Document ID: FERC-2012-1701-0001
Agency: ferc
Document Type: Rule
Title: Electricity Market Transparency Provisions of Section 220 of the Federal Power Act
Posted Date: 2012-10-11T04:00Z

[Federal Register Volume 77, Number 197 (Thursday, October 11, 2012)]
[Rules and Regulations]
[Pages 61895-61936]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-23746]

[[Page 61895]]

Vol. 77

Thursday,

No. 197

October 11, 2012

Part III

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

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

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

[[Page 61896]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

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

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

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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

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

FOR FURTHER INFORMATION CONTACT: 

Maria Vouras, Office of Enforcement, Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8062, 
Maria.Vouras@ferc.gov.
Steven Reich, Office of Enforcement, Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6446, 
Steven.Reich@ferc.gov.
Christina Switzer, Office of the General Counsel, Federal Energy 
Regulatory Commission, 888 First Street NE., Washington, DC 20426, 
(202) 502-6379, Christina.Switzer@ferc.gov.

SUPPLEMENTARY INFORMATION: 

Order No. 768

Final Rule

Table of Contents

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

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

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

Final Rule

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

[[Page 61898]]

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

I. Introduction

A. Order No. 2001

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

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

[[Page 61899]]

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

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

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

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

[[Page 61900]]

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

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

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

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

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

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

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

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

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

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

[[Page 61901]]

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

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

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

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

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

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

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

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

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

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

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

[[Page 61902]]

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

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

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

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

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

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

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

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

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

[[Page 61903]]

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[Page 61904]]

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

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

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

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

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

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

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

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

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

[[Page 61905]]

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[Page 61906]]

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

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

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

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

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

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

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

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

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

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

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

[[Page 61907]]

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[Page 61908]]

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[Page 61909]]

under a non-public utility's reciprocity OATT, the non-public utility 
should follow the existing conventions for transmission providers 
reporting transmission capacity reassignments in the EQR.
b. Burden
i. NOPR
    76. In the NOPR, the Commission recognized that extending the EQR 
filing requirements to non-public utility market participants will 
impose a new burden on those market participants. The Commission agreed 
that it would make every effort to provide guidance and technical 
assistance prior to implementation of the EQR filing requirements for 
non-public utilities.
ii. Comments
    77. Some commenters question whether the Commission has adequately 
considered the burden imposed on non-public utilities. For example, 
Southwestern Power Administration asserts that section 220 of the FPA 
provides the Commission with limited authority to seek information from 
certain non-public utilities and requires the Commission to weigh the 
value of the information against the regulatory burden it would impose 
on those entities. Southwestern Power Administration argues that 
requiring it to report information about its sales will serve no useful 
purpose that would justify the burden of reporting this information and 
that the Commission has not shown otherwise.\141\
---------------------------------------------------------------------------

    \141\ Southwestern Power Administration at 2-3.
---------------------------------------------------------------------------

    78. California DWR argues that the NOPR fails to comply with 
Federal statutes that require the Commission to carefully consider the 
costs and benefits of imposing burdens on governmental entities. For 
instance, California DWR states that the Paperwork Reduction Act 
requires agencies to certify that a new reporting requirement is not 
unnecessarily duplicative and that the Unfunded Mandates Reform Act of 
1995 requires agencies to prepare a written statement of 
intergovernmental mandates that describe the analyses and consultations 
on the unfunded mandate.\142\ California DWR also states that Executive 
Order 12866 requires agencies to propose or adopt regulations after it 
determines that the benefits of the intended regulation justify the 
costs and that the Regulatory Right to Know Act requires agencies to 
conduct cost-benefit analysis of their regulatory initiatives and 
report their findings to the Office of Management and Budget.\143\
---------------------------------------------------------------------------

    \142\ California DWR at 6-7 (citing Paperwork Reduction Act, 44 
U.S.C. 3506(c)(3) (2006); Unfunded Mandates Reform Act of 1995, 2 
U.S.C. 1531, et seq. (2006)).
    \143\ Id. at 5-6 (citing Executive Order 12866, 58 FR 51735 
(Oct. 4, 1993); Regulatory Right to Know Act, 31 U.S.C. 1105 
(2006)).
---------------------------------------------------------------------------

    79. Southwestern Power Administration states that it does not have 
the staffing needed to track and report EQR data, and that hiring 
additional staff to comply would pose increased costs with no 
commensurate benefit to its customers or incremental improvement to 
market transparency.\144\ California DWR argues that the NOPR as 
written would give non-public utilities an incentive to self-supply to 
avoid wholesale power sales in order to reduce reporting burdens, which 
appears contrary to business requirements.\145\
---------------------------------------------------------------------------

    \144\ Southwestern Power Administration at 4.
    \145\ California DWR at 7.
---------------------------------------------------------------------------

    80. If the Commission requires non-public utilities to submit EQRs, 
then NRECA argues that the Commission could reduce the burden on non-
public utilities by simplifying the filing requirements as it relates 
to billing adjustments. NRECA states that it is common practice for a 
cooperative to bill its members under long-term contracts on the basis 
of budgets and that these charges are later trued-up to reflect the 
actual costs associated with the sale. NRECA states that EQR 
regulations require entities to file either revised EQRs or new 
transactions with the class name ``Billing Adjustments'' to report 
changes in billing data after the initial EQR filing deadlines. NRECA 
asserts that it would be very burdensome for cooperatives that use 
budget-based billing to submit revised EQRs or Billing Adjustments to 
reflect true-ups to actual costs. Thus, NRECA argues that the 
Commission should simplify the filing requirements for cooperatives 
that use budget-based billing by specifying that true-ups associated 
with budget-based billing do not trigger the requirement to submit 
revised EQRs or Billing Adjustments.\146\
---------------------------------------------------------------------------

    \146\ NRECA at 18-19.
---------------------------------------------------------------------------

    81. LPPC encourages the Commission to provide sufficient lead time 
to enable non-public utilities to comply, and suggests a period of six 
months from the date of the final rule. LPPC also requests that the 
Commission have staff assist in training programs that will facilitate 
compliance.\147\
---------------------------------------------------------------------------

    \147\ LPPC at 10.
---------------------------------------------------------------------------

iii. Commission Determination
    82. The Commission has carefully weighed, in developing this Final 
Rule, the burden associated with an entity filing the EQR against the 
benefits associated with greater transparency in the nation's wholesale 
electric markets. The Commission concludes that the burden of reporting 
information in the EQR is outweighed by the benefits of greater 
transparency provided by the EQR.
    83. The burden of preparing an EQR filing varies, depending on the 
complexity of a company's transactions. If a company has a few long-
term contracts of limited complexity, its EQR filing is simple: an 
unchanging description of its contracts from quarter to quarter with 
monthly or quarterly reports of the transactions under that contract. 
As the company's sales activities become more complex, with more 
frequent adjustments to price and a greater variety of counterparties 
and sales locations, its technological capabilities for tracking its 
transactions tend to become more sophisticated. As a result, complex, 
detailed EQRs tend to be associated with companies more capable of 
generating such a filing. Filers whose participation in the electric 
wholesale markets occurs under long-term, cost-based contracts with a 
limited number of counterparties will expend relatively little effort 
in complying with the EQR filing requirement. In addition, we believe 
that excluding from the reporting requirement sales by non-public 
utilities under long-term, cost-based agreements required to be made to 
certain customers under Federal or state statute will help lessen the 
burden on non-public utilities. Therefore, we believe that non-public 
utilities would not be encouraged to self-supply to avoid the reporting 
requirements, as suggested by California DWR.
    84. In response to NRECA's concern about the difficulty for non-
public utility cooperatives that use budget-based billing to submit 
revised EQRs or billing adjustments to reflect true-ups or actual 
costs, the Commission will not require true-ups by non-public utility 
cooperatives with budget-based billing in the EQR. The Commission's 
policy regarding refilings or billing adjustments stems from the 
statutory requirement under FPA section 205(c) to have a public 
utility's rates on file. Specifically, in recognition of the fact that 
public utilities may not have complete, final data for the full quarter 
by EQR filing deadlines, the Commission requires that any additions or 
changes to an EQR filing must be made by the end of the following 
quarter, when the filer is expected to file the best available new 
data.\148\ Filers are

[[Page 61910]]

required to file material changes, either as a full refiling or as a 
transaction with the class name ``Billing Adjustment.'' \149\ It is 
worth emphasizing that refiling EQRs, with a billing adjustment to 
reflect the receipt of new information, is only necessary if the filer 
considers the change to previous EQR totals to be material.\150\ The 
Commission has found that this policy balances the need for timely, 
accurate EQR data, while reducing the burden on filing entities by 
identifying price changes on a transaction-by-transaction basis due to 
some after-the-fact billing transaction long after the EQR was 
due.\151\ In the case of budget-based billing, non-public utility 
cooperatives are not covered by FPA section 205 and the true-up process 
will likely have little effect on the market dynamics the Commission is 
trying to capture with this Final Rule. For these reasons, the 
Commission will exclude true-ups by non-public utility cooperatives 
associated with budget-based billing from the EQR's refiling or billing 
adjustment policy.
---------------------------------------------------------------------------

    \148\ Order No. 2001-E, 105 FERC ] 61,352 at PP 9-10. According 
to the EQR Data Dictionary, a Billing Adjustment (BA) designates an 
incremental material change to one or more transactions due to a 
change in settlement results. BA may be used in a refiling after the 
next quarter's filing is due to reflect the receipt of new 
information. It may not be used to correct an inaccurate filing. See 
Order No. 2001-G, 120 FERC ] 61,270 at P 33.
    \149\ Order No. 2001-E, 105 FERC ] 61,352 at PP 9-10.
    \150\ Order No. 2001-G, 120 FERC ] 61,270 at PP 33-34.
    \151\ Id.
---------------------------------------------------------------------------

    85. We agree with LPPC that the Commission should provide 
sufficient lead time to enable non-public utilities to comply. Over the 
past ten years, the Commission has been proactive in its outreach on 
many aspects of the EQR; in issuing this Final Rule, the Commission 
acknowledges that new filers will need the opportunity to learn about 
the filing. Accordingly, non-public utility filers are required to file 
EQRs beginning with the third quarter (Q3) of 2013, covering the period 
July through September 2013. The Commission directs staff to assist 
filers with compliance. For example, the Commission intends to convene 
a staff-led technical conference, to be announced at a future date, to 
assist non-public utilities in collecting and filing EQR data.

B. Refinements to the Existing EQR Requirements

1. General Refinements
a. Trade Date & Time and Type of Rate
i. NOPR
    86. In the NOPR, the Commission proposed to require any market 
participant that is required to file an EQR to report in the EQR the 
date on which parties to a reported transaction agreed upon a price 
(trade date) and the type of rate by which the price was set. The 
Commission stated in the NOPR that the term ``trade date'' means ``the 
date upon which the parties agree upon the price of a transaction.'' 
The Commission also proposed four types of rates: ``fixed,'' 
``formula,'' ``index,'' and ``RTO/ISO price.'' A fixed rate would be 
defined as a fixed charge per unit of consumption. A formula rate would 
be defined as a calculation of a rate based upon a formula that does 
not contain an index component. An index rate would be defined as a 
calculation of a rate based upon an index or a formula that contains an 
index component. An ``RTO/ISO price'' would be defined as a rate that 
is based on an RTO/ISO published price or formula that contains an RTO/
ISO price component. The Commission also proposed to require market 
participants to report the time of trade, defined as ``the time upon 
which the parties agree upon the price of a transaction.''
ii. Comments
    87. DC Energy, Joint Market Monitors, and Pennsylvania Commission 
support the Commission's proposal to require the trade date and time 
and type of rate in EQR.\152\ However, as discussed further below, many 
commenters are opposed to parts of the proposal.
---------------------------------------------------------------------------

    \152\ See, e.g., DC Energy at 4-5; Joint Market Monitors at 4-5; 
and Pennsylvania Commission at 4.
---------------------------------------------------------------------------

(a) Trade Date
    88. With respect to the proposed requirement to report the trade 
date, Powerex states it should not be onerous to report such data 
because market participants likely already track it.\153\ However, some 
commenters question the need for trade data and note some difficulty in 
ascertaining the appropriate date to report. EEI questions the need for 
trade date information, arguing that contracts negotiated to cover 
specific transactions will include trade-specific details so that 
transactions can be distinguished based on the associated contract 
information in the EQR. In addition, EEI suggests that, if the 
Commission requires reporting of trade dates, it should clarify that 
the trade date is the effective date of the legally binding agreement 
between parties with respect to the transaction. In this vein, EEI 
contends that the ``official'' trade date agreed to by market 
participants for each transaction and documented in trade capture 
systems and related transaction documentation is the appropriate date 
to use. EEI states that its members and other market participants 
document the ``official'' date in their trade capture systems and 
related transaction documentation. EEI also recommends that the 
requirement for trade date apply only to transactions entered into 
after the Commission adopts a final rule.\154\
---------------------------------------------------------------------------

    \153\ Powerex at 14.
    \154\ EEI at 12-13.
---------------------------------------------------------------------------

    89. EPSA asks the Commission to clarify whether RTO or ISO sales 
are included in the date/time reporting requirement as these 
transactions do not meet the Commission's proposed definition of 
agreement of the parties upon a price because RTO or ISO mitigation 
schemes may alter awarded prices, which are not known to the market 
participant and are not received until after the flow data. EPSA notes 
that in its NOI comments it expressed concern that the date parties 
agree to a price is not synonymous with the transaction date. EPSA adds 
that there are several elements apart from price, including volume, 
point of delivery, nature of firmness, credit terms, duration, enabling 
agreement status, upon which the parties must reach agreement before 
they execute that trade. EPSA states that ``[i]f the final rule makes 
time and date determinations based on the setting of price there will 
be a need to clearly explain how that is done for the many scenarios in 
the power business; only with this additional explanation can complying 
entities ensure that EQR data is not only transparent but 
useful.''\155\ Entergy questions the usefulness of the trade date and 
notes examples of situations where the price in effect when the 
transaction was entered would not be the rate when the transaction 
began.\156\ Entergy adds that, for hourly market sales, a trade date 
would be difficult to determine because it may be subject to review and 
agreement at a later date.\157\
---------------------------------------------------------------------------

    \155\ EPSA at 7.
    \156\ Entergy at 2 (``while a rate may be arranged at the 
outset, changes in tariff rates and other circumstances may affect 
the rate between the time the transaction was made and the date the 
transaction flows'').
    \157\ Id. at 2-3. Entergy provides the example of a price for an 
hourly market sale being agreed upon during the day ahead or on an 
hourly basis, but the final prices being subject to review and 
agreement at a later date. Id. at 3.
---------------------------------------------------------------------------

(1) Commission Determination
    90. The Commission adopts, with modification, the NOPR proposal to 
require reporting of the trade date in the EQR. The NOPR proposed to 
define the trade date as the date on which parties

[[Page 61911]]

to a reported transaction agreed upon a price. We will clarify this 
definition of trade date, as suggested by EEI, to state that it is 
``the date upon which the parties made the legally binding agreement on 
the price of the transaction.''
    91. As stated in the NOPR, the trade date for transactions 
currently is not provided or collected publicly.\158\ The trade date is 
essential to assessing the significance of prices in relation to market 
conditions in effect at that time. The EQR only collects the start and 
end date of physical transactions as well as other data details for 
contracts. In current EQR filings, trades entered into months before 
the transaction start and end dates are indistinguishable from trades 
entered into minutes before the transaction occurs, making it difficult 
to determine whether pricing is appropriate given market conditions. In 
addition, many of the prices reported in the EQR result from 
confirmation made under master agreements and the prices are not set in 
the contracts themselves, so the Commission is not able to determine 
from EQR data when the price was set. The Commission concludes that 
requiring market participants to report the date on which parties to a 
reported transaction agreed upon a price (trade date) is necessary to 
improve market transparency. The trade date should be reported in the 
EQR transaction section accompanied by each specific sales transaction.
---------------------------------------------------------------------------

    \158\ NOPR, FERC Stats. & Regs. ] 32,676 at P 91.
---------------------------------------------------------------------------

    92. We further clarify that, in cases where pricing detail is 
provided in the contract description, the Contract Execution Date 
should be considered the trade date. Where applicable, this 
clarification will virtually eliminate any additional burden associated 
with this field by allowing the filer to complete the trade date field 
for each transaction by using a date (Contract Execution Date in the 
contracts section) already provided in the filing. It also will obviate 
the need to identify whether this requirement applies to transactions 
with trade dates before the initial filing that includes this field. It 
is unlikely that a transaction will occur during or after the first 
filing under these new rules that both became legally binding before 
the effective date of this Final Rule and does not have an appropriate 
Contract Execution Date already reported.
    93. In response to EPSA, we clarify that RTO and ISO transactions 
do, in fact, reflect an agreement of the parties upon a price. Parties 
are legally bound by the terms of the relevant RTO or ISO tariff and 
sellers agree to sell a product at the price at which their offer is 
awarded. Although the price may be altered after it is awarded due to 
the application of mitigation or other RTO or ISO market rules, we 
clarify that the trade date should reflect the price at the time of the 
initial award. RTOs and ISOs operate a number of different markets 
where similar products are offered. For example, energy can be offered 
day-ahead or real-time. Capacity is offered monthly, annually and 
several years in advance. In each of these cases, the addition of a 
trade date will help the Commission and the public gain a better 
understanding of the market environment in which a given transaction 
was consummated.
    94. In response to Entergy's concern about hourly transactions 
being changed at a later date, we clarify that filers are expected to 
identify the price associated with the transaction as it was agreed to. 
If there is some disagreement or uncertainty between the parties 
regarding the terms of the transaction on the ``trade date,'' the 
Commission has promulgated a refiling policy to allow the selling party 
to correct those terms when the disagreement is settled or the 
uncertainty is eliminated. Correcting the reporting, however, does not 
change the fact that the reported transaction occurred because the 
parties to the transaction had agreed to something on a given date. 
That date would not change even if the parties' understanding of what 
they agreed to evolves.
    95. In addition, in response to EEI's suggestion that the 
Commission should hold a technical conference to discuss the 
requirement for trade date data, the Commission notes that it intends 
to convene a staff-led technical conference following issuance of this 
Final Rule, to be announced at a future date, to discuss the additional 
fields required under this Final Rule, including the field for trade 
date.
(b) Time of Trade
    96. Several commenters indicate concerns about the NOPR's proposal 
to require market participants to report the time of trade. Some 
commenters contend that the time of trade, defined in the NOPR as the 
time upon which parties agree upon the price of a transaction, can be 
difficult to identify definitively.\159\ Certain commenters argue that 
the time parties agree on price may not be the time the trade occurred 
or was finalized.\160\ For example, EDF Trading states that parties may 
agree to the price or pricing mechanism hours or even days before they 
come to an agreement regarding other material terms of the transaction, 
meaning that the time upon which parties agree upon the price of a 
transaction frequently will not correspond to the time at which parties 
execute or confirm that transaction.\161\
---------------------------------------------------------------------------

    \159\ See, e.g., EDF Trading at 7; EEI at 10-11; Entergy at 2-3; 
EPSA at 6-7; Pacific Northwest IOUs at 2; Westar at 2.
    \160\ See, e.g., EDF Trading at 7; EEI at 10-11; Entergy at 2-3; 
EPSA at 7.
    \161\ EDF Trading at 7.
---------------------------------------------------------------------------

    97. Several commenters also state that the actual price of a 
transaction may be subject to revision even after parties have reached 
agreement on the price.\162\ For example, Westar asserts that if a 
market participant is party to a liquidated damages contract and the 
transaction is curtailed, the party will not know the price of the 
contract until weeks after the power is delivered.\163\ Entergy states 
that rates for future transactions may be affected by changes in tariff 
rates and other circumstances between the time when the transaction was 
made and the date the transaction flows. Further, Entergy states that 
some hourly market sales may have final prices that are subject to 
review and agreement at a later date.\164\ Finally, EPSA states that 
the Commission needs to clarify whether RTO or ISO sales are included 
in the date/time reporting requirement as these transactions do not 
meet the Commission's proposed definition of agreement of the parties 
upon a price.\165\
---------------------------------------------------------------------------

