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

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DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM04-7-000] Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities May 19, 2006. AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Notice of proposed rulemaking.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is proposing to amend its regulations to revise Subpart H to Part 35 of Title 18 of the Code of Federal Regulations governing market-based rates for public utilities pursuant to the Federal Power Act (FPA). The Commission is proposing to codify and, in certain respects, revise its current standards for market-based rates for sales of electric energy, capacity, and ancillary services. The Commission is proposing to retain several of the core elements of its current standards for granting market-based rates. However, we propose certain revisions to these standards and seek comment on other issues. The Commission also proposes to streamline certain aspects of its filing requirements to reduce the administrative burdens on applicants, customers and the Commission.

DATES:

Comments are due August 7, 2006. Reply comments are due September 6, 2006. Comments should be double spaced and include an executive summary.

ADDRESSES:

You may submit comments, identified by Docket No. RM04-7-000, by one of the following methods:

• Agency Web Site: http://www.ferc.gov . Follow the instructions for submitting comments via the eFiling link found in the Comment Procedures Section of the preamble.

• Mail: Commenters unable to file comments electronically must mail or hand deliver an original and 14 copies of their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street, NE., Washington, DC 20426. Please refer to the Comment Procedures Section of the preamble for additional information on how to file paper comments.

FOR FURTHER INFORMATION CONTACT:

Kelly A

l: Commenters unable to file comments electronically must mail or hand deliver an original and 14 copies of their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street, NE., Washington, DC 20426. Please refer to the Comment Procedures Section of the preamble for additional information on how to file paper comments.

FOR FURTHER INFORMATION CONTACT:

Kelly A. Perl (Technical Information), Office of Energy Markets and Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6421. 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:

I. Introduction II. Background and Overview III. Discussion A. Horizontal Market Power 1. Current Policy 2. Proposal B. Vertical Market Power 1. Current Policy 2. Proposal C. Affiliate Abuse/Reciprocal Dealing 1. Power Sales Restrictions 2. Market-Based Rate Code of Conduct for Affiliate Transactions Involving Power Sales and Brokering, Non-Power Goods and Services and Information Sharing D. Mitigation 1. Current Policy 2. Proposal E. Implementation Process 1. Current Practice 2. Proposal F. Market-Based Rate Power Sales Tariff G. Miscellaneous Issues 1. Waivers 2. Foreign Sellers 3. Change in Status 4. Third-Party Providers of Ancillary Services IV. Information Collection Statement V. Environmental Analysis VI. Regulatory Flexibility Act Analysis VII. Comment Procedures VIII. Document Availability I. Introduction

oposal E. Implementation Process 1. Current Practice 2. Proposal F. Market-Based Rate Power Sales Tariff G. Miscellaneous Issues 1. Waivers 2. Foreign Sellers 3. Change in Status 4. Third-Party Providers of Ancillary Services IV. Information Collection Statement V. Environmental Analysis VI. Regulatory Flexibility Act Analysis VII. Comment Procedures VIII. Document Availability I. Introduction

1. Pursuant to sections 205 and 206 of the Federal Power Act (FPA), 1 the Commission is proposing to amend its regulations to revise Subpart H to Part 35 of Title 18 of the Code of Federal Regulations to govern market-based rate authorizations for wholesale sales of electric energy, capacity and ancillary services by public utilities, including modifying all existing market-based authorizations and tariffs so they will be expressly conditioned on or revised to reflect certain new requirements proposed herein. The major components of this Notice of Proposed Rulemaking (NOPR) are summarized in the next section.

1 16 U.S.C. 824d, 824e (2000).

II. Background

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

3. The courts have reviewed the Commission's market-based rate program and found that it satisfies the FPA

er and its affiliates lack, or have adequately mitigated, market power in transmission; (3) whether the seller or its affiliates can erect other barriers to entry; and (4) whether there is evidence involving the seller or its affiliates that relates to affiliate abuse or reciprocal dealing.

3. The courts have reviewed the Commission's market-based rate program and found that it satisfies the FPA. The FPA requires that all rates demanded by public utilities for the sale of electric energy at wholesale be found ‘just and reasonable.’ 2 The United States Supreme Court has explained that the just and reasonable standard “does not compel the Commission to use any single pricing formula.” 3 The United States Court of Appeals for the D.C. Circuit has long held that “when there is a competitive market the [Commission] may rely upon market-based prices in lieu of cost-of-service regulation to assure a “just and reasonable” result.” 4 The Commission's authorization of market-based rates has been found to satisfy the just and reasonable standard of the FPA. 5

2 Louisiana Energy and Power v. FERC, 141 F.3d 364, 365 (D.C. Cir. 1998) ( citing 16 U.S.C. 824d(a)) ( Louisiana Energy ).

3 Mobil Oil Exploration v. United Distribution Co., 498 U.S. 211, 224 (1991).

4 Elizabethtown Gas Company v. FERC, 10 F.3d 866, 870 (D.C. Cir. 1993) ( Elizabethtown Gas ), ( citing Tejas Power Corp. v. FERC , 908 F.2d 998, 1004 (D.C. Cir. 1990)).

5 See Louisiana Energy; Elizabethtown Gas; Consumers Energy Company v. FERC, 367 F.3d 915, 923 (D.C. Cir. 2004).

824d(a)) ( Louisiana Energy ).

3 Mobil Oil Exploration v. United Distribution Co., 498 U.S. 211, 224 (1991).

4 Elizabethtown Gas Company v. FERC, 10 F.3d 866, 870 (D.C. Cir. 1993) ( Elizabethtown Gas ), ( citing Tejas Power Corp. v. FERC , 908 F.2d 998, 1004 (D.C. Cir. 1990)).

5 See Louisiana Energy; Elizabethtown Gas; Consumers Energy Company v. FERC, 367 F.3d 915, 923 (D.C. Cir. 2004).

4. The Commission initiated the instant rulemaking proceeding in April 2004 to consider “the adequacy of the current four-prong analysis and whether and how it should be modified to assure that prices for electric power being sold under market-based rates are just and reasonable under the Federal Power Act.” 6 At that time, the Commission noted that much has changed in the industry since the four-prong analysis was first developed and posed a number of questions that would be explored through a series of technical conferences. The comments from these technical conferences are considered in this NOPR. 7

6 Market-Based Rates for Public Utilities, 107 FERC ¶ 61,019 at P 1 (2004) (initiating rulemaking proceeding).

7 A summary of the comments submitted in this proceeding is attached as Appendix E. A list of the commenters is included in Appendix D.

5. On April 14, 2004, the Commission issued an order modifying the then-existing generation market power 8 The April 14 Order adopted a policy that would provide sellers a number of procedural options, including two indicative generation market power screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis), and the option of proposing mitigation tailored to the particular circumstances of the seller that would eliminate the ability to exercise market power. The order also explained that sellers could choose to adopt cost-based rates.

8 AEP Power Marketing, Inc., 107 FERC ¶ 61,018 (April 14 Order), order on reh'g, 108 FERC ¶ 61,026 (2004) (July 8 Order).

nd an uncommitted market share analysis), and the option of proposing mitigation tailored to the particular circumstances of the seller that would eliminate the ability to exercise market power. The order also explained that sellers could choose to adopt cost-based rates.

8 AEP Power Marketing, Inc., 107 FERC ¶ 61,018 (April 14 Order), order on reh'g, 108 FERC ¶ 61,026 (2004) (July 8 Order).

6. On July 8, 2004, the Commission acted on requests for rehearing of the April 14 Order, reaffirming the basic analysis, but clarifying and modifying certain instructions for performing the generation market power analysis. The Commission clarified, among other things, the types of data on which sellers and intervenors may rely, and that adjustments may be allowed in certain circumstances. The Commission also clarified that mitigation would be imposed in all markets where a seller is found to have generation market power.

7. The Commission believes it is now appropriate to revise and codify the standards for market-based rates for wholesale sales of electric energy, capacity and ancillary services. Refining and codifying effective standards for market-based rates will help customers by ensuring that they are protected from the exercise of market power. It will also provide greater certainty to sellers seeking market-based rate authority.

8. The regulations proposed herein would adopt in most respects the Commission's current standards for granting market-based rates. We believe these standards have, with the exceptions noted below, allowed the Commission to distinguish between applicants that have market power and those that do not. For example, the current interim horizontal (generation) market power screens 9 have allowed the Commission to identify a number of smaller applicants that do not have generation market power

ndards for granting market-based rates. We believe these standards have, with the exceptions noted below, allowed the Commission to distinguish between applicants that have market power and those that do not. For example, the current interim horizontal (generation) market power screens 9 have allowed the Commission to identify a number of smaller applicants that do not have generation market power. The Commission authorized these applicants to obtain or retain market-based rate authority, which benefits customers by encouraging new entry and by providing them with the greater flexibility in product offerings that market-based rate approval conveys. The current screens also have allowed the Commission to more accurately identify instances where certain larger sellers may possess market power. If an applicant fails our screens, this does not, however, constitute a definitive finding of market power. Rather, our current standards allow any applicant that fails these screens to demonstrate that it lacks market power in generation using the delivered price test (DPT). 10 The DPT has provided appropriate flexibility in allowing the Commission to consider the differing factual situations of particular sellers, such as those that have a responsibility for serving native load customers. The Commission proposes to continue to apply the DPT in such a flexible manner.

9 As discussed below, the Commission proposes to henceforth refer to the generation market power analysis as the horizontal market power analysis.

10 See April 14 Order at P 106 (“The [DPT] defines the relevant market by identifying potential suppliers based on market prices, input costs, and transmission availability, and calculates each suppliers' economic capacity and available economic capacity for each season/load condition. The results of the [DPT] can be used for pivotal supplier, market share and market concentration analyses.”).

9. In cases where the applicant has failed the DPT, or has otherwise chosen to adopt default cost-based mitigation or to propose other cost-based mitigation ( e.g., cost-based rates) or tailored mitigation, our current policies protect customers by ensuring that applicants with market power in a given area have that market power mitigated. We recognize, however, that there has been uncertainty regarding the rate methodologies to use in developing cost-based market power mitigation and the effectiveness of the existing cost-based mitigation. We therefore seek comment in this rulemaking on several issues relating to cost-based market power mitigation, including: (i) Whether there should be a standard methodology for determining cost-based ceiling rates and the appropriate methodology for sales of less than one week; (ii) whether selective discounting should be allowed for sellers that have been found to have market power, or that accept a presumption of market power, and are offering power under cost-based rates; and (iii) whether a mitigated seller that seeks to sell excess power generated within a mitigated market should be required to first offer its available capacity at cost-based rates to customers within the mitigated market.

10. We also propose certain modifications to the horizontal (generation) market power screens to reflect our experience in applying them and the comments received in this proceeding

i) whether a mitigated seller that seeks to sell excess power generated within a mitigated market should be required to first offer its available capacity at cost-based rates to customers within the mitigated market.

10. We also propose certain modifications to the horizontal (generation) market power screens to reflect our experience in applying them and the comments received in this proceeding. First, the Commission proposes to modify the treatment of newly-constructed generation to avoid a situation in which all generation becomes exempt from our market power analyses as new generation is constructed and older (pre-1996) generation is retired. Second, although we propose to retain the default relevant geographic market (control area), we provide guidance as to the factors the Commission will consider in evaluating whether, in a particular case, to adopt an expanded geographic market instead of relying on the default geographic market. Third, we propose to change the native load proxy for the market share screens from the minimum peak day in the season to the average peak native load, averaged across all days in the season, and to clarify that native load can only include load attributable to native load customers as that term is defined insection 33.3(d)(4)(i) of the Commission's regulations. 11 Fourth, we propose to allow applicants the option of using seasonal capacity instead of nameplate capacity, 12 and to retain the snapshot in time approach for the screens but to allow “known and measurable” changes (sometimes referred to as foreseeable and reasonably certain at the time of filing) for the DPT.

11 18 CFR 33.3(d)(4)(i) (2005).

12 Nameplate capacity is the full-load continuous rating of a generator, prime mover, or other electric power production equipment under specific conditions as designated by the manufacturer. Installed generator nameplate rating is usually indicated on a nameplate physically attached to the generator.

d reasonably certain at the time of filing) for the DPT.

11 18 CFR 33.3(d)(4)(i) (2005).

11. With regard to vertical market power and, in particular, transmission market power, the Commission proposes to continue the current policy under which an open access transmission tariff (OATT) is deemed to mitigate a seller's transmission market power. 13 However, in recognition of the fact that OATT violations may nonetheless occur, we propose that violation(s) of the OATT may be cause to revoke market-based rate authority in addition to any other applicable remedies, such as civil penalties. We also note that concerns regarding the adequacy of the current OATT will be addressed in Docket No. RM05-25-000, Preventing Undue Discrimination and Preference in Transmission Service. We are today issuing a Notice of Proposed

13 See Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21,540 (May 10, 1996), FERC Stats. & Regs., Regulations Preambles January 1991-June 1996 ¶ 31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12,274 (March 14, 1997), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,048 (1997), order on reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

, 62 FR 12,274 (March 14, 1997), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,048 (1997), order on reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

12. With regard to vertical market power and, in particular, other barriers to entry, we propose to continue our current approach but provide clarification of what types of factors we would examine and we propose to combine the other barriers to entry analysis with the rest of our vertical market power analysis.

13. With regard to affiliate abuse, the Commission proposes to discontinue referring to affiliate abuse as a separate “prong” of our analysis and instead proposes to codify in our regulations an explicit requirement that any seller with market-based rate authority must comply with the affiliate sales restrictions and other affiliate provisions. 14 The Commission proposes to address affiliate abuse by requiring that the conditions set forth in the proposed regulations be satisfied on an ongoing basis as a condition of obtaining and retaining market-based rate authority. The Commission proposes to retain its policy that sales of power between a franchised public utility and any of its non-regulated power sales affiliates 15 must be pre-approved by the Commission. To demonstrate that an affiliate sale is just, reasonable and not unduly discriminatory, an applicant has several options, including pricing that sale at a market index that meets certain standards, conducting an auction that reflects certain guidelines, or otherwise meeting the standards set forth in Edgar . 16 An affiliate sale that has not been pre-approved under these standards will constitute a tariff violation

an affiliate sale is just, reasonable and not unduly discriminatory, an applicant has several options, including pricing that sale at a market index that meets certain standards, conducting an auction that reflects certain guidelines, or otherwise meeting the standards set forth in Edgar . 16 An affiliate sale that has not been pre-approved under these standards will constitute a tariff violation. In addition, we reaffirm that the Commission currently requires that sales made under market-based rate tariffs, including those made to affiliates, must be reported in an Electric Quarterly Report (EQR). With regard to affiliate transactions under a market-based rate tariff, we reaffirm that we either grant or deny authorization to make affiliate sales. To the extent that we authorize an affiliate transaction, we reaffirm that, consistent with the Commission's regulations, 17 any such agreement shall not be filed with the Commission.

