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

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Start Preamble Start Printed Page 39904 Issued June 21, 2007.

AGENCY:

Federal Energy Regulatory Commission, Department of Energy.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is amending 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 codifying and, in certain respects, revising its current standards for market-based rates for sales of electric energy, capacity, and ancillary services. The Commission is retaining several of the core elements of its current standards for granting market-based rates and revising them in certain respects. The Commission also adopts a number of reforms to streamline the administration of the market-based rate program.

DATES:

Effective Date: This rule will become effective September 18, 2007.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

Debra A. Dalton (Technical Information), Office of Energy Markets and Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6253.

Elizabeth Arnold (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-8818.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph Nos.
I. Introduction1
II. Background7
III. Overview of Final Rule12
IV. Discussion33
A. Horizontal Market Power33
1. Whether to Retain the Indicative Screens33
2. Indicative Market Share Screen Threshold Levels and Pivotal Supplier Application Period80
a. Market Share Threshold82
b. Pivotal Supplier Application Period94
3. DPT Criteria96
4. Other Products and Models118
5. Native Load Deduction125
a. Market Share Indicative Screen125
b. Pivotal Supplier Indicative Screen143
c. Clarification of Definition of Native Load150
d. Other Native Load Concerns153
6. Control and Commitment156
a. Presumption of Control164
b. Requirement for Sellers to have a Rate on File212
7. Relevant Geographic Market215
a. Default Relevant Geographic Market215
b. NERC's Balancing Authority Area and Default Geographic Area247
c. Additional Guidelines for Alternative Geographic Market and Flexibility253
d. Specific Issues Related to Power Pools and SPP279
e. RTO/ISO Exemption285
8. Use of Historical Data292
9. Reporting Format302
10. Exemption for New Generation (Formerly Section 35.27(a) of the Commission's Regulations)307
a. Elimination of Exemption in Section 35.27(a)307
b. Grandfathering327
c. Creation of a Safe Harbor335
11. Nameplate Capacity339
12. Transmission Imports346
a. Use of Historical Conditions and OASIS Practices348
b. Use of Total Transfer Capability (TTC)363
c. Accounting for Transmission Reservations365
d. Allocation of Transmission Imports based on Pro Rata Shares of Seller's Uncommitted Generation Capacity370
e. Miscellaneous Comments376
f. Required SIL Study for DPT Analysis382
13. Procedural Issues387
B. Vertical Market Power397
1. Transmission Market Power400
a. OATT Requirement403
b. OATT Violations and MBR Revocation411
c. Revocation of Affiliates' MBR Authority422
2. Other Barriers to Entry428
3. Barriers Erected or Controlled by Other Than The Seller452
4. Planning and Expansion Efforts454
5. Monopsony Power459
C. Affiliate Abuse464
1. General Affiliate Terms and Conditions464
Start Printed Page 39905
a. Codifying Affiliate Restrictions in Commission Regulations464
b. Definition of “Captive Customers”469
c. Definition of “Non-Regulated Power Sales Affiliate”484
d. Other Definitions496
e. Treating Merging Companies as Affiliates499
f. Treating Energy/Asset Managers as Affiliates503
g. Cooperatives518
2. Power Sales Restrictions529
3. Market-Based Rate Affiliate Restrictions (formerly Code of Conduct) for Affiliate Transactions Involving Power Sales and Brokering, Non-Power Goods and Services and Information Sharing544
a. Uniform Code of Conduct/Affiliate Restrictions—Generally546
b. Exceptions to the Independent Functioning Requirement553
c. Information Sharing Restrictions570
d. Definition of “Market Information”590
e. Sales of Non-Power Goods or Services595
f. Service Companies or Parent Companies Acting on Behalf of and for the Benefit of a Franchised Public Utility599
D. Mitigation604
1. Cost-Based Rate Methodology606
a. Sales of One Week or Less606
b. Sales of more than one week but less than one year632
c. Sales of one year or greater658
d. Alternative methods of mitigation660
2. Discounting699
3. Protecting Mitigated Markets720
a. Must Offer720
b. First-Tier Markets776
c. Sales that Sink in Unmitigated Markets794
d. Proposed Tariff Language825
E. Implementation Process832
1. Category 1 and 2 Sellers836
a. Establishment of Category 1 and 2 Sellers836
b. Threshold for Category 1 Sellers and Other Proposed Modifications845
2. Regional Review and Schedule869
F. MBR Tariff897
1. Tariff of General Applicability901
2. Placement of Terms and Conditions925
3. Single Corporate Tariff928
G. Legal Authority938
1. Whether Market-Based Rates Can Satisfy the Just and Reasonable Standard Under the FPA938
Consistency of Market-based Rate Program with FPA Filing Requirements956
2. Whether Existing Tariffs Must Be Found to Be Unjust and Unreasonable, and Whether the Commission Must Establish a Refund Effective Date972
H. Miscellaneous975
1. Waivers975
a. Accounting Waivers979
b. Timing988
c. Part 34 Waivers Blanket Authorizations993
2. Sellers Affiliated with a Foreign Utility1000
3. Change in Status1008
a. Fuel Supplies1011
b. Transmission Outages1019
c. Control1027
d. Triggering Events1033
e. Timing of Reporting1035
f. Sellers Affiliated with a Foreign Utility1040
4. Third-Party Providers of Ancillary Services1046
a. Internet Postings and Reporting Requirements1052
b. Pricing for Ancillary Services in RTOs/ISOs1062
5. Reactive Power and Real Power Losses1072
a. Reactive Power1073
b. Real Power Losses1075
V. Section-by-Section Analysis of Regulations1077
VI. Information Collection Statement1105
VII. Environmental Analysis1124
VIII. Regulatory Flexibility Act1125
IX. Document Availability1129
X. Effective Date and Congressional Notification1132
Regulatory Text
Appendix A to Subpart H: Standard Screen Format
Appendix B to Subpart H: Corporate Entities and Assets sample appendix
Appendix C to the Final Rule: Required Provisions of the Market-Based Rate Tariff
Start Printed Page 39906
Appendix D to the Final Rule: Regions and Schedule for Regional Market power Update Process
Appendix E to the Final Rule: List of Commenters and Acronyms
Attachment A to the Final Rule: MOELLER, Commissioner, dissenting in part

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

I. Introduction

1. On May 19, 2006, the Commission issued a Notice of Proposed Rulemaking (NOPR), pursuant to sections 205 and 206 of the Federal Power Act (FPA),[1] in which the Commission proposed to amend its regulations governing market-based rate authorizations for wholesale sales of electric energy, capacity and ancillary services by public utilities. In the NOPR, the Commission proposed to modify all existing market-based authorizations and tariffs so they would reflect any new requirements ultimately adopted in the Final Rule. After considering the comments received in response to the NOPR, the Commission adopts in many respects the proposals contained in the NOPR, but with a number of modifications.

2. This Final Rule represents a major step in the Commission's efforts to clarify and codify its market-based rate policy by providing a rigorous up-front analysis of whether market-based rates should be granted, including protective conditions and ongoing filing requirements in all market-based rate authorizations, and reinforcing its ongoing oversight of market-based rates. The specific components of this rule, in conjunction with other regulatory activities, are designed to ensure that market-based rates charged by public utilities are just and reasonable. There are three major aspects of the Commission's market-based rate regulatory regime.

3. First is the analysis that is the subject of this rule: whether a market-based rate seller or any of its affiliates has market power in generation or transmission and, if so, whether such market power has been mitigated.[2] If the seller is granted market-based rates, the authorization is conditioned on: affiliate restrictions governing transactions and conduct between power sales affiliates where one or more of those affiliates has captive customers; a requirement to file post-transaction electric quarterly reports (EQRs) containing specific information about contracts and transactions; a requirement to file any change of status; and a requirement for all large sellers to file triennial updates.[3]

4. Second, for wholesale sellers that have market-based rate authority and sell into day ahead or real-time organized markets administered by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs), they do so subject to specific RTO/ISO market rules approved by the Commission and applicable to all market participants. These rules are designed to help ensure that market power cannot be exercised in those organized markets and include additional protections (e.g., mitigation measures) where appropriate to ensure that prices in those markets are just and reasonable. Thus, a seller in such markets not only must have an authorization based on an analysis of that individual seller’s market power, but it must also abide by additional rules contained in the RTO/ISO tariffs.

5. Third, the Commission, through its ongoing oversight of market-based rate authorizations and market conditions, may take steps to address seller market power or modify rates. For example, based on its review of triennial market power updates required of market-based rate sellers, its review of EQR filings made by market-based rate sellers, and its review of required notices of change in status, the Commission may institute a section 206 proceeding to revoke a seller's market-based rate authorization if it determines that the seller may have gained market power since its original market-based rate authorization. The Commission may also, based on its review of EQR filings or daily market price information, investigate a specific utility or anomalous market circumstances to determine whether there has been any conduct in violation of RTO/ISO market rules or Commission orders or tariffs, or any prohibited market manipulation, and take steps to remedy any violations. These steps could include, among other things, disgorgement of profits and refunds to customers if a seller is found to have violated Commission orders, tariffs or rules, or a civil penalty paid to the United States Treasury if a seller is found to have engaged in prohibited market manipulation or to have violated Commission orders, tariffs or rules.

6. The Commission recognizes that several recent court decisions by the United States Court of Appeals for the Ninth Circuit [4] have created some uncertainty for sellers transacting pursuant to our market-based rate program. The cases raise issues with respect to the circumstances under which sellers' pre-authorized market-based rate sales may be subject to retroactive refunds and the circumstances under which buyers might be able to invalidate or modify contracts based on the argument that the contracts were entered into at a time when markets were dysfunctional. The Commission's first and foremost duty is to protect customers from unjust and unreasonable rates; however, we recognize that uncertainties regarding rate stability and contract sanctity can have a chilling effect on investments and a seller's willingness to enter into long-term contracts and this, in turn, can harm customers in the long run. The Commission recently provided guidance in this regard, noting that these Ninth Circuit decisions addressed a unique set of facts and a market-based rate program that has undergone substantial improvement since 2001, and reiterating that an ex ante finding of the absence of market power, coupled with the EQR filing and effective regulatory oversight qualifies as sufficient prior review for market-based rate contracts to satisfy the notice and filing requirements of FPA section 205.[5] Through this Final Rule, the Commission is clarifying and further Start Printed Page 39907improving its market-based rate program. Moreover, the Commission will explore ways to continue to improve its market-based rate program and processes to assure appropriate customer protections but at the same time provide greater regulatory and market certainty for sellers in light of the above court opinions.

II. Background

7. 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.

8. The Commission initiated the instant rulemaking proceeding in April 2004 to consider “the adequacy of the current 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.

9. On April 14, 2004, the Commission issued an order modifying the then-existing generation market power analysis and its policy governing market power mitigation, on an interim basis.[7] The April 14 Order adopted a policy that provided 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. On July 8, 2004, the Commission addressed 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. Over the next year, the Commission convened four technical conferences, seeking input regarding all four prongs of the analysis.

10. On May 19, 2006, the Commission issued a NOPR in this proceeding.[8] The Commission explained that refining and codifying effective standards for market-based rates would help customers by ensuring that they are protected from the exercise of market power and would also provide greater certainty to sellers seeking market-based rate authority.

11. The regulations proposed in the NOPR adopted in most respects the Commission's existing standards for granting market-based rates, and proposed to streamline certain aspects of its filing requirements to reduce the administrative burdens on sellers, customers and the Commission. The Commission received over 100 comments and reply comments in response to the NOPR. A list of commenters is attached as Appendix E.

III. Overview of Final Rule

12. In this Final Rule, the Commission revises and codifies in the Commission's regulations the standards for market-based rates for wholesale sales of electric energy, capacity and ancillary services. The Commission also adopts a number of reforms to streamline the administration of the market-based rate program. As set forth below, the Final Rule adopts in many respects the proposals contained in the NOPR, but with a number of modifications.

Horizontal Market Power

13. In this Final Rule, the Commission adopts, with certain modifications, two indicative market power screens (the uncommitted market share screen (with a 20 percent threshold) and the uncommitted pivotal supplier screen), each of which will serve as a cross check on the other to determine whether sellers may have market power and should be further examined. Sellers that fail either screen will be rebuttably presumed to have market power. However, such sellers will have full opportunity to present evidence (through the submission of a Delivered Price Test (DPT) analysis) demonstrating that, despite a screen failure, they do not have market power, and the Commission will continue to weigh both available economic capacity and economic capacity when analyzing market shares and Hirschman-Herfindahl Indices (HHIs).

14. With regard to control over generation capacity, the Commission finds that the determination of control is appropriately based on a review of the totality of circumstances on a fact-specific basis. No single factor or factors necessarily results in control. The Commission will require a seller to make an affirmative statement as to whether a contractual arrangement (energy management agreement, tolling agreement, specific contractual terms, etc.) transfers control and to identify the party or parties it believes controls the generation facility. Regarding a presumption of control, the Commission will continue its practice of attributing control to the owner absent a contractual agreement transferring such control, and we provide guidance as to how we will consider jointly-owned facilities.

15. The Commission adopts its current approach with regard to the default relevant geographic market, with some modifications. In particular, the Commission will continue to use a seller's control area (balancing authority area) [9] or the RTO/ISO market, as applicable, as the default relevant geographic market. However, where the Commission has made a specific finding that there is a submarket within an RTO, that submarket becomes the default relevant geographic market for sellers located within the submarket for purposes of the market-based rate analysis. The Commission also provides guidance as to the factors the Commission will consider in evaluating whether, in a particular case, to adopt an alternative geographic market instead of relying on the default geographic market.

16. The Commission modifies 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 clarifies that native load can only include load attributable to native load customers based on the definition of native load commitment in § 33.3(d)(4)(i) of the Commission's regulations. In addition, sellers are Start Printed Page 39908given the option of using seasonal capacity instead of nameplate capacity.

17. The Commission retains the snapshot in time approach based on historical data for both the indicative screens and the DPT analysis and disallows projections to that data. A standard reporting format is adopted for sellers to follow when summarizing their analysis.

18. The Commission modifies the treatment of newly constructed generation and adopts an approach that requires all sellers to perform a horizontal analysis for the grant of market-based rate authority.

19. With regard to simultaneous transmission import limit studies (SILs), the Commission adopts the requirement that the SIL study be used as a basis for transmission access for both the indicative screens and the DPT analysis. Further, the Commission clarifies that the SIL study as shown in Appendix E of the April 14 Order is the only study that meets our requirements. The Commission provides guidance regarding how to perform the SIL study, including accounting for specific OASIS practices.

20. Finally, the Commission adopts procedures under which intervenors in section 205 proceedings may obtain expedited access to Critical Energy Infrastructure Information (CEII) or other information for which privileged treatment is sought.

Vertical Market Power

21. With regard to vertical market power and, in particular, transmission market power, the Commission continues the current policy under which an open access transmission tariff (OATT) is deemed to mitigate a seller's transmission market power. However, in recognition of the fact that OATT violations may nonetheless occur, the Commission states that a finding of a nexus between the specific facts relating to the OATT violation and the entity's market-based rate authority may subject the seller to revocation of its market-based rate authority or other remedies the Commission may deem appropriate, such as disgorgement of profits or civil penalties. In addition, the Commission creates a rebuttable presumption that all affiliates of a transmission provider should lose their market-based rate authority in each market in which their affiliated transmission provider loses its market-based rate authority as a result of an OATT violation.

22. With regard to other barriers to entry, the Commission adopts the NOPR proposal to consider a seller's ability to erect other barriers to entry as part of the vertical market power analysis, but modifies the requirements when addressing other barriers to entry. The Commission also provides clarification regarding the information that a seller must provide with respect to other barriers to entry (including which inputs to electric power production the Commission will consider as other barriers to entry). The Commission adopts a rebuttable presumption that ownership or control of, or affiliation with an entity that owns or controls, intrastate natural gas transportation, intrastate natural gas storage or distribution facilities; sites for generation capacity development; and sources of coal supplies and the transportation of coal supplies such as barges and rail cars do not allow a seller to raise entry barriers, but intervenors are allowed to demonstrate otherwise. The Final Rule also requires a seller to provide a description of its ownership or control of, or affiliation with an entity that owns or controls, intrastate natural gas transportation, intrastate natural gas storage or distribution facilities; sites for generation capacity development; and sources of coal supplies and the transportation of coal supplies such as barges and rail cars. The Commission will require sellers to provide this description and to make an affirmative statement that they have not erected barriers to entry into the relevant market and will not erect barriers to entry into the relevant market. The Final Rule clarifies that the obligation in this regard applies both to the seller and its affiliates, but is limited to the geographic market(s) in which the seller is located.

Affiliate Abuse

23. With regard to affiliate abuse, the Commission adopts the NOPR proposal to discontinue considering affiliate abuse as a separate “prong” of the market-based rate analysis and instead to codify affiliate restrictions in the Commission's regulations and address affiliate abuse by requiring that the provisions provided in the affiliate restrictions be satisfied on an ongoing basis as a condition of obtaining and retaining market-based rate authority. As codified in this Final Rule, the affiliate restrictions include a provision prohibiting power sales between a franchised public utility with captive customers and any market-regulated power sales affiliates[10] without first receiving Commission authorization for the transaction under section 205 of the FPA. The Commission also codifies as part of the affiliate restrictions the requirements that previously have been known as the market-based rate “code of conduct” (governing the separation of functions, the sharing of market information, sales of non-power goods or services, and power brokering), as clarified and modified in this Final Rule. The Commission modifies certain of these provisions, including separation of functions and information sharing, consistent with certain requirements and exceptions contained in the Commission's standards of conduct.[11] In the Final Rule the Commission defines “captive customers” as “any wholesale or retail electric energy customers served under cost-based regulation” and provides clarification that the definition of “captive customers” does not include those customers who have retail choice, i.e., the ability to select a retail supplier based on the rates, terms and conditions of service offered. In addition, among other clarifications, the Commission clarifies and modifies the definition of “non-regulated power sales affiliate,” and changes the term to “market-regulated power sales affiliate.”

24. The Commission also provides clarification as to what types of affiliate transactions are permissible and the criteria used to make those decisions, and how the Commission will treat merging partners. In addition, the Commission codifies in the regulations a prohibition on the use of third-party entities, including energy/asset managers, to circumvent the affiliate restrictions, but does not adopt the NOPR proposal to treat energy/asset managers as affiliates. The Commission also provides clarification regarding the Commission's market-based rate policies as they relate to cooperatives.

Mitigation

25. With regard to mitigation, in the Final Rule the Commission retains the incremental cost plus 10 percent methodology as the default mitigation for sales of one week or less; the default mitigation rate for mid-term sales (sales of more than one week but less than one year) priced at an embedded cost “up to” rate reflecting the costs of the unit(s) expected to provide the service; and the existing policy for sales of one year or more (long-term) sales.[12] The Start Printed Page 39909Commission will continue to allow sellers to propose alternative cost-based methods of mitigation tailored to their particular circumstances. The Final Rule also states that the Commission will make its stacking methodology available for the public.[13] In addition, the Commission will continue the practice of allowing discounting and will permit selective discounting by mitigated sellers provided that the sellers do not use such discounting to unduly discriminate or give undue preference.

26. The Commission concludes that use of the Western Systems Power Pool (WSPP) Agreement may be unjust, unreasonable or unduly discriminatory or preferential for certain sellers. Therefore, in an order being issued concurrently with this Final Rule, the Commission is instituting a proceeding under section 206 of the FPA to investigate whether, for sellers found to have market power or presumed to have market power in a particular market, the WSPP Agreement rate for coordination energy sales is just and reasonable in such market.

27. The Commission does not impose an across-the-board “must offer” requirement for mitigated sellers. While wholesale customer commenters have raised concerns relating to their ability to access needed power, the Commission concludes that there is insufficient record evidence to support instituting a generic “must offer” requirement.

28. The Commission limits mitigation to the market in which the seller has been found to possess, or chosen not to rebut the presumption of, market power and does not place limitations on a mitigated seller's ability to sell at market-based rates in areas in which the seller has not been found to have market power.

29. Finally, regarding mitigation, the Final Rule allows mitigated sellers to make market-based rate sales at the metered boundary between a mitigated balancing authority area and a balancing authority area in which the seller has market-based rate authority under the conditions set forth herein, including a record retention requirement, and provides a tariff provision to allow for such sales.

Implementation Process

30. The Commission adopts the NOPR proposal to create a category of sellers (Category 1 sellers) that are exempt from the requirement to automatically submit updated market power analyses, with certain clarifications and modifications. In addition, the Commission adopts the NOPR proposal to implement a regional approach to updated market power analyses, but reduces the number of regions from nine to six.

31. As for a standardized tariff, the Commission does not adopt the NOPR proposal to adopt a market-based rate tariff of general applicability that all market-based rate sellers will be required to file as a condition of market-based rate authority and to require each corporate family to have only one tariff, with all affiliates with market-based rate authority separately identified in the tariff. Instead, the Commission adopts specific market-based rate tariff provisions that the Commission will require to be part of a seller's market-based rate tariff. However, the Commission will allow a seller to include seller specific terms and conditions in its market-based rate tariff, but the Commission will not review any of these provisions, as they are presumed to be just and reasonable based on the Commission's finding that the seller and its affiliates lack or have adequately mitigated market power in the relevant market.

Miscellaneous Issues

32. The Commission also provides clarifications in the Final Rule with regard to accounting waivers, Part 34 blanket authorizations, sellers affiliated with foreign entities, and the change in status reporting requirement. Further, the Commission abandons the posting requirements for third party sellers of ancillary services at market-based rates as redundant of other reporting requirements.

IV. Discussion

A. Horizontal Market Power

1. Whether To Retain the Indicative Screens

33. As discussed in detail below, the Commission is adopting in this Final Rule two indicative horizontal market power screens, each of which will serve as a cross-check on the other to determine whether sellers may have market power and should be further examined. Although some sellers disagree with the use of two screens or find flaws in them, we conclude that this conservative approach will allow the Commission to more readily identify potential market power. Sellers that fail either screen will be rebuttably presumed to have market power. However, such sellers will have full opportunity to present evidence (through the submission of a DPT analysis) demonstrating that, despite a screen failure, they do not have market power. No screen is perfect, but we believe this approach appropriately balances the need to protect against market power with the desire not to place unnecessary filing burdens on utilities.

34. The first screen is the wholesale market share screen, which measures for each of the four seasons whether a seller has a dominant position in the market based on the number of megawatts of uncommitted capacity owned or controlled by the seller as compared to the uncommitted capacity of the entire relevant market.[14]

35. The second screen is the pivotal supplier screen, which evaluates the potential of a seller to exercise market power based on uncommitted capacity at the time of the balancing authority area's annual peak demand. This screen focuses on the seller's ability to exercise market power unilaterally. It examines whether the market demand can be met absent the seller during peak times. A seller is pivotal if demand cannot be met without some contribution of supply by the seller or its affiliates.[15]

36. Use of the two screens together enables the Commission to measure market power at both peak and off-peak times, and to examine the seller's ability to exercise market power unilaterally and in coordinated interaction with other sellers. Use of the two screens, therefore, provides a more complete picture of a seller's ability to exercise market power.[16]

37. As discussed more fully in the following sections, with regard to determining the total supply in the relevant market, the horizontal market power analysis centers on and examines the balancing authority area where the seller's generation is physically located. Total supply is determined by adding the total amount of uncommitted capacity located in the relevant market (including capacity owned by the seller and competing suppliers) with that of uncommitted supplies that can be imported (limited by simultaneous transmission import capability) into the relevant market from the first-tier markets.

38. Uncommitted capacity is determined by adding the total nameplate or seasonal capacity [17] of Start Printed Page 39910generation owned or controlled through contract and firm purchases, less operating reserves, native load commitments and long-term firm sales.[18] Uncommitted capacity from a seller's remote generation (generation located in an adjoining balancing authority area) should be included in the seller's total uncommitted capacity amounts. Any simultaneous transmission import capability should first be allocated to the seller's uncommitted remote generation. Any remaining simultaneous transmission import capability would then be allocated to any uncommitted competing supplies.

39. Capacity reductions as a result of operating reserve requirements should be no higher than State and Regional Reliability Council operating requirements for reliability (i.e., operating reserves). Any proposed amounts that are higher than such requirements must be fully supported and will be considered on a case-by-case basis. Moreover, if an intervenor provides conclusive evidence that a seller did not in actual practice comply with the NERC or regional reliability council operating reserve requirements, then we will take this into account in determining the amount of the operating reserve deduction. However, we emphasize that we expect each utility to meet its NERC and regional reliability council reserve requirements, and that absent a clear showing to the contrary by an intervenor, the required operating reserve requirement is what we will use as the deduction in the market-based rate calculation.[19]

40. The Commission does not expect that sellers will have planned generation outages scheduled for the annual peak load day. However, on a case-by-case basis, the Commission will consider credible evidence that planned generation outages for the peak load day of the year should be included based on the particular circumstances of the seller.[20]

41. With regard to the pivotal supplier analysis, after computing the total uncommitted supply available to serve the relevant market, the next step in this analysis involves identifying the wholesale market. The proxy for the wholesale load is the annual peak load (needle peak) less the proxy for native load obligation (i.e., the average of the daily native load peaks during the month in which the annual peak load day occurs). Peak load is the largest electric power requirement (based on net energy for load) during a specific period of time, usually integrated over one clock hour and expressed in megawatts, for the native load and firm wholesale requirements sales.

42. To calculate the net uncommitted supply available to compete at wholesale, the pivotal supplier analysis deducts the wholesale load from the total uncommitted supply. If the seller's uncommitted capacity is less than the net uncommitted supply, the seller satisfies the pivotal supplier portion of the generation market power analysis and passes the screen. 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.

43. With regard to the wholesale market share analysis, which measures for each of the four seasons whether a seller has a dominant position in the market based on the number of megawatts of uncommitted capacity owned or controlled by the seller as compared to the uncommitted capacity of the entire relevant market, uncommitted capacity amounts are used, as described above, with the following variation. Planned outages (that were done in accordance with good utility practice) for each season will be considered. Planned outage amounts should be consistent with those as reported in FERC Form No. 714. To determine the amount of planned outages for a given season, the total number of MW-days of outages is divided by the total number of days in the season. For example, if 500 MW of generation that is out for six days during the winter period the calculation of planned outages would be: (500 MW × 6)/91 or 33 MW.

44. The market share analysis adopts an initial threshold of 20 percent. That is, a seller who has less than a 20 percent market share in the relevant market for all seasons will be considered to satisfy the market share analysis.[21] A seller with a market share of 20 percent or more in the relevant market for any season will have a rebuttable presumption of market power but can present historical evidence to show that the seller satisfies our generation market power concerns.

Commission Proposal

45. In the NOPR, the Commission proposed to retain the indicative screens (pivotal supplier and market share) to assess horizontal market power that were initially adopted in April 2004.[22] Because the indicative screens are intended only to identify the sellers that require further review, the Commission proposed to retain the 20 percent threshold for the wholesale market share indicative screen, stating that the 20 percent market share threshold strikes the right balance in seeking to avoid both “false negatives” and “false positives.” The Commission also proposed to continue to measure pivotal suppliers at the time of the annual peak load in the pivotal supplier indicative screen, which is the most likely point in time that a seller will be a pivotal supplier. For this reason, the Commission did not propose to expand the pivotal supplier analysis to other time periods.

Comments

46. Numerous commenters question whether the Commission should retain the current indicative screens in whole or in part. For example, Southern, Duke and EEI advocate abandoning the market share indicative screen altogether. They argue that the market share indicative screen is “fatally flawed” because it does not take into account wholesale demand in the relevant market [23] which makes it difficult for traditional utilities outside of RTOs/ISOs to pass.[24] E.ON. US. and PNM/Tucson separately argue that one must consider the level of demand that is seeking supply and, more particularly, what ability sellers have to exercise market power over those buyers.[25] In this regard, E.ON. US. and Start Printed Page 39911PNM/Tucson argue that to the extent the market share screen does not consider wholesale demand, it is not a useful indicator, and in fact is almost universally a false indicator of the ability of a seller to exercise market power over demand. Also, EEI argues that because of design flaws inherent in the market share screen as well as the negative impact that the use of this test has had since 2004 on the development of competitive wholesale markets (through the inappropriate exclusion of the majority of non-RTO utilities from participating in that market), the market share screen should be eliminated for all market power screening and analysis purposes.[26]

47. EEI contends that the Commission should use only the pivotal supplier screen for indicative screening purposes and the DPT pivotal supplier and market concentration analyses for the purposes of rebutting the presumption of generation market power that would result from the failure of the indicative pivotal supplier screen. EEI argues that if the Commission continues to use the market share screen as an initial screen, the Commission should not include a market share test as a component of any subsequent DPT analysis of market power.

48. E.ON U.S. and PNM/Tucson generally agree, stating that market share is an unreliable measure of market power in competitive energy markets and that the courts have long recognized that market share is not a reliable indicator of market power in regulated markets.[27] In particular, E.ON U.S. and PNM/Tucson argue that even a marginal failure of the market share screen results in a rebuttable presumption of market power that has tremendous consequences by forcing sellers to proceed to costly and time-consuming DPT analysis or agree to mitigation. As a result, the “false positives” arising from the market share screen dampen the vigor of competitive wholesale market participation by unnecessarily curtailing the market-based authority of entities that, in fact, lack market power (to the extent such entities choose not to pursue a costly and uncertain effort to rebut the presumption of market power created by the screen failure).[28]

49. Duke and Southern suggest that a wholesale contestable load analysis (also described as a “competitive alternatives” analysis) [29] should be added to the indicative screens, which would consider the amount of excess market supply available to serve the amount of wholesale demand seeking supply.[30] Generally, if available non-applicant supply is at least twice the contestable load, advocates of the contestable load analysis believe that is sufficient to make a finding that the market is competitive.[31] Other commenters agree that the market share indicative screen can diminish competition because sellers that are subjects of an FPA section 206 investigation tend to choose mitigation rather than challenge the presumption of market power.[32]

50. Duke argues that the Commission has yet to establish a need for using the market share indicative screen in addition to the pivotal supplier indicative screen in assessing the potential for the exercise of generation market power. In this regard, Duke argues that the Commission itself acknowledged in the April 14 Order (establishing the new indicative market power screens) that if a supplier passes the pivotal supplier indicative screen, it would not be able to exercise generation market power. Thus, Duke concludes that the use of any other indicative screens would appear to be redundant and an unwarranted burden on market-based rate sellers.[33] Further, Duke submits that neither of the rationales originally cited by the Commission in support of the market share screen—its ability to identify “coordinating behavior,” or its ability to detect the exercise of market power in off-peak periods—has been validated. In this regard, Duke submits that the potential for “coordinating behavior” should consider overall market concentration levels as measured by HHIs and in any event, such behavior is already subject to oversight and substantial penalties under the antitrust laws and the Commission's recently adopted rule prohibiting market manipulation. Further, Duke claims that the nearly universal failure rate of load-serving utilities under the market share indicative screen in their control areas underscores its limited value as an indicator of off-peak market power.[34]

51. Duke states that a review of filings by vertically integrated utilities that are not RTO participants shows that the vast majority have failed the market share screen in their control areas, and most have subsequently been forced to adopt some form of cost-based mitigation for wholesale sales in that market. Yet Duke is unaware of any credible evidence suggesting that any form of generation market power has been exercised by these utilities. Instead, Duke states that the Commission has revoked market-based rate authority and imposed mitigation on the basis of indicative screen results that suggest the potential for market power.[35] APPA/TAPS counter that the Commission should not limit its response to market power only to instances of its actual exercise; they note that the Commission considers whether a seller and its affiliates have market power or have mitigated it, not whether it has been exercised.[36]

52. Another commenter suggests substituting the HHI for the market share indicative screen or supplementing the indicative screens with the HHI, reasoning that the market must be evaluated, not just the individual market share.[37]

53. Southern states that the Commission should rely upon any indicative screens only in conjunction with an optional “expedited track” safe harbor review. Under Southern's proposal, the indicative screens would be voluntary and those submitting to and passing the screens would be permitted to retain or obtain market-based rate authority, subject to a proceeding under section 206 of the FPA, under which the party seeking to challenge the rate must submit substantial evidence justifying revocation. If a seller fails the screen(s), or if it elects to submit a DPT rather than voluntarily submit the indicative screens, then a robust market power assessment should be used to determine whether (or the extent to which) the Start Printed Page 39912seller should be permitted to sell power at market-based rates.

54. In Southern's view, failure of the indicative screens should not give rise to a presumption of market power.[38] Southern argues that mere failure to pass a screen, without more robust market power assessments, is an insufficient basis upon which to base a presumption of market power. Southern argues this is because, in the case of the pivotal supplier screen, the Commission itself admits that it does not give a full picture and that the DPT provides better information. With regard to the market share screen, Southern argues that the market share screen has even more basic problems as an indicator of market power. Southern states that, because of the market share analysis' serious flaws, the great majority of integrated franchised public utilities inevitably will fail the market share screen. Thus, with respect to integrated franchised public utilities, the market share screen serves no real purpose other than to state the obvious: Integrated franchised public utilities build and maintain adequate resources to serve their native loads and inevitably will have market shares greater than 20 percent in their home control areas under the Commission's computational procedures. Southern states that, since the DPT reduces the level of false positives and is a more definitive means for determining the existence of market power, the Commission should use the DPT as the default test.[39] PPL agrees with Southern's proposal that the indicative screens be made voluntary.[40]

55. Southern states that if the market share screen is retained, it should be adjusted for forced outages because such capacity is not available. Southern also notes that forced outages are tracked and reported to the North American Electric Reliability Corporation (NERC), which presents generating unit availability statistics data for generator unit groups.[41]

56. NRECA disagrees with Southern's proposal, stating that forced outage deductions have little effect when applied to all sellers.[42] It also believes that sellers do not make forced outage deductions in long-term contracts; therefore, it is inappropriate to make the deduction for the market power tests.

57. While EPSA does not agree with some of the Commission's proposed changes to the horizontal analysis in the NOPR (i.e., changes to the post-1996 exemption and the native load proxy), in general, EPSA supports the two indicative screens as a means for indicating that an entity might have market power.

58. EPSA notes that it is time to move beyond the battle over crafting the perfect screens, arguing: (1) It is likely no such perfect screens exist, as evidenced by the fact that stakeholders and the Commission have gone through several iterations to get to today's screens; and (2) in the end, the screens are only indicative measures. EPSA notes that failure of one or both of the screens does not brandish an entity with market power, but merely raises a flag that further analysis is necessary in order to assess an entity's ability to exercise market power. The current state of wholesale electricity markets, EPSA argues, requires indicative screens that are neither definitive nor an aperture letting everything pass, but rather a sieve that catches potential problems for further examination. EPSA agrees with retention of both of the current indicative screens and the “next steps” set forth for those entities that fail one or both of those screens.

59. Several other commenters also support retention of the indicative screens. Some of these commenters state that, because section 205 of the FPA requires rates to be just and reasonable, a market share indicative screen is appropriate to ensure that outcome. NRECA adds that “[b]ecause of past or present State regulation, many traditional public utilities have acquired dominant market shares of generation capacity in their own control areas—sufficient to enable them to exercise market power absent regulation of their behavior. NRECA submits that regardless of the cause the incumbent public utilities will remain the dominant firms in their own control areas absent significant new market entry in the form of new generation construction in the control area by independent firms, or significant transmission construction to permit entry by generation outside the control area. Morgan Stanley also favors retaining the market share indicative screen, noting that failure of the market share indicative screen does not mean the process is unfair, and asserting that exclusive reliance on the pivotal supplier indicative screen may compromise market power detection.[43]

60. With regard to the suggestion that the Commission adopt a contestable load analysis, several commenters criticize the contestable load analysis, stating that it changes the focus of the market power analysis from the seller to the market. They counter that the contestable load analysis is unsound, with APPA/TAPS citing Federal Trade Commission (FTC) comments in this proceeding that such an analysis is flawed.[44] NRECA states that commenters have not provided sufficient justification for using a contestable load analysis.

61. With regard to Southern's suggestion that the indicative screens be made voluntary and function as a safe harbor, such that screen failure would simply mean that further review of the seller would be appropriate, but not merit a section 206 investigation, NRECA states that Southern's argument is contrary to law. NRECA argues that, as the proponent of a tariff allowing it to charge market-based rates, the public utility has the burden of proof to demonstrate that its wholesale rates will be disciplined by competition. NRECA submits that failing the indicative screens indicates that the seller has not yet provided “ ‘empirical proof’ ” that competition will drive down prices to just and reasonable levels as the FPA requires.[45]

Commission Determination

62. We adopt the proposal in the NOPR to retain both of the indicative screens. The intent of the indicative screens is to identify the sellers that raise no horizontal market power concerns and can otherwise be considered for market-based rate authority. At the same time, sellers that do not pass the indicative screens are allowed to provide additional analysis Start Printed Page 39913for Commission consideration. Because the indicative screens are intended to screen out only those sellers that raise no horizontal market power concerns, as opposed to other sellers that raise concerns but may not necessarily possess horizontal market power, we find it appropriate to use conservative criteria and to rely on more than one screen. A conservative approach at the indicative screen stage of the proceeding is warranted because, if a seller passes both of the indicative screens, there is a rebuttable presumption that it does not possess horizontal market power.

63. The rebuttable presumption of horizontal market power that attaches to sellers failing one of the indicative screens is just that—a rebuttable presumption. It is not a definitive finding by the Commission; sellers are provided with several procedural options including the right to challenge the market power presumption by submitting a DPT analysis, or, alternatively, sellers can accept the presumption of market power and adopt some form of cost-based mitigation.[46] Accordingly, we will adopt the proposal to continue to use the two indicative screens and find that failure of either indicative screen creates a rebuttable presumption of market power. We reiterate our finding that “[f]ailure to pass either of the indicative screens * * * will constitute a prima facie showing that the rates charged by the seller pursuant to its market-based rate authority may have become unjust and unreasonable and that continuation of the seller's market-based rate authority may no longer be just and reasonable.” [47]

64. This approach, contrary to the claims of several commenters, will help to further competitive markets by allowing sellers without market power to sell power at market-based rates, and it will similarly give customers security that sellers that fail the screens are required to submit to further scrutiny and/or mitigation.

65. The pivotal supplier and market share indicative screens measure different aspects of market power. As the Commission stated in the April 14 Order, the uncommitted pivotal supplier indicative screen measures the ability of a firm to dominate the market at peak periods. The uncommitted market share analysis provides a measure as to whether a supplier may have a dominant position in the market, which is another indicator of potential unilateral market power and the ability of a seller to effect coordinated interaction with other sellers. The market share screen is also useful in measuring market power because it measures a seller's size relative to others in the market, in particular, the seller's share of generating capacity uncommitted after accounting for its obligations to serve native load. The market share screen provides a snapshot of these market shares in each season of the year. Taken together, the indicative screens can measure a seller's market power at both peak and off-peak times.[48] Both market share and pivotal supplier indicative screens are appropriate first steps for the Commission to use in determining if it needs a more robust analysis to determine whether the seller has market power. We conclude that having two screens as backstops to one another will better assist us in determining the existence of potential market power. Accordingly, we reject the suggestion of several commenters to abandon the market share indicative screen. We will retain both the pivotal supplier and market share indicative screens as described in the NOPR, as well as apply the rebuttable presumption of market power for those sellers that fail either indicative screen.[49]

66. In addition, the Commission will not adopt suggestions to alter the indicative screens in order to incorporate a contestable load analysis, as proposed by EEI and others. As noted by the FTC, APPA/TAPS, and NRECA, the contestable load analysis is flawed because, among other things, it does not consider control of generation through contracts. The Commission explained in the April 14 Order that the roles of the indicative screens are meant to be complementary. The pivotal supplier indicative screen indicates whether demand can be met without some contribution of supply by the seller at peak times, while the market share indicative screen indicates whether the seller has a dominant position in the market and may therefore have the ability to exercise horizontal market power, both unilaterally and in coordination with other sellers.[50] The contestable load analysis is essentially a variant on the pivotal supplier screen with differences in the calculation of wholesale load and the test thresholds, because, like the pivotal supplier screen, it addresses whether suppliers other than the seller can meet the demand in the relevant market. Therefore incorporating such an analysis would not improve our ability to establish a presumption of whether a seller has market power. The contestable load analysis therefore would add little useful information, and without the market share indicative screen, the Commission would have insufficient information because there would be no analysis of a seller's size relative to the other sellers in the market, and no information on the seller's market power during off-peak periods.

67. In addition, the contestable load analysis fails to consider the relative price of the competing supplies. Commenters have argued that if available non-applicant supply is at least twice the contestable load, the market is competitive. However, this analysis fails to consider whether the available non-applicant supply is competitively priced and, thus, in the market. This weakness in the contestable load analysis is addressed in the DPT analysis which considers only supply that is competitively priced.

68. We also reject arguments by E.ON U.S. and PNM/Tucson that the wholesale market share screen should be replaced because, they argue, it does not consider the size of the wholesale supply in the relevant market relative to the wholesale demand in that market. E.ON. U.S. and PNM/Tucson are requesting an analysis very similar to the contestable load analysis, whose defining characteristic is measuring the wholesale supply market relative to wholesale demand, which, as stated above, is essentially the same as the pivotal supplier screen, and would therefore add little useful information to the screening process.

69. We reject Duke's claim that because neither of the rationales originally cited by the Commission in support of the market share indicative screen—its ability to identify “coordinating behavior,” or its ability to detect the exercise of market power in off-peak periods—has been validated, the wholesale market share indicative screen is unnecessary. Specifically, the Commission believes that the ability of market participants to exercise market power through “coordinating behavior” is a legitimate concern under the FPA, in addition to the fact that it has long been recognized by the antitrust Start Printed Page 39914authorities.[51] The Commission also believes it is possible to exercise market power in off-peak periods because during such times the amount of supply in the market may be greatly reduced (e.g., because of planned outages for plant maintenance), meaning that a seller that is not dominant at peak times might be at off-peak.

70. Moreover, we agree with APPA/TAPS that market-based rate assessments are used to determine the ability to exercise, not the exercise of, market power. The Commission need not wait passively until market power is exercised. Rather, it is incumbent on the Commission to set policies that will ensure that rates remain just and reasonable under section 205 of the FPA. Requiring sellers to submit screens that analyze the sellers' potential to exercise market power is consistent with such a policy.

71. We are unpersuaded by E.ON U.S.'s and PNM/Tucson's argument that “false positives” arising from the market share screen dampen the vigor of competitive wholesale market participation by unnecessarily curtailing the market-based rate authority of entities that, according to E. ON. U.S. and PNM/Tucson, lack market power. We recognize that a conservative screen may result in some false positives, but must weigh that against the cost of the false negatives that would occur if we adopted a less conservative screen or eliminated the market share indicative screen.

72. E.ON U.S. and PNM/Tucson, to support their point, cite several court cases in which market shares were alleged not to be reliable indicators of market power in regulated markets. However, the cases cited are not relevant to the issue of whether the Commission should retain the wholesale market share screen. The purpose of our indicative screens is to distinguish sellers that may raise horizontal market power concerns and those that do not; the market share screen is not the end of our horizontal market power analysis. In contrast, the cases cited by E.ON U.S. and PNM/Tucson [52] involve allegations of unlawful restraint of trade in violation of the Sherman Act,[53] a Federal antitrust statute prohibiting trade monopolies. The focus in such cases (whether a company has violated the Sherman Act) and the standard for making such a determination is different than the focus of the Commission at the indicative screen stage of the horizontal market power analysis (identifying sellers that require further horizontal market analysis without making a definitive finding regarding market power).

73. On both theoretical and practical grounds, we reject the argument by EEI and others that the market share indicative screen can diminish competition because some sellers that are the subject of a section 206 investigation choose mitigation rather than challenge the presumption of market power. First, mitigating a seller with market power ensures that the other sellers in the market cannot benefit from an artificially high market price due to the seller with market power exercising market power. Second, in our experience, sellers that choose mitigation rather than challenge the presumption of market power have market shares that are likely to indicate a dominant position in a geographic market.[54] In addition, many sellers have successfully rebutted the presumption of market power after failing one of the indicative screens.[55]

74. Further, we will not adopt the suggestion to substitute the HHI for the market share indicative screen or to supplement the indicative screens with the HHI. The indicative screens are used to separate sellers who are presumed to have market power from those that, absent extraordinary and transitory circumstances, clearly do not. We will not substitute the market share screen with an HHI screen because, as we have stated above, the seller's market share conveys useful information about its ability to exercise market power, so eliminating the market share screen in favor of the HHI could increase the risk of false negatives.[56] In addition, a high HHI can be the result of high market shares of sellers in the market other than the seller, and the focus of our analysis is on the seller's ability to exercise market power, so the HHI would provide little additional information to allow us to identify those sellers who clearly do not have market power. Finally, the HHI primarily provides information on the ability of sellers to exercise market power through coordinated behavior, while the market share screen primarily provides information on a particular seller's ability unilaterally to exercise market power. We will not supplement the indicative screens with the HHI screen because the indicative screens are sufficiently conservative to identify those sellers that have a rebuttable presumption of market power, without having to add an additional layer of review at the initial stage.

75. We clarify that sellers and intervenors may present alternative evidence such as a DPT study or historical sales and transmission data to support or rebut the results of the indicative screens. For example, intervenors could present evidence based on historical wholesale sales data or challenge the assumption that competing suppliers inside a balancing authority area have access to the market (such a challenge could take into account both the actual historical transmission usage at the time of the study as well as the amount of available transmission capacity at that time).[57] A seller may present evidence in support of a contention that, notwithstanding the results of the indicative screens, it does not possess market power.[58] However, sellers should not expect that the Commission will postpone initiating a section 206 investigation to protect customers while it examines this supplemental information if screen failures are indicated.[59] Nevertheless, the Commission may factor in this alternative evidence before deciding whether to initiate a section 206 investigation if the alternative evidence is appropriately supported, comprehensive and unambiguous, and Start Printed Page 39915conducive to prompt review by the Commission.

76. We will not adopt Southern's suggestion that the indicative screens be made voluntary. We will continue to require that sellers submit the indicative screens or concede the presumption of market power before they file a DPT. However, as discussed above, a seller may submit with its indicative screens a DPT as alternative evidence. As stated above, submission of a DPT analysis as alternative evidence at the same time a seller submits the indicative screens may result in the Commission instituting a section 206 proceeding to protect customers, based on failure of an indicative screen, while the Commission considers the merits of the DPT analysis.

77. We do not agree with Southern's view that failure of the indicative screen(s) does not provide a sufficient basis to establish a rebuttable presumption of market power. The indicative screens are intended to identify the sellers that raise no horizontal market power concerns and can otherwise be considered for market-based rate authority. Sellers failing one or both of the indicative screens, on the other hand, are identified as sellers that potentially possess horizontal market power and for which a more robust analysis is required. The uncommitted pivotal supplier screen focuses on the ability to exercise market power unilaterally. Failure of this screen indicates that some or all of the seller's generation must run to meet peak load. The uncommitted market share analysis indicates whether a supplier has a dominant position in the market. Failure of the uncommitted market share screen may indicate the seller has unilateral market power and may also indicate the presence of the ability to facilitate coordinated interaction with other sellers. It is on this basis that we find that a rebuttable presumption of market power is warranted when a seller fails one or both of the indicative screens. However, we agree with Southern that the DPT is a more definitive means for determining the existence of market power. As a result, we allow sellers that have failed one or both of the indicative screens to rebut the presumption of market power by performing the DPT. Further, because failure of one or both of the indicative screens only creates a rebuttable presumption of market power and sellers have a Commission-endorsed analysis that they can use to rebut that presumption (the DPT), we find without merit Southern's view that the indicative screens create a priori evidentiary presumption of guilt, are improper, and create due process concerns.

78. With regard to Southern's suggestion that we use the DPT as the default test, we find that if we were to do so our ability to protect customers while the analysis is evaluated could be compromised. The DPT is a more involved and complex analysis. The Commission has also at times set a DPT analysis for evidentiary hearing which greatly extends the time between when the DPT is submitted to the Commission and when a final decision is rendered. The rates customers are subject to during the time period before the issuance of a Commission order addressing a seller's DPT would not be subject to refund and, accordingly, the customers would be unprotected if the seller ultimately is found to have market power. However, under our current policy, and as adopted herein, if a seller wishes to file a DPT rather than the indicative screens it may do so. In doing so, the seller concedes that it fails the indicative screens, which concession establishes a rebuttable presumption of market power, and the Commission will issue an order initiating a section 206 proceeding to investigate whether the seller has market power and establishing a refund effective date for the protection of customers while the Commission evaluates the filed DPT. In the case of a seller that concedes the failure of one or both of the screens and submits the DPT in the same filing, the Commission is able to establish a refund effective date at an earlier time than if the seller were able to skip the screen stage entirely and file a DPT without conceding a screen failure.

79. We will reject Southern's request that forced outages be deducted from capacity. As we stated in the July 8 Order, “forced outages are non-recurring events that do not reflect normal operating conditions.” [60] Allowing deduction of forced outages will generally not change indicative screen results, because all sellers will be able to deduct forced outages, offsetting each other. In the unlikely event that forced outage numbers were not completely offsetting, allowing forced outages in the indicative screens would benefit owners of relatively unreliable fleets at the expense of owners of relatively reliable fleets.

2. Indicative Market Share Screen Threshold Levels and Pivotal Supplier Application Period

Commission Proposal

80. In the NOPR, the Commission proposed to retain the 20 percent threshold for the wholesale market share screen (i.e., with a market share of less than 20 percent, the seller would pass the screen). The Commission stated that since the screens are indicative, not definitive, a relatively conservative threshold for passing them was appropriate. Indeed, pursuant to the horizontal market power analysis, 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.

81. The Commission proposed 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. It stated that the pivotal supplier analysis examines the seller's market power during the annual peak, and that the hours near that point in time are the most likely times that a seller will be a pivotal supplier.

a. Market Share Threshold

Comments

82. A number of commenters argue that 20 percent is too low a threshold for the market share indicative screen. Some point out that, given native load requirements, it is very difficult for investor-owned utilities outside of RTOs/ISOs to fall below the 20 percent threshold for the market share indicative screen.[61] Duke also notes that the 20 percent criterion is incompatible with regional planning requirements because, according to Duke, the amount of capacity needed to satisfy regional planning reserve margins “would place the utility at substantial risk of exceeding the 20 percent threshold.” [62]

83. E.ON U.S. argues that, because the courts have not considered a 20 percent market share to indicate a market power concern, associating a market share indicative screen failure with a presumption of market power is inappropriate.[63] Additionally, Progress Start Printed Page 39916Energy argues that it is inappropriate to associate failure of the market share screen with a presumption of market power when U.S. Department of Justice (DOJ) merger guidelines state that only firms with 35 percent or more market share have market power.[64]

84. PPL states that it agrees that the 20 percent threshold should be replaced by a 35 percent threshold in the market share screen and argues that such an increase will avoid the false-positive failure rate of the indicative screens, and the cost, time and repercussions in the financial markets of the extended pendency of a market-based rate renewal proceeding while a DPT is conducted and considered.[65]

85. In reply, APPA/TAPS state that there is no reason to raise the market share indicative screen threshold above 20 percent simply because investor-owned utilities have trouble passing the market share indicative screen.[66] NRECA and TDU Systems note that the factors that EEI believes make it difficult to pass the indicative screens—a large amount of reserves and little available transfer capability—are precisely the factors to consider when evaluating whether a market is competitive.[67]

86. Rather than raising the threshold level, TDU Systems propose to lower the threshold to 15 percent for the market share indicative screen, claiming that 20 percent was never justified by the Commission or shown to be the right balance.[68] Citing Commission and judicial precedent, TDU Systems also note that the grant of market-based rate authority cannot be made without the discipline of market forces.[69]

87. These commenters cite a recent decision of the U.S. Court of Appeals for the Ninth Circuit [70] to buttress their positions, arguing that even market shares lower than 20 percent can lead to market manipulation.

88. In reply to these arguments, Duke states that certain commenters' reliance on this is mistaken because that decision addressed market manipulation, not market power.[71] Duke asserts that virtually any supplier, regardless of its market share, has some ability to manipulate market outcomes by engaging in anomalous bidding practices.

Commission Determination

89. The Commission will retain the 20 percent market share threshold for the indicative market share screen. EEI and others argue that the Commission should use a 35 percent threshold as a presumption of market power because the DOJ merger guidelines state that only firms with 35 percent or more market share have market power. As the Commission stated in the July 8 Order, however, in a market comprised of five equal-sized firms with 20 percent market shares, the HHI is 2,000, which is above the DOJ/FTC HHI threshold of 1,800 for a highly concentrated market, and in markets for commodities with low demand price-responsiveness like electricity, market power is more likely to be present at lower market shares than in markets with high demand elasticity.[72] Therefore, we will retain a conservative 20 percent threshold for this indicative screen.

90. When arguing that a 20 percent threshold for the market share screen is too low, E.ON. U.S. and PNM/Tucson ignore that the indicative screens are based on uncommitted capacity, not total capacity. When calculating uncommitted capacity for the market share screen, a seller deducts from its total capacity the capacity dedicated to long-term sales contracts, operating reserves,[73] planned outages, and native load [74] as measured by the appropriate native load proxy. As a result, a substantial amount of seller capacity may not be counted in measures of market share. Therefore, it is inappropriate to compare market shares based on uncommitted capacity to the market shares in the cases that E.ON. U.S. and PNM/Tucson cite.

91. We further note that other commenters have argued that the 20 percent threshold is too high. We disagree. The 20 percent threshold is meant to strike a balance between having a conservative but realistic screen and imposing undue regulatory burdens. The Commission's experience in the context of market-based rate proceedings demonstrates this point. In the three years since the April 14 Order, the Commission has revoked the market-based rate authority of two sellers, thirteen sellers relinquished their market-based rate authority, and six companies satisfied the Commission's concerns for the grant of market-based rate authority at the DPT phase. In addition, intervenors have the opportunity to present other evidence such as historical data in order to rebut the presumption that sellers lack market power.[75] Moreover, no commenter advocating a 15 percent threshold for the market share has shown why it is superior to the current 20 percent threshold. Therefore, we find that the 20 percent market share threshold strikes the right balance in seeking to avoid both “false negatives” and “false positives” and we will not reduce the wholesale market share screen to 15 percent, as suggested by TDU Systems.

