135 FERC ¶ 61,053 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

[Docket No. RM10-12-000] 

 

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

(April 21, 2011) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: The Commission proposes to amend its regulations pursuant to section 220 

of the Federal Power Act (FPA), as enacted by section 1281 of the Energy Policy Act of 

2005 (EPAct 2005), to facilitate price transparency in markets for the sale and 

transmission of electric energy in interstate commerce. In doing so, the Commission 

proposes to require market participants that are excluded from the Commission’s 

jurisdiction under FPA section 205 and have more than a de minimis market presence to 

file Electric Quarterly Reports (EQR) with the Commission. 

In addition, the Commission proposes to refine the existing EQR filing 

requirements by directing all filers to: (1) report the transaction date and time, as well as 

the type of rate by which the price in the transaction or contract was set (i.e., fixed price, 

formula, index, regional transmission organization/independent system operator 

(RTO/ISO) price, or index); (2) indicate whether the transaction was reported to an index 

publisher; (3) identify the broker or exchange used for a transaction, if applicable; and 

(4) report electronic tag (e-Tag) ID data in EQRs. The Commission also proposes to: 
Docket No. RM10-12-000 - 2 - 

(1) standardize the unit for reporting energy and capacity transactions; (2) omit the time 

zone from the contract section; and (3) eliminate the Data Universal Numbering System 

(DUNS) data requirement. These refinements to the existing EQR filing requirements 

reflect the evolving nature of electricity markets and promote greater price transparency 

and confidence in electricity markets. 

DATES: Comments are due [60 days after publication in the FEDERAL REGISTER] 

ADDRESSES: You may submit comments, identified by docket number by any of the 

following methods: 

 Agency Web Site: http://ferc.gov. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format 

and not in a scanned format. 

 Mail/Hand Delivery: Commenters unable to file comments electronically must 

mail or hand-deliver an original and 14 copies of their comments to: Federal 

Energy Regulatory Commission, Secretary of the Commission, 888 First Street, 

NE, Washington, DC 20426. 

FOR FURTHER INFORMATION CONTACT: 

Maria Vouras 

Office of Enforcement 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

(202) 502-8062 

Maria.Vouras@ferc.gov 

Christina Switzer 

Office of General Counsel 
Docket No. RM10-12-000 - 3 - 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

(202) 502-6379 

Christina.Switzer@ferc.gov 

William Sauer 

Office of Enforcement 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

(202) 502-6639 

William. Sauer@ferc.gov 

SUPPLEMENTARY INFORMATION

:
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 

NOTICE OF PROPOSED RULEMAKING 

TABLE OF CONTENTS

 Paragraph Numbers

I. Background ............................................................................................................................3.

A. Order No. 2001.................................................................................................................3.

B. EPAct 2005.......................................................................................................................5.

C. Notice of Inquiry ..............................................................................................................8.

II. Discussion.............................................................................................................................9.

A. Extending the EQR Filing Requirements to Non-Public Utilities ...................................9.

1. Background...................................................................................................................9.

2. Commission Authority .................................................................................................14.

3. Proposed Filing Requirements for Non-Public Utilities ..............................................30.

B. Refinements to the Existing EQR Requirements .............................................................75.

1. Background...................................................................................................................75.

2. General Refinements ....................................................................................................78.

3. Additional EQR Enhancements....................................................................................106.

III. Information Collection Statement .......................................................................................121.

IV. Environmental Analysis ......................................................................................................122.

V. Regulatory Flexibility Act [Analysis Or Certification]........................................................123.

VI. Comment Procedures ..........................................................................................................124.

VII. Document Availability.......................................................................................................128.

Appendix A: List of Commenters 

Appendix B: Proposed Refinements to the Existing EQR
135 FERC ¶ 61,053 

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 

NOTICE OF PROPOSED RULEMAKING 

(April 21, 2011) 

1. To facilitate price transparency in markets for the sale and transmission of electric 

energy in interstate commerce, the Federal Energy Regulatory Commission 

(Commission) proposes to revise its regulations to require market participants that are 

excluded from the Commission’s jurisdiction under section 205 of the Federal Power Act 

(FPA)1

 and have more than a de minimis market presence to file Electric Quarterly 

Reports (EQR) with the Commission.2

 In doing so, the Commission proposes to exercise 

 

(continued...) 

1

 16 U.S.C. 824d. For ease of reference, this Notice of Proposed Rulemaking 

(NOPR) refers to market participants that are not public utilities under section 201(f) of 

the FPA as “non-public utilities.” FPA section 201(f) provides: No provision in this Part 

shall apply to, or be deemed to include, the United States, a State or any political 

subdivision of a State, an electric cooperative that receives financing under the Rural 

Electrification Act of 1936 (7 U.S.C. 901 et seq.) or that sells less than 4,000,000 

megawatt hours of electricity per year, or any agency, authority, or instrumentality of any 

one or more of the foregoing, or any corporation which is wholly owned, directly or 

indirectly, by any one or more of the foregoing, or any officer, agent, employee of any of 

the foregoing acting as such in the course of his official duty, unless such provision 

makes specific reference thereto. 16 U.S.C. 824(f). 

2

 These proposed requirements would not apply to a transaction for the purchase 

or sale of wholesale electric energy or transmission services within the Electric 
Docket No. RM10-12-000 - 2 - 

its authority under section 220 of the FPA,3

 as adopted in the Energy Policy Act of 2005 

(EPAct 2005).4

 This proposal would allow the Commission and the public to gain a 

more complete picture of wholesale power and transmission markets in interstate 

commerce by providing additional information concerning price formation and market 

concentration in these markets. Public access to additional sales and transmission-related 

information in the EQR would improve market participants’ ability to assess supply and 

demand fundamentals and to price interstate wholesale market transactions. It also would 

strengthen the Commission’s ability to identify potential exercises of market power or 

manipulation and to better evaluate the competitiveness of the interstate wholesale 

markets. 

2. In addition, the Commission proposes to make certain revisions to the existing 

EQR filing requirements and apply those revisions to all market participants filing EQRs. 

The Commission proposes to revise the EQRs currently filed by public utilities under 

FPA section 205(c) and that will be filed by non-public utilities under FPA section 220. 

These revisions include the addition of new fields for: (1) reporting the transaction date 

and time, as well as the type of rate; (2) indicating whether the sales transaction was 

reported to an index publisher; (3) identifying the broker or exchange used for a sales 

 

Reliability Council of Texas (ERCOT), consistent with the exclusion set forth in FPA 

section 220(f). 16 U.S.C. 824t(f). 

3

 16 U.S.C. 824t. 

4

 EPAct 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005). 
Docket No. RM10-12-000 - 3 - 

transaction, if applicable; and (4) reporting electronic tag (e-Tag) ID data. The 

Commission also proposes to eliminate the time zone from the contract section and the 

Data Universal Numbering System (DUNS) data requirement. Further, the Commission 

proposes to standardize the unit for reporting energy and capacity transactions. These 

refinements to the existing EQR filing requirements reflect the evolving nature of 

electricity markets, would increase market transparency for the Commission and the 

public, and would allow market participants to file the information in the most efficient 

manner possible.5

 

I. Background

A. Order No. 2001

3. The Commission set forth the EQR filing requirements in Order No. 2001.6

 

Order No. 2001 requires public utilities to electronically file EQRs summarizing 

transaction information for short-term and long-term cost-based sales and market-based 

 5

 The Commission also is reviewing the software currently used to file EQRs. 

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 - 4 - 

rate sales and the contractual terms and conditions in their agreements for all 

jurisdictional services.7

 The Commission established the EQR reporting requirements to 

help ensure the collection of information needed to perform its regulatory functions over 

transmission and sales,8

 while making data more useful to the public and allowing public 

utilities to better fulfill their responsibility under FPA section 205(c) 9

 to have rates on 

file in a convenient form and place.10 As noted in Order No. 2001, the EQR data is 

designed to “provide greater price transparency, promote competition, enhance 

confidence in the fairness of the markets, and provide a better means to detect and 

discourage discriminatory practices.”11

4. Since issuing Order No. 2001, the Commission has provided guidance and refined 

the reporting requirements, as necessary, to simplify the filing requirements and to reflect 

changes in the Commission’s rules and regulations.12 For instance, in 2007 the 

 7

 Order No. 2001, FERC Stats. & Regs. ¶ 31,127. 

8 Id. P 13-14. 

9

 16 U.S.C. 824d(c). 

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

11 Id. P 31. 

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 - 5 - 

Commission adopted an Electric Quarterly Report Data Dictionary, which provides in 

one document the definitions of certain terms and values used in filing EQR data.13 

Moreover, in 2007, the Commission required transmission capacity reassignment to be 

reported in the EQR.14 The refinements to the existing EQR requirements that we are 

proposing in this NOPR build upon the Commission’s prior improvements to the 

reporting requirements and further enhance the goals of providing greater price 

transparency, promoting competition, instilling confidence in the fairness of the markets, 

and providing a better means to detect and discourage discriminatory and manipulative 

practices. 

B. EPAct 2005

5. In EPAct 2005, Congress added section 220 to the FPA,15 directing the 

Commission to “facilitate price transparency in markets for the sale and transmission of 

electric energy in interstate commerce” with “due regard for the public interest, the 

 13 Order No. 2001-G, 120 FERC ¶ 61,270. 

14 Preventing Undue Discrimination and Preference in Transmission Service,

Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, at P 817, 

order on reh'g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. 

¶ 31,261 (2007), order on reh'g and clarification, Order No. 890-B, 73 FR 39092 

(July 8, 2008), 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 74 FR 

12540 (March 25, 2009), 126 FERC ¶ 61,228 (2009), order on clarification, Order 

No. 890-D, 74 FR 61511 (Nov. 25, 2009), 129 FERC ¶ 61,126. 

15 16 U.S.C. 824t. 
Docket No. RM10-12-000 - 6 - 

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

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

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

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

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

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

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

provisions in the Natural Gas Act.20

6. In 2006, Commission staff conducted an extensive outreach effort to formulate 

options for implementing EPAct 2005’s transparency provisions for wholesale natural 

gas and electricity markets. As a result, the Commission used its new transparency 

authority to adopt additional filing and posting requirements for the sale or transportation 

of physical natural gas in interstate commerce in Orders No. 704 and 720. Order No. 704 

 16 In addition, FPA section 220(b)(1-2) directs the Commission to exempt from 

disclosure information that is “detrimental to the operation of an effective market or [that 

would] jeopardize system security,” and “to ensure that consumers and competitive 

markets are protected from the adverse effects of potential collusion or other 

anticompetitive behaviors that can be facilitated by untimely public disclosure of 

proprietary trading information.” 16 U.S.C. 824t(b)(1-2). 

17 16 U.S.C. 824t(a)(2). 

18 Id. 824t(a)(3)(A). 

19 Id. 824t(d). 

20 15 U.S.C. 717t-2. 
Docket No. RM10-12-000 - 7 - 

requires buyers and sellers of more than a de minimis volume of natural gas to report 

aggregate volumes of relevant transactions in an annual filing.21 In Order No. 720, the 

Commission required major non-interstate pipelines to post daily scheduled volume and 

other data for certain receipt and delivery points.22 Order No. 720 also requires interstate 

pipelines to post information regarding no-notice service.23

7. The Commission declined to extend such requirements to wholesale electricity 

markets because, at the time of the Natural Gas Transparency Notice of Proposed 

Rulemaking, the Commission was considering other reforms to its regulation of 

electricity markets.24 In particular, the Commission was undertaking open access 

 21 Transparency Provisions of Section 23 of the Natural Gas Act, Order No. 704, 

73 FR 1014 (Jan. 4, 2008), FERC Stats. & Regs. ¶ 31,260, at P 32 (2007), order on reh’g, 

Order No. 704-A, 73 FR 55726 (Sept. 26, 2008), FERC Stats. & Regs. ¶ 31,275, order 

dismissing reh’g and clarification, Order No. 704-B, 125 FERC ¶ 61,302 (2008), order 

granting clarification, Order No. 704-C, 75 FR 35632 (June 23, 2010), 131 FERC 

¶ 61,246 (2010); see also, Pipeline Posting Requirements under Section 23 of the Natural 

Gas Act, Order No. 720, 73 FR 73494 (Dec. 2, 2008), FERC Stats. & Regs. ¶ 31,283, at 

P 3 (2008), order on reh’g, Order No. 720-A, 73 FR 73494 (Dec. 2, 2008), FERC Stats. 

& Regs. ¶ 31,302, order on reh'g and clarification, Order No. 720-B, 75 FR 44893 

(July 30, 2010), FERC Stats. & Regs. ¶ 31,314 (2010). 

22 Order No. 720, FERC Stats. & Regs. ¶ 31,283 at P 1. 

23 Id.

24 See Transparency Provisions of Section 23 of the Natural Gas Act; 

Transparency Provisions of the Energy Policy Act, Notice of Proposed Rulemaking, 

72 FR 20791 (April 26, 2007), FERC Stats. & Regs. ¶ 32,614, at P 9-11 (2007) (Natural 

Gas Transparency NOPR) (“The Commission does not propose action with respect to 

electric markets at this time. The Commission has recently addressed and is currently 

addressing electric market transparency in other proceedings.”). 
Docket No. RM10-12-000 - 8 - 

transmission service reforms and the more general review of competition in wholesale 

electricity markets.25 As a result of these efforts, the Commission issued two final rules. 

In Order No. 890, the Commission exercised its remedial authority “to limit further 

opportunities for undue discrimination, by minimizing areas of discretion, addressing 

ambiguities and clarifying various aspects of the pro forma [Open Access Transmission 

Tariff].”26 Moreover, in Order No. 719, the Commission made reforms “to improve the 

operation [and competitiveness] of organized wholesale electric power markets” in 

connection with “fulfilling its statutory mandate to ensure supplies of electric energy at 

just, reasonable and not unduly discriminatory or preferential rates.”27 Although these 

final rules improved transparency in wholesale markets in a number of ways, the 

Commission believes the revisions proposed in this order are necessary to facilitate price 

transparency in wholesale electricity markets. 

 25 Id.

26 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 40. 

27 Wholesale Competition in Regions with Organized Electric Markets, Order 

No. 719, 73 FR 64100 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281 (2008), order on 

reh'g, Order No. 719-A, 74 FR 37776 (July 29, 2009), FERC Stats. & Regs. ¶ 31,292, 

order on reh'g and clarification, Order No. 719-B, 129 FERC ¶ 61,252 (2009). 
Docket No. RM10-12-000 - 9 - 

C. Notice of Inquiry

8. On January 21, 2010, the Commission issued a Notice of Inquiry28 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. In response to the Transparency NOI, the Commission 

received 40 comments. Of those comments, twenty-eight discuss extending the EQR 

filings to non-public utilities; five discuss EQR refinements; and six discuss both. We 

have considered these comments in drafting the proposals in this NOPR, and we invite 

further comments on these proposals. 

II. Discussion

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

1. Background

a. Need for Information from Non-Public Utilities

9. Currently, market participants that fall within the Commission’s jurisdiction under 

FPA section 205(c)29 must file EQRs summarizing contractual terms and conditions in 

their agreements for jurisdictional services, including market-based rate sales, cost-based 

sales, transmission service, and transmission capacity reassignments. In addition, EQR 

 28 Electricity Market Transparency Provisions of Section 220 of the Federal 

Power Act, Notice of Inquiry, 75 FR 4805 (Jan. 29, 2010), FERC Stats. & Regs. ¶ 35,565 

(2010) (Transparency NOI).

29 FPA section 205(c) requires public utilities to file all rates and charges 

for any transmission or sale subject to the Commission’s jurisdiction in a 

convenient form and place for public inspection. 16 U.S.C. 824d(c). 
Docket No. RM10-12-000 - 10 - 

filers must provide detailed transactional information for power sales and transmission 

capacity reassignments made during the most recent calendar quarter. 

