Federal Energy Regulatory Commission, DOE.
Notice of proposed rulemaking.
The Federal Energy Regulatory Commission (Commission) is proposing to amend its regulations to revise Subpart H to Part 35 of Title 18 of the Code of Federal Regulations governing market-based rates for public utilities pursuant to the Federal Power Act (FPA). The Commission is proposing to codify and, in certain respects, revise its current standards for market-based rates for sales of electric energy, capacity, and ancillary services. The Commission is proposing to retain several of the core elements of its current standards for granting market-based rates. However, we propose certain revisions to these standards and seek comment on other issues. The Commission also proposes to streamline certain aspects of its filing requirements to reduce the administrative burdens on applicants, customers and the Commission.
Comments are due August 7, 2006. Reply comments are due September 6, 2006. Comments should be double spaced and include an executive summary.
You may submit comments, identified by Docket No. RM04–7–000, by one of the following methods:
• Agency Web Site:
• Mail: Commenters unable to file comments electronically must mail or hand deliver an original and 14 copies of their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street, NE., Washington, DC 20426. Please refer to the Comment Procedures Section of the preamble for additional information on how to file paper comments.
Kelly A. Perl (Technical Information), Office of Energy Markets and Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502–6421. Elizabeth Arnold (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502–8818.
1. Pursuant to sections 205 and 206 of the Federal Power Act (FPA),
2. In 1988, the Commission began considering proposals for market-based pricing of wholesale power sales. The Commission acted on market-based rate proposals filed by various wholesale suppliers on a case-by-case basis. Over the years, the Commission developed a four-prong analysis used to assess whether a seller should be granted market-based rate authority: (1) Whether the seller and its affiliates lack, or have adequately mitigated, market power in generation; (2) whether the seller and its affiliates lack, or have adequately mitigated, market power in transmission; (3) whether the seller or its affiliates can erect other barriers to entry; and (4) whether there is evidence involving the seller or its affiliates that relates to affiliate abuse or reciprocal dealing.
3. The courts have reviewed the Commission's market-based rate program and found that it satisfies the FPA. The FPA requires that all rates demanded by public utilities for the sale of electric energy at wholesale be found ‘just and reasonable.’
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. On April 14, 2004, the Commission issued an order modifying the then-existing generation market power
6. On July 8, 2004, the Commission acted on requests for rehearing of the April 14 Order, reaffirming the basic analysis, but clarifying and modifying certain instructions for performing the generation market power analysis. The Commission clarified, among other things, the types of data on which sellers and intervenors may rely, and that adjustments may be allowed in certain circumstances. The Commission also clarified that mitigation would be imposed in all markets where a seller is found to have generation market power.
7. The Commission believes it is now appropriate to revise and codify the standards for market-based rates for wholesale sales of electric energy, capacity and ancillary services. Refining and codifying effective standards for market-based rates will help customers by ensuring that they are protected from the exercise of market power. It will also provide greater certainty to sellers seeking market-based rate authority.
8. The regulations proposed herein would adopt in most respects the Commission's current standards for granting market-based rates. We believe these standards have, with the exceptions noted below, allowed the Commission to distinguish between applicants that have market power and those that do not. For example, the current interim horizontal (generation) market power screens
9. 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 (
10. We also propose certain modifications to the horizontal (generation) market power screens to reflect our experience in applying them and the comments received in this proceeding. First, the Commission proposes to modify the treatment of newly-constructed generation to avoid a situation in which all generation becomes exempt from our market power analyses as new generation is constructed and older (pre-1996) generation is retired. Second, although we propose to retain the default relevant geographic market (control area), we provide guidance as to the factors the Commission will consider in evaluating whether, in a particular case, to adopt an expanded geographic market instead of relying on the default geographic market. Third, we propose to change the native load proxy for the market share screens from the minimum peak day in the season to the average peak native load, averaged across all days in the season, and to clarify that native load can only include load attributable to native load customers as that term is defined insection 33.3(d)(4)(i) of the Commission's regulations.
11. With regard to vertical market power and, in particular, transmission market power, the Commission proposes to continue the current policy under which an open access transmission tariff (OATT) is deemed to mitigate a seller's transmission market power.
12. With regard to vertical market power and, in particular, other barriers to entry, we propose to continue our current approach but provide clarification of what types of factors we would examine and we propose to combine the other barriers to entry analysis with the rest of our vertical market power analysis.
13. With regard to affiliate abuse, the Commission proposes to discontinue referring to affiliate abuse as a separate “prong” of our analysis and instead proposes to codify in our regulations an explicit requirement that any seller with market-based rate authority must comply with the affiliate sales restrictions and other affiliate provisions.
14. We also propose certain reforms to streamline the administration of the market-based rate program. As discussed more fully below, in an effort to streamline and simplify the market-based rate program in general, while maintaining a high degree of oversight, the Commission proposes several changes and clarifications. Significant areas of modification involve the three-year updated market power analysis (triennial review or updated market power analysis) that all sellers with market-based rate authority are required to file, and the development of a market-based rate tariff of general applicability.
15. With regard to updated market power analyses, the Commission's current general practice is to require an updated market power analysis to be submitted within three years from the date of the Commission order granting the seller market-based rate authority or accepting the previous triennial review. The Commission proposes to modify that general practice and put in place a structured, systematic review to assist the Commission in analyzing sellers in markets based on a coherent and consistent set of data. In particular, the Commission proposes to modify the requirements for filing updated market power analyses in two ways. First, the Commission proposes to establish two categories of sellers with market-based rate authorization. The first category, Category 1 (approximately 550 sellers), would consist of power marketers and power producers that own or control 500 MW or less of generating capacity in aggregate and that are not affiliated with a public utility with a franchised service territory. In addition, Category 1 sellers must not own or control transmission facilities, other than limited equipment necessary to connect individual generating facilities to the transmission grid, (or must have been granted waiver of the requirements of Order No. 888 because such facilities are limited and discrete and do not constitute an integrated grid
16. The second category, Category 2 (approximately 600 sellers), would include all sellers that do not qualify for Category 1. Category 2 sellers, in addition to the change in status reports, would be required to file regularly scheduled triennial reviews.
17. A second significant change is our proposal to adopt a market-based rate tariff of general applicability (MBR tariff), applicable to all sellers authorized to sell electric energy, capacity or ancillary services at wholesale at market-based rates. Further, the Commission proposes that, rather than each entity having its own MBR tariff, which can result in dozens of tariffs for each corporate family with potentially conflicting provisions, each corporate family would have only one tariff, with all affiliates with market-based rate authority separately
18. In the April 14 Order, the Commission adopted two indicative screens for assessing generation market power that provide a rebuttable presumption of whether market power exists for a utility applying to obtain or retain market-based rate authority. Sellers that do not pass the initial screens are, among other things, allowed to provide additional evidence for Commission consideration. Such an approach allows the Commission to concentrate its efforts on sellers that may possess generation market power while screening out those sellers that do not pose such concerns.
19. The Commission uses two indicative screens for assessing whether a particular seller raises any generation market power concerns, each with its own specific focus and attributes: a pivotal supplier analysis based on uncommitted capacity at the time of the market's annual peak demand; and a market share analysis of uncommitted capacity applied on a seasonal basis. If a seller passes both screens, there is a rebuttable presumption that the seller does not possess market power in generation. However, the Commission allows intervenors to present evidence to rebut the presumption. On the other hand, if a seller fails either screen, this creates a rebuttable presumption that market power exists in generation.
20. Section 35.27(a) of the Commission's regulations states that “any public utility seeking authorization to engage in sales for resale of electric energy at market-based rates shall not be required to demonstrate any lack of market power in generation with respect to sales from capacity for which construction has commenced on or after July 9, 1996.”
21. Alternatively, a seller may forego submitting a generation market power analysis and accept a presumption of market power and go directly to mitigation by proposing case-specific mitigation that eliminates the ability to exercise market power, or agreeing to the default rates discussed below. Under such circumstances there will be a presumption of market power in all of the default relevant markets.
22. If a seller's proposed mitigation
23. In addition, a seller that owns, operates or controls transmission is required to conduct simultaneous transmission import capability studies for its home control area and each of its directly-interconnected first-tier control areas consistent with the requirements set forth in the April 14 Order, as clarified in
24. A seller may provide a streamlined application to show that it passes the indicative screens. Thus, with respect to simultaneous import capability, if a seller can show that it passes the screens for each relevant geographic market without considering imports, no such simultaneous import analysis needs to be provided. Further, the Commission recognizes that certain sellers will not have the ability to perform a simultaneous import capability study. Accordingly, if a seller demonstrates that it is unable to perform a simultaneous import capability study for the control area in which it is located, the seller may propose to use a proxy amount for transmission limits. Such proposals are considered on a case-by-case basis.
25. The default relevant geographic markets under both screens are first, the control area market where the seller is physically located, and second, the markets directly interconnected to the seller's control area market (first-tier control area markets).
26. The Commission allows sellers and intervenors to present additional sensitivity runs as part of their market power studies to show that some other geographic market should be considered as the relevant market in a particular case. For example, sellers or intervenors can present evidence that the relevant market is broader (or more limited) than a particular control area. However, applicants presenting evidence that the relevant market is larger or smaller than the default relevant market must first complete the screens based on the default market as discussed above. To the extent some other geographic market is studied, the proponent of using that alternative market must adhere to including
27. Both the pivotal supplier analysis and the market share analysis recognize utilities' obligations to serve native load. Because utilities generally use the same generating units to make off-system wholesale sales and to serve native load, and because the amount of generation needed to serve native load can vary from hour to hour, some reasonable proxy is needed to represent the amount of generation that is needed to serve native load. Accordingly, the pivotal supplier analysis, for both sellers and competing suppliers, uses the average of the daily native load peaks during the month in which the annual peak demand day occurs as a proxy for native load obligation. The market share analysis for both sellers and competing suppliers uses the native load obligation on the minimum peak demand day for a given season.