14 In the case of non-exempt wholesale generator (EWG) public utilities, for matters arising under Part II of the FPA, the term “affiliate” is defined as that term is used in section 358.3(b) and (c) (formerly section 161.2) of the Commission's regulations. Section 358.3(b) defines “affiliate” as “another person which controls, is controlled by, or is under common control with, such person.” Section 358.3(c) states that “control (including the terms ‘controlling,’ ‘controlled by,’ and ‘under common control with’) * * * includes, but is not limited to, the possession, directly or indirectly and whether acting alone or in conjunction with others, of the authority to direct or cause the direction of the management or policies of a company

y, or is under common control with, such person.” Section 358.3(c) states that “control (including the terms ‘controlling,’ ‘controlled by,’ and ‘under common control with’) * * * includes, but is not limited to, the possession, directly or indirectly and whether acting alone or in conjunction with others, of the authority to direct or cause the direction of the management or policies of a company. A voting interest of 10 percent or more creates a rebuttable presumption of control.” The term “affiliate” in the case of EWG public utilities is defined as “any company, 5 percent or more of the outstanding voting securities of which are owned, controlled or held with power to vote, directly or indirectly, by such company.” See Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005, Order No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & Regs. ¶ 31,096 (2006). (To be codified at 18 CFR section 366.1 (2006).)

15 By “non-regulated” power sales affiliate, the Commission is referring to non-traditional power sellers including a power marketer, EWG, qualifying facilities (QFs), or other power seller affiliate, whose power sales are not regulated on a cost basis under the FPA.

16 Boston Edison Company Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 (1991) ( Edgar ) (Describing types of evidence that can be used to demonstrate lack of affiliate abuse.)

17 See 18 CFR 35.1(g) (2005).

used to demonstrate lack of affiliate abuse.)

17 See 18 CFR 35.1(g) (2005).

14. We also propose certain reforms to streamline the administration of the market-based rate program. As discussed more fully below, in an effort to streamline and simplify the market-based rate program in general, while maintaining a high degree of oversight, the Commission proposes several changes and clarifications. Significant areas of modification involve the three-year updated market power analysis (triennial review or updated market power analysis) that all sellers with market-based rate authority are required to file, and the development of a market-based rate tariff of general applicability.

15. With regard to updated market power analyses, the Commission's current general practice is to require an updated market power analysis to be submitted within three years from the date of the Commission order granting the seller market-based rate authority or accepting the previous triennial review. The Commission proposes to modify that general practice and put in place a structured, systematic review to assist the Commission in analyzing sellers in markets based on a coherent and consistent set of data. In particular, the Commission proposes to modify the requirements for filing updated market power analyses in two ways. First, the Commission proposes to establish two categories of sellers with market-based rate authorization. The first category, Category 1 (approximately 550 sellers), would consist of power marketers and power producers that own or control 500 MW or less of generating capacity in aggregate and that are not affiliated with a public utility with a franchised service territory. In addition, Category 1 sellers must not own or control transmission facilities, other than limited equipment necessary to connect individual generating facilities to the transmission grid, (or must have been granted waiver of the requirements of Order No

ontrol 500 MW or less of generating capacity in aggregate and that are not affiliated with a public utility with a franchised service territory. In addition, Category 1 sellers must not own or control transmission facilities, other than limited equipment necessary to connect individual generating facilities to the transmission grid, (or must have been granted waiver of the requirements of Order No. 888 because such facilities are limited and discrete and do not constitute an integrated grid 18 ) and must present no other vertical market power issues. Category 1 sellers would not be required to file a regularly scheduled triennial review. The Commission would monitor any market power concerns for these sellers through the change in status reporting requirement, 19 and through ongoing monitoring by the Commission's Office of Enforcement.

18 See, e.g., Black Creek Hydro, Inc., 77 FERC ¶ 61,232 (1996).

19 See 18 CFR 35.27(c) (2005) (reporting requirement for any change reflecting a departure from the characteristics the Commission relied upon in granting market-based rate authority). Failure to timely file a change in status report would constitute a tariff violation.

16. The second category, Category 2 (approximately 600 sellers), would include all sellers that do not qualify for Category 1. Category 2 sellers, in addition to the change in status reports, would be required to file regularly scheduled triennial reviews. 20 To ensure greater consistency in the data used to evaluate Category 2 sellers, the Commission proposes to require each Category 2 seller to file updated market power analyses for its relevant geographic markets (default and any proposed alternative markets) on a schedule that will allow examination of the individual seller at the same time that the Commission examines other sellers in these relevant markets and contiguous markets within a region from which power could be imported

ommission proposes to require each Category 2 seller to file updated market power analyses for its relevant geographic markets (default and any proposed alternative markets) on a schedule that will allow examination of the individual seller at the same time that the Commission examines other sellers in these relevant markets and contiguous markets within a region from which power could be imported. The Commission would continue to make findings on an individual seller basis, but would have before it a complete picture of the uncommitted capacity and simultaneous import capability into the relevant geographic markets under review.

20 Failure to timely file a triennial review would constitute a tariff violation.

17. A second significant change is our proposal to adopt a market-based rate tariff of general applicability (MBR tariff), applicable to all sellers authorized to sell electric energy, capacity or ancillary services at wholesale at market-based rates. Further, the Commission proposes that, rather than each entity having its own MBR tariff, which can result in dozens of tariffs for each corporate family with potentially conflicting provisions, each corporate family would have only one tariff, with all affiliates with market-based rate authority separately

III. Discussion

A. Horizontal Market Power

1. Current Policy

a. Test for Generation Market Power.

18. In the April 14 Order, the Commission adopted two indicative screens for assessing generation market power that provide a rebuttable presumption of whether market power exists for a utility applying to obtain or retain market-based rate authority. Sellers that do not pass the initial screens are, among other things, allowed to provide additional evidence for Commission consideration. Such an approach allows the Commission to concentrate its efforts on sellers that may possess generation market power while screening out those sellers that do not pose such concerns.

for a utility applying to obtain or retain market-based rate authority. Sellers that do not pass the initial screens are, among other things, allowed to provide additional evidence for Commission consideration. Such an approach allows the Commission to concentrate its efforts on sellers that may possess generation market power while screening out those sellers that do not pose such concerns.

19. The Commission uses two indicative screens for assessing whether a particular seller raises any generation market power concerns, each with its own specific focus and attributes: a pivotal supplier analysis based on uncommitted capacity at the time of the market's annual peak demand; and a market share analysis of uncommitted capacity applied on a seasonal basis. If a seller passes both screens, there is a rebuttable presumption that the seller does not possess market power in generation. However, the Commission allows intervenors to present evidence to rebut the presumption. On the other hand, if a seller fails either screen, this creates a rebuttable presumption that market power exists in generation. 21 In this instance, the seller may: (1) File a more robust market power study, the DPT; 22 (2) file a mitigation proposal tailored to its particular circumstances that would eliminate the ability to exercise market power; or (3) inform the Commission that it will either adopt the default cost-based rates discussed in the April 14 Order or propose other cost-based rates and submit cost support for such rates. Before the Commission considers the DPT, the seller must be found to have failed one (or both) of the two indicative screens or so concede. 23 Accordingly, the DPT is considered as an alternative study to support the grant or continuation of market-based rate authority. In all cases, the seller or intervenors may present evidence such as historical wholesale sales data to support their opinion of whether the seller does or does not possess market power

be found to have failed one (or both) of the two indicative screens or so concede. 23 Accordingly, the DPT is considered as an alternative study to support the grant or continuation of market-based rate authority. In all cases, the seller or intervenors may present evidence such as historical wholesale sales data to support their opinion of whether the seller does or does not possess market power.

21 In such a case, the Commission will institute a section 206 proceeding and such a seller's rates prospectively will be made subject to refund until a final determination of market power is made or the seller accepts a presumption of market power and so mitigates. April 14 Order, 107 FERC ¶ 61,018 at n. 10.

22 The only additional market power study allowed is the DPT. However, the Commission allows such sellers to present evidence, based on historical wholesale sales data, in support of a contention that, notwithstanding the results of the two indicative screens, they do not possess market power.

23 April 14 Order, 107 FERC ¶ 61,018 at P 37.

20. Section 35.27(a) of the Commission's regulations states that “any public utility seeking authorization to engage in sales for resale of electric energy at market-based rates shall not be required to demonstrate any lack of market power in generation with respect to sales from capacity for which construction has commenced on or after July 9, 1996.” 24 Sellers meeting the criteria of section 35.27(a) of our regulations, as clarified in LG&E Capital , 25 may provide evidence demonstrating that they satisfy this section of our regulations rather than submit a generation market power analysis. However, if a seller sites generation in an area where it or its affiliates own or control other generation assets, the seller must provide an analysis regarding whether its new capacity ( i.e. , post-July 9, 1996), when added to existing capacity, raises generation market power concerns.

24 18 CFR 35.27(a) (2005)

section of our regulations rather than submit a generation market power analysis. However, if a seller sites generation in an area where it or its affiliates own or control other generation assets, the seller must provide an analysis regarding whether its new capacity ( i.e. , post-July 9, 1996), when added to existing capacity, raises generation market power concerns.

24 18 CFR 35.27(a) (2005).

25 LG&E Capital Trimble County LLC, 98 FERC ¶ 61,261 (2002) ( LG&E Capital ).

21. Alternatively, a seller may forego submitting a generation market power analysis and accept a presumption of market power and go directly to mitigation by proposing case-specific mitigation that eliminates the ability to exercise market power, or agreeing to the default rates discussed below. Under such circumstances there will be a presumption of market power in all of the default relevant markets.

22. If a seller's proposed mitigation 26 does not eliminate its ability to exercise market power, then the seller may not charge market-based rates in the geographic area(s) where market power is found, and the seller is subject to cost-based default rates or other cost-based rates that the seller proposes and the Commission approves. The Commission's default rates are as follows: (1) Sales of power of one week or less must be priced at the seller's incremental cost plus a 10 percent adder; (2) sales of power of more than one week but less than one year must be priced at an embedded cost “up to” rate reflecting the costs of the unit or units expected to provide the service; and (3) new contracts for sales of power for one year or more must be priced at a rate not to exceed the embedded cost of service, and the contract must be filed with the Commission for review. Mitigated sellers must first receive Commission approval for each long-term power sale prior to transacting. 27

26 Proposals for alternative mitigation in these circumstances could include cost-based rates or other mitigation that the Commission may deem appropriate

must be priced at a rate not to exceed the embedded cost of service, and the contract must be filed with the Commission for review. Mitigated sellers must first receive Commission approval for each long-term power sale prior to transacting. 27

26 Proposals for alternative mitigation in these circumstances could include cost-based rates or other mitigation that the Commission may deem appropriate. For example, an applicant could propose to transfer operational control of enough generation to a third party such that the applicant would satisfy our generation market power concerns.

27 The Commission notes here that, to the extent a party believes market power is being exerted in the course of negotiating a long-term purchase, such party may file a complaint pursuant to section 206 of the FPA.

b. Additional Requirement for Transmission Owners.

23. In addition, a seller that owns, operates or controls transmission is required to conduct simultaneous transmission import capability studies for its home control area and each of its directly-interconnected first-tier control areas consistent with the requirements set forth in the April 14 Order, as clarified in Pinnacle West Capital Corp., 110 FERC ¶ 61,127 (2005). These studies are used in the pivotal supplier screen, market share screen, and DPT to approximate the transmission import capability. When centering the generation market power analysis on the transmission providing utility's first-tier control area ( i.e. , markets), the transmission-providing seller should use the methodologies consistent with its implementation of its Commission-approved OATT, thereby making a reasonable approximation of simultaneous import capability that would have been available to suppliers in surrounding first-tier markets during each seasonal peak. The transfer capability should also include any other limits (such as stability, voltage, Capacity Benefit Margin, or

24. A seller may provide a streamlined application to show that it passes the indicative screens

T, thereby making a reasonable approximation of simultaneous import capability that would have been available to suppliers in surrounding first-tier markets during each seasonal peak. The transfer capability should also include any other limits (such as stability, voltage, Capacity Benefit Margin, or

24. A seller may provide a streamlined application to show that it passes the indicative screens. Thus, with respect to simultaneous import capability, if a seller can show that it passes the screens for each relevant geographic market without considering imports, no such simultaneous import analysis needs to be provided. Further, the Commission recognizes that certain sellers will not have the ability to perform a simultaneous import capability study. Accordingly, if a seller demonstrates that it is unable to perform a simultaneous import capability study for the control area in which it is located, the seller may propose to use a proxy amount for transmission limits. Such proposals are considered on a case-by-case basis.

c. Relevant Geographic Markets.

25. The default relevant geographic markets under both screens are first, the control area market where the seller is physically located, and second, the markets directly interconnected to the seller's control area market (first-tier control area markets). 28 In this default analysis, the Commission considers only those supplies that are located in the market being considered (relevant market) and those in first-tier markets to the relevant market. Sellers located in and a member of regional transmission organizations (RTO)/independent system operators (ISO) 29 that perform functions such as single central commitment and dispatch with a single energy market and Commission-approved market monitoring and mitigation may consider the geographic region under the control of the RTO/ISO as the default relevant geographic market for purposes of completing their analyses. 30 Currently, these markets are operated by PJM Interconnection, LLC (PJM), ISO New England, Inc

perform functions such as single central commitment and dispatch with a single energy market and Commission-approved market monitoring and mitigation may consider the geographic region under the control of the RTO/ISO as the default relevant geographic market for purposes of completing their analyses. 30 Currently, these markets are operated by PJM Interconnection, LLC (PJM), ISO New England, Inc. (ISO-NE), New York Independent System Operator, Inc. (NYISO), Midwest Independent Transmission System Operator (Midwest ISO) and California Independent System Operator Corporation (CAISO). For sellers whose assets are physically located geographically within the RTO/ISO boundaries, there is only one default relevant market for those assets, and that is the RTO/ISO in which they are located and are a member. Likewise, where a generator is interconnecting to a non-affiliate owned transmission system, there is only one relevant market, the control area in which the generator is located.

28 For applications by sellers with no physical generation assets (such as power marketers) and that are affiliated with generation asset owning utilities, the Commission evaluates the affiliate generation owner's market power when evaluating whether to grant market-based rate authority for the power marketer.

29 We note that the membership status described is such that the seller that owns transmission facilities other than limited equipment necessary to connect individual generating facilities to the transmission grid has turned over operational control of those transmission assets to the RTO/ISO.

30 LG&E Energy Marketing, Inc., 111 FERC ¶ 61,153 (2005) (noting that where applicants are members of the Midwest ISO and their control area is within the Midwest ISO geographic footprint, the default relevant geographic market for the generation market power analyses is the Midwest ISO).

the transmission grid has turned over operational control of those transmission assets to the RTO/ISO.