10. Transactions made by both public utility and non-public utility market participants 

provide critical pricing information that market participants can use to make betterinformed decisions about, among other things, sales, purchases, and infrastructure 

investments. Access to reliable data reduces differences in available information among 

various market participants, results in greater market confidence, lowers transaction 

costs, and ultimately supports competitive markets, which helps lower electricity costs 

for consumers. Applying the EQR filing requirements to the non-public utilities that fall 

above the de minimis threshold will increase price transparency to the public and the 

Commission and aid the Commission in its oversight of wholesale power and 

transmission markets. As the Commission explained in implementing the transparency 

provisions under section 23 of the Natural Gas Act: 

The Commission’s market-oriented policies for the wholesale natural gas 

industry require that interested persons have broad confidence that 

reported market prices accurately reflect the interplay of legitimate market 

forces. Without confidence in the fairness of price formation, the true 

value of transactions is very difficult to determine. Further, price 

transparency makes it easier for us to ensure that jurisdictional prices are 

“just and reasonable.”30

11. Based on the most recent data available in the 2009 U.S. Energy Information 

Administration’s (EIA) Form 861, non-public utilities account for significant volumes of 

 30 Order No. 704-A, 124 FERC ¶ 61,269 at P 3; see also Order No. 704, FERC 

Stats. & Regs. ¶ 31,260 at P 7. 
Docket No. RM10-12-000 - 11 - 

the 3.2 billion MWh of total annual wholesale electricity sales made within the 48 

contiguous states (excluding ERCOT).31 In particular, about 29 percent of those 

wholesale sales are made by non-public utilities. Non-public utilities make a significant 

portion of sales in certain regional wholesale markets within the United States. The 2009 

EIA Form 861 data indicates that non-public utilities account for 60 and 70 percent of 

wholesale sales within the Western Electric Coordinating Council (WECC) and SERC 

Reliability Corporation (SERC) regions, respectively. Similarly, non-public utilities 

make up about 80 percent of all wholesale sales that occur within the Florida Reliability 

Coordinating Council (FRCC). Given non-public utilities’ significant presence in 

national and regional wholesale electricity markets, obtaining information about their 

sales transactions is important to unmasking how prices are formed in electricity markets. 

The lack of information from non-public utilities results in an incomplete picture of these 

markets, and hampers the ability of the public and the Commission to detect and address 

the potential exercise of market power and manipulation. 

12. Among the refinements this NOPR proposes to the EQR filing requirements is a 

requirement that all market participants provide information about the index publishers, if 

any, to which they report their transactions and any broker or exchange they use. This 

 31 See U.S. Energy Information Administration, Form EIA-861, Annual Electric 

Power Industry Report (April 2010), available at 

http://www.eia.doe.gov/cneaf/electricity/page/eia861.html. 
Docket No. RM10-12-000 - 12 - 

information would provide greater transparency regarding electricity index prices and 

how well those index prices reflect market forces, thus creating greater confidence in the 

electricity market. In addition, this NOPR proposes several refinements to the EQR 

filing requirements, including requiring all filers to report: (1) the transaction date and 

time; (2) the type of rate by which the price in the transaction or contract was set (i.e., 

fixed price, formula, index, or RTO/ISO price); and (3) e-Tag ID data. The Commission 

also proposes to: (1) standardize the unit for reporting energy and capacity transactions; 

(2) omit the time zone from the contract section; and (3) eliminate the DUNS number 

requirement. 

13. Section 220(a)(4) of the FPA requires the Commission to “consider the degree of 

price transparency provided by existing price publishers and providers of trade 

processing services, and . . . rely on such publishers and services to the maximum extent 

possible.” As discussed below, we have reviewed existing publications and we believe 

that the additional data that would be required under this NOPR is not available through 

existing sources and is necessary to provide a complete picture of price formation in 

wholesale power markets. 

b. Notice of Inquiry Regarding Extending the EQR Filing 

Requirements 

14. In the Transparency NOI, the Commission sought comments regarding whether 

the Commission should extend the EQR filing requirements to non-public utilities. The 

Commission also sought comments on what information the Commission should collect, 

whether the Commission should establish a threshold for reporting, and the burden on 
Docket No. RM10-12-000 - 13 - 

market participants that would have to adapt their existing systems to be able to provide 

the information. The Commission also asked whether extending the filing requirements 

would impact market liquidity. 

2. Commission Authority

a. Comments

15. Several commenters question whether the Commission has the authority to extend 

the EQR filing requirements to non-public utilities.32 Many of these commenters 

emphasize that the Commission’s jurisdiction under section 220 is limited to collecting 

information regarding wholesale electricity and transmission markets. They point to 

section 220(b), which states that “[t]he Commission may prescribe rules . . . [that] 

provide for the dissemination, on a timely basis, of information about the availability and 

prices of wholesale electric energy and transmission service.”33 They argue that nonpublic utilities constitute a small percentage of the wholesale market, and therefore 

information from these market participants will not enhance transparency significantly.34 

In addition, Alaska Power argues that utilities in Alaska do not engage in energy and 

 32 APPA; NRECA; Southwest Transmission; EMCOS; Public Systems; East 

Texas Electric Cooperatives; Cities/M-S-R; TANC; MID; New York Public Power; 

Delaware Municipal; California DWR; Public Power Council; Allegheny; Utah 

Associated Municipal; NCPA; NYMPA/MEUA. 

33 16 U.S.C. 824t(b). 

34 APPA; NRECA; EMCOS; Public Systems; East Texas Electric Cooperatives; 

TANC; Delaware Municipal; Utah Associated Municipal; NYMPA/MEUA. 
Docket No. RM10-12-000 - 14 - 

transmission transactions in interstate commerce and, therefore, should not be required to 

file EQRs. Many commenters also argue that there is a lack of evidence to support 

imposing the EQR filing requirements on non-public utilities.35 For instance, NRECA 

and TANC argue that, in the Transparency NOI, the Commission overstated the volume 

of sales that would be reported if the Commission extended the filing requirements to 

non-public utilities.36 APPA asserts that EIA statistics on non-public utility sales cited 

by the Commission in the Transparency NOI reflect bundled retail sales to consumers 

rather than information on wholesale sales, which is relevant to the Commission’s 

oversight of jurisdictional wholesale markets.37 NRECA and TANC claim that the 

Commission should have excluded retail sales from EIA’s estimate of electric utility s

that are made by entities other than public utilities.

ales 

O) market transparency. 

 

38 TANC also asserts that the 

Commission should have excluded sales from utilities in ERCOT because those utilities 

are outside the Commission’s section 220 jurisdiction. APPA asserts that the 

Commission’s efforts would be better spent focusing on Regional Transmission 

Organization (RTO) and Independent System Operators (IS

35 Southwest Transmission; East Texas Electric Cooperatives; TANC; Utah 

Associated Municipal. 

36 NRECA at 11; TANC at 16. 

37 APPA at 5-6. 

38 NRECA at 11. 
Docket No. RM10-12-000 - 15 - 

16. NRECA and TANC further contend that the absence of EQR information from 

non-public utilities has not hampered the Commission’s ability to approve market-based 

rates. For example, TANC argues that the Commission has been conducting ex ante and 

ex post analyses of public utilities’ market power and has been approving and evaluating 

mergers for decades without information from non-jurisdictional entities. 

17. Cities/M-S-R state that entities under consideration in this proceeding have no 

statutory obligation to file their energy sales agreements with the Commission, nor are 

their rates subject to reasonableness determinations before the Commission. 

Accordingly, Cities/M-S-R argue that there is no need to use the EQR mechanism to 

replace other filing obligations, such as an annual filing with the EIA, for entities exempt 

from section 205 of the FPA. 

18. Other commenters argue that the Commission has the authority under the FPA to 

extend the EQR filing requirements to non-public utilities. EEI asserts that section 220 

provides the Commission with clear authority and responsibility to extend the EQR filing 

requirements. DC Energy notes that section 205 also provides the Commission with 

broad authority to require otherwise exempt entities to provide information related to the 

rates for jurisdictional services. 

19. Several commenters also support the Commission’s effort to increase transparency 

in wholesale electricity markets and assert that the additional reporting requirements will 
Docket No. RM10-12-000 - 16 - 

assist the Commission in carrying out its statutory obligations.39 The City of Dover 

states that reporting is needed to enable the Commission to understand the impact of 

certain transactions. DC Energy strongly supports the Commission’s efforts and argues 

that such reporting will help facilitate the detection of market power. In addition, 

California PUC states that the additional filing requirements can help state regulatory 

agencies: (1) oversee utility procurement; (2) establish statewide renewable 

portfolio standards, energy efficiency initiatives, demand response programs, and 

capacity market activities; and (3) further greenhouse gas policies. 

b. Discussion

20. The market transparency provisions in section 220 of the FPA direct the 

Commission to “facilitate price transparency” in markets for the sale and transmission of 

electric energy in interstate commerce.40 The transparency provisions authorize the 

Commission to “prescribe such rules as the Commission determines necessary and 

appropriate” for the dissemination of “information about the availability and prices of 

wholesale electric energy and transmission service.”41 These provisions expand the 

Commission’s authority to collect such information, not only from public utilities, but 

 39 See, e.g., City of Dover at 1; DC Energy at 5-6; California PUC at 2-3; PG&E at 

3; Wisconsin Electric at 2; EEI at 3. 

40 16 U.S.C. 824t(a)(1). 

41 Id. at 824t(a)(2). 
Docket No. RM10-12-000 - 17 - 

“from any market participant”42 with more than a de minimis market presence.43 The 

Commission proposes, in this NOPR, to fulfill its responsibility under section 220 of the 

FPA by requiring non-public utilities with more than a de minimis market presence in 

wholesale markets to comply with the EQR filing requirements outlined in the next 

section. 

21. Currently, market participants that fall within the Commission’s jurisdiction under 

FPA section 205 must file EQRs. Section 201(f) of the FPA exempts certain entities (i.e., 

Federal entities, municipalities, and certain cooperatives with Rural Electrification Act 

financing and that sell less than 4,000,000 MWh of electricity per year) from the 

Commission’s section 205 jurisdiction.44 However, the transparency provisions in FPA 

section 220 specifically permit the Commission to obtain price and availability 

information from “any market participant.” The phrase “any market participant” is not 

defined in section 220 and is not limited to public utilities subject to the Commission’s 

jurisdiction under section 205 of the FPA. 

 42 Id. at 824t(a)(3). This section states, in relevant part, that “[t]he Commission 

may obtain the information described in paragraph (2) from any market participant.” Id. 

(emphasis added). 

43 Id. at 824t(d). 

44 Id. at 824(f). 
Docket No. RM10-12-000 - 18 - 

22. We interpret “any market participant” to include non-public utilities that fall under 

FPA section 201(f).45 Such an interpretation of “any market participant” is consistent 

with the broad mandate in section 220 to “facilitate price transparency in the markets for 

the sale and transmission of electric energy in interstate commerce, having due regard for 

the public interest, the integrity of those markets, fair competition, and the protection of 

consumers.” Furthermore, in EPAct 2005, Congress amended section 201(b)(2) of the 

FPA46 to provide that, “[n]otwithstanding section 201(f),” the entities described in section 

201(f) shall be subject to the Commission’s jurisdiction for purposes of carrying out 

certain provisions, including FPA section 220. Thus, reading FPA section 201(b)(2) in 

conjunction with section 220, EPAct 2005 granted the Commission authority to collect 

information concerning the availability and prices of wholesale electric energy and 

transmission service from entities that are not public utilities. 

23. We disagree with certain commenters’ assertions that information about wholesale 

sales made by non-public utilities will not significantly enhance price transparency 

because non-public utilities are a small percentage of the wholesale market. As noted 

above, based on 2009 EIA Form 861 data, non-public utility sales account for 

 45 See id. at 824t(a)(3)(A). 

46 FPA section 201(b)(2) states that: Notwithstanding section 201(f), the 

provisions of sections . . . 220 . . . shall apply to the entities described in such provisions, 

and such entities shall be subject to the jurisdiction of the Commission for purposes of 

carrying out such provisions and for purposes of applying the enforcement authorities of 

this Act with respect to such provisions. Id. at 824(b)(2). 
Docket No. RM10-12-000 - 19 - 

approximately 29 percent of wholesale sales in the 48 contiguous states (excluding 

ERCOT),47 while non-public utilities account for 60 and 70 percent of wholesale sales 

within the WECC and SERC regions, respectively. Similarly, non-public utilities make 

up about 80 percent of all wholesale sales that occur within FRCC. Given non-public 

utilities’ significant presence in national and regional wholesale electricity markets, 

obtaining information about their sales transactions is essential to understanding how 

prices are formed in electricity markets. 

24. Certain commenters dispute the accuracy of the 29 percent figure cited in the 

Transparency NOI48 as the percentage of wholesale sales made by non-public utilities, 

arguing that the Commission incorrectly relied on EIA statistics pertaining to non-public 

utility bundled sales instead of wholesale sales. In particular, NRECA, APPA, and 

TANC argue that the Transparency NOI calculated the 29 percent figure based on EIA’s 

figures for retail electric utility sales, labeled “Sales to Ultimate Consumers.” In fact, 

 47 The Commission has excluded ERCOT from its calculations consistent with 

FPA section 220(f), which states that section 220 does not apply to wholesale sales of 

electric energy or transmission services within ERCOT. Id. at 824t(f). However, 

ERCOT members would need to report wholesale power sale contract and transaction 

information in EQR to the extent they make interstate sales outside of ERCOT. 

48 Specifically, the Transparency NOI stated that EIA’s Electric Power Industry 

Overview 2007 estimated that 29 percent of electric utility sales are made by publiclyowned electric utilities (municipals, public utility districts or public power districts, state 

authorities, irrigation districts, and joint municipal action agencies, consumer-owned 

rural electric cooperatives, and Federal electric utilities). See Transparency NOI, FERC 

Stats. & Regs. ¶ 35,565 at P 9 & n. 21 (citing Energy Information Administration, 

Electric Power Industry Overview 2007 (March 2009) available at

http://www.eia.doe.gov/cneaf/electricity/page/prim2/toc2.html). 
Docket No. RM10-12-000 - 20 - 

however, the Commission arrived at the 29 percent figure in the Transparency NOI by 

using the 2007 EIA Form 861 wholesale sales data classified by EIA as “Sales for 

Resale,” and not “Sales to Ultimate Consumers.”49 This 29 percent figure remains the 

same using the most recently available date (i.e. 2009) from EIA Form 861.50 Thus, the 

percentages of wholesale sales made by non-public utilities cited in the Transparency 

NOI and this NOPR are accurate. 

25. With respect to APPA’s comments that the Commission should focus on 

increasing market transparency in RTOs/ISOs instead of increasing market transparency 

by requiring non-public utilities to file EQRs, we agree that transparency in the organized 

markets is important. In fact, the RTOs/ISOs already make available a significant 

amount of information about the availability and prices for wholesale sales and 

transmission service within their markets. For example, in Order No. 719, the 

Commission further promoted transparency in RTO/ISO markets by directing 

RTOs/ISOs to reduce the lag time for the release of offer and bid data and requiring 

RTOs/ISOs to justify in compliance filings their policy regarding the aggregation of offer 

data and cost data, discussing how the policy avoids participant harm and the possibility 

 49 See Annual Electric Power Industry Report Instructions, available at

hptt://www.eia.doe.gov/cneaf/electricity/forms/eia861.pdf. 

50 At the time that the Commission issued the Transparency NOI, EIA had not yet 

released the data for 2009. 
Docket No. RM10-12-000 - 21 - 

of collusion, while fostering market transparency.51 However, notwithstanding the high 

value the Commission places on market transparency in RTO/ISO markets, we continue 

to believe that increasing transparency broadly across all markets subject to the 

Commission’s jurisdiction by requiring all market participants, including non-public 

utilities with more than a de minimis presence in those markets, to provide information 

through EQRs is equally important. 

26. NRECA’s and TANC’s arguments that the Commission should not require nonpublic utilities to report information in the EQR because the Commission has been 

approving market-based rates and evaluating mergers for decades without such 

information miss the mark. Disseminating information through the EQR about wholesale 

sales made by non-public utilities would benefit the Commission, market participants and 

the public in several different ways in addition to improving the Commission’s ability to 

evaluate jurisdictional sellers’ market-based rate authorizations and proposed mergers 

and acquisitions. Information about non-public utility sales would provide a more 

complete view of the prices and volumes that underlie price formation in the wholesale 

power markets. Information on all sales, rather than sales made only by public utilities, 

would allow market participants to value their transactions more accurately and increase 

confidence that market prices reflect all relevant supply and demand forces. Such 

 51 See Wholesale Competition in Regions with Organized Electric Markets, Order 

No. 719, 73 FR 64100 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281 (2008), order on 

reh’g, Order No. 719-A, 74 FR 37776 (Jul. 29, 2009), FERC Stats. & Regs. ¶ 31,292, 

order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009). 
Docket No. RM10-12-000 - 22 - 

information, in combination with other information tools, would also allow the 

Commission to better monitor for indications of market power and manipulation at major 

trading hubs and on electricity indices. For example, without the inclusion of non-public 

utility transactions in the EQR, the Commission may incorrectly conclude that substantial 

market price deviations, or other indicators, at major trading hubs or on electricity indices 

are attributable to the exercise of market power or manipulation by a public utility, when 

in fact, those price deviations reflect legitimate market forces caused by significant 

volumes being transacted by non-public utilities. 

27. In addition, as the Commission explained in the Transparency NOI, obtaining 

EQR information from non-public utilities would strengthen the Commission’s oversight 

of its market-based rate program under FPA section 205 and provide a better basis for 

considering whether to approve merger and acquisition proposals under FPA section 

203.52 The Commission’s market-based rate program is grounded in an ex ante analysis 

of whether to grant a seller market-based rate authority and an ex post analysis of whether 

a seller with market-based rate authority has obtained excessive market share since it was 

granted authorization to transact at market-based rates or since the last review of such 

rates.53 One tool used in some cases to conduct an ex ante analysis of whether to grant 

 

(continued...) 