28. In the pivotal supplier screen, a market participant's uncommitted capacity is determined by adding the total nameplate capacity of generation owned or controlled through contract and firm purchases, less operating reserves, native load commitments and long-term firm sales. To calculate the net uncommitted supply available to compete at wholesale, the wholesale load proxy (annual peak load less the native load proxy discussed above) is deducted from total uncommitted capacity in the market.
29. In the market share analysis, uncommitted capacity is defined similarly to the pivotal supplier screen, with the additional deduction for planned outages that were done in accordance with good utility practice. Under the market share analysis, a seller that has less than a 20 percent market share in the relevant market for all seasons is considered to satisfy the market share analysis.
30. In addition, any seller, regardless of size, has the option of making simplifying assumptions in its analysis where appropriate. In performing all screens, sellers are required to prepare them as designed,
31. Sellers failing one or more of the initial screens will have a rebuttable presumption of market power. If such a seller chooses not to proceed directly to mitigation, it must present a more thorough analysis using the Commission's DPT.
32. The DPT defines the relevant market by identifying potential suppliers based on market prices, input costs, and transmission availability, and calculates each supplier's economic capacity and available economic capacity for each season/load period.
33. Under the DPT, to determine whether a seller is a pivotal supplier in each of the season/load periods, sellers are required to compare the load in the relevant market to the amount of competing supply. The seller will be considered pivotal if the sum of the competing suppliers' economic capacity is less than the load level plus a reserve requirement for the relevant period. The analysis using available economic capacity to account for sellers' and competing suppliers' native load commitments is also required.
34. Each supplier's market share is calculated based on economic capacity, the DPT's analog to installed capacity. The market shares for each season/load period reflect the costs of the seller's and competing suppliers' generation, thus giving a more complete picture of the seller's ability to exercise market power in a given market.
35. Sellers preparing a DPT also must calculate the market concentration using the Hirschman-Herfindahl Index (HHI) based on market shares.
36. Sellers and intervenors may present evidence such as historical wholesale sales data, which can be used to calculate market shares and market concentration and to refute or support the results of the DPT. The Commission encourages sellers to present the most complete analysis of competitive conditions in the market as the data allow. In this regard, the Commission allows the introduction of such evidence beyond the most recent 12 months. The use of unadjusted historical sales and transmission data will provide an accurate depiction of actual market activity. Therefore, the Commission requires sellers submitting historical sales and transmission data as evidence to submit the actual data.
37. The FPA requires that all rates charged by public utilities for the transmission or sale for resale of electric energy be just and reasonable.
38. For sellers that have a presumption of market power in generation (
39. The Commission adopted the indicative generation market power screens in the April 14 Order for interim purposes, and instituted the instant rulemaking proceeding to, among other things, review of these screens and, as a whole, the horizontal market power portion of the Commission's four-prong analysis. The Commission has gained
40. Because the indicative screens are intended only to identify the sellers that require further review, we propose to retain the 20 percent threshold for the wholesale market share screen. The screens are indicative, not definitive. Indeed, pursuant to the horizontal market power analysis where an applicant is seeking to obtain or retain market-based rate authority, the Commission will not make a definitive finding that a seller has market power unless and until the more robust analysis, the DPT, is considered. Instead, where a seller fails one of the indicative screens, a section 206 proceeding is instituted to more closely examine a seller's potential for exercising horizontal market power and does not mean a definitive finding has been made. Failure to pass either of the indicative screens creates a rebuttable presumption of market power. A seller that fails the initial screens is given 60 days from the date of issuance of an order finding a screen failure to: (1) File a DPT analysis; (2) file a mitigation proposal tailored to its particular circumstances that would eliminate the ability to exercise market power; or (3) inform the Commission that it will adopt the default cost-based rates or propose other cost-based rates and submit cost support for such rates.
41. Some commenters argue that the 20 percent threshold is too low; others argue that it is too high. The Commission believes that the 20 percent threshold strikes the right balance in seeking to avoid both “false negatives” and “false positives” and proposes to continue using 20 percent. Because the presumption of horizontal market power established by the failure of the wholesale market share screen is rebuttable, coupled with the adjustment to the native load proxy discussed below, sellers should be assured that the 20 percent threshold is not unnecessarily stringent.
42. We also propose to continue the use of annual peak load in the pivotal supplier analysis and not to expand the pivotal supplier analysis to include monthly assessments. The pivotal supplier analysis examines the seller's market power during the annual peak. The hours near that point in time are the most likely times that a seller will be a pivotal supplier.
43. Similarly, for the DPT analysis, we propose to retain our current threshold including 2,500 for HHIs, as well as our current practice of weighing all the relevant factors in the analysis, in determining whether a seller does or does not have horizontal market power. We propose to continue to do so on a case-by-case basis, weighing such factors as available economic capacity, economic capacity, HHIs, and other historical wholesale sales data. The thresholds are well-established and appropriate, allowing the Commission to make a reasoned determination after reviewing all the evidence in the record. The DPT does not function like the initial screens in that the failure of either the economic capacity or available economic capacity analyses does not result in an automatic failure as a whole.
44. To reduce the number of “false positives” in the wholesale market share screen, however, we propose to adjust the native load proxy. Many commenters have noted that the current native load proxy for the market share screen is too limited and results in too much uncommitted capacity attributable to the seller. The Commission stated in the April 14 Order that by using the two screens together, the Commission is able to measure market power both at peak and off-peak times, and the ability to exercise market power both unilaterally and in coordinated interaction with other sellers. In the April 14 Order, the Commission adopted the native load proxy for the wholesale market share screen in order to balance the concerns of market participants. We now believe that the current proxy used in the market share screen may be too conservative. Accordingly, the Commission proposes to change the allowance for the native load deduction under the market share screen from the minimum native load peak demand for the season to the average native load peak demand for the season. This change makes the deduction for the market share screen consistent with the deduction allowed under the pivotal supplier screen. We propose to retain a season-by-season analysis. For example, the proxy for summer would be the average native load peak for June, July and August. The pivotal supplier screen's native load proxy would remain unchanged from its current proxy of the average of the daily native load peaks during the month in which the annual peak day load occurs. We seek comments on our proposal.
45. We believe there has been some inconsistency in the way in which sellers have reflected native load in performing both the screens and the DPT analysis. For this reason, we also propose to clarify that for the horizontal market power analysis, native load can only include load attributable to native load customers as defined in section 33.3(d)(4)(i) of the Commission's regulations,
46. The Commission stated that uncommitted capacity is determined by adding the total capacity of generation owned or controlled through contract and firm purchases less, among other things, long-term firm requirements sales that are specifically tied to generation owned or controlled by the seller and that assign operational control of such capacity to the buyer.
47. The Commission has stated that contracts can confer the same rights of control of generation or transmission
48. In recent years, some owners have turned to third parties to manage the day-to-day activities of running and dispatching plants and/or selling output. Such third-party contractors, often referred to as energy managers and/or asset managers, can be responsible for multiple facilities through multiple energy management agreements. These management agreements may, directly or indirectly, transfer control of the capacity. The Commission is concerned that there may be instances where, in effect, control of capacity has changed hands, but this capacity has not been attributed to the correct seller for purposes of calculating our market screens.
49. In cases examining whether an entity is a public utility, the Commission has examined the totality of the circumstances in evaluating whether the entity effectively has control over capacity that it manages.
50. The Commission also proposes to clarify that an entity (such as an asset manager or other such entity) that controls generation from which jurisdictional power sales are made is required to have a rate on file with the Commission. If the rate authority sought is market-based rate authority, then that entity is subject to the same conditions and requirements as any other like seller (
51. The Commission proposes to continue to use its current approach with regard to the relevant geographic market. The default relevant geographic market is the control area where the seller is physically located and the control areas directly interconnected to that control area (with the exception of a generator interconnecting to a non-affiliate owned or controlled transmission system, in which case the relevant market is only the control area in which the seller is located). The Commission also proposes to continue to designate the RTO/ISO in which a seller is located and is a member as the default relevant geographic market for RTO/ISOs with sufficient market structure and a single energy market, and not require sellers to consider, as part of the relevant market, markets first-tier to the RTO/ISO in which the seller is located and is a member.
52. We note that the North American Electric Reliability Council (NERC) no longer uses the designation of control area since it approved the “NERC Reliability Functional Model” on February 10, 2004. We seek comment as to whether or not the adoption of the NERC functional model should change the criteria for specifying the default relevant geographic market, and if so, in what way it should be specified and how readily available is the relevant data.
53. The Commission proposes to continue to provide flexibility by
54. Reaching beyond the default market in which an entity is located can mean addressing additional physical and other challenges than when trading within that market. When assessing an expanded geographic market pursuant to the horizontal analysis, the Commission looks for assurance that no frequently recurring physical impediments to trade exist within the expanded market that would prevent competing supply in the expanded area from reaching wholesale customers. Any proposal to use an expanded market (
55. The Commission also considers whether there is other evidence that would support the existence of an expanded market. In deciding whether customers may be considered as part of an expanded geographic market, the Commission will also consider evidence that they can access the resources outside of the default geographic market on similar terms and conditions as those inside the default geographic market.