26. The Commission allows sellers and intervenors to present additional sensitivity runs as part of their market power studies to show that some other geographic market should be considered as the relevant market in a particular case. For example, sellers or intervenors can present evidence that the relevant market is broader (or more limited) than a particular control area. However, applicants presenting evidence that the relevant market is larger or smaller than the default relevant market must first complete the screens based on the default market as discussed above. To the extent some other geographic market is studied, the proponent of using that alternative market must adhere to including all monitored lines/constraints and critical contingencies that were historically applied during the seasonal peaks in assessing available transmission for non-affiliate transmission customers ( i.e. , consistent with Open Access Same-Time Information System (OASIS)). Sellers and intervenors may also provide evidence that, because of internal transmission limitations ( e.g. , load pockets), the relevant market is smaller than the control area.

d. Performance of the Indicative Screens.

27. Both the pivotal supplier analysis and the market share analysis recognize utilities' obligations to serve native load. Because utilities generally use the same generating units to make off-system wholesale sales and to serve native load, and because the amount of generation needed to serve native load can vary from hour to hour, some reasonable proxy is needed to represent the amount of generation that is needed to serve native load

d the market share analysis recognize utilities' obligations to serve native load. Because utilities generally use the same generating units to make off-system wholesale sales and to serve native load, and because the amount of generation needed to serve native load can vary from hour to hour, some reasonable proxy is needed to represent the amount of generation that is needed to serve native load. Accordingly, the pivotal supplier analysis, for both sellers and competing suppliers, uses the average of the daily native load peaks during the month in which the annual peak demand day occurs as a proxy for native load obligation. The market share analysis for both sellers and competing suppliers uses the native load obligation on the minimum peak demand day for a given season.

28. In the pivotal supplier screen, a market participant's 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. To calculate the net uncommitted supply available to compete at wholesale, the wholesale load proxy (annual peak load less the native load proxy discussed above) is deducted from total uncommitted capacity in the market. 31 If the seller's uncommitted capacity is equal to or greater than the net uncommitted supply, then the seller fails the pivotal supplier analysis, which creates a rebuttable presumption of market power.

31 April 14 Order, 107 FERC ¶ 61,018 at P 99.

P 99.

29. In the market share analysis, uncommitted capacity is defined similarly to the pivotal supplier screen, with the additional deduction for planned outages that were done in accordance with good utility practice. Under the market share analysis, a seller that has less than a 20 percent market share in the relevant market for all seasons is considered to satisfy the market share analysis. 32 A seller with a market share of 20 percent or more in the relevant market for any season has a rebuttable presumption of market power but can present historical evidence to show that the seller satisfies the Commission's generation market power concerns. 33

32 The 20 percent threshold is consistent with section 4.134 of the U.S. Department of Justice 1984 Merger Guidelines issued June 14, 1984, reprinted in Trade Reg. Rep. P13,103 (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.”

33 The other evidence the Commission will consider is historical sales and/or access to transmission to move supplies within, out of, and into a control area market.

30. In addition, any seller, regardless of size, has the option of making simplifying assumptions in its analysis where appropriate. In performing all screens, sellers are required to prepare them as designed, 34 and must use the most recently available unadjusted 12 35 Sellers filing abbreviated studies may request waiver of the full data requirements.

34 Sellers presenting evidence that the relevant market is larger or smaller than the default relevant market ( i.e. , control area) must first complete the screens based on the default relevant geographic market.

35 The Commission clarified on rehearing that it will allow adjustments necessary to perform the screens if the seller fully justifies the need for and methodology used for the adjustment and files all workpapers supporting the adjustments and documenting the source data used

t relevant market ( i.e. , control area) must first complete the screens based on the default relevant geographic market.

e. The Delivered Price Test (DPT).

31. Sellers failing one or more of the initial screens will have a rebuttable presumption of market power. If such a seller chooses not to proceed directly to mitigation, it must present a more thorough analysis using the Commission's DPT. 36 The DPT is used to analyze the effect on competition for transfers of jurisdictional facilities in section 203 proceedings, 37 using the framework described in Appendix A of the Merger Policy Statement as revised in Order No. 642. 38 The DPT is an established test that has been used routinely to analyze market power in the merger context for many years, and it has been affirmed by the courts. 39

36 April 14 Order, 107 FERC ¶ 61,018 at P 105-12.

37 16 U.S.C. 824b (2000).

38 Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, 61 F.R. 68595 (1996), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,044 (1996), reconsideration denied , Order No. 592-A, 62 F.R. 33341 (1997), 79 FERC ¶ 61,321 (1997) (Merger Policy Statement); see also Revised Filing Requirements Under Part 33 of the Commission's Regulations, Order No. 642, 65 F.R. 70984 (2000), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,111 (2000), order on reh'g, Order No. 642-A, 66 F.R. 16121 (2001), 94 FERC ¶ 61,289 (2001).

39 See, e.g., Wabash Valley Power Associates, Inc. v. FERC, 268 F. 3d 1105 (D.C. Cir. 2001).

icy Statement); see also Revised Filing Requirements Under Part 33 of the Commission's Regulations, Order No. 642, 65 F.R. 70984 (2000), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,111 (2000), order on reh'g, Order No. 642-A, 66 F.R. 16121 (2001), 94 FERC ¶ 61,289 (2001).

39 See, e.g., Wabash Valley Power Associates, Inc. v. FERC, 268 F. 3d 1105 (D.C. Cir. 2001).

32. The DPT defines the relevant market by identifying potential suppliers based on market prices, input costs, and transmission availability, and calculates each supplier's economic capacity and available economic capacity for each season/load period. 40 The results of the DPT are used for pivotal supplier, market share and market concentration analyses. Using the economic capacity for each supplier, sellers are required to provide pivotal supplier, market share and market concentration analyses. Examining these three measures with the more robust output from the DPT allows sellers to present a more complete view of the competitive conditions and their positions in the relevant markets.

40 Super-peak, peak, and off-peak, for Winter, Shoulder and Summer periods and an additional highest super-peak for the Summer.

33. Under the DPT, to determine whether a seller is a pivotal supplier in each of the season/load periods, sellers are required to compare the load in the relevant market to the amount of competing supply. The seller will be considered pivotal if the sum of the competing suppliers' economic capacity is less than the load level plus a reserve requirement for the relevant period. The analysis using available economic capacity to account for sellers' and competing suppliers' native load commitments is also required.

34. Each supplier's market share is calculated based on economic capacity, the DPT's analog to installed capacity

d pivotal if the sum of the competing suppliers' economic capacity is less than the load level plus a reserve requirement for the relevant period. The analysis using available economic capacity to account for sellers' and competing suppliers' native load commitments is also required.

34. Each supplier's market share is calculated based on economic capacity, the DPT's analog to installed capacity. The market shares for each season/load period reflect the costs of the seller's and competing suppliers' generation, thus giving a more complete picture of the seller's ability to exercise market power in a given market.

35. Sellers preparing a DPT also must calculate the market concentration using the Hirschman-Herfindahl Index (HHI) based on market shares. 41 For the DPT, a showing of an HHI less than 2,500 in the relevant market for all season/load periods for sellers that have also shown that they are not pivotal and do not possess more than a 20 percent market share in any of the season/load periods would constitute a showing of a lack of market power, absent compelling contrary evidence. We will, however, consider all relevant facts and circumstances in reviewing a DPT, (including native load obligations), and we will balance the record evidence in determining whether or not the seller has generation market power. Thus, even sellers that exceed the foregoing thresholds may receive market-based rates under appropriate circumstances. 42

41 The HHI is the sum of the squared market shares. For example, in a market with five equal size firms, each would have a 20 percent market share. For that market, HHI = (20) 2 + (20) 2 + (20) 2 + (20) 2 + (20) 2 = 400 + 400 + 400 + 400 + 400 = 2,000.

42 See, e.g., Kansas City Power & Light Co., 113 FERC ¶ 61,074 at P 30-35 (2005) ( Kansas City ); Acadia Power Partners, LLC, 113 FERC ¶ 61,073 at P 40-45 (2005) ( Acadia ).

red market shares. For example, in a market with five equal size firms, each would have a 20 percent market share. For that market, HHI = (20) 2 + (20) 2 + (20) 2 + (20) 2 + (20) 2 = 400 + 400 + 400 + 400 + 400 = 2,000.

42 See, e.g., Kansas City Power & Light Co., 113 FERC ¶ 61,074 at P 30-35 (2005) ( Kansas City ); Acadia Power Partners, LLC, 113 FERC ¶ 61,073 at P 40-45 (2005) ( Acadia ).

36. Sellers and intervenors may present evidence such as historical wholesale sales data, which can be used to calculate market shares and market concentration and to refute or support the results of the DPT. The Commission encourages sellers to present the most complete analysis of competitive conditions in the market as the data allow. In this regard, the Commission allows the introduction of such evidence beyond the most recent 12 months. The use of unadjusted historical sales and transmission data will provide an accurate depiction of actual market activity. Therefore, the Commission requires sellers submitting historical sales and transmission data as evidence to submit the actual data.

37. The FPA requires that all rates charged by public utilities for the transmission or sale for resale of electric energy be just and reasonable. 43 Thus, where a market-based rate seller is found to have market power in generation ( e.g. , after reviewing a seller's DPT), it is incumbent upon the Commission to either reject such rates or to ensure that adequate mitigation measures are in place to ensure that the rates are just and reasonable. The Commission provides default cost-based rates to ensure that wholesale rates are just and reasonable. If a seller does not pass the generation market power screens, or foregoes the screens entirely, the Commission sets the just and reasonable rate at the default cost-based rate unless it approves different mitigation based on case-specific circumstances.

43 16 U.S.C. 824d(a) (2000).

38. For sellers that have a presumption of market power in generation ( e.g

esale rates are just and reasonable. If a seller does not pass the generation market power screens, or foregoes the screens entirely, the Commission sets the just and reasonable rate at the default cost-based rate unless it approves different mitigation based on case-specific circumstances.

43 16 U.S.C. 824d(a) (2000).

38. For sellers that have a presumption of market power in generation ( e.g. those failing one or both of the indicative screens), the Commission will institute a section 206 proceeding and the seller's rates will prospectively be made subject to refund. 44 For sellers already charging market-based rates, market-based rates will not be revoked and cost-based rates will not be imposed until the Commission issues an order making a definitive finding that the seller has market power in generation (typically, after the Commission has ruled on a DPT analysis) or, where the seller accepts a presumption of market power, an order is issued addressing whether default cost-based rates or case-specific cost-based rates are to be applied. The Commission will revoke the market-based rate authority in all geographic markets where a seller is found to have market power in generation. 45

44 The refund floor would be the default cost-based rates or, if applicable, any case-specific cost-based rates proposed by the seller and accepted by the Commission. Accordingly, the seller has certainty as to its potential refund obligation, if any. April 14 Order, 107 FERC ¶ 61,018 at n. 143.

45 The seller has the option of withdrawing its market-based rate request in whole or in part.

2. Proposal

39. The Commission adopted the indicative generation market power screens in the April 14 Order for interim purposes, and instituted the instant rulemaking proceeding to, among other things, review of these screens and, as a whole, the horizontal market power portion of the Commission's four-prong analysis. The Commission has gained

a. Indicative Screens and DPT Criteria.

2. Proposal

a. Indicative Screens and DPT Criteria.

40. Because the indicative screens are intended only to identify the sellers that require further review, we propose to retain the 20 percent threshold for the wholesale market share screen. The screens are indicative, not definitive. Indeed, pursuant to the horizontal market power analysis where an applicant is seeking to obtain or retain market-based rate authority, the Commission will not make a definitive finding that a seller has market power unless and until the more robust analysis, the DPT, is considered. Instead, where a seller fails one of the indicative screens, a section 206 proceeding is instituted to more closely examine a seller's potential for exercising horizontal market power and does not mean a definitive finding has been made. Failure to pass either of the indicative screens creates a rebuttable presumption of market power. A seller that fails the initial screens is given 60 days from the date of issuance of an order finding a screen failure to: (1) File a DPT analysis; (2) file a mitigation proposal tailored to its particular circumstances that would eliminate the ability to exercise market power; or (3) inform the Commission that it will adopt the default cost-based rates or propose other cost-based rates and submit cost support for such rates. 46

46 April 14 Order, 107 FERC ¶ 61,018 at P 208.

cost-based rates and submit cost support for such rates. 46

46 April 14 Order, 107 FERC ¶ 61,018 at P 208.

41. Some commenters argue that the 20 percent threshold is too low; others argue that it is too high. The Commission believes that the 20 percent threshold strikes the right balance in seeking to avoid both “false negatives” and “false positives” and proposes to continue using 20 percent. Because the presumption of horizontal market power established by the failure of the wholesale market share screen is rebuttable, coupled with the adjustment to the native load proxy discussed below, sellers should be assured that the 20 percent threshold is not unnecessarily stringent.

42. We also propose to continue the use of annual peak load in the pivotal supplier analysis and not to expand the pivotal supplier analysis to include monthly assessments. The pivotal supplier analysis examines the seller's market power during the annual peak. The hours near that point in time are the most likely times that a seller will be a pivotal supplier.

43. Similarly, for the DPT analysis, we propose to retain our current threshold including 2,500 for HHIs, as well as our current practice of weighing all the relevant factors in the analysis, in determining whether a seller does or does not have horizontal market power. We propose to continue to do so on a case-by-case basis, weighing such factors as available economic capacity, economic capacity, HHIs, and other historical wholesale sales data. The thresholds are well-established and appropriate, allowing the Commission to make a reasoned determination after reviewing all the evidence in the record. The DPT does not function like the initial screens in that the failure of either the economic capacity or available economic capacity analyses does not result in an automatic failure as a whole. 47

47 Kansas City , 113 FERC ¶ 61,074 at P 30; Acadia , 113 FERC ¶ 61,073 at P 40.

b. Native Load.

g the Commission to make a reasoned determination after reviewing all the evidence in the record. The DPT does not function like the initial screens in that the failure of either the economic capacity or available economic capacity analyses does not result in an automatic failure as a whole. 47

47 Kansas City , 113 FERC ¶ 61,074 at P 30; Acadia , 113 FERC ¶ 61,073 at P 40.

b. Native Load.

