Supporting Statement Rm04-7fr

41

FERC-(516), RM04-7-000 Final Rule Issued June 22, 2007

SUPPORTING STATEMENT FOR

FERC-516 Electric Rate Schedule Filings,

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

In Docket No. RM04-7-000 (Final Rule)

The Federal Energy Regulatory Commission (FERC, Commission),

Requests Office of Management and Budget (OMB) review and approval of an information collection requirement. At the Notice of Proposed Rulemaking (NOPR) stage, FERC-516 was pending OMB review in another rulemaking and so the Commission designated the FERC-516 requirements in this proceeding as FERC-919(516), Electric Rate Schedule Filings. The NOPR was designated as a new Information Collection Request (ICR) and OMB designated it as 2006-1902-004.

However, as FERC-516 is currently not the subject of OMB review, the Commission intends to add the hours associated with this final rule to the hours associated with FERC-516 and reported in OMB’s inventory ROCIS under the control number 1902-0096. The Final Rule adds 71,210 hours to 438,921 hours reported in OMB’s inventory for a total of 510,131 hours. FERC-516 (1902-0096) is currently approved through May 31, 2010.

In this Final Rule, FERC 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 in accordance with 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.  FERC also proposes to streamline aspects of its filing requirements to reduce the administrative burdens on applicants, customers and on FERC.

Background

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.

The courts have reviewed the Commission’s market-based rate program and found that it satisfies the FPA. The FPA requires that all rates demanded by public utilities for the sale of electric energy at wholesale be found “just and reasonable.”¹ The United States Supreme Court has explained that the just and reasonable standard “does not compel the Commission to use any single pricing formula.”² The United States Court of Appeals for the D.C. Circuit has long held that “when there is a competitive market the [Commission] may rely upon market-based prices in lieu of cost-of-service regulation to assure a ‘just and reasonable’ result.”³ The Commission’s authorization of market-based rates has been found to satisfy the just and reasonable standard of the FPA.⁴

The Commission initiated the instant rulemaking proceeding in April 2004 to consider “the adequacy of the current four-prong analysis and whether and how it should be modified to assure that prices for electric power being sold under market-based rates are just and reasonable under the Federal Power Act.”⁵ At that time, the Commission noted that much has changed in the industry since the four-prong analysis was first developed and posed a number of questions that would be explored through a series of technical conferences. The comments from those technical conferences were considered when drafting the NOPR.

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.⁶ The April 14 Order adopted a policy that would provide sellers a number of procedural options, including two indicative generation market power screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis), and the option of proposing mitigation tailored to the particular circumstances of the seller that would eliminate the ability to exercise market power. The order also explained that sellers could choose to adopt cost-based rates.

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

NOPR (Docket No. RM04-7-000)

On May 19, 2006, in Docket No. RM04-7-0000, the Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to adopt in most respects the Commission’s current standards for granting market-based rates. The Commission believed that these standards have, with the exceptions noted below, allowed the Commission to distinguish between applicants that have market power and those that do not. For example, the current interim horizontal (generation) market power screens have allowed the Commission to identify a number of smaller applicants that do not have generation market power. The Commission authorized these applicants to obtain or retain market-based rate authority, which benefits customers by encouraging new entry and by providing them with the greater flexibility in product offerings that market-based rate approval conveys. The current screens also have allowed the Commission to more accurately identify instances where certain larger sellers may possess market power. If an applicant fails the Commission’s screens, this does not, however, constitute a definitive finding of market power. Rather, the Commission’s current standards allow any applicant that fails these screens to demonstrate that it lacks market power in generation using the delivered price test (DPT).⁷ The DPT has provided appropriate flexibility in allowing the Commission to consider the differing factual situations of particular sellers, such as those that have a responsibility for serving native load customers. The Commission proposes to continue to apply the DPT in such a flexible manner.

In cases where the applicant has failed the DPT, or has otherwise chosen to adopt default cost-based mitigation or to propose other cost-based mitigation (e.g., cost-based rates) or tailored mitigation, FERC’s current policies protect customers by ensuring that applicants with market power in a given area have that market power mitigated. The Commission recognizes, however, that there has been uncertainty regarding the rate methodologies to use in developing cost-based market power mitigation and the effectiveness of the existing cost-based mitigation. The Commission sought comment in the NOPR on several issues relating to cost-based market power mitigation, including:

(i) whether there should be a standard methodology for determining cost-based ceiling rates and the appropriate methodology for sales of less than one week;

(ii) whether selective discounting should be allowed for sellers that have been found to have market power, or that accept a presumption of market power, and are offering power under cost-based rates; and

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

The Commission also proposed certain modifications to the horizontal (generation) market power screens to reflect its experience in applying them and the comments received in this proceeding. First, the Commission proposed to modify the treatment of newly-constructed generation to avoid a situation in which all generation becomes exempt from its market power analyses as new generation is constructed and older (pre-1996) generation is retired. Second, although the Commission proposed to retain the default relevant geographic market (control area); it provided guidance as to the factors the Commission will consider in evaluating whether, in a particular case, to adopt an expanded geographic market instead of relying on the default geographic market. Third, the Commission proposed to change the native load proxy for the market share screens from the minimum peak day in the season to the average peak native load, averaged across all days in the season, and to clarify that native load can only include load attributable to native load customers as that term is defined in section 33.3(d)(4)(i) of the Commission’s regulations.⁸ Fourth, the Commission proposed to allow applicants the option of using seasonal capacity instead of nameplate capacity,⁹ and to retain the snapshot in time approach for the screens but to allow “known and measurable” changes (sometimes referred to as foreseeable and reasonably certain at the time of filing) for the DPT.

