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

Federal RegisterOct 30, 2015

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM14-14-000; Order No. 816]

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

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is amending its regulations that govern market-based rate authorizations for wholesale sales of electric energy, capacity, and ancillary services by public utilities pursuant to the Federal Power Act. This order represents another step in the Commission's efforts to modify, clarify and streamline certain aspects of its market-based rate program. The Commission is eliminating or refining certain existing filing requirements for market-based rate sellers as well as providing clarification regarding several issues. The specific components of this rule, in conjunction with other regulatory activities, are designed to ensure that the market-based rates charged by public utilities are just and reasonable.

DATES:

Effective Date:

This rule will become effective January 28, 2016.

FOR FURTHER INFORMATION CONTACT:

Greg Basheda (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6479.

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

SUPPLEMENTARY INFORMATION:

Order No. 816

Final Rule

Table of Contents

Paragraph Nos.

I. Introduction

II. Background

III. Overview of Final Rule

IV. Discussion

A. Horizontal Market Power

1. Sellers in RTOs/ISOs

2. Sellers With Fully Committed Long-Term Generation Capacity

3. Relevant Geographic Market for Certain Sellers in Generation-Only Balancing Authority Areas

4. Reporting Format for the Indicative Screens and SIL Submittals 1 and 2

5. Competing Imports

6. Capacity Ratings

7. Reporting of Long-Term Firm Purchases

108

8. Clarification of Commission Language in Performing SIL Studies

146

B. Vertical Market Power—Land Acquisition Reporting

200

1. Commission Proposal

200

2. Comments

202

3. Commission Determination

207

C. Notices of Change in Status

213

1. Geographic Focus

213

2. New Affiliation and Behind-the-Meter Generation

241

3. Reporting of Long-Term Firm Purchases

256

D. Asset Appendix

259

1. Changes to the Existing Columns

260

2. Reporting Power Purchase Agreements

268

3. Clarifications Regarding the Existing Columns

272

4. Changes Regarding OATT Waiver and Citations in Transmission Asset List

295

5. Electronic Format

301

6. Database

308

E. Category 1 and Category 2 Sellers

314

1. Commission Proposal

314

2. Comments

319

3. Commission Determination

320

F. Corporate Families

323

1. Corporate Organizational Charts

323

2. Single Corporate Tariff

336

G. Part 101 and 141 Waivers

339

1. Commission Proposal

339

2. Comments

342

3. Commission Determination

345

H. Miscellaneous Issues

351

1. Regional Reporting Schedule

351

2. Affirmative Statement

354

3. Comments of Barrick

357

V. Section-by-Section Analysis of Regulations

360

VI. Information Collection Statement

370

VII. Environmental Analysis

380

VIII. Regulatory Flexibility Act

381

IX. Document Availability

384

X. Effective Date and Congressional Notification

387

Appendix C to the Final Rule: Regional Reporting Schedule

Appendix D to the Final Rule: Generalized Map of Geographic Regions

Appendix E to the Final Rule: Summary Tables for SIL Calculation

Appendix F to the Final Rule: List of Commenters and Acronyms

Order No. 816

Final Rule

(Issued October 16, 2015)

I. Introduction

1. On June 19, 2014, the Commission issued a Notice of Proposed Rulemaking (NOPR), pursuant to sections 205 and 206 of the Federal Power Act (FPA),

in which the Commission proposed to revise its current standards for market-based rates for sales of electric energy, capacity, and ancillary services.

The Commission proposed to modify and streamline certain aspects of the Commission's filing requirements to reduce the administrative burden on market-based rate sellers

and the Commission.

16 U.S.C. 824d, 824e.

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

FERC Stats. & Regs. ¶ 32,702 (2014) (NOPR).

The term “seller” as used in this Final Rule includes sellers that have already been granted market-based rate authority as well as applicants for market-based rate authority, unless otherwise noted.

2. This Final Rule represents another step in the Commission's efforts to modify, clarify and streamline certain aspects of its market-based rate program. Some aspects of this Final Rule eliminate or refine existing filing requirements, while other aspects of the Final Rule require submission of additional information from market-based rate sellers. For example, this Final Rule redefines the default relevant geographic market for an independent power producer (IPP) with generation capacity located in a generation-only balancing authority and requires sellers to report all long-term firm purchases that have an associated long-term firm transmission reservation in their indicative screens and asset appendices. The Final Rule provides clarification on issues including capacity ratings and preparation of simultaneous transmission import limit (SIL) studies. Streamlining is accomplished through, for example, elimination of the land acquisition reporting requirement, reduction in the number of notice of change in status filings due to establishment of a 100 megawatt (MW) threshold for reporting new affiliations, and clarification that sellers need not report behind-the-meter generation in the indicative screens and asset appendices. The specific components of this rule, in conjunction with other regulatory activities, are designed to ensure that the market-based rates charged by public utilities are just and reasonable.

3. Pursuant to sections 205 and 206 of the FPA, the Commission is amending its regulations to revise subpart H to part 35 of title 18 of the Code of Federal Regulations (CFR), which governs market-based rate authorizations for wholesale sales of electric energy, capacity, and ancillary services by public utilities.

II. Background

4. In 1988, the Commission began considering proposals for market-based pricing of wholesale power sales. The Commission acted on market-based rate proposals filed by various wholesale suppliers on a case-by-case basis. Over the years, the Commission developed a four-prong analysis to assess whether a seller should be granted market-based rate authority: (1) Whether the seller and its affiliates lack, or have adequately mitigated, market power in generation; (2) whether the seller and its affiliates lack, or have adequately mitigated, market power in transmission; (3) whether the seller or its affiliates can erect other barriers to entry; and (4) whether there is evidence involving the seller or its affiliates that relates to affiliate abuse or reciprocal dealing.

5. In 2006, the Commission issued a notice of proposed rulemaking, which led to the issuance in 2007 of Order No. 697, which clarified and codified the Commission's market-based rate policy and generally retained the four prong analyses.

As to the first prong, the Commission adopted two indicative screens for assessing horizontal market power: The pivotal supplier screen and the wholesale market share screen (with a 20 percent threshold). Each of these uses a “snapshot in time” approach based on historical data

and serves as a cross check on the other to determine whether sellers may have horizontal market power and should be further examined.

The Commission stated that passage of both indicative screens establishes a rebuttable presumption that the seller does not possess horizontal market power. Sellers that fail either indicative screen are rebuttably presumed to have market power and are given the opportunity to present evidence such as a delivered price test (DPT) analysis or historical sales and transmission data to demonstrate that, despite a screen failure, they do not have market power.

The Commission specified that in traditional markets (outside regional transmission organization/independent system operator (RTO/ISO) markets), the default relevant geographic market for purposes of the indicative screens is first, the balancing authority area(s) where the seller is physically located, and second, the markets directly interconnected to the seller's balancing authority area (first-tier balancing authority areas).

Generally, sellers that are located in and are members of the RTO/ISO may consider the geographic region under the control of the RTO/ISO as the default relevant geographic market for purposes of the indicative screens.

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

Order No. 697, FERC Stats. & Regs. ¶ 31,252,

clarified,

121 FERC ¶ 61,260 (2007) (Clarifying Order),

order on reh'g,

Order No. 697-A, FERC Stats. & Regs. ¶ 31,268,

clarified,

124 FERC ¶ 61,055,

order on reh'g,

Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 (2008),

order on reh'g,

Order No. 697-C, FERC Stats. & Regs. ¶ 31,291 (2009),

order on reh'g,

Order No. 697-D, FERC Stats. & Regs. ¶ 31,305 (2010),

aff'd sub nom. Mont. Consumer Counsel

FERC,

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

cert. denied,

133 S. Ct. 26 (2012).

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 17.

Id.

PP 62, 75.

Id.

P 13; 18 CFR 35.37(c)(3).

The Commission also noted that “[w]here a generator is interconnecting to a non-affiliate owned or controlled transmission system, there is only one relevant market (

i.e.,

the balancing authority area in which the generator is located).” Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232 n.217.

Where the Commission has made a specific finding that there is a submarket within an RTO/ISO, that submarket becomes a default relevant geographic market for sellers located within the submarket for purposes of the market-based rate analysis.

See Id.

PP 15, 231.

6. With respect to the vertical market power analysis, in cases where a public utility or any of its affiliates owns, operates, or controls transmission facilities, the Commission requires that there be a Commission-approved Open Access Transmission Tariff (OATT) on file, or that the seller or its applicable affiliate has received waiver of the OATT requirement, before granting a seller market-based rate authorization.

The Commission also considers a seller's ability to erect other barriers to entry as part of the vertical market power analysis.

As such, the Commission requires a seller to provide a description of its ownership or control of, or affiliation with an entity that owns or controls, intrastate natural gas transportation, storage or distribution facilities; sites for generation capacity development; and physical coal supply sources and ownership of or control over who may access transportation of coal supplies (collectively, inputs to electric power production).

In Order No. 697-C, the Commission revised the change in status reporting requirement

in section 35.42 of the Commission's regulations to require a market-based rate seller to report the acquisition of control of sites for new generation capacity development on a quarterly basis instead of within 30 days of the acquisition.

The Commission adopted a rebuttable presumption that the ownership or control of, or affiliation with any entity that owns or controls, inputs to electric power production does not allow a seller to raise entry barriers but will allow intervenors to demonstrate otherwise.

Finally, as part of the vertical market power analysis, the Commission also requires a seller to make an affirmative statement that it has not erected barriers to entry into the relevant market and will not erect barriers to entry into the relevant market.

Id.

P 408.

Id.

P 440.

Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 176.

Order No. 697-C, FERC Stats. & Regs. ¶ 31,291 at P 18; 18 CFR 35.42(d).

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 446; 18 CFR 35.37(c).

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 447 (clarifying that the obligation in this regard applies to both the seller and its affiliates but is limited to the geographic market(s) in which the seller is located).

7. If a seller is granted market-based rate authority, the authorization is conditioned on: (1) Compliance with affiliate restrictions governing transactions and conduct between power sales affiliates where one or more of those affiliates has captive customers;

(2) a requirement to file post-transaction electric quarterly reports (EQR) with the Commission containing: (a) A summary of the contractual terms and conditions in every effective service agreement for market-based power sales; and (b) transaction information for effective short-term (less than one year) and long-term (one year or longer) market-based power sales during the most recent calendar quarter;

(3) a requirement to file any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority;

and (4) a requirement for large sellers to file updated market power analyses every three years.

18 CFR 35.39.

18 CFR 35.10b.

18 CFR 35.42.

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 3; 18 CFR 35.37(a)(1).

8. In Order No. 697, the Commission created two categories of sellers.

Category 1 sellers are wholesale power marketers and wholesale power producers that own or control 500 MW or less of generation in aggregate per region; that do not own, operate, or control transmission facilities other than limited equipment necessary to connect individual generation facilities to the transmission grid (or have been granted waiver of the requirements of Order No. 888

); that are not affiliated with anyone that owns, operates, or controls transmission facilities in the same region as the seller's generation assets; that are not affiliated with a franchised public utility in the same region as the seller's generation assets; and that do not raise other vertical market power issues.

Category 1 sellers are not required to file regularly scheduled updated market power analyses. Sellers that do not fall into Category 1 are designated as Category 2 sellers and are required to file updated market power analyses.

However, the Commission may require an updated market power analysis from any market-based rate seller at any time, including those sellers that fall within Category 1.

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 848.

Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities,

Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996),

order on reh'g,

Order No. 888-A, FERC Stats. & Regs. ¶ 31,048,

order on reh'g,

Order No. 888-B, 81 FERC ¶ 61,248 (1997),

order on reh'g,

Order No. 888-C, 82 FERC ¶ 61,046 (1998),

aff'd in relevant part sub nom. Transmission Access Policy Study Group

FERC,

225 F.3d 667 (D.C. Cir. 2000),

aff'd sub nom. New York

FERC,

535 U.S. 1 (2002).

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 849 n.1000; 18 CFR 35.36(a).

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 850.

Id.

P 853.

9. In Order No. 697, the Commission further stated that through its ongoing oversight of market-based rate authorizations and market conditions, the Commission may take steps to address seller market power or modify rates. For example, based on its review of updated market power analyses, EQR filings, or notices of change in status, the Commission may institute a proceeding under section 206 of the FPA to revoke a seller's market-based rate authorization if it determines that the seller may have gained market power since its original market-based rate authorization. The Commission also may, based on its review of EQR filings or daily market price information, investigate a specific utility or anomalous market circumstance to determine whether there has been a violation of RTO/ISO market rules or Commission orders or tariffs, or any prohibited market manipulation, and take steps to remedy any violations.

Id.

P 5.

10. After more than six years of experience with the implementation of Order No. 697, the Commission proposed a number of changes to the market-based rate program which, taken as a whole, it believed would simplify and streamline certain aspects of the market-based rate program and reduce the burden on industry and the Commission, while continuing to ensure that the standards for market-based rate sales of electric energy, capacity and ancillary services result in sales that are just and reasonable. The Commission also proposed a number of changes to improve transparency in the market-based rate program, some of which represent increases in information collected from market-based rate sellers.

11. The Commission received 23 comments in response to the NOPR. A list of commenters is attached as Appendix F.

Although the Commission did not request reply comments, several commenters nonetheless submitted reply comments. The Commission will reject such reply comments.

III. Overview of Final Rule

12. In this Final Rule, we adopt in many respects the proposals contained in the NOPR with further modifications and clarifications and decline to adopt others. Our findings are summarized below.

13. First, with respect to the Commission's horizontal market power analysis, we are not, at this time, adopting the proposal to relieve market-based rate sellers in RTO/ISO markets of the obligation to submit indicative screens. However, we are confirming clarifications and adopting many of the other proposed modifications to the horizontal market power analysis. For example, we clarify that sellers may explain that their generation capacity in the relevant geographic market (including first-tier markets) is fully committed in lieu of submitting indicative screens as part of their horizontal market power analysis. We also clarify that, when the current Commission-accepted SIL values into the relevant market are zero for all four seasons and the seller's and its affiliates' generation capacity in the relevant market is fully committed, the seller does not need to submit indicative screens. In addition, we adopt the NOPR proposal regarding reporting of long-term firm purchases.

14. We adopt the proposal to define the default relevant geographic market for an IPP located in a generation-only balancing authority area as the balancing authority area(s) of each transmission provider to which the IPP's generation-only balancing authority area is directly interconnected. We explain that an IPP should study all of its uncommitted

generation capacity from the generation-only balancing authority area in the balancing authority area(s) of each transmission provider to which it is directly connected, and we provide examples and clarification of this policy.