44. To reduce the number of “false positives” in the wholesale market share screen, however, we propose to adjust the native load proxy. Many commenters have noted that the current native load proxy for the market share screen is too limited and results in too much uncommitted capacity attributable to the seller. The Commission stated in the April 14 Order that by using the two screens together, the Commission is able to measure market power both at peak and off-peak times, and the ability to exercise market power both unilaterally and in coordinated interaction with other sellers. In the April 14 Order, the Commission adopted the native load proxy for the wholesale market share screen in order to balance the concerns of market participants. We now believe that the current proxy used in the market share screen may be too conservative. Accordingly, the Commission proposes to change the allowance for the native load deduction under the market share screen from the minimum native load peak demand for the season to the average native load peak demand for the season. This change makes the deduction for the market share screen consistent with the deduction allowed under the pivotal supplier screen. We propose to retain a season-by-season analysis. For example, the proxy for summer would be the average native load peak for June, July and August. The pivotal supplier screen's native load proxy would remain unchanged from its current proxy of the average of the daily native load peaks during the month in which the annual peak day load occurs. We seek comments on our proposal.

plier screen. We propose to retain a season-by-season analysis. For example, the proxy for summer would be the average native load peak for June, July and August. The pivotal supplier screen's native load proxy would remain unchanged from its current proxy of the average of the daily native load peaks during the month in which the annual peak day load occurs. We seek comments on our proposal.

45. We believe there has been some inconsistency in the way in which sellers have reflected native load in performing both the screens and the DPT analysis. For this reason, we also propose to clarify that for the horizontal market power analysis, native load can only include load attributable to native load customers as defined in section 33.3(d)(4)(i) of the Commission's regulations, 48 as it may be revised from time to time. We seek comments on this proposal.

48 18 CFR 33.3(d)(4)(i) provides: Native load commitments are commitments to serve wholesale and retail power customers on whose behalf the potential supplier, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate its system to meet their reliable electricity needs.

c. Control and Commitment of Generation.

46. The Commission stated that uncommitted capacity is determined by adding the total capacity of generation owned or controlled through contract and firm purchases less, among other things, long-term firm requirements sales that are specifically tied to generation owned or controlled by the seller and that assign operational control of such capacity to the buyer. 49 The Commission further stated that long-term firm load following contracts may be deducted to the extent that the seller has included in its total capacity a corresponding generating unit or long-term firm purchase that will be used to meet the obligation even if such contracts are not tied to a specific generating unit and do not convey operational control of the generation. 50

49 July 8 Order, 108 FERC ¶ 61,026 at P 65.

50 Id

long-term firm load following contracts may be deducted to the extent that the seller has included in its total capacity a corresponding generating unit or long-term firm purchase that will be used to meet the obligation even if such contracts are not tied to a specific generating unit and do not convey operational control of the generation. 50

49 July 8 Order, 108 FERC ¶ 61,026 at P 65.

50 Id. at P 66.

47. The Commission has stated that contracts can confer the same rights of control of generation or transmission 51 In short, if a seller has control over certain capacity such that the seller can affect the ability of the capacity to reach the relevant market, then that capacity should be attributed to the seller when performing the generation market power screens. 52 The capacity associated with contracts that confer operational control of a given facility to an entity other than the owner must be assigned to the entity exercising control over that facility, rather than to the entity that is the legal owner of the facility. 53

51 Citizens Power and Light Corp. , 48 FERC ¶ 61,210 at 61,777 (1989) ( Citizens Power ). See also Bechtel Power Corp. , 60 FERC ¶ 61,156 (1992) (finding that an entity that was contractually engaged to provide operation and maintenance services was not an “operator” of jurisdictional facilities because the entity did not “operate” the facilities at issue but rather, in essence, was functioning merely as the owner's agent with respect to the operation of the jurisdictional facilities); D.E. Shaw Plasma Power, L.L.C. , 102 FERC ¶ 61,265 at P 33-36 (2003) ( D.E. Shaw ) (finding that a power marketer's “investment adviser” affiliate was a public utility where it had sole discretion to determine the trades to be entered into by the power marketer, as well as the power to execute the contracts, and therefore operated jurisdictional facilities rather than acted as merely an agent of the owner); R.W. Beck Plant Management, Ltd. , 109 FERC ¶ 61,315 at P 15 (2004) ( R.W

finding that a power marketer's “investment adviser” affiliate was a public utility where it had sole discretion to determine the trades to be entered into by the power marketer, as well as the power to execute the contracts, and therefore operated jurisdictional facilities rather than acted as merely an agent of the owner); R.W. Beck Plant Management, Ltd. , 109 FERC ¶ 61,315 at P 15 (2004) ( R.W. Beck ) (finding R.W. Beck Plant Management, Ltd. (Beck) was a public utility subject to the FPA in connection with its activities as manager of public utility Central Mississippi Generating Company, LLC because Beck effectively governed the physical operation of certain jurisdictional transmission and interconnection facilities and served as the decision-maker in determining sales of wholesale power).

52 July 8 Order, 108 FERC ¶ 61,026 at P 65.

53 Reporting Requirement for Changes in Status for Public Utilities with Market-Based Rate Authority , Order No. 652, 70 FR 8253 (Feb. 18, 2005), FERC Stats. & Regs., Regulations Preambles January 2001-December 2005 ¶ 31,175 at P 47, order on reh'g , Order No. 652-A, 111 FERC ¶ 61,413 (2005).

48. In recent years, some owners have turned to third parties to manage the day-to-day activities of running and dispatching plants and/or selling output. Such third-party contractors, often referred to as energy managers and/or asset managers, can be responsible for multiple facilities through multiple energy management agreements. These management agreements may, directly or indirectly, transfer control of the capacity. The Commission is concerned that there may be instances where, in effect, control of capacity has changed hands, but this capacity has not been attributed to the correct seller for purposes of calculating our market screens.

e may be instances where, in effect, control of capacity has changed hands, but this capacity has not been attributed to the correct seller for purposes of calculating our market screens.

49. In cases examining whether an entity is a public utility, the Commission has examined the totality of the circumstances in evaluating whether the entity effectively has control over capacity that it manages. 54 Likewise, in providing guidance regarding events that trigger a requirement to submit a notice of change in status, the Commission has indicated that, to determine whether control has been acquired, sellers should examine whether they can affect the ability of capacity to reach the relevant market. 55 Although this analysis is inherently fact-dependent to some degree, the Commission is interested in providing greater certainty and clarity in this area, which should increase the uniformity in reporting capacity and reduce the possibility of tariff violations. The Commission therefore seeks comment on whether it should make certain generic findings, or create certain generic presumptions, regarding the indicia of control. Specifically, the Commission seeks comment on whether any of the following functions should merit a finding or presumption of control and, if so, on what basis: directing outages, fuel procurement, plant operations, energy and capacity sales, and/or credit and liquidity decisions. Alternatively, rather than focusing on these discrete items, should the Commission establish a presumption of control for any entity that has some discretion over the output of the plant(s) that it manages? Would such an approach promote greater certainty and better align the test with the ultimate goal of attributing plant capacity to those who control its output? If the Commission adopted such a presumption, how should it address instances where discretion over plant output may be shared between more than one party? We also propose to clarify that, in the event we adopt any such presumptions, the Commission would nonethel

romote greater certainty and better align the test with the ultimate goal of attributing plant capacity to those who control its output? If the Commission adopted such a presumption, how should it address instances where discretion over plant output may be shared between more than one party? We also propose to clarify that, in the event we adopt any such presumptions, the Commission would nonetheless allow individual sellers to rebut the presumption on the basis of their particular facts and circumstances.

54 D.E. Shaw, 102 FERC ¶ 61,265 at P 33-36; R.W. Beck, 109 FERC ¶ 61,315 at P 15.

55 Order No. 652, FERC Stats. & Regs. ¶ 31,175 at P 47.

50. The Commission also proposes to clarify that an entity (such as an asset manager or other such entity) that controls generation from which jurisdictional power sales are made is required to have a rate on file with the Commission. If the rate authority sought is market-based rate authority, then that entity is subject to the same conditions and requirements as any other like seller ( e.g. , the entity must provide a horizontal and vertical market power analysis and include in its horizontal analysis all assets it owns or controls in the relevant market). If such an entity controls an asset from which jurisdictional power sales are being made and such entity does not have a rate on file, it is violating section 205 of the FPA. 56 We wish to emphasize, however, that our intent is not to limit or stifle the provision of energy management services. These services can provide benefits to customers and the marketplace. Rather, our intent is to provide greater certainty and clarity as to when such arrangements confer control so that the capacity being controlled is properly reported and the entity assuming such control has received the necessary authorizations under the FPA for providing jurisdictional services.

56 18 U.S.C. 824d (c) (2000).

d. Relevant Geographic Market.

o customers and the marketplace. Rather, our intent is to provide greater certainty and clarity as to when such arrangements confer control so that the capacity being controlled is properly reported and the entity assuming such control has received the necessary authorizations under the FPA for providing jurisdictional services.

56 18 U.S.C. 824d (c) (2000).

d. Relevant Geographic Market.

51. The Commission proposes to continue to use its current approach with regard to the relevant geographic market. The default relevant geographic market is the control area where the seller is physically located and the control areas directly interconnected to that control area (with the exception of a generator interconnecting to a non-affiliate owned or controlled transmission system, in which case the relevant market is only the control area in which the seller is located). The Commission also proposes to continue to designate the RTO/ISO in which a seller is located and is a member as the default relevant geographic market for RTO/ISOs with sufficient market structure and a single energy market, and not require sellers to consider, as part of the relevant market, markets first-tier to the RTO/ISO in which the seller is located and is a member. 57 We believe that designating a default relevant geographic market provides sellers and intervenors a measure of certainty regarding the relevant market. We note that the default market seems to be acceptable to most sellers as there have been relatively few sellers who have proposed to expand or contract the default relevant geographic market.

57 April 14 Order, 107 FERC ¶ 61,018 at P 187.

be acceptable to most sellers as there have been relatively few sellers who have proposed to expand or contract the default relevant geographic market.

57 April 14 Order, 107 FERC ¶ 61,018 at P 187.

52. We note that the North American Electric Reliability Council (NERC) no longer uses the designation of control area since it approved the “NERC Reliability Functional Model” on February 10, 2004. We seek comment as to whether or not the adoption of the NERC functional model should change the criteria for specifying the default relevant geographic market, and if so, in what way it should be specified and how readily available is the relevant data.

53. The Commission proposes to continue to provide flexibility by

54. Reaching beyond the default market in which an entity is located can mean addressing additional physical and other challenges than when trading within that market. When assessing an expanded geographic market pursuant to the horizontal analysis, the Commission looks for assurance that no frequently recurring physical impediments to trade exist within the expanded market that would prevent competing supply in the expanded area from reaching wholesale customers. Any proposal to use an expanded market ( i.e. , a market other than the default geographic market) should include a demonstration regarding whether there are frequently binding transmission constraints during historical seasonal peaks examined in the screens and at other competitively significant times that prevent competing supply from reaching the customers within the expanded market. In this regard, we propose to require that a demonstration be made based on historical data. In addition, we would require that a sensitivity analysis be performed analyzing under what circumstance(s) transmission constraints would bind.

55. The Commission also considers whether there is other evidence that would support the existence of an expanded market

e customers within the expanded market. In this regard, we propose to require that a demonstration be made based on historical data. In addition, we would require that a sensitivity analysis be performed analyzing under what circumstance(s) transmission constraints would bind.

55. The Commission also considers whether there is other evidence that would support the existence of an expanded market. In deciding whether customers may be considered as part of an expanded geographic market, the Commission will also consider evidence that they can access the resources outside of the default geographic market on similar terms and conditions as those inside the default geographic market.

56. Such evidence submitted to show that the applicant's customers have access to resources outside of their control area at terms and conditions similar to those at which they can access resources inside the control area could be empirical or it could point to factors that indicate a single market. For example, the Commission has previously stated that the operation of a single central unit commitment and dispatch function for the proposed geographic market would be an indicator of a single market. However, there are other ways to demonstrate that two or more control areas are indeed a single market. For example, other evidence of a single market could include a demonstration that: there is a single transmission rate; there is a common OASIS platform for scheduling transmission service across separate control areas; there is a correlation of price movements between the areas being considered as an expanded geographic market or other information regarding wholesale transactions in the proposed single market. Evidence of active trading throughout the proposed geographic market would also be considered.

57. In determining whether two or more control areas are a single market the Commission would weigh, on a case-by-case basis, all the factors presented

etween the areas being considered as an expanded geographic market or other information regarding wholesale transactions in the proposed single market. Evidence of active trading throughout the proposed geographic market would also be considered.

57. In determining whether two or more control areas are a single market the Commission would weigh, on a case-by-case basis, all the factors presented. As discussed above, there are several factors the Commission would consider once it has been established that historically there were no physical impediments to trade, and no one factor or factors would be dispositive. Rather, all factors will be considered and as a whole will indicate whether there exists a single market.

58. We seek comment on our proposed guidance and, in particular, whether there are other factors the Commission should consider when assessing a proposed expanded market. Are there any factor(s) that should be given more weight or are essential in determining the scope of the market ( e.g. , are there any factors that, if not satisfactorily addressed, would preclude the need to consider any other factors)? Should the Commission apply the same criteria when determining whether the geographic market is smaller than the default geographic market?

59. In addition, as discussed previously, the Commission proposes to designate the RTO/ISO in which the seller is located and is a member as the default relevant geographic market for RTO/ISOs with sufficient market structure and a single energy market. We believe the added protections provided in structured markets with market monitoring, market power mitigation and transparency generally result in a market where attempts to exercise market power would be sufficiently mitigated.

ed in structured markets with market monitoring, market power mitigation and transparency generally result in a market where attempts to exercise market power would be sufficiently mitigated.

60. In the April 14 Order, the Commission identified PJM, ISO-NE, NYISO, and CAISO as meeting the criteria for being considered a single market for purposes of performing the generation market power screens. 58 The Commission also stated that, applicants can incorporate the mitigation they are subject to in ISO/RTO markets as part of their market power analysis. For example, if a market power study showed that an applicant had local market power, the applicant could point to RTO mitigation rules as evidence that this market power has been adequately mitigated. In a later order, 59 the Commission found that the Midwest ISO also met the criteria for being considered a single market for purposes of performing the generation market power screens.

58 Id. at 187.

59 Alliant Energy Corporate Services, Inc., 109 FERC ¶ 61,289 at P 31 (2004).

61. However, our experience with corporate mergers and acquisitions indicates that these same RTOs 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. 60 Therefore, the Commission seeks 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 geographic market for the horizontal market power analysis. In particular, should the Commission continue its approach of considering the entire geographic region as the default relevant market? Should the Commission consider the entire geographic region for purposes of the indicative screens but consider RTO/ISO submarkets for purposes of the DPT

nd a single energy market, as the default relevant geographic market for the horizontal market power analysis. In particular, should the Commission continue its approach of considering the entire geographic region as the default relevant market? Should the Commission consider the entire geographic region for purposes of the indicative screens but consider RTO/ISO submarkets for purposes of the DPT. In addition, should the Commission adopt general criteria to define submarkets? If so, what criteria should the Commission adopt?

