Data Collection for Analytics and Surveillance and Market-Based Rate Purposes

Federal RegisterJul 26, 2019

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM16-17-000; Order No. 860]

Data Collection for Analytics and Surveillance and Market-Based Rate Purposes

AGENCY:

Federal Energy Regulatory Commission, Department of Energy.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is revising its regulations governing market-based rates for public utilities. The Commission will collect certain information currently filed in the electric market-based rate program in a consolidated and streamlined manner through a relational database. The relational database construct modernizes the Commission's data collection processes, eliminates duplications, and renders information collected through its market-based rate program usable and accessible for the Commission. The Commission will not adopt the proposal from the NOPR to collect Connected Entity data from market-based rate Sellers and entities trading virtual or holding financial transmission rights in this final rule. With respect to the market-based rate program, the Commission will adopt changes that reduce and clarify the scope of ownership information that Sellers must provide as part of their market-based rate filings. In addition, the Commission will modify its regulations to change the information required in a Seller's asset appendix as well as the format through which such information must be submitted. The revised regulations will require a Seller to update the relational database on a monthly basis to reflect any changes that have occurred but will also extend the change in status filing requirement to a quarterly filing obligation. Finally, the Commission will modify its regulations to eliminate the requirement that Sellers submit corporate organizational charts.

DATES:

This rule will become effective October 1, 2020.

FOR FURTHER INFORMATION CONTACT:

Carol Johnson (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202) 502-8521,

Carol.Johnson@ferc.gov

Byron Corum (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202) 502-6555,

Byron.corum@ferc.gov

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph Nos.

I. Introduction

II. Submission of Information Through a Relational Database

A. Commission Proposal

B. Comments

C. Commission Determination

III. Obtaining a Legal Entity Identifier (LEI)

A. Commission Proposal

B. Comments

C. Commission Determination

IV. Substantive Changes to Market-Based Rate Requirements

A. Asset Appendix

1. New Format

2. Reporting of Generation Assets

3. Power Purchase Agreements

4. Providing EIA Codes for Unit-Specific Power Purchase Agreements

101

5. Vertical Assets

108

B. Ownership Information

112

1. Commission Proposal

112

2. Comments

115

3. Commission Determination

121

C. Passive Owners

130

1. Commission Proposal

130

2. Comments

131

3. Commission Determination

137

D. Foreign Governments

142

1. Commission Proposal

142

2. Comments

143

3. Commission Determination

146

E. Indicative Screens

147

1. Commission Proposal

147

2. Comments

148

3. Commission Determination

150

F. Other Market-Based Rate Information

156

1. Commission Proposal

156

2. Comments

157

3. Commission Determination

158

V. Ongoing Reporting Requirements

160

A. Commission Proposal

160

B. Comments

162

C. Commission Determination

171

VI. Connected Entity Information

182

A. Commission Proposal

182

B. Comments

183

C. Commission Determination

184

VII. Initial Submissions

185

A. Commission Proposal

185

B. Comments

187

C. Commission Determination

191

VIII. Data Dictionary

201

A. Overview

201

1. Commission Proposal

201

2. Comments

204

3. Commission Determination

209

B. Updates to the Data Dictionary

218

1. Commission Proposal

218

2. Comments

219

3. Commission Determination

220

C. Filing Information Table

221

1. Comments

222

2. Commission Determination

223

D. Natural Persons Table

224

1. Comments

225

2. Commission Determination

226

E. Entities Table

227

1. Comments

228

2. Commission Determination

229

F. Generation Assets Table

230

1. Comments

231

2. Commission Determination

232

G. MBR Information Tables

235

1. Comments

236

2. Commission Determination

239

H. PPAs Table

245

1. Comments

246

2. Commission Determination

249

I. Indicative Screens Tables

253

1. Comments

254

2. Commission Determination

255

J. Entities to Entities Table and Natural Person Affiliates to Entities

258

1. Comments

259

2. Commission Determination

260

K. Entities to Generation Assets Table

262

1. Comments

263

2. Commission Determination

264

L. Vertical Assets Table

268

1. Comments

269

2. Commission Determination

270

M. Posted Changes to the Reference Tables

271

1. Commission Proposal

271

2. Comments

272

3. Commission Determination

273

N. Submission on Behalf of Multiple Entities

274

1. Commission Proposal

274

2. Comments

275

3. Commission Determination

276

IX. Confidentiality

278

A. Commission Proposal

278

B. Comments

279

C. Commission Determination

284

X. Due Diligence

286

A. Commission Proposal

286

B. Comments

287

C. Commission Determination

291

XI. Implementation and Timing

299

A. Commission Proposal

299

B. Comments

300

C. Commission Determination

308

XII. Information Collection Statement

319

XIII. Environmental Analysis

335

XIV. Regulatory Flexibility Act

336

XV. Document Availability

339

XVI. Effective Dates and Congressional Notification

342

I. Introduction

1. On July 21, 2016, the Federal Energy Regulatory Commission (Commission) issued a Notice of Proposed Rulemaking (NOPR)

proposing to revise its regulations to collect certain data for analytics and surveillance purposes from Sellers

and certain other participants in the organized wholesale electric markets subject to the Commission's jurisdiction pursuant to the FPA.

The Commission also proposed to change certain aspects of the substance and format of information submitted for market-based rate purposes. The Commission commenced the instant rulemaking in order to modernize its data collection processes, eliminate duplication, ease compliance burdens, and render information collected through its programs more usable and accessible for the Commission.

Data Collection for Analytics and Surveillance and Market-Based Rate Purposes,

Notice of Proposed Rulemaking, 156 FERC ¶ 61,045 (2016) (NOPR). The instant proceeding was the outgrowth of two prior rulemaking proceedings that had previously been withdrawn and superseded.

See Collection of Connected Entity Data from Regional Transmission Organizations and Independent System Operators,

Notice of Proposed Rulemaking, 152 FERC ¶ 61,219 (2015) (Connected Entity NOPR);

Collection of Connected Entity Data from Regional Transmission Organizations and Independent System Operators,

Withdrawal of Proposed Rulemaking and Termination of Rulemaking Proceeding, 156 FERC ¶ 61,046 (2016);

Ownership Information in Market-Based Rate Filings,

Notice of Proposed Rulemaking, 153 FERC ¶ 61,309 (2015) (Ownership NOPR);

Ownership Information in Market-Based Rate Filings,

Withdrawal of Proposed Rulemaking and Termination of Rulemaking Proceeding, 156 FERC ¶ 61,047 (2016).

A Seller is defined as any person that has authorization to or seeks authorization to engage in sales for resale of electric energy, capacity or ancillary services at market-based rates under section 205 of the Federal Power Act (FPA). 18 CFR 35.36(a)(1); 16 U.S.C. 824d.

The organized wholesale electric markets subject to the Commission's jurisdiction refers to the markets operated by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) operating in the United States. These RTOs and ISOs include: PJM Interconnection, L.L.C. (PJM), New York Independent System Operator, Inc. (NYISO), ISO New England Inc. (ISO-NE), California Independent System Operator Corporation (CAISO), Midcontinent Independent System Operator, Inc. (MISO), and Southwest Power Pool, Inc. (SPP).

2. As such, the revisions proposed included new requirements for entities, other than those described in FPA section 201(f),

that trade virtual products

or that hold financial transmission rights (FTR)

(collectively, Virtual/FTR Participants) and for Sellers to report certain information about their legal and financial connections to other entities (Connected Entity Information) to assist the Commission in its analytics and surveillance efforts. The Commission further proposed to consolidate and streamline the data collection through the creation of a relational database.

The Commission also proposed to collect certain information currently submitted by Sellers in the relational database, reasoning that the relational database would allow for the automatic generation of an asset appendix and organizational chart that is specific to each Seller. Given this functionality, the Commission also proposed to eliminate the requirement in Order No. 816 that Sellers submit corporate organizational charts.

Lastly, the Commission proposed other revisions to the market-based rate program.

16 U.S.C. 824(f).

Virtual trading involves sales or purchases in an RTO/ISO day-ahead market that do not go to physical delivery. By making virtual energy sales or purchases in the day-ahead market and settling these positions in the real-time, any market participant can arbitrage price differences between the two markets.

See Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities,

Order No. 697, 119 FERC ¶ 61,295, at P 921 n.1047,

clarified,

121 FERC ¶ 61,260 (2007),

order on reh'g,

Order No. 697-A, 123 FERC ¶ 61,055,

clarified,

124 FERC ¶ 61,055,

order on reh'g,

Order No. 697-B, 125 FERC ¶ 61,326 (2008),

order on reh'g,

Order No. 697-C, 127 FERC ¶ 61,284 (2009),

order on reh'g,

Order No. 697-D, 130 FERC ¶ 61,206 (2010),

aff'd sub nom. Mont. Consumer Counsel

FERC,

659 F.3d 910 (9th Cir. 2011),

cert. denied sub nom. Public Citizen, Inc.

FERC,

567 U.S. 934 (2012).

The term “FTR” as used in the NOPR was intended to cover not only Financial Transmission Rights, a term used by PJM, ISO-NE, and MISO, but also Transmission Congestion Contracts in NYISO, Transmission Congestion Rights in SPP, and Congestion Revenue Rights in CAISO.

See

NOPR, 156 FERC ¶ 61,045 at P 1 n.6.

A relational database is a database model whereby multiple data tables relate to one another via unique identifiers. A relational database contains a table for each type of object (

e.g.,

generation assets), with each row in the table containing information about a single instance of that object (

e.g.,

a particular generation unit) and each column representing a particular attribute of that object (

e.g.,

a generation unit's capacity rating). Relational databases are structured to allow for easy data retrieval while avoiding inconsistencies and redundancies.

See Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities,

Order No. 816, 153 FERC ¶ 61,065, at P 320 (2015),

order on reh'g,

Order No. 816-A, 155 FERC ¶ 61,188 (2016). The organizational chart requirement was suspended in Order No. 816-A “until the Commission issues an order at a later date addressing this requirement.” Order No. 816-A, 155 FERC ¶ 61,188 at P 47. The relevant organizational chart requirements currently appear in §§ 35.37(a)(2) and 35.42(c) of the Commission's regulations.

3. The Commission received 31 comments in response to the NOPR. A list of commenters, including the abbreviated names used in this final rule, is attached as an appendix to this final rule.

4. In this final rule, we adopt the approach to data collection proposed in the NOPR, with several modifications and clarifications as discussed below. We adopt the proposal to collect market-based rate information in a relational database but decline to adopt the proposal to require Sellers and Virtual/FTR Participants to submit Connected Entity Information.

Notwithstanding this decision, we note that the market-based rate information will assist the Commission in administering both its market-based rate and analytics and surveillance programs.