52 See Transparency NOI, 130 FERC ¶ 61,039 at P 10-12. 

53 The Ninth Circuit Court of Appeals upheld the Commission’s market-based rate 

regulatory scheme because it relies on a “system [that] consists of a finding that the 

applicant lacks market power (or has taken sufficient steps to mitigate market power), 

coupled with strict reporting requirements to ensure that the rate is ‘just and reasonable’ 
Docket No. RM10-12-000 - 23 - 

market-based rate authority to a seller is the delivered price test (DPT). The DPT defines 

the relevant market by identifying potential suppliers based on market prices, input costs, 

and transmission availability, and then calculates each supplier’s economic capacity and 

available economic capacity for each season/load condition.54 Rather than relying on a 

DPT analysis for analyzing a market-based rate seller’s authority that is based on proxy 

prices and published price indices for sales by non-public utilities, obtaining more 

complete price and volume information for sales of electricity by non-public utilities 

would more accurately reflect market prices, improve the quality of the DPT results and 

assist the Commission in identifying whether sellers can exercise market power. The 

DPT also is used by the Commission to evaluate the effect on competition with respect to 

proposed mergers and acquisitions under FPA section 203. Therefore, obtaining more 

 

and that markets are not subject to manipulation.” State of California, ex rel. Bill 

Lockyer v. FERC, 383 F.3d 1006, 1013 (9th Cir. 2004), cert. denied (S. Ct. Nos. 06-888 

and 06-1100, June 18, 2007) (Lockyer). 

54 See Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and 

Ancillary Services by Public Utilities, Order No. 697, 72 FR 39904 (July 20, 2007), 

FERC Stats. & Regs. ¶ 31,252, clarified, 121 FERC ¶ 61,260 (2007), order on reh’g, 

Order No. 697-A, 73 FR 25832 (May 7, 2008), FERC Stats. & Regs. ¶ 31,268, clarified, 

124 FERC ¶ 61,055, order on reh’g, Order No. 697-B, 73 FR 79610 (Dec. 30, 2008), 

FERC Stats. & Regs. ¶ 31,285 (2008), order on reh’g, Order No. 697-C, 74 FR 30924 

(June 29, 2009), FERC Stats. & Regs. ¶ 31,291 (2009), order on reh’g, Order No. 697-D, 

75 FR 14342 (March 25, 2010), FERC Stats. & Regs. ¶ 31,305 (2010). The Commission 

requires the DPT if a seller fails one of the indicative screens. The indicative screens 

analyze the number of megawatts of capacity an applicant owns or controls, rather than 

analyzing actual price data. However, “sellers that do not pass the indicative screens are 

allowed to provide additional analysis for Commission consideration,” including price 

data. Order No. 697, FERC Stats. & Regs ¶ 31,252 at P 62. 
Docket No. RM10-12-000 - 24 - 

complete price and volume information would provide a better basis for considering 

whether to approve merger and acquisition proposals. 

28. Such information from non-public utilities would also provide the Commission 

with important actual sales information for performing ex post analysis of whether a 

jurisdictional seller with market-based rate authority has gained an excessive market 

share since the original authorization to transact at market-based rates or since the 

Commission’s last review of such rates. Information about sales by non-public utility 

market participants will allow the Commission to compare prices for power sold by 

jurisdictional sellers with those of non-public utility sellers in the same market. 

29. Cities/M-S-R argues that the EQR mechanism should not replace other filings 

made by non-public utilities, such as an annual filing with the EIA, because non-public 

utilities have no statutory obligation to file sales agreements with the Commission and 

their rates are not subject to the Commission’s reasonableness determinations. Although 

non-public utilities are not subject to the same filing requirements and rate determinations 

under FPA sections 205 and 206 as public utilities are, we propose that reporting in the 

EQR is the proper mechanism for non-public utilities to make information about their 

wholesale sales and transmission available to the public. As we note below, existing 

sources of information about non-public utility wholesale sales are insufficient to 

facilitate price transparency. The EQR is an established public reporting process that 

already provides substantial transparency into public utility sales. Furthermore, by 

requiring non-public utilities to file information in the EQR in the format used by public 

utilities, we can help ensure the consistency and comparability of the information. 
Docket No. RM10-12-000 - 25 - 

Consistency and comparability between filers is important because wholesale markets do 

not distinguish between sellers that are subject to the Commission’s FPA section 205 

jurisdiction or the Commission’s regulations and sellers that are typically exempt from 

such Commission’s jurisdiction. Expanding the applicability of the Commission’s EQR 

filing requirements allows the Commission and the public to equally evaluate all 

transactions in the market. 

30. With respect to Cities/M-S-R’s arguments that they do not file sales agreements or 

need reasonableness determinations from the Commission on their rates, so they should 

not be required to file EQRs, we note that our jurisdiction under FPA section 220’s 

transparency provisions is limited to the dissemination of information that will aid in 

market transparency for the public and the Commission. Section 220 gives the 

Commission no jurisdiction related to, nor do our proposed regulations govern, the rates, 

terms, and conditions of service of market participants that are excluded from the 

Commission’s FPA section 205 jurisdiction. The Commission is requiring only the 

posting of information important to ensuring market transparency and is not engaging in 

traditional regulation of rates, terms and conditions of service for non-public utilities. 

31. In response to Alaska Power, we propose to exempt utilities located entirely in 

Alaska from the EQR filing requirements because they are electrically isolated from the 

contiguous United States. In addition, we propose to apply this exemption to utilities 

located entirely in Hawaii. 
Docket No. RM10-12-000 - 26 - 

3. Proposed Filing Requirements for Non-Public Utilities

a. Existing Sources of Information

i. Comments

32. California DWR, NRECA, New York Public Power, City of Fayetteville, and 

SWP argue that section 220 of the FPA requires the Commission to determine that 

existing price publications are insufficient before establishing any new reporting 

requirements. Commenters also urge the Commission to consider whether new reporting 

requirements would be duplicative of existing sources, such as EIA reports, ISO/RTO 

data, and private index publishers.55 Public Systems claim that the Commission may not 

impose EQR filing requirements on market participants in New England because RTOs 

in New England already provide the public with extensive data regarding price and the 

availability of wholesale electric energy. SWP also suggests that the Commission could 

combine data from multiple sources, such as the California Independent System Operator 

(CAISO), existing EQRs, and pricing publications, to conduct ex ante or ex post market 

analyses. 

33. According to APPA, before expanding EQR requirements to non-public utilities, 

the Commission should look closely at the amount and type of wholesale sales these 

utilities actually make and consider other sources of available information on such sales, 

 55 See, e.g., East Texas Electric Cooperatives at 2-3; New York Public Power at 3-

4; NRECA at 6-8; Cities/M-S-R at 10-11; DEMEC at 3-4; Public Systems at 11-15; 

TANC at 10-11, 14-15; SWP at 8. 
Docket No. RM10-12-000 - 27 - 

such as EIA publications and forms, to determine whether the additional information 

supplied through their EQR filings would help in achieving the Transparency NOI’s 

stated goals. NRECA and Cities/M-S-R state that cooperatives and other electric utilities 

annually file form EIA-861, “Annual Electric Power Industry Report,” with the EIA. 

They explain that this form includes information such as peak load, generation, electric 

purchases, sales and revenues. Moreover, NRECA states that EIA provides access to the 

daily volumes, high and low prices, and weighted average prices from hubs around the 

country. In addition, NRECA states that cooperatives that receive Rural Utilities Service 

(RUS) financing are required to file RUS Form 12, which includes such information as 

electric purchases, sales, and revenues and is publicly available through a database 

purchased from Ventyx.56 NRECA also states that the Energy Management Institute 

provides results of a daily survey of wholesale transactions that they conduct in all the 

major trading regions of the country. Furthermore, TANC and NRECA note that forward 

market prices are available through the New York Mercantile Exchange and the 

IntercontinentalExchange. Finally, Sam Rayburn Municipal believes that any additional 

reporting requirement would be duplicative because its power supply structure is simple 

and reported in detail in its formal financing, accounting and engineering documents.57 

 56 Ventyx is a commercial provider that offers Velocity Suite, an application that 

includes data from generation and transmission cooperatives, distribution cooperatives, 

municipal utilities, and other market participants exempt from the Commission’s FPA 

section 205 jurisdiction. 

57 Sam Rayburn Municipal at 2. 
Docket No. RM10-12-000 - 28 - 

ii. Discussion 

34. In carrying out Congress’ directive to facilitate price transparency in wholesale 

sales and transmission markets, FPA section 220 requires that the Commission consider 

the degree of price transparency provided by existing price publishers and trade 

processing services, and rely on such publishers and services to the maximum extent 

possible.58 As pointed out by commenters, there are already a number of sources of 

publicly available information about wholesale markets, including EIA and RUS forms, 

RTOs/ISOs, electric index publishers, and commercial data providers that provide 

varying degrees of price transparency. However, the Commission believes the degree of 

price transparency provided by existing sources is insufficient for facilitating price 

transparency. 

35. The two most significant publicly available forms that capture information about 

non-public utility power sales are the EIA Form 861 and the RUS Form 12. EIA Form 

861 reports total volume (MWh) and revenue associated with a filer’s wholesale power 

sales for an entire year.59 However, Form EIA Form 861 does not detail individual 

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

timeframe as well as other transaction details contained in EQR. Rather, EIA Form 861 

filers report their aggregated annual volume of sales for resale and corresponding 

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

59 On line 12 of Schedule 2, Part B, EIA Form 861 collects information on 

electricity “Sales for Resale.” http://www.eia.doe.gov/cneaf/electricity/forms/eia861.pdf. 
Docket No. RM10-12-000 - 29 - 

revenues. RUS Form 12 provides accounting details for power transaction by entities 

that fall under 7 U.S.C. 901 authority.60 RUS Form 12 provides considerably more detail 

than EIA Form 861 through the inclusion of the energy purchaser and other contract 

details for individual energy sales.61 However, RUS Form 12 provides only limited price 

transparency because the form does not contain information on delivery location and 

time. Delivery location and time are critical for gaining insight into price formation.62 

Without transaction-specific delivery location and time information, Form EIA 861 and 

RUS Form 12 do not provide sufficient price transparency into wholesale electricity 

markets. Therefore, expanding EQR filing requirements to non-public utilities would 

provide price transparency that is not available through EIA Form 861 or RUS Form 12. 

36. RTOs/ISOs post extensive information about RTO/ISO wholesale market prices 

and market participant bid/offer data that provide valuable transparency for spot 

wholesale power markets run by RTOs/ISOs. These postings contain detailed location, 

market and product information. However, these postings are limited to the wholesale 

 60 RUS Form 12b SE itemizes sales of electricity while RUS Form 12b PP 

itemizes purchases of electricity. http://www.usda.gov/rus/dcs/electric-forms/form12-

2006.pdf, http://www.usda.gov/rus/dcs/downloads/form12/1717b-3.pdf. 

61 RUS Form 12b SE data field “Statistical Classification (b)” provides detail on 

whether the sale is for requirements service, long-term firm service or intermediate-term 

firm service, among other classifications. 

http://www.usda.gov/rus/dcs/downloads/form12/1717b-3.pdf. 

62 For example, one would expect power sold in a load-constrained area during onpeak hours to be priced very differently from power sold in a generation-rich area during 

off-peak hours. 
Docket No. RM10-12-000 - 30 - 

electricity markets that are administered by RTOs and ISOs. In addition, publicly posted 

RTO/ISO data does not provide price transparency into the bilateral transactions entered 

into by market participants within the RTO/ISO balancing authority area that can impact 

RTO/ISO market price formation. These bilateral transactions are frequently scheduled 

into the RTO/ISO market.63 The terms of bilateral transactions are often not reported to 

RTO/ISO markets and not included in publicly posted price and bid/offer data. While 

some bilateral transactions are already reported in the EQR, expanding the EQR filing 

requirements to include non-public utilities would give the Commission and the public a 

better view into bilateral transactions. This data would also enhance the RTO/ISO 

market monitoring units’ ability to monitor RTO/ISO markets. Thus, expanding EQR 

filing requirements to non-public utilities would provide valuable price transparency into 

bilateral wholesale electricity markets that is not currently captured in publicly posted 

data from RTOs/ISOs. 

37. Existing daily index publications provide a degree of price transparency into spot 

wholesale electricity markets by capturing certain transactions. However, this price 

transparency is limited because these index publications do not capture longer-term 

transactions. Expanding EQR filing requirements to non-public utilities would provide 

price transparency for longer-term transactions not included in daily index publications. 

 63 For example, NYISO estimates that approximately 50 percent of the energy 

scheduled in their markets was transacted bilaterally. See

http://www.nyiso.com/public/about_nyiso/understanding_the_markets/energy_market/in

dex.jsp. 
Docket No. RM10-12-000 - 31 - 

38. Organized exchanges, such as the IntercontinentalExchange, also provide valuable 

price information, but that information is limited only to prices for particular power 

products at standardized locations. Finally, commercial data providers, like Ventyx, 

provide a valuable service by collecting and packaging existing publicly available data. 

However, their products are limited by the availability of existing information, and 

therefore do not, in themselves, increase price transparency. 

39. In addition, information about non-public utility transmission service and 

reassigned transmission capacity sales may be available in the Open Access Same-Time 

Information System (OASIS). However, information on OASIS is not readily accessible 

to the public. Thus, requiring information about non-public utility transmission service 

and reassigned transmission capacity sales to be made publicly available through the 

EQR will facilitate price transparency in the transmission markets and aid the public and 

the Commission in detecting and addressing possible market power and manipulation in 

these markets. 

b. Scope of Proposed EQR Filing Requirements for Non-Public 

Utilities

i. Comments

40. BPA and Cities/M-S-R question whether the Commission needs all of the 

information included in the EQR and whether quarterly filings are necessary. In 

particular, BPA believes that the critical information that the Commission needs to 

measure the size of the relevant market is contained in the transaction section, Field 

Numbers 46-67, and that the information in the contract section would not be necessary 
Docket No. RM10-12-000 - 32 - 

or helpful to the Commission. In addition, APPA and Salt River note that the 

Commission may need to customize the EQR filing forms to reflect the types of 

information applicable to public power entities.64 However, EEI states that if particular 

reporting requirements do not apply to a given filer, it can simply indicate “not 

applicable.” 

41. In addition, BPA asserts that the burden would be greatly reduced if the 

Commission were to limit the filing requirements for BPA to wholesale power sales at 

market-based rates. Thus, BPA supports excluding the cost-based sales to consumerowned utilities, direct services industries, and inter-business line transmission services 

transactions. 

42. APPA asserts that sales by joint action agencies, state agencies, and power or 

water districts to their own members should not be reported.65 APPA argues that if the 

Commission expands EQR filing requirements to public power utilities, these agencies 

and districts should only be required to file EQR information on their excess power sales 

(i.e., sales to entities other than their member utilities or long-term distribution 

customers). TAPS and Public Power argue that joint-action agencies should not be 

required to report transactional information on long-term, wholesale sales of power to 

their member utilities. In addition, TAPS argues that generation and transmission (G&T) 

 64 Salt River at 4-5. 

65 APPA at 5. 
Docket No. RM10-12-000 - 33 - 

cooperatives’ sales to their members should not be included. TAPS explains that 

although technically at wholesale, such sales are analogous to a vertically integrated 

utility’s internal supply of its retail sales unit and subsequent retail sale, neither of which 

is reported through public utilities’ EQRs.66 

43. LPPC and Salt River argue that the Commission should avoid requirements for 

reporting on long-term power supply arrangements that are solely between nonjurisdictional entities. For instance, LPPC argues that the power sold under long-term 

arrangements between non-jurisdictional entities is not a factor to market participants 

when considering competitive purchases or sales nor is it relevant to the Commission’s 

market manipulation oversight. Thus, such power arrangements do not factor into the 

market over which the Commission has oversight.67 

44. By contrast, PG&E, Wisconsin Electric, and EEI believe that market participants 

that are excluded from the Commission’s section 205 jurisdiction should file the same 

data elements that jurisdictional entities are required to file under the EQR Data 

Dictionary. 

ii. Commission Proposal

45. The Commission proposes to apply the same EQR requirements to non-public 

utilities that it currently requires from public utilities, with some adjustments, as 

 66 TAPS at 2, 12. 

67 LPPC at 3. 
Docket No. RM10-12-000 - 34 - 

discussed below. In particular, the Commission proposes that non-public utilities be 

required to report the same information about wholesale sales, transmission service, and 

transmission capacity reassignments that are currently reported by public utilities. 

Expanding the same EQR data elements to non-public utilities will help ensure 

comparability and consistency with filings by public utilities, which will make it easier 

for market participants and the public to use the information. In addition, requiring the 

same sales and transmission-related information from non-public utilities will allow the 

Commission to better evaluate the performance of wholesale markets as a whole and 

make it easier to determine that jurisdictional prices are “just and reasonable.” 

