140 FERC ¶ 61,232 

UNITED STATES OF AMERICA 

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 

(Issued September 21, 2012) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Final Rule. 

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: (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 
Docket No. RM10-12-000 - 2 - 

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.

EFFECTIVE DATE: This rule will become effective [Insert date 60 days after 

publication in the FEDERAL REGISTER]

FOR FURTHER INFORMATION CONTACT: 

Maria Vouras 

Office of Enforcement 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

(202) 502-8062 

Maria.Vouras@ferc.gov 

Steven Reich 

Office of Enforcement 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

(202) 502-6446 

Steven.Reich@ferc.gov 

Christina Switzer 

Office of the General Counsel 

Federal Energy Regulatory Commission 
Docket No. RM10-12-000 - 3 - 

888 First Street, NE 

Washington, DC 20426 

(202) 502-6379 

Christina.Switzer@ferc.gov 

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Electricity Market Transparency Provisions of Section 

220 of the Federal Power Act 

Docket No. RM10-12-000 

ORDER NO. 768 

FINAL RULE 

TABLE OF CONTENTS 

 Paragraph Numbers 

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 Utilities ................................... 10.

1. Need for Information from Non-Public Utilities and Commission’s Legal 

Authority ............................................................................................................................ 10.

a. Value of Information from Non-Public Utilities ...................................................... 10.

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.
Docket No. RM10-12-000 ii 

a. Scope of EQR Filing Requirements for Non-Public Utilities .................................. 59.

i. NOPR .................................................................................................................... 59.

ii. Comments ............................................................................................................ 60.

iii. Commission Determination ................................................................................ 73.

b. Burden ...................................................................................................................... 76.

i. NOPR .................................................................................................................... 76.

ii. Comments ............................................................................................................ 77.

iii. Commission Determination ................................................................................ 82.

B. Refinements to the Existing EQR Requirements ............................................................. 86.

1. General Refinements .................................................................................................... 86.

a. Trade Date & Time and Type of Rate ...................................................................... 86.

i. NOPR .................................................................................................................... 86.

ii. Comments ............................................................................................................ 87.

(a) Trade Date ...................................................................................................... 88.

(1) Commission Determination ...................................................................... 90.

(b) Time of Trade ................................................................................................ 96.

(1) Commission Determination ...................................................................... 102.

(c) Type of Rate ................................................................................................... 103.

(1) Commission Determination ...................................................................... 105.

b. Resale of Financial Transmission Rights in Secondary Markets ............................. 109.

i. NOPR .................................................................................................................... 109.

ii. Comments ............................................................................................................ 110.

iii. Commission Determination ................................................................................ 111.

c. Standardizing the Unit for Reporting Energy and Capacity Transactions ............... 112.

i. NOPR .................................................................................................................... 112.

ii. Comments ............................................................................................................ 113.

iii. Commission Determination ................................................................................ 116.

d. Omitting the Time Zone from the Contract Section of the EQR ............................. 119.

i. NOPR .................................................................................................................... 119.

ii. Comments ............................................................................................................ 120.

iii. Commission Determination ................................................................................ 121.

2. Additional EQR Enhancements .................................................................................... 122.

a. Identify Transactions Reported to Index Publishers ................................................ 122.

i. NOPR .................................................................................................................... 122.

ii. Comments ............................................................................................................ 123.

iii. Commission Determination ................................................................................ 127.

b. Identify the Exchange/Broker used to Consummate a Transaction ......................... 132.

i. NOPR .................................................................................................................... 132.

ii. Comments ............................................................................................................ 133.

iii. Commission Determination ................................................................................ 137.

c. Collection of e-Tag ID Data ..................................................................................... 143.
Docket No. RM10-12-000 iii 

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.

Appendix A: Revisions to the EQR Data Dictionary Clean Version 

Appendix B: List of Commenters on the NOPR 

Appendix C: Revisions to the EQR Data Dictionary Redline Version 
140 FERC ¶ 61,232 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Jon Wellinghoff, Chairman; 

 Philip D. Moeller, John R. Norris, 

 Cheryl A. LaFleur, and Tony T. Clark. 

Electricity Market Transparency Provisions of 

Section 220 of the Federal Power Act 

Docket No. RM10-12-000 

ORDER NO. 768 

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 FPA2

 and have more than a de minimis market 

presence to file Electric Quarterly Reports (EQR) with the Commission.3

 After 

 1

 EPAct 2005, Pub. L. No. 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 

(continued...) 
Docket No. RM10-12-000 - 2 - 

consideration of the comments filed in response to the Notice of Proposed Rulemaking 

(NOPR),4

 the Commission concludes that the requirements in this Final Rule will allow 

the Commission and the public to gain a more complete picture of interstate wholesale 

electric power and transmission markets by providing additional information concerning 

price formation and market concentration in these electric markets. Public access to 

additional sales and transmission-related information in the EQR improves market 

participants’ ability to assess supply and demand fundamentals and to price interstate 

wholesale electric market transactions. It also strengthens the Commission’s ability to 

identify potential exercises of market power or manipulation and to better evaluate the 

competitiveness of interstate wholesale electric markets. 

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 

 

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). 
Docket No. RM10-12-000 - 3 - 

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, costbased 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 
Docket No. RM10-12-000 - 4 - 

Commission and the public, and will allow market participants to file the information in 

the most efficient manner possible.5

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 nonpublic 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 

 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). 

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). 
Docket No. RM10-12-000 - 5 - 

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

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 

 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. 

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). 
Docket No. RM10-12-000 - 6 - 

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. 

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 

 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. 

15 16 U.S.C. 824t. 
Docket No. RM10-12-000 - 7 - 

integrity of those markets, fair competition, and the protection of consumers.”16 FPA 

section 220 grants the Commission authority to obtain and disseminate “information 

about the availability and prices of wholesale electric energy and transmission service to 

the Commission, State commissions, buyers and sellers of wholesale electric energy, 

users of transmission services, and the public.”17 The statute specifies that the 

Commission may obtain this information from “any market participant,”18 except for 

entities with a de minimis market presence.19 EPAct 2005 added a similar transparency 

provision in the Natural Gas Act,20 which led to additional filing and posting 

requirements for the sale or transportation of physical natural gas in interstate commerce 

in Order Nos. 704 and 720.21

 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 

(continued...) 
Docket No. RM10-12-000 - 8 - 

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 

 

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). 

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. 
Docket No. RM10-12-000 - 9 - 

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. 

C. Procedural History 

9. On January 21, 2010, the Commission issued a Notice of Inquiry26 seeking 

comments on whether the Commission should apply the EQR filing requirements to nonpublic 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

 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). 

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 Appendix B for a list of commenters and their abbreviated names as used 

here. 
Docket No. RM10-12-000 - 10 - 

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 

 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). 
Docket No. RM10-12-000 - 11 - 

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. 

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 

 31 See id. at 824t(a)(3)(A). 
Docket No. RM10-12-000 - 12 - 

transmission markets. The Commission stated that non-public utilities have a significant 

presence in national and regional wholesale electricity markets32 so that obtaining 

information about their sales transactions is important to unmasking how prices are 

formed in electricity markets. The lack of information from non-public utilities results in 

an incomplete picture of these markets, and hampers the ability of the public and the 

Commission to detect and address the potential exercise of market power and 

manipulation. 

ii. Comments 

12. Several commenters argue that extending the EQR filing requirements to nonpublic 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 

 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, nonpublic 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).32 

The Commission noted that about 29 percent of those wholesale sales were made by nonpublic 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. 

33 See, e.g., California DWR at 1-2; NRECA at 4; NYMPA/MEUA at 3; 

Southwestern Power Administration at 3. 
Docket No. RM10-12-000 - 13 - 

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

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 

 34 NYMPA/MEUA at 3. 

35 Southwestern Power Administration at 3. 

36 APPA at 4; Public Systems at 2; TAPS at 17-20. 

37 APPA at 9-10; NRECA at 8. 
Docket No. RM10-12-000 - 14 - 

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 nonpublic 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

 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. 
Docket No. RM10-12-000 - 15 - 

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

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 

 40 NRECA at 7-8. 

41 Id. 
Docket No. RM10-12-000 - 16 - 

competition, which relies on a lack of market power or adequate mitigation to ensure just 

and reasonable pricing.42

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

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 

 42 Joint Market Monitors at 3.

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. 
Docket No. RM10-12-000 - 17 - 

Pennsylvania Commission’s ability to monitor its retail markets for anti-competitive and 

manipulative behavior.45

18. EEI states that public utilities would benefit from access to EQR information from 

non-public utilities in undertaking analyses used for market-based rate applications.46 In 

contrast, LPPC asserts that information regarding long-term agreements would not assist 

the Commission in conducting a delivered price test (DPT) for market-based rate 

authorizations and mergers. LPPC asserts that the delivered price test measures 

concentration in short-term markets and focuses on the ability of suppliers to deliver 

energy to relevant markets as measured by their short-term variable costs. LPPC 

therefore contends that disclosure of the prices reflected in long-term wholesale contracts 

between non-public utilities would do nothing to improve the accuracy of determining 

either short-term destination market prices or the short-term variable costs of potential 

suppliers.47

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 

 45 Pennsylvania Commission at 7. 

46 EEI at 3-4. 

47 LPPC at 9-10. 
Docket No. RM10-12-000 - 18 - 

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. 

20. The NOPR explained that transactions made by both public utility and non-public 

utility market participants provide critical pricing information that market participants 

 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. 
Docket No. RM10-12-000 - 19 - 

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

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 marketbased rate program is grounded in an ex ante analysis of whether to grant a seller marketbased 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 

 49 NOPR, FERC Stats. & Regs. ¶ 32,676 at P 11. 

50 Id. P 27. 
Docket No. RM10-12-000 - 20 - 

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 

 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 (9thCir. 2004), cert. denied (S. Ct. Nos. 06-888 and 

06-1100, June 18, 2007)). 