15. We amend the indicative screen reporting format and require that the horizontal market power indicative screens and SIL Submittals 1 and 2 be filed in workable electronic spreadsheets. We find that solar photovoltaic and solar thermal facilities are energy limited. However, we determine that, due to their unique characteristics, solar photovoltaic facilities, unlike other energy-limited facilities, must use nameplate capacity and may not use historical five-year average capacity factors.

16. We adopt the proposal to require a market-based rate seller to report in its indicative screens and asset appendix all of its long-term firm purchases of capacity and/or energy that have an associated long-term firm transmission reservation regardless of whether the market-based rate seller has control over the generation capacity supplying the purchased power. We also adopt a modified formula for converting energy to capacity, and make corresponding changes to the change in status reporting requirements.

17. We confirm most of the clarifications proposed in the NOPR regarding the SIL studies and provide some additional clarifications in response to comments.

18. With respect to the Commission's vertical market power analysis, we adopt the proposal to eliminate the requirement that market-based rate sellers file quarterly land acquisition reports and provide information on sites for generation capacity development in market-based rate applications and triennial updated market power analyses. With respect to other change in status proposals, we clarify that the 100 MW threshold does

not

include generation capacity that can be imported from first-tier markets. Similarly, we find that applicants and sellers are

not

limited to nameplate ratings when determining the 100 MW threshold. We have reconsidered the proposed clarification that market-based rate sellers must account for behind-the-meter generation in their indicative screens and asset appendices and find that behind-the-meter generation need not be accounted for in the indicative screens and asset appendices and will not count towards the 100 MW change in status threshold or the 500 MW Category 1 seller threshold.

19. We also adopt a 100 MW change in status threshold for reporting new affiliations to align with the existing 100 MW threshold for reporting net increases in generation capacity.

20. We adopt changes to the asset appendix that sellers must submit with most market-based rate filings, and will also require that the asset appendix be submitted in an electronic format that can be searched, sorted, and otherwise accessed using electronic tools. In addition, based on comments received, we will add two additional worksheets to the asset appendix, one for end notes and another for long-term firm purchases. We provide some additional clarifications on the asset appendix as well.

21. We adopt the NOPR proposal to require a seller filing an initial application for market-based rate authority, an updated market power analysis, or a notice of change in status reporting new affiliations to include a corporate organizational chart. However, we clarify that the organizational chart need only to include the seller's affiliates as defined in section 35.36(a)(9) of the Commission's regulations rather than all upstream owners, “energy subsidiaries” and “energy affiliates.”

22. We adopt the NOPR proposal and clarify that granting waiver of 18 CFR part 101 under market-based rate authority does not waive the requirements under Part I of the FPA for hydropower licensees. In addition, we clarify how hydropower licensees that only make sales at market-based rates may satisfy the requirements in part 101 of the Commission's regulations (Uniform System of Accounts), and confirm that hydropower licensees that have Commission-approved cost-based rates are required to comply with the full requirements of the Uniform System of Accounts.

23. We also provide clarifications in the Final Rule with regard to simplifying assumptions, the criteria for determining seller category status, how to file a single corporate tariff, the regional reporting schedule, and the vertical affirmative statement obligation.

IV. Discussion

A. Horizontal Market Power

1. Sellers in RTOs/ISOs

a. Commission Proposal

24. Section 35.37 of the Commission's regulations requires market-based rate sellers to submit market power analyses: (1) When seeking market-based rate authority; (2) every three years for Category 2 sellers; and (3) at any other time the Commission requests a seller to submit an analysis. A market power analysis must address a seller's potential to exercise horizontal and vertical market power. If an RTO/ISO seller

fails the indicative screens for the RTO/ISO, it can seek to obtain or retain market-based rate authority by relying on Commission-approved RTO/ISO monitoring and mitigation.

RTO/ISO sellers are sellers that study an RTO, ISO, and submarkets therein as a relevant geographic market.

In Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 111, the Commission stated that “to the extent a seller seeking to obtain or retain market-based rate authority is relying on existing Commission-approved [RTO/ISO] market monitoring and mitigation, we adopt a rebuttable presumption that the existing mitigation is sufficient to address any market power concerns.”

25. The Commission proposed to not require sellers in RTO/ISO markets to submit indicative screens as part of their horizontal market power analyses if they rely on Commission-approved monitoring and mitigation to prevent the exercise of market power. Under the proposal, RTO/ISO sellers instead would simply state that they are relying on such mitigation to address any potential market power they might have, and describe their generation and transmission assets and provide an asset appendix with a list of generation assets and entities with market-based rate authority (generation list) and a list of transmission assets and natural gas intrastate pipelines and gas storage facilities (transmission list). Under this proposal, all RTO/ISO sellers seeking market-based rate authority in an RTO/ISO market would make an initial filing, consistent with current practice, and those sellers required to file updated market power analyses every three years (

i.e.,

Category 2 sellers) would continue to make their scheduled filings. The Commission noted that it would retain the ability to require an updated market power analysis, including indicative screens, from any market-based rate seller at any time.

b. Comments

26. Some commenters support the Commission's proposal to allow market-based rate sellers in RTO/ISO markets with Commission-approved monitoring and mitigation to not file indicative screens when submitting initial applications requesting market-based rate authority and updated market power analyses.

Some commenters

request that the Commission clarify aspects of its proposal

or extend the proposal to additional circumstances.

Some commenters oppose the Commission's proposal, raising issues regarding the Commission's legal authority to eliminate the indicative screens

or the effectiveness of RTO/ISO monitoring and mitigation.

For example, Potomac Economics agrees with the general principal underlying the Commission's proposal, but states that in some cases, participants selling into RTO markets may be exempt from certain market power mitigation measures or the mitigation measures may not be fully effective and that the Commission's proposal may allow some participants with potential market power to sell at market-based rates without this market power being fully addressed.

APPA/NRECA contend that the proposal is a fundamental departure from the market-based rate scheme that the courts have previously upheld.

American Electric Power Service Corporation (AEP) at 4-5; Electric Power Supply Association (EPSA) at 3-4; FirstEnergy Service Company (FirstEnergy) at 4-5; Golden Spread Electric Cooperative, Inc. (Golden Spread) at 6; NextEra

Energy, Inc. (NextEra) at 2; Subsidiaries of NRG Energy, Inc. (NRG Companies) at 8-9.

See, e.g.,

E.ON Climate & Renewables North America LLC (E.ON) at 3-4; Southern California Edison Company (SoCal Edison) at 16; Julie Solomon and Matthew Arenchild (Solomon/Arenchild) at 2; Edison Electric Institute (EEI) at 6.

See, e.g.,

FirstEnergy at 10; AEP at 6; EEI at 7.

American Antitrust Institute (AAI) at 3-7; American Public Power Association and National Rural Electric Cooperative Association (APPA/NRECA) at 6-21; Transmission Access Policy Study Group (TAPS) at 1-2, 5-9, 17-18.

Potomac Economics at 3-4.

Potomac Economics at 2.

APPA/NRECA at 8-10 (citing

Mont. Consumer Counsel v. FERC,

659 F.3d 910;

California ex rel. Lockyer v. FERC,

383 F.3d 1006 (9th Cir. 2004) (

Lockyer

);

Blumentha v. FERC,

552 F.3d 875,882 (D.C. Cir. 2009) (

Blumenthal

)).

c. Commission Determination

27. The Commission received 15 comments on this issue from a wide variety of market participants. Indeed, this was one of the most widely commented upon aspects of the Commission's NOPR. The comments included those who fully support the Commission's proposal, those who favor only portions of it, those who seek clarification of it and those who oppose it. And among those who oppose it, there are various reasons for their opposition, which include legal, economic, and implementation issues. While the Commission considers further the issues that were raised in these comments, we are not prepared to adopt at this time the proposal in the NOPR and will continue with our current practice of requiring that sellers in RTO/ISO markets submit the indicative screens when submitting initial applications requesting market-based rate authority and updated market power analyses and relying on the Commission-approved market monitoring and mitigation. We will transfer the record on this aspect of the NOPR to Docket No. AD16-8-000 for possible consideration in the future as the Commission may deem appropriate.

28. Because we continue to value the information obtained through the indicative screens and are not prepared at this time to adopt the proposal, market-based rate sellers in RTO/ISO markets must continue to submit the indicative screens as part of their horizontal market power analysis unless the seller and its affiliates do not own or control generation capacity or all of their capacity is fully committed. We will continue to allow sellers to seek to obtain or retain market-based rate authority by relying on Commission-approved RTO/ISO monitoring and mitigation in the event that such sellers fail the indicative screens for the RTO/ISO markets.

See

Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 11.

2. Sellers With Fully Committed Long-Term Generation Capacity

a. Commission Proposal

29. The Commission has found that, if generation is committed to be sold on a long-term firm basis to one or more buyers and cannot be withheld by a seller, it is appropriate for a seller to deduct such capacity when performing the indicative screens.

In the NOPR, the Commission clarified that where all generation owned or controlled by a seller and its affiliates in the relevant balancing authority areas or markets including first-tier balancing authority areas or markets is fully committed, sellers may satisfy the Commission's market-based rate requirements regarding horizontal market power by explaining that their capacity is fully committed in lieu of including indicative screens in their filings. The Commission proposed to clarify that, in order to qualify as “fully committed,” a seller must commit the generation capacity so that none of it is available to the seller or its affiliates for one year or longer.

See id.

P 41.

30. The Commission proposed that sellers claiming that all of their relevant generation capacity

is fully committed would have to include the following information: the amount of generation capacity that is fully committed, the names of the counterparties, the length of the long-term contract, the expiration date of the contract, and a representation that the contract is for firm sales for one year or longer. The Commission stated that in order to qualify as fully committed, the commitment of the generation capacity cannot be limited during that 12-month consecutive period in any way, such as limited to certain seasons, market conditions, or any other limiting factor. Furthermore, the Commission stated that a seller's generation would not qualify as fully committed if, for example, the seller has generation necessary to serve native load, provider of last resort obligations, or a contract that could allow the seller to reclaim, recall, or otherwise use the capacity and/or energy or regain control of the generation under certain circumstances (such as transmission availability clauses).

“Relevant” generation capacity refers to seller and affiliated capacity in the study area, including the first tier.

31. Additionally, the Commission stated that, consistent with the existing regulations, a change in status filing will be required when a long-term firm sales agreement expires if it results in a net increase of 100 MW or more.

The Commission noted that such a change would be a departure from the characteristics the Commission relied upon in granting market-based rate authority.

See

18 CFR 35.42(a).

b. Comments

32. Many commenters support the Commission's proposal.

For example, EPSA agrees with the Commission's assessment that the study of uncommitted generation in indicative screens becomes a purely mathematical task and provides no significant additional information when sellers' fully-committed long-term capacity is deducted from the indicative screens.

NextEra, also agreeing with the Commission's proposal, states that where all generation owned or controlled by sellers and their affiliates is fully committed to purchasers not affiliated with the seller, the ability to exercise market power is severely limited or non-existent.

FirstEnergy states that it supports the proposal because a seller whose generation capacity is fully committed on a long-term basis lacks the ability to exercise horizontal market power by withholding such capacity from the market.

EPSA at 4; Solomon/Arenchild at 2; NextEra at 3; EEI at 8; FirstEnergy at 7; NRG Companies at 10.

EPSA at 5.

NextEra at 3.

FirstEnergy at 7.

33. NRG Companies also support the proposal and request that the Commission clarify that even if the seller and/or its affiliates have uncommitted capacity in one or more

first-tier markets, no indicative screens will be required if all of their generation capacity in the relevant market is fully committed under long-term contracts and (1) the simultaneous import limitation for the relevant market is zero, indicating that no capacity can be imported from affiliates in first-tier markets, or (2) neither the seller nor its affiliates have firm transmission rights into the relevant market from any first-tier market in which its affiliates have uncommitted capacity.

NRG Companies at 10-11.

34. NextEra states that there is no need to provide screens in balancing authority areas where all generation owned or controlled by sellers and their affiliates is fully committed to purchasers not affiliated with the seller and further requests that the Commission not require screens if there is uncommitted capacity in any first-tier market when 100 percent of the seller's generation capacity in the relevant market is fully committed.

NextEra at 4.

35. EPSA requests clarification that the proposed term “fully committed” would also apply to circumstances where a seller retains the right to sell capacity to a second buyer, but only when the first buyer under the long-term contract waives the right to purchase. EPSA explains that if the buyer under a long-term contract has the right to call on the full output of the seller's generation, and the seller may only offer the capacity to a second buyer when the first buyer foregoes its purchase right, then that capacity should be considered fully committed and thus, excluded from the indicative screens.

EPSA at 5.

36. Solomon/Arenchild state that the Commission's proposal that the exemption from the submittal of screens depends, in part, on whether the seller has uncommitted capacity in first-tier markets is inconsistent with its general approach in defining geographic markets and when screens are required. They recommend that the Commission's proposal be amended. In the NOPR, the Commission stated that “where all generation owned or controlled by a seller and its affiliates in the relevant balancing authority areas or markets

including first-tier balancing authority areas or markets

is fully committed, sellers may explain that their capacity is fully committed in lieu of including indicative screens in their filings in order to satisfy the Commission's market-based rate requirements regarding horizontal market power.”

Solomon/Arenchild propose that the language “including first-tier balancing authority areas or markets” be excluded.

Alternatively, they state that the definition could be modified to only include first-tier supply that has a corresponding long-term firm transmission agreement into the relevant balancing authority area.

NOPR, FERC Stats. & Regs. ¶ 32,702 at P 43 (emphasis added).

Solomon/Arenchild at 2-3.

Id.

at 3.

37. With regard to the information a seller must provide, NextEra seeks clarification on the phrase “firm sales for one year or longer.” NextEra requests that the Commission clarify that the term “firm” has the same meaning as in the Commission's EQR Data Dictionary, where it is defined as “a service or product that is not interruptible for economic reasons.”

NextEra at 4-5 (citing

http://www.ferc.gov/docs-filing/eqr/order770/data-dictionary.pdf

38. NextEra does not oppose the Commission's proposal to require that sellers provide the expiration date of the contract in updated market power analyses, but NextEra states that it does not agree with requiring this information in initial market-based rate applications. NextEra states that, more often than not, at the time a seller files for market-based rate authority, the expiration date is unknown.

EEI does not support requiring the expiration date and notes that the expiration date is reported separately in EQR filings.

Id.

at 5.