Given our decision not to pursue collection of Connected Entity Information in this final rule, the remainder of this final rule focuses on the proposals and comments regarding the collection of market-based rate information and other proposed changes to the market-based rate program.

5. The relational database construct that we adopt in this final rule provides for a more modern and flexible format for the reporting and retrieval of information. Sellers will be linked to their market-based rate affiliates through common ultimate upstream affiliate(s).

Through this linkage, the relational database will allow for the automatic generation of a complete asset appendix based solely on the information submitted into the relational database.

In the NOPR, the Commission proposed the term “ultimate affiliate owner.” NOPR, 156 FERC ¶ 61,045 at P 8. Herein, we replace this proposed term with “ultimate upstream affiliate” to reflect that an ultimate upstream affiliate could have control, but not ownership of a Seller. We define ultimate upstream affiliate as the furthest upstream affiliate(s) in the ownership chain—

i.e.,

each of the upstream affiliate(s) of a Seller, who itself does not have 10 percent or more of its outstanding securities owned, held or controlled, with power to vote, by any person (including an individual or company). As discussed below, we codify this definition of “ultimate upstream affiliate” by amending § 35.36(a) of the Commission's regulations. We made corresponding changes to the regulations in §§ 35.37(a)(1), 35.37(a)(2), and 35.42(a)(v) to reflect this new term. For clarity, in this final rule we will use the terms “upstream affiliate” and “ultimate upstream affiliate” in place of “affiliate owner” and “ultimate affiliate owner” when referencing the NOPR proposal and comments.

6. To allow for this functionality, we will require Sellers to submit into the relational database certain information concerning their upstream affiliates, generation assets, long-term firm sales and purchases, vertical assets, category status, the specific markets in which the Seller is authorized to sell operating reserves, and whether the Seller is subject to mitigation or other limitations. We also adopt the NOPR proposal requiring Sellers to submit their indicative screen information in extensible markup language (XML) format, which will enable the information to be included in the

relational database. Services will be available to automatically generate tabular indicative screen results based on this information, and the Seller will be able to reference these screen results as part of its initial application and, where appropriate, its triennial market power update or change in status filing.

7. The submission of generator-specific generation information and long-term firm sales information represent new substantive requirements to the market-based rate program but are counterbalanced by other revisions to the program that will reduce burden on Sellers. These revisions include reducing the amount of ownership information that Sellers need to provide, eliminating the requirement to provide corporate organizational charts, and eliminating the requirement to demonstrate ownership passivity where the Seller has made an affirmative statement concerning passive ownership interests. The automated generation of a Seller's asset appendix will also reduce burden to the extent that Sellers will no longer be required to report the assets of their market-based rate affiliates.

8. In this final rule, we provide more detail on the relational database construct and how entities can interact with the relational database to make submissions and prepare market-based rate filings. We also modify the reporting requirements for updates, including timing of change in status filings and quarterly database updates. Among other things, all updates to the relational database will be due on the 15th day of the month following a change. In light of these monthly relational database updates, we will require that Sellers file notices of change in status on a quarterly basis rather than within 30 days of any such changes, thus potentially reducing the number of change in status filings required of Sellers throughout the year. We also discuss modifications to the data dictionary provided in the NOPR (NOPR data dictionary) and provide a new version of the data dictionary (MBR Data Dictionary), which will be available on the Commission's website. As discussed below, the MBR Data Dictionary may undergo minor or non-material changes on occasion. The process for making minor or non-material changes to the MBR Data Dictionary will be the same as that used for the Electric Quarterly Report (EQR) data dictionary. As is the process for EQR, any significant changes to the reporting requirements or the MBR Data Dictionary will be proposed in a Commission order or rulemaking, which would provide an opportunity for comment.

We will also post on the Commission's website high-level instructions that describe the mechanics of the relational database submission process and how to prepare filings that incorporate information that is submitted to the relational database. The revised regulatory text from this final rule will take effect on October 1, 2020. However, submission obligations will follow the implementation schedule discussed below.

See Filing Requirements for Electric Utility Service Agreements,

155 FERC ¶ 61,280, at P 5,

order on reh'g,

157 FERC ¶ 61,180, at PP 40-43 (2016).

II. Submission of Information Through a Relational Database

A. Commission Proposal

9. In the NOPR, the Commission proposed to create a relational database that would accommodate the needs of both the Commission's market-based rate and analytics and surveillance programs. The Commission proposed that information would be submitted into the relational database using an XML schema.

The Commission stated that the XML schema would permit filers to assemble an XML filing package that includes all of the necessary attachments, including the cover letter and any related market-based rate tariffs.

The Commission intended that, upon the receipt of the filing, the XML schema could be parsed

into its component parts, with certain information placed into its eLibrary system and other information submitted into the new database, where it could be made available for review by the Commission and other interested parties.

As the Commission previously explained, XML schemas facilitate the sharing of data across different information systems, particularly via the internet, by structuring the data using tags to identify particular data elements. The tagged information can be extracted and separately searched.

See Electronic Tariff Filings,

Order No. 714, 124 FERC ¶ 61,270, at P 12 & n.8 (2008). The Commission currently collects other data, including EQRs and eTariffs using XML.

See

Order No. 714, 124 FERC ¶ 61,270 (using XML for eTariff filings);

see also Revised Public Utility Filing Requirements,

Order No. 2001, 99 FERC ¶ 61,107,

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 filings,

Order No. 2001-D, 102 FERC ¶ 61,334,

order refining filing requirements,

Order No. 2001-E, 105 FERC ¶ 61,352 (2003),

clarification order,

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, 125 FERC 61,103 (2008) (using XML for EQRs).

NOPR, 156 FERC ¶ 61,045 at P 14.

Parse means to capture the hierarchy of the text in the XML file and transform it into a form suitable for further processing. Order No. 714, 124 FERC ¶ 61,270 at n.9.

The Commission also stated that the mechanics and formatting for data submission by filers would be provided on the Commission's website. NOPR, 156 FERC ¶ 61,045 at P 14.

B. Comments

10. Commenters generally expressed approval of the Commission's proposal to collect market-based rate information in a relational database but also suggested certain changes and clarifications.

EPSA commends the Commission for taking proactive steps to consolidate its various data collection and streamlining efforts and proposals.

Similarly, Independent Generation states that it generally supports the proposal to limit ownership reporting and notes that, correctly interpreted, the proposal would significantly reduce the burden of collecting, monitoring and reporting extensive information concerning corporate relationships that do not relate to the reporting entity's jurisdictional activities.

See e.g.,

APPA at 6 (“[t]he streamlined method of submitting the data to the relational database appears to provide benefits to [Sellers], the Commission and its staff, and the public.”); EPSA at 2 (commending the Commission for “taking proactive steps to consolidate its various data collection and streamlining efforts and proposals”).

EPSA at 2;

see also

APPA at 5-6 (also recommending specific changes). The proposals are referenced in n.1 above.

Independent Generation at 3-4 (“It is essential that the rule be narrowly tailored to capture entities with ultimate decision-making authority over FERC-jurisdictional activities without sweeping in countless intermediate, passive, or non-controlling entities that have no influence over such activities. Further, aligning the Connected Entity ownership reporting requirement with the [market-based rate] program ownership reporting requirement (also focused on ultimate affiliate owners) will reduce reporting errors and omissions and increase the usefulness of the information collected.”).

11. NextEra agrees that the creation of the relational database could ultimately help streamline the reporting process and reduce the amount of information submitted to the Commission in many filings.

TAPS also supports the Commission's objectives to render market-based rate information more usable and accessible, better understand the financial and legal connections among market participants and other entities, and streamline information collection through a relational database.

NextEra at 9 (“However, there is significant uncertainty about how this system would be implemented, and the initial burden of uploading and verifying data is likely to be significant.”).

TAPS at 5;

see also

Energy Ottawa at 5 (noting that P 66 n.67 of the NOPR clarifies that, consistent with Commission Order No. 816, certain QFs are not reportable assets).

ELCON and AFPA at 10.

38. Moreover, ELCON and AFPA assert that, when conducting the indicative screens, many Sellers conservatively include output from QFs, consistent with Commission-approved simplifying assumptions for market power and pivotal supplier analyses; but it is now not clear how these QFs would be treated in the relational database or the “populated” Asset Appendix.

ELCON and AFPA request that, given the apparent incongruity between requiring “all assets” in the relational database with exempting QFs from the indicative screen and asset appendix under Order Nos. 816 and 816-A, the Commission explicitly exclude QFs from the reporting obligations, or at a minimum provide guidance and clarification.

Id.

at 11 (“An additional complication may arise in a situation that requires relying on the accuracy of relational database submissions from other third-party `affiliates' being used to populate that [Sellers]' specific asset appendix.”).

c. Commission Determination

39. We adopt the proposals in the NOPR to require Sellers to submit asset appendix information in XML format and that each Seller would no longer report assets owned by its affiliates with market-based rate authority. We also adopt the proposal to require that a Seller include in its relational database submission any assets that are owned or controlled by an affiliate that does not have market-based rate authority.

See revisions to §§ 35.37(a)(1) and (a)(2).

40. As described in the NOPR, once a Seller identifies its own assets, the assets of its affiliates without market-based rate authority, and its ultimate upstream affiliate(s), the relational database will contain sufficient information to allow the Commission to identify all of that relevant Seller's affiliates (

i.e.,

those with a common ultimate upstream affiliate) to create a complete asset appendix for the Seller, which includes all of its affiliates' assets. Additional information concerning the mechanics of this process will be made available on the Commission's website.

41. The majority of commenters agree that the automation of the asset appendix is preferable to the alternative approach presented in the NOPR, which would have required Sellers to continue to provide information on all of their affiliates' assets when submitting asset appendix information to the relational database.

As EEI observes, the preferred alternative avoids repetitious filings and system overwrites if information is added or changed.

See, e.g.,

APPA at 10-11; GE at 15-16; NextEra at 11.

See

EEI at 19.

42. We are adopting the requirement that a Seller include, in its relational database submission, any assets that are owned or controlled by an affiliate that does not have market-based rate authority because without this requirement, information about these assets—which is relevant to the Seller's market power analysis—would be missing from the asset appendix, rendering the Seller's filing incomplete. We appreciate commenter concerns that the term “any assets” is broad. Therefore, we clarify that in this final rule “any assets” refers to assets that are reportable in the asset appendix: Generation assets, long-term PPAs, and vertical assets.