With regard to vertical market power and, in particular, transmission market power, the Commission proposed to continue the current policy under which an open access transmission tariff (OATT) is deemed to mitigate a seller’s transmission market power.¹⁰ However, in recognition of the fact that OATT violations may nonetheless occur, the Commission proposed that violation(s) of the OATT may be cause to revoke market-based rate authority in addition to any other applicable remedies, such as civil penalties. The Commission also noted that concerns regarding the adequacy of the current OATT were being addressed in Docket No. RM05-25-000, Preventing Undue Discrimination and Preference in Transmission Service. The Commission issued simultaneously with this NOPR, a separate NOPR RM05-25-000 as noted above, to reform the OATT.

Concerning vertical market power and, in particular, other barriers to entry, the Commission proposed to continue its current approach but provide clarification of what types of factors it would examine and the Commission proposed to combine the other barriers to entry analysis with the rest of its vertical market power analysis.

For affiliate abuse, the Commission proposed to discontinue referring to affiliate abuse as a separate “prong” of its analysis and instead proposes to codify in its regulations an explicit requirement that any seller with market-based rate authority must comply with the affiliate sales restrictions and other affiliate provisions.¹¹ 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 proposed to retain its policy that sales of power between a franchised public utility and any of its non-regulated power sales affiliates¹² must be pre-approved by the Commission. To demonstrate that an affiliate sale is just, reasonable and not unduly discriminatory, an applicant has several options, including pricing that sale at a market index meets certain standards, conducting an auction that reflects certain guidelines, or otherwise meeting the standards set forth in Edgar.¹³ An affiliate sale that has not been pre-approved under these standards will constitute a tariff violation. In addition, the Commission reaffirmed that it currently requires that sales made under market-based rate tariffs, including those made to affiliates, must be reported in an Electric Quarterly Report (EQR).

With regard to affiliate transactions under a market-based rate tariff, the Commission reaffirmed that it either grant or deny authorization to make affiliate sales. To the extent that the Commission authorizes an affiliate transaction, it reaffirmed that, consistent with the Commission’s regulations,¹⁴ any such agreement shall not be filed with the Commission.

The Commission also proposed certain reforms to streamline the administration of the market-based rate program. The Commission also proposed several changes and clarifications. Significant areas of modification involved the three-year updated market power analysis (triennial review or updated market power analysis) that all sellers with market-based rate authority are required to file, and the development of a market-based rate tariff of general applicability.

With regard to updated market power analyses, the Commission’s current general practice is to require an updated market power analysis to be submitted within three years from the date of the Commission order granting the seller market-based rate authority or accepting the previous triennial review. The Commission proposed to modify that general practice and put in place a structured, systematic review to assist the Commission in analyzing sellers in markets based on a coherent and consistent set of data. In particular, the Commission proposed to modify the requirements for filing updated market power analyses in two ways. First, the Commission proposed to establish two categories of sellers with market-based rate authorization. The first category, Category 1 (approximated as 550 sellers), would consist of power marketers and power producers that own or control 500 MW or less of generating capacity in aggregate and that are not affiliated with a public utility with a franchised service territory. In addition, Category 1 sellers must not own or control transmission facilities, other than limited equipment necessary to connect individual generating facilities to the transmission grid, (or must have been granted waiver of the requirements of Order No. 888 because such facilities are limited and discrete and do not constitute an integrated grid)¹⁵ and must present no other vertical market power issues. Category 1 sellers would not be required to file a regularly scheduled triennial review. The Commission would monitor any market power concerns for these sellers through the change in status reporting requirement,¹⁶ and through ongoing monitoring by the Commission’s Office of Enforcement.

The second category, Category 2 (approximated as 600 sellers), would include all sellers that do not qualify for Category 1. Category 2 sellers, in addition to the change in status reports, would be required to file regularly scheduled triennial reviews.¹⁷ To ensure greater consistency in the data used to evaluate Category 2 sellers, the Commission proposed to require each Category 2 seller to file updated market power analyses for its relevant geographic markets (default and any proposed alternative markets) on a schedule that would allow examination of the individual seller at the same time that the Commission examines other sellers in these relevant markets and contiguous markets within a region from which power could be imported. The Commission would continue to make findings on an individual seller basis, but would have before it a complete picture of the uncommitted capacity and simultaneous import capability into the relevant geographic markets under review.

A second significant change was the Commission’s proposal to adopt a market-based rate tariff of general applicability (MBR tariff), applicable to all sellers authorized to sell electric energy, capacity or ancillary services at wholesale at market-based rates. Further, the Commission proposed that, rather than each entity having its own MBR tariff, which can result in dozens of tariffs for each corporate family with potentially conflicting provisions, each corporate family would have only one tariff, with all affiliates with market-based rate authority separately identified in the tariff. This would reduce the administrative burden and confusion that occurs when there are multiple, and potentially conflicting, tariffs in a single corporate family. FERC’s intent to streamline the terms of an MBR tariff is not to reduce the flexibility of sellers and customers in negotiating the terms of individual transactions. Rather, this flexibility will continue to exist. The purpose of a tariff of general applicability that requires the seller to comply with the applicable provisions of the market-based rate regulations is simply to codify, on a consistent basis, the basic requirements of market-based rate authorization.

Final Rule (Docket No. RM04-7-000)

On June 21, 2007, in Docket No. RM04-7-0000, the Commission issued a Final Rule that revises and codifies the Commission’s regulations for 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. The Final Rule adopts in many respects the proposals contained in the NOPR as noted above, but with a number of modifications.

Horizontal Market Power

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).

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 the Commission provides guidance as to how it will consider jointly-owned facilities.