56. Such evidence submitted to show that the applicant's customers have access to resources outside of their control area at terms and conditions similar to those at which they can access resources inside the control area could be empirical or it could point to factors that indicate a single market. For example, the Commission has previously stated that the operation of a single central unit commitment and dispatch function for the proposed geographic market would be an indicator of a single market. However, there are other ways to demonstrate that two or more control areas are indeed a single market. For example, other evidence of a single market could include a demonstration that: there is a single transmission rate; there is a common OASIS platform for scheduling transmission service across separate control areas; there is a correlation of price movements between the areas being considered as an expanded geographic market or other information regarding wholesale transactions in the proposed single market. Evidence of active trading throughout the proposed geographic market would also be considered.
57. In determining whether two or more control areas are a single market the Commission would weigh, on a case-by-case basis, all the factors presented. As discussed above, there are several factors the Commission would consider once it has been established that historically there were no physical impediments to trade, and no one factor or factors would be dispositive. Rather, all factors will be considered and as a whole will indicate whether there exists a single market.
58. We seek comment on our proposed guidance and, in particular, whether there are other factors the Commission should consider when assessing a proposed expanded market. Are there any factor(s) that should be given more weight or are essential in determining the scope of the market (
59. In addition, as discussed previously, the Commission proposes to designate the RTO/ISO in which the seller is located and is a member as the default relevant geographic market for RTO/ISOs with sufficient market structure and a single energy market. We believe the added protections provided in structured markets with market monitoring, market power mitigation and transparency generally result in a market where attempts to exercise market power would be sufficiently mitigated.
60. In the April 14 Order, the Commission identified PJM, ISO–NE, NYISO, and CAISO as meeting the criteria for being considered a single market for purposes of performing the generation market power screens.
61. However, our experience with corporate mergers and acquisitions indicates that these same RTOs have, at times, been divided into smaller submarkets for study purposes because frequently binding transmission constraints prevent some potential suppliers from selling into the destination market.
62. Lastly, if the Commission determines that an RTO/ISO submarket is the appropriate default geographic region in a particular case and an applicant is found to have market power within that submarket, should the Commission consider mitigation in addition to existing RTO market monitoring and mitigation?
63. We propose to retain the “snapshot in time” approach for the screens,
64. However, we propose in the DPT analysis to allow applicants and intervenors to account for changes in the market that are known and measurable at the time of filing.
65. As suggested by a commenter, we propose to require all sellers to submit the results of their indicative screen analysis in a uniform format to the maximum extent practicable. This format will promote consistency and will aid the Commission in the decision-making process. Sellers must cross reference the inputs with the data and workpapers they otherwise submit including those in accordance with Appendix G of the April 14 Order. Use of a uniform format for reporting results is not intended to limit other workpapers the seller may wish to submit. The format we propose to adopt can be found in Appendix C. We seek comments on this proposal.
66. Section 35.27(a) of the Commission's regulations states:
Notwithstanding any other requirements, any public utility seeking authorization to engage in sales for resale of electric energy at market-based rates shall not be required to demonstrate any lack of market power in generation with respect to sales from capacity for which construction has commenced on or after July 9, 1996.
67. The Commission clarified in the April 14 Order that some sellers with capacity built after July 9, 1996 (section 35.27(a) exemption) may avoid submitting a horizontal market power analysis if they meet the requirements of section 35.27(a) of the Commission's regulations. The Commission stated that, as it indicated in Order No. 888, it will consider whether a seller citing section 35.27(a) nevertheless possesses horizontal market power if specific evidence is presented by an intervenor, and a seller still must study whether its new capacity, when added to existing capacity, raises horizontal market power concerns.
68. Under current procedures, if all the generation owned or controlled by an applicant for market-based rate authority and its affiliates in the relevant control area is new generation, such applicant is not required to provide a horizontal market power analysis because of the exemption under section 35.27(a).
69. Although we remain committed to encouraging new entry of generation, we are concerned that the continued use of the section 35.27(a) exemption may become too broad. Over time, this exemption would encompass all market participants as all pre-July 9, 1996 generation is retired. For this reason, some commenters suggest that the Commission should eliminate the exemption altogether.
70. We agree with these commenters that our current practice will have unintended adverse consequences over time and therefore should be reformed. Accordingly, we propose to eliminate the express exemption provided in section 35.27(a), but to do so in a manner that will not act as a disincentive for the construction of new generation. As explained further below, this change will not affect many sellers, given that they already are required to include all new capacity when submitting a market analysis for their pre-1996 generation. Further, our proposal will assure that all generation is treated on an equal footing, such that market participants with similar market shares in the same geographic market are not treated differently based solely on the vintage of their assets.
71. Under this proposal, the Commission would require that all new applicants seeking market-based rate authority on or after the effective date of
72. Further, with regard to triennial reviews, the Commission's proposal to eliminate the section 35.27(a) exemption would require that, in its triennial review, a seller must perform a horizontal market power analysis of all of its generation regardless of when it was built, thus eliminating any special treatment of generation built after July 9, 1996. However, as discussed above, because the Commission allows for a streamlined analysis, including simplifying assumptions, where appropriate, any additional burden imposed by the proposed elimination of the section 35.27(a) exemption will be minimal. In addition, the Commission anticipates that those entities that otherwise would have relied on the exemption will, in most cases, qualify as Category 1 sellers and thus no longer be required to file triennial reviews.
73. By proposing to eliminate the express exemption set forth in section 35.27(a), we are not proposing to require sellers with market-based rate authority to submit a new horizontal market power analysis (
74. Thus, our proposal to eliminate section 35.27(a) should not impose significant additional burdens on new generation or otherwise deter new entry. We seek comments on this proposal.
75. Based on our experience, we propose to allow sellers the option of using seasonal capacity instead of nameplate capacity as currently required. The seller must be consistent in its choice and use one or the other measure of capacity ratings throughout the analysis. The use of seasonal capacity ratings we believe more accurately reflects the seasonal real power capability and is not inconsistent with industry standards, and therefore it may be more convenient for sellers to acquire and compile the associated data. In addition, we do not think the use of such ratings will materially impact results. We seek comment on this proposal, including comment as to whether this information is publicly available to all market participants.
76. We propose to continue our use of limiting capacity that can be imported into a relevant market to the results of a simultaneous transmission import capability study, and to reaffirm several aspects of the requirements regarding how to properly construct a simultaneous transmission import capability study for use in the indicative screens and the DPT.
77. The simultaneous transmission import capability study is intended to provide a reasonable simulation of historical conditions. In particular, the simultaneous transmission import capability study is not the theoretical maximum import capability or a best import case scenario. It is a benchmark of historical operating conditions and practices of the applicable transmission provider (
78. In addition to the power flow cases, as noted in Appendix E of the April 14 Order, the seller must supply supporting documentation, and this documentation should include the operational practices historically used, reliability margins, and all firm/network reservations held by the seller or its affiliates that are modeled in the cases. The simultaneous transmission import capability study must reasonably reflect the transmission provider's OASIS practices and the techniques used must have been historically available to customers. We propose to continue to use the instructions set forth in the April 14 Order.
79. Further, the April 14 Order required simultaneous transmission import capability studies to include firm point-to-point and network transmission reservations. Firm/network reservations should be subtracted from the simultaneous transmission import capability if they are not historically modeled in the power flow case. In all cases, sellers are required to provide documentation of the firm/network reservations.
80. We expect control area operators with market-based rate authority to provide simultaneous transmission import capability studies in a timely manner, consistent with the methodology described in the April 14 Order, for their control area and directly interconnected first-tier control areas in response to requests by sellers seeking market-based rate authority.
81. We also propose to reaffirm certain aspects of an approximation explained in Appendix E of the April 14 Order. The April 14 Order allows directly interconnected first-tier control areas (to the market being studied) to be considered when conducting the study. However, it does not allow control areas that are second tier to the control area being studied to be considered.
82. We propose to specify how the calculation of a seller's pro rata share of simultaneous transmission import capability should be performed. When studying its first-tier control area, the seller should allocate imports (after taking into account firm reservations by attributing them to the holders of the reservations including those applicable to the seller) pro rata between the seller and its competitors based on
83. The Commission notes that Order No. 662
84. The Commission historically has considered transmission market power and other barriers to entry as two separate parts of the four-prong market-based rate analysis. However, as discussed below, the examination of a seller's ability to engage in transmission market power and a seller's ability to exclude competitors from the market by erecting other barriers to entry through the control of inputs to electric power production both involve the evaluation of potential vertical market power. On this basis, in this NOPR the Commission proposes to reformulate its market-based rate analysis to consider issues relating to transmission market power and other barriers to entry under the heading “vertical market power.” This proposal is intended primarily to alter the way in which we characterize these issues, rather than changing the fundamental nature of the analyses that we perform.
85. To the extent that a market-based rate seller, or any of its affiliates, owns, operates, or controls transmission facilities, the Commission has required the seller to have an OATT on file before granting market-based rate authorization. The OATT was implemented in 1996 when the Commission issued Order No. 888 to remedy undue discrimination or preference in access to the monopoly owned transmission grid. Having a Commission-approved OATT on file satisfies the Commission's concerns with regard to transmission market power. In addressing our transmission market power concerns, a seller, including its affiliates, that does not own, operate or control transmission facilities should make an affirmative statement that neither it, nor any of its affiliates, owns, operates or controls any transmission facilities.
86. The Commission issued a Notice of Inquiry in
87. Although the principal barriers to entry can be raised through the ownership or control of transmission facilities, the Commission also evaluates barriers to entry other than transmission (other barriers to entry). In the early 1990s, the Commission considered whether a seller or its affiliates could erect other barriers to entry through ownership or control of sites for new capacity development, key inputs to generation, or the transportation of key inputs to generation.
