143 FERC ¶ 61,054

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Jon Wellinghoff, Chairman;

 Philip D. Moeller, John R. Norris,

Cheryl A. LaFleur, and Tony Clark.

Electricity Market Transparency 

Provisions of Section 220 of the 

Federal Power Act

 Docket No. RM10-12-002

ORDER NO. 768-A

ORDER ON REHEARING AND CLARIFICATION

(Issued April 18, 2013)

1. On September 21, 2012, the Federal Energy Regulatory Commission 

(Commission) issued a Final Rule in this proceeding, Order No. 768,1 to require market 

participants that are excluded from the Commission’s jurisdiction under Federal Power 

Act (FPA) section 2052 (non-public utilities) and have more than a de minimis market 

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

 In addition, 

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

Act, Order No. 768, 77 Fed. Reg. 61896 (Oct. 11, 2012), FERC Stats. & Regs. ¶ 31,336 

(2012) (Final Rule).

2 16 U.S.C. § 824d (2006).

3 The Final Rule refers to market participants that are not public utilities under 

section 201(f) of the FPA as “non-public utilities.” FPA section 201(f) provides: “No 

provision in this subchapter 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, 

(continued...)
Docket No. RM10-12-002 - 2 -

Order No. 768 revised the EQR filing requirements applicable to both public utility and 

non-public utility market participants in the interstate wholesale electric markets by 

adding new fields for: (1) reporting the trade date and type of rate; (2) identifying the 

exchange used for a sales transaction, if applicable; (3) reporting whether a broker was 

used to consummate a transaction; (4) reporting electronic tag ID (e-Tag ID) data; and 

(5) reporting standardized prices and quantities for energy, capacity and booked out 

power transactions. The Commission also required EQR filers to indicate in the existing 

ID data section whether they report their sales transactions to an index publisher and, if 

so, to which index publisher(s) and, if applicable, to identify which types of transactions 

are reported. 

2. Eight requests for rehearing and/or clarification of Order No. 768 were filed, and 

two requests for a stay of the implementation of Order No. 768.4 In this order, we deny 

the requests for rehearing and grant certain requests for clarification. As noted below, the 

Commission has already extended the compliance effective date for the e-Tag ID 

requirement set forth in Order No. 768. To the extent commenters seek a stay of other 

requirements in Order No. 768, the Commission denies those stay requests.

 

or 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) (2006). 

4 Requests for rehearing and/or clarification were filed by the American Public 

Power Association (APPA) and Large Public Power Council (LPPC) (collectively 

APPA/LPPC), EDF Trading North America, LLC (EDF Trading), the Edison Electric 

Institute (EEI) and Electric Power Supply Association (EPSA), (collectively EEI/EPSA), 

Energy Compliance Consulting, LLC (ECC), EQR-Filing Entities (which includes Direct 

Energy Marketing Inc., El Paso Electric Company, Exelon Corporation, Hess 

Corporation, Shell Energy North America and the Western Power Trading Forum), 

National Rural Electric Cooperative Association (NRECA), and Powerex Corporation 

(Powerex). Associated Electric Cooperative, Inc. (Associated Electric) filed comments in 

support of NRECA’s filing. EEI/EPSA and EQR-Filing Entities each filed for partial 

stays. 
Docket No. RM10-12-002 - 3 -

I. Background

3. The Commission set forth the EQR filing requirements in Order No. 2001,

5 which

requires public utilities to electronically file EQRs summarizing transaction information 

for short-term and long-term cost-based sales and market-based rate sales and the 

contractual terms and conditions in their agreements for all jurisdictional services. The 

Commission established the EQR reporting requirements to help ensure the collection of 

information needed to perform its regulatory functions over transmission and sales of 

electric energy6 while making data more useful to the public and allowing public utilities 

to better fulfill their responsibility under FPA section 205(c)7 to have rates on file in a 

convenient form and place.8

 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.”9

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.10 Moreover, prior to issuing Order 

 5 Revised Public Utility Filing Requirements, Order No. 2001, 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, 120 FERC ¶ 61,270, order on reh’g and clarification, 

Order No. 2001-H, 121 FERC ¶ 61,289 (2007), order revising filing requirements, Order 

No. 2001-I, FERC Stats. & Regs. ¶ 31,282 (2008). 

6 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at PP 13-14.

7 16 U.S.C. § 824d(c) (2006).

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

9 Id.

10 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 

(continued...)
Docket No. RM10-12-002 - 4 -

No. 768, the Commission issued a notice of inquiry and a notice of proposed rulemaking 

seeking comments regarding its proposal to extend EQR filing requirements to nonpublic utilities and to amend the EQR filing requirements.11 The Commission also 

convened a technical conference in this proceeding on December 12, 2012. In addition, 

in Order No. 770, the Commission amended its regulations to change the process for 

filing EQRs.12 The new reporting requirements directed under Order No. 768, as 

clarified below, along with the changes to the process for filing EQRs set forth in Order 

No. 770, will apply to EQR filings to be reported for the third quarter of 2013. These 

third quarter 2013 filings will provide data for the period July 1, 2013 through 

September 30, 2013, and are due by October 31, 2013. 

5. In the Energy Policy Act of 2005,13 Congress added section 220 to the FPA, which 

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

transmission of electric energy in interstate commerce” with “due regard for the public 

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

consumers.”14 FPA section 220 grants the Commission authority to obtain and 

 

transmission capacity reassignments in EQRs); Notice of Electric Quarterly Reports 

Technical Conference, 73 Fed. Reg. 2477 (Jan. 15, 2008) (announcing a technical 

conference to discuss changes associated with the EQR Data Dictionary).

11 Electricity Market Transparency Provisions of Section 220 of the Federal 

Power Act, Notice of Inquiry, FERC Stats. & Regs. ¶ 35,565 (2010); Electricity Market 

Transparency Provisions of Section 220 of the Federal Power Act, Notice of Proposed 

Rulemaking, FERC Stats. & Regs. ¶ 32,676 (2011) (Transparency NOPR).

12 In particular, due to technology changes that rendered the filing process in use 

outmoded, ineffective, and unsustainable, the Commission is discontinuing the use of 

Commission-distributed software to file an EQR. Instead, the Commission has adopted a 

web-based approach to filing EQRs that will allow a filer to submit EQRs directly 

through the Commission’s website. See Revisions to Electronic Quarterly Report Filing 

Process, Order No. 770, FERC Stats. & Regs. ¶ 31,338 (2012).

13 Pub. L. No. 109-58, 119 Stat. 594 (2005).

14 16 U.S.C. § 824t(a)(1) (2006). 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 

(continued...)
Docket No. RM10-12-002 - 5 -

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.”15 The statute 

specifies that the Commission may obtain this information from “any market 

participant,”16 except for entities with a de minimis market presence.17 Therefore, Order 

No. 768 revised Commission regulations to require market participants that are excluded 

from the Commission’s jurisdiction under FPA section 205 and have more than a 

de minimis market presence to file EQRs with the Commission.18 

6. The EQR reporting requirements adopted in Order No. 768 build upon the 

Commission’s prior improvements to the reporting requirements and further enhance the 

goals of providing greater price transparency, promoting competition, instilling 

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

discourage anti-competitive, discriminatory, and manipulative practices.19

II. Discussion

A. Requests for Partial Stay and Technical Conference

a. Comments

7. EEI/EPSA and the EQR-Filing Utilities request that the Commission immediately 

stay the e-Tag ID requirement and encourage the Commission to reconsider the e-Tag ID 

information provision in its entirety.20 They argue that the Commission should stay the 

 

collusion or other anticompetitive behaviors that can be facilitated by untimely public 

disclosure of transaction-specific information.” 16 U.S.C. § 824t(b)(1-2).

15 Id. § 824t(a)(2).

16 Id. § 824t(a)(3)(A).

17 Id. § 824t(d).

18 Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 1.

19 See id. P 6.

20 EEI/EPSA at 2.
Docket No. RM10-12-002 - 6 -

requirement because much of the cost of providing the information will be incurred up 

front and a stay will avoid irreparable harm in the form of sunk costs to EQR filers.21 

EEI/EPSA, EQR-Filing Utilities and EDF Trading suggest that the Commission convene 

a technical conference to discuss the need for the e-Tag information and the burden 

associated with reporting it.

22 EEI/EPSA and the EQR-Filing Utilities state that, if after 

that technical conference, the Commission remains inclined to require reporting of e-Tag 

ID information, the Commission (with the partial stay in place) should undertake a smallarea, limited-time study of the e-Tag ID data (e.g., focusing on a single balancing 

authority area for a single quarter) to ensure the usefulness of the information is worth the 

burden involved in providing it before imposing this requirement.23 

8. Powerex states that, in addition to issuing guidance regarding e-Tag ID reporting 

and convening a technical conference to assist filers in implementing the revised filing 

requirements, the Commission may also want to consider conducting EQR user group 

workshops to provide opportunities for EQR filers to obtain further Commission staff 

guidance and input.24 Powerex also suggests that the Commission consider holding the 

compliance deadline for e-Tag ID reporting in abeyance until the Commission develops 

the requirements and guidelines that EQR filers can easily follow to accurately submit 

such information.25 

b. Commission Determination 

9. Upon consideration of the concerns raised by parties on rehearing with respect to 

collecting and reporting e-Tag ID data by Order No. 768’s implementation date, the 

Commission issued an order partially extending the compliance effective date so that 

EQR filers do not need to begin including e-Tag ID data in EQRs filed for the third 

 21 Id. at 6.

22 EEI/EPSA at 2, 17; EQR-Filing Utilities at 16; EDF Trading at 3. APPA/LPPC 

state they agree with EEI/EPSA’s suggestion to hold a technical conference. 

APPA/LPPC at 4.

23 EEI/EPSA at 3; EQR Filing Utilities at 16.

24 Powerex at 4-5.

25 Id. at 5.
Docket No. RM10-12-002 - 7 -

quarter of 2013.

26 In that order, the Commission directed staff to prepare a status report 

to be issued within one year from the date of the issuance of the order, unless the 

Commission has already taken action on this matter.27 The order noted that the partial 

extension will allow the Commission more time to fully assess the benefits and burdens 

associated with market participants linking e-Tag ID information and transactions in the 

EQR considering other recent data collection efforts.28

B. Requests for Rehearing

1. The E-Tag ID Requirement

10. As stated in Order No. 768, e-Tags are used to schedule physical interchange 

transactions and contain information about where the power is sourced and delivered; the 

responsible parties in the receipt, delivery and movement of the power; the timing; and 

the volumes and specified details regarding which transmission paths are used.29 The 

e-Tag ID is a subset of information associated with a full e-Tag that consists of four 

components: (1) Source Balancing Authority Entity Code; (2) Purchasing-Selling Entity 

Code; (3) e-Tag Code or Unique Transaction Identifier; and (4) Sink Balancing Authority 

Code.30 Order No. 768 required EQR filers to submit e-Tag IDs for each transaction 

reported in the EQR if an e-Tag was used to schedule the transaction.31

 26 See Electricity Market Transparency Provisions of Section 220 of the Federal 

Power Act, 142 FERC ¶ 61,105 (2013). 

27 Id. P 4.

28 See id. P 3, n.5 (citing Availability of E-Tag Information to Commission Staff, 

Order No. 771, 77 Fed. Reg. 76367 (Dec. 28, 2012), FERC Stats. & Regs. ¶ 31,339 

(2012); Enhancement of Electricity Market Surveillance and Analysis Through Ongoing 

Electronic Delivery of Data from Regional Transmission Organizations and Independent 

System Operators, Order No. 760, 77 Fed. Reg. 26674 (May 7, 2012), FERC Stats. 

& Regs. ¶ 31,330 (2012)).

29 Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 156.

30 Id.

31 Id.
Docket No. RM10-12-002 - 8 -

a. Comments

11. A number of parties sought rehearing and/or clarification of the e-Tag ID 

requirement.32 Parties argue, among other things, that the Commission has understated 

the substantial burden involved in providing e-Tag ID information for each reported 

transaction and overestimated the benefits of the information.33 

 b. Commission Determination

12. As noted above, the Commission issued an order extending the compliance 

effective date with respect to the e-Tag ID reporting requirement so that EQR filers do 

not need to begin including e-Tag ID data in the EQR in the third quarter of 2013.34 The 

Commission will address issues raised on rehearing and clarification pertaining to the 

e-Tag ID reporting requirement in an order to be issued later in this proceeding. 

2. Reporting Sales Made to RTOs and ISOs

a. Comments

13. Various parties argue that the Commission should require RTOs and ISOs instead 

of market participant sellers to report RTO and ISO market transactions. EEI/EPSA 

request that the Commission adopt the recommendations by EEI in their comments on the 

Transparency NOPR that RTOs and ISOs be required to file with the Commission data 

reflecting all sales to them (RTO/ISO sales) each quarter or to make the data available to 

the Commission and the public in a way that meets the transparency requirements of 

Order No. 2001 and any final rule issued in this docket.