52 NOPR, FERC Stats. & Regs. ¶ 32,676 at P 27. 
Docket No. RM10-12-000 - 21 - 

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 nonpublic utilities may not outweigh the burden imposed on the non-public utilities that 

would need to report such sales in the EQR. 

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

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 

 53 16 U.S.C. 824t(f). 
Docket No. RM10-12-000 - 22 - 

rather than 29 percent, as stated in the NOPR. APPA also points out that its calculation 

of non-public utility sales does not exclude certain sales in Alaska, Hawaii and ERCOT 

due to the lack of sufficient detail in EIA data.54 Even if non-public utilities account for 

approximately 19.4 percent of nationwide wholesale sales, as APPA contends, the 

Commission finds this percentage of sales in the nationwide wholesale electricity market 

to be significant. APPA and NRECA also argue that the Commission’s analysis using 

EIA Form 861 data overstated the number of non-public utility wholesale sales in 

regional markets. Although EIA data is not sufficiently detailed to provide a complete 

and precise estimate of wholesale sales made by non-public utilities, the Commission’s 

market analysis using EIA data nevertheless indicates that non-public utilities account for 

a significant portion of sales in certain regional markets. The lack of publicly available 

data regarding non-public utility sales challenges the ability of the public and the 

Commission to rely on existing information sources to form an accurate picture of 

wholesale electricity markets and does not provide the level of price transparency that 

this Final Rule seeks to achieve. 

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 

 54 APPA at 8-9. 
Docket No. RM10-12-000 - 23 - 

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. 

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. 

 55 See NOPR, FERC Stats. & Regs. ¶ 32,676 at P 25. 

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. 
Docket No. RM10-12-000 - 24 - 

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 

 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. 
Docket No. RM10-12-000 - 25 - 

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. 

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, 

 59See id. P 37. 
Docket No. RM10-12-000 - 26 - 

commercial data providers, and through the Open Access Same-Time Information 

System (OASIS). Thus, the Commission proposed to expand EQR filing requirements to 

non-public utilities to provide price transparency that is not available through these 

existing sources of information. 

ii. Comments 

29. Certain commenters agree with the Commission that information available from 

existing price publishers and trade processing services is incomplete and, thus, 

inadequate.60 However, other commenters argue that the Commission’s NOPR is overly 

broad and proposes to collect duplicative information.61 They further argue that the 

Commission must tailor its request to collect information that it currently lacks. 

California DWR asserts that the Paperwork Reduction Act requires the Commission to 

certify that a new reporting requirement such as this one is not unnecessarily duplicative 

of information otherwise reasonably accessible to the Commission. In addition, 

California DWR asserts that FPA section 220(a)(4) similarly requires that, before 

additional reporting to ensure price transparency in electric markets may be ordered, the 

Commission must make a determination that existing data sources are insufficient. 

 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. 
Docket No. RM10-12-000 - 27 - 

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

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

 62 California DWR at 3, 5-6. 

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. 
Docket No. RM10-12-000 - 28 - 

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

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 

 67 NRECA at 5. 

68 California DWR at 3; Public Systems at 14; TAPS at 18. 

69 California DWR at 2-3. 
Docket No. RM10-12-000 - 29 - 

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. 

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 

 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. 
Docket No. RM10-12-000 - 30 - 

transactions and sales outside the RTO markets in its EQR along with voluminous 

market-settlement data that they receive from the RTO.72

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 rereport 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

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 

 72 Id. at 15. 

73 California DWR at 4-5. 

74 EEI at 6. 
Docket No. RM10-12-000 - 31 - 

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. 

36. In general, the Commission and the public need a more compete picture of 

markets across the country, including smaller markets, even if a significant part of those 

markets is served by non-public utilities. Market dynamics, including markets dominated 

by non-public utilities, can change throughout the year through a host of factors including 

weather conditions, outages, and contract expirations. 

37. Annual data collections from two of the most significant publicly available forms 

that capture information about non-public utility power sales, the EIA Form 861 and the 

RUS Form 12, do not provide sufficiently detailed or timely information to assess those 

market dynamics. As stated in the NOPR, EIA Form 861 does not detail individual 

wholesale transactions, including the counterparty, location, price, and delivery 

 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. 
Docket No. RM10-12-000 - 32 - 

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

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-

 77 See NOPR, FERC Stats. & Regs. ¶ 32,676 at P 35. 

78 Id.

79 Id. P 25. 

80 Id.
Docket No. RM10-12-000 - 33 - 

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

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 

 81 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 336. 

82 Order No. 2001-E, 105 FERC ¶ 61,352 at P 12. 
Docket No. RM10-12-000 - 34 - 

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. 
Docket No. RM10-12-000 - 35 - 

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

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 

 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. 

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. 
Docket No. RM10-12-000 - 36 - 

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

43. EEI submits that setting the threshold at 4,000,000 MWh would still leave a 

significant portion of the market unreported. EEI states that by setting the threshold at 

1,000,000 MWh, the Commission would gain substantial additional information while 

inconveniencing a modest number of non-public utilities. EEI explains that, according to 

the EIA, of the 3,265 entities (including both public and non-public utilities) that filed the 

Form EIA-861 in 2009, 138 had sales over 4,000,000 MWh representing 91.8 percent of 

total U.S. wholesale sales, whereas 254 had sales over 1,000,000 MWh representing 

98.7 percent of total U.S. wholesale sales. Of the 116 entities with sales between 

1,000,000 and 4,000,000 MWh, EEI asserts that 67 were public power agencies and 

cooperatives representing approximately 3.9 percent of total U.S. wholesale sales, and the 

remaining 49 were investor-owned utilities and private power marketers representing 

3.0 percent of such sales.88 EEI further states that according to the NOPR’s burden 

statement, only five non-public utility Balancing Authorities are picked up if the 

threshold for Balancing Authorities is reduced from 4,000,000 to 1,000,000 MWh.89

 87 DC Energy at 5. 

88 EEI at 8 (citing NOPR, FERC Stats. & Regs. ¶ 32,676 at P 125). 

89 Id.
Docket No. RM10-12-000 - 37 - 

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

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 

 90 See, e.g., NRECA at 16; TAPS at 6. 

91 NRECA at 16-17. 
Docket No. RM10-12-000 - 38 - 

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

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

 92 TAPS at 6. 

93 Shell at 12. 
Docket No. RM10-12-000 - 39 - 

(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

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. 

 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. 

98 Id. at 10-11. 
Docket No. RM10-12-000 - 40 - 

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

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

 99 Allegheny at 4-5. 

100 NRECA at 11-12; Allegheny at 5; Transmission Dependent Utility Systems at 

5; Public Systems at 11. 

101 NRECA at 11-12. 
Docket No. RM10-12-000 - 41 - 

50. NRECA further alleges that the Commission’s justification for including intrafamilial 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

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 

 102 Id. at 12. 

103 Transmission Dependent Utility Systems at 8. 

104 TAPS at 10. 
Docket No. RM10-12-000 - 42 - 

cooperatives in a three-tier system to report their sales on their EQRs, because this would 

result in double reporting.105

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

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 

 105 NRECA at 17; Associated Electric Cooperative at 3-4. 

106 Cities/M-S-R at 10-11. 
Docket No. RM10-12-000 - 43 - 

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

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. 

 107 Southwestern Power Administration at 4-5. 
Docket No. RM10-12-000 - 44 - 

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 Act108 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 

 108 See 5 U.S.C. 601. 

109 See 15 U.S.C. 632. 
Docket No. RM10-12-000 - 45 - 

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. 

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 

 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). 

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).
Docket No. RM10-12-000 - 46 - 

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.

57. Consistent with the NOPR proposal, the Commission finds it appropriate to use 

the total annual wholesale sales volumes reported as “Sales for Resale” in EIA Form 861 

for purposes of calculating the de minimis threshold.113 Basing the threshold calculation 

on the total annual wholesale sales figure already reported by non-public utilities in EIA 

Form 861 will avoid the need for them to make a separate calculation of annual 

wholesale sales for EQR purposes and ensure a consistent method for calculating the 

threshold. Therefore, in response to Cities/M-S-R’s request for clarification of how joint 

action agencies should determine whether they exceed the de minimis threshold, we 

clarify that they should use the wholesale sales volumes reported as their “Sales for 

Resale” figure in EIA Form 861. However, as explained below, the Commission will not 

require non-public utilities to report sales made to members, or intra-familial sales, in the 

 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. 
Docket No. RM10-12-000 - 47 - 

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.

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

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 marketbased sales, transmission service, and transmission capacity reassignments, that public 

 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 § II.A.1.a. and infra § II.A.2.a.

115 See discussion at supra P 18. 
Docket No. RM10-12-000 - 48 - 

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

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 longterm agreements.117 TAPS asserts that requiring joint action agencies and G&T 

 116 EEI at 6-7. 

117 See, e.g., APPA at 4; Cities/M-S-R at 9; Public Systems at 9; TAPS at 11. 
Docket No. RM10-12-000 - 49 - 

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

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 longterm 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 

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 

 118 TAPS at 11. 

119 APPA at 4-5. 

120 Cities/M-S-R at 10. 
Docket No. RM10-12-000 - 50 - 

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 flowthrough of purchased power from a G&T cooperative to its distribution member 

cooperative.122

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 

 121 Public Systems at 9. 

122 Transmission Dependent Utility Systems at 5-6. 

123 See, e.g., APPA at 5; Public Systems at 12; TAPS at 9. 
Docket No. RM10-12-000 - 51 - 

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, longterm 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 verticallyintegrated utilities accomplish through their corporate structure and thus sales to their 

members should not be considered wholesale sales.126

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, 

 124 APPA at 5. 

125 TAPS at 9. 

126 Public Systems at 10. 

127 Public Systems at 12; TAPS at 12. 
Docket No. RM10-12-000 - 52 - 

installs energy efficiency measures, or relies on its own generation to serve its load even 

though such activities reduce the load-serving entity’s need for market purchases.128

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

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. 