60 Examples of these submarkets include ISO-NE's Southwest Connecticut, NYISO's East of Central East (Zones F through K), PJM-East (roughly New Jersey, Southeastern Pennsylvania and the Delmarva Peninsula), Midwest ISO excluding Wisconsin-Upper Michigan (WUMS), and CAISO's SP15.

62. Lastly, if the Commission determines that an RTO/ISO submarket is the appropriate default geographic region in a particular case and an applicant is found to have market power within that submarket, should the Commission consider mitigation in addition to existing RTO market monitoring and mitigation?

e. Use of Historical Data.

63. We propose to retain the “snapshot in time” approach for the screens, i.e. , sellers must use the most recently available unadjusted 12 months' historical data. 61 Historical 62

61 In accordance with the proposed filing schedule discussed below, data for the indicative

62 July 8 Order, 108 FERC ¶ 61,026 at P 119.

64. However, we propose in the DPT analysis to allow applicants and intervenors to account for changes in the market that are known and measurable at the time of filing. 63 This proposal mirrors the Commission's approach in connection with its merger analysis. In Order No. 642, we stated that we intend to consider current and reasonably foreseeable regional developments as part of our merger analysis. In the Merger Policy Statement, we adopted the U.S

plicants and intervenors to account for changes in the market that are known and measurable at the time of filing. 63 This proposal mirrors the Commission's approach in connection with its merger analysis. In Order No. 642, we stated that we intend to consider current and reasonably foreseeable regional developments as part of our merger analysis. In the Merger Policy Statement, we adopted the U.S. Department of Justice/Federal Trade Commission Horizontal Merger Guidelines 64 as the analytical framework for analyzing the effect on competition. Those guidelines “address the issue of changing market conditions by stating that ‘[t]he Agency will consider reasonably predictable effects of recent or ongoing changes in market conditions in interpreting market concentration and market share data.’ ” 65 Examples of known and measurable changes in the market that would be allowed include new long-term contracts, expiration of long-term contracts, planned and imminent plant deactivations/retirements, and planned and imminent plant additions, regardless of ownership. Sellers who elect to adjust historical data to reflect known and measurable changes would be required to perform the analysis using the most recent historical data and then provide a sensitivity analysis including adjustments for all known and measurable changes in the market and not just those advantageous to the seller. 66 Applicants and intervenors proposing known and measurable changes to be considered in the DPT analysis will bear the burden of proof for their adjustments to historical data. We seek comments on whether the Commission should provide a limitation on the time period past the historical test period for which sellers can account for changes, what that time period should be, and how flexible or inflexible that limitation should be. In addition, we seek comments on exactly what types of changes should be allowed and under what circumstances. 67

63 See 18 CFR 35.13(a) (2005).

64 U.S

ments on whether the Commission should provide a limitation on the time period past the historical test period for which sellers can account for changes, what that time period should be, and how flexible or inflexible that limitation should be. In addition, we seek comments on exactly what types of changes should be allowed and under what circumstances. 67

63 See 18 CFR 35.13(a) (2005).

64 U.S. Department of Justice and Federal Trade Commission, Horizontal Merger Guidelines (1997) (DOJ/FTC Guidelines).

65 Oklahoma Gas and Electric Company and NRG McClain LLC, 105 FERC ¶ 61,297 (2003) ( OG&E ), citing the DOJ/FTC Guidelines, § 1.521.

66 See Western Resources, Inc., 65 FERC ¶ 61,106 (1993).

67 For example, in OG&E, the Commission accepted one change as known and measurable and rejected another. Specifically, the Commission found that the expiration of a long-term power sales contract within a year was a known and measurable change and should be part of the base case analysis (105 FERC ¶ 61,297 at P 33). In the same order, the Commission found that an upgrade of a transmission facility that was identified by the Southwest Power Pool as a persistent limiting facility, but was not under construction or even in the planning stage, was not “a foreseeable and reasonably certain change in the market” and therefore should not be part of the base case analysis ( id. at P 32).

f. Reporting Format.

65. As suggested by a commenter, we propose to require all sellers to submit the results of their indicative screen analysis in a uniform format to the maximum extent practicable. This format will promote consistency and will aid the Commission in the decision-making process. Sellers must cross reference the inputs with the data and workpapers they otherwise submit including those in accordance with Appendix G of the April 14 Order. Use of a uniform format for reporting results is not intended to limit other workpapers the seller may wish to submit. The format we propose to adopt can be found in Appendix C

ncy and will aid the Commission in the decision-making process. Sellers must cross reference the inputs with the data and workpapers they otherwise submit including those in accordance with Appendix G of the April 14 Order. Use of a uniform format for reporting results is not intended to limit other workpapers the seller may wish to submit. The format we propose to adopt can be found in Appendix C. We seek comments on this proposal.

g. Exemption for New Generation (Section 35.27(a) of the Commission's Regulations).

66. Section 35.27(a) of the Commission's regulations states:

Notwithstanding any other requirements, any public utility seeking authorization to engage in sales for resale of electric energy at market-based rates shall not be required to demonstrate any lack of market power in generation with respect to sales from capacity for which construction has commenced on or after July 9, 1996. 68

68 18 CFR 35.27(a) (2005).

67. The Commission clarified in the April 14 Order that some sellers with capacity built after July 9, 1996 (section 35.27(a) exemption) may avoid submitting a horizontal market power analysis if they meet the requirements of section 35.27(a) of the Commission's regulations. The Commission stated that, as it indicated in Order No. 888, it will consider whether a seller citing section 35.27(a) nevertheless possesses horizontal market power if specific evidence is presented by an intervenor, and a seller still must study whether its new capacity, when added to existing capacity, raises horizontal market power concerns. 69 As the Commission stated in Order No. 888, the evaluation of market-based rates for existing capacity will include consideration of new capacity. 70

69 April 14 Order, 107 FERC ¶ 61,018 at P 115, 116.

70 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,657.

and a seller still must study whether its new capacity, when added to existing capacity, raises horizontal market power concerns. 69 As the Commission stated in Order No. 888, the evaluation of market-based rates for existing capacity will include consideration of new capacity. 70

69 April 14 Order, 107 FERC ¶ 61,018 at P 115, 116.

70 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,657.

68. Under current procedures, if all the generation owned or controlled by an applicant for market-based rate authority and its affiliates in the relevant control area is new generation, such applicant is not required to provide a horizontal market power analysis because of the exemption under section 35.27(a). 71

71 April 14 Order, 107 FERC ¶ 61,018 at P 38.

69. Although we remain committed to encouraging new entry of generation, we are concerned that the continued use of the section 35.27(a) exemption may become too broad. Over time, this exemption would encompass all market participants as all pre-July 9, 1996 generation is retired. For this reason, some commenters suggest that the Commission should eliminate the exemption altogether. 72

72 American Public Power Association (APPA) Comments (March 15, 2005) at P 35.

70. We agree with these commenters that our current practice will have unintended adverse consequences over time and therefore should be reformed. Accordingly, we propose to eliminate the express exemption provided in section 35.27(a), but to do so in a manner that will not act as a disincentive for the construction of new generation. As explained further below, this change will not affect many sellers, given that they already are required to include all new capacity when submitting a market analysis for their pre-1996 generation. Further, our proposal will assure that all generation is treated on an equal footing, such that market participants with similar market shares in the same geographic market are not treated differently based solely on the vintage of their assets.

ffect many sellers, given that they already are required to include all new capacity when submitting a market analysis for their pre-1996 generation. Further, our proposal will assure that all generation is treated on an equal footing, such that market participants with similar market shares in the same geographic market are not treated differently based solely on the vintage of their assets.

71. Under this proposal, the Commission would require that all new applicants seeking market-based rate authority on or after the effective date of 73

73 April 14 Order, 107 FERC ¶ 61,018 at P 117. In the April 14 Order, the Commission explained that appropriate simplifying assumptions are those assumptions that do not affect the underlying methodology utilized by the generation market power screens. For example, if an applicant passes our generation market power screens by only considering the control area market's host utility as a competitor, the Commission foresees no benefit from completing a study to include other competitors. Similarly, if an applicant would pass the screens without considering competing supplies from adjacent control areas, the applicant need not include such imports in its studies. With regard to a new generator, such an applicant may base its horizontal market power analysis on the most recently approved study for the control area in which it is located.

72. Further, with regard to triennial reviews, the Commission's proposal to eliminate the section 35.27(a) exemption would require that, in its triennial review, a seller must perform a horizontal market power analysis of all of its generation regardless of when it was built, thus eliminating any special treatment of generation built after July 9, 1996. However, as discussed above, because the Commission allows for a streamlined analysis, including simplifying assumptions, where appropriate, any additional burden imposed by the proposed elimination of the section 35.27(a) exemption will be minimal

power analysis of all of its generation regardless of when it was built, thus eliminating any special treatment of generation built after July 9, 1996. However, as discussed above, because the Commission allows for a streamlined analysis, including simplifying assumptions, where appropriate, any additional burden imposed by the proposed elimination of the section 35.27(a) exemption will be minimal. In addition, the Commission anticipates that those entities that otherwise would have relied on the exemption will, in most cases, qualify as Category 1 sellers and thus no longer be required to file triennial reviews.

73. By proposing to eliminate the express exemption set forth in section 35.27(a), we are not proposing to require sellers with market-based rate authority to submit a new horizontal market power analysis ( i.e. , perform the generation market power screens) each time that they add a new generating unit. Rather, a seller with market-based rate authority would be required to file a “change in status” report under Order No. 652 notifying the Commission of the acquisition of additional generation, 74 the same requirement that exists today. Such sellers are not required to file a market power analysis of their generation with their change in status filing, nor do we propose they should. 75

74 Order No. 652, FERC Stats. & Regs. ¶ 31,175 at P 68. The threshold of additional generation that triggers the reporting requirement is a net increase of 100 MW or more. See Order No. 652-A, 111 FERC ¶ 61,413 at P 24-25.

75 Further, in the event the seller acquires existing generation, it may also need to seek approval therefor consistent with the provisions of section 203 of the FPA as amended. 16 U.S.C. 824b (2000). Energy Policy Act of 2005 §§ 261 et seq. , Pub. L. 109-58, 199 Stat. 594 (2005) (EPAct 2005).

74. Thus, our proposal to eliminate section 35.27(a) should not impose significant additional burdens on new generation or otherwise deter new entry. We seek comments on this proposal.

seek approval therefor consistent with the provisions of section 203 of the FPA as amended. 16 U.S.C. 824b (2000). Energy Policy Act of 2005 §§ 261 et seq. , Pub. L. 109-58, 199 Stat. 594 (2005) (EPAct 2005).

74. Thus, our proposal to eliminate section 35.27(a) should not impose significant additional burdens on new generation or otherwise deter new entry. We seek comments on this proposal.

h. Nameplate Capacity.

75. Based on our experience, we propose to allow sellers the option of using seasonal capacity instead of nameplate capacity as currently required. The seller must be consistent in its choice and use one or the other measure of capacity ratings throughout the analysis. The use of seasonal capacity ratings we believe more accurately reflects the seasonal real power capability and is not inconsistent with industry standards, and therefore it may be more convenient for sellers to acquire and compile the associated data. In addition, we do not think the use of such ratings will materially impact results. We seek comment on this proposal, including comment as to whether this information is publicly available to all market participants.

i. Transmission Imports.

76. We propose to continue our use of limiting capacity that can be imported into a relevant market to the results of a simultaneous transmission import capability study, and to reaffirm several aspects of the requirements regarding how to properly construct a simultaneous transmission import capability study for use in the indicative screens and the DPT.

DPT.

77. The simultaneous transmission import capability study is intended to provide a reasonable simulation of historical conditions. In particular, the simultaneous transmission import capability study is not the theoretical maximum import capability or a best import case scenario. It is a benchmark of historical operating conditions and practices of the applicable transmission provider ( e.g. , modeling the system in a reliable and economic fashion as it would have been operated in real time). The analysis should not deviate from OASIS practice during each historical seasonal peak. Appendix E of the April 14 Order states that the power flow cases should represent the transmission provider's tariff provisions and all firm/network reservations held by seller/affiliate resources during the most recent seasonal peaks. We propose to reaffirm that “all” means both short- and long-term firm/network reservations.

78. In addition to the power flow cases, as noted in Appendix E of the April 14 Order, the seller must supply supporting documentation, and this documentation should include the operational practices historically used, reliability margins, and all firm/network reservations held by the seller or its affiliates that are modeled in the cases. The simultaneous transmission import capability study must reasonably reflect the transmission provider's OASIS practices and the techniques used must have been historically available to customers. We propose to continue to use the instructions set forth in the April 14 Order.

79. Further, the April 14 Order required simultaneous transmission import capability studies to include firm point-to-point and network transmission reservations. Firm/network reservations should be subtracted from the simultaneous transmission import capability if they are not historically modeled in the power flow case. In all cases, sellers are required to provide documentation of the firm/network reservations.

14 Order required simultaneous transmission import capability studies to include firm point-to-point and network transmission reservations. Firm/network reservations should be subtracted from the simultaneous transmission import capability if they are not historically modeled in the power flow case. In all cases, sellers are required to provide documentation of the firm/network reservations.

80. We expect control area operators with market-based rate authority to provide simultaneous transmission import capability studies in a timely manner, consistent with the methodology described in the April 14 Order, for their control area and directly interconnected first-tier control areas in response to requests by sellers seeking market-based rate authority. 76 This includes all the required data, documentation and workpapers to support the study.

76 July 8 Order, 108 FERC ¶ 61,026 at P 124.

81. We also propose to reaffirm certain aspects of an approximation explained in Appendix E of the April 14 Order. The April 14 Order allows directly interconnected first-tier control areas (to the market being studied) to be considered when conducting the study. However, it does not allow control areas that are second tier to the control area being studied to be considered.

82. We propose to specify how the calculation of a seller's pro rata share of simultaneous transmission import capability should be performed. When studying its first-tier control area, the seller should allocate imports (after taking into account firm reservations by attributing them to the holders of the reservations including those applicable to the seller) pro rata between the seller and its competitors based on

j. Procedural Issues.

83. The Commission notes that Order No. 662 77 issued June 21, 2005, addressed concerns that CEII claims in market-based rate filings are overbroad

ler should allocate imports (after taking into account firm reservations by attributing them to the holders of the reservations including those applicable to the seller) pro rata between the seller and its competitors based on

j. Procedural Issues.