92. The Commission does not accept Duke's assertion that the market share indicative screen is incompatible with regional planning requirements. The April 14 Order allows operating reserves necessary for reliability, as determined by State or regional reliability councils,[76] to be deducted from total capacity attributed to the seller.

93. We also reject the argument that the 20 percent threshold is too low because of native load obligations of investor-owned utilities outside of RTOs. First, the calculation of 20 percent is the same regardless of whether a seller is located in an RTO or not. Second, as discussed herein, we allow for a native load deduction in the wholesale market share screen and are increasing the deduction to address concerns raised by investor-owned utilities and others. Given the increased native load deduction, our market share screen adequately incorporates investor-owned utilities' native load obligations while necessarily maintaining the conservative nature of the screens.

b. Pivotal Supplier Application Period

Comments

94. Some commenters recommend that the pivotal supplier indicative screen should be applied monthly, rather than just in a seller's peak month. They reason that sellers, though not pivotal in the highest demand period, might be pivotal at different times of the year or in off-peak periods, such as in the spring or fall when power plants are on planned outages.[77]

Commission Determination

95. The Commission will not require the pivotal supplier indicative screen to be applied monthly, as some commenters suggest, because we believe Start Printed Page 39917it is unnecessary and overly burdensome to do so. Even though conditions of tight supply may occur at other times of the year or in abnormal operating conditions, the combination of the pivotal supplier analysis and the wholesale market share screen is sufficient, because suppliers with market power at such times are also likely to fail at least one of these screens. Moreover, if intervenors believe that a seller is pivotal during non-peak periods, they are permitted to file evidence to that effect. Accordingly, using only the peak month in the pivotal supplier indicative screen is appropriate. We note that if a seller fails the indicative screens and submits a DPT, it is required to provide a pivotal supplier analysis for each season and for both peak and non-peak hours.

3. DPT Criteria

Commission Proposal

96. With regard to the DPT analysis, the Commission proposed to retain the current thresholds (20 percent for the market share analysis and 2,500 for the HHI analysis), as well as the current practice of weighing all the relevant factors presented in determining whether a seller does or does not have horizontal market power. The Commission proposed to continue to do so on a case-by-case basis, weighing such factors as available economic capacity, economic capacity, market share, HHIs, and historical sales and transmission data.[78]

Comments

97. Several commenters suggest changes to the DPT criteria. One suggested change is to emphasize [79] or rely exclusively [80] on the available economic capacity measure, in order to properly account for native load. For example, one commenter argues that the economic capacity prong of the DPT analysis is not a useful indicator of the presence or absence of market power when applied to vertically integrated utilities in their home control areas because that analysis completely disregards native load obligations, making this prong virtually unpassable by such utilities. This commenter also notes that even using the available economic capacity measure, a seller with a market share above 35 percent would fail the DPT “even though there is no real market power problem because the in-area wholesale customers have access to ample supplies of competitively priced power.” [81] In this regard, he argues that the DPT should be changed to take into account “competitive alternatives available for wholesale customers.” [82]

98. Several other commenters disagree with the 2,500 HHI threshold for the DPT. Some reason that a 2,500 HHI threshold is not well justified and that an 1,800 HHI threshold is more appropriate because this is the criterion used in a highly concentrated market. They argue that if a 2,500 HHI threshold is used, it should be used with a 15 percent market share because these are the criteria of the oil-pipeline test from which the HHI 2,500 criterion is obtained.[83] State AGs and Advocates note that the Commission has never systematically attempted to correlate the results of the pivotal supplier indicative screen, the market share indicative screen, or the DPT (including HHI results) proposed in the NOPR with actual independently derived data and measures as to the existence of market power in any wholesale electricity market in the U.S.[84] Without having done this type of systematic and quantitative evaluation of the proposed market power tests based on some type of independent verification, State AGs and Advocates contend that the Commission cannot be confident that the three proposed tests are reasonably accurate and, therefore, useful tests to determine the existence of market power in any electricity market. For example, State AGs and Advocates ask how the Commission knows if an HHI corresponds to the point at which market power begins, and whether it varies by factors such as input price, generation mix and different market structures through the country.[85]

99. Furthermore, State AGs and Advocates claim that the DPT is not an adequate tool for assessing market power “in any context.” First, they state that the DPT will not discern bidding strategies of different suppliers. In addition, they assert that a DPT does not consider the differences between fundamentally different types of market structures: short-term energy only markets, short-term capacity markets, ancillary service markets, and long-term contract markets for energy and capacity.[86]

100. A number of commenters believe that the HHI threshold sufficient for passage of the DPT should remain at 2,500.[87] PPL states that lowering the HHI threshold to 1,800 will cause more false positives and direct capital away from the generation sector.

101. EEI and Progress Energy recommend that only the pivotal supplier and HHI analyses of the DPT should be retained, particularly if the market share analysis under the indicative screens is retained. They argue that the pivotal supplier and HHI analyses are more than sufficient to determine whether the potential for market power exists.[88]

102. A few commenters are skeptical about the need for a DPT. Southern states that “granting market-based rates should not require the same analysis as for a merger,” and that the Commission should reconsider using the DPT.[89] In this regard, Southern argues that unlike mergers, which are difficult and costly to undo, the Commission has the ability to continuously police the exercise of market power. Further, Southern states that the Energy Policy Act of 2005 provides for stiff civil and criminal penalties. Southern adds that the Commission recently issued new rules against market manipulation to thwart exercises of market power.

103. AARP expresses concern about the lack of competition in wholesale electric markets. It argues that market-based rate reviews are intended to determine whether the seller's market-based rates will be just and reasonable, not whether a seller passes the various tests. AARP argues that real-world evidence that may not fit neatly within the specified market-based rate criteria must be considered before the Commission can conclude that a seller lacks market power. AARP states that, as the NOPR recognizes (PP 63-64), both historical and forward-looking evidence should be considered.

Commission Determination

104. The Commission will continue to use the DPT for companies that fail the Start Printed Page 39918market power indicative screens. The DPT is a well-established test that has been used routinely by the Commission to analyze market power in the merger context. The fact that it is used in section 203 cases does not demonstrate that it is inappropriate for market-based rate cases. Rather, it provides a well-established tool for assessing market power that is known and widely used in the electric industry. Moreover, in both contexts, the DPT allows for the calculation of market shares and market concentration values under a wide range of season and load conditions.

105. 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 DPT. The DPT is also used to analyze the effect on competition for transfers of jurisdictional facilities in section 203 proceedings,[90] using the framework described in Appendix A of the Merger Policy Statement and revised in Order No. 642.[91]

106. 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 condition.[92] The results of the DPT can be used for pivotal supplier, market share and market concentration analyses.

107. Using the economic capacity for each supplier, sellers should provide pivotal supplier, market share and market concentration analyses. Examining these three factors with the more robust output from the DPT will allow sellers to present a more complete view of the competitive conditions and their positions in the relevant markets.

108. Under the DPT, to determine whether a seller is a pivotal supplier in each of the season/load conditions, sellers should compare the load in the destination market to the amount of competing supply (the sum of the economic capacities of the competing suppliers). 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 that is no higher than State and Regional Reliability Council operating requirements for reliability) for the relevant period. The analysis should also be performed using available economic capacity to account for sellers' and competing suppliers' native load commitments. In that case, native load in the relevant market would be subtracted from the load in each season/load period. The native load subtracted should be the average of the native load daily peaks for each season/load condition.

109. Each supplier's market share is calculated based on economic capacity. The market shares for each season/load condition reflect the costs of the sellers' and competing suppliers' generation, thus giving a more complete picture of the sellers' ability to exercise market power in a given market. For example, in off-peak periods, the competitive price may be very low because the demand can be met using low-cost capacity. In that case, a high-cost peaking plant that would not be a viable competitor in the market would not be considered in the market share calculations, because it would not be counted as economic capacity in the DPT. Sellers must also present an analysis using available economic capacity and explain which measure more accurately captures conditions in the relevant market.

110. Under the DPT, sellers must also calculate the market concentration using the HHI based on market shares.[93] HHIs have been used in the context of assessing the impact of a merger or acquisition on competition. However, as noted by the U.S. Department of Justice in the context of designing an analysis for granting market-based pricing for oil pipelines, concentration measures can also be informative in assessing whether a supplier has market power in the relevant market. “The Department and the Commission staff have previously advocated an HHI threshold of 2,500, and it would be reasonable for the Commission to consider concentration in the relevant market below this level as sufficient to create a rebuttable presumption that a pipeline does not possess market power.” [94]

111. A showing of an HHI less than 2,500 in the relevant market for all season/load conditions for sellers that have also shown that they are not pivotal and do not possess a 20 percent or greater market share in any of the season/load conditions would constitute a showing of a lack of market power, absent compelling contrary evidence from intervenors. Concentration statistics can indicate the likelihood of coordinated interaction in a market. All else being equal, the higher the HHI, the more firms can extract excess profits from the market. Likewise a low HHI can indicate a lower likelihood of coordinated interaction among suppliers and could be used to support a claim of a lack of market power by a seller that is pivotal or does have a 20 percent or greater market share in some or all season/load conditions. For example, a seller with a market share of 20 percent or greater could argue that that it would be unlikely to possess market power in an unconcentrated market (HHI less than 1,000). As with our initial screens, sellers and intervenors may present evidence such as historical wholesale sales. Those data could be used to calculate market shares and market concentration and could be used to refute or support the results of the DPT. The Commission encourages the most complete analysis of competitive conditions in the market as the data allow.

112. We will continue to weigh both available economic capacity and economic capacity when analyzing market shares and HHIs. Based on our substantial experience in applying the DPT over the past decade, we have found that both analyses are useful indicators of suppliers' potential to exercise market power, and we are unwilling to rely solely on one measure or the other.[95] For example, in markets where utilities retain significant native load obligations, an analysis of available economic capacity may more accurately assess an individual seller's competitiveness, as well as the overall competitiveness of a market, because available economic capacity recognizes the native load obligations of the sellers. On the other hand, in markets where the Start Printed Page 39919sellers have been predominantly relieved of their native load obligations, an analysis of economic capacity may more accurately reflect market conditions and a seller's relative size in the market.

113. Likewise, we find the HHI market concentration measure to be useful in assessing the market power of individual sellers, and it complements the market share and pivotal supplier measures in the DPT stage of the analysis. Furthermore, no commenter has presented a compelling argument for why the Commission should lower or raise the HHI threshold in the DPT. Accordingly, we will retain 2,500 as the appropriate threshold for passing this part of the DPT for the reasons we stated in the April 14 Order.[96] We will not adopt the suggestion to lower the market share threshold to 15 percent from 20 percent, for the reasons set forth above, in the NOPR and July 8 Order.[97] Commenters have presented no compelling reason to do so, and in our experience since the April 14 Order, we have not seen cases where the HHI was over 2,500 and the seller's market share was between 15 and 20 percent, which would be the type of situation about which APPA/TAPS and others are concerned. Accordingly, such a reform would not likely result in additional findings of market power.

114. State AGs and Advocates claim that the DPT is not an adequate tool for assessing market power because it will not discern bidding strategies of different suppliers. However, State AGs and Advocates miss the point of the analysis: by determining whether a seller has capacity that can compete in the market under various season and load conditions, the DPT provides an accurate picture of market conditions. Examining market conditions allows the Commission to determine whether a seller has market power. The DPT does this by examining short-term energy markets and, in particular, sellers' available generation capacity. In addition, absent entry barriers, and a specific finding of market power, the Commission has said that long-term markets are competitive. With regard to ancillary services, as discussed herein, the Commission requires market power analyses for those services to support a request for market-based rate authority. Assessing competing suppliers' bidding strategies, ex ante, would not illuminate the state of the market and the ability of sellers to alter prices within it.

115. We also reject Southern's argument that the DPT analysis is unnecessary because of the Commission's enhanced civil penalty authority and continuing policing of sellers with market-based rate authorization. While those are critical components of our program to ensure just and reasonable market-based rates, they are not a substitute for an analysis of the potential market power of sellers seeking market-based rate authority. In addition, Southern's argument that rules against market manipulation will thwart all exercises of market power is speculative.

116. We will not change the DPT to take into account competitive alternatives available for wholesale customers as proposed by a commenter. We stated above our reasons for rejecting use of a contestable load analysis in the indicative screens, and we reject it for the DPT for the same reasons.

117. AARP and State AGs and Advocates argue that the Commission should consider evidence from actual market data in determining whether market power exists rather than rely on the results of the DPT to determine whether a seller has market power. We agree that actual market data is an important part of a determination of whether a seller may have market power. In this regard, we look at actual market data, both in the initial analysis and in ongoing monitoring of the EQR data. As the Commission stated in the April 14 Order, “[a]s with our initial screens, applicants and intervenors may present evidence such as historical wholesale sales. Those data could be used to calculate market shares and market concentration and could be used to refute or support the results of the Delivered Price Test.” [98] In addition, as part of our ongoing monitoring activities, we examine the EQR data in an effort to identify whether market prices may indicate an exercise of market power.

4. Other Products and Models

Comments

118. ELCON expresses concern over the entire horizontal market power analysis process: indicative screens, followed by DPT or mitigation for those that fail the indicative screens. ELCON notes that the evolution of these practices generally occurred in a series of highly contested proceedings, and did not benefit from the broader and more balanced review afforded by a generic rulemaking. ELCON states that its concern is that the practices unduly shift the burden of proof to potential victims of market power abuse. This concern would only be academic, ELCON continues, if the market structures were truly competitive and there were strong structural protections against the exercise of market power. But the hybrid nature of most regional markets, combined with inadequate infrastructure, creates an environment that discourages trust in market outcomes.[99]

119. Some commenters urge the Commission to allow different product definitions, e.g., short-term power and long-term power, in the calculation of the indicative screens and the DPT. For example, NRECA argues that the Final Rule must require sellers to identify the relevant product markets, including the distinct products for which they seek market-based rate authority, and demonstrate that they lack market power in those product markets.[100] The Montana Counsel argues that the Commission's screens and DPT analysis models measure market power during certain test days for current time periods,[101] and that capacity that is available to make short-term energy sales may not be available for long-term, firm power sales. Thus, the Montana Counsel asserts that the Commission may not rely exclusively on short-term or spot markets to measure whether there are competitive long-term markets.

120. Other commenters remain divided over whether long-term power markets should be included in the market power analysis. PPL urges that long-term markets should not be considered in a market power analysis because of infeasibility and also because it violates the Commission's precedent that there is no long-term market power unless there exist barriers to entry.[102] In contrast, NRECA and TDU Systems state that long-term markets need to be analyzed in the market power analysis because monopolies will probably persist into the future for many consumers [103] and these consumers need protection. TDU Systems suggest using an installed capacity indicative screen for long-term markets.[104]

121. State AGs and Advocates and NASUCA suggest that the Commission adopt behavioral modeling, such as Start Printed Page 39920game theory, rather than structural analysis, because the latter cannot capture market power behavior.[105] NASUCA suggests that the Commission hold a technical conference to consider behavioral modeling. Duke disagrees with NASUCA's and others' calls for behavioral models, contending that they are theoretically complex and data-intensive and do not meet the prerequisite of being simple, easily understood and readily verifiable by the Commission.

Commission Determination

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

123. We reject ELCON's contentions regarding the development of our horizontal market power analysis. While the screens and DPT criteria did arise out of specific cases, there have been numerous opportunities in this rulemaking for interested parties to express any concerns and propose alternatives, including technical conferences and numerous rounds of written comments. We believe that this rulemaking has given all interested parties ample opportunity to voice any and all options for revising the screens and DPT criteria and proposing alternatives, and has given us the opportunity to evaluate whether these tools remain appropriate. We conclude that they do.

124. Finally, we will not adopt the suggestion by some commenters that behavioral modeling be used in addition to, or in place of, the indicative screens and the DPT. Although game theory has been used in laboratory experiments and in theoretical studies where the number of players and choices available to players are limited, we do not consider it a practical approach for the volume of analyses we must perform, particularly since a vast amount of choices are available and many of those are unobservable. The data gathering and analysis burden imposed on sellers and the Commission would be overly burdensome and impractical.

5. Native Load Deduction

a. Market Share Indicative Screen

Commission Proposal

125. To reduce the number of “false positives” in the wholesale market share indicative screen, the Commission proposed in the NOPR to adjust the native load proxy for this screen. The Commission proposed to change the allowance for the native load deduction under the market share indicative 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 indicative screen consistent with the deduction allowed under the pivotal supplier indicative screen.

Comments

126. TDU Systems argue that the Commission provides no empirical evidence supporting this change—i.e., no evidence of an excessive number of false positives produced by the Commission's current policy. TDU Systems also state that the Commission does not explain why it believes its current proxy “results in too much uncommitted capacity attributable to the seller.” [106] In particular, TDU Systems state that the Commission does not explain what factors it used to determine the appropriate level of uncommitted capacity to which it compared the current proxy.

127. APPA/TAPS agree, adding that the Commission proposal appears to be a results-driven effort to eliminate the need for some public utilities to submit a DPT.[107] APPA/TAPS argue that the Commission's “false positives” justification loses sight of the stakes involved in the market-based rate determination. They state that the price of a false positive associated with the initial screens will be the seller's submission of the DPT. APPA/TAPS argue that that price pales in comparison to the unreasonably high prices and market power exercise that can result from a false negative. According to APPA/TAPS, it is thus entirely appropriate for the Commission to take a closer look when a utility fails the initial screens, even when the Commission ultimately allows market-based rate authorization.[108]

128. In addition, APPA/TAPS state that, as well as lacking evidentiary basis, the proposed adjustment is not based on sound economic principles. APPA/TAPS argue that when the Commission originally adopted the native load proxy for the market share screen, it said the screen should reflect “all of the capacity that is available to compete in wholesale markets at some point during the season.” [109] APPA/TAPS state that now the Commission proposes to eliminate even more of the capacity that is available to compete at some point in the season by increasing the proxy to the average native load peak demand for the season.

129. APPA/TAPS further argue that adoption of the Commission's proposal would mean that the market-based rate screens would make no assessment of off-peak periods, even though the Commission has said that the market share screen is intended to measure market power during off-peak times.[110] They state that “screens should examine market power for the on-peak and off-peak periods of the different seasons.” [111]

130. Finally, APPA/TAPS argue that consistency across the two screens defeats the purpose of having more than one screen. The market share screen is intended to reflect capacity that could compete, including during off-peak periods. By contrast, the pivotal supplier screen is specifically intended to measure market power risks at system peak.

131. APPA/TAPS offer that if the Commission nonetheless believes some consistency is desired it can achieve it by using a native load proxy for the market share screen based upon the average minimum loads. Such a proxy would be consistent with the Commission's original intent of a screen that identifies “all of the capacity that is available to compete in wholesale markets at some point during the season.” [112]

132. Other commenters generally support the Commission's proposal to use seasonal average native load as the native load proxy for the market share indicative screen. Many state that the proposed native load proxy is a more accurate representation of native load obligations.[113] Several commenters Start Printed Page 39921suggest excluding weekends and holidays from the proxy native load calculation because these periods are not representative of normal load hours.[114]

133. EEI argues that even with this proposed change, the generation capacity required by a utility to serve its native load is still being understated.[115] It states that utilities are required to meet the peak demands of their native load customers plus maintain a reserve margin for reliability purposes. This requirement directly determines the amount of generation capacity that a supplier can commit to the wholesale opportunity sales market. As such, EEI argues that the change proposed in the NOPR is a step in the right direction in terms of more accurately recognizing the amount of generation capacity required by a utility to meet native load requirements, but still understates the actual requirements.

134. EEI contends that from a generation planning perspective, no one with any expertise in that area doubts the native load proxy described in the April 14 Order underestimates the amount of capacity that a supplier needs to meet native load requirements and therein both overstates the amount of capacity that the supplier has to compete in the wholesale market as well as the supplier's market share. As a result of this overestimation of the capacity that a supplier would have to compete in the wholesale market, EEI contends that non-RTO vertically integrated utilities have failed the market share screen using the current native load proxy when many simply do not have market power.[116] EEI concludes that such a high number of “e positives” for market power that have occurred using the current proxy clearly supports the Commission's proposal to move the native load proxy to the average peak load in the season.

Commission Determination

135. We adopt the NOPR proposal to change the native load proxy under the market share indicative screen from the minimum native load peak demand for the season to the average of the daily native load peak demands for the season, making the native load proxy for the market share indicative screen consistent with the native load proxy under the pivotal supplier indicative screen.

136. In this regard, we find that the market share screen should be calculated using as accurate a representation of market conditions for each season studied as possible. We find that using the current native load proxy using the minimum native load level for the season does not provide an accurate picture of the conditions throughout the season.

137. We recognize that increasing the native load proxy will have the effect of reducing the market share for traditional utilities with significant native load obligations, and therefore may result in fewer failures of the wholesale market share screen for some sellers. However, we believe that such a result is justified. We are seeking a screen that provides a reasonably accurate picture of a seller's position given market conditions across seasons, so that we can eliminate those sellers who clearly do not have market power and focus our analysis on those who might. We believe that a native load proxy based on the average of peak load conditions is more representative, and thus more accurate, than a proxy based on extreme (i.e., minimum) peak load conditions. We also believe that basing the native load proxy on the average of the peaks will make the screens more accurate in eliminating sellers without market power while focusing on ones that may have market power.

138. For sellers that contend that the proposed native load proxy will result in too many false positives, we note that under the existing native load proxy, fewer than 25 companies have been the subject of section 206 investigations since the April 14 Order. For entities that fear this change in native load proxy will lead to too many “false negatives,” (companies with market power passing under the indicative screens), we note that intervenors can always challenge the presumption of no market power. Moreover, no intervenor in this proceeding has pointed to specific companies that have passed the screens but still have market power.

139. We reject APPA/TAPS' argument that changing the native load proxy would result in the market-based rate screens making no assessment of off-peak periods. In fact, the native load proxy we approve here is based on the average of the native load daily peaks which also include low load days. The use of the average peak demand for the native load proxy provides for an assessment of all periods, peak and off-peak seasons, because such a proxy considers peak native load of each day in each season. Combined with the pivotal supplier screen that captures the annual peak conditions, we find that the two screens adequately capture market conditions over the year.

140. We also reject APPA/TAPS' argument that consistency across the two screens defeats the purpose of having more than one screen. The screens in and of themselves are inherently different methodologies in that the pivotal supplier screen considers whether the seller's generation must run to meet peak load, whereas the market share screen looks at the seller's size relative to other sellers in the market. We are looking for an assessment of the uncommitted seasonal capacity available to sellers to compete in wholesale markets and, as stated above, find that the average of the daily peak loads in a season more accurately reflects seller's commitments.

141. APPA/TAPS suggest that if we do raise the native load deduction, we only raise it to the average minimum for the season, rather than the average native load peak demand for the season. The intent of the wholesale market share screen is to assess market conditions during the season, not only during off-peak hours. APPA/TAPS is misplaced in its assertion that our original intent was for the market share screen to focus solely on off-peak conditions. In the April 14 Order we stated that “by using the two screens together, the Commission is able to measure market power both at peak and off-peak times.” [117] Our statement simply recognizes that a seller with a dominant position in the market could have market power in the off-peak as well as the peak. Clearly the pivotal supplier analysis is designed to assess market power at peak times, but that does not imply that the wholesale market share screen is designed only to assess market power in the off-peak period.

142. Finally, we will not exclude weekends and holidays from the market share native load proxy. Since we adopt herein the use of an average peak demand for the native load proxy for the market share screen, the exclusion of weekends and holidays would inappropriately skew the results. Use of an average load addresses the issue of the variability between unusually high or low load days, is more objective, and easily applied. If weekends and holidays are excluded, only approximately 70 percent of total load hours would be accounted for. The Start Printed Page 39922average native load measure that includes weekends and holidays, and which we adopt, is truly an average of all load conditions.

b. Pivotal Supplier Indicative Screen

Commission Proposal

143. In the NOPR, the Commission proposed to retain the pivotal supplier screen's native load proxy at its current level of the average of the daily native load peaks during the month in which the annual peak day load occurs.[118]

Comments

144. Southern states that the pivotal supplier screen is conceptually sound; however, the manner of its current implementation reflects a significant flaw. In particular, Southern claims that the wholesale load (market size) is determined by the difference between the control area's needle peak demand and the average of the daily peaks in that peak month. Southern argues that it is not at all clear how or why this mathematical exercise (which in its opinion reflects an “apples and oranges” comparison) provides any meaningful measure of competitive wholesale demand during any relevant period.

145. For example, Southern continues, under some circumstances, all or a large portion of the wholesale load determined in this fashion could be the seller's own native load. Subtracting the average daily peaks in the peak month from a single needle peak to derive a “proxy” for competitive wholesale demand necessarily assumes that all of this difference is unsatisfied wholesale market demand that is subject to competition. Southern argues that this is not a valid assumption and the Commission has provided no reason to believe that it is. Southern therefore urges the Commission to abandon this aspect of the interim pivotal supplier analysis and instead use an estimate of actual wholesale load, rather than deriving it indirectly through an arithmetic exercise. For example, the seller's native load peak could be subtracted from the control area peak load on an “apples to apples” basis (for example, needle peaks, seasonal peaks, or average daily peaks) to derive, in Southern's view, a much better wholesale load proxy.[119] Southern asserts that such a reform would be relatively easy to implement and would yield much more meaningful results.[120]

146. NRECA disagrees with Southern's proposed modification to the pivotal supplier screen to use actual wholesale load, stating Southern provides no evidence that this modification would provide a more accurate estimate of the wholesale load than the current approach.[121]

Commission Determination

147. We retain the average daily peak native load as the native load proxy used in the pivotal supplier screen, as proposed in the NOPR, and we reject Southern's argument that our method of computing the native load proxy is unreasonable. Southern argues that because the wholesale demand is determined by subtracting the average daily peaks in the peak month from a single needle peak, the Commission is relying on an invalid assumption with regard to the wholesale demand during any relevant period. However, Southern's claim that our deduction of the average of the daily native load peaks from the needle peak is a “mixing of apples and oranges” ignores our reasoning in the April 14 Order:

conditions in peak periods can provide significant opportunity to exercise market power. As capacity is utilized to meet demand there is less available to sell on the margin and often less competition. Only focusing on needle peaks that occur for a single hour and that are only known after the fact does not give an accurate reflection of the competitive dynamics of peak periods. As demand increases during peak periods, buyers and sellers are positioning themselves in the market with similar but incomplete information. Buyers are projecting their needs and trying to secure needed power, while sellers are negotiating to obtain the highest price for that power. With increasing demand, fewer units are available to serve anticipated peak needs and buyers bid to secure dwindling supply load increases. In addition, buyers must be prepared for the contingency that a unit will be forced out and they will need to purchase in a period of even greater scarcity.[[122] ]

148. Further, both native load proxies provide an adequate solution to a complicated issue. Resources used to serve native load fluctuate over the course of the day and through the seasons. As the Commission stated in the April 14 Order, “we recognize that not all generation is available all of the time to compete in wholesale markets and that some accounting for native load requirements is warranted here. However, wholesale and retail markets are not so easily separated such that a clear distinction can be made between generation serving native load and generation competing for wholesale load. Most utility generation units are not exclusively devoted to serving native load, or selling in wholesale markets.” [123]

149. For these reasons we continue to believe that the average of the native load peaks in the peak month is a reasonable proxy for the native load deductions under this screen. Moreover, we also find that Southern's proposed method of estimating the actual wholesale load is inappropriate because it would artificially reduce the seller's share of that load. This is because Southern's methodology only deducts the seller's native load peak from the control area peak (not the native load peaks of any other sellers in the control area), leaving the seller with a disproportionately small share of the remaining market.

c. Clarification of Definition of Native Load

Commission Proposal

150. In the NOPR, the Commission expressed its belief that there has been some inconsistency in the way in which sellers have reflected native load in performing both the screens and the DPT analysis. Because the states are under various degrees of retail restructuring, the definition of native load customers has lacked precision. Accordingly, the Commission proposed to clarify that, for the horizontal market power analysis, native load can only include load attributable to native load customers as defined in § 33.3(d)(4)(i) of the Commission's regulations,[124] as it may be revised from time to time.

Comments

151. APPA/TAPS support the native load clarification, without providing additional explanation. A number of other commenters discussed the native load clarification in the context of defining retail contracts or provider of last resort (POLR) load as native load. PPL Companies request that this clarification not be adopted unless the Commission provides further clarification that an entity selling power to a retail customer under a long-term Start Printed Page 39923contract is able to deduct that capacity.[125]

Commission Determination

152. We will adopt the NOPR proposal that, for the horizontal market power analysis, native load can only include load attributable to native load customers as defined in § 33.3(d)(4)(i) of our regulations. We address the comments of PPL Companies' and others below in the “Other Native Load Concerns” section.

d. Other Native Load Concerns

Comments

153. Some commenters suggest alterations to the definition of native load or to the circumstances when contract capacity may be deducted from total capacity. One commenter recommends that POLR load be counted as native load.[126] Sempra argues that generators should be allowed to take native load deductions for power supplied to franchised utilities that divested their generation.[127] It argues that allowing such suppliers to claim native load deductions correctly assigns these obligations to the entities that actually commit the generation resources necessary to serve native load and results in a more accurate assessment of the suppliers' remaining uncommitted capacity. It notes that such sales may be for terms of less than one year, and that under the Commission's policy such suppliers cannot deduct those commitments as long-term firm sales. Sempra further points out that franchised utilities do not need a one-year or greater commitment to take a native load deduction. It concludes that marketers and other suppliers should thus be allowed to account for the native load commitments they undertake, regardless of the term of each underlying contract.[128]

Commission Determination

154. We will not adopt suggestions that sellers receive native load deductions for all their POLR contracts or for all contracts that serve utilities that have divested their generation. Even in cases where independent power producers (IPPs) serve what used to be franchised public utilities' native load, IPPs do not serve it under the same terms as those utilities.[129] Unlike franchised public utilities, IPPs may choose to exit the market once the contracts they sell power under have expired. However, we remind IPPs that POLR contracts with a term of one year or more may be deducted from total capacity under some circumstances. As the Commission explained in the July 8 Order, “applicants may deduct `load following' and `provider of last resort' contracts for terms of one year or more under certain conditions. Specifically, we will allow sellers to deduct long-term firm load following contracts to the extent that the seller has included in its total capacity a corresponding generating unit or long-term firm purchase contract that will be used to meet the obligation. The seller's contractual peak load obligation under the contract should be used as the capacity adjustment in the pivotal supplier analysis and the seasonal baseline demand levels served under the contract should be used as the adjustments in the market share analysis. The residual capacity will be considered available for sales in the wholesale spot markets and treated as uncommitted capacity.” [130] Also, in response to PPL Companies, we note that long-term (one year or more) firm contracts that cede control may always be deducted from total capacity.

155. We will allow IPPs to deduct short term native load obligations if they can show that the power sold to the utility was used to meet native load. We agree with Sempra that allowing such suppliers to claim native load deductions correctly assigns these obligations to the entities that actually commit the generation resources necessary to serve native load and results in a more accurate assessment of the suppliers' remaining uncommitted capacity, and that such sales may be for terms of less than one year. Under our current policy such suppliers cannot deduct those commitments as long-term firm sales, whereas franchised utilities do not need a one-year or greater commitment to take a native load deduction.

6. Control and Commitment

Commission Proposal

156. The Commission noted in the NOPR 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.[131] 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.[132]

157. Noting that contracts can confer the same rights of control of generation or transmission facilities as ownership of those facilities, the Commission stated that 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. 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.[133]

158. In the NOPR, the Commission stated that in recent years some owners have outsourced to third parties pursuant to energy management agreements the day-to-day activities of running and dispatching their generating plants and/or selling output. The Commission noted that the agreement may, directly or indirectly, transfer control of the capacity. The Commission expressed concern that under such third-party agreements, there may be instances where control of capacity has changed hands, but this capacity has not been attributed to the correct seller for the purposes of the generation market power screens.[134]

159. 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.[135] Likewise, in providing guidance regarding events that trigger a requirement to submit a notice of change in status, the Commission has Start Printed Page 39924indicated that, to determine whether control has been acquired, sellers should examine whether they can affect the ability of capacity to reach the relevant market.

160. The Commission asked in the NOPR whether, in the interest of providing greater certainty and clarity regarding the determination of control, it should make generic findings or create generic presumptions regarding what constitutes control. In particular, the Commission sought comment on whether any of the following functions should merit a finding or presumption of control and, if so, on what basis: directing plant outages, fuel procurement, plant operations, energy and capacity sales, and/or credit and liquidity decisions.[136]

161. Alternatively, rather than focusing on these discrete functions, the Commission asked if it should establish a presumption of control for any entity that has some discretion over the output of the plant(s) that it manages. The Commission asked whether such an approach would promote greater certainty. The Commission also asked, if it adopted such a presumption, how it should address instances where discretion over plant output may be shared between more than one party.[137]

162. The Commission proposed to clarify that, in the event it adopted any such presumptions, an individual seller could rebut the presumption of control on the basis of its particular facts and circumstances. In addition, the Commission proposed to clarify that an 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.[138]

163. The intent of the Commission's proposals was to provide greater certainty and clarity as to the treatment of capacity that is subject to energy management agreements and outsourcing of functions so that the capacity is properly reported (and studied) and to make clear that any entity to which control is attributed must receive the necessary authorizations under the FPA in order to provide jurisdictional services.[139]

a. Presumption of Control

164. As an initial matter, most commenters support the Commission's desire to provide greater clarity and certainty regarding the determination of control.[140] In this regard, many commenters express concerns that attributing generation capacity to sellers that do not necessarily control that generation may result in the seller falsely appearing to have market power and ultimately result in unnecessary mitigation. Commenters also express the need for the determination of control to be consistent for both the market-based rate authorizations and the change in status filings.

165. However, most commenters also oppose the Commission's proposal to establish generic findings or generic presumptions regarding what constitutes control, arguing that such findings must be made on a case-by-case basis. Others suggest a rebuttable presumption that control lies with the owner unless specific facts indicate otherwise.

i. Fact Specific Determinations

Comments

166. Various commenters argue for a fact specific determination of control.[141] For example, Alliance Power Marketing, a supplier of energy management services, argues that a case-by-case approach provides increased certainty for generators and asset managers who relied upon Commission precedent in developing their current arrangements.[142]

167. Several commenters state that they have some sympathy with the Commission's desire to provide certainty and clarity in this area, however, they do not agree that there should be generic presumptions regarding the indicia of control. One commenter argues that details of each contract vary, depending upon parties and circumstances involved as well as on conditions in the market place, and therefore it must be reviewed and evaluated with care.[143] This commenter suggests that an individual seller should be obligated to submit its contracts to the Commission for review, and allowed to present its case on the basis of its particular facts and circumstances.

168. Similarly, APPA/TAPS believe that the Commission is correct to assign capacity to a seller for purposes of running the screens/DPT; however, they point out that generic findings or presumptions would be helpful only if the particulars of a contract aligned with the factual assumptions underlying a presumption. Otherwise, they state that a presumption could produce wrong results.[144] APPA/TAPS suggest that any arrangement that could create opportunities for sellers to coordinate their behavior with other competitors should be reported and that as part of the seller's assigning control over long-term contracts for purposes of the screens/DPT, the Commission should require a seller to submit the relevant contracts with the market-based rate application or triennial update and identify the contractual provisions that support the seller's control determinations.[145] APPA/TAPS suggest that marketing alliances or joint operating agreements can affect a seller's market position and should be considered in the determination of control.[146]

169. Powerex argues that clarity is particularly important as the new market manipulation rule makes it unlawful “to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading.” [147] In this regard, Powerex urges the development of a single principle or set of principles that need to be met to establish control over an asset. Powerex argues that the development of such principles will help take the guesswork out of compliance and provide greater certainty for the market, as compared to a laundry list of possible contract types. Powerex states that the control principle should focus on physical output as opposed to financial terms, since it is physical output that addresses the Commission's physical withholding concerns and relates to the agency's market screens.[148]

170. EEI, EPSA, and Reliant argue that the Commission should continue to look at the totality of circumstances and attach the presumption of control when an entity can affect the ability of capacity to reach the market.[149]

171. NYISO states that based on its experience in the administration of bid-based markets, what matters in the control of a plant is the ability to determine or significantly influence (a) Start Printed Page 39925The levels of the bids from the plant, and (b) the level of output from the plant. Accordingly, the Commission should focus directly on these critical facts, rather than creating presumptions based on indirect indicia of an ability to control these key competitive parameters. NYISO claims that plant engineering or technical operations may be outsourced without conferring an ability to control price or output, so that the outsourcing is not of particular competitive significance. If, however, an entity could determine or significantly influence bids or output, then it would be reasonable for the Commission to place a burden on that entity to demonstrate that it is not in a position to benefit from a possible exercise of market power. NYISO claims that if more than one party is in a position to exercise control over bids or output, then both such parties should have the burden of rebutting this presumption. NASUCA concurs.[150] Because of the fact-specific nature of these issues, the NYISO endorses the Commission's proposal to allow individual sellers to rebut the presumption on the basis of their particular facts and circumstances.[151]

172. Westar argues determinations of control over generating plants are essential elements of the negotiated risk sharing arrangement in virtually every energy management contract and that the Commission should not change its precedent absent clear evidence of market uncertainty or a finding that the established guidelines are inappropriate.[152]

173. Southern suggests that the approach taken in Order No. 652, where the Commission provided an illustrative list of contracts and arrangements that involve changes of control, is reasonable.[153]

Commission Determination

174. As discussed in the sections that follow, the Commission concludes that the determination of control is appropriately based on a review of the totality of circumstances on a fact-specific basis. No single factor or factors necessarily results in control. The electric industry remains a dynamic, developing industry, and no bright-line standard will encompass all relevant factors and possibilities that may occur now or in the future. 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.[154]

175. Though we note the widespread support among commenters for the Commission's effort to provide greater clarity and certainty regarding the determination of control, there are differing points of view as to what circumstances or combination of circumstances convey control. These circumstances vary depending on the attributes of the contract, the market and the market participants. Thus, we conclude that it would be inappropriate to make a generic finding or generic presumption of control, but rather that it is appropriate to continue making our determinations of control on a fact-specific basis.

176. We agree with commenters such as Powerex and Westar that the Commission should rely on a set of principles or guidelines to determine what constitutes control. This has been our historical approach and we find no compelling reason to modify our approach at this time. Accordingly, as suggested by EEI, EPSA and others, we will consider the totality of circumstances and attach the presumption of control when an entity can affect the ability of capacity to reach the market. Our guiding principle is that an entity controls the facilities when it controls the decision-making over sales of electric energy, including discretion as to how and when power generated by these facilities will be sold.[155]

177. With regard to suggestions that we require all relevant contracts to be filed for review and determination by the Commission as to which entity controls a particular asset (e.g., with an initial application, updated market power analysis, or change in status filing), we will not adopt this suggestion. Under section 205 of the FPA, the Commission may require any contracts that affect or relate to jurisdictional rates or services to be filed. However, the Commission uses a rule of reason with respect to the scope of contracts that must be filed and does not require as a matter of routine that all such contracts be submitted to the Commission for review. Our historical practice has been to place on the filing party the burden of determining which entity controls an asset. As discussed below, we will require a seller to make an affirmative statement as to whether a contractual arrangement transfers control and to identify the party or parties it believes controls the generation facility. Nevertheless, the Commission retains the right at the Commission's discretion to request the seller to submit a copy of the underlying agreement(s) and any relevant supporting documentation.

ii. Rebuttable Presumption Regarding Ownership

Comments

178. MidAmerican argues that the Commission should adopt a presumption of control based on physical ownership of the generation (as adjusted for long-term sales or purchase power agreements). MidAmerican states that it is physical ownership that typically determines which entity controls the output of the generation and determines its ability to reach relevant markets. While many entities may have partial control over a unit's output, it is the owner that is most likely to affect market power.[156]

179. Morgan Stanley states that as a general rule, when assessing market power, the Commission should specifically adopt a rebuttable presumption that the entity that owns [157] the generation asset controls the generation capacity.[158] This presumption would shift if the asset owner relinquishes to a third-party the final decision-making authority over whether a unit runs (i.e., if the third-Start Printed Page 39926party can trump the asset owner's dispatch instruction, then the third-party has control over whether the capacity reaches the market). Morgan Stanley states that such final decision-making authority would include authority to schedule outages.[159]

180. FirstEnergy proposes that where a generation owner is a public utility under Part II of the FPA, the Commission should adopt a rebuttable presumption that such owner controls all of the generating capacity that it owns.[160] FirstEnergy asserts that even where another entity is responsible for day-to-day operation of a generating unit, the generation owner generally will retain managerial discretion over the operation of the unit and over the sale of power from that unit into the market.[161]

181. A number of commenters argue that jointly-owned plants should be assigned based on percentage of ownership.[162] For example, Pinnacle states that, in the Southwest region, the joint ownership of base-load generating plants is the norm, and there is typically one party that has operational control over the facility. However, if the Commission refines the criteria for assigning generation to an entity based on factors such as directing plant outages, fuel procurement, and plant operations (or similar factors), there is concern that jointly-owned generation may be attributed in whole to each of the owners if there is joint decision-making on such factors (e.g., if such decisions are made through a consortium of utilities forming a plant's joint operating committee) and result in unintentional double counting. Pinnacle also raises a concern that where joint plant owners appoint one of the joint owners to operate the plant, the entire plant will be attributed to the operator, rather than being attributed to each of the joint owners in shares. According to Pinnacle, the Final Rule should clarify that capacity of jointly-owned plants operated by one of the owners will be assigned to each joint owner based on its percentage interest.[163] Pinnacle states that the current rules under the interim screens with regard to assigning generating capacity to an entity appear to be workable.[164]

182. Many other commenters raise concerns about double counting in cases of shared control.[165] For example, with regard to shared facilities, FirstEnergy states that control of the plant should be attributed to the entity that is deemed to own the energy supplied from the plant. FirstEnergy offers that, if circumstances arise in which discretion over plant output is shared among more than one party, the Commission should permit the affected parties to resolve between themselves the entity to which capacity available in the unit will be attributed. FirstEnergy concludes that if the Commission adopts a regional approach to updated market power analyses, the Commission will be able to monitor those circumstances in which specified generation capacity is attributed to the wrong market participant.[166]

Commission Determination

183. With regard to the suggestion that we adopt a rebuttable presumption that the owner of the facility controls the facility, our historical approach has been that the owner of a facility is presumed to have control of the facility unless such control has been transferred to another party by virtue of a contractual agreement. We will adopt that approach. Accordingly, while we do not specifically adopt a rebuttable presumption that the owners control the facility, we will continue our practice of assigning control to the owner absent a contractual agreement transferring such control.

184. We note that the Commission has developed precedent regarding the contractual arrangements that can transfer control. In these cases, the Commission has stated that control refers to arrangements, contractual or otherwise, that confer control of generation or transmission facilities just as effectively as they could through ownership.[167] The capacity associated with contracts that confer operational control to an entity other than the owner thus must be assigned to the entity exercising control over that facility, rather than to the entity that is the legal owner of the facility, when performing the generation market power screens.[168]

185. With regard to FirstEnergy's suggestion that the affected parties make a determination regarding the entity to whom capacity available in the generating unit will be attributed in order to avoid any unwarranted double counting in the attribution of control,[169] the Commission agrees that this is a constructive and appropriate approach. However, although we wish to avoid double counting as a general matter, the Commission will not rule out the possibility of double counting in circumstances where it is unclear what entity has control. For example, if different parties could control dispatch decisions under various circumstances, to err on the conservative side, the Commission may attribute generation to more than one seller for the purposes of the horizontal analysis.

186. To determine whether there are contracts transferring control to a seller seeking market-based rate authority, similar to the requirements for change in status filings,[170] the Commission will Start Printed Page 39927require sellers when filing an application for market-based rate authority or an updated market power analysis, to make an affirmative statement as to whether any contractual arrangements result in the transfer of control of any assets, including whether the seller is conferring control to another entity or obtaining control of another entity's assets. Moreover, in addition to requiring such affirmative statements as to whether any contractual arrangements result in the transfer of control of any assets,[171] the Commission will require sellers, when filing an application for market-based rates, an updated market power analysis, or a required change in status report with regard to generation, to specify the party or parties they believe has control of the generation facility and to what extent each party holds control.

187. We understand that affected parties may hold differing views as to the extent to which control is held by the parties. Accordingly, we also will require that a seller making such an affirmative statement seek a “letter of concurrence” from other affected parties identifying the degree to which each party controls a facility and submit these letters with its filing. Absent agreement between the parties involved, or where the Commission has additional concerns despite such agreement, the Commission will request additional information which may include, but not be limited to, any applicable contract so that we can make a determination as to which seller or sellers have control.

188. With regard to Pinnacle's concern regarding joint plant owners appointing one of the joint owners to operate the plant, we reserve judgment as a general matter. However, we understand that there may be situations where a jointly-owned generation facility is operated by one of the joint-owners for the benefit of and on behalf of all of the joint-owners. Under these circumstances, it may be reasonable to allocate capacity based on ownership percentages. Such a determination should be made on a case-specific basis.

189. We remind sellers that in performing the horizontal market power analysis all capacity owned or controlled by the seller must be accounted for. In this regard, we expect that sellers, in performing such market power analyses, will clearly identify all assets for which they have control, or relinquished control, through contract.

iii. Energy Management Agreements

Comments

190. Most commenters state that energy management agreements and the functions listed in the NOPR (directing plant outages, fuel procurement, plant operations, energy and capacity sales, and/or credit and liquidity decisions) should not be presumed to convey control. Financial Companies state that a generic presumption of control by energy managers will “chill a seller's willingness to provide energy management services.” [172] Others suggest that the Commission should not adopt such a presumption and, in the alternative, should consider the specific aspects of an agreement. Additionally, some commenters request clarification on contract terms that are widely used in energy management agreements and may or may not convey control.

191. Sempra and financial entities argue that the Commission should not adopt a presumption that energy management agreements confer control over generating capacity.[173] They state that energy management and comparable agreements do not convey unlimited discretion and should not shift the presumption of control away from the entity that has final authority to dispatch the physical output of the plant.

192. Constellation agrees that the Commission should focus on whether an energy manager may make decisions about physical operation without final authority from a plant owner.[174]

193. Westar expresses concerns that the NOPR's invitation to consider ultimate control to reside with any entity that has some discretion over the output of a plant would invite confusion and undercut the Commission's declared objective to provide greater certainty and clarity in this area.[175] Alliance Power Marketing also expresses concern that a presumption that some discretion constitutes control will discourage innovation in the market, particularly with regard to option contracts and third-party arrangements.[176]

194. Alliance Power Marketing differentiates between asset/energy managers acting purely as agents and those that do not meet the legal definition of agents, suggesting that a market facilitator meeting the criteria of an agent should be exempt from attribution of control. The agent criteria identified by Alliance Power Marketing are: (1) The entity holds legal indicia of an agent's role; (2) the entity is neither a market participant nor an affiliate of a market participant; (3) the entity has limited, if any, financial stake in power market outcomes; and (4) the entity is subject to supervision or control in its activities on behalf of its principals.[177] Alliance Power Marketing submits that agents do not control generation if they are acting on behalf of their clients, do not assume the risk of transactions, and never take title to power. Constellation notes that the Commission has previously recognized that an agent who is acting subject to the direction of the owner should be not found to have control of a facility.[178]

195. Financial Companies disagree with Alliance Power Marketing's differentiation. They caution the Commission about imposing overly restrictive limitations on which entities qualify as agents or independent contractors and recommend that the Commission reject Alliance Power Marketing's proposal and suggest instead that ultimate decision-making authority is most relevant whether or not an agent is or is not a market participant.[179]

196. In contrast, NASUCA submits that the Commission should presume that energy management agreements convey control when energy managers can control generation output or the price or quantity of service offered.[180] Even more specifically, NASUCA recommends that the Commission reject formulations that would cloak market power of energy managers who control or affect electricity pricing, or the pricing of critical cost components such as fuel. Instead the Commission should adopt a rule that at a minimum encompasses the exercise of control over prices, bids, or output, including the ability to affect the cost of fuel and other inputs to generation.[181]

Commission Determination

197. After careful consideration of the comments, the Commission will not adopt a presumption of control regarding energy management agreements or the functions outlined in Start Printed Page 39928the NOPR.[182] We agree with commenters that energy management and comparable agreements do not necessarily convey unlimited discretion and control away from the entity that owns the plant. In this regard, as noted above, it is the totality of the circumstances that will determine which entity controls a specific asset.

198. Further, the Commission will not adopt a presumption of control in the case of shared discretion over the output and physical operation of a plant. The Commission is aware that varying degrees of discretion may be shared in some cases, and believes that the determination of control in these cases is best addressed on a fact-specific basis. As noted by Sempra, there may always be an element of discretion associated with the implementation of instructions or guidelines included in energy management agreements.[183]

199. With regard to Alliance Power Marketing's differentiation between asset/energy managers acting purely as agents and those that do not meet the legal definition of agents, and suggestion that “a market facilitator meeting the criteria of an agent should be exempt from attribution of control,” we find this differentiation in and of itself not determinative. Instead, consistent with our conclusion that the determination of control is appropriately based on a review of the totality of the circumstances on a fact-specific basis such that no single factor or factors necessarily results in control, it is the combination of the rights conveyed that determine control, not whether an entity considers itself to be an agent and not a market participant.

iv. Specific Functions and Contract Terms

Comments

200. With regard to specific functions and specific contract terms, many commenters do not believe that functions such as directing plant outages, fuel procurement, plant operations, energy and capacity sales, and credit and liquidity merit a presumption of control.

201. NYISO and FirstEnergy both suggest that the functions listed in the NOPR may be outsourced without conveying ultimate control. According to EEI, the list of functions described in the NOPR would not provide greater guidance.[184] Rather, EEI believes a focus on the ability to withhold will be more effective than establishing presumptions based on the functions described in the NOPR. In particular, EEI argues that establishing presumptions for these individual functions would be difficult, because often it would be a combination of various functions that would result in the ability to affect bringing the capacity to market.[185]

202. Duke believes that the Commission should avoid simplistic presumptions as to what constitutes control over resources for market power purposes and how and when specific generation should be imputed to market participants for purposes of the screen analysis. Duke argues that in a market power context, such determinations should be fact-driven and based on a pragmatic assessment of which party has the ability to withhold a specific amount of capacity from the market. For example, the Commission should not automatically impute control over capacity based solely on contract language that appears to convey some element of discretion over unit operation to a particular party, notwithstanding the absence of any real world ability for that entity to withhold that capacity from the market. Duke states that the Commission should recognize that the ability to economically or physically withhold output from the market rests with the party that makes the final determination of whether generation (energy and/or capacity) will be offered into the market. Even a purchaser with dispatch rights may not have the ability to withhold supply, if the capacity owner has the right to schedule energy when the purchaser chooses not to do so. Similarly, a party with a contractual right to capacity (as opposed to energy), even with a call option for energy priced at market, does not have operational control over energy. Duke states that any contract in which rights to the energy ultimately revert to the owner/operator or for which energy is available only at a market price leaves control in the hands of the owner/operator. According to Duke, there should not be a blanket presumption that certain types of commercial arrangements or contractual language imply control in all instances.[186]

203. PG&E argues that any presumptions about control over generation should be based on whether a seller controls the dispatch of energy (i.e., can affect the ability of the capacity to reach the relevant market). This general presumption should cover all types of transactions and business arrangements, rather than trying to address every possible function. Such an approach will be more effective than establishing presumptions based on individual functions, as various factors may intersect or combine to provide this control. Relevant factors include authority over the use or provision of fuel to the plant.[187]

204. PPL expresses concern that any arrangement in which a gas supplier could receive the output of a gas-fired generator as payment for the gas it supplies to the generator, if it is the only supplier to that generator, may convey control. PG&E appears to agree, stating that authority over the use or provision of fuel to the plant is a relevant factor with regard to control.[188]

205. EEI also appears to agree that fuel ownership may result in a change in control of plant output when, in the context of what triggers a change in status filing, it states: “The Commission should continue the current policy that changes in the ownership of fuel supplies in and of themselves need not be reported. Only if the change in ownership of inputs results in a change of control of the output of the plant should a change in status filing be required. If a public utility acquires fuel supplies, there is no need to notify the Commission, unless the business structure, like a tolling agreement, actually results in discretion over the plant output.” [189]

206. Sempra states that the Commission has generally treated energy management agreements as tolling agreements and requests that the Commission acknowledge the differences between the two.[190] APPA/TAPS state that particularly under tolling arrangements, while the supplier of fuel may not be operating the plant, it controls the plants' production of energy for sale, thus affecting market outcomes.[191] Constellation argues that plant operations and sales of output are functions that may convey control, but notes that the variety of case-specific facts limits the benefit of a blanket presumption of control.

207. Commenters also request that the Commission provide guidance regarding other contract types and terminology Start Printed Page 39929such as call option contracts (with liquidated damages), contracts that allow variance in volume or delivery point, QF contracts, RMR contracts, capacity contracts, and load obligations.[192]

208. Finally, EEI seeks clarification that energy only contracts over 100 MW for a term greater than one year that do not include rights to specific capacity are one type of contract that does not transfer control.

Commission Determination

209. In Order No. 652, the Commission provided a non-exclusive, illustrative list of contractual arrangements that are subject to the change in status filing requirement. The list includes agreements that relate to “operation (including scheduling and dispatch), maintenance, fuel supply, risk management, and marketing [of plant output]. These types of arrangements have in some cases also been referred to as energy management agreements, asset management agreements, tolling agreements, and scheduling and dispatching agreements.” [193] The Commission clarifies that the illustrative list included in Order No. 652 provides guidance with regard to new applications for market-based rate authority and updated market power analyses as well as to change in status filings.

210. With respect to requests for clarification of whether certain contractual arrangements transfer control (such as call option contracts; liquidated damages contracts; contracts that allow variance in volume, source, or delivery point; QF contracts; RMR contracts; capacity contracts; and load obligations), for the reasons stated above, the Commission declines to address particular contractual terminology in isolation. The label placed on a specific contract does not determine whether it conveys control. Such determination necessarily must be made on a fact-specific basis.