35 The EQR-Filing Utilities also 

request that the Commission adopt EEI’s recommendation to have RTOs and ISOs file 

EQRs directly for all reportable sales to RTOs and ISOs or require that the RTOs and 

 32 See, e.g., EEI/EPSA; EQR Filing Utilities; EDF Trading; Powerex. 

33 EEI/EPSA at 5, EQR Filing Utilities at 2-3, EDF Trading at 2. APPA/LPPC 

and NRECA state that they generally support EEI/EPSA’s request for rehearing 

regarding the burden of reporting e-Tag ID data. APPA/LPPC at 2; NRECA at 1, 7.

34 See Electricity Market Transparency Provisions of Section 220 of the Federal 

Power Act, 142 FERC ¶ 61,105.

35 EEI/EPSA at 18.
Docket No. RM10-12-002 - 9 -

ISOs provide to their members EQR-formatted reports that comply with the requirements 

of Order No. 768.36 EQR-Filing Utilities also argue that failing to require RTOs and 

ISOs to file EQRs for transactions they manage or to provide EQR-formatted reports for 

their members, when they are Commission-jurisdictional parties that can provide the 

most accurate data in the most efficient manner, represents an unnecessary burden on 

hundreds of ISO market participants that is not reflected in the burden estimate and thus, 

contravenes the Paperwork Reduction Act and Executive Order 13563.37

14. EEI/EPSA also encourage the Commission to relieve market participants other than 

the RTOs and ISOs from responsibility for filing duplicative information on the RTO and 

ISO sales in their own EQRs, though individual market participants should still be 

allowed to do so, if they so choose. EEI/EPSA state that the Commission should specify 

that market participants other than RTOs and ISOs are required to submit EQRs to the 

Commission showing only their bilateral sales to counterparties other than RTOs and 

ISOs. 

15. EEI/EPSA argue that market participants currently must untangle often limited and 

confusing information provided by the RTOs and ISOs in order to file their own 

individual EQRs.38 EEI/EPSA state that RTOs and ISOs are counterparties to most 

transactions in their markets but RTOs and ISOs currently do not provide EQR 

information for those transactions to the Commission, and not all RTOs and ISOs provide 

clear information about those transactions for other market participants to use in 

compiling their own EQRs. EEI/EPSA add that requiring RTOs and ISOs to provide 

EQR information for transactions to which they are counterparties would ensure that the 

information is available from its primary source rather than placing the burden on other 

market participants that may not otherwise have sufficient information. 39

16. At a minimum, EEI/EPSA state, the Commission should clearly require all RTOs 

and ISOs to provide complete data for all RTO and ISO market transactions, including 

data that other market participants need to prepare their own EQRs, consistent with the 

 36 EQR-Filing Utilities at 3.

37 Id. at 4.

38 EEI/EPSA at 3-4.

39 Id. at 7.
Docket No. RM10-12-002 - 10 -

requirements and implementation dates of Order No. 768 and earlier EQR orders, and in 

a form that allows easy importation of the data to each filer’s EQR. EEI/EPSA state that, 

since the inception of the EQR, reporting RTO and ISO sales has been a challenging part 

of filing transaction data for both utilities and Commission EQR staff and that the effort 

to compile RTO/ISO sales data has outweighed the effort required to compile nonRTO/ISO sales. EEI/EPSA note that some RTOs and ISOs have developed reports that 

they provide to their members to assist the members’ EQR reporting obligations, but the 

reports are inconsistent between and among the RTOs and ISOs even though the RTOs 

and ISOs have worked with the Commission’s staff to develop the reports. Therefore, 

according to EEI/EPSA, it is hard for RTO and ISO members to determine exactly how 

to file these data properly. EEI/EPSA add that some of the RTO and ISO members have 

found the reports of certain RTOs and ISOs to be unreliable, so the members have had to 

prepare their EQR data from their own internal systems. 40 EEI/EPSA also note that the 

California ISO does not provide such a report, so its members are left to decipher their 

invoices and report their transactions, which results in inconsistent and incomplete RTO 

and ISO data.41 EEI/EPSA argue that, by requiring RTOs and ISOs to report RTO/ISO 

sales data directly to the Commission, the Commission would ensure that the data are 

reported consistently, completely, and correctly. In addition, EEI/EPSA argue that 

requiring RTOs and ISOs to provide the information would help reduce the EQR 

reporting burden on market participants other than RTOs and ISOs.42

17. EEI/EPSA recommend that the Commission convene a technical conference with 

representatives from the industry and each of the RTOs and ISOs to address issues related 

to RTO/ISO sales data, including developing consistent reporting practices among the 

RTOs and ISOs; ensuring that RTO/ISO sales data are reported correctly; addressing how 

best to file underlying contract information; adopting company-naming conventions for 

RTO and ISO members that are consistent with the names used by those members in their 

own EQRs; ensuring that, where scheduling agents transact on behalf of several RTO and 

ISO members, each member’s sales are properly recognized by the RTO and ISO; and 

addressing such other implementation issues as may be identified.43

 40 Id. at 19.

41 Id. at 19-20.

42 Id. at 20.

43 Id. at 21.
Docket No. RM10-12-002 - 11 -

b. Commission Determination

18. The Commission denies rehearing. The Commission will continue to require the 

entities making wholesale sales, including sales to the RTO/ISO or through the RTO/ISO 

markets, to report such sales in their EQRs, rather than requiring the RTO or ISO to 

report these sales directly in the EQR. Under FPA section 205(c), every public utility 

must file with the Commission schedules showing their rates, terms and conditions of 

jurisdictional services in a convenient form and place for public inspection.44 In 

implementing FPA section 205(c), Order No. 2001 required public utility sellers to file 

contract and transaction information about their wholesale sales in the EQR, including 

sales they make to an RTO/ISO, or through an RTO’s or ISO’s market.45 The 

Commission concluded that the more accessible format of the EQR will make the 

information more useful to the public and the Commission and better fulfill public 

utilities’ responsibility under FPA section 205(c) to have rates on file in a convenient 

form and place.46 Consistent with Order No. 2001 and public utilities’ filing obligations 

under FPA section 205(c), the Commission will continue to require public utility sellers

to report their wholesale sales in the EQR, including sales to an RTO or ISO. RTOs or 

ISOs must continue to file their own EQRs to the extent they make wholesale power or 

transmission sales. RTO or ISO activities that facilitate the transactions of their members 

 44 Section 205(c) of the FPA, 16 U.S.C. 824d(c)(2006), provides: 

Under such rules and regulations as the Commission may prescribe, every 

public utility shall file with the Commission, within such time and in such 

form as the Commission may designate, and shall keep open in convenient 

form and place for public inspection schedules showing all rates and charges 

for any transmission or sale subject to the jurisdiction of the Commission, 

and the classification, practices, and regulations affecting such rates and 

charges, together with all contracts which in any manner affect or relate to 

such charges, classifications, and services. 

45 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 335. To the extent that an 

RTO or ISO makes wholesale power sales or transmission sales, these sales are subject to 

the same reporting requirements that would be applicable to any other public utility. 

See id.

46 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 31.
Docket No. RM10-12-002 - 12 -

will also continue to be exempted from reporting.47 Although we will not require RTOs 

to make EQR filings to satisfy other public utilities’ obligations under section 205(c) to 

have their rates on file, we reiterate that RTOs and ISOs may file power sales transaction 

information on behalf of a member or participant as an agent, if authorized by the 

member or participant to do so.

48 

19. In addition, in Order No. 768, the Commission determined that non-public utilities 

above the de minimis threshold should generally report the same information about 

wholesale sales and transmission that are being currently reported in EQRs by public 

utilities to help ensure comparability and consistency in EQR data.

49 In keeping with 

Order No. 768 and the Commission’s efforts to facilitate price transparency under FPA 

section 220, we likewise will require non-public utilities to report in their EQRs any sales 

they make to RTOs or ISOs. 

20. The Commission has previously permitted RTOs and ISOs to file power sales 

transaction information on behalf of members or market participants as an agent, if 

authorized to do so by the members or market participants.

50 Commission staff has 

worked with staffs from RTOs and ISOs to map RTO/ISO settlement data to EQR data 

for use by RTO/ISO market participants in filing their EQRs.51 We continue to 

encourage RTOs and ISOs to compile such data for use by market participants. We also 

encourage RTO/ISO staffs to continue working with Commission staff with respect to 

 47 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 335 (“To the extent that an 

RTO facilitates transactions by its members but title to the power never passes to or from 

the RTO, these transactions would be reported by the parties making the sales and not by 

the RTO itself.”).

48 Id. P 336.

49 Order No. 768 did make certain modifications to the information to be reported 

by non-public utilities in the EQR, as discussed in the Final Rule. See Order No. 768,

FERC Stats. & Regs. ¶ 31,336 at PP 73-74. 

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

51 See Order No. 2001-E, 105 FERC ¶ 61,352 at P 12. We note that SPP’s new 

Integrated Marketplace is scheduled to begin in 2014 and we encourage SPP to conduct 

mapping between the new Integrated Marketplace data and EQR data. 
Docket No. RM10-12-002 - 13 -

compiling such data. Furthermore, the Commission may determine that convening 

another technical conference52 would be beneficial, but the Commission will not convene 

a technical conference at this time. 

3. Extension of Implementation Deadline

21. As noted above, Order No. 768 specified that the requirements in the Final Rule 

would be implemented for both public utility and non-public utility EQR filers beginning 

the third quarter of 2013.53

a. Comments

22. EEI/EPSA request that the Commission extend the deadline for the implementation 

of Order No. 768’s requirements to the first quarter of 2014 EQR (rather than the 

third quarter of 2013 EQR), or the first EQR that is due at least 12 months after the 

Commission completes work in response to their request for rehearing, whichever is 

later.54 EEI/EPSA state that the extension of the deadline for Order No. 768’s 

requirements will ensure that market participants have adequate time to adjust and test 

their revised trade-capture systems and internal information collection and reporting 

software and systems before having to report the new information.55 EEI/EPSA state that 

the Commission should provide at a minimum a full year for EQR filers to be able to 

change their internal procedures, protocols, staffing and software to collect the new 

information required by Order No. 768.56

b. Commission Determination

23. The Commission declines to extend the implementation deadline for Order No. 768

beyond the third quarter of 2013 for the requirements set forth in Order No. 768 aside 

 52 The Commission convened a technical conference in this proceeding on 

December 12, 2012.

53 See Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 4.

54 EEI/EPSA at 4.

55 Id.

56 Id. at 29.
Docket No. RM10-12-002 - 14 -

from the e-Tag ID reporting requirement, which has already been extended.

57 We are

not persuaded that market participants will have insufficient time to adjust and test their 

trade-capture and reporting systems to report the information required under Order 

No. 768 by the third quarter of 2013. This is particularly the case given the 

Commission’s extension of Order No. 768’s compliance date with respect to the e Tag ID 

reporting requirement, which parties generally argued presents the most significant 

compliance challenge of Order No. 768.

4. Calculating the De Minimis Market Presence Threshold

24. In Order No. 768, the Commission uniformly adopted a 4 million MWh de minimis

EQR threshold for all non-public utilities.58 Specifically, the Commission stated it would

exempt under the de minimis market presence threshold a non-public utility that make 

4 million MWh or less of annual wholesale sales (based on an average of the wholesale 

sales it made in the preceding three years). The Commission determined that it was 

appropriate to use the total annual wholesale sales volumes already reported by nonpublic utilities in EIA Form 861 to calculate the de minimis threshold because this 

wholesale sales figure would obviate the need to perform a separate sales calculation for 

EQR purposes and it would ensure one consistent method for calculating the threshold.59 

In addition, Order No. 768 determined that certain types of wholesale sales made by 

non-public utilities did not need to be reported in the EQR, including sales by a 

non-public utility cooperative to its members. 

a. Comments

25. NRECA requests rehearing of the Commission’s inclusion of member sales 

transactions in the 4 million MWh de minimis market presence threshold, arguing that 

those sales take place entirely outside of markets, do not result in any market presence 

 57 See Electricity Market Transparency Provisions of Section 220 of the Federal 

Power Act, 142 FERC ¶ 61,105.

58 Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 54.

