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

Federal RegisterMay 7, 2008

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM04-7-001; Order No. 697-A]

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

Issued April 21, 2008.

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Order on Rehearing and Clarification.

SUMMARY:

In this order on rehearing, the Commission affirms its basic determinations in Order No. 697, and grants rehearing and clarification regarding certain revisions to its regulations and to the standards for obtaining and retaining market-based rate authority for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. The Commission also clarifies several aspects of the implementation process adopted in Order No. 697.

DATES:

Effective Date: This rule will become effective June 6, 2008.

FOR FURTHER INFORMATION CONTACT:

Debra A. Dalton (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6253, and Elizabeth Arnold (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-8818.

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph numbers

I. Introduction

II. Discussion

A. Horizontal Market Power

1. Whether to Retain the Indicative Screens

2. Indicative Market Share Screen Threshold Levels

3. DPT Criteria

4. Other Products and Models

5. Native Load Deduction

6. Relevant Geographic Market

7. Use of Historical Data

116

8. Transmission Imports

132

9. Further Guidance Regarding Control and Commitment of Capacity

147

B. Vertical Market Power

151

1. OATT Violations and Market-Based Rate Revocation

151

2. Treatment of FTRs

163

3. Other Barriers to Entry

166

C. Affiliate Abuse

181

1. General Affiliate Terms & Conditions

182

2. Power Sales Restrictions

223

3. Market-Based Rate Affiliate Restrictions

233

D. Mitigation

260

1. Cost-Based Rate Methodology

260

2. Protecting Markets With Mitigated Sellers

294

E. Implementation Process

341

1. Category 1 and 2 Sellers

343

2. Regional Review and Schedule

363

3. Clarifications on Implementation Process

373

4. Market-Based Rate Tariff Clarifications

383

F. Legal Authority

395

1. Whether Market-Based Rates Can Satisfy the Just and Reasonable Standard Under the FPA

395

2. Consistency of Market-Based Rate Program with FPA Filing Requirements

435

3. Whether Existing Tariffs Must Be Found To Be Unjust and Unreasonable, and Whether the Commission Must Establish a Refund Effective Date

497

G. Miscellaneous

501

1. Change in Status

501

2. Third Party Providers of Ancillary Services

516

3. Requesting Market-Based Rate Authority for QFs

524

H. Clarifications of the Commission's Regulations

528

III. Information Collection Statement

535

IV. Document Availability

536

V. Effective Date

539

Regulatory Text

Appendix A to Subpart H: Standard Screen Format

Appendix C to Order No. 697-A: Revised Tariff Language

Appendix D to Order No. 697-A: Revised Regional Review Schedule

Appendix E to Order No. 697-A: Petitioner Acronyms

Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

I. Introduction

1. On June 21, 2007, the Federal Energy Regulatory Commission (Commission) issued Order No. 697,

codifying and, in certain respects, revising its standards for obtaining and retaining market-based rates for public utilities. In order to accomplish this, as well as streamline the administration of the market-based rate program, the Commission modified its regulations at 18 CFR part 35, subpart H, governing market-based rate authorization. The Commission explained that there are three major aspects of its market-based regulatory regime: (1) Market power analyses of sellers and associated conditions and filing requirements; (2) market rules imposed on sellers that participate in Regional Transmission Organization (RTO) and Independent System Operator (ISO) organized markets; and (3) ongoing oversight and enforcement activities. The Final Rule focused on the first of the three features to ensure that market-based rates charged by public utilities are just and reasonable. Order No. 697 became effective on September 18, 2007.

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

Order No. 697, 72 FR 39,904 (Jul. 20, 2007), FERC Stats. & Regs. ¶ 31,252 (2007) (Final Rule).

2. On December 14, 2007, the Commission issued an order clarifying four aspects of Order No. 697.

Specifically, that order addressed: (1) The effective date for compliance with the requirements of Order No. 697; (2) which entities are required to file updated market power analyses for the Commission's regional review; (3) the data required for the horizontal market power analyses; and (4) what constitutes “seller-specific terms and conditions” that sellers may list in their market-based rate tariffs in addition to the standard provisions listed in Appendix C to Order No. 697. The Commission also extended the deadline for sellers to file the first set of regional triennial studies that were directed in Order No. 697 from December 2007 to 30 days after the date of issuance of the Clarification Order.

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

121 FERC ¶ 61,260 (2007) (

Clarification Order

3. In this order, the Commission responds to a number of requests for rehearing and clarification of Order No. 697. In most respects, the Commission reaffirms its determinations made in Order No. 697 and denies rehearing of these issues. With respect to several issues, however, the Commission grants rehearing or provides clarification.

4. For example, the Commission affirms in large part the determinations made in Order No. 697 concerning the horizontal market power analysis, including the use of the 20 percent threshold for the indicative wholesale market share screen and the Delivered Price Test (DPT), the use of a 2,500 Hirschman-Herfindahl Index (HHI) threshold for the DPT analysis, and the use of the average peak native load as the native load proxy for the indicative wholesale market share screen and DPT analysis. The Commission also affirms its decision to use a balancing authority area or the RTO/ISO region as the default relevant geographic market. Similarly, the Commission affirms the decision that, where the Commission has made a specific finding that there is a submarket within an RTO/ISO, that submarket should be considered the default relevant geographic market. However, the Commission grants rehearing concerning the finding that Northern PSEG is a submarket within PJM. On reconsideration, we conclude that we erred in relying on a finding of a submarket in a particular proceeding that was subsequently vacated on procedural grounds.

5. In response to requests for clarification concerning existing mitigation in RTO/ISOs, the Commission adopts a rebuttable presumption that the existing Commission-approved RTO/ISO mitigation is sufficient to address market power concerns in the RTO/ISO market, including mitigation applicable to RTO/ISO submarkets. However, intervenors may challenge that presumption. Depending on the nature of the evidence submitted by an intervenor, the Commission will consider whether to institute a separate section 206 proceeding to investigate whether the existing RTO/ISO mitigation continues to be just and reasonable.

6. While the Commission affirms its determination to continue the use of historical data and a “snapshot in time approach,” the Commission will consider sensitivity studies, on a case-by-case basis, that present clear and compelling evidence that certain changes in a market should be taken into account as part of the market power analysis in a particular case.

7. With regard to simultaneous transmission import limit (SIL) studies, the Commission clarifies that the use of simultaneous total transfer capability (TTC) in the SIL study must properly account for all firm transmission reservations, transmission reliability margin, and capacity benefit margin.

8. The Commission affirms its determinations concerning the vertical market power analysis and clarifies that sellers are not required to report on financial transmission rights as part of the vertical market power analysis.

9. The Commission codifies in the regulations at 18 CFR 35.36 a definition of “affiliate” for purposes of Order No. 697 based on the definition adopted in the Affiliate Transactions Final Rule.

In addition, the Commission reiterates in this order a number of clarifications that it made in the Affiliate Transactions Final Rule regarding the term “captive customers,” the purpose of the definition, and its focus on “cost-based regulation.” Among other things, the Commission notes that if a state regulatory authority in a retail choice state does not believe that retail customers are sufficiently protected and that our affiliate restrictions should apply to the local franchised public utility, it may ask the Commission to deem its retail customers to be captive customers for purposes of applying the affiliate restrictions.

Cross-Subsidization Restrictions on Affiliate Transaction,

Order No. 707, 73 FR 11013 (Feb. 29, 2008), FERC Stats. & Regs. ¶ 31,264 (Feb. 21, 2008) (Affiliate Transactions Final Rule).

10. The Commission clarifies that the new affiliate restriction regulations promulgated in Order No. 697 supersede codes of conduct approved by the Commission prior to the effective date of Order No. 697. The Commission also provides a number of clarifications concerning employees who are not subject to the independent functioning requirement. Further, the Commission grants rehearing regarding the adoption of a two-way information sharing restriction in 18 CFR 35.39(d), finding, among other things, that a one-way information sharing restriction adequately protects captive customers.

11. The Commission for the most part affirms its determinations concerning mitigation, including retaining the Commission's default mitigation and declining to impose a generic “must offer” requirement. The Commission clarifies that it has not prejudged the types of specific situations in which it might impose a “must offer” requirement on a particular seller. In response to rehearing requests concerning the Commission's mitigation of long-term transactions based on the result of a failure of a short-term indicative screen, the Commission is modifying its policy with respect to

mitigation of long-term transactions (one year or more in duration). In this regard, the Commission will allow a mitigated seller to demonstrate on a case-by-case basis that it does not have market power with respect to a specific long-term contract.

12. Concerning the tariff provision adopted in the Final Rule for mitigated sellers that want to make market-based rate sales at the metered boundary between a balancing authority area in which the seller was found, or presumed, to have market power and a balancing authority area in which the seller has market-based rate authority, after considering comments raised regarding the difficulty of determining and documenting whether the power sold is intended to serve load in the balancing authority area in which the seller has market power, the Commission is revising the tariff language to eliminate the intent element.

13. The Commission affirms, among other things, its determination in Order No. 697 to create a category of market-based rate sellers (Category 1 sellers) that are not required to automatically submit updated market power analyses, as well as its decision to adopt a regional filing process for updated market power analyses. In response to concerns raised regarding the potential for Category 1 sellers to exercise market power in load pockets or other transmission-constrained areas, we explain that we are modifying our approach. To the extent that a Commission-identified submarket is under analysis (relevant submarket), if the Commission determines based on analysis of indicative screens filed by other sellers that there may be potential market power concerns with respect to any Category 1 sellers in the relevant submarket, the Commission will, if appropriate, require an updated market power analysis to be filed by such Category 1 sellers and allow other parties to comment. In this regard, the Commission would be exercising its right to require an updated market power analysis at any time.

14. The Commission also provides clarifications regarding other aspects of the Final Rule, including addressing questions that have arisen concerning the implementation process adopted in Order No. 697 and providing clarifications concerning the change in status reporting requirement.

15. Finally, the Commission rejects as without merit arguments raised by petitioners challenging the Commission's authority to adopt market-based rates and alleging that the market-based rate program fails to comply with the requirements of the FPA.

II. Discussion

A. Horizontal Market Power

1. Whether To Retain the Indicative Screens

Final Rule

16. In Order No. 697, the Commission adopted, with some modifications, two indicative market power screens (the uncommitted market share screen and the uncommitted pivotal supplier screen) to determine whether sellers may have market power and should be further examined. The Commission explained that sellers that fail either screen would rebuttably be presumed to have market power, but they would have an opportunity to present evidence (through the submission of a Delivered Price Test (DPT) analysis) demonstrating they do not have market power. The Commission concluded that, although some sellers disagree with the use of two screens or find flaws in them, the conservative approach of using two screens together would allow the Commission to more readily identify potential market power by measuring market power at both peak and off-peak times and both unilaterally and in coordinated interaction with other sellers. The Commission explained that a conservative approach at the indicative screen stage of the proceeding is warranted because, if a seller passes both of the indicative screens, there is a rebuttable presumption that it does not possess horizontal market power.

In conclusion, the approach represented an appropriate balance between the need to protect against market power and the desire not to place unnecessary filing burdens on utilities.

Order No. 697 at P 62.

Id.

P 33, 35.

17. The wholesale market share screen measures for each of the four seasons whether a seller has a dominant position in the market based on the number of megawatts of uncommitted capacity owned or controlled by the seller as compared to the uncommitted capacity of the entire relevant market. When calculating uncommitted capacity, a seller adds the total nameplate or seasonal capacity of generation owned or controlled through contract plus long-term firm purchases and deducts operating reserves, native load commitments, and long-term firm sales.

Order No. 697 states that uncommitted capacity is determined by adding the total nameplate capacity of generation owned or controlled through contract and firm purchases, less operating reserves, native load commitments and long-term firm sales. Order No. 697 at P 38. Order No. 697 further states that uncommitted capacity from a seller's remote generation (generation located in an adjoining balancing authority area) should be included in the seller's total uncommitted capacity amounts.

Id.

However, one of the standard screen formats included at Appendix A to Order No. 697 does not capture these details. Part I—Pivotal Supplier Analysis, inadvertently does not include Row H (imported power) and Row M (average daily Peak Native Load in Peak month, a proxy for native load commitment) in calculating Row K (total uncommitted supply). We thus correct this error in the Revised Appendix A to include the missing variables of the equation.

18. The pivotal supplier analysis evaluates the potential of a seller to exercise market power based on uncommitted capacity at the time of the relevant market's annual peak demand, focusing on the seller's ability to exercise market power unilaterally. It examines whether the market demand can be met absent the seller during peak times; a seller is determined to be pivotal if demand cannot be met without some contribution of supply by the seller or its affiliates. For purposes of identifying the wholesale market, the Commission explained that the “proxy for the wholesale load is the annual peak load (needle peak) less the proxy for native load obligation (

i.e.

, the average of the daily native load peaks during the month in which the annual peak load day occurs).”

Id.

P 41.

19. The Commission chose not to adopt suggestions to alter the indicative screens in order to incorporate a contestable load analysis, as proposed by some commenters. Such an analysis would consider the amount of excess market supply available to serve the amount of wholesale demand seeking supply at a particular moment in time.

The Commission reasoned that such an analysis is essentially a variant on the pivotal supplier screen with differences in the calculation of wholesale load and the test thresholds since it addresses whether suppliers other than the seller can meet the demand in the relevant market. The Commission concluded that incorporating such an analysis would not improve its ability to establish a presumption of whether a seller has market power, and “without the market share indicative screen, the Commission would have insufficient information because there would be no analysis of a seller's size relative to the other sellers in the market, and no information on the seller's market power during off-peak periods.”

Additionally, the

Commission noted that the contestable load analysis fails to consider the relative price of the competing supplies and thus whether the available non-applicant supply is competitively priced and, hence, in the market.

See Id.

P 49. Generally, advocates of the contestable load analysis believe that, if available non-applicant supply is at least twice the contestable load, that is sufficient to make a finding that the market is competitive.

Id.

P 66.

Order No. 697 also dealt with the following issues, about which rehearing has not been sought: Control and commitment of generation resources; elimination of former 18 CFR 35.27, which had exempted newly-constructed generation from the horizontal market power analysis; reporting format for the indicative screens; nameplate capacity; and several procedural issues.

Requests for Rehearing

20. On rehearing, Southern contends that the Final Rule violates the requirement in FPA section 206 that the Commission bears the burden of proof in section 206 proceedings and that the Commission's determinations be based on substantial evidence.

According to Southern, this shifting of the burden of proof occurs through the use of indicative screens that Southern submits are inherently flawed and which, if failed, result in a presumption of market power that must be rebutted by sellers. Southern states that once a screen failure occurs and a presumption of market power arises, a seller only has two options: either accept a determination that it has market power and adopt cost-based rate mitigation measures, or provide the Commission with a DPT analysis.