 128 TAPS at 12. 

129 Id. 14. 

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 

(continued...) 
Docket No. RM10-12-000 - 53 - 

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

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

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 

 

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)). 

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

133 TAPS at 13. 
Docket No. RM10-12-000 - 54 - 

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

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

 134 NRECA at 17-18. 

135 APPA at 7, n.11. 

136 LPPC at 4. 

137 Id. at 6. 
Docket No. RM10-12-000 - 55 - 

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 nonjurisdictional and jurisdictional entities to provide a more complete picture of energy 

markets.138

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

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 

 138 EEI at 6. 

139 See NOPR, FERC Stats. & Regs. ¶ 32,676 at P 45. 
Docket No. RM10-12-000 - 56 - 

requirement for non-public utilities above the de minimis threshold: (1) sales by a nonpublic 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. 

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 “NonPublic Utility”) in those fields. If a non-public utility has a previously filed reciprocity 

open access transmission tariff (OATT), it should refer to that reciprocity OATT in Field 

Number 19 under FERC Tariff Reference. In addition, non-public utilities should mark 

“NPU” with respect to the “cost-based” or “market-based” options available under 

“Product Type Information” captured in Field Number 30, because these options are 

defined based on types of Commission-approved tariffs. If transmission capacity is 

reassigned under a non-public utility’s reciprocity OATT, the non-public utility should 

 140 See discussion at supra § II.A.1.a. 
Docket No. RM10-12-000 - 57 - 

follow the existing conventions for transmission providers reporting transmission 

capacity reassignments in the EQR. 

b. Burden 

i. NOPR 

76. In the NOPR, the Commission recognized that extending the EQR filing 

requirements to non-public utility market participants will impose a new burden on those 

market participants. The Commission agreed that it would make every effort to provide 

guidance and technical assistance prior to implementation of the EQR filing requirements 

for non-public utilities. 

ii. Comments 

77. Some commenters question whether the Commission has adequately considered 

the burden imposed on non-public utilities. For example, Southwestern Power 

Administration asserts that section 220 of the FPA provides the Commission with limited 

authority to seek information from certain non-public utilities and requires the 

Commission to weigh the value of the information against the regulatory burden it would 

impose on those entities. Southwestern Power Administration argues that requiring it to 

report information about its sales will serve no useful purpose that would justify the 

burden of reporting this information and that the Commission has not shown 

otherwise.141

 141 Southwestern Power Administration at 2-3. 
Docket No. RM10-12-000 - 58 - 

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

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 

 142 California DWR at 6-7 (citing Paperwork Reduction Act, 44 USC 3506(c)(3) 

(2006); Unfunded Mandates Reform Act of 1995, 2 USC 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 USC 1105 (2006)). 

144 Southwestern Power Administration at 4. 
Docket No. RM10-12-000 - 59 - 

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

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

81. LPPC encourages the Commission to provide sufficient lead time to enable nonpublic utilities to comply, and suggests a period of six months from the date of the final 

 145 California DWR at 7. 

146 NRECA at 18-19. 
Docket No. RM10-12-000 - 60 - 

rule. LPPC also requests that the Commission have staff assist in training programs that 

will facilitate compliance.147

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, 

 147 LPPC at 10. 
Docket No. RM10-12-000 - 61 - 

we believe that excluding from the reporting requirement sales by non-public utilities 

under long-term, cost-based agreements required to be made to certain customers under 

Federal or state statute will help lessen the burden on non-public utilities. Therefore, we 

believe that non-public utilities would not be encouraged to self-supply to avoid the 

reporting requirements, as suggested by California DWR. 

84. In response to NRECA’s concern about the difficulty for non-public utility 

cooperatives that use budget-based billing to submit revised EQRs or billing adjustments 

to reflect true-ups or actual costs, the Commission will not require true-ups by non-public 

utility cooperatives with budget-based billing in the EQR. The Commission’s policy 

regarding refilings or billing adjustments stems from the statutory requirement under 

FPA section 205(c) to have a public utility’s rates on file. Specifically, in recognition of 

the fact that public utilities may not have complete, final data for the full quarter by EQR 

filing deadlines, the Commission requires that any additions or changes to an EQR filing 

must be made by the end of the following quarter, when the filer is expected to file the 

best available new data.148 Filers are required to file material changes, either as a full 

 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. 
Docket No. RM10-12-000 - 62 - 

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, nonpublic 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 nonpublic utility cooperatives associated with budget-based billing from the EQR’s refiling 

or billing adjustment policy. 

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 

 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.
Docket No. RM10-12-000 - 63 - 

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 
Docket No. RM10-12-000 - 64 - 

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. 

(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 

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

Commission at 4. 

153 Powerex at 14. 
Docket No. RM10-12-000 - 65 - 

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

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 

 154 EEI at 12-13. 
Docket No. RM10-12-000 - 66 - 

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

(1) Commission Determination 

90. The Commission adopts, with modification, the NOPR proposal to require 

reporting of the trade date in the EQR. The NOPR proposed to define the trade date as 

the date on which parties to a reported transaction agreed upon a price. We will clarify 

this definition of trade date, as suggested by EEI, to state that it is “the date upon which 

the parties made the legally binding agreement on the price of the transaction.” 

91. As stated in the NOPR, the trade date for transactions currently is not provided or 

collected publicly.158 The trade date is essential to assessing the significance of prices in 

relation to market conditions in effect at that time. The EQR only collects the start and 

 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. 

158 NOPR, FERC Stats. & Regs. ¶ 32,676 at P 91. 
Docket No. RM10-12-000 - 67 - 

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. 

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. 
Docket No. RM10-12-000 - 68 - 

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. 
Docket No. RM10-12-000 - 69 - 

95. In addition, in response to EEI’s suggestion that the Commission should hold a 

technical conference to discuss the requirement for trade date data, the Commission notes 

that it intends to convene a staff-led technical conference following issuance of this Final 

Rule, to be announced at a future date, to discuss the additional fields required under this 

Final Rule, including the field for trade date. 

(b) Time of Trade 

96. Several commenters indicate concerns about the NOPR’s proposal to require 

market participants to report the time of trade. Some commenters contend that the time 

of trade, defined in the NOPR as the time upon which parties agree upon the price of a 

transaction, can be difficult to identify definitively.159 Certain commenters argue that the 

time parties agree on price may not be the time the trade occurred or was finalized.160 

For example, EDF Trading states that parties may agree to the price or pricing 

mechanism hours or even days before they come to an agreement regarding other 

material terms of the transaction, meaning that the time upon which parties agree upon 

the price of a transaction frequently will not correspond to the time at which parties 

execute or confirm that transaction.161

 159 See, e.g., EDF Trading at 7; EEI at 10-11; Entergy at 2-3; EPSA at 6-7; Pacific 

Northwest IOUs at 2; Westar at 2. 

160 See, e.g., EDF Trading at 7; EEI at 10-11; Entergy at 2-3; EPSA at 7. 

161 EDF Trading at 7. 
Docket No. RM10-12-000 - 70 - 

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

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 

 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.”). 

166 See, e.g., EDF Trading at 7-8; EEI at 9; Entergy at 1-2; EPSA at 5; Financial 

(continued...) 
Docket No. RM10-12-000 - 71 - 

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 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

 

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. 
Docket No. RM10-12-000 - 72 - 

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

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

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 

 170 Financial Institutions Energy Group at 8. 

171 Powerex at 14. 

172 EEI at 13. 
Docket No. RM10-12-000 - 73 - 

carefully tailored to maximize benefits while minimizing the burden on reporting 

entities.173

(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 

 173 Id. at 14. 
Docket No. RM10-12-000 - 74 - 

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 

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

(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 

 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. 

176 Id. at 15. 
Docket No. RM10-12-000 - 75 - 

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 
Docket No. RM10-12-000 - 76 - 

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 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. 
Docket No. RM10-12-000 - 77 - 

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

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. 

 177 EEI at 8. 

178 Financial Institutions Energy Group at 4. 
Docket No. RM10-12-000 - 78 - 

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 

 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”). 
Docket No. RM10-12-000 - 79 - 

insofar as having common units for reporting energy and capacity will simplify data 

interpretation.181

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

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 

 181 Pennsylvania Commission at 5. 

182 EEI at 16.
Docket No. RM10-12-000 - 80 - 

reduce errors and inconsistencies that would result from each reporting entity developing 

its own conversions.183

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 

 183 Entergy at 3.
Docket No. RM10-12-000 - 81 - 

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 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. 
Docket No. RM10-12-000 - 82 - 

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

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). 

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

185 EEI at 8-9. 
Docket No. RM10-12-000 - 83 - 

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 

 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. 
Docket No. RM10-12-000 - 84 - 

is critical to better enable the Commission to understand how index prices are established 

and how market forces affect index prices.188

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

125. Financial Institutions Energy Group suggests that the Commission clarify that 

reporting entities have no responsibility for how brokers or trading facilities may use 

 188 Pennsylvania Commission at 5. 

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. 
Docket No. RM10-12-000 - 85 - 

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

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

 192 Financial Institutions Energy Group at 10. 

193 Shell Energy at 10. 

194 Financial Institutions Energy Group at 9. 
Docket No. RM10-12-000 - 86 - 

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 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 

 195 See NOPR, FERC Stats. & Regs. ¶ 32,676 at P 111. 
Docket No. RM10-12-000 - 87 - 

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

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 

 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. 

199 Id. P 113. 
Docket No. RM10-12-000 - 88 - 

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. 

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 website.201 In addition, to assist the Commission in keeping the list of 

 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)). 
Docket No. RM10-12-000 - 89 - 

index publishers current, we expect filers to notify Commission staff by emailing 

eqr@ferc.gov if they begin reporting to an index publisher that is not listed in the EQR. 