59 Id. P 57.
Docket No. RM10-12-002 - 15 -

under FPA section 220(d),60 are not influenced by market prices and have no influence on 

market prices.61

26. NRECA argues that generation and transmission (G&T) rural electric cooperatives 

typically were created for the express purpose of selling power to their distribution 

cooperative members and they enter into cost-based power sales contracts for terms that 

are often 30 or 40 years and relate to matters other than power purchases, such as 

construction activities.62 NRECA states that sales pursuant to those contracts cannot be 

considered to constitute a market presence because they take place entirely outside the 

power sales markets and many were negotiated before power sales markets even 

existed.63 In addition, states NRECA, while the Commission justified requiring public 

utilities to file EQRs “to comply with the requirement under FPA section 205(c) to show 

all rates, terms and conditions of jurisdictional services,” the Commission does not have 

section 205(c) jurisdiction over sales by non-public utilities.64 NRECA also argues that 

Order No. 768 correctly held that sales by non-public utilities to their members should 

not be reported in their EQRs and that the same logic compels the conclusion that sales 

by non-public utilities to their members should not be included in determining whether 

the utility exceeds the 4 million MWh threshold for reporting, since those sales do not 

constitute a market presence.65 NRECA states that such sales will not provide the type of 

information needed to assist the Commission in meeting its obligations under FPA 

section 205(c) or fulfilling the FPA section 220 objectives of monitoring collusion or 

anticompetitive conduct.66 

 60 FPA section 220(d) provides that: “The Commission shall not require entities 

who have a de minimis market presence to comply with the reporting requirement of this 

section.” 16 U.S.C. 824t (2006).

61 NRECA at 1.

62 Id. at 3. 

63 Id. at 4.

64 Id. (citing Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 56).

65 Id. at 4.

66 Id.
Docket No. RM10-12-002 - 16 -

27. Associated Electric supports NRECA’s request for rehearing and clarification of 

the Commission’s inclusion of intra-familial or members sales in the 4 million MWh 

market presence threshold.67 Associated Electric states that it is organized as a three-tier 

G&T cooperative that includes both sales to regional G&Ts at one level and regional 

G&T cooperatives’ sales to distribution cooperatives at another level.68 Associated 

Electric states that its sales to its G&T cooperatives are at cost, pursuant to long-term 

contracts, and prices associated with the transactions between the regional G&T 

cooperatives and the distribution cooperatives, which are made pursuant to long-term 

contract, reflect only the cost that Associated Electric charges to its distribution 

cooperatives.69 Associated Electric states that, while occurring through a two-step 

process, the sales from Associated Electric to the regional G&T cooperatives and the 

Regional G&T cooperatives’ sales to the distribution cooperative are in effect a single 

transfer of energy procured by Associated Electric for the distribution cooperatives.70 

28. NRECA and Associated Electric argue that, if the Commission does not grant their 

requests for rehearing on this issue, the Commission should grant waivers of the EQR 

reporting requirement, on a case-by-case basis, to non-public utilities that exceed the 

4 million MWh threshold. NRECA suggests that such a waiver may be granted where, 

for example, a non-public utility may make more than 4 million MWh of sales to its 

members but may have only a few thousand MWh of sales to non-members.71 NRECA 

also argues that the Commission should grant automatic waivers of the EQR filing 

requirement under certain circumstances, thereby eliminating the need for a non-public 

utility to file a waiver request. NRECA states that the Commission may determine that 

non-public utilities with less than 1 million MWh of sales to non-members, for example,

automatically qualify for an exemption and do not need to file a waiver request.72

 67 Associated Electric at 1.

68 Id. at 2.

69 Id.

70 Id.

71 NRECA at 5; see also Associated Electric at 3.

72 Id.
Docket No. RM10-12-002 - 17 -

b. Commission Determination

29. The Commission denies rehearing. We reject NRECA’s suggestion that the 

Commission should exclude non-public utility cooperative sales to their members from 

the calculation of the de minimis market presence threshold. Order No. 768 set the 

de minimis market presence threshold at 4 million MWh of annual wholesale sales,

consistent with the definition of a small utility under the Regulatory Flexibility Act,

73

Small Business Act,

74 and the threshold used in FPA section 201(f) to exclude certain 

electric cooperatives from the Commission’s jurisdiction.75 The Commission continues 

to find it appropriate to base the de minimis market presence threshold on the annual 

wholesale sales figure already reported by non-public utilities in EIA Form 861. This 

will avoid the necessity of a separate sales calculation solely for EQR purposes and 

ensure one consistent, publicly available method for calculating the threshold.76 

Furthermore, while the Commission does not have rate jurisdiction over sales made by 

non-public utilities under FPA section 205(c), the Commission does have the authority to 

collect information about the availability and prices of wholesale electric energy from 

 73 See 5 U.S.C. § 601.

74 See 15 U.S.C. § 632.

75 FPA section 201(f) provides, in relevant part: “[n]o provision in this subchapter 

shall apply to, or be deemed to include . . . an electric cooperative that receives financing 

under the Rural Electrification Act of 1936 (7 U.S.C. 901 et seq.) or that sells less than 

4,000,000 megawatt hours of electricity per year.” 16 U.S.C. § 824(f) (2006). See also

Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 55. 

76 See Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 57. The volumes 

reported as “Sales for Resale” in EIA Form 861 capture the wholesale sales made by a 

reporting entity. In particular, EIA Form 861 instructions for Line 12, define “Sales for 

Resale” as the amount of electricity sold for resale purposes, including “sales for resale to 

power marketers (reported separately in previous years), full and partial requirements 

customers, firm power customers and non-firm customers.” See EIA, Annual Electric 

Power Industry Report Instructions, available at

http://www.eia.gov/survey/form/eia_861/instructions.pdf.
Docket No. RM10-12-002 - 18 -

non-public utilities above the de minimis threshold under FPA section 220, as explained 

in Order No. 768.

77

30. In addition, we reject NRECA’s argument that non-public utility cooperative 

member sales should not be included in the calculation of the de minimis market presence 

threshold because they take place under long-term power contracts entirely outside of 

power sales markets. As the Commission recognized in Order No. 768, non-public 

utilities have a significant presence in national and regional wholesale electric markets

and the lack of information from these entities 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.78 However, the Commission 

also determined that certain types of wholesale sales by non-public utilities, including 

sales by a non-public utility cooperative to its members, should be excluded from the 

EQR reporting requirement because these sales do not significantly impact wholesale 

price formation in electric markets and the benefit of obtaining information about such 

sales may not outweigh the burden on non-public utilities that would need to report them 

in the EQR.

79 To the extent a non-public utility cooperative above the de minimis market 

presence threshold makes “surplus” wholesale sales that are not subject to the reporting 

exclusion for member sales, it must report those sales in the EQR.80 

31. A non-public utility cooperative may have a significant presence in wholesale 

electricity markets based on the volume of total wholesale sales it makes, but certain 

types of wholesale sales made by the non-public utility cooperative (i.e., sales to its 

members) may not significantly impact price formation. However, member sales make 

up a segment of sales in the market and can impact supply and demand fundamentals by

relieving the members of the non-public utility cooperative from seeking out or availing 

themselves of other supply options in the market. Likewise, the supply used to meet 

members’ needs is not available generally to other market participants. Therefore, the 

 77 Order No. 768, FERC Stats. & Regs. ¶ 31,336 at PP 19-27.

78 Id. P 21.

79 See id. P 22. In particular, the Commission noted that these member sales 

generally take place between the non-public utility and a pre-determined customer 

without arm’s-length negotiations. 

80 See Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 22.
Docket No. RM10-12-002 - 19 -

Commission continues to believe that it is not necessary at this time to require non-public 

utility cooperatives to report specific information about individual member sales in the 

EQR because of how those particular sales are priced. Including member sales in the

calculation of the 4 million MWh de minimis market presence threshold calculation for 

non-public utility cooperatives speaks to the presence these entities have in the market as 

a whole rather than to how certain power sales are priced. 

32. In response to NRECA’s and Associated Electric’s suggestion that the Commission

should grant waivers, on a case-by-case basis, to non-public utilities that exceed the 4 

million MWh threshold, we note that companies may request, on an individual basis, a 

waiver from the EQR reporting requirements. As stated in Order No. 768, the 

Commission has previously granted certain requests for waiver of the EQR filing 

requirements on a case-by-case basis.

81 

5. Customer Company Name

33. In Order No. 768, the Commission required reporting of the Customer Company 

Name in Field Numbers 16 and 48 exactly as the Customer Company Name appears on 

the reported contract.

82 

a. Comments

34. EEI/EPSA and ECC seek rehearing of the requirement in Order No. 768 to report 

the name of the customer as it appears on the reported contract in both the contract and 

transaction sections.83 EEI/EPSA maintain that the Commission should provide more 

flexibility in this area. They argue that the name on the “reported contract” may not be 

the name of the counterparty today because the contract may have been assigned to 

another entity or the counterparty may have had a name change in the interim. 

EEI/EPSA and ECC argue that listing the original counterparty as the Customer 

Company Name when the current counterparty may be an entirely different company or a 

renamed entity would be inconsistent with guidance previously provided by the 

Commission’s EQR staff or would create inconsistent data, which previously has been 

 81 Id. P 191. See Bridger Valley Elect. Assoc., Inc., 101 FERC ¶ 61,146 (2002). 

82 Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 171.

83 EEI/EPSA at 26; ECC at 2.
Docket No. RM10-12-002 - 20 -

cited as a violation by the Commission’s audit staff.

84 EEI/EPSA and ECC add that 

complying with this requirement would impose a significant burden because it would 

require a review of each contract reported in the EQR to see if the Customer Company 

Name is exactly as it appears on each contract.85

b. Commission Determination

35. The Commission denies rehearing but grants clarification on this issue. In their 

comments, EEI/EPSA and ECC appear to equate the “reported contract” in the EQR with 

the original contract that existed between the parties before any name change. They seem 

to interpret the Commission’s requirement to mean that they would need to continue 

listing the original counterparty as the Customer Company Name even when the current 

company may be a different company or renamed entity. However, what the 

Commission intended is that the contract-related information reported in the EQR should 

include the current name of the counterparty, as that name may have changed due to 

contract assignments or for other reasons. In instances where the customer 

counterparty’s name changes from the customer name included in the original contract, 

filers should use the name of the current counterparty as the Customer Company Name in 

the contract and transaction sections of the EQR. To further clarify this point, the 

Commission will revise the definition of Customer Company Name in the EQR Data 

Dictionary to read: “The name of the purchaser of contract products and services.” If an 

EQR seller is unsure how to list the Customer Company Name, Commission staff is 

available to provide informal guidance.

C. Requests for Clarification

1. Software Revisions to the Current EQR System

36. In Order No. 770, the Commission amended its regulations to change the process 

for filing EQRs by adopting a web-based approach to filing EQRs.86 The new process 

will allow a public utility or non-public utility to file an EQR directly through the 

Commission’s website, either through a web interface or by submitting an Extensible 

 84 Id.

85 EEI/EPSA at 27; ECC at 2-3.

86 Order No. 770, FERC Stats. & Regs. ¶ 31,338.
Docket No. RM10-12-002 - 21 -

Mark-Up Language (XML)-formatted file. The changes to the EQR process will apply to 

EQR filings beginning the third quarter of 2013.

a. Comments

37. APPA/LPPC and NRECA state that the Commission should begin collecting and 

reporting EQR data from non-public utilities after the implementation of the new 

software, if the Commission has not completed work on the new software by May 31, 

2013.87 APPA/LPPC and NRECA also ask that EQR technical conferences be available 

via webcast for the benefit of those new filers that may not be able to attend the 

conferences in person.88

38. ECC requests clarification as to how the data required under Order No. 768 will be 

filed in CSV89 and XML format in the Commission’s new web portal. ECC states that it 

appears filers will need to import five spreadsheets of CSV (ID, Contract, Transaction, 

e-Tag, Index Publishers) rather than the current three, but it would be helpful for utilities 

that are developing new EQR-data downloads from their trade capture systems and 

developers of third-party software to create XML files out of spreadsheets to know 

exactly what the format will be.90 ECC also requests that the XML Schema Definition 

(XSD) documents that were published by the Commission in the Docket No. RM12-3 

proceeding to describe the elements in the XML document be updated to include the new 

fields.

b. Commission Determination

39. In response to APPA/LPPC, the Commission clarifies that it does not plan to 

collect EQR information from non-public utilities until after the Commission has 

implemented the new EQR software pursuant to Order No. 770. The Commission also 

plans to transcribe EQR technical conferences and make them available via webcast for 

the benefit of filers that may not be able to attend the conferences in person. 

 87 APPA/LPPC at 3; NRECA at 6.

88 Id.

89 Comma-separated values or comma delimited files.

90 ECC at 9.
Docket No. RM10-12-002 - 22 -

40. Furthermore, as noted by ECC, under the new EQR software system, filers will 

need to import an additional spreadsheet for Index Publishers. As the date for complying 

with the e-Tag ID requirement has been extended, a separate spreadsheet for e-Tag ID 

will not be added at this time. In addition, we note that the XSD documents published as 

part of the Order No. 770 proceeding will be updated to include the new fields.

