FERC-919(516), RM04-7-001 Final Rule on
Rehearing
SUPPORTING STATEMENT FOR
FERC-919(516) Electric Rate Schedule Filings: Market Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, In Docket No. RM04-7-001 (Order On Rehearing)
The Federal Energy Regulatory Commission (FERC, Commission), is
submitting this final rule on rehearing to the Office of Management and Budget (OMB) for informational purposes only. 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. OMB assigned the OMB control No. 1902-0234 to the proposed requirements.
At the final rule stage as FERC-516 was not the subject of OMB review, and the Commission proposed to add the hours associated with the final rule to the hours associated with FERC-516 and to report in OMB’s inventory (ROCIS) under the control number 1902-0096. The Final Rule would add 71,210 hours to the already 438,921 hours reported in OMB’s inventory for a total of 510,131 hours if the two information collection requests are consolidated. FERC-516 (1902-0096) is currently approved through May 31, 2010.
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 existing 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 existing 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 existing 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 proposed 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 existing policies protected customers by ensuring that applicants with market power in a given area have that market power mitigated. The Commission recognized, 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 the NOPR 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 existing 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 the NOPR, a separate NOPR RM05-25-000 as noted above, to reform the OATT. This was followed a Final Rule, Order No. 890 which was designed to strengthen the pro forma open-access transmission tariff to ensure that it achieves its original purpose of remedying undue discrimination; provide greater specificity to reduce opportunities for undue discrimination and facilitate the Commission’s enforcement; and increase transparency in the rules applicable to planning and use of the transmission system.11
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.12 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 affiliates13 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.14 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,15 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 existing 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)16 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,17 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.18 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) Order No. 697.
On June 21, 2007, the Commission issued Order No. 697,19 codifying and, in certain respects, revising its standards for obtaining and retaining market-based rates for public utilities. In order to accomplish this, as well as streamline the administration of the market-based rate program, the Commission modified its regulations at 18 CFR part 35, subpart H, governing market-based rate authorization. The Commission explained that there are three major aspects of its market-based regulatory regime: (1) market power analyses of sellers and associated conditions and filing requirements; (2) market rules imposed on sellers that participate in Regional Transmission Organization (RTO) and Independent System Operator (ISO) organized markets; and (3) ongoing oversight and enforcement activities. The Final Rule focused on the first of the three features to ensure that market-based rates charged by public utilities are just and reasonable. Order No. 697 became effective on September 18, 2007.
Specifically in the Final Rule, FERC codified and, in certain respects, revised its existing standards for market-based rates for sales of electric energy, capacity, and ancillary services. The Commission retained several of the core elements of its existing standards for granting market-based rates and revising them in certain respects. FERC also proposed to streamline aspects of its filing requirements to reduce the administrative burdens on applicants, customers and on FERC.
(Docket No. RM04-7-003) Order Clarifying Final Rule
On December 14, 2007, the Commission issued an order clarifying four aspects of Order No. 697.20 Specifically, that order addressed: (1) the effective date for compliance with the requirements of Order No. 697; (2) which entities are required to file updated market power analyses for the Commission’s regional review; (3) the data required for the horizontal market power analyses; and (4) what constitutes “seller-specific terms and conditions” that sellers may list in their market-based rate tariffs in addition to the standard provisions listed in Appendix C to Order No. 697. The Commission also extended the deadline for sellers to file the first set of regional triennial studies that were directed in Order No. 697 from December 2007 to 30 days after the date of issuance of the Clarification Order.
(Docket No. RM04-7-001) Order No. 697-A, Order on Rehearing
In an order on rehearing issued April 21, 2008, the Commission affirmed its basic determinations in Order No. 697, and granted rehearing and clarification regarding certain revisions to its regulations and to the standards for obtaining and retaining market-based rate authority for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. The Commission also clarified several aspects of the implementation process adopted in Order No. 697.
Specifically, FERC responded to a number of requests for rehearing and clarification of Order No. 697. In most respects, the Commission reaffirmed its determinations made in Order No. 697 and denied rehearing of these issues. With respect to several issues, however, the Commission granted rehearing or provided clarification.
For example, the Commission affirmed in large part the determinations made in Order No. 697 concerning the horizontal market power analysis, including the use of the 20 percent threshold for the indicative wholesale market share screen and the Delivered Price Test (DPT), the use of a 2,500 Hirschman-Herfindahl Index (HHI) threshold for the DPT analysis, and the use of the average peak native load as the native load proxy for the indicative wholesale market share screen and DPT analysis. The Commission also affirmed its decision to use a balancing authority area or the RTO/ISO region as the default relevant geographic market. Similarly, the Commission affirmed the decision that, where the Commission has made a specific finding that there is a submarket within an RTO/ISO, that submarket should be considered the default relevant geographic market. However, the Commission granted rehearing concerning the finding that Northern PSEG is a submarket within PJM. On reconsideration, the Commission concluded that it erred in relying on a finding of a submarket in a particular proceeding that was subsequently vacated on procedural grounds.
In response to requests for clarification concerning existing mitigation in RTO/ISOs, the Commission adopted a rebuttable presumption that the existing Commission-approved RTO/ISO mitigation is sufficient to address market power concerns in the RTO/ISO market, including mitigation applicable to RTO/ISO submarkets. However, intervenors may challenge that presumption. Depending on the nature of the evidence submitted by an intervenor, the Commission will consider whether to institute a separate section 206 proceeding to investigate whether the existing RTO/ISO mitigation continues to be just and reasonable.
While the Commission affirmed its determination to continue the use of historical data and a “snapshot in time approach,” the Commission will consider sensitivity studies, on a case-by-case basis, that present clear and compelling evidence that certain changes in a market should be taken into account as part of the market power analysis in a particular case.
In other provisions of Order No. 697, the Commission affirmed:
• its determinations concerning the vertical market power analysis and clarified that sellers are not required to report on financial transmission rights as part of the vertical market power analysis;
• its determination in Order No. 697 to create a category of market-based rate sellers (Category 1 sellers) that are not required to automatically submit updated market power analyses, as well as its decision to adopt a regional filing process for updated market power analyses. In response to concerns raised regarding the potential for Category 1 sellers to exercise market power in load pockets or other transmission-constrained areas, the Commission explained that it was modifying its approach. To the extent that a Commission-identified submarket is under analysis (relevant submarket), if the Commission determines based on analysis of indicative screens filed by other sellers that there may be potential market power concerns with respect to any Category 1 sellers in the relevant submarket, the Commission will, if appropriate, require an updated market power analysis to be filed by such Category 1 sellers and allow other parties to comment. In this regard, the Commission would be exercising its right to require an updated market power analysis at anytime.
• its determinations concerning mitigation, including retaining the Commission’s default mitigation and declining to impose a generic “must offer” requirement. The Commission clarified that it has not pre-judged the types of specific situations in which it might impose a “must offer” requirement on a particular seller. In response to rehearing requests concerning the Commission’s mitigation of long-term transactions based on the result of a failure of a short-term indicative screen, the Commission has modified its policy with respect to mitigation of long-term transactions (one year or more in duration). In this regard, the Commission will allow a mitigated seller to demonstrate on a case-by-case basis that it does not have market power with respect to a specific long-term contract.