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 an applicant’s control area (balancing authority area) 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.

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, applicants are given the option of using seasonal capacity instead of nameplate capacity.

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 reporting form is adopted to provide sellers a standard form on which to summarize their analysis.

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.

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.

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

Vertical Market Power

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.

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 coal supplies and the transportation of coal supplies such as barges and rail cars does not allow an applicant 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 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

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 set forth 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 non-regulated power sales affiliates without first receiving Commission authorization for the transaction under § 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 the 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 standards of conduct. 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-power sales affiliates.”

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

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.¹⁸ The Commission will continue to allow applicants 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. 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.

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 § 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.

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.

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.

Finally, regarding mitigation, the Final Rule allows mitigated sellers to make market-based rate sales at the transmission interface between a mitigated market and a market in which the seller has market-based rate authority under certain circumstances, including a record retention requirement, and provides a tariff provision to allow for such sales.

Implementation Process

The Commission is adopting 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.

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.

Miscellaneous Issues

The Commission also provides clarifications in the Final Rule with regard to accounting waivers, 18 CFR 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.

6040. JUSTIFICATION

5328. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY

Section 205(c) of the FPA requires that every public utility have all of its jurisdictional rates and tariffs on file with the Commission and make them available for public inspection, within such time and in such form as the Commission may designate. Section 205(d) of the FPA requires that every public utility must provide notice to FERC and the public of any changes to its jurisdictional rates and tariffs, file such changes with FERC, and make them available for public inspection, in such manner as directed by the Commission. In addition, FPA section 206 requires FERC, upon complaint or its own motion, to modify existing rates or services that are found to be unjust, unreasonable, unduly discriminatory pr preferential. FPA section 207 further requires the Commission upon complaint by a state commission and a finding of insufficient interstate service, to order the rendering of adequate interstate service by public utilities, the rates for which would be filed in accordance with FPA sections 205 and 206.

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

5329. HOW, BY WHOM, AND FOR WHAT PURPOSE THE INFORMATION IS TO BE USED AND THE CONSEQUENCES OF NOT COLLECTING THE INFORMATION

The Commission had previously required utilities seeking market-based rate authority to file market power analysis and now in this final rule the Commission is codifying that requirement in its regulations. Section 35.27(a) of the Commission’s regulations currently provides that any public utility seeking market-based rate authority is not required to submit a generation market power analysis with respect to sales from capacity for which construction commenced on or after July 9, 1996. Under existing procedures, if all of the generation owned or controlled by an applicant for market-based rate authority and its affiliates in the relevant control area is post-July 9, 1996 generation, the applicant is not require to submit generation market power analysis. In the NOPR, the Commission proposed to eliminate the express exemption provided in section 35.27(a). This modification as adopted in the final rule will require that all new applicants seeking market-based rate authority on or after the effective date of the final rule, whether or not all of their and their affiliates’ generation was built or acquired after July 9, 1996, must provide a market power analysis of their generation to support their application for market-based rate authority.

The Federal Power Act (FPA) requires that all rates charged by public utilities for the transmission or sale for resale of electric energy be just and reasonable.¹⁹ Thus, where a market-based rate seller is found to have market power in generation (e.g., after reviewing a seller’s DPT), it is incumbent upon the Commission to either reject such rates or to ensure that adequate mitigation measures are in place to ensure that the rates are just and reasonable. The Commission provides default cost-based rates to ensure that wholesale rates are just and reasonable. If a seller does not pass the generation market power screens, or foregoes the screens entirely, the Commission sets the just and reasonable rate at the default cost-based rate unless it approves different mitigation based on case-specific circumstances.

For sellers that have a presumption of market power in generation (e.g. those failing one or both of the indicative screens), the Commission will institute a section 206 proceeding and the seller’s rates will prospectively be made subject to refund.²⁰ For sellers already charging market-based rates, market-based rates will not be revoked and cost-based rates will not be imposed until the Commission issues an order making a definitive finding that the seller has market power in generation (typically, after the Commission has ruled on a DPT analysis) or, where the seller accepts a presumption of market power, an order is issued addressing whether default cost-based rates or case-specific cost-based rates are to be applied. The Commission will revoke the market-based rate authority in all geographic markets where a seller is found to have market power in generation.²¹

Market Power Analyses: Consistent with current practice, the market power analysis helps inform the Commission as to whether an entity seeking market-based rate authority lacks market power, and whether sales by that entity will be just and reasonable.

Market-Based Rate Tariff: Market-based rate tariffs with standard provisions will improve the efficiency of the Commission in its analysis and determination of market-based rate authority. These will reduce document preparation time overall and provide utilities with the clearly defined expectations of the Commission.

Updated Market Power Analyses: The updated market power analyses allow the Commission to monitor market-based rate authority to detect changes in market power or potential abuses of market power. The updated market power analysis permits the Commission to determine that continued market-based rate authority will still yield rates that are just and reasonable.

Without this information, the Commission would be unable to discharge its responsibility to approve or modify electric utility rate and tariff filings. Failure to issue these requirements would permit discrimination in interstate transmission services by public utilities.

5330. DESCRIBE ANY CONSIDERATION FOR THE USE OF IMPROVED INFORMATION TECHNOLOGY TO REDUCE BURDEN AND TECHNICAL OR LEGAL OBSTACLES TO REDUCING BURDEN

There is an ongoing effort to determine the potential and value of improved information technology to reduce the burden. The Commission has adopted user friendly electronic formats and software in order to facilitate the required electronic formats for rate filings and will develop formats for any subsequent filings. In Order No. 614 (65 FR 18221, April 7, 2000) the Commission amended its regulations to streamline rate schedules sheet designation procedures for electric industry schedules.