Southern concludes that by applying the indicative screens codified in the Final Rule, the Commission will effectively shift to sellers the evidentiary burden in a section 206 proceeding.

Southern argues that the screens are inherently flawed in their ability to definitively assess market power when none is actually present, noting that the Final Rule acknowledges that the screens are conservative in nature and may result in false positives indicating market power.

Southern argues that because of their conservative nature and propensity to result in false positives, such screens cannot properly provide a basis for shifting the burden of proof to sellers, and are incapable of providing substantial evidence of market power.

Southern Rehearing Request at 7-8 (citing 16 U.S.C. 824e(a);

FPC

Sierra Pacific Power Co.,

350 U.S. 348 at 353 (1956) (

Sierra

);

Public Service Commission of New York

FERC,

642 F.2d 1335, 1345 (D.C. Cir. 1980);

Public Service Co. of New Mexico,

115 FERC ¶ 61,090, at P 33 (2006)).

Id.

at 7 (citing Order No. 697 at P 63).

Id.

at 8.

Id.

(citing Order No. 697 at P 62, 71, 74, 89). Further, Southern asserts that only in instances of high market share should a prima facie case of market power be established, which would shift the burden of proof.

Id.

at 10 & n.10 (citing

U.S.

Syufy,

903 F.2d 659, 664 (9th Cir. 1990);

Hunt-Wesson Foods, Inc.

Ragu Foods, Inc.,

627 F.2d 919, 924 (9th Cir. 1980),

cert. denied,

450 U.S. 921 (1981)).

21. To remedy this, Southern argues that the Commission should reconsider its determination in the Final Rule that a failure of an indicative screen results in a presumption of market power. Instead, the Commission should determine that the indicative screens are only intended to identify sellers that appear to raise no horizontal market power concerns and thus can be considered for market-based rate authority without the necessity of further analysis. In other words, passing the screens should raise a favorable presumption that a seller does not have market power, and a seller would never be “presumed” to have generation market power.

Id.

at 11.

22. Southern further argues that the Final Rule's market share screen and its application of the DPT are arbitrary and capricious, not supported by substantial evidence, without a rational basis, and contrary to established legal precedent.

Specifically, Southern contends that the market share screen and the DPT improperly fail to account for the size of the wholesale market demand that could be served by the uncommitted capacity in the relevant region.

Southern argues that wholesale market demand should be considered in the market share screen and the DPT because market power concerns only exist if a seller has the power to raise prices above competitive levels or exclude competition in the relevant market for a not insubstantial amount of time.

According to Southern, even the Department of Justice (DOJ) merger analysis, on which the Final Rule relies, would take the wholesale market into account when determining an entity's “market share.”

Southern comments that in the Final Rule the Commission appeared to give four reasons why it was unwilling to consider market demand (

i.e.

, contestable load), and contends that these reasons provide an insufficient basis for rejecting a contestable load analysis.

Southern believes that the weight of the evidence clearly demonstrates that to be legitimate indicators of market power, the market share screen and DPT should take the relevant wholesale demand into account.

Id.

at 20 (citing 5 U.S.C. 706(2)(A) and (E) (2000);

Union Pac. Fuels, Inc.

FERC,

129 F.3d 157, 161 (D.C. Cir. 1997) (holding that review of Commission orders is made under the arbitrary and capricious standard of the Administrative Procedure Act);

Sithe Independence Power Partners

FERC,

165 F.3d 944 (D.C. Cir. 1999) (stating that the Commission must be able to demonstrate that it has “made a reasoned decision based upon substantial evidence in the record” and the “path of [its] reasoning” must be clear) (

quoting Town of Norwood

FERC,

962 F.2d 20, 22 (D.C. Cir. 1992)).

Id.

at 3-4 (citing

United States

Grinnell Corp.,

384 U.S. 563, 571 (1966);

MetroNet Services Corp.

U.S. West Communications,

329 F.3d 986 (9th Cir. 2003);

United States

Dentsply International, Inc.,

399 F.3d 181, 187 (3rd Cir. 2005)).

Id.

at 12-13.

Id.

at 13.

Id.

at 15 and Frame affidavit at ¶ 25, referring to Order No. 697 at P 66-67.

Commission Determination

23. We disagree with Southern's contention that the Final Rule violates the requirement in the FPA that the Commission bears the burden of proof in section 206 proceedings. We also disagree with Southern's view that failure of the indicative screen(s) does not provide a sufficient basis to establish a rebuttable presumption of market power.

24. As a general matter, we agree that the burden of proof in a section 206 proceeding is on the Commission where the Commission institutes the proceeding on its own motion. However, we find Southern's argument that the burden of proof in a section 206 proceeding is unlawfully shifted to entities that fail one of the indicative screens to be without merit. As an initial matter, the burden of going forward is on the Commission in the first instance, and ultimately, when the Commission institutes a proceeding under section 206 of the FPA. In the Final Rule, the Commission has established through rulemaking a generic test to support its burden of going forward: A seller's failure of one of the indicative screens establishes a rebuttable presumption of market power. The burden of going forward then shifts to the seller once such a proceeding is initiated to rebut the presumption of market power. Once the seller submits additional evidence to rebut the presumption of market power, the Commission must determine, based on substantial evidence in the record, whether the seller has market power. Thus, the ultimate burden of proof under FPA section 206 remains with the Commission.

On this basis, the

Commission is not unlawfully shifting the burden of proof to the seller that fails one of the screens.

See AEP Power Marketing, Inc.,

108 FERC ¶ 61,026, at P 30 (2004) (July 8 Order) (“Failure of a screen establishes a rebuttable presumption of market power, which satisfies the Commission's initial burden of going forward in such proceedings. The burden of going forward will then be upon the applicant once such a proceeding is initiated.”);

see Id.

P 29 (stating that passing both screens or failing one merely establishes a rebuttable presumption, and explaining that in the case of an intervenor in a section 205 proceeding that seeks to prove that the applicant possesses market power, “the intervenor need only meet a ‘burden of going forward’ with

evidence that rebuts the results of the screens. At that point, the burden of going forward would revert back to the applicant to prove that it lacks market power.”) (citing

Pennzoil Co.

FERC,

645 F.2d 360, 392 (5th Cir. 1981),

cert. denied,

454 U.S. 1142 (1982);

accord Transcontinental Gas Pipe Line Corp.,

Opinion No. 135, 17 FERC ¶ 61,232, at 61,450 (1981) (“The presumption * * * is the same as that which arises from a prima facie case: It imposes on the party against whom it is directed the burden of going forward with substantial evidence to rebut or meet the presumption, but does not shift the burden of persuasion.”);

Generic Determination of Rate of Return on Common Equity for Electric Utilities,

Order No. 389-A, 29 FERC ¶ 61,223, at 61,458 (1984) (concluding that rebuttable presumption that a rate of return based on a benchmark is just and reasonable does not shift ultimate burden of proof imposed by Federal Power Act));

see also Southern Companies Energy Marketing, Inc.,

111 FERC ¶ 61,144, at P 24 (2005) (stating that a “screen failure satisfies the Commission's burden of going forward and shifts to the applicant the burden of presenting evidence rebutting the presumption of market power”),

order dismissing reh'g as moot,

119 FERC ¶ 61,300 (2007).

25. Moreover, in Order No. 697, the Commission addressed an argument by Southern that failure of the screens does not provide a sufficient basis to establish a rebuttable presumption of market power, and Southern has failed on rehearing to convince us that a seller should never be presumed to have generation market power. In particular, the Commission explained that the indicative screens are intended to identify the sellers that raise no horizontal market power concerns and can otherwise be considered for market-based rate authority. Sellers failing one or both of the indicative screens, on the other hand, are identified as sellers that potentially possess horizontal market power and for which a more robust analysis is required. The Commission explained that the uncommitted pivotal supplier screen focuses on the ability to exercise market power unilaterally. Failure of this screen indicates that some or all of the seller's generation must run to meet peak load. The uncommitted market share analysis indicates whether a supplier has a dominant position in the market. Failure of the uncommitted market share screen may indicate that the seller has unilateral market power and may also indicate the presence of the ability to facilitate coordinated interaction with other sellers. It is on this basis that the Commission finds that a rebuttable presumption of market power is warranted when a seller fails one or both of the indicative screens. The screens themselves represent the first piece of evidence that the potential for market power exists since failure of one or both of the screens indicates that the seller may be a pivotal supplier in the market or has a high enough market share of uncommitted capacity to raise horizontal market power concerns.

In addition, we note that although we find that failure of an indicative screen is a sufficient basis to establish a presumption of market power, the Commission allows such a seller to continue to sell under market-based rate authority until a definitive finding is made, albeit with rates subject to refund to protect customers.

See

Order No. 697 at P 65.

26. We disagree with Southern's argument that the indicative screens have a propensity to result in false positive indications of market power, do not provide substantial evidence of market power and, therefore, cannot provide a basis for shifting the evidentiary burden to sellers. As we explained in Order No. 697, the indicative screens are intended to screen out those sellers that raise no horizontal market power concerns and can otherwise be considered for market-based rate authority from those sellers that raise concerns but may not necessarily possess horizontal market power.

While we recognize that the conservative nature of the screens may result in some false positives, a conservative approach at the indicative screen stage is warranted because if a seller passes both of the indicative screens, there is a rebuttable presumption that it does not possess horizontal market power. Thus, we must weigh the risk of false positives and any resulting repercussions on a seller (e.g., section 206 proceeding, rate subject to refund, temporary regulatory uncertainty) against the costs of adopting a less conservative screen or eliminating the market share indicative screen.

In particular, if the screens result in a false positive indication of market power, the seller has the opportunity to rebut the presumption of market power while it continues to have market-based rate authority. However, if we were to adopt a less conservative screen, that could result in a false negative,

i.e.

, a false indication of no market power and customers would not be adequately protected. Accordingly, if the Commission were to adopt Southern's approach we are concerned that false negatives would become a reality and the Commission would not be able to fulfill its FPA section 205 and 206 mandate to ensure just, reasonable and not unduly discriminatory rates. On this basis, we believe that evidence of an indicative screen failure is sufficient to establish a rebuttable presumption of market power, in which case the seller will then have the opportunity to rebut that presumption of market power.

. P 62.

. P 71.

27. Additionally, in response to Southern's concerns regarding the conservative nature of the indicative screens, Order No. 697 changed the native load proxy under the market share indicative screen from the minimum native load peak demand for the season to the average of the daily native load peak demands for the season, making the native load proxy for the market share indicative screen consistent with the native load proxy under the pivotal supplier screen.

A native load proxy based on the average of peak load conditions is more representative, and thus more accurate, than a proxy based on minimum peak load conditions. Basing the native load proxy on the average of the peaks will make the screens more accurate in eliminating sellers without market power while focusing on ones that may have market power.

Thus, the updated native load proxy will reduce the likelihood that false positive indications of market power will occur.

. P 135.

. P 137.

28. Accordingly, we affirm our determination in the Final Rule that a failure of an indicative screen results in a presumption of market power, and reject Southern's proposal that a seller never be “presumed” to have horizontal market power as a result of an indicative screen failure.

Southern Rehearing Request at 11.

29. The Commission also disagrees with Southern's assertion that the market share screen and the DPT analysis do not account for the size of wholesale market demand, and are therefore arbitrary and capricious.

While Southern may disagree with our approach to considering wholesale market demand, both the market share screen and the DPT consider wholesale market demand by considering uncommitted capacity. Uncommitted capacity considers wholesale market demand by reducing the seller's available capacity by the amount of capacity committed to serve demand. In addition, in both the initial screen and the DPT, the Commission requires a pivotal supplier analysis, which looks at whether there is sufficient competing supply to serve wholesale demand.

We further address Southern's arguments with regard to the DPT analysis below.

30. In addition, we disagree with Southern that our choice of how to account for the wholesale market demand has resulted in the market share screen and the DPT being arbitrary and

capricious. The development of the market share screen and the DPT resulted from lengthy public proceedings at which varying perspectives and arguments were taken into account. Over the years, and in light of the Commission's FPA responsibilities, the Commission has carefully considered various points of view in an open transparent dialogue with the electric industry and has based its determinations on sound regulatory principles. In particular, the market share screen provides a straightforward economically sound and accepted method to identify those sellers that have the potential to exercise market power.

The uncommitted pivotal supplier screen measures the ability of the firm to dominate the market at peak periods. Further, the market share screen indicates whether a supplier may have a dominant position in the market and measures the ability of a seller to affect coordinated interaction with other sellers that could be accomplished during both peak and off-peak times. The market share screen is useful in measuring market power because it measures a seller's size relative to others in the market, specifically, the seller's share of generating capacity that is uncommitted after accounting for its obligations to serve native load. It also provides a snapshot of these market shares in each season of the year.

Thus, the indicative screens measure a seller's market power at both peak and off-peak times and therefore indirectly measure market power potential during periods of both relatively high and low demand.

With regard to Southern's argument that in the Final Rule the Commission appeared to give four reasons why it was unwilling to consider market demand (

i.e.

, contestable load), and Southern's contention that these reasons provide an insufficient basis for rejecting a contestable load analysis, we reaffirm our determination that the contestable load analysis is flawed and essentially a variant on the pivotal supplier screen.

Like the pivotal supplier screen, the contestable load analysis addresses whether suppliers other than the seller can meet the demand in the relevant market. Thus, incorporating such an analysis would not improve our ability to establish a presumption of whether a seller possesses market power and would add little useful information.

See In the Matter of Merger Policy Under the Federal Power Act

, May 7, 1996, Comments of the U.S. Department of Justice, Docket No. RM96-6-000 (providing comments on the Commission's standards for determining whether a proposed merger is in the public interest, recommending that the Commission apply a market share screen to identify quickly those mergers that are unlikely to raise competitive issues and concluding that the Horizontal Merger Guidelines provide “sound competitive analysis”);

see also

U.S. Department of Justice and the Federal Trade Commission, Horizontal Merger Guidelines, section 2.0, reprinted at 4 Trade Reg. Rep. (CCH) ¶ 13,104 (Issued April 2, 1992, Revised April 8, 1998).

Order No. 697 at P 65.

. P 66.

2. Indicative Market Share Screen Threshold Levels

Final Rule

31. Order No. 697 retained the 20 percent threshold for the wholesale market share screen (

i.e.