EEI at 8.

c. Commission Determination

39. Consistent with the NOPR, the Commission clarifies here that when all of a seller's generation capacity is sold on a long-term firm basis to one or more buyers, the seller has no uncommitted capacity and in such cases will not be required to file the indicative screens. Sellers may explain that their generation capacity is fully committed in lieu of including indicative screens in their filings in order to satisfy the Commission's market-based rate requirements regarding horizontal market power in instances where all generation owned or controlled by a seller and its affiliates in the relevant balancing authority areas or markets, including first-tier balancing authority areas or markets, is fully committed. We clarify that to qualify as fully committed, a seller must commit the capacity to a non-affiliated buyer so that none of it is available to the seller or its affiliates for one year or longer. We also adopt the proposal that for those sellers claiming that all of their relevant capacity is fully committed they must include the following information: The amount of generation capacity that is fully committed, the names of the counterparties, the length of the long-term contract, the expiration date of the contract, and a representation that the contract is for firm sales for one year or longer. In order to qualify as fully committed, the commitment of the generation capacity cannot be limited during that 12-month consecutive period in any way, such as limited to certain seasons, market conditions, or any other limiting factor. As stated in the NOPR, a seller's generation would not qualify as fully committed if, for example, that generation is needed for the seller to meet its native load or provider of last resort obligations, or the power sales contract in question could allow the seller to reclaim, recall, or otherwise use the generation capacity and/or energy or regain rights to the generation under certain circumstances (such as transmission availability clauses). Additionally, a change in status filing will be required when a long-term firm sales agreement expires if it results in a net increase of 100 MW or more.

40. We do not adopt the suggestions by NRG Companies, NextEra, and Solomon/Arenchild regarding capacity in first-tier markets. We will not implement NRG Companies' and NextEra's proposals that the Commission not require sellers to submit indicative screens even if they have uncommitted capacity in one or more first-tier markets as long as all of the seller's capacity in the relevant market is fully committed. A seller may fail an indicative screen in a market where it does not have any uncommitted capacity due to its imports into the study area.

However, when the current Commission-accepted SIL values into the relevant market are zero for all four seasons, the seller does not have to consider imports in its market-power studies. Therefore, we clarify that if the seller's capacity in the relevant market is fully committed and all the SIL values into the relevant market are zero, the seller does not need to submit the indicative screens.

For example, this can occur when a seller is relatively large and the study area is relatively small and relies significantly on imports to meet its load obligations.

41. We do not adopt the suggestion from Solomon/Arenchild to only consider first-tier supply that has long-term firm transmission rights into the relevant market. First-tier generation capacity without long-term firm

transmission rights still can be imported into the relevant market as long as the SIL value is not zero; albeit on a non-firm,

pro rata

basis.

The SIL values used in the Commission's horizontal market power analysis are net of long-term firm transmission reservations. While a seller's

pro rata

share of the SIL value or transmission capacity that may be used to import generation capacity from the first-tier ultimately may be small, it should not be ignored.

Stated another way, if the SIL value is not zero, and the seller has uncommitted generation capacity in a first-tier market, that uncommitted capacity is capable of reaching the study area and will affect the market power analysis. However, a seller's first-tier uncommitted capacity has to compete with non-affiliated first-tier uncommitted capacity to enter the study area, so the Commission allows sellers to allocate to themselves a portion of the SIL value based on the percentage of uncommitted generation capacity they and their affiliates own in the aggregated first-tier area in relation to the total amount of uncommitted generation capacity in this area.

See

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 373-375.

42. We also decline to adopt EPSA's request that we clarify that a seller's generation capacity is fully committed where the seller retains the right to sell capacity to a second buyer.

We are concerned that permitting a more flexible definition of fully committed could create the potential for sellers to claim that their contracts meet the standard for fully committed even where it is not clear that the capacity's output is fully committed. Moreover, the contract-specific analysis could create inconsistencies in the way data is reported.

Here we are referring to a situation in which the seller retains rights to sell the same generation capacity to a second buyer. We are not referring to a contractual arrangement whereby capacity is fully committed but is sold to multiple buyers;

e.g.,

500 MW of a 1,000 MW unit is sold to buyer A, while the remaining 500 MW of the unit is sold to buyer B, with A and B having exclusive rights to their respective shares of the unit.

43. With regard to NextEra's request that the Commission clarify that “firm” has the same meaning as in the Commission's EQR Data Dictionary, we clarify here that the term “firm” means a “service or product that is not interruptible for economic reasons,” as it is defined in the Commission's EQR Data Dictionary.

44. We believe that NextEra raises a valid point concerning unknown expiration dates. Therefore, we clarify here that if a contract expiration date is unknown at the time of the market-based rate filing, the seller must follow up with an informational filing, in the docket in which the seller was granted market-based rate authorization, to inform the Commission of the contract expiration date, within 30 days of the date becoming known. In response to EEI's argument that the expiration date is reported separately in EQR filings, we note many contracts reported in EQR filings do not include expiration dates. Further, there can be a time gap between when a seller receives market-based authority and when it submits its EQR. This time gap may be as large as 120 days, and would not meet the need for this information. Therefore, we will require expiration date information to show that generation capacity is fully committed.

3. Relevant Geographic Market for Certain Sellers in Generation-Only Balancing Authority Areas

a. Commission Proposal

45. In the NOPR, the Commission noted that “the horizontal market power analysis centers on and examines the balancing authority area where the seller's generation is physically located”

and that the default relevant geographic market under both indicative screens “will be first, the balancing authority area where the seller is physically located [the seller's home balancing authority area] and second, the markets directly interconnected to the seller's balancing authority area (first-tier balancing authority area markets).”

However, the Commission noted that “[w]here a generator is interconnecting to a non-affiliate owned or controlled transmission system, there is only one relevant market (

i.e.,

the balancing authority area in which the generator is located).”

Similarly, the Commission noted that RTO/ISO sellers are required “to consider, as part of the relevant market, only the relevant [RTO/ISO] market and not first-tier markets to the [RTO/ISO].”

NOPR, FERC Stats. & Regs. ¶ 32,702 at P 47 (quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 37).

Id.

(quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232).

Id.

(quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232 n.217).

Id.

(quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 231 n.215).

46. The Commission noted that Order No. 697 stated that a “balancing authority area means the collection of generation, transmission, and loads within the metered boundaries of a balancing authority, and the balancing authority maintains load/resource balance within this area.”

The Commission further noted that, given that generation-only balancing authority areas do not have any load, these balancing authority areas do not appear to meet the Commission definition of a default relevant geographic market. In light of the unusual and complex circumstances that are associated with defining the relevant geographic market of an IPP located in a generation-only balancing authority area, and in light of the fact that a generation-only balancing authority area is not a market, the Commission proposed in the NOPR that the default relevant geographic market(s) for such a seller would be the balancing authority areas of each transmission provider to which its generation-only balancing authority area is directly interconnected. The Commission proposed that such IPP seller study all of its uncommitted generation capacity from the generation-only balancing authority area in the balancing authority area(s) of each transmission provider to which it is directly interconnected, since all such uncommitted capacity could potentially be sold into any of the markets that are directly interconnected to the IPP's generation-only balancing authority area, even if the IPP has not sold into that market.

Id.

P 51.

47. In the NOPR, the Commission stated that “[f]or purposes of market power analyses for market-based rate authority, we propose to define an IPP as a generation resource that has power production as its primary purpose, does not have any native load obligation, is not affiliated with any transmission owner located in the first-tier markets in which the IPP is competing and does not have an affiliate with a franchised service territory. This IPP could also have an OATT waiver on file with the Commission.”

Id.

P 49 n.50.

48. To illustrate the NOPR proposal, the Commission explained that if an IPP is located in a generation-only balancing authority area that is embedded within a transmission provider's balancing authority area, and that balancing authority area is the only balancing authority area that the IPP's generation-only balancing authority area is directly interconnected with, then the IPP would provide indicative screens for that transmission provider's balancing authority area.

The Commission proposed that an IPP in this situation would not need to study the transmission provider's balancing authority first-tier markets, just as would be the case if that generator were similarly located in the transmission provider's balancing authority area.

49. The Commission provided another example for an IPP located in a generation-only balancing authority area in a remote area such as the desert southwest. In that case, the IPP would have to provide indicative screens for the balancing authority area(s) of the transmission provider(s) to which its generation-only balancing authority area

is directly interconnected. The IPP would assume that all of its uncommitted capacity could compete in each balancing authority area of the transmission provider(s) to which its generation-only balancing authority area is directly interconnected, since all such uncommitted capacity could potentially be sold in each market to which there is a direct interconnection, even if the IPP has not sold into that market in the past. An IPP in this situation would not need to study any first-tier markets.

See

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232 n.217.

50. For an IPP in a generation-only balancing authority area directly interconnected to a transmission provider at an energy trading hub, the Commission proposed that the IPP would provide indicative screens that study itself in the balancing authority area of each transmission provider that is directly interconnected at the trading hub. Thus, the balancing authority areas that are directly interconnected at the hub would each be relevant geographic markets for that IPP, and the IPP would provide indicative screens that study the IPP in each of those transmission providers' balancing authority areas. The Commission proposed that the IPP would provide indicative screens that assume that all of its uncommitted capacity may compete in each of the balancing authority areas that are directly interconnected at that trading hub, since all such uncommitted capacity could potentially be sold in each market to which there is a direct interconnection, even if the IPP has not sold into that market in the past. The IPP in this situation would not need to provide indicative screens that study itself in any markets that are first-tier to the various balancing authority areas that are directly interconnected at the trading hub.

b. Comments

51. Solomon/Arenchild agree in principal with the Commission's proposal to define relevant geographic market(s) for sellers located in generation-only balancing area as the balancing authority areas of each transmission provider to which the generation-only balancing authority area is directly interconnected. Solomon/Arenchild suggest that the Commission confirm that the proposal also applies to quasi-generation-only balancing authority areas, such as Ohio Valley Electric Corporation and Alcoa Power Generating, Inc.—Yadkin Division. According to Solomon/Arenchild, in these quasi-generation-only balancing authority areas, generation was built to serve load in a balancing authority area, but there is no longer any material load present in the balancing authority area.

Solomon/Arenchild at 15.

52. However, Solomon/Arenchild voice concerns with the Commission's proposal to have an IPP provide screens that study the IPP in the balancing authority area of each transmission provider that is directly interconnected at the trading hub. Citing the example in the NOPR regarding IPPs interconnected to the Hassayampa switchyard, Solomon/Arenchild state that, as proposed, the solution is overly burdensome and likely to have unintended consequences.

They explain that the Commission's proposal, as they understand it, would require New Harquahala Generating Company, LLC (Harquahala) and Arlington Valley, LLC (Arlington Valley) to each perform indicative screens for all Arizona Nuclear Power Project switchyard participants. They state that this would be at least six balancing authority areas and perhaps more, resulting in a “significant increase in the scope of the analysis and the burden.”

The Commission explained in the NOPR that if an IPP in a generation-only balancing authority area in the Arizona desert is directly interconnected to a transmission provider at the Palo Verde trading hub at the Palo Verde and Hassayampa switchyards, then it would provide screens that study all of its uncommitted capacity in each balancing authority area that is directly interconnected at the switchyard. NOPR, FERC Stats. & Regs. ¶ 32,702 at P 56.

Solomon/Arenchild at 15-17 (citing NOPR, FERC Stats. & Regs. ¶ 32,702 at P 56).

53. Solomon/Arenchild also argue that the proposal does not clarify many of the steps that must be considered. They state that a seller has to determine if each of the analyses require a presumption that 100 percent of the output of each of the relevant merchant generators can be “imported” into each of the six or more balancing authority areas. They further state that the SIL studies done by the transmission owners in the region would have to be aligned with the analyses and they question whether that means that each of the balancing authority areas would be required to conduct two SIL studies—one that assumes each of the potentially relevant generators reside “within” their balancing authority areas and one that does not. Solomon/Arenchild also question whether Harquahala and Arlington Valley should be singled out from their other counterparts who are also interconnected at Hassayampa, merely because they reside in a generation-only balancing authority area.

Id.

at 17.

54. Solomon/Arenchild state that the proposal to conduct indicative screens for multiple interconnected balancing authority areas appears to merely create multiple opportunities for the generator in a generation-only balancing authority area to fail an indicative screen. Solomon/Arenchild further state that in proposing that each generator consider multiple relevant balancing authority areas, it seems that the Commission is acknowledging the highly interconnected nature of the region (a key reason for the existence of a “hub”), while still rejecting the proposition that a “hub” itself can be a relevant market. Solomon/Arenchild explain that it is worth noting that in the Western Interconnection (unlike in the Eastern Interconnection), load flow models such as those underlying the SIL analyses are based not on individual balancing authority areas, but on “areas” that more closely approximate real world conditions.

Id.

at 17-18 (noting that Western Electricity Coordinating Council transmission models used an “Area 14,” which covers the Arizona “region” as the basis for SIL studies rather than the individual balancing authority areas).

55. Solomon/Arenchild state that the proposal could have significant market-distortive effects. Solomon/Arenchild postulate that if a generator fails an indicative screen in the Salt River Project balancing authority area, but not in the Arizona Public Service balancing authority area, the Salt River Project balancing authority area may lose opportunities to purchase at market-based rates, and generators may lose opportunities to sell at market-based rates. Solomon/Arenchild contend that this would not occur if somewhat broader markets are considered. Solomon/Arenchild conclude that, in the absence of creating broader markets for generation-only balancing authority areas like those at Hassayampa, the Commission should not change its current practice. That is, sellers in generation-only balancing authority areas should use as the default relevant market, the directly interconnected balancing authority areas and that the scope of such definitions be evaluated on a case-by-case basis.

Id.

at 18.

56. Lastly, Solomon/Arenchild request that the Commission clarify that, to the extent that a seller fails the indicative screens in the balancing authority area(s) to which it is directly interconnected, sales at the “hubs” be treated as “at the metered boundary” of a seller's mitigated balancing authority

area, and hence, allow market-based rate sales at the hubs.

Id.

57. Romkaew Broehm and Gerald A. Taylor (Broehm/Taylor) agree with the Commission's logic in proposing to define relevant markets as the balancing authority areas that are directly interconnected to the generation only-balancing authority area. However, Broehm/Taylor encourage the Commission to look beyond its default market rule when defining a proper relevant geographic market for a market power analysis for all sellers. Broehm/Taylor question whether a seller's home balancing authority area and its first-tier balancing authority area would be adequate for determining relevant default markets. According to Broehm/Taylor, during the 2000-2001 Western power crisis experience, suppliers with generation more than two wheels away could easily reach the California buyers and became pivotal sellers, simply by having firm transmission rights at the key interfaces.

Broehm/Taylor explain that if the Commission were to require sellers to report all of their transmission reservation data, a seller with reservations on a path from a first-tier to a second-tier balancing authority area would need to perform a market power analysis for the second-tier balancing authority area.