211. Similarly, with regard to EEI's request for clarification that energy-only contracts over 100 MW for a term greater than one year that do not include rights to specific capacity are one type of contract that does not transfer control, for the reasons stated above, the Commission declines to address such a specific contractual arrangement generically.

b. Requirement for Sellers To Have a Rate on File

Comments

212. Alliance Power Marketing questions the Commission's proposal to clarify that any entity that controls generation from which jurisdictional sales are made is required to have a rate on file. Alliance Power Marketing believes that this proposal appears more akin to an inquiry than a Proposed Rulemaking.[194] Pinnacle requests clarification as to whether a non-jurisdictional entity is required to have a rate on file if that entity is the operator of a facility jointly-owned by jurisdictional and non-jurisdictional entities.[195]

Commission Determination

213. With regard to comments concerning the Commission's statement in the NOPR as to the need for an entity that controls generation from which jurisdictional power sales are made to have a rate on file, the Commission is reiterating, not modifying, the existing obligation to make rate filings. Under section 205 of the FPA,

every public utility shall file with the Commission * * * schedules showing all rates and charges for any * * * sale subject to the jurisdiction of the Commission, and the classifications, practices, and regulations affecting such rates and charges, together with all contracts which in any manner affect or relate to such rates, charges, classifications, and services.[[196] ]

Part II of the FPA defines a public utility as “any person who owns or operates facilities subject to the jurisdiction of the Commission.” [197] Any entity not otherwise exempted from the Commission's regulations that owns or operates jurisdictional facilities from which jurisdictional power sales are made is a public utility required to have a rate on file with the Commission, unless the Commission has determined that such an entity does not in fact have “control” over the jurisdictional facilities sufficient to deem it a public utility (for example, if its ownership is passive, or its operation of facilities is as an agent subject to the control of the owner of the facilities). For any entity that is a public utility, if its rate authority is market-based, then it is subject to the conditions of authorization by the Commission (including the requirement to demonstrate lack of generation market power by the submission of market screens as spelled out in the horizontal market power section of this Final Rule). If an entity is a public utility and making jurisdictional sales without having a rate on file, those sales may be subject to refund, and the entity may be subject to a civil penalty.[198]

214. In response to Pinnacle, we clarify that if an entity has control of a jurisdictional facility and that entity is making jurisdictional sales, it would be a public utility subject to the jurisdiction of the Commission and would be required to have a rate on file with the Commission. However, if an entity is specifically exempted from the Commission's regulation pursuant to FPA section 201(f), it would not be considered a public utility under the FPA and, accordingly, would not be required to have a rate on file.

7. Relevant Geographic Market

a. Default Relevant Geographic Market

Commission Proposal

215. In the NOPR, the Commission proposed to continue to use its historical approach with regard to the relevant geographic market. The Commission stated that the default relevant geographic market is the control area where the generation owned or controlled by the seller is physically located and each of 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 proposed to continue to designate RTOs/ISOs with sufficient market structure and a single energy market in which a seller is located and is a member as the default relevant geographic market. In such circumstances the Commission would not require sellers to consider the first-tier markets to such RTOs/ISOs as being part of the default relevant geographic markets. In addition, the Commission noted in the NOPR that its experience with corporate mergers and acquisitions indicates that the same RTOs/ISOs that the Commission has identified as meeting the criteria for being considered a single market for purposes of performing the generation market power screens have, at times, been divided into smaller submarkets for study purposes Start Printed Page 39930because frequently binding transmission constraints prevent some potential suppliers from selling into the destination market. Therefore, the Commission sought comment on its approach under the market-based rate program of considering the entire geographic region under control of the RTO/ISO, with a sufficient market structure and a single energy market, as the default relevant market. We asked whether the Commission should continue its approach of considering the entire geographic region as the default market for purposes of the indicative screens but consider RTO/ISO submarkets for purposes of the DPT.

Comments

216. With regard to the RTO/ISO market, several commenters state that, based on all the protections associated with structured RTO/ISO markets with Commission-approved market monitoring and mitigation, the Commission should continue its current approach of allowing the entire geographic region of an RTO/ISO to be the default relevant market for the horizontal market power analysis.[199] They state that retention of this standard will simplify preparation of market power analyses by sellers within qualified RTOs.

217. Several commenters as well urge the Commission not to consider RTO or ISO submarkets. Sempra states that it recognizes that RTOs are at times divided into submarkets, such as for purposes relating to corporate merger and acquisition analyses, but it submits that the Commission should not consider RTO or ISO submarkets when conducting a market power analysis. Sempra states that the use of submarkets will result in uncertainty, confusion, and increased litigation as to the geographic boundaries of the “right” submarket that should be analyzed. According to Sempra, sellers that operate in RTO and ISO markets currently know with certainty the relevant geographic market for purposes of regulatory obligations such as reporting relevant changes in status, and the use of submarkets will eliminate that certainty and will open the door to competing definitions of submarkets. Sempra states that the existence of internal transmission constraints does not justify breaking up RTOs and ISOs into submarkets for purposes of the Commission's market power analysis. Sempra states that notably, only RTOs and ISOs with sufficient market structure and a single energy market can be used as default geographic markets. These attributes allow RTOs, ISOs, and their members to adopt mechanisms, including local markets or mitigation, that address potential concerns about local market power resulting from transmission constraints.[200]

218. Similarly, EPSA, PG&E, PPL, ISO-NE, CAISO and NYISO support use of the entire RTO/ISO as the relevant geographic market where the RTOs/ISOs operate a single centralized market and generally where there are measures for monitoring and oversight.[201]

219. In addition, EPSA offers that changes to the size of markets can be addressed on a case-by-case basis by sellers or when an intervenor presents specific evidence supporting reduction of the relevant geographic market.[202] PG&E states that in the case of a single control area like CAISO, there is little rationale or basis to determine how to subdivide a control area. Where there may be intermittent congestion within certain areas, the control area as a whole has regional planning and monitoring, avoiding the need to subdivide. In addition, the empirical fact that most sellers make no effort to justify an alternate geographic market—whether larger or smaller—supports the control area as the appropriate measure.[203]

220. PPL states that if the Commission were to impose stringent market power tests based upon temporary transmission limitations beyond generators' control (e.g., infrequent intra-control area transmission system limitations), the Commission could make worse an already tenuous financial situation for existing generators in such areas and continue to deter new generation investment. Defining a geographic market smaller than a control area may lead to high failure rates of the screens. PPL states that associated loss of market-based rate authority (if that is the remedy imposed by the Commission) could precipitate economic retirements of those needed generators.

221. Finally, Ameren suggests that, for purposes of the DPT, the relevant geographic market should be the applicable RTO/ISO footprint, just as it is for purposes of the indicative screens, unless the Commission already has found the existence of a submarket in the relevant portion of the RTO/ISO. In such cases, the Commission should give due consideration to any existing Commission-approved market monitoring and mitigation regime already in place within the RTO/ISO that provides for mitigation of the submarket. If the relevant RTO/ISO does not have in place a mitigation program for an identified submarket, the Commission may then consider appropriate submarket-specific mitigation in connection with granting market-based rate authorization.

222. On the other side of the issue, several commenters urge the Commission to consider internal transmission constraints and possible submarkets within RTOs/ISOs. The California Board proposes that the Commission permit RTOs to identify submarkets within their control area, as needed, to help determine possible local market power. The California Board states that if the Commission develops or approves criteria which sellers may use to expand their geographic market, then the same criteria must be applicable in RTOs to limit the size of a geographic market. The New Jersey Board states that intervenors should be allowed to present evidence that the relevant geographic market is smaller (or larger) than the default RTO/ISO market and states that evidence of binding transmission constraints is relevant when examining horizontal market power.[204]

223. State AGs and Advocates state that almost any large default geographic market will have many transmission-constrained areas (load pockets) within it and that the Commission must require applicants for market-based rate authority to do a proper analysis of the degree of market power that is likely to be exercised by all sellers, including the applicants, in all relevant load pockets or transmission-constrained regions or subregions in which the sellers control generation capacity. They state that all load pockets must be considered as appropriate geographic markets whenever they exist.

224. APPA/TAPS state that the presumption of the RTO footprint as the default geographic market must be truly rebuttable, including rebuttals based upon evidence that the RTO itself treats an area as a separate market.[205] APPA/TAPS state that in practice, however, the presumption appears to be irrebuttable. They argue that if known load pockets such as WUMS (or, for example, the Delmarva Peninsula, Southwest Connecticut, or the City of Start Printed Page 39931San Francisco, among others) do not rebut the geographic market presumption, the rebuttable presumption effectively becomes irrebuttable. APPA/TAPS recommend that in advance of each region's market-based rate review, RTOs should provide market participants with transmission studies that reveal where binding transmission constraints arise so that those data can be used in addressing the proper relevant geographic market. In addition, APPA/TAPS state that in the § 203 context, the Commission has correctly found that transmission constraints lead to distinct geographic markets, at least when those constraints are binding. They submit that no reasonable basis exists to distinguish between the competitive analyses used to establish relevant geographic markets in the section 203 and the section 205 contexts.[206]

225. In response to APPA/TAPS, EPSA states that in cases where the Commission denied a seller's argument to change its relevant geographic market, the Commission carefully considered the positions of parties advocating a different market and simply found their arguments insufficient to warrant a modification to the market definition.[207] EPSA states that it cannot be said that a presumption is irrebuttable simply because the Commission has, to date, deferred to RTO/ISO mitigation mechanisms to this point.

226. With regard to non-RTO areas, APPA/TAPS states that while the control area provides a reasonable starting point, the Commission's obligation to base its market-based rate decision on “empirical proof” requires reliance on specific facts that demonstrate whether the relevant geographic market should be the control area, or a smaller or larger area. APPA/TAPS further state that, for non-RTO areas, the seller should affirmatively address whether the geographic market should default to the control area or whether a smaller or larger area is appropriate, and support that result with evidence. They add that intervenors should also be allowed to introduce evidence regarding the question.[208]

227. With regard to both RTO/ISO and non-RTO areas, several other commenters urge the Commission to consider changing its existing policy on the default geographic market. State AGs and Advocates state that the best policy would be to have no “default” market criteria, but to have each applicant for market-based rates determine on an analytical basis what market area makes the most sense for its circumstances based on the actual transmission constraints that it faces.[209] NRECA states that using individual control areas or RTOs as the default market for evaluating a transmission provider's market power fails to account for the binding transmission constraints and load pockets that have developed within those markets.[210]

228. Morgan Stanley states that it supports the Commission's practice of relying on control areas and RTO/ISO regions when assessing market power as the default markets, but believes the Commission may be missing instances of market power by failing to also review known events that can create narrower or broader markets. For example, Morgan Stanley states that the Commission acknowledges that binding transmission constraints and the existence of load pockets can cause considerable market power issues. Therefore, Morgan Stanley asserts that the Commission should indeed consider whether a seller may possess the ability to exercise market power in a portion of an otherwise competitive market. To enable the Commission to do so, sellers should address known constraints in their description of the relevant geographic market in their market power filings, particularly in markets for which they are the control area operator.[211]

229. The California Commission states that while it agrees that designating a relevant geographic area will reduce uncertainty to all market participants, designation of a static geographic market in a dynamic market may defeat the purpose of market certainty and may have unintended adverse consequences over time. For example, with the implementation of locational marginal pricing (LMP) in the CAISO control area, there will be many submarket areas known as local areas. This will trigger “false negatives” (i.e., absence of market power even when there is market power) in a control area analysis. A seller may pass both screens and receive market-based rate authority when tested against the broader geographic control area, such as the entire CAISO control area market. However, the same seller may not pass the screens when tested against a particular sub-area or local area. Accordingly, the California Commission states that the Commission should be flexible in designating geographic areas to determine market power. The Commission should designate geographic areas by considering current and reasonably foreseeable regional developments, as the Commission currently does in merger cases following DOJ/FTC merger guidelines.[212] Similarly, the Commission should consider the presence or absence of market power due to continuous developments of major market events (e.g., area outages, congestion due to new market developments, and the development of load) that can have significant impact as inputs in the market power screening calculation.

230. In contrast, EEI disagrees with those commenters that would require the seller in each filing to affirmatively address with supporting evidence whether the geographic market should default to the control area or RTO/ISO area. EEI states that this requirement would defeat the purpose of having default areas to expedite and simplify the market-based rate filing process, noting that it is more efficient for any affected party to have the right to challenge the selection of the default market, as exists under the proposed regulations.[213]

Commission Determination

231. The Commission will adopt in this Final Rule its current approach with regard to the default relevant geographic market, with some modifications. In particular, the Commission will continue to use a seller's balancing authority area [214] or the RTO/ISO market, as applicable, as the default relevant geographic market.[215] However, where the Commission has made a specific finding that there is a submarket within an RTO/ISO, that submarket becomes the default relevant geographic market for sellers located within the submarket for purposes of the market-based rate analysis.

232. With regard to traditional (non-RTO/ISO) markets, our default relevant geographic market under both indicative screens will be first, the balancing Start Printed Page 39932authority area where the seller is physically located,[216] and second, the markets directly interconnected to the seller's balancing authority area (first-tier balancing authority area markets).[217] We also clarify that if a transmission-owning Federal power marketing agency (e.g., the Tennessee Valley Authority, Bonneville Power Administration) is the home or first-tier market to the seller, then that seller must treat that Federal power marketing agency's balancing authority area as a relevant geographic market and file market power analysis on it just as it would any other relevant market.[218] Under the indicative screens, we will consider only those supplies that are located in the market being considered (relevant market) and those in first-tier markets to the relevant market. For non-RTO sellers, we adopt a rebuttable presumption that the seller's balancing authority area and each of its neighboring first-tier balancing authority areas are each relevant geographic markets.

233. Although a number of commenters oppose the use of the balancing authority area as the default geographic market in traditional markets, they have submitted no compelling evidence that our historical approach is inadequate or insufficient for the typical situation. Indeed, using balancing authority areas allows the Commission and public to rely on publicly available data provided for balancing authority areas that are relevant to the market-based rate analysis discussed herein. These data are accurate and generally available. We will, however, continue to allow sellers and intervenors to present evidence on a case-by-case basis to show that some other geographic market should be considered as the relevant market in a particular case.[219] We clarify that the seller must provide the Commission with a study based on the default geographic market, and we will allow 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. This evidence would be an addition to the required study based on the relevant geographic market as referred to in this Final Rule.

234. We do not adopt the suggestion by APPA/TAPS that the seller should affirmatively address whether the geographic market should default to the balancing authority area. We believe that EPSA's argument that such a requirement would defeat the purpose of having default areas and add uncertainty into the market is more persuasive. By defining default geographic markets, we provide the industry as much certainty as possible while also providing affected parties the right to challenge the default geographic market definition and provide evidence in that regard.

235. With regard to RTO/ISO markets, we agree with many commenters that RTOs/ISOs with a sufficient market structure and a single energy market with Commission-approved market monitoring and mitigation provide strong market protections. As a general matter, sellers located in and members of the RTO/ISO may consider the geographic region under the control of the RTO/ISO as the default relevant geographic market for purposes of completing their horizontal analyses, unless the Commission already has found the existence of a submarket.

236. Where the Commission has made a specific finding that there is a submarket within an RTO/ISO, we believe that the market-based rate analysis (both indicative screens and DPT) should consider that submarket as the default relevant geographic market. This is consistent with how the Commission has treated such submarkets in the merger context. For example, in some merger orders, the Commission has found that PJM-East, and Northern PSEG are markets within PJM;[220] Southwestern Connecticut (SWCT) and Connecticut Import interface (CT) are separate markets within ISO-NE;[221] and New York City and Long Island are separate markets within NYISO.[222] Accordingly, we conclude that sellers located in these RTO/ISO submarkets should not use the entire PJM, ISO-NE and NYISO footprints as their relevant geographic markets for purposes of the market-based rate analysis. Instead, they should use as the default geographic market for their market-based rate analysis the submarkets that the Commission already has found constitute separate markets in those RTOs/ISOs.

237. We agree with APPA/TAPS that if the Commission makes a specific finding that the relevant geographic market is one other than the balancing authority area or RTO/ISO geographic region, the Commission's finding should define the default market going forward. For example, if the Commission finds that a submarket exists within an RTO, that submarket becomes the default geographic market for all sellers that own or control generation capacity within that submarket.

238. To the extent that the Commission finds that a submarket exists within an RTO/ISO, intervenors or sellers can provide evidence to the contrary (i.e., the submarket, like our other default geographic markets, is rebuttable). In addition, if a seller or intervenor argues that the seller operates in an RTO/ISO submarket and presents sufficient evidence to support that conclusion, we will consider those arguments even if the Commission has not previously found that a submarket exists.

239. As a general matter, because we recognize the arguments raised by commenters that defining default geographic markets (whether balancing authority area, RTO/ISO footprint or RTO/ISO submarket) may not be appropriate in all circumstances, on a case-by-case basis, we will allow sellers and intervenors to present additional sensitivity analyses [223] as part of their market power analysis to show that some other geographic market should be considered as the relevant market in a particular case. For example, sellers or intervenors could present evidence that the relevant market is broader than a particular balancing authority area. Sellers and intervenors may also provide evidence that because of internal transmission limitations (e.g., load pockets) the relevant market (or markets) is smaller than the balancing authority area, RTO/ISO footprint or RTO/ISO submarket. We believe this is a balanced approach because it establishes a presumption that the Commission will in most cases rely on default geographic markets, while at the same time, the Commission will give sellers and intervenors the opportunity to argue that the facts of a particular Start Printed Page 39933case support the use of some other geographic area as the relevant market.

240. We also provide, as discussed further below, guidance regarding the type of analysis required to rebut the default geographic markets including default markets for balancing authority areas, RTO/ISO markets, and RTO/ISO submarkets.

241. In this regard, sellers can incorporate the mitigation they are subject to in RTO/ISO markets or RTO/ISO submarkets with Commission-approved market monitoring and mitigation as part of their market power analysis. For example, if a market power analysis shows that a seller has local market power, the seller may point to RTO/ISO mitigation rules as evidence that this market power has been adequately mitigated. We believe the added protections provided in structured markets with market monitoring and mitigation generally result in a market where prices are transparent and attempts to exercise of market power will be sufficiently mitigated.

242. With respect to market concentration resulting within RTO/ISO submarkets, we will continue to consider existing RTO mitigation. The Commission will consider an existing Commission-approved market monitoring and mitigation regime already in place within the RTO/ISO that provides for mitigation of the submarket. For example, New York City will be treated as a separate default market for market-based rate study purposes. However, because it has existing In-City mitigation, we will assess whether any concerns over market power are already mitigated. We agree with Ameren that if the relevant RTO/ISO does not have in place a mitigation program for an identified submarket, the Commission may then consider whether and, if so, to what extent appropriate submarket-specific mitigation is needed.

243. In response to APPA/TAPS' statement that in practice the presumption of the RTO footprint as the default geographic market appears to be irrebuttable, this is simply not the case. The Commission carefully considers the positions and evidence submitted by parties advocating a different geographic market. Although we may have found that arguments made in a particular case were unconvincing, or that market power was adequately mitigated by existing mitigation,[224] we did, and will continue to, provide the opportunity for sellers to rebut the presumption. Moreover, as discussed above, where the Commission has made a specific finding that there is a submarket within an RTO, that submarket (not the RTO footprint) becomes the default relevant geographic market for sellers located within the submarket for purposes of the market-based rate analysis.

244. In this proceeding, we have considered expanding the default geographic region of a single RTO/ISO where contiguous RTOs/ISOs may have a common market as suggested by Ameren and find that there is insufficient support to make a generic finding that any contiguous RTOs/ISOs form a single geographic market.

245. With regard to the California Board's proposal that the Commission permit RTOs to identify submarkets within their balancing authority area, as needed to help determine possible local market power, we agree that this is an appropriate approach. However, we note that this is neither a new nor a novel approach. The Commission has historically considered the views of RTOs/ISOs in this regard and will continue to do so. We note, however, that to the extent RTOs/ISOs believe there is a market power issue within their RTO/ISO, they should notify the Commission promptly and not wait for an application by an entity seeking market-based rate authority or a current seller submitting an updated market power analysis.

246. Finally, to avoid any possible uncertainty or confusion about the RTO/ISO submarket, we identify RTO/ISO submarkets that the Commission to date has found to constitute a separate market. The Commission found submarkets in the PJM market, PJM East and Northern PSEG.[225] In Wisvest-Connecticut, LLC, the Commission also found two submarkets, SWCT and CT in ISO-NE.[226] In National Grid plc, the Commission again found two submarkets, New York City and Long Island, in NYISO.[227] These RTO/ISO submarkets will be the default geographic markets for purposes of the market-based rate analysis.

b. NERC's Balancing Authority Area and Default Geographic Area

Commission Proposal

247. In the NOPR, the Commission noted that the North American Electric Reliability Corporation (NERC) no longer uses the designation of control area since it approved the Reliability Functional Model (Functional Model). The Commission sought 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 the relevant data is.

Comments

248. Several commenters state that since NERC no longer uses control area designations, and its Functional Model refers to “balancing authority areas,” the Commission should modify slightly its approach to default geographic markets by simply replacing the term “control area” with “balancing authority area.” They state that such a change will align the Commission's rules with NERC's Functional Model, thus helping to avoid confusion.[228]

249. NYISO states that the control area is a valid starting point for the analysis of market-based rates. NYISO states that under the most recent version of the Reliability Functional Model posted on the NERC Web site (version 3, April 21, 2006), the “Balancing” and “Market Operations” functions appear to correlate to the traditional notion of Start Printed Page 39934a control area operator for purposes of assessing competitive markets. Thus, the adoption of the Functional Model would appear to create issues more of terminology than substance. NYISO states that, whatever the terminology, the process of defining geographic markets should focus on the area in which grid operations generally facilitate the ability of generators to compete in the scheduling and dispatch of resources, and the ability of loads to purchase from such resources.[229]

Commission Determination

250. With regard to the use of the Functional Model by NERC, we agree with commenters that the Commission should modify slightly its approach to default geographic markets by replacing the term “control area” with “balancing authority area.”

251. A balancing authority area means the collection of generation, transmission, and loads within the metered boundaries of a balancing authority, and the balancing authority maintains load/resource balance within this area.[230] Similar to control area, a balancing authority area is physically defined with metered boundaries that we refer to as the balancing authority area. Every generator, transmission facility, and end-use customer must be in a balancing authority area.[231] The responsibilities of a balancing authority include the following: (1) Match, at all times, the power output of the generators within the balancing authority area and capacity and energy purchased from or sold to entities outside the balancing authority area, with the load within the balancing authority area in compliance with the Reliability Standards; (2) maintain scheduled interchange and control the impact of interchange ramping rates with other balancing authority areas, in compliance with Reliability Standards; (3) have available sufficient generating capacity, and Demand Side Management to maintain Contingency Reserves in compliance with Reliability Standards; and (4) have available sufficient generating capacity, Demand Side Management, and frequency response to maintain Regulating Reserves and Operating Reserves in compliance with Reliability Standards.[232] It is the interconnection and coordination between balancing authority areas that provides a foundation for the Commission to analyze transmission limitations and other transfers of energy and provides a reasonable measure of the relevant geographic market under typical circumstances.

252. The Commission adopts in this Final Rule “balancing authority area,” instead of “control area.” We believe that such a change will align the Commission's rules with NERC's Functional Model, thus helping to avoid confusion.

c. Additional Guidelines for Alternative Geographic Market and Flexibility

Commission Proposal

253. In the NOPR, the Commission proposed to continue to provide flexibility by allowing sellers and intervenors to present evidence that the market is smaller or larger than the default market. The Commission explained that when assessing an expanded geographic market pursuant to the horizontal analysis, it 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. The Commission stated that any proposal to use an expanded 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. The Commission proposed to require that such a demonstration be made based on historical data, and said it would require that a sensitivity analysis be performed analyzing under what circumstances transmission constraints would bind.

254. The Commission explained that it also considers whether there is other evidence that would support the existence of an expanded market, such as evidence that customers can access the resources outside of the default geographic market on similar terms and conditions as those inside the default geographic market. It stated that such evidence could be empirical or it could point to factors that indicate a single market. It noted that 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, but that 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; or 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. The Commission stated that evidence of active trading throughout the proposed geographic market would also be considered. It stated that in determining whether two or more control areas are a single market it would weigh, on a case-by-case basis, all the factors presented. The Commission noted that once it has been established that historically there were no physical impediments to trade, there are several factors the Commission would consider, and no one factor would be dispositive. The Commission sought comment on this proposed guidance and, in particular, whether there are other factors it should consider when assessing a proposed expanded market and whether there are any factors that should be given more weight or are essential in determining the scope of the market. The Commission also asked whether it should apply the same criteria when determining whether the geographic market is smaller than the default geographic market.

Comments

255. A number of commenters agree that it is appropriate to provide sellers flexibility in presenting evidence that the appropriate geographic market is broader than the default geographic market.[233] Several state that greater Commission guidance is needed so that sellers wishing to argue for a broader market definition have clear objective criteria and can provide evidence that the Commission will find probative.

256. Puget submits that the examples listed in the NOPR provide some guidance but are still too general to be of use to a seller submitting a new market power study. It states that the Commission should: (1) Provide additional guidance on the levels of price convergence and trading activity across a proposed alternative market that will support a seller's filing; (2) be more specific regarding the level of transmission constraints that will preclude a finding of an expanded Start Printed Page 39935market; and (3) not rely heavily, if at all, on transmission operation factors—such as common OASIS or common unit commitment and dispatch—that are not necessarily indicative of a common market.[234]

257. Southern states that the Commission's proposed focus on evidence pertaining to frequently binding transmission constraints for purposes of considering a larger geographic market seems appropriate. However, Southern argues that the NOPR's apparent requirement of additional evidence (beyond the absence of transmission constraints) to support a larger geographic market is unnecessary. Moreover, Southern submits that evidence of a single unit commitment and dispatch function, a single transmission rate, and a common OASIS platform is not likely to exist in the absence of an RTO or ISO. Accordingly, making such evidence a requirement for a larger geographic market would render illusory the opportunity for expansion for non-RTO/ISO sellers.[235]

258. Avista agrees that the absence of these factors does not necessarily mean that a market contains impediments to trading or that wholesale customers are unable to secure supply from alternative sources. Avista supports the Commission's proposal to state what type of evidence demonstrates active trading throughout the proposed geographic market. Avista submits that a regional geographic market could and should be established based upon: (1) The presence of an actively traded liquid trading hub within the relevant defined market area; (2) transparent pricing information from that hub being widely available; and (3) the presence of extensive direct or single-wheel transmission access, both for sellers into the competitive hub market and for buyers' access to the hub market for purposes of serving load.[236]

259. Powerex supports the Commission's initial specification of evidence that may be used to support a demonstration of a broader or smaller geographic market. However, Powerex is concerned that the Commission's enumeration of relevant categories of evidence is at present a partial list, and is not sufficiently comprehensive to address the unique circumstances that are likely to be present in various regions. Powerex states that the Commission should clarify that additional types of evidence may also be used to support the propriety of a broader or smaller market definition.

260. One commenter states that the appropriate definition of the relevant geographic market can be (and very often will be) conditional—that is, when there are no binding transmission constraints on imports into the relevant control area, the relevant market appropriately encompasses a broader area than the default geographic market; and when transmission constraints into the control area are binding, the control area is the appropriate geographic market. Accordingly, sellers should be allowed (or encouraged) to present analytical results for several market definitions, dependent on the existence or nonexistence of binding transmission constraints, to sharpen the focus on when market power might be a real concern.[237]

261. APPA/TAPS generally agree that the factors set forth by the Commission for assessing whether an alternative geographic market is appropriate are reasonable, but urge that the factors be non-exclusive and non-prescriptive. In addition to the factors the Commission identified in the NOPR, APPA/TAPS suggest that a seller be allowed to point to any joint transmission planning and coordinated construction processes as evidence that the relevant market should be larger than its own control area.[238] APPA/TAPS state that a seller that is correctly advancing efforts to expand markets deserves to have that recognized and a seller that is not undertaking such efforts should live with the consequences of the resulting smaller market.

262. PPL states that if the Commission is to consider the potential existence of geographic markets smaller or larger than a control area, it should carefully consider the specific circumstances surrounding the control area of concern, and use an objective review process. That is, the Commission should consider these factors through the following means: (1) Evaluation of the historical frequency of, and times when, physical transmission constraints limit the ability to transmit power within and between control areas, RTOs, and other defined regions within which electricity system supply and demand are balanced in real-time; (2) consideration of correlations of electricity prices, and electricity price day-to-day changes, within and between control areas, RTOs, and other defined regions within which electricity supply and demand are balanced in real time; (3) reference to historical evidence of actual transactions (including swaps/exchanges, etc.) wherein power is delivered within, imported to, or exported from, control areas, RTOs and sub-regions of RTOs; and (4) consideration of operational paradigms for obtaining transmission services and the extent to which the system allows for transparent access to transmission services.[239]

263. Several commenters urge the Commission to provide flexibility by suggesting a trading hub for an alternative geographic market. E.ON U.S. and PNM/Tucson state that the Commission should take regional commercial patterns into account when evaluating proposals to use a larger or smaller market, and they support allowing a seller to present a market power analysis specific to a trading hub.[240]

264. Indianapolis P&L asks that the Commission clarify that sellers can propose different geographic definitions in their screen analyses. Indianapolis P&L states that the NOPR is unclear as to whether different geographic markets can be proposed for the indicative screen analyses or only for additional, “second stage” analyses, such as the DPT.[241]

265. Powerex seeks clarification on how the definition of “home control area” (the control area where the seller is located) applies to an entity that has small-volume contracts in multiple control areas remote from its physical location. Powerex asks whether contracts with third parties, to the extent they confer some level of “control,” create a multitude of home control areas. Powerex seeks additional guidance, including whether the answer to the question depends on the quantity of generation available under each contract, the level of control, whether the seller is affiliated with the transmission provider in that control area, or the remoteness of the contracted generation from the sellers' physical location.[242]

266. Duke requests clarification of whether first-tier markets, which are part of a larger RTO/ISO market (with an energy market that has central commitment and dispatch and Commission-approved market monitoring and mitigation) can be represented as the entire RTO/ISO market. For example, in the case of the Duke Energy Carolinas' control area, which is directly interconnected to the AEP transmission system, Duke queries Start Printed Page 39936whether all of PJM would be the relevant first-tier market for purposes of determining the simultaneous import limitations into the Duke Energy Carolinas control area.[243]

Commission Determination

267. As an initial matter, we acknowledge the desire for the Commission to provide greater guidance to sellers wishing to argue for a broader or smaller market definition. We continue to believe that default geographic markets are adequate and sufficient for the typical situation. However, defaults may not be appropriate in all circumstances. Therefore, we will attempt to provide additional guidance and clarification to help inform market participants regarding the factors we believe are significant to consider when defining the market.[244]

268. First, we reiterate that reaching beyond the default geographic market in which an entity is located can mean addressing additional physical and other challenges than when trading within that market. When assessing an alternative geographic market, the Commission looks for assurance that no frequently recurring physical impediments to trade exist within the alternative geographic market that would prevent competing supply in the alternative geographic market from reaching wholesale customers. Any proposal to use an alternative geographic market (i.e., a market other than the default geographic market) must include a demonstration regarding whether there are frequently binding transmission constraints during historical seasonal peaks examined in the screens and at other competitively significant times that prevent competing supply from reaching customers within the proposed alternative geographic market. We will require that a demonstration be made based on historical data and that a sensitivity analysis be performed analyzing under what circumstances transmission constraints would bind. If the seller fails to show that there are no frequently binding constraints at these critical times, then the Commission may not consider other evidence of an expanded market since we regard this as a necessary condition that must be satisfied to justify an expanded market.

269. The Commission also considers whether there is other evidence that would support the existence of an alternative geographic market. In deciding whether customers may be considered as part of an expanded geographic market, the Commission will 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.

270. Any such evidence submitted to show that the seller's customers have access to resources outside of their balancing authority area at terms and conditions similar to those at which they can access resources inside the balancing authority 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 balancing authority 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 balancing authority areas; or 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.

271. In determining whether two or more balancing authority areas are a single market, the Commission would weigh, on a case-by-case basis, all relevant 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.[245]

272. With regard to Puget's request that the Commission provide additional guidance with regard to the levels of price convergence, trading activity, and transmission constraints that define a market, no such generic finding will encompass all possibilities and, therefore, in all instances define the market. Accordingly, we will not attempt to do so here.

273. We also reject Southern's contention that the Commission has somehow rendered “illusory” the opportunity for entities outside RTOs and ISOs to demonstrate a larger geographic market.[246] The examples provided by the Commission of ways an entity could demonstrate a larger geographic market were just that: examples.[247] The Commission does not require an entity proposing an alternative geographic market to provide evidence other than historical transmission access. Sellers and intervenors in both RTO/ISO and non-RTO/ISO markets may present any probative evidence based on historical data of transmission availability, wholesale sales, resource accessibility, and market prices.

274. In response to Indianapolis Power & Light's comments, we clarify that when a seller submits its screen analysis, it can also propose an alternative analysis based on the use of a geographic market larger than the default geographic market. However, such proposal should be made in addition to, not in lieu of, the screen analysis based on the default geographic market.

275. With regard to using trading hubs as alternative market areas, the Commission understands that numerous electricity trading hubs have emerged over the past few years. A trading hub is a representative location at which multiple sellers buy and sell power and ownership changes hands, typically with trading of financial and physical products. For physical trades, the hub may represent a specific delivery point or set of points. Currently only select trading hubs account for the majority of physical power trading although there remains the possibility that market demand could initiate trading hubs for each balancing authority area. In evaluating market power, however, trading hub data alone does not provide a foundation for the Commission to analyze transmission limitations and other transfers of energy. Moreover, with regard to trading hubs, the combination of physical and diverse financial products, the low barriers for Start Printed Page 39937entry of new participants, and the unlimited potential for resale of limited physical output may not provide a reasonable measure of the relevant geographic market under typical situations, as a balancing authority area does. Therefore, while trading data may be considered in the illustration of relevant price correlation or of liquid trading activity to demonstrate that two or more balancing authority areas are indeed a single market, the Commission will not allow use of a trading hub to define a relevant geographic market.

276. With regard to one commenter's suggestion that the Commission should allow (or encourage) sellers to present analytical results for several market definitions because the appropriate definition of the relevant geographic market can be conditioned on the existence or nonexistence of binding transmission constraints, the Commission agrees in principle. The Commission provides an opportunity for sellers who fail one or more of the initial screens to present a more thorough analysis using the DPT. As the April 14 Order states “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 condition.” [248] In addition, in the Merger Policy Statement the Commission stated that the flows on a transmission system can be very different under different supply and demand conditions (e.g. peak vs. off-peak). Consequently, the amount and price of transmission available for suppliers to reach wholesale buyers at different locations throughout the network can vary substantially over time. If this is the case, the DPT analysis should treat these narrower periods separately and separate geographic markets should be defined for each period.[249]

277. The Commission believes that the DPT can address the dynamic nature of markets. Under the DPT, the amount and price of transmission available for suppliers to reach wholesale buyers at different locations throughout the network during different season/load conditions (e.g., peak vs. off-peak) can be analyzed. For example, an area may become constrained only during the highest load levels, in which case the relevant geographic market could differ across seasons, and separate geographic markets could be defined for each period. However, as discussed earlier, in an effort to provide as much regulatory certainty as possible, the Final Rule adopts as the default geographic market the balancing authority area or the RTO footprint, as applicable, but allows sellers or intervenors to propose alternative markets based on historical transmission and sales data.

278. We clarify in response to Powerex that sellers should do market power studies for each balancing authority area where they own or control assets (i.e., should study all balancing authority areas where generation assets they own or control are located) regardless of the quantity or location of generation they control (subject to the terms adopted herein regarding Category 1 sellers). Also, to the extent a market power study is required, sellers should study each balancing authority area where they own or control assets regardless of whether the seller is affiliated with the transmission provider in that balancing authority area. The Commission also clarifies for Duke that if the first-tier markets for a seller (whether or not the seller is a member of the RTO) are part of a larger RTO/ISO market, all of the RTO/ISO market would be a relevant first-tier market for purposes of determining the simultaneous import limitations.

d. Specific Issues Related to Power Pools and SPP

Commission Proposal

279. In the NOPR, the Commission proposed to continue its practice of designating an RTO/ISO in which a seller is located as the default relevant geographic market if the RTO/ISO has sufficient market structure and a single energy market with Commission approved market monitoring and mitigation.

Comments

280. A number of commenters urge the Commission to consider power pools as geographic market areas. Midwest Energy claims that, “under current Commission policy, sellers of power in RTOs/ISOs with a full-fledged single central commitment and dispatch system are allowed to treat the full RTO footprint as the relevant geographic market, thereby facilitating qualification for market-based rates. Sellers in a Commission-approved RTO without a single central commitment and dispatch system are relegated to a relevant market defined by their own control area.” [250] Midwest Energy urges the Commission to consider changing its existing policy to create a presumption that the relevant geographic market for a Commission-approved RTO is the region covered by a single transmission tariff.[251] Alternatively, Midwest Energy states that the Commission could require, in addition to a regional tariff, the implementation of a Commission-approved market monitor and a centrally dispatched energy imbalance market. It states that these changes would allow sellers to treat the Southwest Power Pool (SPP) region as the relevant geographic market.

281. Westar states that the Commission should find that a transmission region with a single OATT, non-pancaked transmission rates, a common OASIS platform for scheduling transmission, and approved market monitoring (e.g., SPP) presumptively qualifies as a single region for purposes of the market power screens. Westar states that although the NOPR identifies single unit commitment and/or centralized dispatch of generation to be an important characteristic of a regional market, the Commission has not always done so. For example, the Commission did not identify this as a defining characteristic when it accepted other RTOs/ISOs as a single region for market-based rate purposes, such as New England. The Commission also did not rely upon centralized dispatch in authorizing market-based power sales across the California, New York or PJM markets. Westar states that the Commission should find that SPP meets the criteria for a single market once its energy imbalance market (EIM) becomes operational.[252]

282. In its reply comments, Southwest Coalition disagrees with those commenters requesting that SPP qualify as a single geographic region for sellers in its region once its EIM is operational. Southwest Coalition states that Westar has not presented any evidence for the Commission to change course with SPP in this rulemaking. It asserts that SPP currently has underway a variety of market implementation proceedings, of which Westar is a party, through which the Commission can make a reasoned decision regarding SPP's status. As such, Southwest Coalition states that this generic rulemaking proceeding is not the appropriate vehicle for considering Westar's request. In addition, Southwest Coalition states that Westar's request represents an improper request for rehearing of the Commission's March 20, 2006 Order in Start Printed Page 39938SPP's market implementation proceeding. Southwest Coalition requests that, if the Commission were to consider Westar's request in this proceeding, the Commission should reject Westar's request for a Commission finding that SPP is a single geographic region for purposes of the Commission's market power screens.[253]

283. Puget argues that applying the control area default to utilities in the Pacific Northwest is arbitrary, and does not result in an accurate measurement of a seller's potential market power in the region's energy markets. According to Puget, the relevant geographic market for the purpose of measuring horizontal market power in the Pacific Northwest is the United States portion of the Northwest Power Pool, which is dominated by a transmission system operated by Bonneville Power Administration. Puget submits that many of the criteria outlined in the NOPR—particularly those addressing parallel price movements, single transmission rates, and active trading—are met in this geographic region. Utilities in the Pacific Northwest would like to have the opportunity to make a showing to the Commission that the relevant geographic market for measuring market power in their region is an area other than their home and first-tier control areas.[254]

Commission Determination

284. We decline to address whether additional regions of the country qualify as relevant geographic markets. Through this Final Rule, we set forth several examples of criteria that sellers can use in proposing an alternative geographic market. Individual sellers can challenge our default geographic market and provide evidence to support their proposal. Intervenors will have the opportunity to comment prior to the Commission rendering a decision.

e. RTO/ISO Exemption

Commission Proposal

285. In the April 14 Order, the Commission concluded that it would no longer exempt sellers located in markets with Commission-approved market monitoring and mitigation from providing generation market power analyses, on the basis that requiring sellers located in such markets to submit screen analyses provides an additional check on the potential for market power.[255] The Commission did not address this point in the NOPR.

Comments

286. In their comments in this proceeding, Reliant, NRG and FirstEnergy urge the Commission to reinstate the exemption.[256] Reliant states that reinstating the exemption would be appropriate because real-time market monitoring by an independent market monitor consistent with Commission-approved rules and Commission-approved targeted mitigation address identification of market power concerns as well as mitigation of market power in those markets and, therefore, eliminate the value of any separate market power analysis submitted by an individual seller. Reliant states that Commission-approved market monitoring and mitigation provide the Commission with a better and more sophisticated picture of market power issues in RTO/ISO markets as compared to a seller's market power analysis, which looks only at market power at a fixed moment in time.

287. Reliant states that if the Commission decides not to reinstate the exemption, it is critical that the Commission continue to use RTO/ISO markets as the default geographic market for sellers with generation located in those markets. Reliant states that the key to the determination of relevant geographic markets is the extent to which sellers can compete in the defined market. RTO/ISO markets with centralized markets provide a platform for all sellers located in the pertinent RTO/ISO market to compete. Thus, Reliant states that it is entirely appropriate to consider such markets as the default market unless and until an intervenor can show that this is no longer appropriate (e.g., due to transmission constraints).[257]

288. In its reply comments, PSEG states that while it believes that the RTO/ISO exemption would be warranted at least for regions with pervasive market monitoring unit (MMU) oversight such as PJM, it recognizes that some affected parties may not be comfortable with a blanket exemption. It suggests that the Commission's regulations should take account of the fact that the Commission has approved comprehensive MMU oversight of markets and that MMUs take their duties seriously and routinely exercise their authority. Accordingly, PSEG proposes that evidence of active MMU oversight supply the basis for obviating the need to conduct a market power study for a particular zone or sub-zone of an RTO or ISO.[258]

289. APPA/TAPS, in contrast, state that reinstating the RTO/ISO exemption would represent an abdication of the Commission's responsibilities.[259]

Commission Determination

290. The Commission declines the request that it reinstate the pre-April 14 Order exemption for sellers located in markets with Commission-approved market monitoring and mitigation from providing generation market power analyses. The Commission will continue to require generation market power analyses from all sellers, including those in RTO/ISO markets. All sellers are required to receive authorization from the Commission prior to undertaking market-based rate sales, and as discussed herein, all new applicants for market-based rate authority are required to, among other things, provide a horizontal market power analysis. The first step for a seller seeking market-based rate authority is to file an application to show that it and its affiliates do not have, or have adequately mitigated, market power. Sellers can refer to RTO/ISO monitoring and mitigating as a factor. We believe that a single market with Commission-approved market monitoring and mitigation and transparent prices provides added protection against a seller's ability to exercise market power but cannot replace the generation market power analysis.

291. To address Reliant's concern, we note that, as discussed above, we will use RTO/ISO markets (including Commission findings with regard to RTO/ISO submarkets) as the default geographic market for the indicative screens for sellers with generation in those markets.

8. Use of Historical Data

Commission Proposal

292. The Commission proposed in the NOPR to retain the “snapshot in time” approach for the indicative screens, so that sellers are required to use the most recently available unadjusted 12 months' historical data. The Start Printed Page 39939Commission stated that historical data are more objective, readily available, and less subject to manipulation than future projections. The Commission proposed to continue to permit sellers to make adjustments to data that are essential to perform the indicative screens provided that the seller fully justifies the need for the adjustments, justifies the methodology used, provides all workpapers in support, and documents the source data.

293. However, the Commission proposed to allow, for the DPT analysis, sellers and intervenors to account for changes in the market that are known and measurable at the time of filing.[260] The Commission noted that this proposal mirrors the Commission's approach in connection with its merger analysis. Sellers and intervenors proposing known and measurable changes to be considered in the DPT analysis would bear the burden of proof for their adjustments to historical data. The Commission sought comment 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, the Commission sought comment on exactly what types of changes should be allowed and under what circumstances.

Comments

294. Various commenters generally support the Commission's proposal to use historical data for the indicative screens and allow known and measurable changes for the DPT.[261] Some suggestions made as to what should be considered known and measurable changes include: Allowing only changes that occur between updated market power analysis filings [262] and allowing only publicly available data or company information.[263] Powerex expresses concern that known and measurable changes may not be publicly available.[264] PG&E suggests that the Commission evaluate on a case-by-case basis whether the seller or intervenor can prove that the change is both foreseeable and reasonable. It says that the Commission should not impose a time restriction on such changes provided that the seller provides the necessary support for changes that it claims are known and measurable.[265]

295. A number of commenters suggest that sellers should be permitted to account for known and measurable changes in both the indicative screens and the DPT.[266] Southern states that the Commission “should not * * * restrict the ability of parties to provide the Commission with the best possible information and analysis.” [267] Duke states that in all instances the objective should be to obtain the most accurate and timely assessment of the seller's ability to exercise market power under current market conditions.[268]

296. NRECA states that the screens should incorporate imminent changes and that an example of known and measurable changes that should be included in initial applications and triennial filings is the capacity freed up by expiring long-term contracts. It submits that these contracts will expire on a known schedule and, if the market is competitive, the seller should not be allowed to assume that the capacity will remain committed to the buyer.[269]

297. PPL argues that long-term contracts should retain the current definition as those expiring in one year or more, and recommends not considering contracts that take effect after one year but before the triennial update is due. It argues that buyers could withhold signing contracts and force a market power finding. PPL also notes that a notice of change in status must be filed at the expiration of contracts that increase the seller's capacity by 100 MW or more and that the Commission can initiate a section 206 investigation at that point if need be.[270]

Commission Determination

298. We will continue to require the use of historical data for both the indicative screens and the DPT in market-based rate cases. The indicative screens are designed as a tool to identify those sellers that raise no generation market power concerns and can otherwise be considered for market-based rate authority. Accordingly, the indicative screens are conservative in nature and not generally subject to debates over projected data, which may unnecessarily prolong proceedings and create regulatory uncertainty. However, in light of adopting a regional approach with regard to regularly scheduled updated market power analyses, we will require the use of the actual historical data for the previous calendar year. Requiring all sellers in a region to provide analyses using the same data set further enhances the Commission's ability to evaluate market power and identify any discrepancies between market studies.

299. After careful consideration of the comments received, the Commission will not adopt the NOPR proposal that the DPT analysis allow sellers and intervenors to account for changes in the market that are known and measurable at the time of filing. Instead, the Commission will adopt its current practice that sellers are required to use, in the preparation of a DPT for a market-based rate analysis, unadjusted historical data and, consistent with the above discussion, the Commission will require the use of the actual historical data for the previous calendar year. The Commission has stated that historical data are more objective, readily available, and less subject to manipulation than future projections.

300. We acknowledge that the Commission's approach in its merger analysis requires applicants and intervenors to account for changes in the market that are known and measurable at the time of filing. However, we find that the purpose of using the DPT in market-based rate proceedings is different from that in merger analysis. Intrinsically, a merger analysis is forward-looking to identify what effect, if any, there will be on competition if the proposed merger is consummated. Even though the Commission has the ability to reopen a merger proceeding under its section 203(b) authority, it is difficult and costly to undo a merger, so the Commission is cognizant of the need to analyze what might happen as a result of a proposed merger and put any necessary mitigation in place prior to consummation of the merger.

301. In contrast, the market-based rate analysis is a “snapshot in time” approach. When the Commission evaluates an application for market-based rate authority, the Commission's focus is on whether the seller passes both of the indicative screens based on unadjusted historical data. Likewise, Start Printed Page 39940when a seller fails one of the screens and the Commission evaluates whether that seller passes the DPT, the Commission's focus is on whether the seller passes the DPT based on unadjusted historical data. The Commission's grant of market-based rate authority is conditioned, among other things, on the seller's obligation to inform the Commission of any change in status from the circumstances the Commission relied upon in granting it market-based rate authority. As such, the Commission's market-based rate program is designed to require sellers to report, and enable the Commission to examine, changes in facts and circumstances on an ongoing basis. Such a reporting requirement provides the Commission with ongoing monitoring in addition to its right to require any market-based rate seller to provide an updated market power analysis at any time. Accordingly, the market-based rate change in status reporting requirement allows the Commission to evaluate changes when they actually happen rather than relying on projections, making it unnecessary and redundant for the Commission to allow sellers to account for known and measurable changes in the DPT for market-based rate purposes. For these reasons and the reasons explained in the April 14 and July 8 Orders and existing Commission precedent, the Commission reaffirms that the indicative screens and DPT analyses should be based on unadjusted historical data.

9. Reporting Format

Commission Proposal

302. In the NOPR, the Commission proposed to require all sellers to submit the results of their indicative screen analysis in a uniform format to the maximum extent practicable and appended a proposed format. This format, provided in Appendix C of the NOPR, was intended to promote consistency and aid the Commission in the decision-making process. The Commission sought comment on this proposal.

Comments

303. Although only a few comments were received on this topic, those comments support the proposal to adopt a uniform reporting format for the indicative screens. APPA/TAPS suggest that the proposed uniform format should help all market participants, especially when assessing the filings of a number of public utilities as part of the proposed regional review process. APPA/TAPS state that the uniformity should also help the Commission analyze market-based rate filings on a consistent basis, thus increasing market participant confidence in those assessments.[271] Other commenters concur with the Commission's proposal for a uniform reporting format. They state that a uniform reporting format will increase consistency and thus aid the Commission in its decision making process.[272]

304. One commenter suggests formatting and presentation changes to the NOPR's Appendix C reporting form. These changes include creating sections for items such as the calculation of seller and market uncommitted capacity and rearranging some in a more logical fashion.[273]

Commission Determination

305. We will adopt the reporting format as proposed in the NOPR, maintaining the same order of items as in the form provided in Appendix C of the NOPR, but note that this form now appears as Appendix A of this Final Rule. We believe standardizing the submission format has benefits to all market participants. As noted, it appears that commenters as well are generally supportive of this proposal to require all sellers to submit the results of their indicative screen analyses in a uniform format.

306. Also, we will adopt many of the formatting changes suggested in the comments. The row letter will be the first column and a better delineation of sections will increase the comprehensibility of the form. The revised form can be found in Appendix A.[274]

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

a. Elimination of Exemption in Section 35.27(a)

Commission Proposal

307. The Commission's regulations provide that any public utility seeking authorization to engage in market-based rate sales is not required to demonstrate a lack of market power in generation with respect to sales from capacity for which construction commenced on or after July 9, 1996.[275] In the NOPR, the Commission noted that when it established the exemption in Order No. 888 it indicated that it would consider whether a seller citing § 35.27(a) nevertheless possesses horizontal market power if specific evidence is presented by an intervenor.[276]

308. The Commission stated in the NOPR that although it remains committed to encouraging new entry of generation, it is concerned that the continued use of the § 35.27(a) exemption may become too broad and, over time, would encompass all market participants as all pre-July 9, 1996 generation is retired. Accordingly, the Commission proposed in the NOPR to eliminate the exemption in § 35.27(a) and to require that all new sellers seeking market-based rate authority on or after the effective date of the Final Rule and all sellers filing updated market power analyses on or after the effective date of the Final Rule must provide a horizontal market power analysis of all of their generation, whether or not it was built after July 9, 1996. Because the Commission allows a seller to make simplifying assumptions where appropriate and to submit a streamlined analysis, the Commission explained that any additional burden imposed on sellers by this reform would be minimal. In addition, the Commission anticipated that those entities that otherwise would have relied on the exemption would, in most cases, qualify as Category 1 sellers and therefore no longer be required to file updated market power analyses as a routine matter. The Commission sought comment on this proposal.

Comments

309. Many commenters support the Commission's proposed elimination of the § 35.27(a) exemption, stating that there should be a level playing field for market-based rate sellers so that all market participants would be required to perform the generation market power screens.[277] A number of commenters support the Commission's position that there is a valid concern that over time the exemption would encompass all generation as older generating units are Start Printed Page 39941retired and new generation is built.[278] Several commenters state that the Commission correctly observes that the indefinite continuation of the exemption would ultimately result in the automatic grant of market-based rate authority to all sellers as pre-1996 generation is retired.[279] They further state that eliminating the exemption will not impose significant new burdens, deter new entry into a market, or create any unreasonable disincentive or impediment for the construction of future generating capacity.[280] Contrary to the assertions of several commenters, FirstEnergy states that the elimination would encourage merchant power developers to expand generation in markets where they do not already have a dominant position which, in turn, would dilute market power concerns in these markets.