, with a market share of less than 20 percent, the seller passes the screen). The Commission reasoned that a relatively conservative threshold for passing the market share screen was appropriate, explaining that the screens are indicative of market power, not definitive. Responding to arguments that the Commission should use a 35 percent threshold as a presumption of market power because the U.S. Department of Justice (DOJ) merger guidelines state that only firms with 35 percent of more market share have market power, the Commission explained:

In a market comprised of five equal-sized firms with 20 percent market shares, the HHI is 2,000, which is above the DOJ/FTC HHI threshold of 1,800 for a highly concentrated market, and in markets for commodities with low demand price-responsiveness like electricity, market power is more likely to be present at lower market shares than in markets with high demand elasticity.

. P 89.

32. The Commission continued that, when arguing that a 20 percent threshold for the market share screen is too low, commenters ignored that the indicative screens are based on uncommitted capacity, not total capacity; as a result, a substantial amount of seller capacity may not be counted in measures of market share. The Commission, therefore, concluded that the 20 percent threshold strikes the right balance in seeking to avoid both false negative and false positive results.

. P 91.

Requests for Rehearing

33. Southern asserts that the Final Rule arbitrarily utilizes a 20 percent market share threshold to establish a presumption of market power.

Further, Southern argues that the 20 percent threshold is contrary to legal precedent holding that a higher market share is required to warrant market power concerns.

Southern Rehearing Request at 4 (citing DOJ 1984 Merger Guidelines, Section 2.4;

Edison Mission Energy, Inc.

FERC

, 394 F.3d 964, 968 (D.C. Cir. 2005) (stating that the Commission must “articulate a satisfactory explanation for its action including a `rational connection between the facts found and the choice made.' ”) (quoting

Motor Vehicle Mfrs. Ass'n

State Farm Mut. Auto. Ins. Co.

, 463 U.S. 29, 43 (1983)).

34. Southern argues that, contrary to the Commission's assertions, the 1984 Merger Guidelines do not support the 20 percent figure used in the market share screen. First, it states that while the particular sentence cited by the Commission from section 4.134 of the 1984 guidelines does actually contain the words “market share of 20 percent,” it does not support the application of a 20 percent threshold under the market share screen when considered in proper context, since other portions of the 1984 Merger Guidelines indicate that the DOJ's definition of “market share” in the context of merger evaluation is different from the Commission's definition of “market share” under its market share screen.

Second, Southern argues that according to the very sentence cited in the Final Rule from the 1984 Merger Guidelines, the 20 percent “market share” threshold refers only to the market share of the

acquired firm

in the overall context of a proposed merger of multiple firms. It does not refer to the market share of the merged firm post-acquisition, nor does it even refer to the market share of the acquiring firm. Third, Southern argues that the Commission's reliance on the 20 percent threshold in section 4.134 of DOJ's 1984 Merger Guidelines is misplaced because that provision is outdated—it is not included in DOJ's

current

horizontal merger guidelines. In this regard, the 1984 Merger Guidelines were used to evaluate both

vertical and horizontal

mergers. The newer versions of DOJ's

horizontal

merger guidelines subsequently adopted in 1992 and 1997 do not carry forward section 4.134's 20 percent market share threshold. Thus, the market share of a single firm does

not

automatically translate into a high HHI as the Commission suggests.

The Final Rule cited section 4.134, stating “[t]he 20 percent threshold is consistent with § 4.134 of the U.S. Department of Justice 1984 Merger Guidelines issued June 14, 1984, reprinted in Trade Reg. Rep. P 13,103 (CCH 1988): `The Department [of Justice] is likely to challenge any merger satisfying the other conditions in which the acquired firm has a market share of 20 percent or more.' ” Order No. 697 at n.21.

. at 16-19.

35. Southern also argues on rehearing that section 2 of the Sherman Antitrust Act, which prohibits not only actual

monopolization but also attempted monopolization and conspiracy to monopolize, has spawned a well-established body of law to address the type of market concerns that the Commission attempts to address in the Final Rule. Southern contends that the Commission's 20 percent threshold falls short when measured against the jurisprudence interpreting section 2 of the Sherman Act and that a more relevant threshold in a non-merger context would arguably be closer to 90 percent than 20 percent.

Whether the Commission's concern arises out of the unilateral ability of a utility to exert market power or the ability of two or more utilities to act concertedly in a way that restrains trade, Southern argues that jurisprudence interpreting the Sherman Act more appropriately addresses those concerns than does merger analysis. Aside from the authorities supporting a rule of law that less than at least a 50 percent market share should be insufficient to suggest market power, Southern argues that many cases and commentators may be cited for the proposition that the Commission's 20 percent threshold is misguided and lacks a rational basis; relatively low market shares should, as a matter of law, preclude findings of market power.

Southern adds that the courts have not only consistently held that market shares in the 20 percent range are insufficient to support a finding of actual monopoly power under section 2 of the Sherman Act, but also have found little difficulty in determining that such market share is not enough to sustain even a claim of attempted monopolization under section 2.

. at 20 (citing

Hiland Dairy

Kroger

, 402 F.2d 968, 976 (8th Cir. 1968) (rejecting 60 or 33 percent market share);

Robinson

Magovern

, 521 F. Supp. 842, 887 (W.D. Pa. 1981)).

. at 22-23 (citing

Cargill, Inc.

Monfort of Colorado, Inc.

, 479 U.S. 104, 119 n.15 (1986) (noting that 20.4 percent market share is probably insufficient to sustain predatory pricing, and citing authorities indicating that 60 percent or more would be necessary);

Bailey

Allgas, Inc.

, 284 F.3d 1237, 1250 (11th Cir. 2002);

Yoder Bros., Inc.

California-Florida Plant Corp.

, 537 F.2d 1347, 1368 (5th Cir. 1976) (stating that a 20 percent market share was insufficient as a matter of law to prove market power)).

. at 24 (citing

H.L. Hayden Co. of New York, Inc.

, v.

Siemens Medical Systems, Inc.

, 879 F.2d 1005, 1017 (2nd Cir. 1989);

Nifty Foods Corp.

Great Atl. & Pac. Tea Co.

, 614 F.2d 832, 841 (2nd Cir. 1980) (one-third market share not enough);

U.S.

ALCOA

, 148 F.2d 416, 424 (2nd Cir. 1945).

36. NASUCA argues on rehearing that in calculating market share when screening for horizontal market power, the Commission should not subtract capacity needed for long-term contracts as “committed” if the contracts are indexed or linked to spot market prices. NASUCA asserts that a seller with a market share of capacity greater than 20 percent can reduce it, and pass a market power screen it would otherwise fail, by “committing” portions of its capacity. NASUCA states that it requested in its NOPR comments that the Commission clarify that it will not consider capacity dedicated to meeting long-term contract sales of energy to be “committed”—and thus disregarded from market share—if the price of energy in the long-term contracts is indexed or linked to spot market prices. NASUCA contends that it identified relevant research in support of its request in citing a model that withdraws the capacity committed under the long-term contracts from the short-run market.

NASUCA states that the Commission overlooked NASUCA's request, and therefore requests that the Commission grant its requested clarification because research indicates that long-term contracts linked to spot market prices do not reduce, and may exacerbate, the ability of a seller to raise spot market prices above competitive levels.

In the alternative, NASUCA seeks further proceedings to examine the exercise of market power by sellers who pass market screens due to their contractual commitment to make long-term energy sales at rates indexed to spot market prices.

NASUCA Rehearing Request at 8 (citing Chloe Lo Coq.

Index Contracts and Spot Market Competition,

University of California Energy Institute, Center for the Study of Energy Markets, June 2006, p. 15, available at

http://www.ucei.berkeley.edu/ThirdTierButtons/PDFButton_Off.jpg

Id.

(citing Order No. 697 at P 82-93).

Commission Determination

37. We affirm our determination to retain the 20 percent threshold for the indicative wholesale market share screen. Use of the 20 percent market share threshold is appropriate since the screen is indicative, not dispositive. Southern's arguments suggest that the 20 percent is dispositive, but it is not. If a seller fails the indicative screens, it can submit a full DPT analysis in which a range of factors are considered, including market shares, HHIs (market concentration) and other factors affecting the relevant markets. A 20 percent market share is not even considered dispositive at that stage; rather, we have approved market-based rates in several cases where a supplier had a market share exceeding 20 percent.

In addition, we note that the cases cited by Southern, where much higher market shares were allowed, involve markets other than electricity.

Electricity markets possess unique characteristics including, but not limited to, inelastic demand and the need to balance the entire transmission grid in real-time. Economic theory and empirical estimates of the short-run elasticities of electricity demand suggest that these unique conditions allow sellers in wholesale electricity markets to exercise market power using a much more limited withholding of supply than industries listed in the cases cited by Southern.

Thus, the use of a conservative threshold such as a 20 percent market share is warranted, particularly for an indicative screen.

PPL Montana, LLC,

115 FERC ¶ 61,204, at P 41 (2006),

order denying reh'g,

120 FERC ¶ 61,096 (2007);

Kansas City Power and Light Co.,

113 FERC ¶ 61,074, at P 26, 30 (2005);

PacifiCorp,

115 FERC ¶ 61,349, at P 29, 32 (2006);

Tampa Electric Co.,

117 FERC ¶ 61,311, at P 26-27 (2006).

Hiland Dairy

Kroger,

402 F.2d 968 (8th Cir. 1968) (concerning a claim of monopolization in the milk and dairy business);

Robinson

Magovern,

521 F. Supp. 842 (W.D. Pa. 1981) (addressing an antitrust action against a hospital);

Cargill, Inc.

Monfort of Colorado, Inc.,

479 U.S. 104 (1986) (concerning a merger in the beef packing industry);

Bailey

Allgas, Inc.,

284 F.3d 1237 (11th Cir. 2002) (addressing an antitrust action arising from a price war between liquid propane gas competitors);

Yoder Bros., Inc.

California-Florida Plant Corp.,

537 F.2d 1347 (5th Cir. 1976) (addressing antitrust claims arising from infringement of plant patents);

H.L. Hayden Co. of New York, Inc.,

Siemens Medical Systems, Inc.,

879 F.2d 1005 (2nd Cir. 1989) (addressing antitrust claims relating to distribution of dental x-ray equipment);

Nifty Foods Corp.

Great Atl. & Pac. Tea Co.,

614 F.2d 832 (2nd Cir. 1980) (concerning an antitrust suit arising from the substitution of a supplier of frozen waffles);

U.S.

ALCOA,

148 F.2d 416 (2nd Cir. 1945) (concerning claims of monopolization of interstate and foreign commerce in the manufacture and sale of aluminum).

Energy Information Administration, “Assumptions to the Annual Energy Outlook 2006,” Report #: DOE/EIA-0554 (2006); James A. Espey & Molly Espey, “Turning on the Lights: A Meta-analysis of Residential Electricity Demand Elasticities,” Journal of Agricultural and Applied Economics, 36:1, at 65-81 (April 2004).

38. Southern asserts that the Final Rule's reliance on the 1984 Merger Guidelines for use of the “20 percent market share” is incorrect. Section 4.134 of the 1984 Merger Guidelines states:

Entry through the acquisition of a relatively small firm in the market may have a competitive effect comparable to new entry. Small firms frequently play peripheral roles in collusive interactions, and the particular advantages of the acquiring firm may convert a fringe firm into a significant factor in the market. The Department is unlikely to challenge a potential competition merger when the acquired firm has a market share of five percent or less. Other things being equal, the Department is increasingly likely to challenge a merger as the market share of the acquired firm increases above the threshold. The Department is likely to challenge any merger satisfying the other conditions in which the acquired firm has a market share of 20 percent of [sic] more.

U.S. Department of Justice Non-Horizontal Merger Guidelines sec. 4.134, originally issued June 14, 1984, as part of the U.S. Department of Justice

Merger Guidelines, reprinted in Trade Reg. Rep. ¶ 13,103 (CCH 1988) (footnote omitted).

39. Upon further review, the context discussed in this quote differs from the issue before us, and provides little guidance here. In the market-based rate context, we focus on whether the applicant has a 20 percent market share as a conservative measure because of the electricity market's characteristics including inelastic demand and the need to balance the entire transmission grid in real-time.

However, the Non-Horizontal Merger Guidelines provide that a firm with a 20 percent share is unlikely to be a “fringe” firm and an insignificant factor in the market. This is the same reason that we use the 20 percent threshold in our indicative screen: Firms with a 20 percent market share would be unlikely to hold a dominant position in the market.

A seller who has less than a 20 percent market share in a season will be considered to satisfy the market share analysis.

AEP Power Marketing, Inc.,

107 FERC ¶ 61,018, at P 102 (April 14 Order),

order on reh'g,

108 FERC ¶ 61,026 (2004) (July 8 Order).

See Id.

P 104.

40. We also reject Southern's argument that the Commission's 20 percent threshold falls short when measured against the jurisprudence interpreting section 2 of the Sherman Act.

Economic theory suggests that it may be possible, given the unique conditions in electricity markets, for sellers to exercise market power, using a much more limited withholding of supply, than industries listed in the cases relied upon by Southern.

Moreover, in contrast to the cases cited, the Commission uses 20 percent as an

indicative

screen, not as a dispositive factor in determining whether market power exists. We have, as indicated, approved market-based rates for firms with market shares in excess of 20 percent.

Southern Rehearing Request at 22-23.

See supra

n.46.

41. We reject NASUCA's request that the Commission require sellers to treat capacity that is committed to long-term contracts that are indexed or linked to spot market prices as uncommitted capacity in calculating market share when screening for horizontal market power. As support, NASUCA cites a model that withdraws the capacity committed under the long-term contracts from the short-run market, and then concludes that the now reduced capacity traded in the spot market lowers the incentives for rival firms to deviate from any collusive behavior by reducing the number of firms in the market and their available capacity.

Therefore, the model cited by NASUCA subtracts capacity committed under long-term contracts from the capacity available in the short-run market, just as we do in our analysis. Similarly, the Commission believes that once capacity is committed long-term, regardless of how that capacity is priced (e.g., whether linked to spot prices or not), the ability of the firm to use that capacity to exercise market power in the spot market is severely limited or non-existent. The ability to collude will be determined by the remaining uncommitted capacity in the spot market, not the capacity that is already committed under long-term contracts. Therefore, we conclude that it is appropriate to subtract capacity committed under long-term contracts when calculating a seller's uncommitted capacity for purposes of performing the indicative screens.

“If collective action is necessary for the exercise of market power, as the number of firms necessary to control a given percentage of total supply decreases, the difficulties and costs of reaching and enforcing an understanding with respect to the control of that supply might be reduced.” U.S. Department of Justice and the Federal Trade Commission, Horizontal Merger Guidelines, section 2.0, reprinted at 4 Trade Reg. Rep. (CCH) ¶ 13,104 (Issued April 2, 1992, Revised April 8, 1998).