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

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. 

 202 See discussion infra at § II.B.2.b. 
Docket No. RM10-12-000 - 90 - 

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

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 

 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. 

206 EEI at 17; EPSA at 10. 
Docket No. RM10-12-000 - 91 - 

Institutions Energy Group states that its members generally capture broker and trading 

platform information for each trade in their trade capture systems.207

135. Several commenters assert that publicly reporting the name of the broker208 or 

exchange209 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 when needed to avoid breaching confidentiality obligations.212

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 

 207 Financial Institutions Energy Group at 11. 

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. 
Docket No. RM10-12-000 - 92 - 

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

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 

 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. 

216 NOPR, FERC Stats. & Regs. ¶ 32,676 at P 114. 
Docket No. RM10-12-000 - 93 - 

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. 

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 
Docket No. RM10-12-000 - 94 - 

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 transactionspecific 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. 

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 

 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. 
Docket No. RM10-12-000 - 95 - 

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 website.220 In addition, to assist the Commission in keeping 

 220 See Order No. 2001-G, 120 FERC ¶ 61,270 at P 5 (citing Revised Public Utility 

Filing Requirements, 106 FERC ¶ 61,281 (2004)). 
Docket No. RM10-12-000 - 96 - 

the list of exchanges current, we expect filers to notify Commission staff by emailing 

eqr@ferc.gov if they begin reporting to an exchange that is not listed in the EQR. 

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 

detailed below, some other commenters oppose the proposal. 

(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 

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

Commission at 5. 

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. 
Docket No. RM10-12-000 - 97 - 

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 

 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. 
Docket No. RM10-12-000 - 98 - 

software that could perform this function and that contracting with a software developer 

would likely be a multi-million dollar proposition.227

(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

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 

 227 Joint Commenters at 4; LPPC at 13. 

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. 
Docket No. RM10-12-000 - 99 - 

that such a major change would have significant consequences, including a dramatic 

reduction in market efficiency.231

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 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

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 eTag 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 

 231 Powerex at 10. 

232 TAPS at 16-17. 

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. 
Docket No. RM10-12-000 - 100 - 

Balancing Authority Area severely limits the utility of requiring and reporting of e-Tag 

data for interchange transactions.234

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

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

 234 TAPS at 15-16. 

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. 

237 Joint Commenters at 3; LPPC at 11-12.
Docket No. RM10-12-000 - 101 - 

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

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

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 

 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. 

241 Id. at 17. 
Docket No. RM10-12-000 - 102 - 

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. 

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 

 242 Shell Energy at 7. 

243 MISO at 4. 
Docket No. RM10-12-000 - 103 - 

American Electric Reliability Corporation (NERC) in the rulemaking proceeding in 

Docket No. RM11-12-000.244

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 

 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)). 

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. 
Docket No. RM10-12-000 - 104 - 

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 Appendix A, EQR Data Dictionary. 

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 resales 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-

 249 The Sink Balancing Authority is the Balancing Authority in which load is 

located. 

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. 
Docket No. RM10-12-000 - 105 - 

Tag IDs through the EQR will facilitate price transparency by enabling all market 

participants and the Commission to “follow” transactions across markets. 

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 
Docket No. RM10-12-000 - 106 - 

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 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 
Docket No. RM10-12-000 - 107 - 

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 eTags, 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.

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 

 251 16 U.S.C. 824t(a)(2). 
Docket No. RM10-12-000 - 108 - 

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 Appendix 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 
Docket No. RM10-12-000 - 109 - 

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. 

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 

 252 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 336. 

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. 
Docket No. RM10-12-000 - 110 - 

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. 

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 
Docket No. RM10-12-000 - 111 - 

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 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 
Docket No. RM10-12-000 - 112 - 

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 

 254 See, e.g., EEI; Entergy; Financial Institutions Energy Group; North American 

Market Monitors; Powerex; Shell Energy. 

255 EEI at 9. 
Docket No. RM10-12-000 - 113 - 

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

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 crossreference 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

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 

 256 Financial Institutions Energy Group at 4-5. 

257 DC Energy at 6. 

258 Entergy at 4. 

259 Joint Market Monitors at 5. 
Docket No. RM10-12-000 - 114 - 

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 Appendix 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. 

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 

 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. 
Docket No. RM10-12-000 - 115 - 

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

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. 

 261 Ronald Rattey at 3-7. 

262 Id. at 13. 

263 Id. at 16-17. 

264 Id. at 17. 
Docket No. RM10-12-000 - 116 - 

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 anticompetitive behaviors that can be facilitated by untimely public disclosure of transactionspecific information, consistent with FPA section 220(b)(2). 

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 

 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. 
Docket No. RM10-12-000 - 117 - 

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. 

177. Financial Institutions Energy Group asserts that the Commission should take into 

account the true technological costs and challenges associated with coming into and 

 266 See, e.g., EDF Trading; EEI; Financial Institutions Energy Group. 
Docket No. RM10-12-000 - 118 - 

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 
Docket No. RM10-12-000 - 119 - 

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. 

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 

 267 EQR Data Dictionary. Company Data 
Docket No. RM10-12-000 - 120 - 

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 

cost268 due to the Final Rule in Docket RM10-12-000 follow. 

FERC-920, in 

the Final Rule 

in Docket 

RM10-12-000 

No. of 

Respondents 

No. of 

Responses 

per 

Respondent 

per Year 

Estimated 

Additional 

Implementing (Onetime) Burden per 

Respondent 

Estimated 

Additional 

Recurring 

Burden per 

Respondent per 

Response 

Estimated 

Additional Average 

Annual Burden Per 

Respondent 

(implementation 

averaged over 

Years 1-3) 

Burden 

Hours Cost ($) 

Burden 

Hours 

Cost 

($) 

Burden 

Hours Cost ($) 

Current Public Utility Filers 

Companies 

within nonCalifornia 

RTO, and 

large cos. 

within Cal. 

RTO 405 4 240.00 $17,214.00 16.00 $829.28 144.00 $9,055.12

 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. 
Docket No. RM10-12-000 - 121 - 

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 

wholesale 

sales per yr. 53 4 400.00 $28,690.00 19.00 $984.77 209.33 $13,502.41

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 nonpublic 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. 
Docket No. RM10-12-000 - 122 - 

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

 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. 

 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. 

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 

(continued...) 
Docket No. RM10-12-000 - 123 - 

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. 

 

corresponding burden hours for the recurring filings under the current EQR system from 

the FERC-516. 
Docket No. RM10-12-000 - 124 - 

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, e-mail: 

DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873]. Comments on 

the requirements of this rule may also be sent to the Office of Information and Regulatory 

Affairs, Office of Management and Budget, Washington, DC 20503 [Attention: Desk 

Officer for the Federal Energy Regulatory Commission]. For security reasons, comments 

should be sent by e-mail to OMB at oira_submission@omb.eop.gov. Please reference 

OMB Control No. 1902-0255, 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). 
Docket No. RM10-12-000 - 125 - 

V. Regulatory Flexibility Act 

186. The RFA273 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

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 

 273 5 U.S.C. 601-612. 

274 13 CFR 121.101. 

275 13 CFR 121.201, Sector 22, Utilities & n.1. 

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. D.C. 205 (D.C. Cir. 2001) (citing Mid-Tex Elec. Coop. v. FERC, 773 

F.2d 327 (D.C. Cir. 1985) (Commission need only consider small entities “that would be 

directly regulated”); Colorado State Banking Bd. v. RTC, 926 F.2d 931 (10th Cir. 1991) 

(Regulatory Flexibility Act not implicated where regulation simply added an option for 

affected entities and did not impose any costs)). 
Docket No. RM10-12-000 - 126 - 

small businesses. It is not required to consider indirect economic consequences, nor is it 

required to consider costs that an entity incurs voluntarily. 

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 nonpublic 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 reduce 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 
Docket No. RM10-12-000 - 127 - 

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 investorowned 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. 

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 

 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. 

278 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 31. 
Docket No. RM10-12-000 - 128 - 

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. 

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 

 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. 
Docket No. RM10-12-000 - 129 - 

hours (8:30 a.m. to 5:00 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 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 website during normal 

business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) 

or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-

8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov. 

VII. Effective Date and Congressional Notification 

195. These regulations are effective [insert date 60 days after publication in the Federal 

Register]. 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. 
Docket No. RM10-12-000 - 130 - 

List of subjects in 18 CFR Part 35 

Filing of Rate Schedules and Tariffs. 

By the Commission. 

( S E A L ) 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

 
Docket No. RM10-12-000 - 131 - 

In consideration of the foregoing, the Commission proposes to amend Part 18 C.F.R 

Part 35, Chapter I, Title 18, Code of Federal Regulations, as follows. 

PART 35 – FILING OF RATE SCHEDULES AND TARIFFS 

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

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

7352. 

2. § 35.10 Form and style of rate schedules; tariffs and service agreements. 

 * * * * * 

3. § 35.10b is revised to read as follows: 

§ 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). 
Docket No. RM10-12-000 - 132 - 

 (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 nonpublic 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, costbased agreement required to be made to certain customers under Federal or state statute. 

4. In § 35.41, paragraph (c) is revised to read as follows: 

§ 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 
Docket No. RM10-12-000 - 133 - 

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 § 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: Appendix A will not be published in the Code of Federal Regulations. 

Appendix A: Revisions to the Data Dictionary Clean Version

Electric Quarterly Report Data Dictionary 

Version 2.0 (issued July 19, 2012) 
Docket No. RM10-12-000 

EQR Data Dictionary 

ID Data

Field # Field Required Value Definition Old New 

1 1 Filer Unique Identifier  FR1 

(Respondent) – An identifier (i.e., “FR1”) used to descontaining Respondent identification information in a (csv) file that is imported into the EQR filing. Only oFR1 identifier may be imported into an EQR for a giv

1 1 Filer Unique Identifier  FS# (where “#” is an integer) 

(Seller) – An identifier (e.g., “FS1”, “FS2”) used to dcontaining Seller identification information in a commthat is imported into the EQR filing. One record for emay be imported into an EQR for a given quarter. 