    \162\ See, e.g., Entergy at 2-3; EPSA at 6-7; Westar at 3.
    \163\ Westar at 3.
    \164\ Entergy at 2-3.
    \165\ EPSA at 6 (``ISO/RTO mitigation schemes sometimes alter 
awarded prices, which are unknown to the market participant and are 
not received until substantially after the flow date.'').
---------------------------------------------------------------------------

    98. Some commenters also indicate that existing trade capture 
systems are not set up to capture the time of trade.\166\ For example, 
Powerex states that the time of trade is not currently recorded and 
significant work would be required to record time of trade, which would 
need to account for trades made verbally.\167\ EDF Trading states that 
under its existing systems and procedures, a trader gathers information 
regarding each transaction as he or she completes it, but does not 
enter the details of each transaction until later in the day when the 
trader has completed most trading activities. EDF Trading states that 
its electronic system creates a time stamp as soon as a trader enters a 
transaction and this system generates information reported in EDF 
Trading's EQRs. EDF Trading asserts that, if the

[[Page 61912]]

Commission requires market participants to report time of trade 
information, traders will be forced to interrupt their trading 
activities to enter each trade into the system electronically as soon 
as parties agree on pricing. According to EDF Trading, such a 
requirement would eliminate flexibility, reduce trading opportunities, 
potentially increase the bid/ask spreads, and impose additional time 
burden on traders during the trading day, the time of day when the 
markets are at their most active.\168\ Similarly, EPSA states that a 
new requirement to log times will inhibit desk personnel and frustrate 
liquid markets.\169\
---------------------------------------------------------------------------

    \166\ See, e.g., EDF Trading at 7-8; EEI at 9; Entergy at 1-2; 
EPSA at 5; Financial Institutions Energy Group at 7; Pacific 
Northwest IOUs at 2; Powerex at 14; Shell Energy at 8; Westar at 3.
    \167\ Powerex at 14.
    \168\ EDF Trading at 7-8.
    \169\ EPSA at 5.
---------------------------------------------------------------------------

    99. Financial Institutions Energy Group states that time of trade 
data may be prone to inaccuracies, noting that errors may arise from 
such factors as clocks that run slow or fast, clocks that are not 
synched, traders forgetting to look at the time or write it down, time 
zone confusions, and illegible handwriting. Financial Institutions 
Energy Group adds that the time on a time-stamped trade confirmation 
from a third party entity, such as a broker, cannot be independently 
verified.\170\
---------------------------------------------------------------------------

    \170\ Financial Institutions Energy Group at 8.
---------------------------------------------------------------------------

    100. EEI and Powerex urge the Commission not to apply the proposal 
to report time of trade to existing transactions. Powerex states that 
it has some transactions that will continue to be reported to the 
Commission for years to come and it is not sure how to identify the 
time of trade for these long-term transactions.\171\ Likewise, EEI 
suggests that the requirement should only apply prospectively for 
transactions entered into after the Commission adopts the final rule in 
this proceeding.\172\
---------------------------------------------------------------------------

    \171\ Powerex at 14.
    \172\ EEI at 13.
---------------------------------------------------------------------------

    101. EEI also suggests that the Commission hold a technical 
conference to: (1) Explore the need for time of trade or trade date 
data; (2) gain a better understanding of impacts on EQR filers and 
affected systems; and (3) ensure that any such reporting requirement is 
carefully tailored to maximize benefits while minimizing the burden on 
reporting entities.\173\
---------------------------------------------------------------------------

    \173\ Id. at 14.
---------------------------------------------------------------------------

(1) Commission Determination
    102. The Commission will not require the time of trade, as proposed 
in the NOPR. As noted in many comments, it may be difficult to specify 
definitively the time at which parties agreed upon the price of a 
transaction and the actual price of the transaction may be revised 
after parties have agreed on the price. In addition, certain commenters 
expressed concern that existing trade capture systems are not set up to 
capture the time of trade and such a requirement may impose additional 
time burden on market participants. In light of these comments, the 
Commission has determined not to require reporting of the time of 
trade.
(c) Type of Rate
    103. EEI questions the need for information regarding the type of 
rate for each transaction and contends that the specific nature of the 
rate involved in a transaction can already easily be determined using 
the Contract Service Agreement ID information provided in the EQR 
contract data. In addition, EEI argues that the burden of providing 
rate type information separately will outweigh its value and asserts 
that rate type information may be difficult to specify, will be of 
little use, could be misleading, and will cause errors.\174\ EEI states 
that, if the Commission requires rate type information, the Commission 
should allow substantial flexibility, recognizing the wide variety of 
rates currently in use.\175\
---------------------------------------------------------------------------

    \174\ In particular, EEI notes that reporting rate type will 
require EQR filers to determine: whether a formula rate with a gas 
or fuel index (or any other index that is not an energy or capacity 
price index) is an ``index'' or ``formula'' rate; what rate type to 
use for an exchange agreement; and what to report if a trade is a 
combination of types. Id. at 15.
    \175\ Id. at 14-15.
---------------------------------------------------------------------------

    104. Finally, EEI asks for clarification as to what type of rate 
would apply to the following examples: (1) A formula rate with a gas or 
fuel index (or any other index that is not an energy or capacity 
index); (2) a rate used for an exchange agreement where one party pays 
an additional charge in addition to supplying return energy; (3) a rate 
structure that goes up (and/or down) a stated amount each year; and (4) 
a formula that is tied to an RTO price, i.e., the greater of the RTO 
price or the contract price.\176\
---------------------------------------------------------------------------

    \176\ Id. at 15.
---------------------------------------------------------------------------

(1) Commission Determination
    105. The Commission adopts the NOPR proposal to require the type of 
rate by which the price was set for each transaction to be reported in 
EQR, with slight modifications to the terms used to describe the types 
of rates. Specifically, the names proposed in the NOPR, ``fixed 
price,'' ``formula,'' ``index,'' and ``RTO/ISO price'' will be changed 
to ``fixed,'' ``formula,'' ``electric index,'' and ``RTO/ISO,'' as 
discussed below. For many of the same reasons discussed above in 
relation to trade date, the Commission disagrees with EEI's assertion 
that the information provided in the EQR contract data is sufficient 
for the Commission to discern which transactions belong to which of the 
following four types of rates proposed: ``fixed,'' ``formula,'' 
``electric index,'' and ``RTO/ISO.'' The contract section of the EQR is 
incomplete in terms of identifying the manner in which the rate on a 
given transaction is calculated. Further, where a rate is detailed, the 
rate descriptions are entered as free-form text providing no 
opportunity to compare across similar transactions. For the many 
transactions without detailed rate descriptions, on the other hand, 
rate type will provide critical information not contained in the 
current filings.
    106. Obtaining information about the type of rate associated with 
each transaction is critical to understanding the role of transactions 
within the market. Like the trade date, rate type will allow interested 
parties to better understand the market context of a given transaction. 
For instance, was the price a fixed number that both parties agreed on 
or an indexed number that was determined by the market? This 
distinction is particularly important in identifying potential market 
manipulation where fixed price transactions may be used to affect 
larger, index-priced positions. For these reasons, the Commission will 
require types of rates to be reported in a separate field in the EQR. 
The type of rate should accompany each specific sales transaction and 
be reported in the EQR transaction section.
    107. EEI's comment that specifying the type of rate may be 
difficult for certain transactions is noted. To provide clarification, 
the following description will be referenced in the EQR Data Dictionary 
and one of the names of one of the rate type options will be changed. 
If the price is the result of an RTO/ISO market and the sale is made to 
the RTO/ISO, its rate type is ``RTO/ISO.'' If no variables are used to 
determine the rate, it should be marked as ``fixed.'' This would 
include transactions where the specific price is stated or a specific 
price with a predetermined escalator is provided (e.g., $35.00/MWh, 
increasing by 2 percent each year). Under a transaction classified with 
the rate type ``fixed,'' both parties would know on the trade date the 
exact price of the product(s) in that transaction.
    108. If the transaction uses an electric-based index in any way, 
either as a base price or as a means to determine a basis, it should be 
identified as an ``electric index.'' This represents a clarification 
from the NOPR which included the

[[Page 61913]]

broader rate type ``index.'' If the price in the transaction is 
otherwise determined by a formula, including a formula that uses 
indices that do not describe specific electric prices, such as a cost 
of living index or coal or natural gas prices, it should be designated 
as rate type ``formula.'' In summary, the Commission will adopt this 
field with the following limited list of rates that are appropriate for 
this field: ``fixed,'' ``formula,'' ``electric index'', and ``RTO/
ISO.''
b. Resale of Financial Transmission Rights in Secondary Markets
i. NOPR
    109. In the NOPR, the Commission declined to require entities to 
report information about financial transmission rights in the EQR.
ii. Comments
    110. The NOPR proposal not to collect information in EQRs about 
resales of financial transmission rights was supported by all who 
commented on the matter. EEI states that collecting this information 
would not significantly improve price transparency.\177\ Financial 
Institutions Energy Group states that the burden imposed by adding a 
new reporting requirement for FTR trades in secondary markets would not 
be justified by the minimal value of the data.\178\
---------------------------------------------------------------------------

    \177\ EEI at 8.
    \178\ Financial Institutions Energy Group at 4.
---------------------------------------------------------------------------

iii. Commission Determination
    111. As indicated in the NOPR, requiring financial transmission 
rights data to be reported by market participants in the EQR, in 
addition to the information already provided by RTOs and ISOs, would 
not significantly improve price transparency in these markets. Although 
little information is available on secondary sales of financial 
transmission rights, there is also little evidence of an active 
secondary market. For these reasons, the Commission will not require 
reporting of secondary sales of FTRs at this time, but will continue to 
monitor market developments if in the future such a requirement becomes 
necessary.
c. Standardizing the Unit for Reporting Energy and Capacity 
Transactions
i. NOPR
    112. In the NOPR, the Commission proposed to include a new field in 
the EQR transaction section to standardize the units for reporting 
energy and capacity within the EQR. Specifically, the Commission 
proposed to require a market participant to report energy transactions 
as $/MWh and capacity transactions as $/MW-month.
ii. Comments
    113. Financial Institutions Energy Group and Joint Market Monitors 
support the NOPR proposal to use standardized units of $/MWh and $/MW-
month for reporting energy and capacity transactions, 
respectively.\179\ Joint Market Monitors state that standardization 
will avoid the considerable time and resources spent by analysts to 
ensure than the units conform before conducting any meaningful 
analysis.\180\ Joint Market Monitors also state that, in some cases, 
the proposed standardization is needed so that the data reported can 
actually be utilized. Pennsylvania Commission supports the proposal to 
standardize units insofar as having common units for reporting energy 
and capacity will simplify data interpretation.\181\
---------------------------------------------------------------------------

    \179\ Financial Institutions Energy Group at 3-4; Joint Market 
Monitors at 5-6.
    \180\ Joint Market Monitors at 5-6. (stating that ``a 
substantial portion of bilateral capacity sales in the California 
ISO's markets have been reported without any indication of the 
amount of capacity (MW) covered by the sale,'' rendering such data 
``useless'').
    \181\ Pennsylvania Commission at 5.
---------------------------------------------------------------------------

    114. Several commenters recommend revisions or clarifications to 
the NOPR proposal to standardize units. EEI agrees that common units 
for reporting energy and capacity transactions would simplify 
interpretation of the data, but requests clarification that such 
conversion consist only of KWh to MWh and KW to MW (i.e., filers can 
still report transactions in MW-Month, MW-Day, KVA, MVAR, etc.). EEI 
also states that some entities report capacity in KVAR and other units 
that do not easily convert to MW and certain rates, such as backup 
rates, may not fit well with standard units. As such, EEI suggests that 
the Commission also allow reporting in alternative units while 
encouraging EQR filers to use standard units if logical and feasible. 
In addition, EEI notes that the Commission will likely have to increase 
the number of digits in the ``Rate'' field to accommodate reporting in 
MWh.\182\
---------------------------------------------------------------------------

    \182\ EEI at 16.
---------------------------------------------------------------------------

    115. Entergy asserts that it currently reports transactions in 
accordance with the units used in the underlying contracts; thus many 
of the transactions it reports would require translation to match the 
proposed standardization. Entergy suggests that the Commission consider 
modifying the EQR software to include an automatic conversion formula 
to reduce errors and inconsistencies that would result from each 
reporting entity developing its own conversions.\183\
---------------------------------------------------------------------------

    \183\ Entergy at 3.
---------------------------------------------------------------------------

iii. Commission Determination
    116. The Commission generally adopts the NOPR proposal to 
standardize the units for reporting energy and capacity sales within 
the EQR transaction section. In the NOPR, the Commission proposed to 
add a new field to capture a common unit for reporting energy and 
capacity transactions. However, instead of adding only one field, the 
Commission will include two new fields to the EQR transaction section 
and will require filers to standardize the units for reporting both 
prices and quantities for energy, capacity, and booked out power 
transactions within the EQR. Accordingly, filers must specify the 
quantity for energy in MWh and the price for energy in $/MWh. Filers 
must specify the quantity for capacity as MW-month and the price for 
capacity in $/MW-month. For booked out power transactions, filers must 
use the same quantity and price conventions associated with energy or 
capacity, as appropriate.
    117. Standardized units will provide greater transparency and 
facilitate the Commission's and public's ability to analyze EQR data. 
Specifically, with price and quantity expressed consistently across all 
filings, EQR filers and users will benefit from the increased ease of 
comparing data for analysis and quality control. The Commission notes 
that, in 2011, energy sales were reported in the EQR approximately 1 
percent of the time in units other than $/MWh and that capacity sales 
were reported in the EQR 86 percent of the time in units other than $/
MW-month. In the case of energy transactions, these statistics refute 
Entergy's assertion that many of the transactions reported in the EQR 
would require translation. In response to EEI's comment, we recognize 
that some entities currently do not report in units that can be easily 
converted to $/MWh for energy and $/MW-month for capacity, however, we 
note that such conversions are even more difficult, if not impossible, 
for entities not actually involved in the transaction, including the 
Commission and the public. The Commission will ensure the appropriate 
number of digits in the EQR software to accommodate the conversion.
    118. The Commission rejects Entergy's suggestion that having the 
EQR software do the data conversion would eliminate some of the 
potential

[[Page 61914]]

errors that might arise in having filers convert their own data from 
the units specified in the underlying contracts. There are many simple 
conversions that the EQR software could make. However, in certain 
instances, there may be insufficient information for the EQR software 
to accurately perform conversions. For example, capacity transactions 
are commonly reported in a ``flat rate'' price with a quantity of 
``one.'' Transactions reported in this manner do not provide sufficient 
information regarding the price of a transaction and do not allow for 
conversion to a standardized unit. Adding new fields that display 
standardized prices and quantities will address these issues.
d. Omitting the Time Zone From the Contract Section of the EQR
i. NOPR
    119. The Commission proposed to eliminate the Contract Time Zone 
(Field Number 45) from the EQR.
ii. Comments
    120. The NOPR proposal to eliminate time zone information in the 
contracts section was supported by those that commented on the 
matter.\184\ EEI states that time zone information is unnecessary and 
that eliminating it will reduce burden on filers.\185\
---------------------------------------------------------------------------

    \184\ See, e.g., EEI at 8-9; Financial Institutions Energy Group 
at 4.
    \185\ EEI at 8-9.
---------------------------------------------------------------------------

iii. Commission Determination
    121. The Commission agrees with commenters supporting the 
elimination of the Contract Time Zone (i.e., currently Field Number 45) 
from existing EQR requirements. We find that this information is 
unnecessary and its elimination will reduce filers' burden. The 
Commission will, however, continue to require EQR filers to report the 
time zone where the transaction took place in the transaction section 
(i.e., new Field Number 56).
2. Additional EQR Enhancements
a. Identify Transactions Reported to Index Publishers
i. NOPR
    122. The Commission proposed to require all market participants 
that are required to file an EQR to report in the transaction section 
of the EQR the particular electric or natural gas index price publisher 
to which they have reported their sales transactions, if applicable. 
The Commission also proposed to eliminate the requirement, under 18 CFR 
35.41(c), that a market-based rate seller notify the Commission whether 
it is reporting transactions to an electricity or natural gas index 
publisher.
ii. Comments
    123. DC Energy, Joint Market Monitors, and Pennsylvania Commission 
support the Commission's proposal to require all EQR filers to report 
in the transaction section of the EQR the index price publisher(s) to 
which they have reported their sales transactions.\186\ Joint Market 
Monitors state that information about reporting to an index publisher 
will assist transparency in pricing.\187\ Pennsylvania Commission 
states that such information is critical to better enable the 
Commission to understand how index prices are established and how 
market forces affect index prices.\188\
---------------------------------------------------------------------------

    \186\ See, e.g., DC Energy at 4-5; Joint Market Monitors at 4-5; 
Pennsylvania Commission at 5.
    \187\ Joint Market Monitors at 5.
    \188\ Pennsylvania Commission at 5.
---------------------------------------------------------------------------

    124. Other commenters assert that, if adopted, the proposal to 
identify every transaction reported to index publishers would result in 
a manual, burdensome process.\189\ For example, EEI states that not all 
trades are reported to index publishers and that information on whether 
a trade is reported is not usually captured on a trade-by-trade basis 
in company trade capture systems. As such, EEI states that this 
proposal would require significant changes to business processes and 
systems as well as create a disincentive for companies to report 
transactions to index publishers.\190\ EPSA states that the NOPR does 
not clearly state whether companies would report the names of 
publishers to whom they report generally or if they have to identify a 
publisher's name for every transaction that has been reported. EPSA 
argues that reporting the index publisher name for every transaction 
would be a difficult and expensive manual process.\191\
---------------------------------------------------------------------------

    \189\ See, e.g., EEI at 16-17; EPSA at 8-9; Financial 
Institutions Energy Group at 10; Shell Energy at 8-10.
    \190\ EEI at 16-17.
    \191\ EPSA at 8-9.
---------------------------------------------------------------------------

    125. Financial Institutions Energy Group suggests that the 
Commission clarify that reporting entities have no responsibility for 
how brokers or trading facilities may use their data. Specifically, 
Financial Institutions Energy Group contends that if a broker elects to 
publish a daily index using information from trades it completed on 
behalf of its customers, reporting entities cannot be responsible for 
disclosing such use in any reporting notice or for trying to discern 
which of their trades were or were not included in the index.\192\
---------------------------------------------------------------------------

    \192\ Financial Institutions Energy Group at 10.
---------------------------------------------------------------------------

    126. Certain commenters recommend alternatives to the Commission's 
proposal. EEI suggests an alternative proposal that would require an 
EQR filer to identify, in a general statement, the index publishers to 
which the filer provides transactional information and the types of 
transactions reported. Shell Energy similarly suggests that, instead of 
requiring sellers to identify the index developer to which a 
transaction was reported, the Commission could require that EQR filers 
reporting to index publishers make their reporting criteria available 
to the Commission.\193\ Financial Energy Institutions Group also urges 
the Commission to retain the practice of requiring sellers to alert the 
Commission on their reporting status at a more generalized level, and, 
if needed, require additional detail in a reporting status statement. 
In addition, Financial Institutions Energy Group proposes that the 
Commission could embed these status reports in the EQR, somewhat like 
it has in FERC Form 552 for natural gas trades.\194\
---------------------------------------------------------------------------

    \193\ Shell Energy at 10.
    \194\ Financial Institutions Energy Group at 9.
---------------------------------------------------------------------------

iii. Commission Determination
    127. The Commission will adopt the proposal in the NOPR to require 
all filers to report in the EQR the index price publisher to which they 
have reported their sales transactions, if applicable, with 
modifications. In light of comments by EPSA, EEI, Financial 
Institutions Energy Group and Shell Energy, expressing concern that 
identifying each applicable transaction in the transaction section 
would result in a manual and burdensome process, the Commission will 
allow index publisher information to be reported more generally, in the 
ID data section of the EQR, instead of on a transactional basis. 
Specifically, EQR filers should report in the ID data section of the 
EQR whether their transactions are reported to an index publisher, and 
if so, which index publisher(s). In addition, if EQR filers report 
specific types of transactions to index price publisher(s), they should 
specify the type(s) of transactions that they report.
    128. For the reasons stated in the NOPR, the Commission believes 
that requiring filers to identify the index price publishers in the EQR 
to which they report their wholesale sale transactions would provide 
the Commission, market participants, and the public with greater 
transparency