We disagree with EEI's contention that the proposal is too burdensome because this same information is currently required in the asset appendix. While it is true that in some circumstances Sellers in a corporate family can make a joint filing with one asset appendix that contains all affiliates and eliminates the need for each Seller to report the same non-MBR assets separately, this is not always the case. In many instances, corporate families file separately and thus submit separate asset appendices. In such cases, duplication already exists. An advantage to the new approach is that the data on the non-market-based rate affiliates will be stored in the database such that no further duplicate reporting will occur unless there is a change. We view EEI's alternative proposal of creating a new table focusing on non-market-based rate assets as presenting a greater burden on Sellers. As discussed below, we are creating a table structure that will allow a one-to-many relationship to exist between the gen_assets table, where all generators in the database will be uniquely identified, and the entities_to_genassets table,

where Sellers will report relationships between themselves (or their non-market-based rate affiliates) and the generators on the gen_assets table. Creating an additional table specifically to focus on the assets of non-market-based rate affiliates would create an unnecessary step and table.

This includes information on long term firm sales power purchase agreements, as discussed below.

We have renamed the “Entities to Generation” table as “entities_to_genassets.”

43. We appreciate EEI's contention that the software would have to be programmed to eliminate duplication if each Seller in a single corporate family includes the same non-market-based rate assets. The table structure is built to allow a one-to-many relationship to exist between the gen_assets table and the entities_to_genassets table.

When creating an asset appendix for a specific Seller, the software will be designed such that the asset appendix will only include the non-market-based rate affiliate asset information submitted by that Seller. It is important to note that the system will pull information from the relational database to create asset appendices unique to each Seller, rather than asset appendices that represent entire corporate families.

Stated another way, the table structure will allow for each generation asset to have many reported relationships.

As an example, Seller A and Seller B are both wholly owned subsidiaries of the same ultimate upstream affiliate, and are affiliated with Entity C, which does not have market-based rate authority. Seller A and Seller B will both submit information on their respective assets. In addition, Seller A and Seller B will both separately report information on Entity C's reportable assets. When an asset appendix is created for Seller A, it will contain the following asset information: For Seller A, the asset information that Seller A submitted for itself; for Seller B, the asset information that Seller B submitted for itself; and, for Entity C, only the asset information that Seller A submitted for Entity C. Similarly, when an asset appendix is created for Seller B, it will contain the following asset information: For Seller A, the asset information that Seller A submitted for itself; for Seller B, the asset information that Seller B submitted for itself; and, for Entity C, only the asset information that Seller B submitted for Entity C.

44. We will not adopt EEI's suggestion to rename the vertical assets table “Vertical Assets Owned by Filer.”

This would be misleading because Sellers are required to report not only their own vertical assets but also the vertical assets owned or controlled by their non-market-based rate affiliates. Contrary to EEI's statement, the NOPR proposal that a Seller include in its relational database submission any assets that are owned or controlled by an affiliate that does not have market-based rate authority, was not limited to generation assets or long-term PPAs, but also included vertical assets. The

identification of a Seller's non-market based rate affiliates' vertical assets is necessary to have a complete asset appendix and to allow the Commission to fully analyze a Seller's potential vertical market power.

However, as discussed in the Data Dictionary Section, we have renamed the vertical assets table the “entities_to_vertical_assets” table to reflect that Sellers will provide information on their relationships to their vertical assets.

45. Sellers will be able to report the assets of their non-market-based rate affiliates in the same XML submission that they use to report their own assets. However, Sellers will need to identify which affiliate owns/controls each reported asset using that affiliate's CID, LEI, or FERC generated ID. This will help to reduce duplication in the relational database and will allow the relational database to produce more accurate and complete asset appendices.

46. We agree with APPA and TAPS that the requirement for Sellers to report assets of their non-market-based rate affiliates should be explicit in the regulatory text and therefore revise the proposed amended § of 35.37(a)(2) to provide that Sellers must report information about the reportable assets of their non-market-based rate affiliates.

APPA at 10-11 n.26; TAPS at 22.

47. We are not changing existing Commission policy regarding exempt QFs and behind-the-meter generation. As the Commission held in Order No. 816, Sellers do not need to include such entities in their asset appendix or indicative screens.

To avoid discrepancies in the auto-generation of the asset appendix, Sellers should not include these assets as part of the relational database submission for market-based rate purposes.

Order No. 816, 153 FERC ¶ 61,065 at P 255.

48. We disagree with Independent Generation's statement that this approach takes control of the data out of the hands of Sellers. Although we are relieving Sellers of the burden of compiling complete asset appendices for their filings, Sellers remain in control of, and in fact have the responsibility to maintain, their data in the relational database. It is true that Sellers will not have control of their affiliates' data; however, as discussed below, we are putting in place measures for Sellers to report to the Commission any errors in their affiliates' submissions that affect the Sellers' asset appendices.

49. We do not find persuasive Independent Generation's and NRG's arguments that the time necessary to review and confirm the accuracy of the relational database constitutes a new burden. We appreciate that Sellers will have to spend time reviewing the accuracy of their information based on what their affiliates submitted. However, this additional burden is counterbalanced by the time savings attributable to the fact that Sellers no longer need to compile and submit information about the assets of their market-based rate affiliates. Further, the only place an affiliate's submission would affect a Seller is the asset appendix. As discussed below, when a submission is made to the database that causes a change in a Seller's asset appendix, a new asset appendix will be generated incorporating the change.

A Seller will have the ability, at any time, to access its latest asset appendix to verify its contents to stay abreast of any changes that have occurred.

The change could be the Seller or an affiliate submitting new, or updating, information that appears in the asset appendices such as its name, generation assets, PPAs, or vertical assets.

50. Independent Generation also raises a concern that Sellers would have to make additional submissions to correct any errors or omissions and that errors can continue to appear in subsequent filings. This is not necessarily the case. A Seller's asset information in the relational database will reflect the information the Seller submitted. To the extent that Sellers make errors or omissions when submitting data, they will be expected to make a subsequent submission to correct that error. When such corrections are made, future asset appendices will only contain the updated information. However, to the extent that Independent Generation shares NRG's concern that Sellers will not have any control over submissions by affiliates that may contain errors or may not be up to date, we note that Sellers will not be expected to correct their affiliates' data. If a Seller disagrees with information submitted by an affiliate that affects the Seller's asset appendix, the Seller should inform the Commission of that disagreement. Sellers will be able to inform the Commission in two ways. First, they can make note of any perceived errors in their transmittal letters. Second, the submittal process will include a commenting feature that will allow Sellers in their XML submissions to comment on the asset data of other Sellers.

This commenting feature will allow Sellers to submit a narrative explaining why they disagree with any of the information contained within the relational database regarding their affiliates' assets. Comments submitted in this manner will only appear on the submitting Seller's Asset Appendix and will not alter the information provided by that Seller's affiliate. This feature can be utilized when an affiliate's information is factually incorrect or is being reported in a manner inconsistent with a Seller's market power analysis and should detail the specific fields that are being disputed and reason for the dispute.

51. We understand Independent Generation's concern that it may not be a simple task for multiple affiliated entities to identify the same ultimate upstream affiliate(s) given complicated ownership structures. However, we believe the requirement to identify the ultimate upstream affiliate(s) represents an overall reduction in burden as Sellers are currently required to identify all affiliates, including their ultimate upstream affiliates and any intermediate upstream affiliates.

Further, each ultimate upstream affiliate in the relational database will have a CID, LEI, and/or FERC generated ID, which will be the means for Sellers to report the connection. The system will allow a Seller to search the database to see if its ultimate upstream affiliates have already been reported to the Commission, and if so, to retrieve each of those entities' CID, LEI, and/or FERC generated ID. This will reduce the likelihood that Sellers attempting to report the same ultimate upstream affiliate(s) inadvertently report different entities, preventing the relational database from making the appropriate connections. This should also lessen NRG's concern that the relational database could give the false impression of relationships between entities.

See

Order No. 697-A, 123 FERC ¶ 61,055 at n.258.

52. In response to concerns raised by NRG, Independent Generation, EEI, and FMP regarding the reporting of jointly owned assets, double-counting, and overwriting, we have revised the information to be set forth in the MBR Data Dictionary. Multiple Sellers will be able to report a relationship with a generation asset, and each Seller will also provide information specific to its relationship with that generation asset. As discussed below in the Reporting of Generation Assets section, only the information reported by a given Seller will be associated with that Seller in any asset appendix created from the relational database.

In cases where the joint-owners of a generation assets are affiliates, that generation asset may appear multiple times in an asset appendix.

53. We disagree with FMP's statement that the relational database would function as an adjudication machine. The relational database is not “deciding” which entities have a relationship, but rather is aggregating the relationship information provided to it by Sellers to depict the relationships between them. When the information in the relational database indicates that two entities are affiliated, it is due to affiliate information being submitted to the relational database. We reiterate that

to the extent that a Seller does not believe it has a relationship with an entity, the Seller will have the ability to correct the data. If the mistaken relationship is the product of an error not made by the Seller, the Seller will be able to explain its disagreement with the output of the relational database in its market-based rate filing.

54. Further, we are not delegating “first-step market-based rate adjudication” to the relational database. Applications for market-based rate authority, change in status filings, and triennial market power updates will continue to be evaluated according to the existing market-based rate regulations in public, docketed market-based rate proceedings. While Sellers will be submitting information to the relational database that may be used in market-based rate proceedings, the relational database does not adjudicate anything. Rather, as explained below, when Sellers are initiating a market-based rate proceeding, they will extract information from the relational database, verify it, and include it as part of their docketed, market-based rate filings.

55. We do not accept Working Group's suggestion that Sellers be able to choose how they wish to submit information into the asset appendix. That approach would disrupt the ability to use the information in the relational database to auto-generate accurate asset appendices and would result in the types of system overwrites and repetitious filings that we are seeking to avoid.

56. We appreciate comments requesting the opportunity to review the information input to the asset appendix before making the filing and have developed a submission and filing mechanism that will accommodate such review. As will be explained in more depth on the Commission's website, each Seller will first submit the required information into the relational database and an asset appendix will be generated for the Seller with a serial number that the Seller can reference in its market-based rate filing. The Seller will have the opportunity to review the asset appendix and, if necessary, make a submission to the relational database to address any errors. Next, when the Seller is comfortable with the asset appendix, it will reference in its transmittal letter the serial number of the asset appendix it wants included as part of its filing. However, the Seller must reference either its most recently created asset appendix or an asset appendix created fewer than 15 days before it makes its filing.

This approach will minimize the need to correct errors through amendments and should mitigate commenters' concerns in that regard.

This ensures that Sellers will submit accurate asset appendices as part of their filings. A new asset appendix will be created after the close of business for any Seller whose asset appendix is affected by a relational database submission made during business hours by it or one of its affiliates. Sellers will also have the ability to request the creation of a new asset appendix “on demand.” While we prefer that Sellers always reference their most recent asset appendix, we realize that Sellers may not know when their affiliates are going to make submissions that affect their asset appendices and that Sellers need an opportunity to review their asset appendix before making a filing.