310. NRECA and APPA/TAPS maintain that, despite EPSA's, Mirant's, and PPL's assertions to the contrary,[281] the Commission did not create the exemption as an incentive to encourage new generation investment.[282] APPA/TAPS elaborates further, agreeing with the Commission that many new entrants would qualify as Category 1 sellers and, therefore, would not have to submit updated market power analyses and that other entrants could make simplifying assumptions to demonstrate that they qualify for market-based rate authority.[283] These commenters contend that the benefits of eliminating the exemption far outweigh any added burdens to ensure that all market participants are treated equally and to ensure that rates for jurisdictional sellers are just and reasonable.[284]

311. In support of the elimination of the § 35.27(a) exemption, NASUCA acknowledges that 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 seller is not required to provide a horizontal market power analysis because of the exemption under § 35.27(a).[285] NASUCA asserts that under the current rule, there is no limit on the amount of post-July 9, 1996 generation that could be exempt from the Commission's analysis of market power. In addition, a commenter explains that the potential to exercise market power has no relation to whether generating plants were built before or after 1996.[286] ELCON suggests that generators that were built after July 9, 1996 are capable of exercising market power.[287] In addition, FirstEnergy points out that merchant power plant developers have begun to aggregate fleets of newer generating plants to which this exemption is applicable, and may now be able to exercise generation market power.[288] PG&E adds, “in situations where all generation owned or controlled by an applicant and its affiliates in the relevant market is new generation, should they control sufficient generation, the applicants and its affiliates may freely exercise market power.” [289] In addition, Morgan Stanley supports elimination of the exemption, stating that maintaining the exemption would have unintended consequences going forward.[290]

312. Among those who oppose elimination of the exemption, Constellation asserts that it would send an unfavorable signal to market participants that the rules may be changed with a retroactive effect, which in turn would deter investment.[291] Constellation also contends that the Commission offers no support and/or analysis to demonstrate its inference that older generating units will be retired in significant quantities to make a substantial difference to the screening analysis of any seller. PPL submits, among other ill-effects, that the elimination will deter investment in areas where there is a limited supply and the new entrant may be deemed pivotal. In addition, PPL contends that some sellers relied on the presumption that they would not need to demonstrate a lack of market power in financing, constructing, and operating their new power plants.[292]

313. EPSA opposes the elimination of the exemption under § 35.27(a). EPSA states that the electric industry needs incentives for new generation and does not need disincentives if capital is to be invested on a timely basis to meet future demand and enhance competition.[293] EPSA asserts that the exemption encourages the development of competitive supply outside of organized markets.[294] Similarly, NRG contends that the elimination of the § 35.27(a) exemption will delay and deter investment in load pockets. NRG also argues that eliminating the exemption runs counter to the Commission's policy of encouraging investment in electric power infrastructure to enhance reliability and market liquidity.[295]

314. In addition, EPSA argues that the purpose of the exemption was to encourage new generation investment by competitive suppliers, especially in areas of the country that are mostly dominated by utility-owned generation.[296] Specifically, EPSA explains that it is in these regions of the country where affiliated generation is largely treated as native load and, thus, is excluded from the market power analysis even though it represents most of the capacity in the region.[297] EPSA explains that, even if a small increment of competitive supply is introduced into the market, the analysis might detect market power when measured against relatively small existing generation. Therefore, without the exemption, a new competitive supplier would fail the test and would have to utilize cost-based rates.[298]

315. Allegheny argues that the Commission overlooks the reason why it initially adopted the exemption. Allegheny states that, in Order No. 888, the Commission determined that long-term generation markets are competitive.[299] Allegheny further argues that “the Commission cannot `gloss over' its prior reasoning without discussion, and without showing that there has been a fundamental change in facts and circumstances that have [sic] caused long-term markets to be no Start Printed Page 39942longer competitive.” [300] PPL asserts that the Commission in Order No. 888 recognized the power that the opportunity of free entry has to eliminate market power concerns and stated that open access advancements removed structural impediments for new entrants competing with existing market participants.[301]

316. Mirant and EPSA expand on arguments that eliminating the exemption will deter investment. They argue that, when reserve levels are tight in a control area where the host utility has lost or forgone its market-based rate authority, a competitive supplier would have to weigh the risks as to whether the Commission would authorize it to make market-based rate sales if it were to build a new asset in that control area.[302] They contend that there is no incentive for a competitive supplier to build new generation if its sales will be mitigated at some level of cost-based rates.[303] In particular, Mirant explains that if a municipal utility issued a request for proposals (RFP) for 600 MW of power commencing in 2010 and terminating in 2020, with the current exemption competitive suppliers could bid on the RFP knowing that the supplier would be authorized to sell the output of its new generating station at market-based rates. However, Mirant asserts that if the exemption were eliminated, a supplier would have to get Commission approval for market-based rate sales prior to bidding on the RFP.[304]

317. Mirant disagrees with the Commission's contention that eliminating the exemption would not affect many sellers and that the cost of compliance would be minimal. Mirant states that five of its subsidiaries would have to file updated market power analyses if the exemption were eliminated because they own more than 500 MW in the relevant market or control area and would not qualify as Category 1 sellers. Mirant argues that its cost of compliance would increase because it would have to prepare four updated market power analyses, each costing $20,000 to prepare and file.[305] In its reply comments, APPA/TAPS state that Mirant's increased cost is paltry compared to the over $3.4 billion in generation revenues reported by Mirant in 2005, which APPA/TAPS suggest is in no small part due to Mirant's market-based rate sales.[306]

318. Some commenters contend that the Commission's concern that over time all older generation will be retired and the Commission will be unable to analyze sellers for market power is not a valid concern in the immediate or mid-term; they state that the most recent retirement announcements concern generation assets that were built in the 1940s and 1950s.[307] PPM and Allegheny argue that the Commission offers no evidence or observations to quantify the magnitude of future retirements.[308] Some commenters assert that, in order for this speculative concern to become realistic, the retirement of generating units that were constructed in the 1980s would have to become commonplace, and it will take decades for this situation to materialize. As such, they suggest that the Commission revisit this issue in 5 to 10 years rather than act prematurely.[309]

319. PPM suggests that, if the Commission wishes to limit the overall amount of generation that is exempt for purposes of conducting a horizontal market power analysis, an alternative approach would be to keep the exemption and phase in exempted units over time. Thus, units that were built after 1996 but before 1999 would lose the exemption in 2010, while facilities built in 2001 would lose it in 2015, and so on.[310]

Commission Determination

320. The Commission adopts the proposal set forth in the NOPR and eliminates the exemption provided in § 35.27(a). All sellers seeking market-based rate authority, or filing updated market power analyses, on or after the effective date of this Final Rule must provide a horizontal market power analysis for all of the generation they own or control. As a number of commenters recognize, over time the exemption would become too broad and would encompass all market participants as pre-July 9, 1996 generation is retired. In addition, we note that even assuming for the sake of argument that there are not a large number of retirements, the current exemption would allow sellers to grow unabated as load increases and could result in such sellers gaining a dominant position in the market without being subject to any horizontal market power analysis. Thus, continuing the exemption would result in unintended consequences where all sellers would be given an automatic presumption that they lack market power in generation. Accordingly, the Commission finds that eliminating the exemption in § 35.27(a) and requiring every new seller to submit a generation market power analysis will allow the Commission to ensure that the seller does not have market power in generation.[311]

321. We do not believe that this change will have an adverse effect on the majority of sellers that have previously relied on the § 35.27(a) exemption. The sellers that have taken advantage of the exemption will largely qualify as Category 1 sellers, and thus will be unaffected to the extent that they will not be required to file a regularly scheduled updated market power analysis. For those sellers seeking market-based rate authority for the first time (e.g., building new generation facilities), and those that do not qualify as Category 1 sellers, there are several mechanisms or alternatives that can help to minimize the burden of submitting a horizontal market power analysis. For example, a seller, where appropriate, can make simplifying assumptions, such as performing the indicative screens assuming no import capacity or treating the host balancing authority area utility as the only other competitor.[312] We expect that, for most sellers, the cost of compliance and document preparation occasioned by the elimination of § 35.27(a) will not be burdensome. To the extent that there are greater costs for some sellers, we find that the benefit of ensuring that markets do not become less competitive over time outweighs any additional costs. Equally important, the elimination of § 35.27(a) will place all sellers on the same footing. On this basis, we disagree with commenters that eliminating the exemption would send an unfavorable Start Printed Page 39943signal to market participants and deter investment.

322. We also disagree with commenters that find our rationale for adopting the exemption in 1996 necessarily constrains our decision making at this time. In light of our experience over the past decade and our desire to have a more rigorous market-based rate program, combined with the concern that over time generation will be retired, we believe a more conservative approach for granting market-based rate authority is appropriate and will provide us a better means to ensure that customers are protected.

323. We find unpersuasive Mirant's concern that, if the § 35.27 exemption were eliminated, a seller would have to get Commission approval for market-based rate sales prior to bidding on an RFP. If Mirant is concerned that certain RFPs require, among other things, that all bidders have in place all regulatory requirements including any applicable market-based rate authority, we find that RFPs typically afford bidders ample opportunity to put together their bids and put in place any necessary regulatory approvals. In this regard, we note that if a potential seller wishes to participate in an RFP but does not have market-based rate authority, the seller can file for such authorization and request expedited treatment and the Commission will use its best efforts to process the request as quickly as possible.

324. With regard to the specific argument raised by Mirant, if a prospective seller wins an RFP, then the capacity would be counted as committed capacity, and therefore would not adversely affect the results of the seller's generation market power screen (which analyzes uncommitted capacity). If the entity loses the RFP, then it would not build the plant. In either case, the need for market-based rate authorization does not appear to discourage new investment by competitive suppliers as Mirant suggests.

325. Some commenters assert that the retirement of generating units that were constructed in the 1980s would have to become commonplace before the Commission's concern is realized that over time all older generation will be retired. Others contend that it will take decades for this situation to materialize. However, commenters have provided no evidence that the elimination of § 35.27(a) will create a regulatory barrier to new construction or otherwise depress the building of new generation facilities, and we need not wait for an inevitable adverse circumstance to materialize.

326. Finally, we will not implement PPM's suggestion that we retain the exemption and apply a phasing in approach whereby generating units would lose the exemption over time based on the date on which the units were built. Such an approach would create several “classes” of generation facilities which would result in confusion for both the Commission and market participants. This confusion would become more acute in situations where market participants may own a number of generating facilities located in the same balancing authority area or relevant geographic market, each of which may be considered a different “class” of generator in terms of filing horizontal market power analyses. Moreover, given the regional review and schedule for updated market power analyses discussed below in this rule, we believe that a phased-in approach would become overly problematic and unmanageable for market participants as a whole. Therefore, we will not accept PPM's suggestion.

b. Grandfathering

Comments

327. EPSA and Mirant suggest grandfathering units for which construction commenced between July 9, 1996 and May 19, 2006, the date of issuance of the NOPR, when generation owners were put on notice that the Commission was considering eliminating the exemption in § 35.27(a).[313] Constellation proposes that the exemption not be eliminated entirely but be limited to generation with construction that commenced on or after July 9, 1996, but before the effective date of the Final Rule in this proceeding.[314] Constellation and EPSA also contend that this would be consistent with the Commission's prior decision to grandfather from PJM's mitigation any generating units that were built in reliance on the post-1996 exemption.[315]

328. Although NASUCA agrees with the Commission's proposal to eliminate the new generator exemption, NASUCA raises a concern about the prospective treatment of sellers with generating plants built after July 9, 1996 that initially received market-based rate authority without any generation market power assessment. NASUCA notes that its understanding is that, “the Commission would effectively “grandfather” the market-based rate status for owners of these newer power plants,[316] at least until the time of the next applicable triennial review, when a market power analysis would be required for continuation of market-based rate authority.” [317] Specifically, NASUCA explains that a Category 2 seller who recently obtained market-based rate authority, could have up to three years of future market-based rate sales with no review of its horizontal market power, while any that fall into Category 1 would be exempted entirely from the triennial review process and thus “grandfathered” indefinitely and able to sell at market-based rates without passing any market power test. If this “grandfathering” is not intended, then, according to NASUCA, the Commission should clarify that new market power assessments must be made now for those sellers whose market power has never been reviewed.[318] Otherwise, NASUCA contends that their rates could be vulnerable to challenge because they are established solely on the basis of market price.[319]

Commission Determination

329. We will not adopt commenters' proposals with regard to the grandfathering of any generating units that were built relying on the exemption in § 35.27(a). As discussed above, we find establishing “classes” of generation facilities would result in confusion for both the Commission and market participants. In this regard, no Start Printed Page 39944commenter has demonstrated that harm would result from having to submit a horizontal market power analysis, and no commenter has claimed that it would lose its financing or that its financing would be adversely affected as a result of the elimination of the exemption in § 35.27(a). Moreover, as the Commission stated in Order No. 888, intervenors could present evidence that a seller seeking market-based rates for sales from new generation possesses market power, and sellers were aware that they may have to submit a horizontal market power analysis even if their generation fell within the exemption.[320] Therefore, we will require that all sellers seeking market-based rate authority for the first time on or after the effective date of the Final Rule in this proceeding must provide a horizontal market power analysis that includes all generation that the seller owns or controls.

330. All existing sellers that fall in Category 2 must provide a horizontal market power analysis that includes all generation that each seller owns or controls when it files its regularly scheduled updated market power analysis. To the extent a Category 1 seller acquires enough generation to be reclassified as a Category 2 seller, that seller will be required to submit a change in status report and provide a horizontal market power analysis.

331. Further, with regard to PJM, in establishing whether units constructed after July 9, 1996 should be exempt from PJM's existing market power mitigation rules, we initially approved the post-1996 exemption based on the concern that the price cap regulation or the mitigation rules in PJM might deter market entry and would create certain equity issues. However, we reconsidered our position and found that the exemption was unduly discriminatory by creating two classes of reliability must run generators: one that is price or offer capped and another that is not. Equally important, other RTOs/ISOs applied local market mitigation rules to all generation within their respective areas regardless of when the generator was built, and we determined that comparable authority for PJM would allow it to address local market power issues.[321] We concluded that units built on or after July 9, 1996 had the same ability to exercise market power as counterparts that were built prior to July 9, 1996. Accordingly, the Commission terminated the blanket exemption, but in the case of units that were built with the expectation that they would not be subject to mitigation, the Commission allowed the exemption to be grandfathered.[322]

332. Our reasons for grandfathering units in PJM are dissimilar enough that our holding in the PJM orders should not affect our decision here. The factors that led to the establishment and later the termination of the exemption from mitigation in PJM are unrelated to the reasons for instituting and, now, eliminating the express exemption in § 35.27(a). In PJM and PJM II, the Commission considered whether local market power mitigation might deter new entry and whether new units were built with the expectation that they would not be subject to mitigation. The Commission grandfathered units that could reasonably have relied on the exemption after it went into effect in their zone.[323] In contrast, in this proceeding the Commission desires a more rigorous market-based rate program and is concerned that over time generation will be retired leaving less and less generation subject to our horizontal analysis or sellers relying on the § 35.27 exemption will otherwise grow to a degree that they have market power in the relevant market in which they are located. The Commission's primary statutory obligation under FPA sections 205 and 206 is to ensure that rates are just and reasonable, and we believe the elimination of the exemption will better provide us with the ability to screen all market participants' ability to exercise horizontal market power regardless of whether their generation units were constructed before or after July 9, 1996. Therefore, we will not allow any grandfathering as part of this proceeding.

333. NASUCA's concerns regarding entities that originally enjoyed the § 35.27 exemption are addressed by our decision, discussed below in the Implementation Process section of this Final Rule, to require a seller that believes it qualifies as Category 1 to make a filing with the Commission at the time that its updated market power analysis for the seller's region would otherwise be due (based on the regional schedule set forth in Appendix D). That filing should explain why the seller meets the Category 1 criteria and should include a list of all generation assets (including nameplate or seasonal capacity amounts) owned or controlled by the seller and its affiliates grouped by balancing authority area. Thus, a seller that previously qualified for the § 35.27 exemption and that believes it qualifies as a Category 1 seller would be required to provide support for its claim to Category 1 status. This filing will give the Commission and interested parties an opportunity to review and, if appropriate, challenge a seller's claim that it qualifies as a Category 1 seller. To the extent that an intervenor has concerns about a seller's potential to exercise market power, the Commission will entertain them at that time.[324] In addition, a seller that previously qualified for the § 35.27 exemption and that believes it qualifies as a Category 2 seller will be required to file an updated market power analysis based on the regional schedule set forth in Appendix D.

334. While it is true that a portion of these sellers will continue to sell at market-based rates for a time until their updated market power analyses (in the case of Category 2 sellers) or their filings addressing qualification as Category 1 sellers are due, no commenter has submitted compelling evidence that Category 1 sellers have unmitigated market power. We will rely on our change in status requirements that require, among other things, all sellers that obtain or acquire a net increase of 100 MW in owned or controlled generation to make a filing with the Commission and to provide the effect, if any, such an increase in generation has on the indicative screens. Additionally, all sellers must file EQRs of transactions no later than 30 days after the end of each reporting quarter. Furthermore, the Commission retains the ability to require an updated market power analysis from any seller at any time. With these procedures in place, we believe NASUCA's concerns are addressed.

c. Creation of a Safe Harbor

Comments

335. NRG urges the Commission to create a “safe harbor” such that “if the generation owner controls less than 20 percent of the capacity in an organized market, the Commission should irrebuttably presume that the new entry will not contribute to market power and thus no demonstration is required to obtain market-based rate authority for the new capacity.” [325] NRG states that Start Printed Page 39945only where an owner controls more than 20 percent of capacity in a relevant market should the presumption be rebuttable and subject to challenge by intervening parties. It is NRG's contention that the creation of such a “safe harbor” retains most of the benefits of the Commission's current policy under § 35.27(a), while preserving its flexibility to investigate where a seller adding generating capacity already has a large market share. NRG believes that this codifies the general approach the Commission took in Order No. 888 [326] and responds to the Commission's evolving concerns in this area, while at the same time facilitating new entry in the organized markets where sufficient safeguards exist.[327] NRG contends that new generation, timely developed and brought online, is imperative; thus, a “safe harbor” for new generation is necessary.

336. Ameren agrees that there is a need for the Commission to address the § 35.27 exemption before it encompasses all generating capacity; however, Ameren submits that the Commission should allow an exemption for new generation under certain circumstances. Ameren argues that “the Commission should amend its regulations to provide that new generation that represents less than 20 percent of the uncommitted capacity at peak in the relevant geographic market be exempt from the requirement of a horizontal market power analysis, so long as the owner of, or entity that controls, such capacity and its affiliates own no other generation or transmission facilities (other than interconnection facilities) in the relevant market.” [328] Ameren submits that the Commission should allow the seller to file a letter which identifies: (1) The transmission system it is interconnected to; (2) the amount of uncommitted capacity it controls; and (3) the Commission-approved market power study that it relied on to determine that its uncommitted capacity is less than twenty percent of the net uncommitted capacity in the relevant geographic market. Ameren contends that this abbreviated process would reduce a seller's cost of compliance and administrative burdens.[329]

Commission Determination

337. The Commission will not create a safe harbor.[330] For the reasons set forth in the April 14 Order and reiterated in the July 8 Order, there will be no safe harbor exemption from the generation market power screen based upon a seller's size.[331] While there is no safe harbor exemption from the screens based on the seller's size, any seller, regardless of size, has the option of making simplifying assumptions in its analysis where appropriate that do not affect the underlying methodology utilized by these screens.

338. Further, while we eliminate the § 35.27 exemption in this Final Rule, we note that sellers that have enjoyed that exemption historically have been required to address the other parts of the market-based rate analysis, vertical market power, affiliate abuse, and other barriers to entry.[332] Therefore, the Commission believes that, on balance, any additional cost of compliance or administrative burden due to this change will not be substantial compared to a seller's investment and revenues.[333]

11. Nameplate Capacity

Commission Proposal

339. In the NOPR, the Commission proposed to allow sellers the option of using seasonal capacity instead of nameplate capacity, as is currently required. The Commission indicated that the seller must be consistent in its choice and thus must choose either seasonal or nameplate capacity and use it consistently throughout the analysis. The Commission stated that it believed the use of seasonal capacity ratings 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. The Commission added that it did not think the use of such ratings will materially impact results. The Commission sought comment on this proposal, including comment as to whether this information is publicly available to all market participants.

Comments

340. Many commenters on this topic express strong support for the proposal to substitute seasonal capacity for nameplate capacity.[334] The reason most commonly cited is that seasonal capacity is a more accurate representation of actual output. Several commenters state that firms should be allowed to use net seasonal capacity,[335] which allows for station service requirements and energy consumed by environmental equipment. MidAmerican points out that station usage, including environmental equipment, can approach 10 percent of overall output in steam plants.[336] EEI states that coal plants, which make up 51 percent of generation in the United States, are required to comply with both Federal and State regulations that mandate emission reductions. The plants are equipped with scrubbers and other emissions reduction technology that require a portion of the power produced by the plant in order to operate, thereby reducing the output available to serve customers. For companies with a large percentage of their generation coming from coal, the reduced output from such equipment could be significant.[337] PG&E favors using seasonal capacity if it could be filed confidentially, because it maintains that it is commercially sensitive information.[338]

341. PG&E requests clarification that if sellers are allowed to submit seasonal capacity, they are allowed to de-rate Start Printed Page 39946hydroelectric capacity resources based on historical output for the past five years, as specified in the April 14 Order.[339] Powerex supports seasonal ratings as more accurate, because hydroelectric systems are often able to generate in excess of nameplate ratings and these “peak capability” ratings are typically reflected in seasonal determinations, and seasonal ratings better reflect operating conditions that can impact the capacity ratings of renewable resources.[340]

342. APPA/TAPS support the adoption of seasonal capacity ratings if they are consistently used, and request that the Commission clarify that the seasonal capacity ratings be used for all plants in a geographic region “so that the consistency benefits of the regional reviews are not diminished.” [341]

Commission Determination

343. We will adopt the NOPR proposal that allows sellers to use seasonal capacity. We clarify that each seller must be consistent in its choice and thus must choose either seasonal or nameplate capacity and use it consistently throughout the analysis. In addition, a seller using seasonal capacity must identify in its submittal from what source the data was obtained.[342] We also note and adopt the Energy Information Administration (EIA) definition of seasonal capacity as it is reported on Form EIA-860, Schedule 3, Part B, Line 2, which provides that seasonal capacity is the “net summer or winter capacity.” [343] EIA instructions elaborate that “net capacity should reflect a reduction in capacity due to electricity use for station service or auxiliaries,” [344] which includes scrubbers and other environmental devices.

344. With regard to energy-limited resources, such as hydroelectric and wind capacity, in lieu of using nameplate or seasonal capacity in their submissions, we will allow such resources to provide an analysis based on historical capacity factors reflecting the use of a five-year average capacity factor including a sensitivity test using the lowest capacity factor in the previous five years, and in recognition of Powerex's concern that hydroelectric systems can generate in excess of nameplate ratings and these “peak capability” ratings, the highest capacity factor in the previous five years. Our approach in this regard will more accurately capture hydroelectric or wind availability.[345]

345. We will not adopt APPA/TAPS' suggestion that we require use of either nameplate capacity or seasonal capacity throughout a region. While we appreciate APPA/TAPS' concern for data consistency for analysis purposes, we note that although we adopt a regional approach for the filing of updated market power analyses, the horizontal market power analysis itself continues to focus on the seller seeking to obtain or retain market-based rate authority. We find that consistency of data is critical within each individual analysis as results could vary depending on the assumptions taken. However, because we are not necessarily analyzing the entire region within a single study, we will not mandate the use of either nameplate capacity or seasonal capacity on a regional basis, but instead will allow sellers to choose either nameplate or seasonal capacity, and require them to identify the choice and use it consistently throughout the analysis.[346]

12. Transmission Imports

346. In the NOPR, the Commission proposed to continue to measure limits on the amount of capacity that can be imported into a relevant market based on the results of a simultaneous transmission import capability study. 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.[347] 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 Transmission Reliability Margin) as defined in the tariff and that existed during each seasonal peak. The “contingency” model should use the same assumptions used historically by the transmission provider in approximating its control area import capability.

347. The Commission also proposed to reaffirm the exclusion of control areas that are second-tier to the control area being studied. In addition, it proposed that a seller's pro rata share of simultaneous transmission import capability should be allocated between the seller and its competitors based on uncommitted capacity. The Commission sought comment on this proposal.

a. Use of Historical Conditions and OASIS Practices

Comments

348. Montana Counsel states that transmission capability used in the tests should not be greater than the capability measures that are shown on the OASIS or that are used to measure ATC into markets unless there is a demonstrated change in available transmission capability.[348] In particular, Montana Counsel states that the Commission's requirement that sellers follow historical OASIS practice during each historical seasonal peak is essential; otherwise, companies could submit screens using transmission availability numbers that differ substantially from those which sellers and transmission Start Printed Page 39947providers use in day-to-day activities in providing transmission market access.[349] In Montana Counsel's view, one cannot rely on capacity being able to reach a market based upon hypothetical transmission availability, as the Commission appropriately recognizes.

349. In response to Montana Counsel's assertion to use OASIS postings, PPL Companies maintain that the Commission should continue to use simultaneous import limit studies. OASIS postings do not adjust for transmission rights controlled by unaffiliated resources that may be used to compete against the seller in wholesale markets. PPL Companies state: “The Commission should reject this proposal and continue to rely on [SILs]. The Commission properly has found that using actual OASIS postings understates import capability because OASIS postings do not take into account the capacity that may be imported as a result of existing reservations.”[350]

350. EEI and Southern request clarification of a perceived conflict in Appendix E, which instructs sellers to use Commission criteria for calculating simultaneous import capability and also to strictly follow their OASIS practices.[351] They recommend that the Commission clarify that if historical practices are different from Appendix E, historical practices should be used to calculate simultaneous transmission import capability and to allocate this transmission capability.

351. Duke asserts that scaling methods for calculating simultaneous transmission import capability should not be solely limited to historical practices used by the seller to post ATC on OASIS. Duke proposes a collaborative method involving the seller and transmission customers. Duke states: “the Commission should allow applicants flexibility to use the appropriate methodology for SIL determinations including collaborative, regional efforts—so that screen results for control area markets can be accurate. For example, the Commission should not be overly prescriptive as to the scaling methodology to be used in such a collaborative effort, as long as the methodology is clearly defined and supported by the applicants.”[352] PPL Companies support the collaborative effort proposed by Duke, stating that sellers should have “the option of proposing alternative [SILs] for first-tier markets, but would have to justify and document the proposed deviations.”[353]

352. Southern states that the SIL study requires “blind” scaling (scaling that does not consider economic dispatch) because only generation that is “on-line” is used. Southern states that to the extent a transmission provider does not customarily employ blind scaling, its use would not be consistent with historical practice. It asserts that a problem with blind scaling is that it does not necessarily reflect reality and therefore has the potential to understate, perhaps significantly, the simultaneous import limit.[354] EEI seeks clarification that the Commission is not requiring blind scaling in a manner that requires proportionate increases and decreases to generation resources. EEI requests clarification that scaling is allowed to include expert judgment reflecting how generation resources would likely be scaled up or down in a real-time operating environment. EEI contends that expert judgment in some cases may determine simultaneous import capability by scaling load rather than generation resources. EEI requests that the Commission defer to expert judgment in scaling and not be overly prescriptive as to whether generation or load is scaled to determine simultaneous import capability.[355]

353. PPL Companies contend the simultaneous import capability should not be limited by load in a control area. Since generators within the control area may sell power within or outside the control area, the Commission should consider the market prices of surrounding regions. If the prices are 105 percent or less, compared to control area prices, then the Commission should assume the resident control area resources will remain within the control area and not result in economic withholding within the seller's area.[356]

Commission Determination

354. The Commission will continue to require sellers to submit the Appendix E analysis, i.e., the SIL study, to calculate aggregated simultaneous transfer capability into the balancing authority area being studied.[357] The Commission reaffirms that the SIL study is “intended to provide a reasonable simulation of historical conditions” [358] and is not “a theoretical maximum import capability or best import case scenario.” [359] To determine the amount of transfer capability under the SIL study, “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) are reflected.” [360] In addition, the “analysis should not deviate from” and “must reasonably reflect” its OASIS operating practices[361] and “the techniques used must have been historically available to customers.” [362] We also reaffirm that the power flow cases (which are used as inputs to the SIL study) should represent the transmission provider's tariff provisions and firm/network reservations held by seller/affiliate resources during the most recent seasonal peaks.[363]

355. The Commission will also continue to allow sensitivity studies, but the sensitivity studies must be filed in addition to, and not in lieu of, an SIL study. We clarify that sensitivity studies are intended to provide the seller with the ability to modify inputs to the SIL study such as generation dispatch, demand scaling, the addition of new transmission and generation facilities Start Printed Page 39948(and the retirement of facilities), major outages, and demand response.[364]

356. The Commission agrees with Montana Counsel and clarifies for PPL Companies that a SIL study must reflect transmission capability no greater than the capability measures that were historically shown on the OASIS or that were historically used to measure transmission capability into markets unless there is a demonstrated change in transmission capability, and account for the actual practice of posting ATC to OASIS in order to capture a realistic approximation of first-tier generation access to the seller's market. Further, and in response to EEI and Southern's comments, the Commission clarifies that when actual OASIS practices conflict with the instructions of Appendix E, sellers should follow OASIS practices and must provide adequate support in the form of documentation of these processes.

357. We disagree with Duke's argument that a seller's (generation or load) scaling methods should not be limited to historical OASIS practices when conducting an SIL. Using historical practices provides an appropriate method to obtain a transparent and measurable analysis of a seller's actual balancing authority area transmission conditions and practices. Improper or theoretical scaling methods which do not represent a seller's actual transmission practices may have the effect of allowing more competing generation into the balancing authority area than could actually be accommodated. This in turn has the effect of reducing a seller's generation market share and perhaps causing the seller to inappropriately pass the market share screen (a false negative).[365] In addition, relying on historical OASIS practices gives a seller the data needed to support its conclusions.

358. With regard to Duke and PPL's request that the Commission allow sellers to submit a flexible SIL study based on regional collaboration, the Commission finds that such an approach does not satisfy our concerns and may result in an unrealistic representation of the market.

359. Southern states that to the extent a transmission provider does not customarily employ blind scaling, its use would not be consistent with historical practice.

We agree and, as noted herein, the horizontal analysis and the SIL study are designed to study historical and realistic conditions during peak seasons. Accordingly, in this circumstance, sellers should follow their OASIS practices and must provide adequate support in the form of documentation of these processes.

360. With regard to EEI's argument that the Commission should consider allowing expert judgment in predicting real-time scaling techniques that will likely be used in real-time market environments, the Commission requires the use of a study that captures historical transmission operating practices. The SIL study is not a prediction of import possibilities; rather, it is a simulation of historical conditions. We assume that such historical conditions are the result of “expert judgment” used when determining generation dispatch and/or scaling techniques to make transmission capacity available during actual system conditions. Accordingly, this expert judgment is captured when conducting an SIL study that is based on historical operating practices.

361. In response to PPL's comments that the SIL should not be limited by load in a balancing authority area, the Commission reiterates that the SIL study is a benchmark of historical conditions, including peak load. It is a study to determine how much competitive supply from remote resources can serve load in the study area. Increasing the load in the study area beyond historical peak levels makes the study less realistic and can bias the study.[366] The Commission does, however, consider sensitivity studies on a case-by-case basis, when submitted in addition to the SIL study and supported by record evidence. For example, in Puget Sound Energy, Inc.'s (Puget) updated market power analysis filing, Puget demonstrated that the simultaneous transmission import limit was greater than the peak load in its balancing authority area, and the Commission allowed Puget to use a simultaneous transmission import limit based on its peak load.[367]

362. PPL also contends the simultaneous import capability should not be limited by load in a balancing authority area since generators within the balancing authority area may sell power within or outside the balancing authority area. Accordingly, PPL believes that the Commission should consider the market prices of surrounding regions. The Commission disagrees. We base the SIL on historical conditions that actually existed during the study periods. In this regard, PPL has provided no compelling reason for the Commission to abandon historical evidence in favor of a theoretical estimation of what could have occurred. We find that PPL's approach would make the studies more subjective and thus less accurate and more prone to dispute and controversy.

b. Use of Total Transfer Capability (TTC)

Comments

363. Southern asserts that the Commission's assumption that all TTC values posted on OASIS platforms are non-simultaneous is not correct. Southern states that although many TTC values may be calculated on a point-to-point non-simultaneous basis, some TTC values are simultaneous, thus accounting for “loop flow” created by other paths. Southern contends that those transmission providers that post simultaneous TTC values on OASIS should have the flexibility to add these TTC values to calculate simultaneous transmission import capability for the control area. Southern believes that conflicts can occur between the generic methods presented in the Appendix E interim market screen order and actual OASIS practices used by transmission providers to post TTC.

Commission Determination

364. Southern's suggestion that the Commission allow the use of simultaneous TTC values is consistent with the SIL study provided that these TTCs are the values that are used in operating the transmission system and posting availability on OASIS. The simultaneous TTCs [368] must represent more than interface constraints at the balancing authority area border and must reflect all transmission limitations within the study area and limitations within first-tier areas. The source (first-tier remote resources) can only deliver power to load in the seller's balancing authority area if adequate transmission is available out of its first-tier area, adequate transmission is available at the seller's balancing authority area Start Printed Page 39949interface, and transmission is internally available. Thus, the TTC must be appropriately adjusted for all applicable (as discussed below) firm transmission commitments held by affiliated companies that represent transfer capability not available to first-tier supply. Sellers submitting simultaneous TTC values must provide evidence that these values account for simultaneity, account for all internal transmission limitations, account for all external transmission limitations existing in first-tier areas, account for all transmission reliability margins, and are used in operating the transmission system and posting availability on OASIS.

c. Accounting for Transmission Reservations

Comments

365. Duke and EEI propose that short-term firm reservations should not be subtracted from simultaneous import limits because longer firm reservation requests can displace control of these transmission holdings.[369] EEI explains, “it is inappropriate to net out transmission capacity that is not reserved to commit long-term generation resources to load. Short-term firm transmission reservations, some as short as one week in duration, provide flexibility to the market and will not necessarily persist for the duration, or even large portions, of the MBR authorization period. Therefore, they should not be used to reduce the estimate of simultaneous import capability.”[370]

366. Southern agrees, referring to the nature of short-term reservations as “transient and unpredictable.” [371] Southern states: “In most cases, short-term purchases by the applicant essentially allow the market to provide generation within the applicant's control area instead of the applicant utilizing its ‘owned’ generation capacity. Alternatively, the associated import capability is released to the market. In either case, these short-term reservations should not be used to inflate artificially the applicant's market share in conjunction with a screen or DPT evaluation.” [372]

367. APPA/TAPS state that the Commission should revisit the treatment of firm transmission reservations held by third parties. In the July 8 Rehearing Order (at P 49), the Commission stated that the SIL study assumed that “all reservations historically controlled by non-affiliates would have been used to compete to inject energy into the transmission provider's control area market if market power or scarcity was driving market prices above other regional prices.” However, if the holder of the reservation is using the transfer capability to serve its own load, it will not be available to third parties to respond to a price increase on the part of the transmission provider/sellers. APPA/TAPS state that presumably the capacity resources associated with the import will be reflected in the capacity total of the party that controls the resource's output. Excluding the transfer capability associated with the resource will not result in a double-deduction. Rather, failing to exclude the transfer capability will result in a double-counting of competing supply. Thus, APPA/TAPS assert that the Commission should revise the treatment of transfer capability held by third parties on a firm basis.[373]

Commission Determination

368. The Commission agrees with Duke, EEI and Southern that short-term firm reservations can be unpredictable, driven by real time system conditions, and do not necessarily indicate that the associated transmission capacity is not available for competing supplies (or to import seller's supplies during the study periods). Accordingly, we conclude that, in calculating simultaneous transmission import limits, short-term firm reservations of 28 days or less in effect during the study periods need not be accounted for.[374] While we find that firm transmission reservations less than or equal to 28 days in duration are usually unpredictable, we believe that firm transmission reservations of a longer duration are not related to the unpredictable nature of real time events and are based upon planned and predictable events. Therefore, the Commission will require sellers to account for firm and network transmission reservations having a duration of longer than 28 days.[375]

369. With regard to APPA/TAPSs' concern, we clarify that the seller's firm, network, and grandfathered transmission reservations longer than 28 days, including reservations for designated resources to serve retail load, shall be fully accounted for in the simultaneous import limit study. We further clarify that reservations held by third parties to import power into the seller's home area should be accounted for by allocating transmission import capability to those parties, and then allocating the remaining SIL pro rata.

d. Allocation of Transmission Imports Based on Pro Rata Shares of Seller's Uncommitted Generation Capacity

Comments

370. Duke and EEI support the Commission proposal to allocate imports on a pro rata basis into a study area based on uncommitted capacity in surrounding areas.[376]

371. However, Powerex expresses concern that pro rata allocation of uncommitted capacity is not a realistic representation of the physical capability of the system, since pro rata allocation assumes that the system can import up to the simultaneous import limit over any combination of transmission paths. Powerex argues that, in reality, some paths become constrained before others, so the allocation of import capability should take account of the physical limitations of the transmission system. Powerex asks that the Commission allow sellers to use allocation methods that are consistent with physical system limitations, where sellers provide documentation showing that the allocation methods used in the screens are realistic or conservative.[377]

372. Morgan Stanley asks the Commission to clarify its proposal of allocating transmission imports pro rata between the seller and its competitors based on uncommitted capacity. Morgan Stanley wonders if the Commission made a typographical error and intended to propose an allocation based on committed capacity. Morgan Stanley believes only the transmission provider (seller) would have uncommitted capacity.[378]

Commission Determination

373. The Commission agrees with Duke and EEI that the current practice of allocating simultaneous import Start Printed Page 39950capability pro rata to sellers based on uncommitted capacity should be continued.[379] However, some clarification may be helpful.

374. Powerex raises concern over the pro rata allocation of uncommitted generation capacity and asserts that this is not a realistic representation of the physical capability of the system since pro rata allocation assumes that the system can import up to the simultaneous import limit over any combination of transmission paths. In this regard, we note that pro rata allocation of transmission capacity based on first-tier uncommitted generation capacity is an approximation and is consistent with the manner in which we conduct the SIL study. In particular, when determining the simultaneous import limit, first-tier balancing authority areas are combined into a single area. The import capability of the study area is the simultaneous transfer limit from the aggregated first-tier market area into the study area.[380] We then allocate imports based on transmission capacity (limited by the physical capabilities of the transmission system as determined by the SIL study) pro rata based on sellers' first-tier uncommitted generation capacity.[381] We recognize that such an approximation may not fit all cases. Accordingly, with regard to allocating transmission imports, sellers can submit additional sensitivity studies based on factors suggested by Powerex, and intervenors may rebut the allocations of import capability made by seller. The Commission will consider such arguments on a case-by-case basis.

375. Morgan Stanley asks if the Commission made a typographical error and intended to propose an allocation based on committed capacity rather than uncommitted capacity. The Commission clarifies that pro rata allocation is used to assign shares of simultaneous transmission import capability to uncommitted generation capacity in the aggregated first-tier balancing authority areas to determine how much uncommitted generation capacity can enter the study area. Morgan Stanley appears to confuse our use of the term uncommitted capacity, apparently believing we are referring to uncommitted transmission capacity. That is not the case as we are referring to uncommitted generation capacity. The reason the use of uncommitted generation capacity is appropriate is because our screens analyze seller's relative uncommitted generation capacity rather than installed generation capacity or, as suggested by Morgan Stanley, committed generation capacity. In particular, the SIL study determines the amount of simultaneous transmission capacity available to be imported by competing supplies from remote resources in first-tier markets. The supplies that are available to be imported and thus compete are necessarily “uncommitted.” Further, it is our experience that uncommitted generation capacity can be held by any number of market participants based on market conditions at a given time. In other words, we do not agree with an assumption that the transmission provider is likely to be the only market participant with uncommitted power supplies.

e. Miscellaneous Comments

Comments

376. PG&E states that RTOs/ISOs having knowledge and control over the entire control area are best suited to perform SIL studies. PG&E requests that the Commission allow an exemption where, in the absence of an accepted SIL study by an RTO/ISO, the seller may substitute historical import levels in place of the SIL study. In addition, PG&E requests that the Commission confirm that sellers that pass screens for each relevant geographic market without considering imports need not provide a simultaneous import analysis.[382]

377. Powerex has concerns about how feasible it is for marketers to obtain non-public data from their transmission provider that is needed to conduct a screen (e.g., a SIL study) on their own. Powerex notes that Bonneville Power Administration (BPA) and Northwest Power Pool (NWPP) do not, as a practice, conduct and post simultaneous transmission import capability studies. Therefore, Powerex asserts that the Commission should maintain the current flexibility of allowing marketers to submit credible proxy study calculations based on publicly available information.[383]

Commission Determination

378. The Commission will continue to require the SIL study for the indicative screens and DPTs in order to assure that restrictions regarding importing first-tier supply are captured for seasonal peak conditions. Benefits of using a uniform transmission import model include: Transparency, consistency, clarity, and reasonable assurance that system conditions have been adequately captured. As also stated above, the Commission provides sellers flexibility to provide sensitivity analyses by modifying inputs to the SIL study.

379. In regard to PG&E's belief that RTOs/ISOs are best equipped to conduct SIL calculations, the Commission will continue to require transmission-providing sellers to perform the SIL studies as necessary. To the extent that an RTO/ISO conducts transmission studies and makes that information available, a seller may rely on the information obtained from its RTO/ISO to conduct its SIL study. Further, the Commission clarifies that to the extent the transmission-owning seller can demonstrate it passes the screens for each relevant geographic market without considering imports, it need not submit a SIL study.[384]

380. Powerex requests that it be able to submit proxies in place of a SIL study. The Commission notes that transmission-providing sellers are required to be the first to file SIL studies, which makes the required data available to non-transmission owning sellers for use in performing their generation market power analyses.[385] However, as the Commission stated in the April 14 Order,

an applicant may provide a streamlined application to show that it passes our screens. Thus, with respect to simultaneous import capability, if an applicant can show that it passes our screens for each relevant geographic market without considering imports, no such simultaneous import analysis needs to be provided. Further, we recognize that certain applicants will not have the ability to perform a simultaneous import capability study. Accordingly, if an applicant demonstrates that it is unable to perform a simultaneous import study for the control area in which it is located, the applicant may propose to use a proxy amount for transmission limits. We will consider such proposals on a case-by-case basis.[386]

381. In this regard, we note that we have accepted proxy amounts for Start Printed Page 39951transmission limits and will continue to consider such requests on a case-by-case basis.[387]

f. Required SIL Study for DPT Analysis

Comments

382. EEI and Southern propose that the Commission not mandate SIL studies as the only method for calculating import limits for DPT analysis. EEI states that while such a study may be an appropriate tool for indicative screens, the DPT is a more comprehensive study and the Commission should allow for more precise, non-standardized approaches for calculating simultaneous import capability for use in the DPT.[388] Southern states that the apparent purpose of Appendix E is to provide a somewhat standardized approach to assessing simultaneous import capability that goes hand-in-hand with the simplified tools used to develop a preliminary assessment of generation market power. It argues that where a seller presents a more thorough generation analysis pursuant to a DPT, it should be permitted to offer a more thorough analysis of transmission import capability.[389]

383. NRECA responds that the Commission should not allow sellers to substitute alternative measures of simultaneous import capability in the DPT. NRECA states that while a seller should be allowed to conduct a SIL study that is more refined than the one required of all sellers, “the applicant's alternative analysis should be submitted in addition to, and not in lieu of, the required analysis” in the DPT.[390] It argues that otherwise, each seller will do the analysis a bit differently so that the analysis will favor passing the tests. According to NRECA, the worst-case scenario is that there will be no standardized approach, which would exacerbate the existing problems created by inadequate access to the data underlying the sellers' market power analysis and the lack of standard reporting and increase the burdens on intervenors and the Commission staff in evaluating applications for market-based rates and market power updates. NRECA states that one advantage of requiring all sellers to use a standard analysis, in addition to whatever other analysis they may choose to offer, is that it can more effectively bring to light the problems now hidden from view in the seller's historical practices, resulting in increased transparency.

Commission Determination

384. For the reasons stated herein regarding the need to as accurately as possible account for transmission limitations when considering power supplies that can be imported into the relevant market under study, the Commission adopts the requirement for use of the SIL study as a basis for transmission access for both the indicative screens and the DPT analysis.

385. The lack of flexibility in creating a simultaneous transmission import limit has been identified by several commenters. However, the Commission believes it has provided sellers sufficient flexibility to adequately represent their process for making transmission available to unaffiliated supply. The Commission shares NRECA's concerns that opening the process to alternative study methods without a specified standard may result in deviations from reasonable depictions of transmission limits historically applied to first-tier suppliers and will likely bias such studies to the benefit of the seller.

386. With regard to the DPT analysis, there are several primary reasons for the continued use of simultaneous transmission import limit studies: Uniformity of modeling affiliated and unaffiliated supply, consideration of simultaneity, consideration of seller and affiliate transmission commitments and reservations, consideration of all internal transmission limitations, consideration of all external transmission limitations existing in first-tier areas, consideration of the seller's (or the seller's transmission provider's) practices for posting ATC, and consideration of peak seasonal conditions. By requiring the SIL study in the DPT analysis, the Commission assures that all factors important in determining transmission access to the seller's market are taken into account.

13. Procedural Issues

Commission Proposal

387. In the NOPR, the Commission noted that Order No. 662 [391] addressed concerns that CEII claims in market-based rate filings are overbroad. In Order No. 662, 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. In Order No. 662, the Commission encouraged the parties in cases in which CEII is filed to promptly negotiate a protective order 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 sought comments in the NOPR on whether CEII designations remain a concern since issuance of Order No. 662.

388. The Commission also sought 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. The Commission asked what would be an appropriate comment period if it were to establish a longer period for submitting comments on indicative screen and DPT analyses.

Comments

389. A number of commenters note that intervenors should be given adequate time to respond to CEII designations. APPA/TAPS suggest that the Commission provide a process to allow interested market participants to obtain CEII authorization in advance of a region's triennial updates. They submit that such authorization would apply to all sellers in the region where market-based rate authority is up for review and would necessitate that the requester file only one request.[392] Montana Counsel states that intervenors should also be given adequate time to respond to confidentiality claims with regard to non-CEII data.[393]

390. A number of commenters support extending the comment period for market-based rate filings. Ameren supports a 30-day comment period on the basis that 30 days has proven to be a sufficient comment period for section 203 filings.[394] Morgan Stanley recommends a 45-to 60-day comment period if the Commission adopts a regional approach for updated market power analyses.[395] NRECA states that under a regional filing process, a 21-day comment period is inadequate when several updated market power analysis filings are reviewed at once, and instead advocates a 90-day comment period from the notice of the filing or from the Start Printed Page 39952date of a completed filing if additional data is requested by the Commission.[396]

Commission Determination

391. In this Final Rule, we adopt procedures under which intervenors in section 205 proceedings may obtain expedited access to CEII or other information for which privileged treatment is sought. A request for access to information for which CEII status or privilege treatment has been claimed generally takes a few weeks for the Commission to process under the standard process found in 18 CFR 388.112 and 388.113.[397] Such a delay in receiving such information may make it difficult for an intervenor to submit timely comments.

392. An expedited process does exist for section 203 filings. Section 33.9 of the Commission's regulations [398] states that a seller seeking to protect any part of its application from public disclosure must also submit a proposed protective order. Parties may sign the proposed protective order and obtain CEII or privileged materials in a more timely manner, without having to spend time negotiating the terms of a protective order or waiting for the Commission to process the request through its standard request process.

393. In order to ensure that intervenors have access in a timely manner to relevant information for which privileged treatment is claimed, we will adopt language similar to § 33.9 in this Final Rule, to be codified at 18 CFR 35.37(f). We intend that the proposed protective order will be self implementing and not require action by the Commission; once a party signs the proposed protective order and returns it to the party submitting protected material, the submitter is expected to provide the material promptly to the requester. We note that the Commission's Model Protective Order is available on the Commission's Internet site and may be used as a guide in preparing proposed protective orders.[399] To expedite processing, the regulation will require that the seller provide the CEII or privileged material to the requester within five days after the protective order is signed and submitted to the seller.

394. With respect to APPA/TAPS's suggestion to make CEII authorization region-wide to coincide with region-wide analysis, we do not believe such a step is necessary or advisable at this time. Our goal with CEII has always been to limit access to those with a legitimate need for the information. We do not expect that all market participants in a region will want to comment on all updated market power analyses within that region. Moreover, we anticipate that our regulatory change requiring submission of a proposed protective order will go a long way to resolving past difficulties in obtaining non-public information in a timely manner.

395. With regard to the comment period for parties to file responses to updated indicative screens, we believe, as we discuss below in the section on Implementation, that extending the comment period for regional updated market power analyses will allow intervenors a better opportunity to review and comment on those filings, especially considering the large number of filings that will be submitted at one time. Hence, we will establish a 60-day comment period for updated market power analyses that are filed in accordance with the schedule in Appendix D.

396. With regard to the comment period for initial applications and for DPT analyses ordered as part of a section 206 proceeding, the Commission will retain the current 21-day comment period. However, we remain willing to consider on a case-by-case basis requests for extensions of time beyond 21 days to submit comments on these filings.

B. Vertical Market Power

397. In the NOPR, the Commission proposed to replace the 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, it proposed that issues relating to whether the seller and its affiliates have 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.

Comments

398. As a general matter, commenters expressed support for the proposed consolidation of the transmission market power and other barriers to entry prong into one vertical market power analysis.[400] According to EPSA, analyzing vertical market dominance in one single prong could be a positive step, provided that the elements of the prong are explicitly specified and effectively enforced.[401] No commenter opposed the Commission's proposal in this regard.

Commission Determination

399. In light of the reasons discussed in the NOPR and the comments received, the Commission will adopt the NOPR proposal to consolidate the transmission market power analysis and other barriers to entry analysis into one vertical market power analysis.

1. Transmission Market Power

Commission Proposal

400. In the NOPR, the Commission noted that it recognized that Order No. 888 did not eliminate all potential to engage in undue discrimination and preference in the provision of transmission service,[402] and that it had issued a Notice of Inquiry and a NOPR regarding whether reforms are necessary to the Order No. 888 pro forma OATT.[403] The Commission concluded that any concerns regarding the adequacy of the OATT should be addressed in that proceeding and not in the MBR Rulemaking proceeding. Therefore, in the NOPR the Commission proposed to continue to find that, where a seller or any of its affiliates owns, operates or controls transmission facilities, a Commission-approved OATT, as modified as a result of the OATT Reform Rulemaking, will adequately mitigate transmission market power.

401. In the NOPR, the Commission further stated that the finding that an Start Printed Page 39953OATT adequately mitigates transmission market power rests on the assumption that individual sellers 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 other remedies the Commission may deem appropriate, such as disgorgement of profits or civil penalties.[404] 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 OATT violation and the entity's market-based rate authority.

402. In addition, the Commission proposed 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 same market on the effective date of revocation of the transmission provider's market-based rate authority.[405]

a. OATT Requirement

Comments

403. Several commenters state that merely having an OATT on file does not sufficiently mitigate vertical market power and that a utility's interpretation and implementation of its OATT can effectively eviscerate market power protections.[406] Some commenters do not believe that tariff changes alone will effectively mitigate vertical market power in the future and therefore request a post-implementation proceeding one year after the issuance of a final rule in the OATT Reform Rulemaking to explore the effectiveness of the updated OATT in assessing vertical market power.[407]

404. EPSA states that the outcome of the OATT Reform Rulemaking will determine the strength and efficacy of the vertical market power screen and stresses the interrelationship of that proceeding to this proposed rule; EPSA continues to advocate that the reform of Order No. 888 and the ability of the OATT to mitigate against market power effectively be evaluated on an ongoing basis.[408]

405. APPA/TAPS similarly state that, for purposes of the vertical market power analysis, it is too early to tell whether the OATT, as modified in the OATT Reform Rulemaking, will mitigate transmission market power.[409] TDU Systems argue that the proposals governing transmission planning and expansion in the OATT Reform Rulemaking are inadequate to mitigate the vertical market power of transmission-owning public utilities.[410]

406. The New York Commission states that the presence of an OATT may mitigate a seller's transmission market power, but only with respect to generator access to the transmission system. It submits that vertically integrated utilities may be able to exercise transmission market power in a manner that would not necessarily violate their OATTs, such as through outage scheduling (e.g., delaying repair and maintenance of transmission lines in a load pocket in which an affiliated generator is located), transmission investment (e.g., delaying or minimizing its investment in the bulk electric transmission system in a load pocket in which an affiliated generator is located), or voltage support (e.g., inadequate support of voltage requirements and being slow to correct voltage support shortcomings).[411] EPSA agrees with the New York Commission that the Commission cannot assume that any transmission provider with a Commission-approved OATT on file has adequately mitigated transmission market power and that “the Commission should require these utilities to demonstrate that they do not have the incentive or ability to engage in such behavior, before they are granted MBR status.” [412]

407. On the other hand, several commenters support the Commission's proposal to maintain the long-standing presumption that a Commission-approved OATT will adequately mitigate transmission market power.[413] EEI states that the comprehensive approach that the Commission has taken to reform the OATT in the OATT Reform Rulemaking is the best approach to assess the adequacy of the OATT to mitigate transmission market power. EEI states that the Commission should continue to find that a Commission-approved OATT, as modified as a result of the OATT Reform Rulemaking, adequately mitigates transmission market power.[414]

Commission Determination

408. The Commission will adopt the NOPR proposal that, to the extent that a public utility with market-based rates, or any of its affiliates, owns, operates, or controls transmission facilities, the Commission will require that a Commission-approved OATT be on file before granting such seller market-based rate authorization. We recognize that the Commission has granted a number of entities waiver of the requirement to file an OATT where the filing entity satisfies the Commission's standards for the grant of such waivers.[415] The Commission will continue to grant waiver of the OATT requirement on a case-by-case basis, and will continue to allow sellers to rely on the grant of such waiver to satisfy the vertical market power part of the analysis. If a seller that previously received waiver of the OATT requirement seeks to continue to rely on that waiver to satisfy the vertical market power part of the analysis, it must make an affirmative statement in its updated market power analysis that it previously received such a waiver, that such waiver remains appropriate, and the basis for that claim. In addressing our vertical market power concerns, a seller, including its affiliates, that does not own, operate or control transmission facilities must make an affirmative statement that neither it, nor any of its affiliates, owns, operates or controls any transmission facilities.

409. In the NOPR, we stated that concerns regarding the adequacy of the OATT should be addressed in the OATT Reform Rulemaking. The Commission received over 6,000 pages of comments relating to potential reforms to the pro forma OATT in that proceeding, and on February 16, 2007 issued a Final Rule adopting numerous improvements to the pro forma OATT that will further limit opportunities for transmission providers to unduly discriminate against transmission customers. As a result, we do not address in this Final Rule specific reforms to the OATT. In addition, the Commission declined in Order No. 890 to establish a one-year review period for the reformed pro forma OATT. The Commission stated it will continue to actively monitor compliance with its orders and, as necessary, institute further proceedings Start Printed Page 39954to meet its statutory obligation to remedy undue discrimination.[416]

410. In response to the concerns of the New York Commission and EPSA that vertically integrated utilities may exercise vertical market power without violating their OATTs through actions such as outage scheduling, investment decisions and inadequate voltage support, we note that the OATT does address such matters as the planning and expansion of facilities, the duty to provide firm and non-firm service and good utility practice. These provisions impose definite obligations on transmission providers. As additional examples, outage scheduling aimed at affecting market prices may constitute market manipulation, and inadequate voltage support may violate a reliability standard under FPA section 215. These provisions adequately address the concerns of the New York Commission and EPSA.

b. OATT Violations and MBR Revocation

Comments

411. A number of commenters agree with the Commission that market-based rate authority should not be revoked unless and until the Commission finds a direct nexus between the OATT violation and the entity's market-based rate authority.[417] EEI states that the Commission should not presume that an OATT violation is sufficient cause to revoke a transmission provider's market-based rate authority because there is no basis for such a presumption.[418] Instead, EEI argues that the Commission should carefully review all facts and circumstances before determining that an OATT violation was a willful exercise in undue discrimination intended to benefit a seller's sales at market-based rates.[419]

412. EPSA asserts that any violation of an entity's OATT in order to favor its own sales or its affiliates would create a nexus to the entity's market-based rate authority. If the Commission does not clarify this point, EPSA requests explanation regarding what exactly would constitute a nexus between an OATT violation and an entity's market-based rates.[420]

413. TDU Systems state that it is unclear what the nexus requirement entails. They propose that if the transmission provider or one of its affiliates has market-based rate authority, there should be a rebuttable presumption that a violation of the OATT has the requisite nexus to support revocation of the market-based rate authority of the transmission provider and its affiliates.[421] TDU Systems state that it should be up to a seller to rebut that presumption.