[[Page 61915]]

into the market forces affecting those index prices and the level of 
companies' sales used to calculate the index prices.\195\ In addition 
to market participants' significant use of index prices in contracting 
for sales in the physical electricity market, the use of index prices 
has expanded to forming settlement prices for financial products.\196\ 
Given that physical spot markets are used to settle financial swaps, 
there is an incentive to manipulate the physical markets to benefit 
larger financial positions.\197\ We find that greater transparency will 
further our understanding of how index prices are formed, thereby 
enhancing public confidence in their accuracy and reliability, 
improving the Commission's ability to monitor price formation in 
wholesale markets and potential exercises of market power and 
manipulation, and helping to ensure robust indices.\198\
---------------------------------------------------------------------------

    \195\ See NOPR, FERC Stats. & Regs. ] 32,676 at P 111.
    \196\ Id. P 112.
    \197\ For example, 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. The market participant could 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. See id.
    \198\ See id.
---------------------------------------------------------------------------

    129. Moreover, obtaining information from market participants, not 
only jurisdictional power sellers with market-based rate authorization 
from the Commission, about the sales reported to specific index 
publishers will strengthen the Commission's and public's ability to 
determine whether these index prices reflect market forces and provide 
market participants with greater confidence in the accuracy of index 
prices.\199\ Therefore, we will require each EQR filer to report in the 
ID Data section the particular index publisher to which they report 
transactions, if applicable, and specify the types of transactions 
reported to the index publisher(s), if applicable. To the extent an EQR 
filer identifies only the name of an index publisher(s) in the ID data 
section of the EQR, the Commission expects the index publisher(s) 
reported in the EQR to reflect the entity or entities to which the 
market participant is reporting all of its trades.
---------------------------------------------------------------------------

    \199\ Id. P 113.
---------------------------------------------------------------------------

    130. To eliminate redundancy between the EQR filings and the 
notification required under 18 CFR 35.41(c) from market-based rate 
sellers,\200\ we will 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. The Commission has 
attached a list of index price publishers in Appendix G that filers can 
choose from in a restricted data field. We acknowledge that the index 
price publisher list may change from time to time. Therefore, 
consistent with notification of changes to the list of entries for 
other restricted fields in the EQR, Commission staff will email all EQR 
filers any future changes to the list of entries contained in the index 
publisher fields and post these changes on the EQR page of the 
Commission's Web site.\201\ In addition, to assist the Commission in 
keeping the list of index publishers current, we expect filers to 
notify Commission staff by emailing eqr@ferc.gov if they begin 
reporting to an index publisher that is not listed in the EQR.
---------------------------------------------------------------------------

    \200\ Section 35.41(c) of the Commission's regulations, 18 CFR 
35.41(c), 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. Section 35.41(c) of 
the Commission's regulations, 18 CFR 35.41(c), 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. See Investigation of Terms and Conditions of Public 
Utility Market-Based Rate Authorizations, 105 FERC ] 61,218, at PP 
116-119 (2003).
    \201\ See Order No. 2001-G, 120 FERC ] 61,270 at P 5 (citing 
Revised Public Utility Filing Requirements, 106 FERC ] 61,281 
(2004)).
---------------------------------------------------------------------------

    131. Since the requirement to identify index publishers is intended 
to reveal transactions that affect other index-based market instruments 
(e.g., transactions that settle using a published index price), the 
Commission will clarify, as requested by Financial Institutions Energy 
Group, that it will not apply to broker-published indices that are 
provided to the broker's clients. Finally, we clarify at Financial 
Institutions Energy Group's request, that the Commission is not 
requiring EQR filers to track, and report on, how brokers or trading 
facilities are using data from their transactions. However, we will 
require EQR filers to report which transactions were consummated using 
an exchange or broker service, as discussed below.\202\
---------------------------------------------------------------------------

    \202\ See discussion infra at Sec.  II.B.2.b.
---------------------------------------------------------------------------

b. Identify the Exchange/Broker Used to Consummate a Transaction
i. NOPR
    132. The Commission proposed to require market participants to 
report in the EQR whether a market participant used an exchange or a 
brokerage service to consummate a transaction.
ii. Comments
    133. DC Energy, Joint Market Monitors, and Pennsylvania Commission 
support the Commission's proposal to require all EQR filers to report 
information regarding whether exchanges or brokers were used to 
consummate a transaction.\203\ In particular, Joint Market Monitors 
state that information about the involvement of brokers will assist in 
understanding the complicated relationship between Commission-
jurisdictional markets and closely-related financial markets.\204\ As 
with the proposal above to obtain information about index publishers, 
Pennsylvania Commission states that information about brokers and 
exchanges is critical to better enable the Commission to understand how 
index prices are established and how market forces affect index 
prices.\205\
---------------------------------------------------------------------------

    \203\ See, e.g., DC Energy at 4-5; North American Market 
Monitors at 4-5; Pennsylvania Commission at 5.
    \204\ North American Market Monitors at 5.
    \205\ Pennsylvania Commission at 5.
---------------------------------------------------------------------------

    134. EEI and EPSA state that broker and exchange information is not 
currently collected by most trade capture systems, so modification of 
the systems in order to meet the proposed requirement would add a 
significant burden.\206\ However, Financial Institutions Energy Group 
states that its members generally capture broker and trading platform 
information for each trade in their trade capture systems.\207\
---------------------------------------------------------------------------

    \206\ EEI at 17; EPSA at 10.
    \207\ Financial Institutions Energy Group at 11.
---------------------------------------------------------------------------

    135. Several commenters assert that publicly reporting the name of 
the broker \208\ or exchange \209\ used to conduct a transaction may 
raise confidentiality concerns. EEI, EPSA and Financial Institutions 
Energy Group state that, depending on contractual terms, market 
participants may not have the ability to publicly disclose the name of 
a broker that was used or which transactions used a broker.\210\ EEI 
states that revealing a broker's identity could lead to unwelcome 
solicitations by other brokers seeking new business.\211\ To address 
confidentiality concerns, EEI and Financial Institutions Energy Group 
suggest that the Commission allow market participants to file their 
EQRs with a request for confidential treatment

[[Page 61916]]

when needed to avoid breaching confidentiality obligations.\212\
---------------------------------------------------------------------------

    \208\ See, e.g., EEI at 17; EPSA at 9-10; Financial Institutions 
Energy Group at 11.
    \209\ Financial Institutions Energy Group at 11.
    \210\ EPSA at 9; Financial Institutions Energy Group at 11.
    \211\ EEI at 17-18.
    \212\ EEI at 17-18; Financial Institutions Energy Group at 11.
---------------------------------------------------------------------------

    136. Finally, several commenters suggest clarifications to the 
Commission's proposal. EEI suggests that if the Commission does decide 
to collect information on broker and exchange use in the EQR, having a 
standardized list of codes for the exchange and brokers would help 
simplify reporting and analysis.\213\ EPSA states that the Commission 
should clarify what specifically constitutes ``use.'' \214\ Financial 
Institutions Energy Group notes that it assumes the NOPR's reference to 
``exchanges'' refers to trading platforms like ICE.\215\
---------------------------------------------------------------------------

    \213\ EEI at 8.
    \214\ EPSA further states that in the NOPR, ``use'' of a broker 
could be construed as specifically using a broker's index to set the 
price of a transaction. Conversely, entities can also use a broker, 
EPSA states, without necessarily basing the price of the transaction 
on a broker index. EPSA at 10-11.
    \215\ Financial Institutions Energy Group at n.28.
---------------------------------------------------------------------------

iii. Commission Determination
    137. The Commission adopts, with modification, the NOPR proposal to 
require EQR filers to report whether an exchange or broker was used to 
consummate a transaction. As stated in the NOPR, exchanges and brokers 
routinely publish index prices composed of wholesale sale transactions 
that were consummated on their exchange or through their brokerage 
services.\216\ Indices published by exchanges and brokers are used by 
market participants in contracting for sales in the physical 
electricity market and as a settlement price associated with financial 
products. By adding transparency as to how these indices are created, 
the Commission and the public will be able to better understand how 
these indices arrive at their published prices, thereby increasing 
public confidence in the indices, improving the Commission's ability to 
monitor price formation in wholesale markets and potential exercises of 
market power and manipulation, and helping to ensure robust indices.
---------------------------------------------------------------------------

    \216\ NOPR, FERC Stats. & Regs. ] 32,676 at P 114.
---------------------------------------------------------------------------

    138. For purposes of this rulemaking, we clarify that the term 
``use'' of an exchange or broker encompasses instances where the 
exchange's or broker's services were used to consummate or effectuate a 
transaction. The term ``use'' does not cover instances where an index 
developed by an exchange or broker is used to identify or set the price 
for a transaction. We also clarify that ``exchanges'' refer to trading 
platforms like ICE or NYMEX. In addition, the Commission will provide a 
standardized list of codes for exchanges for EQR filers to use, as 
suggested by EEI. This list is included in Appendix H of the EQR Data 
Dictionary.
    139. Certain commenters argue that publicly reporting the name of 
the broker or exchange may raise confidentiality concerns and suggest 
that the Commission allow requests for confidential treatment when 
market participants file EQRs. The transparency provisions of FPA 
section 220 require the Commission to balance the need to disseminate 
information to the public with concerns about confidentiality. The 
Commission must comply with Congress' directive that the rules to 
facilitate price transparency ``provide for the dissemination, on a 
timely basis, of 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.'' \217\ However, the 
Commission must also ``seek 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 transaction-specific information.'' \218\ 
Requiring filers to identify whether an exchange or broker was used to 
consummate a transaction provides for public dissemination of data that 
facilitates price transparency. We determine that the 30-day time delay 
after each calendar quarter in filing EQRs should prevent collusion or 
other anticompetitive behaviors that can result from untimely public 
disclosure of transaction-specific information. This finding is 
consistent with the Commission's determination in Order No. 2001 that 
the 30-day time delay in the filing of transaction-specific information 
in the EQR ``will greatly reduce the usefulness of the data as a tool 
for collusion.'' \219\ Therefore, we find that the Commission has 
appropriately balanced the need for transparency with confidentiality 
concerns and, thus, we will not allow market participants to request 
confidential treatment for their EQR filings.
---------------------------------------------------------------------------

    \217\ 16 U.S.C. 824t(a)(2).
    \218\ Id. 824t(b)(2).
    \219\ Order No. 2001, FERC Stats. & Regs. ] 31,127 at PP 17, 
122; see also Order No. 2001-A, 100 FERC ] 61,074 at PP 19-21.
---------------------------------------------------------------------------

    140. Given the use of exchanges in contracting for sales of 
electricity in physical markets and as a settlement price associated 
with financial products, we will require EQR filers to identify in the 
EQR the exchange used to consummate a transaction on a transactional 
basis. However, because broker-produced indices appear to be used less 
prevalently at this time by market participants and in light of 
commenter concerns that revealing the identity of a broker may 
encourage unwanted solicitation by brokers, the Commission will not 
require the names of the brokers to be disclosed. Instead, if a broker 
is utilized to consummate a transaction, the term ``BROKER'' shall be 
selected from the Commission-provided list in Appendix H of the EQR 
Data Dictionary.
    141. Although EEI and EPSA indicate that broker and exchange 
information is not currently collected by most trade capture systems, 
we note that Financial Institutions Energy Group comments that its 
members generally collect this information. We expect that, on balance, 
the benefit of transparent pricing should outweigh the burden 
associated with developing automated systems to capture this data.
    142. We acknowledge that the list of exchanges may change from time 
to time. Therefore, consistent with the notification of changes to the 
list of entries for other restricted fields in the EQR, Commission 
staff will email all EQR filers any future changes to the list of 
entries to the exchange fields and post these changes on the EQR page 
of the Commission's Web site.\220\ In addition, to assist the 
Commission in keeping the list of exchanges current, we expect filers 
to notify Commission staff by emailing eqr@ferc.gov if they begin 
reporting to an exchange that is not listed in the EQR.
---------------------------------------------------------------------------

    \220\ See Order No. 2001-G, 120 FERC ] 61,270 at P 5 (citing 
Revised Public Utility Filing Requirements, 106 FERC ] 61,281 
(2004)).
---------------------------------------------------------------------------

c. Collection of e-Tag ID Data
i. NOPR
    143. The Commission proposed to require market participants to 
submit e-Tag IDs for each transaction reported in the EQR in the event 
an e-Tag is used to schedule the transaction.
ii. Comments
    144. DC Energy, Joint Market Monitors, and Pennsylvania Commission 
support the Commission's proposal to require EQR filers to submit e-Tag 
IDs for each transaction reported in the EQR if an e-Tag is used to 
schedule the transaction.\221\ However, as

[[Page 61917]]

detailed below, some other commenters oppose the proposal.
---------------------------------------------------------------------------

    \221\ See, e.g., DC Energy at 4-5; Joint Market Monitors at 4-5; 
Pennsylvania Commission at 5.
---------------------------------------------------------------------------

(a) Burdens
    145. Some commenters oppose the proposal based on anticipated 
burdens associated with inclusion of e-Tag IDs in the EQR.\222\ EDF 
Trading anticipates that this new requirement could add as much as 
eight hours of additional work each day, or a full-time equivalent 
employee, and would require additional technology investments.\223\ 
EPSA states that the proposal would require significant, if not 
exorbitant, system modifications; their members have reported that, at 
a minimum, two or more full-time employees may need to be hired to 
properly compile e-Tag data.\224\ Financial Institutions Energy Group 
notes that e-Tag IDs are not included in their trade capture systems; 
therefore, matching e-Tag IDs and individual transactions would raise 
significant information technology, manual intervention and 
reconciliation concerns. Financial Institutions Energy Group's members 
conservatively estimate that complying with the NOPR proposals, with e-
Tags accounting for the greatest expenditures, would cost between 
$55,000 and $400,000 per company to implement and between $2,500 and 
$10,000 per company each quarter.\225\ Commenters also state that one 
utility has estimated that the proposed e-Tag ID data could require 
that company to hire two to three or more new full-time personnel to 
extract, review, and report the data, ultimately, at ratepayer 
expense.\226\ Joint Commenters and LPPC also note that they are unaware 
of any available off-the-shelf software that could perform this 
function and that contracting with a software developer would likely be 
a multi-million dollar proposition.\227\
---------------------------------------------------------------------------

    \222\ See, e.g., EDF Trading at 6; EPSA at 17; Entergy at 3; 
Financial Institutions Energy Group at 16; Joint Commenters at 4; 
LPPC at 12-13; Pacific Northwest IOUs at 2-3; Shell Energy at 5.
    \223\ EDF Trading at 6.
    \224\ EPSA at 17.
    \225\ Financial Institutions Energy Group at 16.
    \226\ EPSA at 17; Joint Commenters at 4; LPPC at 12-13.
    \227\ Joint Commenters at 4; LPPC at 13.
---------------------------------------------------------------------------

(b) Implementation Issues
    146. Some commenters assert that e-Tag IDs would not be easy to 
match with individual transactions.\228\ EDF Trading argues that e-Tags 
do not reflect transactions; they reflect the culmination of 
transactions.\229\ Westar states that there can be multiple e-Tags for 
any given trade and, if the Commission imposes this requirement, what 
is now a single line of data in the EQR will become multiple lines of 
data, substantially increasing the volume and burden of the reporting 
requirement for market participants. Similarly, Financial Institutions 
Energy Group states that transactions and schedules may not always 
align because a particular trade may be associated with more multiple 
e-Tags.\230\
---------------------------------------------------------------------------

    \228\ See, e.g., EDF Trading at 3-4; EPSA at 16; Financial 
Institutions Energy Group at 12; Joint Commenters at 3-5; LPPC at 
12-13; Pacific Northwest IOUs at 2; Powerex at 5-10; Shell Energy at 
6-7; TAPS at 16-17; Ronald Rattey at 11-13; Westar at 4-5.
    \229\ EDF Trading at 3.
    \230\ Westar at 4.
---------------------------------------------------------------------------

    147. Powerex contends that compliance with the EQR proposal with 
respect to e-Tags would constitute a dramatic change in industry 
practice for many market participants because each trade would be 
required to be represented with one e-Tag. Powerex adds that such a 
major change would have significant consequences, including a dramatic 
reduction in market efficiency.\231\
---------------------------------------------------------------------------

    \231\ Powerex at 10.
---------------------------------------------------------------------------

    148. TAPS states that joint action agencies' and G&T cooperatives' 
use of network transmission service or secondary network transmission 
service to deliver resources to dispersed network loads may produce 
confusing results when filed with an e-Tag ID in EQR. For instance, 
TAPS asserts that if a joint action agency's resource is supplying 
multiple members' loads located in a different Balancing Authority, one 
e-Tag may be used to transfer power between Balancing Authority Areas 
and would not identify the particular loads being served or the 
quantities of power being served to those loads.\232\
---------------------------------------------------------------------------

    \232\ TAPS at 16-17.
---------------------------------------------------------------------------

    149. Some commenters state that the Commission's proposal to 
require EQR filers to submit e-Tag IDs in the EQR would result in an 
incomplete picture because not all transactions are scheduled using e-
Tags.\233\ TAPS states that the resulting reporting of e-Tag ID 
information for only a subset of sales will cause confusion rather than 
enhance transparency. According to TAPS, the absence of e-Tag data for 
transactions within a Balancing Authority Area severely limits the 
utility of requiring and reporting of e-Tag data for interchange 
transactions.\234\
---------------------------------------------------------------------------

    \233\ See, e.g., EDF Trading at 3; Entergy at 3-4; Financial 
Institutions Energy Group at 13 (``e-Tags are not created for 
movements within Balancing Authorities, but rather for movements 
between them.''); LPPC at 12; NRECA at 19; TAPS at 15-17.
    \234\ TAPS at 15-16.
---------------------------------------------------------------------------

    150. Some commenters mentioned that e-Tag and transaction 
information is captured by different systems and by separate personnel, 
complicating compliance with the Commission's proposal.\235\ For 
example, Financial Institutions Energy Group states that the functions 
of scheduling and trading are performed at different times and by 
different personnel, so that the path used to schedule and tag a 
specific flow does not always indicate what may have motivated the 
trader to execute the trade.\236\
---------------------------------------------------------------------------

    \235\ See, e.g., Entergy at 3; EPSA at 14-15; Financial 
Institutions Energy Group at 12-14; Joint Commenters at 5; LPPC at 
14; Ronald Rattey at 11-13; Shell Energy at 5.
    \236\ Financial Institutions Energy Group at 12.
---------------------------------------------------------------------------

    151. Joint Commenters and LPPC are concerned that the burdens of 
reporting e-Tag IDs will outweigh the value of such information. They 
note that power sales contracts typically specify a point of delivery, 
which already is reported in the EQR. Further, they state that most 
power sales contracts do not specify source or sink information (thus, 
such information is not typically collected in trade capture systems) 
because that information is not needed for market participants to 
negotiate a transaction and agree on its terms.\237\
---------------------------------------------------------------------------

    \237\ Joint Commenters at 3; LPPC at 11-12.
---------------------------------------------------------------------------

    152. Some commenters also mentioned that certain parties may not be 
privy to e-Tag data.\238\ As EDF Trading states, a market participant 
in the middle of the path would report the transaction on its EQR, but 
may not have recorded the e-Tag information and, as such, would not be 
able to report it. Also, EDF Trading states, if a counterparty is 
inadvertently omitted from a multiple party transaction e-Tag, the 
market participant may be unable to view the e-Tag.\239\ EPSA similarly 
states that in many cases, the seller does not have direct access to e-
Tag data because the seller is not involved in scheduling.\240\
---------------------------------------------------------------------------

    \238\ See, e.g., EDF Trading at 3-5; EPSA at 13-14; Westar at 5.
    \239\ EDF Trading at 5.
    \240\ EPSA at 13.
---------------------------------------------------------------------------

    153. EPSA also states that e-Tag data may be commercially 
sensitive. Specifically, EPSA contends that if e-Tag information is 
made public it would allow a competitor to trace the supply sources 
used for specific customers and use that information to lure the 
customer away from the supplier. EPSA also argues that e-Tag data 
typically includes multiple counterparties and, as such, e-Tag data is 
not only commercially sensitive but most contracts do not allow the 
release of data regarding counterparties.\241\
---------------------------------------------------------------------------

    \241\ Id. at 17.