2. Reporting of Generation Assets

a. Commission Proposal

57. In the NOPR, the Commission proposed two changes to the information required to be reported regarding generation assets. First, the Commission proposed to require that each generator be reported separately for purposes of the relational database and that Sellers report the Plant Name, Plant Code, Generator ID and Unit Code (if applicable) information from the Energy Information Agency (EIA) Form EIA-860 database. Second, the Commission proposed that Sellers be required to report in the relational database the “Telemetered Location: Market/Balancing Authority Area” and “Telemetered Location: Geographic Region” in which the generator should be considered for market power purposes when that location differs from the reported physical location.

b. Comments

58. GE and NextEra seek clarifications regarding the use of EIA-860 data. GE asks that to the extent a Seller is aware that the EIA data for its assets is inaccurate, that the Commission clarify whether the Seller should use the published EIA-860 data or whether it should submit to the Commission more up-to-date information known to it.

GE notes that EIA, at times, has two versions of their data available, “Final Data” which may be over a year old, and “Early Release” data which may not be fully edited. GE requests clarification as to which version of the data Sellers should use. NextEra requests that the Commission clarify that EIA-860 data need only be reported if available.

NextEra states that it is possible that a Seller may submit its initial application in advance of this information being entered into the EIA-860 database. Therefore, the Commission should clarify that such information, if unavailable at the time of filing, may be entered in the quarterly relational database update filing.

NextEra notes that, “[i]n addition to a delay in filing resulting from [the] burden in finding the employee responsible for submitting EIA-860 data,” the information has never before been needed by the Commission in accepting market-based rate filings. NextEra contends that the Commission did not provide rationale as to why including this information should be a condition precedent to acceptance of an application.

GE at 24-25.

NextEra at 12.

Id.

at 12-13.

59. EEI, EPSA, and FMP note that the EIA-860 database only includes generators with a nameplate rating of one MW or greater,

and EEI argues that Sellers should only be required to provide information on facilities with a nameplate rating of one MW or larger, as the EIA-860 database does not include information on any facilities smaller than one MW.

EEI at 21; EPSA at 29; FMP at DD Appendix 6-8.

EEI at 21.

60. EPSA argues that the requirement to provide unit-specific generation information constitutes a change in the rules governing market power analysis and is beyond the scope of this rulemaking.

EPSA at 29-30.

61. EPSA and Brookfield note certain concerns regarding the use of EIA codes. EPSA states that EIA nomenclature is impractical to collect for purposes of achieving a consistent, granular view into the asset mix in each Seller's filing and notes that some wind farms are identified under a single ID without distinction of individual turbines with their own plant names and plant codes, while other wind farms have IDs for each of their turbines.

100

Brookfield notes that it has at least one plant with multiple EIA plant codes and requests that the Commission allow multiple entries.

101

100

Id.

at 30.

101

Brookfield at 9.

62. Independent Generation seeks clarification on whether Sellers should pro-rate assets on a proportional basis or whether each Seller will be required to account for the full capacity of the unit in its market power analysis.

102

EEI and FMP recommend that the Commission add an option for “nameplate” in the adjusted capacity rating field of the data dictionary.

103

EEI and FMP note that

Order No. 816 stated that to the extent a Seller is attributing to itself less than a facility's full capacity rating, the Seller can explain this fact in the end notes column. In light of the “entities_genassets” table having an ownership percentage field, they ask the Commission to reconcile whether there is a need to explain the amount attributed in the ownership percentage field.

104

Designated Companies ask the Commission to clarify whether a Seller only reports one rating and how best to identify which season corresponds to which rating and which rating corresponds to the associated de-rating of a facility.

105

102

Independent Generation at 15.

103

EEI at DD Appendix 6-10; FMP at DD Appendix 6-8.

104

EEI at DD Appendix 6-10; FMP at DD Appendix 6-8.

105

Designated Companies at 18-19.

63. Others recommend that in-service date be changed to “in-service date if after final rule” because it is burdensome to locate the actual date in many cases (or a year or default date should be set).

106

Brookfield at 10; EEI at DD Appendix 6-10; FMP at DD Appendix 6-8.

c. Commission Determination

64. We adopt the NOPR proposal to require each generator to be reported separately for purposes of the relational database and that Sellers report the Plant Code, Generator ID, and Unit Code (if applicable) (collectively, EIA Code) information from the EIA-860 database. However, the Commission will capture the Plant Name from the EIA-860 database and therefore we will not require Sellers to report it to the Commission's relational database as had originally been proposed in the NOPR.

107

In response to comments that certain generators may not appear in the EIA-860 database, the Commission is creating a Commission Issued “Asset Identification” (Asset ID) number. Sellers will obtain Asset ID numbers for their generators that are not included in the EIA-860 database prior to making their relational database submission to the Commission.

108

Commission staff will maintain a look-up table containing EIA Codes and Asset ID numbers to help Sellers to find the appropriate Code or ID for their assets.

107

The Commission will also capture the nameplate capacity and operating year from the EIA-860 database.

108

When creating the Asset ID, Sellers will be required to provide basic information about the generator such as its plant name, nameplate capacity, and month and year it began commercial operation (if known).

65. We disagree with EPSA's comments that requiring Sellers to report generation units separately is a rule change impacting market power analysis. The requirement to report generators individually is a modification to the way assets should be reported to the Commission and not a change in how the generation assets are analyzed. The Commission's current rules allow Sellers to report their generation assets at either the plant or individual generator level. Requiring Sellers to report generators at the more granular generator level will reduce redundancy, reduce the need for explanatory notes in the relational database, and make the asset appendices more accurate. Further, the use of EIA-860 data and Asset IDs will make accessing and reporting generation data less burdensome for Sellers in some respects, as some of the current requirements are being eliminated (

e.g.,

nameplate capacity and in-service date) given that the Commission can obtain comparable information from the EIA-860 database using the Plant Code as well as the Generator ID, and Unit Code provided by the Seller.

66. We do not share EPSA and Brookfield's concerns regarding the use of EIA codes. The EIA-860 data is the most complete public database of generators available and can be relied upon to have accurate, detailed information on generation assets. We understand that there may be some instances where data is reported to EIA in an inconsistent manner.

109

In those instances, Sellers should use the most granular information possible and, if necessary, make use of the “end notes” field in the entities_to_genassets table to provide explanations where necessary. For example, if a Seller owns one turbine in a wind farm that reports to EIA all of the turbines under one Gen ID; the Seller should report the EIA Code with the single Gen ID, and explain in the end notes field that the Gen ID covers multiple turbines, but that the Seller only owns one turbine.

110

In the case of Brookfield's plant with multiple EIA codes, Brookfield will be able to report all of the relevant EIA codes.

111

109

This includes EPSA's wind farm example where some wind farms report the individual turbines as unique generators with their own Gen IDs, and others report the entire wind farm under one Gen ID.

110

As discussed below, the Commission will only retrieve from the EIA-860 certain basic information about the generator, such as nameplate capacity and operating year. Sellers will still provide information such as the adjusted capacity rating when they make their submissions. In that way, Sellers will be able to show if the actual amount of capacity they own is different than the EIA figure.

111

We are not sure if Brookfield is indicating that its EIA codes are redundant. However, to the extent that they are redundant and will result in inaccurate or duplicative entries in the asset appendix, Brookfield should explain in its narrative or end notes column.

67. We also adopt the NOPR proposal that Sellers be required to report the telemetered market/balancing authority area of their generation, but not the proposal to require Sellers to report the telemetered region of their generation.

112

As explained in the NOPR, providing the telemetered location will ensure that the Commission is able to properly match identified generators with the markets/balancing authority areas in which they are studied in a Seller's market power analysis. Providing the market/balancing authority area will be sufficient for the Commission to identify the region in which the generation is located.

113

112

We also clarify that Sellers are required to report the telemetered market/balancing authority area, even when it is the same as the physical market/balancing authority area. The NOPR contains an unclear statement, which could be read to suggest that Sellers only need to report the telemetered location when it differs from physical location.

See

NOPR, 156 FERC ¶ 61,045 at P 36.

113

This is true for other tables in the MBR Data Dictionary where the NOPR proposed to require both the market/balancing authority and region. We have accordingly revised those tables to only require the market/balancing authority area. The Commission will also be able to determine if a generator is in Canada, Mexico, or ERCOT by using the reported market/balancing authority area.

68. The MBR Data Dictionary will have multiple generation-related tables. The gen_assets table will store the basic information about all of the generators in the database, such as the generator's name, nameplate capacity, and in-service date. This information will be populated by the information from EIA-860 or the information provided by Sellers' when they request an Asset ID. Sellers will not submit information directly to the gen_assets table when updating the database. Instead, Sellers will update the entities_to_genassets table with the information pertinent to their (or their non-MBR affiliate's) relationship to the generation asset. This includes information on the type of relationship (ownership or control), the generator's location (physical and telemetered), de-rated capacity of the facility and de-rating methodology used, the actual amount of capacity controlled, and any explanatory notes.

69. We have restructured the tables in response to concerns about joint-ownership and overwriting of data. This structure will allow for more than one Seller to report a relationship with a specific asset. However, only the details that the Seller assigns to the generation asset via its submissions will appear on that Seller's entry in the asset appendix.

114

As an example, Seller A

and Seller B can both report a relationship with Generator X. Seller A can report via the entities_to_genassets table that the capacity rating of Generator X is 20 MW; and Seller B can report via the entities_to_genassets table that the capacity rating of Generator X is 25 MW. When an asset appendix is created for Seller A (or an affiliate of Seller A), there will be a row containing Seller A's relationship with Generator X that will reflect Seller A's capacity rating of 20 MW. Similarly, for a Seller that is an affiliate of both Seller A and Seller B, its asset appendix will have two separate rows for Generator X: One to report its relationship to Seller A (with the 20 MW capacity rating) and a second to report its relationship to Seller B (with the 25 MW capacity rating).

114

However, the Plant Name, Nameplate Capacity, and Operation Date information will be

pulled from EIA-860 or provided when Sellers seek an Asset ID.

70. This solution should resolve many of the concerns about the accuracy of the EIA data. The Commission will only rely on EIA data (or information input when creating an Asset ID) for basic information about generation assets such as Plant Name, Nameplate Capacity, and In-service Date.

115

The rest of the information in the asset appendix will be provided by Sellers. If a Seller believes the Plant Name, Nameplate Capacity, or In-service Date for one of its generation assets is incorrect, the Seller will be able to note the error in its transmittal letter or use the commenting feature discussed above.