Concerning the tariff provision adopted in the Final Rule for mitigated sellers that want to make market-based rate sales at the metered boundary between a balancing authority area in which the seller was found, or presumed, to have market power and a balancing authority area in which the seller has market-based rate authority, after considering comments raised regarding the difficulty of determining and documenting whether the power sold is intended to serve load in the balancing authority area in which the seller has market power, the Commission revised the tariff language to eliminate the intent element.
.
In other provisions of Order No. 697, the Commission clarified:
• with regard to simultaneous transmission import limit (SIL) studies, the use of simultaneous total transfer capability (TTC) in the SIL study must properly account for all firm transmission reservations, transmission reliability margin, and capacity benefit margin.
• that the new affiliate restriction regulations promulgated in Order No. 697 supersede codes of conduct approved by the Commission prior to the effective date of Order No. 697. The Commission also provided a number of clarifications concerning employees who are not subject to the independent functioning requirement. Further, the Commission granted rehearing regarding the adoption of a two-way information sharing restriction in 18 CFR 35.39(d), finding, among other things, that a one-way information sharing restriction adequately protects captive customers.
• regarding other aspects of the Final Rule, including addressing questions that have arisen concerning the implementation process adopted in Order No. 697 and providing clarifications concerning the change in status reporting requirement.
The Commission codified in the regulations at 18 CFR 35.36 a definition
of “affiliate” for purposes of Order No. 697 based on the definition adopted in the Affiliate Transactions Final Rule.21 In addition, the Commission reiterated in the rehearing order a number of clarifications that it made in the Affiliate Transactions Final Rule regarding the term “captive customers,” the purpose of the definition, and its focus on “cost-based regulation.” Among other things, the Commission noted that if a state regulatory authority in a retail choice state does not believe that retail customers are sufficiently protected and that the Commission’s affiliate restrictions should apply to the local franchised public utility, it may ask the Commission to deem its retail customers to be captive customers for purposes of applying the affiliate restrictions.
Finally, the Commission rejected as without merit arguments raised by petitioners challenging the Commission’s authority to adopt market-based rates and alleging that the market-based rate program fails to comply with the requirements of the FPA.
While the rehearing order clarified aspects of the existing information collection requirements for the market-based rate program, it does not add to these requirements.
JUSTIFICATION
CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY
Section 205(c) of the Federal Power Act (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/Commission 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.
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 the final rule the Commission codified that requirement in its regulations. Section 35.27(a) of the Commission’s regulations 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 requires 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.22 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.23 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.24
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.
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 was to perform edit checks at the utility site to ensure a complete filing and a successful upload at the Commission. The proposed tariffs would change from a tariff-sheet format to a section-based format that is better suited for electronic filing. The software underwent testing and refinements to reflect industry comments that were given in several technical conferences held in the summer of 2005 and during testing periods.
In RM01-5-000 Supplemental NOPR issued April 17, 2008, the Commission is proposing to require regulated entities filing to make all tariff and rate case filings, as well as other material involved in these filings electronically. The creation of an electronic database will provide easier access to tariffs and allow the viewing of proposed tariff sections in context. One of the principal benefits of such a database is the ability to do historical research into tariffs. For example, proceedings such as complaints may involve past tariff provisions that have already been revised by the utility by the time the complaint is considered by the Commission. In order to expeditiously process such filings, the Commission, the parties, and the public need to be able to obtain the tariff provision that apply to the time period under review, rather than the currently effective tariff provision.25
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.
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 is 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.
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 and final rules. As the final rule on rehearing merely clarifies FERC’s final rule, the Commission continues to believe based on its position in the final rule, that the final rule on rehearing will not have an impact on small entities. The final rule on rehearing 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 Commission already indicated in the Final Rule, it 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, as the Commission stated in the final rule, 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.
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 noted 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 codified this requirement. The Commission believes this is a continuation of already existing obligation that will require minimal resources and applies to all applicable sellers.
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 Market Regulation 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.
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. The following provides a summary of major issues addressed on rehearing.
In Order No. 697, the Commission adopted as noted above, with some modifications, two indicative market power screens (the uncommitted market share screen and the uncommitted pivotal supplier screen) to determine whether sellers may have market power and should be further examined. The Commission explained that sellers that fail either screen would rebuttably be presumed to have market power, but they would have an opportunity to present evidence (through the submission of a Delivered Price Test (DPT) analysis) demonstrating they do not have market power. The Commission concluded that, although some sellers disagree with the use of two screens or find flaws in them, the conservative approach of using two screens together would allow the Commission to more readily identify potential market power by measuring market power at both peak and off-peak times and both unilaterally and in coordinated interaction with other sellers. The Commission explained that a conservative approach at the indicative screen stage of the proceeding is warranted because, if a seller passes both of the indicative screens, there is a rebuttable presumption that it does not possess horizontal market power.26 In conclusion, the approach represented an appropriate balance between the need to protect against market power and the desire not to place unnecessary filing burdens on utilities.27
The wholesale market share screen measures for each of the four seasons whether a seller has a dominant position in the market based on the number of megawatts of uncommitted capacity owned or controlled by the seller as compared to the uncommitted capacity of the entire relevant market. When calculating uncommitted capacity, a seller adds the total nameplate or seasonal capacity of generation owned or controlled through contract plus long-term firm purchases and deducts operating reserves, native load commitments, and long-term firm sales.28
The pivotal supplier analysis evaluates the potential of a seller to exercise market power based on uncommitted capacity at the time of the relevant market’s annual peak demand, focusing on the seller’s ability to exercise market power unilaterally. It examines whether the market demand can be met absent the seller during peak times; a seller is determined to be pivotal if demand cannot be met without some contribution of supply by the seller or its affiliates. For purposes of identifying the wholesale market, the Commission explained that the “proxy for the wholesale load is the annual peak load (needle peak) less the proxy for native load obligation (i.e., the average of the daily native load peaks during the month in which the annual peak load day occurs).”29
The Commission chose not to adopt suggestions to alter the indicative screens in order to incorporate a contestable load analysis, as proposed by some commenters. Such an analysis would consider the amount of excess market supply available to serve the amount of wholesale demand seeking supply at a particular moment in time.30 The Commission reasoned that such an analysis is essentially a variant on the pivotal supplier screen with differences in the calculation of wholesale load and the test thresholds since it addresses whether suppliers other than the seller can meet the demand in the relevant market. The Commission concluded that incorporating such an analysis would not improve its ability to establish a presumption of whether a seller has market power, and “without the market share indicative screen, the Commission would have insufficient information because there would be no analysis of a seller’s size relative to the other sellers in the market, and no information on the seller’s market power during off-peak periods.”31 Additionally, the Commission noted that the contestable load analysis fails to consider the relative price of the competing supplies and thus whether the available non-applicant supply is competitively priced and, hence, in the market.32
Requests for Rehearing
On rehearing, Southern contends that the Final Rule violates the requirement in FPA section 206 that the Commission bears the burden of proof in section 206 proceedings and that the Commission’s determinations are based on substantial evidence.33 According to Southern, this shifting of the burden of proof occurs through the use of indicative screens that Southern submits are inherently flawed and which, if failed, result in a presumption of market power that must be rebutted by sellers. Southern states that once a screen failure occurs and a presumption of market power arises, a seller only has two options: either accepts a determination that it has market power and adopts cost-based rate mitigation measures, or provides the Commission with a DPT analysis.34 Southern concludes that by applying the indicative screens codified in the Final Rule, the Commission will effectively shift to sellers the evidentiary burden in a section 206 proceeding.35 Southern argued that the screens are inherently flawed in their ability to definitively assess market power when none is actually present, noting that the Final Rule acknowledges that the screens are conservative in nature and may result in false positives indicating market power.36 Southern argued that because of their conservative nature and propensity to result in false positives, such screens cannot properly provide a basis for shifting the burden of proof to sellers, and are incapable of providing substantial evidence of market power.
