[Federal Register Volume 77, Number 197 (Thursday, October 11, 2012)]
[Rules and Regulations]
[Pages 61896-61936]
From the Federal Register Online via the Government Publishing 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,
[email protected].
Steven Reich, Office of Enforcement, Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6446,
[email protected].
Christina Switzer, Office of the General Counsel, Federal Energy
Regulatory Commission, 888 First Street NE., Washington, DC 20426,
(202) 502-6379, [email protected].
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.
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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.
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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.
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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.
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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\
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\141\ Southwestern Power Administration at 2-3.
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78. California DWR argues that the NOPR fails to comply with
Federal statutes that require the Commission to carefully consider the
costs and benefits of imposing burdens on governmental entities. For
instance, California DWR states that the Paperwork Reduction Act
requires agencies to certify that a new reporting requirement is not
unnecessarily duplicative and that the Unfunded Mandates Reform Act of
1995 requires agencies to prepare a written statement of
intergovernmental mandates that describe the analyses and consultations
on the unfunded mandate.\142\ California DWR also states that Executive
Order 12866 requires agencies to propose or adopt regulations after it
determines that the benefits of the intended regulation justify the
costs and that the Regulatory Right to Know Act requires agencies to
conduct cost-benefit analysis of their regulatory initiatives and
report their findings to the Office of Management and Budget.\143\
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\142\ California DWR at 6-7 (citing Paperwork Reduction Act, 44
U.S.C. 3506(c)(3) (2006); Unfunded Mandates Reform Act of 1995, 2
U.S.C. 1531, et seq. (2006)).
\143\ Id. at 5-6 (citing Executive Order 12866, 58 FR 51735
(Oct. 4, 1993); Regulatory Right to Know Act, 31 U.S.C. 1105
(2006)).
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79. Southwestern Power Administration states that it does not have
the staffing needed to track and report EQR data, and that hiring
additional staff to comply would pose increased costs with no
commensurate benefit to its customers or incremental improvement to
market transparency.\144\ California DWR argues that the NOPR as
written would give non-public utilities an incentive to self-supply to
avoid wholesale power sales in order to reduce reporting burdens, which
appears contrary to business requirements.\145\
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\144\ Southwestern Power Administration at 4.
\145\ California DWR at 7.
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80. If the Commission requires non-public utilities to submit EQRs,
then NRECA argues that the Commission could reduce the burden on non-
public utilities by simplifying the filing requirements as it relates
to billing adjustments. NRECA states that it is common practice for a
cooperative to bill its members under long-term contracts on the basis
of budgets and that these charges are later trued-up to reflect the
actual costs associated with the sale. NRECA states that EQR
regulations require entities to file either revised EQRs or new
transactions with the class name ``Billing Adjustments'' to report
changes in billing data after the initial EQR filing deadlines. NRECA
asserts that it would be very burdensome for cooperatives that use
budget-based billing to submit revised EQRs or Billing Adjustments to
reflect true-ups to actual costs. Thus, NRECA argues that the
Commission should simplify the filing requirements for cooperatives
that use budget-based billing by specifying that true-ups associated
with budget-based billing do not trigger the requirement to submit
revised EQRs or Billing Adjustments.\146\
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\146\ NRECA at 18-19.
---------------------------------------------------------------------------
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.
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iii. Commission Determination
82. The Commission has carefully weighed, in developing this Final
Rule, the burden associated with an entity filing the EQR against the
benefits associated with greater transparency in the nation's wholesale
electric markets. The Commission concludes that the burden of reporting
information in the EQR is outweighed by the benefits of greater
transparency provided by the EQR.
83. The burden of preparing an EQR filing varies, depending on the
complexity of a company's transactions. If a company has a few long-
term contracts of limited complexity, its EQR filing is simple: an
unchanging description of its contracts from quarter to quarter with
monthly or quarterly reports of the transactions under that contract.
As the company's sales activities become more complex, with more
frequent adjustments to price and a greater variety of counterparties
and sales locations, its technological capabilities for tracking its
transactions tend to become more sophisticated. As a result, complex,
detailed EQRs tend to be associated with companies more capable of
generating such a filing. Filers whose participation in the electric
wholesale markets occurs under long-term, cost-based contracts with a
limited number of counterparties will expend relatively little effort
in complying with the EQR filing requirement. In addition, we believe
that excluding from the reporting requirement sales by non-public
utilities under long-term, cost-based agreements required to be made to
certain customers under Federal or state statute will help lessen the
burden on non-public utilities. Therefore, we believe that non-public
utilities would not be encouraged to self-supply to avoid the reporting
requirements, as suggested by California DWR.