115

The EIA data contains “operational month” and “operational year” fields, which the Commission will use for In-Service Date information.

71. In response to NextEra, we clarify that EIA-860 data need only be reported if available. However, if EIA-860 data is unavailable for a generation asset, the Seller should check to see if another Seller has obtained an Asset ID for that generation asset, and, if not, obtain an Asset ID for that generation asset. If, at a later date, EIA-860 data becomes available for that asset, the Seller should update its relationship to that generation asset to provide the EIA information in its next monthly database submission.

116

We disagree with NextEra's contention that the burden associated with finding the employee responsible for submitting the EIA-860 data will cause a delay. First, the only EIA-860 data that Sellers will be responsible for submitting into the relational database is the Plant Code, Generator ID, and Unit Code, which is necessary to identify which generation assets the Seller is referencing when submitted the entities_to_genassets table. Sellers will not have to resubmit this information in advance of every market-based rate filing. Instead, Sellers will report all of their generation assets (as well as the assets of any affiliates without market-based rate authority) when making their baseline or initial submissions. We anticipate that most Sellers will not have to provide additional asset information after submitting their baseline or initial submissions. However, in cases where a Seller does need to add, remove, or update information on a generation asset, it will be able to do so without having to resubmit information for all of its generation assets. Rather, it will only have to resubmit/update the information for that specific generation asset.

116

The monthly relational database submissions are discussed in the Ongoing Reporting Requirements section of this final rule.

72. In response to GE, we clarify that Sellers should use the latest available “Final Data” from EIA. When the Final Data is released, the Commission will update the relevant information in the reference tables because, as GE notes, the “Early Release” data may be incomplete.

73. In response to comments regarding the need for clarity in reporting generation asset capacity, we have added an option for “Nameplate” under the adj_rating_options field in the entities_to_genassets table.

74. We clarify that Sellers should not pro-rate assets on a proportional basis when submitting the de-rated capacity of an asset in the cap_rating_adjusted field.

117

In response to EEI and FMP, we further clarify that there is no longer a need for a Seller to explain in the end notes fields that it is attributing to itself less than the full amount of a facility. However, a Seller will not provide its attributable capacity in the ownership_percentage field, as we have removed that field. Instead, we have added an “amount” field to the new entities_to_genassets table in the MBR Data Dictionary. In the amount field, Sellers will provide the megawatts controlled by the entity that it is reporting as controlling the asset.

118

Further, in response to Independent Generation, we clarify that Sellers will not be required to account for the full capacity of the unit in their market power analysis. While Sellers may conservatively assume in their market power analyses that they own or control the full output of a facility, they are only required to attribute to themselves the actual energy and/or capacity that they and their affiliates own or control.

117

As noted above, the nameplate capacity for assets in the EIA-860 will be populated from the EIA-860 database and the nameplate capacity for assets with Asset IDs will be inserted when the Asset ID is created.

118

The total in the amount field should be calculated using the same capacity rating methodology used to find the total de-rated capacity of that generator. If the reported entity does not control the generation asset, the Seller should input “0” as the amount.

75. In response to Designated Companies, we clarify that Sellers will only report one rating in the cap_rating_adjusted and amount fields. The cap_rating_adjusted and adj_rating_options fields are analogous to the “Capacity Rating Used in Filing (MW)” and “Capacity Rating: Methodology Used” columns created in Order No. 816, and modified in Order No. 816-A, and should be populated in the same manner.

76. We deny requests to change “in-service date” to “in-service date if after final rule.” First, in-service date information is currently required in Sellers' asset appendices and is not a new requirement. Also, as noted above, for entities with EIA codes, the Commission will obtain the operational month and operational year information from the EIA database. Therefore, Sellers will only have to provide the in-service date for assets for which they are requesting an Asset ID. To the extent that Sellers do not know the precise in-service date for an asset for which they are requesting an Asset ID, they may use a default date of January 1, 2020 or, if they know the year, but not the month and date, they may use the appropriate year and assume January 1 as the month and day.

119

Similarly, if they know the month, but not the actual date, they can use the first day of the month.

3. Power Purchase Agreements

a. Commission Proposal

77. In addition to long-term firm purchase agreements, the Commission proposed to require Sellers to submit into the relational database information on long-term firm sales (

i.e.,

those one year or longer) agreements. The Commission stated that to the extent that a Seller believes there are any unique qualities of the contract that would not otherwise be captured by the relational database, the Seller is free to explain this as part of its horizontal market power discussion.

b. Comments

78. EEI and Independent Generation oppose the proposal to require Sellers to include information on long-term firm sales in the PPAs table.

120

They argue that the proposal is duplicative of sales information already reported through

EQR.

121

EEI disagrees that the requirement will improve consistency in reporting between purchasers and Sellers. According to EEI, Sellers often sell to, and purchase power from, non-jurisdictional assets such that the purchases and sales will not match up.

122

EEI states that the requirement to report long-term firm sales would violate the Paperwork Reduction Act and the Office of Management and Budget (OMB) prohibitions against duplicative collections of data.

123

120

EEI at 19; Independent Generation at 15.

121

EEI at 19, 20; Independent Generation at 15.

122

EEI at 20.

123

Id.

(citing Paperwork Reduction Act of 1980, Pub. L. 96-511, 94 Stat. 2812, 44 U.S.C. 3501-352; Paperwork Reduction Act of 1995, Pub. L. 104-13, 109 Stat 163).

79. If the Commission retains the requirement to report long-term sales agreements, EEI and GE state that additional clarity is needed as to: (1) Whether the sales reporting obligation is parallel to purchases in that purchases must have associated firm transmission;

124

(2) how to complete the amount field for full and partial requirements contracts;

125

(3) whether a heat rate call option should be reported; and (4) whether system contracts or just unit-specific contracts are intended to be captured.

126

EEI states that, as with PPA data, there is considerable confusion as to the requirement in Order No. 816 that asset appendices be both current and reflect triennial data from the study period.

127

124

Id.

at 20 & n.45 (“If the obligation is parallel, the Commission must address how the Seller would be expected to know this information. And if the obligation is not parallel, it raises the question of the need for the information as it could not be used for matching purposes.”).

125

Id.

at 20; GE at 30.

126

GE at 30.

127

EEI at 20-21.

80. AVANGRID, and ELCON and AFPA request clarification on the NOPR proposal that if a Seller believes there are any unique qualities of the contract that would not otherwise be captured by the relational database, the Seller is free to explain this as part of its horizontal market power discussion.

128

They state that the NOPR provides little guidance on the characteristics of a contract that would be sufficiently unique to report,

129

and that the Commission should clarify that this obligation applies only to market-based rate-related filings and should identify the need for, and define, the sort of unique qualities to which the NOPR refers.

130

128

AVANGRID at 13; ELCON and AFPA at 13 (citing NOPR, 156 FERC ¶ 61,045 at P 37).

129

AVANGRID at 13.

130

ELCON and AFPA at 13.

81. AVANGRID also states that it is unclear when the “multi-lateral contract identifier” row would apply and what information needs to be listed and that the table requests filing entities identify the date of last change of a contract, but it is unclear if a filing entity is required to track and report all changes, even minor, non-substantive revisions and corrections.

131

AVANGRID at 13.

82. EEI strongly objects to the reporting of the source of supply for long-term PPAs.

132

EEI argues that it is unclear as to what data is being sought, and requires analysts to review contracts on an individual basis to gather the data, which are not collected elsewhere. EEI states that this is the type of requirement that cannot and should not be imposed without reissuing the NOPR to explain what is being required and its purpose.

133

132

EEI at 21. EEI notes that Commission staff explained at the Workshop that it wanted to expand Source reporting beyond a unit-specific power purchase agreement to system sales.

133

Id.

at 21-22.

83. EEI explains that the Commission should recognize that there are data elements specific to PPA sellers that purchasers may not have contractual rights to receive, which are necessary in order to meet the new reporting requirements and that, therefore, the Commission should apply a “reasonable efforts” standard.”

134

Id.

at 22.

84. Several commenters requested clarifications regarding the definition of, and reporting requirements related to, power purchase agreements.

135

See e.g.,

Duke at 2 n.4; GE at 30.

c. Commission Determination

85. We adopt the NOPR proposal to require Sellers to include information on long-term firm sales. Collecting information on long-term firm sales will help the Commission ensure that purchasers and sellers report and treat transactions in a consistent and accurate manner. It will also allow for corroboration of the long-term sale information in the indicative screens and delivered price tests, in a manner similar to installed capacity and long-term purchases.

86. We will maintain the definition of long-term firm sales established in Order No. 816.

136

Sellers will be required to report sales that are both long-term and firm. Long-term is defined as sales for one year or longer. Firm means a “service or product that is not interruptible for economic reasons.”

137

As discussed more below, long-term firm sales will be reportable even if they do not have associated firm transmission.

136

Order No. 816, 153 FERC ¶ 61,065 at PP 39-44.

137

This is consistent with the definition of firm used in the EQR Data Dictionary and for long-term firm purchases.

See

Order No. 816, 153 FERC ¶ 61,065 at P 43.

87. In regard to long-term firm sales, Sellers will be required to provide to the relational database the identity of the counter-party (using a CID, LEI, or FERC generated ID), the type of sale,

138

relevant dates, the amount, relevant de-rating information, and the source market/balancing authority area.

139

We note that the source market/balancing authority area will be required for all long-term firm sales.

138

Type of Sale can be Unit Specific, Slice of System, or Portfolio.

139

For unit-specific sales, Sellers will know the location of their generators. The source for slice of system sales will be the market/balancing authority area where the Seller's system is located. Sellers will identify all markets/balancing authority areas if generation is sourced from more than one area. If the source for a portfolio sale is generation purchased at a hub, and the location of the generation supplying the energy/capacity is unknown, sellers will provide the hub name.

88. We disagree with EEI's statement that the collection of this information here and in the EQR is a violation of the requirements of the Paperwork Reduction Act and OMB prohibitions against duplicate collection of data. While Sellers may report to the relational database some of the same contracts that they will report in their EQRs, the information is not unnecessarily duplicative. First, this data collection captures information on long-term firm purchases and sales, while the EQR only collects sales information. Further, where the EQR and this data collection have overlapping information

i.e.,

agreement identifier, identities of parties, source and sink information, and contract start and end dates, this information is necessary for several reasons.

89. The power purchase agreement identifier, although similar to the EQR contract service agreement identifier, is different in that this unique identifier will remain assigned to a particular agreement in perpetuity whereas the EQR contract service agreement ID field does not necessarily retain the same identifier over different quarters.