83. The Commission notes that Order No. 662 77 issued June 21, 2005, addressed concerns that CEII claims in market-based rate filings are overbroad. In response to commenters' concerns that intervenors should have sufficient time to respond to market-based rate filings for which CEII is claimed, the Commission stated that it is willing to consider on a case-by-case basis requests for extensions of time to prepare protests to market-based rate filings where an intervenor demonstrates that it needs additional time to obtain and analyze CEII. The Commission encouraged the parties in cases in which CEII is filed to promptly negotiate a protective order in the proceeding governing access to the CEII, or privately negotiate for the submitter to provide the data to interested parties pursuant to an appropriate non-disclosure agreement. The Commission seeks comments on whether CEII designations remain a concern since issuance of that rule. The Commission also seeks comments regarding whether the comment period (generally 21 days from the date of filing) provided for parties to file responses to the indicative screens and DPT analyses is sufficient. If the Commission were to establish a longer period for submitting comments in these cases, what would be an appropriate comment period?

77 Critical Energy Infrastructure Information, Order No. 662, 70 FR 37031 (June 28, 2005), FERC Stats. & Regs. ¶ 31,189 (June 21, 2005).

B. Vertical Market Power

84. The Commission historically has considered transmission market power and other barriers to entry as two separate parts of the four-prong market-based rate analysis

nts in these cases, what would be an appropriate comment period?

77 Critical Energy Infrastructure Information, Order No. 662, 70 FR 37031 (June 28, 2005), FERC Stats. & Regs. ¶ 31,189 (June 21, 2005).

B. Vertical Market Power

84. The Commission historically has considered transmission market power and other barriers to entry as two separate parts of the four-prong market-based rate analysis. However, as discussed below, the examination of a seller's ability to engage in transmission market power and a seller's ability to exclude competitors from the market by erecting other barriers to entry through the control of inputs to electric power production both involve the evaluation of potential vertical market power. On this basis, in this NOPR the Commission proposes to reformulate its market-based rate analysis to consider issues relating to transmission market power and other barriers to entry under the heading “vertical market power.” This proposal is intended primarily to alter the way in which we characterize these issues, rather than changing the fundamental nature of the analyses that we perform.

1. Current Policy

Transmission

85. To the extent that a market-based rate seller, or any of its affiliates, owns, operates, or controls transmission facilities, the Commission has required the seller to have an OATT on file before granting market-based rate authorization. The OATT was implemented in 1996 when the Commission issued Order No. 888 to remedy undue discrimination or preference in access to the monopoly owned transmission grid. Having a Commission-approved OATT on file satisfies the Commission's concerns with regard to transmission market power. In addressing our transmission market power concerns, a seller, including its affiliates, that does not own, operate or control transmission facilities should make an affirmative statement that neither it, nor any of its affiliates, owns, operates or controls any transmission facilities. 78

78 See, e.g., Citizens Power, 48 FERC ¶ 61,210.

's concerns with regard to transmission market power. In addressing our transmission market power concerns, a seller, including its affiliates, that does not own, operate or control transmission facilities should make an affirmative statement that neither it, nor any of its affiliates, owns, operates or controls any transmission facilities. 78

78 See, e.g., Citizens Power, 48 FERC ¶ 61,210.

86. The Commission issued a Notice of Inquiry in Preventing Undue Discrimination and Preference in Transmission Services , 79 that seeks to explore whether, and if so, which, reforms are necessary to the Order No. 888 pro forma OATT and to the individual public utility OATTs, given the current state of the electric industry, the complaints of customers regarding remaining undue discrimination, and the apparent uncertainties and inconsistent application concerning various tariff provisions that have arisen since implementation of Order No. 888. The Commission is issuing a notice of proposed rulemaking in that proceeding concurrently with this NOPR.

79 See Preventing Undue Discrimination and Preference in Transmission Service , 70 FR 55796 (Sept. 23, 2005), FERC Stats. & Regs., Regulations Preambles January 2001-December 2005 ¶ 35,553 (2005) (OATT Reform Rulemaking).

Other Barriers to Entry

87. Although the principal barriers to entry can be raised through the ownership or control of transmission facilities, the Commission also evaluates barriers to entry other than transmission (other barriers to entry). In the early 1990s, the Commission considered whether a seller or its affiliates could erect other barriers to entry through ownership or control of sites for new capacity development, key inputs to generation, or the transportation of key inputs to generation

p or control of transmission facilities, the Commission also evaluates barriers to entry other than transmission (other barriers to entry). In the early 1990s, the Commission considered whether a seller or its affiliates could erect other barriers to entry through ownership or control of sites for new capacity development, key inputs to generation, or the transportation of key inputs to generation. 80 The Commission has also considered other barriers to entry, such as: control of major engineering and consulting firms, 81 control of fuel supplies, ownership or control of equipment, 82 and the control of transportation or distribution of fuel supplies in the relevant markets. 83

80 See Doswell Limited Partnership , 50 FERC ¶ 61,251 at 61,758 (1990) ( Doswell ); Commonwealth Atlantic Limited Partnership , 51 FERC ¶ 61,368 at 62,244-45 (1990) ( Commonwealth Atlantic ), cited in Entergy Services, Inc. , 58 FERC ¶ 61,234 at n.85 (1992) ( Entergy MBR I ).

81 See Wallkill Generating Company, L.P. (Wallkill ), 56 FERC ¶ 61,067 (1991).

82 See Louisville Gas and Electric Company , 62 FERC ¶ 61,016 at 61,147 (1993) ( LG&E ); Entergy MBR I , 58 FERC at 61,759; Pacific Gas and Electric Company , 53 FERC ¶ 61,145 at 61,505 (1990).

83 In Enron Power Marketing, Inc. , 65 FERC ¶ 61,305 at 62,405 (1993), order on clarification and reh'g , 66 FERC ¶ 61,244 (1994), the Commission determined that a power marketer may be affiliated with an interstate natural gas pipeline because, under the Commission's requirements, such pipelines must offer open-access services on a non-discriminatory basis. See also Vantus Energy Corporation , 73 FERC ¶ 61,099 at 61,316 (1995)

c. , 65 FERC ¶ 61,305 at 62,405 (1993), order on clarification and reh'g , 66 FERC ¶ 61,244 (1994), the Commission determined that a power marketer may be affiliated with an interstate natural gas pipeline because, under the Commission's requirements, such pipelines must offer open-access services on a non-discriminatory basis. See also Vantus Energy Corporation , 73 FERC ¶ 61,099 at 61,316 (1995). In Idaho Power Company , 110 FERC ¶ 61,219 at 61,816 (2005), the Commission considered a utility's ownership and control of rail cars to transport coal in its evaluation of the other barriers to entry prong and held that there are many other companies from which rail cars may be leased, and that the total number of cars that the utility could be considered to control (less than 200) was insignificant relative to the total number of such cars.

88. In particular, the Commission considered such things as a power producer's ownership of building sites and its affiliation with or ownership of interstate natural gas pipelines, engineering and construction firms, or local natural gas distribution systems. For example, in Wallkill, the Commission determined that affiliation with a major engineering and construction firm could not be used to erect barriers to entry because there were a large number of such firms operating on a national basis. Further, in LG&E, the Commission found that although LG&E did not own facilities used to transport natural gas, its affiliate owned gas lines and gas storage facilities. In light of this, the Commission stated that should LG&E or any of its affiliates deny, delay, or require unreasonable terms, conditions, or rates for gas services to a potential electric competitor, the electric competitor could file a complaint with the Commission

nd that although LG&E did not own facilities used to transport natural gas, its affiliate owned gas lines and gas storage facilities. In light of this, the Commission stated that should LG&E or any of its affiliates deny, delay, or require unreasonable terms, conditions, or rates for gas services to a potential electric competitor, the electric competitor could file a complaint with the Commission. The Commission has made similar findings in subsequent cases where a seller or its affiliates own or control any natural gas intrastate facilities or distribution facilities, stating that should such seller or any of its affiliates deny, delay, or require unreasonable terms, conditions, or rates for fuel or services to a potential electric competitor in bulk power markets, then the competitor may file a complaint with the Commission that could result in the suspension of the seller's authority to sell power at market-based 84

84 LG&E, 62 FERC ¶ 61,016 at 61,148.

2. Proposal

89. As discussed above, the Commission proposes to replace its existing four-prong analysis (generation market power, transmission market power, other barriers to entry, affiliate abuse/reciprocal dealing) with an analysis that focuses on horizontal market power and vertical market power. Accordingly, we propose that issues relating to whether the seller and its affiliates lack transmission market power or whether they can erect other barriers to entry be addressed together as part of the vertical market power part of the analysis.

90. Regarding transmission issues, the current policy is that having a Commission-approved OATT on file is sufficient to mitigate transmission market power. However, the Commission has also recognized that Order No. 888 did not eliminate all potential to engage in undue discrimination and preference in the provision of transmission service. 85 For this and other reasons, the Commission has initiated a Notice of Inquiry to address potential reforms to the current OATT

Commission-approved OATT on file is sufficient to mitigate transmission market power. However, the Commission has also recognized that Order No. 888 did not eliminate all potential to engage in undue discrimination and preference in the provision of transmission service. 85 For this and other reasons, the Commission has initiated a Notice of Inquiry to address potential reforms to the current OATT. 86 We believe that any concerns regarding the adequacy of the OATT should be addressed in that proceeding. We therefore will propose to continue to find that a Commission-approved OATT, as modified as a result of the OATT Reform Rulemaking, will adequately mitigate transmission market power.

85 In Order No. 2000, the Commission found that “opportunities for undue discrimination continue to exist that may not be remedied adequately by [the] functional unbundling [remedy of Order No. 888] * * *” Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,089 at 31,105 (1999), order on reh'g, Order No. 2000-A, FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,092 (2000), aff'd sub nom. Public Utility District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).

86 See Preventing Undue Discrimination and Preference in Transmission Service, 70 FR 55796 (Sept. 23, 2005), FERC Stats. & Regs., Proposed Regulations ¶ 35,553 (2005) (OATT Reform Rulemaking). A notice of proposed rulemaking is being issued in that proceeding concurrently with this NOPR.

this NOPR.

91. Nevertheless, the finding that an OATT adequately mitigates transmission market power rests on the assumption that individual applicants comply with their OATTs. If they do not, violations of the OATT may be cause to revoke market-based rate authority or to subject the seller to another remedy the Commission may deem appropriate, such as disgorgement of profits or civil penalties. 87 There may be OATT violations in circumstances that, after applying the factors in the Enforcement Policy Statement, merit revocation or limitation of market-based rate authority. However, before the Commission will consider revoking an entity's market-based rate authority for a violation of the OATT, there must be a nexus between the specific facts relating to the OATT violation and the entity's market-based rate authority. The Commission proposes that, if it determines, as a result of a significant OATT violation, that the market-based rate authority of a transmission provider will be revoked within a particular market, each affiliate of the transmission provider that possesses market-based rate authority will have it revoked in that market on the effective date of revocation of the transmission provider's market-based rate authority. We remind sellers that they must abide by the provisions of the OATT if they do not want an adverse impact on their ability to charge market-based rates.

87 See, e.g., The Washington Water Power Company, 83 FERC ¶ 61,282 (1998).

92. The Commission also proposes to continue considering a seller's ability to erect other barriers to entry, but to do so as part of the vertical market power analysis. We propose that, in order for a seller to demonstrate that it satisfies our vertical market power concerns, with respect to other barriers to entry, it must demonstrate that it and its affiliates cannot erect other barriers to entry

. The Commission also proposes to continue considering a seller's ability to erect other barriers to entry, but to do so as part of the vertical market power analysis. We propose that, in order for a seller to demonstrate that it satisfies our vertical market power concerns, with respect to other barriers to entry, it must demonstrate that it and its affiliates cannot erect other barriers to entry. In this regard, we propose to continue to require a seller to provide a description of its affiliation, ownership or control of inputs to electric power production ( e.g., fuel supplies within the relevant control area); ownership or control of gas storage or intrastate transportation and distribution of inputs to electric power production; and control of sites for new capacity development in the relevant market. We also propose to require sellers to make an affirmative statement that they have not erected barriers to entry into the relevant market and that they cannot do so.

93. In addition, the Commission proposes to provide additional regulatory certainty by clarifying which inputs to electric power production the Commission will consider as other barriers to entry in its vertical market power review, and seeks comments on this proposal. The Commission proposes that the analysis continue to include the consideration of ownership or control of sites for development of generation in the relevant market, fuel inputs such as coal facilities in the relevant market, and the transportation, storage or distribution of inputs to electric power production such as intrastate gas storage and distribution systems, and rail cars/barges for the transportation of coal. The Commission also clarifies that applicants need not address interstate transportation of natural gas supplies because such transportation is regulated by this Commission. 88 Our open access regulations adequately prevent sellers from withholding interstate pipeline capacity

r production such as intrastate gas storage and distribution systems, and rail cars/barges for the transportation of coal. The Commission also clarifies that applicants need not address interstate transportation of natural gas supplies because such transportation is regulated by this Commission. 88 Our open access regulations adequately prevent sellers from withholding interstate pipeline capacity. Interstate pipelines are required to sell available capacity at the approved maximum rates. In addition, interstate pipeline capacity held by firm shippers that is not utilized or released is available from the pipeline on an interruptible basis. As to the commodity, Congress has found the natural gas market competitive. 89

88 Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's Regulations, Order No. 636, 57 FR 13267 (Apr. 16, 1992), FERC Stats. & Regs. Regulations Preambles January 1991-June 1996 ¶ 30,939 (Apr. 8, 1992).

89 Natural Gas Wellhead Decontrol Act of 1989, Pub. L. 101-60, 103 Stat. 157 (1989); Natural Gas Policy Act of 1978, section 601(a)(1), 15 U.S.C. 3431 (deregulating the wellhead price of natural gas).

94. Several commenters have suggested that a transmission planning and expansion process can ameliorate vertical market power. The Commission is seeking comments on the issues of transmission planning and expansion in the notice of proposed rulemaking in the OATT Reform Rulemaking that is being issued concurrently with this NOPR. We seek comment on whether these planning and expansion efforts under the OATT Reform Rulemaking will address commenters' concerns here.

ued concurrently with this NOPR. We seek comment on whether these planning and expansion efforts under the OATT Reform Rulemaking will address commenters' concerns here.

95. The Commission seeks comment on whether other inputs to electric power production should be considered as potential barriers to entry and, if so, what criteria the Commission should use to evaluate evidence that is presented. We also seek comment on whether the exercise of buyer's market power by the transmission provider should be considered a potential barrier to entry and, if so, what criteria the Commission should use to evaluate evidence that is presented.

C. Affiliate Abuse

96. The fourth prong of the Commission's current market-based rate analysis examines whether there is evidence involving the seller or its 90 As the Commission has explained, “[t]he Commission's concern with the potential for affiliate abuse is that a utility with a monopoly franchise may have an economic incentive to exercise market power through its affiliate dealings.” 91 The Commission stated that potential abuses include such practices as affiliates selling products to a utility with a franchised service territory (franchised public utility) at excessive prices, or a franchised public utility providing inputs to an affiliate at preferentially low prices. Both of these practices are examples of market power that is exercised to the disadvantage of captive customers. The Commission also has explained that there may be a potential for affiliate abuse through means such as the pricing of non-power goods and services or the sharing of market information.