46. In their comments, several market participants suggest that non-public utilities 

should not be required to file certain sales in the EQR, such as certain cost-based sales. 

BPA, for instance, suggested that cost-based sales to consumer-owned utilities, interbusiness line transmission services transactions and sales to direct services industries, 

which are developed based on cost-based rates, should not be filed.68 Other commenters 

suggest that joint action agencies should not be required to report transactional 

information on the long-term, wholesale sales of power to their member utilities. 

47. The Commission proposes that all wholesale sales, including cost-based and 

market-based sales, be included in EQR filings from non-public utilities with more than a 

de minimis market presence. Although several commenters argue that certain sales, such 

 68 Cities/M-S-R at 9. 
Docket No. RM10-12-000 - 35 - 

as sales by joint action agencies, state agencies, and power or water districts to their own 

members, should not be reported, we conclude that excluding these wholesale sales in the 

EQR adversely impacts price transparency in wholesale electricity markets. Specifically, 

these sales can impact market prices regardless of whether or not they are made by 

entities that fall under the Commission’s FPA section 205 jurisdiction. For instance, if 

the agencies and districts did not supply their members, then the members would have to 

purchase supply from other sources in the market. Also, depending on these agency and 

district rules, the members may be able to sell excess power into the market. In either 

case, these sales would have an effect on the formation of prevailing market prices. Sales 

transactions by non-public utilities, whether cost-based or market-based, can influence 

wholesale electricity markets. Excluding certain segments of wholesale sales would 

result in an incomplete picture of wholesale price formation and would hamper the ability 

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

power and manipulation. 

48. Furthermore, we agree with TAPS that a vertically integrated utility that internally 

supplies its retail sales unit would not need to report that supply in the EQR because there 

is no wholesale sale in this situation. However, in the case of a G&T cooperative selling 

to its member cooperatives to meet the members’ load obligations, this would constitute a 

wholesale sale that must be reported in the EQR. Such reporting is consistent with how 

jurisdictional cooperatives report their sales in the EQR. Any subsequent sale by a 

member cooperative to its retail customers would be a retail sale that is not reported in 

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

49. We believe that certain data fields in the EQR may not be applicable to filings 

made by non-public utilities. For example, contract data Field Number 19 (FERC Tariff 

Reference) and transaction data Field Number 50 (FERC Tariff Reference) require filers 

to insert a “FERC Tariff Reference.” Non-public utilities may not possess an appropriate 

FERC Tariff Reference (Fields 19 and 50) for certain wholesale contracts and 

transactions. In cases where a FERC Tariff Reference is not applicable, the Commission 

proposes to require that a filer state that the appropriate FERC Tariff Reference is “Not 

Required,” or “n/r,” in their EQR filing. However, if the sale relates to a previously filed 

reciprocal open access transmission tariff (OATT), the Commission proposes that the 

appropriate reference to the reciprocal OATT be included in the EQR. In addition, nonpublic utilities can mark as “Not Required,” or “n/r,” for the “Product Type Information” 

captured in Field Number 30, which relates to whether the transaction is “cost-based,” 

“capacity reassignment,” “market-based,” or “other,” because the values for Field 

Number 30 are defined based on types of FERC-approved tariffs.

50. In its comments, BPA noted that the information necessary for the Commission to 

measure the size of a relevant market for merger analysis can be found in the transaction 

section (Field Numbers 46 through 67) of the EQR, but that the contract section (Field 

Numbers 14 through 45) does not appear to be necessary or helpful for merger analysis. 

The Commission agrees with BPA’s assessment that the transaction section would be the 

relevant data fields in the EQR to use in determining the size of a wholesale energy 

market. However, the EQR’s function is not limited to merger analysis, as discussed 

above. 
Docket No. RM10-12-000 - 37 - 

51. Furthermore, limiting EQR data to only transactions data would significantly 

detract from the Commission’s efforts to facilitate price transparency under FPA section 

220. The contract section of the EQR provides critical price transparency information in 

several ways. First, the contract section provides information and valuable context on 

when rates were established and the terms of the rates. Without contextual information, 

such as when and how a rate was agreed upon, the sales price that is reported in the 

transaction section (Field Number 64) might appear anomalous compared to other prices 

reported in the transaction section. Second, there are a number of products and 

agreements that are reported solely on the contract section of the EQR, such as 

emergency energy, interconnection agreements, membership agreements, and must run 

agreements.69 These products and agreements can impact a market participant’s ability 

to make sales and access transmission, which are aspects of price formation. Therefore

excluding them would limit the price transparency impact associated with expanding the 

EQR to non-public utilities. 

, 

c. Burden 

i. Comments

52. EEI believes that the burden on non-public utilities would be no greater than the 

burden on jurisdictional entities, once systems are in place to collect and compile the 

 69 For a detailed list, please refer to Appendix B in the Electric Quarterly Report 

Data Dictionary, Version 1.1, available at http://www.ferc.gov/docs-filing/eqr/softtools/eqrdatadictionary.pdf. 
Docket No. RM10-12-000 - 38 - 

information. However, several commenters state that complying with any additional 

reporting requirements would be a significant burden for municipals and cooperatives. 

Public Power Council states that the EQR requirements are burdensome and the value of 

the information that the Commission would collect from most Northwest public power 

entities does not justify the cost that would be expended by non-public utilities to produce 

the information. Further, Utah Associated Municipal states that filing EQRs to report 

those sales made every hour of every day to nearly every member utility would give the 

Commission no useful information relevant to its purposes. 

53. Cities/M-S-R argue that it is unnecessarily burdensome for the Commission to 

collect transaction data for market transparency purposes on a quarterly basis and state 

that the Commission has created annual, not quarterly, reporting requirements under the 

natural gas transparency provisions. Cities/M-S-R also assert that the data required on 

Form 552 for natural gas transactions is less involved than EQR data fields and creates a 

more limited burden on responding parties. Further, Cities/M-S-R state that the scope of 

the EQR information is broader than necessary and the frequency is too great for the 

limited purpose of obtaining information to improve the Commission’s delivered price 

test analysis. 

54. According to APPA, a number of its members estimated that they would require 

from two weeks to nine months for the initial setup, and one to three days to compile, 

verify, and file the EQR each quarter. The City of Fayetteville states that it has not done 

a detailed cost/time analysis, but believes that it would fall in the upper quartile of the 

time estimates reported in the APPA comments. Allegheny estimates that significant 
Docket No. RM10-12-000 - 39 - 

computer system changes and additional ongoing personnel resources may be required, 

the costs of which would need to be passed along to the cooperative’s customers. Salt 

River estimates that it would need at least six months to develop an internal EQR filing 

program. In addition, Salt River encourages the Commission to provide guidance 

through workshops or training sessions and to provide opportunities for interaction with 

staff while preparing initial filings, and to allow sufficient time to ensure completeness 

and accuracy of the filings. Based on its own experience, DC Energy states that, while 

the burden will vary depending on the scope and amount of activities, there would be an 

upfront time investment of 2-4 person-weeks to design and implement an EQR 

tracking/reporting system, and an ongoing reporting burden of 2-3 person-days per 

quarter. It states that this estimate is based on a “self-build model” and believes there 

also are off-the-shelf products that will automatically generate these reports for an entity, 

resulting in less of a burden. 

55. BPA states that the burden would be greatly reduced if the Commission were to 

limit the filing requirements for BPA to wholesale power sales at market-based rates 

(thereby excluding inter-business line transmission services transactions, and the 

statutorily-mandated cost-based sales to consumer-owned utilities and direct services 

industries70) and eliminate the fields associated with contract data. BPA also argues that 

it should not be required to report transmission services sales made by BPA’s 

 70 BPA notes that direct services industries are generally a defined set of aluminum 

companies and large industries in the Pacific Northwest. BPA at 1. 
Docket No. RM10-12-000 - 40 - 

functionally separated Power Services section to its Transmission Services section 

because these inter-business line transactions are not discretionary, open market 

transactions that would aid the Commission in evaluating market power issues. 

ii. Discussion

56. We acknowledge that enhancing price transparency by extending the EQR filing 

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

market participants. However, we believe that, on balance, the benefit of increased price 

transparency stemming from the filing of such information will outweigh the burden on 

these market participants above the de minimis threshold. We assume that most nonpublic utilities already capture transaction-specific information for accounting and 

record-keeping purposes. Therefore, we believe the burden imposed will relate primarily 

to the required format for submitting that information. In addition, we believe that the 

amount of burden created by requiring non-public utilities to file EQRs will depend on 

how many transactions the non-public utility makes. Accordingly, entities with a 

relatively small number of wholesale sales will face less of a burden. 

57. Cities/M-S-R contend that the data collected under the natural gas market 

transparency provisions is less burdensome because it is collected annually, not quarterly, 

and contains less detail than the EQR data. We note that the Commission has 

promulgated two rules under the natural gas market transparency provisions in section 23 
Docket No. RM10-12-000 - 41 - 

of the NGA,71 Order Nos. 704 and 720. Order No. 704 requires certain purchasers and 

sellers of natural gas to file an annual report about specified physical natural gas 

transactions. Order No. 720 requires major non-interstate pipelines to file certain receipt 

and delivery information on a daily basis. Therefore, Order No. 720 requires data to be 

provided more frequently than the EQR. In addition, Order No. 720 requires noninterstate pipelines to post detailed information, including the transportation service 

provider’s name, posting data, posting time, nomination cycle, location name, additional 

locational information if needed to distinguish between points, location purpose 

description, posted capacity, scheduled volume, available capacity, and measurement unit 

for each receipt or delivery point that meets certain criteria.72 Although the level of detail 

in the EQR may be greater than that required under Order Nos. 704 and 720, this 

difference reflects variations between transactions made in the natural gas and electricity 

markets. 

58. We disagree with Cities/M-S-R’s suggestion that the Commission seeks to obtain 

EQR information from non-public utilities solely to improve the Commission’s DPT. As 

discussed above, the Commission proposes to require non-public utilities to file EQRs to 

fulfill Congress’s directive in FPA section 220 to facilitate price transparency in markets 

for the sale and transmission of electric energy in interstate commerce. The information 

 71 15 U.S.C. 717t-2. 

72 See 18 CFR 284.14. 
Docket No. RM10-12-000 - 42 - 

in these EQRs will provide valuable information that serves a number of purposes. This 

information will provide a more complete picture of price formation in wholesale 

electricity markets for the Commission and the public. In addition, obtaining sales price 

and volume information in EQRs from non-public utilities will increase the 

Commission’s ability to monitor utilities' power sales for indications of market power 

and manipulation. Also, as explained in the Transparency NOI,73 and discussed above, 

collecting EQR information from non-public utilities would improve the quality of the 

DPT results and assist the Commission in determinations concerning a seller’s ability to 

exercise market power and provide a better basis for considering whether to approve 

merger/acquisition proposals under FPA section 203. 

59. We believe that the EQR compliance burden on non-public utilities above the de 

minimis threshold would be greatest during the initial set-up phase, when data is mapped 

into the new required format. However, to the extent a filer uses the same format for 

each EQR, once the filer's system is mapped to the interim and final formats, the burden 

will be significantly reduced. The Commission invites comment from non-public utilities 

and public utilities on how their existing data capture processes have been or can be 

mapped to facilitate EQR filing in its current and proposed formats. 

60. We recognize that the initial implementation and ongoing reporting associated 

with the proposed EQR filing requirements will result in additional costs and burden on 

 73 See Transparency NOI, FERC Stats. & Regs. ¶ 35,565 at P 9-12. 
Docket No. RM10-12-000 - 43 - 

non-public utilities. However, the Commission has tried to balance the need for data with 

efforts to minimize the burden on filers. To help alleviate the burden of filing EQRs, the 

Commission has designed a system that allows EQRs to be filed using the Internet so that 

all filers submit EQRs to the Commission electronically. In addition, the Commission is 

only requiring those non-public utilities that fall above the de minimis threshold test to 

file EQRs. We also agree with Salt River that workshops or training sessions to provide 

guidance may be helpful and we will make every effort to provide technical assistance 

prior to the implementation of the EQR filing requirements for non-public utilities. 

d. De Minimis Threshold

i. Comments

61. Commenters propose a wide range of de minimis market presence thresholds for 

non-public utility exemptions from the EQR filing requirements, from 8 million MWh to 

100 MWh of annual sales. In favor of the 8 million MWh threshold, two commenters74

point to FPA section 206(e), which gives the Commission refund authority over certain 

sales made by non-jurisdictional entities except for an entity that sells less than 8 million 

MWh of electricity per year.75 Cities/M-S-R also argue that a threshold of at least 8 

million MWh per year is appropriate because of the growth in the electricity market, as 

 74 Cities/M-S-R at 14; Imperial at 6. 

75 16 U.S.C. 206(e). 
Docket No. RM10-12-000 - 44 - 

evidenced by the reported wholesale sales, which have nearly tripled between 1997 and 

2008.76 

62. Other commenters recommend a threshold level of 4 million MWh, based on 

either annual wholesale sales77 or annual total sales.78 In support of a 4 million MWh 

threshold, many commenters refer to section 201(f) of the FPA, which specifically 

excludes from the Commission’s jurisdiction electric cooperatives that sell less than 4 

million MWh of electricity per year.79 They also cite to the definition of a small utility 

under the Regulatory Flexibility Act and Small Business Act, which define a utility as 

small if its total annual output (i.e., wholesale and/or retail) does not exceed 4 million 

MWh.80 APPA states that a threshold of 4 million MWh annual wholesale sales would 

capture approximately 70 percent of public power utilities’ wholesale sales, and 82 

 76 Cities/M-S-R at 14. 

77 See, e.g., APPA at 9; NRECA at 26; New York Public Power at 6; Delaware 

Municipal at 5; City of Fayetteville at 7; Southwest Transmission at 3; Alaska Power at 2. 

78 See, e.g., City of Dover at 2; Northwest Utility at 2; TANC at 20. 

79 In particular, FPA section 201(f) provides, in part, that "[n]o provision in this 

subchapter shall apply to, or be deemed to include . . .an electric cooperative that receives 

financing under the Rural Electrification Act of 1936 (7 U.S.C. 901 et seq.) or that sells 

less than 4,000,000 megawatt hours of electricity per year." 16 U.S.C. 824(f). 

80 The Regulatory Flexibility Act (RFA) definition of a “small entity” refers to a 

definition provided in the Small Business Act, which defines a “small business concern” 

as a business that is independently owned and operated and that is not dominant in its 

field of operation. See 15 U.S.C. 632. According to the Small Business Act, a small 

electric utility is one that has a total electric output of less than 4 million MWh in the 

preceding year. 15 U.S.C. 631. 
Docket No. RM10-12-000 - 45 - 

percent of wholesale sales made by cooperative, Federal, and public power utilities 

combined. APPA argues that using annual wholesale sales will eliminate the potential 

for double-counting some public power wholesale sales in RTO regions, such as joint 

action agency sales to their members. APPA also argues that the use of EIA data to 

determine which utilities are above the de minimis threshold for reporting purposes will 

eliminate the potential for double-counting some public power wholesale sales in RTO 

regions. For example, notes APPA, joint action agencies situated in RTO regions are 

often required to sell their wholesale power into their RTO’s market at the point of 

generation, buy it back at their members’ load nodes, and then sell the same energy to 

their members. Using EIA data would eliminate potential double-counting of these joint 

action agency sales to members as sales to an RTO as well. Additionally, the City of 

Fayetteville argues that, in promoting wholesale market transparency, retail sales to 

ultimate consumers should not be counted toward the cutoff, because such sales do not 

bear on whether a section 201(f) entity’s wholesale market presence is de minimis. 

63. EMCOS believes that 4 million MWh based on total annual sales is appropriate, 

but that both inter-affiliate sales by consumer-owned utilities and must-offer sales into 

Day 2 markets should be excluded to avoid over-reporting. NRECA and Allegheny 

argue that the Commission also should not consider sales by G&T cooperatives to their 

members as wholesale sales for purposes of the de minimis 4 million MWh sales 

threshold. NRECA states that when a G&T cooperative makes sales to its member 

cooperatives under long-term wholesale power contracts, it is essentially acting as the 

functional equivalent of a generation division of a vertically integrated public utility. 
Docket No. RM10-12-000 - 46 - 

NRECA also argues that if the Commission does not exclude sales by G&T cooperatives 

to their member cooperatives, then it should establish a rebuttable presumption that nonpublic utility cooperatives that sell less than 4 million MWh of power to third parties 

other than their member cooperatives are exempt from the filing requirement as having a 

de minimis impact on wholesale markets if such sales constitute less than 2 percent of 

wholesale sales in the region. 