2. Trade Date

41. In Order No. 768, the Commission defined the Trade Date as the “date upon which 

the parties made the legally binding agreement on the price of the transaction.”91 Order 

No. 768 further clarified that, in cases where pricing detail is provided in the contract 

description, the Contract Execution Date should be considered the Trade Date.92 

a. Comments

42. EEI/EPSA and ECC request that the Commission provide certain clarifications of 

Order No. 768 with respect to the Trade Date.

93 EEI/EPSA request that the Commission 

confirm that the Contract Execution Date, which is already reported in the EQR, may be 

used as the Trade Date even if a contract is subsequently amended to change the price 

after the initial execution date.94 ECC contends that, if a contract is amended to change 

the price after the initial execution date, the execution date will no longer be the date 

the parties agreed upon the price being reported. 95 ECC also takes issue with the 

clarification provided in Order No. 768 that, in cases where pricing detail is provided in 

the contract description, the Contract Execution Date should be considered the Trade 

Date.96 EEI/EPSA and ECC request that the Trade Date for preexisting transactions not 

be required and that the Trade Date requirement apply prospectively to transactions 

 91 Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 90.

92 Id. P 92.

93 The EQR-Filing Utilities state that they support the requests for clarifications 

included in the EEI/EPSA rehearing request. EQR-Filing Utilities at 4.

94 EEI/EPSA at 22.

95 Id. at 4.

96 ECC at 3 (citing Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 92).
Docket No. RM10-12-002 - 23 -

entered into during or after the first quarterly reporting period when Order No. 768’s 

provisions must be implemented.97 EEI/EPSA and ECC maintain that applying the Trade 

Date requirement prospectively will help address the concern that many longer-term 

contracts are not captured in utilities’ trade capture systems and the execution date for 

those contracts may need to be added manually to the transaction data. 98 EEI/EPSA and 

ECC request confirmation that the proper trade date for a sale to an RTO or ISO is when 

the markets clear and, therefore, normally the correct Trade Date for a day-ahead energy 

sale to an ISO is the day before the power flowed, and the proper Trade Date for a realtime energy sale is the day the power flowed.99 EEI/EPSA and ECC also request 

clarification of what the appropriate Trade Date would be for RTO or ISO products other 

than energy or capacity, such as uplift.100 

b. Commission Determination

43. The Commission provides the following clarifications. With respect to the 

appropriate Trade Date in instances where the price is amended subsequent to the initial 

contract execution date, we clarify that the parties should report the Trade Date as the 

date they agreed to the subsequent price change. The intent of this field is to enable the 

Commission to better characterize market conditions under which the pricing terms 

reported were determined. If a contract amendment changes the pricing terms, that 

change should be reflected in the Trade Date.101

44. With respect to the proper Trade Date for a sale to an RTO or ISO, the 

Commission clarifies that the Trade Date is when the markets clear. Accordingly, the 

correct Trade Date for a day-ahead energy sale to an RTO or ISO is the day before the 

power flowed; the proper Trade Date for a real-time energy sale is the day the power 

flowed. Similarly, the day the markets clear should also be used as the Trade Date for 

uplift. For example, if an uplift credit is related to a day-ahead energy sale to an RTO or 

 97 EEI/EPSA at 24; ECC at 5.

98 EEI/EPSA at 24; ECC at 4.

99 EEI/EPSA at 22-23; ECC at 5.

100 EEI/EPSA at 23; ECC at 5.

101 The date reported in Field 22, Commencement Date of Contract Terms, should 

also be updated appropriately when the pricing terms change.
Docket No. RM10-12-002 - 24 -

ISO, the correct Trade Date for the uplift credit is the day before the power flowed. If an 

uplift credit is related to a real-time energy sale to an RTO or ISO, the correct Trade Date 

for the uplift credit is the day the power flowed. Furthermore, we note that the Trade 

Date requirement will be applied prospectively so that only the Trade Date for 

transactions entered into on or after July 1, 2013 and reported in the third quarter of 2013 

EQR must be reported.

3. Type of Rate 

45. Order No. 768 required EQR filers to specify in the EQR the Type of Rate by 

which the price is set for each transaction. In particular, the Commission required that

filers specify whether the transaction price is “fixed,” “formula,” “electric index,” or 

“RTO/ISO.”102

a. Comments

46. Commenters request the following clarifications with respect to the requirement to 

provide the Type of Rate by which the price is set for a transaction:

• EEI/EPSA request that the description of the rate type in Order No. 768 at 

PP 107-108 be referenced in the EQR Data Dictionary. 

• EEI/EPSA and ECC state Order No. 768 should be clarified to state that “If the 

price is the result of an RTO/ISO market or the sale is made to the RTO/ISO, 

its rate type is ‘RTO/ISO,’” consistent with the Data Dictionary definition of 

the RTO/ISO rate type as “A rate that is based on RTO/ISO published price or 

formula that contains an RTO/ISO price component.”103

• EEI/EPSA state that P 107 of Order No. 768 does not specify what the type of 

rate would be in a scenario where a formula is tied to an RTO price, such as the 

greater of the RTO price or the contract price.104

 102 Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 105. 

103 EEI/EPSA at 24; ECC at 7.

104 EEI/EPSA at 24.
Docket No. RM10-12-002 - 25 -

• EEI/EPSA and ECC request that the rate type based on “electric index” be 

defined.105 ECC states that “electric index” is not mentioned in the Data 

Dictionary definition of the index rate type and seeks clarification that an 

electric index is an index published by an index publisher such as those 

required to be listed in Field Number 72 or what other examples there are of an 

electric index.106

• EEI/EPSA contend that there is a burden associated with gathering the rate-type 

data that is not recognized in Order No. 768 because it is unlikely that the rate 

types captured in trade-capture systems line up exactly with the EQR Data 

Dictionary definitions so they request that the Commission apply the rate-type 

provision only prospectively.

107

• ECC seeks clarification of what should be entered in Field Number 53 

(Exchange/Broker Service) if a sale was executed using a broker on the 

Intercontinental Exchange (ICE) or the New York Mercantile Exchange 

(NYMEX). 

b. Commission Determination

47. In response to the issues raised by commenters, we provide the following 

clarifications:

• We will include the description of the rate type in the EQR Data Dictionary.

• We clarify that the rate type “RTO/ISO” in Order No. 768 is “the result of an 

RTO/ISO market or the sale is made to the RTO/ISO.”

• We will modify the EQR Data Dictionary definition of rate type “Electric 

Index” to state: “A calculation of a rate based upon an index or formula that 

contains an electric index component.” We also clarify that, for purposes of 

Rate Type, “Electric Index” is an index published by an index publisher such as 

 105 Id. at 25; ECC at 7.

106 ECC at 8.

107 EEI/EPSA at 25.
Docket No. RM10-12-002 - 26 -

those required to be listed in Field Number 73 or a price published by an 

RTO/ISO (e.g., PJM West or Illinois Hub). Thus, where a price is based on an 

electric index that references an RTO/ISO pricing point (e.g., PJM West or 

Illinois Hub) the Type of Rate should be reported as “Electric Index.”

• Consistent with the clarified definition of “Electric Index” Type of Rate as a “A 

calculation of a rate based upon an index or formula that contains an electric

index component,” in a situation where a formula is tied to an RTO/ISO price, 

such as the greater of the RTO/ISO price or the contract price, the Type of Rate 

should be listed as “Electric Index.” It is not a “Formula” Type of Rate because 

it contains an electric index component, the RTO/ISO price. It is not an 

“RTO/ISO” Type of Rate because it is not the “result of an RTO/ISO market or 

[a] sale [] made to the RTO/ISO.”

• We clarify that the rate type requirement will apply prospectively so that only 

the rate type for transactions entered into on or after July 1, 2013 and reported 

for the third quarter of 2013 (the implementation date of Order No. 768) must 

be reported.

• We clarify that, if a sale was executed on an exchange, such as ICE or 

NYMEX, using a broker as an intermediary, the filer should enter “Broker” in 

Field Number 54 (Exchange/Brokerage Service).

4. Standardization of Units

48. Order No. 768 added two new fields to the EQR transaction section and required 

filers to standardize the units for reporting prices and quantities for energy, capacity, and 

booked out power transactions within the EQR.108 The Commission required filers to: 

specify the quantity for energy in MWh and the price for energy in $/MWh; specify 

capacity as MW-month and the price for capacity as $/MW-month; and use the same 

quantity and price conventions associated with energy or capacity, as appropriate, for 

booked out power transactions.109

 108 Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 116.

109 Id.
Docket No. RM10-12-002 - 27 -

a. Comments

49. With regard to standardized units, EEI/EPSA and ECC request clarification that a 

capacity rate that is based on a MW-year basis can be divided by 12 to get the MWmonth rate, regardless of the number of days in the month.110 EEI/EPSA state that there 

is a burden associated with gathering this data that is not recognized in Order No. 768 

and, thus, request that the requirement be applied prospectively only. 111

b. Commission Determination

50. The Commission clarifies that a capacity rate based on a MW-year basis can be 

divided by 12 to get an appropriate MW-month rate, regardless of the number of days in 

the month. Alternatively, filers may also calculate a MW-month rate by accounting for 

the number of days in a month. In addition, in response to EEI/EPSA, we clarify that the 

requirement to standardize units in the EQR will apply prospectively (i.e., to transactions 

entered into on or after July 1, 2013 and reported in EQRs filed for periods beginning 

with the third quarter of 2013).

5. EQR Data Dictionary

a. Comments

51. EEI/EPSA request that the Commission make certain corrections to some of the 

new fields in the Data Dictionary, which are marked in bold below.

112

• Fields currently referenced in the definition of, Contract Data section, new 

Field 21, should be replaced with “fields 17, 22 and 24 through 43.”113

• In the Contract Data section, the new fields in the “Required” column entries 

should be corrected to read: “One of four rate fields (33, 34, 35, or 36) must be 

included.” 

 110 EEI/EPSA at 26; ECC at 8.

111 EEI/EPSA at 26.

112 Id. at 27-29.

113 Id. at 27.
Docket No. RM10-12-002 - 28 -

• In the Transaction Data section, new Field Number 66, the definition should be 

revised to read: “Specify the quantity in MWh if the product is energy or 

booked out power and specify the quantity in MW-month if the product is 

capacity or booked out power.”

• In the Transaction Data section, new Field Number 67, the definition should be 

revised to read: “Specify the price in $/MWh if the product is energy or booked 

out power and specify the price in $/MW-month if the product is capacity or 

booked out power.”

• In the Transaction Data section, new Field Number 69, the definition should be 

revised to replace “Total Transmission Charge (Field 66)” with “Total 

Transmission Charge (Field 68).”

• In the e-Tag Data section, new Field Number 74, the definition should be 

revised to read: “The e-Tag contains: The Source Balancing Authority Entity 

Code where the generation is located; the Purchasing-Selling Balancing 

Authority Entity Code; the e-Tag Code; and the Sink Balancing Authority 

Entity Code.” 

• In the e-Tag section, new Field Number 75, the definition should be revised to 

read: “The first date the transaction is scheduled using the e-Tag ID reported in 

Field Number 74. Begin Date must not be before the Transaction Begin Date 

specified in Field Number 50 and must be reported in the same time zone 

specified in Field Number 55.”

• In the e-Tag Data section, new Field Number 76, the definition should be 

revised to read: “The last date the transaction is scheduled using the e-Tag ID 

reported in Field Number 74. End Date must not be after the Transaction End 

Date specified in Field Number 51 and must be reported in the same time zone 

specified in Field Number 55.”

• In the e-Tag Data section, new Field Number 77, the definition should be 

revised to read: “Unique reference number assigned by the seller for each 

transaction that must be the same as reported in Field Number 49.”
Docket No. RM10-12-002 - 29 -

52. In addition, Powerex states that British Columbia Transmission Corporation should 

be removed from the list of Balancing Authorities in the EQR Data Dictionary because 

British Columbia Transmission Corporation is no longer responsible for operating the 

Balancing Authority in British Columbia.114

b. Commission Determination

53. Order No. 768 made certain revisions to the EQR Data Dictionary. Since then the 

Commission issued Order No. 770, which contains more recent revisions to the Data 

Dictionary. These revisions reflect changes to certain field numbers. In response to 

EEI/EPSA, we specify below what revisions were already made in the EQR Data 

Dictionary in Order No. 770 and two new edits that will be made pursuant to this order. 

A new EQR Data Dictionary incorporating these revisions is attached to this order. 

• The fields referenced in Field Number 22 (Commencement Date of Contract 

Terms), formerly referred to as New Field Number 21 in Order No. 768, are 

now correctly designated, pursuant to Order No. 770, as “fields 18, 23, and 

25 through 44.” 