84. In response to NRECA's concern about the difficulty for non-
public utility cooperatives that use budget-based billing to submit
revised EQRs or billing adjustments to reflect true-ups or actual
costs, the Commission will not require true-ups by non-public utility
cooperatives with budget-based billing in the EQR. The Commission's
policy regarding refilings or billing adjustments stems from the
statutory requirement under FPA section 205(c) to have a public
utility's rates on file. Specifically, in recognition of the fact that
public utilities may not have complete, final data for the full quarter
by EQR filing deadlines, the Commission requires that any additions or
changes to an EQR filing must be made by the end of the following
quarter, when the filer is expected to file the best available new
data.\148\ Filers are
[[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.
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85. We agree with LPPC that the Commission should provide
sufficient lead time to enable non-public utilities to comply. Over the
past ten years, the Commission has been proactive in its outreach on
many aspects of the EQR; in issuing this Final Rule, the Commission
acknowledges that new filers will need the opportunity to learn about
the filing. Accordingly, non-public utility filers are required to file
EQRs beginning with the third quarter (Q3) of 2013, covering the period
July through September 2013. The Commission directs staff to assist
filers with compliance. For example, the Commission intends to convene
a staff-led technical conference, to be announced at a future date, to
assist non-public utilities in collecting and filing EQR data.
B. Refinements to the Existing EQR Requirements
1. General Refinements
a. Trade Date & Time and Type of Rate
i. NOPR
86. In the NOPR, the Commission proposed to require any market
participant that is required to file an EQR to report in the EQR the
date on which parties to a reported transaction agreed upon a price
(trade date) and the type of rate by which the price was set. The
Commission stated in the NOPR that the term ``trade date'' means ``the
date upon which the parties agree upon the price of a transaction.''
The Commission also proposed four types of rates: ``fixed,''
``formula,'' ``index,'' and ``RTO/ISO price.'' A fixed rate would be
defined as a fixed charge per unit of consumption. A formula rate would
be defined as a calculation of a rate based upon a formula that does
not contain an index component. An index rate would be defined as a
calculation of a rate based upon an index or a formula that contains an
index component. An ``RTO/ISO price'' would be defined as a rate that
is based on an RTO/ISO published price or formula that contains an RTO/
ISO price component. The Commission also proposed to require market
participants to report the time of trade, defined as ``the time upon
which the parties agree upon the price of a transaction.''
ii. Comments
87. DC Energy, Joint Market Monitors, and Pennsylvania Commission
support the Commission's proposal to require the trade date and time
and type of rate in EQR.\152\ However, as discussed further below, many
commenters are opposed to parts of the proposal.
---------------------------------------------------------------------------
\152\ See, e.g., DC Energy at 4-5; Joint Market Monitors at 4-5;
and Pennsylvania Commission at 4.
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(a) Trade Date
88. With respect to the proposed requirement to report the trade
date, Powerex states it should not be onerous to report such data
because market participants likely already track it.\153\ However, some
commenters question the need for trade data and note some difficulty in
ascertaining the appropriate date to report. EEI questions the need for
trade date information, arguing that contracts negotiated to cover
specific transactions will include trade-specific details so that
transactions can be distinguished based on the associated contract
information in the EQR. In addition, EEI suggests that, if the
Commission requires reporting of trade dates, it should clarify that
the trade date is the effective date of the legally binding agreement
between parties with respect to the transaction. In this vein, EEI
contends that the ``official'' trade date agreed to by market
participants for each transaction and documented in trade capture
systems and related transaction documentation is the appropriate date
to use. EEI states that its members and other market participants
document the ``official'' date in their trade capture systems and
related transaction documentation. EEI also recommends that the
requirement for trade date apply only to transactions entered into
after the Commission adopts a final rule.\154\
---------------------------------------------------------------------------
\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.
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(1) Commission Determination
90. The Commission adopts, with modification, the NOPR proposal to
require reporting of the trade date in the EQR. The NOPR proposed to
define the trade date as the date on which parties
[[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\
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\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\
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\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.
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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.
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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\
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\173\ Id. at 14.
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(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.
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(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.
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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.
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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\
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\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.
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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.
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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.
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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.
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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 [email protected] 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\
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\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 [email protected] 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.
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\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.
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\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: [email protected], 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 [email protected]. 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
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
[email protected].
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