140

Regarding fields that serve to identify the parties to an agreement, this is not a direct overlap as the EQR relies on counterparty/purchaser names while the relational database relies on unique identifiers, such as CID, LEI, and FERC

generated ID, which are more precise and will help prevent a single entity from being reported with multiple names.

140

There is currently no requirement for the contract service agreement ID field in the EQR database to remain constant across every quarterly submission, making it difficult in some cases to consistently map a PPA with a contract reported through EQR. The Commission will continue to be mindful of opportunities to minimize overlap in the future.

90. In addition, Sellers currently are required to provide information regarding their counterparties to long-term firm purchases as part of their asset appendix. This final rule extends the PPA reporting to long-term firm sales. Similarly, information concerning the source and sink information of long-term firm purchases is already required to be reported in a Seller's asset appendix; we are merely altering the format in which the information is submitted and extending the requirements to long-term firm sales.

141

This information will allow the Commission to ensure that Sellers attribute the capacity associated with these PPAs to the appropriate markets/balancing authority areas when performing market power analyses.

142

Similarly, the end date is necessary to remove a PPA from a Seller's asset appendix upon its actual expiration.

141

See

Order No. 816-A, 155 FERC ¶ 61,188 at P 61; 18 CFR 35, Subpt. H, App. A. The reporting requirements in Order Nos. 816 and 816-A were approved by OMB on December 22, 2015 and July 21, 2016 (OMB Control No. 1902-0234).

142

We also note that the analogous EQR point of receipt and point of delivery balancing authority area fields are only required to be reported in EQR if specified in a contract.

91. There is also a time differential between the EQR reporting requirement and the long-term firm sales information required in a Seller's asset appendix. EQRs are submitted quarterly and the EQR submission obligation begins after a Seller receives market-based rate authority. In contrast, a Seller will have to provide information to this database prior to obtaining market-based rate authority, because it is necessary to create the asset appendix and to analyze the Seller's indicative screens.

92. Furthermore, the relational database submission requires certain information that is not contained in the EQR submission,

e.g.,

supply type and supply identifier, and Sellers will be able to include in their relational database submissions the de-rated capacity of their unit-specific contracts, information that is not reported in EQRs. This will allow the Commission to more accurately review Sellers' indicative screens, which often reflect de-rated capacity numbers. Moreover, information on long-term firm sales made by certain non-jurisdictional public utilities is not reflected in EQRs

143

but must be reported in the relational database as a long-term firm purchase in the Seller's asset appendix. Further, where similar data are required in both the EQR and the instant proceeding, we have deliberately harmonized the definitions of that data to simplify the data gathering aspect of the requirement.

143

Only non-public utilities above the

de minimis

market presence threshold are required to report their wholesale sales in the EQR, subject to certain reporting exclusions.

93. In response to EEI, we clarify that the long-term sales reporting obligation is not parallel to purchases in that purchases must have associated firm transmission. We understand that the Seller may not always know if the buyer has procured firm transmission. To EEI's question about the need for this information, as stated above, this information will allow the Commission to corroborate the long-term sales information in the indicative screens and delivered price tests.

94. In response to EEI and GE, we clarify that Sellers should complete the amount field for full and partial requirements contracts. For a full requirements contract, the amount should equal the buyer's most recent historical annual peak load. For a partial requirements contract, the amount should equal the portion of the buyer's requirements served by the seller multiplied by the buyer's annual peak load. For example, if the Seller supplies 50 percent of the buyer's requirements, it should multiply the buyer's annual peak load by 0.5 and place this value in the amount field.

95. We also clarify that Sellers' asset information, including long-term firm sales and purchase data, should be current in the relational database. The Commission's expectation has always been that the information in a Seller's asset appendix should be current. We recognize that at times this may create a data disconnect with the study period of a market power analysis. However, the Commission provided guidance on this issue in Order No. 816.

144

Order No. 816, 153 FERC ¶ 61,065 at PP 289-294.

96. In regard to long-term firm purchases, Sellers will be required to report to the relational database information on the counter-party (by providing a CID, LEI, or FERC generated ID), the type of purchase,

145

relevant dates, the amount, relevant de-rating information, and the sink market/balancing authority area.

146

In response to comments, we are not requiring Sellers to report the source market/balancing authority area for their long-term firm purchases. Source information for long-term firm purchases may provide useful information, but it is not critical to the Commission's examination of a specific Seller's market power. For that purpose the sink market/balancing authority area is more relevant, because that is where the Seller should study that energy/capacity.

145

Type of purchase can be Unit Specific, Slice of System, or Portfolio.

146

If the sink is a hub, Sellers will identify the hub.

97. We decline to adopt a “reasonable efforts” standard for data elements specific to PPAs as EEI suggests. Sellers are already reporting substantially all of this information in their asset appendices pursuant to Order No. 816-A.

147

The only additional information that Sellers will need to provide regarding their long-term firm purchases is the counterparty's CID, LEI, or FERC generated ID, de-rated capacity rating and details on their de-rating methodology (if they use a de-rating methodology), and two additional dates. This is information that should be available to Sellers with long-term firm purchases. As discussed in the Due Diligence section of this final rule, Sellers are subject to § 35.41(b) of the Commission's regulations when providing information to the Commission and are expected to exercise due diligence to ensure the accuracy of their submissions, including reporting the data elements specific to PPAs.

147

As revised in Order No. 816-A, the LT Firm Power Purchase Agreement sheet of the Asset Appendix requires Sellers to provide the following information for each reported purchase agreement: Seller (counterparty) Name, Amount of PPA, Source Market/balancing authority area, Sink Market/balancing authority area, Sink Geographic Region, Start Date, End Date, Type of PPA (Unit or System), and any relevant end notes.

98. In response to AVANGRID, and ELCON and APPA's requests for guidance on how to populate the “contractual details” row in the PPA table of the MBR Data Dictionary, we have replaced the “contractual details” row with an “explanatory notes” field. The “explanatory notes” field will work the same as the “End Notes” sheet in the current asset appendix, allowing Sellers to provide additional information or clarifications regarding the reported PPA if they desire to do so.

148

See

Order No. 816, 153 FERC ¶ 61,065 at P 267.

99. In response to AVANGRID's comment, we have removed from the MBR Data Dictionary the “multi-lateral contract” row. Given our decision to not pursue the Connected Entities requirements and associated required contract information, and our revisions to the MBR Data Dictionary in regard to the reporting of long-term firm purchases and sales, this row is no longer necessary.

100. We need not provide in this final rule additional clarifications regarding the definition and reporting thresholds for long-term power purchase agreements. The definitions and thresholds established in Order No. 816 continue to apply.

149

See id.

PP 130-45,

order on reh'g,

Order No. 816-A 155 FERC ¶ 61,188 at PP 26-28.

4. Providing EIA Codes for Unit-Specific Power Purchase Agreements

a. Commission Proposal

101. The Commission proposed that for unit-specific power purchase agreements, Sellers must provide the associated Plant Code and Generator ID from the Form EIA-860 database, which will provide the unique identifier for that unit.

b. Comments

102. EEI and EPSA oppose this proposal, arguing that it is burdensome when the filing entity is the purchaser.

150

EEI argues that a purchaser has no basis for knowing such information and should not be tasked with searching for it.

151

EPSA states that this proposal would not provide the Commission with useful information and that the EIA data is not granular enough to tie all specific units within a facility to specific PPAs.

152

150

EEI at 21; EPSA at 31.

151

EEI at 21.

152

EPSA at 31.

103. EPSA expresses concerns that EIA data does not provide useful tracking information regarding which entities control specific units within a facility, making it difficult to identify which PPAs and off-takers are tied to specific units within a facility.

153

EPSA comments that some units may have more than one PPA and more than one off-taker, and all potential off-takers share the energy produced by the entire facility; and that in other instances a sales contract may tie a specific off-taker to a specific turbine. EPSA states that there is confusion about the reporting of geographic region for generation units that serve multiple regions.

154

EPSA notes that some units in a plant may be pseudo-tied to another region, while others may not. According to EPSA, if EIA does not have separate generator IDs for each unit, it will be impossible to break down these unit commitments using EIA nomenclature.

155

153

Id.

at 30.

154

Id.

155

Id.

c. Commission Determination

104. We adopt the proposal that, for unit-specific power purchase agreements, Sellers must provide the associated EIA Codes or FERC Asset IDs, which will provide the unique identifier for that unit. This requirement will apply to both unit-specific sales and unit-specific purchases. Providing this information will allow the Commission to match reported long-term purchases and sales to ensure that generators are ascribed to the appropriate Sellers in market-power analyses. While we understand that the Commission and Sellers will not be able to match all reported purchases to a reported sale,

156

there is value in maximizing the instances that it can be done and in having corroborating data wherever possible.

156

For example, this could occur where a Seller makes a purchase from an entity that is not a Seller and thus is not required to submit any information to the relational database.

105. We disagree with EPSA and EEI's comments that providing this information on purchases is burdensome for Sellers; and we also disagree with EEI's argument that Sellers have no basis to know this information regarding their purchases and should not be tasked with searching for it. First, the Commission already requires Sellers to track and report information about their purchases under unit-specific long-term PPAs pursuant to Order No. 816-A.

157

We reiterate that this requirement is only for unit-specific purchases. If the PPA is not tied to a specific generator, then Sellers will not have to provide this information. If a Seller is entering into a PPA to purchase power from a specific generator, the Seller should know from which generator it is purchasing, and we do not believe it is burdensome for the Seller to report this information.

157

Order No. 816-A, 155 FERC ¶ 61,188 at P 25 (“We also clarify that the generation capacity associated with a unit-specific long-term contract should be reported in the `Notes' portion of the asset appendix.”).

106. EPSA's concern regarding the use of EIA data to track information regarding the PPAs is misplaced. The Commission does not plan to use the EIA data (or FERC Asset IDs) to track information about the off-takers under a particular PPA. Rather, Sellers will provide the details of their long-term PPAs, including the identity of the relevant counter-parties and off-takers. The EIA data, or relevant Asset IDs, will merely serve as identifiers for generators in unit-specific purchases or sales.

107. In regard to EPSA's concern that certain units may have more than one PPA and more than one off-taker, we clarify that it is acceptable for a specific generator to have multiple purchase agreements with multiple counter-parties and we have designed the database to allow generators to be associated with multiple reported PPAs. If EPSA's concern is that a Seller may be attributed an incorrect amount of generation in its asset appendix, we note that the Seller itself will input into the relational database the amount of generation or capacity that should be attributed to it.

158

Further, to the extent that Sellers want to provide further explanation, there will be a place for explanatory notes, similar to current Asset Appendices.

158

In addition, the Seller will be providing its own indicative screen information and horizontal market power analysis, which will reflect the amount of capacity that the Seller is attributing to itself and its affiliates.