1 1 Filer Unique Identifier  FA1 

(Agent) – An identifier (i.e., “FA1”) used to designatAgent identification information in a comma-delimiteimported into the EQR filing. Only one record with tbe imported into an EQR for a given quarter. 

2 2 Company Name  Unrestricted text (100 characters) (Respondent) – The name of the company taking resp

complying with the Commission's regulations related 

2 2 Company Name  Unrestricted text (100 characters) (Seller) – The name of the company that is authorized 

indicated in the company's FERC tariff(s). This namthe Company Name of the Respondent. 

2 2 Company Name  Unrestricted text (100 characters) (Agent) – The name of the entity completing the EQR 

Company Name need not be the name of the companjurisdiction. 

3 X 4 3 Contact Name  Unrestricted text (50 characters) (Respondent) – Name of the person at the Responden

responsibility for compliance with the Commission's 
Docket No. RM10-12-000 

EQR Data Dictionary 

ID Data

Field # Field Required Value Definition Old New 

4 3 Contact Name  Unrestricted text (50 characters) (Seller) – The name of the contact for the company au

sales as indicated in the company's FERC tariff(s). Tsame as the Contact Name of the Respondent. 

4 3 Contact Name  Unrestricted text (50 characters) (Agent) – Name of the contact for the Agent, usually 

prepares the filing. 

5 4 Contact Title  Unrestricted text (50 characters) Title of contact identified in Field Number 3. 

6 5 Contact Address  Unrestricted text Street address for contact identified in Field Number 

7 6 Contact City  Unrestricted text (30 characters) City for the contact identified in Field Number 3. 

8 7 Contact State  Unrestricted text (2 characters) Two character state or province abbreviations for the 

Field Number 3. 

9 8 Contact Zip  Unrestricted text (10 characters) Zip code for the contact identified in Field Number 3

10 9 Contact Country Name 

CA - Canada MX - Mexico US – United States UK – United Kingdom 

Country (USA, Canada, Mexico, or United Kingdomidentified in Field Number 3. 

11 10 Contact Phone  Unrestricted text (20 characters) Phone number of contact identified in Field Number 

12 11 Contact E-Mail  Unrestricted text E-mail address of contact identified in Field Number 
Docket No. RM10-12-000 

EQR Data Dictionary 

ID Data

Field # Field Required Value Definition Old New 

12 

Transactions Reported to Index Price Publisher(s) 



Y (Yes) N (No) 

Filers should indicate whether they have reported theindex price publisher(s). If they have, filers should inwhich index publisher(s) in Field Number 72. 

13 13 Filing Quarter  YYYYMM 

A six digit reference number used by the EQR softwaquarter and year of the filing for the purpose of imporfiles. The first 4 numbers represent the year (e.g., 20numbers represent the last month of the quarter (e.g., 06=2nd quarter, 09=3rd quarter, 12= 4th quarter). 
Docket No. RM10-12-000 

EQR Data Dictionary 

Contract Data 

Field # Field Required Value Definition Old New 

14 14 Contract Unique ID 

An integer proceeded by the letter “C” (only used when importing contract data) 

An identifier beginning with the letter “C” and f(e.g., “C1”, “C2”) used to designate a record coinformation in a comma-delimited (csv) file thaEQR filing. One record for each contract produinto an EQR for a given quarter. 

15 15 Seller Company Name  Unrestricted text (100 characters) 

The name of the company that is authorized to min the company’s FERC tariff(s). This name muprovided as a Seller's “Company Name” in Field Data (Seller Data). 

16 16 Customer Company Name  Unrestricted text (70 characters) The name of the counterparty. 

17 X 

18 17 Contract Affiliate  Y (Yes) 

N (No) 

The customer is an affiliate if it controls, is contcommon control with the seller. This includes a as a functional unit. A customer of a seller who Wholesale Generator may be defined as an affilUtility Holding Company Act and the FPA. 

19 18 FERC Tariff Reference  Unrestricted text (60 characters) 

The FERC tariff reference cites the document thand conditions under which a Seller is authorizetransmission sales, power sales or sales of relateservices at cost-based rates or at market-based rmarket-based, the tariff that is specified in the Fthe Seller Market Based Rate Authority must be 
Docket No. RM10-12-000 

EQR Data Dictionary 

Contract Data 

Field # Field Required Value Definition Old New 

20 19 Contract Service Agreement ID  Unrestricted text (30 characters) 

Unique identifier given to each service agreemethe filing company to produce the agreement, if identifier may be the number assigned by FERC agreements that have been filed with and acceptCommission, or it may be generated as part of aidentification system. 

21 20 Contract Execution Date  YYYYMMDD The date the contract was signed. If the parties s

dates, use the most recent date signed. 

22 21 

Commencement Date of Contract Terms 

 YYYYMMDD 

The date the terms of the contract reported in fiethrough 45 (as defined in the data dictionary) bethose terms became effective on multiple dates more amendments), the date to be reported in thmost recent amendment became effective. If threcent reported amendment does not have an effwhen service began pursuant to the contract or mamendment may be used. If the terms reported through 45 have not been amended since Januardate the contract became effective (or absent an initial date when service began) may be used. 

23 22 Contract Termination Date If specified in the contract. YYYYMMDD The date that the contract expires. 

24 23 Actual Termination Date If contract terminated. YYYYMMDD The date the contract actually terminates. 

25 24 

Extension Provision Description 

 Unrestricted text Description of terms that provide for the continu
Docket No. RM10-12-000 

EQR Data Dictionary 

Contract Data 

Field # Field Required Value Definition Old New 

26 25 Class Name  --- See definitions of each class name below. 26 25 Class Name  F - Firm 

For transmission sales, a service or product that over non-firm service. For power sales, a servicnot interruptible for economic reasons. 

26 25 Class Name  NF - Non-firm 

For transmission sales, a service that is reserved an as-available basis and is subject to curtailmenlesser priority compared to Firm service. For an or product for which delivery or receipt of the einterrupted for any reason or no reason, without either the buyer or seller. 

26 25 Class Name  UP - Unit Power Sale Designates a dedicated sale of energy and capac

than one specified generation unit(s). 

26 25 Class Name  N/A - Not Applicable To be used only when the other available Class 

27 26 Term Name 

LT - Long Term ST - Short Term N/A - Not Applicable 

Contracts with durations of one year or greater aContracts with shorter durations are short-term. 

28 27 Increment Name  --- See definitions for each increment below. 28 27 Increment Name  H - Hourly Terms of the contract (if specifically noted in th

to 6 consecutive hours (≤ 6 consecutive hours). 

28 27 Increment Name  D - Daily 

Terms of the contract (if specifically noted in thmore than 6 and up to 60 consecutive hours (>6 hours). 
Docket No. RM10-12-000 

EQR Data Dictionary 

Contract Data 

Field # Field Required Value Definition Old New 

28 27 Increment Name  W - Weekly 

Terms of the contract (if specifically noted in th60 consecutive hours and up to 168 consecutive consecutive hours). 

28 27 Increment Name  M - Monthly 

Terms of the contract (if specifically noted in thmore than 168 consecutive hours up to, but not (>168 consecutive hours and < 1 year). 

28 27 Increment Name  Y - Yearly Terms of the contract (if specifically noted in th

year or more (≥ 1 year). 

28 27 Increment Name  N/A - Not Applicable Terms of the contract do not specify an increme

29 28 Increment Peaking Name  --- See definitions for each increment peaking nam

29 28 Increment Peaking Name  FP - Full Period The product described may be sold during those 

on-peak and off-peak in the NERC region of the 

29 28 Increment Peaking Name  OP - Off-Peak The product described may be sold only during 

as off-peak in the NERC region of the point of d

29 28 Increment Peaking Name  P - Peak The product described may be sold only during 

as on-peak in the NERC region of the point of d

29 28 Increment Peaking Name  N/A - Not Applicable To be used only when the increment peaking na

the contract. 

30 29 Product Type Name  --- See definitions for each product type below. 30 29 Product Type Name  CB - Cost Based Energy or capacity sold under a FERC-approved 
Docket No. RM10-12-000 

EQR Data Dictionary 

Contract Data 

Field # Field Required Value Definition Old New 

30 29 Product Type Name  CR - Capacity Reassignment An agreement under which a transmission provi

transfers all or portion of its rights to an eligible 

30 29 Product Type Name  MB - Market Based Energy or capacity sold under the seller’s FERC

based rate tariff. 

30 29 Product Type Name  T - Transmission The product is sold under a FERC-approved tran30 29 Product Type Name  Other The product cannot be characterized by the othe

31 30 Product Name  See Product Name Table, Appendix A. Description of product being offered. 

32 31 Quantity 

If specified 

in the 

contract 

Number with up to 4 decimals Quantity for the contract product identified. 

33 32 Units 

If specified 

in the 

contract 

See Units Table, Appendix E. Measure stated in the contract for the product so

34 33 Rate 

One of four rate fields (34, 35, 36, or 37) must be included. 