3. DPT Criteria

Final Rule

42. In Order No. 697, the Commission announced that it would continue to use the DPT to make a definitive determination of whether a seller has market power and that it would continue to weigh both available economic capacity and economic capacity when analyzing market shares and Hirschman-Herfindahl Indices (HHI).

The Commission chose to retain the HHI threshold of 2,500 for passing the DPT, and to retain the 20 percent market share threshold. Responding to arguments that if a 2,500 HHI threshold is retained, it should be used with a 15 percent market share because these are the criteria of the oil pipeline test from which the 2,500 HHI was derived, the Commission noted that it “had not seen cases where the HHI was over 2,500 and the seller's market share was between 15 and 20 percent, which would be the type of situation about which [commenters] are concerned.”

Order No. 697 at P 13, 104, 106.

Id.

P 113.

Requests for Rehearing

43. Montana Counsel argues that the Commission should clarify that capacity committed to a competitor's native load or otherwise unavailable on a firm basis should not be considered available to compete with the applicant's generation, and as such should not be included as available capacity in the DPT analysis. Montana Counsel states that in its order on PPL Montana's request for renewal of market-based rate authority, the Commission stated that it was “not inconsistent with how DPTs have historically been conducted” for PPL Montana to include as available competing generation capacity that was committed elsewhere.

Montana Counsel contends that this is inappropriate insofar as generation committed to serve another utility's native load cannot be available to compete with the applicant's generation on a firm basis. Montana Counsel states that while it appears that Order No. 697 remedies this mistake in stating that total supply is determined by adding the total amount of uncommitted capacity located in the relevant market (including capacity owned by the seller and competing suppliers) with that of uncommitted supplies that can be imported (limited by simultaneous transmission import capability) into the relevant market from the first-tier markets, the Commission does not explicitly change the Commission's prior policy.

Accordingly, Montana Counsel requests clarification that the Commission will not allow applicants to count as available economic capacity generation that is in fact committed; if necessary and in the alternative, Montana Counsel requests rehearing of this issue.

Montana Counsel Rehearing Request at 9 (citing

PPL Montana, LLC,

115 FERC ¶ 61,204, at P 49 (2006)).

Id.

at 10 (citing Order No. 697 at P 37-38).

44. TDU Systems argue on rehearing that the Final Rule fails to explain how the adoption of a 2,500 HHI threshold is rationally related to the Commission's objective of precluding market-based rates in highly concentrated markets.

They assert that the Commission should lower the HHI threshold to 1,800 as the appropriate threshold for treating a market as highly concentrated, and that the Commission's refusal to do so in the Final Rule was arbitrary and capricious. TDU Systems state that, since the Commission set out in the Final Rule “to provide ‘a rigorous up-front analysis of whether market-based rates should be

granted,’ it is somewhat puzzling as to why the Commission believes that the case for any change in the status quo must be ‘compelling.’ ”

TDU Systems state that “The Final Rule fails to explain how the adoption of an 1,800 Herfindahl-Hirschman Index (‘HHI’) threshold is rationally related to its objective of precluding market-based rates in highly concentrated markets. TDU Systems Rehearing Request at 2 (citing

Motor Vehicle Mfrs. Ass'n

State Farm Mut. Auto Ins. Co.,

463 U.S. 29, 42-43 (1983);

Pac. Gas & Elec. Co.

FERC,

373 F.3d 1315, 1319 (D.C. Cir. 2004)). However, the Final Rule retained 2,500 as the appropriate threshold for passing the HHI component of the DPT.

Id.

at 12-13 (citing Order No. 697 at P 2).

45. TDU Systems note that 1,800 is the level which the Commission uses in its merger regulations and contends that the Commission placed too much reliance on the 1994 DOJ recommendations

as to market rates in the very different oil pipeline market for arriving at the 2,500 HHI threshold. TDU Systems state that electric utilities do not face the same competition from other modes of transportation and demand elasticity as do oil pipelines. They state that these factors support their argument for a lower HHI.

If the Commission does not adopt the 1,800 level consistent with effective competition, TDU Systems contend that it should reduce the market-share threshold to 15 percent.

April 14 Order, 107 FERC ¶ 61,018, at P 110 & n.96 (citing Comments of the U.S. Dept. of Justice, Docket No. RM94-1-000 (Jan. 18, 1994)).

TDU Systems Rehearing Request at 14.

. at 6-7 (citing DOJ Comments, Docket No. RM94-1-000 (Jan. 18, 1994), at 13).

46. TDU Systems argue that they made a strong case for reducing the triggering HHI level to 1,800 in their NOPR comments, and that the Commission appears not to have considered it carefully. They assert that if a market is regarded as “highly concentrated,” the DOJ guidelines indicate that even modest increases in concentration will likely raise significant competitive concerns. They contend that, in such a market, other agencies presume that an HHI increase of 100 or more is likely to create or enhance market power. They conclude that, regardless of what the Commission ordered in the April 14 Order, there is no good reason at this time to regard a market with a 2,000 HHI as not highly concentrated.

. at 13.

47. Southern argues that for the same reasons that the market share screen should take into account the overall size of the wholesale market and include a contestable load analysis, the DPT should take into account the overall size of the wholesale market, or should be replaced by a contestable load analysis.

Southern Rehearing Request at 3-4, 11-16 and Frame Affidavit at ¶ 5, 21-22.

Commission Determination

48. In response to the Montana Counsel's request, we clarify that capacity committed to a competitor's native load or otherwise unavailable on a long-term firm basis, will not be considered available to compete with the seller's generation, and as such will not be included as available economic capacity in the DPT analysis. We also note that Montana Counsel misrepresents our findings in the PPL Montana proceeding. In that proceeding, it was not argued that the capacity in question was committed elsewhere. Rather, the Commission addressed the argument that capacity “may” be committed. PPL Companies rebutted that argument by explaining that the buyers at issue did not have long-term firm transmission available to export the energy in question from the NorthWestern control area, and that because the buyers could elect to leave this capacity in the NorthWestern control area, the capacity in question should not be excluded from the available economic capacity in the NorthWestern control area. The Commission noted that PPL Companies' treatment of this capacity is not inconsistent with how DPTs have historically been conducted.

49. The Commission rejects TDU Systems' proposal to reduce the HHI threshold level to 1,800. The Commission will continue to use a 2,500 HHI and a 20 percent market share as the thresholds for the DPT analysis. The Commission believes that the market share/HHI thresholds of 20 percent and 2,500, respectively, enable the Commission to identify dominant firms in highly concentrated markets, rather than firms with market shares above 20 percent that operate in less concentrated markets (e.g., HHIs less than 2,500), resulting in fewer false positives.

Further, the Commission will continue to examine each DPT analysis on a case-by-case basis, weighing other factors, besides market share and HHIs, such as historical sales and transmission data.

Thus, we will retain 2,500 as the appropriate threshold for passing the HHI component of the DPT.

Notwithstanding TDU Systems' argument that the Final Rule fails to explain how the adoption of a 2,500 HHI threshold is rationally related to the Commission's objective of precluding market-based rates in highly concentrated markets, the Commission has explained why 2,500 is the appropriate threshold, and we reject TDU Systems' contention that the Commission did not carefully consider arguments for reducing the threshold to 1,800. At less than 2,500 HHI in the relevant market for all season/load conditions, there is little likelihood of coordinated interaction among suppliers in a market.

TDU Systems argue that the DOJ Merger Guidelines use an 1,800 HHI, but fail to note that the focus of the Guidelines is on

increases

in market concentration produced by a merger. For example, an existing market could have an HHI of 2,400 and the DOJ would take no action if the acquired firm was very small. It is therefore not the 1,800 HHI figure, standing alone, that merits scrutiny by the DOJ, but rather the relative

increase

in concentration that could cause the DOJ to investigate further. We therefore do not believe that our approach conflicts in any way with the DOJ merger guidelines. We also reaffirm our determination not to adopt TDU Systems' suggestion to lower the market share threshold to 15 percent from 20 percent. As we explained, we believe that the 20 percent threshold strikes the right balance in seeking to avoid both false negatives and false positives.

As explained in Order No. 697 at P 100, lowering the HHI threshold to 1,800 will cause more false positives and direct capital away from the generation sector.

Order No. 697 at P 96.

. P 113; April 14 Order, 107 FERC ¶ 61,018, at P 111.

April 14 Order, 107 FERC ¶ 61,018 at P 111.

Order No. 697 at P 113; July 8 Order, 108 FERC ¶ 61,026 at P 95-97; NOPR at P 41.

50. With regard to Southern's argument that the DPT should take into account the overall size of the wholesale market or be replaced by a contestable load analysis, the Commission reaffirms its determination that the contestable load analysis is essentially a variant on the pivotal supplier screen, and therefore redundant. As a variant of the pivotal supplier screen, the contestable load analysis has differences in the calculation of wholesale load and the test thresholds. Like the pivotal supplier screen, it addresses whether suppliers other than the seller can meet the demand in the relevant market. Incorporating such an analysis would not improve our ability to establish a presumption of whether a seller possesses market power and would add little useful information.

In addition, because the indicative screens measure a seller's market power at both peak and off-peak times, they therefore measure market power potential during periods of both high and low demand, and this concern need not be addressed in the DPT.

Order No. 697 at P 66.

. P 65-66.

51. We also reject Southern's argument that the DPT should be replaced by the contestable load analysis. First, unlike the DPT, the contestable load analysis fails to consider relative prices of competing

suppliers.

Second, contrary to Southern's claim, the DPT does consider wholesale load because it analyzes ten different seasons/load periods and the Available Economic Capacity (AEC) analysis deducts the native load commitments of all suppliers, which includes wholesale commitments.

. P 67.

4. Other Products and Models

Final Rule

52. Regarding relevant product markets, the Commission stated in the Final Rule:

[w]e will not generically alter the indicative screens or the DPT to allow different product analyses for short-term or long-term power as some commenters suggest. As the Commission has stated in the past, absent entry barriers, long-term capacity markets are inherently competitive because new market entrants can build alternative generating supply. There is no reason to generically require that the horizontal analysis consider those products that are affected by entry barriers. Instead, we will consider intervenors' arguments in this regard on a case-by-case basis.

Id.

P 122.

53. The Commission also rejected suggestions by some commenters that it adopt behavioral modeling, such as game theory, in addition to or in place of the indicative screens and the DPT. The Commission explained that, although game theory has been used in laboratory experiments and in theoretical studies where the number of players and choices available to players are limited, it is not a practical approach given the volume of analyses the Commission must perform. The Commission noted that a large number of choices are available in market power analyses and many of those are unobservable, and concluded that data gathering and analysis burden imposed on sellers and the Commission if it were to adopt behavior modeling would be overly burdensome and impractical.

Id.

P 124.

Requests for Rehearing

54. NASUCA argues that the Commission must investigate whether sellers are able to raise electricity auction market rates to higher non-competitive levels, without collusion, through strategic bidding and gaming behavior in Commission-approved auction markets.

NASUCA states that experience, mathematical game theory analysis, judicial decisions, and laboratory simulations indicate that market participants who pass market power screens nonetheless may be able to elevate prices in Commission-approved auction markets through non-collusive strategic bidding, withholding, and gaming tactics.

NASUCA states that the Commission's market power screens are based on a static analysis of single sellers' market shares, stating that less than a 20 percent share of the relevant market capacity is sufficient and less than the supply margin on the annual peak day satisfies the “supply margin assessment.” NASUCA concludes that neither of these tools addresses the problem identified in the research that sellers in these specialized markets repeatedly communicate through their bidding behavior.

NASUCA Rehearing Request at 5.

Id.

at 2.

Id.

at 6.

55. NASUCA states that, to its knowledge, the Commission has never publicly discussed mathematical game theory analysis in depth in its orders, has not investigated the problem, and has held no technical conference or workshop to invite researchers to present their findings regarding gameability of the wholesale electricity markets.

NASUCA argues that strategic market behavior analysis is needed to assess whether current market designs allow participants, without overt collusion, to elevate market prices to unreasonable and non-competitive levels. The purpose of such analysis would be to take corrective action to prevent gaming behavior, by revising market designs or rules. NASUCA asserts that the Commission misunderstood NASUCA's request in finding that consideration and analysis of such behavior would be burdensome.

Id.

at 7 (citing Order No. 697 at P 121, 124).

Id.

at 7 (citing Order No. 697 at P 124).

56. NASUCA argues that the “primary purpose” of the FPA and the Commission is protection of utility consumers. NASUCA states that, in order to achieve confidence that rates set in Commission-sanctioned markets are reasonable, the Commission must investigate strategic bidding and market gaming by market participants.

NASUCA therefore requests that, at a minimum, the Commission commence a proceeding to investigate this and begin it by inviting researchers who have identified strategic auction market gaming as a problem in auction markets of the type used for the sale of electricity to present their research at a public technical conference.

Id.

(citing

Electrical Dist. No. 1

FERC

, 774 F.2d 490, 492-93 (D.C. Cir. 1984)).

57. APPA/TAPS argue that, in addition to the existing indicative screens, the Commission should require that the market share screen be submitted using only firm transmission capacity.

In this regard, APPA/TAPS state that applicants should be required to “submit a `firm transmission Market Share Screen' where the SIL [simultaneous transmission import limit] study reflects only firm transmission capacity.”

According to APPA/TAPS, running the market share screen using only firm transmission in the SIL study would provide evidence about who could realistically compete to sell long-term, firm products. Further, APPA/TAPS argue that the pivotal supplier screen is not well adapted to examining market conditions for long-term products, and that the firm transmission market share screen could be performed to provide better insight into the market for long-term products. APPA/TAPS assert that to understand what long-term generation capacity may be available and backed by firm transmission service, the market share screen should be run using an SIL study of firm transmission capacity only, preferably using available transfer capability (ATC) for the upcoming annual period, but at a minimum, run without capacity benefit margin (CBM) modeled as available, even on a non-firm basis.

APPA/TAPS also argue that the Commission should require sellers to calculate the simultaneous available import capability of their systems using the firm ATC values that transmission customers are given, and use those results to prepare one of the iterations of the market share screen.

APPA/TAPS Rehearing Request at 13.

Id.

at 16.

Id.

at 17.

Commission Determination

58. We have considered the strategic bidding literature and various theoretical models which demonstrate that market participants who pass market power screens nonetheless may be able to elevate prices in Commission-approved auction markets through “non-collusive strategic bidding, withholding, and gaming tactics.” However, the Commission does not think it is necessary to investigate the possibility of whether sellers or market participants are able to engage in strategic bidding, withholding and gaming tactics to elevate prices in auction markets in order to determine whether to grant market-based rate authority. First, these theoretical or gaming models require consideration of numerous assumptions and hypothetical future behavior that may quickly become invalid because of the

changing behavior of market participants, changes in the market or changes in other factors, e.g., supply or demand. Accordingly, the Commission is concerned that they would not be reliable tools in helping assess whether a seller has market power. Second, the type of behavior described by NASUCA may be prohibited by the Commission's Anti-Manipulation Rule at section 1c.2 of the Commission's regulations.