• The fields referenced in Field Number 34 (Rate), formerly referred to as New 

Field Number 33, as of Order No. 770, correctly states: “One of four rate fields 

(34, 35, 36, or 37) must be included.” 

• The definition in Field Number 67 (Standardized Quantity), formerly referred 

to as New Field Number 66, will be revised to read: “Specify the quantity in 

MWh if the product is energy or booked out power and specify the quantity in 

MW-month if the product is capacity or booked out power.”

• Field Number 68 (Standardized Price), formerly referred to as New Field 

Number 67, will be revised to read: “Specify the price in $/MWh if the product 

is energy or booked out power and specify the price in $/MW-month if the 

product is capacity or booked out power.”

• The definition in Field Number 70 (Total Transaction Charge), formerly 

referred to as New Field Number 69, as of Order No. 770, correctly states “plus 

Total Transmission Charge (Field 69).”

 114 Powerex at 6.
Docket No. RM10-12-002 - 30 -

54. We will defer any revisions to the e-Tag Data section of the Data Dictionary until 

such time as the Commission acts on the e-Tag-related issues in this proceeding. In 

response to Powerex, we will remove British Columbia Transmission Corporation from 

the list of Balancing Authorities in the Data Dictionary. 

55. The Commission is also making certain additional edits to update the EQR Data 

Dictionary. We are updating the definitions in Field Numbers 2 (Company Name), 

4 (Contact Name), 16 (Seller Company Name), 19 (FERC Tariff Reference), and 

72 (Seller Company Name) to reflect the inclusion of non-public utility EQR filers. 

We are also adding “NPU – Non-Public Utility” to the Product Type Names in Field 

Number 30 for use by non-public utility filers.

115 We are also updating the list of 

Balancing Authority names and abbreviations in Appendix A of the Data Dictionary to 

reflect recent changes made by the new official source of such data, the Open Access 

Technology, Inc. (OATI) webRegistry. Appendix A of the Data Dictionary previously 

included the registered Balancing Authority names and abbreviations that were kept 

current as part of the Transmission Service Information Network (TSIN) by the North 

American Electric Reliability Council (NERC).116 In November 2012, the NERC TSIN 

Registry site was decommissioned and replaced by the OATI webRegistry. Furthermore, 

consistent with the switch to the OATI webRegistry, we are also deleting the reference to 

“NERC” in the definitions in Field Number 39 (Point of Receipt Balancing Authority 

(PORBA)) and in Field Number 40 (Point of Delivery Balancing Authority (PODBA)). 

We are also updating the list of Hub names in Appendix C of the Data Dictionary.

117

 115 Order No. 768, FERC Stats. & Regs. ¶ 31,336 at P 75.

116 See Order No. 2001-E, 105 FERC ¶ 61,352 at P 4.

117 The EQR (FERC-920, as updated by Order No. 770) and the corresponding 

Data Dictionary are currently pending review by the Office of Management and Budget 

(OMB) under section 3507(d) of the Paperwork Reduction Act of 1995. The Data 

Dictionary currently pending OMB review in ICR 201302-1902-003 was attached to the 

Errata Notice issued November 19, 2012, in Docket No. RM12-3. OMB’s regulations at 

5 C.F.R. § 1320 require that OMB approve certain reporting and recordkeeping 

requirements (collections of information) imposed by an agency. The Commission will 

submit the revised Data Dictionary attached to this order to OMB for review. Comments 

concerning the Data Dictionary should be submitted to the Commission in this docket 

and to the Office of Management and Budget, Office of Information and Regulatory 

Affairs, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy 

(continued...)
Docket No. RM10-12-002 - 31 -

6. Effective Date of the Rule

a. Comments

56. EEI/EPSA also seeks clarification that Order No. 768’s new reporting 

requirements, including Trade Date and Type of Rate, apply only prospectively to 

transactions entered into after the implementation obligation commences, and that 

information such as Trade Date does not have to be researched and provided for 

transactions entered into and reported in EQRs submitted before this date.118 Thus, 

EEI/EPSA argue, for transactions entered into prior to Order No. 768, whether an 

agreement is cost-based, a long-term, market-based rate service agreement, or a 

confirmation under the EEI Master Agreement, the Commission should allow such preOrder No. 768 Trade Dates to be reported as “pre-rule.”119 EEI/EPSA states that this will 

minimize the need for market participants to undertake extensive manual research to 

provide this information.120 EEI/EPSA add that it takes utilities substantial time, 

resources, and efforts to make changes in their trade-capture and other information 

collection systems to obtain the information required under Order No. 768.121 ECC 

requests rehearing of the requirement to enter the Trade Date for existing transactions and 

specifically requests that the Trade Date for preexisting transactions not be required and 

only be required for new transactions.122

 

Regulatory Commission, phone: (202) 395-4638, fax: (202) 395-7285]. For security 

reasons, comments to OMB should be submitted by e-mail to: 

oira_submission@omb.eop.gov. Comments submitted to OMB should include FERC920 and OMB Control Number 1902-0255. 

118 EEI/EPSA at 4, 30.

119 Id. at 30.

120 Id. at 4.

121 Id. at 8.

122 ECC at 2.
Docket No. RM10-12-002 - 32 -

b. Commission Determination

57. As noted above, Order No. 768’s reporting requirements, including Trade Date and 

Type of Rate, will apply prospectively. Accordingly, transactions entered into on or after 

July 1, 2013, should reflect the requirements set forth in Order No. 768, including trade 

date and type of rate, beginning with EQRs filed for the third quarter of 2013 in October 

2013. Transactions entered into before July 1, 2013 will not need to reflect these 

reporting requirements. 

D. Requests for Extensions of Time

1. Comments

58. NRECA requests that the Commission confirm that it will continue to grant 

extensions of time to file EQRs to market participants who show good cause for the 

extension.123 NRECA states that it anticipates some new filers may have difficulty 

completing their initial reports and the new filing and software requirements may make it 

more difficult to comply with filing deadlines.124

2. Commission Determination

59. The Commission confirms that it will continue to grant extensions of time to file 

EQRs to market participants who show good cause for the extension.

 123 NRECA at 6-7. Associated Electric supports NRECA’s request to clarify that 

the Commission will grant extensions of time for good cause shown. Associated Electric 

at 3.

124 Id. at 7.
Docket No. RM10-12-002 - 33 -

The Commission orders:

The requests for rehearing are denied and certain requests for clarification are 

granted, as discussed in the body of this order.

By the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket No. RM10-12-002 - 34 -

Appendix A: EQR Data Dictionary

Electric Quarterly Report Data Dictionary

Version 2.2 (issued April 18, 2013)
Docket No. RM10-12-002 - 35 -

EQR Data Dictionary

ID Data

Field # Field Required Value Definition

1 Filer Unique 

Identifier

 FS# (where “#” is 

an integer)

(Seller) – An identifier (e.g., “FS1”, “FS2”) used to designate a record 

containing Seller identification information in a comma-delimited (csv) 

file that is imported into the EQR filing. One record for each seller 

company may be imported into an EQR for a given quarter.

1 Filer Unique 

Identifier

 FA1

(Agent) – An identifier (i.e., “FA1”) used to designate a record containing 

Agent identification information in a comma-delimited (csv) file that is 

imported into the EQR filing. Only one record with the FA1 identifier 

may be imported into an EQR for a given quarter.

2 Company Name  Unrestricted text 

(100 characters)

(Seller) – The name of the company that is authorized to make sales as 

indicated in the company's FERC tariff(s) or that is required to file the 

EQR under section 220 of the Federal Power Act.

2 Company Name  Unrestricted text 

(100 characters)

(Agent) – The name of the entity completing the EQR filing. The Agent's 

Company Name need not be the name of the company under Commission 

jurisdiction. 

3 Company Identifier 

A 7-digit integer 

preceded by the 

letter “C”

(Seller) – Identifier obtained through the Commission’s Company 

Registration system.

4 Contact Name  Unrestricted text 

(50 characters)

(Seller) – The name of the contact for the company authorized to make 

sales as indicated in the company's FERC tariff(s) or that is required to 

file the EQR under section 220 of the Federal Power Act. 

4 Contact Name  Unrestricted text 

(50 characters)

(Agent) – Name of the contact for the Agent, usually the person who 

prepares the filing.

5 Contact Title  Unrestricted text 

(50 characters)

Title of contact identified in Field Number 4.

6 Contact Address  Unrestricted text Street address for contact identified in Field Number 4.
Docket No. RM10-12-002 - 36 -

EQR Data Dictionary

ID Data

Field # Field Required Value Definition

7 Contact City  Unrestricted text 

(30 characters) City for the contact identified in Field Number 4.

8 Contact State  Unrestricted text 

(2 characters)

Two character state or province abbreviations for the contact identified in 

Field Number 4.

9 Contact Zip  Unrestricted text 

(10 characters) Zip code for the contact identified in Field Number 4.

10 Contact Country 

Name



CA - Canada

MX - Mexico

US – United 

States

UK – United 

Kingdom

Country (USA, Canada, Mexico, or United Kingdom) for contact address 

identified in Field Number 4.

11 Contact Phone  Unrestricted text 

(20 characters)

Phone number of contact identified in Field Number 4.

12 Contact E-Mail  Unrestricted text E-mail address of contact identified in Field Number 4.

13

Transactions 

Reported to Index 

Price Publisher(s)



Y (Yes)

N (No)

Filers should indicate whether they have reported their sales transactions 

to index price publisher(s). If they have, filers should indicate specifically 

which index publisher(s) in Field Number 73.

14 Filing Quarter  YYYYMM

A six digit reference number used by the EQR software to indicate the 

quarter and year of the filing for the purpose of importing data from csv 

files. The first 4 numbers represent the year (e.g., 2007). The last 2 

numbers represent the last month of the quarter (e.g., 03=1st quarter; 

06=2nd quarter, 09=3rd quarter, 12= 4th quarter). 
Docket No. RM10-12-002 - 37 -

EQR Data Dictionary

Contract Data

Field # Field Required Value Definition

15 Contract Unique ID 

An integer preceded

by the letter “C” (only 

used when importing 

contract data) 

An identifier beginning with the letter “C” and followed by a number 

(e.g., “C1”, “C2”) used to designate a record containing contract 

information in a comma-delimited (csv) file that is imported into the 

EQR filing. One record for each contract product may be imported 

into an EQR for a given quarter.

16 Seller Company 

Name

 Unrestricted text (100 

characters)

The name of the company that is authorized to make sales as indicated 

in the company’s FERC tariff(s) or that is required to file the EQR 

under section 220 of the Federal Power Act. This name must match 

the name provided as a Seller's “Company Name” in Field Number 2 

of the ID Data (Seller Data).

17 Customer 

Company Name

 Unrestricted text (70 

characters) The name of the purchaser of contract products and services. 

18 Contract Affiliate  Y (Yes)

N (No)

The customer is an affiliate if it controls, is controlled by or is under 

common control with the seller. This includes a division that operates 

as a functional unit. A customer of a seller who is an Exempt 

Wholesale Generator may be defined as an affiliate under the Public 

Utility Holding Company Act and the FPA.

19 FERC Tariff 

Reference

 Unrestricted text (60 

characters)

The FERC tariff reference cites the document that specifies the terms 

and conditions under which a Seller is authorized to make 

transmission sales, power sales or sales of related jurisdictional 

services at cost-based rates or at market-based rates. If the sales are 

market-based, the tariff that is specified in the FERC order granting 

the Seller Market Based Rate Authority must be listed. If a nonpublic utility does not have a FERC Tariff Reference, it should enter 

“NPU” for the FERC Tariff Reference. 
Docket No. RM10-12-002 - 38 -

EQR Data Dictionary

Contract Data

Field # Field Required Value Definition

20 Contract Service 

Agreement ID

 Unrestricted text (30 

characters)

Unique identifier given to each service agreement that can be used by 

the filing company to produce the agreement, if requested. The 

identifier may be the number assigned by FERC for those service 

agreements that have been filed with and accepted by the 

Commission, or it may be generated as part of an internal 

identification system.

21 Contract Execution 

Date

 YYYYMMDD The date the contract was signed. If the parties signed on different 

dates, use the most recent date signed.

22

Commencement 

Date of Contract 

Terms

 YYYYMMDD

The date the terms of the contract reported in fields 18, 23 and 25 

through 44 (as defined in the data dictionary) became effective. If 

those terms became effective on multiple dates (i.e.: due to one or 

more amendments), the date to be reported in this field is the date the 

most recent amendment became effective. If the contract or the most 

recent reported amendment does not have an effective date, the date 

when service began pursuant to the contract or most recent reported 

amendment may be used. If the terms reported in fields 18, 23 and 25 

through 44 have not been amended since January 1, 2009, the initial 

date the contract became effective (or absent an effective date the 

initial date when service began) may be used.