414. APPA/TAPS assert that the nexus standard adds an unnecessary and counter-productive test.[422] APPA/TAPS submit that if an OATT violation denies, delays, or diminishes the availability of transmission service or raises its costs, that alone should suffice for consideration of revocation of market-based rate authority. They argue that whether the violation had a nexus to the seller's market-based rate sales may be irrelevant. APPA/TAPS state that a nexus requirement could divert the Commission and injured parties through needless disputes about whether the alleged violator used the OATT violation to enable a specific sale under its market-based rate tariff authority, ignoring the larger picture painted by the transmission provider's anticompetitive conduct and exercise of transmission market power. Thus, instead of the “nexus” standard, APPA/TAPS states that the Commission should require that the OATT violation be “material,” i.e., one that denies customers the just, reasonable and non-discriminatory and comparable transmission service that is essential to mitigation of transmission market power.[423]

415. Reliant suggests that the Commission should strengthen its vertical market power analysis by looking at the extent to which a transmission provider has denied transmission access to competing suppliers and should seek justification for such denials.[424] For those transmission providers seeking market-based rate authority, Reliant asserts that any suppliers unable to reach a customer as a result of an inappropriate denial should not be included as competing generation in the transmission provider's horizontal market power screens until the transmission provider remedies the problem.[425]

416. Duke urges the Commission to clarify that a seller's market-based rate authority should not be subject to limitation or revocation if it participates in an RTO that is the subject of an OATT violation. According to Duke, once the transmission owner transfers control over its facilities to an RTO, adherence to the OATT is in the control of the RTO, not the transmission owner.[426]

Commission Determination

417. We will adopt the NOPR proposal to revoke an entity's market-based rate authority in response to an OATT violation only upon a finding of a nexus between the specific facts relating to the OATT violation and the entity's market-based rate authority, and reiterate our statement in the NOPR that an OATT violation may subject the seller to other remedies the Commission may deem appropriate, such as disgorgement of profits or civil penalties.[427] As stated in the NOPR, the finding that an OATT adequately mitigates transmission market power rests on the assumption that individual entities comply with the OATT and there may be OATT violations in circumstances that, after applying the factors in the Enforcement Policy Statement,[428] merit revocation or limitation of market-based rate authority. We find, however, that it is inappropriate to revoke a seller's market-based rate authority for an OATT violation unless there is a nexus between the specific facts relating to the OATT violation and the seller's market-based rate authority. This will ensure that our actions are not arbitrary or capricious and that they are based on an adequate factual record. We will not, as TDU Systems suggest, adopt a rebuttable presumption that any OATT violation has the requisite nexus to support revocation of market-based rate authority. There is a wide range of types of OATT violations, including ones that may be inadvertent and ones that are neither intended to affect, nor in fact affect, the market-based rate sales of the transmission provider or its affiliates. We therefore believe adoption of a general rebuttable presumption of a nexus for any and all OATT violations is not justified.

418. Several commenters sought clarification regarding what would constitute a sufficient nexus between the specific facts relating to the OATT violation and the seller's market-based rate authority. Determining what Start Printed Page 39955constitutes a sufficient factual nexus is best left to a case-by-case consideration. The wide range of positions among commenters on how to define a sufficient factual nexus itself suggests that this finding is best made after review of a specific factual situation. Some commenters assert that a finding of a “material” violation of the OATT would be sufficient. We disagree. While a seller's inconsequential OATT violation would not serve as a basis for revoking that entity's market-based rate authority, our view is that revocation is warranted only when an OATT violation has occurred and the violation had a nexus to the market-based rate authority of the violator or its affiliates.

419. The Commission emphasizes that we have discretion to fashion remedies for OATT violations that relate to the violator's market-based rate authority in instances in which we do not find sufficient justification for revocation of that authority. For example, in appropriate circumstances, we may modify or add additional conditions to the violator's market-based rate authority or impose other requirements to help ensure that the violator does not commit future, similar misconduct. We also will consider whether to impose sanctions such as assessment of civil penalties for particularly serious OATT violations in addition to revocation of the violator's market-based rate authority.

420. We agree with Duke that a seller's market-based rate authority should not be subject to limitation or revocation if it participates in an RTO that is the subject of an OATT violation committed by the RTO. We note, however, that if the seller itself is involved in an OATT violation, the Commission will investigate the seller's actions where appropriate, and may revoke market-based rate authority even though the seller is in an RTO.

421. With regard to Reliant's suggestion that the Commission should examine the extent to which a transmission provider has denied transmission access to competing suppliers as part of its vertical market power analysis, we will allow intervenors on a case-by-case basis to file evidence if they believe they have been denied transmission access in violation of the OATT. Depending on specific facts, such denials could constitute an OATT violation and could warrant remedies such as a reduction of competing supplies for purposes of the horizontal analysis.

c. Revocation of Affiliates' MBR Authority

Comments

422. Some commenters oppose the proposal to revoke the market-based rate authority of all affiliates of a transmission provider within a particular market, regardless of whether they were involved in the transmission provider's violation of its OATT. These commenters argue that the proposal to revoke all affiliates' market-based rate authority ignores the principles of the Commission's code of conduct and standards of conduct, including provisions restricting the sharing of market information and requiring separation of functions.[429] They argue that, in light of the separation of a company's marketing function and transmission function under the standards of conduct, a company's market-based rates should not be revoked because of an OATT violation by an affiliated transmission owner unless there has also been a violation of the standards of conduct, and there is a nexus between the standards of conduct violation and the OATT non-compliance.[430] They assert that, unless there is a violation of the standards of conduct, merchants will have no involvement in the actions of transmission providers.[431]

423. Xcel submits that, before imposing a penalty that would effectively penalize the merchant function, the Commission should require a demonstration that a utility's transmission function violated the OATT so as to knowingly benefit the activities of its merchant function.[432] Xcel and Allegheny Energy state that the Commission should not penalize the merchant side of an entity when the OATT violation by the transmission provider causes no harm, was not the result of deliberate manipulative conduct, was not part of a pattern of misconduct, or did not involve senior management of the transmission provider.[433] Similarly, Indianapolis P&L advocates punishment of a marketing or generation-only affiliate only to the extent such affiliate colludes or conspires with such OATT mis-administration or if such an affiliate financially benefits from such an act.[434]

Commission Determination

424. In response to concerns raised by commenters, we do not adopt the proposal from the NOPR to revoke the market-based rate authority of each affiliate of a transmission provider that loses its market-based rate authority within a particular market as a result of the transmission provider's OATT violation. Rather, we will create a rebuttable presumption that all affiliates of a transmission provider should lose their market-based rate authority in each market in which their affiliated transmission provider loses its market-based rate authority as a result of an OATT violation. We will allow an affiliate of a transmission provider to retain its market-based rate authority in a market area if the affiliate overcomes the rebuttable presumption with respect to that market area.

425. This issue generally will arise when a transmission provider merits revocation of its market-based rate authority as a result of an OATT violation. We have long held that the existence of an OATT is deemed to mitigate vertical market power by a transmission provider and its affiliates in a particular market. An OATT violation by a transmission provider that merits revocation of the transmission provider's market-based rate authority in a particular market will, at a minimum, raise the question whether the transmission provider's affiliates continue to qualify for market-based rates in that market under the standards that we have established.[435] Start Printed Page 39956As a result, we believe that it is appropriate to establish a rebuttable presumption that if we find that a transmission provider should lose its market-based rate authority in a particular market, all affiliates of the transmission provider should also lose their market-based rate authority in the same market.

426. We are mindful, however, that the circumstances of a particular affiliate may not always justify the imposition of a remedy so severe as revocation of market-based rate authority in a particular market when its affiliated transmission provider loses its market-based rate authority in that market as a result of an OATT violation. To ensure that a determination to revoke market-based rate authority in a particular market for a transmission provider and all of its affiliates that possess such authority is adequately based upon record evidence, we will allow an opportunity for each such affiliate to make a showing that it should retain its market-based rate authority or that enforcement action against it should be less severe than revocation. The determination whether an affiliate has overcome the rebuttable presumption depends on an analysis of specific facts in the record. Relevant facts would include, for example, whether (1) The affiliate knew of, participated in, or was an accomplice to the OATT violation, (2) the affiliate assisted the transmission provider in exercising market power, or (3) the affiliate benefited from the violation.

427. Consistent with our approach to revocation of a transmission provider's market-based rates, the Commission clarifies that a decision to revoke the market-based rate authority of the transmission provider's affiliates in the affected market will also be based on a finding that the transmission provider's violation of its OATT has a nexus to the market-based rate authority of those affiliates.

2. Other Barriers to Entry

Commission Proposal

428. The Commission proposed in the NOPR that, in order for a seller to demonstrate that it satisfies the Commission's vertical market power concerns, it must demonstrate that neither it nor its affiliates can erect other barriers to entry (i.e., barriers other than transmission). In this regard, the Commission proposed 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 or distribution of inputs to electric power production; and ownership or control of sites for new generation capacity development. The Commission also proposed 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.

429. In addition, the Commission proposed 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 sought comments on this proposal. Specifically, the Commission proposed 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.

430. The Commission also clarified that sellers need not address interstate transportation of natural gas supplies because such transportation is regulated by this Commission.[436] The Commission explained that its open access regulations adequately prevent sellers from withholding interstate pipeline capacity. 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, the Commission noted that Congress has found the natural gas market competitive.[437]

431. The Commission also sought comment on whether ownership or control of 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.

Comments

432. Several commenters state that the Commission's other barriers to entry criteria are long-standing, well established and thus no expansion of current policy is necessary.[438] They submit that the requirement that the analysis include the consideration of ownership or control of sites for development of generation in the relevant market, fuel inputs such as coal supplies 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, is broad and provides sufficient information for the Commission to assess the seller's potential to erect barriers to entry. They assert that this information, coupled with the proposal 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, provides the Commission with appropriate information.[439]

433. APPA/TAPS suggest that the proposed entry barriers affirmation should be signed and affirmed by a senior corporate official.[440] However, APPA/TAPS state that the Commission should not codify the specific entry barriers that it will consider given the ever-changing nature of electricity markets.[441] They submit that while illustrations of entry barriers can provide guidance to sellers and market participants, the Commission should not limit the kinds of entry barriers it will consider.

434. Sempra states that, to the extent the new analytic framework (the consolidation of the former transmission market power and other barriers to entry factors into the vertical market power analysis) would recognize existing Start Printed Page 39957precedent and not work to place additional burdens on market-based rate sellers, Sempra would support it.[442]

435. Several sellers support continuation of the Commission's policy that sellers need not address natural gas and its interstate transportation as part of their vertical market power analysis.[443] In contrast, a commenter states that the Commission should not make a blanket exemption for sellers or their affiliates who own or control natural gas pipeline capacity. Notwithstanding the Commission's statement that natural gas interstate pipelines are regulated by the Commission and that the regulations adequately prevent sellers from withholding capacity, this commenter argues that the natural gas open access rules do not adequately mitigate vertical market power in all situations. It encourages the Commission to require sellers with significant firm interstate pipeline capacity rights to demonstrate that they do not have vertical market power.[444]

436. APPA/TAPS state that the Commission should clarify that it will consider control over interstate natural gas transportation if the issue is raised in a market-based rate proceeding.[445] APPA/TAPS state that even if sellers do not have to address interstate gas transportation as part of the vertical market power test, intervenors should not be precluded from raising concerns and introducing evidence regarding a seller's position in the interstate natural gas transportation market as a potential entry barrier and APPA/TAPS seek clarification in this regard.[446]

437. Several commenters state that the markets for the other inputs to generation factor (e.g., fuel supply other than natural gas, transportation and storage) are workably competitive and provide few opportunities for a seller to raise entry barriers. They therefore suggest that the Commission create a rebuttable presumption that the markets for other factor inputs such as coal, oil and distillate commodity markets, the transportation and storage of these fuels, sites for new plants, etc., are workably competitive. They urge that, absent a showing to the contrary, ownership or control of such assets need not be analyzed.[447] In this regard, Duke states that the Commission should allow sellers to make the representation that they cannot erect such barriers, while allowing other parties to introduce evidence challenging such an assertion.[448]

438. PG&E states that, similar to the rules for interstate transportation of natural gas supplies (under which Commission open access regulations adequately prevent sellers from withholding interstate gas pipeline capacity), State regulation of access to gas storage, natural gas pipelines, or natural gas distribution should be a basis for finding that an entity with ownership or control of such assets cannot erect barriers to entry or otherwise hold or exercise vertical market power in the generation market.[449]

439. SoCal Edison urges the Commission to clarify that, with regard to sites for building generation, mere ownership of real estate does not reasonably support an inference of a barrier to entry, and that sellers are not required, in the first instance, to make any affirmative demonstration of the absence of potential that their real estate holdings might constitute a theoretical barrier to entry. Rather, the Commission should clarify that it would pursue such inquiry only to the extent colorable issues are raised by way of protest or intervention.[450] Sempra states the Commission should modify the regulatory text in three respects. First, the Commission should explicitly exclude from the definition of “inputs to electric power production” in proposed § 35.36(a)(4) interstate transportation of natural gas supplies (both ownership/control of facilities as well as ownership/control of capacity) and the gas commodity itself. Second, the Commission should also exclude from the definition of “inputs to electric power production” intrastate natural gas facilities or distribution facilities, particularly where such facilities are operated under pervasive State regulations and in accordance with open access principles. Third, the Commission should make clear in this provision and at § 35.27(e) of its proposed regulations (pertaining to a seller's vertical market power analysis), that the only “inputs” that need to be addressed are those present in the seller's relevant geographic market(s).[451]

Commission Determination

440. As discussed above, the Commission will adopt the NOPR proposal to consider a seller's ability to erect other barriers to entry as part of the vertical market power analysis, but we will modify the requirements when addressing other barriers to entry. We also provide clarification below regarding the information that a seller must provide with respect to other barriers to entry (including which inputs to electric power production the Commission will consider as other barriers to entry) and we modify the proposed regulatory text in that regard.

441. In this rule, the Commission draws a distinction between two categories of inputs to electric power production: One consisting of natural gas supply, interstate natural gas transportation (which includes interstate natural gas storage), oil supply, and oil transportation, and another consisting of intrastate natural gas transportation, intrastate natural gas storage or distribution facilities; sites for generation capacity development; and sources of coal supplies and the transportation of coal supplies such as barges and rail cars.

442. With regard to the first category, based upon the comments received and further consideration, the Commission will not require a description or affirmative statement with regard to ownership or control of, or affiliation with an entity that owns or controls, natural gas and oil supply, including interstate natural gas transportation and oil transportation.

443. In the case of natural gas, prices for wellhead sales were decontrolled by Congress.[452] Further, the Commission has granted other sellers blanket authority to make sales at market rates. In the case of transportation of natural gas, pipelines operate pursuant to the open and non-discriminatory requirements of Part 284 of the Commission's regulations.[453] These regulations mandate that all available pipeline capacity be posted on the pipelines' Web site, and that available capacity cannot be withheld from a Start Printed Page 39958shipper willing to pay the maximum approved tariff rate.

444. Similarly, we note that oil pipelines are common carriers under the Interstate Commerce Act, specifically under section 1(4), and are required to provide transportation service “upon reasonable request therefore” [454] and that Congress has not chosen to regulate sales of oil.

445. In response to APPA/TAPS' request for clarification, we note that as an initial matter, to the extent intervenors are concerned about a seller's market power from ownership or control of interstate natural gas transportation, this would be actionable first in a complaint proceeding under section 5 of the Natural Gas Act before turning to market-based rate consequences.

446. With regard to the second category, in light of the comments received, and upon further consideration, the Commission adopts a rebuttable presumption that sellers cannot erect barriers to entry with regard to the ownership or control of, or affiliation with any entity that owns or controls, intrastate natural gas transportation, intrastate natural gas storage or distribution facilities; sites for generation capacity development; and sources of coal supplies and the transportation of coal supplies such as barges and rail cars.[455] To date, the Commission has not found such ownership, control or affiliation to be a potential barrier to entry warranting further analysis in the context of market-based rate proceedings. However, unlike the first category of inputs, the Commission does not have sufficient evidence to remove these inputs from the analysis entirely. Accordingly, we will rebuttably presume that ownership or control of, or affiliation with an entity that owns or controls, intrastate natural gas transportation, intrastate natural gas storage or distribution facilities; sites for generation capacity development; and sources of coal supplies and the transportation of coal supplies such as barges and rail cars do not allow a seller to raise entry barriers, but will allow intervenors to demonstrate otherwise. We note that this rebuttable presumption only applies if the seller describes and attests to these inputs to electric power production, as described herein.

447. With regard to this second category of inputs to electric power production, we will require a seller to provide a description of its ownership or control of, or affiliation with an entity that owns or controls, intrastate natural gas transportation, storage or distribution facilities; sites for generation capacity development; and sources of coal supplies and the transportation of coal supplies such as barges and rail cars. The Commission will require sellers to provide this description and to make an affirmative statement, with some modifications to the affirmative statement from what was proposed in the NOPR. Instead of requiring sellers to make an affirmative statement that they have not erected barriers to entry into the relevant market, we will require sellers to make an affirmative statement that they have not erected barriers to entry into the relevant market and will not erect barriers to entry into the relevant market. We clarify that the obligation in this regard applies both to the seller and its affiliates, but is limited to the geographic market(s) in which the seller is located.

448. We therefore modify the proposed regulations to require a seller to provide a description of its ownership or control of, or affiliation with an entity that owns or controls, intrastate natural gas transportation, intrastate natural gas storage or distribution facilities; sites for generation capacity development; sources of coal supplies and the transportation of coal supplies such as barges and rail cars, to ensure that this information is included in the record of each market-based rate proceeding. In addition, a seller is required to make an affirmative statement that it has not erected barriers to entry into the relevant market and will not erect barriers to entry into the relevant market.

449. While some commenters raise concerns that codification of these possible barriers may inappropriately limit the analysis of a seller's potential to erect other barriers to entry, we clarify that we are codifying what showing a seller must make in order to receive authority to make sales of electric power at market-based rates. By so doing, we are not preventing intervenors from raising other barriers to entry concerns for consideration on a case-by-case basis. This approach will allow unique or newly developed barriers to entry to be brought before the Commission.

450. We will not adopt APPA/TAPS' proposal that the affirmation be signed and affirmed by a senior corporate officer. Section 35.37(b) of the Commission's regulations requires sellers to “provide accurate and factual information and not submit false or misleading information, or omit material information, in any communication with the Commission * * *”. [456] The Commission has ample authority to enforce its regulations, and therefore does not believe that it is necessary in these circumstances to require the affirmative statement to be signed by a senior corporate official.

451. The changes made to the evaluation of other barriers to entry, as described above, should not be more burdensome on market-based rate sellers than that which is currently in place. For the most part, the Commission is maintaining its current policy, with some variation and additional guidance on what is required. The policy adopted in this Final Rule should provide sellers with additional clarity regarding what needs to be addressed as a potential other barrier to entry and the way in which to address it.

3. Barriers Erected or Controlled by Other Than The Seller

Comments

452. APPA/TAPS state that entry conditions and barriers, regardless of origin, need to be considered in both the horizontal and vertical market power tests.[457] APPA/TAPS state that the Commission should not focus solely on entry barriers erected by the seller itself and that the Commission must be receptive to claims that entry barriers in the seller's market provide or enhance market power, even if the seller itself did not erect the barriers.[458] Another commenter states that the Commission should maintain a separate evaluation on other barriers to entry that are not caused by a seller, thus requiring a seller to address barrier to entry issues to the relevant market, even if those barriers are not caused by a seller or its affiliates.

Commission Determination

453. The Commission finds that it is not reasonable to routinely require sellers to make a showing regarding potential barriers to entry that others might erect and that are beyond the seller's control. However, we will allow intervenors to present evidence in this regard, and by this means we will be able to assess the existence of barriers to entry beyond the seller's control but which may affect the seller's ability to exercise market power. Should a potential barrier in the relevant market Start Printed Page 39959be raised by an intervenor, the Commission will address such claims on a case-by-case basis.

4. Planning and Expansion Efforts

454. In the NOPR, the Commission noted that several commenters had suggested that a transmission planning and expansion process can ameliorate vertical market power, and, accordingly, the Commission was seeking comment on the issues of transmission planning and expansion in the notice of proposed rulemaking in the OATT Reform Rulemaking. The Commission sought comment in the NOPR on whether the planning and expansion efforts in the OATT Reform Rulemaking would address commenters' concerns here.

Comments

455. APPA/TAPS state that there will be a continuing need to address transmission market power issues, even after adoption of a revised pro forma OATT, because the improvements in transmission planning and expansion will not be immediately felt.[459] EPSA states that it advocates robust, independent and mandatory regional planning as a means to combat vertical market power and ensure competitive markets.[460]

456. TDU Systems recommend that the Commission revoke a transmission provider's market-based rate authority if it fails to build transmission to accommodate the needs of its transmission customers demonstrated through an open, joint planning process.[461] TDU Systems submit that willful failure to plan, maintain and expand the transmission system to meet transmission customers' needs is an abuse of vertical market power and creates structural barriers to competition.

457. ELCON states that while it is encouraged by proposals in the OATT Reform Rulemaking, it recommends that transmission market power be the subject of a new rulemaking.[462] Similarly, EPSA asserts that a technical conference to develop the barriers to entry portion of the screens would help ensure an open, accessible, and robust competitive market.[463]

Commission Determination

458. We find that our reforms to the pro forma OATT to require coordinated transmission planning on a local and regional level address the concerns raised by commenters. While we recognize that the transmission planning reforms in Order No. 890 are still in the process of being implemented, failure to plan, maintain and expand the transmission system in accordance with the applicable, Commission-approved OATT has always been, and will continue to be, an OATT violation. Order No. 890 provides for revocation of an entity's, and possibly that of its affiliates, market-based rate authority in response to an OATT violation upon a finding of a specific factual nexus between the violation and the entity's market-based rate authority.[464] Should such a violation occur, the Commission will address it in that context. The Commission does not find that the need exists to convene a technical conference in this regard. The OATT Reform Rulemaking dealt extensively with this issue and the Commission finds that it has been adequately addressed in Order No. 890.

5. Monopsony Power

459. In the NOPR, the Commission sought 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.

Comments

460. Allegheny states that the NOPR provided no explanation for why a transmission provider's buyer's market power should be relevant to the analysis.[465] EEI argues that the Commission should not consider buyer's market power as a barrier to entry because it is not relevant to the analysis. According to EEI, the market-based rate analysis considers the ability of the applicant to exercise market power as a seller, not a buyer, which is consistent with the Commission's authority under section 205 of the FPA, which regulates the sale of electricity. EEI asserts that states generally have jurisdiction over the purchase of electricity by franchised utilities.[466]

461. EPSA argues that if a utility holds a dominant purchasing position in the wholesale marketplace that allows it to exert excessive and discretionary buying power (of both supply and supply generation facilities), the exercise of market power will then lie with the buyer, not the seller. This problem is exacerbated when such a purchasing utility also owns, controls or dispatches its own proprietary supply and the relevant transmission system.

462. EPSA states that some would argue that the Commission cannot order economic dispatch or competitive solicitation because the FPA grants the Commission jurisdiction over sales, not purchases. However, EPSA submits that the Commission would not be mandating purchases, but eliminating the exercise of market power which directly raises the prices for wholesale sales. In so doing, the Commission would be using its tools under sections 205 and 206 of the FPA to ensure just and reasonable wholesale rates by allowing competitive alternatives to enter the market and protecting consumers from practices that will result in excessive rates and charges. EPSA argues that the Commission must develop a transparent, methodical process for assessing this segment of the vertical market power analysis. EPSA submits that load serving entities that are transmission providers must, in addition to providing enhanced transmission services, facilitate accessible long-term markets through all-source competitive procurement processes, preferably via state created and supervised means, with independent third party oversight. It asserts that the Commission must achieve and ensure these goals through a transparent, well-developed process. EPSA requests that the Commission convene a technical conference in order to fully develop that process and ensure that barriers to entry are properly mitigated.[467]

Commission Determination

463. EPSA's proposal not only raises jurisdictional issues, but EPSA has failed to provide specific instances in which the exercise of monopsony power has taken place and has provided no guidance as to how buyer market power should be measured (even assuming the Commission has jurisdiction to address it). The Commission does not believe it is appropriate to attempt to address these difficult issues without specific evidence of monopsony power and a clear delineation of the State-Federal jurisdiction issues that would arise in the context of a specific seller and specific set of circumstances. For the same reason, we will not grant EPSA's request to convene a technical conference to address such issues generically. Until EPSA or others provide such information concerning a particular seller in either a market-based Start Printed Page 39960rate proceeding or a complaint, we defer judgment on the many difficult issues raised by EPSA.

C. Affiliate Abuse

1. General Affiliate Terms and Conditions

a. Codifying Affiliate Restrictions in Commission Regulations

Commission Proposal

464. In the NOPR the Commission proposed to discontinue referring to affiliate abuse as a separate “prong” of the market-based rate analysis and instead proposed to codify in the 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 restrictions. The Commission proposed 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 indicated that a seller seeking to obtain or retain market-based rate authority will be obligated to provide a detailed description of its corporate structure so that the Commission can be assured that the Commission's requirements are being applied correctly. In particular, the Commission proposed that sellers with franchised service territories be required to make a showing regarding whether they serve captive customers and to identify all “non-regulated” power sales affiliates, such as affiliated marketers and generators.[468]

465. The Commission further proposed that, as a condition of receiving market-based rate authority, sellers must adopt the MBR tariff (included as Appendix A to the NOPR) which includes a provision requiring the seller to comply with, among other things, the affiliate restrictions in the regulations. The Commission noted that failure to satisfy the conditions set forth in the affiliate restrictions will constitute a tariff violation. The Commission sought comment on these proposals

Comments

466. As a general matter, commenters support the Commission's proposal to codify the affiliate restrictions in the Commission's regulations.[469] No comments were received opposing the proposal to codify affiliate restrictions in the Commission's regulations.

Commission Determination

467. The Commission will adopt the proposal in the NOPR to discontinue considering affiliate abuse as a separate “prong” of the market-based rate analysis and instead codify in the Commission's regulations in § 35.39 an explicit requirement that any seller with market-based rate authority must comply with the affiliate restrictions. This will address affiliate abuse by requiring that the conditions set forth in the regulations be satisfied on an ongoing basis as a condition of obtaining and retaining market-based rate authority. Included in the regulations will be a provision expressly prohibiting power sales between a franchised public utility with captive customers and any market-regulated power sales affiliates without first receiving Commission authorization for the transaction under section 205 of the FPA. Also included in the regulations will be the requirements that have previously been known as the market-based rate “code of conduct,” as those requirements have been revised in this Final Rule.

468. Additionally, although we do not adopt the proposal to require that, as a condition of receiving market-based rate authority, sellers must adopt the MBR tariff (included as Appendix A to the NOPR), we do adopt a set of standard tariff provisions that we will require each seller to include in its market-based rate tariff, including a provision requiring the seller to comply with, among other things, the affiliate restrictions in the regulations. We further adopt the proposal that failure to satisfy the conditions set forth in the affiliate restrictions will constitute a tariff violation.

b. Definition of “Captive Customers”

Commission Proposal

469. The Commission stated in the NOPR that, among other things, in the Commission's Final Rule on transactions subject to section 203 of the FPA, the Commission defined the term “captive customers” to mean “any wholesale or retail electric energy customers served under cost-based regulation.”[470] The Commission sought comment on whether the same definition should be used for purposes of this rule.

Comments

470. While a number of commenters support the Commission's proposal to codify the affiliate abuse “prong” in the Commission's regulations,[471] they comment that the proposed affiliate abuse restrictions do not do enough to protect retail customers from affiliate abuse.[472] NASUCA argues that affiliate abuse restrictions should be applicable to any affiliate with any retail customers, whether or not the retail affiliate is a “franchised” utility, whether or not it has a State-imposed “service obligation,” and whether or not its customers are characterized as “captive.” NASUCA submits that the Commission should not rely on a State's adoption of a retail access regime for any determination that a customer is not captive. Further, although NASUCA comments that the Commission's proposed definition for “captive customers” is an improvement from the text of the proposed regulation (which contains no definition of “captive customers”), NASUCA suggests it could also invite distinctions turning on the meaning of “cost-based regulation” that might cause future uncertainty in some circumstances and a corresponding loss of customer protection.[473]

471. New Jersey Board argues that when customers lack realistic alternatives to purchasing power from their local utility, regardless of a legal right to competitive power suppliers, such customers are still captive. New Jersey Board states that most customers in retail choice states still rely on the provider-of-last-resort for electric service and, thus, are still captive customers.[474] New Jersey Board comments that, due to the relatively young retail choice and deregulation programs in many states, “it would be premature to declare electric retail choice to be vibrant enough to leave consumer protection from affiliate abuses completely to the marketplace.” [475] New Jersey Board states that, even where there are a few Start Printed Page 39961providers that comprise the market, such oligopolies often exhibit the same lack of competition and high prices as are seen in a monopoly market. Thus, affiliate abuse would remain a concern where utilities would be granted market-based rate authority.[476]

472. AARP similarly comments that the proposed definition of “captive customers” fails to capture the potential for adverse impacts on retail customers of “default” suppliers and thus, the coverage of the Commission's affiliate restrictions should be expanded to prevent customers from bearing the costs of non-regulated marketing affiliates of the public utility they rely on for reliable service.[477]

473. ELCON suggests that “captive customers” should be defined as any end-users that do not have real competitive opportunities.[478] It recommends that the Commission adopt a case-specific approach to identifying captive customers to account for the failure of retail competition in many restructured states.

474. A number of other commenters argue that the proposed definition of “captive customers” is too broad [479] and would improperly include customers with competitive alternatives. They state that the Commission should clarify that “captive customers” does not include customers in states with retail choice.[480] Duke recommends that the Commission define “captive customer” as “any electric energy customer that cannot choose an alternative energy supplier.” [481] Duke adds that initial commenters, such as ELCON, provide no support for their assertion that state retail access programs do not generate effective competition and that most provider-of-last-resort customers are actually captive.

475. Ameren comments that while there are sellers with market-based rate authority that have no captive wholesale customers for energy, but do have a cost-based rate schedule for reactive power supply, the fact that a seller has wholesale customers under a single cost-based rate for reactive power should not render the entity a seller with “captive customers” and therefore, subject to the affiliate restrictions.[482] It states that such a seller would have no ability to transfer benefits from its “captive customers” (customers taking reactive power services at cost-based rates) to subsidize its unregulated market-based rate sales, given the different products at issue and the restrictions of the cost-based rates for reactive power.

476. APPA/TAPS submit that the definition of “captive customers” should include wholesale transmission customers captive to the transmission provider's system.[483] APPA/TAPS state that affiliate abuse not only raises costs to wholesale customers, it can also harm competition such as through cross-subsidization that provides the seller with an unfair competitive advantage. Therefore, APPA/TAPS state that wholesale transmission customers captive to the transmission provider's system are particularly vulnerable to this kind of competitive harm and should be included in the definition of “captive customers” in the regulations.[484]

477. EEI responds to APPA/TAPS' comment by stating that it is “completely unnecessary” to include transmission dependent utilities in the definition of captive customers since Order No. 888 already provides sufficient protections for transmission customers. Additionally, EEI replies that transmission dependent utilities are like customers with retail choice who have chosen to stay under cost-based rates while other transmission customers have broader options. EEI responds that the Commission does not currently consider such customers captive and there is no reason to change this policy.[485]

Commission Determination

478. The Commission adopts the NOPR proposal to define “captive customers” as “any wholesale or retail electric energy customers served under cost-based regulation.”

479. The Commission clarifies in response to several comments that the definition of “captive customers” does not include those customers who have retail choice, i.e. the ability to select a retail supplier based on the rates, terms and conditions of service offered. Retail customers who choose to be served under cost-based rates but have the ability, by virtue of State law, to choose one retail supplier over another, are not considered to be under “cost-based regulation” and therefore are not “captive.”

480. As the Commission has explained, retail customers in retail choice states who choose to buy power from their local utility at cost-based rates as part of that utility's provider-of-last-resort obligation are not considered captive customers because, although they may choose not to do so, they have the ability to take service from a different supplier whose rates are set by the marketplace. In other words, they are not served under cost-based regulation, since that term indicates a regulatory regime in which retail choice is not available.[486] On the other hand, in a regulatory regime in which retail customers have no ability to choose a supplier, they are considered captive because they must purchase from the local utility pursuant to cost-based rates set by a State or local regulatory authority.[487] Therefore, with this clarification, the Commission will adopt the definition of “captive customers” proposed in the NOPR and clarifies, that, as the Commission did in Order No. 669-A, we will include the definition of captive customers in the regulations. Regarding wholesale customers, sellers should continue to explain why, if they have wholesale customers, those customers are not captive.

481. We note that it is not the role of this Commission to evaluate the success or failure of a State's retail choice program including whether sufficient choices are available for customers inclined to choose a different supplier. In this regard, the states are best equipped to make such a determination and, if necessary, modify or otherwise revise their retail access programs as they deem appropriate. Further, to the extent a retail customer in a retail choice state elects to be served by its local utility under provider-of-last-resort obligations, the State or local rate setting authority, in determining just and reasonable cost-based retail rates, would in most circumstances be able to review the prudence of affiliate purchased power costs and disallow pass-through of costs incurred as a result of an affiliate undue preference.

482. We also decline to include transmission customers in the definition of “captive customers” for purposes of market-based rates. We agree with EEI that the Commission's open access Start Printed Page 39962policies protect transmission customers from the exercise of vertical market power. In this regard, we note that the Commission recently issued Order No. 890, which revised the pro forma OATT to ensure that it achieves its original purpose of remedying undue discrimination. Order No. 890 provided greater clarity regarding the requirements of the pro forma OATT and greater transparency in the rules applicable to the planning and use of the transmission system, in order to reduce opportunities for the exercise of undue discrimination, make undue discrimination easier to detect, and facilitate the Commission's enforcement of the tariff.

483. In response to Ameren's comments that a seller with wholesale customers under a single cost-based rate for reactive power should not be considered a seller with “captive customers” subject to the affiliate restrictions, we agree that such customers are not captive for purposes of market-based rates. The concerns underlying the affiliate restrictions do not apply to sales of reactive power because those sales are typically either made to transmission providers so that the transmission provider can satisfy its obligation to provide reactive power or made by the transmission provider under its applicable OATT.

c. Definition of “Non-Regulated Power Sales Affiliate”

Commission Proposal

484. Proposed § 35.36(a)(6) defined “non-regulated power sales affiliate” as “any non-traditional power seller affiliate, including a power marketer, exempt wholesale generator, qualifying facility or other power seller affiliate, whose power sales are not regulated on a cost basis under the FPA.”

Comments

485. A number of commenters seek clarification and modification of the Commission's proposed definition of “non-regulated power sales affiliate.”

486. Southern requests clarification that a franchised public utility does not become a non-regulated power sales affiliate simply because it may make some wholesale sales under market-based rate authority.

487. SoCal Edison argues that the Commission offers no explanation for including Qualifying Facilities (QFs) in the definition of “non-regulated power sales affiliate.” It states that the proposed definition of non-regulated power sales affiliate would subject QFs that may not have market-based rate authority to the code of conduct. It states that the NOPR proposal would constitute a departure from traditional PURPA implementation and from the Commission's recently revised regulations reaffirming that QF contracts created pursuant to a statutory regulatory authority's implementation of PURPA are exempt from review under sections 205 and 206 of the FPA.[488] PG&E asserts that the Commission should clarify the meaning of “non-regulated power sales affiliate” so that it does not encompass all affiliates such as parent companies or the natural gas LDC function of the regulated, franchised utility.[489]

488. Xcel states that it is not clear whether the following result was intended, but the definition arguably could cover a “traditional” utility with a franchised retail service territory that had converted all of its wholesale sales from cost-based to market-based rates. According to Xcel, not all utilities will be selling at cost-based rates at wholesale, even though they may still be doing so at retail in franchised service territories.[490] Xcel does not believe that it would be reasonable to exclude from the definition of “non-regulated power sales affiliate” a utility that serves retail customers under a franchised service territory. Xcel also comments that the Commission should allow a waiver provision for utilities' subsidiaries or affiliates to be treated under the Commission's affiliate sales rules as affiliated utilities rather than as “non-regulated power sales affiliates.” [491] Xcel believes that the proposed definition would generally serve to demarcate affiliates that should be treated as regulated from those that should be treated as non-regulated under the Commission's affiliate rules but states that it is not desirable or beneficial to draw a completely bright line between the two. Xcel states that some flexibility may be beneficial for both utilities and their customers and the Commission should not foreclose innovative structures by adopting hard and fast rules.[492]

489. NASUCA also suggests revisions to this definition, out of concern that several of the terms used (non-regulated, non-traditional, regulated on a cost basis) are vague, inaccurate and unnecessary.[493] NASUCA suggests that the term be renamed “power sales affiliate with market-based rates” and defined as “any power seller affiliate utility, including a power marketer, exempt wholesale generator, qualifying facility or other power seller affiliate, with market-based rates authorized under these rules or Commission orders.” [494]

Commission Determination

490. The Commission will modify the definition of “non-regulated power sales affiliate,” and change the term to “market-regulated power sales affiliate.” [495] In response to various commenters, we clarify that this definition is intended to apply only to non-franchised power sales affiliates (whose power sales are not regulated on a cost basis under the FPA, e.g., affiliates whose power sales are made at market-based rates) of franchised public utilities. Additionally, while we recognize that we have used the term “non-regulated” in the past, we believe that “market-regulated” is a more appropriate description for the entities we intend to capture in this definition. Accordingly, in this Final Rule, we revise the definition of “market-regulated power sales affiliate” to mean “any power seller affiliate other than a franchised public utility, including a power marketer, exempt wholesale generator, qualifying facility or other power seller affiliate, whose power sales are regulated in whole or in part at market-based rates.” Because the revised definition includes only non-franchised public utilities, it does not apply to a franchised public utility that makes some sales at market-based rates.[496]

491. Xcel posits a somewhat different scenario under which it believes that a franchised public utility would fall within the definition of “non-regulated power sales affiliate,” namely, if such utility makes no wholesale sales that are regulated on a cost basis (making only wholesale sales at market-based rates) but serves retail customers under a franchised service territory. With the revision to the definition of “market-regulated power sales affiliate” that we adopt here, such a utility would not fall within the definition of “market-regulated power sales affiliate” since it has a franchised service territory.

492. In addition, we note that the Commission has historically placed affiliate restrictions only on the Start Printed Page 39963relationship between a franchised public utility with captive customers and any affiliated market-regulated power sales affiliate. Nevertheless, we believe that there may be circumstances in which it also would be appropriate to impose similar restrictions on the relationship of two affiliated franchised public utilities where one of the affiliates has captive customers and one does not have captive customers. In such a case, there is a potential for the transfer of benefits from the captive customers of the first franchised utility to the benefit of the second franchised utility and ultimately to the joint stockholders of the two affiliated franchised public utilities. Commenters in the instant proceeding did not address the potential for affiliate abuse in this situation (i.e., between a franchised public utility with captive customers and an affiliated franchised public utility without captive customers). Accordingly, we do not generically impose the affiliate restrictions on such relationships but will evaluate whether to impose the affiliate restrictions in such situations on a case-by-case basis.

493. However, to avoid confusion between references to a “franchised public utility with captive customers” and a “franchised public utility without captive customers” we will revise the definition of “franchised public utility” in § 35.36(a)(5) to remove the reference to captive customers. Accordingly, “franchised public utility” will be defined as “a public utility with a franchised service obligation under State law.” Further, we will revise other sections of the affiliate restrictions to specifically use the term “franchised public utility with captive customers” to clarify when the affiliate restrictions apply.

494. Additionally, not all qualifying facilities are necessarily included in the proposed definition of “market-regulated power sales affiliate.” Only those qualifying facilities whose market-based rate sales fall under the Commission's jurisdiction would fall within the definition of “market-regulated power sales affiliate.” To the extent that some of a qualifying facility's sales are regulated under the FPA, even if other sales are regulated by the states, such a qualifying facility would be considered a market-regulated power sales affiliate by virtue of its FPA jurisdictional sales.

495. Additionally, the Commission clarifies that the definition of “market-regulated power sales affiliate” does not encompass all affiliates such as parent companies or the natural gas LDC function of the regulated franchised utility; rather, it only includes non-franchised, power sales affiliates (sellers) that sell power in whole or in part at market based rates, and not an affiliated service company or others who are not authorized to make sales of power.

d. Other Definitions

In the NOPR, the Commission proposed to adopt a restriction on affiliate sales of electric energy, whereby no wholesale sale of electric energy could be made between a public utility seller with a franchised service territory and a non-regulated power sales affiliate without first receiving Commission authorization under FPA section 205. This restriction would be a condition of obtaining and retaining market-based rate authority, and a failure to satisfy that condition would be a violation of the seller's market-based rate tariff.[497]

Comments

496. Constellation proposes that the language in the proposed affiliate sales restriction provision be amended to use the defined term “franchised public utility” by replacing the phrase “public utility Seller with a franchised service territory” with “Seller that is a franchised public utility.” Constellation submits that this change would make clear that the affiliate restrictions apply only if the seller is affiliated with a public utility that has captive customers, which it states appears to be the Commission's intent.[498]

497. FirstEnergy proposes that a definition of franchised service territory be added to the regulations to clarify that the affiliate sales restriction would only apply to transactions involving public utilities with captive retail customers, and would not apply in areas in which there is retail choice.[499]

Commission Determination

498. The Commission's intent was that the affiliate sales restriction in proposed § 35.39(a) (now § 35.39(b)) would apply where a utility with a franchised service territory with captive customers proposes to make wholesale sales at market-based rates to a market-regulated power sales affiliate, or vice versa. Accordingly, we will revise § 35.39(a) (now § 35.39(b)) to replace “public utility Seller with a franchised service territory” with “franchised public utility with captive customers.” In light of this clarification, we do not believe it necessary to add a definition of franchised service territory to the regulations, as proposed by FirstEnergy.

e. Treating Merging Companies as Affiliates

Commission Proposal

499. In the NOPR, the Commission noted that, for purposes of affiliate abuse, companies proposing to merge are considered affiliates under their market-based rate tariffs while their proposed merger is pending, and sought comments regarding at what point the Commission should consider two non-affiliates as merging partners.[500]

Comments

500. PG&E comments that affiliate sales regulations should not apply to contracts that pre-date the announcement of a merger. PG&E states that the Commission should allow merging companies sufficient time (e.g., 30 days) after the announcement of a merger before enforcing the affiliate sales regulations in order to give the merging companies time to acquire the necessary information and documents to prevent a company from being held responsible for activities of the merging company that it has no knowledge of or control over.[501]

Commission Determination

501. The Commission will continue to require that, for purposes of affiliate abuse, companies proposing to merge will be treated as affiliates under their market-based rate tariffs while their proposed merger is pending.[502] The Commission will adopt the proposal to use the date a merger is announced as the triggering event for considering two non-affiliates as merging partners. In this regard, we reject PG&E's proposal that the Commission allow an additional 30 days after an announced merger to begin treating, for the purpose of affiliate abuse, merging partners as affiliates. With the extensive discussions, negotiations and review that precede the formal announcement of plans to merge, there is sufficient time for companies to acquire the necessary information and documents related to the proposed merger, particularly given that utilities are on notice of our policy in this regard.

502. The Commission clarifies that the requirement that merging companies Start Printed Page 39964be treated as affiliates while the proposed merger is pending only applies prospectively from the date the merger is announced and does not apply to any contracts entered into that pre-date the announcement of the merger.[503] However, in the case of an umbrella agreement that pre-dates the announcement of the merger, any transactions under such umbrella agreement that are entered into on or after the date the merger is announced would be subject to the affiliate restrictions. Further, if an announced merger does not go forward, the affiliate restrictions will cease to apply as of the date the announcement is made that the merger will not go forward.

f. Treating Energy/Asset Managers as Affiliates

Commission Proposal

503. In the NOPR, the Commission proposed that unaffiliated entities that engage in energy/asset management of generation on behalf of a franchised public utility with captive customers be bound by the same affiliate restrictions as those imposed on the franchised public utility and the non-regulated power sales affiliates.[504] The Commission recognized that there has been an increased range of activities engaged in by asset or energy managers.[505] The Commission noted that although asset managers can provide valuable services and benefit consumers and the marketplace, such relationships also could result in transactions harmful to captive customers.[506] Accordingly, the Commission proposed that an entity managing generation for the franchised public utility should be subject to the same affiliate restrictions as the franchised public utility (e.g., restrictions on affiliate sales and information sharing). The Commission referenced a settlement in which Enforcement staff alleged that an affiliated power marketer acting as an asset manager for three generation-owning affiliates violated § 214 of the FPA.[507] As a result, if a company is managing generation assets for the franchised public utility, such entity would be subject to the same information sharing provision as the franchised public utility with regard to information shared with non-regulated affiliates, such as power marketers and power producers.[508] Similarly, asset managers of a non-regulated affiliate's generation assets would be subject to the same affiliate restrictions as the market-regulated power sales affiliate, including the information sharing provision.[509]

Comments

504. Morgan Stanley comments that unaffiliated asset and energy managers should not be treated as affiliates of owners of the managed portfolios and that it would be overly inclusive for the Commission to adopt a presumption of control that would treat the energy manager as a franchised utility for purposes of the affiliate abuse rules.[510] Financial Companies argue that the Commission should not apply the affiliate abuse restrictions generically to all unaffiliated energy managers that provide management services to a franchised utility or its affiliates. Rather, the Commission should evaluate applicability of the affiliate abuse restrictions on a case-by-case basis.[511]

505. Allegheny claims that the Commission failed to consider the costs to customers, which are likely to be substantial through the loss of efficiencies by treating asset managers as affiliates.[512] Allegheny claims that there will be higher costs because: (1) The affiliated asset manager will need to pass added costs on to the franchised utility; (2) if the affiliated asset manager cannot pass on costs, it may no longer provide the service and the utility may need to set up duplicative asset management capability, resulting in higher costs; or (3) the franchised utility will need to hire a third-party asset manager, presumably more expensive.[513] Constellation makes a similar argument about the substantial costs and reduction of efficiencies by discouraging energy/asset management agreements.[514]

506. EPSA states that it opposes the Commission's proposal to treat asset managers as affiliates. It submits that asset managers are not legally affiliates of the companies with which they have a contract. If the basis for the proposal to treat asset managers as affiliates is for transparency purposes, EPSA says that all such contracts and transactions with asset managers are already reportable under the change in status final rule.[515]

507. Alliance Power Marketing argues that by imposing affiliate abuse restrictions on entities acting on behalf of a regulated public utility or its non-regulated affiliates, the Commission seeks to alter the fundamental principle of responsibility and liability of the regulated entity by making the third-party also directly accountable, thus blurring the lines of accountability. Furthermore, a critical element in applying affiliate abuse restrictions to entities' action on behalf of generation owners lies in having a stake in the outcome rather than just considering some direct or indirect control. Alliance Power Marketing asserts that evaluating control over the outcome as the threshold for asset managers could sweep up many entities, such as RTOs/ISOs, governmental and cooperative entities, that could have jurisdictional and practical ramifications.[516]

508. A number of other commenters oppose the Commission's proposal to treat unaffiliated energy/asset managers as part of the franchised public utility. They argue that the current code of conduct already provides the protections sought by such a proposal and the Commission fails to explain the need for such expanded regulation.[517] Furthermore, they submit that such proposal does not consider the additional costs to consumers through lost efficiencies.[518]

509. PG&E argues that the Commission proposal to consider “entities acting on behalf of and for the benefit of [the utility/affiliate]” as part of the utility/affiliate itself is unnecessary and overly broad.[519]

510. Indianapolis P&L does not oppose the Commission's proposal to treat asset managers as affiliates for the limited purposes of the code of conduct, standards of conduct or inter-affiliate transaction issues, but it states that the Commission should not treat unaffiliated asset managers as affiliates when determining how much generating Start Printed Page 39965capacity should be attributed to a generation asset owner.[520]

511. Financial Companies and Morgan Stanley both state in their reply comments that the Commission should not impose affiliate restrictions on unaffiliated energy managers, as the Commission provides no basis for such requirement [521] and no evidence that energy managers can engage in cross-subsidization of unregulated affiliates.[522]

Commission Determination

512. From the various comments submitted it is apparent that our proposal has created confusion as to our intent with regard to the treatment of energy/asset managers under the proposed affiliate restrictions. Accordingly, we clarify and simplify our approach, as discussed below.

513. The Commission is concerned that there exists the potential for a franchised public utility with captive customers to interact with a market-regulated power sales affiliate in ways that transfer benefits to the affiliate and its stockholders to the detriment of the captive customers. Therefore, the Commission has adopted certain affiliate restrictions to protect the captive customers and, in this Final Rule, is codifying those restrictions in our regulations. To that end, we make clear that such utilities may not use anyone, including energy/asset managers, to circumvent the affiliate restrictions (e.g., independent functioning and information sharing prohibitions). Accordingly, we adopt and codify in our regulations at § 35.39(c)(1) and 35.39(g) an explicit prohibition on using third-party entities to circumvent otherwise applicable affiliate restrictions.

514. We note that energy/asset managers provide a variety of services for franchised public utilities and market-regulated power sales affiliates, including, but not limited to, operating generation plants (sometimes under tolling agreements), acting as billing agents, bundling transmission and power for customers, and scheduling transactions. However, regardless of the relationships and duties of an energy/asset manager to a franchised public utility or its non-regulated affiliate, the energy/asset manager may not act as a conduit to circumvent the affiliate restrictions.[523]

515. This approach is consistent with past Commission orders that have identified the potential that affiliated exempt wholesale generators or qualifying facilities could serve as a conduit for providing below-cost services to an affiliated power marketer at the expense of captive customers of the public utility operating companies and imposed restrictions to prevent this.[524]

516. Although several commenters assert that the costs of asset management will increase as a result of requiring asset managers to observe the affiliate restrictions, they did not provide any examples of why the costs would increase. The Commission notes that under this Final Rule, all asset managers are not required to observe the affiliate restrictions, only those asset managers which control or market generation of the franchised public utility with captive customers or a market-regulated power sales affiliate of a franchised public utility with captive customers. In those instances, the need to protect captive customers outweighs any generalized assertions of increased cost.

517. We note that to the extent that a franchised public utility with captive customers and one or more of its non-regulated marketing affiliates obtains the services of the same energy/asset manager, such an arrangement would create opportunities to harm captive customers depending on how the energy/asset manager is structured. For example, without internal separation between the energy/asset managers' regulated and non-regulated businesses, there would exist opportunities to harm captive customers.

g. Cooperatives

Comments

518. Suez/Chevron asks the Commission to clarify that jurisdictional utilities organized as cooperatives are not exempt from the affiliate abuse rules and that all jurisdictional public utilities with captive customers, including utilities organized as cooperatives, must comply with the affiliate abuse rules.[525]

519. El Paso E&P argues that it would appear that the proposed affiliate restrictions would apply to power sales at market-based rates made by G&T cooperatives to their State-regulated member distribution cooperatives. It states that based on the definition of a “franchised public utility” as “a public utility with a franchised service obligation under State law and that has captive customers,” distribution cooperatives that are granted franchised service territories by State regulatory agencies would be included in this definition. El Paso E&P asserts that a G&T cooperative with authority to sell power at market-based rates would be defined as a non-regulated power seller and, accordingly, sales made by a G&T cooperative at market-based rates to its affiliated member distribution cooperatives would, under the proposed regulations, be required to comply with the requirements of the rule.[526]

520. However, El Paso E&P argues that the Commission has previously stated that affiliate abuse is not a concern for cooperatives owned by other cooperatives because the cooperatives' ratepayers are its members. El Paso E&P alleges that the Commission has never sufficiently explained the basis for its prior statements. According to El Paso E&P, the Commission's prior statements are based on the findings in Hinson Power[527] that lack of concern with the potential for affiliate abuse is premised on the absence of captive customers that would be subject to the exercise of market power. El Paso submits that the fact that ratepayers of the distribution cooperative are also members of such cooperatives should not alleviate the Commission's concern about potential affiliate abuse issues. El Paso E&P claims that industrial customers of distribution cooperatives with franchised service territories are captive to service from the generation and transmission and distribution cooperatives that serve them and are in need of protection from the Commission to ensure that they are charged just and reasonable rates.[528]

521. NRECA submits that El Paso misreads the proposed regulations by classifying distribution cooperatives as a “public utility Seller” under the proposed regulations and NRECA comments that it is not aware of any distribution cooperatives that would be classified as “public utility Sellers” thus triggering the restriction on affiliate sales without first receiving Commission approval. NRECA states that nearly all distribution cooperatives are not regulated as public utilities under the FPA because they either have Rural Electrification Act (REA) financing or sell less than 4 million Start Printed Page 39966MWh per year and thus do not qualify as a “public utility” under section 201(f) of the FPA. Furthermore, NRECA comments that very few distribution cooperatives sell any electricity for resale. Thus, they would not need to obtain market-based rate authority under section 205 even if they were not relieved of that obligation by section 201(f).[529] NRECA also comments that the Commission has explained the reasoning behind not requiring cooperatives to comply with the affiliate abuse requirements by stating that “in the case of a cooperative, the cooperative's members are both the ratepayers and the shareholders, and thus there is no potential danger of shifting benefits from one to another.” [530]

522. El Paso E&P responds that NRECA incorrectly interprets the scope of the proposed affiliate restriction and that NRECA ignores the definition of “franchised public utility” as “a public utility with a franchised service obligation under State law and that has captive customers.” El Paso E&P submits that this definition clearly includes distribution cooperatives. El Paso E&P further replies that the fact that distribution cooperatives are not “public utilities” regulated by the Commission is irrelevant because the Commission is not proposing to regulate sales by such distribution cooperatives. Rather, it is proposing to regulate wholesale sales by the generation and transmission cooperatives to their member distribution cooperatives. Therefore, El Paso E&P argues, the Commission should clarify the regulations to ensure that generation and transmission cooperatives are covered under the affiliate restrictions.[531]

523. El Paso E&P also responds that NRECA's attempt to divorce a generation and transmission cooperative's market-based rate sales to its distribution cooperative members from the distribution cooperative's sales to captive customers ignores the cooperative structure. It states that a generation and transmission cooperative is comprised of its member distribution cooperatives and both the generation and transmission and distribution cooperatives act in concert in connection with sales to industrial customers.[532] El Paso E&P also submits that NRECA's argument suggests that the Commission has no jurisdiction over sales to State-regulated franchised public utilities that are not cooperatives.[533] According to El Paso E&P, the captive customers of distribution cooperatives are in need of the same protection from the Commission notwithstanding that the distribution cooperatives are regulated by the states.[534]

524. El Paso E&P also states that wholesale electric sales approved by the Commission must be passed through at the retail level. Thus, El Paso E&P states that it is not sufficient to suggest that the Commission need not be concerned because the distribution cooperatives' rates are subject to State regulation.[535] Finally, El Paso E&P responds that NRECA cannot seek the protection of this Commission when its members are purchasers of power, and then claim its members should be exempt from scrutiny when they are sellers to captive customers such as El Paso E&P. It asserts that captive customers of generation and transmission and their member distribution cooperatives are in need of protection.[536]

Commission Determination

525. FPA section 201(f) specifically exempts from the Commission's regulation under Part II of the FPA, except as specifically provided, electric cooperatives that receive REA financing or sell less than 4 million megawatt hours of electricity per year.[537] Thus, such electric cooperatives are not considered public utilities under the FPA and our market-based rate regulations do not apply to those electric cooperatives. Further, with respect to distribution-only cooperatives, they either do not meet the “public utility” definition because they do not own or operate facilities used for wholesale sales or transmission in interstate commerce or, if they do own or operate such facilities, they are exempted from Part II regulation by virtue of FPA section 201(f). In this regard, we note that NRECA states that it is unaware of any distribution cooperatives in the United States that would be “public utility Sellers” under the proposed regulations.[538] Such a cooperative would not be subject to the affiliate restrictions in the proposed regulations at § 35.39.