Violations of the Anti-Manipulation Rule include behavior constituting a fraud that had the purpose of impairing, obstructing, or defeating a well-functioning market.

The Commission's Office of Enforcement monitors activity in the electric markets and conducts investigations to determine whether market participants are violating the Anti-Manipulation Rule. To the extent that NASUCA or any other entity has specific allegations of market manipulation, that entity should contact the Commission's Enforcement Hotline or the Division of Investigations of the Office of Enforcement. Finally, as the Commission stated in Order No. 697, for practical considerations the data gathering and analysis burden imposed on sellers and the Commission to consider all the hypothetical types of behavior would be overly burdensome and impractical.

Prohibition of Energy Market Manipulation

, Order No. 670, 71 FR 4244 (Jan. 26, 2006), FERC Stats. & Regs. ¶ 31,202 (2006),

reh'g denied

, 114 FERC ¶ 61,300 (2006).

Order No. 670, FERC Stats. & Regs. ¶ 31,202 at P 50-53.

Order No. 697 at P 124.

59. With regard to APPA/TAPS' argument that the existing indicative screens should be altered so that sellers are required to “submit a `firm transmission Market Share Screen' where the SIL study reflects only firm transmission capacity” in order to examine market conditions for long-term products, we reiterate that the indicative screens are intended to identify sellers that raise no horizontal market power concerns in short-term markets, and we decline to allow different product analyses for short-term or long-term power. We address the issue of the analysis of the competitiveness of long-term markets in the section of this order addressing mitigation. Thus, we reject APPA/TAPS' argument that sellers should be required to submit a firm transmission market share screen where the SIL study reflects only firm transmission capacity.

5. Native Load Deduction

Final Rule

60. In Order No. 697, the Commission modified the native load proxy for the market share screen from the minimum peak day in the season to the average peak native load, averaged across all days in the season, making the native load proxy for the market share indicative screen consistent with the native load proxy under the pivotal supplier indicative screen. The Commission found that using the existing native load proxy did not provide an accurate picture of the conditions throughout the season. The Commission explained that a native load proxy based on the average of peak load conditions is more representative, and thus more accurate, than a proxy based on extreme (minimum) peak load conditions, and further, that basing the native load proxy on the average of the peaks is more accurate by eliminating sellers without market power while focusing on ones that may have market power.

61. In addition, the Commission clarified that native load can only include load attributable to native load customers based on the definition of native load in section 33.3(d)(4)(i) of the Commission's regulations and gave sellers the option of using seasonal capacity instead of nameplate capacity.

Requests for Rehearing

62. TDU Systems assert on rehearing that the Commission's failure to explain how its modification of the native load proxy in the wholesale market share screen is rationally related to the objective of accurately detecting the market power of electric utilities in their home control areas is arbitrary and capricious.

TDU Systems Rehearing Request at 3 (citing

Motor Vehicle Mfrs. Ass'n

State Farm Mut. Auto Ins. Co.

, 463 U.S. 29, 42-43 (1983);

Pac. Gas & Elec. Co.

FERC

, 373 F.3d 1315, 1319 (D.C. Cir. 2004)).

63. TDU Systems argue that the Commission should maintain the existing native load proxy for use in the wholesale market share screen

because the Commission does not provide a reasoned analysis and supporting evidence for increasing the native load proxy for the market share indicative screen from the minimum daily native load peak demand for the season to the average daily native load peak demand for the season.

Id.

at 7.

Id.

at 8, 18.

64. TDU Systems point out the Commission's explanation that the virtue of having the two indicative screens is that they each measure different market conditions,

and assert that, to achieve that purpose, they should use different proxies for native load obligations. TDU Systems conclude that the Commission should revise the market share screen to use the minimum native load during the season as the proxy.

April 14 Order, 107 FERC ¶ 61,018 at P 90 (2004).

TDU Systems Rehearing Request at 20.

Commission Determination

65. In response to TDU Systems' assertion that changing the native load proxy is arbitrary and capricious and may not accurately detect the market power of electric utilities in their home balancing authority areas, we acknowledge that increasing the native load proxy may have the effect of reducing the market share for traditional utilities and could result in fewer failures of the market share screen.

However, as we explained in Order No. 697, the native load proxy adopted in Order No. 697 more accurately describes the conditions faced by sellers across seasons rather than simply at the most extreme peak load conditions.

For instance, using the minimum peak day in the native load proxy only measures sellers' available capacity on a single day, and does not reflect the more general conditions faced by sellers throughout the season. Because changing the native load deduction will lead to a more accurate measure of uncommitted capacity for load-serving entities, there will be a more accurate measure of the conditions faced by competing suppliers. Thus, the native load proxy is more accurate in detecting the market power of electric utilities in their home balancing authority areas.

We note that use of the average daily native load peak demand for the season is also applicable to first-tier competitors. Thus, while a traditional utility applicant will have a lower amount of uncommitted capacity than it would have had using a native load proxy based on the minimum daily native load peak demand for the season, so too will traditional utility sellers in first-tier markets. Accordingly, although the traditional utility applicant's uncommitted capacity is reduced, so too is the relative size of the market considering imports from first-tier markets. All else being equal, the market shares of the traditional utility applicant may not change much if at all.

94 Order No. 697 at P 137.

66. We reject TDU Systems' argument that because the pivotal supplier and market share screens measure different market conditions they should therefore use different native load proxies. We disagree and find that is not appropriate to use different native load proxies for the different screens. Although the screens themselves use inherently different methodologies, the native load does not vary depending on which

screen is used. Accordingly, we find that use of the average peak native load as the native load proxy for both screens provides an accurate picture of the conditions throughout the season.

67. We also clarify the definition of native load as it is used in the DPT analysis. With regard to the statement in the Final Rule that under the DPT, a seller “will be considered pivotal if the sum of the competing suppliers' economic capacity is less than the load level (plus a reserve requirement that is no higher than State and Regional Reliability Council operating requirements for reliability) for the relevant period”

we clarify that the analysis should also be performed using available economic capacity to account for sellers' and competing suppliers' native load commitments. We further clarify that native load in the relevant market (sellers' and competing suppliers') should be subtracted from the total load in each season/load period, and that the native load subtracted should be the average of the hourly native load for each season load condition.

Id.

P 108.

See id.

P 150 (citing 18 CFR 33.3(d)(4)(i)).

6. Relevant Geographic Market

Final Rule

68. In Order No. 697, the Commission adopted its existing approach with respect to the default relevant geographic market, with some modifications. The Commission announced that it would continue to use a seller's balancing authority area

or the RTO/ISO market,

as applicable, as the default relevant geographic market, explaining that the use of defined default geographic markets provides the industry with as much certainty as possible while also providing parties the right to challenge the default geographic market definition and submit pertinent evidence.

Previously, the Commission had used the term “control area,” but in the Final Rule it replaced that term with “balancing authority area” with regard to relevant geographic markets.

An RTO/ISO must have a sufficient market structure and a single energy market with Commission-approved market monitoring and mitigation.

Order No. 697 at P 235.

69. With respect to traditional (non-RTO/ISO) markets, the Commission adopted a rebuttable presumption that the seller's default relevant geographic market under both indicative screens would be the balancing authority area where the seller is physically located, and each of its neighboring first-tier balancing authority areas.

100

Id.

P 231-32.

70. With respect to RTO/ISO markets, the Commission stated that sellers located in and 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 completing their horizontal analyses, unless the Commission has already found the existence of a submarket. Where the Commission makes a specific finding that there is a submarket within an RTO/ISO, that submarket becomes the default relevant geographic market for sellers located within the submarket for purposes of the market power analysis (both indicative screens and DPT). In the Final Rule, the Commission concluded that sellers located in these RTO/ISO submarkets should not use the entire RTO/ISO footprints as their relevant geographic markets. The Commission explained that this policy is consistent with how it has treated such submarkets in the context of mergers; the Final Rule cited several cases to support this proposition, including

Exelon Corp.

101

where the Commission found that PJM-East and Northern PSEG are sub-markets within PJM Interconnection (PJM).

101

112 FERC ¶ 61,011,

reh'g denied

, 113 FERC ¶ 61,299 (2005) (

Exelon

). The Commission noted that Exelon later terminated the merger. Order No. 697 at P 236 and n.220.

71. The Commission stated that it would continue to allow sellers and intervenors to present evidence on a case-by-case basis to show that some other geographic market should be considered as the relevant market in a particular case. To the extent that the Commission finds that a submarket exists within an RTO/ISO, intervenors or sellers can provide evidence to the contrary; thus, a submarket, like the other default geographic markets, is a rebuttable default geographic market.

102

The Commission explained that it will also consider arguments that a seller operates in an RTO/ISO submarket even if the Commission has not previously found that a submarket exists. Likewise, sellers and intervenors also may present evidence that the relevant market is broader than a particular balancing authority area or RTO/ISO footprint or submarket.

102

Id.

P 238.

72. The Commission stated that sellers may incorporate the mitigation they are subject to in RTO/ISO markets or submarkets with Commission-approved market monitoring and mitigation as part of their market power analysis.

103

By way of example, if a market power analysis indicates that a seller may have market power, the seller may point to the RTO/ISO mitigation rules as evidence that its market power has been adequately mitigated. The same is true for submarkets; for instance, New York City will be treated as a separate default market for market-based rate study purposes, and its existing In-City mitigation will be used to assess whether any concerns over market power are already mitigated.

104

103

Id.

P 241.

104

Id.

P 242.

Requests for Rehearing

73. TDU Systems and NRECA object to the Commission's determination to use a balancing authority area or RTO/ISO region as a default relevant geographic market; they believe that a seller should always have the burden of defining the appropriate geographic market or submarket and that the Commission cannot lawfully place the burden on customers or intervenors to show that the “default” market is

not

the relevant geographic market.

105

Thus, NRECA argues that the Commission's determination to use the applicant public utility's balancing authority area or the RTO/ISO region as the default relevant geographic market is arbitrary, capricious, contrary to law, in excess of statutory authority, and not supported by substantial evidence.

106

Further, according to NRECA, the Final Rule did not adequately respond to NRECA's argument that default geographic markets should not be used because the Commission cannot place the burden on intervenors to demonstrate that the default market is not the relevant geographic market, and failed to satisfactorily explain the Commission's action “ `including a rational connection between the facts found and the choice made.' ”

107

105

TDU Systems Rehearing Request at 15; NRECA Rehearing Request at 18.

106

NRECA Rehearing Request at 2-3 (citing

Secretary of Labor

Keystone Coal Mining Corp.

, 151 F.3d 1096, 1100 (D.C. Cir. 1998) (

Keystone

); 5 U.S.C. 556(d); 5 U.S.C. 706(2)(A), (C), (E); 16 U.S.C. 824d(e); 16 U.S.C. 825l(b);

Preventing Undue Discrimination and Preference in Transmission Service

, Order No. 890, 72 FR 12265 (March 15, 2007), FERC Stats. & Regs. ¶ 31,241, at P 901-1094 (2007),

order on reh'g and clarification

, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 (2007)).

107

Id.

at 20 (quoting

Pac. Gas & Elec. Co.

FERC

, 373 F.3d 1315, 1319 (D.C. Cir. 2004)).

74. TDU Systems state that, although the Commission has attempted to create a “balanced approach,” it is arbitrary and capricious to grant market-based rate authority based on the inaccurate assumption that in most cases, the Commission will rely on RTO/ISO regions as default geographic markets. TDU Systems cite

Keystone

for the proposition that evidentiary presumptions are only permissible in the presence of a connection between

proven and inferred facts, and asserts that, “[e]ven with the submarkets the Commission identifies in the Final Rule (at P 246), the exceptions to the rule are still far too numerous to declare that the proposal can pass the `so probable that it is sensible' test.”

108

It argues that public utility sellers should have an affirmative obligation, meeting the strict standard for burden shifting, to identify the relevant geographic market and justify the market used in their horizontal market power analyses. Using the wrong default geographic markets prevents the Commission from accurately assessing the public utility's market power and thus contravenes the statutory prerequisites.

108

TDU Systems Rehearing Request at 15.

75. NRECA and TDU Systems claim that the use of RTO/ISO regions and balancing authority areas as default relevant markets in many cases will not produce valid screen results because they do not take into account well-known binding transmission constraints and load pockets, such as those the Commission has found in the New York Independent System Operator (NYISO) and the ISO New England (ISO-NE) submarkets.

109

They assert that the Commission should eliminate the use of the seller's balancing authority area or RTO/ISO region as the relevant market and instead require an applicant to identify the relevant geographic market based on actual data including grid topology and existing transmission constraints.

110

109

NRECA Rehearing Request at 19 (“Given that the Commission was able to find submarkets in relatively compact and contiguous regions such as [NYISO] and [ISO-NE], then the notion of using far-flung RTO/ISO regions such as the Midwest ISO and SPP as default markets is untenable”); TDU Systems Rehearing Request at 15.

110

NRECA Rehearing Request at 20; TDU Systems Rehearing Request at 16.

76. In contrast to the arguments raised on rehearing by NRECA and TDU Systems, PSEG and Reliant find fault with the Commission's ruling that the larger RTO/ISO region will not be used as the default geographic market for market-based rate sellers located in RTO/ISO areas where the Commission has found submarkets to exist. PSEG claims that the ruling departs from many years of Commission policy utilizing the RTO/ISO as the default relevant geographic market and is inconsistent with the Commission's confidence in the impact of RTO/ISO market monitoring and mitigation.

111

PSEG asserts that this major change in policy is not supported by substantial evidence, is not a product of reasoned decision making,

112

and claims that “it is difficult to discern the legal or factual basis for the change.”

113

Regarding the Commission's explanation that the consideration of submarkets is consistent with the Commission's merger analysis, PSEG states that “simply because the Commission needed to examine submarket impacts in the context of an individual merger proceeding does not make that submarket appropriate as a default geographic market to be applied going forward on a generic basis for all sellers in that submarket.”

114

PSEG argues that the focus of the market power analysis is substantively different in the two types of proceedings, and that the public was not on notice that the Commission might rely on findings from a merger proceeding to create a generic rule applicable to all parties located in the same area, thus constituting “retroactive rulemaking.” Moreover, PSEG contends that by basing a generic determination of submarkets on prior merger filings rather than after a systematic review of market power in a region, the Commission adopts a policy that discriminates against some market participants because a market-based rate seller can be located in an RTO/ISO sub-region that has greater instances of transmission constraints than any of the submarkets specifically identified in Order No. 697, but will still be able to proceed with a market-based rate application using the RTO/ISO as the default relevant geographic market.