To remedy this, Southern argued that the Commission should reconsider its determination in the Final Rule that a failure of an indicative screen results in a presumption of market power. Instead, the Commission should determine that the indicative screens are only intended to identify sellers that appear to raise no horizontal market power concerns and thus can be considered for market-based rate authority without the necessity of further analysis. In other words, passing the screens should raise a favorable presumption that a seller does not have market power, and a seller would never be “presumed” to have generation market power.37
Southern further argued that the Final Rule’s market share screen and its application of the DPT are arbitrary and capricious, not supported by substantial evidence, without a rational basis, and contrary to established legal precedent.38 Specifically, Southern contends that the market share screen and the DPT improperly fail to account for the size of the wholesale market demand that could be served by the uncommitted capacity in the relevant region.39 Southern argued that wholesale market demand should be considered in the market share screen and the DPT because market power concerns only exist if a seller has the power to raise prices above competitive levels or exclude competition in the relevant market for a not insubstantial amount of time.40 According to Southern, even the Department of Justice (DOJ) merger analysis, on which the Final Rule relies, would take the wholesale market into account when determining an entity’s “market share.”41 Southern comments that in the Final Rule the Commission appeared to give four reasons why it was unwilling to consider market demand (i.e., contestable load), and contends that these reasons provide an insufficient basis for rejecting a contestable load analysis.42 Southern believes that the weight of the evidence clearly demonstrates that to be legitimate indicators of market power, the market share screen and DPT should take the relevant wholesale demand into account.
Commission’s Response
The Commission disagrees with Southern’s contention that the Final Rule violates the requirement in the FPA that the Commission bears the burden of proof in section 206 proceedings. The Commission also disagrees 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.
As a general matter, the Commission agrees that the burden of proof in a section 206 proceeding is on the Commission where the Commission institutes the proceeding on its own motion. However, the Commission finds Southern’s argument that the burden of proof in a section 206 proceeding is unlawfully shifted to entities that fail one of the indicative screens to be without merit. As an initial matter, the burden of going forward is on the Commission in the first instance, and ultimately, when the Commission institutes a proceeding under section 206 of the FPA. In the Final Rule, the Commission has established through rulemaking a generic test to support its burden of going forward: a seller’s failure of one of the indicative screens establishes a rebuttable presumption of market power. The burden of going forward then shifts to the seller once such a proceeding is initiated to rebut the presumption of market power. Once the seller submits additional evidence to rebut the presumption of market power, the Commission must determine, based on substantial evidence in the record, whether the seller has market power. Thus, the ultimate burden of proof under FPA section 206 remains with the Commission.43 On this basis, the Commission is not unlawfully shifting the burden of proof to the seller that fails one of the screens.
Moreover, in Order No. 697, the Commission addressed an argument by Southern that failure of the screens does not provide a sufficient basis to establish a rebuttable presumption of market power, and Southern has failed on rehearing to convince us that a seller should never be presumed to have generation market power. In particular, the Commission explained that the indicative screens are intended to identify the sellers that raise no horizontal market power concerns and can otherwise be considered for market-based rate authority. Sellers failing one or both of the indicative screens, on the other hand, are identified as sellers that potentially possess horizontal market power and for which a more robust analysis is required. The Commission explained that the uncommitted pivotal supplier screen focuses on the ability to exercise market power unilaterally. Failure of this screen indicates that some or all of the seller’s generation must run to meet peak load. The uncommitted market share analysis indicates whether a supplier has a dominant position in the market. Failure of the uncommitted market share screen may indicate that the seller has unilateral market power and may also indicate the presence of the ability to facilitate coordinated interaction with other sellers. It is on this basis that the Commission finds that a rebuttable presumption of market power is warranted when a seller fails one or both of the indicative screens. The screens themselves represent the first piece of evidence that the potential for market power exists since failure of one or both of the screens indicates that the seller may be a pivotal supplier in the market or has a high enough market share of uncommitted capacity to raise horizontal market power concerns.44 In addition, the Commission notes that although it finds that failure of an indicative screen is a sufficient basis to establish a presumption of market power, the Commission allows such a seller to continue to sell under market-based rate authority until a definitive finding is made, albeit with rates subject to refund to protect customers.
The Commission disagrees with Southern’s argument that the indicative screens have a propensity to result in false positive indications of market power, do not provide substantial evidence of market power and, therefore, cannot provide a basis for shifting the evidentiary burden to sellers. As the Commission explained in Order No. 697, the indicative screens are intended to screen out those sellers that raise no horizontal market power concerns and can otherwise be considered for market-based rate authority from those sellers that raise concerns but may not necessarily possess horizontal market power.45 While the Commission recognizes that the conservative nature of the screens may result in some false positives, a conservative approach at the indicative screen stage is warranted because if a seller passes both of the indicative screens, there is a rebuttable presumption that it does not possess horizontal market power. Thus, the Commission must weigh the risk of false positives and any resulting repercussions on a seller (e.g., section 206 proceeding, rate subject to refund, temporary regulatory uncertainty) against the costs of adopting a less conservative screen or eliminating the market share indicative screen.46 In particular, if the screens result in a false positive indication of market power, the seller has the opportunity to rebut the presumption of market power while it continues to have market-based rate authority.
However, if the Commission were to adopt a less conservative screen, that could result in a false negative, i.e., a false indication of no market power and customers would not be adequately protected. Accordingly, if the Commission were to adopt Southern’s approach the Commission is concerned that false negatives would become a reality and the Commission would not be able to fulfill its FPA section 205 and 206 mandate to ensure just, reasonable and not unduly discriminatory rates. On this basis, the Commission believes that evidence of an indicative screen failure is sufficient to establish a rebuttable presumption of market power, in which case the seller will then have the opportunity to rebut that presumption of market power.
Additionally, in response to Southern’s concerns regarding the conservative nature of the indicative screens, Order No. 697 changed the native load proxy under the market share indicative screen from the minimum native load peak demand for the season to the average of the daily native load peak demands for the season, making the native load proxy for the market share indicative screen consistent with the native load proxy under the pivotal supplier screen.47 A native load proxy based on the average of peak load conditions is more representative, and thus more accurate, than a proxy based on minimum peak load conditions. Basing the native load proxy on the average of the peaks will make the screens more accurate in eliminating sellers without market power while focusing on ones that may have market power.48 Thus, the updated native load proxy will reduce the likelihood that false positive indications of market power will occur.
Accordingly, the Commission affirms its determination in the Final Rule that a failure of an indicative screen results in a presumption of market power, and rejects Southern’s proposal that a seller never be “presumed” to have horizontal market power as a result of an indicative screen failure.49
The Commission also disagrees with Southern’s assertion that the market share screen and the DPT analysis do not account for the size of wholesale market demand, and are therefore arbitrary and capricious.50 While Southern may disagree with the Commission’s approach to considering wholesale market demand, both the market share screen and the DPT consider wholesale market demand by considering uncommitted capacity. Uncommitted capacity considers wholesale market demand by reducing the seller’s available capacity by the amount of capacity committed to serve demand. In addition, in both the initial screen and the DPT, the Commission requires a pivotal supplier analysis, which looks at whether there is sufficient competing supply to serve wholesale demand.