526. For electric cooperatives that are public utility sellers and not exempted from public utility regulation by FPA section 201(f), as discussed above, the Commission will continue to treat such electric cooperatives as not subject to the Commission's affiliate abuse restrictions, based on a finding that transactions of an electric cooperative with its members do not present dangers of affiliate abuse through self-dealing. Even if an electric cooperative is not statutorily exempted from our regulation under Part II of the FPA, we conclude that a waiver of § 35.39 is appropriate. As the Commission has previously explained, “affiliate abuse takes place when the affiliated public utility and the affiliated power marketer transact in ways that result in a transfer of benefits from the affiliated public utility (and its ratepayers) to the affiliated power marketer (and its shareholders).” [539] However, as the Commission has previously stated in many market-based rate orders over the years,[540] where a cooperative is involved, the cooperative's members are both the ratepayers and the shareholders. Any profits earned by the cooperative will enure to the benefit of the cooperative's ratepayers. Therefore, we have found that there is no potential danger of shifting benefits from the ratepayers to the shareholders.[541]

527. Finally, we agree with NRECA's argument that the issue that El Paso E&P discusses in its comments is not a concern that can be addressed through affiliate restrictions in market-based rates, but is rather more of a concern of discrimination in the allocation of benefits and burdens among retail ratepayers. The Commission does not possess jurisdiction to review a distribution cooperative's retail rates; that issue falls under State law. Moreover, El Paso E&P's argument that wholesale electric sales approved by the Commission must be passed through at the retail level is misplaced. As the courts have previously held, State commissions are not precluded from reviewing the prudence of a company's purchasing decisions, and may disallow pass-through of wholesale purchase costs unless the purchaser had no legal right to refuse to make a particular purchase.[542]

Start Printed Page 39967

528. Therefore, for the reasons stated above, the Commission will continue to follow its current precedent and find that electric cooperatives that are public utility sellers and not exempted from public utility regulation by FPA § 201(f) are not subject to the Commission's affiliate abuse requirements.

2. Power Sales Restrictions

Commission Proposal

529. In the NOPR the Commission proposed to continue the policy of reviewing power sales transactions between regulated and “non-regulated” affiliates under section 205 of the FPA. This policy means, among other things, that a general grant of market-based rate authority does not apply to affiliate sales between a regulated and a non-regulated affiliate, absent express authorization by the Commission.

530. The Commission proposed to amend the regulations to include a provision expressly prohibiting power sales between a franchised public utility [543] and any of its non-regulated power sales affiliates without first receiving authorization for the transaction under section 205 of the FPA.

531. Additionally, although it did not propose to codify the requirement in the regulatory text, the Commission proposed that sellers seeking authorization to engage in affiliate transactions will continue to be obligated to provide evidence as to whether there are captive customers that would trigger the application of the affiliate restrictions. The Commission stated that if the Commission finds, based on the evidence provided by the seller, that the seller has no captive customers, the affiliate restrictions in the regulations would not apply.

532. The Commission proposed to continue its prior approach for determining what types of affiliate sales transactions are permissible and the criteria that should be used to make those decisions, including evaluation of the Allegheny and Edgar criteria.[544] Although it did not propose to codify a safe harbor provision in the regulations, the Commission noted that when affiliates participate in a competitive solicitation process, application of the Allegheny criteria would constitute a safe harbor that affiliate abuse conditions are satisfied in a transaction between a franchised public utility and its affiliates. The Commission emphasized, however, that using a competitive solicitation is not the only way to address concerns that an affiliate transaction does not pose undue preference concerns.[545]

533. The Commission said it continues 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. The Commission proposed 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 [546] for eligibility for use in jurisdictional tariffs. The Commission sought comment on whether evidence other than competitive solicitations, RTO price or non-RTO price indices, or benchmarks described in the NOPR should be accepted in an application for authority to engage in market-based affiliate power sales. In addition, the Commission proposed to consider two merging partners as affiliates as of the date a merger is announced, and sought comments on this proposal (or whether to use the date the § 203 application is filed with the Commission, or another time). The Commission also proposed that unaffiliated entities that engage in energy/asset management of generation on behalf of a franchised public utility or non-regulated utility be bound to comply with the same affiliate restrictions as those imposed on the franchised public utility and the non-regulated power sales affiliate.

534. The Commission said it continues 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. The Commission proposed 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 [547] for eligibility for use in jurisdictional tariffs. The Commission sought comment on whether evidence other than competitive solicitations, RTO price or non-RTO price indices, or benchmarks described in the NOPR should be accepted in an application for authority to engage in market-based affiliate power sales. In addition, the Commission proposed to consider two merging partners as affiliates as of the date a merger is announced, and sought comments on this proposal (or whether to use the date the § 203 application is filed with the Commission, or another time). The Commission also proposed that unaffiliated entities that engage in energy/asset management of generation on behalf of a franchised public utility or non-regulated utility be bound to comply with the same affiliate restrictions as those imposed on the franchised public utility and the non-regulated power sales affiliate.

Comments

535. Industrial Customers urge the Commission to recognize that when an affiliate transaction has been subject to a State-approved process, separate section 205 approvals for such transactions should not be required. If, however, the Commission does maintain the section 205 approval, “the imprimatur of State commission approval should create a rebuttable presumption that the transaction is just and reasonable.” [548] NASUCA comments that the Commission should not assume the reasonableness of all affiliate sales under contracts with Start Printed Page 39968prices linked to spot markets or other auction results.[549]

536. Other commenters urge the Commission to clarify that, while requests for proposals consistent with the Allegheny and Edgar standards and affiliate sales based on market index prices constitute a safe harbor for affiliate abuse, those should not be the only safe harbors.[550] The Commission should state it is willing to consider other information and evidence, including affiliate sales reviewed and authorized by a State regulatory agency, as safe harbors as well.[551]

537. New Jersey Board disagrees with comments that the Commission should consider State approval of affiliate sales as a safe harbor and responds that the Commission should assure that affiliate abuse does not take place and not ignore affiliate sales based on actions and oversight by State commissions.[552]

538. State AGs and Advocates oppose the Commission's proposal to find affiliate sales of wholesale power just and reasonable if such sales are made through an auction that reflects certain guidelines such as those set forth in Edgar and Allegheny. Instead, State AGs and Consumer Advocates state that the Commission should develop behavioral market power tests that apply to all market structures and that each auction should be assessed separately and evaluated on the merits of the proposal.[553]

539. Industrial Customers oppose the Commission's proposal to rely on an RTO/ISO benchmark price or index to mitigate affiliate abuse concerns and argues that tying an affiliate transaction to a price index should not allow utilities to escape scrutiny.[554]

Commission Determination

540. The Commission adopts the proposal to continue its approach for determining what types of affiliate transactions are permissible and the criteria used to make those decisions. Although we are not codifying a safe harbor in our regulations, when affiliates participate in a competitive solicitation process for power sales, we will consider proper application of the Allegheny guidelines to constitute a safe harbor that the affiliate abuse concerns are satisfied in a transaction between a franchised public utility with captive customers and its non-regulated power sales affiliate. The Commission will consider proposed competitive solicitations on a case-by-case basis. We again emphasize that using a competitive solicitation by applying the Allegheny and Edgar guidelines is not the only way an affiliate transaction can address our concerns that the transaction does not pose undue preference concerns. We will consider other approaches on a case-by-case basis. Also, to the extent a seller is not bound by the affiliate restrictions because neither the seller nor the buyer has captive customers, we find that the Edgar principles do not apply and the seller does not need to make a filing with regard to a proposed competitive solicitation.[555]

541. A number of commenters urge the Commission to find that a State-approved solicitation process creates a rebuttable presumption that an affiliate transaction satisfies the Commission's affiliate abuse concerns. The Commission will consider a State-approved process as evidence in its consideration as to whether our affiliate abuse concerns have been adequately addressed, but the Commission will not treat a State-approved process as creating a rebuttable presumption that our affiliate abuse concerns have been addressed. In this regard, the Commission has a responsibility under section 205 of the FPA to ensure that all jurisdictional rates charged are just and reasonable and not unduly discriminatory or preferential. While a State-approved solicitation process may provide evidence that the wholesale rates proposed as a result of that process are just and reasonable and do not involve any undue discrimination or preference, we do not believe it is appropriate to create a rebuttable presumption.

542. Further, the Commission will continue to allow an established, relevant market price or index such as in an RTO or ISO to be used as a benchmark for the reasonableness of the price of an affiliate transaction. In this regard, we disagree with commenters that relying on such prices or indices allows utilities to escape Commission scrutiny. Such an index 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).[556] The Commission previously stated 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.[557]

543. In addition, while the Commission has found in the past that certain non-RTO price indices are acceptable indicators of market prices, we continue to 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 [558] and November 19 Price Index Order. Therefore, the Commission will 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 and reflects the market price where the affiliate transaction occurs (i.e., is a relevant index).[559]

3. Market-Based Rate Affiliate Restrictions (Formerly Code of Conduct) for Affiliate Transactions Involving Power Sales and Brokering, Non-Power Goods and Services and Information Sharing

Commission Proposal

544. The Commission stated in the NOPR that it continues to believe that a code of conduct is necessary to protect captive customers from the potential for affiliate abuse. In light of the repeal of the Public Utility Holding Company Act of 1935 [560] and the fact that holding company systems may have franchised public utility members with captive customers as well as numerous non-regulated power sales affiliates that engage in non-power goods and services transactions with each other, the Commission stated that it is important to have in place restrictions that preclude transferring captive customer benefits to stockholders through a company's non-regulated power sales business. Therefore, the Commission stated its belief that it is appropriate to condition all market-based rate authorizations, including authorizations Start Printed Page 39969for sellers within holding companies, on the seller abiding by a code of conduct for sales of non-power goods and services and services between power sales affiliates. In addition, the Commission stated that greater uniformity and consistency in the codes of conduct is appropriate and, therefore, proposed to adopt a uniform code of conduct to govern the relationship between franchised public utilities with captive customers and their “non-regulated” affiliates, i.e., affiliates whose power sales are not regulated on a cost basis under the FPA. The Commission proposed to codify such affiliate restrictions in the regulations and to require that, as a condition of receiving market-based rate authority, franchised public utility sellers with captive customers comply with these restrictions. The Commission proposed that the failure to satisfy the conditions set forth in the affiliate restrictions will constitute a tariff violation.

545. The Commission sought comments on this proposal and on whether the specific affiliate restrictions proposed in the NOPR are sufficient to protect captive customers. In particular, the Commission sought comments on what changes, if any, should be adopted.

a. Uniform Code of Conduct/Affiliate Restrictions—Generally

Comments

546. Some commenters support codifying the code of conduct affiliate restrictions in the regulations and comment that it will lead to consistent codes of conduct across all sellers, thus creating greater transparency, and will aid the Commission's enforcement efforts.[561] ELCON argues that the ability of large utility holding companies with one foot in “competition” and one foot in “regulation” creates a myriad of potential problems.[562] Several State agencies and consumer commenters generally support the proposal to codify uniform code of conduct restrictions in the Commission's regulations.[563] NASUCA comments that the separation of function requirements should apply to any affiliate with retail customers, not just to affiliates who are franchised public utilities.[564]

547. FP&L, however, does not believe it is unduly preferential to have different codes of conduct.[565] Indianapolis P&L argues that a single tariff/code of conduct does not make sense for diversified energy companies with geographically widespread operations.[566]

548. FP&L states that the Commission should include in the regulatory text the statement that the affiliate restrictions are waived where a seller demonstrates that there are no captive customers.[567] EEI states that utilities already found not to have captive customers because of retail choice should be grandfathered and should not have to request waiver of the code of conduct again.[568]

Commission Determination

549. The Commission will adopt the proposed affiliate restrictions with certain modifications and clarifications. These restrictions govern the separation of functions, the sharing of market information, sales of non-power goods or services, and power brokering. The Commission will require that, as a condition of receiving and retaining market-based rate authority, sellers comply with these affiliate restrictions unless otherwise permitted by Commission rule or order. As discussed herein, these affiliate restrictions govern the relationship between franchised public utilities with captive customers and their “market-regulated” affiliates, i.e., affiliates whose power sales are regulated in whole or in part on a market-based rate basis.

550. Failure to satisfy the conditions set forth in the affiliate restrictions will constitute a violation of the market-based rate tariff. As discussed in greater detail below, the Commission agrees with many of the commenters that the requirements and exceptions in the affiliate restrictions should follow those requirements and exceptions codified in the standards of conduct, where applicable.[569] The Commission believes that modeling these restrictions and the exceptions to those restrictions on the standards of conduct will lead to greater consistency and transparency and a greater understanding of permissible activities.

551. The Commission clarifies that any sellers that have previously demonstrated and been found not to have captive customers, and therefore have received a waiver of the market-based rate code of conduct requirement in whole or in part, will not be required to request another waiver of the associated affiliate restrictions. However, those sellers are still under the obligation to report to the Commission any changes in status that may affect the basis on which the Commission relied in granting their waiver, consistent with the requirements of Order No. 652.[570] Additionally, those sellers also will be required to meet the requirements necessary to maintain their market-based rate authority when they file their regularly scheduled updated market power analyses. As a result, they will be required to demonstrate that they continue to lack captive customers in order to support a continued waiver of the affiliate restrictions in the regulations. Sellers will also need to explain why any wholesale customers are not captive, as explained above.

552. In response to FP&L and EEI, because we clarify in this Final Rule that, where a seller demonstrates and the Commission agrees that it has no captive customers, the affiliate restrictions will not apply, the Commission does not believe it is necessary to include in the regulatory text a provision stating that the affiliate restrictions are waived where a seller demonstrates and the Commission agrees that it has no captive customers. Start Printed Page 39970

b. Exceptions to the Independent Functioning Requirement

Commission Proposal Regarding Separation of Employees and Shared Employees

553. In the NOPR, the Commission proposed regulatory language in § 35.39(b)(2) (now § 35.39(c)(2)) codifying the independent functioning requirement. Specifically, the Commission stated, to the maximum extent practical, the employees of a non-regulated power sales affiliate will operate separately from the employees of any affiliated franchised public utility.

554. The Commission did not propose to include any exceptions to the independent functioning requirements. However, the Commission invited commenters to propose additions to, substitutions for or elimination of the proposed affiliate restrictions.[571]

Comments

555. A number of commenters request that the Commission modify the affiliate restrictions to adopt some of the requirements and exceptions consistent with those codified in Order No. 2004, such as allowing the sharing of senior officers and members of the board of directors, field and maintenance employees and support employees. According to EPSA, the affiliate restrictions should provide specifically for permissible sharing of officers (not just sharing of support personnel) between a franchised public utility and a non-regulated power sales affiliate. EPSA notes that Order No. 2004 allows for shared officers as long as they do not direct, organize or execute day-to-day business transactions.[572]

556. Duke comments that treatment of shared employees under the affiliate restrictions should follow the obligations adopted in the standards of conduct. For example, Duke urges the Commission to allow the sharing of officers and directors.[573] Additionally, Avista states that the proposed affiliate restrictions should distinguish between operational and non-operational employees.[574]

557. PG&E urges the Commission to clarify which employees cannot be shared. PG&E states that prohibiting employees involved in general operation of generation facilities, who lack control over generation availability, from being shared would be overly broad and unduly restrictive.[575] PPL similarly requests clarification of which employees would be deemed “shared employees” under the affiliate restrictions.[576]

558. NiSource requests that the Commission create an exception to allow the sharing between operational employees of the franchised public utility and its non-regulated sales affiliates of any information necessary to maintain the safe and reliable operation of the bulk power system, similar to the exception in the standards of conduct at § 358.5(b)(8) of the Commission's regulations.[577]

559. EEI and FirstEnergy also request that the independent functioning requirement and information sharing restrictions in the proposed affiliate restrictions should have an exception for sharing employees and market information for emergency circumstances affecting system reliability.[578]

560. On the other hand, Morgan Stanley urges the Commission not to adopt a blanket exception to the affiliate restrictions for emergency situations because the commenters' proposal regarding what constitutes an “emergency” is vague and leaves too much discretion to the individual sellers. Additionally, Morgan Stanley explains that communications with an affiliate during an emergency may not adequately address an emergency; sharing information with all sellers in the market would provide a better foundation to deal with any emergency.[579]

Commission Determination

561. The Commission will revise the independent functioning requirement of the affiliate restrictions to include exceptions relating to permissibly shared senior officers and members of boards of directors, shared support personnel, and shared field and maintenance personnel. With regard to permissibly shared individuals, the Commission will impose a “no-conduit rule” similar to that in the standards of conduct.[580] Under the no conduit rule, to be codified at § 35.39(g), a permissibly shared employee is prohibited from acting as a conduit for disclosing market information to employees, officers or directors that are not shared.

562. The Commission agrees that a franchised public utility with captive customers and its market-regulated power sales affiliates should be permitted to share senior officers and members of the board of directors to conduct corporate governance functions, and to take advantage of the efficiencies of corporate integration.[581] Therefore, the Commission is adopting an exception at § 35.39(c)(2)(d) that permits a franchised public utility with captive customers and its market-regulated power sales affiliate to share senior officers and members of the board of directors. Specifically, a franchised public utility with captive customers and its market-regulated power sales affiliate may share senior officers and members of boards of directors provided that these individuals do not participate in directing, operating or executing generation or market functions.[582] In addition, to prevent permissibly shared senior officers or members of the board of directors from using their preferential access to market information to harm captive customers, consistent with the no-conduit rule codified at § 35.39(g), the permissibly shared senior officers and directors may not act as a conduit to provide market information to non-shared employees of the franchised public utility with captive customers or its market-regulated power sales affiliates.

563. The Commission also agrees that it is appropriate to codify an exception that permits the sharing of support employees between the franchised public utility with captive customers and its market-regulated power sales affiliates comparable to the standards of conduct exception, likewise subject to the no-conduit rule.[583]

564. The Commission rejects Duke's request that the Commission include a non-exhaustive list of examples of permissible shared support employees within the body of § 35.39. However, we clarify that the types of permissibly shared support employees under the standards of conduct are the types of permissibly shared support employees that will be allowed under the affiliate restrictions in § 35.39(c)(2)(c). Such employees include those in legal, accounting, human resources, travel and information technology.[584] Because permissibly shared employees may have access to market information, they are Start Printed Page 39971prohibited from acting as a conduit to provide market information to employees of the franchised public utility with captive customers and the market-regulated power sales affiliates that are not permitted to be shared.

565. The Commission also agrees to codify an exception to the independent functioning requirement to allow franchised public utilities with captive customers and their market-regulated power sales affiliates to share field and maintenance employees. Field and maintenance employees perform purely manual, technical or mechanical duties that are supportive in nature and do not have planning or direct operational responsibilities. Such employees would likely be part of shared work crews to do repair or maintenance work on facilities or equipment. Examples of activities that may be performed by shared field and maintenance employees are reading meters, replacing parts in generators, restringing transmission lines, snow removal or maintaining roadways. The key is that these employees do not also perform operational duties.[585] A field or maintenance employee cannot be shared if that employee also engages in marketing activities, makes decisions that would affect marketing activities, or controls generation. We also consider the immediate supervisors of field and maintenance employees as permissibly shared employees so long as they cannot control operations, e.g. restrict or shut down generation facilities.[586]

566. The Commission agrees with commenters that allowing the sharing of field and maintenance employees between a franchised public utility with captive customers and its market-regulated power sales affiliates is unlikely to harm captive customers, provided that those shared employees do not act as a conduit for sharing market information with employees of the franchised public utility with captive customers or market-regulated power sales affiliates. The permissibly shared field and maintenance employees are required to observe the no-conduit rule.

567. The Commission disagrees with NiSource that a broad exception to the independent functioning and information sharing requirement is needed for the reliable operation of the bulk power system. Such an exception would be so broad that it would swallow the rule and create too many opportunities for shared employees to take actions to harm captive customers based upon their decision making authority and control over the bulk power system. The Commission will consider requests for waiver of the affiliate restriction requirements to address the specific circumstances of the operation of a bulk power system and notes that, subsequent to NiSource's comments, the Commission granted a partial waiver of the code of conduct requirements for the situation described in NiSource's comments.[587]

568. While the Commission does not agree with NiSource's proposal for a broad exception to the affiliate restrictions for everyday operations of the bulk power system, the Commission does agree with EEI and FirstEnergy that the affiliate restrictions should contain an exception related to emergency circumstances affecting system reliability. As such, the Commission will adopt an exception to the independent functioning requirement and the information sharing restrictions for emergency circumstances affecting system reliability comparable to the exception in the standards of conduct.[588] The exception will apply to both the independent functioning requirements and the information sharing restrictions. The Commission will modify proposed § 35.39(d) (to be codified at § 35.39(c)(2)(b)) to add a provision that states that, notwithstanding any other restrictions in this section, in emergency circumstances affecting system reliability, a market-regulated power sales affiliate and the franchised public utility with captive customers may take the necessary steps to keep the bulk power system in operation. The relaxation of the requirements during system emergencies is intended to ensure that the franchised public utility with captive customers and market-regulated power sales affiliate(s) can maintain reliability of the power grid. However, the market-regulated power sales affiliate or the franchised public utility must report to the Commission and disclose to the public on its Web site each emergency that resulted in any deviation from the restrictions of § 35.39(c)(2)(b), within 24 hours of such deviation. Reports to the Commission of emergency deviations under the affiliate restrictions in § 35.39(c)(2)(b) will be made using the “EY” docket prefix.

569. The Commission and the public will be able to monitor the frequency of these emergency deviations through the reporting requirement. Members of the public can seek redress from the Commission if they feel that the exception has been abused or used improperly.

c. Information Sharing Restrictions

Commission Proposal

570. In the NOPR, the Commission proposed regulatory language to codify the information sharing restrictions. Specifically, the Commission proposed that the regulations provide that all market information sharing between a franchised public utility and a non-regulated power sales affiliate will be disclosed simultaneously to the public. This includes, but is not limited to any communication concerning power or transmission business, present or future, positive or negative, concrete or potential.[589]

Comments

571. Ameren supports codification of the information sharing restrictions, but recommends that proposed § 35.39(c) be revised to allow permissibly shared senior officers and directors to receive market information so long as they do not act as a conduit to improperly share such information, akin to the standards of conduct.

572. Avista argues that the Commission should allow officers to be shared by affiliates, subject to the no-conduit rule.[590] EEI argues that for corporate governance and accountability purposes, there should be an exception to the information sharing prohibitions for shared senior officers, subject to the no conduit rule.[591]

573. EPSA also asks the Commission to provide a specific time period for the length of time that posted information needs to remain on the Web site.[592]

574. PPL comments that the Commission should clarify which situations would permit deviations from the code of conduct regarding Start Printed Page 39972information sharing. Specifically, it suggests that the Commission adopt, for the affiliate restrictions, the standards of conduct exception that permits the sharing of information to comply with Nuclear Regulatory Commission (NRC) requirements.[593]

575. A number of commenters argue that the Commission should not adopt the two-way information sharing prohibition in the uniform code of conduct because they disagree that a communication from the non-regulated power sales affiliate to the franchised public utility could potentially harm captive customers.[594]

576. Duke notes that while the two-way restriction is consistent with the default code of conduct that the Commission has used since 1999, the Commission has approved many codes of conduct that contain one-way restrictions (i.e., codes that restrict a franchised public utility from sharing marketing information with its non-regulated power sales affiliates, but do not place a similar restriction on a non-regulated power marketer from sharing market information with its affiliated franchised utility). Duke says the Commission has failed to explain the elimination of previously-approved one-way restrictions.[595] It submits that the one-way code of conduct is sufficient to address affiliate abuse concerns and that the two-way code of conduct requirement will impose substantial costs on market-based rate sellers with no discernible benefits.[596] According to Duke, a number of market participants have made important organizational and commercial decisions based on current policies and precedents allowing one-way communications. In the absence of any basis for reversing that policy, Duke submits that the Commission should reconsider its proposal to mandate two-way information sharing restrictions.

577. In addition, Duke argues that only two commenters, EPSA and ELCON, expressed even generalized support for a standardized code of conduct containing the two-way code restriction, but did not address the underlying policy issues of why or how a traditional utility's regulated customers could be harmed if their unregulated affiliate were to share market information with the utility.[597]

578. According to FP&L, the proposed two-way information sharing restriction does not provide any additional protection for captive customers. Rather, such a restriction may place artificial and unnecessary barriers on a company's ability to conduct business.[598] According to FP&L, the two-way restriction proposed in § 35.39(c) (to be codified at § 35.39(d)) concerning the communication of all market information between a franchised public utility and its non-regulated power sales affiliates is unnecessary if sales of capacity and energy between those entities are prohibited under the specific terms of the market-based rate tariff. It submits that, if the Commission nevertheless concludes that a two-way restriction on communications should be adopted, then the final regulations should provide an exception if, in the market-based rate tariff, the non-regulated power sales affiliates have restricted sales to, and purchases from, their franchised public utility affiliate without having received advance Commission approval pursuant to a separate filing under section 205 of the FPA.[599]

579. Similarly, EEI argues that the Commission has not explained how the two-way information sharing prohibition protects captive customers.[600]

Commission Determination

580. The Commission will revise the information sharing prohibitions to adopt certain exceptions. As discussed earlier with regard to the independent functioning requirement, we are creating exceptions to permit shared senior officers and members of a board of directors, as well as to permit shared field and maintenance employees. Permissibly shared employees may share all types of market information. However, the information sharing provision, like all the affiliate restrictions, is subject to the “no-conduit” rule that we codify in the regulations. The no-conduit rule allows permissibly shared employees to receive market information so long as they are not conduits for sharing that information with employees that are not permissibly shared. In addition, as also discussed earlier in the independent functioning section, market information may be shared to address emergency circumstances affecting system reliability in order to keep the bulk power system in operation, provided that the subsequent reporting provisions are followed.

581. In response to PPL Companies' concern as to communications relating to nuclear power plants, the Commission clarifies that the types of communications permitted under the standards of conduct for nuclear safety and regulatory requirements are also permitted under the affiliate restrictions.[601] Specifically, the Commission permitted transmission providers to communicate with affiliated and nonaffiliated nuclear power plants to enable the nuclear power plants to comply with the requirements of the NRC as described in the NRC's February 1, 2006 Generic Letter 2006-002, Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power.[602]

582. In response to EPSA's request regarding the specific time period that posted material needs to remain on the Web site, the Commission concludes that it is appropriate to use the requirements set forth regarding OASIS postings in 18 CFR 37.7(b). Specifically, the material must be posted for 90 days and then be retained and made available upon request for download for five years from the date when first posted. The archived material must be available in the same electronic form used as when it was originally posted.

583. The Commission will adopt the two-way information sharing restriction in proposed § 35.39(c) (now § 35.39(d)). The purpose of the affiliate restrictions in § 35.39 is to ensure that franchised public utility sellers with captive customers will not be able to engage in affiliate abuse to the detriment of those captive customers. One way the Commission achieves this is by restricting the sharing of information between a franchised public utility with captive customers and a market-regulated power sales affiliate. The Commission has long required a seller Start Printed Page 39973to address any potential affiliate abuse concerns before receiving Commission authorization to sell at market-based rates. The Commission has previously held that “[t]here are many ways for the affiliated public utility and the affiliated power marketer to exchange information that would exacerbate affiliate abuse concerns.” [603] Therefore, the Commission required that the sellers “ensure that market information is not shared among affiliates.” [604]

584. The Commission later reaffirmed this in stating the general standards under which it reviews applications for market-based rate authority, including a demonstration by an affiliate that “there are adequate procedures in place to ensure that market information is not shared between it and the affiliate public utility.” [605]

585. With regard to Duke's suggestion that we have failed to explain the elimination of the one-way restriction, we will provide the following example of our concern in this regard.

586. One example of how of improper sharing of information could harm captive customers is a circumstance where both a franchised public utility and its market-regulated power sales affiliate are considering whether to bid into an RFP to provide power. If the market-regulated power sales affiliate has absolute freedom to inform its franchised public utility affiliate that it intends to bid into the RFP, including but not limited to the price and quantity it intends to offer, the franchised public utility affiliate has the ability and incentive to use that information to benefit its stockholders at the expense of its captive customers (e.g., by either not bidding into the RFP or doing so at a price above that of its affiliate).

587. While we recognize that some sellers may need to adjust their activities to comply with the two-way information restriction, we do not believe that such adjustments will impose significant costs upon those sellers. Furthermore, as explained above, we believe that the two-way information sharing restriction will provide captive customers a more complete protection from affiliate abuse. We find that any potential cost to sellers is outweighed by the increased protection a two-way information sharing restriction provides to captive customers.

588. Therefore, to ensure that all captive customers are protected from the potential for affiliate abuse, the Commission will adopt the proposed two-way information restriction in § 35.39(d). Any sellers whose activities are currently governed by a code of conduct with a one-way information restriction will be deemed to have adopted a two-way information restriction as of the effective date of this Final Rule.

589. The Commission restates that the affiliate restrictions only apply when captive customers exist; therefore, if the Commission has found that there are no captive customers, then, consistent with § 35.39(b) through (g), the affiliate restrictions, including the prohibition on information sharing, will not apply.

d. Definition of “Market Information”

Comments

590. Progress Energy urges the Commission to clarify the definition of the term “market information” which it argues is arbitrarily broad and may include public as well as non-public market information.[606] SoCal Edison states that the Commission should only prohibit the sharing of non-public market information among a utility and its market-regulated power sales affiliates, as outlined in the standards of conduct.[607] EPSA also asserts that the Commission should clarify that the simultaneous posting requirement should apply to the communication of all non-public market information (not all market information). It notes that Order No. 2004 specifically applies to non-public transmission information, not all transmission information.

Commission Determination

591. The Commission previously explained that “market information” includes information on sales or purchases that will not be made (as well as purchases and sales that will be made), as well as any information concerning a utility's power or transmission business—broker-related or not, past, present or future, positive or negative, concrete or potential, significant or slight.[608] In an effort to provide additional clarity and regulatory certainty, we will provide further guidance and adopt and codify in § 35.36(a)(8) the following definition of market information: “market information means non-public information related to the electric energy and power business including, but not limited to, information regarding sales, cost of production, generator outages, generator heat rates, unconsummated transactions, or historical generator volumes. Market information includes information from either affiliates or non-affiliates.”

592. The Commission clarifies that the definition does not prohibit the disclosure of publicly available information. We find that, because of its very nature of being publicly available to all entities, restrictions on sharing publicly available information are unnecessary. In addition, the definition does not prohibit the sharing of transmission information. The standards of conduct already prevent improper disclosures of non-public transmission information by a transmission provider to its marketing and energy affiliates, which would include both the franchised public utility with captive customers and the market-regulated power sales affiliate.[609]

593. Further, as we have indicated, a principal purpose of the affiliate restrictions is to ensure that the interaction between a franchised public utility and its market-regulated affiliate does not result in harm to the franchised public utility's captive customers. Therefore, we clarify that, as a general matter, the definition of “market information” includes information that, if shared between a franchised public utility and a market-regulated affiliate, may result in a detriment to the franchised public utility's captive customers. Therefore, market information includes, but is not limited to, information concerning sales and purchases that will not be made such as in circumstances where parties have discussed a potential contract but no agreement has been reached. In contrast, market information does not include information that would not result in an advantage to the recipient that could be used to the detriment of the franchised public utility's captive customers. For example, a franchised public utility with captive customers and its market-regulated power sales affiliate may share information related to the relocation of the franchised public utility's headquarters, business opportunities outside the United States, general turbine safety information and internal procedures for general maintenance activities (other than scheduling). We clarify that the definition of “market information” includes, but is not limited to, written, printed, verbal, audiovisual, or graphic information.

594. We are adding language to the information sharing restriction of § 35.39(d)(1) to make clear that disclosures of market information are Start Printed Page 39974prohibited, unless simultaneously disclosed to the public, if the information could be used to the detriment of captive customers. For example, if a franchised public utility with captive customers conducts negotiations with an unaffiliated generator to acquire power, but does not reach an agreement, the franchised public utility with captive customers is prohibited from sharing with its market-regulated power sales affiliate any non-public information it acquired through the unsuccessful negotiations unless such information is simultaneously disclosed to the public. Information relating to any other entities' electric energy or power business is also subject to the sharing of market information restriction if such information could be used to the detriment of captive customers. Also subject to the information sharing restriction is information regarding brokering activities, past sales and purchase activities, and the availability or price of inputs to generation such as natural gas supply if such information could be used to the detriment of captive customers. For example, a franchised public utility with captive customers is restricted from disclosing to its market-regulated power sales affiliate any non-public information about a non-affiliated generator's upcoming maintenance or outage schedules or information about the non-affiliated generator's historical generation volumes, unless such information is simultaneously disclosed to the public. In addition, neither the franchised public utility with captive customers nor its market-regulated power sales affiliate may tell the other that it intends to sell power to a third party, including but not limited to the price and quantity it intends to offer, unless such information is simultaneously disclosed to the public. Similarly, a market-regulated power sales affiliate is likewise restricted from telling its franchised public utility affiliate with captive customers about any other business opportunity that it is considering or is undertaking, unless such information is simultaneously disclosed to the public.

e. Sales of Non-Power Goods or Services

Commission Proposal

595. In the NOPR, the Commission proposed regulatory language to codify the requirements governing sales of non-power goods or services. The Commission proposed that sales of any non-power goods or services by a franchised public utility to a market-regulated power sales affiliates will be at the higher of cost or market price, and that sales of any non-power goods or services by a market-regulated power sales affiliate to an affiliated franchised public utility will not be at a price above market.

Comments

596. PG&E argues that, while charging the high of cost or market price may be appropriate for sales of goods, it is “inoperable and inappropriate” for sales of services because market prices for sales of service by a third party may be hard to ascertain due to limited providers and that prices from a third party provider will not take into account efficiencies resulting from a utility and its affiliate sharing services.[610] PG&E further comments that charging the higher of cost or market, as proposed, may increase costs for both the utility and the affiliate by discouraging the efficient sharing of services. Therefore, PG&E proposes that instead of charging the higher of cost or market price for non-power services, the Commission should allow a proxy for the market price such as the fully-loaded cost plus a reasonable profit, e.g., five percent.[611]

Commission Determination

597. The Commission will adopt the NOPR proposal to codify the requirement that sales of non-power goods and services by a franchised public utility with captive customers to a market-regulated power sales affiliate be at the higher of cost or market price, unless otherwise authorized by the Commission. This requirement, along with other requirements in the affiliate restrictions, protect a franchised public utility's captive customers against inappropriate cross-subsidization of market-regulated power sales affiliates by ensuring that the utility with captive customers does not recover too little for goods and services that the utility provides to a market-regulated power sales affiliate.[612] We also adopt the NOPR proposal to codify the requirement that sales of any non-power goods or services by a market-regulated power sales affiliate to an affiliated franchised public utility with captive customers will not be at a price above market, unless otherwise authorized by the Commission. This requirement protects a utility's captive customers against inappropriate cross-subsidization of market-regulated power sales affiliates by ensuring that the utility with captive customers does not pay too much for goods and services that the utility receives from a market-regulated power sales affiliate.

598. We note that PG&E fails to provide the Commission with any specific examples of non-power services for which there is no corresponding third-party provider. Therefore, we are not persuaded by PG&E that there is a need or a benefit to changing our precedent on this issue. We will adopt the affiliate restrictions as proposed and require that sales of non-power goods or services by a franchised public utility with captive customers to a market-regulated power sales affiliate be at the higher of cost or market price. Nevertheless, we will address on a case-by-case basis arguments that charging the higher of cost or market for certain sales of non-power services may not be appropriate in a particular case.

f. Service Companies or Parent Companies Acting on Behalf of and for the Benefit of a Franchised Public Utility

Commission Proposal

599. The Commission proposed in the NOPR to treat companies that are acting on behalf of and for the benefit of franchised public utilities with captive customers, for purposes of the affiliate provisions, as that franchised public utility. Likewise, in the case of non-regulated affiliates, the proposed affiliate provisions treat companies that are acting on behalf of and for the benefit of non-regulated affiliates, for purposes of the affiliate provisions, as the non-regulated affiliates.[613]

Comments

600. EEI asks the Commission to clarify that the code of conduct (affiliate restrictions) provisions to be codified in the regulations do not preclude the use of service companies that manage assets for both regulated and unregulated affiliates.[614] EEI submits that the language of proposed § 35.39(b) (now § 35.39(c)) uses “entities acting on behalf of and for the benefit of a franchised pubic utility (such as entities managing the electric generation assets of the franchised public utility)” whereas the NOPR text reads “entities acting on behalf of and for the benefit of a franchised public utility (such as service companies and entities managing the generation assets of the franchised pubic utility).” EEI argues that the treatment of service companies as part of the franchised public utility in the preamble to the NOPR is different from the language in the proposed Start Printed Page 39975regulation and makes the Commission's intent unclear. It submits that many companies use service companies to provide support activities to the franchised utility and non-regulated affiliates consistent with the no-conduit rule. EEI asks the Commission to clarify that the standardization of the code of conduct is not intended to change this practice. PG&E claims that under a plain reading of the proposed regulation, a parent company that acts on behalf of either the utility or the affiliate will be considered a part of the utility or affiliate, and communication with either entity will be restricted under proposed § 35.39(c) (now § 35.39(d)).[615] It argues that the Commission should only consider a holding company or parent company as an affiliate subject to the information sharing prohibitions if it engages in energy transactions on its own behalf.[616]

601. Southern states that it is unclear how the Commission intends to address and apply the requirements of separation of functions and information sharing in the context of public utility holding companies that have system pooling agreements.[617] Southern recommends the Commission refine the definition of “non-regulated power sales affiliate” at least insofar as that term is used in the proposed separation of functions and information sharing provisions to exclude pooled system affiliates of traditional franchised utilities where affiliate interactions and sharing of benefits and burdens of pooled operations are addressed under an arrangement filed and approved under section 205.[618]

602. EEI requests that the Commission clarify that, in circumstances where sales between affiliates have been made in connection with an approved system agreement, such agreements continue to govern.[619] Southern requests that the Final Rule clarify that affiliated operating companies may continue to operate on a pooled basis.[620] Southern states that traditional centralized service company affiliates providing system pooling support services under filed and approved system agreements should not be treated as non-regulated power sales affiliates.[621]

Commission Determination

603. The Commission clarifies that it did not intend to include service companies as “entities acting on behalf of and for the benefit of a franchised public utility” for purposes of the separation of functions provision in § 35.39(b) (now § 35.39(c)) to the extent that such service companies do not engage in generation or marketing activities.[622] Although service companies not engaged in generation or marketing activities are not included in the coverage of § 35.39(e), they may not act as a conduit for providing non-public market information between a franchised public utility and a market-regulated power sales affiliate. However, unless otherwise permitted by Commission rule or order, service companies cannot be used to direct, organize or execute generation or marketing activities for both the franchised public utility and the market-regulated power sales affiliate(s). In response to Southern's and EEI's request to clarify that affiliated operating companies may continue to operate as a pool or pursuant to an approved system agreement, nothing in this Final Rule precludes pool operation pursuant to filed tariffs or agreements approved by the Commission and nothing in this rule changes filed system agreements approved by the Commission. To the extent that individual companies enter into new pooling or system agreements, the Commission will continue to review those agreements on a case-by-case basis to ensure that, among other things, affiliate transactions meet the requirements of section 205 of the FPA and otherwise satisfy our affiliate abuse concerns.

D. Mitigation

604. In the NOPR, the Commission sought comment on whether the default mitigation adopted in the April 14 Order is appropriate as currently structured. The Commission's current default mitigation rates are as follows: (1) Sales of power of one week or less will 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 (sometimes referred to as “mid-term sales”) will 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 will be priced at a rate not to exceed the embedded cost of service, and the contract will be filed with the Commission for review and approved prior to the commencement of service.[623]

605. In the NOPR, the Commission sought comment on the following four issues that have arisen in implementing cost-based mitigation: (i) The rate methodology for designing cost-based mitigation; (ii) discounting; (iii) protecting customers in mitigated markets; and (iv) sales by mitigated sellers that “sink” in unmitigated markets.

1. Cost-Based Rate Methodology

a. Sales of One Week or Less

Commission Proposal

606. The Commission noted that two principal issues concerning rate methodology have arisen in implementing the April 14 Order. The first relates to power sales of one week or less being made at incremental cost plus 10 percent.[624] The Commission noted that sellers have argued that this is a departure from the Commission's historical acceptance of “up to” rates for short-term energy sales, including sales of one week or less, and sought comment on whether to continue to apply a default rate for such sales that is tied to incremental cost plus 10 percent. The Commission sought comment as to: (i) Whether there are problems associated with using “up to” rates for shorter-term sales and, if so, what are they; (ii) whether the current approach provides utilities a disincentive to offer their power to wholesale customers in their local control area for short-term sales; and (iii) whether an “up to” rate adequately mitigates market power for such sales.

Start Printed Page 39976

Comments

607. While not opposing the default rate, APPA/TAPS state that as an alternative, sales of one week or less could occur under the traditional “split the savings” methodology.[625] APPA/TAPS submit that both of these methods are consistent with the Commission's observation that “[a]bsent market power, a generator would typically run if it had excess power and could cover its incremental costs plus some return.” [626]

608. While the Carolina Agencies claim that sales of one week or less should not carry a capacity charge, they concede that a reasonable contribution to the mitigated supplier's fixed costs may be appropriate (e.g., by including a modest adder over the supplier's incremental cost of energy).[627]

609. NRECA and AARP ask the Commission to retain the incremental cost plus 10 percent methodology for mitigating sales of one week or less.[628] NRECA expresses a concern that the Commission's default cost-based rates (for all three products—sales of one week or less; sales of more than one week but less than one year; and sales of one year or longer) may be subject to gaming by larger public utilities, especially because the sellers hold all of the critical data. It asserts that if sellers have too much leeway in choosing which units they will use to calculate their incremental or embedded costs, the default cost-based rates will not provide an effective rate ceiling, and the purpose of the default mitigation will be undermined. NRECA proposes that the Commission require sellers subject to default cost-based rates to submit both pre- and post-approval filings supporting the mitigated cost-based rates for short- and mid-term sales. NRECA suggests that the seller justify its mitigated rates beforehand by demonstrating its incremental costs or embedded costs, as appropriate, and then file after-the-fact quarterly reports of the actual sales and the actual incremental or embedded costs incurred in making these sales.[629] NRECA suggests that this approach would subject mitigated cost-based rate sales to a cost-based formula rate, and therefore to refund, upon Commission review of the quarterly compliance filing.[630]

610. NASUCA urges the Commission to require that all mitigated rates, and any rate discounts, whether for more or less than one year in duration, must be filed and made subject to public scrutiny and Commission review under section 205 of the FPA.[631] NASUCA is concerned that under the NOPR, only rates to be in effect for more than one year are required to be filed publicly in advance and subject to protest, intervention, prior Commission review and revision. It argues, however, that section 205 contains no exception from the filing requirement for sales of less than one year.[632] Given that all new rate schedules and contracts affecting rates must be publicly filed, NASUCA asks the Commission not to reduce section 205's procedural safeguards for sales of less than one year at cost-based rates (i.e., by not requiring that they be subject to prior notice and review).[633]

611. Some commenters oppose the incremental cost plus 10 percent default rate, with several alleging that it deviates from prior Commission precedent without sufficient justification and fails to adequately compensate sellers.[634] Some commenters also allege that such an approach will deter new entry and gives sellers the incentive to sell outside the mitigated market.

612. For example, Westar states that the Commission's reasoning in the July 8 Order which explained that the cost plus 10 percent default rate represents a “conservative proxy for a reasonable margin available in a competitive market,” [635] suffers from two fatal flaws. First, the Commission failed to distinguish or even mention Terra Comfort wherein, Westar and Duke submit, the Commission found that 10 percent adders provide no contribution to fixed costs, and it rejected the argument that “utilities routinely forego these margins and sell at 110 percent of incremental cost.” [636] Second, according to Westar, in adopting this default rate the Commission relied heavily upon an order that applied the formula in an RTO under entirely different circumstances.[637]

613. MidAmerican and Westar note that, in support of the default rate, in the April 14 Order the Commission cited a PJM tariff provision pursuant to which generators dispatched out of economic merit have their bids mitigated to incremental costs plus 10 percent to prevent them from exercising market power and, at the same time, providing revenues which include a margin.[638] MidAmerican and Westar contend that this is merely an example of a mitigation mechanism, not a rationale for a broad-scale default mitigation scheme that ignores years of precedent.[639] They submit that the PJM tariff mitigates bids for a select set of generators. They state that, regardless of the level of their bids, those generators are still paid the market clearing price because only the offer is capped. Further, because PJM's methodology applied this offer cap only to a limited number of hours, MidAmerican and Westar state that sellers were also free to bid above the cap in the majority of the hours of the year.[640] In contrast, MidAmerican and Westar claim that the incremental cost plus 10 percent default rate is an absolute cap on revenues that would apply to all sales of one week or less in length.[641]

614. Although the July 8 Order explained that incremental cost plus 10 percent was a backstop, default rate, and that entities were free to propose alternative mitigation schemes, MidAmerican asserts that this ignores the fact that the Commission has routinely accepted alternative cost-based rates for sales of one week or less. As such, MidAmerican maintains that there is no reason why “split the savings” rates, or rates reflecting a demand charge, could not be used as a default rate for mitigated sales of one week or less.[642]

615. Several commenters also argue that the energy-only incremental cost plus 10 percent methodology does not allow for proper recovery of capacity-based costs on sales of one week or less thereby artificially depressing the prices of these short-term sales and possibly deterring new entry.[643] These commenters state that sellers should be Start Printed Page 39977allowed to recover a contribution to their fixed/capacity costs.

616. Some commenters contend that the default cost-based rates create an incentive to sell outside the mitigated market because they recover less than cost-based rates historically accepted that included a demand charge. However, they assert that setting rates that require buyers to make a reasonable contribution to the seller's fixed costs for the use of the capacity would create an incentive for the seller to make sales within its mitigated control area.[644] Duke and the Oregon Commission add that allowing recovery of capacity-based costs also ensures that wholesale customers bear their fair share of system costs.[645]

617. Several commenters also claim that by artificially depressing short-term sales prices, the default rate transfers wealth from the supplier's retail customers to wholesale customers.[646] Such retail customers, these commenters state, have paid the fully-allocated costs of the system and obtain revenue credits to their costs from the supplier's short-term sales. Where short-term sales are made on a non-interruptible basis, and the incremental cost plus 10 percent rate prices them only at incremental running cost, Progress Energy contends that wholesale purchasers are receiving the benefits of capacity without cost.[647] Progress Energy and EEI submit that retail native load customers, as a result, lose the economic benefits that would otherwise accrue to them through revenue credits from short-term wholesale sales.[648] Wholesale customers charged through an embedded cost-of-service are also harmed, Progress Energy adds, because they lose the economic benefits that would otherwise accrue to them through revenue credits from short-term wholesale sales.[649]

618. Progress Energy and Duke instead favor an “up to” cost-based default rate for sales of one week or less.[650] For such sales, Progress Energy supports an “up to” rate design flexible enough to allow rates as low as the mitigated seller's incremental costs and as high as 100 percent of the seller's capacity and energy costs. According to Progress Energy, a mitigated seller could choose to make sales as low as its incremental cost when either (1) The unmitigated market price of competing sellers dictates that price, or (2) the mitigated seller needs to sell its excess generation at that price to maintain a minimum generation control margin. Given that there is a short-term market for capacity, Progress Energy asks that the default cost-based rates include a price structure that allows pricing of capacity-only sales.[651]

619. Xcel suggests that the Commission should allow for an even higher emergency price in situations where purchasers need to make a purchase not simply to achieve economic benefits but where the purchaser is capacity deficient. Xcel submits that in such instances, a purchaser plainly obtains a capacity benefit from the purchase of such power. Historically, the Commission has allowed an emergency rate of $100 per MWh for emergency service. Given that gas prices have dramatically increased since that standard rate began to be utilized, Xcel claims that an emergency rate of the higher of cost plus 10 percent or $1,000 per MWh would be appropriate in the present environment.[652]

Commission Determination

620. The Commission will retain the incremental cost plus 10 percent methodology as the default mitigation for sales of one week or less, while continuing to allow sellers to propose alternative cost-based methods of mitigation tailored to their particular circumstances. As discussed more fully below, we clarify that in retaining the incremental cost plus 10 percent methodology as the default mitigation for sales of one week or less we do not otherwise limit a seller's ability to propose different cost-based rates for sales of one week or less.[653]

621. Although a number of commenters suggest that the Commission should adopt a different default cost-based ratemaking methodology for sales of one week or less, they have failed to persuade us that the existing default rate is inappropriate. As the Commission has previously stated, an incremental cost rate that allows a fair recovery of the incremental cost of generating with a 10 percent adder to provide for a margin over incremental cost is reasonable.[654] Incremental costs plus 10 percent represents a conservative proxy for a reasonable rate available in a competitive market.[655] On this basis, we find incremental cost plus 10 percent to be an appropriate default rate. Moreover, we allow sellers the opportunity to design, support, and propose other cost-based rates that they believe are more appropriate for their particular circumstances.

622. Several commenters note that the Commission has permitted various cost-based rate methodologies prior to the April 14 Order, including a split-the-savings formula. These entities express concern that the use of the incremental cost plus 10 percent methodology as the default mitigation rate for sales of one week or less forecloses the possibility of other cost-based pricing methodologies. However, this is not the case. Rather than precluding alternative mitigation proposals, the April 14 Order allows sellers to propose case-specific tailored mitigation, or adopt the default cost-based rate. The April 14 Order described the default mitigation rate as “a backstop measure” intended to ensure a just and reasonable rate.[656] The Commission re-emphasized this in its July 8 Order explaining: “In the instant case, the 10 percent adder is to be used only as a backstop or default measure in the event that an applicant does not opt to propose its own mitigation.” [657]

623. As such, the incremental cost plus 10 percent rate represents a default, cost-based rate to protect customers from the potential exercise of market power and provide sellers regulatory rate certainty by establishing a “safe harbor.” Any proposal for alternative cost-based rates will be considered on a case-by-case basis.

624. Further, with regard to including capacity charges in rates for one week or less, a seller may propose to recover such charges and the Commission will consider these charges based on the specific facts and circumstances presented. Rather than ignoring alternative forms of cost-based rates, as some commenters claim, the Commission's policy offers sellers the opportunity to propose such alternatives.

625. Use of the default rate as set forth in the April 14 and July 8 Orders also is not inconsistent with Terra Comfort, as some commenters claim. As explained above, contrary to some commenters' allegations, the Commission does not confine mitigated sellers to rates that forego a contribution to fixed/capacity costs. In Terra Comfort, the Commission explained that Start Printed Page 39978“most utilities maintain on file for all services flexible demand charge ceilings designed to reflect a 100-percent contribution to the fixed costs of their facilities.” [658] The Commission then added that utilities are not obligated to “forego these margins and sell at 110 percent of incremental costs.” [659] In the April 14 Order, the Commission, consistent with its holding in Terra Comfort, explained that “as a backstop measure, we will also provide ‘default' rates to ensure that wholesale rates do not go into effect, or remain in effect, without assurance that they are just and reasonable.” [660] Contrary to Duke's assertion that this default rate suggests that sellers do not have economic justification (or need) to recover a share of their fixed/capacity costs in the prices charged for such transactions,[661] the Commission's policy allows “applicants to propose case-specific mitigation tailored to their particular circumstances that eliminates the ability to exercise market power, or adopt cost-based rates such as the default rates herein.” [662] The Commission explained in the April 14 Order that “[p]roposals for alternative mitigation in these circumstances could include cost-based rates or other mitigation that the Commission may deem appropriate.” [663] Consistent with industry practice and Commission precedent, therefore, where mitigated sellers can properly justify such contributions, they may propose to recover contributions to fixed/capacity costs under the Commission's mitigation policy.