Broehm/Taylor state that this suggests that the Commission should expand its review to consider other information, such as sellers' transmission reservation data. Broehm/Taylor therefore recommend that the Commission require all sellers to summarize their historical short-term trade patterns outside their home balancing authority area and report their firm transmission service reservations of one month or longer as part of their triennial updated market power analysis filing. Broehm/Taylor state that sellers are required to report this information to the Commission via EQRs and that this information can be used to determine whether or not the default geographic markets as defined by the Commission are adequate for purposes of market power analyses.

Broehm/Taylor at 3.

Id.

at 3-5.

Id.

at 5-6.

58. EPSA generally supports the proposal, but suggests consistent treatment in the Commission's evaluation of nested balancing authority areas. It requests that the Commission clarify that it will implement the proposal in such a manner to ensure that as long as there is network deliverability from the nested balancing authority areas through the interconnected balancing authority areas and to the first-tier balancing authority areas, those first-tier balancing authority areas should be included in the indicative screens of sellers in the generation-only balancing authority areas. According to EPSA, this approach would more accurately reflect the geographic area in which the energy from the nested balancing authority area is available and with which it can compete. They also state that this approach would be consistent with the analysis for an IPP's balancing authority area that is connected to a trading hub.

EPSA at 6.

59. NRG Companies request that the Commission clarify that if a seller in a generation-only balancing authority area fails the indicative market power screens and surrenders or loses market-based rate authorization to sell in one or more of the markets connected to the trading hub, the seller will still be allowed to make market-based rate sales at the trading hub, as long as it retains market-based rate authorization in at least one of the balancing authority areas interconnected to the trading hub. NRG Companies state that such clarification is consistent with the Commission's holding in Order No. 697 that a seller that has lost market-based rate authorization and is making sales subject to cost-based mitigation may continue to “make market-based rate sales at the metered boundary between a mitigated balancing authority area and a balancing authority in which the seller has market-based rate authority.”

NRG Companies at 12-13 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 817).

60. EEI encourages the Commission to clarify that IPPs connected to a hub would need to perform the market power analyses only for the home market of each transmission provider connected to the hub, not the transmission provider's first-tier adjacent markets, and that the IPPs could conduct a single analysis, not separate ones for each provider's market. EEI also requests the Commission consider whether a similar approach could be used for entities that are not IPPs and for entities that have a

de minimis

amount of load in their balancing authority areas.

EEI at 9.

c. Commission Determination

61. We adopt the NOPR proposal to define the default relevant geographic market(s) for an IPP located in a generation-only balancing authority area as the balancing authority areas of each transmission provider to which the IPP's generation-only balancing authority area is directly interconnected. For purposes of this provision, we define an eligible IPP as a generation resource that has power production as its primary purpose, does not have any native load obligation, is not affiliated with any transmission owner located in the target or first-tier markets in which the IPP is competing and does not have an affiliate with a franchised service territory.

NOPR, FERC Stats. & Regs. ¶ 32,702 at P 49 n.50. This IPP could also have an OATT waiver on file with the Commission or qualify for a blanket waiver under 18 CFR 35.28(d).

62. We also adopt the proposal for such an IPP to study all of its uncommitted generation capacity from the generation-only balancing authority area in the balancing authority area(s) of each transmission provider to which it is directly interconnected. We clarify that we do not consider other generation-only balancing authority areas to which an IPP may be interconnected to be balancing authority areas of transmission providers. If an IPP is located in a generation-only balancing authority area that is embedded within a transmission provider's balancing authority area, and that balancing authority area is the only balancing authority that the IPP's generation-only balancing authority area is directly interconnected with, then the IPP only needs to study that transmission provider's balancing authority area. An IPP in this situation would not need to study the transmission provider's first-tier markets. An example of this situation is NaturEner Power Watch, LLC (NaturEner), which has a generation-only balancing authority area that is located within the NorthWestern Energy balancing authority area. NaturEner would provide indicative screens that examine all of its uncommitted capacity in the NorthWestern Energy balancing authority area. NaturEner would not need to study itself in any other balancing authority areas unless its generation-only balancing authority area is directly interconnected to other balancing authority areas.

63. Similarly, if the IPP is located in a generation-only balancing authority area and is not embedded within a single transmission provider's balancing authority area, the IPP would need to provide indicative screens for the balancing authority area(s) of the transmission provider(s) to which its generation-only balancing authority area is directly interconnected. For example, if it were the case that the generation-only balancing authority areas of the Gila River Power Company LLC and

Sundevil generation plants are each directly interconnected with the balancing authority area operated by Arizona Public Service Co. (APS), then each of those IPPs would study themselves in the APS balancing authority area, and each would treat all other competing generators from generation-only balancing authority areas directly interconnected with the APS balancing authority area as being in the APS balancing authority area. The IPPs in generation-only balancing authority areas would also study themselves in the same manner in any other balancing authority areas to which their generation-only balancing authority area is directly interconnected.

An IPP in this situation would not need to study any of the transmission providers' first-tier markets, just as would be the case if it were a generator located within the transmission provider's home balancing authority area.

However, the transmission provider, in all cases, would consider the IPP generation capacity as first-tier generation when conducting its SIL studies and indicative screens.

See

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232 n.217.

64. Finally, we adopt the proposal to require an IPP in a generation-only balancing authority area that is directly interconnected to a transmission provider at a trading hub to provide indicative screens that study itself in the balancing authority area of each transmission provider that is directly interconnected at the trading hub

and to assume that all of its uncommitted capacity may compete in each of those balancing authority areas.

If the uncommitted capacity of an IPP studying a balancing area authority directly interconnected to a trading hub exceeds the transmission provider's SIL, then the capacity assumed available to compete in that balancing authority area will be equal to the SIL.

As noted in the NOPR, when we state that the transmission providers' balancing authority areas are directly interconnected at the hub we are assuming that all such balancing authority areas are directly interconnected with each other. NOPR, FERC Stats. & Regs. ¶ 32,702 at P 56 n.58.

For example, if an IPP in a generation-only balancing authority area in the desert southwest is directly interconnected to a transmission provider at the Palo Verde trading hub at the Palo Verde and Hassayampa switchyards, then the IPP would provide screens that study all of its uncommitted capacity in each balancing authority area that is directly interconnected at the trading hub. An IPP in this situation would not need to study any markets that are first-tier to the various balancing authority areas that are directly interconnected at the trading hub.

65. We appreciate the concerns of Solomon/Arenchild that this requirement is overly burdensome, but think the proposal achieves an appropriate balance. Historically, these sellers frequently failed the indicative screens for their home markets since they often own or control the majority of installed capacity, but have no associated load from which to reduce their market shares. The Commission's approach in this Final Rule likely will obviate the need to submit a DPT to rebut the presumption of market power that results from failure of the indicative screens, which typically is more burdensome and expensive than preparing indicative screens for multiple markets. In addition, the obligation to submit screens for all balancing authority areas directly interconnected to a trading hub would apply to a limited number of market-based rate sellers and these sellers could rely on previously-accepted studies to complete their indicative screen analyses. We believe that this approach helps sellers by providing explicit guidance on the definition of the default market for their specific situation.

66. In response to Solomon/Arenchild's concern that a transmission provider would need to conduct two SIL studies, we clarify that SIL studies should consider the IPP's generation capacity as first-tier generation to each balancing authority area studied. There would be no need to conduct a second SIL study that assumes that the IPP is located within a transmission provider's balancing authority area. However, if an IPP has a long-term firm transmission reservation into a particular transmission provider's balancing authority area for all or a portion of its output, then the SIL study would have to reflect the fact that the IPP's generation capacity associated with the transmission reservation would be a firm import to that specific transmission provider. However, multiple SIL studies would not need to be performed; in this case, the IPP's generation capacity associated with the transmission reservation would be modeled as a firm import to the relevant transmission provider's balancing authority area.

67. With regard to requests that the Commission clarify that, to the extent a seller fails the indicative screen in the balancing authority area(s) it is directly interconnected to, sales at hubs are treated as “at the metered boundary”

of a seller's mitigated balancing authority area, and hence, market-based rate sales at hubs are allowed, we clarify as follows. An IPP would be allowed to make market-based rate sales at a trading hub if it loses market-based rate authority in one of the markets connected to the trading hub, so long as the hub is not located within the market in which the IPP is prohibited from selling.

Mitigated sellers are allowed to make market-based rate sales for export at the metered boundary between a mitigated balancing authority area and a balancing authority area in which the seller has market-based rate authority.

See

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 819-821.

Resale of any sort by an affiliate of the mitigated seller into the seller's mitigated balancing authority area(s) (

i.e.,

by looping power through adjacent markets) are violations of a Commission-approved tariff that may also, depending on the facts, violate the Commission's market manipulation regulations.

See id.

P 831.

68. We find Broehm/Taylor's request that the Commission require all market-based rate sellers to report their historical sales and transmission reservation data and to use such data to define the relevant geographic market, including markets beyond the first-tier, to be outside the scope of this rulemaking. This aspect of the NOPR proposal is limited to the relevant geographic market for IPPs in generation-only balancing authority areas.

69. We interpret EPSA's reference to nested balancing authority areas to mean generation-only balancing authority areas that are embedded within a transmission provider's balancing authority area. With regard to EPSA's request to require IPPs in generation-only balancing authority areas to provide indicative screens for first-tier balancing authority areas when there is network deliverability from the embedded balancing authority area through the interconnected balancing authority area to the first-tier balancing authority areas, we reiterate that an IPP in this situation would not need to study the transmission provider's first-tier markets, even if there is available transmission capacity. As noted above, if an IPP is located in a generation-only balancing authority area that is embedded within a transmission provider's balancing authority area, and that balancing authority area is the only balancing authority that the IPP's generation-only balancing authority area is directly interconnected with, then the IPP only needs to study that transmission provider's balancing authority area.

70. We clarify, in response to the request from Solomon/Arenchild, that the Commission's proposal also is meant to apply to quasi-generation-only balancing authority areas such as Ohio Valley Electric Corporation, Alcoa Power Generating, Inc.-Yadkin Division and Electric Energy Inc. We interpret EEI's request for the Commission to consider applying the proposal to entities that are not IPPs and entities that have a

de minimis

amount of load

in their balancing authority areas to also be referring to quasi-generation-only balancing authority areas.

71. In response to EEI's request, we clarify that an IPP in a generation-only balancing authority area that is directly interconnected to a hub would need to perform the market power analyses only for the home market of each transmission provider connected to the hub, not the transmission provider's first-tier adjacent markets. However, we decline to grant EEI's request to allow IPPs to provide a single analysis for all balancing authority areas interconnected to the trading hub and Solomon/Arenchild's similar request for broader markets to be considered. Preparing a single analysis for all balancing authority areas interconnected to a trading hub would require that these areas be combined into a single, consolidated market. We believe that such a request is beyond the scope of this proceeding.

See

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 268 (“[a]ny proposal to use an alternative geographic market (

i.e.,

a market other than the default geographic market) must include a demonstration regarding whether there are frequently binding transmission constraints . . . that prevent competing supply from reaching customers within the proposed alternative geographic market.”).

4. Reporting Format for the Indicative Screens and SIL Submittals 1 and 2

a. Commission Proposal

72. When submitting indicative screens as part of a horizontal market power analysis, sellers are required to use the standard screen formats adopted by the Commission in Order Nos. 697 and 697-A, which are provided in appendix A to subpart H of part 35.

Although sellers currently submit their indicative screens using the standard formats, they perform their own mathematical calculations. In the NOPR, the Commission noted that in

Puget Sound Energy, Inc.

the Commission adopted standardized formats for reporting SIL study results, which includes Submittal 1, a spreadsheet that calculates the SIL values to be used in the indicative screens. However, the Commission noted in the NOPR that the current standard screen formats for indicative screens does not have a row for SIL values even though the Uncommitted Capacity Import values are constrained by the SIL values from row 10 of Submittal 1 used to report SIL study results.

The Commission noted in the NOPR that the market share screen was inadvertently deleted from appendix A to subpart H of part 35 at the time that the Commission made a correction to the pivotal supplier screen in Order No. 697-A. NOPR, FERC Stats. & Regs. ¶ 32,702 at P 42 n.39.

135 FERC ¶ 61,254 (2011) (

Puget

73. Thus, the Commission proposed to amend the indicative screen reporting formats in appendix A of subpart H of part 35. The Commission proposed that appendix A include new rows for SIL Values, Long-Term Firm Purchases (from outside the study area), and Remote Capacity (from outside the study area) in both the pivotal supplier and market share screen reporting formats. The Commission stated that including a row in the indicative screens for SIL Values will help reinforce the relationship between affiliated and non-affiliated generation capacity imports and the SIL value. The Commission also proposed to modify the descriptive text of the rows in the indicative screens for Installed Capacity, Long-Term Firm Purchases, Long-Term Firm Sales, and Uncommitted Capacity Imports.

The Commission stated that the new rows and their descriptions will clarify whether the resources are either inside or outside the study area for Installed Capacity and Long-Term Firm Purchases. Furthermore, the description for Uncommitted Capacity Imports will now be consistent across both indicative screens. The Commission provided an example of the proposed new indicative screens reporting formats in appendix A of the NOPR.

The Commission proposed to change the phrase “Imported Power” in Rows D and H of the pivotal supplier screen to “Uncommitted Capacity Imports.” The Commission also proposed to make the same change to Row E of the Market Share Screen. Thus, under this proposal, all four rows in the indicative screens will have the same text for this field, which represents affiliate and non-affiliate uncommitted capacity able to be imported from the first tier.

74. The Commission proposed to revise the regulations at 18 CFR 35.37(c)(4) to require sellers to file the indicative screens in a workable electronic spreadsheet format.

The Commission also proposed to post on the Commission's Web site a pre-programmed spreadsheet as an example that sellers may use to submit their indicative screens.

“Workable electronic spreadsheet” refers to a machine readable file with intact, working formulas as opposed to a scanned document such as an Adobe PDF file.

The Commission explained in the NOPR that if a seller chooses to create its own workable electronic spreadsheet, the file it submits must have the same format as the sample spreadsheet on the Commission Web site.

75. Next, the Commission proposed to add a paragraph to the end of section 35.37(c), making it paragraph (5), to codify the Commission's requirement that sellers submitting SIL studies adhere to the direction and required format for Submittals 1 and 2 found on the Commission's Web site

and submit their information, as instructed, in workable electronic spreadsheets.

The sample spreadsheets for Submittals 1 and 2 are found at the Commission's Web site at

http://www.ferc.gov/industries/electric/gen-info/mbr/authorization.asp

under “Quick Links.”

b. Comments

76. APPA/NRECA and Golden Spread state that they support requiring sellers to file the indicative screens in a workable, electronic spreadsheet format.