Number with up to 4 decimals The charge for the product per unit as stated in t
Docket No. RM10-12-000 

EQR Data Dictionary 

Contract Data 

Field # Field Required Value Definition Old New 

35 34 Rate Minimum 

One of four rate fields (34, 35, 36, or 37) must be included 

Number with up to 4 decimals Minimum rate to be charged per the contract, if 

36 35 Rate Maximum 

One of four rate fields (34, 35, 36, or 37) must be included 

Number with up to 4 decimals Maximum rate to be charged per the contract, if 

37 36 Rate Description 

One of four rate fields (34, 35, 36, or 37) must be included 

Unrestricted text 

Text description of rate. If the rate is currently website, a citation of the FERC Accession NumFERC tariff including page number or section minstead of providing the entire rate algorithm. Iavailable on the FERC website, include the rate calculated. If the algorithm would exceed the 1limit, it may be provided in a descriptive summaand methods of calculations) with a detailed citaFERC tariff including page number and sectioncharacters are required, the contract product masubsequent line of data until the rate is adequate

38 37 Rate Units 

If specified 

in the 

contract

See Rate Units Table, Appendix F. Measure stated in the contract for the product so
Docket No. RM10-12-000 

EQR Data Dictionary 

Contract Data 

Field # Field Required Value Definition Old New 

39 38 

Point of Receipt Balancing Authority(PORBA) 

If specified 

in the 

contract

See Balancing Authority Table, Appendix B. 

The registered NERC Balancing Authority (formControl Area) where service begins for a transmtransmission-related jurisdictional sale. The Babe identified with the abbreviation used in OASreceipt occurs at a trading hub specified in the E“Hub” should be used. 

40 39 

Point of Receipt Specific Location (PORSL) 

If specified 

in the 

contract

Unrestricted text (50 characters). If “HUB” is selected for PORCA, see Hub Table, Appendix C. 

The specific location at which the product is recthe contract. If receipt occurs at a trading hub, a name must be used. If more points of receipt arthan can fit into the 50 character space, a descripof points may be used. ‘Various,’ alone, is unaccontract itself uses that terminology. 

41 40 

Point of Delivery Balancing Authority(PODBA) 

If specified 

in the 

contract

See Balancing Authority Table, Appendix B. 

The registered NERC Balancing Authority (formControl Area) where a jurisdictional product is dservice ends for a transmission or transmission-sale. The Balancing Authority will be identified used in OASIS applications. If delivery occurs of two control areas, the control area that the proshould be used. If delivery occurs at a trading hEQR software, the term “Hub” should be used. 

42 41 

Point of Delivery Specific Location (PODSL) 

If specified 

in the 

contract

Unrestricted text (50 characters). If “HUB” is selected for PODCA, see Hub Table, Appendix C. 

The specific location at which the product is delthe contract. If receipt occurs at a trading hub, a name must be used. 
Docket No. RM10-12-000 

EQR Data Dictionary 

Contract Data 

Field # Field Required Value Definition Old New 

43 42 Begin Date 

If specified 

in the 

contract

YYYYMMDDHHMM First date for the sale of the product at the rate s

44 43 End Date 

If specified 

in the 

contract

YYYYMMDDHHMM Last date for the sale of the product at the rate sp

45 X 
Docket No. RM10-12-000 

EQR Data Dictionary 

Transaction Data

Field # Field Required Value Definition Old New 

46 44 Transaction Unique ID 

An integer proceeded by the letter “T” (only used when importing transaction data) 

An identifier beginning with the letter “T” and f(e.g., “T1”, “T2”) used to designate a record coninformation in a comma-delimited (csv) file that EQR filing. One record for each transaction recinto an EQR for a given quarter. A new transactused every time a price changes in a sale. 

47 45 Seller Company Name  Unrestricted text (100 Characters) 

The name of the company that is authorized to min the company's FERC tariff(s). This name muprovided as a Seller's “Company Name” in Field (Seller Data). 

48 46 Customer Company Name  Unrestricted text (70 Characters) The name of the counterparty. 49 X 

50 47 FERC Tariff Reference  Unrestricted text (60 Characters) 

The FERC tariff reference cites the document thand conditions under which a Seller is authorizetransmission sales, power sales or sales of relateservices at cost-based rates or at market-based ramarket-based, the tariff that is specified in the Fthe Seller Market Based Rate Authority must be 

51 48 Contract Service Agreement ID  Unrestricted text (30 Characters) 

Unique identifier given to each service agreementhe filing company to produce the agreement, if identifier may be the number assigned by FERC agreements that have been filed and approved by it may be generated as part of an internal identif

52 49 Transaction Unique Identifier  Unrestricted text (24 Characters) Unique reference number assigned by the seller 
Docket No. RM10-12-000 

EQR Data Dictionary 

Transaction Data

Field # Field Required Value Definition Old New 

53 50 Transaction Begin Date 

YYYYMMDDHHMM (csv import) MMDDYYYYHHMM (manual entry) 

First date and time the product is sold during the 

54 51 Transaction End Date 

YYYYMMDDHHMM (csv import) MMDDYYYYHHMM (manual entry) 

Last date and time the product is sold during the 

 52 Trade Date 

YYYYMMDD (csv import) MMDDYYYY (manual entry) 

The date upon which the parties made the legally on the price of a transaction. 

53 Exchange/Brokerage Service 

See Exchange/Brokerage Service Table, Appendix H. 

If a broker service is used to consummate or effethe term “Broker” shall be selected from the Comlist. If an exchange is used, the specific exchangselected from the Commission-provided list. 

 54 Type of Rate  --- See type of rate definitions below. 

 54 Type of Rate  Fixed A fixed charge per unit of consumption. 

 54 Type of Rate  Formula A calculation of a rate based upon a formula tha

index component. 

 54 Type of Rate  Electric Index A calculation of a rate based upon an index or a 

an index component. 

 54 Type of Rate  RTO/ISO A rate that is based on an RTO/ISO published pr

contains an RTO/ISO price component. 

55 55 Time Zone  See Time Zone Table, Appendix D. The time zone in which the sales will be made u
Docket No. RM10-12-000 

EQR Data Dictionary 

Transaction Data

Field # Field Required Value Definition Old New 

56 56 

Point of Delivery Balancing Authority (PODBA) 



See Balancing Authority Table, Appendix B. 

The registered NERC Balancing Authority (formControl Area) abbreviation used in OASIS appli

57 57 

Point of Delivery Specific Location (PODSL) 



Unrestricted text (50 characters). If “HUB” is selected for PODBA, see Hub Table, Appendix C. 

The specific location at which the product is deloccurs at a trading hub, a standardized hub name 

58 58 Class Name  --- See class name definitions below. 58 58 Class Name  F - Firm A sale, service or product that is not interruptibl

reasons. 

58 58 Class Name  NF - Non-firm 

A sale for which delivery or receipt of the energfor any reason or no reason, without liability on buyer or seller. 

58 58 Class Name  UP - Unit Power Sale Designates a dedicated sale of energy and capac

than one specified generation unit(s). 

58 58 Class Name  BA - Billing Adjustment 

Designates an incremental material change to ondue to a change in settlement results. “BA” may after the next quarter’s filing is due to reflect the information. It may not be used to correct an ina

58 58 Class Name  N/A - Not Applicable To be used only when the other available class n

59 59 Term Name 

LT - Long Term ST - Short TermN/A - Not Applicable 

Power sales transactions with durations of one ylong-term. Transactions with shorter durations a

60 60 Increment Name  --- See increment name definitions below. 60 60 Increment Name  H - Hourly Terms of the particular sale set for up to 6 conse

consecutive hours) Includes LMP based sales in 
Docket No. RM10-12-000 

EQR Data Dictionary 

Transaction Data

Field # Field Required Value Definition Old New 

60 60 Increment Name  D - Daily 

Terms of the particular sale set for more than 6 aconsecutive hours (>6 and ≤ 60 consecutive hou

over a peak or off-peak block during a single da

60 60 Increment Name  W - Weekly 

Terms of the particular sale set for over 60 conseto 168 consecutive hours (>60 and ≤ 168 consec

sales for a full week and sales for peak and off-p

particular week. 

60 60 Increment Name  M - Monthly 

Terms of the particular sale set for set for more thours up to, but not including, one year (>168 co1 year). Includes sales for full month or multi-wgiven month. 

60 60 Increment Name  Y - Yearly 

Terms of the particular sale set for one year or m

Includes all long-term contracts with defined priprice, formula, or index). 

60 60 Increment Name  N/A - Not Applicable To be used only when other available increment 

61 61 Increment Peaking Name  --- See definitions for increment peaking below. 61 61 Increment Peaking Name  FP - Full Period The product described was sold during Peak and 61 61 Increment Peaking Name  OP - Off-Peak The product described was sold only during thos

off-peak in the NERC region of the point of deli

61 61 Increment Peaking Name  P - Peak The product described was sold only during thos

on-peak in the NERC region of the point of deliv

61 61 Increment Peaking Name  N/A - Not Applicable To be used only when the other available increm

not apply. 

62 62 Product Name  See Product Names Table, Appendix A. Description of product being offered. 
Docket No. RM10-12-000 

EQR Data Dictionary 

Transaction Data

Field # Field Required Value Definition Old New 

63 63 Transaction Quantity  Number with up to 4 decimals. The quantity of the product in this transaction. 

64 64 Price  Number with up to 6 decimals. Actual price charged for the product per unit. T

cannot be averaged or otherwise aggregated 

65 65 Rate Units  See Rate Units Table, Appendix F Measure appropriate to the price of the product s

 66 Standardized Quantity  Number with up to 4 decimals. For product names energy, capacity, and booked 

Specify the quantity in MWh if the product is enpower and specify the quantity in MW if the pro

67 Standardized Price  Number with up to 6 decimals. For product names energy, capacity, and booked 

Specify the price in $/MWh if the product is enepower and specify the price in $/MW-month if t

66 68 Total Transmission Charge  Number with up to 2 decimals Payments received for transmission services wh

identified. 

67 69 Total Transaction Charge  Number with up to 2 decimals Transaction Quantity (Field 63) times Price (Fie

Transmission Charge (Field 66). 
Docket No. RM10-12-000 

EQR Data Dictionary 

Index Reporting Data

Field # Field Required Value Definition Old New

 70 Filer Unique Identifier  FS# (where “#” is an integer) The “FS” seller number from the ID Data table c

index reporting company. 