5. Vertical Assets

a. Commission Proposal

108. The Commission proposed to eliminate the requirement that Sellers provide specific details about their transmission facilities in their asset appendices. Instead, the Commission proposed that Sellers only report in the relational database whether they have transmission facilities covered by a tariff in a particular balancing authority area and region. With respect to the natural gas pipeline information, the Commission proposed to revise the requirements so that a Seller will only be required to indicate for purposes of the relational database whether it owns natural gas pipeline and storage facilities, and if so, to identify in which balancing authority area and region those assets are located.

b. Comments

109. We did not receive any comments opposing this requirement. However, EEI argues that the Commission should determine that the reporting of affiliates, ownership, and Vertical Assets by XML eliminates the need for narratives on these subjects in market-based rate filings.

159

EEI argues that textual descriptions and lists of assets and affiliates should no longer be required and, if the final rule requires the same information in narrative and in XML, it violates OMB prohibitions and the Paper Reduction Act.

160

Conversely, TAPS argues that the Commission should maintain an ongoing narrative reporting of sufficient information concerning certain aspects of the market-based rate corporate family to monitor and ensure that the relational database is working and that the Commission possesses the necessary

information to perform its required market-based rate oversight.

161

159

EEI at 22.

160

Id.

161

TAPS at 9-11.

c. Commission Determination

110. We adopt the proposal to eliminate the requirement that Sellers provide specific details about their transmission facilities and only require Sellers to submit into the relational database information as to whether they have transmission facilities covered by a tariff in a particular balancing authority area.

162

Additionally, we adopt the proposal that for purposes of the database, a Seller only needs to indicate, if applicable, that it owns natural gas pipeline and/or storage facilities and identify in which balancing authority area those assets are located.

162

In line with our determination on the reporting of generation assets, Sellers will not need to report the region their transmission, or other vertical assets are located. Providing the market/balancing authority area will be sufficient for the Commission to identify the region in which the assets are located.

111. Further, we will maintain the requirement that Sellers provide a narrative on their vertical assets, affiliates, and ownership in their market-based rate filings.

163

Thus, we are not proposing to revise the vertical market power requirements in §§ 35.37(d) and (e). As TAPS notes, requiring a description of ultimate upstream affiliates and affiliates relevant to the horizontal and vertical market power analyses as a supplement to the information in the relational database will ensure that the database includes the information necessary for market-based rate authorization purposes and for ensuring that the new relational database functions properly.

164

163

The need for narratives in regard to ownership is addressed below in the Ownership Information section.

164

TAPS at 11.

B. Ownership Information

1. Commission Proposal

112. In Order No. 697-A, the Commission stated that Sellers seeking to obtain or retain market-based rate authority must identify all upstream owners and describe the business activity of its owners and whether they are involved in the energy industry.

165

In carrying forward and superseding the proposals in the Ownership NOPR,

166

the Commission proposed in this NOPR proceeding to reduce and clarify the scope of this requirement such that Sellers would only need to provide for market-based rate purposes information on a subset of upstream affiliates (

i.e.,

entities that fall within the definition of affiliate found in 18 CFR 35.36(a)(9)(i)).

167

This subset would include upstream affiliates that either: (1) Are an “ultimate upstream affiliate,” defined as the furthest upstream affiliate in the ownership/control chain; or (2) have a franchised service area or market-based rate authority, or directly own or control generation; transmission; intrastate natural gas transportation, storage or distribution facilities; physical coal supply sources or ownership of or control over who may access transportation of coal supplies.

168

165

Order No. 697-A provides: “A seller seeking market-based rate authority must provide information regarding its affiliates and its corporate structure or upstream ownership. To the extent that a seller's owners are themselves owned by others, the seller seeking to obtain or retain market-based rate authority must identify those upstream owners. Sellers must trace upstream ownership until all upstream owners are identified. Sellers must also identify all affiliates. Finally, an entity seeking market-based rate authority must describe the business activities of its owners, stating whether they are in any way involved in the energy industry.” Order No. 697-A, 123 FERC ¶ 61,055 at n.258.

166

Ownership NOPR, 153 FERC ¶ 61,309.

see also

ELCON and AFPA at 9.

172

ELCON and AFPA at 9.

116. NextEra requests clarification of the proposed requirement that Sellers identify all upstream affiliates with market-based rate authority and other upstream affiliates that directly own or control generation. NextEra suggests that the Commission require Sellers to identify all affiliates relevant to the specific market power analysis but allow Sellers to identify other upstream affiliates by reference to the relational database.

173

NextEra at 13-14.

117. In light of the Commission's proposal to require the reporting of affiliates and ownership information through the relational database, EEI and SoCal Edison request that the Commission eliminate the need for narratives on these subjects in new market-based rate applications, triennial filings, and change-in-status filings.

174

EEI adds that if the same narratives are required in addition to the information submitted in XML format into the relational database, the proposal would violate the requirements of the Paperwork Reduction Act and OMB's prohibitions against duplicative collection of data.

175

174

EEI at 22; SoCal Edison at 1.

175

EEI at 22.

118. TAPS requests that the Commission require that Sellers provide information identifying and describing all upstream affiliates, including intermediate upstream affiliates, which it describes as the “trunk” of the corporate family tree. TAPS is concerned that if the relational database does not work as planned, “the Commission will be left with pieces of trees and no backup information as to

whether and how they fit together.”

176

TAPS is also concerned that the relational database is vulnerable to the reporting errors of a few entities causing ripple effects that undermine its accuracy.

177

For example, TAPS describes a hypothetical where an ultimate upstream affiliate of several Sellers is a hedge fund that owns 10.1 percent of their common parent holding company. If the hedge fund sells off 0.2 percent of the parent holding company, it would fall below the 10 percent threshold under the definition of “affiliate” and would no longer be the ultimate upstream affiliate of the commonly owned Sellers. TAPS submits that not all of the affiliates Sellers may notice and report this subtle change in ownership, and, as a result, the relational database would no longer recognize the relationship between the affiliated Sellers who properly updated their ultimate upstream owner status and those that did not.

178

176

TAPS at 9.

177

Id.

at 19.

178

Id.

at 20.

119. Most commenters support the Commission's proposal to eliminate the organizational chart requirement, claiming that the proposal will reduce burden on Sellers.

179

However, TAPS requests that Sellers be required to submit an organizational chart but propose that the chart “would include only upstream affiliate owners and those affiliates required to be included in [sic] market power analysis—not all of the entities required in the organizational chart the Commission adopted in Order No. 816.”

180

179

AVANGRID at 7; Independent Generation at 15.

180

TAPS at 10.

120. Regarding the proposal to assign unique identifiers to a Seller's upstream affiliates and publish this information on the Commission's website, Designated Companies state that if the relationship of a Seller with an upstream affiliate is privileged, it is appropriate that the identity of the upstream affiliate also remain non-public.

181

Designated Companies at 5.

3. Commission Determination

121. We will adopt the NOPR proposal to require that, as part of its market-based rate application or baseline submission, a Seller must identify through the relational database its ultimate upstream affiliate(s).

182

Because this is a characteristic the Commission will rely upon in granting market-based rate authority, Sellers must also inform the Commission when they have a new ultimate upstream affiliate as part of their change in status reporting obligations, consistent with the NOPR proposal, which we adopt and codify in § 35.42(a)(1)(v). Any new ultimate upstream affiliate information must also be submitted into the relational database on a monthly basis, as discussed further in the Ongoing Reporting Requirements section of this final rule.

182

See revisions to §§ 35.37(a)(1) and (a)(2) of the Commission's regulations. Existing Sellers must submit their ultimate upstream affiliate information into the relational database as part of their baseline filings, as discussed in Initial Submissions section.

122. Beyond a Seller's ultimate upstream affiliate(s), the Commission proposed to require Sellers to report a second category of upstream affiliates, specifically, those upstream affiliates that: (a) Have a franchised service area or market-based rate authority; or (b) directly own or control generation; transmission; intrastate natural gas transportation, storage or distribution facilities; physical coal supply sources or ownership of or control over who may access transportation of coal supplies.

183

We will not require submission of this second proposed category of ownership information because, as noted by commenters, any such assets, and thus their respective owners/controllers, are already captured in the Seller's narrative and asset appendix as part of the demonstrations that a Seller must make to show a lack of horizontal and vertical market power.

183

NOPR, 156 FERC ¶ 61,045 at P 25.

123. We have considered TAPS's request to require additional upstream affiliate information, but find that this would impose an unjustified burden on Sellers in light of the ability to use information in the relational database to discover affiliates through Sellers' reporting of a common ultimate upstream affiliate. We recognize that this may present some risk of reporting errors in the case described by TAPS of a subtle change in ownership percentage resulting in new ultimate upstream affiliates that may not be universally noticed and reported by all affiliated Sellers. However, we believe that these errors can be identified and addressed when a Seller views its auto-generated asset appendix.

124. Additionally, we adopt the proposal to remove the requirement for Sellers to submit corporate organizational charts adopted in Order No. 816. Because each Seller is required to identify in the database their ultimate upstream affiliate(s), the Commission will be able to create an organizational chart for each Seller that identifies both its ultimate upstream affiliates and its affiliates with market-based rate authority. Therefore, we reject TAPS's request that the Commission maintain a requirement that Sellers provide a chart of all upstream affiliate owners in their narrative. The organizational chart that the Commission will be able to create using information in the database is sufficient to allow the Commission to understand the connection between affiliates, as well as the relevant assets for a Seller's market power analysis. The regulatory changes proposed in the NOPR and adopted herein remove references to the organizational chart requirement in 18 CFR 35.37(a)(2) and 35.42(c).

125. We disagree with EEI and SoCal Edison that the submission of ownership information in the relational database obviates the need for such information in a Seller's market-based rate narrative and that continuing to require it violates the Paperwork Reduction Act and OMB's prohibitions against duplicative collection of data. The NOPR proposals contained minimal overlap of the information submitted in the narrative and into the database, and our determinations in this final rule further reduce this overlap by requiring less ownership information in the database.

126. However, as revised in this final rule, the only ownership information that Sellers will provide to the relational database is the Seller's ultimate upstream affiliate(s), information that is necessary to generate the asset appendix, which, together with the indicative screens, constitutes a portion of the Seller's horizontal market power analysis.

184

A complete horizontal market power demonstration should also identify the Seller's ultimate upstream affiliate(s), which will not be evident from the asset appendix that is produced as part of the record in the market-based rate proceeding. Accordingly, we will continue to require a narrative description of a Seller's ownership structure, which identifies all ultimate upstream affiliates whenever the Seller submits a market power analysis, as set forth in revisions to § 35.37(a)(2). This information will be readily evident to the Seller and will not present an increase in burden.