In addition, the Commission disagrees with Southern that its choice of how to account for the wholesale market demand has resulted in the market share screen and the DPT being arbitrary and capricious. The development of the market share screen and the DPT resulted from lengthy public proceedings at which varying perspectives and arguments were taken into account. Over the years, and in light of the Commission’s FPA responsibilities, the Commission has carefully considered various points of view in an open transparent dialogue with the electric industry and has based its determinations on sound regulatory principles. In particular, the market share screen provides a straightforward economically sound and accepted method to identify those sellers that have the potential to exercise market power.51 The uncommitted pivotal supplier screen measures the ability of the firm to dominate the market at peak periods. Further, the market share screen indicates whether a supplier may have a dominant position in the market and measures the ability of a seller to affect coordinated interaction with other sellers that could be accomplished during both peak and off-peak times. The market share screen is useful in measuring market power because it measures a seller’s size relative to others in the market, specifically, the seller’s share of generating capacity that is uncommitted after accounting for its obligations to serve native load. It also provides a snapshot of these market shares in each season of the year.52 Thus, the indicative screens measure a seller’s market power at both peak and off-peak times and therefore indirectly measure market power potential during periods of both relatively high and low demand.53
With regard to Southern’s argument that in the Final Rule the Commission appeared to give four reasons why it was unwilling to consider market demand (i.e., contestable load), and Southern’s contention that these reasons provide an insufficient basis for rejecting a contestable load analysis, the Commission reaffirms its determination that the contestable load analysis is flawed and essentially a variant on the pivotal supplier screen.54 Like the pivotal supplier screen, the contestable load analysis addresses whether suppliers other than the seller can meet the demand in the relevant market. Thus, incorporating such an analysis would not improve the Commission’s ability to establish a presumption of whether a seller possesses market power and would add little useful information.55
The Commission held in Order No. 697 that it would retain the “snapshot in time” approach for the indicative screens and the DPT, so that sellers will be required to use actual historical data for the previous calendar year in their market power analyses. After careful consideration of the comments received, the Commission chose not to adopt the NOPR proposal that the DPT analysis allow sellers and intervenors to account for changes in the market that are known and measurable at the time of filing. Instead, the Commission decided to retain its existing practice that sellers are required to use unadjusted historical data in the preparation of a DPT for a market-based rate analysis and clarified that it would require the use of the actual historical data for the previous calendar year.
The Commission distinguished this treatment from the approach in the Commission’s merger analysis, which requires applicants and intervenors to account for changes in the market that are known and measurable at the time of filing. The Commission found that the purpose of using the DPT in market-based rate proceedings is different from that in a merger analysis. Whereas a merger analysis is forward-looking and it is difficult and costly to undo a merger, the market-based rate analysis is a “snapshot in time” approach where the Commission’s focus is on whether the seller passes the indicative screens and the DPT based on unadjusted historical data. The Commission considered that its grant of market-based rate authority is conditioned on, among other things, the seller’s obligation to inform the Commission of any change in status from the circumstances the Commission relied on in granting it market-based rate authority on an ongoing basis. Thus, the change in status reporting requirement allows the Commission to evaluate changes when they actually happen rather than relying on projections, making it unnecessary and redundant for the Commission to allow sellers to account for known and measurable changes in the DPT.
Requests for Rehearing
Montana’s General Counsel (Montana Counsel) argued that the Commission erred in refusing to allow adjustments to the DPT analysis to account for known and measurable future changes, such as contracts for the sale of capacity belonging to the seller that will expire during the term of its market-based rate authority. Montana Counsel asserted that by refusing to consider known and measurable changes, the Commission is intentionally allowing the DPT analysis to be conducted based on data and assumptions that are known not to be representative of reality.56 Montana Counsel argued that it is inherently irrational, arbitrary, and capricious to allow companies whose generation market power is being analyzed to deduct the generation that is being tested from its supply on grounds that the generation is committed, as the Commission does when the contracts for power from that generation are expiring. Montana Counsel stated that such a market power test is inherently flawed, and that this flawed test has concrete results, with negative impacts for consumers. Montana Counsel cited the Commission’s May 2006 renewal of PPL Montana’s market-based rate authority, in spite of the fact that the main utility in Montana, NorthWestern Energy, must buy from PPL Montana to serve its load, as an example of the negative impact that the market power test can have on consumers.57
Montana Counsel noted that the Final Rule distinguishes the market-based rate process from the Commission’s merger analysis by saying that while mergers are difficult to undo, sellers with market-based rate authority must file change in status reports, allowing the Commission to evaluate changes when they happen. Montana Counsel argued that the Commission misses the point that if the change in status is caused by the expiration of a long-term contract for the sale of capacity, then by the time the change in status report is submitted, the seller may have already re-sold the capacity at a price reflecting the seller’s underlying market power.58
Montana Counsel contends that the refusal to consider known and measurable changes is especially inappropriate in light of the fact that the Commission considers mitigation proposed by the seller.59 Montana Counsel argued that, if the Commission will consider an applicant’s “‘propos[al] to transfer operational control of enough generation to a third party such that the applicant would satisfy [the Commission’s] generation market power concerns’” it should also consider whether an applicant’s available capacity will increase during the market-based rate authorization period when contracts expire.60
NRECA similarly asserted that the Final Rule’s failure to require applicants and allow intervenors to incorporate known and measurable changes to historical data in the indicative screens and the DPT in favor of a rigid “snapshot” analysis of historical data is arbitrary, capricious, contrary to law, and in excess of statutory authority.61 NRECA argued that, if the Commission knows a change will take place, it would be arbitrary and capricious to grant market-based rate authority based on an assumption that the change will not take place.62 Long-term contracts will expire on a known schedule, and the seller should not be allowed to assume that the capacity will remain committed to the buyer. According to NRECA, the Commission cannot, consistent with the FPA, ignore that pending change in circumstances. At a minimum, intervenors should have the opportunity to demonstrate the applicant’s market power using data reflecting conditions after the contracts expire.63
NRECA stated that the Commission’s reliance on change in status filings as the means to report the expiration of a long-term contract is illogical and does not constitute reasoned decision making.64 NRECA believes that absent a full market power analysis, it is impossible to adequately determine the effect of the change. NRECA submits that the triennial review will often come too late to protect customers.65
TDU Systems also argued that the Commission should require applicants’ market-power analyses to reflect imminent changes which are known and measurable. They agree that historical data are more objective, but object that when they are not representative of market conditions that will exist during the three-year period of market-based rate authority, considering imminent changes is legally required.66 For soon-to-expire long-term contracts, TDU Systems asserted that the seller should not be permitted to assume that the capacity will remain committed to the buyer. The burden should not be shifted to the intervenors to propose the adjustment; rather, an applicant should be required to include it as part of the analysis.67
Commission Response
The Commission will continue the use of historical data for both the indicative screens and the DPT in market-based rate cases. The Commission rejects several petitioners’ requests that the Commission should require sellers to reflect imminent changes that are known and measurable, and therefore the Commission denies rehearing on this issue. Regarding the Commission’s reliance upon historical rather than projected data in analyzing market power studies, and its determination not to require sellers to reflect changes that are known and measurable, the Commission’s practice for many years has been to use a “snapshot in time approach” based on the most recently available historical data at the time of filing, i.e., to rely upon studies based on unadjusted historical data. The Commission continues to allow intervenors to submit sensitivity analyses including projected data, but the Commission rejects the proposal that applicants include adjustments to historical data as part of the required analyses.