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[[Page 61918]]

    154. Several commenters propose modifications to or clarifications 
of the NOPR proposal. Shell Energy suggests that, if the Commission 
ultimately decides to adopt the proposal to include e-Tag IDs in the 
EQR, it should limit this requirement to real-time transactions. 
According to Shell Energy, excluding long-term transactions for which 
numerous e-Tag IDs could be generated without a substantive difference 
in the transaction itself would reduce the reporting burden.\242\ MISO 
seeks clarification from the Commission that the requirement to provide 
e-Tag data as part of the EQR is in fact limited to market participants 
and is inapplicable to RTOs and ISOs.\243\ MISO comments that a 
potential inaccuracy in reporting e-Tag data could arise if it is 
required to report this information. Although MISO provides its market 
participants with transaction files containing the net position of 
import and export schedules at a given node, MISO states that a market 
participant may have several import and export schedules at a given 
node with each schedule having its own e-Tag, which is reported as only 
one net transaction in the EQR file. Therefore, according to MISO, if 
it were required to provide e-Tag IDs as required transaction data, 
MISO would report each schedule as a separate transaction in the EQR 
file, rather than a net position, thereby overstating the market 
participant's net position.
---------------------------------------------------------------------------

    \242\ Shell Energy at 7.
    \243\ MISO at 4.
---------------------------------------------------------------------------

    155. Finally, Shell Energy states that the proposal to include e-
Tag ID data in the EQR is unnecessary because the Commission is 
proposing to receive that data from the North American Electric 
Reliability Corporation (NERC) in the rulemaking proceeding in Docket 
No. RM11-12-000.\244\
---------------------------------------------------------------------------

    \244\ Shell Energy at 6 (citing Availability of E-Tag 
Information to Commission Staff, Notice of Proposed Rulemaking, FERC 
Stats. & Regs. ] 32,675 (2011) (E-Tag Availability Rulemaking)).
---------------------------------------------------------------------------

iii. Commission Determination
    156. As stated in the NOPR, e-Tags are used to schedule physical 
interchange transactions and contain information about 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 
specified details regarding which transmission paths are used.\245\ The 
e-Tag ID is a subset of information associated with a full e-Tag that 
consists of four components: (1) Source Balancing Authority Entity 
Code; \246\ (2) Purchasing-Selling Entity Code; \247\ (3) e-Tag Code or 
Unique Transaction Identifier; \248\ and (4) Sink Balancing Authority 
Entity Code.\249\ The Commission will adopt its NOPR proposal to 
require EQR filers to submit e-Tag IDs for each transaction reported in 
the EQR if an e-Tag was used to schedule the transaction. Filers should 
report in the EQR the e-Tag ID matched up to the Transaction Unique 
Identifier, Field No. 50 along with the start and end dates for the 
tags, as noted in Attachment A, EQR Data Dictionary.
---------------------------------------------------------------------------

    \245\ NOPR, FERC Stats. & Regs. ] 32,676 at P 115.
    \246\ The Source Balancing Authority is the Balancing Authority 
in which the generation is located.
    \247\ 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 operation services.
    \248\ 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.
    \249\ The Sink Balancing Authority is the Balancing Authority in 
which load is located.
---------------------------------------------------------------------------

    157. The Commission is cognizant of an increased burden associated 
with a requirement to match transactions with associated e-Tag IDs in 
the EQR. We find that, on balance, this burden is justified given the 
importance of this information for facilitating price transparency in 
jurisdictional markets. Requiring e-Tags as part of the EQR will allow 
the Commission to fill a significant gap in the existing EQR 
information by enabling the identification of linked transactions and 
the source location of wholesale sales transactions. Using the current 
EQR information, it is difficult to identify linked re-sales or chains 
of transactions between filers. By identifying separate transactions 
that share e-Tag IDs and delivery timeframes, the Commission and the 
public will be able to better understand the links and chains between 
transactions.\250\ Therefore, accessing e-Tag IDs through the EQR will 
facilitate price transparency by enabling all market participants and 
the Commission to ``follow'' transactions across markets.
---------------------------------------------------------------------------

    \250\ For example, the Commission and the public 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.
---------------------------------------------------------------------------

    158. Furthermore, the mark-ups observed for linked transactions are 
a valuable indicator of competitiveness in the wholesale market. 
Specifically, one would expect the arbitrage value to be closely 
associated with the cost to secure transmission between the linked 
transaction delivery points. Persistent price differences that are not 
consistent with transmission costs could indicate an opportunity for 
market participants to participate economically in that market or it 
could indicate a market inefficiency that needs to be addressed. 
Without knowing where power is being generated, it is difficult to 
determine whether an interchange transaction is the result of 
competitively arbitraging price separations between markets or anti-
competitive or manipulative behavior.
    159. In addition, since there is currently no way to connect 
wholesale sales in the bilateral markets to their source generation 
through public data or data available to the Commission, it is 
difficult to identify the economic value of transmission usage, 
particularly outside of RTO and ISO markets. For example, when 
transmission is curtailed, there is no way for the Commission or the 
public to understand the economic impact of curtailment to the 
customer. Production cost studies estimate the effect of transmission 
curtailments through an idealized representation of economic dispatch, 
which is not reflective of the actual value of the curtailed 
transactions. Knowledge of the actual market value of transmission 
service between two regions would reveal more precisely the true value 
of increasing transmission capacity. This increased market transparency 
would both signal the need for new transmission investment and aid 
regional transmission planning. For example, revealing differences in 
relative value would help stakeholders prioritize the selection of 
competing transmission projects within regional planning debates. 
Having the tools to reveal the actual market value of transmission 
service also could be used by stakeholders to justify, and the 
Commission to evaluate, transmission cost allocation proposals. Where 
the difference in wholesale energy prices at source and sink exceeds 
the cost of delivery through transmission service, net economic gains 
can be directly tied to the availability and use of transmission 
deliveries.
    160. Requiring e-Tag IDs could further aid in the identification of 
loop flows (unscheduled flows). To the extent that energy is delivered 
using complex contract paths, one would expect some degree of 
unscheduled flows. However, Balancing Authorities typically only have 
access to e-Tags that source, sink or wheel through their Balancing 
Authority Areas. As such, a Balancing

[[Page 61919]]

Authority may not see unscheduled flows through their Balancing 
Authority Area from interchange schedules that do not source, sink or 
wheel through their Balancing Authority Area (and thus are invisible to 
them). Requiring e-Tag IDs in the EQR would allow entities to identify 
interchange schedules that are affecting their system. Balancing 
Authorities and others could then use EQR data after the fact to help 
identify if some of these schedules corresponded to instances of 
unscheduled flows through their Balancing Authority Area. This 
knowledge could help them address instances of unscheduled flows in the 
future and allow staff to evaluate more fully the merits of related 
proposals.
    161. Given the range of productive uses for this information, the 
Commission concludes that requiring EQR filers to submit e-Tag IDs in 
the EQR is necessary and appropriate for the dissemination of 
information about the availability and prices of wholesale electric 
energy and transmission service.\251\ The Commission acknowledges 
commenters' concerns that requiring EQR filers to submit e-Tag IDs in 
the EQR could result in an incomplete picture for a particular 
transaction because not all transactions are scheduled using e-Tags. 
However, it does not follow that the Commission should not require the 
submission of e-Tag IDs for those transactions that are scheduled using 
e-Tags. Moreover, the Commission finds that the absence of an e-Tag ID 
itself provides valuable information to the Commission and the public 
regarding the nature of the transaction. For instance, e-Tags are not 
generally used for energy schedules that are contained within one 
Balancing Authority Area. If a transaction is not scheduled using e-
Tags, the filer would leave those fields blank. The EQR currently has 
several fields that may be left blank because they do not apply. If the 
e-Tag ID fields are left blank, then we would assume that they there is 
no e-Tag associated with the sale to report.
---------------------------------------------------------------------------

    \251\ 16 U.S.C. 824t(a)(2).
---------------------------------------------------------------------------

    162. In response to concerns about the difficulty of aligning e-Tag 
IDs to a particular transaction given the one-line per transaction 
format in the current EQR database, the Commission is making technical 
changes to the existing EQR database to accommodate the relationships 
between a transaction(s) and associated e-Tag ID(s). The Commission 
recognizes that there may not be a one-to-one relationship between a 
transaction reported in the EQR and the e-Tag ID(s) associated with 
that particular transaction. Therefore, the Commission will design, as 
seen in Attachment A, a separate EQR database table to accommodate the 
possibility of a one-to-many, many-to-one, or many-to-many relationship 
between a transaction(s) and associated e-Tag ID(s). The Commission 
will incorporate these technical changes to the EQR database before 
this requirement is implemented. In addition, the Commission may 
provide guidance on how to match e-Tag IDs to specific transactions in 
the EQR, to the extent filers seek such guidance.
    163. Regarding Shell Energy's request for clarification that long-
term transactions should be excluded from an e-Tag ID requirement, we 
find that requiring e-Tag IDs for only short-term transactions would 
not achieve the Commission's transparency goals in this proceeding. 
Specifically, long-term contracts commonly do not include source 
location details. Instead, the transaction source location may be 
determined every day based on economics and operating conditions of the 
system. Accordingly, we find that including e-Tag ID details for all 
applicable transactions, regardless of duration, would benefit the 
Commission and other users of the EQR. In response to MISO, we clarify 
that the requirement to provide e-Tag IDs associated with transactions 
is imposed on market participants rather than RTOs and ISOs. However, 
as noted in Order No. 2001, RTOs and ISOs may file power sales 
transaction information on behalf of their members or market 
participants as an agent, if authorized to do so by the member or 
market participant.\252\ MISO expresses concern about compiling reports 
for market participants with transactions and associated e-Tag IDs 
because market participants may have several import and export 
schedules at a given node, with each schedule having its own associated 
e-Tag ID, being reported as only one net import/export transaction in 
the EQR. As discussed above, the Commission will make design changes to 
the existing EQR database structure that can accommodate multiple 
schedules with multiple associated e-Tag IDs. We believe this will 
enable MISO to continue to compile reports for market participants with 
multiple transactions and associated e-Tag IDs, if requested by market 
participants to do so.
---------------------------------------------------------------------------

    \252\ Order No. 2001, FERC Stats. & Regs. ] 31,127 at P 336.
---------------------------------------------------------------------------

    164. Certain commenters state that they may not be privy to e-Tag 
data, they may be omitted from a multiple party transaction if they are 
in the middle of the path, or they may be sellers that did not schedule 
a transactions and thus lack access to the e-Tag. We note that the 
NAESB Electronic Tagging Functional Specifications,\253\ governing the 
implementation of the e-Tag process, specify that the e-Tag must 
contain the entities along the path associated with the tracking of 
title and responsibility. In particular, Section 2.6.1.1 (Submitting a 
New e-Tag Request) of the Functional Specifications provides that the 
``e-Tag Author must write a complete representation of the transaction 
as defined in NERC/NAESB Standards and supported in Section 6, Data 
Model Overview.'' Section 6.1.2.2 (Title Transfers) of the Functional 
Specifications specifies that the market segments of an e-Tag 
``represent those portions of the path that are associated with the 
tracking of title and responsibility.'' Therefore, the Commission 
expects that market participants would be able to access e-Tags 
associated with their transactions even if the market participant is in 
the middle of the path or does not necessarily schedule a transaction.
---------------------------------------------------------------------------

    \253\ E-Tags are implemented through the requirements set forth 
in the NAESB Electronic Tagging Functional Specifications, Version 
1.8.1 (Oct. 27, 2009). The NAESB Wholesale Electric Quadrant (WEQ) 
Business Practice Requirement 004-2 states that the ``primary method 
of submitting the Request for Interchange (RFI) to the Interchange 
Authority shall be an e-Tag using protocols in compliance with the 
Electronic Tagging Functional Specification, Version 1.8.'' See 
NAESB Wholesale Electric Quadrant (WEQ) Business Practice Standards 
(Version 002.1), published March 11, 2009.
---------------------------------------------------------------------------

    165. Contrary to EPSA's comments, we do not find that the e-Tag IDs 
required to be reported under this Final Rule contain confidential 
information. As described above, the e-Tag ID information required to 
be provided under this Final Rule is only a subset of the information 
contained in a complete e-Tag. In particular, e-Tag IDs capture the 
following information: The source Balancing Authority in which 
generation is located; a unique transaction identifier assigned by the 
e-Tag system when transmission service to accommodate the transaction 
is reserved; and the sink Balancing Authority in which load is located. 
By revealing the Balancing Authority from where the power originated, 
the e-Tag ID is not revealing information about specific supply sources 
or generators, as suggested by EPSA. Furthermore, we note that the e-
Tag ID information required to be filed under this Final Rule 
identifies only one party, i.e., the author of the tag, or Purchasing-
Selling Entity. The e-Tag ID does not, as suggested by EPSA, reveal 
multiple

[[Page 61920]]

counterparties. For these reasons, the Commission believes that the 
information contained in e-Tag IDs is not confidential.
    166. Shell Energy asserts that requiring e-Tag IDs under this Final 
Rule is unnecessary because the Commission proposes to receive e-Tag 
information in the E-Tag Availability Rulemaking. However, there are 
key differences between the requirement under this Final Rule for EQR 
filers to provide e-Tag ID information and the proposal for Commission 
staff to obtain complete e-Tags in the E-Tag Availability Rulemaking. 
Under this Final Rule, EQR filers must match up a specific transaction 
with a particular e-Tag ID, if applicable. By matching up the e-Tag ID 
with specific pricing information captured by the EQR, market 
participants would be able to identify the source location of a 
transaction because one component of the e-Tag ID is the source 
Balancing Authority where the power originated. EQRs currently capture 
only the delivery location of transactions. By revealing the source and 
sink locations of transactions, the EQR will allow the Commission and 
the public to see the path that the transaction took. This knowledge of 
the transaction path will help improve the ability of market 
participants and the Commission to determine the actual market value of 
transmission service and to identify scheduled paths that appear 
inconsistent with physical flows.
    167. In contrast to this Final Rule's requirement for filers to 
provide e-Tag IDs in the EQR, the Commission proposes in the E-Tag 
Availability Rulemaking to obtain market participants' complete e-Tags. 
A complete e-Tag contains not only e-Tag IDs, but also information 
about transmission reservations, firmness, and transmission 
curtailments. The complete e-Tags would be made available to Commission 
staff, not the public, because they may contain commercially sensitive 
information.
d. Eliminating the DUNS Number Requirement
i. NOPR
    168. The Commission proposed to eliminate the DUNS number 
requirement from EQR filings.
ii. Comments
    169. Some commenters support the Commission's proposal to eliminate 
DUNS identification from the EQR.\254\ EEI strongly supports the 
Commission's proposal to eliminate DUNS numbers from EQR because DUNS 
numbers have not proven to be a unique method to identify market 
participants.\255\ Financial Institutions Energy Group states that its 
members have expended tremendous resources trying to determine the 
correct DUNS numbers to use. Financial Institutions Energy Group also 
suggests that future attempts to rely on counterparty identifiers 
should not be pursued unless the Commission is certain that only one 
such identifier will apply to each entity and that such an identifier 
is readily available to any entity with an EQR reporting 
obligation.\256\
---------------------------------------------------------------------------

    \254\ See, e.g., EEI; Entergy; Financial Institutions Energy 
Group; North American Market Monitors; Powerex; Shell Energy.
    \255\ EEI at 9.
    \256\ Financial Institutions Energy Group at 4-5.
---------------------------------------------------------------------------

    170. Certain commenters suggest that the Commission replace DUNS 
with another system that allows for the unique identification of 
companies. DC Energy states that without either a DUNS number or some 
other mandatory uniform unique identifier, inconsistent reporting of 
company names in EQR would make it difficult to cross-reference across 
separate filers and/or periods.\257\ Entergy proposes to report the 
name of the entity exactly as it appears on the reported contract in 
both the contract and transaction reports.\258\ Joint Market Monitors 
consider it very important that the EQR permit ready and exact 
identification of the transacting parties and propose that filing 
parties report the precise legal name under which the participant is 
organized.\259\
---------------------------------------------------------------------------

    \257\ DC Energy at 6.
    \258\ Entergy at 4.
    \259\ Joint Market Monitors at 5.
---------------------------------------------------------------------------

iii. Commission Determination
    171. The Commission adopts the NOPR's proposal to eliminate the 
DUNS requirement. The Commission required DUNS numbers in an effort to 
help ensure more precise identification of sellers and counterparties. 
However, DUNS numbers have proven to be an imprecise identification 
system, as entities may have multiple DUNS numbers, only one DUNS 
number, or no DUNS number at all. The Commission has considered various 
alternatives to the use of DUNS numbers, but finds none of the 
suggested approaches would provide a viable replacement. Accordingly, 
the Commission will continue to rely on the insertion of customer 
company names in the free-form fields, Field Numbers 16 and 48. In this 
regard, however, the Commission finds reasonable Entergy's suggestion 
to require reporting of the name of the entity exactly as it appears on 
the reported contract,\260\ in both the contract and transaction 
sections. Therefore, we will revise the EQR Data Dictionary to reflect 
this change, as reflected in Attachment A. The Commission will also 
consider the possibility of requiring other types of unique identifiers 
in future and recognizes that there is, for example, an effort 
currently led by the International Standards Organization to promote 
standard legal entity identifiers.
---------------------------------------------------------------------------

    \260\ The reported contract would exclude multi-lateral master 
agreements, such as the WSPP Agreement, consistent with the 
Commission's determination in Order No. 2001-G, 120 FERC ] 61,270 at 
P 14.
---------------------------------------------------------------------------

e. Other Issues
i. Comments
    172. Ronald Rattey states that the data the Commission proposes to 
obtain in this proceeding and the E-Tag Availability Rulemaking, are 
unlikely to give Commission staff the capability to prevent, monitor or 
stop abuses. According to Ronald Rattey, the major flaws in EQR 
reporting requirements are that the data is three or more months old 
before the Commission collects it and the EQR does not require purchase 
transactions to be reported.\261\ Ronald Rattey suggests that the 
Commission should attempt to establish links between EQR, transmission 
contracts and reservations, and e-Tag scheduling data.\262\ In 
addition, he recommends that the Commission access and use real-time 
generation and transmission supply and demand data.\263\ Ronald Rattey 
also states that the Commission should access and analyze bid and offer 
data in RTOs and ISOs and develop the expertise to monitor financial 
markets.\264\
---------------------------------------------------------------------------

    \261\ Ronald Rattey at 3-7.
    \262\ Id. at 13.
    \263\ Id. at 16-17.
    \264\ Id. at 17.
---------------------------------------------------------------------------

ii. Commission Determination
    173. As discussed above, the Commission believes the information to 
be provided in this proceeding will improve the transparency of 
wholesale power and transmission markets in interstate commerce and 
strengthen the Commission's ability to identify potential exercises of 
market power or manipulation. This information, along with the e-Tag 
information proposed to be provided through the rulemaking proceeding 
on E-Tag Availability Rulemaking, and other resources and information, 
will also help the Commission staff to identify and address potential 
exercises of market power or manipulation.

[[Page 61921]]

    174. The Commission disagrees that EQR data is flawed because there 
is a reporting lag. In Order No. 2001, the Commission determined that 
the lag of 30 to 120 days in reporting EQR data appropriately balances 
the Commission's and public's need for data transparency while 
preventing possible harm to competitors and misuse of the data.\265\ 
The Commission continues to find that the existing reporting timelines 
are appropriate. Moreover, we find that the 30 to 120 day lag in EQR 
data helps to protect consumers and competitive markets from the 
adverse effects of potential collusion or other anti-competitive 
behaviors that can be facilitated by untimely public disclosure of 
transaction-specific information, consistent with FPA section 
220(b)(2).
---------------------------------------------------------------------------

    \265\ See Order No. 2001, FERC Stats. & Regs. ] 31,127 at PP 17, 
122, order on reh'g, Order No. 2001-A, 100 FERC ] 61,074 at PP 19-
21.
---------------------------------------------------------------------------

    175. In addition, the Commission will not require the reporting of 
purchase transactions in the EQR. The Commission established the EQR in 
Order No. 2001 using its authority under FPA section 205(c) to require 
public utility sellers to file information showing their rates, terms 
and conditions of service. The Commission is extending EQR reporting 
requirements to non-public utilities above the de minimis threshold as 
part of this rulemaking, pursuant to its authority under FPA section 
220, to require information that will facilitate price transparency in 
jurisdictional markets for the sale and transmission of electricity. 
Requiring purchase transactions to be reported in the EQR would go 
beyond the scope of this proceeding. Finally, the Commission notes that 
it already accesses and uses information about financial markets for 
energy to investigate possible manipulation of physical energy markets.

