FERC Seeks Comments on Proposed Rulemaking Regulations for Market Based Rates of Electric Energy, Capacity and Ancillary Services
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WASHINGTON, July 25 -- The Federal Energy Regulatory Commission published the following proposed rule in the Federal Register:
Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities
A Proposed Rule by the Federal Energy Regulatory Commission on 07/25/2014
Publication Date: Friday, July 25, 2014
Agencies: Department of Energy
Federal Energy Regulatory Commission
Dates: Comments are due September 23, 2014.
Comments Close: 09/23/2014
Entry Type: Proposed Rule
Action: Notice of proposed rulemaking.
Document Citation: 79 FR 43535
Page: 43535 -43572 (38 pages)
CFR: 18 CFR 35
Agency/Docket Number: Docket No. RM14-14-000
Document Number: 2014-16002
Shorter URL: https://federalregister.gov/a/2014-16002
Notice Of Proposed Rulemaking.
The Federal Energy Regulatory Commission (Commission) is proposing to amend its regulations governing market-based rates for public utilities pursuant to the Federal Power Act (FPA). The Commission is proposing to revise its current standards for market-based rates for sales of electric energy, capacity, and ancillary services to streamline certain aspects of its filing requirements to reduce the administrative burden on applicants and the Commission. The Commission seeks comment on the proposed revisions. In addition, the Commission provides some clarification regarding the standards for obtaining and retaining market-based rate authority.
Comments are due September 23, 2014.
Comments, identified by docket number, may be filed in the following ways:
Electronic Filing through http://www.ferc.gov. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format.
Mail/Hand Delivery: Those unable to file electronically may mail or hand-deliver comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE., Washington, DC 20426.
Instructions: For detailed instructions on submitting comments and additional information on the rulemaking process, see the Comment Procedures Section of this document.
FOR FURTHER INFORMATION CONTACT:
Joseph Cholka (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission,888 First Street NE., Washington, DC 20426, 202-502-8876.
Carol Johnson (Legal Information), Office of the General Counsel,Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, 202-502-8521.
1. Pursuant to sections 205 and 206 of the Federal Power Act (FPA),  the Commission is proposing to amend its regulations to revise Subpart H to Part 35 of Title 18 of the Code of Federal Regulations (CFR), which governs market-based rate authorizations for wholesale sales of electric energy, capacity, and ancillary services by public utilities.
2. In 1988, the Commission began considering proposals for market-based pricing of wholesale power sales. The Commission acted on market-based rate proposals filed by various wholesale suppliers on a case-by-case basis. Over the years, the Commission developed a four-prong analysis to assess whether a seller should be granted market-based rate authority: (1) Whether the seller and its affiliates lack, or have adequately mitigated, market power in generation; (2) whether the seller and its affiliates lack, or have adequately mitigated, market power in transmission; (3) whether the seller or its affiliates can erect other barriers to entry; and (4) whether there is evidence involving the seller or its affiliates that relates to affiliate abuse or reciprocal dealing.
3. In April 2004, the Commission initiated a rulemaking proceeding to consider the adequacy of its market-based rate 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 FPA.  At that time, the Commission noted that much had changed in the industry since its analysis was first developed and posed a number of questions that would be explored through a series of technical conferences. Following the technical conferences, the Commission issued a notice of proposed rulemaking that led to the issuance in 2007 of Order No. 697, which clarified and codified the Commission's market-based rate policy. 
4. In Order No. 697, the Commission adopted two indicative screens for assessing horizontal market power: The pivotal supplier screen and the wholesale market share screen (with a 20 percent threshold), each of which serves as a cross check on the other to determine whether sellers may have market power and should be further examined.  The Commission stated that passage of both indicative screens establishes a rebuttable presumption that the seller does not possess horizontal market power. Sellers that fail either indicative screen are rebuttably presumed to have market power and are given the opportunity to present evidence through a delivered price test (DPT) analysis demonstrating that, despite a screen failure, they do not have market power.  The Commission uses a "snapshot in time" approach based on historical data for both the indicative screens and the DPT analysis. 