There are several reasons why this approach benefits customers and is otherwise in the public interest. First, as the Commission explained in the Final Rule, historical data are more objective, readily available, and less subject to manipulation by applicants than future projections.68 If the Commission were to allow applicants to submit studies based on their future projections or that reflect “imminent changes,” then sellers would be able to selectively “cherry pick” those changes that benefited the seller in obtaining market-based rate authorization while ignoring other equally likely future changes that would undermine the seller’s chances for obtaining such authorization. Second, this approach benefits customers, state commissions and other affected intervenors because it requires the use of a consistent methodology that can be replicated by intervenors, rather than allowing sellers to submit customized market power studies that, due to myriad selective adjustments, are difficult to analyze and can hide the presence of market power. Third, it is important to note that the “snapshot in time” approach does not preclude the Commission from considering future changes in market conditions; rather, 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. 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 predicted changes in the DPT for market-based rate purposes.
Furthermore, accounting for “imminent changes” would be excessively burdensome with regard to expiring contracts because, for an accurate representation, a review of all expiring contracts and all contracts being negotiated inside all balancing authority areas in the relevant market and the seller’s first-tier markets might be necessary. In addition, because the definition of “imminent” is a matter of interpretation and may change depending on the circumstances, it would produce regulatory uncertainty. Furthermore, future changes are not necessarily known and measurable. For example, a long-term contract may be expiring in a year, but until it expires, it often can be renewed for the same term(s). Therefore, an analysis that assumes that the long-term capacity of that contract was uncommitted would not always be correct, and therefore could overstate the seller’s market power. When a change does occur the Commission has a method to evaluate the new situation through its requirement that sellers with market-based rate authority report changes in status and what effect, if any, such a change has on the grant of market-based rate authority. In any event, the Commission may require a full market power analysis at any time including as a result of a seller’s change in status filing.
With regard to Montana Counsel’s argument that the Commission should allow evidence of known and measurable changes rather than a strict adherence to historical data because if a change in status is caused by the expiration of a long-term contract for the sale of capacity, then by the time a seller’s change in status filing is submitted, a seller may have already re-sold the capacity at a price reflecting the seller’s underlying market power, the Commission recognizes that a seller’s change in status filing would not be filed until after a long-term contract expires. However, there are countervailing reasons why the Commission believes that the use of historical data is appropriate and reaffirms its practice of using a “snapshot in time approach.”69 As explained above, the Commission adopted this approach because historical data are more objective, readily available, and less subject to manipulation by sellers than future projections. The Commission reiterates its concern that if the Commission were to require sellers to submit studies or change in status filings based on their future projections such as “imminent changes,” then sellers would be able to selectively “cherry pick” those changes that benefited the seller in retaining market-based rate authorization while ignoring other equally likely future changes that would undermine the seller’s chances for obtaining or retaining market-based rate authorization. Similarly, intervenors could introduce only those imminent changes that result in higher market shares for a seller, thus artificially increasing the seller’s market shares. In addition, requiring a seller to submit market power analyses that reflect future or “imminent changes” such as the future expiration of a long-term contract would be excessively burdensome because, for an accurate representation, review of all expiring contracts, and all contracts being negotiated inside the relevant market and the seller’s home balancing authority area and its first-tier markets may be necessary. Otherwise, the seller’s analysis might be incomplete and produce invalid results.
In addition, as explained above, future changes are not necessarily known and measurable since a long-term contract may be expiring in a year, but until it expires, it often can be renewed for the same term. Likewise, the Commission does not allow the seller to deduct capacity that it is currently negotiating to sell to third parties. To do so would allow the seller to argue that it has an “imminent” sale and the Commission should consider that capacity to be committed, resulting in lowering the seller’s market shares. The danger in this circumstance is, like the expiring contract that could be extended, the sale may not actually occur and the seller could appear to have rebutted the presumption of market power when in fact, based on actual data, it has market power. Therefore, an analysis that assumes that the long-term capacity associated with an expiring contract is uncommitted would not always be correct. In addition, because the definition of “imminent” is a matter of interpretation and may change depending on the circumstances, it would produce regulatory uncertainty. For all of these reasons, the Commission’s determination to rely on unadjusted historical data in the indicative screens and the DPT analysis is based on reasoned decision making.
Notwithstanding the Commission’s policy requiring the use of historical data and a “snapshot in time approach,” in previous cases, the Commission nevertheless has addressed evidence presented by intervenors who sought to demonstrate that upon expiration of a long-term contract, a seller would be able to exercise market power.70 Indeed, in cases where this issue has arisen, the Commission considered the impact of the expiring long-term contract on the seller’s market power and concluded that even when adjustments were made to the available economic capacity measure to account for expiring contracts, the seller did not fail the indicative screens.71
While the Commission continues to believe that the “snapshot in time approach” is appropriate, and will continue to require the use of historical data in the market power analysis, the Commission nevertheless will consider, on a case-by-case basis, clear and compelling evidence presented by sellers and intervenors that seek to demonstrate that certain changes in the market, such as the expiration of a long-term contract, should be taken into account as part of the market power analysis in a particular case. Entities who seek to make this demonstration must present clear and compelling evidence in support of their argument. The Commission will address any countervailing factors that affect whether the seller will have the ability to exercise market power. Such countervailing factors could include, but are not limited to, any competitor that similarly has expiring long-term contracts and any other factors that might impact the market power analysis such as plant retirements, transmission access, and generation upgrades. In this regard, we remind entities that they must perform the market power screens as designed but may also provide a sensitivity analysis consistent with the discussion above.
The Commission rejects Montana Counsel’s argument that, if the Commission considers a seller’s proposal to transfer operational control of enough generation to a third party as part of its proposed mitigation so that the seller would satisfy the Commission’s horizontal market power concerns, then the Commission should also consider imminent changes that would increase a seller’s market shares. Consideration of a proposal to transfer operational control of generation as part of a seller’s proposed mitigation, unlike consideration of imminent changes as part of a seller’s market power analysis, does not run the risk that a seller’s market power may be hidden. Moreover, the act of transferring control may be enough to reduce the seller’s market shares sufficiently to address market power concerns.
The Commission adopted a two-way information sharing restriction in § 35.39(d) prohibiting a franchised public utility with captive customers from sharing information with a market-regulated power sales affiliate, and vice-versa.72
Requests for Rehearing
Southern argued the Commission erred in Order No. 697 by adopting a two-way information restriction (§ 35.39(d)) that prevents a franchised public utility from receiving information from its market-regulated power sales affiliate. Southern claims that the Commission failed to demonstrate that communications from a market-regulated power sales affiliate to a franchised public utility would harm captive customers and that the existing one-way communication restriction currently in many Commission-accepted codes of conduct is insufficient.