EEI states that to the extent that the Commission's proposal simply reflects the Commission's current requirements for conducting the indicative screens and

Puget

submittal analyses, the changes are appropriate and reasonable.

APPA/NRECA at 4; Golden Spread at 7.

EEI at 9.

77. EEI requests that the Commission specify that it simply wants market-based rate sellers to file the information electronically using standard formats such as Adobe, Excel, or Word. EEI adds that if the Commission has something more complex in mind, it should explain the need for a more complex approach and should work with the regulated community in developing the new formats that will be posted on the FERC Web site, and in preparing other such guidance, information, and requirements related to the market-based rate program, to ensure that all are reasonable, clear, accurate, easy to use, and most cost-effective.

Id.

at 9-10.

78. Solomon/Arenchild state that the proposal to require sellers to provide a summary spreadsheet of the SIL components used to calculate the SIL values in the electronic spreadsheet format provided on the Commission's Web site is potentially helpful but seek clarification as to whether only Line 10 of Submittal 1 is required to be filed publicly.

Solomon/Arenchild at 11-12.

79. El Paso commends the proposal to add new rows to clearly identify Long-Term Firm Purchases and Remote Capacity from outside the study area. It states that these reporting modifications will not only provide clarity and transparency for the Commission's review, but will also correctly recognize traditional entities, like El Paso, which have invested in remote generation capacity to serve their native load customers.

El Paso states that the Commission should extend its proposal further and apply it to the study of first-tier balancing authority areas. El Paso states that the Commission's proposed modifications to the standard screen

formats in appendix A do not consider when a seller with remote generation performs the analysis for the balancing authority areas market where its remote generation is located. El Paso recommends that the Commission extend its proposal to modify the horizontal screen formats to add the following rows to the screen formats in appendix A: (i) “Seller Native Load outside the study area” as a separate line in row K of the Market Share Analysis and (ii) “Amount of Seller Load outside the study area attributable to Seller Capacity inside the study area, if any” as a separate line in row N of the Pivotal Supplier Analysis.

El Paso at 2-3.

Id.

at 3-4.

c. Commission Determination

80. We adopt the NOPR proposal to amend the indicative screen reporting formats in appendix A of subpart H of part 35 to include new rows for SIL Values, Long-Term Firm Purchases (from outside the study area), and Remote Capacity (from outside the study area) in both the pivotal supplier and market share screen reporting formats. We also adopt the NOPR proposal to revise the regulations at 18 CFR 35.37, as proposed in the NOPR, to require sellers to file the indicative screens in a workable electronic spreadsheet format and to codify the requirement that sellers submitting SIL studies adhere to the direction and required formats for SIL Submittals 1 and 2 found on the Commission's Web site and submit their information in workable electronic spreadsheets. The adopted indicative screen reporting formats for appendix A to subpart H is provided in appendix A of this Final Rule.

81. In response to EEI's request that the Commission specify that it simply wants market-based rate sellers to file the information electronically using standard formats such as Adobe, Excel, or Word, we clarify that Excel or another spreadsheet format will be acceptable but an Adobe PDF file will not be acceptable. As the Commission stated in the NOPR, a “workable electronic spreadsheet” refers to a machine readable file with intact, working formulas as opposed to a scanned document such as an Adobe PDF file. If a seller chooses to create its own workable electronic spreadsheet, the file it submits must have the same format as the sample spreadsheet on the Commission Web site.

It must have one worksheet for each of the indicative screens and each screen must have the same exact rows, columns, and descriptive text as the sample worksheets. Cells requiring negative values must be pre-programmed to only allow negative values. Likewise, cells with calculated values must contain a working formula that calculates the value for that cell. The file must be submitted in one of the spreadsheet file formats accepted by the Commission for electronic filing. The list of acceptable file formats can be found at the Commission's Web site:

http://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp

82. In response to Solomon/Arenchild's request that the Commission clarify whether only row 10 of Submittal 1 is required to be filed publicly, we clarify that the Commission expects that all of Submittal 1, not just row 10, will be filed publicly. Submittal 1 provides summary numeric data showing how the SIL values were calculated for a given relevant geographic market and some of this data already is publicly available. While we discourage submitting any portion of Submittal 1 as privileged, to the extent a filer intends to request privileged treatment for any portion of Submittal 1 or any other portion of its filing, such filing must comply with 18 CFR 388.112, including the justification for privileged treatment,

i.e.,

why the information is exempt from disclosure under the mandatory public disclosure requirements of the Freedom of Information Act, 5 U.S.C. 552 (2012).

83. We believe there is no need to expand the indicative screens as proposed by El Paso because the scenario El Paso describes can be addressed within the screens, as amended by this Final Rule. However, we clarify that a seller with remote generation serving the seller's home balancing authority area (rather than serving the balancing authority area where the generation is physically located) should account for that generation capacity in row C “Long-Term Firm Sales (in and outside the study area)” if that generation is used to serve load in the seller's home study area by virtue of dynamic scheduling and/or long-term firm transmission reservations. If the seller's remote generation is not committed to serving load in the seller's home balancing authority area, then that generation should be studied as uncommitted generation in the first-tier balancing authority area where it is located.

5. Competing Imports

a. Commission Proposal

84. In the NOPR, the Commission noted that it permits sellers to make simplifying assumptions, where appropriate, and to submit streamlined horizontal market power analyses. The Commission noted that Order No. 697 provided that “ `a seller, where appropriate, can make simplifying assumptions, such as performing the indicative screens assuming no import capacity or treating the host balancing authority area utility as the only other competitor.' ”

In the NOPR, the Commission clarified that the phrase “assuming no import capacity” means that a seller may assume “no

competing

import capacity” from the first-tier area (

i.e.,

directly interconnected balancing authority areas or markets).

The Commission further clarified that the seller must still include any uncommitted capacity that it and its affiliates can import into the study area.

NOPR, FERC Stats. & Regs. ¶ 32,702 at P 66 (quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 321).

Id.

P 67 (emphasis in original).

b. Comments

85. EEI, APPA/NRECA, and Golden Spread support the Commission's proposed clarifications regarding sellers performing simplified indicative screens assuming no competing import capacity.

100

EEI at 10; APPA/NRECA at 4; Golden Spread at 7.

c. Commission Determination

86. We confirm the Commission's clarification in the NOPR regarding competing import capacity. Specifically, “assuming no import capacity” means that a seller may assume “no

competing

import capacity” from the first-tier markets (

i.e.,

adjacent balancing authority areas or markets). This clarification is consistent with the April 14, 2004 Order

101

and other Commission orders.

102

The seller must still include any uncommitted capacity that it and its affiliates can import into the study area.

101

AEP Power Marketing, Inc. et al.,

107 FERC ¶ 61,018, at P 38 (April 14 Order),

order on reh'g,

108 FERC ¶ 61,026 (2004) (“Where appropriate, the screens allow the applicant to submit streamlined applications or to forego the generation market power analysis entirely and, in the alternative, go directly to mitigation. For example, if an applicant would pass the screens without considering

competing

supplies from adjacent control areas, the applicant need not include such imports in its studies.” (emphasis added)).

102

See, e.g., Acadia Power Partners, LLC et al.,

107 FERC ¶ 61,168, at P 12 (2004) (“We remind applicants that they may provide streamlined applications, where appropriate, to show that they pass both screens. For example, if an applicant would pass both screens without considering

competing

supplies imported from adjacent control areas, the applicant need not include such imports.” (emphasis added) (footnote omitted)).

6. Capacity Ratings

a. Commission Proposal

87. In the NOPR, the Commission noted that it allows sellers submitting indicative screens to rate their generation facilities using either nameplate or seasonal capacity ratings.

The Commission stated that Order No. 697 allows sellers with energy-limited resources, such as hydroelectric and wind generation facilities, to provide an analysis based on historical capacity factors reflecting the use of a five-year average capacity factor, including a sensitivity test using the lowest and highest capacity factors for the previous five years. The Commission noted that since the issuance of Order No. 697, the Commission has recognized that sellers with newly-built energy-limited generation facilities may not have five years of historical data and has allowed the use of the five most recent years of regional average capacity factors from the Energy Information Administration (EIA) to determine capacity factors for those resources.

88. In the NOPR, the Commission proposed to identify solar technologies as energy-limited generation resources and to allow such sellers to use either nameplate capacity or five-year historical average capacity ratings to determine the capacity rating for their solar technology generation resources. The Commission stated that similar to other energy-limited generation resources, sellers using the five-year average capacity factor must include sensitivity tests using the lowest and highest capacity factors for the previous five years. The Commission proposed that sellers with energy-limited generation facilities (including solar technologies) that do not have five years of historical data may use nameplate capacity, or the EIA-derived, regional capacity factor for the previous five years appropriate to their specific technology as defined in the EIA publication

Annual Energy Outlook,

103

but may not use seasonal ratings.

104

For sellers using EIA-derived estimates, the Commission proposed to require that sellers submit their calculation of the regional capacity factor as well as copies of the appropriate tables of regional generation capacity ratings from EIA's

Annual Energy Outlook

in their filing.

103

See

EIA, Annual Energy Outlook (May 2014),

available at http://www.eia.gov/forecasts/aeo/source_renewable.cfm.

In Table 58 through Table 58.9 “Renewable Energy Generation by Fuel—(by Area),” EIA provides data for the total generating capacity, and actual (or estimated) electricity generated by renewable type for 22 “electricity market module regions” covering the lower 48 states. After converting the inputs into matching units, sellers can divide actual (or estimated) electricity generated by installed capacity to find the capacity factor.

104

The Commission stated that sellers should use either nameplate, a five-year average of historical data, or EIA-derived five-year average regional capacity factors instead of seasonal capacity factors for energy-limited resources. The Commission noted that a five-year average wind capacity factor derived from EIA regional data was an appropriate proxy for wind generators that do not have five years of historical data.

89. In addition, the Commission sought industry input in identifying additional technologies that are energy-limited generation resources, and what capacity factors should be used to rate them. The Commission acknowledged that solar photovoltaic facilities will effectively function with zero capacity during nighttime hours or during heavy overcast conditions, as the sun does not provide much, if any, solar energy from solar photovoltaic facilities during such conditions. Thus, the Commission sought comment on whether these operating characteristics warrant establishing a different method of setting capacity factors for solar generation as compared to other generation technologies.

90. Also in the NOPR, the Commission proposed to clarify that, within each filing, a seller must use the same capacity rating methodology for similar generation assets. The Commission stated that if a seller chooses in a particular filing to use seasonal ratings for one of its thermal units, it must use seasonal ratings for all of its thermal units in that filing. Likewise, if the seller chooses to use an alternative rating methodology, such as the five-year average for any energy-limited generation resource, it must use the five-year average for all energy-limited generation resources in that filing for which five years of historical data is available; otherwise it must use the EIA-derived capacity factors for those resources for which the seller does not have five years of data. The Commission stated that the seller must specify in the filing's transmittal letter or accompanying testimony, and in the generation asset appendix, which rating methodologies it is using. The seller must use the specified rating methodologies consistently throughout its entire filing, including in its transmittal letter, asset appendix, and indicative screens. The Commission noted that this proposal does not preclude the seller from using a different capacity rating methodology for each type of generation facility (thermal or energy limited) in subsequent filings (

e.g.,

in its initial filing a seller may use nameplate ratings for its thermal units, then in its next filing choose to use seasonal ratings for its thermal units).

b. Comments

i. Identify Solar as Energy Limited

91. Many commenters support the Commission's proposal to identify solar technologies as energy-limited generation resources.

105

See, e.g.,

E.ON at 4; NextEra at 6; EEI at 11; SunEdison, Inc. (SunEdison) at 1.

ii. Use of Capacity Factors

92. E.ON agrees with the Commission's proposal to allow a seller that owns or controls solar technology generating resources to use either nameplate capacity or five-year historical average capacity ratings to determine capacity rating, and to use EIA-derived, regional capacity factor estimates if the seller does not have five-year historical capacity data. EEI asks the Commission to consider allowing a given seller, with or without five years of historical data, to use an alternative to the EIA regional capacity ratings if the seller can demonstrate that the alternative is more accurate as to one or more of the specific solar-generation facilities at issue in the filing, while allowing use of actual or historical data for other facilities in the same market.

93. Many commenters sought clarification on the Commission's proposals regarding use of capacity factors for energy-limited resources. E.ON seeks clarification that if the seller relies on EIA-derived capacity factors for a solar resource, it is not precluded from using actual historical five-year data to establish capacity factors for its other energy-limited resources.

106

SoCal Edison requests clarification as to the calculation of the five-year average capacity factor for a given triennial; specifically, what periods do the five years cover, and what is the average, is it by unit or technology.

107

SoCal Edison also asks if the EIA-derived capacity factor is used, whether it is to apply to nameplate capacity or seasonal ratings.

108

EEI requests that the Commission clarify that companies can use the average of the data available in the EIA data tables, up to a maximum of a five-year average.

109

SoCal Edison strongly supports allowing a seller to use nameplate capacity ratings anytime a seller is required to file only an asset appendix.

106

E.ON at 5.

107

SoCal Edison at 15-16.

108

Id.

at 16.

109

EEI at 12 (noting that some of the EIA tables only cover 2011 forward, so five years of EIA data might not be available).

94. Broehm/Taylor state that the Commission should require use of the average historical capacity factor of existing energy limited resources with the same technologies within the same region instead of the EIA-derived, regional capacity factor estimates proposed by the Commission. Broehm/Taylor state that the EIA-derived,

regional capacity factor estimates are an annual average value that does not reflect seasonality, thereby creating a disconnect with the Commission's indicative screens, which are required to be performed on a seasonal basis. Broehm/Taylor further state that generation patterns for certain energy limited resources such as solar and wind may vary by months and seasons in certain locations.

110

Broehm/Taylor at 6.

95. Further, Broehm/Taylor state that they “seek Commission clarification on whether the availability factors

111

are required to be applied only to nameplate capacity ratings of energy limited resources.” Broehm/Taylor ask whether the Commission's statement “that sellers without five years of historical data cannot use seasonal ratings imply that the availability factors should not be applied to seasonal ratings.” Broehm/Taylor state that, if this is the case, it is appropriate to apply the same availability calculation to both new and existing units of energy limited resources. Broehm/Taylor caution that sellers need to be consistent in using capacity ratings for calculating historical capacity factors and if the capacity ratings are nameplate in the historical capacity factor calculation, these capacity factors should be applied to nameplate capacity ratings.