In Order No. 2001, (67 FR 31043, May 8, 2002) the Commission revised the format through which traditional public utilities and power marketers must satisfy their obligation, in accordance with Section 205 of the FPA and Part 35 of the Commission’s regulations, to file agreements with the Commission. Public utilities that have standard forms of agreement in their transmission tariffs, cost-based power sales tariffs, or tariffs for other generally applicable services no longer have to file conforming service agreements with the Commission. The filing requirement for conforming agreements is now satisfied by filing the standard form of agreement and an electronic Electric Quarterly Report. Order No. 2001 also lifted the requirement that parties to an expiring conforming agreement file a notice of cancellation or a cancellation tariff sheet with the Commission. The public utility can simply remove the agreement from its Electric Quarterly Report.

Non-conforming agreements, which are agreements for transmission, cost-based power sales and other generally applicable services that do not conform to an applicable standard form of agreement in a public utility’s tariff, must continue to be filed with the Commission for approval before going into effect. This category excludes unexecuted agreements and agreements that do not precisely match the applicable standard form of service agreement.

In RM01-5-000, FERC proposed that future tariff filings be made over the Internet with software developed (and distributed to public utilities for their use at no cost) software to be downloaded at the users' sites) to enter data manually (for small data sets and to edit corrections) and/or to download spreadsheet data, or other properly formatted system output, directly into the application. In addition, the software will perform edit checks at the utility site to ensure a complete filing and a successful upload at the Commission. The proposed tariffs will change from a tariff-sheet format to a section-based format that is better suited for electronic filing. The software has undergone testing and refinements to reflect industry comments that were given in several technical conferences held in the summer of 2005 and during testing periods. Integration of eTariff with FERC’s internal business process software is proceeding with a target date of the third calendar quarter 2007.

As the Commission increases its use of electronic media for filing, storage, retrieval, and tracking of information and documents, greater uniformity in filing procedures, wherever practical, will greatly expedite and simplify the conversion to electronic media.

5331. DESCRIBE EFFORTS TO IDENTIFY DUPLICATION AND SHOW SPECIFICALLY WHY ANY SIMILAR INFORMATION ALREADY AVAILABLE CANNOT BE USED OR MODIFIED FOR USE FOR THE PURPOSE(S) DESCRIBED IN INSTRUCTION NO. 2.

Electric Rate schedules and tariffs contain rate information that are not available

from other sources and therefore, no use or other modification of the information can be

made to perform oversight and review responsibilities under applicable legislation (e.g.

Federal Power Act, Energy Policy Act of 1992 and the Energy Policy Act of 2005). All

of the Commission’s public information collections are subject to analysis and review by

Commission staff and are examined for redundancy. Further, Commission staff conducted

an internal review of this collection of information to determine the necessity of the

Commission’s strategic objectives.

5332. METHODS USED TO MINIMIZE BURDEN IN COLLECTION OF INFORMATION INVOLVING SMALL ENTITIES

The Commission has reviewed those public utilities that constitute “small business concerns” under the Regulatory Flexibility Act for compliance with the proposed rule. FERC does not believe that the final rule will have an impact on small entities. The final rule will be applicable to all public utilities seeking and currently possessing market-based rate authority.

The submission of a market power analysis is currently required of all entities seeking authority to sell at market-based rates, and the Final Rule does not expand which entities will be required to file these analyses. The Final Rule does not create a new reporting requirement. It does, however, expand the scope of the analysis that must be submitted for those entities that previously were exempted from preparing a generation market power analysis by virtue of 18 CFR 35.27(a). The Commission is concerned that the continued use of the § 35.27(a) exemption, in time, would encompass all market participants as all pre-July 9, 1996 generation is retired. Nevertheless, because the Commission allows an applicant to make simplifying assumptions, where appropriate, and therefore to submit a streamlined analysis, the Commission believes that any additional burden imposed by the elimination of the § 35.27(a) exemption will be minimal. In addition, Standard tariff provisions will decrease document preparation by clearly defining the information sought by the Commission.

For certain sellers, the triennial review submissions that provide updated market power analyses are required for the retention of market-based rate authority. Category 2 utilities shall continue to submit this analysis, which poses no greater burden than that already in place. However, the regulations will result in fewer filings with the Commission after the next three years than currently required for qualified smaller utilities’ (Category 1) retention of market-based rate authority. Therefore, the Final Rule will be less burdensome economically and reduce the frequency of document preparation for market-based rate authority retention for qualified smaller utilities.

5333. CONSEQUENCE TO FEDERAL PROGRAM IF COLLECTION WERE CONDUCTED LESS FREQUENTLY

It is not possible to collect this data less frequently. If the collection were conducted less frequently, the Commission would be unable to perform its mandated oversight and review responsibilities with respect to electric rates. Furthermore, Section 205 of the FPA mandates that the information be filed every time a licensee or public utility proposes to change its rates. In the final rule, FERC notes that its current requirement to retain market-based rate tariffs, under Market Behavior Rule 4, that sellers notify the Commission within 15 days of the date of any changes to its indices reporting status. FERC proposes to codify this requirement. The Commission believes this is a continuation of already existing obligation that will require minimal resources and applies to all applicable sellers.