90 See Commonwealth Atlantic Limited Partnership, 51 FERC ¶ 61,368 at 62,245 (1990) (discussing potential for reciprocal dealing if a buyer agrees to pay more for power from a seller in return for that seller (or its affiliates) paying more for power from the buyer (or its affiliates)).

91 Edgar, 55 FERC ¶ 61,382 at 62,167 n.56. See also TECO Power Services Corp

sharing of market information.

91 Edgar, 55 FERC ¶ 61,382 at 62,167 n.56. See also TECO Power Services Corp. and Tampa Electric Co., 52 FERC ¶ 61,191 at 61,697 n. 41 (1990) (“The Commission has determined that self-dealing may arise in transactions between affiliates because affiliates have incentives to offer terms to one another which are more favorable than those available to other market participants.”).

97. The Commission in the past has used two means to ensure that affiliate abuse does not occur: restrictions on sales between a franchised public utility and its affiliates, and requiring a code of conduct that governs the relationship between franchised public utilities and their affiliates.

1. Power Sales Restrictions

a. Current Policy.

98. The Commission currently prohibits power sales at market-based rates between a franchised public utility and its affiliates without first receiving authorization of the transaction under section 205 of the FPA. 92 In order to be granted market-based rate authorization, a franchised public utility and all of its affiliates must include such a prohibition in their market-based rate tariffs unless the Commission has otherwise authorized the seller to transact with its affiliates.

92 Aquila, Inc., 101 FERC ¶ 61,331 (2002).

ased rate tariffs unless the Commission has otherwise authorized the seller to transact with its affiliates.

92 Aquila, Inc., 101 FERC ¶ 61,331 (2002).

99. The Commission has stated its concern that a franchised public utility and an affiliate may be able to transact in ways that transfer benefits from the captive customers of the franchised public utility to the affiliate and its shareholders. 93 Where a franchised public utility makes a power sale to an affiliate, the Commission is concerned that such a sale could be made at a rate that is too low, in effect, transferring the difference between the market price and the lower rate from captive customers to the “non-regulated” affiliated entity. Where an entity makes power sales to an affiliated franchised public utility, the concern is that such sales not be made at a rate that is too high, which would give an undue profit to the affiliated entity at the expense of the franchised public utility's captive customers. The Commission has found that a transaction between two non-traditional utility affiliates (such as power marketers, EWGs, or QFs) does not raise the same concern about cross subsidization because neither has a franchised service territory and therefore has no captive customers. As the Commission has explained, no matter how sales are conducted between non-traditional affiliates, profits or losses ultimately affect only the shareholders. 94

93 See, e.g., Heartland Energy Services Inc., 68 FERC ¶ 61,223 at 62,062 (1994) (Heartland).

94 FirstEnergy Generation Corporation, 94 FERC ¶ 61,177 (2001); USGen Power Services, L.P., 73 FERC ¶ 61,302 at 61,846 (1995).

100. In determining whether to allow power sales affiliate transactions, the Commission, over time, has adopted several methods, all of which have focused on ensuring that captive customers are adequately protected against affiliate abuse. We discuss these below.

101

94 FirstEnergy Generation Corporation, 94 FERC ¶ 61,177 (2001); USGen Power Services, L.P., 73 FERC ¶ 61,302 at 61,846 (1995).

101. In Edgar, the Commission described three types of evidence that can be used to show that an affiliate power sales transaction is above suspicion ensuring that the market is not distorted and captive ratepayers are protected: (1) Evidence of direct head-to-head competition between the affiliate and competing unaffiliated suppliers in a formal solicitation or informal negotiation process; (2) evidence of the prices non-affiliated buyers were willing to pay for similar services from the affiliate; or (3) benchmark evidence that shows the prices, terms, and conditions of sales made by non-affiliated sellers. 95 The Commission stated that when an entity presents evidence regarding a competitive solicitation, the Commission requires assurance that: (1) A competitive solicitation process was designed and implemented without undue preference for an affiliate; (2) the analysis of bids did not favor affiliates, particularly with respect to non-price factors; and (3) the affiliate was selected based on some reasonable combination of price and non-price factors. 96

95 Edgar, 55 FERC ¶ 61,382 at 62,168-69.

96 Id. at 62,168. A seller with market-based rate authority would not necessarily be required to make a separate affirmative showing of no market power in order to fulfill the Edgar standards and receive authority to engage in an affiliate transaction.

102

e affiliate was selected based on some reasonable combination of price and non-price factors. 96

95 Edgar, 55 FERC ¶ 61,382 at 62,168-69.

102. In subsequent cases, the Commission expanded on the competitive solicitation prong of Edgar and has stated that it must evaluate the bidding process and determine that, based on the evidence, a proposed power sale between affiliates is the result of direct head-to-head competition. 97

97 See, e.g., Rockland Electric Company, 102 FERC ¶ 61,097 (2003); Connecticut Light & Power Company and Western Massachusetts Electric Company, 90 FERC ¶ 61,195 at 61,633-34 (2000); Aquila Energy Marketing Corp., 87 FERC ¶ 61,217 at 61,857-58 (1999); MEP Pleasant Hill, LLC, 88 FERC ¶ 61,027 at 61,059-60 (1999); Edgar, 55 FERC ¶ 61,382 at 62,167-69.

103. The Commission has provided guidelines as to how the Commission will evaluate whether a competitive solicitation process satisfies the Edgar criteria. The underlying principle when evaluating a competitive solicitation process under the Edgar criteria is that no affiliate should receive undue preference during any stage of the process.

104. In Allegheny, the Commission stated that the following four guidelines will help the Commission determine if a competitive solicitation process satisfies that underlying principle: It is transparent; products are well defined; bids are evaluated comparably with no advantage to affiliates; and it is designed and evaluated by an independent entity. 98 The Allegheny guidelines serve as one example of evidence that a competitive solicitation has resulted in just and reasonable rates; they do not constitute the only way in which an applicant could demonstrate that a competitive solicitation was not unduly discriminatory

ned; bids are evaluated comparably with no advantage to affiliates; and it is designed and evaluated by an independent entity. 98 The Allegheny guidelines serve as one example of evidence that a competitive solicitation has resulted in just and reasonable rates; they do not constitute the only way in which an applicant could demonstrate that a competitive solicitation was not unduly discriminatory.

98 See, e.g., Allegheny Energy Supply Company, LLC, 108 FERC ¶ 61,082 (2004) ( Allegheny ); Rockland Electric Company, 102 FERC ¶ 61,097 (2003); Conectiv Energy Supply, Inc., 91 FERC ¶ 61,076 (2000).

105. The Commission has granted blanket authorization to make power sales to affiliates pursuant to a market-based rate tariff subject to certain conditions. For this blanket authorization, the Commission has required that sales of power by a franchised public utility to an affiliate be made at a rate no lower than the rate charged to non-affiliates; the utility offering to sell power to an affiliate must make the same offer, at the same time, to non-affiliated entities; and the utility must post simultaneously the actual price charged to its affiliate for all 99 These provisions were originally included as part of Detroit Edison's cost-based rate tariff in response to a request by Detroit Edison to sell power to its affiliated power marketer at negotiated rates subject to a cost-based price cap. However, the Commission's practice has been to allow such a provision in other sellers' market-based rate tariffs. Utilities that request this blanket authorization have been required to include those conditions in their market-based rate tariffs. 100

99 Detroit Edison Co. , 80 FERC ¶ 61,348 at 62,198 (1997).

100 See , e.g. , Alliant Services Company , 85 FERC ¶ 61,344 at 62,335 (1998); Tucson Electric Power Company , 82 FERC ¶ 61,141 at 61,525 (1998).

106

ion in other sellers' market-based rate tariffs. Utilities that request this blanket authorization have been required to include those conditions in their market-based rate tariffs. 100

99 Detroit Edison Co. , 80 FERC ¶ 61,348 at 62,198 (1997).

100 See , e.g. , Alliant Services Company , 85 FERC ¶ 61,344 at 62,335 (1998); Tucson Electric Power Company , 82 FERC ¶ 61,141 at 61,525 (1998).

106. The Commission also has authorized sales when a “non-regulated” affiliate seeks to sell power to an affiliated franchised public utility where sufficient pricing safeguards were in place to ensure that there was no room for manipulation. 101 In Advanced Resources , the Commission found adequate a plan where the power marketer sold energy to its affiliated franchised public utility at the lowest price paid by the franchised public utility to a non-affiliate under certain standard supplier agreements. Specifically, the Commission granted authorization because the price in these standard supplier agreements was equal to the average price of power sold to the franchised public utility through the PJM power exchange. Because the price of the franchised public utility's purchases from the power marketer was set equal to the price of the franchised public utility's purchases from PJM, the Commission concluded there was no room for manipulation.

101 See , e.g. , GPU Advanced Resources, Inc. , 81 FERC ¶ 61,335 (1997) ( Advanced Resources ); FirstEnergy Trading & Power Marketing, Inc. , 84 FERC ¶ 61,214 at 62,037-38, reh'g denied , 85 FERC ¶ 61,311 (1998) (rejecting tariffs without prejudice to the applicants submitting alternative proposals that delineate the nature of the transactions to be undertaken and demonstrate that any proposed safeguards mitigate the potential for affiliate abuse).

107

61,335 (1997) ( Advanced Resources ); FirstEnergy Trading & Power Marketing, Inc. , 84 FERC ¶ 61,214 at 62,037-38, reh'g denied , 85 FERC ¶ 61,311 (1998) (rejecting tariffs without prejudice to the applicants submitting alternative proposals that delineate the nature of the transactions to be undertaken and demonstrate that any proposed safeguards mitigate the potential for affiliate abuse).

107. The Commission also has allowed sales between affiliates pursuant to a market-based rate tariff without imposing any price or transaction conditions where there were no captive wholesale or retail customers or where captive customers were adequately protected from affiliate abuse. 102 In these cases, the Commission found that captive customers were protected through fixed rate contracts, retail rate freezes, retail access, and an inability for the captive ratepayer to be harmed through fuel adjustment clauses. The Commission also has found that tying the price of an affiliate transaction to an established, relevant market price or index mitigates affiliate abuse concerns. 103

102 See , e.g. , Consumers Energy Company , 94 FERC ¶ 61,180 (2001) (finding there are adequate safeguards including Consumer Energy disallowing revenues for sales to CMS Marketing to be factored into any rate calculations for wholesale customers, existence of retail rate freeze, and phase in of retail choice); FirstEnergy Corp. , 94 FERC ¶ 61,182 at 61,630 (2001) (finding of adequate safeguards based on FirstEnergy's commitment to hold wholesale customers harmless from changes in cost, a retail rate freeze in Ohio, and caps on retail rates in Pennsylvania); Exelon Generation Company , L.L.C. , 93 FERC ¶ 61,140 at 61,425 (2000), reh'g denied , 95 FERC ¶ 61,309 (2001) (finding there are adequate safeguards including retail access, rate freezes, rate caps, and other mechanisms)

e safeguards based on FirstEnergy's commitment to hold wholesale customers harmless from changes in cost, a retail rate freeze in Ohio, and caps on retail rates in Pennsylvania); Exelon Generation Company , L.L.C. , 93 FERC ¶ 61,140 at 61,425 (2000), reh'g denied , 95 FERC ¶ 61,309 (2001) (finding there are adequate safeguards including retail access, rate freezes, rate caps, and other mechanisms).

103 Brownsville Power I, L.L.C., 111 FERC ¶ 61,398 at P 10 (2005) (Brownsville); See also FirstEnergy Trading Servs., Inc., 88 FERC ¶ 61,067 at 61,156 (1999) (FirstEnergy Trading); Union Light, Heat, and Power Co., 110 FERC ¶ 61,212 at P16 (2005) (affirming that use of Midwest ISO Day 2 market prices meets the Edgar test and mitigates concerns regarding transactions between affiliates); Idaho Power Company, 95 FERC ¶ 61,147 (2001) (accepting use of the Dow Jones Mid-Columbia Index and the Dow Jones Palo Verde Index for affiliate sales); Pinnacle West Capital Corporation, 91 FERC ¶ 61,290 (2000) (allowing use of the lesser of the Palo Verde Index and system incremental cost as a cap on the price for sales between affiliates); DPL Energy, Inc., 90 FERC ¶ 61,200 (2000) (affirming that use of the “into Cinergy” index price as a price cap for its power sales to Dayton P&L mitigates affiliate abuse concerns); Ameren Services Company , 86 FERC 61,212 (1999) (accepting use of “into Cinergy” for sales between affiliates).

b. Proposal .

mitigates affiliate abuse concerns); Ameren Services Company , 86 FERC 61,212 (1999) (accepting use of “into Cinergy” for sales between affiliates).

b. Proposal .

108. We remain concerned about the potential adverse impact that affiliate power sales transactions may have on captive customers 104 and propose to continue our policy of reviewing affiliate transactions under section 205 of the FPA. Although we have traditionally identified affiliate abuse as the fourth prong of our test for market-based rate authority, in practice this prong is not only evaluated at the time an application is filed, but rather is satisified on an ongoing basis through the requirement that sellers obtain prior approval, under the foregoing standards, for affiliate power sales. To reflect and codify this practice, we propose to discontinue referring to affiliate abuse as a separate “prong” of our analysis and instead we propose to codify in our regulations at 18 CFR part 35, subpart H, an explicit requirement that any seller with market-based rate authority must comply with the affiliate power sales restrictions and other affiliate provisions. 105 Thus, we will address affiliate abuse by requiring that the conditions set forth in the proposed regulations be satisfied on an ongoing basis as a condition of obtaining and retaining market-based rate authority. However, we note that a seller seeking to obtain or retain market-based rate authority will continue to be obligated to provide a detailed description of its corporate structure so that we can be assured that our standards are being applied correctly. In particular, applicants with franchised service territories will be required to make a showing regarding whether they serve customers and to identify all non-regulated power sales affiliates, such as affiliated marketers and generators. 106

104 See Edgar , 55 FERC ¶ 61,382 at 62,167

description of its corporate structure so that we can be assured that our standards are being applied correctly. In particular, applicants with franchised service territories will be required to make a showing regarding whether they serve customers and to identify all non-regulated power sales affiliates, such as affiliated marketers and generators. 106

104 See Edgar , 55 FERC ¶ 61,382 at 62,167.

105 With regard to reciprocal dealing, we believe that any concerns as to a seller's ability to engage in reciprocal dealing are addressed by the affiliate abuse provisions we propose to include in the Commission's regulations as well as the Commission's final rule prohibiting energy market manipulation. See Prohibition of Energy Market Manipulation , Order No. 670, 71 FR 4244 (January 26, 2006), FERC Stats. & Regs. ¶ 31,202 (2006), order on reh'g, Order No. 670-A, 114 FERC ¶ 61,300 (2006).