112

111

Broehm/Taylor use the term “availability factors” several times. The Commission has never used availability factors as a basis for de-rating generation capacity.

112

Broehm/Taylor at 7.

iii. Identifying Other Energy-Limited Resources

96. In response to the Commission's request for industry input in identifying additional technologies that are energy-limited generation resources, SoCal Edison identifies the following: Hydro, wind, solar, biomass, and geothermal resources. It further states that it believes this list can and should be expanded as appropriate.

113

SoCal Edison at 15.

iv. Require Same Rating Methodology for All Resources of the Same Technology

97. NextEra states that it does not support requiring the same rating methodology for all resources of the same technology. To better reflect a seller's market power, NextEra urges the Commission to provide sellers the option in submitting indicative screens to reflect, if known, the historical capability for resources of the same technology and, if unknown, to submit EIA regional data for those specific resources.

114

EEI echoes these concerns stating that sellers should be able to use five-year historical data for particular energy-limited generation resources where the sellers have the information, even as they may need to use a regional capacity factor for other such facilities for which they do not have the information.

115

114

NextEra at 7.

115

EEI at 11.

v. Limiting Capacity Standard to Peak Hours for Solar

98. FirstEnergy states that the Commission properly recognized in the NOPR that solar photovoltaic facilities will effectively function with zero capacity during nighttime hours or during heavy overcast conditions.

116

FirstEnergy states that in the event that the Commission permits capacity ratings of solar technologies to be based on historical generation output rather than on nameplate ratings, such capacity ratings should be based on the output of such generating facilities during peak day-light hours only.

117

Idaho Power believes that using peak hours for determining solar capacity factors would be appropriate and would provide better data.

118

Broehm/Taylor state that the Commission did not provide the definition of peak hours and suggests that the Commission give reasonable flexibility to sellers with regard to the number of peak hours when calculating availability factors for energy limited technologies as long as sellers justify their approach.

119

116

FirstEnergy at 7.

117

Id.

at 8.

118

Idaho Power at 3.

119

Broehm/Taylor at 7-8.

99. However, SoCal Edison contends that the screens are not designed for a particular hour or the peak hour for many types of generation, all hours should be considered when calculating the capacity rating.

120

EPSA states that using peak hours will not provide a better measure of capacity for solar technology generation resources, and consistent with other intermittent energy resources, such as wind, a historical average capacity rating during peak hours would more accurately represent output of the facility incorporating the variability of output given environmental and weather events that affect solar generation resources output.

121

E.ON states that it is unclear that the use of peak hours is appropriate. It states that these energy-limited resources can provide energy in daylight hours and not necessarily only in peak-defined hours. E.ON asks that if the Commission ultimately adopts some limiting capacity standard, whether that is peak hours or otherwise, that the Commission clarify that the solar photovoltaic resource would not be precluded from selling energy products at market-based rates in any off-peak hours.

122

EEI states that the Commission should allow a seller to use an alternative to EIA regional capacity ratings if they can demonstrate that the alternative is more accurate as to one or more of the specific solar facilities at issue in the filing. EEI states that the Commission should give sellers the option to base solar capacity factors on peak hours rather than all hours, but should not require them to do so.

123

NextEra states that as the horizontal market power indicative screens are intended to study peak hours, it believes that it may be more consistent to require the nameplate capacity rating, which for solar technologies largely correlate to peak load times, rather than the five-year average capacity factor or EIA regional data.

124

120

SoCal Edison at 15.

121

EPSA at 6-7.

122

E.ON at 5.

123

EEI at 11.

124

NextEra at 6.

c. Commission Determination

100. We adopt the NOPR proposals with certain modifications and clarifications. Specifically, we will allow sellers with energy-limited generation facilities to use capacity factors to de-rate those facilities in their market power analysis, with certain clarifications discussed below. We will also identify solar thermal technologies as energy-limited technologies, but require the use of nameplate capacity ratings for solar photovoltaic units.

i. Identify Solar as Energy Limited

101. We accept the NOPR proposal to identify solar photovoltaic and solar thermal facilities as energy-limited generation resources. However, as discussed below we will continue to require a seller to use nameplate ratings for its solar photovoltaic facilities. We will allow a seller to treat solar thermal facilities in the same manner as other energy-limited resources. If a seller chooses to use a rating based on a five-year average capacity factor for solar thermal facilities in their filings, they must follow all of the requirements discussed in this Final Rule regarding the use of capacity factors. Further, a seller must use the same rating methodology for non-affiliated solar thermal facilities, as it does for its own solar thermal facilities.

102. For solar photovoltaic facilities we adopt NextEra's proposal and

require the use of nameplate capacity in the asset appendices and market power studies. As noted above, there was no consensus among commenters as to whether to de-rate solar photovoltaic facilities based on either an annual capacity factor or an on-peak capacity factor. Given the generation profile of solar photovoltaic facilities (

i.e.,

output is highest during peak hours), we believe that use of nameplate ratings is reasonable for the purposes of the horizontal market power analysis. In addition, the Commission's experience to date is that sellers typically use nameplate ratings for solar photovoltaic facilities in their market power analyses and asset appendices, so this requirement is consistent with current industry practice. Although we are requiring the use of nameplate capacity for solar photovoltaic resources, we clarify that adopting the use of a limiting capacity factor, such as peak hours, for any generation resource, would not preclude that resource from selling energy products at market-based rates in off-peak hours.

125

E.ON at 5.

ii. Use of Capacity Factors

103. We will continue to allow a seller with energy-limited generation facilities other than solar photovoltaic to use capacity factors to de-rate those facilities in its market power analysis. For purposes of this discussion we are excluding solar photovoltaic from using capacity factors; as discussed above, solar photovoltaic will be rated on nameplate rating. We clarify that for energy-limited facilities, a seller may use either the nameplate capacity or a rating based on a five-year average capacity factor. When a seller chooses to use a certain rating methodology for an energy-limited resource, it must consistently use that rating methodology for that specific type of energy-limited resource in its market-power studies (

i.e.,

its energy-limited facilities, and non-affiliated energy-limited facilities).

126

A seller must specify in the filing's transmittal letter or accompanying testimony, and in the applicable asset appendices, which rating methodology it is using for each technology. To the extent that a seller chooses to use a capacity factor, it must use a unit-specific, historical five-year average for any unit for which it can obtain five or more years of operating history, and use the EIA-derived regional capacity factor for any unit for which it is unable to obtain five years of operating history.

127

126

This is a change from the NOPR proposal to require that if a seller uses an alternative rating methodology for any energy-limited resource, it must use an alternative rating for all energy-limited resources.

127

Sellers must use five years of historical data even if that means using data from multiple EIA reports. We recognize that this may necessitate sellers including years after the study period. However, this information is still historical and therefore consistent with the requirements of Order No. 697, FERC Stats. & Regs. ¶ 31,252, at PP 298-301.

104. A seller must use the same capacity rating method for non-affiliated energy-limited facilities that it uses to rate the capacity of its own energy-limited facilities when they are preparing their market-power analyses. Thus, a seller that uses nameplate ratings for its own energy-limited facilities should use nameplate ratings for all other energy-limited facilities included in their horizontal market power studies. Likewise, a seller that de-rate its own energy-limited facilities using five-year average capacity factors should de-rate non-affiliated energy-limited facilities using EIA regional average capacity factors in its screens and DPTs. Consistent with Order No. 697, we will continue to require a seller that de-rates its energy-limited facilities to include sensitivity tests using the lowest capacity factor in the previous five years, and the highest capacity factor in the previous five years.

128

Id.

P 344.

105. In the NOPR the Commission stated that a seller would be allowed to use different capacity rating methodologies in subsequent filings. However, we find here that a seller must use the same rating methodology in subsequent filings until the next updated triennial market power analysis. Thus, a seller would not be allowed to change its rating methodologies until its next updated triennial market power analysis (

e.g.,

if a seller uses nameplate ratings for nuclear plants in its triennial, it must use nameplate for nuclear in all filings, until its subsequent triennial). If a seller is a Category 1 seller (

i.e.,

not required to file an updated triennial market power analysis), it would be allowed to change rating methodologies when its region's transmission owners' updated triennial market power analyses are due. We reject SoCal Edison's request to allow a seller to switch rating methods just because it is filing an asset appendix. A seller must use the same rating methodology for each specific technology in all filings. We do not see this as more burdensome, because the capacity rating for most facilities will not change between filings. In fact, we believe this may be less burdensome because companies will not have different versions of their asset appendix.

106. We adopt the NOPR proposal to require that a seller submit its calculations of the regional capacity factor as well as copies of the appropriate tables of regional generation capacity ratings from EIA's

Annual Energy Outlook

in its filing. We also clarify that when using the EIA tables to calculate a regional average for energy-limited facilities, a seller should calculate capacity factors using the most recent five calendar years of data available in the tables. Further, the capacity factors should be applied per unit, to each generation facility and applied to the facilities' nameplate ratings. Although we intend the use of EIA regional capacity factors as a simple and objective means for a seller to de-rate energy-limited facilities, we will allow a seller to propose alternative methods of de-rating such facilities in response to EEI and Broehm/Taylor's comments. A seller proposing alternative methodologies must provide the data and calculations used to derive the capacity factors to the Commission in public, non-privileged files. Further, the seller must also provide the EIA regional average capacity factor as a comparison and explain why it believes its methodology provides a more accurate capacity rating than the EIA regional average. We will decide on a case-by-case basis whether to accept any such proposed alternative methodology.

iii. Identifying Other Energy-limited Resources

107. In the NOPR, the Commission sought industry input in identifying additional technologies that are energy-limited generation resources, and what capacity factors should be used to rate them. As discussed above, we adopt the proposal to identify solar thermal technologies as energy limited. However, given that the Commission only received one comment identifying additional technologies (other than solar) and the Commission did not receive any comments regarding what capacity factors should be used to rate additional technologies, we will not specifically identify any additional technologies as energy limited at this time.

7. Reporting of Long-Term Firm Purchases

a. Commission Proposal

108. In Order No. 697, the Commission stated that a seller's uncommitted capacity, as calculated in the indicative screens, is determined by adding the total nameplate or seasonal

capacity of generation owned or controlled through contract and long-term firm capacity purchases, minus operating reserves, native load commitments, and long-term firm sales.

129

The Commission also stated that generation capacity associated with contracts that confer operational control of a given facility to an entity other than the owner must be assigned to the entity exercising control over that facility. Therefore, market-based rate sellers have been required to report long-term firm purchases in row B of the indicative screens (Long-Term Firm Purchases) only if the purchase granted them control of the capacity. Similarly, for purposes of reporting a change in status, sellers have been required to report long-term firm capacity purchases when assessing their cumulative generation capacity only if such purchases confer control of such capacity to them.

130

In the NOPR, the Commission noted that this requirement applies to long-term firm energy purchases to the extent that the long-term firm energy purchase would allow the purchaser to control generation capacity.

131

129

Id.

P 38.

130

See

Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at PP 99-101.

131

NOPR, FERC Stats. & Regs. ¶ 32,702 at P 73 (citing Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at PP 99-101).

109. In the NOPR, the Commission noted that the limited reporting of long-term firm purchases may create errors or misleading results in the indicative screens submitted by some sellers including incorrectly-sized markets and negative market shares for franchised public utilities and inconsistencies between the SIL values reported in the screens and the SIL values calculated for the relevant market or balancing authority area. The Commission noted instances where neither the seller nor the purchaser under a long-term firm power sale is attributed with the generation capacity that is used to make the sale because the seller deducted the capacity committed under the long-term firm power sale from its uncommitted capacity while the purchaser followed existing Commission policy and, because it did not “control” this capacity, did not include it as part of its uncommitted capacity.

110. The Commission proposed in the NOPR to modify the policy with respect to the reporting of long-term firm purchases in the indicative screens. Specifically, the Commission proposed to require applicants

132

under the market-based rate program to report all of their long-term firm purchases of capacity and/or energy in their indicative screens and asset appendices, where the purchaser has an associated long-term firm transmission reservation, regardless of whether the seller has operational control over the generation capacity supplying the purchased power.

133

The Commission proposed that if the long-term firm purchase involves the sale of energy and does not identify an associated capacity amount, the purchaser must convert the amount of energy to which it is entitled into an amount of generation capacity for purposes of its indicative screens and asset appendices,

i.e.,

include the amount of the capacity as long-term firm purchases in rows B (Long-Term Firm Purchases (from inside the study area)) or B1 (Long-Term Firm Purchases (from outside the study area)) of the proposed revised indicative screens and include it in its asset appendix. The Commission proposed that a seller under that firm power purchase agreement must continue this approach the next time it submits a market-based rate triennial or change in status filing with the Commission,

i.e.,

convert the energy into capacity and include the amount of capacity as a long-term firm sale in row C (Long-Term Firm Sales).

134

The Commission proposed that, when making these filings, both the purchaser and the seller must show how they made the energy-to-capacity conversion. Although the Commission proposed this attribution of capacity as a general policy, the Commission noted that applicants or intervenors may raise fact-specific circumstances that they believe may support a different attribution of capacity.

132

Although we generally use the term “sellers” elsewhere in the Final Rule when referring to market-based rate sellers and applicants, in this section, we refer to such sellers as “applicants” to avoid confusion when discussing market-based rate sellers who are purchasers under long-term firm power purchase agreements.

133

NOPR, FERC Stats. & Regs. ¶ 32,702 at P 79. In

Vantage Wind, LLC,

139 FERC ¶ 61,063 (2012) (

Vantage Wind

), the Commission directed the purchasers to report all long-term firm purchases if the purchase had long-term firm transmission rights associated with those resources. In the NOPR, the Commission assumed for purposes of the proposal that all long-term firm purchases necessarily have long-term firm transmission rights associated with them. If that is not the case, the Commission stated that applicants or intervenors are free to raise fact-specific circumstances that they believe may support a different attribution of capacity. NOPR, FERC Stats. & Regs. ¶ 32,702 at P 79 n.97.

134

In the NOPR, the Commission stated that many power purchase agreements for firm energy specify an associated capacity commitment from the seller. In cases where capacity commitments are not specified in the power purchase agreement, we propose that applicants use the following formula to convert energy to capacity (on a one-year basis): [Energy (MWh)/8,760]/capacity factor = capacity (MW).

Where energy (MWh) is the total amount of energy purchased under the power purchase agreement over the calendar year; 8,760 is the total hours of a calendar year (use 8,784 in a leap year); capacity factor is actual capacity factor achieved by the unit(s) supplying the energy during the calendar year and is a measure of a generating unit's actual output over a specified period of time compared to its potential or maximum output over that same period. For example, if 700,000 MWh is the amount of firm energy purchased under a power purchase agreement during a calendar year, and the capacity factor of the generator supplying the energy is 0.8 or 80 percent, then the 700,000 MWh of energy would be converted into approximate 100 MW of capacity. That is: (700,000 MWh/8,760)/0.8 = 100 MW. NOPR, FERC Stats. & Regs. ¶ 32,702 at P 79 n.98.

