, this information is 
available on eLibrary. The full text of this document is available on 
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or 
downloading. To access this document in eLibrary, type the docket 
number excluding the last three digits of this document in the docket 
number field.
    User assistance is available for eLibrary and the FERC's Web site 
during normal business hours from FERC Online Support at (202) 502-6652 
(toll free at 1-866-208-3676) or e-mail at ferconlinesupport@ferc.gov, 
or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. E-
mail the Public Reference Room at public.referenceroom@ferc.gov.

List of Subjects in 18 CFR Part 35

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

    By direction of the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    In consideration of the foregoing, the Commission proposes to amend 
18 CFR Part 35, Chapter I, Title 18, Code of Federal Regulations, as 
follows.

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

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

    2. Section 35.10b is revised to read as follows:


Sec.  35.10b  Electric Quarterly Reports.

    Each public utility as well as each non-public utility with more 
than a de minimis market presence shall file an updated Electric 
Quarterly Report with the Commission covering all services it provides 
pursuant to this part, for each of the four calendar quarters of each 
year, in accordance with the following

[[Page 24209]]

schedule: for the period from January 1 through March 31, file by April 
30; for the period from April 1 through June 30, file by July 31; for 
the period July 1 through September 30, file by October 31; and for the 
period October 1 through December 31, file by January 31. Electric 
Quarterly Reports must be prepared in conformance with the Commission's 
software and guidance posted and available for downloading from the 
FERC Web site (http://www.ferc.gov).
    (a) For purposes of this section, the term ``non-public utility'' 
means any market participant exempted from the Commission's 
jurisdiction by virtue of the Federal Power Act, 16 U.S.C. 824f. The 
term does not include an entity that engages in purchases or sales of 
wholesale electric energy or transmission services within the Electric 
Reliability Council of Texas or any entity that engages solely in sales 
of wholesale electric energy or transmission services in the states of 
Alaska or Hawaii.
    (b) For purposes of this section, the term ``de minimis market 
presence'' means any non-public utility that makes 4,000,000 megawatt 
hours or less of annual wholesale sales, based on the average annual 
sales for resale over the preceding three years as published by the 
Energy Information Administration's Form 861 unless the non-public 
utility is a Balancing Authority that makes 1,000,000 megawatt hours or 
more of annual wholesale sales, as published by the Energy Information 
Administration's Form 861.
    3. In Sec.  35.41, paragraph (c) is revised to read as follows:


Sec.  35.41  Market behavior rules.

* * * * *
    (c) Price reporting. To the extent a Seller engages in reporting of 
transactions to publishers of electric or natural gas price indices, 
Seller must provide accurate and factual information, and not knowingly 
submit false or misleading information or omit material information any 
such publisher, by reporting its transactions in a manner consistent 
with the procedures set forth in the Policy Statement on Natural Gas 
and Electric Price Indices, issued by the Commission in Docket No. 
PL03-3-000, and any clarifications thereto. Seller must notify the 
Commission as part of its Electric Quarterly Report filing requirement 
in Sec.  35.10b of this chapter whether it reports its transactions to 
publishers of electricity and natural gas indices. In addition, Seller 
must adhere to any other standards and requirements for price reporting 
as the Commission may order.
* * * * *

    Note:  The following Appendixes will not appear in the Code of 
Federal Regulations.

Appendix A: List of Commenters

------------------------------------------------------------------------
         Short name or acronym                      Commenter
------------------------------------------------------------------------
Alaska Power...........................   Alaska Power Association
Allegheny..............................   Allegheny Electric Cooperative
APPA...................................   American Public Power
                                          Association
BPA....................................   Bonneville Power
                                          Administration
California DWR.........................   California Department of Water
                                          Resources State Water Project
California PUC.........................   Public Utilities Commission of
                                          the State of California
Cities/M-S-R...........................   City of Redding, California,
                                          City of Santa Clara,
                                          California, and M-S-R Public
                                          Power Agency
City of Dover..........................   City of Dover, Delaware
City of Fayetteville...................   Public Works Commission of the
                                          City of Fayetteville, North
                                          Carolina
Consolidated Edison Energy, Inc. and      Consolidated Edison Energy,
 Consolidated Edison Solutions, Inc.      Inc. and Consolidated Edison
                                          Solutions, Inc
Delaware Municipal.....................   Delaware Municipal Electric
                                          Corporation, Inc.
DC Energy..............................   DC Energy, LLC
Duke Energy............................   Duke Energy Corporation
EEI....................................  Edison Electric Institute
EPSA...................................   Electric Power Supply
                                          Association
East Texas Cooperatives................   East Texas Electric
                                          Cooperatives
ELCON..................................   Electricity Consumers Resource
                                          Council
EMCOS..................................   Eastern Massachusetts Consumer-
                                          Owned Systems
FirstEnergy............................   FirstEnergy Service Company
Imperial...............................   Imperial Irrigation District
LPPC...................................   Large Public Power Council
MID....................................   Modesto Irrigation District
Morgan Stanley.........................   Morgan Stanley Capital Group,
                                          Inc.
New York Public Power..................   New York Association of Public
                                          Power
Northwest Utility......................   Northwest Requirements Utility
NRECA..................................   National Rural Electric
                                          Cooperative Association
NYMPA/MEUA.............................   Northern California Power
                                          Agency; New York Municipal
                                          Power Agency and Municipal
                                          Electric Utilities Association
                                          of New York
PG&E...................................   Pacific Gas and Electric
                                          Company
PJM....................................   PJM Interconnection, LLC
Public Power Council...................   Public Power Council
Public Systems.........................   Connecticut Municipal Electric
                                          Energy Cooperative,
                                          Massachusetts Municipal
                                          Wholesale Electric Company,
                                          and New Hampshire Electric
                                          Cooperative, Inc.
Salt River.............................   Salt River Project
Sam Rayburn Municipal..................   Sam Rayburn Municipal Power
                                          Agency
SDG&E..................................   San Diego Gas & Electric
                                          Company
Southwest Transmission.................   Southwest Transmission
                                          Dependent Utility Group
TANC...................................   Transmission Agency of
                                          Northern California
TAPS...................................   Transmission Access Policy
                                          Study Group
Utah Associated Municipal..............   Utah Associated Municipal
                                          Power Systems
Wisconsin Electric.....................  Wisconsin Electric Power
                                          Company
------------------------------------------------------------------------


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[[Page 24211]]

[GRAPHIC] [TIFF OMITTED] TP29AP11.046

[FR Doc. 2011-10113 Filed 4-28-11; 8:45 am]
BILLING CODE 6717-01-P