Southern stated that the Commission provided one example of how information shared with a franchised public utility by its market-regulated affiliate might harm captive customers. Specifically, the Commission stated that in an RFP situation where both a franchised public utility and its market-regulated affiliate are considering whether to submit a bid and the market-regulated affiliate is allowed to share its price and quantity information, the franchised public utility could possibly use the information for the benefit of its stockholders at the expense of its captive customers. However, Southern submits that § 35.39(d) is written much broader than is necessary to address this concern, and could serve to unnecessarily prevent a franchised public utility from receiving operational information under Commission-approved generation pooling arrangements. Southern argued that the Commission has not suggested much less demonstrated that a franchised public utility’s knowledge of the status of its market-regulated affiliate’s units could advantage the market-regulated affiliate at the expense of the franchise public utility’s captive customers. Accordingly, Southern alleged Order No. 697 is without a rational basis in this regard and unsupported by substantial evidence.73
Southern believes that the two-way restriction would actually harm captive customers by impairing the pooling arrangement, thereby denying them the traditional benefits of integration and coordinated operations and by triggering costs and inefficiencies that far outweigh any conceivable benefit. Accordingly, Southern requests that the Commission reconsider the two-way information sharing restriction.
Moreover, according to Southern, the Commission failed to recognize the implementation burden that will be imposed by the two-way restriction. Southern submits that the Commission has grossly underestimated the expense and effort that will be required for utilities to implement the two-way restriction.74 Based on its actual experience, Southern believes that compliance with the two-way restriction will be very costly to utilities and require a substantial amount of time to complete, potentially in excess of six months (a much longer period than is allowed by an effective date of 60 days after the Final Rule’s publication in the Federal Register).75 While some utilities may be able to complete their implementation of the two-way restriction within this period, Southern argues it is more likely that most utilities will need more time to ensure compliance. Thus, to the extent the Commission maintains the two-way restriction, Southern requests that the Commission allow utilities and their market-regulated power sales affiliates sufficient time to implement the two-way restriction.76
To the extent the Commission maintains the restriction, in any form, Southern requests that the Commission clarify the scope of § 35.39(d) and limit the types of information that are restricted to be consistent with the above-described example set forth in Order No. 697. 77 Southern states that, at a minimum, the Commission should provide an exception for information provided to franchised public utilities by their market-regulated affiliate pursuant to participation in Commission-approved pooling arrangements. Finally, and to the extent the Commission retains any two-way restrictions, it should allow franchised public utilities and their market-regulated power sales affiliates sufficient time to assess their organizations and technology infrastructures and implement the measures necessary to ensure compliance.78
Commission’s Response
After consideration of Southern’s arguments, the Commission will grant Southern’s request for rehearing on this issue.
As previously explained, the purpose of the affiliate restrictions is to ensure that captive customers of a franchised public utility are adequately protected from any harm that may arise from affiliate dealings. In an attempt to provide regulatory certainty, and upon further review, the Commission finds that the one-way information sharing restriction, which prohibits a franchised public utility with captive customers from sharing market information with a market-regulated power sales affiliate, adequately protects captive customers. The Commission has not been presented with any specific examples how captive customers have been harmed by a market-regulated power sales affiliate sharing market information with its franchised public utility with captive customers. The Commission also notes that adopting a one-way information sharing restriction is consistent with the Commission’s approach in the Standards of Conduct.
While the Commission is granting Southern’s request for rehearing on this issue, the Commission reminds sellers that the information sharing provision, like all affiliate restrictions, is subject to the no-conduit rule. 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. Additionally, the Commission reminds all market-based rate sellers that the FPA prohibits any seller from providing an undue preference to an affiliate or any other seller.79
In Order No. 697, the Commission adopted a definition of market information: “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.”80 The Commission explained that market information includes information that, if shared between a franchised public utility and a market-regulated affiliate, could result in a detriment to the franchised public utility’s captive customers.81
Requests for Rehearing
Ameren argued that, in introducing its new definition of “market information,” for purposes of the restrictions on affiliates sharing information, the Commission incorrectly quotes from its 1996 order in UtiliCorp United, Inc.82 Specifically; Ameren alleges that the Commission recited the list of types of data from UtiliCorp, but added “past” to the litany. According to Ameren, this “misquote” sets the stage for the new definition to include past information, such as “historical generator volumes” and “past sales and purchase activities.” Ameren requested rehearing of this expansion of the definition of the term “market information” to include past information. In addition, Ameren stated that the Commission does not explain how past information, such as historical generator volumes, could be used to the detriment of the franchised public utility’s captive customers.83
Commission’s Response
The Commission denies Ameren’s request for rehearing. The Commission is intentionally including past market information in the information disclosure prohibitions because there are instances in which the sharing of historical (or past) market information between a franchised public utility with captive customers and a market-regulated power sales affiliate can potentially harm captive customers. For example, if a market-regulated power sales utility had knowledge of its affiliated franchised public utility’s prior costs of purchasing power, it could use this information to outbid a competitor in a request for proposals to supply power to the franchised public utility. The Commission notes, however, that the restriction on sharing market information, whether past, present, or future, does not apply to information that is publicly available.84
In Order No. 697, the Commission continued its requirement for sellers to report any change in status that departs from the characteristics relied upon by the Commission in authorizing sales at market-based rates.85 Events that constitute a change in status include, among other things, ownership or control of generation capacity that result in net increases of 100 MW or more, and change in upstream ownership. Notification of any such changes in status must be filed no later than 30 days after the change occurs.
Also in Order No. 697, the Commission created a category of market-based rate sellers that are exempt from the requirement to submit regularly scheduled updated market power analyses. These Category 1 sellers have been carefully defined by the Commission to have attributes that are not likely to present market power concerns.86 Market power concerns for Category 1 sellers are monitored by the Commission through the change in status reporting requirement and through ongoing monitoring by the
Commission’s Office of Enforcement. All other sellers, Category 2 sellers, are, in addition, required to continue to file regularly scheduled updated market power analyses. 87
Requests for Rehearing
TDU Systems asserted that to protect consumers more adequately, the Commission should require a Category 2 seller to submit an updated market power analysis in each instance in which a seller’s generation increases by a predetermined percentage or an absolute amount.88 TDU Systems stated that under the Commission’s present rules, a public utility that builds or acquires new generation capacity or merges with another company is not required to submit a new horizontal market power analysis. It is required only to file a change in status report for any net increase of 100 MW or more. TDU Systems references a proposal made by another commenter in response to the NOPR asking the Commission to require an updated market power analysis in each instance in which a seller’s generation increases by a predetermined percentage or absolute amount. According to TDU Systems, the Commission did not directly address this proposal in the Final Rule,89 but indirectly touched on the issue by stating that an updated market power analysis may be required from any sellers, Category 1 or 2, at any time.
TDU Systems asserted that the Commission erred in failing to address the merits of this proposal in the Final Rule.90 They contend that the Commission should not burden itself with deciding when major additions to generation, revealed in a change in status report, are likely to alter the results of its market power tests. They submit that it would not be an unreasonable burden on Category 2 sellers to prepare updated analyses within a reasonable time from the acquisition of additional generation.
Commission’s Response
In the Final Rule, the Commission stated that it retains the tools necessary to ensure that all rates are just and reasonable, with initial market power evaluations, ongoing monitoring by the Commission, change in status reporting requirements, and scheduled updated market power analyses for Category 2 sellers.91 The Commission continues to believe that these requirements provide the Commission with the tools it needs to ensure that rates remain just and reasonable.
In Order No. 652, the Commission clarified and standardized market-based rate sellers’ reporting requirement for changes in status and the Commission considered and rejected the idea that change in status filings include an updated market power analysis. The Commission explained that it is incumbent on an applicant to decide whether a change in status is a material change and that an applicant should provide adequate support and analysis, including an updated market power analysis if it chooses.92 Thus, if a market-based rate seller believes that a change in status does not affect the continuing basis of the Commission’s grant of market-based rate authority, it should clearly state the reasons on which it bases this conclusion, including an updated market power analysis if it so chooses.