64. LPPC asks the Commission to exempt non-jurisdictional entities from having to 

report long-term sales agreements (of greater than one year) between non-jurisdictional 

entities. LPPC also asks the Commission to provide a mechanism for requests for waiver 

sought by parties on the ground that specific transactions or categories of transactions are 

not of a nature that their reporting is relevant to the Commission’s oversight of the 

wholesale marketplace. LPPC states that examples of typical long-term agreements 

between non-jurisdictional entities are the thirty-year sales agreements between 

municipal utilities and MEAG Power, which was formed by the Georgia Assembly for 

the purpose of generating power to be sold under long-term agreements to municipal 

utility participants. LPPC states that the power sold under these agreements does not 

factor into the market over which the Commission has oversight. 

65. Some commenters further note that the Commission has used a 4 million MWh of 

total sales threshold in several contexts. For instance, TANC states that the Commission 

has used this threshold in granting waivers of standards of conduct for transmission 
Docket No. RM10-12-000 - 47 - 

providers under Order Nos. 888,81 889,82 and 890,83 and with respect to the requirement 

that RTOs/ISOs accept demand response bids by aggregators of retail customers.84 

Furthermore, some commenters, such as LPPC, argue that a utility that sells 4 million 

MWh or less of energy per year is too small to affect the electricity markets, so excluding 

it from the EQR requirements would still provide the Commission with information on 

the large majority of wholesale transactions by non-jurisdictional entities. 

66. By contrast, EEI and DC Energy recommend adopting relatively low thresholds. 

EEI states that the Commission could apply one of the following thresholds: (1) 100 

MWh of sales for resale per year used by the Commission in the context of FERC Forms 

1 and 1-F between major and non-major utilities; or (2) 114,000 MWh of sales per year, 

 81 Promoting Wholesale Competition Through Open Access Non-Discriminatory 

Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities 

and Transmitting Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. 

& Regs. ¶ 31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12274 

(Mar. 14, 1997), FERC Stats. & Regs. ¶ 31,048, order on reh'g, Order No. 888-B, 62 FR 

64688 (Dec. 9, 1997), 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 

FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study 

Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 

U.S. 1 (2002). 

82 Open Access Same-Time Information System and Standards of Conduct, Order 

No. 889, 61 FR 21737 (May 10, 1996), FERC Stats. & Regs. ¶ 31,035 (1996), order on 

reh'g, Order No. 889-A, 62 FR 12484 (March 14, 1997), FERC Stats & Regs. ¶ 31,049, 

reh'g denied, Order No. 889-B, 81 FERC ¶ 61,253 (1997). 

83 Order No. 890, FERC Stats. & Regs. ¶ 31,241. 

84 TANC at 19-20 (citing Wolverine Power Supply Coop., Inc., 127 FERC 

¶ 61,159, at P 15 (2009); Order No. 719, FERC Stats. & Regs. ¶ 31,218). 
Docket No. RM10-12-000 - 48 - 

based on what a qualifying facility (QF) exempted from FPA section 205 (20 MW or 

smaller) could produce in a year.85

67. Sam Rayburn Municipal believes that a threshold exemption should exist where 

there is no retail competition or the relative size or amount of power transactions is 

insignificant by size or substance. 

ii. Discussion

68. FPA section 220(c)(2)(d) specifies that the Commission shall not require entities 

with a de minimis market presence to comply with the reporting requirements of FPA 

section 220. At present, the Commission collects data regarding cost-based sales, 

market-based rate sales, transmission service, and transmission capacity reassignments 

from entities subject to section 205 of the FPA. Data regarding sales, transmission 

service, and transmission capacity reassignments provided by non-public utilities is not 

readily available. Without this data, the public is unable to observe a significant number 

of trades and is unable to develop a more complete view of wholesale power and 

transmission markets. As discussed above, a more complete view of price formation in 

the markets will provide the public with greater price transparency to evaluate the 

concentration of market participants in a market and the market participant’s ability to 

unduly influence the market, and will assist the public and the Commission in detecting 

and addressing the potential exercise of market power and manipulation. 

 85 EEI at 4. 
Docket No. RM10-12-000 - 49 - 

69. The Commission proposes that a non-public utility would be exempt under the de

minimis market presence threshold from filing EQRs if it makes 4 million MWh or less 

of annual wholesale sales (based on an average of the wholesale sales it made in the 

preceding three years), unless the non-public utility is a Balancing Authority86 that makes 

1 million MWh or more of annual wholesale sales (based on an average of wholesale 

sales it made in the preceding three years). As requested by some commenters, the 

Commission proposes to calculate the de minimis market presence threshold on the 

amount of annual wholesale sales made by the non-public utility rather than total (i.e. 

wholesale and retail) sales. The transparency provisions in FPA section 220 focus on the 

Commission requiring information concerning the availability and prices of “wholesale 

electric energy and transmission service.”87 Therefore, the Commission proposes to use 

only the wholesale electricity sales made by non-public utilities for purposes of 

calculating the de minimis market presence threshold. 

70. To reduce the filing burden and promote clear compliance requirements, the 

Commission proposes that non-public utilities use the annual wholesale sales volumes 

 86 As defined in the North American Electric Reliability Corporation’s (NERC) 

Glossary of Terms Used in Reliability Standards, a Balancing Authority is the 

“responsible entity that integrates resource plans ahead of time, maintains loadinterchange-generation balancing within a Balancing Authority Area, and supports 

Interconnection frequency in real time.” See

http://www.nerc.com/files/Glossary_of_Terms_2011Mar15.pdf. 

87 See 16 U.S.C. 824t(a)(2). 
Docket No. RM10-12-000 - 50 - 

they currently report to EIA to calculate whether they meet the de minimis threshold. 88 

The Commission proposes that the threshold be calculated using the “Sales for Resale” 

data published in EIA Form 861.89 “Sales for Resale” as reported in EIA Form 861 does 

not include retail sales, as addressed above. 

71. The Commission believes that establishing a 4 million MWh annual wholesale 

sales threshold for non-public utilities that are not Balancing Authorities will allow the 

Commission and the public to access information from market participants whose 

transactions could have an impact on wholesale market prices and thereby increase price 

transparency for the markets and aid in the Commission’s oversight of wholesale 

electricity markets,90 while alleviating the reporting burden for smaller entities. 

72. With respect to non-public utilities that are Balancing Authorities, the 

Commission believes requiring them to file EQRs if they make 1 million MWh or more 

of annual wholesale sales will provide a more complete picture of prices within the 

balancing authority area markets that are operated by non-public utilities and thereby 

 88 This proposal is consistent with APPA’s suggestion to use EIA data when 

calculating the de minimis threshold. See APPA at 9-10. 

89 “Sales for Resale” figures can be found on Line 12 in “Schedule 2, Part B. 

Energy Sources and Disposition.” See

http://www.eia.doe.gov/cneaf/electricity/forms/eia861/eia861instr.pdf. 

90 It is important to note that electricity markets can be comprised of markets that 

are regional, local, and even nodal. For example, exerting market power does not 

necessarily involve a large volume of physical sales. In fact, small volumes of power 

sales can influence market pricing, particularly when transmission limitations and other 

dynamics exist. 
Docket No. RM10-12-000 - 51 - 

assist market participants and the Commission, particularly with respect to conducting 

market-based rate analyses for jurisdictional market-based rate sellers. For traditional 

(non-RTO/ISO) markets, the Commission uses the balancing authority area as the default 

relevant geographic market for its market-based rate analysis.91 For example, Order 

No. 697 noted that if a transmission-owning Federal power marketing agency is the home 

or first-tier market to a seller located outside of an RTO/ISO, then that seller must treat 

that Federal power marketing agency’s balancing authority area as a relevant geographic 

market and file a market power analysis on it just as it would any other relevant market.92 

Obtaining sales information from non-public utility Balancing Authorities that operate 

that balancing authority area would greatly assist the Commission in determining whether 

to grant a seller market-based rate authority (ex ante analysis) and allow a more effective 

after-the-fact examination of market-based rate authorizations (ex post analysis). The 

Ninth Circuit Court of Appeals upheld the Commission’s market-based rate program 

based on the dual requirement of an ex ante finding of the absence of market power and 

post-approval reporting requirements through the EQR. Specifically, the Ninth Circuit 

held that “FERC’s system consists of a finding that the applicant lacks market power (or 

has taken sufficient steps to mitigate market power), coupled with strict reporting 

 91 See Order No. 697, FERC Stats. & Regs ¶ 31,252 at P 232. 

92 See id. 
Docket No. RM10-12-000 - 52 - 

requirements to ensure that the rate is ‘just and reasonable’ and that markets are not 

subject to manipulation.”93 

73. APPA expresses concern about double counting of wholesale sales by joint action 

agencies situated in RTO/ISO markets. APPA notes that joint action agencies in 

RTO/ISO regions are often required to sell their wholesale power into the RTO/ISO 

market at the point of generation, buy it back at their members’ load nodes and then sell 

the same energy to their members. APPA suggests that using EIA data would eliminate 

double counting of these joint action agency-to-member transactions as sales to an 

RTO/ISO. As noted above, the Commission proposes that non-public utilities use EIA 

data to determine whether they meet the de minimis threshold. However, the 

Commission is concerned with capturing all wholesale power sales as they occur (no 

matter how many times the power changes hands). Therefore, in the example provided 

by APPA, the Commission agrees that EIA data should be used by the joint action agency 

to determine whether it meets the de minimis threshold for filing EQRs. However, if the 

joint action agency, or other non-public utility, determines that it falls above the de 

minimis threshold based on the EIA data, then the Commission would expect the joint 

action agency or other non-public utility to report all wholesale sales in a manner that is 

consistent with existing EQR reporting standards. 

 93 Lockyer, 383 F.3d 1013. 
Docket No. RM10-12-000 - 53 - 

74. Some commenters argue that the Commission should not consider sales such as 

inter-affiliate sales by consumer-owned utilities or sales by G&T cooperatives to their 

members for purposes of the de minimis threshold. For ease of reference, we shall refer 

to the transactions raised by NRECA, and others as "inter-familial transactions". We 

disagree with commenters’ assertions that wholesale inter-familial transactions should 

not be considered sales for purposes of the de minimis annual wholesale sales threshold. 

Rather, the Commission believes that any sale of wholesale electricity should count 

towards the threshold, regardless of the type of transaction from which the sale originated 

(e.g., G&T cooperative sales to its members captured under long-term wholesale power 

agreements). Moreover, reporting of wholesale inter-familial transactions will assist the 

Commission and the public in monitoring price formation and understanding electricity 

prices, quantities, and market trends, particularly in bilateral markets. 

75. We further note that the Commission will not propose the rebuttable presumption 

suggested by NRECA that non-public utility cooperatives that sell less than 4 million 

MWh of power to third parties other than their member cooperatives are exempt from the 

EQR filing requirements as having a de minimis impact on wholesale markets if such 

sales constitute less than 2 percent of wholesale sales in the region. We also do not 

propose a mechanism for requesting waiver of the EQR reporting requirements on the 

basis that the nature of specific transactions or categories of transactions are not relevant 

to the Commission's oversight of wholesale markets. Under the proposed de minimis

threshold, a non-public utility that makes 4 million MWh or less of annual wholesale 

sales would be exempt from filing EQRs unless the non-public utility is a Balancing 
Docket No. RM10-12-000 - 54 - 

Authority making 1 million MWh or more of annual wholesale sales. Because entities 

with a de minimis market presence are thereby exempted from the EQR filing 

requirement, the Commission does not believe it is necessary to establish a rebuttable 

presumption or waiver procedures. In addition, as explained above, we believe that it is 

necessary to capture a G&T cooperative’s sales to its members for transparency purposes, 

and therefore will not propose the rebuttable presumption approach as suggested by 

NRECA. 

76. Sam Rayburn Municipal believes that a threshold exemption should exist where 

there is no retail competition or the relative size or amount of power transactions is 

insignificant by size or substance under this effort. We agree with Sam Rayburn 

Municipal’s comments about a threshold exemption, but we disagree with its comment 

on an exemption where retail competition does not exist. In states where retail 

competition is not present there are still wholesale transactions that are of interest to the 

Commission and public. These transactions are part of wholesale electricity price 

formation even in regions where retail competition does not exist. Additionally, it is the 

Commission’s duty to ensure market transparency and obtain reporting from a sufficient 

number of market participants to accurately understand the physical electricity market as 

a whole. 
Docket No. RM10-12-000 - 55 - 

77. EMCOS believes that must-offer sales into a “Day-2” RTO/ISO market should be 

excluded because they involve output committed under contracts.94 In particular, 

EMCOS commented that must-offer sales into “Day-2” central security-constrained 

dispatch/central unit commitment markets should be excluded from the calculation of the 

de minimis threshold, because such sales reflect only the application of a tariff 

requirement for bidding both load and the output of resources already contractually 

committed to serving that load in order to facilitate bid-based pricing, and do not provide 

useful information about the exchange of commercial consideration leading to price 

formation. The Commission believes that resources committed under contract do impact 

price formation and should be included in the de minimis threshold calculation. Mustoffer provisions often do not dictate the price at which a unit may offer its supply into the 

market. Even if a must-offer unit is a price taker through self-scheduling, the unit is 

impacting price formation through its supply into RTO/ISO markets. 

B. Refinements to the Existing EQR Requirements

1. Background

78. In addition to seeking comments on whether the Commission should extend the 

EQR reporting requirements to non-public utilities, the Commission also sought 

comments regarding certain refinements to the EQR reporting requirements. 

Specifically, the Commission sought guidance on whether to: (1) require the reporting of 

 94 EMCOS at 12. 
Docket No. RM10-12-000 - 56 - 

the trade date, type of rate, and resales of financial transmission rights in secondary 

markets; (2) use a standard unit for reporting energy and capacity transactions; and 

(3) omit the time zone from the contract section. 

79. As discussed above, the Commission has determined that it should consider 

whether substantial reforms to the EQR reporting requirements are needed. After 

considering comments received in response to the Transparency NOI, the Commission is 

proposing in this NOPR to make the following refinements to the EQR: (1) reporting of 

the transaction date; (2) reporting of the type of rate by which the price was set (i.e., fixed 

price, formula, index, or RTO/ISO price); (3) standardizing the unit for reporting energy 

and capacity transactions (i.e., $/MWh, $/MW-month); and (4) omitting the time zone 

from the contract section. The Commission is also proposing not to require the reporting 

of resales of financial transmission rights in secondary markets. 

80. In addition, the Commission proposes other refinements that were not included in 

the Transparency NOI. In particular, the Commission proposes to require EQR filers to: 

(1) report the time that the transaction took place; (2) identify the broker or exchange 

used for a sales transaction, if applicable; (3) indicate whether the transaction was 

reported to an index publisher; and (4) report certain e-Tag data. The Commission also 

proposes to eliminate the DUNS number requirement. 

2. General Refinements

81. In combination with the broader effort to improve the Commission’s access to 

information about the availability and prices of wholesale sales of electricity, the 

Transparency NOI considered other refinements to the existing EQR filing requirements. 
Docket No. RM10-12-000 - 57 - 

As discussed above, these refinements included: (1) reporting the trade date (i.e., the date 

on which a transaction price is set) and the type of rate (i.e., fixed price, a formula, an 

index, or an RTO/ISO price); (2) reporting resales of financial transmission rights in 

secondary markets; (3) standardizing the unit for reporting energy and capacity 

transactions (i.e., $/MWh and $/MW-month); and (4) omitting the time zone from the 

contract section of the EQR. The proposals described above are detailed in Appendix B.

a. Trade Date & Time and Type of Rate

i. Comments

82. DC Energy agrees that the EQR reporting requirement should include the contract 

date, and states that master agreements or evergreen contracts do not preclude an entity 

from specifying when the agreement to transact was executed.95 California PUC also 

supports the addition of requirements to report the trading date information and to specify 

whether the reported rate is a fixed price, a formula, or an index. It states that prices 

without trading dates are less informative because prices change over time.96

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

and type of rate from all filers likely will require system changes and thus outweighs the 

value of such information.97 In addition, EPSA suggests that there are several problems 

 95 DC Energy at 10. 

96 California PUC at 3-4. 

97 EEI at 6-7; EPSA at 2-3; Duke Energy supports the comments filed by EEI at 2. 
Docket No. RM10-12-000 - 58 - 

with adding the trade date, such as it being subject to multiple interpretations and creating 

major software problems in the Commission's EQR program.98 

84. EPSA’s other major concern with this reporting requirement is timing. Any 

reporting requirement would have to be prospective only, as “trade date” is not currently 

a reporting requirement. Thus, there may be major software problems created with the 

Commission's EQR program. EPSA states that, if implemented by the Commission 

without grandfathering preexisting transactions, there would be no way for reporting 

entities to differentiate new deals from old, and the old deals will not have a reported 

trade date. Thus, any analysis done with this newly reported data would have a field 

precluded from historical data. Any adjustments made to prior quarters' data presumably 

would need to include this information, which may be impossible to gather for 

preexisting transactions. EPSA is concerned that the Commission’s EQR software would 

generate error messages for leaving the field blank. The Transparency NOI provides no 

discussion of these problems and EPSA states that the Commission should seriously 

consider these concerns before requiring that transaction dates be reported. 