III. Information Collection Statement

A. Comments

    176. Certain commenters argue that the NOPR's burden estimates are 
too low.\266\ EEI contends that the estimates dismiss the burden on 
filers who are required to file every quarter even if they have no 
transactions to report. EEI also states that the estimates lump 
together filers within a corporate family even though each company that 
must file an EQR bears its own burden and different staff is often 
involved in filing information on behalf of each company. EEI further 
notes that, if any of the proposed additions to data are adopted, 
companies will have to undertake software re-programming and staff 
training, which would involve significant costs that do not appear 
reflected in the burden estimates. According to EEI, one company has 
estimated that computer programming changes alone will cost nearly 900 
hours of staff time and more than $66,000 to design, develop and test 
necessary software. EEI states that another company has estimated the 
cost of changes to its software to be between $200,000 and $500,000, 
depending on the nature of the application changes and time frame for 
implementing them.
---------------------------------------------------------------------------

    \266\ See, e.g., EDF Trading; EEI; Financial Institutions Energy 
Group.
---------------------------------------------------------------------------

    177. Financial Institutions Energy Group asserts that the 
Commission should take into account the true technological costs and 
challenges associated with coming into and maintaining compliance with 
the proposed reporting requirements. Financial Institutions Energy 
Group states that the NOPR significantly underestimates the changes 
that reporting entities would need to make to their information 
technology systems and procedures to comply with certain aspects of the 
proposed rules. Financial Institutions Energy Group states that its 
members conservatively estimate their own implementation costs to run 
between $55,000 to $400,000 per company, with e-Tags accounting for the 
greatest expenditures. In addition, Financial Institutions Energy Group 
estimates that the ongoing costs would range from $2,500 to $10,000 per 
company for each quarterly report. With respect to the time involved in 
implementing the proposed changes for current filers, Financial 
Institutions Energy Group states its members estimate their own 
implementation timelines range from 190 to 1350 man hours per company 
and an ongoing 48 hours per company for each quarterly report.

B. Commission Determination

    178. In response to EEI, we note that most of the revisions to the 
EQR required by this Final Rule are transaction-related. The revisions 
that are not transaction-related, including the elimination of the DUNS 
number requirement and requirement to report the time zone for 
contracts, will reduce the burden of filing an EQR. Although the 
Commission is allowing a seller to indicate information related to 
index publishers in the ID Data section, companies without transactions 
would have no transactions to report and would simply enter ``no.'' 
Because contracts tend to remain consistent from quarter to quarter, 
the EQR allows filers to copy this information forward from one filing 
to the next. The EQR software will provide the capability to do this 
without copying forward the deleted fields in the contracts section 
(customer DUNS number and time zone), thereby minimizing additional 
burden.
    179. In developing the burden estimates, the Commission took into 
account the fact that filers within a corporate family should be able 
to benefit from cost-sharing efficiencies (such as sharing staff and 
EQR filing software) unavailable to independent filers. For purposes of 
calculating the number of respondents, we are counting each individual 
respondent, even though many companies submit a single filing for a 
number of subsidiary entities or submit several filings through a 
single Agent. As a rudimentary example, there are 31 filings from 
companies with names that begin with ``FPL Energy,'' 23 with ``NRG,'' 
19 with ``PPL,'' 16 with ``Calpine,'' 14 with ``GenOn,'' 13 with 
``Covanta,'' 11 with ``Dynegy,'' and 11 with ``Georgia-Pacific'' and 
each identify the same person ``as the Agent, usually the person who 
prepares the filing.'' \267\ The Commission recognizes that not all 
corporate families take advantage of possible efficiencies through 
using common personnel to file the EQR, but it would appear that 
certain efficiencies are possible and should be accounted for in 
estimating the reporting burden.
---------------------------------------------------------------------------

    \267\ EQR Data Dictionary. Company Data.
---------------------------------------------------------------------------

    180. In response to comments that the Commission did not account 
for the information technology changes required to implement these new 
requirements, Commission staff has increased the estimate of the 
additional one-time implementation burden to be 400 hours for each non-
public utility, 240 hours for each current filer with transactions, and 
1 hour for each current filer with no transactions. Commission staff 
has estimated the additional recurring burden for each quarterly filing 
to be 19 hours for each non-public utility, 16 hours for each current 
filer with transactions, and no change for current filers with no 
transactions. The Commission's estimates of the additional average 
reporting burden and cost \268\ due to the Final Rule in Docket RM10-
12-000 follow.
---------------------------------------------------------------------------

    \268\ The burden and cost estimates provided are in addition to 
the estimates for the current EQR reporting requirements for current 
filers.
    In the pending EQR Refresh rule in Docket No. RM12-3-000, for 
current EQR filers and current filing requirements, the staff 
estimates the average burden per respondent per quarterly filing to 
be: 32 hours for Companies within non-California RTO, and large 
companies within the California RTO; 80 hours for medium/small 
Companies within the California RTO; 3 hours for Companies not 
within an RTO; and 0.083 hours [5 minutes] for Companies with no 
transactions. Comments on the estimates for current burden and cost 
should be submitted in Docket No. RM12-3-000.

[[Page 61922]]

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              Estimated additional      Estimated additional      Estimated additional
                                                                             implementing (one-time)    recurring burden per      average annual burden
                                                                Number of     burden per respondent    respondent per response       per respondent
 FERC-920, in the Final Rule in Docket  RM10-12-   Number of    responses  ---------------------------------------------------- (implementation averaged
                       000                        respondents      per                                                               over years 1-3)
                                                                respondent     Burden                    Burden                -------------------------
                                                                 per year      hours      Cost  ($)      hours      Cost  ($)      Burden
                                                                                                                                   hours      Cost  ($)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Current Public Utility Filers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Companies within non-California RTO, and large            405            4       240.00    17,214.00        16.00       829.28       144.00     9,055.12
 cos. within Cal. RTO...........................
Medium/small companies within Cal. RTO..........           20            4       240.00    17,214.00        16.00       829.28       144.00     9,055.12
Companies not within RTO........................          663            4       240.00    17,214.00        16.00       829.28       144.00     9,055.12
Companies with no transactions..................          695            4         1.00        71.73         0.00         0.00         0.33        23.91
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              New Non-Public Utility Filers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Non-Public Utility, with >4 million MWH                    53            4       400.00    28,690.00        19.00       984.77       209.33    13,502.41
 wholesale sales per yr.........................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    181. When averaging the one-time implementation burden and cost 
over Years 1-3, the total additional annual burden and cost for all 
filers (due to the Final Rule in RM10-12) are 167,998.33 burden hours 
and $10,584,214.76.
    182. The Commission recognizes that there will be an initial 
implementation burden for the new non-public utility filers, and an 
initial implementation burden related to the new data for existing 
filers. To help with this implementation, the Commission intends to 
convene a staff-led technical conference, to be announced at a future 
date, to assist non-public utilities in collecting and filing EQR data. 
In addition, non-public utility filers are required to file EQRs 
beginning with the third quarter (Q3) of 2013, covering the period July 
through September 2013. Current filers also are required to file EQRs 
consistent with this Final Rule beginning with Q3 of 2013.
    183. The Commission directs staff to assist filers with compliance. 
The technical conference and staff assistance should minimize the 
implementation burden.
    Information Collection Costs: The estimates of the additional one-
time implementation cost and recurring cost are provided in the 
previous table. The Commission staff has estimated the implementation 
cost using the following professionals, hourly costs, and the estimated 
percent of implementation time: \269\
---------------------------------------------------------------------------

    \269\ Hourly average wage is an average and was calculated using 
Bureau of Labor Statistics (BLS), Occupational Employment Statistics 
data for May 2011 (for NAICS 221100--Electric Power Generation, 
Transmission and Distribution, at http://bls.gov/oes/current/naics4_221100.htm#00-0000) for the senior accountant, financial 
analyst, information technology analyst, and support staff. The 
average hourly figure for legal staff is a composite from BLS and 
other resources, taking into account the hourly cost for both in-
house and contractor organizations.
---------------------------------------------------------------------------

     Legal staff (at $250/hour), 10 percent of the 
implementation time
     Senior accountant (at $51.38/hr.), financial analyst (at 
$68.12/hr.), and/or support staff (at $35.99/hr.), averaged at $51.83/
hr., 10 percent of the implementation time, and 100 percent of the 
recurring burden
     Information technology analyst (at $57.24/hour), 60 
percent of the implementation time
     Support staff (at $35.99/hr), 20 percent of the 
implementation time.
    Title: FERC-920, Electric Quarterly Report (EQR) [OMB No.: 1902-
0255] \270\ Action: Proposed new EQR filers and additional reporting 
requirements for all filers.
---------------------------------------------------------------------------

    \270\ The Commission is establishing the FERC-920 (OMB Control 
No. 1902-0255) for the EQR reporting requirements and separating the 
EQR requirements from the remaining reporting requirements under 
FERC-516 (OMB Control No. 1902-0096). Upon approval by OMB of the 
FERC-920, FERC plans to remove the EQR and corresponding burden 
hours for the recurring filings under the current EQR system from 
the FERC-516.
---------------------------------------------------------------------------

    Respondents: Electric utilities
    Frequency of Responses: Initial implementation and quarterly 
filings (beginning Q3 of 2013).
    Need for Information: The Commission is revising the EQR to 
facilitate price transparency in markets for the sale and transmission 
of electric energy in interstate commerce. The Commission is requiring 
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 EQRs with the Commission. In addition, the 
Commission is making revisions to the existing filing requirements to 
reflect the evolving nature of interstate wholesale electric markets, 
to increase market transparency for the Commission and the public, and 
to 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.
    184. 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, email: 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

[[Page 61923]]

Officer for the Federal Energy Regulatory Commission]. For security 
reasons, comments should be sent by email to OMB at oira_submission@omb.eop.gov. Please reference OMB Control No. 1902-0255, 
FERC-920, and Docket No. RM10-12 in your submission.

IV. Environmental Analysis

    185. 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.\271\ The 
actions taken here fall within categorical exclusions in the 
Commission's regulations for information gathering, analysis, and 
dissemination.\272\ Therefore, an environmental assessment is 
unnecessary and has not been prepared in this rulemaking.
---------------------------------------------------------------------------

    \271\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 486 FR 1750 (Jan. 22, 1988), FERC Stats. & Regs. 
] 30,783 (1987).
    \272\ 18 CFR 380.4(a)(5).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act

    186. The RFA \273\ 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.\274\ 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 4,000,000 MWh.\275\
---------------------------------------------------------------------------

    \273\ 5 U.S.C. 601-612.
    \274\ 13 CFR 121.101.
    \275\ 13 CFR 121.201, Sector 22, Utilities & n.1.
---------------------------------------------------------------------------

    187. As discussed in Order No. 2000,\276\ in making this 
determination, 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.
---------------------------------------------------------------------------

    \276\ See Regional Transmission Organizations, Order No. 2000, 
65 FR 809 (Jan. 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. DC 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)).
---------------------------------------------------------------------------

    188. For non-public utilities, the Commission will exempt under the 
de minimis market presence threshold non-public utilities that make 
4,000,000 MWh or less of annual wholesale sales (based on an average of 
the wholesale sales it made in the preceding three years). This de 
minimis threshold will exclude small non-public utilities. Therefore, 
this Final Rule will not have a significant economic impact on any 
small non-public utility.
    189. This Final Rule also adopts revisions to the existing EQR 
filing requirements, and thus will affect current EQR filers. Based on 
analysis of the EQR filings made in the four quarters of 2011, there 
are 1,783 entities that currently file an EQR, but given clearly 
identifiable affiliate relationships, that number is reduced to 1,215 
entities. Of those, 97 reported more than 4,000,000 million MWh of 
wholesale sales in the EQR. Of the remaining 1,118 entities that 
reported less than 4,000,000 MWh of wholesales sales in the EQR, 641 
filed transactions in the EQR. The rest that would be subject to this 
Final Rule, 477 entities, did not file transactions in any quarter of 
2011; we conclude that this Final Rule will minimally affect them.
    190. As for the remaining 641 entities, we note that there are two 
types of companies among those currently filing EQRs that merit 
additional consideration. First, there are investor-owned utilities 
that make both wholesale and retail sales. The SBA's definition of a 
small utility is based on a utility's total electric output for the 
preceding twelve months, which includes a utility's retail sales. 
However, our estimate in this section is based on information available 
in the EQR, which includes annual wholesale sales but not retail sales. 
If we were able to include retail sales, we believe that most investor-
owned utilities that currently file EQRs make more than 4,000,000 
annual wholesale and retail sales, and thus, would not be classified as 
small. Second, there are power marketers that often do not own or 
control generation or transmission, and may be affiliated with 
companies that are not primarily engaged in the sale of electric energy 
(such as financial institutions or hedge funds).\277\ However, 
information regarding whether a power marketer is affiliated with a 
larger company is generally not included in an EQR filing, making it 
difficult to determine the number of small entities that are affiliated 
with a larger company, thereby leading to an inflated estimate of the 
number of companies affected by this Final Rule that are truly small.
---------------------------------------------------------------------------

    \277\ Some of these such as Google, Occidental Chemical and 
ONEOK may not qualify as small in their primary area of business and 
are participating in the electric market as part of an overall 
corporate strategy.
---------------------------------------------------------------------------

    191. Moreover, while the Final Rule adopts revisions to the 
existing EQR filing requirements, it does not create an entirely new 
reporting requirement for current EQR filers. Since 2001, the 
Commission has used the EQR filing requirement to meet its statutory 
obligation to have a public utility's rates on file.\278\ The 
Commission also requires a company that has been granted market-based 
rate authority to file an EQR.\279\ Thus, current EQR filers already 
have in place a system to capture and report EQR data, and will need to 
modify their systems rather than create an entirely new system. Any 
alternative means for meeting that obligation likely will entail 
greater burden than the electronic collection of transaction data that 
has been occurring in the EQR since 2002. In addition, we believe that 
the burden of complying decreases the smaller the filer is because it 
will have less information to report. Furthermore, we note that 
companies may request, on an individual basis, waiver from the EQR 
reporting requirements.\280\ Thus, the Commission certifies that this 
Final Rule will not have a significant impact on a substantial number 
of small entities.
---------------------------------------------------------------------------

    \278\ Order No. 2001, FERC Stats. & Regs. ] 31,127 at P 31.
    \279\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 334.
    \280\ As stated in the NOPR, the Commission has granted requests 
for waiver of the EQR filing requirements. See NOPR, FERC Stats. & 
Regs. ] 32,676 at P 135, n.147 (citing Bridger Valley Elect. Assoc., 
Inc., 101 FERC ] 61,146). Entities with a waiver will continue to 
have a waiver and will not need to file a new request for waiver.
---------------------------------------------------------------------------

VI. Document Availability

    192. 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.
    193. From FERC's Home Page on the Internet, this information is 
available on eLibrary. The full text of this document

[[Page 61924]]

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.
    194. 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 email at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

VII. Effective Date and Congressional Notification

    195. These regulations are effective December 10, 2012. The 
Commission has determined, with the concurrence of the Administrator of 
the Office of Information and Regulatory Affairs of OMB, that this rule 
is not a ``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996.

List of Subjects in 18 CFR Part 3

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

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

    In consideration of the foregoing, the Commission amends 18 CFR 
part 35, Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

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

0
2. 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 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 that is exempted from the Commission's 
jurisdiction under 16 U.S.C. 824(f).
    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.
    (c) For purposes of this section, the following wholesale sales 
made by a non-public utility with more than a de minimis market 
presence are excluded from the EQR filing requirement:
    (1) Sales by a non-public utility, such as a cooperative or joint 
action agency, to its members; and
    (2) Sales by a non-public utility under a long-term, cost-based 
agreement required to be made to certain customers under Federal or 
state statute.
0
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 to 
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 
identify as part of its Electric Quarterly Report filing requirement in 
Sec.  35.10b of this chapter the publishers of electricity and natural 
gas indices to which it reports its transactions. In addition, Seller 
must adhere to any other standards and requirements for price reporting 
as the Commission may order.

    Note: Attachment A will not be published in the Code of Federal 
Regulations.

Attachment A: Revisions to the Data Dictionary Clean Version

Electric Quarterly Report Data Dictionary

Version 2.0 (issued July 19, 2012)

                                          EQR Data Dictionary--ID Data
----------------------------------------------------------------------------------------------------------------
       Field No.
-----------------------        Field          Required          Value                     Definiiton
    Old         New
----------------------------------------------------------------------------------------------------------------
1.........  1.........  Filer Unique           [check]   FR1................  (Respondent)--An identifier (i.e.,
                         Identifier.                                           ``FR1'') used to designate a
                                                                               record containing Respondent
                                                                               identification information in a
                                                                               comma-delimited (csv) file that
                                                                               is imported into the EQR filing.
                                                                               Only one record with the FR1
                                                                               identifier may be imported into
                                                                               an EQR for a given quarter.
1.........  1.........  Filer Unique           [check]   FS (where   (Seller)--An identifier (e.g.,
                         Identifier.                      ``'' is     ``FS1'', ``FS2'') used to
                                                          an integer).         designate a record containing
                                                                               Seller identification information
                                                                               in a comma-delimited (csv) file
                                                                               that is imported into the EQR
                                                                               filing. One record for each
                                                                               seller company may be imported
                                                                               into an EQR for a given quarter.
1.........  1.........  Filer Unique           [check]   FA1................  (Agent)--An identifier (i.e.,
                         Identifier.                                           ``FA1'') used to designate a
                                                                               record containing Agent
                                                                               identification information in a
                                                                               comma-delimited (csv) file that
                                                                               is imported into the EQR filing.
                                                                               Only one record with the FA1
                                                                               identifier may be imported into
                                                                               an EQR for a given quarter.