5. With respect to the horizontal market power analysis, in traditional markets (outside regional transmission organization/independent system operator (RTO/ISO) markets),  the default relevant geographic market for purposes of the indicative screens is first, the balancing authority area(s) where the seller is physically located, and second, the markets directly interconnected to the seller's balancing authority area (first-tier balancing authority areas).  Generally, sellers that are located in and are members of the RTO may consider the geographic region under the control of the RTO as the default relevant geographic market for purposes of the indicative screens. 
6. With respect to the vertical market power analysis, in cases where a public utility or any of its affiliates owns, operates, or controls transmission facilities, the Commission requires that there be a Commission-approved Open Access Transmission Tariff (OATT) on file, or that the seller or its applicable affiliate has received waiver of the OATT requirement, before granting a seller market-based rate authorization.  The Commission also considers a seller's ability to erect other barriers to entry as part of the vertical market power analysis.  As such, the Commission requires a seller to provide a description of its ownership or control of, or affiliation with an entity that owns or controls, intrastate natural gas transportation, storage or distribution facilities; sites for generation capacity development; and physical coal supply sources and ownership of or control over who may access transportation of coal supplies (collectively, inputs to electric power production).  In Order No. 697-C, the Commission revised the change in status reporting requirement in section 35.42 of the Commission's regulations to require market-based rate sellers to report the acquisition of control of sites for new generation capacity development on a quarterly basis instead of within 30 days of the acquisition.  The Commission adopted a rebuttable presumption that the ownership or control of, or affiliation with any entity that owns or controls, inputs to electric power production does not allow a seller to raise entry barriers but will allow intervenors to demonstrate otherwise.  Finally, as part of the vertical market power analysis, the Commission also requires sellers to make an affirmative statement that they have not erected barriers to entry into the relevant market and will not erect barriers to entry into the relevant market. The Commission clarified that the obligation in this regard applies to both the seller and its affiliates but is limited to the geographic market(s) in which the seller is located. 
7. If a seller is granted market-based rate authority, the authorization is conditioned on: (1) Compliance with affiliate restrictions governing transactions and conduct between power sales affiliates where one or more of those affiliates has captive customers;  (2) a requirement to file post-transaction electric quarterly reports (EQR) with the Commission containing: (a) A summary of the contractual terms and conditions in every effective service agreement for market-based power sales; and (b) transaction information for effective short-term (less than one year) and long-term (one year or longer) market-based power sales during the most recent calendar quarter;  (3) a requirement to file any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority;  and (4) a requirement for large sellers to file updated market power analyses every three years. 
8. In Order No. 697, the Commission created two categories of sellers.  Category 1 sellers are wholesale power marketers and wholesale power producers that own or control 500 megawatts (MW) or less of generation in aggregate per region; that do not own, operate, or control transmission facilities other than limited equipment necessary to connect individual generation facilities to the transmission grid (or have been granted waiver of the requirements of Order No. 888  ); that are not affiliated with anyone that owns, operates, or controls transmission facilities in the same region as the seller's generation assets; that are not affiliated with a franchised public utility in the same region as the seller's generation assets; and that do not raise other vertical market power issues.  Category 1 sellers are not required to file regularly scheduled updated market power analyses. Sellers that do not fall into Category 1 are designated as Category 2 sellers and are required to file updated market power analyses.  However, the Commission may require an updated market power analysis from any market-based rate seller at any time, including those sellers that fall within Category 1. 
9. In Order No. 697, the Commission further stated that through its ongoing oversight of market-based rate authorizations and market conditions, the Commission may take steps to address seller market power or modify rates. For example, based on its review of updated market power analyses, EQR filings, or notices of change in status, the Commission may institute a proceeding under section 206 of the FPA to revoke a seller's market-based rate authorization if it determines that the seller may have gained market power since its original market-based rate authorization. The Commission also may, based on its review of EQR filings or daily market price information, investigate a specific utility or anomalous market circumstance to determine whether there has been a violation of RTO market rules or Commission orders or tariffs, or any prohibited market manipulation, and take steps to remedy any violations. 