111. The Commission stated that the intent of the proposed reform is to have an applicant report all long-term firm purchases that it makes where the selling entity has a legal obligation to provide the purchaser with an energy supply that cannot be interrupted for economic reasons or at the seller's discretion. If the purchaser has contractual rights to receive the output of a long-term firm energy purchase, the Commission proposed that the amount of the capacity supplying that purchase must be reported in the purchaser's screens.

112. In the NOPR, the Commission stated that the proposal to require applicants to report all of their long-term firm purchases of capacity and/or energy in their indicative screens and asset appendices is supported based on several considerations. First, it will size the market correctly and therefore improve the accuracy of the indicative screens, especially for franchised public utilities, whose indicative screens are used by the non-transmission owning sellers to prepare their own indicative screens. Currently, applicants often do not report some or all of their long-term firm purchases because they do not control these resources. Including all long-term firm purchases in the indicative screens will properly size the market and eliminate the unrealistic results (

e.g.,

negative market shares) caused by the under-reporting of generation noted above.

113. Second, the Commission stated that this proposed change will establish consistent treatment of long-term firm sales and long-term firm purchases in the indicative screens. The Commission noted that applicants typically deduct long-term firm sales without making a determination as to whether those sales confer operational control to the purchaser. The Commission explained that, in Order No. 697, it did not require that sellers make such a determination before deducting the capacity supporting long-term firm sales: “Uncommitted capacity is determined

by adding the total nameplate or seasonal capacity of generation owned or controlled through contract and firm purchases, less operating reserves, native load commitments and long-term firm sales.”

135

In Order No. 697, the Commission stated that “[s]ellers may deduct generation associated with their long-term firm requirements sales, unless the Commission disallows such deductions based on extraordinary circumstances.”

136

135

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 38 (footnotes omitted).

136

Id.

P 38 n.18.

114. In the NOPR, the Commission explained that it is only on the “buy” side of long-term firm purchases that the Commission has considered the issue of control in reporting capacity in the screens.

137

The Commission stated that the result is that some generation capacity sold under long-term power purchase agreements “disappears” from the market because neither the seller nor the purchaser includes the capacity as part of its uncommitted capacity (

i.e.,

the seller subtracts the amount sold under the long-term power purchase agreement from its capacity for purposes of its screens, but sometimes the purchaser does not add the corresponding amount to its capacity for purposes of its screens). The Commission stated that it is inevitable that some generation capacity will be excluded from the indicative screens, with resulting errors in market shares and overall market size, when differing standards are applied to long-term firm purchases and long-term firm sales with respect to the allocation of such capacity. The Commission stated that the NOPR proposal will make those standards consistent, reducing such errors.

137

Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at PP 99, 100.

115. Third, requiring the reporting of all long-term firm power purchases also will ensure consistent treatment of owned or installed capacity and long-term firm purchases in the indicative screens. The Commission stated that the horizontal market power analysis implicitly assumes that applicants control all of their owned or installed capacity listed in their indicative screens but this is not necessarily the case.

138

For example, in situations where an applicant is a minority owner of a jointly-owned generating unit, it is quite possible that the applicant will not have operational control (

i.e.,

commitment and dispatch authority) over the unit.

139

However, applicants typically include all of their owned or controlled generation capacity in the indicative screens regardless of whether they actually control the commitment and dispatch of this capacity. Accordingly, the Commission proposed that an applicant with long-term firm purchases treat such contracted-for capacity in a similar manner to an applicant that owns capacity; that is, such purchases should be included in the applicant's portfolio of generation for the indicative screens.

138

As the Commission explained in the NOPR, in Order No. 697, the Commission noted that its historical approach has been that the owner of a facility is presumed to have control of the facility unless such control has been transferred to another party by virtue of a contractual agreement. The Commission stated in Order No. 697 that it would continue its practice of assigning control to the owner absent a contractual agreement transferring such control. Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 183.

139

Another example is when a generator confers operational control to a third party through a long-term tolling agreement.

See, e.g., Shell Energy North America (US), L.P.,

135 FERC ¶ 61,090, at P 3 (2011).

116. Further, the Commission stated in the NOPR that for those applicants incorrectly reporting long-term firm power purchases in the wrong row of the indicative screens,

140

uniform reporting of these purchases will also help to ensure consistency between the SIL values reported in the screens and the Commission's accepted SIL values for the relevant market or balancing authority area. In the NOPR, the Commission stated that improperly classifying long-term firm purchases (or imports of remotely-owned installed capacity) as Imported Power in the existing screens (row D of the pivotal supplier screen and row E of the market share screen) may lead to an overstatement of the market's SIL values.

141

The Commission explained in the NOPR that this is because the sum of the values in the existing pivotal supplier screen for Seller and Affiliate Imported Power shown in row D and Non-Affiliate Imported Power shown in row H should be less than or equal to the Commission-accepted SIL values. All Commission-accepted SIL values account for (

i.e.,

subtract) long-term transmission reservations into the study area, so that they reflect the transmission capability available to competing sellers after accounting for the capability that the local utility has reserved for its own use to import power from remote resources. Thus, the Commission explained that classifying long-term firm purchases as Imported Power effectively “double counts” import capability in the screens because it adds back the import capability associated with long-term firm purchases and assumes that this capability is available to potential competitors. The Commission stated that this problem does not arise if long-term firm purchases (and imports of remotely-owned installed capacity) are properly classified in the indicative screens as Long-Term Firm Purchases (rows B1 and F1 in the proposed screen format for the pivotal screen) and Remote Capacity (rows A1 and E1 in the proposed screen format for the pivotal screen), respectively. The Commission stated that this proposal is intended to help clarify how to classify imports of firm power and remotely-owned capacity. The Commission also proposed these changes to the screen format for the market-share screen.

140

The NOPR stated that “[a]s the Commission noted in

Vantage Wind,

improperly classifying long-term firm purchases (or imports of remotely-owned installed capacity) as Imported Power in the existing screens . . . may lead to an overstatement of the market's SIL values.” NOPR, FERC Stats. & Regs. ¶ 32,702 at P 85 (citing

Vantage Wind,

139 FERC ¶ 61,063).

141

The Commission noted

Vantage Wind,

139 FERC ¶ 61,063 at P 16 (“In its updated market power analysis, Puget accounted for both its remote generation from its Colstrip plant located in Montana and its firm power purchase agreements from Bonneville Power Administration as Imported Power (Line D of the market share screen and the pivotal supplier screen) rather than as Installed Capacity (Line A of the market share screen and the pivotal supplier screen) or a Long-term Firm Purchase (Line B of the market share screen and the pivotal supplier screen), respectively. Consequently, the total SIL shown in Puget's screens exceeded the net SIL value for the Puget balancing authority area as accepted by the Commission in [

Puget,

135 FERC ¶ 61,254]. When Vantage Wind applied the Commission-approved SIL values to its analysis without making any other adjustments to Puget's screens, Vantage Wind appeared to fail the screens because Puget's capacity was underreported.”).

b. Comments

117. Commenters mostly disagree with the proposal, either supporting the Commission's existing “control test” or expressing concerns that the Commission's proposal does not actually make the reporting more accurate.

142

SoCal Edison states that the Commission's identified flaws in the control test and the current reporting of long-term purchases are not well supported and do not merit abandonment of the control test.

143

In particular, SoCal Edison disputes the “disappearing capacity” concern raised in the NOPR, asserting that generation capacity associated with long-term firm sales is reflected in some manner in the screens.

144

SoCal Edison also contends that the Commission's assertion that a long-term firm purchase is just like ownership with regard to the ability to

get energy to the market is demonstrably false in some cases.

145

142

EPSA at 10; APPA/NRECA at 21-24; SoCal Edison at 3-11; Solomon/Arenchild at 8-10; Avista at 2-4; NextEra at 8; TAPS at 2.

143

SoCal Edison at 3.

144

Id.

at 5.

145

Id.

at 11.

118. E.ON and FirstEnergy agree with the Commission's proposal.

146

FirstEnergy states that “attribution of all such capacity to the purchaser, as proposed by the FERC, will recognize appropriately the rights of the purchaser in the purchased resource and will help to improve the consistency of market power studies.”

147

E.ON requests clarification that sellers of long-term capacity in RTO markets would not be required to submit indicative screens solely because the purchaser was required to do so.

148

146

E.ON at 6; FirstEnergy at 8.

147

FirstEnergy at 8-9.

148

E.ON at 7.

119. EEI urges the Commission to engage in further dialogue, noting that some EEI members have concerns, and some agree with at least some elements of the proposal. EEI states that some members were concerned that they would lose flexibility to reflect actual ownership and control of assets in indicative screens and asset appendices, and whether they would need to report the long-term contracts in the asset appendix.

149

EEI at 12.

120. Avista/Puget state that the Commission's proposed solution goes too far and that the Commission instead should retain its current treatment of purchased capacity and/or energy based on the concept of operational control established in Order No. 697, with certain modifications to ensure that the capacity does not disappear from reports of the market.

150

To prevent generation capacity from disappearing in the indicative screens, Avista/Puget propose that the Commission modify its current policy with regard to the seller's treatment of sold energy such that it is the mirror image of the purchaser's treatment. Under Avista/Puget's proposal, generating capacity associated with a long-term sale would be assigned to the seller, for purposes of conducting the indicative screen computations, if the contract does not convey control of the capacity to the purchaser.

151

150

Avista Corp. and Puget Sound Energy, Inc. (Avista/Puget) at 2.

151

Id.

at 4.

121. TAPS expresses concerns that the proposed change may well result in inaccurate reporting and mask the market power of large sellers where they retain control over the resource(s).

152

APPA/NRECA concede that this may fix some administrative problems, but worry that the resulting indicative screens will not accurately reflect actual market shares or pivotal supplier conditions.

153

152

TAPS at 2.

153

APPA/NRECA at 21-24.

122. Indicated Utilities state that if the Commission adopts this rule, it should exempt from this requirement the capacity and/or energy associated with power purchase agreements from inherently intermittent qualifying small power production facilities entered into under 18 CFR part 292, subpart C, namely solar and wind qualifying facilities.

154

Indicated Utilities state that power purchase agreements with intermittent resource qualifying facilities are often fundamentally different from other power purchase agreements and thus warrant different treatment from that proposed in the NOPR.

155

For that reason Indicated Utilities urge the Commission to retain for such power purchase agreements its existing policy of attributing capacity and/or energy to the entity that “controls” the qualifying facilities, as that term has been used in Order No. 697.

156

154

Indicated Utilities at 2.

155

Id.

at 5.

156

IWU at 7.

123. EPSA questions the utility of this proposal and seeks clarification of how this requirement would differ from the reporting required in EQRs. EPSA states that it appears that the information required to be reported by this proposal would duplicate the information provided by sellers contained in the EQRs, which are required to be filed under current Commission regulations. EPSA suggests that if the Commission is seeking this information, then the Commission should not adopt the proposed revision but just refer to the EQR data.

157

EPSA at 9-10.

124. EPSA requests clarification that in evaluating long-term contracts for the indicative screens, sellers are still permitted to make conservative assumptions in their initial application and triennial updated market power analyses.

158

Id.

at 10.

125. Indicated Utilities state that the Commission should clarify that this proposed change—whether for intermittent qualifying small power production facilities power purchase agreements or other power purchase agreements—applies only to the indicative screens and asset appendices, and does not apply to any DPT analyses submitted to rebut a presumption of market power brought about by failure of one or both of the screens. Indicated Utilities contend that it would be consistent with the Commission's post-Order No. 697 approach for the proposed policy to apply only to the indicative screens while maintaining the current “control-based” approach to DPT analyses. Indicated Utilities state that the indicative screens are designed to be screens, while the DPT, on the other hand, is more granular and a more accurate means of assessing horizontal market power.

159

Indicated Utilities at 8-9.

126. SoCal Edison states that it does not generally object to the Commission collecting data on all long-term firm purchases through the asset appendix, but SoCal Edison asks the Commission to clarify that inclusion of a long-term firm purchase in an asset appendix does not constitute a concession that a purchase should appear in a market power screen analysis. SoCal Edison states that a seller should be permitted to rebut the presumption that any particular long-term firm purchase should be counted if the applicant is seeking to exclude the long-term firm purchase from a market power analysis. SoCal Edison further submits that if the applicant has no obligation to submit such screens, it need not rebut the presumption, but reserves the right to do so if ever requested to submit a screen analysis.

160

SoCal Edison at 12.

127. Several commenters request clarification of various aspects of the proposal. SoCal Edison requests that the Commission explain how the buyer is to obtain the capacity factor information, which may not exist, in order to convert energy-only transactions.

161

Solomon/Arenchild state that converting an energy-only contract to MW-equivalents rather than the full amount of capacity may create confusion. Solomon/Arenchild ask whether the determining characteristic is whether a capacity payment is part of the long-term contract.

162

NextEra expresses concerns with the formula proposed for converting long-term energy purchases to a capacity value.

163

NextEra suggests that rather than requiring the actual energy supplied during a calendar year in the capacity calculation, a purchaser/seller should be allowed to rely on EIA regional data for energy-limited resources. NextEra states that otherwise there could be a significant overstatement of the capacity value submitted in triennial market power updates or notices of change in status.

164

APPA/NRECA state that the proposed conversation mechanism in

footnote 98 of the NOPR calculates capacity as an average annual number, whereas the peak capacity purchased during a shorter interval in the study period would be the most relevant number.

161

Id.

at 17.

162

Solomon/Arenchild at 10-11.

163

NextEra at 9.

164

Id.

at 10.

128. SoCal Edison states that although the NOPR proposes reporting of long-term firm purchases where the purchase has an associated long-term firm transmission reservation, the concept of a long-term firm transmission reservation does not exist within the California Independent System Operator Corporation (CAISO) market. Therefore, SoCal Edison states that the Commission should clarify for CAISO and any other region that has eliminated long-term firm reservations, how this standard should be applied.

165

SoCal Edison at 13.

129. Solomon/Arenchild ask for clarification on the treatment of jointly-owned facilities. They state that although the NOPR proposal abandons the need to determine the party that controls capacity under long-term contracts, the need for letter of concurrence seems to remain. They state that because the letter of concurrence previously was tied to the issue of the degree to which each party controls a facility, and control is no longer a factor, it is difficult to understand when letters of concurrence are appropriate.