23 Contract 

Termination Date

If specified 

in the 

contract

YYYYMMDD The date that the contract expires.

24 Actual Termination 

Date

If contract 

terminated YYYYMMDD The date the contract actually terminates.

25

Extension 

Provision 

Description

 Unrestricted text Description of terms that provide for the continuation of the contract.
Docket No. RM10-12-002 - 39 -

EQR Data Dictionary

Contract Data

Field # Field Required Value Definition

26 Class Name  --- See definitions of each class name below.

26 Class Name  F - Firm

For transmission sales, a service or product that always has priority 

over non-firm service. For power sales, a service or product that is 

not interruptible for economic reasons.

26 Class Name  NF - Non-firm

For transmission sales, a service that is reserved and/or scheduled on 

an as-available basis and is subject to curtailment or interruption at a 

lesser priority compared to Firm service. For an energy sale, a service 

or product for which delivery or receipt of the energy may be 

interrupted for any reason or no reason, without liability on the part of 

either the buyer or seller.

26 Class Name  UP - Unit Power Sale Designates a dedicated sale of energy and capacity from one or more 

than one specified generation unit(s).

26 Class Name  N/A - Not Applicable To be used only when the other available Class Names do not apply.

27 Term Name 

LT - Long Term

ST - Short Term

N/A - Not Applicable

Contracts with durations of one year or greater are long-term. 

Contracts with shorter durations are short-term.

28 Increment Name  --- See definitions for each increment below.

28 Increment Name  H - Hourly Terms of the contract (if specifically noted in the contract) set for up 

to 6 consecutive hours (≤ 6 consecutive hours).

28 Increment Name  D - Daily

Terms of the contract (if specifically noted in the contract) set for 

more than 6 and up to 60 consecutive hours (>6 and ≤ 60 consecutive 

hours). 
Docket No. RM10-12-002 - 40 -

EQR Data Dictionary

Contract Data

Field # Field Required Value Definition

28 Increment Name  W - Weekly

Terms of the contract (if specifically noted in the contract) set for over 

60 consecutive hours and up to 168 consecutive hours (>60 and ≤ 168 

consecutive hours). 

28 Increment Name  M - Monthly

Terms of the contract (if specifically noted in the contract) set for 

more than 168 consecutive hours up to, but not including, one year 

(>168 consecutive hours and < 1 year).

28 Increment Name  Y - Yearly Terms of the contract (if specifically noted in the contract) set for one 

year or more (≥ 1 year).

28 Increment Name  N/A - Not Applicable Terms of the contract do not specify an increment.

29 Increment Peaking 

Name

 --- See definitions for each increment peaking name below.

29 Increment Peaking 

Name

 FP - Full Period The product described may be sold during those hours designated as 

on-peak and off-peak at the point of delivery. 

29 Increment Peaking 

Name

 OP - Off-Peak The product described may be sold only during those hours designated 

as off-peak at the point of delivery.

29 Increment Peaking 

Name

 P - Peak The product described may be sold only during those hours designated 

as on-peak at the point of delivery.

29 Increment Peaking 

Name

 N/A - Not Applicable To be used only when the increment peaking name is not specified in 

the contract.

30 Product Type 

Name

 --- See definitions for each product type below.

30 Product Type 

Name

 CB - Cost Based Energy or capacity sold under a FERC-approved cost-based rate tariff.
Docket No. RM10-12-002 - 41 -

EQR Data Dictionary

Contract Data

Field # Field Required Value Definition

30 Product Type 

Name

 CR - Capacity 

Reassignment

An agreement under which a transmission provider sells, assigns or 

transfers all or portion of its rights to an eligible customer.

30 Product Type 

Name

 MB - Market Based Energy or capacity sold under the seller’s FERC-approved marketbased rate tariff.

30 Product Type 

Name

 T - Transmission The product is sold under a FERC-approved transmission tariff.

30 Product Type 

Name

 NPU – Non-Public 

Utility

The product is sold by a non-public utility that is required to file the 

EQR under section 220 of the Federal Power Act.

30 Product Type 

Name

 Other The product cannot be characterized by the other product type names.

31 Product Name  See Product Name 

Table, Appendix A. Description of product being offered.

32 Quantity

If specified 

in the 

contract

Number with up to 4 

decimals Quantity for the contract product identified.

33 Units

If specified 

in the 

contract

See Units Table, 

Appendix E. Measure stated in the contract for the product sold.

34 Rate

One of 

four rate 

fields (34, 

35, 36, or 

37) must 

be 

included

Number with up to 4 

decimals The charge for the product per unit as stated in the contract.
Docket No. RM10-12-002 - 42 -

EQR Data Dictionary

Contract Data

Field # Field Required Value Definition

35 Rate Minimum

One of 

four rate 

fields (34, 

35, 36, or 

37) must 

be 

included

Number with up to 4 

decimals Minimum rate to be charged per the contract, if a range is specified.

36 Rate Maximum

One of 

four rate 

fields (34, 

35, 36, or 

37) must 

be 

included

Number with up to 4 

decimals Maximum rate to be charged per the contract, if a range is specified.

37 Rate Description

One of 

four rate 

fields (34, 

35, 36, or 

37) must 

be 

included

Unrestricted text

Text description of rate. If the rate is currently available on the FERC 

website, a citation of the FERC Accession Number and the relevant 

FERC tariff including page number or section may be included 

instead of providing the entire rate algorithm. If the rate is not 

available on the FERC website, include the rate algorithm, if rate is 

calculated. If the algorithm would exceed the 150 character field 

limit, it may be provided in a descriptive summary (including bases 

and methods of calculations) with a detailed citation of the relevant 

FERC tariff including page number and section. If more than 150 

characters are required, the contract product may be repeated in a 

subsequent line of data until the rate is adequately described. 

38 Rate Units

If specified 

in the 

contract

See Rate Units Table, 

Appendix F. Measure stated in the contract for the product sold.
Docket No. RM10-12-002 - 43 -

EQR Data Dictionary

Contract Data

Field # Field Required Value Definition

39

Point of Receipt 

Balancing 

Authority(PORBA)

If specified 

in the 

contract

See Balancing 

Authority Table, 

Appendix B.

The registered Balancing Authority (formerly called NERC Control 

Area) where service begins for a transmission or transmission-related 

jurisdictional sale. The Balancing Authority will be identified with 

the abbreviation used in OASIS applications. If receipt occurs at a 

trading hub, the term “Hub” should be used.

40

Point of Receipt 

Specific Location 

(PORSL)

If specified 

in the 

contract

Unrestricted text (50 

characters). If “HUB” 

is selected for 

PORBA, see Hub 

Table, Appendix C.

The specific location at which the product is received if designated in 

the contract. If receipt occurs at a trading hub, a standardized hub 

name must be used. If more points of receipt are listed in the contract 

than can fit into the 50 character space, a description of the collection 

of points may be used. ‘Various,’ alone, is unacceptable unless the 

contract itself uses that terminology.

41

Point of Delivery 

Balancing 

Authority(PODBA)

If specified 

in the 

contract

See Balancing 

Authority Table, 

Appendix B.

The registered Balancing Authority (formerly called NERC Control 

Area) where a jurisdictional product is delivered and/or service ends 

for a transmission or transmission-related jurisdictional sale. The 

Balancing Authority will be identified with the abbreviation used in 

OASIS applications. If delivery occurs at the interconnection of two 

control areas, the control area that the product is entering should be 

used. If delivery occurs at a trading hub, the term “Hub” should be 

used. 

42

Point of Delivery 

Specific Location 

(PODSL)

If specified 

in the 

contract

Unrestricted text (50 

characters). If “HUB” 

is selected for 

PODBA, see Hub 

Table, Appendix C.

The specific location at which the product is delivered if designated in 

the contract. If receipt occurs at a trading hub, a standardized hub 

name must be used. 

43 Begin Date

If specified 

in the 

contract

YYYYMMDDHHMM First date for the sale of the product at the rate specified.
Docket No. RM10-12-002 - 44 -

EQR Data Dictionary

Contract Data

Field # Field Required Value Definition

44 End Date

If specified 

in the 

contract

YYYYMMDDHHMM Last date for the sale of the product at the rate specified.
Docket No. RM10-12-002 - 45 -

EQR Data Dictionary

Transaction Data

Field # Field Required Value Definition

45 Transaction Unique ID 

An integer preceded

by the letter “T” (only 

used when importing 

transaction data)

An identifier beginning with the letter “T” and followed by a number 

(e.g., “T1”, “T2”) used to designate a record containing transaction 

information in a comma-delimited (csv) file that is imported into the 

EQR filing. One record for each transaction record may be imported 

into an EQR for a given quarter. A new transaction record must be 

used every time a price changes in a sale.

46 Seller Company Name  Unrestricted text (100 

Characters)

The name of the company that is authorized to make sales as 

indicated in the company's FERC tariff(s) or that is required to file 

the EQR under section 220 of the Federal Power Act. This name 

must match the name provided as a Seller's “Company Name” in 

Field 2 of the ID Data (Seller Data).

47 Customer Company 

Name

 Unrestricted text (70 

Characters) The name of the purchaser of contract products and services.

48 FERC Tariff 

Reference

 Unrestricted text (60 

Characters)

The FERC tariff reference cites the document that specifies the terms 

and conditions under which a Seller is authorized to make 

transmission sales, power sales or sales of related jurisdictional 

services at cost-based rates or at market-based rates. If the sales are 

market-based, the tariff that is specified in the FERC order granting 

the Seller Market Based Rate Authority must be listed. If a nonpublic utility does not have a FERC Tariff Reference, it should enter 

“NPU” for the FERC Tariff Reference.

49 Contract Service 

Agreement ID

 Unrestricted text (30 

Characters)

Unique identifier given to each service agreement that can be used by 

the filing company to produce the agreement, if requested. The 

identifier may be the number assigned by FERC for those service 

agreements that have been filed and approved by the Commission, or 

it may be generated as part of an internal identification system.

50 Transaction Unique 

Identifier

 Unrestricted text (24 

Characters) Unique reference number assigned by the seller for each transaction.
Docket No. RM10-12-002 - 46 -

EQR Data Dictionary

Transaction Data

Field # Field Required Value Definition

51 Transaction Begin 

Date



YYYYMMDDHHMM 

(csv import)

MMDDYYYYHHMM 

(manual entry)

First date and time the product is sold during the quarter. 

52 Transaction End Date 

YYYYMMDDHHMM 

(csv import)

MMDDYYYYHHMM 

(manual entry)

Last date and time the product is sold during the quarter. 

53 Trade Date 

YYYYMMDD (csv 

import)

MMDDYYYY 

(manual entry)

The date upon which the parties made the legally binding agreement 

on the price of a transaction.

54 Exchange/Brokerage 

Service

See 

Exchange/Brokerage 

Service Table, 

Appendix H.

If a broker service is used to consummate or effectuate a transaction, 

the term “Broker” shall be selected from the Commission-provided 

list. If an exchange is used, the specific exchange that is used shall 

be selected from the Commission-provided list.

55 Type of Rate  --- See type of rate definitions below.

55 Type of Rate  Fixed A fixed charge per unit of consumption. No variables are used to 

determine this rate.

55 Type of Rate  Formula A calculation of a rate based upon a formula that does not contain an 

electric index component. 

55 Type of Rate  Electric Index

A calculation of a rate based upon an index or a formula that contains 

an electric index component. An electric index includes an index 

published by an index publisher such as those required to be listed in 

Field Number 73 or a price published by an RTO/ISO (e.g., PJM 

West or Illinois Hub).

55 Type of Rate  RTO/ISO If the price is the result of an RTO/ISO market or the sale is made to 

the RTO/ISO.
Docket No. RM10-12-002 - 47 -

EQR Data Dictionary

Transaction Data

Field # Field Required Value Definition

56 Time Zone  See Time Zone Table, 

Appendix D. The time zone in which the sales will be made under the contract.

57

Point of Delivery 

Balancing Authority 

(PODBA)



See Balancing 

Authority Table, 

Appendix B.

The registered Balancing Authority (formerly called NERC Control 

Area) abbreviation used in OASIS applications.

58

Point of Delivery 

Specific Location 

(PODSL)



Unrestricted text (50 

characters). If “HUB” 

is selected for 

PODBA, see Hub 

Table, Appendix C.

The specific location at which the product is delivered. If receipt 

occurs at a trading hub, a standardized hub name must be used.

59 Class Name  --- See class name definitions below.

59 Class Name  F - Firm A sale, service or product that is not interruptible for economic 

reasons.

59 Class Name  NF - Non-firm

A sale for which delivery or receipt of the energy may be interrupted 

for any reason or no reason, without liability on the part of either the 

buyer or seller.

59 Class Name  UP - Unit Power Sale Designates a dedicated sale of energy and capacity from one or more 

than one specified generation unit(s).