10. As discussed below, after over six years of experience with the implementation of Order No. 697, we propose certain changes and clarifications in order to streamline and simplify the market-based rate program, and to enhance and improve the program's processes and procedures. Based on our experience, we have found that the burdens associated with certain of our requirements may outweigh the benefits in certain circumstances. For these reasons, we propose a number of changes to the market-based rate program which, taken as a whole, will reduce the burden on industry and the Commission, while continuing to ensure that the standards for market-based rate sales of electric energy, capacity and ancillary services result in sales that are just and reasonable. We also include several specifications and propose a number of minor changes that will add clarity to, and improve transparency in, the market-based rate program.
Summary of Proposals
11. Although we intend to retain the horizontal indicative screens, we propose certain modifications to our horizontal market power analysis. First, we propose to allow sellers in RTO markets to address horizontal market power issues in a streamlined manner that would not involve the submission of indicative screens if the seller relies on Commission-approved monitoring and mitigation to prevent the exercise of market power. We also propose to clarify that where all generation capacity owned or controlled by a seller and its affiliates in the relevant balancing authority areas (including first-tier balancing authority areas or markets) is fully committed, sellers may explain that their capacity is fully committed in lieu of submitting indicative screens as part of their horizontal market power analysis.
12. While we are retaining the definition of the default geographic market for the vast majority of sellers, we are proposing a redefined default relevant geographic market for an independent power producer (IPP) with generation capacity located in a generation-only balancing authority area. We propose that, instead of the default geographic market being the generation-only balancing authority area where its generation is located, the IPP's default geographic market(s) will be the balancing authority area(s) of each transmission provider to which the generation-only balancing authority area is directly interconnected.
13. In Order No. 697, the Commission adopted standard indicative screen formats for submitting a horizontal market power analysis. We propose to add rows to the indicative screen format for sellers to specify Simultaneous Transmission Import Limit (SIL) Values, Long-Term Firm Purchases (from outside the study area), and Remote Capacity (from outside the study area), as well as modifications to the descriptive text of the rows to make them more consistent. We further propose to revise the regulations to require that sellers file the indicative screens in a workable electronic spreadsheet format. We also propose to revise the Commission's regulations to codify the requirement, first discussed in Puget Sound Energy, Inc.,  that sellers submitting SIL studies adhere to the direction and required format for Submittals 1 and 2 found on the Commission's Web site and that sellers submit Submittals 1 and 2 in a workable electronic spreadsheet format.
14. The Commission previously stated that sellers could make simplifying assumptions such as "performing the indicative screens assuming no import capacity." We clarify that "assuming no import capacity" means a seller may assume that there is no competing import capacity from the first-tier balancing authority areas or markets.
15. The Commission generally permits sellers submitting indicative screens to rate their generation facilities using either nameplate or seasonal capacity ratings. In addition, the Commission allows sellers with energy-limited resources, such as hydroelectric and wind generation facilities, to use a five-year average capacity factor. We propose to include solar technologies as energy-limited generation resources. We further propose that sellers with energy-limited resources that do not have five years of historical data may use regional capacity factor estimates appropriate to the specific technology as derived by the United States Energy Information Administration (EIA) to determine the capacity for those resources. We also propose to clarify that a seller must use the same capacity rating methodology for similar generation assets throughout a particular filing.
16. The Commission has stated that a seller's uncommitted capacity is determined by adding the nameplate or seasonal capacity of generation owned or controlled through contract and long-term firm capacity purchases, less operating reserves, native load commitments, and long-term firm sales. Therefore, sellers have been reporting their long-term firm purchases as part of their capacity if the purchase granted them control of that capacity. We propose to require sellers to report all of their long-term firm purchases of capacity and/or energy in their indicative screens and asset appendices, regardless of whether the seller has operational control over the generation capacity supplying the purchased power. This approach will help size the market correctly and will establish consistent treatment of long-term firm sales and long-term firm purchases.
17. The Commission's vertical market power analysis examines affiliation, ownership or control of inputs to electric power production, including sites for generation capacity development. In this Notice of Proposed Rulemaking (NOPR), we propose to eliminate the requirement that sellers provide information on sites for generation capacity development in their market-based rate applications and triennial updated market power analyses and to similarly relieve sellers of their obligation to file quarterly land acquisition reports.