166

Solomon/Arenchild at 11.

c. Commission Determination

130. We adopt the proposal to report long-term firm purchases in the indicative screens, with modification and clarifications as discussed below. We believe that requiring applicants under the market-based rate program to report all of their long-term firm purchases of energy and/or capacity, regardless of whether the applicant has operational control of the generation capacity supplying the purchased power, will improve the accuracy of the indicative screens.

131. Some commenters contend that the proposed change will not make the screens more accurate because it may understate the market power of entities selling long-term firm capacity and/or energy.

167

However, this argument overlooks the fact that sellers in most cases already are deducting capacity sold pursuant to long-term firm contracts. The differing standards applied to purchasers and sellers with respect to control are the basis for the “disappearing capacity” problem described in the NOPR. Furthermore, as explained below, the Commission believes that it is more appropriate to attribute such capacity to the purchaser rather than the seller.

167

APPA/NRECA at 24; TAPS at 2.

132. We are not persuaded by SoCal Edison's arguments disputing the existence of a “disappearing capacity” problem under the current policy. For example, SoCal Edison claims that even if an applicant does not attribute a long-term firm energy and/or capacity purchase to itself, the associated capacity will show up in the screens as non-affiliate capacity.

168

This is potentially true only if the purchased capacity is located in the same balancing authority area or market as the purchaser because the non-affiliated capacity included in the indicative screens only includes capacity located in the study area.

169

Many of the long-term purchases reported in certain regions cross balancing authority areas,

i.e.,

the purchase is made from a resource external to the purchaser's home market. Therefore, capacity associated with long-term purchases often is not included in the indicative screens. Moreover, not reporting a long-term firm purchase from an external generation resource would make the screens inconsistent with the SILs, which account for long-term transmission reservations. Long-term firm purchases usually have an associated long-term firm transmission reservation. SoCal Edison's arguments also ignore the problems that can arise when an applicant's long-term firm purchases are recorded in an incorrect line of the indicative screens, which the Commission noted in

Vantage Wind

170

and explained in the NOPR.

168

SoCal Edison at 5.

169

The indicative screens include rows for long-term firm sales and purchases made by non-affiliated sellers. However, the existence of these rows does not support SoCal Edison's argument because a long-term firm purchase made by SoCal Edison from a seller external to SoCal Edison's market (CAISO) would not show up as a long-term firm purchase made by a non-affiliated seller in CAISO. Thus, the capacity associated with the long-term firm purchase that SoCal Edison did not report would not show up in its indicative screens for the CAISO market.

170

Vantage Wind,

139 FERC ¶ 61,063 at P 16.

133. Avista/Puget proposes to fix the “disappearing capacity” problem by allowing sellers of long-term firm energy and/or capacity to only deduct such capacity in their indicative screens if they relinquish operational control over the capacity.

171

While this proposal would solve the “disappearing capacity” problem, we find that it is more appropriate to attribute capacity from a long-term firm power purchase agreement accompanied by a long-term firm transmission reservation to a purchaser/load serving entity, rather than to the seller, because the purchaser can use that contract to meet its capacity requirements. The seller cannot withhold the power from the purchaser even though the seller has operational control over the generating unit(s) supplying the power. Power purchase agreements may give the purchaser significant economic control over the power;

e.g.,

the purchaser can bid the energy into centralized spot markets (if present).

171

Avista at 4.

134. Moreover, applying the control test to the seller would largely negate the Commission's policy with respect to fully committed generation capacity, as described elsewhere in this Final Rule. Under this policy, in order to satisfy the Commission's market-based rate requirements regarding horizontal market power, sellers may explain that their generation capacity is fully committed in lieu of including indicative screens. Today, new generating units, many of which are wind and solar units, often represent that they are fully committed under long-term power purchase agreements and deduct all of their capacity in the indicative screens or do not provide screens at all. Under Avista/Puget's proposal to assign the control test to the seller of long-term firm capacity, such sellers would only be able to deduct their capacity if they demonstrated that the purchaser had operational control of the generating unit. These sellers either would have to demonstrate that they no longer have control of their generation capacity or, if that was not the case, submit indicative screens. What currently are routine filings requesting market-based rate authority for new fully committed generators could in some cases become complicated.

135. We reject Indicated Utilities' proposal to exempt applicants from reporting long-term firm purchases backed by intermittent or energy-limited qualifying facility resources.

172

We believe that there is no reason to ignore such long-term firm purchases in the indicative screens and that Indicated Utilities' position confuses the operational characteristics of such resources with operational control. The fact that a solar or wind unit will not produce energy at certain times is equally true whether an applicant owns a solar or wind unit or purchases energy from a solar or wind unit through a long-term firm power purchase agreement. We clarify, however, that consistent with our direction elsewhere in this Final Rule, long-term firm purchases backed by energy-limited resources may be de-rated based on a

five-year average capacity factor based either on the unit's operating history or the EIA regional average. Providing this capacity rating option to applicants will yield consistent treatment of such resources in the indicative screens, whether owned or purchased.

173

This capacity rating option also addresses NextEra's concern regarding the potential overstatement of capacity associated with long-term firm power purchase agreements in the indicative screens.

172

IWU at 7.

173

See supra

Section IV.A.6.

136. Regarding SoCal Edison's argument concerning the distinctions between owning and purchasing generation, we reiterate that, for the purpose of horizontal market power analyses, long-term firm power purchase agreements convey rights to generation capacity that are similar (though not identical) to ownership because they provide the purchaser with a resource that the purchaser can rely on to serve its load. The common definition of a “firm” purchase is a service or product that is not interruptible for economic reasons.

174

This was the Commission's primary reason for concluding in the NOPR that a long-term firm purchase was comparable to ownership. Such purchases provide a resource that a load-serving entity can count towards its capacity requirement. The variable nature of energy-limited resources is the primary reason given by SoCal Edison for disputing the NOPR's contention that long-term firm energy agreements provide the purchaser with energy that only can be interrupted for limited and specified reasons.

175

However, as discussed above, the variable nature of certain energy-limited generators is a separate issue, and we will allow applicants to de-rate long-term firm power purchase agreements backed by energy-limited resources according to a five-year average capacity factor as discussed below. This will permit equivalent treatment of energy-limited resources in the indicative screens whether owned or purchased under long-term firm power purchase agreements.

174

The EQR Data Dictionary uses this definition as well.

175

SoCal Edison at 11.

137. With regard to EPSA's contention that reporting of long-term firm power purchase agreements in the indicative screens is duplicative of reporting such transactions in EQRs, the indicative screens and EQRs perform separate functions. The former is an

ex ante

analysis of a seller's potential market power while the latter enables an

ex post

analysis of its sales. Information on long-term firm purchases and sales is required to complete the indicative screens. The need to provide this information is not “waived” because it also is reported after-the-fact in EQRs or other forms. Therefore, we affirm the need for applicants to report long-term firm purchases in the indicative screens.

138. With respect to questions raised regarding the treatment of long-term firm purchases in DPT analyses, we clarify that applicants must attribute long-term firm power purchase agreements to the purchaser when the power purchase agreement has an associated long-term transmission reservation. An applicant that includes long-term firm power purchase agreements in its screens should include the same power purchase agreements in any DPT analyses filed to rebut the presumption of market power resulting from a screen failure. The fact that DPTs are more detailed, granular market power analyses does not negate the need to attribute long-term firm purchases to purchasers. We recognize that this may lead to inconsistencies in the treatment of long-term purchases between DPT analyses submitted in section 203 filings and those submitted in section 205 filings, but there already are several differences between DPT analyses filed in section 203 and 205 proceedings (

e.g.,

the section 203 analysis is a forward-looking analysis whereas the section 205 analysis is historical).

139. We confirm that long-term firm power purchase agreements that are reported in the indicative screens also should be reported in the asset appendix, appendix B, as proposed in the NOPR. However, we agree with commenters that the existing appendix B is not designed to report long-term firm purchases, particularly those that are not backed by specific generating units. Therefore, the Commission is creating a separate sheet in appendix B specifically for applicants to report all long-term firm purchases included in their indicative screens. This new sheet to the asset appendix is described in the discussion of the asset appendix below.

176

See infra

Section IV.D.

140. With respect to the process for converting long-term firm energy-only contracts to MW equivalents, we provide clarification and have decided to modify the approach set forth in the NOPR. First, with respect to a question raised by Solomon/Arenchild, we clarify that such conversions are needed only if a capacity amount (MW) is not specified in the contract. Long-term firm power purchase agreements that have a capacity amount specified need not be converted, regardless of whether the contract includes a separate capacity payment.

141. Upon consideration of the comments, we will modify the energy-to-capacity conversion formula proposed in the NOPR. We find there is some merit to SoCal Edison's argument that firm energy contracts cannot necessarily be linked to specific generating units (although the energy comes from a set of generating units that ultimately can be identified). Thus, we are adopting an alternative conversion approach that is responsive to these concerns; this approach is conceptually similar to the approach proposed in the NOPR but uses a different factor—load rather than generation—to convert energy into a capacity value.

177

Although we are adopting an alternative approach in the Final Rule, the alternative approach is a logical outgrowth of the approach proposed in the NOPR.

See Aeronautical Radio, Inc.

FCC,

928 F.2d 428, 445-446 (D.C. Cir. 1991) (citing

United Steelworkers of America

Marshall,

647 F.2d 1189, 1221 (D.C. Cir.1980),

cert. denied,

453 U.S. 913, 101 (1981)) (holding that the notice requirement of section 553 of the Administrative Procedure Act is fulfilled “so long as the content of the agency's final rule is a `logical outgrowth' of its rulemaking proposal.”).

142. In place of the conversion formula set forth in the NOPR, applicants should use their actual load factor

178

in the relevant study period to convert a long-term firm energy-only contract to a MW equivalent. To determine the MW equivalent, applicants should first determine the average MW purchased under the long-term firm energy contracts over the study period.

179

Applicants should then divide the average MW purchased by their load factor to obtain the capacity value for the contract.

178

Load factor is the average load divided by the peak load in a specified time period. For example, if during a calendar year a franchised public utility has a peak load of 2,000 MW and total sales to native load customers of 10,000,000 MWh, its load factor is [(10,000,000/8760)/2000] = 0.57 or 57 percent.

179

Average MW equals total MWh purchased during the study period divided by the total hours in the study period.

143. Long-term firm energy contracts serve the purchaser's load for a term of at least one year, so the purchaser's load factor is a reasonable basis to establish the capacity value of a long-term firm energy contract. This approach also avoids the need to calculate a capacity factor and link the purchase back to a generating unit or set of generating units. Applicants have ready access to their load data so performing this conversion should not be problematic or burdensome.

144. Applicants would continue to have the option of proposing a different method of attributing capacity based on

the specific terms and conditions of their power purchase agreement. Any alternative attribution method would have to be fully supported and justified.

145. We provide several clarifications to the reporting of long-term firm power purchase agreements. First, we clarify that an applicant should report a long-term firm purchase of capacity and/or energy that has an associated long-term firm transmission reservation for either point-to-point or network transmission service. In addition, we clarify that this requirement applies regardless of whether the long-term firm transmission reservation is held by the purchaser or seller of the capacity/energy. In response to SoCal Edison's query, we clarify that the requirement that applicants only include long-term firm power purchase agreements in their indicative screens if they have an associated long-term transmission reservation will not apply within an RTO/ISO market if that RTO/ISO does not have long-term firm transmission reservations or their equivalent. Instead, applicants in such RTO/ISO markets will be required to report all long-term firm energy and/or capacity purchases from generation capacity located within the RTO/ISO market if the generation is a designated as a network resource or as a resource with capacity obligations. We further clarify that letters of concurrence will not be required to establish which party to a long-term firm power purchase agreement has control of the underlying generation resource(s).

180

However, sellers may need to submit a letter of concurrence to support claims that they do not own or control the entire capacity of a generation facility.

See

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 187.

8. Clarification of Commission Language in Performing SIL Studies

146. The SIL study is used in both the indicative screens and the DPT analysis as the basis for establishing the amount of power that can be imported into the relevant geographic market.

181

In the NOPR, the Commission summarized previous Commission SIL guidance to transmission operators provided in the April 14 Order,

Puget,

and Order No. 697. The Commission noted that the April 14 Order requires that power flow benchmark cases reasonably simulate the historical conditions that were present

182

and requires that sellers consider “all internal/external contingency facilities and all monitored/limiting facilities that were used historically to approximate area-area transmission availability” and utilize scaling methods according to the same methods used historically for non-affiliate resources.

183

181

Id.

P 19.

182

Historical conditions include “facility/line deratings used to maintain capacity benefit margins (CBM) and transmission reliability (TRM/CBM), actual unit dispatch used to fulfill network and firm reservation obligation, the actual peak demand, generator operating limits opposed on all resources in real time, other limits/constraints imposed by the TP [Transmission Provider] during the season peaks.” April 14 Order,

107 FERC ¶ 61,018 at app. E.

183

NOPR, FERC Stats. & Regs. ¶ 32,702 at PP 147, 151 (citing April 14 Order, 107 FERC ¶ 61,018 at app. E).

147. In the NOPR, the Commission noted that

Puget

clarified that sellers must “[p]rovide copies of all Operating Guide descriptions that were applied in the scaling section,” as well as any operating guides used to ignore limiting elements in the SIL study results.

184

The Commission also stated that applicants must exclude study area non-affiliated load from study area native load, and should not include first-tier generation serving study area non-affiliated load in net area interchange. In addition, the Commission specified that applicants must document all instances where the SIL study differs from historical practices.

185

184

Id.

P 150 (citing

Puget,

135 FERC ¶ 61,254 at app. B, Reporting Requirements for Submittals 8, 9).

185

Id.

(citing

Puget,

135 FERC ¶ 61,254 at app. B, Reporting Requirements for Submittals 10 and 11).

148. In the NOPR, the Commission also noted the Commission's finding in Order No. 697 that SIL studies performed by sellers “should not deviate from” and “must reasonable[ly] reflect” the seller's Open Access Same-Time Information System (OASIS) operating practices and “techniques used must have [been] historically available to customers.”

186

The Commission further stated that “by OASIS practices, we mean sellers shall use the same OASIS methods and studies used historically by sellers (in determining simultaneous operational limits on all transmission lines and monitored facilities) to estimate import limits from aggregated first-tier control areas into the study area.”

187

Furthermore, the Commission stated that Order No. 697 requires that power flow cases “represent the transmission provider's tariff provisions and firm/network reservations held by seller/affiliate resources during the most recent seasonal peaks.”

188

186

Id.

P 146 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354 (internal citations omitted)).

187

Id.

P 146 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354 n.361).

188

Id.

P 152 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354);