71 Seller Company Name  Unrestricted text (100 characters) 

The name of the company that is authorized to min the company’s FERC tariff(s). This name muprovided as a Seller's “Company Name” in Field Data (Seller Data). 

 72 

Index Price Publisher(s) To Which Sales Transactions Have Been Reported 



If "Yes" is selected for Field 12, see Index Price Publisher, Appendix G. 

The index price publisher(s) to which sales transreported. 

73 Transactions Reported  Unrestricted text (100 characters) Description of the types of transactions reported 

identified in this record. 
Docket No. RM10-12-000 

EQR Data Dictionary 

e-Tag Data

Field # Field Required Value Definition Old New

 74 e-Tag ID 

If an eTag ID 

was used 

to 

schedule 

the EQR 

transaction

Unrestricted text (30 Characters) 

The e-Tag ID contains: The Source Balancing Ageneration is located; The Purchasing-Selling BEntity Code; the e-Tag Code; and the Sink Bala

75 e-Tag Begin Date 

If an eTag ID 

was used 

to 

schedule 

the EQR 

transaction

YYYYMMDD (csv import) MMDDYYYY (manual entry) 

The first date the transaction is scheduled using in Field Number 71. Begin Date must not be beBegin Date specified in Field Number 51 and msame time zone specified in Field Number 56. 

 76 e-Tag End Date 

If an eTag ID 

was used 

to 

schedule 

the EQR 

transaction

YYYYMMDD (csv import) MMDDYYYY (manual entry) 

The last date the transaction is scheduled using tin Field Number 71. End Date must not be after Date specified in Field Number 52 and must be time zone specified in Field Number 56. 

77 Transaction Unique Identifier 

If an eTag ID 

was used 

to 

schedule 

the EQR 

transaction

Unrestricted text (24 Characters) 

Unique reference number assigned by the seller that must be the same as reported in Field Numb
Docket No. RM10-12-000 

EQR Data Dictionary 

Appendix A. Product Names

Product Name 

Contract Product 

Transaction Product Definition 

BLACK START SERVICE  

Service available after a system -wide blackout where a gensystem restoration activities without the availability of an ou(Ancillary Service). 

BOOKED OUT POWER  

Energy or capacity contractually committed bilaterally for dactually delivered due to some offsetting or countervailing tonly). 

CAPACITY   A quantity of demand that is charged on a $/KW or $/MW b

CUSTOMER CHARGE   Fixed contractual charges assessed on a per customer basis t

billing service. 

DIRECT ASSIGNMENT FACILITIES CHARGE   Charges for facilities or portions of facilities that are constru

sole use/benefit of a particular customer. 

EMERGENCY ENERGY   Contractual provisions to supply energy or capacity to anoth

critical situations. 

ENERGY   A quantity of electricity that is sold or transmitted over a pe

ENERGY IMBALANCE  

Service provided when a difference occurs between the schedelivery of energy to a load obligation (Ancillary Service). Freported if the contract provides for sale of the product. For by third-party providers (i.e., non-transmission function) are 

EXCHANGE  

Transaction whereby the receiver accepts delivery of energy account and returns energy at times, rates, and in amounts athe receiver is not an RTO/ISO. 

FUEL CHARGE   Charge based on the cost or amount of fuel used for generat
Docket No. RM10-12-000 

EQR Data Dictionary 

Appendix A. Product Names

Product Name 

Contract Product 

Transaction Product Definition 

GENERATOR IMBALANCE  

Service provided when a difference occurs between the outplocated in the Transmission Provider’s Control Area and a dthat generator to (1) another Control Area or (2) a load withProvider’s Control Area over a single hour (Ancillary Servicreported if the contract provides for sale of the product. For by third-party providers (i.e., non-transmission function) are 

GRANDFATHERED BUNDLED   Services provided for bundled transmission, ancillary servic

contracts effective prior to Order No. 888's OATTs. 

INTERCONNECTION AGREEMENT  

Contract that provides the terms and conditions for a generasystem owner, transmission owner, transmission provider, oto physically connect to a transmission system or distributio

MEMBERSHIP AGREEMENT   Agreement to participate and be subject to rules of a system 

MUST RUN AGREEMENT   An agreement that requires a unit to run. 

NEGOTIATED-RATE TRANSMISSION   Transmission performed under a negotiated rate contract (ap

merchant transmission companies). 

NETWORK   Transmission service under contract providing network serv

NETWORK OPERATING AGREEMENT  

An executed agreement that contains the terms and conditionetwork customer operates its facilities and the technical anassociated with the implementation of network integration tr

OTHER   Product name not otherwise included. 

POINT-TO-POINT AGREEMENT   Transmission service under contract between specified Poin

Delivery. 

REACTIVE SUPPLY & VOLTAGE CONTROL   Production or absorption of reactive power to maintain volta

transmission systems (Ancillary Service). 

REAL POWER TRANSMISSION LOSS   The loss of energy, resulting from transporting power over a 
Docket No. RM10-12-000 

EQR Data Dictionary 

Appendix A. Product Names

Product Name 

Contract Product 

Transaction Product Definition 

REASSIGNMENT AGREEMENT   Transmission capacity reassignment agreement. REGULATION & FREQUENCY RESPONSE  

Service providing for continuous balancing of resources (geinterchange) with load, and for maintaining scheduled intercby committing on-line generation where output is raised or lnon-generation resources capable of providing this service athe moment-by-moment changes in load (Ancillary Service)reported if the contract provides for sale of the product. For by third-party providers (i.e., non-transmission function) are 

REQUIREMENTS SERVICE  

Firm, load-following power supply necessary to serve a speccustomer's aggregate load during the term of the agreement. service may include some or all of the energy, capacity and products. (If the components of the requirements service are they should be reported separately in the transactions tab.) 

SCHEDULE SYSTEM CONTROL & DISPATCH  

Scheduling, confirming and implementing an interchange scBalancing Authorities, including intermediary Balancing Autransmission service, and ensuring operational security durintransaction (Ancillary Service). 

SPINNING RESERVE  

Unloaded synchronized generating capacity that is immediasystem frequency and that is capable of being loaded in a shnon-generation resources capable of providing this service (For Contracts, reported if the contract provides for sale of thTransactions, sales by third-party providers (i.e., non-transmreported. 
Docket No. RM10-12-000 

EQR Data Dictionary 

Appendix A. Product Names

Product Name 

Contract Product 

Transaction Product Definition 

SUPPLEMENTAL RESERVE  

Service needed to serve load in the event of a system contingreater delay than SPINNING RESERVE. This service may generating units that are on-line but unloaded, by quick-starinterruptible load or other non-generation resources capable service (Ancillary Service). For Contracts, reported if the cosale of the product. For Transactions, sales by third-party prtransmission function) are reported. 

SYSTEM OPERATING AGREEMENTS  

An executed agreement that contains the terms and conditiosystem or network customer shall operate its facilities and thoperational matters associated with the implementation of n

TOLLING ENERGY   Energy sold from a plant whereby the buyer provides fuel to 

and receives power in return for pre-established fees. 

TRANSMISSION OWNERS AGREEMENT  

The agreement that establishes the terms and conditions undtransmission owner transfers operational control over designfacilities. 

UPLIFT   A make-whole payment by an RTO/ISO to a utility. 
Docket No. RM10-12-000 - 157 - 

EQR Data Dictionary 

Appendix B. Balancing Authority

Balancing Authority Abbreviation Outside US*

AESC, LLC - Wheatland CIN AEWC 

Alabama Electric Cooperative, Inc. AEC 

Alberta Electric System Operator AESO 

Alliant Energy Corporate Services, LLC - East ALTE 

Alliant Energy Corporate Services, LLC- West ALTW 

Ameren Transmission. Illinois AMIL 

Ameren Transmission. Missouri AMMO 

American Transmission Systems, Inc. FE 

Aquila Networks – Kansas WPEK 

Aquila Networks - Missouri Public Service MPS 

Aquila Networks - West Plains Dispatch WPEC 

Arizona Public Service Company AZPS 

Associated Electric Cooperative, Inc. AECI 

Avista Corp. AVA 

Batesville Balancing Authority BBA 

BC Hydro T & D - Grid Operations BCHA 

Big Rivers Electric Corp. BREC 

Board of Public Utilities KACY 

Bonneville Power Administration Transmission BPAT 

British Columbia Transmission Corporation BCTC 

California Independent System Operator CISO 

Carolina Power & Light Company - CPLW CPLW 

Carolina Power and Light Company - East CPLE 

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 
Docket No. RM10-12-000 - 158 - 

EQR Data Dictionary 

Appendix B. Balancing Authority

Balancing Authority Abbreviation Outside US*

Cleco Power LLC CLEC 

Columbia Water & Light CWLD 

Comision Federal de Electricidad CFE 

Comision Federal de Electricidad CFEN 

Constellation Energy Control and Dispatch GRIF 

Constellation Energy Control and Dispatch - Arkansas PUPP 

Constellation Energy Control and Dispatch - City of Benton, AR BUBA 

Constellation Energy Control and Dispatch - City of Ruston, LA DERS 

Constellation Energy Control and Dispatch - Conway, Arkansas CNWY 

Constellation Energy Control and Dispatch - Gila River GRMA 

Constellation Energy Control and Dispatch - Glacier Wind Energy GWA 

Constellation Energy Control and Dispatch - Harquehala HGMA 

Constellation Energy Control and Dispatch - North Little Rock, AK DENL 

Constellation Energy Control and Dispatch - Osceola Municipal Light OMLP 

Constellation Energy Control and Dispatch - Plum Point PLUM 

Constellation Energy Control and Dispatch – Red Mesa REDM 

Constellation Energy Control and Dispatch - West Memphis, Arkansas WMUC 

Dairyland Power Cooperative DPC 

DECA, LLC - Arlington Valley DEAA 

Duke Energy Corporation DUK 

East Kentucky Power Cooperative, Inc. EKPC 

El Paso Electric EPE 

Electric Energy, Inc. EEI 

Empire District Electric Co., The EDE 

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 
Docket No. RM10-12-000 - 159 - 