18. The Commission requires that sellers report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority. We propose to revise the regulations to clarify that the 100 MW reporting threshold for filing a notice of change in status is not limited to markets previously studied; thus if a seller acquires generation that causes a cumulative net increase of 100 MW or more in any relevant geographic market, the seller must file a notice of change in status. We also propose to revise the regulations to include long-term firm purchases of capacity and/or energy in calculating the 100 MW change in status threshold. Although there currently is no threshold for reporting a change in status that results in a new affiliation, we propose to revise the regulations to include a 100 MW threshold for reporting new affiliations.
19. The Commission requires that sellers include with each new application, market power analysis, and relevant change in status notification an asset appendix that lists all affiliates that have market-based rate authority and identifies assets owned or controlled by the seller and its affiliates. We propose to revise the asset appendix by revising the headings of several columns to be more clear and consistent. We also propose several clarifications to the asset appendix requirements. In particular: (1) A seller must enter the entire amount of a generator's capacity, even if the seller only owns part of the generator; (2) a seller must list one of three specified uses for assets in the asset list containing electric transmission and intrastate gas assets; and (3) sellers should not list assets in which passive ownership interests have been claimed. We also propose to modify the asset appendix to add a new column in the list of transmission assets for the citation to the Commission order accepting the OATT or granting waiver of the OATT requirement. We further propose to require that sellers submit the asset lists in an electronic spreadsheet format that can be searched, sorted, and accessed using electronic tools. We also seek comment on whether it would be useful to develop a comprehensive searchable public database of the information contained in the asset appendix, which sellers could access to update their asset appendices.
20. There are two categories of market-based rate sellers. Category 1 sellers are exempt from the requirement to automatically submit updated market power analyses every three years. Market-based rate Category 2 sellers are required to submit an updated market power analysis every three years according to a regional schedule. We include an updated schedule and region map as part of this NOPR.
21. One of the criteria that must be satisfied to be a Category 1 seller in a region is that the seller and its affiliates must own or control 500 MW or less of generation in aggregate in that region. We propose to codify in the Commission's regulations a distinction in determining seller category status for power marketers and power producers. For each region, a power marketer should include all affiliated generation in that region, while a power producer would only need to include affiliated generation capacity that is located in the same region as the power producer's generation asset(s). We propose this difference in treatment based on the fact that a power marketer is assumed to have no home market, while it is assumed that a majority of a power producer's sales will be in market(s) in which it owns generation assets.
22. While sellers have been required to describe their affiliates and upstream owners when filing initial applications, updated market power analyses and notices of change in status involving new affiliations, we propose to add a requirement in the regulations that sellers provide an organizational chart as well. We propose that the organizational chart be similar to that which we require from FPA section 203 applicants.
23. Although we have previously explained that joint filers are permitted to designate one market-based rate seller to file a single, joint master corporate market-based rate tariff for inclusion in the Commission's eTariff database that reflects the joint tariff for all affiliated sellers, many sellers have not taken advantage of the option to file a joint master corporate market-based rate tariff. We propose to clarify on the Commission's Web site how a corporate family that chooses to submit a joint master corporate tariff should identify its designated filer and what each of the other filers should submit into their respective eTariff databases.
24. We also propose to provide clarification regarding several issues related to how to perform SIL studies and regarding the associated Submittals 1 and 2. In particular, we propose to clarify issues relating to what is meant by Open Access Same-Time Information System (OASIS) practices, how to deal with conflicts between OASIS practices and Commission direction provided in Appendix B of Puget, and what is the correct load value to use in the SIL study.