While the Commission appreciates TDU Systems’ proposal and agrees that it would not necessarily be an unreasonable burden to require Category 2 sellers to prepare updated analyses within a reasonable time from the acquisition of additional generation, the Commission is not persuaded that its current approach is not adequate. The existing reporting requirement provides the Commission a sufficient tool to allow it to assess whether there is a potential market power concern and, if so, the Commission reserves the right to require the seller to submit a market power study. In addition, the seller is required to provide an affirmative statement as to what effect, if any, the added generation has on its market power. For a seller to make such an affirmative statement, it must determine what effect the added generation has on the market power analysis. To the extent the seller makes an affirmative statement that there is no effect on its market power, it is bound to that statement and faces remedial action, including civil penalties, if it has misrepresented the effect.
Therefore, the Commission will not require entities to automatically file an updated market power analysis with their change in status filings, such as that required by a triennial review. However, an entity may provide such an analysis if it chooses. Furthermore, regardless of the seller’s representation, if the Commission has concerns with a change in status filing (for example, market shares are below 20 percent, but are relatively high nonetheless), the Commission retains the right to require an updated market power analysis at any time.93
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 that were proposed in the 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.9495
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 specifies 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 Final Rule. 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 used the same estimates in the Final Rule as it did in the NOPR.96
As noted in the Final Rule, the number of respondents expected to file revised market-based rate tariffs 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 estimated the total number to be filed to be approximately 1230, rather than 650 as reported in the NOPR. The Commission conformed 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 the Final Rule, the Commission required 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 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 as stated in the Final Rule 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--97 |
217 |
6 |
3,900 |
Triennial Review Category 1--98 |
0 |
0 |
0 |
0 |
Triennial Review Category 2--99 |
600 |
200--100 |
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 |
410101 |
6 |
2460 |
Category 1 Qualification Filings102 |
630 |
210103 |
15104 |
3150 |
Updated Analyses Category 2105 |
600 |
200106 |
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 |
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 $ 472,500.107
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.
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).
REASONS FOR CHANGES IN BURDEN INCLUDING THE NEED FOR ANY INCREASE
This Final Rule represented 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.
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
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.
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.).
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] defined 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 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 Fed. Reg. 12,266 (March 15, 2007). FERC Statutes and Regulation , Regulations Preambles January 2006-January 2008.
12 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).)
13 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.
14 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.)
15 See 18 CFR § 35.1(g) (2005).
16 See, e.g., Black Creek Hydro, Inc., 77 FERC ¶ 61,232 (1996).
17 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.
18 Failure to timely file a triennial review would constitute a tariff violation.
19 Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 697, 72 Fed. Reg. 39,904 (Jul. 20, 2007), FERC Stats. & Regs. ¶ 31,252 (2007) (Final Rule).
20 Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 121 FERC ¶ 61,260 (2007) (Clarification Order).
21 Cross-Subsidization Restrictions on Affiliate Transaction, Order No. 707, 73 FR 11013 (Feb. 29, 2008), FERC Stats. & Regs. ¶ 31,264 (Feb. 21, 2008) (Affiliate Transactions Final Rule).
22 16 U.S.C. 824d(a) (2000).
23 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.
24 The seller has the option of withdrawing its market-based rate request in whole or in part.
25 See FPL Energy Marcus Hook, L.P. v. PJM Interconnection, LLC, 118 FERC ¶ 61,169, at P 11, n.9 (2007) (parties litigated a complaint case based on a superseded tariff provision).
26 Order No. 697 at P 62.
27 Id. P 33, 35.
28 Order No. 697 states that uncommitted capacity is determined by adding the total nameplate capacity of generation owned or controlled through contract and firm purchases, less operating reserves, native load commitments and long-term firm sales. Order No. 697 at P 38. Order No. 697 further states that uncommitted capacity from a seller’s remote generation (generation located in an adjoining balancing authority area) should be included in the seller’s total uncommitted capacity amounts. Id. However, one of the standard screen formats included at Appendix A to Order No. 697 does not capture these details. Part I – Pivotal Suppler Analysis, inadvertently does not include Row H (imported power) and Row M (average daily Peak Native Load in Peak month, a proxy for native load commitment) in calculating Row K (total uncommitted supply). The Commission thus corrected this error in the Revised Appendix A to include the missing variables of the equation.
29 Id. P 41.
30 See id. P 49. Generally, advocates of the contestable load analysis believe that, if available non-applicant supply is at least twice the contestable load that is sufficient to make a finding that the market is competitive.
31 Id. P 66.
32 Order No. 697 also dealt with the following issues, about which rehearing has not been sought: control and commitment of generation resources; elimination of former 18 CFR 35.27, which had exempted newly-constructed generation from the horizontal market power analysis; reporting format for the indicative screens; nameplate capacity; and several procedural issues.
33 Southern Rehearing Request at 7-8 (citing 16 U.S.C. 824e(a); FPC v. Sierra Pacific Power Co., 350 U.S. 348 at 353 (1956) (Sierra); Public Service Commission of New York v. FERC, 642 F.2d 1335, 1345 (D.C. Cir. 1980); Public Service Co. of New Mexico, 115 FERC ¶ 61,090, at P 33 (2006)).
34 Id. at 7 (citing Order No. 697 at P 63).
35 Id. at 8.
36 Id. (citing Order No. 697 at P 62, 71, 74, 89). Further, Southern asserts that only in instances of high market share should a prima facie case of market power be established, which would shift the burden of proof. Id. at 10 & n.10 (citing U.S. v. Syufy, 903 F.2d 659, 664 (9th Cir. 1990); Hunt-Wesson Foods, Inc. v. Ragu Foods, Inc., 627 F.2d 919, 924 (9th Cir. 1980), cert. denied, 450 U.S. 921 (1981)).
37 Id. at 11.
38 Id. at 20 (citing 5 U.S.C. 706(2)(A) and (E) (2000); Union Pac. Fuels, Inc. v. FERC, 129 F.3d 157, 161 (D.C. Cir. 1997) (holding that review of Commission orders is made under the arbitrary and capricious standard of the Administrative Procedure Act); Sithe Independence Power Partners v. FERC, 165 F.3d 944 (D.C. Cir. 1999)(stating that the Commission must be able to demonstrate that it has “made a reasoned decision based upon substantial evidence in the record” and the “path of [its] reasoning” must be clear) (quoting Town of Norwood v. FERC, 962 F.2d 20, 22 (D.C. Cir. 1992)).
39 Id. at 3-4 (citing United States v. Grinnell Corp., 384 U.S. 563, 571 (1966); MetroNet Services Corp. v. U.S. West Communications, 329 F.3d 986 (9th Cir. 2003); United States v. Dentsply International, Inc., 399 F.3d 181, 187 (3rd Cir. 2005)).