EQR Data Dictionary 

Appendix B. Balancing Authority

Balancing Authority Abbreviation Outside US*

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 

Idaho Power Company IPCO 

Imperial Irrigation District IID 

Indianapolis Power & Light Company IPL 

ISO New England Inc. ISNE 

JEA JEA 

Kansas City Power & Light, Co KCPL 

Lafayette Utilities System LAFA 

LG&E Energy Transmission Services LGEE 

Lincoln Electric System LES 

Los Angeles Department of Water and Power LDWP 

Louisiana Energy & Power Authority LEPA 

Louisiana Generating, LLC LAGN 

Louisiana Generating, LLC - City of Conway CWAY 

Louisiana Generating, LLC - City of West Memphis WMU 

Louisiana Generating, LLC - North Little Rock NLR 

Madison Gas and Electric Company MGE 

Manitoba Hydro Electric Board, Transmission Services MHEB 

Michigan Electric Coordinated System MECS 

Michigan Electric Coordinated System - CONS CONS 

Michigan Electric Coordinated System - DECO DECO 

MidAmerican Energy Company MEC 

Midwest ISO MISO 

Minnesota Power, Inc. MP 
Docket No. RM10-12-000 - 160 - 

EQR Data Dictionary 

Appendix B. Balancing Authority

Balancing Authority Abbreviation Outside US*

Montana-Dakota Utilities Co. MDU 

Muscatine Power and Water MPW 

Nebraska Public Power District NPPD 

Nevada Power Company NEVP 

New Brunswick System Operator NBSO 

New Horizons Electric Cooperative NHC1 

New York Independent System Operator NYIS 

Northern Indiana Public Service Company NIPS 

Northern States Power Company NSP 

NorthWestern Energy NWMT 

Ohio Valley Electric Corporation OVEC 

Oklahoma Gas and Electric OKGE 

Ontario - Independent Electricity System Operator ONT 

OPPD CA/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 Colorado PSCO 

Public Service Company of New Mexico PNM 

Puget Sound Energy Transmission PSEI 

Reedy Creek Improvement District RC 

Sacramento Municipal Utility District SMUD 

Salt River Project SRP 

Santee Cooper SC 

SaskPower Grid Control Centre SPC 

Seattle City Light SCL 

Seminole Electric Cooperative SEC 

Sierra Pacific Power Co. - Transmission SPPC 
Docket No. RM10-12-000 - 161 - 

EQR Data Dictionary 

Appendix B. Balancing Authority

Balancing Authority Abbreviation Outside US*

South Carolina Electric & Gas Company SCEG 

South Mississippi Electric Power Association SME 

South Mississippi Electric Power Association SMEE 

Southeastern Power Administration - Hartwell SEHA 

Southeastern Power Administration - Russell SERU 

Southeastern Power Administration - Thurmond SETH 

Southern Company Services, Inc. SOCO 

Southern Illinois Power Cooperative SIPC 

Southern Indiana Gas & Electric Co. SIGE 

Southern Minnesota Municipal Power Agency SMP 

Southwest Power Pool SWPP 

Southwestern Power Administration SPA 

Southwestern Public Service Company SPS 

Sunflower Electric Power Corporation SECI 

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 New Smyrna Beach NSB 

Westar Energy - MoPEP Cities MOWR 

Western Area Power Administration - Colorado-Missouri WACM 

Western Area Power Administration - Lower Colorado WALC 

Western Area Power Administration - Upper Great Plains East WAUE 

Western Area Power Administration - Upper Great Plains West WAUW 

Western Farmers Electric Cooperative WFEC 

Western Resources dba Westar Energy WR 

Wisconsin Energy Corporation WEC 
Docket No. RM10-12-000 - 162 - 

EQR Data Dictionary 

Appendix B. Balancing Authority

Balancing Authority Abbreviation Outside US*

Wisconsin Public Service Corporation WPS 

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. 
Docket Nos. RM01-8-009 and RM01-8-010 

EQR Data Dictionary 

Appendix C. Hub 

HUB Definition ADHUB The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Inter

the AEP/Dayton Hub. 

AEPGenHub The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Inter

the AEPGenHub. 

COB The set of delivery points along the California-Oregon commonly identified as a

counterparties to constitute the COB Hub. 

Cinergy (into) The set of delivery points commonly identified as and agreed to by the counterp

delivery into the Cinergy balancing authority. 

Cinergy Hub (MISO) The aggregated Elemental Pricing nodes ("Epnodes") defined by the Midwest In

Transmission System Operator, Inc., as Cinergy Hub (MISO). 

Entergy (into) The set of delivery points commonly identified as and agreed to by the counterp

delivery into the Entergy balancing authority. 

FE Hub The aggregated Elemental Pricing nodes ("Epnodes") defined by the Midwest In

Transmission System Operator, Inc., as FE Hub (MISO). 

Four Corners The set of delivery points at the Four Corners power plant commonly identified 

counterparties to constitute the Four Corners Hub. 

Illinois Hub (MISO) The aggregated Elemental Pricing nodes ("Epnodes") defined by the Midwest In

Transmission System Operator, Inc., as Illinois Hub (MISO). 

Mead The set of delivery points at or near Hoover Dam commonly identified as and ag

counterparties to constitute the Mead Hub. 

Michigan Hub (MISO) The aggregated Elemental Pricing nodes ("Epnodes") defined by the Midwest In

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 

counterparties to constitute the Mid-Columbia Hub. 

Minnesota Hub (MISO) The aggregated Elemental Pricing nodes ("Epnodes") defined by the Midwest In

Transmission System Operator, Inc., as Minnesota Hub (MISO). 

NEPOOL (Mass Hub) The aggregated Locational Marginal Price (“LMP”) nodes defined by ISO New 
Docket Nos. RM01-8-009 and RM01-8-010 

EQR Data Dictionary 

Appendix C. Hub 

Hub. 

NIHUB The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Inter

the Northern Illinois Hub. 

NOB The set of delivery points along the Nevada-Oregon border commonly identified 

the counterparties to constitute the NOB Hub. 

NP15 The set of delivery points north of Path 15 on the California transmission grid co

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 counterp

delivery into the Northwestern Energy Montana balancing authority. 

PJM East Hub The aggregated Locational Marginal Price nodes (“LMP”) defined by PJM Inter

the PJM East Hub. 

PJM South Hub The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Inter

the PJM South Hub. 

PJM West Hub The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Inter

the PJM Western Hub. 

Palo Verde The switch yard at the Palo Verde nuclear power station west of Phoenix in Ariz

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 counterp

delivery into the Southern Company balancing authority. 

SP15 The set of delivery points south of Path 15 on the California transmission grid co

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 counterp

delivery into the Tennessee Valley Authority balancing authority. 

ZP26 The set of delivery points associated with Path 26 on the California transmission 

identified as and agreed to by the counterparties to constitute the ZP26 Hub. 
Docket Nos. RM01-8-009 and RM01-8-010 

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 
Docket Nos. RM01-8-009 and RM01-8-010 

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 MW-YR Megawatt Year RKVA Reactive Kilovolt Amperes FLAT RATE Flat Rate 
Docket Nos. RM01-8-009 and RM01-8-010 

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 
Docket Nos. RM01-8-009 and RM01-8-010 

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 
Docket Nos. RM01-8-009 and RM01-8-010 

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

Appendix B: List of Commenters on the NOPR 

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 
Docket Nos. RM01-8-009 and RM01-8-010 - 171 -

MISO Midwest Independent Transmission System 

 Operator, Inc. 

Northern California Power Northern California Power Agency 

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 Companies281

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 Southwestern Power Administration 

Power Association 

TAPS Transmission Access Policy Study Group 

Transmission Dependent Utility Transmission Dependent Utility Systems 

 281 Filed only a motion to intervene. 
Docket Nos. RM01-8-009 and RM01-8-010 - 172 -

Systems 

Westar Westar Energy, Inc. 
Docket Nos. RM01-8-009 and RM01-8-010 - 173 -

Note: Appendix C will not be published in the Code of Federal Regulations.

Appendix C: Revisions to the Data Dictionary Redline Version

Electric Quarterly Report Data Dictionary 

Version 2.0 (issued July 19, 2012) 
Docket Nos. RM01-8-009 and RM01-8-010 - 174 -

Docket No. RM10-12-000 - 176 - 
Docket No. RM10-12-000 - 177 - 
Docket No. RM10-12-000 - 178 - 
Docket No. RM10-12-000 - 179 - 
Docket No. RM10-12-000 - 180 - 
Docket No. RM10-12-000 - 181 - 
Docket No. RM10-12-000 - 182 - 
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Docket No. RM10-12-000 - 188 - 
Docket No. RM10-12-000 - 189 - 
Docket No. RM10-12-000 - 190 - 
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Docket No. RM10-12-000 - 194 - 
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Docket No. RM10-12-000 - 198 - 
Docket No. RM10-12-000 - 199 - 
Docket No. RM10-12-000 - 200 - 
Docket No. RM10-12-000 - 201 - 
Docket No. RM10-12-000 - 202 - 
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Docket No. RM10-12-000 - 207 - 
Docket No. RM10-12-000 - 208 - 
Docket No. RM10-12-000 - 209 - 

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

Appendix B: List of Commenters on the NOPR 

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 
Docket No. RM10-12-000 - 210 - 

MISO Midwest Independent Transmission System 

 Operator, Inc. 

Northern California Power Northern California Power Agency 

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 Companies282

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 Southwestern Power Administration 

Power Association 

TAPS Transmission Access Policy Study Group 

Transmission Dependent Utility Transmission Dependent Utility Systems 

Systems 

 282 Filed only a motion to intervene. 
Docket No. RM10-12-000 - 211 - 

Westar Westar Energy, Inc.