5334. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION COLLECTION

Public Utilities and licensees make electric rate schedule filing applications only

when they have developed new electric rate schedules or revisions to existing rate

schedules. Section 205 of the Federal Power Act requires the Commission to take action

on these applications within 60 days of the filing. This proposed program meets all of OMB's section 1320.5 requirements with the exception of part "d" thereof. Section 1320.5(d) limits the collection of data to an original and two copies of any document. The data provided under FERC-516 includes service agreements and transaction reports and would be filed by the respondents to comply with the provisions as indicated in Item A (1.). Currently an original and five copies are required to be submitted to the Commission. This is the minimum necessary to permit processing within the statutory time frame for Commission action. The original is routed to eLibrary for public viewing over the Commission's web site. One copy is distributed to the Public Reference and Files Maintenance Branch for public inspection in the Commission's Public Reference Room. An additional copy is distributed to the Office of General Counsel for legal review. Three copies are distributed to the Office of Energy Markets and Reliability for technical review by analysts in rate filings, rate investigations and financial analysis.

However, if the eTariff NOPR is adopted and electronic filing is put into place, this will eliminate the need for paper copies entirely for service agreements and transactional reports. During this transitional period, however, the traditional number of hard copies will still be needed for efficient processing of the data.

5335. DESCRIBE EFFORTS TO CONSULT OUTSIDE THE AGENCY: SUMMARIZE PUBLIC COMMENTS AND AGENCY'S RESPONSE TO THESE COMMENTS

The Commission's procedures require that the rulemaking notice be published in the Federal Register, thereby allowing all public utilities and licensees, pipeline companies, state commissions, federal agencies, and other interested parties an opportunity to submit comments, or suggestions concerning the proposal. The rulemaking procedures also allow for public conferences to be held as required. Comments were due 60 days from publication in the NOPR in the Federal Register.

Requirement for Sellers to have a Rate on File

Comments

Alliance Power Marketing questioned 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 believed that this proposal appears more akin to an inquiry than a Proposed Rulemaking.²² Pinnacle requested 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.²³

Commission Determination

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.[²⁴]

Part II of the FPA defines a public utility as “any person who owns or operates facilities subject to the jurisdiction of the Commission.”²⁵ 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.²⁶

In response to Pinnacle, the Commission clarifies 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.

Use of Historical Data

Commission Proposal

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 Commission 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.

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.²⁷ 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

Various commenters generally supported the Commission’s proposal to use historical data for the indicative screens and allow known and measurable changes for the DPT.²⁸ Some suggestions made as to what should be considered known and measurable changes include: allowing only changes that occur between updated market power analysis filings²⁹ and allowing only publicly available data or company information.³⁰ Powerex expressed concern that known and measurable changes may not be publicly available.³¹ PG&E suggested 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.³²

A number of commenters suggested that sellers should be permitted to account for known and measurable changes in both the indicative screens and the DPT.³³ Southern stated that the Commission “should not . . . restrict the ability of parties to provide the Commission with the best possible information and analysis.”³⁴ 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.³⁵

NRECA stated 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.³⁶

PPL argued 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 argued that buyers could withhold signing contracts and force a market power finding. PPL also noted 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.³⁷

Commission Determination

The Commission 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, the Commission 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.

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.

The Commission acknowledges that its 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, the Commission finds 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.

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, when 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.

Reporting Format

Commission Proposal

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

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 suggested 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 states 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.³⁸ Other commenters concurred with the Commission's proposal for a uniform reporting format. They stated that a uniform reporting format will increase consistency and thus aid the Commission in its decision making process.³⁹

One commenter suggested 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.⁴⁰

Commission Determination

The Commission 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. The Commission believes 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.

Also, the Commission 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.⁴¹

Timing of Reporting

Comments

At present, the Commission requires the reporting of changes in status to be “filed no later than 30 days after the legal or effective date of the change in status, including a change in ownership or control, whichever is earlier.”⁴² The proposed regulatory text maintains this requirement.

CAISO supported the current requirement that entities with market-based rate authority must report changes of status no later than 30 days after the change has occurred. CAISO proposed that any change in status be reported not only to the Commission but also to the relevant market monitor where the facilities are located. CAISO stated that this minimal additional burden on the supplier will ensure that RTO and ISO staff are operating with the latest possible information.⁴³

SoCal Edison recommended that the Commission revise the change in status reporting requirement to focus upon the actual acquisition of the resources in question – for power sales contracts, the date of physical power delivery. SoCal Edison stated that the Commission’s current policies make it virtually impossible for a seller to provide a meaningful evaluation of whether or not a forward contract with delivery months or years in the future creates a departure from the characteristics the Commission relied upon in granting market-based rate authority as much as three years previously. SoCal Edison notes that, as currently written, the policy requires reporting of procurement activities potentially years in advance of any power delivery because the effective date of the contract – usually the execution date – may significantly precede the date of physical delivery – that is, the actual transfer of control over generation resources.⁴⁴

Commission Determination

The Commission provides clarification regarding when a change in status filing should be filed. In Order No. 652, the Commission determined that reports of changes in status must be filed no later than 30 days after the legal or effective date of the change in status, including a change in ownership or control, whichever is earlier.⁴⁵ However, it was not the Commission’s intention, as SoCal Edison noted, to require reporting of procurement activities potentially years in advance of any power delivery. The Commission agrees with SoCal Edison that the current policy may be unclear and may cause an entity to file a notice of change in status years in advance of the actual transaction, i.e., change in ownership or transfer of control. The Commission requires a meaningful evaluation of whether a change creates a departure from the characteristics the Commission relied upon in granting market-based rate authority. It would be difficult for the Commission to accurately evaluate whether or not, for example, a forward contract with delivery months or years in the future will affect the conditions the Commission relied upon for the market-based rate authorization. Accordingly, the Commission will modify § 35.42(b) (formerly § 35.43(b)) to provide that, in the case of power sales contracts with future delivery, such contracts are reportable 30 days after the physical delivery has begun.