115

PSEG asserts that a fairer approach would be to review potential submarkets comprehensively as part of the regional review process that will be conducted according to the schedule provided in Appendix D of the Final Rule.

116

111

PSEG Rehearing Request at 2-3 (

quoting

Order No. 697 at P 290 (“We believe that a single market with Commission-approved market monitoring and mitigation and transparent prices provides added protection against a seller's ability to exercise market power * * *”)).

112

. at 6 (citing

Moraine Pipeline Co

. v.

FERC

, 906 F.2d 5, 9 (D.C. Cir. 1990) (reasoned decision making requires that the Commission must not just acknowledge arguments made, but must “respond to [such] arguments and * * * articulate its decision based on evidence in the record”);

Motor Vehicles Mfrs. Ass'n

. v.

State Farm Mutual Auto. Ins. Co.

, 463 U.S. 29, 43, 48, 57 (1983);

Williams Natural Gas Co

. v.

FERC

, 90 F.3d 531, 533 (D.C. Cir. 1996) (To be upheld, the Commission's order must be “supported by substantial evidence and reached by reasoned decision-making—that is, a process demonstrating the connection between the facts found and the choice made.”)).

113

. PSEG also cites

Missouri Public Service Commission

FERC

, 234 F.3d 36, 40 (D.C. Cir. 2000) (when “the Commission balances competing interests in arriving at its decision, it must explain on the record the policies which guide it.”).

114

. at 6-7.

See also

Reliant Rehearing Request at 5-6, warning that sellers may have no choice but to intervene and potentially litigate in additional proceedings where the Commission may possibly make a finding that identifies a new submarket.

115

. at 8.

116

. at 9.

77. Reliant states that the record does not support the use of submarkets in indicative screens, noting that one commenter advocated use of a submarket when applying the DPT but that no commenters suggested that the indicative screens should be performed utilizing a submarket. Reliant argues that when a submarket is used within an RTO/ISO in indicative screens, the applicable default market used will be smaller than the full market within which a seller participates. Reliant claims that this is inconsistent with the design and intent of the indicative screens because identification of a submarket is unpredictable, and because a submarket identified in another potentially unrelated proceeding may be used.

117

Reliant Rehearing Request at 5-6.

78. PSEG argues further that the Commission ignored record evidence proving the lack of technical and policy merit in creating submarkets when performing market power analyses submitted by the three RTO/ISOs that commented on the issue; and it claims that California ISO (CAISO), ISO-NE, and NYISO agree that there is no technical and structural need for the examination of RTO/ISO submarkets.

118

According to PSEG, the Commission's failure to meaningfully consider that evidence and to respond to it was arbitrary and capricious and not reasoned decisionmaking.

119

118

PSEG Rehearing Request at 4-6 (citing NYISO NOPR comments at 3-4; ISO-NE NOPR comments at 4 and 6; and CAISO NOPR comments at 13).

119

. at 6 (citing

Moraine Pipeline Co

. v.

FERC

, 906 F.2d 5, 9 (D.C. Cir. 1990) (holding that the Commission must not just acknowledge arguments made but must respond to such arguments)).

79. PSEG contends that submarkets are inappropriate as default relevant geographic markets because they are largely a product of transmission constraints that periodically create short-term price differences between neighboring geographic areas. Such differences, it states, are not static and can be altered over the long term by transmission reinforcements, new generation entry, and changes in load.

120

It concludes that the unpredictable nature of those forces makes submarkets unreliable for assessing market power, and believes that the Commission should have retained the RTO/ISO as the default relevant geographic market so long as the RTO/ISO has market monitoring and

mitigation programs in place in conjunction with a regional transmission expansion planning program.

120

Reliant Rehearing Request at 7-8; PSEG Rehearing Request at 9-10. Reliant limits its objections to the use of submarkets in indicative screens.

80. With specific reference to the Commission's generic finding of submarkets in Eastern PJM and Northern PSEG, PSEG alleges that the Commission erred in relying on a prior ruling in the Exelon-PSEG merger proceeding,

121

which merger was subsequently terminated. According to PSEG, the Commission cannot rely on the Exelon-PSEG merger proceeding because that analysis was dependent on the assumption that Exelon and PSEG would merge; the termination of the merger changed key assumptions that were material to the market power analysis examining what changes to competitive conditions would occur as a consequence of the merger.

121

PSEG Rehearing Request at 10, referring to

Exelon Corp.

, 112 FERC ¶ 61,011,

order on reh'g

, 113 FERC ¶ 61,299 (2005).

Commission Determination

81. We affirm our decision to use a balancing authority area or RTO/ISO region as a default relevant geographic market. In Order No. 697, the Commission fully explained the basis for using default geographic markets. The Commission explained that the use of defined default geographic markets provides sellers and intervenors a measure of certainty regarding the relevant market while also providing parties the right to challenge the default geographic market definition and submit pertinent evidence of an alternative geographic market based on actual data.

82. As discussed more fully below, we reject NRECA's and TDU Systems' argument that the Commission's determination to use the applicant public utility's balancing authority area or the RTO/ISO region as the default relevant geographic market is arbitrary, capricious, contrary to law, in excess of statutory authority, and not supported by substantial evidence. In Order No. 697 the Commission carefully considered and balanced various arguments on both sides of the issue concerning whether it is appropriate to use default geographic markets for purposes of the horizontal analysis.

83. Our use of the applicant public utility's balancing authority area or the RTO/ISO region as the default relevant geographic market is supported by the evidence. In particular, with regard to traditional (non-RTO/ISO) markets, the Commission adopted as the default geographic market first the balancing authority area where the seller is physically located and, second, the markets directly interconnected to the seller's balancing authority area (first-tier balancing authority area markets). Our decision to use the balancing authority area or the RTO/ISO region as the default geographic market closely tracks our guidance provided in Order No. 697 on what constitutes a market.

122

Our experience has indicated that typically there are frequently recurring physical impediments to trade between balancing authority areas that would prevent competing supplies from first-tier markets from reaching wholesale customers.

123

Thus, our decision to consider balancing authority areas as the default geographic market is neither arbitrary nor capricious but, rather, firmly embedded in the characteristics of our jurisdictional markets.

122

Order No. 697 at P 231-232.

123

. P 268.

84. In addition, with regard to public policy considerations and regulatory certainty, the Commission explained in Order No. 697 that using balancing authority areas allows the Commission and the public to rely on publicly available data provided for balancing authority areas that are relevant to the market-based rate analysis.

124

Further, it is the interconnection and coordination between balancing authority areas that provides a foundation for the Commission to analyze transmission limitations and other transfers of energy and provides reasonable measures of the relevant geographic market under typical circumstances.

125

124

. P 233.

125

. P 251. Similar to a control area, a balancing authority area is physically defined with metered boundaries that we refer to as the balancing authority area. Every generator, transmission facility, and end-use customer must be in a balancing authority area. The responsibilities of a balancing authority include the following: (1)

Match

, at all times, the power output of the generators within the balancing authority area and capacity and energy purchased from or sold to entities outside the balancing authority area, with the load within the balancing authority area in compliance with the Reliability Standards; (2) maintain scheduled interchange and control the impact of interchange ramping rates with other balancing authority areas, in compliance with Reliability Standards; (3) have available sufficient generating capacity, and Demand Side Management to maintain Contingency Reserves in compliance with Reliability Standards; and (4) have available sufficient generating capacity, Demand Side Management, and frequency response to maintain Regulating Reserves and Operating Reserves in compliance with Reliability Standards.

. (citing Approved Reliability Standards

. http://www.ferc.gov/industries/electric/indus-act/reliability/standards.asp

85. With regard to RTO/ISO markets, the Commission's approach has been well considered and consistent with our approach described above regarding traditional markets. After weighing all the facts, including our experience regulating these markets, the Commission concluded that the geographic region under the control of the RTO/ISO is the appropriate market absent evidence to the contrary. Thus, as a starting point and consistent with our guidance on what constitutes a market, the Commission has made a finding that the geographic region under the control of the RTO/ISO is appropriate for use as the default geographic market. In addition, where the Commission has made a specific finding that there is a submarket within an RTO/ISO, the Commission explained that the submarket should be considered as the default relevant geographic market. Thus, our decision to consider the geographic region under the control of the RTO/ISO as the default geographic market, unless the Commission makes a specific finding of the existence of a submarket, is neither arbitrary nor capricious, but similarly embedded in the characteristics of our jurisdictional markets.

86. With regard to TDU Systems' and NRECA's assertion that a seller should always have the burden of defining the appropriate geographic market or submarket and that the Commission cannot lawfully place the burden on customers or intervenors to show that the “default” market is not the relevant geographic market, we disagree. As stated above, after careful consideration and based on the facts before us, the Commission has made findings regarding these geographic markets. We reject TDU Systems' and NRECA's argument that under

Keystone

, the Commission may not grant market-based rate authority based on the assumption that, in most cases, the Commission will rely on RTO/ISO regions as default geographic markets because such a presumption shifts the burden of establishing the relevant geographic market from the seller to intervenors. In

Keystone

, the court found that an evidentiary presumption is only permissible if there is “a sound and rational connection between the proved and inferred facts.”

126

Contrary to TDU Systems' and NRECA's argument that there is no evidence to support use of RTO/ISO regions as default geographic markets, and, as explained in the Final Rule, the RTO/ISO regions have historically been used as default geographic markets.

127

explained in the Final Rule and prior orders, we have used RTO/ISO regions as the default market for many reasons, including the central commitment and dispatch in most RTOs/ISOs, the elimination of trade barriers within those regions (e.g., pancaked rates), common market mitigation and other factors.

128

On rehearing, TDU Systems and NRECA have presented no empirical evidence demonstrating that RTO/ISO regions should not be used as default geographic markets, or that the use of RTO/ISO regions as default geographic markets is inadequate or insufficient for the typical situation.

126

Keystone

, 151 F.3d 1096 at 1100.

127

See

April 14 Order at P 41, 187 (stating that when performing the generation market power analysis, applicants located in RTOs/ISOs with sufficient market structure may consider the geographic region under the control of the RTO/ISO

as the relevant default geographic region for purposes of completing their analyses, and comparing the practice to the Commission's earlier approach under the hub and spoke analysis).

128

See

e.g.

, April 14 Order at P 187-191; July 8 Order at P 177;

Mystic I, LLC

, 111 FERC ¶ 61,378, at P 14-19 (2005) (rejecting challenge to the use of ISO-NE market as the relevant geographic market on the basis that local market power mitigation is in place: “[W]ithout specific evidence to the contrary, we are satisfied that ISO-NE has Commission-approved tariff provisions in place to address instances where transmission constraints would otherwise allow generators to exercise local market power and that these rules and procedures will apply in the NEMA/Boston zone within ISO-NE.”);

Wisconsin Electric Power Co.

, 110 FERC ¶ 61,340, at P 19-20,

reh'g denied

, 111 FERC ¶ 61,361, at P 13-15 (2005) (rejecting challenge to use of Midwest ISO market as the relevant geographic market on basis that local market power mitigation measures exist: “The tighter thresholds in NCAs such as WUMS in the Midwest ISO, and the resulting tighter mitigation of bids, are local market power mitigation measures” and should adequately address specific concerns regarding the possibility that Wisconsin Electric can exercise market power in the WUMS region).

Accord AEP Power Marketing, Inc.

, 109 FERC ¶ 61,276 (2004),

reh'g denied

, 112 FERC ¶ 61,320, at P 23-25 (2005),

aff'd

Industrial Energy Users-Ohio

FERC

, No. 05-1435 (D.C. Cir. Feb. 16, 2007) (use of PJM footprint as relevant geographic market; noting existence of Commission-approved market monitoring and mitigation).

See also Midwest Independent Transmission System Operator, Inc.

, 109 FERC ¶ 61,157, at P 463 (2004) (noting that the Midwest ISO-wide market will not be considered as the default geographic market until such time as the Midwest ISO becomes a single market and performs functions such as single central commitment and dispatch with Commission-approved market monitoring and mitigation).

87. We agree with NRECA and TDU Systems that we should take into account binding transmission constraints and load pockets in both RTO/ISO regions and balancing authority areas and Order 697 does so. Based on our findings on binding transmission constraints, the Commission has identified six submarkets in NYISO, PJM, and ISO-NE, as described in Order No. 697.

129

Where the Commission has made a specific finding that there is a submarket within an RTO/ISO or within any other market, the market-based rate analysis (both the indicative screens and the DPT) should consider that submarket as the default relevant geographic market.

130

We note that NRECA and TDU Systems' argument that the use of RTO/ISO regions and balancing authority areas as the default relevant market in many cases will not produce valid screen results because this use does not take into account “well-known binding transmission constraints and load pockets” is overly simplistic. The Commission has provided in Order No. 697

131

guidance as to the record information needed to make a determination that an alternative geographic market is appropriate (e.g., expanded market, submarket). The Commission will, and has,

132

carefully considered record evidence regarding geographic markets. In particular, “well-known” is an arbitrary term and does not meet the type of evidence needed for the Commission to base a determination. Accordingly, we will continue to use a seller's balancing authority area or the RTO/ISO market, as applicable, as the default relevant geographic market, unless the Commission makes a specific finding of the existence of a submarket.

129

. P 236.

130

131

. P 267-278.

132

See Pinnacle West Capital Corp.

, 122 FERC ¶ 61,035 (2008).

88. We disagree with PSEG's statement that, “simply because the Commission needed to examine submarket impacts in the context of an individual merger proceeding does not make that submarket appropriate as a default geographic market to be applied going forward on a generic basis for all sellers in that submarket.” As discussed above, our determination of what constitutes a geographic market is not dependent upon whether the type of proposal before us is in the context of a market-based rate or merger proceeding. Rather, we base our determination on facts relating to a particular region and the guidelines we have provided regarding what constitutes a geographic market. Whether in a merger proceeding, RTO proceeding, or market-based rate proceeding the fundamental characteristics of a market does not change nor should we ignore our findings because administratively they were made in a different proceeding.

89. With regard to PSEG's argument that the public was not on notice that the Commission might rely on findings from a merger proceeding that could apply in subsequent market-based rate proceedings, we reiterate that, to the extent that the Commission finds that a submarket exists within an RTO/ISO, intervenors or sellers can provide evidence to the contrary (

i.e.

, the submarket, like our other default geographic markets, is rebuttable).