88. In particular, the Commission considered such things as a power producer's ownership of building sites and its affiliation with or ownership of interstate natural gas pipelines, engineering and construction firms, or local natural gas distribution systems. For example, in
89. As discussed above, the Commission proposes to replace its existing four-prong analysis (generation market power, transmission market power, other barriers to entry, affiliate abuse/reciprocal dealing) with an analysis that focuses on horizontal market power and vertical market power. Accordingly, we propose that issues relating to whether the seller and its affiliates lack transmission market power or whether they can erect other barriers to entry be addressed together as part of the vertical market power part of the analysis.
90. Regarding transmission issues, the current policy is that having a Commission-approved OATT on file is sufficient to mitigate transmission market power. However, the Commission has also recognized that Order No. 888 did not eliminate all potential to engage in undue discrimination and preference in the provision of transmission service.
91. Nevertheless, the finding that an OATT adequately mitigates transmission market power rests on the assumption that individual applicants comply with their OATTs. If they do not, violations of the OATT may be cause to revoke market-based rate authority or to subject the seller to another remedy the Commission may deem appropriate, such as disgorgement of profits or civil penalties.
92. The Commission also proposes to continue considering a seller's ability to erect other barriers to entry, but to do so as part of the vertical market power analysis. We propose that, in order for a seller to demonstrate that it satisfies our vertical market power concerns, with respect to other barriers to entry, it must demonstrate that it and its affiliates cannot erect other barriers to entry. In this regard, we propose to continue to require a seller to provide a description of its affiliation, ownership or control of inputs to electric power production (
93. In addition, the Commission proposes to provide additional regulatory certainty by clarifying which inputs to electric power production the Commission will consider as other barriers to entry in its vertical market power review, and seeks comments on this proposal. The Commission proposes that the analysis continue to include the consideration of ownership or control of sites for development of generation in the relevant market, fuel inputs such as coal facilities in the relevant market, and the transportation, storage or distribution of inputs to electric power production such as intrastate gas storage and distribution systems, and rail cars/barges for the transportation of coal. The Commission also clarifies that applicants need not address interstate transportation of natural gas supplies because such transportation is regulated by this Commission.
94. Several commenters have suggested that a transmission planning and expansion process can ameliorate vertical market power. The Commission is seeking comments on the issues of transmission planning and expansion in the notice of proposed rulemaking in the OATT Reform Rulemaking that is being issued concurrently with this NOPR. We seek comment on whether these planning and expansion efforts under the OATT Reform Rulemaking will address commenters' concerns here.
95. The Commission seeks comment on whether other inputs to electric power production should be considered as potential barriers to entry and, if so, what criteria the Commission should use to evaluate evidence that is presented. We also seek comment on whether the exercise of buyer's market power by the transmission provider should be considered a potential barrier to entry and, if so, what criteria the Commission should use to evaluate evidence that is presented.
96. The fourth prong of the Commission's current market-based rate analysis examines whether there is evidence involving the seller or its
97. The Commission in the past has used two means to ensure that affiliate abuse does not occur: restrictions on sales between a franchised public utility and its affiliates, and requiring a code of conduct that governs the relationship between franchised public utilities and their affiliates.
98. The Commission currently prohibits power sales at market-based rates between a franchised public utility and its affiliates without first receiving authorization of the transaction under section 205 of the FPA.
99. The Commission has stated its concern that a franchised public utility and an affiliate may be able to transact in ways that transfer benefits from the captive customers of the franchised public utility to the affiliate and its shareholders.
100. In determining whether to allow power sales affiliate transactions, the Commission, over time, has adopted several methods, all of which have focused on ensuring that captive customers are adequately protected against affiliate abuse. We discuss these below.
101. In
102. In subsequent cases, the Commission expanded on the competitive solicitation prong of
103. The Commission has provided guidelines as to how the Commission will evaluate whether a competitive solicitation process satisfies the
104. In
105. The Commission has granted blanket authorization to make power sales to affiliates pursuant to a market-based rate tariff subject to certain conditions. For this blanket authorization, the Commission has required that sales of power by a franchised public utility to an affiliate be made at a rate no lower than the rate charged to non-affiliates; the utility offering to sell power to an affiliate must make the same offer, at the same time, to non-affiliated entities; and the utility must post simultaneously the actual price charged to its affiliate for all
106. The Commission also has authorized sales when a “non-regulated” affiliate seeks to sell power to an affiliated franchised public utility where sufficient pricing safeguards were in place to ensure that there was no room for manipulation.
107. The Commission also has allowed sales between affiliates pursuant to a market-based rate tariff without imposing any price or transaction conditions where there were no captive wholesale or retail customers or where captive customers were adequately protected from affiliate abuse.
b.
108. We remain concerned about the potential adverse impact that affiliate power sales transactions may have on captive customers
109. Consistent with the foregoing, we propose to amend the Commission's regulations to include a provision expressly prohibiting power sales between a franchised public utility and any of its non-regulated affiliates without first receiving authorization of the transaction under section 205 of the FPA. Further, we propose that, as a condition of receiving market-based rate authority, sellers must adopt the MBR tariff (included as Appendix A to this NOPR) which includes a provision requiring the seller to comply with, among other things, the affiliate provisions in the regulations. We note that failure to satisfy the conditions set forth in the affiliate provisions will constitute a tariff violation. We seek comments on this proposal.
110. Sellers seeking authorization to engage in affiliate transactions will continue to be obligated to provide evidence to support a determination as to whether there are captive customers that would trigger the application of our standards for affiliate power sales.
111. We propose to continue our past approach for determining what types of affiliate transactions are permissible and the criteria that should be used to make those decisions. When affiliates participate in a competitive solicitation process, application of the
112. In
113. We continue to believe that tying the price of an affiliate transaction to an established, relevant market price or index such as in an RTO or ISO is acceptable benchmark evidence and mitigates affiliate abuse concerns so long as that benchmark price or index reflects the market price where the affiliate transaction occurs (
114. Although the Commission has found in the past that certain
115. The Commission seeks comment on whether evidence other than competitive solicitations, RTO price or non-RTO price indices, or benchmarks described above, should be accepted in an application for authority to engage in affiliate power sales.
116. With regard to merging companies the Commission has stated that for the purposes of affiliate abuse, merging companies will be considered affiliates under the market-based rate tariff while their merger is pending.
117. The Commission also proposes that entities that engage in energy/asset management of generation on behalf of a franchised public utility be treated as affiliates of that franchised public utility in a manner similar to that of non-regulated affiliates and be subject to the affiliate provisions we propose herein. The Commission also proposes that entities that engage in energy/asset management of generation on behalf of non-regulated affiliates of a franchised public utility be treated in a similar manner as the non-regulated affiliates. We seek comment on this proposal.
118. The Commission currently requires that sales made under market-based rate tariffs, including those made to affiliates, be reported in an EQR.
119. Although, at one time, the Commission's policy was to require certain market-based rate sellers to file their long-term market-based rate power sales service agreements with the Commission,
120. The Commission requires affiliates of franchised public utilities that request market-based rate authority to submit a market-based rate code of conduct to govern the relationship between the franchised public utility and its affiliates. Historically, the purpose of the market-based rate code of conduct
121. The market-based rate code of conduct requirements have evolved through market-based rate orders.
1. To the maximum extent practical, the employees of [Power Marketer/Power Producer] will operate separately from the employees of [Public Utility].
2. All market information shared between [Public Utility] and [Power Marketer/Power Producer] will be disclosed simultaneously to the public. This includes all market information, including but not limited to, any communication concerning power or transmission business, present or future, positive or negative, concrete or potential. Shared employees in a support role are not bound by this provision, but they may not serve as an improper conduit of information to non-support personnel.
3. Sales of any non-power goods or services by [Public Utility], including sales made through its affiliated EWGs or QFs, to [Power Marketer/Power Producer] will be at the higher of cost or market price.
4. Sales of any non-power goods or services by the [Power Marketer/Power Producer] to [Public Utility] will not be at a price above market.
To the extent [Power Marketer/Power Producer] seeks to broker power for [Public Utility]:
5. [Power Marketer/Power Producer] will offer [Public Utility's] power first.
6. The arrangement between [Power Marketer/Power Producer] and [Public Utility] is non-exclusive.
7. [Power Marketer/Power Producer] will not accept any fees in conjunction with any Brokering services it performs for [Public Utility].
122. The Commission has also accepted the inclusion of an additional provision to govern brokering activities where a franchised public utility brokers for one of its affiliates.
123. Numerous significant changes have taken place in the electric industry relevant to the market-based rate code of conduct requirement since the Commission approved the first market-based rate codes of conduct in the mid-1990s. The Commission has required open access transmission service in Order No. 888; there has been an increase in the number of power marketers and power producers
124. There also has been an increased range of activities engaged in by asset or energy managers.
125. While the Commission has required that entities comply with the provisions of the market-based rate code of conduct, the market-based rate code of conduct has not been codified in the Commission's regulations. Further, some applicants for market-based rate authority have requested and received variations from the market-based rate code of conduct. Such variations, while reasonable in individual circumstances, may over time become inconsistent with the Commission's goals of protecting captive customers and fostering transparent and consistent regulation of the market. Likewise, some corporate families have filed several different market-based rate codes of conduct for their affiliates while others have filed only one or have received a waiver of the market-based rate code of conduct requirement.
126. An example of inconsistent market-based rate codes of conduct was revealed in Commission staff's audit of Progress Energy, Inc. In that proceeding, there were eight different codes with differing provisions for different Progress affiliates.