626. Such alternative mitigation has been proposed and accepted. For example, Progress Energy correctly notes that one of its subsidiaries proposed as mitigation—and the Commission approved—a cost-based “up-to” capacity charge and a cost-based energy charge for the subsidiary's power sales of less than one year, including sales of one week or less, in the mitigated control area.[664] Progress Energy is correct in observing that this decision was consistent with the Commission's long-standing policy of permitting the pricing of short-term sales at cost-based “up-to” capacity charges and cost-based energy charges.[665] Rather than artificially depressing the prices of short-term sales, exacting a wealth transfer, or limiting a seller's ability to respond to market conditions, as Progress suggests, the default cost-based rate for sales of one week or less provides a backstop measure intended to protect customers by ensuring that, in the event a seller loses or relinquishes its market-based rate authority, there is a readily available cost-based rate under which such sellers may choose to transact, and the mitigated seller by establishing a refund floor that provides it with rate certainty.

627. As to some commenters' suggestion that the incremental cost plus 10 percent methodology, and cost-based rates in general, adversely affect retail rates because they exact a wealth transfer from the supplier's retail customers to wholesale customers, the July 8 Order rejected such claims on the ground that they were “unsupported and speculative.” [666] Not only do these claims remain unsupported but they suggest that the Commission should allow wholesale rates in excess of a just and reasonable rate. This result would not be just and reasonable. As the Commission stated in the July 8 Order, “our rate making policy is designed to provide for recovery of prudently incurred costs plus a reasonable return on investment.” [667] Moreover, the Commission explained that “the opportunity for the applicants to propose alternative, tailored mitigation measures should allow adequate consideration of the effect on investment and customers.” [668]

628. We will not adopt Progress Energy's request that the default rate be modified to include a price structure allowing pricing of capacity-only sales. Progress Energy fails to provide adequate justification to provide for such a rate in our default cost-based rates. For example, Progress Energy states that there is a short-term market for capacity-only sales but fails to explain how this market is a power sales market (for which our default cost-based rates apply) rather than an ancillary services market which is not contemplated in the default cost-based power sales rates. Nevertheless, as noted above, a mitigated seller has the opportunity to propose and justify an alternative to the default rate.

629. Similarly, in response to NASUCA's request that the Commission require all mitigated rates and discounts to be filed under section 205 of the FPA, we note that all mitigation proposals must be filed with the Commission for review. These filings are noticed and interested parties are given an opportunity to intervene, comment, or protest the submittal. With regard to discounts, as we explain in the discounting section of this Final Rule, discounts made to customers, like all other rates, are required to be reported in the seller's EQRs.

630. We also note that the Commission stated in the April 14 Order that where a seller proposes to adopt the default cost-based rates (or where it proposes other cost-based rates), it must provide cost support for such rates.[669] The Commission will examine the proposed rates on a case-by-case basis. With regard to sales of one week or less, where the seller fails to provide sufficient cost support, the Commission will direct the seller to submit a compliance filing to provide the formulas and methodology according to which it intends to calculate incremental costs.[670] We note here that, to the extent a seller proposes a cost-based rate formula, we will require the rate formula used be provided for Commission review and such formula included in the cost-based rate tariff including formulas used in calculating incremental cost.

631. The Commission also has set proposed default cost-based rates for hearing when appropriate.[671] We believe that this case-by-case review of proposed default cost-based rates adequately addresses NRECA's and Suez/Chevron's concerns. Moreover, to the extent that an entity contends that a mitigated seller is flowing inappropriate costs through its formula rate, section 206 of the FPA provides a process for filing a complaint.

b. Sales of More Than One Week But Less Than One Year

Commission Proposal

632. In the NOPR, the Commission sought comment on issues related to the design of an “up to” cost-based rate. The Commission noted in the NOPR Start Printed Page 39979that it has allowed significant flexibility in designing “up to” rates in the past, and invited comments on whether such flexibility is still warranted. In particular, the Commission noted that there are often disputes over which units are “most likely to participate” or “could participate” in coordinated sales, and asked if it should continue to allow utilities flexibility in selecting the particular units that form the basis of the “up to” rate. If not, the Commission asked which units should form the basis of an “up to” rate, and how such a rate should be calculated. In addition, parties were invited to comment on whether a standard rate methodology should be prescribed that would allow a seller to avoid a hearing on this issue. The Commission asked whether a methodology that is based on average costs (both variable and embedded) would allow a seller to avoid a hearing because it eliminates the seller's discretion in designating particular units as “likely to participate.” The Commission also inquired as to whether there are other approaches that would accomplish a similar objective.

Comments

i. Selecting the Particular Units That Form the Basis of the “Up to” Rate

633. Regarding whether the Commission should continue to allow utilities flexibility in selecting the particular units that form the basis of the “up to” rate, EEI argues for flexibility because selection of generating units for these short-terms sales is made with the goal of minimizing the cost-of-service to the utility's native load customers.[672] Several commenters note that the Commission has the ability to verify the validity of the seller's analysis through an audit of the company's records to monitor transactions made under the “up to” rates.[673]

634. Pinnacle asks the Commission to establish a stacking methodology that determines default units most likely to run while allowing utilities to propose a different stack based on historical operational sales data. Pinnacle also urges the Commission to clarify that the variable cost for the unit can be defined as the system incremental cost.[674]

635. Other commenters raise concerns with respect to the discretion given to utilities to choose units used to calculate the ceiling.[675] They submit that taking only a small snapshot of certain generating plants to develop cost-based rates will subject buyers to the discretion of sellers possessing market power.

636. APPA/TAPS, the Carolina Agencies and AARP oppose allowing mitigated sellers too much flexibility in designing mitigation methods on the grounds that such an approach would result in market-based rates disguised as cost-based mitigated rates.[676] For mid-term sales, APPA/TAPS and AARP urge the Commission to require a well-supported analysis of the units most likely to provide the service.[677]

637. The Carolina Agencies ask the Commission to consider whether pricing service based on the costs of units “likely to participate” is sufficiently rigorous to meet the operative statutory standards. They oppose the “units most likely to participate” method on the basis that the cost and dispatch assumptions used in the underlying analyses are subjective and difficult to verify. The Carolina Agencies state that the identified “likely to participate” units often wind up being those units on the system with the highest fixed costs, regardless of whether the units are of a type that one might expect to be cycled or ramped for short-term sales. If mitigated utilities are allowed to continue using this method, the Carolina Agencies urge the Commission to develop a set of generic guidelines that will yield more rigorous, less subjective analyses.[678]

ii. Standard Default Rate Methodology To Allow a Seller To Avoid a Hearing

638. With regard to whether a standard methodology should be prescribed that would allow a seller to avoid a hearing on rate methodology (e.g., a methodology that is based on average costs (both variable and embedded)), many commenters urge the Commission to continue to allow flexibility rather than imposing a standard methodology based on average costs.[679]

639. Westar argues that the use of a standard methodology based on average costs would constitute a radical departure from long-settled Commission policy. Westar states that in Opinion No. 203, the Commission found that cost-based pricing cannot keep pace with fluctuating markets,[680] and that imposing average cost pricing would only exacerbate the market inefficiencies that result under cost-based rate making by eliminating pricing flexibility and lowering ceiling rates.[681]

640. Westar adds that public utilities have the statutory right under section 205 to propose and file their rates, and that the Commission lacks the power to impose rates upon public utilities.[682] Westar therefore opposes standardizing cost-based rates in any manner that would curb a mitigated seller's section 205 discretion to select a pricing methodology.[683] Westar contends that the Commission's section 206 authority to require rate changes is limited to instances where the Commission finds that the utility's presumptively just and reasonable existing rate is unjust and unreasonable, and that the Commission's proposed alternative is just and reasonable.[684] According to Westar, the NOPR offers no support for a finding that the wide variety of previously approved cost-based rate methodologies are no longer just and reasonable, and must be replaced with a standardized rate method.[685]

641. Duke and PPL support “up to” rates [686] based on the embedded costs of Start Printed Page 39980the units most likely to provide the service.[687] According to Duke, the average costs of all units in a utility's installed generating capacity base could be quite different than the costs of the specific units most likely to participate in the short-term wholesale market.[688] As such, Duke claims that a system-average cost approach could force the mitigated seller to charge non-native load customers less than the cost actually incurred for generating power whenever incremental costs are greater than average costs, thereby creating a disincentive for the mitigated seller to market wholesale power in a control area where it does not have market-based rate authority.[689]

642. Progress Energy states that it opposes a standardized methodology because it will not send appropriate price signals to customers or appropriately compensate the seller for costs where the seller's generating units or the customer's usage deviates materially from the standardized methodology. Rather than adopting a “units most likely” approach, Progress Energy prefers a methodology that identifies units based on load conditions that are more closely associated with typical market clearing opportunities, between the average of monthly minimum loads and the average of monthly peak loads. Such an approach, Progress Energy argues, better represents conditions where sales occur.[690]

643. While supporting flexibility in the design of up-to rates,[691] Ameren urges the Commission to prescribe a standard methodology that sellers could opt to use to avoid prolonged and costly factual disputes. Ameren asserts that a formula rate based on information from FERC Form No. 1, where available, and incorporating the AEP Methodology [692] could easily form the basis of such a standard methodology.[693]

644. Because of concerns with regard to the discretion given to sellers to choose units used to calculate the cost-based rate, the NC Towns assert that a standard, system-average ratemaking methodology would provide a certainty beneficial to both utilities and wholesale customers, as well as help reduce protracted negotiations and litigation surrounding parties' concepts of a cost-based rate.[694]

645. For mid-term sales that carry a capacity charge, the Carolina Agencies contend that charge should be based on the utility's fully allocated system-wide cost of capacity. The Carolina Agencies state that energy associated with the purchased capacity also should be priced on a system average basis, in order to adhere to the principle that capacity and energy charges be developed on a consistent basis.[695] For these mid-term sales, the Carolina Agencies also support giving Load Serving Entities (LSEs) located within the mitigated utility's control area an option between: (1) Locking-in their price for capacity and/or energy in advance of delivery, at the mitigated utility's forecasted cost of energy and its cost-based tariff rate for capacity; or (2) having their charges determined through a formula rate that would charge purchasers an annually-updated price reflecting the utility's actual system-wide average costs.[696]

646. The Carolina Agencies add that any change in the Commission's pricing policy that would yield more reasonable cost-based rates must be coupled with a “must-offer” requirement. Lower cost-based rates without a concurrent “must-offer” requirement, they argue, will only provide the mitigated utility with an even greater incentive to sell all its available power beyond the mitigated region, thereby exacerbating the problems of depleted supply and profiteering by remaining suppliers.[697]

647. For mid-term sales, NRECA asks the Commission to enforce a matching or consistency principle. Here, NRECA advocates using the same generating units “as the basis for the fixed and variable costs in determining the default embedded-cost rate. In no case should a seller be allowed to mix high-fixed-cost units with high-variable-cost units to artificially inflate the embedded-cost rate. If a seller can show that a portfolio of generating units is likely to be used to provide service, then the seller might be permitted to use a weighted average of the fixed and variable costs of the portfolio.” [698]

Commission Determination

648. Under the Commission's current policy, the default mitigation rate for mid-term sales (sales of more than one week but less than one year) is priced at an embedded cost “up to” rate reflecting the costs of the unit(s) expected to provide the service. The Commission will retain this approach as the default mitigation for mid-term sales. As is the case with sales for one week or less, sellers may choose to adopt the default cost-based rate or propose alternative cost-based rates.

Selecting the Particular Units That Form the Basis of the “Up to” Rate

649. When a seller adopts the default cost-based mid-term rate or otherwise proposes a cost-based rate designed on the unit or units expected to run, the Commission will continue to allow the seller flexibility in selecting the particular units that form the basis of the “up to” rate. Entities that included various proposals for “up to” cost-based rate methodologies in their comments may propose those or other methodologies as alternatives to the default cost-based rates, and the Commission will consider any such proposal on a case-by-case basis. Any seller proposing an alternative mitigation methodology, including a cost-based methodology with demand or capacity charges, carries the burden of justifying its proposal.

650. We agree with commenters that the Commission has the ability to verify the validity of the seller's analysis and will continue to do so in our review of proposed cost-based rates. We will continue to conduct our own analysis of whether a proposed cost-based rate is just and reasonable and, if warranted, will set such a proposed rate for evidentiary hearing where there are issues of material fact.

651. In response to the concerns raised by some commenters regarding the discretion given to sellers in the design of “up-to” rates, as noted above, the Commission considers all evidence when reviewing a cost-based rate proposal and, if a company has not justified selection of certain generating Start Printed Page 39981units, we will not accept the proposed rate. Under the FPA, we have the authority to accept, reject, or modify a proposed rate based on an analysis of the specific facts and circumstances.

652. Further, we find that the approach we adopt in this regard allowing sellers flexibility in designing “up to” rates for purposes of mitigation, subject to Commission review and approval, is consistent with the Commission's historical approach to the pricing of cost-based rates. Because the Commission will have the opportunity to review a seller's proposed “up to” rates, we find that allowing mitigated sellers flexibility in choosing which units are used to calculate the proposed cost-based rate will not result in market-based rates being disguised as cost-based mitigated rates.

653. In response to Pinnacle's suggestion that the Commission make available a stacking methodology to be used to determine which units are most likely to run, we will do so for informational purposes and will make the methodology available on the FERC Internet site. We also note, however, that sellers may propose to use their own stacking methodology.

654. With regard to the Carolina Agencies' question of whether pricing service based on the costs of units “likely to participate” is sufficiently rigorous to meet the operative statutory standards, we find that it is. Historically, the Commission has allowed such an approach and the Carolina Agencies have failed to convince us that, whether or not the underlying analysis is difficult to verify, the approach does not result in just and reasonable rates. In addition, with regard to Carolina Agencies' position with regard to a “must-offer” provision, we discuss proposals for a “must-offer” provision below in the section on protecting mitigated markets.

Standard Default Rate Methodology To Allow a Seller To Avoid a Hearing

655. Regarding a standard default rate methodology that would allow a seller to avoid a hearing on rate methodology (e.g., a methodology that is based on average costs (both variable and embedded)), we note that the Commission has approved various rate methodologies in the past. Rather than adopting a specific default rate methodology in this Final Rule, we affirm that, to the extent the Commission has previously accepted a particular rate methodology, that methodology is presumed to be just and reasonable until the Commission makes a contrary finding.[699]

656. The Commission will continue to allow sellers flexibility in designing “up to” cost-based rate proposals as alternatives to the default methodology. Entities that included various proposals for “up to” cost-based rate methodologies in their comments may propose those or other methodologies as alternatives to the default cost-based rates, and the Commission will consider any such proposal on a case-by-case basis.[700] Any seller proposing an alternative mitigation methodology carries the burden of justifying its proposal.

657. We acknowledge that a standard default rate methodology may provide, as several commenters suggest, some level of certainty and avoid prolonged factual disputes. However, we are persuaded by the concerns expressed by others that designing a standard default rate methodology based, for example, on average costs may not account for the actual costs of the units making the sales, and thus may not allow the seller to recover its costs.

c. Sales of One Year or Greater

Comments

658. While the NOPR did not propose changes to the default pricing for long-term sales (sales of one year or more), several entities filed comments on that issue. APPA/TAPS and AARP reiterate their support for pricing such sales on an embedded cost basis.[701] They submit that the Commission should not depart from its default cost-based mitigation policy with regard to long-term sales. The NC Towns also favor using system average costs in a rate base, rate of return model for determining long term cost-based rates.[702] Similarly, the Carolina Agencies assert that long-term sales to embedded LSEs should be priced at the mitigated utility's fully allocated average embedded cost of capacity and system average energy costs. As with short-term sales, the Carolina Agencies urge the Commission to allow the embedded LSEs the choice between: (1) Locking-in their price at the mitigated utility's embedded cost rates; or (2) agreeing to have their charges determined through an annually updated formula rate that reflects the utility's actual system-wide average costs.[703]

Commission Determination

659. We will retain our existing policy for sales of one year or more (long-term) sales. Specifically, we will continue to require mitigated sellers to price long-term sales on an embedded cost of service basis and to file each such contract with the Commission for review and approval prior to the commencement of service.[704] We discuss below the Carolina Agencies' request for a “must offer” requirement.

d. Alternative Methods of Mitigation

Commission Proposal

660. In the NOPR, the Commission noted that sellers that are found to have market power (i.e., after the Commission has ruled on a DPT analysis), or that accept a presumption of market power, can either accept the Commission's default cost-based mitigation measures or propose alternative methods of mitigation. With regard to alternative methods of mitigation, the Commission asked in the NOPR whether it should allow as a means of mitigating market power the use of agreements that are not tied to the cost of any particular seller but rather to a group of sellers. The Commission asked whether the use of such agreements as a mitigation measure would satisfy the just and reasonable standard of the FPA.

Comments

661. Many commenters favor allowing alternative mitigation methods tied to the costs of a group of sellers, in particular the Western Systems Power Pool Agreement (WSPP Agreement),[705] or transparent competitive market prices in regional markets. Xcel asserts that the FPA does not require a mitigated rate to reflect a utility's own cost-of-service.[706]

662. E.ON U.S. supports mitigation that sets prices at competitive market Start Printed Page 39982levels. It claims that cost-based rate mitigation eliminates the potential for new competition in a mitigated area. In this regard, E.ON U.S. argues that profits are available only when market prices are below the mitigated utility's cost-based rates, which reduces the incentive for investment in new generation as long as buyers can obtain below market-price energy from generation facilities of the mitigated utility's ratepayers.[707] E.ON U.S. adds that mitigation reflective of competitive prices results in mitigated sellers that are indifferent as to the buyer's location and competitive price signals to which buyers can respond accordingly.[708]

Use of the WSPP Agreement Rate To Mitigate Market Power

663. Several entities suggest that the rates under the WSPP Agreement may be an appropriate alternative mitigation method.[709] Westar asserts that the purpose of the cost-based rate schedules under the WSPP Agreement is to mitigate perceived market power,[710] and notes that the Commission has also accepted use of the WSPP Agreement to mitigate market power in various contexts.[711] Westar contends that parties to the WSPP Agreement may sell under the cost-based rate schedules of the WSPP Agreement regardless of whether they have a separate tariff and authorization from the Commission.[712] Thus, Westar claims that the NOPR's implicit question whether additional authorization is needed to make mitigated sales is misplaced since the WSPP Agreement, as an accepted tariff/rate schedule, establishes the lawful filed rate.

664. Pinnacle notes that the WSPP Agreement's price caps were established based on a system-wide average cost and serve to put entities without market-based rate authority on a similar footing. In Pinnacle's view, such agreements enhance liquidity in the regional markets and facilitate transactions due to the commonality of terms and conditions.[713]

665. PG&E adds that the WSPP Agreement is the most commonly used standardized power sales contract in the electric industry. PG&E states that the WSPP membership continuously updates the WSPP Agreement to ensure that it represents up-to-date terms for power sales contracts and notes that the process of updating its terms involves a diversified, experienced group of market participants focused on developing an appropriate rate for short-term sales. PG&E concludes that the terms of the WSPP tariff should be an accepted alternative rate to the default rate determined by the Commission.[714]

666. In contrast, APPA/TAPS and AARP oppose alternative mitigation methods tied to the costs of a group of sellers because there is no assurance that the group rate would reflect the costs of the seller subject to mitigation.[715] Further, APPA/TAPS have concerns that selecting the appropriate group and obtaining the necessary cost information could be extremely difficult and controversial.[716]

Commission Determination

667. We will address on a case-by-case basis whether the use of an agreement that is not tied to the cost of any particular seller but rather to a group of sellers is an appropriate mitigation measure.

668. With regard to the WSPP Agreement, as discussed below, we conclude that use of the WSPP Agreement may be unjust, unreasonable or unduly discriminatory or preferential for certain sellers. Therefore, in an order being issued concurrently with this Final Rule, the Commission is instituting a proceeding under section 206 of the FPA to investigate whether, for sellers found to have market power or presumed to have market power in a particular market, the WSPP Agreement rate for coordination energy sales is just and reasonable in such market.

669. The WSPP Agreement was initially accepted by the Commission on a non-experimental basis in 1991,[717] providing for flexible pricing for coordination sales and transmission services. Currently, there are over 300 members of the WSPP Agreement located from coast to coast in the United States and Canada, including private, public and governmental entities, financial institutions and aggregators, and wholesale and retail customers. The WSPP Agreement as it exists today permits sellers of electric energy to charge either an uncapped market-based rate (for public utility sellers, they must have obtained separate market-based rate authorization from the Commission to do this), or an “up to” cost-based ceiling rate. For sellers without market-based rate authority, the cost-based ceiling rate under the WSPP Agreement consists of an individual seller's forecasted incremental cost plus an “up-to” demand charge based on the costs of a sub-set (eighteen sellers) of the original WSPP Agreement members, not necessarily the costs of any one seller. The up-to demand charge is based on the average fixed costs of the generating facilities of that sub-set of WSPP Agreement members; it was designed to reflect the costs of a hypothetical average utility member in 1989. The only limitations are: (1) That the trades by Commission-regulated public utilities must be short-term (lasting one year or less), and (2) that they be priced at or below the ceilings for sellers without market-based rate authority.

670. In a number of recent orders, the Commission accepted the use of the WSPP Agreement as a mitigation measure subject to the outcome of the instant proceeding and any determinations that the Commission makes regarding mitigation in this proceeding. In those cases, we explained that the WSPP Agreement contains a Commission-approved cost-based rate schedule that has been found to be just and reasonable. Further, we noted that parties to the WSPP Agreement have “the option of transacting under the WSPP Agreement and thus can make sales under the WSPP Agreement without any further authorization from the Commission.” [718]

Start Printed Page 39983

671. Though the Commission has allowed sellers to charge flexible cost-based ceiling rates that are not necessarily based on a particular seller's own costs (such as the WSPP Agreement ceiling rate), we are concerned that the evolution and use of the WSPP Agreement ceiling rate and the evolution of competitive markets have resulted in circumstances in which the WSPP rate may no longer be just and reasonable for sellers that are found to have market power or are presumed to have market power in a particular market, i.e., sellers under the WSPP Agreement that do not have market-based rate authority or that lose or relinquish market-based rate authority.

672. We recognize that the ceiling rate under the WSPP Agreement has been found to be a just and reasonable cost-based rate by this Commission as well as by the U.S. Court of Appeals for the D.C. Circuit,[719] and that it has been in use for over 15 years by sellers irrespective of whether they have market power. Nevertheless, the WSPP Agreement ceiling rate contains extensive pricing flexibility and relies in part on market forces to set the rate at or below the demand charge cap, and we believe the WSPP Agreement rate needs to be revisited in light of its widespread use and changes in electric markets since 1991. When originally approved by the Commission in 1991, there were 40 members under the WSPP Agreement; now there are over 300 members. Additionally, the WSPP Agreement is now used by entities not only in the Western Interconnection, but throughout the continental United States. Further, the demand charge component of the WSPP Agreement ceiling rate is based on the costs of only 18 of the original WSPP members in 1991 (utilizing 1989 data) and does not reflect the costs of the members that joined the agreement since 1991.

673. For these reasons, concurrently with issuance of this Final Rule, we are instituting in Docket No. EL07-69-000 a proceeding under section 206 of the FPA to investigate whether the WSPP Agreement ceiling rate is just and reasonable for a public utility seller in a market in which such seller has been found to have market power or is presumed to have market power. All interested entities will have an opportunity to address this issue through a paper hearing.

674. As noted above, the Commission has accepted, subject to the outcome of this rulemaking proceeding, the use of the WSPP Agreement ceiling rate as mitigation by a number of sellers. These sellers may continue to use the WSPP Agreement ceiling rate as mitigation, subject to refund (and the refund effective date established in Docket No. EL07-69-000) and subject to the outcome of the section 206 proceeding.

Market-Based Proposals for Mitigation

Comments

675. Commenters are generally concerned that where the Commission's current mitigation approach focuses on a seller's own cost of service, it imposes cost-based rates on a mitigated utility in the home control area regardless of whether the prices of alternative sources of supply in the mitigated market exceed the mitigated seller's cost-based rates.[720] Rather than relying on cost-based price caps that may bear no relationship to market conditions, several commenters support allowing mitigation methods based on transparent competitive market prices in regional markets.[721] Commenters suggest various market indicia that the Commission could use as price proxies in market-based mitigation alternatives.[722]

676. Because different markets may be uncompetitive for different reasons, and the same mitigation measure is not necessarily equivalent in all situations, several commenters urge the Commission to consider more tailored, market-based rate approaches to mitigation on a case-by-case basis.[723] MidAmerican suggests that any specific index chosen could be reflected in the tariff of mitigated sellers (for sales up to one year) or in agreements filed with the Commission (for sales of one year or longer).[724]

677. Duke explains that market-based rate mitigation alternatives could be applied to mitigated sellers whose control area markets are adjacent to a Commission-approved market. If the proxy prices are established in markets that the Commission has found to be functionally competitive, Duke contends that the price will by definition be just and reasonable. Duke submits that the Commission approved similar mitigation for sales by the LG&E Parties sinking in the Big Rivers control area capped at the Midwest ISO's LMP at the Big Rivers control area interface.[725]

678. E.ON U.S. argues that allowing index-based price caps as a mitigation option is just and reasonable because such sales are either subject to the market monitoring provisions of an RTO, or in the case of price indices, are structured according to the Commission's instructions with regard to market price reporting. They add that index-based price caps are efficient because: (a) They can be used to address pricing requirements for varying time commitments; (b) they meet the Commission's criteria for accurate and timely reporting; and (c) they do not require the administrative overhead and complexity associated with calculating and reporting cost-based rates.[726]

679. MidAmerican and the Oregon Commission submit that using an appropriate price index as a proxy could ensure that prices are derived from competitive conditions and do not reflect the market power of the mitigated seller (or, for that matter, of any seller).[727] Duke, MidAmerican, and the Oregon Commission reason that allowing a published price index would effectively make the mitigated seller a price taker rather than a price setter.[728] E.ON U.S., PNM/Tucson, and Indianapolis P&L also suggest that requiring cost-based mitigation may result in sellers giving up their market-based rate authority in mitigated areas Start Printed Page 39984due to the significant time and expense of developing a cost-of-service filing.[729] Where sellers opt to give up market-based rate authority, these commenters conclude that buyers will be harmed by a reduction in the number of competitive options available to them in mitigated markets.

680. MidAmerican claims that using price indices would (a) Eliminate the incentive for round-trip transactions; (b) alleviate the need to determine whether the need for mitigation should be based on the point of delivery, the sink location, or some other determinant; and (c) reduce contention over how to calculate cost-based rates.[730] EEI and the Oregon Commission conclude that allowing mitigated rates to be based on competitive market prices would: (1) Maintain supply choices for captive customers by encouraging mitigated suppliers to participate actively in the mitigated markets; (2) avoid the unintended consequences of cost-based rate mitigation (e.g., incentive to sell outside the mitigated region); (3) help to ensure that buyers continue to receive accurate price signals and not inappropriately lean on cost-based rates in times of peak demand; and (4) be consistent with the Commission's goal of encouraging competitive market solutions.[731]

681. APPA/TAPS reject this reasoning, arguing that a dominant supplier has other incentives not to sell to captive customers beyond just the availability of a higher price elsewhere, including the desire to disadvantage competing suppliers within its control area. Therefore, even if a market price index is used as a mitigation alternative, APPA/TAPS submit that a “must offer” obligation remains necessary.[732]

682. According to some commenters, capping mitigated prices at the levels of relevant price indices would also reduce the market distortions that exist under dual price systems.[733] E.ON U.S., Xcel, PNM/Tucson, Duke, EEI, MidAmerican and the Oregon Commission generally contend that allowing market-based rate mitigation methods would reduce the incentive, arising from price disparities in dual-price systems (a regime where a seller has market-based rate authority in some markets but is limited to cost-based sales in other market(s)), for mitigated sellers to seek market-based rate sales beyond the mitigated market.[734] This, in turn, would obviate the need for a “must offer” requirement or mitigation of sales outside the mitigated region. Somewhat similarly, EEI warns that if the Commission implements a “must offer” obligation, suppliers may not apply for market-based rate authorization in markets where they are likely to fail any of the market power screens.[735]

683. Some commenters add that the Commission surrenders nothing in terms of consumer protection by allowing market-based price caps as a mitigation option. In their view, permitting such mitigation will likely increase the willingness of sellers to engage in market transactions in mitigated areas and result in buyers paying no more than what is already recognized as a just and reasonable competitive market price.[736]

684. MidAmerican, E.ON U.S., PNM/Tucson, and Indianapolis P&L all note that the Commission (1) Has found that inter-affiliate sales are permissible at RTO price indices, and (2) proposes in the NOPR (at P 113-14) to extend this policy to market indices satisfying the November 19 Price Index Order.[737] These commenters argue that if sales at a meaningful market index are per se just and reasonable for affiliate transactions, there is no reason why such sales are not per se just and reasonable for non-affiliate transactions.[738] PNM/Tucson add that even in regions without organized RTO/ISO markets, sellers with market-based rate authority have established highly liquid trading hubs (e.g., Four Corners or Palo Verde) that also produce market prices that are readily available, transparent, can serve as an appropriate proxy, and satisfy the Commission's index pricing standards.[739]

685. Another commenter supports the adoption of more market-oriented approaches to mitigation. For daily and hourly transactions, this commenter asks the Commission to be receptive to rates tied to an acceptable price index at a liquid trading point. For long term transactions, rather than focusing on average embedded costs, which this commenter claims are likely to be a poor proxy for market rates, the Commission should consider capacity and associated energy rates that provide a competitive rate of return on new generation units built in the region. Where transmission constraints bind only occasionally and the seller does not have market power absent such constraints, this commenter reasons that it is rational to only apply mitigated rates to sales made at the time such constraints are binding. Similarly, where indicative screens or the DPT analysis point to the existence of a market power problem in a well-defined seasonal or peak period, this commenter favors confining rate mitigation to sales made in the relevant market during that period.[740]

686. APPA/TAPS acknowledge that cost-based rates do not achieve competitive wholesale markets.[741] Ideally, wholesale customers should have a meaningful choice of suppliers whose costs are disciplined by competitive forces and remedies focused on fostering structurally competitive markets will help to ensure that future consumers have choices. Until such structural remedies are fully implemented, APPA/TAPS maintain that mitigated sellers should sell at cost-based rates.[742]

687. APPA/TAPS and Morgan Stanley do not categorically oppose the use of price indices as a mitigation alternative that could be justified with substantial evidence, but urge caution and ask the Commission not to assume that the index relied upon is a just and reasonable, and comparable, proxy for the mitigated market.[743] Morgan Stanley explains that given the price variation among transmission nodes, it is not possible to generically find that any one index-based price would be an adequate proxy for another node(s). APPA/TAPS explain that a thinly traded market, or one separated by transmission constraints, could create volatility or arbitrage possibilities that would leave captive customers worse-off than a cost-based mitigated rate. They add that appropriate price proxies may not be available for all products, and that RTO-administered real-time or day-ahead markets would not generally provide acceptable proxies for price mitigation in markets for weekly, monthly or annual sales. APPA/TAPS also note that the Southeast has no real liquid trading hubs.[744] While urging the Commission to continue requiring cost-based mitigation, Morgan Stanley does not oppose allowing mitigated sellers to Start Printed Page 39985justify an index-based mitigation approach as appropriate for their specific circumstances. According to Morgan Stanley, such an approach may prove justifiable where a viable, liquid index exists within or adjacent to the territory in which a finding of market power exists.[745]

688. NRECA likewise is concerned that there is no assurance that (1) The external market price would be a competitive price; (2) external markets are a reasonable proxy for non-existent competitive market prices in the mitigated market; and (3) there are sufficient monitoring and enforcement mechanisms to ensure these first two conditions are continually being met.[746] Unless these three concerns are addressed, NRECA asserts that the Commission may not lawfully rely on an external market price as a proxy in a mitigated market, particularly where the FPA is clear that the Commission may not approve market-based rates absent “empirical proof” that “existing competition would ensure that the actual price is just and reasonable.”[747] Moreover, where “Congress could not have assumed that ‘just and reasonable' rates could conclusively be determined by reference to market price,”  [748] NRECA argues that the Commission may not rely exclusively on market prices but rather must have a regulatory “escape hatch” or “safeguard” mechanism [749] if actual competitive pressures alone cannot keep rates just and reasonable. NRECA, similar to APPA/TAPS, is concerned that proxy indices are irrelevant oftentimes because they are too far removed from the mitigated market to be adequately representative. While NRECA admits that such indices may be adequate in some instances, it takes the position that, at most, the Commission could entertain proxy index proposals from mitigated sellers on a case-by-case basis.[750]

689. The Carolina Agencies are similarly concerned that market-based indices based on LMPs from adjacent markets in many hours will reflect transmission congestion that may not be representative of congestion patterns in the mitigated market, and therefore must not be deemed a just and reasonable proxy for an entirely different market. Moreover, LSEs in RTOs with Day 2 markets have some ability to limit their exposure to LMP spikes through the use of hedging tools (i.e. Auction Revenue Rights and Financial Transmission Rights). However, the Carolina Agencies argue, LSEs in mitigated markets would face these LMP gyrations from adjacent markets as proxy prices without any hedging protections. These agencies further claim that there are no other sources of non-LMP price information in their region that are reliable enough to serve as proxy prices.[751] In the Carolina Agencies' view, because price information from non-LMP markets is mostly illiquid, non-transparent and easily manipulated due to the low volume of transactions, such reference prices are unlikely to be an accurate and reasonable proxy for competitive prices in the mitigated control area. They state that, as the Commission has reported, “some electric power markets are almost entirely opaque both to regulators and to price takers. In these markets (such as electricity in the Southeast), so little information is available that price indices either do not develop or have little value in price discovery.” [752] The Carolina Agencies also wonder how a meaningful proxy could be determined for a market price in a control area where a dominant supplier has market power.[753]

690. The Carolina Agencies and NASUCA oppose providing mitigated utilities with the option of filing cost-based rates or choosing the market rates of a neighboring control area.[754] NASUCA adds that commenters articulate no legal theory by which mitigated sellers should be allowed any market rate or how the Commission has power to grant any waiver of the rate filing and review requirements of section 205 of the FPA.[755] Rather than allowing mitigated rates to be determined by market prices in adjacent market areas, NASUCA urges the Commission to deny any form of market rates to mitigated utilities and require such suppliers to comply with section 205 of the FPA by filing their rates subject to the traditional review to ensure just and reasonable rates.[756]

691. If the presence of transmission constraints in a dominant transmission provider's control area allow it to charge supra-competitive market-based rates there, APPA/TAPS submit that the Commission must require these constraints to be addressed.[757] These commenters ask the Commission to impose mitigating conditions on market-based rate authority to increase access to existing transmission facilities as well as to expand their transmission access through rolled-in upgrades. For example, APPA/TAPS,[758] and the Carolina Agencies [759] suggest that the Commission could condition the market-based rate authority of a mitigated seller on the demonstrated willingness of vertically-integrated transmission owners to jointly plan and construct new generation projects with market participants, and/or to participate with them in collaborative, open regional transmission planning processes.

692. Xcel responds that, aside from such a requirement being impractical, the Commission has no legal authority to impose a condition requiring joint planning of new facilities nor jurisdiction over the construction of new facilities.[760] Xcel states that the FPA does not provide the Commission with certificate jurisdiction over generation facilities or otherwise, nor does the Commission have the authority to order utilities to enter into such a contract.[761]

Commission Determination

693. The Commission continues to believe that proposed alternative methods of mitigation should be cost-based. However, as discussed below, while we will not allow the use of alternative “market-based” mitigation on a generic basis, we will permit sellers to submit alternative non-cost-based mitigation proposals for Commission consideration on a case-by-case basis.

694. A variety of suggestions have been made such as basing mitigated prices on: Prices from an adjoining LMP market that are transparent and contemporaneously available; published index prices; prices capped at levels reported in the Electric Quarterly Reports for sales in neighboring markets; a utility's own sales in areas where it does not possess market power; Start Printed Page 39986and competitive solicitations with a sufficient amount of bidders or opportunity cost pricing. However, while some commenters suggest that market-based rate mitigation may cure several of the cost-based mitigation regime's alleged ailments, they fail to convincingly address a fundamental concern with such mitigation. That is, why a market-based price from one market would be a relevant and appropriate proxy price to mitigate market power found in a different market.

695. Specifically, we reject Duke's argument that we should allow market-based rate mitigation alternatives to be used by mitigated sellers whose control area markets are adjacent to a Commission-approved market because if the proxy prices are established in markets that the Commission has found to be functionally competitive, the price will by definition be just and reasonable. Although Duke is correct that a price in a market may be presumed to be just and reasonable in the market in which it has been approved, Duke's claim fails because that price has not been shown to be just and reasonable for other markets with differing competitive circumstances.[762] Duke's argument also fails to recognize that the Commission does not certify markets as competitive; rather, we make determinations on whether individual sellers in a market have market power. In addition, contrary to Duke's view, the Commission's acceptance of proposed mitigation in the Big Rivers control area does not support Duke's proposal in this regard. In LG&E Energy Marketing Inc.,[763] the Commission accepted a proposal that capped—at the Midwest ISO's LMP price at the Big Rivers control area interface—all market-based sales by LG&E sinking in the Big Rivers control area not sold pursuant to contractual agreements already in existence. However, Duke fails to point out that, when LG&E proposed to mitigate its sales into the Big Rivers control area, LG&E was a member of the Midwest ISO and, accordingly, capping LG&E's sales price at the Midwest ISO LMP at the Big Rivers interface was appropriate.

696. Commenters raise many reasons why allowing the use of an index could be beneficial such as: Using an appropriate price index as a proxy could ensure that prices are derived from competitive conditions and do not reflect the market power of the mitigated seller; allowing a published price index would effectively make the mitigated seller a price taker rather than a price setter; use of an index price would eliminate the incentive for round-trip transactions and alleviate the need to determine whether the need for mitigation should be based on the point of delivery, the sink location, or some other determinant; would maintain supply choices for captive customers by encouraging mitigated suppliers to participate actively in the mitigated markets; would help to ensure that buyers continue to receive accurate price signals and not inappropriately lean on cost-based rates in times of peak demand; and, would be consistent with the Commission's goal of encouraging competitive market solutions.

697. However, we agree with Morgan Stanley and others that, given price variations among transmission nodes, we should not generically find that one index-based price is necessarily an adequate proxy for another node. Commenters urging the Commission to consider such alternatives on a case-by-case basis acknowledge that different markets may be uncompetitive for different reasons.[764] While commenters speak of “relevant price indexes,” their comments contain little more than undeveloped proposals and limited discussion as to how such an index would be chosen, and why it would be an appropriate proxy for the mitigated market. For example, commenters fail to explain how a proxy price based on existing competition from one market with distinct traits such as transmission congestion ensures a just and reasonable price in another market that has its own unique traits and circumstances. Deriving prices from competitive conditions, making a mitigated seller a price taker rather than a price setter, and reducing market distortions are all goals commenters claim market-based mitigation can help achieve. Nonetheless, the use of an external market price to establish the just and reasonable price in the mitigated market has not yet been shown to be appropriate.

698. While we will not allow the use of “market-based” mitigation on a generic basis, we nevertheless will permit sellers to submit non-cost-based mitigation proposals, such as the use of an index or an LMP proxy, for Commission consideration on a case-by-case basis based on their particular circumstances. Sellers choosing to propose such alternative mitigation will carry the burden of showing why and how the proposed index-based price is relevant, appropriate and a just and reasonable price for the mitigated market. While several commenters also seek to have the Commission make market-based rate authorization of mitigated sellers contingent upon their pledging to jointly plan and construct future generation projects with market participants, or pursue other structural conditions, they have not justified imposing such a burden. For those sellers that are affected with a market power concern, we discuss elsewhere in this Final Rule the means by which we will require adequate mitigation. Moreover, we believe that we have adequately addressed these concerns related to planning in our recent Order No. 890, where we require all jurisdictional transmission owners to engage in transmission planning with other market participants. Therefore, we find no reason to mandate a mitigated seller's participation in such arrangements.

2. Discounting

Commission Proposal

699. In the NOPR, the Commission explained that a supplier authorized to sell under an “up to” cost-based rate has an incentive to discount its sales price when the market price in the supplier's local area is lower than the cost-based ceiling rate. During these periods, a rational seller will discount its sales to maximize revenue. In the past, the Commission has encouraged discounting as an efficient practice that can maximize revenues to reduce the revenue requirements borne by requirements customers.

700. Here, the primary issue is whether a seller can “selectively” discount, i.e., offer different prices to different purchasers of the same product during the same time period. The Commission invited comment on whether selective discounting should be allowed for sellers that are found to have market power or have accepted a presumption of market power and are offering power under cost-based rates. If so, the Commission sought comment on what mechanisms (reporting or otherwise), if any, are necessary to protect against undue discrimination. By contrast, were it to forbid selective discounting, the Commission asked for comment on whether it should require the utility to post discounts to ensure that they are available to all similarly-situated customers. Start Printed Page 39987

Comments

701. Some commenters favor selective discounting because it provides an opportunity to meet competition where necessary to retain and attract business. They add that the contracting flexibility afforded by selective discounting allows sellers to modify rates and tailor sales based on customer-specific factors such as load characteristics and credit ratings. They argue that such flexibility maximizes liquidity and available capacity and energy.[765]

702. MidAmerican and Indianapolis P&L both state that section 206 of the FPA already prohibits undue discrimination and provides well-established procedures for entities that have been subjected to undue discrimination.[766] Westar notes that the Commission's long-standing policy is to allow selective discounting and asserts that discounting to customers who have competitive alternatives is not unduly discriminatory.[767]

703. PG&E maintains that it is just and reasonable for a seller to offer a discount below its cost-based mitigated rate if the seller will gain other (non-market power) advantages such as repeat customers or lower transaction costs. PG&E also suggests that principles of efficiency and competition support providing selective discounts to entities with larger needs.[768]

704. Duke contends that sales arising from selective discounting spread fixed costs over more units of service, thereby reducing the “up to” rate.[769] Moreover, without the ability to selectively discount, Duke submits that utilities will not have the opportunity to compete for many wholesale transactions in the mitigated control area.[770]

705. Southern asserts that if selective discounting were eliminated, then the resulting loss of a low-cost source of supply would harm the customers. In Southern's view, captive customers also lose because of foregone opportunities to optimize capacity nominally dedicated to native load service.[771] EEI adds that where a mitigated seller is already precluded from making market-based rate sales within mitigated areas, selective discounting does not give rise to conditions that support the potential exercise of market power.[772]

706. Other commenters generally oppose allowing mitigated sellers to selectively discount sales. For example, TDU Systems claim that selective discounting is unnecessary because a seller subject to cost-based mitigation in its home control area would not face competition by definition. They also contend that selective discounting would allow mitigated sellers to engage in price discrimination in a non-competitive market, thereby permitting the seller to exercise market power by economically or physically withholding capacity to increase the posited market price. Thus, in the TDU Systems' view, a rule allowing selective discounting would effectively grant market-based rate authority in a non-competitive market, in contravention of the requirements of the FPA.[773]

707. While NC Towns generally encourage discounts to cost-based rates, they oppose selective discounting because they do not believe that the size of a load should be a factor when determining whether to give a buyer a discount.[774]

708. APPA/TAPS question why a dominant seller would offer discounts to captive customers with no other viable supply options. They add that there is no evidence that local, competing generation exists or that there is available transmission capacity that could support significant imports. In order to avoid discrimination, APPA/TAPS advocate requiring a mitigated supplier to offer captive customers any discounts that it offers to other purchasers.[775] Factors such as a customer's capacity factor, credit rating or fuel costs may justify adjustments to seller-specific cost-based rates, but such factors, argue APPA/TAPS, should be reflected in the seller's cost-based rates rather than through selective discounting.[776]

709. If selective discounting is permitted, TDU Systems and NRECA urge the Commission to require sellers to file reports of the discounts offered, and encourage the Commission to vigorously enforce its market manipulation and affiliate transactions rules.[777]

710. Suez/Chevron urges the Commission to require selective discounts to be contemporaneously offered to similarly-situated buyers, and separately identified in the mitigated seller's EQR.[778] To minimize the potential for market power abuse when a mitigated seller selectively discounts to an affiliate,[779] Suez/Chevron supports requiring a presumption that nonaffiliated buyers are similarly-situated, and therefore entitled to the same discount as a mitigated seller offers to its affiliate.[780]

711. PG&E, in contrast, opposes requiring the seller to make discounts available to all similarly-situated entities. According to PG&E, it would be difficult to determine which entities are in fact similarly-situated because the seller would have to consider multiple factors, such as quantity of load, timing, flexibility, credit rating, and purchases history.[781]

712. Ameren disagrees with a posting requirement, arguing that the Commission's requirements for separate filings and advance approval of affiliate power sales provide the appropriate oversight and mechanisms necessary to police discounting concerns regarding selective discounts favoring affiliates. Ameren concludes that a requirement to post discounts is unduly burdensome given that the only discounts of concern are in the affiliate sales, which are subject to separate filing requirements.[782] PG&E, in turn, notes that the affiliate restrictions also provide protection against the use of selective discounts to benefit affiliates.[783]

Commission Determination

713. We will continue our practice of allowing discounting from the default cost-based mitigated rates for short- and mid-term sales and will permit selective discounting by mitigated sellers provided that the sellers do not use such discounting to unduly discriminate or give undue preference. We believe that selective discounting that does not constitute undue discrimination can improve liquidity, available capacity and energy, and customer supply Start Printed Page 39988options. In other words, non-discriminatory discounting can provide benefits to the market.

714. APPA/TAPS question why a dominant seller would offer discounts to captive customers with no other viable supply options, and the TDU Systems comment that selective discounting is unnecessary because a mitigated seller by definition would not face competition in its home control area. However, in times when there are viable alternatives, a seller under an “up to” cost-based rate has an incentive to discount its sales price when the market price in the seller's mitigated market is lower than the cost-based ceiling rate. Allowing a mitigated seller to non-discriminatorily discount the rate when there are viable alternatives in the market benefits customers by providing more supply options in such instances.

715. Discounting also can maximize revenue by optimizing capacity nominally dedicated to native load service, allowing the supplier to spread fixed costs over more units of service. Maximizing revenue in this manner can help reduce the “up to” rate, and therefore the revenue requirements borne by captive customers. The Commission has previously determined that requiring a mitigated entity to limit sales to its ceiling rates “is at odds with the long-standing policy of allowing ‘up to' cost-based rates.” [784]

716. The FPA requires that all rates charged by public utilities for the sale or resale of electric energy be “just and reasonable.” [785] If a seller's cost-based rate has been found to be just and reasonable by the Commission, it follows that discounted rates below such a cost-based rate are also just and reasonable.[786] However, a seller may not lawfully discount to gain, or profit from, market power advantages. We emphasize that section 205 of the FPA prohibits public utilities, in any power sale subject to the Commission's jurisdiction, from granting any undue preference or advantage to any person [787] and also prohibits undue discrimination.[788]

717. With regard to comments that the Commission establish a reporting mechanism, under the Commission's existing reporting requirements entities making power sales must submit EQRs containing: A summary of the contractual terms and conditions in every effective service agreement for all jurisdictional services, including market-based and cost-based power sales and transmission services; and, transaction information for effective short-term (less than one year) and long-term (one year or greater) power sales during the most recent calendar quarter.[789] Through this reporting requirement, the Commission monitors the rates charged by mitigated sellers.

718. Several commenters also seek to have the Commission require selective discounts to be posted and contemporaneously offered to similarly-situated buyers. Some seek a presumption that nonaffiliated buyers are similarly situated whenever a mitigated seller offers an affiliate a discount. The Commission will not require mitigated sellers to contemporaneously post in a public forum all discounts provided for cost-based sales (i.e., where the sale is made at a price below the maximum up-to cost-based rate approved by the Commission in that tariff or rate schedule). Proponents of a posting requirement have not justified nor demonstrated how the Commission's EQR requirement fails to provide an adequate means by which to monitor such discounts. In addition, many sales are made below the cost-based cap, and the commenters' proposals would place an undue burden on sellers that would be required to contemporaneously post rates that the Commission has already deemed to be just and reasonable. Accordingly, the Commission will not require the contemporaneous posting of discounted cost-based rates. Finally, commenters have provided no basis to conclude that nonaffiliated buyers are similarly situated whenever a mitigated seller offers an affiliate a discount, and we will not adopt the proposed presumption in this regard. Thus, sellers may selectively discount only if they do so in a manner that is not unduly discriminatory or preferential.

719. Further, we agree with MidAmerican that identifying discriminatory selective discounting requires fact-specific evaluations. Because individual proceedings are the best instrument available to the Commission for such efforts, allegations of undue discrimination arising from selective discounting are best addressed on a case-by-case basis.

3. Protecting Mitigated Markets

a. Must Offer

Commission Proposal

720. Under the Commission's current mitigation policy, a seller that loses market-based rate authority in its home control area is limited to charging cost-based rates in that control area; however, there is no requirement that the seller offer its available power to customers in that home control area. Instead, the seller is free to market all of its available power to purchasers outside that control area if it chooses to do so. If, for example, market prices outside the mitigated seller's control area exceed the cost-based caps within the mitigated control area, then the seller will, other things being equal, have an incentive to sell outside. As noted in the NOPR, wholesale customers have argued that default cost-based mitigation of this kind is of little value if a seller can market its excess capacity at market-based rates in other control areas. In the NOPR, the Commission sought comment on whether its current policy is appropriate, and if not, what further restrictions are needed. The Commission asked whether it should adopt a form of “must offer” requirement in mitigated markets to ensure that available capacity (i.e., above that needed to serve firm and native load customers) is not withheld. If so, the Commission asked if such a “must offer” requirement should be limited to sales of a certain period to help ensure that wholesale customers use that power to serve their own needs, rather than simply remarketing that power outside the control area and profiting. [790] If it were to adopt such a “must offer” requirement, the Commission asked what rules there should be to define the “available” capacity that must be offered , in order to avoid case-by-case disputes over this issue.

Comments

721. Wholesale customers generally support a “must offer” requirement,” stating that it is needed to ensure that power is available for purchase in the mitigated market and to protect them from incurring higher costs to serve Start Printed Page 39989load.[791] They argue that the existence of a dual price system (a regime where a seller has market-based rate authority in some markets but is limited to cost-based sales in other market(s)) creates an incentive for a mitigated seller to sell its power outside of the mitigated market whenever market prices in the outside market are above the mitigated seller's cost-based price. They are concerned particularly with the situation where a wholesale customer faces few or no alternatives in the mitigated market due to transmission constraints.