133

Moreover, in the NOPR in this proceeding, the Commission explained that its experience with corporate mergers and acquisitions indicates that the RTO/ISOs that the Commission has identified as meeting the criteria for being considered a single market for purposes of performing the generation market power screens have, at times, been divided into smaller submarkets for study purposes because frequently binding transmission constraints prevent some potential suppliers from selling into the destination market. Therefore, the Commission sought comment on its approach under the market-based rate program of considering the entire geographic region under control of the RTO/ISO, with a sufficient market structure and a single energy market, as the default relevant market. Further, the NOPR asked whether the Commission should continue its approach of considering the entire geographic region as the default market for purposes of the indicative screens but consider RTO/ISO submarkets for purposes of the DPT.

134

Thus, contrary to PSEG's argument, since the issuance of the NOPR in May 2006, the public has been on notice that the Commission might rely on findings from a merger proceeding that could apply in determining RTO/ISO submarkets that may be used in market-based rate proceedings.

133

Order No. 697 at P 238.

134

NOPR at P 61; Order No. 697 at P 215.

90. However, we will grant PSEG's request for rehearing regarding the Commission's determination in the Final Rule that because the Commission made a prior finding in the Exelon-PSEG merger proceeding that Northern PSEG is a separate market in PJM, sellers in PJM should use that submarket as the default geographic market for their market-based rate analysis. After the parties in that case terminated the merger, the U.S. Court of Appeals for the D.C. Circuit vacated the Commission's orders on procedural grounds. In light of the ultimate disposition of Exelon/PSEG merger proceeding, on reconsideration, we conclude that we erred in relying on a prior finding of submarkets that was made in that proceeding.

135

Exelon Corp.

, 112 FERC ¶ 61,011,

reh'g denied

, 113 FERC ¶ 61,299 (2005),

vacated

PPL Electric Utilities Corp

. v.

FERC, No. 06-1009 (D.C. Cir. Dec. 21, 2006)

91. With regard to PJM East, however, we note that in proceedings other than the Exelon/PSEG merger, the

Commission also treated PJM-East as a market within PJM.

136

Accordingly, we reaffirm our finding in the Final Rule that because the Commission already has found that PJM-East constitutes a separate market in PJM, sellers located in PJM should use PJM-East as the default geographic market.

136

See,

e.g.,

El Paso Energy Corporation,

92 FERC ¶ 61,076 (2000),

Energy East Corporation

, 96 FERC ¶ 61,322 (2001),

Potomac Electric Power Company,

96 FERC ¶ 61,323 (2001).

92. We reject PSEG's argument that the Commission's policy discriminates against some market participants. In particular, PSEG contends that a market-based rate seller can be located in an RTO/ISO sub-region that has greater instances of transmission constraints than any of the submarkets specified in the Final Rule, but will be able to proceed with a market-based rate application using the RTO/ISO as the default relevant market. As the Commission has stated, default geographic markets are adequate and sufficient for the typical situation, and by defining default geographic markets, we provide the industry as much certainty as possible while also providing affected parties the right to challenge the default geographic market definition and provide evidence in that regard.

137

Thus, in the example posited by PSEG, if there is evidence that indicates high instances of transmission constraints within an RTO that has not been previously found to constitute a submarket, intervenors have the opportunity to present that evidence to the Commission. Accordingly, because all market participants have the opportunity to challenge the default geographic market definition, this policy does not discriminate against some market participants. Rather, the Commission's policy in this regard recognizes the findings the Commission has already made and Order No. 697 provides guidance to parties that wish to challenge the default geographic markets.

137

Id.

P 234.

93. With regard to PSEG's claims that the Commission failed to consider evidence submitted by CAISO, ISO-NE, and NYISO that there is no technical and structural need for the examination of RTO/ISO submarkets, we find that where the Commission has made a specific finding that there is a submarket within an RTO/ISO, the market-based rate analysis should reflect the facts and consider that submarket as the default relevant geographic market. To do otherwise would be inconsistent with our findings of a submarket in the first instance. In particular, the Commission has consistently stated that the Commission-approved market monitoring and mitigation provides added protection against a seller's ability to exercise market power, but cannot replace the generation market power analysis.

138

While we consider carefully comments by interveners, this Commission will also consider all the facts before us before making a finding.

138

See

Order No. 697 at P 290.

94. In addition, while PSEG is correct that transmission constraints can be temporary, as noted above, all of the submarkets that the Commission has identified result from frequently binding transmission constraints during historical seasonal peaks examined; these particular constraints have not tended to be temporary in nature. Evidence with respect to whether a transmission constraint is temporary or is frequently binding will be considered in determining whether a submarket exists. To the extent that some existing constraints may be alleviated by construction of new transmission facilities, parties may bring these situations to our attention for further consideration.

95. Without a correctly defined submarket, sellers with market power in the RTO/ISO market may not be identified, and their market power mitigated in both the real-time and day-ahead markets. While we acknowledge PSEG's claim that the Commission's determination on RTO/ISO submarkets departs from Commission policy utilizing the RTO/ISO as the default relevant geographic market, we disagree with PSEG's claim that this is inconsistent with Commission confidence in the impact of RTO/ISO market monitoring and mitigation. The purpose of this rulemaking proceeding has been to consider and evaluate the Commission's current market-based rate policy and to make adjustments to this approach, as warranted. Thus, we have carefully considered the facts before us, including our historical approach, and found it reasonable that where the Commission has made a specific finding that there is a submarket within an RTO/ISO, the market-based rate analysis should reflect those facts and consider that submarket as the default relevant geographic market because to do otherwise would be inconsistent with our findings of a submarket in the first instance. In addition, the Commission has been in the process of developing and improving policies that best protect customers and promote market competition in a manner that accounts for the changing nature of developing electricity markets. We will not depart from this basic approach.

96. Moreover, PSEG overstates the difference between our prior policy and the policy adopted in Order No. 697. Prior to Order No. 697, the Commission did not identify submarkets within an RTO/ISO as default geographic markets, but one of the principal reasons for this policy was the ability to rely on Commission-approved mitigation in submarkets within RTOs/ISOs to mitigate any localized market power. Although Order No. 697 changed our approach to geographic market definition as it relates to submarkets, applicants may propose to continue to rely on Commission-approved mitigation in these submarkets as adequate to address any market concerns.

RTO/ISO Exemption

Final Rule

97. Prior to the April 14 Order, the Commission exempted sellers located in markets with Commission-approved market monitoring and mitigation from providing generation market power analyses stating that such sellers will be governed by the specific thresholds and mitigation provisions approved for the particular markets.

139

In the April 14 Order, the Commission determined that it would no longer exempt these sellers, on the basis that requiring sellers located in such markets to submit screen analyses provided an additional check on the potential for market power. In Order No. 697, the Commission declined the request by commenters that it reinstate the pre-April 14 Order exemption for sellers located in markets with Commission-approved market monitoring and mitigation from providing generation market power analyses. Instead, the Commission indicated that it would continue to require generation market power analyses from all sellers, including those in RTO/ISO markets. The Commission noted that while a single market with Commission-approved market monitoring and mitigation and transparent prices provides added protection against a seller's ability to exercise market power, it cannot replace the generation market power analysis.

140

139

See AEP Power Marketing, Inc.,

97 FERC ¶ 61,219 (2001).

140

Id.

P 290.

Requests for Rehearing

98. Reliant and PSEG argue that the Commission should reconsider its decision not to exempt sellers located in markets with Commission-approved

market monitoring and mitigation from submitting horizontal market power analyses. Reliant contends that the Commission did not explain what value a separate horizontal market power analysis would have, given that market monitoring by an independent market monitor consistent with Commission-approved rules and mitigation already identifies and mitigates market power. According to Reliant, market monitoring and mitigation provides a better picture of market power issues in RTO/ISO markets as compared to an individual seller's separate horizontal market power analysis which considers only market power at a fixed moment in time and also provides relief from the costs and burdens of producing a horizontal market power analysis.

141

In the alternative, if the Commission declines to reinstate the exemption, Reliant asserts that the Commission should clarify that Commission-approved mitigation rules presumptively mitigate a seller's market power and, in addition, the Commission should reconsider its decision to utilize previously identified RTO/ISO submarkets as the relevant geographic market for the indicative screens.

141

Reliant Rehearing Request at 2-3.

99. Reliant opines that a fundamental purpose and objective of market monitoring and mitigation is to detect actual, and the potential for, market power and to safeguard against it so as to ensure that no seller in the market can dominate the market, manipulate price, or otherwise act to stifle competition.

142

Accordingly, Reliant argues that a presumption that a seller's market power is adequately mitigated where Commission-approved market monitoring and mitigation rules are in effect is entirely appropriate, unless an intervenor can demonstrate why Commission-approved mitigation is insufficient in a particular case. According to Reliant, it is not appropriate to add the administrative burden of applying indicative screens if the Commission believes that market monitoring and mitigation is generally working.

143

142

Id.

at 3 (citing

Market Monitoring Units in Regional Transmission Organizations and Independent System Operators,

111 FERC ¶ 61,267, at P 1 (2005) (market monitoring units perform an important role in enhancing competitiveness of RTO/ISO markets by, among other things, monitoring organized wholesale markets to identify potential anticompetitive behavior by market participants and providing comprehensive market analysis critical for informed policy decision making); April 14 Order, 107 FERC ¶ 61,018 at P 186, 190 (recognizing the pro-competitive benefits of RTO/ISO markets with market monitoring and mitigation)).

143

Id.

at 7.

100. PSEG asserts that the Commission erred in failing to create a presumption that, even when the Commission has found submarkets to exist, no further analysis of the submarkets is required so long as a robust RTO/ISO market monitoring and mitigation scheme is in place. According to PSEG, a demonstration of a lack of market power in submarkets should only be required if there is reason to question whether such local market power is being addressed. RTO/ISO markets with Commission-approved market monitoring and mitigation programs in place should have a presumption that analysis of potential submarkets is not required. PSEG states that, to the extent other market participants believe otherwise, the burden should fall on them to show that an analysis of these submarkets was in fact required.

144

PSEG Rehearing Request at 11-12.

101. To further support its position, PSEG notes that none of the three RTO/ISOs that filed comments on the NOPR saw any reason for applying mitigation outside of their existing programs. PSEG states that not accepting the efficacy of the RTO/ISO mitigation for purposes of the market-based rate assessment potentially undermines the authority and role of the RTO/ISOs.

145

PSEG suggests that the Advanced Notice of Proposed Rulemaking on organized markets would be a preferable way for the Commission to fine-tune the market monitoring and mitigation functions of such organizations on a prospective basis.

146

145

Id.

146

Id.

at 12 (citing

Wholesale Competition in Regions with Organized Electric Markets, Advanced Notice of Proposed Rulemaking

, 72 FR 36276 (July 2, 2007), FERC Stats. & Regs. ¶ 32,617 (2007) (considering potential reforms to attributes of organized markets, including market monitoring).

102. Similarly, EEI requests that the Commission clarify that “mitigated sellers in RTOs and ISOs may rely on Commission-approved market monitoring and mitigation for sales within the RTOs and ISOs without each seller having to demonstrate that such mitigation suffices in place of the default mitigation, unless a complainant demonstrates that the RTO and ISO monitoring and mitigation does not suffice as to a particular seller.”

147

EEI is concerned that the Commission may unnecessarily burden sellers in the organized markets with having to demonstrate in each individual proceeding that the RTO/ISO mitigation measures suffice as an alternative to Order No. 697's default mitigation.

147

EEI Rehearing Request at 4-5.

103. NRG believes that Order No. 697 creates ambiguity regarding how the Commission's default market power mitigation regime will interact with existing mitigation regimes that have been approved in organized RTO/ISO markets. NRG asserts that this ambiguity will discourage suppliers from building new generation in constrained areas. Thus, NRG seeks clarification, and, alternatively, rehearing, on two points. First, NRG asks that the Commission clarify that it will rebuttably presume that existing RTO/ISO regimes adequately mitigate market power for any sellers located in an RTO/ISO market that fail to pass indicative screens and a DPT analysis.

148

Second, in the event that a seller's market power is found not to be adequately mitigated, the Commission should clarify that the seller is allowed to propose its own tailored mitigation measures not necessarily based on embedded costs.

149

148

NRG Rehearing Request at 2.

149

Id.

at 3.

104. On the first point, NRG explains that the Final Rule does not explicitly state that RTO/ISO monitoring and mitigation protocols will provide sufficient mitigation for any market power presumed if a seller fails the screens. NRG asserts that any generation market power a seller might possess has already been mitigated by those protocols. Thus, such sellers should not automatically be treated the same way as other mitigated sellers and subjected to default mitigation. However, NRG contends that the Final Rule leaves in question whether existing RTO/ISO mitigation regimes or the conflicting mitigation regime adopted in the Final Rule will govern in future seller-specific cases. NRG warns that this regulatory uncertainty will put new investment at risk, an outcome that should be avoided given the great efforts made to put in place alternatives to RMR contracts.

150

In addition, NRG claims that the ambiguity threatens to harm state-sanctioned competitive procurement programs, which typically require binding bids which cannot be conditioned on obtaining subsequent Commission approval.

151

150

Id.

at 7 (citing

Devon Power LLC,

115 FERC ¶ 61,340 (2006) (concerning the New England FCM settlement) and

PJM Interconnection, L.L.C.,

117 FERC ¶ 61,331 (2006) (concerning the PJM RPM settlement)).

151

Id.

at 10-12.

105. Regarding the second requested clarification, NRG notes that in several places in the Final Rule, the Commission states that it will retain existing cost-based default mitigation rates, but is unclear whether alternative, tailored mitigation rates must be cost-

based. NRG seeks clarification that the apparent limitation to cost-based alternatives was inadvertent. In addition, NRG states that “the Commission should make clear that in reviewing alternative mitigation measures proposed by merchant generators in RTOs, it will consider whether the proposed measures will support and attract necessary investment on reasonable terms, and recover the supplier's cost of capital.”

152

Id.

at 16.

106. NYISO states that it is unclear whether the Commission intended to adopt a default mitigation measure that would be inconsistent with its previously approved market design and mitigation measures for the NYISO's bid-based, uniform clearing-price auction markets.

153

In particular, NYISO argues that there is no evidentiary or policy basis that would justify the imposition of default mitigation in the form of a revenue cap, rather than a bid cap, in Commission-approved Locational Based Marginal Price markets like NYISO.

154

153

NYISO Rehearing Request at 4 (citing

New York Independent System Operator, Inc.,

89 FERC ¶ 61,196 (1999),

order on compliance and reh'g,

90 FERC ¶ 61,317,

clarified,

91 FERC ¶ 61,154 (2000) (orders addressing the NYISO's proposed Market Mitigation Measures);

New York Independent System Operator, Inc., et al.