127. The Commission continues to believe that a code of conduct is necessary to protect captive customers from the potential for affiliate abuse. Further, in light of the repeal of the Public Utility Holding Company Act of 1935 and the fact that holding company systems may have franchised public utility members with captive customers as well as numerous “non-regulated” power sales affiliates that engage in non-power goods and services transactions with each other, it is important that the Commission have in place restrictions to preclude transferring captive customer benefits to stockholders through a company's “non-regulated” power sales business. We therefore believe it is appropriate to condition all market-based rate authorizations, including authorizations for sellers within holding companies, on the seller abiding by a code of conduct for sales of non-power goods and services between power sales affiliates.
128. We also believe that greater uniformity and consistency in the codes of conduct is appropriate. With the experience gained over the years in approving various codes of conduct, including our standard code of conduct, we are proposing to adopt a uniform code of conduct to govern the relationship between franchised public utilities with captive customers and their “non-regulated” affiliates,
129. The proposed provisions are the same as those in the standard code of conduct that exists today with the following exceptions. First, the proposed regulations use the term “non-regulated” affiliates instead of power marketer/power producer to make it clear that the provisions apply to the relationship between a franchised public utility and any of its affiliates that are not regulated under cost-based regulation. This includes affiliate power marketers and affiliate power producers, such as EWGs and QFs.
130. Second, in the case of companies that are acting on behalf of and for the benefit of franchised public utilities with captive customers, the proposed affiliate provisions treat such companies, for purposes of the affiliate provisions, as the franchised public utility. For example, if a company has been created to manage generation assets for the franchised public utility, such entity is subject to the same information sharing provision as the franchised public utility with regard to information shared with non-regulated affiliates, such as power marketers and power producers.
131. Likewise, in the case of non-regulated affiliates, the proposed affiliate provisions treat companies that are acting on behalf of and for the benefit of non-regulated affiliates, for purposes of the affiliate provisions, as the non-regulated affiliates. For example, asset managers of a non-regulated affiliate's generation assets are treated as the non-regulated affiliate with regard to, for example, the information sharing provision. We seek comment on this proposal.
132. The Commission invites comments proposing other additions, substitutions, or eliminations to the proposed affiliate provisions.
133. The Commission began accepting applications for market-based power sales in the late 1980s as a means to provide greater flexibility to transactions in emerging competitive wholesale power markets. The analysis for horizontal market power at that time was the “hub and spoke” methodology, and under that methodology most sellers received market-based rate approval. If, however, a seller failed the hub and spoke analysis for a particular market, as a general matter, no specific mitigation was imposed. Rather, the seller could continue to sell power under existing cost-based rate schedules on file with the Commission in that area.
134. The Commission began providing greater flexibility in setting cost-based rates for coordination sales during this period as well. Historically, utilities had set the rate for coordination sales on a “split the savings” formula
135. This more flexible approach to wholesale power sales continued largely unchanged until 2001 when the Commission adopted the supply margin assessment (SMA) test.
136. In the April 14 and July 8 Orders, the Commission replaced the SMA test with two indicative screens for assessing horizontal market power, the pivotal supplier screen and the wholesale market share screen, and modified the Commission's approach to cost-based mitigation.
137. In the April 14 Order, the Commission adopted default mitigation tailored to three distinct products: (1) Sales of power of one week or less will be priced at the seller's incremental cost plus a 10 percent adder; (2) sales of power of more than one week but less than one year will be priced at an embedded cost “up-to” rate reflecting the costs of the unit(s) expected to provide the service; and (3) sales of power for one year or more will be priced at an embedded cost of service basis and each such contract will be filed with the Commission for review and approved prior to the commencement of service. The Commission determined that sellers that are found to have market power (
138. We seek comment on whether the default mitigation set forth in the April 14 Order is appropriate as currently structured. In particular, certain recurring issues have arisen in implementing the cost-based mitigation and we seek comment on these issues. Specifically, we seek comment, as discussed further below, on four issues of recurring significance: (i) The rate methodology for designing cost-based mitigation; (ii) discounting; (iii) protecting customers in mitigated markets; and (iv) sales by mitigated sellers that “sink” in unmitigated markets.
139. We first seek comment on issues associated with the rate methodology for designing cost-based mitigation. There are two principal issues concerning rate methodology that have arisen in implementing the April 14 Order. The first relates to the requirement that sales of less than one week be made at incremental cost plus 10 percent. Sellers have argued that this is a departure from the Commission's historical acceptance of “up to” rates for short-term energy sales, including sales of less than one week. We seek comment on whether to continue to apply a default rate for sales of less than one week that is tied to incremental cost plus 10 percent. Are there problems associated with using “up to” rates for shorter-term sales and, if so, what are they? Does the current approach provide utilities a disincentive to offer their power to wholesale customers in their local control area for short-term sales? Would an “up to” rate adequately mitigate market power for such sales?
140. The second rate methodology issue relates to the design of an “up to” cost-based rate. In the past, the Commission has allowed significant flexibility in designing “up to” rates. Is that flexibility still warranted? For example, there are often disputes over which units are “most likely to participate” or “could participate” in coordination sales. Should the Commission continue to allow utilities flexibility in selecting the particular units that form the basis of the “up to” rate? If not, what units should an “up to” rate be based upon, and how should that rate be calculated? Should the Commission prescribe a standard methodology that would allow an applicant to avoid a hearing on rate methodology? Would a methodology that is based on average costs (both variable and embedded) allow an applicant to avoid a hearing because it eliminates the seller's discretion in designating particular units as “likely to participate”? Are there other approaches that would accomplish a similar objective?
141. In the April 14 and July 8 Orders, the Commission stated that sellers that are found to have market power (
142. Finally, the Commission notes that if a mitigated seller is returning to existing cost-based rates, the Commission would have the obligation to consider whether those rates are sufficient for that purpose, and would have the authority to institute a proceeding under FPA section 206 to investigate their justness and reasonableness.
143. A seller that has authorization to sell under an “up to” cost-based rate has an incentive to discount its sales price when the market price in the seller's local area is lower than the cost-based ceiling rate. During these periods, a rational seller will discount its sales to maximize revenue. In the past the Commission has encouraged discounting as an efficient practice that can maximize revenues to reduce the revenue requirements borne by customers.
144. The primary issue in this area is whether a seller can “selectively” discount,
145. Under our current policy, if a seller loses market-based rate authority in its home control area, any sales in that control area must be pursuant to cost-based rates; however, there is no requirement that the seller offer its available power to customers in that home control area. Instead, the seller is free to market all its available power to purchasers outside that control area if, for example, market prices outside its control area exceed the cost-based caps. Wholesale customers have argued that default cost-based mitigation of this kind is of little value if a mitigated seller can simply market its excess capacity at market-based rates in other control areas.
146. The Commission seeks comment on whether its current policy is appropriate and, if not, what further restrictions are necessary. In particular, we seek comment on the following:
a. Is it appropriate to continue to allow sellers that are subject to mitigation in their home control area to sell power at market-based rates outside their control area? Does this represent undue discrimination or otherwise constitute “withholding” in the home control area that is inconsistent with the FPA's mandate that rates be just, reasonable and not unduly discriminatory? Or, does this reflect economically efficient behavior and encourage necessary trading within and across regions, particularly in peak periods when marginal prices rise above average embedded costs?
b. Should the Commission adopt a form of “must offer” requirement in mitigated markets to ensure that available capacity (i.e., above that needed to serve firm and native load customers) is not withheld? If so, should the must offer requirement be limited to sales of a certain period to help ensure that wholesale customers use that power to serve their own needs, rather than simply remarketing that power outside the control area and profiting? For example, should there be an annual open season under which the mitigated seller offers its available capacity to local customers for the following year at the cost-based ceiling rate and, if customers do not commit to purchase that capacity, then the seller is free to sell the remaining capacity at market-based rates where it has authority to do so? If we adopt such a must offer requirement, what rules should there be to define “available” capacity to avoid case-by-case disputes over this issue?
c. As an alternative, should the Commission find that any seller that has lost market-based rate authority in its home control area should not be able to sell power at market-based rates in adjacent (first tier) control areas?
Would this be appropriate mitigation and easier to implement than a must offer requirement? Or, would such mitigation unnecessarily discourage trading and flexibility in markets for which the seller has been found not to have market power?
147. The Commission has stated that its role is to assure customers that sellers who are authorized to sell at market-based rates do not have market power or have adequately mitigated the potential exercise of market power.
148. Some companies have proposed limiting mitigation to sales that “sink in” the mitigated market, that is, so that mitigation would only apply to end users in the mitigated market.
149. The Commission seeks comment on whether it should modify or revise its current policy and, if so, how. In particular, we seek comment on the following:
a. Should the Commission allow market-based rate sales by a mitigated seller within a mitigated market if those sales do not “sink” in that control area? If so, under what circumstances should the Commission allow such sales and how would the Commission ensure that such sales do indeed “sink” in an unmitigated control area? How does the Commission distinguish possible permissible sales to the border of the restricted control area from sales that are not permitted within the restricted control area?
b. Under such a policy, what opportunities, if any, are presented to “game” the mitigation? If it is determined that a mitigated seller's sales in fact do not “sink” outside the restricted control area, what penalties should the Commission consider?
c. If the Commission retains its current policy of prohibiting all market-based rate sales by a mitigated seller in a mitigated market what effect, if any, does such a policy have on existing contractual arrangements? With regard to existing transmission rights a buyer may have in a mitigated market, how easily could existing market-based rate agreements between that buyer and the mitigated seller be amended to provide for delivery of power in an unmitigated market under the same economic terms as exists today?