40 Id. at 12-13.
41 Id. at 13.
42 Id. at 15 and Frame affidavit at ¶ 25, referring to Order No. 697 at P 66-67.
43 See AEP Power Marketing, Inc., 108 FERC ¶ 61,026, at P 30 (2004) (July 8 Order) (“Failure of a screen establishes a rebuttable presumption of market power, which satisfies the Commission’s initial burden of going forward in such proceedings. The burden of going forward will then be upon the applicant once such a proceeding is initiated.”); see id. P 29 (stating that passing both screens or failing one merely establishes a rebuttable presumption, and explaining that in the case of an intervenor in a section 205 proceeding that seeks to prove that the applicant possesses market power, “the intervenor need only meet a ‘burden of going forward’ with evidence that rebuts the results of the screens. At that point, the burden of going forward would revert back to the applicant to prove that it lacks market power.”) (citing Pennzoil Co. v. FERC, 645 F.2d 360, 392 (5th Cir. 1981), cert. denied, 454 U.S. 1142 (1982); accord Transcontinental Gas Pipe Line Corp., Opinion No. 135, 17 FERC ¶ 61,232, at 61,450 (1981) (“The presumption … is the same as that which arises from a prima facie case: it imposes on the party against whom it is directed the burden of going forward with substantial evidence to rebut or meet the presumption, but does not shift the burden of persuasion.”); Generic Determination of Rate of Return on Common Equity for Electric Utilities, Order No. 389-A, 29 FERC ¶ 61,223, at 61,458 (1984) (concluding that rebuttable presumption that a rate of return based on a benchmark is just and reasonable does not shift ultimate burden of proof imposed by Federal Power Act)); see also Southern Companies Energy Marketing, Inc., 111 FERC ¶ 61,144, at P 24 (2005) (stating that a “screen failure satisfies the Commission’s burden of going forward and shifts to the applicant the burden of presenting evidence rebutting the presumption of market power”), order dismissing reh’g as moot, 119 FERC ¶ 61,300 (2007).
44 See Order No. 697 at P 65.
45 Id. P 62.
46 Id. P 71.
47 Id. P 135.
48 Id. P 137.
49 Southern Rehearing Request at 11.
50 The Commission further addresses Southern’s arguments with regard to the DPT analysis in the rule.
51 See In the Matter of Merger Policy Under the Federal Power Act, May 7, 1996 Comments of the U.S. Department of Justice, Docket No. RM96-6-000 (providing comments on the Commission’s standards for determining whether a proposed merger is in the public interest, recommending that the Commission apply a market share screen to identify quickly those mergers that are unlikely to raise competitive issues and concluding that the Horizontal Merger Guidelines provide “sound competitive analysis”); see also U.S. Department of Justice and the Federal Trade Commission, Horizontal Merger Guidelines, section 2.0, reprinted at 4 Trade Reg. Rep. (CCH) ¶13,104 (Issued April 2, 1992, Revised April 8, 1998).
52 Order No. 697 at P 65.
53 Id.
54 Id. P 66.
55 Id.
56 Montana Counsel Rehearing Request at 7.
57 Id. at 7-8 (citing PPL Montana, LLC, 115 FERC ¶ 61,204 (2006) (PPL Montana)). Montana Counsel included its request for rehearing of PPL Montana, filed June 16, 2006 in Docket No. EL05-124, et al., as Attachment A to its request for rehearing of Order No. 697. Id. at 8. The Montana Counsel’s rehearing request in the PPL Montana proceeding asserted that the Commission’s decision to renew the market-based rate authority of the PPL Montana Companies is in error insofar as it is contrary to record evidence and the requirements of the Federal Power Act. The Commission denied Montana Counsel’s request for rehearing in PLL Montana LLC, 120 FERC ¶ 61,096 (2007).
58 Id. at 8-9.
59 Id. at 9 (citing Order No. 697 at P 25, 63 n.46).
60 Id.
61 NRECA Rehearing Request at 3, 21 (citing Cal. ex rel. Lockyer v. FERC, 383 F.3d 1006 (9th Cir. 2004) (Lockyer); 5 U.S.C. 706(2)(A), (C)).
62 Id. at 21 (citing Mo. Pub. Serv. Comm’n v. FERC, 337 F.3d 1066, 1075 (D.C. Cir. 2003) (“Reliance on facts that an agency knows are false at the time it relies on them is the essence of arbitrary and capricious decision making.”)).
63 Id. at 22.
64 Id. (citing Motor Vehicle Mfrs. Ass’n, 463 U.S. at 43; Pac. Gas & Elec. Co. v. FERC, 373 F.3d at 1319).
65 Id. at 23 (citing Lockyer, 383 F.3d at 1014-15. See also TDU Systems Rehearing Request at 17.
66 TDU Systems Rehearing Request at 7, 16 (citing Mo. Pub. Serv. Comm’n v. FERC, 337 F.3d 1066, 1075 (D.C. Cir. 2003)).
67 Id. at 17.
68 Order No. 697 at P 299.
69 For the reasons stated above, the Commission also rejects NRECA’s argument that the triennial review and the change in status filing will come too late.
70 PPL Montana, LLC, 115 FERC ¶ 61,204, at P 46 (2006), order denying reh’g, 120 FERC ¶ 61,096, at P 52-54 (2007); Boralex Livermore Falls LP, 122 FERC ¶ 61,033, at P 43 (2008).
71 Id.
72 Id. P 583.
73 Southern Rehearing Request at 6 (citing Motor Vehicles Mfrs. Ass’n., 463 U.S. at 43 (1983) (stating that the agency must articulate a “rational connection between the facts found and the choice made”); Burlington Truck Lines v. U.S., 371 U.S. 156, 168 (1962); Western Union v FCC, 856 F.2d 315, 318 (D.C. Cir. 1988) (stating that an agency must demonstrate a “rational connection between the facts found and the choice made”)).
74 Id. at 37.
75 Order No. 697 at P 1133.
76 Southern Rehearing Request at 36, 39.
77 Id. at 39.
78 Id. at 40-41.
79 See 16 USC 824d (2001).
80 Order No. 697 at P 591 (to be codified at 18 CFR 35.36(a)(8)).
81 Id. P 593.
82 75 FERC ¶ 61,168 (1996) (UtiliCorp).
83 Ameren Rehearing Request at 8.
84 Order No. 697 at P 592. To use an example cited by Ameren, once past sales information is filed with the Commission in an EQR, such information would not be covered by the information disclosure prohibition.
85 Order No. 697 at P 1009-1045 (codifying the requirement, as amended, at 18 CFR 35.42).
86 Id. at P 853.
87 Previously, updated market power analyses were submitted within three years of any order granting a seller market-based rate authority, and every three years thereafter.
88 TDU Systems at 28 (citing NRECA NOPR comments at 24. NRECA gives examples of predetermined thresholds as a certain percentage increase over the current amount, or any increase over some absolute amount).
89 TDU Systems indicate that NRECA suggested this proposal. TDU Systems at 27-28 (citing NRECA NOPR comments at 23-25).
90 Id. at 4-5 (citing K N Energy, Inc. v. FERC, 968 F.2d 1295, 1303 (D.C. Cir. 1991)).
91 Order No. 697 at P 853-854.
92 Order No. 652, FERC Stats. & Regs. ¶ 31,175 at P 94-95.
93 Order No. 697 at P 856-857.
94 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.
96 As noted above the number of market-based rate sellers has increased since issuance of the NOPR in May 2006.
97 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.
98 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.
99 Category 2 Sellers are any sellers not in Category 1.
100 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.
101 We expect responses to be staggered over the course of three years. Accordingly, the number of respondents (1230) has been divided by three.
102 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.
103 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.
104 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.
105 Category 2 sellers are any sellers not in Category 1.
106 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.
107 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.
| File Type | application/msword |
| Author | Mpmed12 |
| Last Modified By | michael miller |
| File Modified | 2008-05-15 |
| File Created | 2008-05-12 |