184

Portions of the asset appendix are also part of the Seller's vertical market power analysis.

127. Further, although some ownership and affiliate information will be discoverable from the relational database and placed into the Seller's asset appendix, which will become part of the record in the market-based rate proceeding, it does not specifically identify all affiliates relevant to the

market power analysis.

185

Therefore, any ownership or affiliate relationship information that has a bearing on a Seller's horizontal and vertical market power analyses—and that is not otherwise captured in the asset appendix—must be identified and described separately in the Seller's narrative. In addition, we remind Sellers of their obligation under § 35.37(e) to describe certain affiliates as part of their vertical market power demonstration.

185

For example, many times a Seller's ultimate upstream affiliate may not itself own any assets and therefore will not appear in the asset appendix. Nevertheless, the identity of the ultimate upstream affiliate is relevant to the seller's horizontal market power analysis. In addition, a Seller's description of its ownership or control of inputs to electric power production, as required to demonstrate a lack of vertical market power under 18 CFR 35.37(e), is not captured in the asset appendix.

128. We do not adopt the proposal that the first time that an entity is identified as an ultimate upstream affiliate by a Seller in an XML submission, the relational database would create a unique identifier for that entity. Sellers will identify their ultimate upstream affiliates by reporting their CIDs, LEIs, or FERC generated IDs, which must be discovered and/or obtained prior to making an XML submission. Reporting the identifiers in this manner will simplify the management of these identifiers and reduce duplication. Finally, we adopt the proposal to make available a list of unique identifiers for Sellers' ultimate upstream affiliate(s). As to TAPS's concern regarding a situation where one affiliate's failure to update ownership information could cause affiliate relationships to be lost, as discussed in the Asset Appendix section, Sellers will have the ability to note errors in their narratives and XML submissions. In addition, we encourage Sellers to contact their affiliates if they believe that an affiliate has not provided accurate, up-to-date information in its own submissions to the relational database.

129. We disagree with Designated Companies that the relationship between the Seller and its ultimate upstream affiliate qualifies for privileged treatment. As the Commission noted in

Ambit,

“the Commission must know the identity of a [S]eller's upstream owners in order to examine the [S]eller's ability to exercise market power in coordinated interaction with other [S]ellers”

186

and the “public interest in transparent decision making and encouraging public participation exceeds [a Seller's] request to shield the identity of its owners.

187

186

Ambit Northeast, LLC,

167 FERC ¶ 61,237, at P 28 (2019).

187

Id.

at P 30.

C. Passive Owners

1. Commission Proposal

130. With respect to any owners that a Seller represents to be passive, the Commission proposed that the Seller affirm in its market-based rate ownership narrative that its passive owner(s) own a separate class of non-voting securities, have limited consent rights, do not exercise day-to-day control over the company, and cannot remove the manager without cause.

188

NOPR, 156 FERC ¶ 61,045 at P 26.

2. Comments

131. APPA and TAPS object to the passive ownership proposal to the extent it eliminates the requirement that Sellers make a demonstration of passivity.

189

APPA and TAPS argue that Commission precedent requires a Seller to provide evidence of passivity beyond an affirmation or representation and that the Commission has not provided any reason for departing from this prior precedent.

190

In contrast, Independent Generation interprets and supports this part of the NOPR as proposing a more streamlined approach to reporting passive investors that avoids the need to file extensive documentation of passive investors' limited voting rights.

191

However, Independent Generation seeks confirmation that a Seller may rely on an affirmation made in good faith after due inquiry as long as the representations remain true to the best of the Seller's knowledge.

192

189

APPA at 11-12; TAPS at 23-25.

190

APPA at 11-12; TAPS at 23-25.

191

Independent Generation at 13.

192

Id.

132. Starwood objects to the requirement that a Seller must identify its passive owners and affirm, among other things, that the passive owners cannot remove the manager without cause.

193

Starwood argues that the Commission has recognized that passive investors are not “affiliates” of a Seller for Commission-jurisdictional purposes because passive interests with limited investor consent or veto rights to protect an investment are not considered voting securities within the definition of “affiliate” under the Commission's regulations. Further, Starwood points out that the Commission confirmed in a declaratory order that certain of Starwood's investors that the Commission deemed to be passive would not need to be identified in any future section 205 market-based rate application, updated market power analysis, or notice of change in status.

194

Thus, Starwood argues that the requirement to identify passive owners in market-based rate data is directly at odds with the Starwood Declaratory Order.

193

Starwood at 7-8.

see also

EEI at DD Appendix 10-16.

226

GE at 29.

227

See

AVANGRID at 17; EEI at 2; FMP at 2; MISO TOs at 8.

3. Commission Determination

158. We adopt the NOPR proposal to require that Sellers submit additional information into the relational database as set forth in the MBR Data Dictionary, with some modification. For example, we have not adopted a requirement for Sellers to provide information regarding ancillary services, but we have adopted the requirement, as set forth in revised § 35.37(a)(1), that Sellers provide information about their operating reserves, which are a subset of ancillary services. Revised § 35.37(a)(1) also specifies that a Seller must submit information about its category status, mitigation, and other limitations. Such information is readily known to the Seller because, as FMP observes, this information is also included in the Seller's market-based rate tariff.

228

The incremental burden of providing this information to the relational database is outweighed by the benefit of having a searchable repository of information that is easily accessible by the Commission and the public through the relational database's services function.

228

In the event of a conflict between the Commission-accepted market-based rate tariff and the information submitted to the relational database, the language in the tariff takes precedence.

159. We disagree that the MBR Data Dictionary must use the exact language from the preamble and regulatory text of the rule. We do not view this as any different from the eTariff filing or EQR submission requirements, which similarly are not detailed in the Commission's regulations.

229

See Filing Requirements for Electric Utility Service Agreements,

155 FERC ¶ 61,280,

order on reh'g,

157 FERC ¶ 61,180.

V. Ongoing Reporting Requirements

A. Commission Proposal

160. The Commission proposed an ongoing quarterly reporting requirement under the regulation for the change in status reporting requirement in § 35.42. However, unlike the existing change in status reporting requirement, the Commission proposed that the quarterly reporting requirement be treated as informational.

230

Specifically, the Commission proposed a new § 35.42(d), which would require a Seller to make a submission updating the relational database on a quarterly basis to reflect any changes not already captured in the required change in connection submissions, change in status filings or any other market-based rate filing such as a notice of cancellation of or revision to a market-based rate tariff. The Commission provided the following list of examples of occurrences that would be reported in the quarterly updates: (1) Retirement of a generation asset; (2) capacity rating changes to an existing generation asset;

231

(3) acquisition of a generation asset that is a reportable asset but not required to be reported in a change in status filing; and (4) loss of affiliation with an affiliate owner that has a franchised service area or market-based rate authority, or directly owns or controls generation, transmission, interstate natural gas transportation, storage or distribution facilities, physical coal supply sources, or ownership of or control over who may access transportation of coal supplies that does not trigger a change in connection submission.

232

The Commission explained that this requirement would help to ensure that the relational database generates an accurate asset appendix, based on current information, for inclusion in a Seller's market-based rate filings and organizational charts for use by the Commission.

233

230

NOPR, 156 FERC ¶ 61,045 at P 67. The Commission typically does not notice or issue orders on informational filings.

See PSEG Services Corp.,

134 FERC ¶ 61,080, at P 15 n.9 (2011).

231

The Commission's change in status regulation regarding generation-related assets is limited to cumulative net increases of 100 MW or more; thus, not all changes in generation assets create a change in status filing obligation.

See

18 CFR 35.42(a).

232

NOPR, 156 FERC ¶ 61,045 at P 66.

233

Id.

P 67.

161. The Commission proposed to retain the requirement for Sellers to file notices of change in status, which are due no later than 30 days after a change in status occurs.

234

However, the Commission did propose a change to § 35.42(a)(2) to include new ultimate upstream affiliates as an example of a change that would trigger a change in status obligation. In addition, the Commission proposed to require Sellers to update the relational database when filing a notice of change in status.

234

See id.

P 65;

see also

18 CFR 35.42(b).

B. Comments

162. Numerous commenters request that any updates to the relational database be made on a quarterly basis instead of the rolling 30-day time window that was proposed for change in connection submissions in the NOPR and that exists for change in status filings pursuant to § 35.42(b).

235

FIEG states that much of the data being requested as part of the change in status filing and change in connection submission is subject to frequent changes, particularly for larger institutions with many different legal and financial connections. FIEG posits that if change in status and change in connection updates were required within 30 days of a change, then many participants would be filing notices weekly, if not more frequently. FIEG states that quarterly ongoing reporting updates would be less burdensome for market participants and less prone to error, while still providing the Commission the information it seeks in a timely manner.

236

235

See

AVANGRID at 22-23; EPSA at 17; FIEG at 14-15; GE at 13-14; EEI at 23 (requesting quarterly reporting for change in connection submissions); NextEra at 7-8; NRG at 8-9; Working Group at 18-19;

see also

Independent Generation at 11 (requesting that change in connection submissions be due on an annual basis or, in the alternative, on a quarterly basis).

236

FIEG at 15.

163. NextEra states that the Commission should consider how the relational database and simplified reporting procedures could simplify other reporting obligations. For example, NextEra notes that certain updates to the relational database could eliminate or simplify change in status filings.

237

NextEra at 10 (“under the change in status reporting requirements the affiliated entities that were each identified in the applicant's MBR filing, must now make their own filing show they have become affiliated with the earlier MBR applicant . . . The change in status filing thus operates as a mirror version of the earlier filing. There is little efficiency in this arrangement. . . .”).

164. Commenters also question how the various updates will work in concert with each other. AVANGRID contends that the NOPR is ambiguous on how multiple data submissions would work

together to ensure the continued accuracy of the relational database.

238

AVANGRID at 11.

165. MISO TOs are concerned about “the potential for repetitive filings and the `ripple effect' that a filing by one entity may have on other [entities]—whether a change by one entity can lead to fifty additional filings because fifty related [entities] are affected.”

239

MISO TOs at 9.

166. TAPS notes that the proposed reporting of changes do not require the same level of comprehensive reporting of affiliate owners as the baseline and triennial filings.

240

TAPS at 15 (noting that under the NOPR, Sellers would need to include ultimate affiliate owner(s) as well as affiliate owners that have a franchised service area or market-based rate authority, or that directly own or control generation; transmission; intrastate natural gas transportation, storage or distribution facilities; physical coal supply sources or ownership of or control over who may access transportation of coal supplies).

167. APPA notes that the comments submitted by TAPS show how seriatim updates could go awry—affiliate data might be lost, and the relational database permanently distorted—unless the updating protocols

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