[[Page 61925]]

 
2.........  2.........  Company Name.......    [check]   Unrestricted text    (Respondent)--The name of the
                                                          (100 characters).    company taking responsibility for
                                                                               complying with the Commission's
                                                                               regulations related to the EQR.
2.........  2.........  Company Name.......    [check]   Unrestricted text    (Seller)--The name of the company
                                                          (100 characters).    that is authorized to make sales
                                                                               as indicated in the company's
                                                                               FERC tariff(s). This name may be
                                                                               the same as the Company Name of
                                                                               the Respondent.
2.........  2.........  Company Name.......    [check]   Unrestricted text    (Agent)--The name of the entity
                                                          (100 characters).    completing the EQR filing. The
                                                                               Agent's Company Name need not be
                                                                               the name of the company under
                                                                               Commission jurisdiction.
3.........  X                                                                 ..................................
4.........  3.........  Contact Name.......    [check]   Unrestricted text    (Respondent)--Name of the person
                                                          (50 characters).     at the Respondent's company
                                                                               taking responsibility for
                                                                               compliance with the Commission's
                                                                               EQR regulations.
4.........  3.........  Contact Name.......    [check]   Unrestricted text    (Seller)--The name of the contact
                                                          (50 characters).     for the company authorized to
                                                                               make sales as indicated in the
                                                                               company's FERC tariff(s). This
                                                                               name may be the same as the
                                                                               Contact Name of the Respondent.
4.........  3.........  Contact Name.......    [check]   Unrestricted text    (Agent)--Name of the contact for
                                                          (50 characters).     the Agent, usually the person who
                                                                               prepares the filing.
5.........  4.........  Contact Title......    [check]   Unrestricted text    Title of contact identified in
                                                          (50 characters).     Field Number 3.
6.........  5.........  Contact Address....    [check]   Unrestricted text..  Street address for contact
                                                                               identified in Field Number 3.
7.........  6.........  Contact City.......    [check]   Unrestricted text    City for the contact identified in
                                                          (30 characters).     Field Number 3.
8.........  7.........  Contact State......    [check]   Unrestricted text    Two character state or province
                                                          (2 characters).      abbreviations for the contact
                                                                               identified in Field Number 3.
9.........  8.........  Contact Zip........    [check]   Unrestricted text    Zip code for the contact
                                                          (10 characters).     identified in Field Number 3.
10........  9.........  Contact Country        [check]   CA--Canada.........  Country (USA, Canada, Mexico, or
                         Name.                           MX--Mexico.........   United Kingdom) for contact
                                                         US--United States..   address identified in Field
                                                         UK--United Kingdom.   Number 3.
11........  10........  Contact Phone......    [check]   Unrestricted text    Phone number of contact identified
                                                          (20 characters).     in Field Number 3.
12........  11........  Contact E-Mail.....    [check]   Unrestricted text..  Email address of contact
                                                                               identified in Field Number 3.
            12........  Transactions           [check]   Y (Yes)............  Filers should indicate whether
                         Reported to Index               N (No).............   they have reported their sales
                         Price Publisher(s).                                   transactions to index price
                                                                               publisher(s). If they have,
                                                                               filers should indicate
                                                                               specifically which index
                                                                               publisher(s) in Field Number 72.
13........  13........  Filing Quarter.....    [check]   YYYYMM.............  A six digit reference number used
                                                                               by the EQR software to indicate
                                                                               the quarter and year of the
                                                                               filing for the purpose of
                                                                               importing data from csv files.
                                                                               The first 4 numbers represent the
                                                                               year (e.g., 2007). The last 2
                                                                               numbers represent the last month
                                                                               of the quarter (e.g., 03 = 1st
                                                                               quarter; 06 = 2nd quarter, 09 =
                                                                               3rd quarter, 12 = 4th quarter).
----------------------------------------------------------------------------------------------------------------

                                       EQR Data Dictionary--Contract Data
----------------------------------------------------------------------------------------------------------------
      Field No.
---------------------        Field             Required            Value                   Definition
   Old        New
----------------------------------------------------------------------------------------------------------------
14.......  14.......  Contract Unique ID       [check]       An integer         An identifier beginning with the
                                                              proceeded by the   letter ``C'' and followed by a
                                                              letter ``C''       number (e.g., ``C1'', ``C2'')
                                                              (only used when    used to designate a record
                                                              importing          containing contract information
                                                              contract data).    in a comma-delimited (csv) file
                                                                                 that is imported into the EQR
                                                                                 filing. One record for each
                                                                                 contract product may be
                                                                                 imported into an EQR for a
                                                                                 given quarter.
15.......  15.......  Seller Company           [check]       Unrestricted text  The name of the company that is
                       Name.                                  (100 characters).  authorized to make sales as
                                                                                 indicated in the company's FERC
                                                                                 tariff(s). This name must match
                                                                                 the name provided as a Seller's
                                                                                 ``Company Name'' in Field
                                                                                 Number 2 of the ID Data (Seller
                                                                                 Data).
16.......  16.......  Customer Company         [check]       Unrestricted text  The name of the counterparty.
                       Name.                                  (70 characters).
17.......  X

[[Page 61926]]

 
18.......  17.......  Contract Affiliate       [check]       Y (Yes)..........  The customer is an affiliate if
                                                             N (No)...........   it controls, is controlled by
                                                                                 or is under common control with
                                                                                 the seller. This includes a
                                                                                 division that operates as a
                                                                                 functional unit. A customer of
                                                                                 a seller who is an Exempt
                                                                                 Wholesale Generator may be
                                                                                 defined as an affiliate under
                                                                                 the Public Utility Holding
                                                                                 Company Act and the FPA.
19.......  18.......  FERC Tariff              [check]       Unrestricted text  The FERC tariff reference cites
                       Reference.                             (60 characters).   the document that specifies the
                                                                                 terms and conditions under
                                                                                 which a Seller is authorized to
                                                                                 make transmission sales, power
                                                                                 sales or sales of related
                                                                                 jurisdictional services at cost-
                                                                                 based rates or at market-based
                                                                                 rates. If the sales are market-
                                                                                 based, the tariff that is
                                                                                 specified in the FERC order
                                                                                 granting the Seller Market
                                                                                 Based Rate Authority must be
                                                                                 listed.
20.......  19.......  Contract Service         [check]       Unrestricted text  Unique identifier given to each
                       Agreement ID.                          (30 characters).   service agreement that can be
                                                                                 used by the filing company to
                                                                                 produce the agreement, if
                                                                                 requested. The identifier may
                                                                                 be the number assigned by FERC
                                                                                 for those service agreements
                                                                                 that have been filed with and
                                                                                 accepted by the Commission, or
                                                                                 it may be generated as part of
                                                                                 an internal identification
                                                                                 system.
21.......  20.......  Contract Execution       [check]       YYYYMMDD.........  The date the contract was
                       Date.                                                     signed. If the parties signed
                                                                                 on different dates, use the
                                                                                 most recent date signed.
22.......  21.......  Commencement Date        [check]       YYYYMMDD.........  The date the terms of the
                       of Contract Terms.                                        contract reported in fields 18,
                                                                                 23 and 25 through 45 (as
                                                                                 defined in the data dictionary)
                                                                                 became effective. If those
                                                                                 terms became effective on
                                                                                 multiple dates (i.e.: due to
                                                                                 one or more amendments), the
                                                                                 date to be reported in this
                                                                                 field is the date the most
                                                                                 recent amendment became
                                                                                 effective. If the contract or
                                                                                 the most recent reported
                                                                                 amendment does not have an
                                                                                 effective date, the date when
                                                                                 service began pursuant to the
                                                                                 contract or most recent
                                                                                 reported amendment may be used.
                                                                                 If the terms reported in fields
                                                                                 18, 23 and 25 through 45 have
                                                                                 not been amended since January
                                                                                 1, 2009, the initial date the
                                                                                 contract became effective (or
                                                                                 absent an effective date the
                                                                                 initial date when service
                                                                                 began) may be used.
23.......  22.......  Contract            If specified in    YYYYMMDD.........  The date that the contract
                       Termination Date.   the contract.                         expires.
24.......  23.......  Actual Termination  If contract        YYYYMMDD.........  The date the contract actually
                       Date.               terminated.                           terminates.
25.......  24.......  Extension                [check]       Unrestricted text  Description of terms that
                       Provision                                                 provide for the continuation of
                       Description.                                              the contract.
26.......  25.......  Class Name........       [check]       .................  See definitions of each class
                                                                                 name below.
26.......  25.......  Class Name........       [check]       F--Firm..........  For transmission sales, a
                                                                                 service or product that always
                                                                                 has priority over non-firm
                                                                                 service. For power sales, a
                                                                                 service or product that is not
                                                                                 interruptible for economic
                                                                                 reasons.
26.......  25.......  Class Name........       [check]       NF--Non-firm.....  For transmission sales, a
                                                                                 service that is reserved and/or
                                                                                 scheduled on an as-available
                                                                                 basis and is subject to
                                                                                 curtailment or interruption at
                                                                                 a lesser priority compared to
                                                                                 Firm service. For an energy
                                                                                 sale, a service or product for
                                                                                 which delivery or receipt of
                                                                                 the energy may be interrupted
                                                                                 for any reason or no reason,
                                                                                 without liability on the part
                                                                                 of either the buyer or seller.
26.......  25.......  Class Name........       [check]       UP--Unit Power     Designates a dedicated sale of
                                                              Sale.              energy and capacity from one or
                                                                                 more than one specified
                                                                                 generation unit(s).
26.......  25.......  Class Name........       [check]       N/A--Not           To be used only when the other
                                                              Applicable.        available Class Names do not
                                                                                 apply.
27.......  26.......  Term Name.........       [check]       LT--Long Term....  Contracts with durations of one
                                                             ST--Short Term...   year or greater are long-term.
                                                             N/A--Not            Contracts with shorter
                                                              Applicable..       durations are short-term.
28.......  27.......  Increment Name....       [check]       .................  See definitions for each
                                                                                 increment below.
28.......  27.......  Increment Name....       [check]       H--Hourly........  Terms of the contract (if
                                                                                 specifically noted in the
                                                                                 contract) set for up to 6
                                                                                 consecutive hours (<= 6
                                                                                 consecutive hours).
28.......  27.......  Increment Name....       [check]       D--Daily.........  Terms of the contract (if
                                                                                 specifically noted in the
                                                                                 contract) set for more than 6
                                                                                 and up to 60 consecutive hours
                                                                                 (>6 and <= 60 consecutive
                                                                                 hours).
28.......  27.......  Increment Name....       [check]       W--Weekly........  Terms of the contract (if
                                                                                 specifically noted in the
                                                                                 contract) set for over 60
                                                                                 consecutive hours and up to 168
                                                                                 consecutive hours (>60 and <=
                                                                                 168 consecutive hours).

[[Page 61927]]

 
28.......  27.......  Increment Name....       [check]       M--Monthly.......  Terms of the contract (if
                                                                                 specifically noted in the
                                                                                 contract) set for more than 168
                                                                                 consecutive hours up to, but
                                                                                 not including, one year (>168
                                                                                 consecutive hours and < 1
                                                                                 year).
28.......  27.......  Increment Name....       [check]       Y--Yearly........  Terms of the contract (if
                                                                                 specifically noted in the
                                                                                 contract) set for one year or
                                                                                 more (>= 1 year).
28.......  27.......  Increment Name....       [check]       N/A--Not           Terms of the contract do not
                                                              Applicable.        specify an increment.
29.......  28.......  Increment Peaking        [check]       .................  See definitions for each
                       Name.                                                     increment peaking name below.
29.......  28.......  Increment Peaking        [check]       FP--Full Period..  The product described may be
                       Name.                                                     sold during those hours
                                                                                 designated as on-peak and off-
                                                                                 peak in the NERC region of the
                                                                                 point of delivery.
29.......  28.......  Increment Peaking        [check]       OP--Off-Peak.....  The product described may be
                       Name.                                                     sold only during those hours
                                                                                 designated as off-peak in the
                                                                                 NERC region of the point of
                                                                                 delivery.
29.......  28.......  Increment Peaking        [check]       P--Peak..........  The product described may be
                       Name.                                                     sold only during those hours
                                                                                 designated as on-peak in the
                                                                                 NERC region of the point of
                                                                                 delivery.
29.......  28.......  Increment Peaking        [check]       N/A--Not           To be used only when the
                       Name.                                  Applicable.        increment peaking name is not
                                                                                 specified in the contract.
30.......  29.......  Product Type Name.       [check]       .................  See definitions for each product
                                                                                 type below.
30.......  29.......  Product Type Name.       [check]       CB--Cost Based...  Energy or capacity sold under a
                                                                                 FERC-approved cost-based rate
                                                                                 tariff.
30.......  29.......  Product Type Name.       [check]       CR--Capacity       An agreement under which a
                                                              Reassignment.      transmission provider sells,
                                                                                 assigns or transfers all or
                                                                                 portion of its rights to an
                                                                                 eligible customer.
30.......  29.......  Product Type Name.       [check]       MB--Market Based.  Energy or capacity sold under
                                                                                 the seller's FERC-approved
                                                                                 market-based rate tariff.
30.......  29.......  Product Type Name.       [check]       T--Transmission..  The product is sold under a FERC-
                                                                                 approved transmission tariff.
30.......  29.......  Product Type Name.       [check]       Other............  The product cannot be
                                                                                 characterized by the other
                                                                                 product type names.
31.......  30.......  Product Name......       [check]       See Product Name   Description of product being
                                                              Table, Appendix    offered.
                                                              A.
32.......  31.......  Quantity..........  If specified in    Number with up to  Quantity for the contract
                                           the contract.      4 decimals.        product identified.
33.......  32.......  Units.............  If specified in    See Units Table,   Measure stated in the contract
                                           the contract.      Appendix E.        for the product sold.
34.......  33.......  Rate..............  One of four rate   Number with up to  The charge for the product per
                                           fields (34, 35,    4 decimals.        unit as stated in the contract.
                                           36, or 37) must
                                           be included.
35.......  34.......  Rate Minimum......  One of four rate   Number with up to  Minimum rate to be charged per
                                           fields (34, 35,    4 decimals.        the contract, if a range is
                                           36, or 37) must                       specified.
                                           be included.
36.......  35.......  Rate Maximum......  One of four rate   Number with up to  Maximum rate to be charged per
                                           fields (34, 35,    4 decimals.        the contract, if a range is
                                           36, or 37) must                       specified.
                                           be included.
37.......  36.......  Rate Description..  One of four rate   Unrestricted text  Text description of rate. If the
                                           fields (34, 35,                       rate is currently available on
                                           36, or 37) must                       the FERC website, a citation of
                                           be included.                          the FERC Accession Number and
                                                                                 the relevant FERC tariff
                                                                                 including page number or
                                                                                 section may be included instead
                                                                                 of providing the entire rate
                                                                                 algorithm. If the rate is not
                                                                                 available on the FERC website,
                                                                                 include the rate algorithm, if
                                                                                 rate is calculated. If the
                                                                                 algorithm would exceed the 150
                                                                                 character field limit, it may
                                                                                 be provided in a descriptive
                                                                                 summary (including bases and
                                                                                 methods of calculations) with a
                                                                                 detailed citation of the
                                                                                 relevant FERC tariff including
                                                                                 page number and section. If
                                                                                 more than 150 characters are
                                                                                 required, the contract product
                                                                                 may be repeated in a subsequent
                                                                                 line of data until the rate is
                                                                                 adequately described.
38.......  37.......  Rate Units........  If specified in    See Rate Units     Measure stated in the contract
                                           the contract.      Table, Appendix    for the product sold.
                                                              F.

[[Page 61928]]

 
39.......  38.......  Point of Receipt    If specified in    See Balancing      The registered NERC Balancing
                       Balancing           the contract.      Authority Table,   Authority (formerly called NERC
                       Authority (PORBA).                     Appendix B.        Control Area) where service
                                                                                 begins for a transmission or
                                                                                 transmission-related
                                                                                 jurisdictional sale. The
                                                                                 Balancing Authority will be
                                                                                 identified with the
                                                                                 abbreviation used in OASIS
                                                                                 applications. If receipt occurs
                                                                                 at a trading hub specified in
                                                                                 the EQR software, the term
                                                                                 ``Hub'' should be used.
40.......  39.......  Point of Receipt    If specified in    Unrestricted text  The specific location at which
                       Specific Location   the contract.      (50 characters).   the product is received if
                       (PORSL).                               If ``HUB'' is      designated in the contract. If
                                                              selected for       receipt occurs at a trading
                                                              PORCA, see Hub     hub, a standardized hub name
                                                              Table, Appendix    must be used. If more points of
                                                              C.                 receipt are listed in the
                                                                                 contract than can fit into the
                                                                                 50 character space, a
                                                                                 description of the collection
                                                                                 of points may be used.
                                                                                 `Various,' alone, is
                                                                                 unacceptable unless the
                                                                                 contract itself uses that
                                                                                 terminology.
41.......  40.......  Point of Delivery   If specified in    See Balancing      The registered NERC Balancing
                       Balancing           the contract.      Authority Table,   Authority (formerly called NERC
                       Authority (PODBA).                     Appendix B.        Control Area) where a
                                                                                 jurisdictional product is
                                                                                 delivered and/or service ends
                                                                                 for a transmission or
                                                                                 transmission-related
                                                                                 jurisdictional sale. The
                                                                                 Balancing Authority will be
                                                                                 identified with the
                                                                                 abbreviation used in OASIS
                                                                                 applications. If delivery
                                                                                 occurs at the interconnection
                                                                                 of two control areas, the
                                                                                 control area that the product
                                                                                 is entering should be used. If
                                                                                 delivery occurs at a trading
                                                                                 hub specified in the EQR
                                                                                 software, the term ``Hub''
                                                                                 should be used.
42.......  41.......  Point of Delivery   If specified in    Unrestricted text  The specific location at which
                       Specific Location   the contract.      (50 characters).   the product is delivered if
                       (PODSL).                               If ``HUB'' is      designated in the contract. If
                                                              selected for       receipt occurs at a trading
                                                              PODCA, see Hub     hub, a standardized hub name
                                                              Table, Appendix    must be used.
                                                              C.
43.......  42.......  Begin Date........  If specified in    YYYYMMDDHHMM.....  First date for the sale of the
                                           the contract.                         product at the rate specified.
44.......  43.......  End Date..........  If specified in    YYYYMMDDHHMM.....  Last date for the sale of the
                                           the contract.                         product at the rate specified.
45.......  X
----------------------------------------------------------------------------------------------------------------

                                      EQR Data Dictionary--Transaction Data
----------------------------------------------------------------------------------------------------------------
       Field No.
-----------------------        Field          Required          Value                     Definition
    Old         New
----------------------------------------------------------------------------------------------------------------
46........  44........  Transaction Unique     [check]   An integer           An identifier beginning with the
                         ID.                              proceeded by the     letter ``T'' and followed by a
                                                          letter ``T'' (only   number (e.g., ``T1'', ``T2'')
                                                          used when            used to designate a record
                                                          importing            containing transaction
                                                          transaction data).   information in a comma-delimited
                                                                               (csv) file that is imported into
                                                                               the EQR filing. One record for
                                                                               each transaction record may be
                                                                               imported into an EQR for a given
                                                                               quarter. A new transaction record
                                                                               must be used every time a price
                                                                               changes in a sale.
47........  45........  Seller Company Name    [check]   Unrestricted text    The name of the company that is
                                                          (100 Characters).    authorized to make sales as
                                                                               indicated in the company's FERC
                                                                               tariff(s). This name must match
                                                                               the name provided as a Seller's
                                                                               ``Company Name'' in Field 2 of
                                                                               the ID Data (Seller Data).
48........  46........  Customer Company       [check]   Unrestricted text    The name of the counterparty.
                         Name.                            (70 Characters).
49........  X
50........  47........  FERC Tariff            [check]   Unrestricted text    The FERC tariff reference cites
                         Reference.                       (60 Characters).     the document that specifies the
                                                                               terms and conditions under which
                                                                               a Seller is authorized to make
                                                                               transmission sales, power sales
                                                                               or sales of related
                                                                               jurisdictional services at cost-
                                                                               based rates or at market-based
                                                                               rates. If the sales are market-
                                                                               based, the tariff that is
                                                                               specified in the FERC order
                                                                               granting the Seller Market Based
                                                                               Rate Authority must be listed.