85. In addition, EPSA states there is an overlap issue. If a deal is concluded in one 

quarter but goes to delivery in another quarter (or quarters), will it have to be reported in 

the quarter the transaction was concluded as well as the quarter(s) of delivery? What 

 98 EPSA at 4. 
Docket No. RM10-12-000 - 59 - 

about any intervening quarters – will the entity have to report deals in some form of 

abeyance between conclusion and delivery? 

86. Also, EPSA states that some of its member companies have reported that they do 

not track how the price was set and therefore could not currently comply with a 

requirement to report the type of rate. Thus, if this proposal is adopted, market 

participants would need to make major system changes to be able to capture and report 

this data. If the Commission proceeds down this route, EPSA contends that the 

Commission should allow a significant period of time for implementation before this 

aspect of a rule change became mandatory so that reporting parties could hire the 

necessary contractors, and have time to reconfigure data capture and reporting systems to 

collect this new data. 

87. However, if the Commission decides to require filers to include the trade date and 

type of rate, then EEI and EPSA propose several revisions. EEI suggests that the 

Commission clarify that “trade date” includes only the date and not the time of day when 

a transaction price was set and only include it in the transactions section, not the contract 

section.99 Also, EEI proposes that “the date the price was agreed to” should refer to the 

date the trade was finally executed.100 According to EPSA, its members have reported 

that through custom and usage in the trading industry, the term “Trade Date” has 

 99 EEI at 6-7. 

100 Id. at 6. 
Docket No. RM10-12-000 - 60 - 

developed the broadly understood meaning of “the date upon which the parties agree 

upon the terms of, and enter, a transaction.” EPSA argues that the Commission should 

give the term “Trade Date” the same meaning it generally has in the industry.101 In 

addition, EEI suggests that if the Commission decides to include the type of rate, then the 

options should be modified to “fixed,” “formula without index,” and “formula with 

index.” EEI also requests that the Commission clearly define these rate types and give 

examples to ensure that industry applies the terms consistently.102 

88. FirstEnergy asserts that the EQR Contract Data already captures the trade date via 

the Contract Execution Date in Field 21, which provides for the date the contract was 

signed. According to FirstEnergy, typically the rate for the transaction will be agreed 

upon on this date. FirstEnergy also states that the Commencement Date is reported in the 

Contract Terms in Field 22, which provides for the date that the terms in the contract are 

effective. Further, FirstEnergy explains that Fields 43 and 44 provide the first and last 

dates for the sale of the product at the specified rate. In addition, FirstEnergy states that 

the Commission’s proposed field to describe the type of rate for each transaction is 

already reported under field 37, Rate Description. According to FirstEnergy, this field 

currently requires that the filing company either cite the FERC accession number for the 

 101 EPSA at 4. 

102 EEI at 7. 
Docket No. RM10-12-000 - 61 - 

relevant FERC tariff or provide the entire rate algorithm.103 Similarly, EPSA argues that 

the “type of rate” information is already captured in the "contract" field and that creating 

a new field would be a significant burden.104

ii. Discussion

89. The current Commission EQR reporting requirements include, among other 

things, the Contract Execution Date (Field Number 21), the Contract Commencement 

Date (Field Number 22), Rate Description (Field Number 37), Begin Date (Field Number 

43), and End Date (Field Number 44).105 These contract fields were not intended to 

capture trade-specific details related to each specific transaction, but rather to capture 

contractual terms and conditions under which two entities transact for all jurisdictional 

services. 

90. We agree with the points made by DC Energy and the California PUC. Master 

agreements and evergreen contracts do not preclude an entity from specifying when an 

agreement to transact was executed. Prices without trading dates are less informative 

because prices change over time. 

 103 FirstEnergy at 2-3. 

104 EPSA at 5. 

105 These fields are outlined in more detail in the Electronic Quarterly Report Data 

Dictionary, Version 1.1, available at http://www.ferc.gov/docs-filing/eqr/softtools/eqrdatadictionary.pdf. 
Docket No. RM10-12-000 - 62 - 

91. Presently, the trade date and type of rate by which the price was set are not 

provided or collected publicly. The trade date is essential to assessing the significance of 

prices in relation to market conditions in effect at that time.106 Many of the prices 

reported in the EQR are the result of confirmation made under master agreements. 

Because the prices are not set in the contracts themselves, the Commission is unable to 

determine from EQR data when the price was set. Additionally, the Commission is 

unable to conclude whether the price was based on a fixed price, a formula, an index, or 

an RTO/ISO price. 

92. Therefore, to improve market transparency, the Commission proposes to require 

market participants to report the date on which parties to a reported transaction agreed 

upon a price (trade date) and, additionally, require the type of rate by which the price was 

set (i.e., fixed price, formula, index, or RTO/ISO price) in its respective EQR filings. 

The date and type of rate are to accompany each specific sales transaction and be 

reported in the EQR transaction section only in the quarter the sale occurs. 

93. We propose to clarify the term “trade date” as “the date upon which the parties 

agree upon the price of a transaction.” As discussed below, we also propose tracking the 

time of the transaction. Further, EEI suggests that the Commission clarify how to specify 

the type of rate and provide examples to ensure that industry applies the terms 

 106 Currently, the EQR collects only the start and end date of physical transactions. 

Trades entered into months before the transaction dates are reported in the same manner 

as trades entered into minutes before the transaction occurs, making it difficult to 

differentiate between trades made under different circumstances. 
Docket No. RM10-12-000 - 63 - 

consistently. As a result, the options for the type of rate that the Commission is 

proposing will be “fixed,” “formula,” “index,” and “RTO/ISO price.” A “fixed” rate will 

be defined as a fixed charge per unit of consumption. An example is an agreement for 

the sale of 30 MWh during every on-peak hour during 2012 for an agreed upon rate in 

advance of delivery. A “formula” rate will be defined as a calculation of a rate based 

upon a formula that does not contain an index component. An example is a cost-ofservice rate. An “index” rate will be defined as a calculation of a rate based upon an 

index or a formula that contains an index component. An example is an options 

agreement where power is sold at a published index price (or at a percentage of that 

published index price). An “RTO/ISO price” will be defined as a rate that is based on an 

RTO/ISO published price or a formula that contains an RTO/ISO price component. An 

example is a generator’s sale to into a RTO/ISO day-ahead market.

94. This proposal would impose additional reporting requirements on any market 

participant that is required to file an EQR with the Commission. The Commission will 

ensure its EQR software can accommodate such requirements before the first EQR filings 

containing the trade date and type of rate must be submitted. Reporting of the trade date 

and type of rate would occur prospectively from the time the requirements are 

implemented. Accordingly, market participants would not have to re-file prior EQR 

filings with the proposed time and date information and would not have to adjust a prior 

quarter’s information on already executed transactions. However, if the Final Rule 

requires EQR filers to report the trade date and type of rate of their transactions, we 

would expect market participants to include the trade date and type of rate for 
Docket No. RM10-12-000 - 64 - 

transactions taking place from the date of the Final Rule’s implementation. Any refilings and adjustments to EQR filings made prior to the date of effectiveness of such a 

rule would follow the EQR filing requirements imposed at the time of the original filing. 

95. Although not raised in the Transparency NOI, the Commission now proposes to 

require market participants to also report the time of trade. We propose to clarify the 

term “time of trade” as “the time upon which the parties agree upon the price of a 

transaction.” The Commission recognizes that not only the date, but also the time of 

trade, is essential in identifying some forms of market manipulation that may be designed 

to target daily index price creation for the purpose of benefiting financial swap 

settlements. Without knowing what time a trade occurred, customers and the 

Commission would have difficulty identifying these out-of-market, or anti-competitive, 

transactions from those that followed the ebbs and flows of the daily market. This is due 

to the fact that competitive market pricing is often fluid to reflect changes in supply and 

demand fundamentals. For example, market pricing for next-day power on the morning 

before delivery may be entirely different than pricing that afternoon as outage, forecast 

and other information continually changes. It is possible for market participants to 

attempt to “direct” physical market pricing throughout the day in an effort to impact 

settlement pricing for other positions. This behavior may involve trading large volumes 

at the beginning of the trading day in order to “direct” pricing in subsequent hours or 

other strategies that concentrate trading in a narrow time window. 
Docket No. RM10-12-000 - 65 - 

b. Resales of Financial Transmission Rights in Secondary Markets

96. In the Transparency NOI, staff sought comments as to whether the Commission 

should collect information about the resale of financial transmission rights in secondary 

markets through reporting to the EQR. Specifically, the Transparency NOI asked 

whether market participants perceive that collecting this information would enhance 

market transparency and, if so, to designate what current EQR filing requirements should 

be imposed on resales of financial transmission rights in secondary markets. In addition, 

comments were sought to identify other filing requirements that may be applicable to the 

resale of financial transmission rights in secondary markets that are not current EQR 

filing requirements and explain whether and, if so, how collection of the information 

would improve market transparency. 

i. Comments

97. California PUC and SDG&E support reporting sales of financial transmission 

rights to increase transparency of financial transmission right trading by both 

transmission and non-transmission owners and to reveal whether sales in the secondary 

market result in market concentration or increased liquidity. SDG&E also supports 

requiring transaction-specific information for financial transmission right secondary 

transactions as is required for all other transactions. APPA, Duke Energy, EEI and 

Morgan Stanley question the need for information concerning resale of financial 

transmission rights and assert that the burden of collecting financial transmission right 

resale information may outweigh the minimal value of such information. EPSA believes 

that the Commission should not collect financial transmission right data as part of this 
Docket No. RM10-12-000 - 66 - 

transparency effort because it would be unnecessary, duplicative and not provide any 

useful information.107 APPA and EPSA state that secondary financial transmission right 

markets are relatively illiquid and Morgan Stanley states that the Commission has 

recognized that financial transmission right markets are thinly traded at this time.108 

FirstEnergy argues that this filing requirement would be duplicative because RTO market 

monitors may have the responsibility for reviewing the secondary bilateral financial 

transmission right markets.109 DC Energy also believes that reporting requirements for 

secondary market financial transmission right sales should be the province of the 

ISOs/RTOs.110 APPA also sees the task of assuring transparency of financial 

transmission right transactions as a responsibility of the RTOs.111 Morgan Stanley 

similarly recommends that the Commission monitor secondary market financial 

transmission right transactions by requesting each RTO to provide quarterly or annual 

data on such transactions arising in their markets.112 In addition, PJM observes that, as a 

threshold question, the Commission should first determine whether it has any jurisdiction 

 107 EPSA at 5-6. 

108 Morgan Stanley at 2. 

109 FirstEnergy at 3-4. 

110 DC Energy at 10-11. 

111 APPA at 13. 

112 Morgan Stanley at 2-3. 
Docket No. RM10-12-000 - 67 - 

over this type of transaction before deciding whether to compel participant reporting.113 

PJM also states that its bulletin board on the PJM eFTR system may provide a means to 

access secondary market financial transmission right transaction information, making 

increased participant reporting unnecessary.114

ii. Discussion

98. We agree with certain commenters that RTOs/ISOs collect and publish some 

financial transmission right data and that RTOs/ISOs are the proper entities for reporting 

information about financial transmission rights. We believe that requiring financial 

transmission right data to be reported by market participants in the EQR, in addition to 

the information already provided by RTOs/ISOs, would not significantly improve price 

transparency in these markets. Therefore, we do not propose to require entities to report 

information about financial transmission rights in the EQR at this time. 

c. Standardizing the Unit for Reporting Energy and Capacity 

Transactions

i. Comments

99. California PUC, DC Energy, and PG&E support standardizing EQR data on 

capacity and energy across all filers to help the Commission and other market 

participants compare prices.115 PG&E further states that $/MWh is an appropriate unit 

 113 PJM at 4-5. 

114 Id. at 2-4. 

115 California PUC at 4; DC Energy at 11; and PG&E at 3. 
Docket No. RM10-12-000 - 68 - 

for energy transactions and $/MW is an appropriate unit for capacity transactions because 

these units are commonly used in organized electricity markets, including the markets 

operated by CAISO.116

100. EEI states that having common units for reporting energy and capacity 

transactions (i.e., $/MWh and $ per MW-month) would simplify interpretation of the 

data, but that the Commission should clarify that this change requires the conversion only 

of KWh to MWh and KW to MW (i.e., utilities can still report transactions in 

MW/Month, MW/Day, KVA, MVAR, etc.). In addition, EEI notes that if the 

Commission makes this change, then it will likely have to increase the number of digits 

allowed in the Rate field – particularly if the units being reported are MWhs.117

101. EPSA does not advocate standardizing units for reporting transactions. EPSA 

states that capacity may be sold on a $/MW-Day, $/MW-Week, $/KW-Day, $/KWWeek, $/KW-Month, or $/KW-Year basis, and argues that the parties should report those 

trades in accordance with the way the products were measured, priced and sold under 

each transaction. According to EPSA, this will reduce the possibility of errors in 

translating one unit to another.118

 116 PG&E at 3. 

117 EEI at 8. 

118 EPSA at 6. 
Docket No. RM10-12-000 - 69 - 

ii. Discussion

102. We propose to insert an additional field to the EQR transaction section to 

standardize the units for reporting energy and capacity within the EQR. We agree with 

several commenters that the usefulness of the additional field will simplify interpretation 

of the data and aid the Commission and other market participants in comparing prices. 

The additional field will provide a consistent rate for comparison purposes and allow the 

Commission to develop internal checks in the EQR software on the accuracy of a filing. 

103. Today, the EQR filing requirements include, among other things, the Transaction 

Rate Units (Field Number 65). This field requires a market participant to report the 

measure for the appropriate price of the product sold.119 To avoid possible confusion, we 

clarify that the additional field we are proposing to add would not remove or replace any 

current EQR filing requirement. It would simply add a new field to capture a common 

unit for reporting energy and capacity transactions. 

104. To ensure that similar sales can be easily compared, the Commission is proposing 

to standardize the units in which energy and capacity sales may be filed in the EQR. 

Therefore, energy transactions will be required to be reported as $/MWh and capacity 

transactions will be required to be reported as $/MW-month. Each filing entity will be 

required to make the conversion for any measurement that is not in this denomination. 

 119 Valid values include: $/KVA, $/KW, $/KW-DAY, $/KW-MO, $/KW-WK, 

$/KW-YR, $/KWH, $/MVAR-YR, $/MW, $/MW-DAY, $/MW-MO, $/MW-WK, 

$/MW-YR, $/MWH, $/RKVA, CENTS, CENTS/KVR, CENTS/KWH, and FLAT 

RATE. Rate units should match product names. 
Docket No. RM10-12-000 - 70 - 

Several commenters suggested that requiring transactions to be reported using a 

standardized unit would introduce conversion errors into EQR. Converting the quantity 

and price for energy and capacity sales to $/MWh and $/MW-month generally requires 

routine, commonly-used calculations. Commission staff is available to assist filers with 

any filing-related questions, including conversion questions. Additionally, the 

Commission will ensure the appropriate number of digits in the EQR software to 

accommodate the conversion. 

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

i. Comments

105. DC Energy and EPSA support eliminating from the contract section of the EQR 

the requirement to report the time zone, so long as the Commission maintains the 

requirement to report the time zone in the transaction report.120 EEI states that the time 

zone information in the contract section of the EQR is simply unnecessary and that 

deleting this requirement would help to reduce burden.121

ii. Discussion

106. We propose eliminating the Contract Time Zone (Field Number 45) as currently 

required in EQR filings. We agree with EEI that time zone information in the contract 

section of the EQR is unnecessary and that eliminating it would reduce the burden of 

 120 DC Energy at 11; EPSA at 6-7. 

121 EEI at 8. 
Docket No. RM10-12-000 - 71 - 

filing the EQR. However, we clarify that, although we propose to eliminate time zone 

information from the contract section, we will continue to require EQR filers to report the 

time zone where the transaction took place in the transaction section (Field Number 55). 

3. Additional EQR Enhancements

107. In the almost nine years since the Commission established EQRs under Order 

No. 2001, large financial markets have emerged and become increasingly intertwined 

with physical wholesale power markets. Further, the diversity and complexity of 

derivatives instruments that are linked to physical power prices have grown 

exponentially. EQR reporting requirements have not kept pace with these market 

evolutions. The refinements proposed in this NOPR are intended to allow the 

Commission and market participants to use the EQR to identify behavior in physical 

power markets that may be designed to influence a market participant’s financial 

positions linked to physical market pricing fundamentals. 

108. The Commission recognizes that there is an incentive to manipulate bilateral 

wholesale spot markets for the purpose of influencing financial swap settlements. 

Although leveraged financial positions can provide legitimate hedging capabilities, they 

can also create incentives for companies to alter physical market prices. Incentives to 

manipulate can be especially strong outside of RTO/ISO markets, where bilateral 

transactions are used to determine swap settlement values. 