106 In this regard, the Commission protects captive customers by ensuring that wholesale rates are just and reasonable.

109. Consistent with the foregoing, we propose to amend the Commission's regulations to include a provision expressly prohibiting power sales between a franchised public utility and any of its non-regulated affiliates without first receiving authorization of the transaction under section 205 of the FPA. Further, we propose that, as a condition of receiving market-based rate authority, sellers must adopt the MBR tariff (included as Appendix A to this NOPR) which includes a provision requiring the seller to comply with, among other things, the affiliate provisions in the regulations. We note that failure to satisfy the conditions set forth in the affiliate provisions will constitute a tariff violation. We seek comments on this proposal.

atisfy the conditions set forth in the affiliate provisions will constitute a tariff violation. We seek comments on this proposal.

110. Sellers seeking authorization to engage in affiliate transactions will continue to be obligated to provide evidence to support a determination as to whether there are captive customers that would trigger the application of our standards for affiliate power sales. 107 If the Commission finds, based on the evidence provided by the seller, that the seller has no captive customers, the affiliate provisions in the regulations would not apply. However, if the record does not support a finding of no captive customers, the seller must abide by all affiliate restrictions contained in the regulations in order to obtain and retain market-based rate authority. In the Commission's Final Rule on transactions subject to section 203, the 108 We seek comment on whether the same definition should be used for purposes of this rule.

107 Sellers that have already received authorization to make sales to affiliates would retain that authorization unless the Commission institutes a section 206 investigation to examine whether the seller's current circumstances continue to satisfy our affiliate abuse concerns and subsequently revokes such authorization.

108 Transactions Subject to FPA section 203 , Order No. 669-A, 71 FR 28422 (May 16, 2006), FERC Stats. & Regs. ¶ 31,097 (2006). See also Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005 , Order No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & Regs. ¶ 31,096 (2006).

111. We propose to continue our past approach for determining what types of affiliate transactions are permissible and the criteria that should be used to make those decisions

(2006). See also Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005 , Order No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & Regs. ¶ 31,096 (2006).

111. We propose to continue our past approach for determining what types of affiliate transactions are permissible and the criteria that should be used to make those decisions. When affiliates participate in a competitive solicitation process, application of the Allegheny criteria would constitute safe harbor criteria that the affiliate abuse condition is satisfied in a transaction between a franchised public utility and its affiliate. The Commission will consider competitive solicitations, on a case-by-case basis. However, we emphasize that using a competitive solicitation is not the only way an affiliate transaction can address our concerns that the transaction does not pose affiliate abuse concerns.

112. In Edgar , two alternatives to competitive solicitation evidence were found to be acceptable evidence of a market price. These alternatives included prices non-affiliates are willing to pay for similar service and benchmark evidence. However, Edgar also noted the difficulty of finding such truly comparable alternative evidence. 109 This difficulty in finding adequate comparable evidence increases the likelihood that applications submitted with such evidence could raise issues of material fact and thus could be set for hearing.

109 See Edgar , 55 FERC ¶ 61,382 at 62,169.

ee Edgar , 55 FERC ¶ 61,382 at 62,169.

113. We continue to believe that tying the price of an affiliate transaction to an established, relevant market price or index such as in an RTO or ISO is acceptable benchmark evidence and mitigates affiliate abuse concerns so long as that benchmark price or index reflects the market price where the affiliate transaction occurs ( i.e. , is a relevant index). 110 The Commission has stated its belief that the added protections in structured markets with central commitment and dispatch and market monitoring and mitigation (such as RTOs/ISOs) generally result in a market where prices are transparent. 111

110 Brownsville , 111 FERC ¶ 61,398 at P10. See also Portland General Elec. Co. , 96 FERC ¶ 61,093 at 61,378 (2001); FirstEnergy Trading , 88 FERC ¶ 61,067 at 61,156 (1999).

111 April 14 Order, 107 FERC ¶ 61,018 at P 189.

114. Although the Commission has found in the past that certain non -RTO price indices are acceptable indicators of market prices, we recognize that price indices at thinly traded points can be subject to manipulation and are otherwise not good measures of market prices, as discussed in the Price Index Policy Statement 112 and November 19 Price Index Order. 113 Accordingly, we propose to allow affiliate transactions based on a non -RTO price index only if the index fulfills the requirements of the November 19 Price Index Order for eligibility for use in jurisdictional tariffs

ints can be subject to manipulation and are otherwise not good measures of market prices, as discussed in the Price Index Policy Statement 112 and November 19 Price Index Order. 113 Accordingly, we propose to allow affiliate transactions based on a non -RTO price index only if the index fulfills the requirements of the November 19 Price Index Order for eligibility for use in jurisdictional tariffs. 114 The requirements include the criteria found in the Price Index Policy Statement, including but not limited to 115 reporting of prices by those not involved in trading, and a process for resolving reporting errors, as well as those specific to jurisdictional tariffs: (1) Providing the volume and number of transaction data on which the index value is based (or clearly indicating when no such data is available); (2) confirming that the Commission can have access to relevant data in the event of an investigation of possible false price reporting or manipulation; and (3) establishing minimum criteria to determine whether there is adequate liquidity for daily, weekly, and monthly electricity indices.

112 Policy Statement On Natural Gas And Electric Price Indices 104 FERC ¶ 61,121 (2003) (Price Index Policy Statement).

113 Order Regarding Future Monitoring Of Voluntary Price Formation, Use Of Price Indices In Jurisdictional Tariffs, And Closing Certain Tariff Docket 109 FERC ¶ 61, 184 (2004) (November 19 Price Index Order).

114 November 19 Price Index Order , 109 FERC ¶ 61,184 at P 40-69.

115 Price Index Policy Statement , 104 FERC ¶ 61,121 at P 34.

115. The Commission seeks comment on whether evidence other than competitive solicitations, RTO price or non-RTO price indices, or benchmarks described above, should be accepted in an application for authority to engage in affiliate power sales.

ompetitive solicitations, RTO price or non-RTO price indices, or benchmarks described above, should be accepted in an application for authority to engage in affiliate power sales.

116. With regard to merging companies the Commission has stated that for the purposes of affiliate abuse, merging companies will be considered affiliates under the market-based rate tariff while their merger is pending. 116 We seek comments regarding at what point the Commission should consider two non-affiliates as merging partners: the date the merger is announced, the date the section 203 application is filed with the Commission, or another time? The Commission proposes to use the date a merger is announced as the triggering event, but we seek comment on this issue.

116 Cinergy, Inc., 74 FERC ¶ 61,281 (1996); Consolidated Edison Energy, Inc., 83 FERC ¶ 61,236 at 62,034 (1998); Central and South West Services, Inc., 82 FERC ¶ 61,101 at 61,103 (1998); Delmarva Power & Light Company, 76 FERC ¶ 61,331 at 62,582 (1996) (“[T]he self-interest of two merger partners converge sufficiently, even before they complete the merger, to compromise the market discipline inherent in arm's-length bargaining that serves as the primary protection against reciprocal dealing.”).

117. The Commission also proposes that entities that engage in energy/asset management of generation on behalf of a franchised public utility be treated as affiliates of that franchised public utility in a manner similar to that of non-regulated affiliates and be subject to the affiliate provisions we propose herein. The Commission also proposes that entities that engage in energy/asset management of generation on behalf of non-regulated affiliates of a franchised public utility be treated in a similar manner as the non-regulated affiliates. We seek comment on this proposal.

118. The Commission currently requires that sales made under market-based rate tariffs, including those made to affiliates, be reported in an EQR

sion also proposes that entities that engage in energy/asset management of generation on behalf of non-regulated affiliates of a franchised public utility be treated in a similar manner as the non-regulated affiliates. We seek comment on this proposal.

118. The Commission currently requires that sales made under market-based rate tariffs, including those made to affiliates, be reported in an EQR. 117 The Commission affirms that its role with regard to market-based rates, and specifically affiliate transactions, will be to either grant or deny authorization to make affiliate sales. Additionally, the Commission reiterates that, once authorized, all such sales should be reported in an EQR.

117 Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31043 (May 8, 2002), FERC Stats. & Regs., Regulations Preambles January 2001-December 2005 ¶ 31,127 (2002).

119. Although, at one time, the Commission's policy was to require certain market-based rate sellers to file their long-term market-based rate power sales service agreements with the Commission, 118 since the issuance of Order No. 2001, the Commission's policy has been to require that such agreements not be filed with the Commission. Notwithstanding this policy, the Commission on occasion may have accepted long-term service agreements for filing. At this time, the Commission reaffirms that long-term affiliate sales contracts under the seller's market-based rate tariff that are authorized by the Commission shall not be filed with the Commission. 119 However, the seller must make a section 205 filing with the Commission to obtain authorization to engage in an

118 See Southern Company Services, Inc., 99 FERC ¶ 61,103 (2002).

119 18 CFR 35.1(g) (2005) (“[A]ny market-based rate agreement pursuant to a tariff shall not be filed with the Commission”).

2. Market-Based Rate Code of Conduct for Affiliate Transactions Involving Power Sales and Brokering, Non-Power Goods and Services and Information Sharing

a. Current Policy.

120

zation to engage in an

118 See Southern Company Services, Inc., 99 FERC ¶ 61,103 (2002).

119 18 CFR 35.1(g) (2005) (“[A]ny market-based rate agreement pursuant to a tariff shall not be filed with the Commission”).

2. Market-Based Rate Code of Conduct for Affiliate Transactions Involving Power Sales and Brokering, Non-Power Goods and Services and Information Sharing

a. Current Policy.

120. The Commission requires affiliates of franchised public utilities that request market-based rate authority to submit a market-based rate code of conduct to govern the relationship between the franchised public utility and its affiliates. Historically, the purpose of the market-based rate code of conduct 120 has been to safeguard against affiliate abuse by protecting against the possible diversion of benefits or profits from franchised public utilities ( i.e. , traditional public utilities with captive ratepayers) to an affiliated entity for the benefit of shareholders. Just as the Commission has expressed concern about the potential for affiliate abuse in connection with power sales between affiliates, it also has recognized that there may be a potential for affiliate abuse through other means, such as the pricing of non-power goods and services or the sharing of market information between affiliates. 121 The market-based rate code of conduct was designed to address these concerns. The Commission has waived the market-based rate code of conduct requirement in cases where there are no captive customers, and thus no potential for affiliate abuse, or where the Commission finds that such customers are adequately protected against affiliate abuse. 122 In such cases, however, the Commission directed the utilities to notify the Commission should they obtain captive customers in the future and expressly reserved the right to reimpose the market-based rate code of conduct requirement. In the Order No

rs, and thus no potential for affiliate abuse, or where the Commission finds that such customers are adequately protected against affiliate abuse. 122 In such cases, however, the Commission directed the utilities to notify the Commission should they obtain captive customers in the future and expressly reserved the right to reimpose the market-based rate code of conduct requirement. In the Order No. 2004 Standards of Conduct rulemaking proceeding, the Commission solicited comment on whether to reform the market-based rate code of conduct but determined that such reform should take place in a separate proceeding. 123

120 The market-based rate code of conduct has at times been confused with the Commission's Standards of Conduct. The electric Standards of Conduct, originally issued in Order No. 889 et seq. , were established to govern the relationship between a public utility's transmission function and its wholesale merchant function (including affiliated power marketers) to ensure that all transmission customers have equal access to transmission information. See Open Access Same-Time Information System and Standards of Conduct, Order No. 889, 61 FR 21737 (1996), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,035 (1996), order on reh'g, Order No. 889-A, 62 FR 12484 (1997), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,049 (1997), reh'g denied, Order No. 889-B, 81 FERC ¶ 61,253 (1997), order on reh'g, Order No. 889-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000). The Standards of Conduct were recently updated by the Commission. See Standards of Conduct for Transmission Providers, Order No. 2004, 68 FR 69134 (Dec. 11, 2003), III FERC Stats. & Regs., Regulations Preambles January 2001-December 2005 ¶ 31,155 (Nov. 25, 2003), order on reh'g, Order No. 2004-A, 69 FR 23562, (Apr. 29, 2004), III FERC Stats

olicy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000). The Standards of Conduct were recently updated by the Commission. See Standards of Conduct for Transmission Providers, Order No. 2004, 68 FR 69134 (Dec. 11, 2003), III FERC Stats. & Regs., Regulations Preambles January 2001-December 2005 ¶ 31,155 (Nov. 25, 2003), order on reh'g, Order No. 2004-A, 69 FR 23562, (Apr. 29, 2004), III FERC Stats. & Regs., Regulations Preambles January 2001-December 2005 ¶ 31,161 (April 16, 2004), order on reh'g, Order No. 2004-B, 69 FR 48371 (Aug. 10, 2004), III FERC Stats. & Regs., Regulations Preambles January 2001-December 2005 ¶ 31,166 (Aug. 2, 2004), order on reh'g, Order No. 2004-C, 70 FR 284 (Jan 4., 2005), III FERC Stats. & Regs., Regulations Preambles January 2001-December 2005 ¶ 31,172 (Dec. 21, 2004), order on reh'g, Order No. 2004-D, 110 FERC ¶ 61,320 (March 23, 2005), appeal docketed sub nom., Natural Gas Fuel Supply Corp. v. FERC, No. 04-1183 (D.C. Circuit).

121 See, e.g., Potomac Electric Power Company, 93 FERC ¶ 61,240 at 61,782 (2000); Heartland, 68 FERC ¶ 61,223 at 62,062-63.

122 See, e.g., CMS Marketing, Services and Trading Co., 95 FERC ¶ 61,308 at 62,051 (2001) (granting request for cancellation of code of conduct where wholesale contracts, as amended, “cannot be used as a vehicle for cross-subsidization of affiliate power sales or sales of non-power goods and services”); Alcoa, Inc., 88 FERC ¶61,045 at 61,119 (1999) (waiving code of conduct requirement where there were no captive customers); Green Power Partners 1 LLC, 88 FERC ¶ 61,005 at 61,010-11 (1999) (waiving code of conduct requirement where there are no captive wholesale customers and retail customers may choose alternative power suppliers under retail access program).

123 Order No. 2004, at 30,853. The following entities submitted comments in the Standards of Conduct rulemaking proceeding in Docket No

no captive customers); Green Power Partners 1 LLC, 88 FERC ¶ 61,005 at 61,010-11 (1999) (waiving code of conduct requirement where there are no captive wholesale customers and retail customers may choose alternative power suppliers under retail access program).

123 Order No. 2004, at 30,853. The following entities submitted comments in the Standards of Conduct ru

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