The Commission rejects CAISO’s proposal that any change in status also be reported to the relevant market monitor where the facilities are located. The Commission finds that informing the Commission of changes in status is sufficient. Change in status filings are noticed and therefore interested entities will have notice of any such filing.

Regional Review and Schedule

In the NOPR, the Commission proposed to require each seller to file an updated market power analysis for its relevant geographic market(s) on a schedule that will allow examination of the individual seller at the same time the Commission examines other sellers in these relevant markets and contiguous markets within a region from which power could be imported. The regional reviews would rotate by geographic region.

Some commenters expressed concern that regional review would increase the burden associated with filing updated market power analyses. Reliant, for example, states that companies which engage in business in multiple regions of the United States would have to file several times over the three year schedule instead of once as is required currently.⁴⁶ Other commenters support the regional review proposal. For example, NRECA maintains that the proposed regional approach will not impose an undue compliance burden on sellers. It notes that the regional review approach will ensure greater consistency in the data used to evaluate Category 2 sellers, citing the Commission’s statement in the NOPR that the Commission “will have before it a complete picture of the uncommitted capacity and simultaneous import capability into the relevant geographic markets under review.”⁴⁷ NRECA states that any increase in the burden on sellers hardly outweighs these substantial benefits. NRECA submits that the Commission has proposed a reasonable procedure to better ensure that market-based rate authority is granted only in appropriate circumstances. When compared with the burden, cost and time required by a cost-of-service rate regime, NRECA asserts that the burden of complying with the regional review approach will be minimal. APPA/TAPS describe the regional review proposed in the NOPR as a sensible proposal to conduct updated market power analyses on a rotating, regional basis to improve the quality and quantity of the data relied upon for market-based rate determinations and to provide the Commission with a more comprehensive picture of competitive conditions in regional markets. They assert that the Commission should not sacrifice improvements to its market-based rate program to the interests of a few companies and that any increased financial cost to companies associated with regional reviews is outweighed by the companies’ profits from market-based rate sales.

Commission Determination

The Commission believes that its proposal properly and fairly balances the need to effectively, comprehensively, and accurately assess market power in wholesale markets with the desire to minimize any administrative burden associated with the filing and review of updated market power analyses. While the Commission recognizes that some sellers may file updates more frequently than currently, the Commission has carefully balanced the interests of all involved, and the Commission believes that regional reviews of updated market analyses will result in more accurate and complete data. This in turn will enhance the Commission's ability to continue to ensure that sellers either lack market power or have adequately mitigated such market power.

Further, in light of commenters’ concern with the regional review schedule, the Commission has modified the schedule as proposed in the NOPR. The NOPR proposed that regional reviews would rotate by geographic region with three regions reviewed per year. Some commenters expressed concerned that, because they operate in multiple regions, they would be required to file updated market power analyses every year rather than every three years. To address this concern, we are reducing the number of filings that sellers with generation in multiple regions will have to make by consolidating the regions and reducing the total number from nine to six. With fewer and larger regions, sellers will likely occupy fewer regions, necessitating fewer filings.

Market-Based Rate Tariff

The NOPR proposed a tariff of general applicability (MBR tariff), which would provide greater consistency and reduce confusion regarding tariffs. The Commission recognized that the requirement to file the specified MBR tariff might cause a minimal burden of document preparation and organization for existing market-based rate sellers, but stated that long-term benefits would be realized for market participants as well as the Commission.

In this Final Rule, the Commission does not adopt the NOPR proposal to require all sellers to adopt a tariff of general applicability. Instead, the Commission adopts a set of standard tariff provisions that it will require each seller to include in its market-based rate tariff. While the Commission will require all market-based rate sellers to make compliance filings to modify their existing tariffs to reflect these standard provisions, these compliance filings are to be made by each seller the next time the seller proposes a tariff change, makes a change in status filing, or submits an updated market power analysis in accordance with the schedule in Appendix D, whichever occurs first.

In the NOPR, the Commission also proposed that all market-based rate sellers file one market-based rate tariff per corporate family. Many commenters expressed concern with this proposal. In light of these concerns, the Commission is not requiring sellers to file one market-based rate tariff per corporate family. Instead, the Commission will allow sellers to elect whether to transact under a single market-based rate tariff for an entire corporate family or under separate tariffs.

9. EXPLAIN ANY PAYMENT OR GIFTS TO RESPONDENTS

Not applicable. The Commission does not provide compensation or remuneration to entities subject to its jurisdiction.

10. DESCRIBE ANY ASSURANCE OF CONFIDENTIALITY PROVIDED TO RESPONDENTS

The Commission generally does not consider the data filed in rate filings to be confidential. There are no confidentiality provisions associated with the data requirements proposed in the subject Final Rule. Specific requests for confidential treatment to the extent permitted by law will be entertained pursuant to 18 C.F.R. Section 388.110. Section 205(c) of the FPA requires that every public utility have all of its jurisdictional rates and tariffs on file with the Commission and make them available for public inspection, within such time and in such form as the Commission may designate. Section 205(d) of the FPA requires that every public utility must provide notice to the Commission and the public of any changes to its jurisdictional rates and tariffs, file such changes with the Commission, and make them available for public inspection, in such manner as directed by the Commission.⁴⁸⁴⁹

11. PROVIDE ADDITIONAL JUSTIFICATION FOR ANY QUESTIONS OF A SENSITIVE NATURE THAT ARE CONSIDERED PRIVATE.

There are no questions of a sensitive nature that are considered private.