[[Page 61929]]

 
51........  48........  Contract Service       [check]   Unrestricted text    Unique identifier given to each
                         Agreement ID.                    (30 Characters).     service agreement that can be
                                                                               used by the filing company to
                                                                               produce the agreement, if
                                                                               requested. The identifier may be
                                                                               the number assigned by FERC for
                                                                               those service agreements that
                                                                               have been filed and approved by
                                                                               the Commission, or it may be
                                                                               generated as part of an internal
                                                                               identification system.
52........  49........  Transaction Unique     [check]   Unrestricted text    Unique reference number assigned
                         Identifier.                      (24 Characters).     by the seller for each
                                                                               transaction.
53........  50........  Transaction Begin      [check]   YYYYMMDDHHMM (csv    First date and time the product is
                         Date.                            import).             sold during the quarter.
                                                         MMDDYYYYHHMM
                                                          (manual entry).
54........  51........  Transaction End        [check]   YYYYMMDDHHMM (csv    Last date and time the product is
                         Date.                            import).             sold during the quarter.
                                                         MMDDYYYYHHMM
                                                          (manual entry).
            52........  Trade Date.........    [check]   YYYYMMDD (csv        The date upon which the parties
                                                          import).             made the legally binding
                                                         MMDDYYYY (manual      agreement on the price of a
                                                          entry).              transaction.
            53........  Exchange/Brokerage   ..........  See Exchange/        If a broker service is used to
                         Service.                         Brokerage Service    consummate or effectuate a
                                                          Table, Appendix H.   transaction, the term ``Broker''
                                                                               shall be selected from the
                                                                               Commission-provided list. If an
                                                                               exchange is used, the specific
                                                                               exchange that is used shall be
                                                                               selected from the Commission-
                                                                               provided list.
            54........  Type of Rate.......    [check]   ...................  See type of rate definitions
                                                                               below.
            54........  Type of Rate.......    [check]   Fixed..............  A fixed charge per unit of
                                                                               consumption.
            54........  Type of Rate.......    [check]   Formula............  A calculation of a rate based upon
                                                                               a formula that does not contain
                                                                               an index component.
            54........  Type of Rate.......    [check]   Electric Index.....  A calculation of a rate based upon
                                                                               an index or a formula that
                                                                               contains an index component.
            54........  Type of Rate.......    [check]   RTO/ISO............  A rate that is based on an RTO/ISO
                                                                               published price or formula that
                                                                               contains an RTO/ISO price
                                                                               component.
55........  55........  Time Zone..........    [check]   See Time Zone        The time zone in which the sales
                                                          Table, Appendix D.   will be made under the contract.
56........  56........  Point of Delivery      [check]   See Balancing        The registered NERC Balancing
                         Balancing                        Authority Table,     Authority (formerly called NERC
                         Authority (PODBA).               Appendix B.          Control Area) abbreviation used
                                                                               in OASIS applications.
57........  57........  Point of Delivery      [check]   Unrestricted text    The specific location at which the
                         Specific Location                (50 characters).     product is delivered. If receipt
                         (PODSL).                         If ``HUB'' is        occurs at a trading hub, a
                                                          selected for         standardized hub name must be
                                                          PODBA, see Hub       used.
                                                          Table, Appendix C.
58........  58........  Class Name.........    [check]   ...................  See class name definitions below.
58........  58........  Class Name.........    [check]   F--Firm............  A sale, service or product that is
                                                                               not interruptible for economic
                                                                               reasons.
58........  58........  Class Name.........    [check]   NF--Non-firm.......  A sale for which delivery or
                                                                               receipt of the energy may be
                                                                               interrupted for any reason or no
                                                                               reason, without liability on the
                                                                               part of either the buyer or
                                                                               seller.
58........  58........  Class Name.........    [check]   UP--Unit Power Sale  Designates a dedicated sale of
                                                                               energy and capacity from one or
                                                                               more than one specified
                                                                               generation unit(s).
58........  58........  Class Name.........    [check]   BA--Billing          Designates an incremental material
                                                          Adjustment.          change to one or more
                                                                               transactions due to a change in
                                                                               settlement results. ``BA'' may be
                                                                               used in a refiling after the next
                                                                               quarter's filing is due to
                                                                               reflect the receipt of new
                                                                               information. It may not be used
                                                                               to correct an inaccurate filing.
58........  58........  Class Name.........    [check]   N/A--Not Applicable  To be used only when the other
                                                                               available class names do not
                                                                               apply.
59........  59........  Term Name..........    [check]   LT--Long Term......  Power sales transactions with
                                                         ST--Short Term N/A--  durations of one year or greater
                                                          .                    are long-term. Transactions with
                                                         Not Applicable.....   shorter durations are short-term.
60........  60........  Increment Name.....    [check]   ...................  See increment name definitions
                                                                               below.
60........  60........  Increment Name.....    [check]   H--Hourly..........  Terms of the particular sale set
                                                                               for up to 6 consecutive hours (<=
                                                                               6 consecutive hours) Includes LMP
                                                                               based sales in ISO/RTO markets.
60........  60........  Increment Name.....    [check]   D--Daily...........  Terms of the particular sale set
                                                                               for more than 6 and up to 60
                                                                               consecutive hours (> 6 and <= 60
                                                                               consecutive hours). Includes
                                                                               sales over a peak or off-peak
                                                                               block during a single day.

[[Page 61930]]

 
60........  60........  Increment Name.....    [check]   W--Weekly..........  Terms of the particular sale set
                                                                               for over 60 consecutive hours and
                                                                               up to 168 consecutive hours (> 60
                                                                               and <= 168 consecutive hours).
                                                                               Includes sales for a full week
                                                                               and sales for peak and off-peak
                                                                               blocks over a particular week.
60........  60........  Increment Name.....    [check]   M--Monthly.........  Terms of the particular sale set
                                                                               for set for more than 168
                                                                               consecutive hours up to, but not
                                                                               including, one year (> 168
                                                                               consecutive hours and < 1 year).
                                                                               Includes sales for full month or
                                                                               multi-week sales during a given
                                                                               month.
60........  60........  Increment Name.....    [check]   Y--Yearly..........  Terms of the particular sale set
                                                                               for one year or more (>= 1 year).
                                                                               Includes all long-term contracts
                                                                               with defined pricing terms (fixed-
                                                                               price, formula, or index).
60........  60........  Increment Name.....    [check]   N/A--Not Applicable  To be used only when other
                                                                               available increment names do not
                                                                               apply.
61........  61........  Increment Peaking      [check]   ...................  See definitions for increment
                         Name.                                                 peaking below.
61........  61........  Increment Peaking      [check]   FP--Full Period....  The product described was sold
                         Name.                                                 during Peak and Off-Peak hours.
61........  61........  Increment Peaking      [check]   OP--Off-Peak.......  The product described was sold
                         Name.                                                 only during those hours
                                                                               designated as off-peak in the
                                                                               NERC region of the point of
                                                                               delivery.
61........  61........  Increment Peaking      [check]   P--Peak............  The product described was sold
                         Name.                                                 only during those hours
                                                                               designated as on-peak in the NERC
                                                                               region of the point of delivery.
61........  61........  Increment Peaking      [check]   N/A--Not Applicable  To be used only when the other
                         Name.                                                 available increment peaking names
                                                                               do not apply.
62........  62........  Product Name.......    [check]   See Product Names    Description of product being
                                                          Table, Appendix A.   offered.
63........  63........  Transaction            [check]   Number with up to 4  The quantity of the product in
                         Quantity.                        decimals.            this transaction.
64........  64........  Price..............    [check]   Number with up to 6  Actual price charged for the
                                                          decimals.            product per unit. The price
                                                                               reported cannot be averaged or
                                                                               otherwise aggregated
65........  65........  Rate Units.........    [check]   See Rate Units       Measure appropriate to the price
                                                          Table, Appendix F.   of the product sold.
            66........  Standardized           [check]   Number with up to 4  For product names energy,
                         Quantity.                        decimals.            capacity, and booked out power
                                                                               only. Specify the quantity in MWh
                                                                               if the product is energy or
                                                                               booked out power and specify the
                                                                               quantity in MW if the product is
                                                                               capacity.
            67........  Standardized Price.    [check]   Number with up to 6  For product names energy,
                                                          decimals.            capacity, and booked out power
                                                                               only. Specify the price in $/MWh
                                                                               if the product is energy or
                                                                               booked out power and specify the
                                                                               price in $/MW-month if the
                                                                               product is capacity.
66........  68........  Total Transmission     [check]   Number with up to 2  Payments received for transmission
                         Charge.                          decimals.            services when explicitly
                                                                               identified.
67........  69........  Total Transaction      [check]   Number with up to 2  Transaction Quantity (Field 63)
                         Charge.                          decimals.            times Price (Field 64) plus Total
                                                                               Transmission Charge (Field 66).
----------------------------------------------------------------------------------------------------------------

                                    EQR Data Dictionary--Index Reporting Data
----------------------------------------------------------------------------------------------------------------
       Field No.
-----------------------        Field          Required          Value                     Definition
    Old         New
----------------------------------------------------------------------------------------------------------------
            70........  Filer Unique           [check]   FS (where   The ``FS'' seller number from the
                         Identifier.                      ``'' is     ID Data table corresponding to
                                                          an integer).         the index reporting company.
            71........  Seller Company Name    [check]   Unrestricted text    The name of the company that is
                                                          (100 characters).    authorized to make sales as
                                                                               indicated in the company's FERC
                                                                               tariff(s). This name must match
                                                                               the name provided as a Seller's
                                                                               ``Company Name'' in Field Number
                                                                               2 of the ID Data (Seller Data).
            72........  Index Price            [check]   If ``Yes'' is        The index price publisher(s) to
                         Publisher(s) To                  selected for Field   which sales transactions have
                         Which Sales                      12, see Index        been reported.
                         Transactions Have                Price Publisher,
                         Been Reported.                   Appendix G.
            73........  Transactions           [check]   Unrestricted text    Description of the types of
                         Reported.                        (100 characters).    transactions reported to the
                                                                               index publisher identified in
                                                                               this record.
----------------------------------------------------------------------------------------------------------------

[[Page 61931]]

                                         EQR Data Dictionary--e-Tag Data
----------------------------------------------------------------------------------------------------------------
      Field No.
---------------------        Field             Required            Value                   Definition
   Old        New
----------------------------------------------------------------------------------------------------------------
           74.......  e-Tag ID..........  If an e-Tag ID     Unrestricted text  The e-Tag ID contains: The
                                           was used to        (30 Characters).   Source Balancing Authority
                                           schedule the EQR                      where the generation is
                                           transaction.                          located; The Purchasing-Selling
                                                                                 Balancing Authority Entity
                                                                                 Code; the e-Tag Code; and the
                                                                                 Sink Balancing Authority.
           75.......  e-Tag Begin Date..  If an e-Tag ID     YYYYMMDD (csv      The first date the transaction
                                           was used to        import).           is scheduled using the e-Tag ID
                                           schedule the EQR  MMDDYYYY (manual    reported in Field Number 71.
                                           transaction.       entry).            Begin Date must not be before
                                                                                 the Transaction Begin Date
                                                                                 specified in Field Number 51
                                                                                 and must be reported in the
                                                                                 same time zone specified in
                                                                                 Field Number 56.
           76.......  e-Tag End Date....  If an e-Tag ID     YYYYMMDD (csv      The last date the transaction is
                                           was used to        import).           scheduled using the e-Tag ID
                                           schedule the EQR  MMDDYYYY (manual    reported in Field Number 71.
                                           transaction.       entry).            End Date must not be after the
                                                                                 Transaction End Date specified
                                                                                 in Field Number 52 and must be
                                                                                 reported in the same time zone
                                                                                 specified in Field Number 56.
           77.......  Transaction Unique  If an e-Tag ID     Unrestricted text  Unique reference number assigned
                       Identifier.         was used to        (24 Characters).   by the seller for each
                                           schedule the EQR                      transaction that must be the
                                           transaction.                          same as reported in Field
                                                                                 Number 50.
----------------------------------------------------------------------------------------------------------------

                                 EQR Data Dictionary--Appendix A. Product Names
----------------------------------------------------------------------------------------------------------------
                                           Contract       Transaction
             Product name                  product          product                     Definition
----------------------------------------------------------------------------------------------------------------
BLACK START SERVICE..................         [check]          [check]   Service available after a system-wide
                                                                          blackout where a generator
                                                                          participates in system restoration
                                                                          activities without the availability of
                                                                          an outside electric supply (Ancillary
                                                                          Service).
BOOKED OUT POWER.....................  ...............         [check]   Energy or capacity contractually
                                                                          committed bilaterally for delivery but
                                                                          not actually delivered due to some
                                                                          offsetting or countervailing trade
                                                                          (Transaction only).
CAPACITY.............................         [check]          [check]   A quantity of demand that is charged on
                                                                          a $/KW or $/MW basis.
CUSTOMER CHARGE......................         [check]          [check]   Fixed contractual charges assessed on a
                                                                          per customer basis that could include
                                                                          billing service.
DIRECT ASSIGNMENT FACILITIES CHARGE..         [check]   ...............  Charges for facilities or portions of
                                                                          facilities that are constructed or
                                                                          used for the sole use/benefit of a
                                                                          particular customer.
EMERGENCY ENERGY.....................         [check]   ...............  Contractual provisions to supply energy
                                                                          or capacity to another entity during
                                                                          critical situations.
ENERGY...............................         [check]          [check]   A quantity of electricity that is sold
                                                                          or transmitted over a period of time.
ENERGY IMBALANCE.....................         [check]          [check]   Service provided when a difference
                                                                          occurs between the scheduled and the
                                                                          actual delivery of energy to a load
                                                                          obligation (Ancillary Service). For
                                                                          Contracts, reported if the contract
                                                                          provides for sale of the product. For
                                                                          Transactions, sales by third-party
                                                                          providers (i.e., non-transmission
                                                                          function) are reported.
EXCHANGE.............................         [check]          [check]   Transaction whereby the receiver
                                                                          accepts delivery of energy for a
                                                                          supplier's account and returns energy
                                                                          at times, rates, and in amounts as
                                                                          mutually agreed if the receiver is not
                                                                          an RTO/ISO.
FUEL CHARGE..........................         [check]          [check]   Charge based on the cost or amount of
                                                                          fuel used for generation.
GENERATOR IMBALANCE..................         [check]          [check]   Service provided when a difference
                                                                          occurs between the output of a
                                                                          generator located in the Transmission
                                                                          Provider's Control Area and a delivery
                                                                          schedule from that generator to (1)
                                                                          another Control Area or (2) a load
                                                                          within the Transmission Provider's
                                                                          Control Area over a single hour
                                                                          (Ancillary Service). For Contracts,
                                                                          reported if the contract provides for
                                                                          sale of the product. For Transactions,
                                                                          sales by third-party providers (i.e.,
                                                                          non-transmission function) are
                                                                          reported.
GRANDFATHERED BUNDLED................         [check]          [check]   Services provided for bundled
                                                                          transmission, ancillary services and
                                                                          energy under contracts effective prior
                                                                          to Order No. 888's OATTs.
INTERCONNECTION AGREEMENT............         [check]   ...............  Contract that provides the terms and
                                                                          conditions for a generator,
                                                                          distribution system owner,
                                                                          transmission owner, transmission
                                                                          provider, or transmission system to
                                                                          physically connect to a transmission
                                                                          system or distribution system.
MEMBERSHIP AGREEMENT.................         [check]   ...............  Agreement to participate and be subject
                                                                          to rules of a system operator.
MUST RUN AGREEMENT...................         [check]   ...............  An agreement that requires a unit to
                                                                          run.
NEGOTIATED-RATE TRANSMISSION.........         [check]          [check]   Transmission performed under a
                                                                          negotiated rate contract (applies only
                                                                          to merchant transmission companies).
NETWORK..............................         [check]   ...............  Transmission service under contract
                                                                          providing network service.
NETWORK OPERATING AGREEMENT..........         [check]   ...............  An executed agreement that contains the
                                                                          terms and conditions under which a
                                                                          network customer operates its
                                                                          facilities and the technical and
                                                                          operational matters associated with
                                                                          the implementation of network
                                                                          integration transmission service.
OTHER................................         [check]          [check]   Product name not otherwise included.

[[Page 61932]]

 
POINT-TO-POINT AGREEMENT.............         [check]   ...............  Transmission service under contract
                                                                          between specified Points of Receipt
                                                                          and Delivery.
REACTIVE SUPPLY & VOLTAGE CONTROL....         [check]          [check]   Production or absorption of reactive
                                                                          power to maintain voltage levels on
                                                                          transmission systems (Ancillary
                                                                          Service).
REAL POWER TRANSMISSION LOSS.........         [check]          [check]   The loss of energy, resulting from
                                                                          transporting power over a transmission
                                                                          system.
REASSIGNMENT AGREEMENT...............         [check]   ...............  Transmission capacity reassignment
                                                                          agreement.
REGULATION & FREQUENCY RESPONSE......         [check]          [check]   Service providing for continuous
                                                                          balancing of resources (generation and
                                                                          interchange) with load, and for
                                                                          maintaining scheduled interconnection
                                                                          frequency by committing on-line
                                                                          generation where output is raised or
                                                                          lowered and by other non-generation
                                                                          resources capable of providing this
                                                                          service as necessary to follow the
                                                                          moment-by-moment changes in load
                                                                          (Ancillary Service). For Contracts,
                                                                          reported if the contract provides for
                                                                          sale of the product. For Transactions,
                                                                          sales by third-party providers (i.e.,
                                                                          non-transmission function) are
                                                                          reported.
REQUIREMENTS SERVICE.................         [check]          [check]   Firm, load-following power supply
                                                                          necessary to serve a specified share
                                                                          of customer's aggregate load during
                                                                          the term of the agreement.
                                                                          Requirements service may include some
                                                                          or all of the energy, capacity and
                                                                          ancillary service products. (If the
                                                                          components of the requirements service
                                                                          are priced separately, they should be
                                                                          reported separately in the
                                                                          transactions tab.)
SCHEDULE SYSTEM CONTROL & DISPATCH...         [check]          [check]   Scheduling, confirming and implementing
                                                                          an interchange schedule with other
                                                                          Balancing Authorities, including
                                                                          intermediary Balancing Authorities
                                                                          providing transmission service, and
                                                                          ensuring operational security during
                                                                          the interchange transaction (Ancillary
                                                                          Service).
SPINNING RESERVE.....................         [check]          [check]   Unloaded synchronized generating
                                                                          capacity that is immediately
                                                                          responsive to system frequency and
                                                                          that is capable of being loaded in a
                                                                          short time period or non-generation
                                                                          resources capable of providing this
                                                                          service (Ancillary Service). For
                                                                          Contracts, reported if the contract
                                                                          provides for sale of the product. For
                                                                          Transactions, sales by third-party
                                                                          providers (i.e., non-transmission
                                                                          function) are reported.
SUPPLEMENTAL RESERVE.................         [check]          [check]   Service needed to serve load in the
                                                                          event of a system contingency,
                                                                          available with greater delay than
                                                                          SPINNING RESERVE. This service may be
                                                                          provided by generating units that are
                                                                          on-line but unloaded, by quick-start
                                                                          generation, or by interruptible load
                                                                          or other non-generation resources
                                                                          capable of providing this service
                                                                          (Ancillary Service). For Contracts,
                                                                          reported if the contract provides for
                                                                          sale of the product. For Transactions,
                                                                          sales by third-party providers (i.e.,
                                                                          non-transmission function) are
                                                                          reported.
SYSTEM OPERATING AGREEMENTS..........         [check]   ...............  An executed agreement that contains the
                                                                          terms and conditions under which a
                                                                          system or network customer shall
                                                                          operate its facilities and the
                                                                          technical and operational matters
                                                                          associated with the implementation of
                                                                          network.
TOLLING ENERGY.......................         [check]          [check]   Energy sold from a plant whereby the
                                                                          buyer provides fuel to a generator
                                                                          (seller) and receives power in return
                                                                          for pre-established fees.
TRANSMISSION OWNERS AGREEMENT........         [check]   ...............  The agreement that establishes the
                                                                          terms and conditions under which a
                                                                          transmission owner transfers
                                                                          operational control over designated
                                                                          transmission facilities.
UPLIFT...............................         [check]          [check]   A make-whole payment by an RTO/ISO to a
                                                                          utility.
----------------------------------------------------------------------------------------------------------------

          EQR Data Dictionary--Appendix B. Balancing Authority
------------------------------------------------------------------------
       Balancing authority             Abbreviation        Outside US*
------------------------------------------------------------------------
AESC, LLC--Wheatland CIN........  AEWC                   ...............
Alabama Electric Cooperative,     AEC                    ...............
 Inc.
Alberta Electric System Operator  AESO                          [check]
Alliant Energy Corporate          ALTE                   ...............
 Services, LLC--East.
Alliant Energy Corporate          ALTW                   ...............
 Services, LLC--West.
Ameren Transmission. Illinois...  AMIL                   ...............
Ameren Transmission. Missouri...  AMMO                   ...............
American Transmission Systems,    FE                     ...............
 Inc.
Aquila Networks--Kansas.........  WPEK                   ...............
Aquila Networks--Missouri Public  MPS                    ...............
 Service.
Aquila Networks--West Plains      WPEC                   ...............
 Dispatch.
Arizona Public Service Company..  AZPS                   ...............
Associated Electric Cooperative,  AECI                   ...............
 Inc.
Avista Corp.....................  AVA                    ...............
Batesville Balancing Authority..  BBA                    ...............
BC Hydro T & D--Grid Operations.  BCHA                          [check]
Big Rivers Electric Corp........  BREC                   ...............
Board of Public Utilities.......  KACY                   ...............
Bonneville Power Administration   BPAT                   ...............
 Transmission.