150. The Commission's current practice is a case-by-case analysis of new applications for market-based rate authorization as well as updated market power analyses. In addition, to date the Commission has allowed sellers to propose their own individualized tariffs.
151. The Commission proposes to put in place a structured, systematic review to assist the Commission in analyzing sellers based on a coherent and consistent set of data for relevant geographic markets. In addition, some corporate families have many subsidiaries with market-based rate authorization, each with its own separate tariff. This has led to confusion, inconsistencies between the tariffs of a single corporate family, and difficulty in coordinating changes to the tariffs. To remedy these concerns, the Commission proposes to streamline the administrative process associated with the filing and review of market-based rate updated market power analyses and to consolidate market-based rate authorizations into a single tariff.
152. The Commission proposes to continue to require sellers to submit updated market power analyses for all relevant geographic markets (default or proposed alternative markets, as discussed previously) in which they own or control generation. However, the Commission proposes to modify this filing requirement in two ways. First, the Commission proposes to establish two categories of sellers with market-based rate authorization. The first category (Category 1) would include 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
153. The second category (Category 2) would include all sellers that do not qualify for Category 1. Category 2 sellers, in addition to the requirement to file change in status reports, would be required to file regularly scheduled triennial reviews. Category 2 sellers are the larger sellers with more of a presence in the market and are more likely to either fail one or more of the indicative screens or pass by a smaller margin than Category 1 sellers.
154. To ensure greater consistency in the data used to evaluate Category 2 sellers, the Commission proposes to require each seller to file updated market power analyses for its relevant geographic markets (default and any proposed alternative markets) on a schedule that will allow examination of the individual seller at the same time the Commission examines other sellers in these relevant markets and contiguous markets within a region from which power could be imported.
155. The Commission proposes to codify in its regulations the obligation for Category 2 sellers to timely file a triennial review. As a result, failure to timely file a triennial review would constitute a violation of the Commission's regulations and the seller's MBR tariff and could result in disgorgement of profits and/or civil
156. Some corporate families own or control generation in multiple control areas and different regions. For example, a corporate family may own generation facilities on the east coast as well as in California. In this instance, the corporate family would be required to file a current triennial review for each region in which members of the corporate family sell power during the time period specified for that region. To the extent a new subsidiary is formed and a new request for market-based rate authority is submitted, triennial reviews will be due at the regularly scheduled time for review of the markets in the region in which the new applicant owns or controls generation. We seek comment on this proposal.
157. In addition, the Commission proposes to require that all triennial review filings and all new applications for market-based rate authority include an appendix listing all generation assets owned or controlled by the corporate family by control area and listing the in-service date and nameplate and/or seasonal ratings by unit. The appendix should also reflect all electric transmission and natural gas intrastate pipelines and/or gas storage facilities owned or controlled by the corporate family and the location of such facilities.
158. Triennial reviews should reflect the most recently available historical data from the calendar year prior to the year of filing.
159. We seek comments on the proposal to adopt these filing requirements.
160. Historically the Commission has not required the filing of a market-based rate tariff of general applicability. However, many sellers have submitted one or more umbrella market-based rate tariffs that set forth the conditions of market-based rate approval and the general terms applicable to all transactions, with individual transactions being negotiated through service agreements, letter confirmations, or other documentation that sets forth the rates and any individualized terms and conditions. This general practice has afforded flexibility to sellers as markets and the industry evolved and as new products and services were sold under market-based rate tariffs. However, this flexible approach has sometimes resulted in inconsistency in the tariffs filed within the same corporate family, which can create confusion for customers and compliance problems, and it also has resulted in inconsistencies in memorializing the conditions of market-based rate approval in such tariffs.
161. As part of our effort to streamline and simplify the market-based rate program in general, while at the same time maintaining a high degree of transparency and oversight, we propose to adopt a market-based rate tariff of general applicability that all sellers authorized to sell wholesale electric power at market-based rates will be required to file as a condition of market-based rate authority.
162. Not all of the provisions of the proposed regulations may be applicable to all sellers. For example, a seller may not wish to offer ancillary services under the tariff. The Commission seeks comments on whether a placeholder should be reserved in the MBR tariff for the seller to indicate those parts of the regulations that are not applicable to that seller.
163. In proposing the adoption of the MBR tariff, our purpose is not to direct the terms and conditions of a particular power sale or to otherwise reduce the flexibility afforded to market-based rate sellers in fashioning the terms of individual transactions. Rather, sellers would continue to negotiate the terms and conditions of sales entered into under their MBR tariff, and the terms and conditions of those underlying agreements and the transaction data would be reflected in the quarterly EQRs. Further, if sellers wish to offer or require certain “generic” terms and conditions that in the past were contained in their market-based rate tariff, they may place customers on notice of such requirements by including such information on a company website and include any related provisions in individual transaction agreements. Our purpose in requiring a MBR tariff of general applicability is to ensure that the MBR tariff on file with the Commission for each seller reflects, in a consistent manner, only those matters that are required to be on file, namely, the identity of the seller(s), the docket number(s) of the market-based rate authorization, the seller's requirement to follow the conditions of market-based rate authorization contained in our proposed regulations, and that the rates, terms and conditions of any particular sale will be negotiated between the seller and individual purchasers. We do not believe any useful purpose is served in having on file the commercial terms preferred by particular applicants, given that the purpose of market-based rate authorization is to provide flexibility in such terms and conditions. Furthermore, our standards for approval of market-based rates do not include a review of such individualized commercial terms and thus, such submissions are unnecessary.
164. Further, the Commission proposes that, rather than each entity having its own MBR tariff, which can result in dozens of tariffs for each corporate family with conflicting provisions, each corporate family has only one tariff on file, with all affiliates with market-based rate authority separately identified in the tariff. This will allow for better transparency with regard to what sellers each corporate family has, and a more customer-friendly tariff. The requirement to have a single MBR tariff does not mean that all members of a corporate family would be counterparties on every sale under the tariff; rather, individual transactions would continue to be consummated
165. We seek comments on this proposal.
166. Regarding the specifics of filing the MBR tariffs, we note that the Commission has initiated a rulemaking proceeding to require the filing of electronic tariffs.
167. Certain entities with market-based rate authority have typically been granted waiver of the Commission's Uniform System of Accounts, and thus have not been subject to specified accounting rules. For instance, Parts 41, 101, and 141 of the Commission's regulations prescribe certain informational requirements that focus on the assets that a public utility owns.
168. The Commission has also granted power marketers' and others' requests for blanket approval under Part 34 of the Commission's regulations for all future issuances of securities and assumptions of liability, assuming that no party objects to such treatment during a notice period which the Commission provides.
169. As the development of competitive wholesale power markets continues, independent and affiliated power marketers and power producers are playing more significant roles in the electric power industry. In light of the evolving nature of the electric power industry, the Commission seeks comment on the extent to which these entities should be required to follow the Uniform System of Accounts, what financial information, if any, should be reported by these entities, and how frequently it should be reported, and whether the Part 34 blanket authorizations continue to be appropriate.
170. The Commission announced in the April 14 Order that, where an applicant is found to have market power (or where the applicant accepts a presumption of market power), the applicant will be required to adopt some form of cost-based rates or other mitigation the applicant proposes and the Commission accepts. Under these circumstances, the Commission found that it is essential that appropriate accounting records be maintained consistent with the Commission's regulations. Accordingly, the Commission indicated it will no longer waive the otherwise applicable accounting regulations (
171. We note that some sellers have had their market-based rate authority revoked, or have elected to relinquish their market-based rate authority after a presumption of market power, and have begun or resumed selling power at cost-based rates. Consistent with the April 14 Order, any waivers previously granted in connection with those sellers' market-based rate authority are no longer applicable. We propose that such revocation of waivers become effective 60 days from the date of an order revoking such waivers in order to provide the affected utility with time to make the necessary filings with the Commission and allow for an orderly transition from selling under market-based rates to cost-based rates. We seek comment in this regard. The Commission seeks input regarding any difficulties sellers may have when transitioning to cost-based rates and whether a prior waiver of the accounting regulations would leave them without adequate data to come into conformance with the accounting rules.
172. Under existing policy, a foreign entity selling in the United States (and each of its affiliates) must not have, or must have mitigated, market power in generation and transmission and not control other barriers to entry. In addition, the Commission considers whether there is evidence of affiliate abuse or reciprocal dealing. However, for foreign sellers, the Commission allows a modified approach to the four prongs.
173. With regard to generation market power, should a foreign seller or any of its affiliates own or control any generation in the United States, or should one of its first-tier markets include a United States market, it should perform the market power screens in the appropriate control area(s).
174. With regard to transmission market power, the Commission requires a foreign seller seeking market-based rate authority to demonstrate that its transmission-owning affiliate offers non-discriminatory access to its transmission system that can be used by competitors of the foreign seller to reach United States markets.
175. For purposes of market-based rate authorization, the Commission does not consider transmission and generation facilities that are located exclusively outside of the United States and that are not directly interconnected to the United States. However, the Commission would consider transmission facilities that are exclusively outside the United States but nevertheless interconnected to an affiliate's transmission system that is directly interconnected to the United States.
176. Regarding other potential barriers to entry, a foreign seller should inform the Commission of any potential barriers to entry that can be exercised by either it or its affiliates in the same manner as a seller located within the United States.
177. Finally, regarding affiliate abuse, the Commission typically requires a power marketer with market-based rate authorization to file for approval under section 205 of the FPA before selling power to or purchasing power from any utility affiliate. However, this general requirement does not apply to situations involving sales of power to or from a foreign utility outside of the Commission's jurisdiction.