109. For these reasons, the Commission proposes to require several new data fields in 

the EQR that will enable market participants and the Commission to identify physical 

wholesale transactions that could contribute to pricing designed to influence financial 
Docket No. RM10-12-000 - 72 - 

swap settlements. These additional enhancements were not raised for comment in the 

Transparency NOI, but rather are being proposed in this NOPR as the Commission 

continues to weigh appropriate measures to help facilitate greater price transparency and 

help ensure that a market participant does not manipulate wholesale electricity markets 

for the purpose of benefiting its financial positions. Thus, the Commission proposes to 

require EQR filers to report in the transaction section of the EQR the following 

information: (1) the index publisher(s) to which the transaction was reported; (2) the 

exchange on which the transaction was consummated or the brokerage firm that arranged 

the transaction; and (3) the time the transaction occurred. 

a. Identify Transactions Reported to Index Publishers

110. The Commission proposes to require all market participants to report in the 

transaction section of EQR the index price publisher to which they have reported their 

sales transactions. The Commission has recognized the importance of price indices in 

energy markets, noting in its Policy Statement on Natural Gas and Electric Price Indices: 

Price indices are widely used in bilateral natural gas and electric 

commodity markets to track spot and forward prices. They are often 

referenced in contracts as a price term; they are related to futures markets 

and used when futures contracts go to delivery; . . . and state commissions 

use indices as benchmarks in reviewing the prudence of gas or electricity 

purchases. Since index dependencies permeate the energy industry, the 

indices must be robust and accurate and have the confidence of market 

participants for such markets to function property and efficiently. 122 

 122 See Price Discovery in Natural Gas and Electric Markets, Policy Statement on 

Natural Gas and Electric Price Indices, 104 FERC ¶ 61,121, at P 6, clarified, 105 FERC 

¶ 61,282 (2003). 
Docket No. RM10-12-000 - 73 - 

111. The Commission believes that requiring in the EQR the names of index price 

publishers to which wholesale power sale transactions are reported would allow the 

Commission, market participants and other interested parties greater transparency to see 

how market forces are affecting those index prices and the market concentration of the 

companies’ sales used to calculate the index prices. 

112. In addition to market participants’ significant use of index prices with respect to 

tracking electric spot and forward prices, the use of index prices has expanded to form 

settlement prices for financial products. Because bilateral physical spot markets are used 

to settle financial swaps, there is an incentive to manipulate the physical markets to 

benefit larger financial positions. For example, linked financial-swap contracts at several 

hubs traded at volumes many times larger than bilateral spot trading at that particular 

hub. The multiple of financial-swaps at such hubs in relation to physical transactions 

indicates that opportunities to profit from physical market manipulation strategies 

involving financial positions already exist. For instance, a market participant with fixed 

price financial-swap contracts could manipulate the physical index price by transacting 

power at a loss for transactions that contribute to the index price. However, the market 

participant could still profit from such activity because any loss from selling power that 

contributes to the index price could be more than offset by financial-swap gains resulting 

from moving the index price. Thus, greater transparency could further our understanding 

of how index prices are formed. This, in turn, could lead to more robust indices, enhance 
Docket No. RM10-12-000 - 74 - 

public confidence in their accuracy and reliability, and improve the Commission’s ability 

to monitor prices for exercises of market power and manipulation. 

113. Section 35.41(c) of the Commission’s regulations123 requires market-based rate 

power sellers to submit a notification to the Commission if they report transactions to 

electric or natural gas price index publishers. However, this regulation does not require 

market-based rate sellers to specify the price index publishers to which they report their 

transactions and it applies only to one subset of market participants whose transactions 

are used to form index prices, i.e., jurisdictional power sellers with market-based rate 

authorization from the Commission. Obtaining information from all market participants 

about which transactions are reported to which index publishers will strengthen the 

Commission’s and interested observers’ ability to determine whether these index prices 

reflect market forces and provide market participants with greater confidence in the 

accuracy of index prices. Therefore, we propose to require each EQR filer to report in 

the transactions section the particular electric or natural gas index publisher to which they 

report transactions, if applicable. To eliminate redundancy between the EQR filings and 

the notification required under 18 CFR 35.41(c) from market-based rate sellers, we 

propose to amend that provision to no longer require notifications from these sellers to 

 123 18 CFR 35.41(c). Investigation of Terms and Conditions of Public Utility 

Market-Based Rate Authorizations, see Order Amending Market-Based Rate Tariffs and 

Authorizations, 105 FERC ¶ 61,218, at P 116-119 (2003). 
Docket No. RM10-12-000 - 75 - 

the Commission stating whether they are reporting transactions to electricity or natural 

gas index publishers, or updates of such notifications. 

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

114. Exchanges and brokers routinely publish index prices composed of wholesale 

transactions that were consummated on their exchange or through their brokerage 

services. Such index prices are used to track electric spot and forward prices and, 

increasingly, to form settlement prices for financial products. We believe that requiring 

information regarding whether exchanges or brokers were used to consummate a 

transaction will promote visibility into index prices and bolster the Commission’s market 

monitoring efforts. 

c. Collection of e-Tag ID Data 

115. To schedule physical interchange transactions,124 market participants submit eTags to transmission system operators. Generally, e-Tags track energy transfers, 

including where the power is sourced and delivered; the responsible parties in the receipt, 

delivery and movement of the power; the timing; and the volumes and specific details 

regarding which transmission paths are used. An e-Tag is reported to NERC or WECC, 

but is not presently reported to the Commission. 

116. The Commission proposes to require EQR filers to submit e-Tag IDs for each 

transaction reported in the EQR in the event an e-Tag is used to schedule the transaction. 

 124 An interchange transaction involves a transfer of energy from a seller to a 

buyer that crosses one or more balancing authority area boundaries. 
Docket No. RM10-12-000 - 76 - 

The e-Tag ID is a subset of information associated with a full e-Tag and consists of four 

components: (1) Source Balancing Authority Entity Code;125 (2) Purchasing-Selling 

Entity Code;126 (3) e-Tag Code or Unique Transaction Identifier;127 and (4) Sink 

Balancing Authority Entity Code.128 Requiring e-Tag IDs as part of EQR filings would 

address a major gap in EQR information as it is currently reported: the source location of 

wholesale sales transactions. E-Tag IDs would assist market participants and the 

Commission in identifying chains of transactions and transaction paths. Using the 

information currently reported in the EQR, it is difficult to identify linked re-sales or 

chains of transactions between filers. EQRs currently require reporting of the Point of 

Receipt Balancing Authority (Field Number 39) for power sales contracts if that 

information is specified in the contract. In practice, however, many EQRs do not contain 

 125 The Source Balancing Authority is defined as the host Balancing Authority in 

which the generation is located. 

126 The Purchasing-Selling Entity is the entity creating and submitting the e-Tag 

request to the authority service, which authorizes implementation of interchange 

schedules between balancing authority areas. The Purchasing-Selling Entity also is the 

entity that purchases or sells, and takes title to, energy, capacity and interconnected 

operations services. 

127 The e-Tag Code is a unique seven-character transaction identifier for each 

bilateral energy transaction scheduled on the transmission network. It is assigned by the 

e-Tag system when transmission service to accommodate the transaction is reserved. 

128 The Sink Balancing Authority is defined as the host Balancing Authority in 

which load is located. 
Docket No. RM10-12-000 - 77 - 

information related to the Point of Receipt Balancing Authority because many contracts 

do not specify source information. 

117. Accessing e-Tag IDs through the EQR would facilitate price transparency by 

enabling all market participants to “follow” transactions across markets. In other words, 

market participants would be able to identify that an energy trade from Company A to 

Company B and an energy trade reported by Company B to Company C are, in fact, a resale of power from Company A to Company C because both sales would reflect the same 

e-Tag ID. Also, the markups observed for these “arbitrage” transactions are a valuable 

indicator of competitiveness in the wholesale market. Specifically, one would expect the 

arbitrage value between differently-priced markets to be closely associated with the cost 

to secure transmission between those markets. Persistent price differences between 

markets that are not consistent with transmission costs could indicate that the ability to 

arbitrage market price differences is not fully competitive. 

118. In addition, the Source Balancing Authority information contained in the e-Tag ID 

would provide additional detail on the contract path used to schedule a transaction. In 

analyzing EQR filings, the Commission has found that source information related to a 

power sale is a vital component in analyzing transactions for anti-competitive behavior. 

Specifically, without some general knowledge of where power is being generated, it 

would be difficult to determine whether an interchange transaction is competitively 

arbitraging price separations between markets or behaving anti-competitively. 

Furthermore, the e-Tag IDs will allow the Commission and market participants to better 

monitor interchange transactions and detect potential abuses. 
Docket No. RM10-12-000 - 78 - 

119. In a NOPR in Docket No. RM11-12-000 (e-Tag NOPR), to be issued concurrently 

with this NOPR, the Commission proposes to require the Commission-certified Electric 

Reliability Organization, i.e., NERC, to provide Commission staff with non-public access 

to complete e-Tag data. This data will, among other things, help the Commission to 

monitor wholesale markets and prevent market manipulation. In the e-Tag NOPR, the 

Commission explains that accessing e-Tag data through NERC, rather than requiring 

individual market participants to provide such data to the Commission, would avoid 

burdening market participants with submitting the complete e-Tags with both NERC and 

the Commission. In addition, it would avoid burdening the Commission with developing 

and maintaining a new system to capture such data from market participants. In this 

NOPR, the Commission is proposing to require individual market participants to file, if 

applicable, a sub-set of e-Tag information, specifically e-Tag IDs, as part of the EQR 

because market participants are able to match their e-Tag IDs with the transactions they 

are required to report in the EQR. As explained above, access to this information in the 

EQR will allow the public and the Commission to “follow” transactions across markets. 

d. Eliminating the DUNS Number Requirement 

i. Comments

120. Under existing requirements, filers must identify all customers and sellers reported 

in the EQRs using DUNS numbers, a numeric identifier assigned by Dun & Bradstreet, 

Inc. The Commission required DUNS numbers in order to distinguish among similarly 
Docket No. RM10-12-000 - 79 - 

named, but different, service providers.129 Although the Transparency NOI did not seek 

comment on whether to continue requiring DUNS numbers in EQRs, several commenters 

urged the Commission to eliminate this requirement. EEI argues that DUNS numbers 

have proven not to be a unique way to identify entities and have become a waste of time, 

resources, and money. In addition, EEI and Wisconsin Electric state that some market 

participants have multiple DUNS numbers, while others have only one or none at all.130 

Wisconsin Electric notes that DUNS numbers listed in the EQR are often incorrect, and 

that not all market participants subscribe to the proprietary cross-referencing service.131 

EPSA asserts that its members view DUNS numbers as more of an administrative burden 

than a help and that an error message occurs even though the Commission has instructed 

a party to input zero when a counterparty does not have a DUNS number. As an 

alternative to DUNS numbers, Wisconsin Electric proposes that the Commission adopt a 

more widely used identification system, such as federal tax IDs. EEI proposes using a 

company’s legal name or a new ID developed through the FERC eTariff program. EPSA 

does not advocate a specific identification method but did recognize that a uniform 

nomenclature should be adopted. 

 129 See Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 90. 

130 Wisconsin Electric at 2. 

131Id. 
Docket No. RM10-12-000 - 80 - 

ii. Proposal

121. The Commission proposes to eliminate the DUNS number requirement from EQR 

filings. Customer/counterparty identification through unique identifier numbers is a 

significant component of EQRs, particularly when identifying sales to individual 

companies. In the EQR, the customer company names are reflected in Field Numbers 16 

and 48 as unrestricted, or free-form, text fields. As a result, the customer company 

names inserted in Field Numbers 16 and 48 are not always uniformly reported by 

different sellers. To help ensure more precise identification of counterparties, however, 

EQRs use DUNS numbers in Field Numbers 17 and 49. However, DUNS numbers have 

proven to be an imprecise identification system. As noted by commenters, EQR filers 

can have multiple DUNS numbers, only one DUNS number, or no DUNS number at all. 

122. In considering alternatives to the use of DUNS numbers, the Commission finds 

that none of the suggested approaches would provide a viable replacement to the current 

approach and requiring a different numbering system would create legacy issues. 

Therefore, the Commission will not replace the DUNS number requirement with another 

approach at this time, but rather will continue to rely on the insertion of customer 

company names in the free-form fields, Field Numbers 16 and 48. 
Docket No. RM10-12-000 - 81 - 

III. Information Collection Statement

123. The Office of Management and Budget (OMB) regulations require approval of 

certain information collection requirements imposed by agency rules.132 Upon approval 

of a collection(s) of information, OMB will assign an OMB control number and an 

expiration date. Respondents subject to the filing requirements of an agency rule will not 

be penalized for failing to respond to these collections of information unless the 

collections of information display a valid OMB control number. The Paperwork 

Reduction Act (PRA)133 requires each federal agency to seek and obtain OMB approval 

before undertaking a collection of information directed to ten or more persons or 

contained in a rule of general applicability.134 

124. The Commission is submitting these reporting and recordkeeping requirements to 

OMB for its review and approval under section 3507(d) of the PRA. Comments are 

solicited on the Commission’s need for this information, whether the information will 

have practical utility, the accuracy of provided burden estimates, ways to enhance the 

quality, utility, and clarity of the information to be collected, and any suggested methods 

 132 5 CFR 1320.8. 

133 44 U.S.C. 3501-3520. 

134 OMB’s regulations at 5 CFR 1320.3(c)(4)(i) require that “Any recordkeeping, 

reporting, or disclosure requirement contained in a rule of general applicability is deemed 

to involve ten or more persons.” 
Docket No. RM10-12-000 - 82 - 

for minimizing the respondent’s burden, including the use of automated information 

techniques.

125. The Commission’s estimate of the additional average annual Public Reporting 

Burden and cost135 related to the proposed rule in Docket RM10-12-000 follow.

Average Annual Burden 

Recurring Operating (implementation cost 

Burden averaged over the 3 yrs.) No. of

No. of responses per Burden hrs. Burden 

respondents per Cost per hrs. per Cost per Burden 

per year respondent respondent response response Hours Cost 

126. In calculating the number of current respondents filing EQRs, the Commission 

looked at the number of agents responsible for submitting the filings of the EQR, which 

came to 1,291 filers. Out of those 1,291 filers, only 831 reported transactions during 

2009. Therefore, the Commission proposes to use 831 as the number of respondents.136 

 

(continued...) 

135 For purposes of calculating the annual averages, the implementation burden 

and cost have been averaged, spread over the 3-year period, and added to the recurring 

burden and cost. 

136 There were 1,435 unique respondents to the EQR reporting for 1,638 unique 

sellers during the third quarter of 2010. Neither the number of respondents nor the 

number of unique sellers accurately reflects the number of entities and affiliated entities 

Current filers 831 4 160 $15,659

Public Utility Filers

 8 $783 70,912 $6,940,157

Non-Public Utilities 

Non-BA, with >4 mill. 

MWH w lesale ho

sales/yr. 53 4 400 $39,148 24 $2,349 12,155 $1,189,577

BA, with >4 mill. MWH 

wholesale and retail 

sales/yr. 3 4 400 $39,148 24 $2,349 688 $67,335

BA, small with >=1mill. 

MWH wholesale and 

retail sales/y . & <=4 r

million MWh 5 4 400 $39,148 24 $2,349 1,147 $112,224

Sub-Total for NonPublic Utilities 61 13,989 $1,369,136

GRAND TOTAL, 

AVERAGE ANNUAL 

ESTIMATES 892 4 84,901 $8,309,293 

respondent 

per year

Implementing Burden
Docket No. RM10-12-000 - 83 - 

Although the Commission estimates the total number of current respondents to be 831, 

this figure overstates the number of corporate families filing the EQR because some of 

the filings were made separately by affiliates from the same company. For instance, of 

the 831 filer names, 28 began with FPL, 24 began with NRG, 12 began with 

Wheelabrator, and 11 began with Dynegy. This trend was common among other filers. 

127. For non-public utility filers, the Commission separately estimated the burden for 

non-balancing authorities with more than 4 million MWh of annual wholesale sales; 

balancing authorities with more than 4 million MWh of annual wholesale and retail sales; 

and balancing authorities with 1 million MWh or more of annual wholesale and retail 

sales. In the RFA Certification section below, the Commission uses the SBA definition 

of a small utility to determine how many small entities will be impacted by the proposed 

rule. The SBA defines a utility as small if, including its affiliates, it is primarily engaged 

in the transmission, generation and/or distribution of electric energy for sale and its total 

electric output for the preceding twelve months did not exceed four million MWh.137 We 

also used the SBA definition to determine the burden on respondents in the table above. 

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

initial implementation associated with filing EQRs. This burden includes the set-up 

 

that respond to the EQR. For instance, respondents will often report sales for unique 

sellers, either individual generation units or affiliated entities, separately in the EQR. 