[[Page 61933]]

 
British Columbia Transmission     BCTC                          [check]
 Corporation.
California Independent System     CISO                   ...............
 Operator.
Carolina Power & Light Company--  CPLW                   ...............
 CPLW.
Carolina Power and Light          CPLE                   ...............
 Company--East.
Central and Southwest...........  CSWS                   ...............
Chelan County PUD...............  CHPD                   ...............
Cinergy Corporation.............  CIN                    ...............
City of Homestead...............  HST                    ...............
City of Independence P&L Dept...  INDN                   ...............
City of Tallahassee.............  TAL                    ...............
City Water Light & Power........  CWLP                   ...............
City Utilities of Springfield...  SPRM                   ...............
Cleco Power LLC.................  CLEC                   ...............
Columbia Water & Light..........  CWLD                   ...............
Comision Federal de Electricidad  CFE                           [check]
Comision Federal de Electricidad  CFEN                          [check]
Constellation Energy Control and  GRIF                   ...............
 Dispatch.
Constellation Energy Control and  PUPP                   ...............
 Dispatch--Arkansas.
Constellation Energy Control and  BUBA                   ...............
 Dispatch--City of Benton, AR.
Constellation Energy Control and  DERS                   ...............
 Dispatch--City of Ruston, LA.
Constellation Energy Control and  CNWY                   ...............
 Dispatch--Conway, Arkansas.
Constellation Energy Control and  GRMA                   ...............
 Dispatch--Gila River.
Constellation Energy Control and  GWA                    ...............
 Dispatch--Glacier Wind Energy.
Constellation Energy Control and  HGMA                   ...............
 Dispatch--Harquehala.
Constellation Energy Control and  DENL                   ...............
 Dispatch--North Little Rock, AK.
Constellation Energy Control and  OMLP                   ...............
 Dispatch--Osceola Municipal
 Light.
Constellation Energy Control and  PLUM                   ...............
 Dispatch--Plum Point.
Constellation Energy Control and  REDM                   ...............
 Dispatch--Red Mesa.
Constellation Energy Control and  WMUC                   ...............
 Dispatch--West Memphis,
 Arkansas.
Dairyland Power Cooperative.....  DPC                    ...............
DECA, LLC--Arlington Valley.....  DEAA                   ...............
Duke Energy Corporation.........  DUK                    ...............
East Kentucky Power Cooperative,  EKPC                   ...............
 Inc.
El Paso Electric................  EPE                    ...............
Electric Energy, Inc............  EEI                    ...............
Empire District Electric Co.,     EDE                    ...............
 The.
Entergy.........................  EES                    ...............
ERCOT ISO.......................  ERCO                   ...............
Florida Municipal Power Pool....  FMPP                   ...............
Florida Power & Light...........  FPL                    ...............
Florida Power Corporation.......  FPC                    ...............
Gainesville Regional Utilities..  GVL                    ...............
Grand River Dam Authority.......  GRDA                   ...............
Grant County PUD No. 2..........  GCPD                   ...............
Great River Energy..............  GRE                    ...............
Great River Energy..............  GREC                   ...............
Great River Energy..............  GREN                   ...............
Great River Energy..............  GRES                   ...............
GridAmerica.....................  GA                     ...............
Hoosier Energy..................  HE                     ...............
Hydro-Quebec, TransEnergie......  HQT                           [check]
Idaho Power Company.............  IPCO                   ...............
Imperial Irrigation District....  IID                    ...............
Indianapolis Power & Light        IPL                    ...............
 Company.
ISO New England Inc.............  ISNE                   ...............
JEA.............................  JEA                    ...............
Kansas City Power & Light, Co...  KCPL                   ...............
Lafayette Utilities System......  LAFA                   ...............
LG&E Energy Transmission          LGEE                   ...............
 Services.
Lincoln Electric System.........  LES                    ...............
Los Angeles Department of Water   LDWP                   ...............
 and Power.
Louisiana Energy & Power          LEPA                   ...............
 Authority.
Louisiana Generating, LLC.......  LAGN                   ...............
Louisiana Generating, LLC--City   CWAY                   ...............
 of Conway.
Louisiana Generating, LLC--City   WMU                    ...............
 of West Memphis.
Louisiana Generating, LLC--North  NLR                    ...............
 Little Rock.
Madison Gas and Electric Company  MGE                    ...............
Manitoba Hydro Electric Board,    MHEB                          [check]
 Transmission Services.
Michigan Electric Coordinated     MECS                   ...............
 System.
Michigan Electric Coordinated     CONS                   ...............
 System--CONS.
Michigan Electric Coordinated     DECO                   ...............
 System--DECO.
MidAmerican Energy Company......  MEC                    ...............

[[Page 61934]]

 
Midwest ISO.....................  MISO                   ...............
Minnesota Power, Inc............  MP                     ...............
Montana-Dakota Utilities Co.....  MDU                    ...............
Muscatine Power and Water.......  MPW                    ...............
Nebraska Public Power District..  NPPD                   ...............
Nevada Power Company............  NEVP                   ...............
New Brunswick System Operator...  NBSO                          [check]
New Horizons Electric             NHC1                   ...............
 Cooperative.
New York Independent System       NYIS                   ...............
 Operator.
Northern Indiana Public Service   NIPS                   ...............
 Company.
Northern States Power Company...  NSP                    ...............
NorthWestern Energy.............  NWMT                   ...............
Ohio Valley Electric Corporation  OVEC                   ...............
Oklahoma Gas and Electric.......  OKGE                   ...............
Ontario--Independent Electricity  ONT                           [check]
 System Operator.
OPPDCA/TP.......................  OPPD                   ...............
Otter Tail Power Company........  OTP                    ...............
P.U.D. No. 1 of Douglas County..  DOPD                   ...............
PacifiCorp-East.................  PACE                   ...............
PacifiCorp-West.................  PACW                   ...............
PJM Interconnection.............  PJM                    ...............
Portland General Electric.......  PGE                    ...............
Public Service Company of         PSCO                   ...............
 Colorado.
Public Service Company of New     PNM                    ...............
 Mexico.
Puget Sound Energy Transmission.  PSEI                   ...............
Reedy Creek Improvement District  RC                     ...............
Sacramento Municipal Utility      SMUD                   ...............
 District.
Salt River Project..............  SRP                    ...............
Santee Cooper...................  SC                     ...............
SaskPower Grid Control Centre...  SPC                           [check]
Seattle City Light..............  SCL                    ...............
Seminole Electric Cooperative...  SEC                    ...............
Sierra Pacific Power Co.--        SPPC                   ...............
 Transmission.
South Carolina Electric & Gas     SCEG                   ...............
 Company.
South Mississippi Electric Power  SME                    ...............
 Association.
South Mississippi Electric Power  SMEE                   ...............
 Association.
Southeastern Power                SEHA                   ...............
 Administration--Hartwell.
Southeastern Power                SERU                   ...............
 Administration--Russell.
Southeastern Power                SETH                   ...............
 Administration--Thurmond.
Southern Company Services, Inc..  SOCO                   ...............
Southern Illinois Power           SIPC                   ...............
 Cooperative.
Southern Indiana Gas & Electric   SIGE                   ...............
 Co.
Southern Minnesota Municipal      SMP                    ...............
 Power Agency.
Southwest Power Pool............  SWPP                   ...............
Southwestern Power                SPA                    ...............
 Administration.
Southwestern Public Service       SPS                    ...............
 Company.
Sunflower Electric Power          SECI                   ...............
 Corporation.
Tacoma Power....................  TPWR                   ...............
Tampa Electric Company..........  TEC                    ...............
Tennessee Valley Authority ESO..  TVA                    ...............
Trading Hub.....................  HUB                    ...............
TRANSLink Management Company....  TLKN                   ...............
Tucson Electric Power Company...  TEPC                   ...............
Turlock Irrigation District.....  TIDC                   ...............
Upper Peninsula Power Co........  UPPC                   ...............
Utilities Commission, City of     NSB                    ...............
 New Smyrna Beach.
Westar Energy--MoPEP Cities.....  MOWR                   ...............
Western Area Power                WACM                   ...............
 Administration--Colorado-
 Missouri.
Western Area Power                WALC                   ...............
 Administration--Lower Colorado.
Western Area Power                WAUE                   ...............
 Administration--Upper Great
 Plains East.
Western Area Power                WAUW                   ...............
 Administration--Upper Great
 Plains West.
Western Farmers Electric          WFEC                   ...............
 Cooperative.
Western Resources dba Westar      WR                     ...............
 Energy.
Wisconsin Energy Corporation....  WEC                    ...............
Wisconsin Public Service          WPS                    ...............
 Corporation.
Yadkin, Inc.....................  YAD                    ...............
------------------------------------------------------------------------
* Balancing authorities outside the United States may only be used in
  the Contract Data section to identify specified receipt/delivery
  points in jurisdictional transmission contracts.

[[Page 61935]]

                  EQR Data Dictionary--Appendix C. Hub
------------------------------------------------------------------------
                HUB                              Definition
------------------------------------------------------------------------
ADHUB.............................  The aggregated Locational Marginal
                                     Price (``LMP'') nodes defined by
                                     PJM Interconnection, LLC as the AEP/
                                     Dayton Hub.
AEPGenHub.........................  The aggregated Locational Marginal
                                     Price (``LMP'') nodes defined by
                                     PJM Interconnection, LLC as the
                                     AEPGenHub.
COB...............................  The set of delivery points along the
                                     California-Oregon commonly
                                     identified as and agreed to by the
                                     counterparties to constitute the
                                     COB Hub.
Cinergy (into)....................  The set of delivery points commonly
                                     identified as and agreed to by the
                                     counterparties to constitute
                                     delivery into the Cinergy balancing
                                     authority.
Cinergy Hub (MISO)................  The aggregated Elemental Pricing
                                     nodes (``Epnodes'') defined by the
                                     Midwest Independent Transmission
                                     System Operator, Inc., as Cinergy
                                     Hub (MISO).
Entergy (into)....................  The set of delivery points commonly
                                     identified as and agreed to by the
                                     counterparties to constitute
                                     delivery into the Entergy balancing
                                     authority.
FE Hub............................  The aggregated Elemental Pricing
                                     nodes (``Epnodes'') defined by the
                                     Midwest Independent Transmission
                                     System Operator, Inc., as FE Hub
                                     (MISO).
Four Corners......................  The set of delivery points at the
                                     Four Corners power plant commonly
                                     identified as and agreed to by the
                                     counterparties to constitute the
                                     Four Corners Hub.
Illinois Hub (MISO)...............  The aggregated Elemental Pricing
                                     nodes (``Epnodes'') defined by the
                                     Midwest Independent Transmission
                                     System Operator, Inc., as Illinois
                                     Hub (MISO).
Mead..............................  The set of delivery points at or
                                     near Hoover Dam commonly identified
                                     as and agreed to by the
                                     counterparties to constitute the
                                     Mead Hub.
Michigan Hub (MISO)...............  The aggregated Elemental Pricing
                                     nodes (``Epnodes'') defined by the
                                     Midwest Independent Transmission
                                     System Operator, Inc., as Michigan
                                     Hub (MISO).
Mid-Columbia (Mid-C)..............  The set of delivery points along the
                                     Columbia River commonly identified
                                     as and agreed to by the
                                     counterparties to constitute the
                                     Mid-Columbia Hub.
Minnesota Hub (MISO)..............  The aggregated Elemental Pricing
                                     nodes (``Epnodes'') defined by the
                                     Midwest Independent Transmission
                                     System Operator, Inc., as Minnesota
                                     Hub (MISO).
NEPOOL (Mass Hub).................  The aggregated Locational Marginal
                                     Price (``LMP'') nodes defined by
                                     ISO New England Inc., as Mass Hub.
NIHUB.............................  The aggregated Locational Marginal
                                     Price (``LMP'') nodes defined by
                                     PJM Interconnection, LLC as the
                                     Northern Illinois Hub.
NOB...............................  The set of delivery points along the
                                     Nevada-Oregon border commonly
                                     identified as and agreed to by the
                                     counterparties to constitute the
                                     NOB Hub.
NP15..............................  The set of delivery points north of
                                     Path 15 on the California
                                     transmission grid commonly
                                     identified as and agreed to by the
                                     counterparties to constitute the
                                     NP15 Hub.
NWMT..............................  The set of delivery points commonly
                                     identified as and agreed to by the
                                     counterparties to constitute
                                     delivery into the Northwestern
                                     Energy Montana balancing authority.
PJM East Hub......................  The aggregated Locational Marginal
                                     Price nodes (``LMP'') defined by
                                     PJM Interconnection, LLC as the PJM
                                     East Hub.
PJM South Hub.....................  The aggregated Locational Marginal
                                     Price (``LMP'') nodes defined by
                                     PJM Interconnection, LLC as the PJM
                                     South Hub.
PJM West Hub......................  The aggregated Locational Marginal
                                     Price (``LMP'') nodes defined by
                                     PJM Interconnection, LLC as the PJM
                                     Western Hub.
Palo Verde........................  The switch yard at the Palo Verde
                                     nuclear power station west of
                                     Phoenix in Arizona. Palo Verde Hub
                                     includes the Hassayampa switchyard
                                     2 miles south of Palo Verde.
SOCO (into).......................  The set of delivery points commonly
                                     identified as and agreed to by the
                                     counterparties to constitute
                                     delivery into the Southern Company
                                     balancing authority.
SP15..............................  The set of delivery points south of
                                     Path 15 on the California
                                     transmission grid commonly
                                     identified as and agreed to by the
                                     counterparties to constitute the
                                     SP15 Hub.
TVA (into)........................  The set of delivery points commonly
                                     identified as and agreed to by the
                                     counterparties to constitute
                                     delivery into the Tennessee Valley
                                     Authority balancing authority.
ZP26..............................  The set of delivery points
                                     associated with Path 26 on the
                                     California transmission grid
                                     commonly identified as and agreed
                                     to by the counterparties to
                                     constitute the ZP26 Hub.
------------------------------------------------------------------------

               EQR Data Dictionary--Appendix D. Time Zone
------------------------------------------------------------------------
                 Time zone                           Definition
------------------------------------------------------------------------
AD........................................  Atlantic Daylight.
AP........................................  Atlantic Prevailing.
AS........................................  Atlantic Standard.
CD........................................  Central Daylight.
CP........................................  Central Prevailing.
CS........................................  Central Standard.
ED........................................  Eastern Daylight.
EP........................................  Eastern Prevailing.
ES........................................  Eastern Standard.
MD........................................  Mountain Daylight.
MP........................................  Mountain Prevailing.
MS........................................  Mountain Standard.
NA........................................  Not Applicable.
PD........................................  Pacific Daylight.
PP........................................  Pacific Prevailing.
PS........................................  Pacific Standard.
UT........................................  Universal Time.
------------------------------------------------------------------------

                 EQR Data Dictionary--Appendix E. Units
------------------------------------------------------------------------
                   Units                             Definition
------------------------------------------------------------------------
KV........................................  Kilovolt.
KVA.......................................  Kilovolt Amperes.
KVR.......................................  Kilovar.
KW........................................  Kilowatt.
KWH.......................................  Kilowatt Hour.
KW-DAY....................................  Kilowatt Day.
KW-MO.....................................  Kilowatt Month.
KW-WK.....................................  Kilowatt Week.
KW-YR.....................................  Kilowatt Year.
MVAR-YR...................................  Megavar Year.
MW........................................  Megawatt.
MWH.......................................  Megawatt Hour.
MW-DAY....................................  Megawatt Day.
MW-MO.....................................  Megawatt Month.
MW-WK.....................................  Megawatt Week.

[[Page 61936]]

 
MW-YR.....................................  Megawatt Year.
RKVA......................................  Reactive Kilovolt Amperes.
FLAT RATE.................................   Flat Rate.
------------------------------------------------------------------------

               EQR Data Dictionary--Appendix F. Rate Units
------------------------------------------------------------------------
                Rate units                           Definition
------------------------------------------------------------------------
$/KV......................................  dollars per kilovolt.
$/KVA.....................................  dollars per kilovolt
                                             amperes.
$/KVR.....................................  dollars per kilovar.
$/KW......................................  dollars per kilowatt.
$/KWH.....................................  dollars per kilowatt hour.
$/KW-DAY..................................  dollars per kilowatt day.
$/KW-MO...................................  dollars per kilowatt month.
$/KW-WK...................................  dollars per kilowatt week.
$/KW-YR...................................  dollars per kilowatt year.
$/MW......................................  dollars per megawatt.
$/MWH.....................................  dollars per megawatt hour.
$/MW-DAY..................................  dollars per megawatt day.
$/MW-MO...................................  dollars per megawatt month.
$/MW-WK...................................  dollars per megawatt week.
$/MW-YR...................................  dollars per megawatt year.
$/MVAR-YR.................................  dollars per megavar year.
$/RKVA....................................  dollars per reactive kilovar
                                             amperes.
CENTS.....................................  cents.
CENTS/KVR.................................  cents per kilovolt amperes.
CENTS/KWH.................................  cents per kilowatt hour.
FLAT RATE.................................  rate not specified in any
                                             other units.
------------------------------------------------------------------------

         EQR Data Dictionary--Appendix G. Index Price Publisher
------------------------------------------------------------------------
 Index price publisher  abbreviation         Index price publisher
------------------------------------------------------------------------
AM..................................  Argus Media.
EIG.................................  Energy Intelligence Group, Inc.
IP..................................  Intelligence Press.
P...................................  Platts.
B...................................  Bloomberg.
DJ..................................  Dow Jones.
Pdx.................................  Powerdex.
SNL.................................  SNL Energy.
------------------------------------------------------------------------

        EQR Data Dictionary--Appendix H. Exchange/Broker Services
------------------------------------------------------------------------
        Exchange/brokerage service                   Definition
------------------------------------------------------------------------
BROKER....................................  A broker was used to
                                             consummate or effectuate
                                             the transaction.
ICE.......................................  Intercontinental Exchange .
NYMEX.....................................  New York Mercantile Exchange
                                             .
------------------------------------------------------------------------

    Note: Attachment B will not be published in the Code of Federal 
Regulations.

Attachment B: List of Commenters on the NOPR
---------------------------------------------------------------------------

    \281\ Filed only a motion to intervene.

------------------------------------------------------------------------
       Short name or acronym                      Commenter
------------------------------------------------------------------------
Allegheny.........................  Allegheny Electric Cooperative.
APPA..............................  American Public Power Association.
Associated Electric Cooperative...  Associated Electric Cooperative,
                                     Inc.
California DWR....................  California Department of Water
                                     Resources State Water Project.
Cities/M-S-R......................  City of Redding, California, City of
                                     Santa Clara, California, and M-S-R
                                     Public Power Agency.
DC Energy.........................  DC Energy, LLC.
EDF Trading.......................  EDF Trading North America, LLC.
EEI...............................  Edison Electric Institute.
EPSA..............................  Electric Power Supply Association.
Entergy...........................  Entergy Services, Inc.
Financial Institutions Energy       Financial Institutions Energy Group.
 Group.
Joint Commenters..................  American Public Power Associated;
                                     Edison Electric Institute; Large
                                     Public Power Council; and National
                                     Rural Electric Cooperative
                                     Association.
Joint Market Monitors.............  North American Market Monitors Joint
                                     Comments.
LPPC..............................  Large Public Power Council.
MISO..............................  Midwest Independent Transmission
                                     System Operator, Inc.
Northern California Power Agency..  Northern California Power Agency.
NRECA.............................  National Rural Electric Cooperative
                                     Association.
NYMPA/MEUA........................  New York Municipal Power Agency and
                                     Municipal Electric Utilities
                                     Association of New York.
Pacific Northwest IOUs............  Avista Corporation; Portland General
                                     Electric Company; and Puget Sound
                                     Energy Company.
Pennsylvania Commission...........  Pennsylvania Public Utility
                                     Commission.
Powerex...........................  Powerex Corporation.
PSEG Companies....................  PSEG Companies \281\.
Public Systems....................  Connecticut Municipal Electric
                                     Energy Cooperative, Massachusetts
                                     Municipal Wholesale Electric
                                     Company, and New Hampshire Electric
                                     Cooperative, Inc.
Shell Energy......................  Shell Energy North America, L.P.
South Mississippi Electric........  South Mississippi Electric Power
                                     Association.
Southwestern Power Association....  Southwestern Power Administration.
TAPS..............................  Transmission Access Policy Study
                                     Group.
Transmission Dependent Utility      Transmission Dependent Utility
 Systems.                            Systems.
Westar............................  Westar Energy, Inc.
------------------------------------------------------------------------

[FR Doc. 2012-23746 Filed 10-10-12; 8:45 am]
BILLING CODE 6717-01-P