12. ESTIMATED BURDEN ON COLLECTION OF INFORMATION

The Commission’s regulations in 18 CFR Part 35 specify those reporting requirements that must be followed in conjunction with the filing of rate schedules under the FPA. The information provided to the Commission under 18 CFR Part 35 is identified for information collection and records retention purposes as FERC-516. Data collection FERC-516 applies to all reporting requirements covered in 18 CFR

Part 35 including: electric rate schedule filings, market power analyses, tariff submissions, market-based rate analyses, and reporting requirements for changes in status for public utilities with market-based rate authority.

The Commission did not receive comments specifically addressing the burden estimates in the NOPR. With the exception of estimates regarding sellers’ market-based rate tariffs, the number of market-based rate sellers, and the burden estimates for Category 1 sellers, the Commission will use the same estimates here as in the NOPR.⁵⁰

The number of respondents expected to file to revise market-based rate tariffs has increased from the estimate set forth in the NOPR, given the Commission’s decision not to require one MBR tariff per corporate family. The Commission expects some sellers will opt to submit a single corporate tariff, but the Commission will estimate the total number to be filed to be approximately 1230, rather than 650 as reported in the NOPR. The Commission will conform the number of responses to reflect this new estimate as well. However, this number may be significantly less if sellers choose the option to file one market-based rate tariff per corporate family. Additionally, the Commission proposed in the NOPR that sellers file their MBR tariffs as directed in the rulemaking proceeding requiring the submission of electronic tariffs. However, in this Final Rule, the Commission is requiring that sellers file their modified tariffs the next time sellers propose a tariff change, make a change in status filing, or submit an updated market power analysis. The Commission has adjusted the number of responses to reflect this requirement.

The public reporting and record retention burden for all four proposed reporting requirements and the records retention requirement is as follows:

As Proposed in the NOPR

Data Collection	No. of Respondents	No. of Responses	Hours Per Response	Total Annual Hours
Initial Market Power Analysis	120	120	130	15,600
Market-Based Rate Tariff	650--51	217	6	3,900
Triennial Review Category 1--52	0	0	0	0
Triennial Review Category 2--53	600	200--54	250	50,000
Totals				69,500

Total Annual hours for Collection: (Reporting + record retention, (if appropriate)

= 69,500hours.

As Stated in the Final Rule

Data Collection	No. of Respondents	No. of Responses	Hours Per Response	Total Annual Hours
Initial Market Power Analysis	120	120	130	15,600
Market-Based Rate Tariff	1230	41055	6	2460
Category 1 Qualification Filings56	630	21057	1558	3150
Updated Analyses Category 259	600	20060	250	50,000
Totals				71,210 hours.

Current OMB inventory for FERC-516 (1902-0096)

	Approved	Program Change Due to New Statute	Program Change Due to Agency Discretion	Change Due to Adjustment in Agency Estimate	Change Due to Potential Violation of the PRA	Previously Approved
Annual Number of Responses for this IC	4,464	230	0	0	0	4,234
Annual IC Time Burden (Hours)	438,921	45,080	0	0	0	393,841
Annual IC Cost Burden (Dollars)	0	0	0	0	0	0

13. ESTIMATED OF THE TOTAL COST BURDEN TO RESPONDENTS

The total annual costs are projected to be for:

a) Initial Market Power Analyses: $2,340,000;

b) market-based rate tariffs: $ 369,000 (first year);

c) Category 1 Qualification Filings $ 472,500.⁶¹

d) Updated Market Power Analyses Category 2 $7,500,000.

Totals:

Commission’s assumptions: The hourly rate of $150 includes attorney fees, engineering consultation fees and administrative support. There are 2080 total work hours in a year. There are no filing fees associated with applications for market-based rate authority.

13. ESTIMATED ANNUALIZED COST TO THE FEDERAL GOVERNMENT

The costs to the Commission are estimated to be $793,891 (6.5 FTE (full time equivalent employees x $122,137).

13. REASONS FOR CHANGES IN BURDEN INCLUDING THE NEED FOR ANY INCREASE

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. 

13. TIME SCHEDULE FOR THE PUBLICATION OF DATA

Schedule for Data Collection and Analysis

Tariff Amendment Filed 60 days after publication in Federal Register

Initial Commission Order 60 days

13. DISPLAY OF EXPIRATION DATE

It is not appropriate to display the expiration date for OMB approval of the

Information collected. Currently, the information on the tariff filings is not collected on a

standard, preprinted form which would avail itself to this display. Rather, public utilities

and licensees prepare and submit filings that reflect the unique or specific circumstances

related to rates and services involved in the filing. In addition, the information contains a

mixture of narrative descriptions and empirical support that varies depending on the

nature of the services to be provided.

13. EXCEPTION TO THE CERTIFICATION STATEMENT

There are exceptions to the Paperwork Reduction Act Submission certification.

Because the data collected for these reporting and recordkeeping requirements are not used for statistical purposes, the Commission does not uses as stated in item 19(I) “effective and efficient statistical survey methodology.” In addition, as noted in no. 17, this information collection does not fully meet the standard set in 19 (g) (vi.).

2. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS.

This is not a collection of information employing statistical methods.

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

2 Mobil Oil Exploration v. United Distribution Co., 498 US 211, 224 (1991).

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

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

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

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

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

8 18 CFR § 33.3(d)(4)(i) (2005).

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

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

11 In the case of non-exempt wholesale generator (EWG) public utilities, for matters arising under Part II of the FPA, the term “affiliate” is defined as that term is used in section 358.3(b) and (c) (formerly section 161.2) of the Commission’s regulations. Section 358.3(b) defines “affiliate” as “another person which controls, is controlled by, or is under common control with, such person.” Section 358.3(c) states that “control (including the terms ‘controlling,’ ‘controlled by,’ and ‘under common control with’) . . . includes, but is not limited to, the possession, directly or indirectly and whether acting alone or in conjunction with others, of the authority to direct or cause the direction of the management or policies of a company. A voting interest of 10 percent or more creates a rebuttable presumption of control.” The term “affiliate” in the case of EWG public utilities is defined as “any company, 5 percent or more of the outstanding voting securities of which are owned, controlled or held with power to vote, directly or indirectly, by such company.” See Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005, Order No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & Regs. ¶ 31,213 (2006). (Codified at 18 CFR section 366.1 (2006).)