59 Class Name  BA - Billing 

Adjustment

Designates an incremental material change to one or more 

transactions due to a change in settlement results. “BA” may be used 

in a refiling after the next quarter’s filing is due to reflect the receipt 

of new information. It may not be used to correct an inaccurate 

filing.

59 Class Name  N/A - Not Applicable To be used only when the other available class names do not apply.

60 Term Name 

LT - Long Term

ST - Short TermN/A -

Not Applicable

Power sales transactions with durations of one year or greater are 

long-term. Transactions with shorter durations are short-term.
Docket No. RM10-12-002 - 48 -

EQR Data Dictionary

Transaction Data

Field # Field Required Value Definition

61 Increment Name  --- See increment name definitions below.

61 Increment Name  H - Hourly Terms of the particular sale set for up to 6 consecutive hours (≤ 6 

consecutive hours) Includes LMP based sales in ISO/RTO markets.

61 Increment Name  D - Daily

Terms of the particular sale set for more than 6 and up to 60 

consecutive hours (>6 and ≤ 60 consecutive hours). Includes sales 

over a peak or off-peak block during a single day.

61 Increment Name  W - Weekly

Terms of the particular sale set for over 60 consecutive hours and up 

to 168 consecutive hours (>60 and ≤ 168 consecutive hours). 

Includes sales for a full week and sales for peak and off-peak blocks 

over a particular week. 

61 Increment Name  M - Monthly

Terms of the particular sale set for set for more than 168 consecutive 

hours up to, but not including, one year (>168 consecutive hours and 

< 1 year). Includes sales for full month or multi-week sales during a 

given month.

61 Increment Name  Y - Yearly

Terms of the particular sale set for one year or more (≥ 1 year). 

Includes all long-term contracts with defined pricing terms (fixedprice, formula, or index).

61 Increment Name  N/A - Not Applicable To be used only when other available increment names do not apply.

62 Increment Peaking 

Name

 --- See definitions for increment peaking below.

62 Increment Peaking 

Name

 FP - Full Period The product described was sold during Peak and Off-Peak hours.

62 Increment Peaking 

Name

 OP - Off-Peak The product described was sold only during those hours designated 

as off-peak at the point of delivery.

62 Increment Peaking 

Name

 P - Peak The product described was sold only during those hours designated 

as on-peak at the point of delivery.

62 Increment Peaking 

Name

 N/A - Not Applicable To be used only when the other available increment peaking names 

do not apply.
Docket No. RM10-12-002 - 49 -

EQR Data Dictionary

Transaction Data

Field # Field Required Value Definition

63 Product Name  See Product Names 

Table, Appendix A. Description of product being offered.

64 Transaction Quantity  Number with up to 4 

decimals. The quantity of the product in this transaction record.

65 Price  Number with up to 6 

decimals.

Actual price charged for the product per unit. The price reported 

cannot be averaged or otherwise aggregated

66 Rate Units  See Rate Units Table, 

Appendix F Measure appropriate to the price of the product sold. 

67 Standardized Quantity  Number with up to 4 

decimals.

For product names energy, capacity, and booked out power only. 

Specify the quantity in MWh if the product is energy or booked out 

power and specify the quantity in MW-month if the product is 

capacity or booked out power.

68 Standardized Price  Number with up to 6 

decimals.

For product names energy, capacity, and booked out power only. 

Specify the price in $/MWh if the product is energy or booked out 

power and specify the price in $/MW-month if the product is 

capacity or booked out power.

69 Total Transmission 

Charge

 Number with up to 2 

decimals

Payments received for transmission services when explicitly 

identified.

70 Total Transaction 

Charge

 Number with up to 2 

decimals

Transaction Quantity (Field 64) times Price (Field 65) plus Total 

Transmission Charge (Field 69).
Docket No. RM10-12-002 - 50 -

EQR Data Dictionary

Index Reporting Data

Field # Field Required Value Definition

71 Filer Unique 

Identifier

 FS# (where “#” is an 

integer)

The “FS” seller number from the ID Data table corresponding to the 

index reporting company.

72 Seller Company 

Name

 Unrestricted text (100 

characters)

The name of the company that is authorized to make sales as indicated 

in the company’s FERC tariff(s) or that is required to file the EQR 

under section 220 of the Federal Power Act. This name must match 

the name provided as a Seller's “Company Name” in Field Number 2 

of the ID Data (Seller Data).

73

Index Price 

Publisher(s) To 

Which Sales 

Transactions Have 

Been Reported



If "Yes" is selected for 

Field 13, see Index 

Price Publisher Table, 

Appendix G.

The index price publisher(s) to which sales transactions have been 

reported.

74 Transactions 

Reported

 Unrestricted text (100 

characters)

Description of the types of transactions reported to the index publisher 

identified in this record.
Docket No. RM10-12-002 - 51 -

EQR Data Dictionary

e-Tag Data**

Field # Field Required Value Definition

75 e-Tag ID

If an eTag ID 

was used 

to 

schedule 

the EQR 

transaction

Unrestricted text (30 

Characters)

The e-Tag ID contains: The Source Balancing Authority where the 

generation is located; The Purchasing-Selling Balancing Authority 

Entity Code; the e-Tag Code; and the Sink Balancing Authority. 

76 e-Tag Begin Date

If an eTag ID 

was used 

to 

schedule 

the EQR 

transaction

YYYYMMDD (csv 

import)

MMDDYYYY 

(manual entry)

The first date the transaction is scheduled using the e-Tag ID reported 

in Field Number 75. Begin Date must not be before the Transaction 

Begin Date specified in Field Number 51 and must be reported in the 

same time zone specified in Field Number 56.

77 e-Tag End Date

If an eTag ID 

was used 

to 

schedule 

the EQR 

transaction

YYYYMMDD (csv 

import)

MMDDYYYY 

(manual entry)

The last date the transaction is scheduled using the e-Tag ID reported 

in Field Number 75. End Date must not be after the Transaction End 

Date specified in Field Number 52 and must be reported in the same 

time zone specified in Field Number 56.

78 Transaction Unique 

Identifier

If an eTag ID 

was used 

to 

schedule 

the EQR 

transaction

Unrestricted text (24 

Characters)

Unique reference number assigned by the seller for each transaction 

that must be the same as reported in Field Number 50.

**Compliance with e-Tag Data requirement has been delayed. See Electricity Market Transparency Provisions of Section 220 of the 
Docket No. RM10

-12-002- 52 -

Federal Power Act, 142 FERC ¶ 61,105 (2013).
Docket No. RM10-12-002 - 53 -

EQR Data Dictionary

Appendix A. Product Names

Product Name

Contract 

Product

Transaction 

Product Definition

BLACK START SERVICE   

Service available after a system -wide blackout where a generator participates in 

system restoration activities without the availability of an outside electric supply 

(Ancillary Service).

BOOKED OUT POWER  

Energy or capacity contractually committed bilaterally for delivery but not 

actually delivered due to some offsetting or countervailing trade (Transaction 

only).

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

CUSTOMER CHARGE   Fixed contractual charges assessed on a per customer basis that could include 

billing service.

DIRECT ASSIGNMENT 

FACILITIES CHARGE  Charges for facilities or portions of facilities that are constructed or used for the sole use/benefit of a particular customer.

EMERGENCY ENERGY  Contractual provisions to supply energy or capacity to another entity during 

critical situations.

ENERGY   A quantity of electricity that is sold or transmitted over a period of time.

ENERGY IMBALANCE   

Service provided when a difference occurs between the scheduled and the actual 

delivery of energy to a load obligation (Ancillary Service). For Contracts,

reported if the contract provides for sale of the product. For Transactions, sales

by third-party providers (i.e., non-transmission function) are reported.

EXCHANGE   

Transaction whereby the receiver accepts delivery of energy for a supplier's 

account and returns energy at times, rates, and in amounts as mutually agreed if 

the receiver is not an RTO/ISO.

FUEL CHARGE   Charge based on the cost or amount of fuel used for generation.
Docket No. RM10-12-002 - 54 -

EQR Data Dictionary

Appendix A. Product Names

Product Name

Contract 

Product

Transaction 

Product Definition

GENERATOR IMBALANCE   

Service provided when a difference occurs between the output of a generator

located in the Transmission Provider’s Control Area and a delivery schedule from

that generator to (1) another Control Area or (2) a load within the Transmission

Provider’s Control Area over a single hour (Ancillary Service). For Contracts, 

reported if the contract provides for sale of the product. For Transactions, sales 

by third-party providers (i.e., non-transmission function) are reported.

GRANDFATHERED 

BUNDLED 

  Services provided for bundled transmission, ancillary services and energy under 

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

INTERCONNECTION 

AGREEMENT  

Contract that provides the terms and conditions for a generator, distribution 

system owner, transmission owner, transmission provider, or transmission system 

to physically connect to a transmission system or distribution system.

MEMBERSHIP 

AGREEMENT  Agreement to participate and be subject to rules of a system operator.

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

NEGOTIATED-RATE 

TRANSMISSION   Transmission performed under a negotiated rate contract (applies only to merchant transmission companies).

NETWORK  Transmission service under contract providing network service.

NETWORK OPERATING 

AGREEMENT  

An executed agreement that contains the terms and conditions under which a 

network customer operates its facilities and the technical and operational matters 

associated with the implementation of network integration transmission service.

OTHER   Product name not otherwise included.

POINT-TO-POINT 

AGREEMENT  Transmission service under contract between specified Points of Receipt and 

Delivery.

REACTIVE SUPPLY & 

VOLTAGE CONTROL   Production or absorption of reactive power to maintain voltage levels on transmission systems (Ancillary Service).

REAL POWER 

TRANSMISSION LOSS   The loss of energy, resulting from transporting power over a transmission system.
Docket No. RM10-12-002 - 55 -

EQR Data Dictionary

Appendix A. Product Names

Product Name

Contract 

Product

Transaction 

Product Definition

REASSIGNMENT 

AGREEMENT  Transmission capacity reassignment agreement.

REGULATION & 

FREQUENCY RESPONSE   

Service providing for continuous balancing of resources (generation and 

interchange) with load, and for maintaining scheduled interconnection frequency 

by committing on-line generation where output is raised or lowered and by other 

non-generation resources capable of providing this service as necessary to follow 

the moment-by-moment changes in load (Ancillary Service). For Contracts, 

reported if the contract provides for sale of the product. For Transactions, sales 

by third-party providers (i.e., non-transmission function) are reported.

REQUIREMENTS SERVICE   

Firm, load-following power supply necessary to serve a specified share of 

customer's aggregate load during the term of the agreement. Requirements 

service may include some or all of the energy, capacity and ancillary service 

products. (If the components of the requirements service are priced separately, 

they should be reported separately in the transactions tab.)

SCHEDULE SYSTEM 

CONTROL & DISPATCH   

Scheduling, confirming and implementing an interchange schedule with other 

Balancing Authorities, including intermediary Balancing Authorities providing 

transmission service, and ensuring operational security during the interchange 

transaction (Ancillary Service).

SPINNING RESERVE   

Unloaded synchronized generating capacity that is immediately responsive to 

system frequency and that is capable of being loaded in a short time period or 

non-generation resources capable of providing this service (Ancillary Service). 

For Contracts, reported if the contract provides for sale of the product. For 

Transactions, sales by third-party providers (i.e., non-transmission function) are 

reported.
Docket No. RM10-12-002 - 56 -

EQR Data Dictionary

Appendix A. Product Names

Product Name

Contract 

Product

Transaction 

Product Definition

SUPPLEMENTAL RESERVE   

Service needed to serve load in the event of a system contingency, available with 

greater delay than SPINNING RESERVE. This service may be provided by 

generating units that are on-line but unloaded, by quick-start generation, or by 

interruptible load or other non-generation resources capable of providing this 

service (Ancillary Service). For Contracts, reported if the contract provides for 

sale of the product. For Transactions, sales by third-party providers (i.e., nontransmission function) are reported.

SYSTEM OPERATING 

AGREEMENTS  

An executed agreement that contains the terms and conditions under which a 

system or network customer shall operate its facilities and the technical and 

operational matters associated with the implementation of network.

TOLLING ENERGY   Energy sold from a plant whereby the buyer provides fuel to a generator (seller) 

and receives power in return for pre-established fees.

TRANSMISSION OWNERS 

AGREEMENT  

The agreement that establishes the terms and conditions under which a 

transmission owner transfers operational control over designated transmission 

facilities.