178. The Commission proposes to retain its current policy when reviewing a foreign seller's application for market-based rate authorization consistent with our overall approach discussed herein. The Commission seeks comments regarding whether this current policy is adequate to grant market-based rate authorization to such sellers.
179. In early 2005, the Commission clarified and standardized market-based rate sellers' reporting requirement for any change in status that departed from the characteristics the Commission relied on in initially authorizing sales at market-based rates. In Order No. 652,
180. The Commission has provided further guidance on change in status filings in several cases. In
181. In addition, market-based rate sellers must report as a change in status each cumulative increase in generation of 100 MW or more that has occurred since the most recent notice of change in status filed by that seller (
182. In Order No. 652, the Commission identified a number of issues that could be pursued in the instant rulemaking proceeding. The Commission had proposed in that rulemaking proceeding to include fuel supplies as an input to electric power production the acquisition of which would be a reportable change in status. However, in the final rule, the Commission determined that this issue would be more appropriately raised in the instant rulemaking proceeding, and stated that the Commission would provide opportunity for interested persons to propose modifications to the existing approach in this proceeding.
183. In Order No. 652, the Commission clarified that the reporting of transmission outages per se as a change in status was not required. However, to the extent a transmission outage affects, on a long-term basis (
184. The Commission declined in Order No. 652 to narrow or delineate the definition of control. The Commission noted that, historically, if a seller has control over certain capacity such that it can affect the ability of the capacity to reach the relevant market, then that capacity should be attributed to the seller when performing the generation market power screens. Further, the capacity associated with contracts that confer operational control of a facility to an entity other than the owner must be assigned to the entity exercising control over that facility. The Commission concluded that it is not possible to predict every contractual agreement that could result in a change of control of an asset. However, the Commission indicated that to the extent that parties wish to propose specific definitions or clarifications to the Commission's historical definition of control, they may do so in the course of the instant rulemaking.
185. In Order No. 652 we did not expand the triggering events for a change in status filing to include actions taken by a competitor (such as a decision to retire a generation unit or take transmission capacity out of service) or natural events (such as hydro-year level, higher wind generation, or load disruptions due to adverse weather conditions). In Order No. 652, we concluded that the reporting obligation should extend only to changes in circumstances within the knowledge and control of the seller. However, in Order No. 652, we stated that interested persons could pursue in the instant rulemaking whether the Commission should expand the triggering events for a change in status filing. Accordingly, we invite comments generally on whether the Commission should expand the triggering events beyond ownership or control of facilities or inputs and affiliation with entities that own or control facilities or inputs or that have a franchised service territory, as adopted in Order No. 652.
186. In Order No. 888, the Commission required transmission providers to offer certain ancillary services at cost-based rates as part of their open access commitment but also contemplated that third parties (parties other than the transmission provider in a particular transaction) would also provide ancillary services.
187. In
188. The guidance offered by the Commission in Order No. 888 and
189. However, in
190. Accordingly, the Commission adopted a policy wherein third-party ancillary service providers that cannot perform a market power study would be allowed to sell ancillary services at market-based rates, but only in conjunction with a requirement that such third parties establish an Internet-based OASIS-like site for providing information about and transacting ancillary services.
191. In this regard, the Commission stated that it will apply this policy only to applicants who are authorized to sell power and energy at market-based rates. In addition, the Commission stated that it will not apply this approach to sales of ancillary services by a third-party supplier in the following situations: (1) The approach will not apply to sales to a regional transmission organization (RTO) or an independent system operator (ISO),
192. The Commission based its policy as announced in
193. The information contained in the Internet-based site would include service availability, prices, and requests granted and denied. To further monitor development of market entry, the Commission required third-party suppliers to file with the Commission one year after their Internet-based site is operational (and at least every three years thereafter
194. In particular, the Commission stated that:
195. We propose to retain our current approach in this regard. We seek comment on whether we should modify or revise our current approach and, if so, how. Also, we seek comment on whether our current conditions such as the requirement to establish an Internet-based site continue to be necessary.
196. Subsections (a) and (b) of this section were added by Order No. 888 in order to implement the post-1996 exemption for new generation and to clarify the authority of state commissions respectively. Order No. 652 later added subsection (c) to implement the change in status reporting requirement.
197. This NOPR proposes to eliminate the post-1996 exemption, and thus the proposed regulatory text deletes subsection (a). Subsection (c) is proposed to move to subpart H section 35.43, and thus the proposed text deletes section 35.27(c). This leaves only current subsection (b) in 35.27. The proposed regulatory text does not revise the language in any way and merely renumbers current subsection (b) to reflect the absence of the other subsections.
198. With the changes proposed herein, the current section heading, “Power Sales at Market-Based Rates,” will no longer be pertinent. The Commission proposes to amend the heading to “Authority of State Commissions” to reflect the content of the remaining provision.
199. This section is proposed to define certain terms specific to Subpart H and to explain the applicability of Subpart H.
200. Subsection (b) is intended to leave room for certain provisions that do not apply to a particular seller should the Commission make a finding, for instance, that a franchised public utility has no captive customers and hence section 35.39(b) is not applicable.
201. We solicit comments on whether further or different language than that proposed here should be incorporated in our regulations.
202. This section describes the market power analysis the Commission employs, as discussed in the preamble, and when sellers must file one. It is intended to identify the key aspects of the analysis without providing too much detail. The Commission is cognizant that the finer points of the market power analysis change over time as individual orders consider new facts and as precedent shifts to follow the evolution of the power industry; the proposed regulations should not be so
203. We solicit comments on the scope of the language that should be incorporated in the regulations.
204. The NOPR raises questions concerning the current approach and seeks comments regarding any changes the Commission should adopt. In addition, we propose to characterize the informal term “up to” cost-based rates as “priced at no higher than a cost-based ceiling reflecting the cost of the units expected to provide service.” We seek comments on whether further or different language than that proposed here should be incorporated in our regulations.
205. This section governs affiliate transactions and affiliate relationships and establishes affiliate conditions that a seller must satisfy as a condition of its market-based rate authority. Subsection (a) includes a provision expressly prohibiting sales between a franchised public utility and any of its non-regulated power sales affiliates without first receiving authorization of the transaction under section 205 of the FPA. This subsection requires that, where the Commission grants a seller authority to engage in affiliate sales under its MBR tariff, any and all such authorizations must be listed in the seller's tariff. We seek comments on the proposal to include this provision in the Commission's regulations.
206. Subsections (b)–(e) contain the market-based rate code of conduct provisions governing the relationship between a franchised public utility and its non-regulated power sales and power brokering affiliates. The provisions of this subsection apply to all franchised public utilities with captive customers. This subsection includes provisions governing the separation of employees, the sharing of market information, sales of non-power goods or services, and power brokering. It proposes that, for purposes of applying the provisions of this section, entities acting on behalf of and for the benefit of a franchised public utility (such as service companies and entities managing the generation assets of the franchised public utility) are considered to be part of the franchised public utility, and entities acting on behalf of and for the benefit of a non-regulated affiliate of a franchised public utility (such as affiliated power marketers and power producers and entities managing the generation assets of the affiliated power marketers and producers) are considered to be part of the non-regulated affiliates. This section is an integral part of the Commission's conditions regarding affiliate abuse where captive customers are concerned. We seek comments on the proposal to include the affiliate provisions in the regulations.
207. This provision restricts sales of ancillary services to those specific geographic markets for which the Commission has authorized market-based rate sales of such. In addition, this section lays out the limitations on third-party ancillary services sales provided in
208. Recently, the Commission rescinded two of its market behavior rules and codified the remainder in section 35.37 of new Subpart H. Also, in a Final Rule issued concurrently with this NOPR, the Commission is revising the record retention period from three years to five years. In this NOPR, we propose to move these market behavior rules, unchanged, from § 35.37 to § 35.41.
209. This proposed provision imposes the requirement that each seller (or its corporate parent) have on file with the Commission the market-based rate tariff that is appended hereto at Appendix A.
210. This section incorporates the provision currently found at subsection 35.27(c), which was codified by Order No. 652. No modifications to the existing language are proposed. We seek comment on whether any changes are warranted.
211. The Office of Management and Budget (OMB) regulations require approval of certain information collection and data retention requirements imposed by agency rules.
212. The Commission has previously required utilities seeking market-based rate authority to file a market power analysis with the Commission; the Commission now proposes to codify that requirement in the Commission's regulations. This proposal reflects the Commission's existing practice and will not impose any additional burden, with the following exception.
213. Section 35.27(a) of the Commission's regulations currently provides that any public utility seeking market-based rate authority shall not be 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 current procedures, if all the generation owned or controlled by an applicant for market-based rate authority and its affiliates in the relevant control area is post-July 9, 1996 generation, such applicant is not required to submit a generation market power analysis. In this NOPR, the Commission proposes to eliminate the express exemption provided in section 35.27(a). This proposal would require that all new applicants seeking market-based rate authority on or after the effective date of the final rule issued in this proceeding, 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. Because the Commission allows an applicant to make simplifying assumptions, where appropriate, and therefore to submit a streamlined analysis, any burden of document preparation occasioned by the proposed elimination of section 35.27(a) should be minimal. Moreover, any burden of document preparation caused by the proposed elimination of section 35.27(a) should apply for the most part only with regard to generation market power analyses required to support an initial application for market-based rate authority.