, 99 FERC ¶ 61,246 (2002) (order on the NYISO's comprehensive mitigation measures filing);

Midwest Independent Transmission System Operator, Inc.,

108 FERC ¶ 61,163, at P 257,

order on reh'g

, 109 FERC ¶ 61,157 (2004) (“We find that the conduct and impact approach with its associated thresholds is an appropriate approach to mitigation in the Midwest ISO's market. The conduct and impact approach allows for a lighter handed approach to mitigation, in which the market is allowed to function as is, except when problems are detected.”)).

154

Id.

at 7.

107. NYISO argues that the imposition of default market power mitigation in the form of revenue caps rather than bid caps would be incompatible with the principles underlying uniform clearing price auctions. NYISO ensures that the market clearing price will either be a competitive price or it will be a mitigated price.

155

Thus, NYISO requests clarification that cost-based mitigation will limit a mitigated entity's permissible maximum bid, but not constrain the mitigated entity from receiving the market clearing price if it is not the marginal seller. Additionally, NYISO argues that if the Commission's default cost-based mitigation is interpreted to impose a revenue cap as well as a bid cap, the NYISO states that it will face significant administrative burdens if revenue caps are imposed rather than bid caps.

156

155

Id.

at 2, 3, 5.

156

Id.

at 7.

108. APPA/TAPS, on the other hand, believe that the Commission should clarify that a seller relying on RTO/ISO mitigation to remedy its market power must demonstrate those measures' effectiveness. APPA/TAPS note that the Final Rule indicates sellers can incorporate existing RTO/ISO mitigation as part of their market power analyses, but asks for clarification that an applicant must make a specific showing that those mitigation measures in fact address the specific concerns in the market-based rate analysis. APPA/TAPS assert that the scope of RTO/ISO mitigation is much narrower than the default, cost-based mitigation the Commission prescribes; it notes that the Commission has stated that RTO/ISO mitigation and the market-based rate analysis are different and that“ ‘pieces of one should not automatically be used as precedent for the other.’ ”

157

APPA/TAPS state that RTO/ISO mitigation measures apply only to spot markets and day-ahead and/or real time, but do not apply to weekly, monthly or long-term transactions, including those negotiated on a bilateral basis, and that RTO/ISO mitigation is often far less protective than the Commission's cost-based default of incremental cost plus 10 percent. APPA/TAPS explain that they are not asking the Commission to make a generic finding that all RTO/ISO mitigation is insufficient to mitigate sellers' generation market power, but that they seek a ruling that the burden of proof that the RTO/ISO mitigation adequately addresses the seller's market power falls on the seller, rather than intervenors. If the Commission does not make that clarification, APPA/TAPS state that it should clarify that it will allow intervenors to challenge such claims and will give meaningful consideration to those challenges.

158

157

APPA/TAPS Rehearing Request at 24 (citing

Midwest Independent Transmission System Operator, Inc.,

109 FERC ¶ 61,157, at P 242 (2004),

order on reh'g

, 111 FERC ¶ 61,043 (2005)).

158

Id.

at 26-27.

Commission Determination

109. The Commission denies the requests of PSEG and Reliant to reconsider its decision to require sellers located in markets with Commission-approved market monitoring and mitigation to submit horizontal market power analyses. As we explained in Order No. 697, while the Commission-approved market monitoring and mitigation in RTO/ISO markets provides protection against a seller's ability to exercise market power, it cannot replace the horizontal market power analyses which provide the Commission and the industry with critical information regarding the potential market power of sellers in the market.

110. We conclude that the dual protections of individual market power analyses and mitigation rules of the RTO/ISOs provide the Commission with better ability to discern and protect against potential market power. While, as discussed below, mitigation rules for the individual RTO/ISOs in most cases should be sufficient to guard against the exercises of market power, we are not comfortable at this time with dispensing of the requirement for sellers in RTO/ISOs to provide us with horizontal market power analyses. Any administrative burden of submitting such analyses is outweighed by the additional information gleaned with respect to a specific seller's market power.

111. APPA/TAPS request that the Commission clarify on rehearing that a seller relying on RTO/ISO mitigation to mitigate its market power must demonstrate the effectiveness of those measures. A number of other petitioners, on the other hand, request that the Commission clarify that it will rebuttably presume that existing RTO/ISO regimes adequately mitigate market power for any sellers located in an RTO/ISO market that fail the indicative screens and the DPT analysis. In response to these requests, 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. However, intervenors may challenge the effectiveness of that mitigation. We agree with PSEG that the challenging party should have the burden of proof to demonstrate that existing RTO/ISO mitigation is not sufficient. Thus, because existing RTO/ISO mitigation has been found to be just and reasonable by the Commission in the context of a proceeding specific to a particular RTO/ISO and involving all of its stakeholders, we believe it appropriate and clarify herein that there is a rebuttable presumption that such RTO/ISO mitigation is adequate to mitigate market power in the RTO/ISO market, including Commission-approved mitigation applicable to RTO/ISO submarkets such as In-City New York. To the extent that a party wishes to challenge that presumption, the challenging party will have the burden of proof.

112. In response to EEI, to the extent the Commission has considered a challenge to existing mitigation and has found it to be adequate, any additional challenges must demonstrate a change in circumstances rather than just rearguing issues on which the Commission has already ruled.

113. A number of petitioners raise issues regarding the types of mitigation that the Commission might impose on mitigated sellers in RTOs/ISOs. NRG requests that, in the event a seller's market power is found not to be adequately mitigated, the Commission should clarify that the seller may propose tailored mitigation measures that are not necessarily based on embedded costs. NYISO states that it is unclear whether the Commission intended to adopt a default mitigation measure for any sellers located in an RTO/ISO market that fail to pass the indicative screens and the DPT analysis and seeks clarification that cost-based mitigation will only limit a mitigated entity's permissible maximum bid, but will not constrain the mitigated entity from receiving the market clearing price if it is not the marginal seller.

114. In response to these issues raised regarding the types of mitigation that the Commission might impose on mitigated sellers in RTO/ISO, the Commission will, depending on the nature of the evidence submitted by an intervenor, consider whether to institute a separate section 206 proceeding that would be open to all interested entities to investigate whether the existing RTO/ISO mitigation continues to be just and reasonable and, if not, how such mitigation should be revised. Any intervenor in such a section 206 proceeding may present evidence on the adequacy of the existing mitigation. If appropriate, the Commission will consider modifying that mitigation on an RTO/ISO-wide basis, rather than on a seller-specific basis, because RTO/ISO mitigation is designed to mitigate market power generally. In other words, if existing mitigation is found to be inadequate for a particular seller, then it is likely to be insufficient for all similarly situated sellers. We note that in reviewing alternative mitigation measures in the context of RTOs, the Commission will consider whether the proposed mitigation measures will adequately deter the exercise of market power, are consistent with the RTO/ISO's market design and will support and attract necessary investment on reasonable terms, and recover the suppliers' cost of capital. With regard to NYISO's request, as discussed above, with regard to sellers located in an RTO/ISO market that fail to pass the indicative screens and the DPT analysis, we will not impose default cost-based rate mitigation (which is used in non-RTO/ISO markets) in addition to RTO/ISO mitigation. Rather, we adopt a rebuttable presumption that the existing mitigation is sufficient to address any market power concerns.

115. With regard to APPA/TAPS' assertion that the scope of RTO/ISO mitigation is much narrower than the default cost-based rate mitigation and its argument that RTO/ISO mitigation provides less protection than the Commission's default mitigation of incremental cost plus 10 percent, we understand that RTO/ISO mitigation measures apply to day-ahead and/or real-time markets, and we reiterate that RTO/ISO mitigation is determined to be just and reasonable when it is approved by the Commission.

159

We review and approve mitigation rules in RTO/ISO markets on the basis of the specific facts and circumstances prevailing in such markets. Thus, customers and other interested parties are fully able, in the context of those proceedings, to comment on whether the mitigation rules are sufficiently strong to deter the exercise of market power. In addition, pursuant to the Final Rule, customers or other affected parties may argue, in the context of a specific market-based rate application or triennial review, that changed circumstances have rendered such mitigation no longer just, reasonable and not unduly discriminatory.

159

APPA/TAPS rely on

Midwest Independent Transmission System Operator, Inc.

, 109 FERC ¶ 61,157, at P 242 (2004),

order on reh'g

, 111 FERC ¶ 61,043 (2005) (Midwest ISO) in arguing that RTO mitigation and the market-based rate analysis are different. We recognize that in Midwest ISO the Commission stated that its market-based rate analysis and mitigation in the Midwest ISO differ, and, as stated above, we reiterate that RTO mitigation is determined to be just and reasonable when it is approved by the Commission.

7. Use of Historical Data

Final Rule

116. The Commission held in the Final Rule that it would retain the “snapshot in time” approach for the indicative screens and the DPT, so that sellers will be required to use actual historical data for the previous calendar year in their market power analyses. After careful consideration of the comments received, the Commission chose not to adopt the NOPR proposal that the DPT analysis allow sellers and intervenors to account for changes in the market that are known and measurable at the time of filing. Instead, the Commission decided to retain its existing practice that sellers are required to use unadjusted historical data in the preparation of a DPT for a market-based rate analysis and clarified that it would require the use of the actual historical data for the previous calendar year.

117. The Commission distinguished this treatment from the approach in the Commission's merger analysis, which requires applicants and intervenors to account for changes in the market that are known and measurable at the time of filing. The Commission found that the purpose of using the DPT in market-based rate proceedings is different from that in a merger analysis. Whereas a merger analysis is forward-looking and it is difficult and costly to undo a merger, the market-based rate analysis is a “snapshot in time” approach where the Commission's focus is on whether the seller passes the indicative screens and the DPT based on unadjusted historical data. The Commission considered that its grant of market-based rate authority is conditioned on, among other things, the seller's obligation to inform the Commission of any change in status from the circumstances the Commission relied on in granting it market-based rate authority on an ongoing basis. Thus, the change in status reporting requirement allows the Commission to evaluate changes when they actually happen rather than relying on projections, making it unnecessary and redundant for the Commission to allow sellers to account for known and measurable changes in the DPT.

Requests for Rehearing

118. Montana Counsel argues that the Commission erred in refusing to allow adjustments to the DPT analysis to account for known and measurable future changes, such as contracts for the sale of capacity belonging to the seller that will expire during the term of its market-based rate authority. Montana Counsel asserts that by refusing to consider known and measurable changes, the Commission is intentionally allowing the DPT analysis to be conducted based on data and assumptions that are known not to be representative of reality.

160

Montana Counsel argues that it is inherently irrational, arbitrary, and capricious to allow companies whose generation market power is being analyzed to deduct the generation that is being tested from its supply on grounds that the generation is committed, as the Commission does when the contracts for power from that generation are expiring. Montana Counsel states that such a market power test is inherently flawed, and that this flawed test has concrete

results, with negative impacts for consumers. Montana Counsel cites the Commission's May 2006 renewal of PPL Montana's market-based rate authority, in spite of the fact that the main utility in Montana, NorthWestern Energy, must buy from PPL Montana to serve its load, as an example of the negative impact that the market power test can have on consumers.

161

160

Montana Counsel Rehearing Request at 7.

161

. at 7-8 (citing

PPL Montana, LLC

, 115 FERC ¶ 61,204 (2006) (

PPL Montana

)). Montana Counsel includes its request for rehearing of

PPL Montana

, filed June 16, 2006 in Docket No. EL05-124,

et al.

, as Attachment A to its request for rehearing of Order No. 697.

. at 8. The Montana Counsel's rehearing request in the PPL Montana proceeding asserts that the Commission's decision to renew the market-based rate authority of the PPL Montana Companies is error insofar as it is contrary to record evidence and the requirements of the Federal Power Act. The Commission denied Montana Counsel's request for rehearing in

PLL Montana LLC

, 120 FERC ¶ 61,096 (2007).

119. Montana Counsel notes that the Final Rule distinguishes the market-based rate process from the Commission's merger analysis by saying that while mergers are difficult to undo, sellers with market-based rate authority must file change in status reports, allowing the Commission to evaluate changes when they happen. Montana Counsel argues that the Commission misses the point that if the change in status is caused by the expiration of a long-term contract for the sale of capacity, then by the time the change in status report is submitted, the seller may have already re-sold the capacity at a price reflecting the seller's underlying market power.

162

. at 8-9.

120. Montana Counsel contends that the refusal to consider known and measurable changes is especially inappropriate in light of the fact that the Commission considers mitigation proposed by the seller.

163

Montana Counsel argues that, if the Commission will consider an applicant's “ ‘propos[al] to transfer operational control of enough generation to a third party such that the applicant would satisfy [the Commission's] generation market power concerns’ ” it should also consider whether an applicant's available capacity will increase during the market-based rate authorization period when contracts expire.

164

163

. at 9 (citing Order No. 697 at P 25, 63 n.46).

164

121. NRECA similarly asserts that the Final Rule's failure to require applicants and allow intervenors to incorporate known and measurable changes to historical data in the indicative screens and the DPT in favor of a rigid “snapshot” analysis of historical data is arbitrary, capricious, contrary to law, and in excess of statutory authority.

165

NRECA argues that, if the Commission knows a change will take place, it would be arbitrary and capricious to grant market-based rate authority based on an assumption that the change will not take place.

166

Long-term contracts will expire on a known schedule, and the seller should not be allowed to assume that the capacity will remain committed to the buyer. According to NRECA, the Commission cannot, consistent with the FPA, ignore that pending change in circumstances. At a minimum, intervenors should have the opportunity to demonstrate the applicant's market power using data reflecting conditions after the contracts expire.

167

165

NRECA Rehearing Request at 3, 21 (citing

Cal. ex rel. Lockyer

FERC

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

Lockyer

); 5 U.S.C. 706(2)(A), (C)).

166

. at 21 (citing

Mo. Pub. Serv. Comm'n

FERC

, 337 F.3d 1066, 1075 (D.C. Cir. 2003) (“Reliance on facts that an agency knows are false at the time it relies on them is the essence of arbitrary and capricious decision making.”)).

167

. at 22.

122. NRECA states that the Commission's reliance on change in status filings as the means to report the expiration of a long-term contract is illogical and does not constitute reasoned decision making.

168

NRECA believes that absent a full market power analysis, it is impossible to adequately determine the effect of the change. NRECA submits that the triennial review will often come too late to protect customers.

169

168

. (citing Motor

Vehicle Mfrs. Ass'n

, 463 U.S. at 43;

Pac. Gas & Elec. Co

. v.

FERC

, 373 F.3d at 1319).

169

. at 23 (citing

Lockyer

, 383 F.3d at 1014-15.