722. APPA/TAPS, the Carolina Agencies and NRECA claim that the Commission has both the authority and obligation to remedy undue discrimination in wholesale sales, which are clearly set forth in sections 205 and 206 of the FPA.[792] They specifically argue that a “must offer” condition is within the Commission's authority as a remedy for the unjust and unreasonable rates and undue discrimination (refusal to sell in the mitigated control area) that are a consequence of the mitigated seller's accumulation of market power.[793] Several commenters reason that, similar to imposing reporting requirements and other conditions on a grant of market-based rate authority, where a seller no longer has market-based rate authority in its home control area, the Commission may impose a “must offer” condition on the continuation of market-based rate authorization outside a mitigated seller's control area.[794] APPA/TAPS and the Carolina Agencies argue that the Commission already imposed a must-offer obligation on the continued availability of market-based rate authority for sellers in the California markets.[795]

723. APPA/TAPS also assert that while Order No. 888 rejected a generic obligation that would have required sellers to continue wholesale sales past the expiration of the contract(s) in question in that proceeding, Order No. 888 explained that the Commission can impose an obligation to continue service on a case-by-case basis.[796]

724. APPA/TAPS and the Carolina Agencies argue that a dominant public utility's physical withholding of generation in the mitigated market in order to make market-based sales elsewhere results in undue discrimination that the Commission has an obligation to remedy. They assert that because wholesale customers in the mitigated market are harmed through decreased supply, increased market concentration, and increased prices, these customers are exposed to the type of injury against which the FPA was designed to protect.[797] The Carolina Agencies also maintain that, whether or not exporting behavior can be considered economically efficient, such behavior results in undue discrimination between (i) The mitigated utility's native load and (ii) LSEs located within the mitigated utility's home control area.[798] This outcome, the Carolina Agencies continue, violates the FPA's mandate that rates be just, reasonable and not unduly discriminatory regardless of whether the mitigated utility's decision to export power is a conscious “withholding” for anticompetitive ends.[799] APPA/TAPS and Carolina Agencies add that vertically-integrated utilities with substantial generation in their home control areas frequently have the ability and incentive to discriminate against their wholesale customers, who compete against them on both the wholesale and retail level.[800]

725. APPA/TAPS and Carolina Agencies maintain that undue discrimination occurs if a dominant public utility unjustifiably disadvantages a class of market participants. They cite case law that the D.C. Circuit found “upholds the power of the Commission to subject approval of a set of voluntary transactions to a condition that providers open up the class of permissible users.” [801] Absent relevant circumstances that render two sets of customers differently situated, they assert that it is unduly discriminatory for a public utility to sell wholesale power to one set of customers (at market-based rates) while denying service to another set (to whom sales, if made, would need to be priced at cost-based rates). They contend there is no justification for disparate treatment in such a case and, therefore, the Commission is obligated under sections 205 and 206 to remedy such undue discrimination by either denying or conditioning the grant of market-based rate authority outside of the mitigated home control area. A “must offer” condition, they claim, would satisfy this obligation by preventing undue discrimination.[802]

726. APPA/TAPS and the Carolina Agencies further allege that, while it may not be unduly discriminatory for a utility to elect to sell to the wholesale Start Printed Page 39990customer who will pay the highest price, it is unduly discriminatory if the price differential is based upon mitigation required as a result of the seller's market power.[803] Where sellers claim a right to seek the highest prices, APPA/TAPS and the Carolina Agencies counter that this profit maximization impulse can neither justify the exercise of market power nor insulate it from correction.[804]

727. According to APPA/TAPS and the Carolina Agencies, it is also unduly discriminatory for a mitigated seller to make market-based rate sales outside its home control area when constraints on that entity's own transmission system prevent embedded customers from similarly accessing those markets as buyers. They argue that refusal to sell wholesale power supplies to embedded LSE customers at fully-compensatory cost-based rates effectively compounds the de facto denial of access by exacerbating both the discrimination and the resulting harm.[805] According to APPA/TAPS and the Carolina Agencies, the claim that mitigated sellers are merely engaging in economically efficient behavior ignores the market power that the sellers possess.[806] They state that when captive customers have few or no supply alternatives in the mitigated market and are constrained from accessing opportunities in the broader market (even with open access tariffs), and the dominant supplier sells its excess capacity beyond the mitigated market, the resulting reduction in output in the mitigated market is not addressed simply by prohibiting the mitigated seller from selling at unmitigated prices in the mitigated region.[807] They conclude that it would be unjust and unreasonable to permit or facilitate such withholding by allowing unconditioned sales at market-based rates outside a mitigated supplier's home control area; this would reserve the benefits of competitive markets exclusively to dominant public utility sellers.[808]

728. A number of commenters claim that a “must offer” requirement is necessary due to their lack of viable options in mitigated control areas. For example, Fayetteville submits that it finds itself without transmission access to make short-term energy purchases to displace its higher cost generation.[809] Fayetteville contends that Progress Energy's dominant position, as well as Fayetteville's inability to access alternative suppliers due to the inadequacy of Progress Energy's transmission system, gives Progress Energy unmitigated market power.[810]

729. The Carolina Agencies add that, while economic efficiency is a worthy goal in structurally sound markets where participants have ready and equal access to meaningful choices, the idea of economic efficiency cannot justify a mitigated supplier's behavior in a control area where its market power arises from import limitations or other factors that deprive captive LSEs of viable options. Nor can, they claim, the goal of economic efficiency trump the Commission's clear duty to protect customers by ensuring that rates are just, reasonable, and not unduly discriminatory.[811]

730. The Carolina Agencies dispute the claim that there is no need for a “must offer” requirement given the Commission's authority to penalize market manipulation. They question whether refusal to sell in the mitigated market would be actionable under the anti-manipulation rules if there is no obligation to offer power to embedded LSEs.[812]

731. NRECA and others ask the Commission to reject the claim that a “must offer” requirement would impede a mitigated seller's ability to fulfill its retail crediting obligations.[813] NRECA responds that retail customers can sometimes benefit from cost-based rates; if competition reduces the market price to a seller's marginal cost, no contribution to fixed costs would be recovered. Commenters note that not all utilities are subject to rules requiring the sharing of profits from off-system sales.[814] NRECA argues that a utility's authority to make off-system sales at market-based rates is a privilege granted by the Commission; if the Commission restricts or conditions that privilege, any obligation the public utility has under State law or regulation to sell excess energy or capacity is pre-empted by the requirements of Federal regulation.[815] The Carolina Agencies and NRECA add that a “must offer” requirement would serve the intended purpose of the Commission's mitigation policy, which is to protect wholesale customers from the exercise of actual and potential market power, not to preserve a utility's ability to reduce retail rates nor its ability to engage in a certain volume of off-system power sales.[816]

732. NRECA, APPA/TAPS and the Carolina Agencies all set forth proposals in their comments for implementing a “must offer” requirement.[817] NRECA suggests requiring a mitigated seller to hold an annual open season to offer long-term service (one year or more), as well as requiring a mitigated seller to offer shorter-term capacity and energy.[818] While not favoring an annual open season, APPA/TAPS and the Carolina Agencies each propose “must-offer” parameters to govern short- and long-term sales.[819] For both short- and long-term sales, the Carolina Agencies would offer captive customers an option between (1) Locking-in their price at the mitigated utility's embedded cost rates or (2) agreeing to have their charges determined through an annually updated formula rate that reflects the mitigated utility's actual system-wide average costs.[820] The APPA/TAPS proposal also includes an obligation to offer captive customers participation on proposed generation projects.[821] Both APPA/TAPS and the Carolina Agencies would limit any “must-offer” to loads actually located in the mitigated control area.

733. NRECA also proposes two alternatives to a “must offer” requirement. First, NRECA suggests that the Commission give captive wholesale customers a right of first refusal to purchase at a market price energy or capacity that the mitigated seller proposes to sell outside the mitigated Start Printed Page 39991market.[822] The weakness of this approach, NRECA acknowledges, is that it would allow the mitigated seller to charge wholesale customers a supra-competitive price in the mitigated market given that the market-based rate outside the control area would be higher than the cost-based rate in the seller's control area.[823]

734. NRECA also suggests as an alternative an enforceable commitment to provide sufficient additional transmission import capacity to mitigate the generation market power. It states that such a commitment could be implemented by re-dispatching resources, relinquishing transmission reservations, or physically upgrading the transmission grid. This would allow additional suppliers to make sales in the mitigated region, thereby mitigating the seller's generation market power. NRECA contends that this approach would directly address the larger issue of the need to eliminate transmission bottlenecks and load pockets that give rise to generation market power.[824]

735. The Carolina Agencies also propose that mitigated utilities be required to investigate and report on transmission expansion or other actions that could remove structural impediments causing market power. The Carolina Agencies claim that such a requirement is consistent with the Commission's affirmative duty to remedy undue discrimination, an area in which the Commission has broad authority to craft remedies.[825]

736. Other commenters argue against imposition of a “must offer” requirement, stating that it would encourage inefficiencies, undermine competition, discourage investment, and perpetuate market power. They also assert that such a requirement goes beyond any cost-of-service requirement that the Commission has ever adopted.[826] They question the need for a “must offer” requirement, claiming that existing Commission statutory authority, regulations, and enforcement mechanisms already sufficiently guard against the market power abuse and market manipulation concerns that “must offer” proponents claim such a provision is needed to prevent.[827]

737. EEI and Progress Energy claim that when the Commission establishes a cost-based rate in a mitigated market, it ensures that the rate meets the just and reasonable and not unduly discriminatory requirements of sections 205 and 206 of the FPA, and thus there is no further Commission action that is required to mitigate the indicated market power.[828]

738. Several commenters that argue against imposition of a “must offer” requirement state that wholesale customers have not presented sufficient evidence to justify the generic imposition of such a requirement. They state that there have been no specific instances cited where a wholesale customer in a mitigated market was unable to obtain service, much less evidence that such instances are commonplace.

739. Duke/Progress Energy argue that the Commission must make a finding that rates or practices are unjust, unreasonable, or unduly discriminatory as a predicate to taking action, and that in the case of a generic rulemaking, “the Commission” cannot rely solely on “unsupported or abstract allegations.”’ [829] They cite National Fuel Gas Supply Corp. v. FERC,[830] where the D.C. Circuit, describing Tenneco Gas v. FERC,[831] stated “[t]he court [in Tenneco] ‘upheld Order 497 in relevant part because FERC presented an adequate justification—by advancing both (i) A plausible theoretical threat of anti-competitive information-sharing between pipelines and their marketing affiliates and (ii) vast record evidence of abuse.’ ”[832] They note that the D.C. Circuit contrasted Tenneco with Order No. 2004 (at issue in National Fuel), where “ ‘FERC has cited no complaints and provided zero evidence of actual abuse between pipelines and their non-marketing affiliates.’ ” They assert that the D.C. Circuit concluded that “ ‘[p]rofessing that an order ameliorates a real industry problem but then citing no evidence demonstrating that there is in fact an industry problem is not reasoned decisionmaking.” ’ [833]

740. According to Duke/Progress Energy, the commenters favoring a “must offer” requirement “have presented no evidence whatsoever to support the conclusion that any systemic discrimination is occurring or that any party is suffering any actual harm under the discrimination theory they have posited.” [834] Duke/Progress Energy offer several examples where they have sold power to LSEs within their control areas after the Commission imposed cost-based mitigation for those sales as evidence that there is no basis for expecting mitigated utilities to abandon long-standing customers and “decades of intersystem coordination and mutual assistance, whereby utilities take whatever measures are possible * * * to help their neighbors maintain reliability.” [835]

741. A number of commenters assert that the Commission's statutory authority to require wholesale sales under section 202(b) and 202(c) of the FPA is limited and cannot justify the imposition of a “must offer” requirement in this context.[836] Southern explains that the Commission has forced power sales by a jurisdictional public utility to wholesale customers under section 202(b) of the FPA only if such customers have proven they lack service alternatives. Southern states that it would be unreasonable to impose a generic obligation to serve at wholesale by means of a “must offer” requirement, absent particularized findings based on a properly developed record that wholesale customers lack reasonable alternatives.[837]

742. EEI agrees that the Commission's section 202(b) authority is clearly aimed at individual transactions where a wholesale customer cannot access supply, with ample due process safeguards to ensure that a requirement to sell is truly warranted and will not Start Printed Page 39992harm the seller.[838] EEI states that the Commission cannot turn such a provision into a blanket regulatory requirement without violating the intent of Congress and inappropriately bypassing these safeguards, nor is such a blanket requirement warranted.[839]

743. Several commenters question the legal support for a “must offer” requirement, arguing that the FPA does not contain an express obligation to serve wholesale customers,[840] and that neither section 205 nor section 206 of the FPA authorize the Commission to mandate or prohibit sales, as long as they are made at just, reasonable, and non-discriminatory rates approved by the Commission.[841]

744. Many commenters also contest claims that sales outside the mitigated control area at market-based rates constitute withholding or undue discrimination. Westar and others suggest that offering generation for sale outside of the mitigated control area at the prevailing market price to serve demand does not constitute withholding. They state that withholding generally refers to either physical withholding (not offering to sell) or economic withholding (offering to sell only at inflated prices), which in either case is intended to raise prices.[842] Duke/Progress Energy claim that “the Commission has confirmed that it is ‘legitimate economically rational’ behavior for a market participant to export power in order to sell at higher prices outside a control area rather than to sell at lower capped prices within a control area.” [843] Westar similarly argues that, absent evidence of manipulation or fraud, a “ ‘seller of a commodity is acting quite rationally and legally to withhold his supply from the market if he believes that in the future the commodity will command a higher price—assuming, of course, the seller is under no legal duty to sell.’ ” [844] Westar and E.ON U.S. reason that the Commission's market behavior rules already address economic withholding concerns.[845]

745. MidAmerican adds that in the limited instances where a wholesale customer cannot obtain service, and where an obligation to serve exists, the Commission can address the issue in fact-specific proceedings of individual sellers.[846] Duke suggests that the “must offer” proponents have failed to demonstrate why “self-supply,” including new construction and supply from external resources, is not a viable option in at least some instances.[847] Duke states, for example, that the Carolina Agencies submit that LSEs will have few if any practical supply options if a mitigated supplier is not subject to a must offer requirement. However in Duke's view, the Carolina Agencies fail to demonstrate why “self-supply,” including construction of local generation by their members, is not a viable option in at least some instances. Nor do they demonstrate lack of ability to secure supply from resources external to the control area. Duke submits that even where construction of new generation may not be cost-effective, “self-supply” includes purchasing as well as self-build. Duke argues that lack of an economic self-build option at a given time does not relieve an LSE of its obligation to acquire generation resources through alternate means such as long-term purchases.[848]

746. Several commenters similarly challenge the claim that choosing to make sales outside the mitigated control area at market-based rates is discriminatory. EEI notes that not all rate distinctions are prohibited by section 205(b) of the FPA. It states that only undue discrimination between customers of the same class that is not justified by cost of service differences, operating conditions, or other considerations is forbidden.[849] In this proceeding, Duke/Progress Energy claim that wholesale customers are seeking a superior product to that offered to other customers outside the mitigated control area: “a Commission-enforced right to a free and unilateral call option to buy any available energy generated by [m]itigated [u]tility assets at cost-based prices, exercisable during peak periods when market prices are high.” [850]

747. EEI adds that the courts also recognize that the just and reasonable standard allows—and can even require—rate differences to reflect different locations and classes of customers.[851] EEI and Progress Energy therefore contend that, once the Commission has determined whether a seller may sell at market-based rates or must use mitigated rates in various markets, the seller must be allowed to sell electricity at the just and reasonable rates approved for the different markets.[852]

748. MidAmerican claims that customer concerns that a mitigated seller will unduly discriminate between the seller's native load and wholesale customers in the mitigated region are baseless because the Commission's jurisdiction does not extend to a comparison of retail and wholesale rates. MidAmerican states that while a seller typically has an obligation to serve retail customers in a franchised service area, that obligation does not extend to wholesale customers. Therefore, MidAmerican states there is no issue of undue discrimination between retail and wholesale rates that either requires or allows a “must offer” requirement.[853]

749. Xcel and others submit that wholesale customers are seeking a preference or entitlement through a “must offer” requirement and are in fact calling for discrimination by asserting a preference to power available for sale by a mitigated seller over all other Start Printed Page 39993purchasers, even those who value it more highly,[854] and have provided no evidence to justify such a preference or entitlement over other potential purchasers.[855] Duke/Progress Energy state that customer claims that “they are victims of market power and therefore need some specially tailored remedy” is erroneous, and that “[b]y imposing cost-based rates * * * within their control area, the Commission has fully mitigated any market power concerns.” [856] Xcel and others also note that the LSEs have no reciprocal obligation to purchase power if a “must offer” requirement were imposed upon mitigated sellers.[857]

750. According to Duke and others, when a mitigated supplier sells excess generation at market-based rates outside of the mitigated control area, it is exhibiting economic behavior.[858] Such behavior encourages trading within and across regions, making markets more competitive. Similarly, Westar contends that a “must offer” requirement prevents markets from allocating scarce resources to customers who value them the most, hindering optimal resource allocation.[859] Westar states that this is inefficient because “the highest cost generation may not be displaced by the seller's lower cost energy.” [860]

751. EEI, Progress Energy, and others also claim that a “must offer” requirement would effectively take economic benefits away from the mitigated utility's retail native load and transfer them to wholesale customers in the mitigated control area.[861] Some of these commenters claim that a “must offer” requirement may result in a windfall for the wholesale customer originally seeking protection from the seller's market power at the expense of the mitigated utility and its native load customers.[862] PNM/Tucson adds that sales made by a utility pursuant to a “must offer” requirement could affect reliability by making capacity unavailable to meet State-established reserve margins.[863]

752. Xcel and Duke point out that a “must offer” requirement at cost-based rates may result in a lost opportunity cost to the seller.[864] A number of commenters assert that mitigation is intended to assure that selling utilities do not benefit from the exercise of market power; it is not to guarantee preferential treatment for particular customers to obtain below-market generation through an obligation to serve.[865]

753. Some commenters further contend that a “must offer” requirement would create significant wealth transfers from mitigated sellers as a result of arbitrage opportunities. For example, wholesale customers would accept the mitigated offer any time the “must offer” price was below the market price, either in or outside of the mitigated region.[866] E.ON U.S. is concerned that a “must offer” requirement giving a buyer the option to buy power at mitigated prices will inevitably result in external third parties negotiating with such a buyer to obtain longer-term access to the mitigated power.[867]

754. In addition, EEI and others argue that a “must offer” requirement would reduce competition and stifle development by providing a disincentive for sellers to develop new generation resources.[868] New entrants would be deterred from building generation due to the disparity between cost-based and market-based rates; [869] other sellers in the mitigated region effectively would be mitigated because they would not be selected by buyers unless their price is below the mitigated price of the “must offer” requirement.[870] At the same time, EEI asserts that the mitigated seller would perpetuate its market power by increasing its capacity in the mitigated control area.[871]

755. Progress Energy and MidAmerican add that a “must offer” requirement would impede a mitigated seller's ability to fulfill its retail crediting obligations and to provide adequate and reliable service to its native load retail customers, which bear, through their retail rates, the fixed costs of the generation to serve them.[872]

756. Southern, Duke and others further suggest that a “must offer” requirement could undermine the required planning and operations processes of utility systems purchasing the “must offer” output.[873] They argue that a “must offer” requirement could bias shorter-term operating decisions where, for example, an LSE has the opportunity to purchase peak supply in real time at less than market prices, thereby avoiding incurring any fixed costs on a day-ahead basis to ensure peak supply availability.[874] They contend that this would eliminate incentives for the LSEs to plan to meet their resource needs and shift planning obligations at the expense of a mitigated utility's native load customers.[875]

757. Another commenter is also wary of a “must offer” requirement, reasoning that such a requirement is normally designed to mitigate physical withholding. This commenter states that it may work well in an organized power market where an independent operator ensures that the power is used to serve the local needs caused by reliability or local resource deficiency. However, without an independent operator, a “must offer” requirement may be more difficult to administer.[876] In advocating for separate market policies and tests for short- and long-term markets, this commenter prefers a price cap for short-term products rather than a “must offer” requirement, asserting that a price cap for short-term products is preferable to a “must offer” approach because it is more economically efficient, fair, and easier to administer.[877] For long-term products, this commenter takes the position that, “[i]n situations where a lack of long-term transmission and/or a lack of long-term supply alternatives exist, it is difficult to think of an Start Printed Page 39994alternative to full cost-of-service rates.” [878] They add that these cost-based rates should offer both fair prices and adequate investment returns to suppliers in the destination market with rate-of-return levels that fully enable incumbent suppliers to make appropriate investments to meet such cost-based obligations.[879]

758. Entergy raises a concern that in the NOPR the Commission erred by failing to define what constitutes available capacity. It asserts that there is difficulty in calculating available capacity because of uncertainty regarding: (1) Loads; (2) qualifying facility puts; (3) unit performance; and (4) fuel arrangements and prices.[880]

Commission Determination

759. After careful consideration of the arguments raised by commenters, we will not impose an across-the-board “must offer” requirement for mitigated sellers. While wholesale customer commenters have raised concerns relating to their ability to access needed power, we conclude that there is insufficient record evidence to support instituting a generic “must offer” requirement.

760. As discussed above, some commenters argue that undue discrimination occurs if a mitigated seller refuses to sell power to customers in the mitigated balancing authority area and instead sells that power at market-based rates to customers outside the mitigated balancing authority area. Some commenters also contend that it is unduly discriminatory for a mitigated seller to make market-based rate sales to competitive markets outside the mitigated balancing authority area when constraints on that seller's own transmission system prevent embedded customers from similarly accessing those markets as buyers. However, these commenters have not provided any evidence of specific instances in which the harms they identify have, or are, occurring. Without such evidence, we decline to impose a generic remedy such as a “must offer” requirement.

761. In National Fuel, the D.C. Circuit vacated a final rule of the Commission, Order No. 2004, as applicable to natural gas pipelines because of the expansion of the standards of conduct to include a new definition of energy affiliates. The court explained that the Commission relied on both theoretical grounds and on record evidence to justify this expansion. The court concluded that the Commission's record evidence did not withstand scrutiny and, thus, concluded the expansion was arbitrary and capricious in violation of the Administrative Procedure Act.[881] While the court left open the possibility of the Commission relying solely on a theoretical threat of abuse, it cautioned that if the Commission chooses to take that approach, “it will need to explain how the potential danger * * * unsupported by a record of abuse, justifies such costly prophylactic rules.” [882] In addition, the court said the Commission would need to explain why individual complaint procedures were insufficient to ensure against abuse.[883]

762. We find here that, although wholesale customer commenters have raised theoretical concerns that they will be unable to access power absent a “must offer” requirement, they have not provided any concrete examples of harm nor explained how the potential harm justifies the generic remedy they seek. Given the lack of evidence in the record that wholesale customers in mitigated markets will be unable to obtain power supplies at reasonable rates, we conclude that there is insufficient basis for instituting a generic “must offer” requirement. Indeed, the record includes evidence of utilities continuing to make cost-based sales after loss or surrender of market-based rate authority.[884]

763. In addition, consistent with the guidance provided in National Fuel, commenters advocating a generic “must offer” have not demonstrated that existing procedures and remedies under the FPA are inadequate to deal with specific cases that may arise. To the contrary, we find that there are potential remedies available on a case-by-case basis to a wholesale customer alleging undue discrimination or other unlawful behavior on the part of a mitigated seller. For example, a wholesale customer can file a complaint pursuant to section 206 of the FPA. It also can bring an action under section 202(b) of the FPA.[885] In addition, it can bring an action pursuant to the statutory prohibition in section 222 of the FPA against market manipulation.

764. While we do not impose a generic “must offer” requirement in this Final Rule, we do not rule out the possibility that we might find the imposition of a “must offer” requirement, or some other condition on the seller's market-based rate authority, to be an appropriate remedy in a particular case depending on the facts and circumstances, as we have done in the past.[886] We note that the Commission has previously imposed a “must offer” requirement as a condition of market-based rate authority for sellers in the California markets.[887] There, the record demonstrated a problem in a limited geographic area that warranted a “must offer” remedy to prevent unjust and unreasonable rates from being charged during certain times and under certain conditions. If a wholesale customer were to present specific evidence documenting that a transmission provider either denied the customer's request for transmission service, in violation of the OATT, or was unreasonably delaying responding to a request for transmission service, in violation of the OATT, we might find the imposition of a “must offer” requirement on a transmission provider to be an appropriate remedy.[888] As the Commission recently explained in Order No. 890, transmission providers must process requests for transmission service “as soon as reasonably practicable after receipt” of such requests [889] and must post performance metrics that are intended “to enhance the transparency of the study process and shed light on whether transmission providers are processing request studies in a non-discriminatory manner.” [890] Order No. 890 explained that “the revised pro forma OATT will greatly enhance our oversight and enforcement capabilities by increasing the transparency of many critical functions Start Printed Page 39995under the pro forma OATT, such as ATC calculation and transmission planning.” [891] Here too, we reiterate that the Commission “intends to use its enforcement powers with respect to the OATT in a fair and even-handed manner, pursuant to the principles set forth in the Policy Statement on Enforcement.” [892]

765. In addition to our conclusion that there is not sufficient record evidence to support the imposition of a generic “must offer” requirement, we are also concerned that adoption of a “must offer” requirement would present a number of difficult implementation and logistical problems.[893]

766. For example, given the difficulties associated with calculations of available transfer capability,[894] we foresee similar disputes over the calculation of available generation capacity were we to impose a generic “must offer” obligation. For instance, how far in advance should such calculations occur—one hour, one day, one month, or some other time frame? Would such calculations be derived on a generator specific basis or on a system basis (and how is transmission factored in)? Would the Commission or the industry need to develop a standard method of calculating available generation capacity? How would available generation capacity be allocated to potential purchasers?

767. We also are concerned that adopting a “must offer” requirement could harm other markets. For example, if a mitigated seller is required to offer its available power first to customers in the mitigated market, such a requirement may effectively preclude the mitigated seller from participating in adjoining markets particularly at times when additional supply is most needed (i.e., when prices in the adjoining market are high). Such a policy may serve to assist one set of customers at the expense of other customers that see their supply options reduced.

768. Parties have asserted that imposing a must offer requirement may discourage long-term planning, while others have disagreed with those arguments. Given that we do not impose any must offer obligation in this rule, we need not and do not address these arguments. If the Commission considers imposing a “must offer” requirement in an individual case, affected parties can raise these arguments at that time.

769. Though APPA/TAPS and the Carolina Agencies are correct that the Commission has previously imposed a “must offer” requirement as a condition of market-based rate authority for sellers in the California markets, as discussed above, that holding supports our approach here. There, the record demonstrated a problem in a limited geographic area that warranted a “must offer” remedy to prevent unjust and unreasonable rates from being charged during certain times and under certain conditions. By contrast, here APPA/TAPS and the Carolina Agencies urge us to impose a generic remedy on all mitigated sellers in all markets without a showing that there is a concrete problem justifying imposition of a “must offer” requirement in all markets.

770. Given that we have not adopted a “must offer” requirement in this Final Rule, we need not, and do not, address arguments asserting that we lack legal authority to do so. If the Commission should adopt any such requirement in an individual case, affected parties can raise any related legal arguments at that time and nothing in this rule precludes them from doing so.

771. For many of the same reasons that we decline to impose a “must offer” requirement, we also decline to adopt the “right of first refusal” requirement proposed by NRECA. Under this approach, a wholesale customer in the mitigated market would be given a right of refusal to purchase, at the market price, power that the mitigated seller proposes to sell outside the mitigated market. For the reasons provided above, there is insufficient record evidence to support imposition of such an across-the-board requirement.

772. A “right of first refusal” also would carry significant administrative burdens. Such an approach would invite disputes about what constitutes a legitimate offer by a third party to purchase power which establishes the basis for the offered rate. There also may be disputes if more than one wholesale customer wants to purchase the power in question. We are also concerned about the long-term viability of a rate setting that is based on mitigated sellers repeatedly negotiating tentative power sale arrangements with would-be buyers in first-tier markets only to have those offers withdrawn so the sale could be made to another buyer. Under such a regime, buyers from outside the mitigated market may be disinclined to invest resources to negotiate tentative contracts knowing that there is a significant chance that another buyer from within the mitigated market will usurp their position and instead get the sale.

773. There are also administrative concerns with how the Commission or third parties could be certain what the actual price and conditions of service would be for the sale in the first-tier market unless the contract was actually executed.

774. In response to NRECA's suggestion that an enforceable commitment to provide sufficient additional transmission import capacity to mitigate generation market power be considered as an alternative, the Commission notes that, consistent with the April 14 Order, a seller that fails one of the generation market power screens is allowed to propose alternative mitigation that the Commission may deem appropriate.[895] As a result, a mitigated seller could propose, as alternative mitigation, to provide additional transmission capacity by, for example, committing to relinquish transmission reservations or to physically upgrade the transmission grid.[896] The Commission would consider such proposals on a case-by-case basis. Moreover, a primary purpose of Order No. 890 is to “increase the ability of customers to access new generating resources and promote efficient utilization of transmission by requiring an open, transparent, and coordinated transmission planning process.” [897]

775. In particular, we believe recent actions we took in Order No. 890 address the Carolina Agencies' proposal that mitigated utilities be required to investigate and report on transmission expansion or other actions that could remove structural impediments exacerbating market power. In Order No. 890, the Commission adopted a number of reforms designed to mitigate transmission market power, including a requirement that all transmission providers develop a coordinated, open and transparent transmission planning process that would, among other things, enable customers to request studies evaluating potential upgrades or other investments that could reduce congestion or integrate new resources and loads.[898] The requests for these Start Printed Page 39996economic planning studies and the responses will be posted on the transmission provider's OASIS site, subject to confidentiality requirements.[899] We believe these steps may assist in reducing structural impediments that contribute to market power.

b. First-Tier Markets

Commission Proposal

776. In the NOPR, the Commission sought comment on whether it is appropriate to continue to allow sellers that are subject to mitigation in their home control area to sell power at market-based rates outside their control area. The Commission asked if this represents undue discrimination or otherwise constitutes “withholding” in the home control area that is inconsistent with the FPA's mandate that rates be just, reasonable and not unduly discriminatory, or, instead, if this reflects economically efficient behavior and encourages necessary trading within and across regions, particularly in peak periods when marginal prices rise above average embedded costs.

777. The Commission also asked if it should find that any seller that has lost market-based rate authority in its home control area should be precluded from selling power at market-based rates in adjacent (first tier) control areas.

Comments

778. A number of commenters state that there is no basis for prohibiting a mitigated seller from selling excess power at market-based rates in adjacent control areas, as the Commission will have determined that the seller does not have the ability to exercise market power in any of those adjacent control areas.[900] Some commenters also claim that prohibiting these sales would limit market activity and constrain the benefits of competitive pricing by excluding sellers from markets in which they do not possess market power.[901]

779. PNM/Tucson contends that prohibiting sales of available capacity at market-based rates in adjacent control areas where the seller does not possess market power would be a disproportionate response that would render the Commission's market-by-market analysis meaningless.[902] Moreover, PNM/Tucson and MidAmerican warn that independent power producers have no incentive to invest in new resources in markets where prices are effectively constrained to the level of another entity's embedded costs.[903]

780. Southern asks the Commission not to impose mitigation that will create flaws in markets that may have periods of genuine temporary scarcity but where the seller does not possess market power.[904] Southern states that prohibiting a mitigated seller from responding to price signals in neighboring markets will adversely affect efficient resource development and contradicts the Commission's desire to promote competitive markets and resource adequacy.[905] Further, foreclosing markets otherwise accessible to resources nominally dedicated to native load service may impair the optimization of those resources by impairing a full response to price signals. This, Southern adds, would harm native load customers because the mitigated utility would be unable to optimize surplus resources, as mandated through State retail credit obligations, thereby depriving retail customers of the benefits of system optimization.[906]

781. Another commenter agrees that a mitigated seller should be allowed to sell available capacity at market-based rates in markets where that seller does not possess market power, provided that this does not raise prices in the mitigated region.[907] This commenter asserts that such sales facilitate regional trading and market efficiency in developing competitive markets.[908] Another commenter contends that unless “costs” are defined in a way that effectively allows competitive market rates to be charged, revoking a seller's market-based rate authority in markets where the seller does not possess market power would reduce the mitigated seller's incentive to supply available power to the market, deprive the mitigated seller and its customers of legitimate economic rent, subsidize those buyers with access to the mitigated rates, and create a rationing problem among buyers with access to the mitigated-rate power.[909]

782. MidAmerican states that, if the Commission were to eliminate a seller's market-based rate authority in all regions, the mitigated prices should only apply prospectively. MidAmerican reasons that existing transactions negotiated in the absence of market power should not be altered, since these previously-negotiated transactions would have no impact on a seller's willingness to make future sales to customers in the home control area.[910]

783. Other commenters oppose allowing mitigated sellers to sell at market-based rates outside the home control area on the basis that it encourages and provides incentives for the seller to engage in physical or economic withholding of its generation output in the home control area. These commenters indicate that their concerns in this regard would be addressed if mitigation is combined with a requirement that the mitigated seller make power available to customers within the mitigated control area. APPA/TAPS state that, absent a “must offer” requirement, it is not clear that prohibiting mitigated sellers from making market-based sales outside their home control areas would necessarily prompt the mitigated seller to sell power in its home control area.[911]

784. However, APPA/TAPS ask the Commission not to rule out across-the-board revocation of market-based rate authority as it may be necessary to motivate mitigated sellers to undertake the kind of structural measures needed to mitigate market power on a long-term basis. If the Commission adopts a policy to revoke or condition market-based rate authority beyond the home control area, APPA/TAPS state that the policy should not be limited to just the first-tier control area. Rather, the revocation or conditions should apply to any market where the seller can use generation located in or originally delivered to its control area to sell outside that mitigated area.[912]

785. The Carolina Agencies state that a generic prohibition on market-based rate sales outside the mitigated market Start Printed Page 39997appears likely to inhibit regional trade to a greater extent than is necessary to protect the interests of embedded LSEs.[913] Both the Carolina Agencies and NC Towns state that there is no clear need to prohibit mitigated sellers from making market-based sales outside their home control areas if a “must offer” requirement is adopted.[914] According to the Carolina Agencies, a mitigated seller should be free to engage in market-based rate sales in other control areas as long as that utility has provided embedded LSEs a reasonable opportunity to purchase capacity and/or energy.

786. As to any claim that it would be unduly discriminatory for the Commission to deny or condition the market-based rate authority of a utility that passes the screens in markets beyond its mitigated home control area, APPA/TAPS and the Carolina Agencies submit that mitigated sellers are not similarly-situated to the other utilities selling at market-based rates in those other competitive markets. They assert that other sellers' market-based rate sales do not implicate those sellers' ability to withhold supply from disfavored wholesale customers in a mitigated control area. Moreover, they argue that it elevates the importance of the screens above the FPA to argue that granting unconditioned market-based rate authority to one seller who passes the screens obligates the Commission to grant unconditioned authority to all who pass the screens. In their view, the Commission would be failing its duty under the FPA if it permitted physical withholding by a dominant utility, as such actions would be unjust, unreasonable, and unduly discriminatory.[915]

787. ELCON advocates suspending any mitigated seller's market-based rates in all markets it can access. Short of this long-term fix, ELCON asserts that other proposals such as “must offer” requirements will be prone to fail because of likely unintended consequences.[916]

788. Morgan Stanley favors requiring mitigated sellers to post the mitigated price and other material terms on a publicly-available Web site for all sales to be made from the units that are part of the portfolio covered by the Commission's market power finding, regardless of where the actual sale sinks.[917] Morgan Stanley asserts that effective mitigation can only occur if it is imposed on all sales from a mitigated supplier's generation portfolio and urges the Commission not to focus on who the purchaser is or where the power sinks.[918] If a mitigated seller chooses to offer its excess power only outside the mitigated region and simply refuses to sell inside its home market, Morgan Stanley is concerned that the market in the “home” territory would be even less competitive than if the seller were allowed to sell there on an unmitigated basis.[919]

789. CAISO states that, where a competitive supply of imports into a mitigated control area does not exist, market power mitigation mechanisms or other incentive schemes will be necessary to ensure that the local supplier makes all of its capacity available to supply energy and ancillary services to the home control area.[920] CAISO asks the Commission to provide greater clarity on the extent to which the antifraud and anti-manipulation rules adopted in Order No. 670 prohibit economic and physical withholding of resources. In particular, CAISO asks the Commission to provide greater clarity on the deceptive conduct criteria it would use to determine whether a particular case of physical or economic withholding would be a violation of the new Part 47 regulations. CAISO explains that greater clarity in this area will help ISO and RTO market monitors in developing effective RTO/ISO market power mitigation rules tailored for the types of physical and economic withholding that are not addressed under Part 47 regulations.

Commission Determination

790. After careful consideration of the arguments raised by commenters, we will retain our current policy and limit mitigation to the market in which the seller has been found to possess, or chosen not to rebut the presumption of, market power. We will not place limitations on a mitigated seller's ability to sell at market-based rates in balancing authority areas in which the seller has not been found to have market power.

791. The Commission authorizes sales of electric energy at market-based rates if the seller and its affiliates do not have, or have adequately mitigated, horizontal and vertical market power in generation and transmission, and cannot erect other barriers to entry. As the Commission has explained, “The consideration of market power is important in determining if customers have genuine alternatives to buying the seller's product.” [921] Commenters favoring revocation of a mitigated seller's market-based rate authority in markets where there has been no finding of market power, as well as those supporting broadening mitigation to first-tier markets, have not provided a sufficient legal basis for such a policy. Where the record demonstrates that a seller does not have market power in a market, or has adequately mitigated any market power, the Commission has authorized such a seller to transact under market-based rates.[922] As the April 14 Order explained, “Market-based rates will not be revoked and cost-based rates will not be imposed until there has been a Commission order making a definitive finding that the applicant has market power * * *” [923]

792. We recognize that wholesale customer commenters are generally concerned that allowing mitigated sellers to sell outside their mitigated markets at market-based rates could encourage such sellers not to offer generation for sale within the mitigated market. However, we agree with the Carolina Agencies that a generic prohibition against such sales could inhibit regional trade to a greater extent than necessary to protect captive LSEs. We note that even some wholesale customer commenters acknowledge that it is not clear that prohibiting mitigated sellers from making market-based sales beyond their mitigated region would prompt the mitigated seller to sell power in the mitigated market. For these reasons, we limit mitigation to the areas in which the seller has market power.

793. For the reasons stated above, we disagree with Morgan Stanley's assertion that effective mitigation can only occur if it is imposed on all sales from a mitigated seller's generation portfolio. In addition, though we appreciate CAISO's request for greater clarity on the criteria the Commission Start Printed Page 39998will use to determine whether economic and physical withholding has occurred, such a determination must be made on a case-by-case basis.

c. Sales That Sink in Unmitigated Markets

Commission Proposal

794. In the NOPR, the Commission stated that some companies have proposed limiting mitigation to sales that “sink in” the mitigated market, that is, so that mitigation would only apply to end users in the mitigated market. However, in MidAmerican Energy Company,[924] the Commission stated that limiting mitigation to sales that “sink in” the mitigated market would improperly limit mitigation to certain sales, namely, only to sales to buyers that serve end-use customers in the mitigated market. The Commission reasoned that limiting mitigation in this manner would improperly allow market-based rate sales within the mitigated market to entities that do not serve end-use customers in the mitigated market.[925] The Commission stated that such a limitation would not mitigate the seller's ability to attempt to exercise market power over sales in the mitigated market and is inconsistent with the Commission's direction in the April 14 and July 8 Orders. On rehearing of the April 14 Order, it was argued that access to power sold under mitigated prices should be restricted to buyers serving end-use customers within the relevant geographic market in which the seller has been found to have market power. In particular, arguments were made that a seller should not be required to make sales at mitigated prices to power marketers or brokers without end-use customers in the relevant market. In the July 8 Order, the Commission rejected the suggestion that mitigated sellers be restricted to selling power only to buyers serving end-use customers, and has since rejected tariff language that proposes to do so.

795. In the NOPR, the Commission sought comment on whether it should modify or revise its current policy. The Commission sought comment on whether and, if so, how it should allow market-based rate sales by a mitigated seller within a mitigated market if those sales do not “sink” in that control area.

Comments

796. While some commenters generally seek to allow a mitigated seller to make sales at market-based rates if those sales do not “sink” in the mitigated market, other commenters support the current policy of requiring all of a mitigated supplier's sales in the mitigated market to be cost-based. The State AGs and Advocates go even further and encourage the Commission to apply its mitigation policy to all wholesale sales that sink in the mitigated market, regardless of the seller, arguing that the impact of market power on price is market-wide in scope.[926]

797. APPA/TAPS support the current policy of requiring cost-based rate mitigation for all sales in the mitigated market regardless of whether the sales ultimately sink in an unmitigated market. APPA/TAPS argue that allowing market-based rate sales in a mitigated market would yield unlawful rates because the mitigated seller would be making market-based rate sales in a market where it has, or is presumed to have, market power.[927]

798. The NYISO agrees that mitigation should not be limited to sales that “sink in” the mitigated market, at least in clearing price auctions such as those administered by the NYISO. The clearing prices are established by the interaction of all eligible buyers and sellers, and the NYISO reasons that there would be no practical basis, nor economic justification, for carving out marketers or brokers who may export their purchases.[928]

799. The Carolina Agencies express concern that limiting mitigation to sales that sink in a mitigated market would reduce supply options for LSEs embedded in that mitigated market. They contend that unrestricted exports from a mitigated market increase the prices charged by other sellers due to scarcity. Even when a sale sinks outside the mitigated market, the Carolina Agencies claim that round-trip gaming will continue, and they question the Commission's ability to effectively detect and stop such gaming by attempting to trace megawatts via NERC tag data or other means. However, the Carolina Agencies submit that with a properly structured “must offer” requirement in place, there is no reason to bar market-based rate sales based on the location of the point of sale or even the identified sink.[929]

800. Other commenters support allowing sales of power within a mitigated market that nonetheless sink in unmitigated markets (i.e., markets where the seller does not possess market power) to be made at market-based rates.[930] As discussed below, they offer various proposals on what factors should determine whether a sale should be priced at market-based rates.

801. Several commenters state that the relevant inquiry should be whether the power serves load (sinks) in a control area where generation market power is an issue. MidAmerican and the Oregon Commission submit that there is no reason to mitigate sales over which the seller is unable to exercise market power.[931] Rather, MidAmerican asks the Commission to refocus on whether a seller could exercise market power, not on the physical location where a change in ownership of energy occurs. MidAmerican argues that if a mitigated seller cannot exercise market power over sales made directly in an outside competitive market, such seller cannot exercise market power over sales made in its home control area that are for export to that outside competitive market.[932] Rather than protecting the ultimate buyers, these commenters submit that mitigating such sales would transfer wealth from the mitigated seller to subsequent entities that can charge market prices in later transactions.[933]

802. MidAmerican and the Oregon Commission claim that if the Commission requires mitigated sellers to mitigate all their sales in the mitigated market such an outcome would encourage gaming, such as round-trip or ricochet transactions.[934] MidAmerican maintains that such gaming can be eliminated when mitigation applies only to sales sinking within the mitigated control area.[935]

803. Duke, E.ON U.S., Westar, Mid-American, Ameren, and Xcel all assert that the availability of supply alternatives to wholesale purchasers should be a determining factor when deciding whether to permit market-based rates for sales that sink in Start Printed Page 39999unmitigated markets.[936] E.ON U.S. points out that the Commission in the April 14 Order noted that the foundation of the market power analysis under the Delivered Price Test is the “destination market.” As such, E.ON U.S. asserts that a relevant factor in determining whether to permit a sale at market-based rates should be the level of choice in supply available to the purchaser, not where the product originates.[937]

804. Westar contends that when the buyer is purchasing to serve load in control areas where the seller lacks market power, the buyer presumably has access to other competitive alternatives and has voluntarily entered into the agreement. Therefore, the Commission should not second guess the buyer's decision.[938] Westar adds that prohibiting all sales in the mitigated control area elevates form over substance because parties can simply alter the implementing details of their transaction to accomplish the same result.[939]

805. Westar argues that the Commission's stated concern in MidAmerican with a seller's “ability to attempt to exercise market power over sales in its control area” is misplaced; the Commission's traditional market power analysis is only concerned with the “incentive” and “ability” to exercise market power, not with “attempts” to do so.[940] As such, it is “ability” and not “attempts” to exercise market power that is a key determinant of whether an actual market power problem exists.

806. Westar further claims that the Commission is not bound by precedent to prohibit all market-based rate sales in a mitigated control area, pointing out that the Commission has accepted four proposals after the July 8 Order that limit mitigation to sales that sink in the mitigated control areas.[941] Moreover, Westar claims that the July 8 Order appears to address the question of who may buy power from a mitigated seller, not where mitigated sales can occur. This leads Westar to conclude that the Commission did not originally intend to preclude mitigated sellers from making market-based sales to buyers over which the seller lacks generation market power, regardless of where the sales occur. Westar urges the Commission to return to this principle.[942]

807. Xcel urges the Commission to focus on the parties' intent and whether alternative supply options are available to the purchaser at the time of contracting, rather than focusing on where energy purchased in the transaction actually sinks in real time. At the time of the transaction, if the purchaser can confirm: (i) It intends to use the power outside of the mitigated control area, and (ii) there are existing transmission arrangements to actually use the power elsewhere, Xcel maintains that it should not matter what the purchaser subsequently does with the power in real time.[943] Xcel and MidAmerican also favor adopting market-index or proxy based mitigation as a way to reduce the concern about where sales actually sink when trying to ensure proper mitigation.[944]

808. EEI, PPL, PNM/Tucson, and Pinnacle take the position that the Commission should consider point of delivery when deciding whether to permit market-based rate sales.[945] EEI asks the Commission to allow mitigated sellers to make market-based rate sales if the delivery point in the contract or sale confirmation is outside the mitigated market, or if the buyer has transmission service to take the power outside the mitigated market. In other words, buyers who choose delivery points inside the mitigated market and do not move the power out will pay mitigated rates, but buyers who choose delivery points inside the mitigated market but move the power outside the mitigated market will pay market-based rates.[946]

809. EEI asserts that its proposal is consistent with the Commission policy that the mitigation must focus on the geographic market that is mitigated, not the type of customer purchasing the power. EEI concludes that the proposal will minimize the impacts on competitive transactions as well as avoid a remedy that will have a negative impact on the liquidity of the competitive market.[947]

810. PNM/Tucson agree that the Commission should use the point of delivery as a determining factor. They contend that transmission tags alone—which they explain are a reliability tool to ensure systems balance from a transmission perspective—are inadequate to monitor market transactions or ensure that sales sink outside a mitigated control area.[948]

811. PNM/Tucson, Pinnacle, E.ON U.S., MidAmerican and PPL all generally argue that sales at or beyond the transmission interface of a mitigated control area should not be mitigated if the seller lacks market power in the adjacent control area.[949] MidAmerican asserts that the Commission's market power analyses demonstrate that the seller has no market power over sales at the border (sales requiring no additional transmission to exit the mitigated region).[950] PNM/Tucson, Pinnacle and E.ON U.S. maintain that prohibiting market-based rate sales at these transmission interfaces would prevent cross border sales at these unique locations and reduce market liquidity in markets where the seller does not possess market power.[951]

812. E.ON U.S. and MidAmerican urge the Commission to view interface/border transactions as fundamentally different from sales in, or sinking in, a control area. These commenters reason that, at transmission interfaces, a buyer has competitive choices from sellers in both control areas that abut the interface, as well as from any seller that can transmit power to that interface from any control area. As a result, buyers taking title to power at a Start Printed Page 40000transmission interface for delivery outside the mitigated control area have competitive choices that do not require transacting with the supplier found to have market power within the mitigated control area(s).[952] Moreover, E.ON U.S. claims that mitigating transactions at control area interfaces could reduce a utility's profits from off-system sales, thereby affecting retail ratepayers by reducing offsets that affect the costs of their retail rates.[953]

813. PNM/Tucson, Pinnacle, E.ON U.S., and MidAmerican note that the Commission indicated in LG&E that sales at the border need not be mitigated along with sales “wholly in” a control area.[954] PNM/Tucson and MidAmerican urge the Commission to codify in the Final Rule LG&E's holding that sales at the transmission interface of a mitigated control area are not “in” the control area, and therefore need not be mitigated.[955] E.ON U.S. similarly asks the Commission to define sales “in” a control area as those where title to power transfers at a physical location wholly within such control area, and should not include sales where title transfers at a transmission interface.[956]

814. Xcel, in comparison, argues that any buyer purchasing power at a generator bus or elsewhere in a mitigated control area for purposes of moving that power out of the mitigated market should be treated no differently than a buyer who takes delivery of purchased power outside of the mitigated region. According to Xcel, mitigation to discipline market power is unnecessary in either of these cases and the location of the delivery point does not matter.[957]

815. Both Dalton Utilities and the Carolina Agencies state that it would be wrong to assume that every contract involving a mitigated supplier is unjust and unreasonable and must be abrogated to protect consumers.[958] Dalton Utilities urge the Commission to clearly state in the final rule that it does not generically abrogate existing long-term market-based rate wholesale requirements and transmission contracts, nor is it requiring such abrogation in subsequent proceedings that revoke the market-based rate authority of a public utility found to possess market power.[959] Dalton Utilities asks the Commission to grandfather existing long-term market-based wholesale contracts in the final rule.[960]

816. The Carolina Agencies add that the effect on existing contracts of a decision to retain the current mitigation policy of prohibiting sales at market-based rates in a mitigated market should be determined on a case-by-case basis. These entities reason that simply because market power may exist (or a presumption that it exists has not been rebutted) does not in every instance mean that the seller actually abused its market position to extract unreasonable terms from its purchaser. The circumstances of each contract must be examined to determine whether its terms reflect the exercise of market power. The Carolina Agencies and Dalton Utilities conclude that generic abrogation or reformation of existing agreements is neither warranted nor consistent with the Commission's manner of resolving other claims of broad-based discrimination.[961]

Commission Determination

817. In order to protect customers from market power concerns, we will continue to apply mitigation to all sales in the balancing authority area in which a seller is found, or presumed, to have market power. However, as discussed below we will allow mitigated sellers to make market-based rate sales at the metered boundary [962] between a mitigated balancing authority area and a balancing authority area in which the seller has market-based rate authority under certain circumstances.

818. Commenters advocating allowing market-based rate sales in a mitigated market provided the power is intended for an unmitigated market (e.g., applying mitigation only to sales that sink in the mitigated market) have failed to adequately explain how customers in the mitigated market would be protected from the potential exercise of market power. In addition, commenters have failed to adequately address how the Commission could effectively monitor such sales to ensure that improper sales were not being made. Indeed, several commenters have noted the complex administrative problems that would be associated with trying to monitor compliance with such a policy.[963]

819. Allowing market-based rate sales by a seller that has been found to have market power, or has so conceded, in the very market in which market power is a concern is inconsistent with the Commission's responsibility under the FPA to ensure that rates are just and reasonable and not unduly discriminatory. While we generally agree that it is desirable to allow market-based rate sales into markets where the seller has not been found to have market power, we do not agree that it is reasonable to allow a mitigated seller to make market-based rate sales anywhere within a mitigated market. It is unrealistic to believe that sales made anywhere in a balancing authority area can be traced to ensure that no improper sales are taking place. Such an approach would also place customers and competitors at an unreasonable disadvantage because the mitigated seller has dominance in the very market in which it is making market-based rate sales.

820. However, we do recognize that sales made at the metered boundary for export do lend themselves to being monitored for compliance, and the nature of these types of sales do not unduly disadvantage customers or competitors. Prohibiting market-based rate sales at these metered boundaries of the balancing authority area could prevent or adversely impact cross border sales at these unique locations and reduce market liquidity in markets where the seller does not possess market power. Buyers taking title to power at a metered boundary for delivery to serve load in a balancing authority area where the seller has market-based rate authority have competitive choices and therefore are not required to transact with the seller found to have market power within the mitigated balancing authority area(s).

821. Accordingly, we will allow such sales to be made at market-based rates. Mitigated sellers making such sales must maintain for a period of five years from the date of the sale all data and information related to the sale that demonstrates that the sale was made at the metered boundary between the mitigated balancing authority area and a balancing authority area in which the seller has market-based rate authority, that the sale is not intended to serve load in the seller's mitigated market, Start Printed Page 40001and that no affiliate of the mitigated seller will sell the same power back into the mitigated seller's mitigated market.

822. Such an approach properly balances commenters' concerns that when a buyer purchases power to serve load in markets where the mitigated seller lacks market power the buyer has access to competitive alternatives with the Commission's obligation under the FPA to ensure that rates are just and reasonable. Further, we find that our approach in this regard does not place an unreasonable burden on the customer, mitigated seller, or competitors. We also emphasize that the mitigation we adopt herein is prospective only. In response to Dalton's concern, we clarify that such mitigation does not modify, abrogate, or otherwise affect existing contractual agreements.[964]

823. Further, we disagree with the Carolina Agencies' contention that short of a “must-offer” provision unrestricted exports from a mitigated market increase the prices charged by other suppliers due to scarcity. Carolina Agencies' argument would only apply when the market prices in the first-tier markets are higher than the seller's cost-based rate in the mitigated market. This situation is not necessarily always the case and, therefore, the Carolina Agencies' concern may be based on an unrealistic assumption.

824. We disagree with MidAmerican and the Oregon Commission's claim that if the Commission requires mitigated sellers to mitigate all their sales in the mitigated market this would encourage gaming, such as round-trip or ricochet transactions. While the Commission issued an order rescinding Market Behavior Rules 2 and 6,[965] Order No. 670 finalized regulations prohibiting energy market manipulation pursuant to the Commission's new Energy Policy Act of 2005 authority. The Commission emphasized in Order No. 670 that “the specific prohibitions of Market Behavior Rule 2 (wash trades, transactions predicated on submitting false information, transactions creating and relieving artificial congestion, and collusion for the purpose of market manipulation), * * * are examples of prohibited manipulation, all of which are manipulative or deceptive devices or contrivances, and are therefore prohibited activities under this Final Rule, subject to punitive and remedial action.” [966] Such fraud and manipulative conduct therefore remains prohibited and subject to the Commission's anti-manipulation and civil penalty authority.

d. Proposed Tariff Language

Comments

825. Several commenters have proposed specific tariff language in the event the Commission allows market-based rate sales in the mitigated market or at the border. For example, PNM/Tucson would require a sale to “have a contractual point of delivery at or beyond the transmission interface of the mitigated control area (assuming that the point of delivery is not in another control area where the seller is also mitigated).” [967] They would also require the seller's market-based rate tariff to explicitly prohibit efforts to collude with a third party to sell to customers in the mitigated control area at market-based rates.[968]

826. PNM/Tucson point out that their proposal contains a significant concession. Under their proposed language, a sale by a mitigated seller at the generation bus in the mitigated control area must be made at mitigated rates. They believe this concession is fair if the Commission insists that market-based rate sales for mitigated sellers are based on contractual points of delivery at or beyond the transmission interface of the mitigated control area. In these companies' view, such an approach would provide needed certainty through a bright line rule and limit factual disputes and investigations.[969]

827. MidAmerican and Ameren also support using tariff or agreement language to ensure power sinks outside of the mitigated market.[970] MidAmerican favors using tariff safeguards and confirmation/oversight procedures to mitigate a seller's ability to exercise generation market power, prevent gaming, and protect wholesale customers in the mitigated region. MidAmerican submits that it has developed and filed market-based rate tariff provisions and verification and oversight procedures that can ensure that export transactions sink outside the mitigated seller's control area.[971] MidAmerican argues that its approach correctly focuses on whether the mitigated seller could exercise market power over transactions that affect entities that purchase on behalf of, or for re-sale to, loads within the market subject to mitigation, rather than the geographical location where customers may take responsibility for transmitting the power to a final destination. Moreover, MidAmerican claims that its proposal would allow the market to work efficiently in areas where the mitigated seller's ability to exercise market power is not an issue. MidAmerican supports a Commission technical conference to further explore this concept with interested parties.[972]

828. Several commenters further propose that mitigated sellers be required to add language to their market-based rate tariffs or to specific market-based rate contracts to restrict re-sales from sinking in the mitigated control area.[973] FP&L argues that requiring such language would reinforce the idea that re-sales into mitigated control areas are violations of a Commission-approved tariff that also, depending on the facts, might violate the Commission's market manipulation regulations.[974]

829. Another commenter agrees that restrictive language in the market-based rate tariff could prevent re-sales into the mitigated control area by helping to ensure that any power purchased at market-based rates within a mitigated control area is exclusively for export to serve loads beyond the mitigated market. Where the Commission is concerned that gaming could lead to the Start Printed Page 40002exercise of market power over wholesale customers in the home control area, this commenter suggests that the Commission reemphasize that efforts to loop power through an adjacent market area in order to raise prices to wholesale customers in mitigated areas above competitive levels is a violation of market-based rate tariffs. Further, this commenter submits that the Commission may require buyers to confirm that power purchased at market-based rates in a mitigated control area is for export, use NERC tag data and transmission scheduling information to verify when purchased power is being exported from the home control area, and require oversight by independent market monitors.[975]

Commission Determination

830. Consistent with our decision above, mitigated sellers choosing to make market-based rate sales at the metered boundary