UPLIFT   A make-whole payment by an RTO/ISO to a utility.
Docket No. RM10-12-002 - 57 -

EQR Data Dictionary

Appendix B. Balancing Authority*

Balancing Authority Abbreviation Outside US*

Alabama Electric Cooperative, Inc. AEC

Alberta Electric System Operator AESO 

Alliant Energy Corporate Services, LLC - East ALTE

Alliant Energy Corporate Services, LLC- West ALTW

Ameren Services Company AMRN

Ameren Transmission. Illinois AMIL

Ameren Transmission. Missouri AMMO

Aquila Networks - Missouri Public Service MPS

Arizona Public Service Company AZPS

Associated Electric Cooperative, Inc. AECI

Avista Corp. AVA

Balancing Authority of Northern California BANC

Batesville Balancing Authority BBA

BC Hydro T & D - Grid Operations BCHA 

Big Rivers Electric Corp. BREC

Board of Public Utilities KACY

Bonneville Power Administration Transmission BPAT

California Independent System Operator CISO

Carolina Power & Light Company - CPLW CPLW

Carolina Power and Light Company - East CPLE

Central and Southwest CSWS

Chelan County PUD CHPD

Cinergy Corporation CIN

City of Homestead HST

City of Independence P&L Dept. INDN

City of Tallahassee TAL

City Water Light & Power CWLP

City Utilities of Springfield SPRM

Cleco Power LLC CLEC

Columbia Water & Light CWLD
Docket No. RM10-12-002 - 58 -

EQR Data Dictionary

Appendix B. Balancing Authority*

Balancing Authority Abbreviation Outside US*

Comision Federal de Electricidad CFE 

Constellation Energy Control and Dispatch CSTO

Constellation Energy Control and Dispatch GRIF

Constellation Energy Control and Dispatch - Arkansas PUPP

Constellation Energy Control and Dispatch - Brazos BRAZ

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

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

Constellation Energy Control and Dispatch - Gila River GRMA

Constellation Energy Control and Dispatch - Glacier Wind Energy GWA

Constellation Energy Control and Dispatch - Harquehala HGMA

Constellation Energy Control and Dispatch – Naturenergy Wind Watch, LLC WWA

Constellation Energy Control and Dispatch - Osceola Municipal Light OMLP

Constellation Energy Control and Dispatch - Plum Point PLUM

Dairyland Power Cooperative DPC

DECA, LLC - Arlington Valley DEAA

Duke Energy Corporation DUK

East Kentucky Power Cooperative, Inc. EKPC

El Paso Electric EPE

Electric Energy, Inc. EEI

Empire District Electric Co., The EDE

Entergy EES

Entergy Arkansas, Inc. EAI

ERCOT ISO ERCO

Florida Municipal Power Pool FMPP

Florida Power & Light FPL

Florida Power Corporation FPC

Gainesville Regional Utilities GVL

Grand River Dam Authority GRDA

Grant County PUD No.2 GCPD

Great River Energy GRE
Docket No. RM10-12-002 - 59 -

EQR Data Dictionary

Appendix B. Balancing Authority*

Balancing Authority Abbreviation Outside US*

Great River Energy GREC

Great River Energy GREN

Great River Energy GRES

Hoosier Energy HE

Hydro-Quebec, TransEnergie HQT 

Idaho Power Company IPCO

Imperial Irrigation District IID

Indianapolis Power & Light Company IPL

ISO New England Inc. ISNE

JEA JEA

Kansas City Power & Light, Co KCPL

Lafayette Utilities System LAFA

Lafayette Utilities System LUSB

LG&E Energy Transmission Services LGEE

Lincoln Electric System LES

Los Angeles Department of Water and Power LDWP

Louisiana Energy & Power Authority LEPA

Louisiana Generating, LLC LAGN

Louisiana Generating, LLC - City of Conway CWAY

Louisiana Generating, LLC - City of West Memphis WMU

Louisiana Generating, LLC - North Little Rock NLR

Madison Gas and Electric Company MGE

Manitoba Hydro Electric Board, Transmission Services MHEB 

Michigan Electric Coordinated System MECS

Michigan Electric Coordinated System - CONS CONS

Michigan Electric Coordinated System - DECO DECO

MidAmerican Energy Company MEC

Midwest ISO MISO

Minnesota Power, Inc. MP

Montana-Dakota Utilities Co. MDU
Docket No. RM10-12-002 - 60 -

EQR Data Dictionary

Appendix B. Balancing Authority*

Balancing Authority Abbreviation Outside US*

Muscatine Power and Water MPW

Nebraska Public Power District NPPD

Nevada Power Company NEVP

New Brunswick System Operator NBSO 

New Horizons Electric Cooperative NHC1

New York Independent System Operator NYIS

Northern Indiana Public Service Company NIPS

Northern States Power Company NSP

NorthWestern Energy NWMT

Nova Scotia Power System Operator NSSO 

Ohio Valley Electric Corporation OVEC

Oklahoma Gas and Electric OKGE

Ontario - Independent Electricity System Operator ONT 

OPPD CA/TP OPPD

Otter Tail Power Company OTP

P.U.D. No. 1 of Douglas County DOPD

PacifiCorp-East PACE

PacifiCorp-West PACW

PJM Interconnection PJM

Portland General Electric PGE

Public Service Company of Colorado PSCO

Public Service Company of New Mexico PNM

Puget Sound Energy Transmission PSEI

Salt River Project SRP

Santee Cooper SC

SaskPower Grid Control Centre SPC 

Seattle City Light SCL

Seminole Electric Cooperative SEC

Sierra Pacific Power Co. - Transmission SPPC

South Carolina Electric & Gas Company SCEG
Docket No. RM10-12-002 - 61 -

EQR Data Dictionary

Appendix B. Balancing Authority*

Balancing Authority Abbreviation Outside US*

South Mississippi Electric Power Association SME

South Mississippi Electric Power Association SMEE

Southeastern Power Administration - Hartwell SEHA

Southeastern Power Administration - Russell SERU

Southeastern Power Administration - Thurmond SETH

Southern Company Services, Inc. SOCO

Southern Illinois Power Cooperative SIPC

Southern Indiana Gas & Electric Co. SIGE

Southern Minnesota Municipal Power Agency SMP

Southwest Power Pool SWPP

Southwestern Power Administration SPA

Southwestern Public Service Company SPS

Sunflower Electric Power Corporation SECI

Tacoma Power TPWR

Tampa Electric Company TEC

Tennessee Valley Authority ESO TVA

Trading Hub HUB

Tucson Electric Power Company TEPC

Turlock Irrigation District TIDC

Upper Peninsula Power Co. UPPC

Utilities Commission, City of New Smyrna Beach NSB

Westar Energy - MoPEP Cities MOWR

Western Area Power Administration - Colorado-Missouri WACM

Western Area Power Administration - Lower Colorado WALC

Western Area Power Administration - Upper Great Plains East WAUE

Western Area Power Administration - Upper Great Plains West WAUW

Western Farmers Electric Cooperative WFEC

Western Resources dba Westar Energy WR

Wisconsin Energy Corporation WEC

Wisconsin Public Service Corporation WPS
Docket No. RM10-12-002 - 62 -

EQR Data Dictionary

Appendix B. Balancing Authority*

Balancing Authority Abbreviation Outside US*

Yadkin, Inc. YAD

* Balancing authorities outside the United States may only be used in the Contract Data 

section to identify specified receipt/delivery points in jurisdictional transmission 

contracts.
Docket No. RM10-12-002 63

EQR Data Dictionary

Appendix C. Hub

HUB Definition

ADHUB The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Interconnection, LLC as 

the AEP/Dayton Hub.

AEPGenHub The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Interconnection, LLC as 

the AEPGenHub.

COB The set of delivery points along the California-Oregon commonly identified as and agreed to by the 

counterparties to constitute the COB Hub.

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

delivery into the Cinergy balancing authority.

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

delivery into the Entergy balancing authority.

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

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

Four Corners The set of delivery points at the Four Corners power plant commonly identified as and agreed to by the 

counterparties to constitute the Four Corners Hub.

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

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

Indiana Hub (MISO) The aggregated Elemental Pricing nodes ("Epnodes") defined by the Midwest Independent 

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

Mead The set of delivery points at or near Hoover Dam commonly identified as and agreed to by the 

counterparties to constitute the Mead Hub.

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

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

Mid-Columbia (Mid-C) The set of delivery points along the Columbia River commonly identified as and agreed to by the 

counterparties to constitute the Mid-Columbia Hub.

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

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

NEPOOL (Mass Hub) The aggregated Locational Marginal Price (“LMP”) nodes defined by ISO New England Inc., as Mass 
Docket No. RM10-12-002 64

EQR Data Dictionary

Appendix C. Hub

Hub.

NIHUB The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Interconnection, LLC as 

the Northern Illinois Hub.

NOB The set of delivery points along the Nevada-Oregon border commonly identified as and agreed to by 

the counterparties to constitute the NOB Hub.

NP15 The set of delivery points north of Path 15 on the California transmission grid commonly identified as 

and agreed to by the counterparties to constitute the NP15 Hub.

NWMT The set of delivery points commonly identified as and agreed to by the counterparties to constitute 

delivery into the Northwestern Energy Montana balancing authority.

PJM East Hub The aggregated Locational Marginal Price nodes (“LMP”) defined by PJM Interconnection, LLC as 

the PJM East Hub.

PJM South Hub The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Interconnection, LLC as 

the PJM South Hub.

PJM West Hub The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Interconnection, LLC as 

the PJM Western Hub.

Palo Verde The switch yard at the Palo Verde nuclear power station west of Phoenix in Arizona. Palo Verde Hub 

includes the Hassayampa switchyard 2 miles south of Palo Verde.

SOCO (into) The set of delivery points commonly identified as and agreed to by the counterparties to constitute 

delivery into the Southern Company balancing authority.

SP15 The set of delivery points south of Path 15 on the California transmission grid commonly identified as 

and agreed to by the counterparties to constitute the SP15 Hub.

TVA (into) The set of delivery points commonly identified as and agreed to by the counterparties to constitute 

delivery into the Tennessee Valley Authority balancing authority.

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

identified as and agreed to by the counterparties to constitute the ZP26 Hub.
Docket No. RM10

-12-002 65

EQR Data Dictionary

Appendix D. Time Zone

Time Zone Definition

AD Atlantic Daylight

AP Atlantic Prevailing

AS Atlantic Standard

CD Central Daylight

CP Central Prevailing

CS Central Standard

ED Eastern Daylight

EP Eastern Prevailing

ES Eastern Standard

MD Mountain Daylight

MP Mountain Prevailing

MS Mountain Standard

NA Not Applicable

PD Pacific Daylight

PP Pacific Prevailing

PS Pacific Standard

UT Universal Time
Docket No. RM10

-12-002 66

EQR Data Dictionary

Appendix E. Units

Units Definition

KV Kilovolt

KVA Kilovolt Amperes

KVR Kilovar

KW Kilowatt

KWH Kilowatt Hour

KW-DAY Kilowatt Day

KW-MO Kilowatt Month

KW-WK Kilowatt Week

KW-YR Kilowatt Year

MVAR-YR Megavar Year

MW Megawatt

MWH Megawatt Hour

MW-DAY Megawatt Day

MW-MO Megawatt Month

MW-WK Megawatt Week

MW-YR Megawatt Year

RKVA Reactive Kilovolt Amperes

FLAT RATE Flat Rate
Docket No. RM10-12-002 67

EQR Data Dictionary

Appendix F. Rate Units

Rate Units Definition

$/KV dollars per kilovolt

$/KVA dollars per kilovolt amperes

$/KVR dollars per kilovar

$/KW dollars per kilowatt

$/KWH dollars per kilowatt hour

$/KW-DAY dollars per kilowatt day

$/KW-MO dollars per kilowatt month

$/KW-WK dollars per kilowatt week

$/KW-YR dollars per kilowatt year

$/MW dollars per megawatt

$/MWH dollars per megawatt hour

$/MW-DAY dollars per megawatt day

$/MW-MO dollars per megawatt month

$/MW-WK dollars per megawatt week

$/MW-YR dollars per megawatt year

$/MVAR-YR dollars per megavar year

$/RKVA dollars per reactive kilovar amperes

CENTS cents

CENTS/KVR cents per kilovolt amperes

CENTS/KWH cents per kilowatt hour

FLAT RATE rate not specified in any other units
Docket No. RM10-12-002 68

EQR Data Dictionary

Appendix G. Index Price Publisher

Index Price 

Publisher 

Abbreviation Index Price Publisher

AM Argus Media

EIG Energy Intelligence Group, Inc.

IP Intelligence Press

P Platts

B Bloomberg

DJ Dow Jones

Pdx Powerdex

SNL SNL Energy
Docket No. RM10-12-002 69

EQR Data Dictionary

Appendix H. Exchange/Broker Services

Exchange/Brokerage 

Service Definition

BROKER A broker was used to consummate or 

effectuate the transaction. 

ICE Intercontinental Exchange

NYMEX New York Mercantile Exchange