25. The Commission has previously stated that the methodology a transmission provider uses to calculate SIL values must be consistent with the methodology it uses for calculating and posting available transmission capability (ATC) and for evaluation of firm transmission service requests. We propose to clarify that "OASIS practices" refers to the seasonal benchmark power flow case modeling assumptions, study solution criteria, and operating practices historically used by the first-tier and study area transmission providers to calculate and post ATC and to evaluate requests for firm transmission service. We further propose to clarify that in performing a SIL study, the transmission provider must follow its OASIS practices consistent with the administration of its tariff. Thus, the seasonal benchmark power flow cases submitted with a SIL study should represent historical operating practices only to the extent that such practices are available to customers requesting firm transmission service. We clarify that where there is a conflict between the transmission provider's tariff or OASIS practices and the Commission's directions in Puget, sellers should follow OASIS practices except where use of actual OASIS practices is incompatible with an analysis of import capability from an aggregated first-tier area. We also remind sellers that the calculated SIL value should account for any limits defined in the tariff, such as stability or voltage. We reiterate that sellers may use load scaling to perform a SIL study if they use load scaling in their OASIS practices as long as they submit adequate support and justification for the scaling factor used and how the resulting SIL value compares had the seller used a generation-shift methodology. We also instruct sellers to subtract all long-term firm import transmission reservations, including reservations held by non-affiliated sellers, from the simultaneous total transfer capability (simultaneous TTC) value. Finally, we clarify that the seller should reduce the simultaneous TTC value by subtracting all wheel through transactions used to serve non-affiliated load embedded in the study area using first-tier area generation. These transactions should be accounted for as long-term firm transmission reservations and reported in Submittal 2.
26. We propose to amend Submittal 1 to revise Row 8 to read "Adjusted Historical Peak Load" and propose to direct sellers to include all load associated with the balancing authority area(s) within the study area, including non-affiliated load. Submittal 1 requires sellers to use FERC Form No. 714 load values or explain the source of the data used. We seek comment on the appropriate source of historical peak load data.
27. We propose to clarify that where a first-tier market or balancing authority area is directly connected to the study area only by controllable tie lines and is not connected to any other first-tier market or balancing authority area, sellers should follow their OASIS practice regarding calculation and posting of ATC for such areas. If the seller's OASIS practices are incompatible with the SIL study, entities may use an alternative process to account for import capability for such tie lines.
28. We propose to provide standard guidance for data submittals and representations that sellers using the simultaneous TTC must provide, including historical data of actual, hourly, real-time TTC values used for operating the transmission system and posting availability on OASIS for each interface during each seasonal study period. We propose to clarify that sellers may use the maximum sum of TTC values for any day and time during each season as long as they demonstrate that these TTC values are simultaneously feasible. Finally, we reiterate that, if there are limited interconnections between first-tier markets, we will review evidence that potential loop flow between first-tier areas is properly accounted for in the underlying SIL values and we clarify that simply attesting that first-tier markets or balancing authority areas are not directly interconnected is not sufficient evidence that TTC values posted on OASIS are simultaneous.
29. We note that there are certain waivers that the Commission has granted to certain sellers with market-based rate authority, e.g., power marketers and independent or affiliated power producers, such as waiver of the Uniform System of Accounts requirements, specifically waiver of Parts 41, 101, and 141 of the Commission's regulations except sections 141.14 and 141.15. We clarify that any waiver of Part 101 granted to a market-based rate seller is limited such that waiver of the provisions of Part 101 that apply to hydropower licensees is not granted with respect to licensed hydropower projects. The Commission further directs that, to the extent that a hydropower licensee has been granted waiver of Part 101 as part of its market-based rate authority, the licensee's market-based rate tariff limitations and exemptions section should be revised to provide that the seller has been granted waiver of Part 101 of the Commission's regulations with the exception that waiver of the provisions that apply to hydropower licensees has not be granted with respect to licensed hydropower projects. Similarly, hydropower licensees that have been granted waiver of Part 141 as part of their market-based rate authority should ensure that the limitations and exemptions section of their market-based rate tariffs specify that waiver of Part 141 has been granted, with the exception of sections 141.14 and 141.15.
30. The Commission's regulations require as part of the vertical market power analysis that sellers make an affirmative statement that they have not erected barriers to entry into the relevant market and will not erect barriers to entry into the relevant market. We propose to revise the regulations to make it clear that the obligation to make the affirmative statement applies to both the seller and its affiliates.
[*Federal RegisterVJ 2014-07-25]
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