Similarly, affiliate relationships exist for unique respondents. These respondents may 

share EQR filing software and techniques or may even be filed by the same staff. 

137 13 CFR 121.101. 
Docket No. RM10-12-000 - 84 - 

software on a utility’s computers, the initial entry of the contract data, and the mapping of 

the transaction data from the utility’s internal computer systems into the format required 

by the Commission. For non-public utility filers, we estimate a burden of 400 hours per 

year for the initial implementation phase. For current EQR filers, we estimate that the 

additional data requirements will involve a burden of 160 hours. This burden is lower 

than that for non-public utility filers because of current filers’ familiarity with EQR 

reporting. 

129. For the recurring effort involved in filing the EQR each subsequent quarter, we 

anticipate that the burden will be minimal, particularly as filing transaction data will be 

automated for companies that have mapped their systems to the required format. Thus, 

we estimate a recurring burden of 24 hours per response (rather than per year) for all nonpublic filers if the requirements of this rulemaking are to be implemented. We have 

estimated that current filers spend about 16 hours to meet the existing recurring 

requirements of filing EQRs. With the additional data proposed to be required, we 

estimate that current filers’ recurring burden will increase by 8 hours. 

Information Collection Costs: The Commission seeks comments on the costs and burden 

to comply with these requirements. 

Total average annual costs = $8,309,293 ($6,940,157 for public utilities plus $1,369,136 

for non-public utilities). The Commission estimates that the hours to complete the EQR 

reporting requirements will be divided among an entity’s accounting, legal and support 

staff. We estimate an average hourly cost of $97.87 (including a senior accountant at 
Docket No. RM10-12-000 - 85 - 

$50.22/hr., a financial analyst at $67.00/hr., legal services at $250/hr., and support staff at 

$24.25/hr.).138

Title: FERC-516, Electric Rate Schedules and Tariff Filings (which includes the Electric 

Quarterly Report [EQR])139

Action: Proposed Revisions to the EQR 

OMB Control No: 1902-0096 

Respondents: Public and non-public utilities 

Frequency of Responses: Initial implementation and quarterly filings 

Necessity of the Information: The Commission is proposing to enact requirements that 

would facilitate price transparency in wholesale markets for the sale and transmission of 

electric energy in interstate commerce by requiring certain non-public utilities to file the 

EQR. This proposal would allow the Commission and the public to gain a more 

complete picture of wholesale power and transmission markets in interstate commerce by 

providing additional information concerning price formation and market concentration in 

these markets. Public access to additional sales and transmission-related information in 

the EQR would improve market participants’ ability to assess supply and demand 

 138 Hourly average wage is an average and was calculated using Bureau of Labor 

Statistics (BLS), Occupational Employment Statistics data for May, 2009 (at 

http://www.bls.gov/oes/) for the accounting, financial, and support staffs. The average 

hourly figure for legal support is a composite from BLS and other resources, taking into 

account the hourly cost for both in-house and contractor organizations. 

139 For administrative purposes, the Commission will consider whether to separate 

the EQR requirements from the remaining reporting requirements under FERC-516. If 

that is done, FERC would then request a separate OMB Control No. for EQR. 
Docket No. RM10-12-000 - 86 - 

fundamentals and to price interstate wholesale market transactions. It also would 

strengthen the Commission’s ability to identify potential exercises of market power or 

manipulation and to better evaluate the competitiveness of the interstate wholesale 

markets. In addition, the Commission proposes to make certain revisions to the existing 

EQR filing requirements and apply those revisions to all market participants filing EQRs. 

These refinements to the existing EQR filing requirements reflect the evolving nature of 

electricity markets, would increase market transparency for the Commission and the 

public, and would allow market participants to file the information in the most efficient 

manner possible. 

Internal review: The Commission has reviewed the proposed changes and has 

determined that the changes are necessary. These requirements conform to the 

Commission’s need for efficient information collection, communication, and 

management within the energy industry. The Commission has assured itself, by means of 

internal review, that there is specific, objective support for the burden estimates 

associated with the information collection requirements. 

130. Interested persons may obtain information on the reporting requirements by 

contacting: Federal Energy Regulatory Commission, 888 First Street, NE, Washington, 

DC 20426 [Attention: Ellen Brown, Office of the Executive Director, e-mail: 

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

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

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

Officer for the Federal Energy Regulatory Commission]. For security reasons, comments 
Docket No. RM10-12-000 - 87 - 

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

OMB Control No. 1902-0096, FERC-516 and the docket number of this proposed 

rulemaking in your submission. 

IV. Environmental Analysis

131. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.140 The actions taken here fall within categorical exclusions 

in the Commission’s regulations for information gathering, analysis, and 

dissemination.141 Therefore, an environmental assessment is unnecessary and has not 

been prepared in this rulemaking. 

V. Regulatory Flexibility Act Certification

132. The RFA142 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 

 140 Regulations Implementing the National Environmental Policy Act, Order 

No. 486, 486 FR 1750 (Jan. 22, 1988), FERC Stats. & Regs. ¶ 30,783 (1987). 

141 18 CFR 380.4(a)(5). 

142 5 U.S.C. 601-612. 
Docket No. RM10-12-000 - 88 - 

definition of a small business.143 The SBA has established a size standard for electric 

utilities, stating that a firm is small if, including its affiliates, it is primarily engaged in 

the transmission, generation and/or distribution of electric energy for sale and its total 

electric output for the preceding twelve months did not exceed four million MWh.144

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

is required to examine only the direct compliance costs that a rulemaking imposes upon 

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

required to consider costs that an entity incurs voluntarily. 

134. Based on EIA Form 861, there are 372 non-public utilities that made wholesale 

sales in 2009.146 As discussed above, the Commission is proposing to exempt from the 

EQR filing requirements non-public utilities with a de minimis market presence. The 

Commission estimates that 311 of the 372 non-public utilities will be exempt from this 

rulemaking because they make four million MWh or less of annual wholesale sales and 

 143 13 CFR 121.101. 

144 13 CFR 121.201, Sector 22, Utilities & n.1. 

145 See Regional Transmission Organizations, Order No. 2000, 65 FR 809 

(January 6, 2000), FERC Stats. & Regs. ¶ 31,089, at 31,237 & n.754 (1999), order on 

reh’g, Order No. 2000-A, 65 FR 12,088 (Mar. 8, 2000), FERC Stats. & Regs. ¶ 31,092 

(2000), aff'd sub nom. Pub. Util. Dist. No. 1 of Snohomish, County Washington v. FERC,

272 F.3d 607, 348 U.S. App. D.C. 205 (D.C. Cir. 2001) (citing Mid-Tex Elec. Coop. v. 

FERC, 773 F.2d 327 (D.C. Cir. 1985) (Commission need only consider small entities 

“that would be directly regulated”); Colorado State Banking Bd. v. RTC, 926 F.2d 931 

(10th Cir. 1991) (Regulatory Flexibility Act not implicated where regulation simply 

added an option for affected entities and did not impose any costs)). 

146 We excluded non-public utilities that are located in Alaska, Hawaii, and Texas. 
Docket No. RM10-12-000 - 89 - 

are not Balancing Authorities. Of the 372, 309 are considered small entities because they 

make four million MWh or less of annual wholesale and retail sales. In balancing the 

need for information with the burden on small utilities, the Commission is proposing to 

base the de minimis threshold on wholesale sales and thus will exempt a majority of small 

non-public utilities from this proposed rulemaking. In fact, the Commission believes that 

the proposed rule, if finalized, would apply to only five non-public utilities (Balancing 

Authorities) that are considered small entities. The Commission believes that the direct, 

economic impact on these five small non-public utilities may be significant in terms of 

initial start-up costs (estimated to be $39,148), but that the recurring costs ($2,349 per 

quarterly filing, or $9,396 per year) will likely be small. However, the Commission does 

not consider five non-public utilities to be a substantial number of small entities. Using 

this de minimis threshold, the proposed rule will apply to approximately 16 percent of the 

372 non-public utilities with wholesale sales, while capturing approximately 85 percent 

of the total volume of non-jurisdictional sales. 

135. This rulemaking also proposes changes to the existing filing requirements and thus 

current EQR filers also will be impacted. Based on analysis of EIA Form 861, there are 

186 public utilities and, of these, 51 make four million MWh or less of annual wholesale 

and retail sales. When considering annual wholesale and retail sales from these 51 

entities together with sales by their affiliates, only 28 combined entities had annual 

wholesale and retail sales of or below four million MWh. The Commission does not 

consider this to be a substantial number of small entities. Furthermore, we note that 

public utilities may request, on an individual basis, waiver from the EQR reporting 
Docket No. RM10-12-000 - 90 - 

requirements.147 In addition, the Commission expects that the direct, economic cost to 

comply will be less significant. While public utilities will need to modify their systems 

to capture and report the additional data, they already have the system in place. The 

estimated additional costs from the proposed rule are: (1) for implementation of the 

changes, $15,659, and (2) for each quarterly report, $783 (or $3,132 annually). Thus, the 

Commission certifies that this proposed rule will not have a significant impact on a 

substantial number of small entities. 

VI. Comment Procedures

136. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due 60 days from 

publication in the Federal Register. Comments must refer to Docket No. RM10-12-000, 

and must include the commenter's name, the organization they represent, if applicable, 

and their address in their comments. 

137. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission's web site at http://www.ferc.gov. The Commission accepts 

most standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

 147 The Commission has granted requests for waiver of the EQR filing 

requirements. See Bridger Valley Elect. Assoc., Inc., 101 FERC ¶ 61,146 (2002). 

Entities with a waiver will continue to have a waiver and will not need to file a new 

request for waiver. 
Docket No. RM10-12-000 - 91 - 

in a scanned format. Commenters filing electronically do not need to make a paper 

filing. 

138. Commenters that are not able to file comments electronically must send an 

original and 14 copies of their comments to: Federal Energy Regulatory Commission, 

Secretary of the Commission, 888 First Street NE, Washington, DC 20426. 

139. All comments will be placed in the Commission's public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters. 

VII. Document Availability

140. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through FERC's Home Page 

(http://www.ferc.gov) and in FERC's Public Reference Room during normal business 

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington, DC 20426. 

141. From FERC's Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 

eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field. 
Docket No. RM10-12-000 - 92 - 

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. 

List of subjects in 18 CFR Part 35 

Electric power rates; Electric utilities; Reporting and recordkeeping requirements

By direction of the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 
Docket No. RM10-12-000 - 93 - 

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. § 35.10b 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). 

(a) For purposes of this section, the term “non-public utility” means any 

market participant exempted from the Commission’s jurisdiction by virtue of the Federal 

Power Act, 16 U.S.C. 824f. 
Docket No. RM10-12-000 - 94 - 

The term does not include an entity that engages in purchases or sales of wholesale 

electric energy or transmission services within the Electric Reliability Council of Texas 

or any entity that engages solely in sales of wholesale electric energy or transmission 

services in the states of Alaska or Hawaii. 

 (b) For purposes of this section, the term “de minimis market presence” means any 

non-public utility that makes 4,000,000 megawatt hours or less of annual wholesale sales, 

based on the average annual sales for resale over the preceding three years as published 

by the Energy Information Administration’s Form 861 unless the non-public utility is a 

Balancing Authority that makes 1,000,000 megawatt hours or more of annual wholesale 

sales, as published by the Energy Information Administration’s Form 861. 

3. In § 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 

factual information, and not knowingly submit false or misleading information or omit 

material information any such publisher, by reporting its transactions in a manner 

consistent with the procedures set forth in the Policy Statement on Natural Gas and 

Electric Price Indices, issued by the Commission in Docket No. PL03-3-000, and any 

clarifications thereto. Seller must notify the Commission as part of its Electric Quarterly 

Report filing requirement in § 35.10b of this chapter whether it reports its transactions to 
Docket No. RM10-12-000 - 95 - 

publishers of electricity and natural gas indices. In addition, Seller must adhere to any 

other standards and requirements for price reporting as the Commission may order. 

 * * * * * 
Docket No. RM10-12-000 - 96 - 

Appendix A: List of Commenters 

Short Name or Acronym Commenter

Alaska Power Alaska Power Association 

Allegheny Allegheny Electric Cooperative 

APPA American Public Power Association 

BPA Bonneville Power Administration 

California DWR California Department of Water Resources 

 State Water Project 

California PUC Public Utilities Commission of the State of 

 California 

Cities/M-S-R City of Redding, California, City of Santa 

 Clara, California, and M-S-R Public Power 

 Agency 

City of Dover City of Dover, Delaware 

City of Fayetteville Public Works Commission of the City of 

 Fayetteville, North Carolina 

Consolidated Edison Energy, Inc. and Consolidated Edison Energy, Inc. and 

Consolidated Edison Solutions, Inc. Consolidated Edison Solutions, Inc. 

 

Delaware Municipal Delaware Municipal Electric Corporation, Inc. 

DC Energy DC Energy, LLC 

Duke Energy Duke Energy Corporation 

EEI Edison Electric Institute 

EPSA Electric Power Supply Association 

East Texas Cooperatives East Texas Electric Cooperatives 

ELCON Electricity Consumers Resource Council 
Docket No. RM10-12-000 - 97 - 

EMCOS Eastern Massachusetts Consumer-Owned 

 Systems 

FirstEnergy FirstEnergy Service Company 

Imperial Imperial Irrigation District 

LPPC Large Public Power Council 

MID Modesto Irrigation District 

Morgan Stanley Morgan Stanley Capital Group, Inc. 

New York Public Power New York Association of Public Power 

Northwest Utility Northwest Requirements Utility 

NRECA National Rural Electric Cooperative Association 

NYMPA/MEUA Northern California Power Agency; New York 

 Municipal Power Agency and Municipal 

 Electric Utilities Association of New York 

PG&E Pacific Gas and Electric Company 

PJM PJM Interconnection, LLC 

Public Power Council Public Power Council 

Public Systems Connecticut Municipal Electric Energy 

 Cooperative, Massachusetts Municipal 

 Wholesale Electric Company, and New 

 Hampshire Electric Cooperative, Inc. 

Salt River Salt River Project 

Sam Rayburn Municipal Sam Rayburn Municipal Power Agency 

SDG&E San Diego Gas & Electric Company

Southwest Transmission Southwest Transmission Dependent Utility 

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

TANC Transmission Agency of Northern California 

TAPS Transmission Access Policy Study Group 

Utah Associated Municipal Utah Associated Municipal Power Systems 

Wisconsin Electric Wisconsin Electric Power Company 
Docket No. RM10-12-000 - 99 - 

Appendix B: Proposed Refinements to the Existing EQR 

Fields Proposed to be Removed 

Field # Field Required Value Definition 

17 Customer DUNS 

Number Yes Nine digit number 

The unique nine digit number 

assigned by Dun and Bradstreet to 

the company identified in Field 

Number 16. 

45 Time Zone Yes The time zone in which the sales 

will be made under the contract. 

49 Customer DUNS 

Number Yes Nine digit number 

The unique nine digit number 

assigned by Dun and Bradstreet to 

the counterpart to the contract. 

Fields Proposed to be Created 

Section Field Required Value Definition 

Transaction Transaction 

Datetime Yes YYYYMMDDHHMM

The date and time when the price 

of this transaction was agreed 

upon. 

Transaction 

Standardized 

Transaction 

Price 

Yes, for 

Energy 

and 

Capacity 

sales only 

Number with up to 

8 decimals. 

Actual price charged for the 

product per unit. The price cannot 

be averaged or otherwise 

aggregated. For energy 

transactions, this price must be 

reported in $/MWh. For capacity 

transactions, this price must be 

reported in $/MW-Month. 

 ---- See definitions for each product 

type below. 

Fixed A rate determined by a fixed 

charge per unit of consumption. 

Formula 

A rate determined using a formula 

that does not contain an index 

component. 

Index 

A rate determined using an index 

or using a formula that contains an 

index component. 

Transaction Type of Rate Yes 

RTO/ISO Price 

A rate determined using a 

RTO/ISO published price or using a 

formula that contains a RTO/ISO 

published price. 

Transaction Broker/Exchange 

Name 

If a the 

transaction 

was 

conducted 

with the 

assistance 

of a broker 

or 

exchange 

Unrestricted Text 

(60 Characters) 

The name of the broker or 

exchange that was used to conduct 

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

Transaction Reported to 

Index Publisher 

If the 

transaction 

was 

reported to 

an Index 

Publisher 

Unrestricted Text 

(60 Characters) 

The name of the index publisher(s) 

that the transaction terms were 

reported to. 

Transaction e-Tag ID 

If the 

transaction 

was 

scheduled 

using an 

e-Tag 

Unrestricted Text 

(30 Characters) 

The e-Tag ID used to schedule the 

energy transaction. The e-Tag ID 

reported, must be identical in 

format to the e-Tag ID used to 

schedule the transaction.