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

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

14 See 18 CFR § 35.1(g) (2005).

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

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

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

18 The Commission notes here that it expects mitigated sellers adopting the default cost-based rates or proposing new cost-based rates will propose a cost-based rate tariff of general applicability for sales of less than one year, and sales of power for one year or longer will be filed with the Commission on a stand-alone basis.

19 16 U.S.C. 824d(a) (2000).

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

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

22 Alliance Power Marketing at 16.

23 Pinnacle at 5.

24 16 U.S.C. 824d(c).

25 16 U.S.C. 824(e).

26 Vermont Electric Cooperative, Inc., 108 FERC ¶ 61,223 (2004), order on reh’g, 110 FERC ¶ 61,232 (2005).

27 See 18 CFR 35.13(a).

28 See, e.g., EEI at 23, PPL at 17-19; Powerex at 18-19.

29 See, e.g., Ameren at 6. Ameren proposes that if a seller chooses to rely on an historical period with no changes, the Commission should honor that choice and not allow intervenors to introduce suggested known and measurable changes. Conversely, if a seller proposes to adjust the historical period for certain known and measurable changes, Ameren states that the Commission should permit intervenors to introduce competing known and measurable changes. Id. at 6-7.

30 Drs. Broehm and Fox-Penner at 12-13 (any adjustments to historical base year must be known and measurable at the time of filing; new capacity additions should only be accounted for if they are on-line or under construction).

31 Powerex at 18-19.

32 PG&E at 9-10.

33 PG&E at 2; Southern at 25-26; Duke at 26; NRECA at 21-23.

34 Southern at 26.

35 Duke at 26.

36 NRECA at 21-23. See also APPA/TAPS at 13-15.

37 PPL reply comments at 3-4.

38 APPA/TAPS at 35.

39 Drs. Broehm and Fox-Penner at 12.

40 Dr. Pace at 8-9.

41 The "Workpapers" column is meant to provide an easy way to find sources and ensure that all submissions are properly sourced. Hence, the items in that column (e.g., "Workpaper 5") were merely meant to be illustrative and do not require that information be submitted on specific workpapers or that workpapers be submitted in a particular order.

42 Order No. 652 at P 106. The Commission clarified that for power sales contracts, “it is irrelevant for the purposes of compliance with the reporting obligation if the effective date on which control is transferred occurs prior to the date on which the purchaser is contractually bound to commence physical delivery.” Order No. 652-A at P 31.

43 CAISO at 15.

44 SoCal Edison at 17-19.

45 Order No. 652 at 106.

46 Similarly, Allegheny, Mirant, FP&L, EEI, FirstEnergy, MidAmerican, TXU, Morgan Stanley, Financial Companies, and EPSA argue that large corporate families could find themselves in a perpetual triennial review that would place a substantial regulatory burden and expense on them.

47 NRECA reply comments at 28, citing NOPR at P 154.

48 See The Power Company of America, L.P. v. FERC, 245 F.3d 839 (D.C. Cir. 2001) (PCA). In PCA, the court found, 245 F.3d at 846, that the Commission may alter its view of what information is required to be on file under section 205(c) of the FPA and  35.15 of the Commission's regulations.

49

50 As noted above the number of market-based rate sellers has increased since issuance of the NOPR in May 2006.

51 The number of respondents for market-based rate tariffs is expected to be 650. The figure 217 represents 650 respondents, per year, over the course of 3 years. Also, the 650 figure takes into account that parent companies will file for their affiliates.

52 Category 1 Sellers are power marketers and power producers that own or control 500 MW or less of generating capacity in aggregate and that are not affiliated with a public utility with a franchised service territory. In addition, Category 1 sellers must not own or control transmission facilities, and must present no other vertical market power issues. The zero in this section represents that Category 1 Sellers are not responsible for filing triennial updates.

53 Category 2 Sellers are any sellers not in Category 1.

54 To determine the number of responses, the number of respondents (600) has been divided by 3 because the responses will be submitted to the Commission on a staggered basis over the course of a three year period.

55 We expect responses to be staggered over the course of three years. Accordingly, the number of respondents (1230) has been divided by three.

56 Category 1 sellers are power marketers and power producers that own or control 500 MW or less of generating capacity in aggregate and that are not affiliated with a public utility with a franchised service territory. In addition, Category 1 sellers must not own, operate or control transmission facilities, and must present no other vertical market power issues. There are approximately 630 Category 1 sellers.

57 To determine the number of responses, the number of respondents (630) has been divided by 3 because the Category 1 filings will be submitted to the Commission on a staggered basis over the course of a three-year period. After the first three years, the number of responses will be zero.

58 This estimate reflects the limited scope of the filing required by Category 1 sellers, i.e., a filing explaining why the seller meets the Category 1 criteria and including a list of all generation assets owned or controlled by the seller and its affiliates grouped by balancing authority area.

59 Category 2 sellers are any sellers not in Category 1.

60 To determine the number of responses, the number of respondents (600) has been divided by 3 because the responses will be submitted to the Commission on a staggered basis over the course of a three year period.

61 The Commission notes that Category 1 sellers will only be required to file on a single occasion Category 1 qualification filings whereas Category 2 sellers will file updated market power analyses every three years.

41