Order 768-A, Order on Rehearing and Clarification in RM10-12-002, with updated Data Dictionary

Docket No. RM10-12-002 32

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, 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.

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 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 non-public 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 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 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 small-area, 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 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

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 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 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 non-RTO/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

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 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 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 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 non-public 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

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

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

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 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 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 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 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.

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 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 real-time 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 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

• 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 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

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 MW-month 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.”

• 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.”

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).”

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

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 pre-Order 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

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.

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.

Appendix A: EQR Data Dictionary

Electric Quarterly Report Data Dictionary

Version 2.2 (issued April 18, 2013)

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.
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).

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 non-public utility does not have a FERC Tariff Reference, it should enter “NPU” for the FERC Tariff Reference.
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.
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).
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.
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 market-based 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.
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.
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.
44	End Date	If specified in the contract	YYYYMMDDHHMM	Last date for the sale of the product at the rate specified.

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 non-public 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.
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.
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.
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 (fixed-price, 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.
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).

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.

EQR Data Dictionary e-Tag Data**
Field #	Field	Required	Value	Definition
75	e-Tag ID	If an e-Tag 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 e-Tag 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 e-Tag 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 e-Tag 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 Federal Power Act, 142 FERC ¶ 61,105 (2013).

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.
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.
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.
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., non-transmission 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.

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
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
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
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
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
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.

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 Hub.
NIHUB	The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Interconnection, LLC as the Northern Illinois Hub.
NOB	The set of delivery points along the Nevada-Oregon border commonly identified as and agreed to by the counterparties to constitute the NOB Hub.
NP15	The set of delivery points north of Path 15 on the California transmission grid commonly identified as and agreed to by the counterparties to constitute the NP15 Hub.
NWMT	The set of delivery points commonly identified as and agreed to by the counterparties to constitute delivery into the Northwestern Energy Montana balancing authority.
PJM East Hub	The aggregated Locational Marginal Price nodes (“LMP”) defined by PJM Interconnection, LLC as the PJM East Hub.
PJM South Hub	The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Interconnection, LLC as the PJM South Hub.
PJM West Hub	The aggregated Locational Marginal Price (“LMP”) nodes defined by PJM Interconnection, LLC as the PJM Western Hub.
Palo Verde	The switch yard at the Palo Verde nuclear power station west of Phoenix in Arizona.  Palo Verde Hub includes the Hassayampa switchyard 2 miles south of Palo Verde.
SOCO (into)	The set of delivery points commonly identified as and agreed to by the counterparties to constitute delivery into the Southern Company balancing authority.
SP15	The set of delivery points south of Path 15 on the California transmission grid commonly identified as and agreed to by the counterparties to constitute the SP15 Hub.
TVA (into)	The set of delivery points commonly identified as and agreed to by the counterparties to constitute delivery into the Tennessee Valley Authority balancing authority.
ZP26	The set of delivery points associated with Path 26 on the California transmission grid commonly identified as and agreed to by the counterparties to constitute the ZP26 Hub.

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

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

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

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

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

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,

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.

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 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 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.

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.

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.

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.

36 EQR-Filing Utilities at 3.

37 Id. at 4.

38 EEI/EPSA at 3-4.

39 Id. at 7.

40 Id. at 19.

41 Id. at 19-20.

42 Id. at 20.

43 Id. at 21.

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.

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.

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.

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.

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.

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.

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.

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.

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.

84 Id.

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

86 Order No. 770, FERC Stats. & Regs. ¶ 31,338.

87 APPA/LPPC at 3; NRECA at 6.

88 Id.

89 Comma-separated values or comma delimited files.

90 ECC at 9.

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).

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.

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.

105 Id. at 25; ECC at 7.

106 ECC at 8.

107 EEI/EPSA at 25.

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

109 Id.

110 EEI/EPSA at 26; ECC at 8.

111 EEI/EPSA at 26.

112 Id. at 27-29.

113 Id. at 27.

114 Powerex at 6.

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 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 FERC-920 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.

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.