214. The second filing requirement proposed in this NOPR is that all market-based rate sellers file one market-based rate tariff per corporate family. The MBR tariff proposed by the Commission is appended to this NOPR. The proposed tariff, coupled with the proposed regulations, will simplify the
215. To retain market-based rate authority, the Commission currently requires that sellers file a triennial review. In this NOPR, the Commission proposes to codify the requirement that certain sellers with market-based rate authority file a triennial review with the Commission to retain that authority. However, the Commission proposes that certain smaller utilities, Category 1 sellers, be relieved of their existing duty to file the triennial review. Thus, larger sellers will not face a greater burden to provide the Commission with the information required for a triennial review, and the burden of supplying the updated analysis may be eliminated for certain smaller entities seeking to retain market-based rate authority.
216. The Commission's regulations, in 18 CFR part 35, specify those reporting requirements that must be followed in conjunction with the filing of rate schedules under the FPA. The information provided to the Commission under 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, triennial reviews, and reporting requirements for changes in status for public utilities with market-based rate authority.
217. The Commission is submitting these reporting and records retention requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act.
MBR Tariff: An MBR tariff for each corporate family with all current sellers to be filed with the Commission after the final rule is effective. In the future, an MBR tariff will be filed occasionally by each utility newly seeking market-based rate authority.
Triennial Review: Updated market power analysis filed every three years for Category 2 sellers seeking to retain market-based rate authority.
MBR Tariff: A market-based rate tariff filed for each corporate family, with all affiliates with market-based rate authority separately identified in the tariff, would improve the efficiency of the Commission in its analysis and determination of market-based rate authority. The MBR Tariff would allow the Commission to have a clear definition of the relationships between parent and affiliate utilities in assessing market-based rate authority and/or the investigation thereof. This will allow for better transparency with regard to what sellers each corporate family has, and a more customer friendly tariff. A tariff of general applicability will also reduce document preparation time overall and provide utilities with the clearly defined expectations of the Commission.
Triennial Review: The triennial review allows the Commission to monitor market-based rate authority to
Interested persons may obtain information on the reporting requirements by contacting: Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426 [Attention: Michael Miller, Office of the Executive Director, Phone: (202) 502–8415, fax: (202) 273–0873, e-mail:
218. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.
219. The Regulatory Flexibility Act of 1980 (RFA)
220. The submission of a market power analysis is currently required of all entities seeking authority to sell at market-based rates, and the proposed rule does not alter which entities will be required to file these analyses. The proposed rule does not create a new reporting requirement. It does, however, propose to 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 section 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 proposed elimination of the section 35.27(a) exemption will be minimal. Thus, public utilities are currently prepared to submit market power analyses and this requirement does not pose a greater burden.
221. The proposed rule requires that each corporate family have on file one MBR tariff of general applicability, with all affiliates with market-based rate authority separately identified in the tariff. Although this may initially increase the burden of document preparation and organization for parent utilities, long-term benefits will be realized that reduce burdens on utilities and the Commission. A tariff of general applicability will decrease document preparation by providing a clearly defined statement of the information sought by the Commission. Moreover, a single tariff for each corporate family will reduce the filing burden on utilities. Small entities affiliated with a parent utility need not prepare a separate tariff; rather, they will merely add their company name to their parent utility's tariff. Thus, the burden is decreased.
222. 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 proposed regulations would result in fewer filings with the Commission than currently required for qualified smaller utilities' (Category 1) retention of market-based rate authority. Those who do have to file are able to use short cuts described above (
223. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due August 7, 2006. Reply comments are due September 6, 2006. Comments and reply comments must refer to Docket No. RM04–7–000, and must include the commenter's name, the organization they represent, if applicable, and their address in their comments. Comments and reply comments may be filed either in electronic or paper format.
224. Comments and reply comments may be filed electronically via the eFiling link on the Commission's Web site at
225. All comments and reply comments will be placed in the Commission's public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments and reply comments on other commenters.
226. In addition to publishing the full text of this document in the
227. From the Commission's Home Page on the Internet, this information is available in the Commission's document management system, eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.
228. User assistance is available for eLibrary and the Commission's Web site during normal business hours. For assistance, please contact FERC Online Support at 1–866–208–3676 (toll free) or (202) 502–8222 (e-mail at
Electric power rates, Electric utilities, Reporting and recordkeeping requirements.
By direction of the Commission.
In consideration of the foregoing, the Commission proposes to amend part 35, Chapter I, Title 18,
1. The authority citation for part 35 continues to read as follows:
16 U.S.C. 791a–825r, 2601–2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.
2. Section 35.27 is revised as follows:
Nothing in this part—
(a) Shall be construed as preempting or affecting any jurisdiction a state commission or other state authority may have under applicable state and federal law, or
(b) Limits the authority of a state commission in accordance with state and federal law to establish:
(1) Competitive procedures for the acquisition of electric energy, including demand-side management, purchased at wholesale, or
(2) Non-discriminatory fees for the distribution of such electric energy to retail consumers for purposes established in accordance with state law.
3. Subpart H is revised to read as follows:
(a) For purposes of this subpart:
(1)
(2)
(3)
(4)
(5)
(6)
(b) The provisions of this subpart apply to all sellers authorized, or seeking authorization, to make sales for resale of electric energy, capacity or ancillary services at market-based rates unless otherwise ordered by the Commission.
(a) In addition to other requirements in subparts A and B, a Seller must submit a market power analysis in the following circumstances: when seeking market-based rate authority; for Category 2 Sellers, every three years, according to the schedule contained in Order No. __, FERC Stats. & Regs. ¶ 31, __; or any other time the Commission directs a Seller to submit one. Failure to timely file an updated market power analysis will constitute a violation of Seller's market-based rate tariff.
(b) A market power analysis must address whether a Seller has horizontal and vertical market power.
(c) There will be a rebuttable presumption that a Seller lacks horizontal market power if it passes two indicative market power screens: first, a pivotal supplier analysis based on the annual peak demand of the relevant market and; second, a market share analysis applied on a seasonal basis. There will be a rebuttable presumption that a Seller possesses horizontal market power if it fails either screen. A Seller that has horizontal market power, or that has not rebutted a presumption of horizontal market power, is subject to mitigation, as described in § 35.38.
(d) To demonstrate a lack of vertical market power, a Seller that owns, operates or controls transmission
(e) To demonstrate a lack of vertical market power in wholesale energy markets through the affiliation, ownership or control of inputs to electric power production, such as the transportation or distribution of the inputs to electric power production, a Seller must provide the following information: a description of its affiliation, ownership or control of inputs to electric power production; a description of its ownership or control of intra-state transportation or distribution of inputs to electric power production; a description of its ownership or control of any sites for new generation capacity development; and a statement that it cannot erect barriers to entry in the relevant markets.
(a) A Seller that has been found to have market power in generation or that is presumed to have horizontal market power by virtue of failing or foregoing the horizontal market power screens, as described in § 35.37(c), may adopt the default mitigation detailed in paragraph (b) of this section or may propose mitigation tailored to its own particular circumstances to eliminate its ability to exercise market power.
(b) Default mitigation consists of three distinct products: (i) sales of power of one week or less priced at the Seller's incremental cost plus a 10 percent adder; (ii) sales of power of more than one week but less than one year priced at no higher than a cost-based ceiling reflecting the costs of the unit(s) expected to provide the service; and (iii) new contracts filed for review under section 205 of the Federal Power Act for sales of power for one year or more priced at a rate not to exceed embedded cost of service.
(a)
(b)
(2) To the maximum extent practical, the employees of a non-regulated power sales affiliate will operate separately from the employees of any affiliated franchised public utility.
(c)
(d)
(2) Sales of any non-power goods or services by a non-regulated power sales affiliate to an affiliated franchised public utility will not be at a price above market.
(e)
(i) The non-regulated power sales affiliate must offer the franchised public utility's power first;
(ii) The arrangement between the non-regulated power sales affiliate and the franchised public utility must be non-exclusive; and
(iii) The non-regulated power sales affiliate may not accept any fees in conjunction with any brokering services it performs for an affiliated franchised public utility.
(2) To the extent a franchised public utility seeks to broker power for a non-regulated power sales affiliate:
(i) The franchised public utility will be required to charge the higher of its costs for the service or the market rate for such services;
(ii) The franchised public utility will be required to market its own power first, and simultaneously make public (on an electronic bulletin board and/or the Internet) any market information shared with its affiliate during the brokering; and
(iii) The franchised public utility will post on an electronic bulletin board and/or the Internet the actual brokering charges imposed.
(a) If a Seller seeks authority to make sales of ancillary services at market-based rates, it may offer such services provided the service has been authorized by the Commission and only in specific geographic markets as the Commission has authorized.
(b) If a Seller is authorized by the Commission to make sales of ancillary services at market-based rates as a third-party ancillary services provider:
(1) Seller shall establish an Internet-based site for providing information regarding ancillary services transactions including, prior to making transactions, postings of offers of services available and offering prices; procedures under which all customers would request service and make bids; postings of the actual transaction prices after the transactions are consummated; and accepted and denied requests and the reasons for denial. The site should conform to the applicable OASIS Standards and Communications Protocols.
(2) [Reserved]
(c) Seller is not authorized to make sales of ancillary services at market-based rates as a third-party ancillary services provider:
(1) To a regional transmission organization or an independent system operator (other than those ancillary services that are subject to § 35.40(a)) that has no ability to self-supply ancillary services but instead depends on third parties;
(2) When the underlying transmission service is on the transmission system of a transmission provider with whom the Seller is affiliated; or
(3) To a public utility who is purchasing ancillary services to satisfy its own Open Access Transmission Tariff requirements to offer ancillary services to its own transmission customers, unless Seller(s) receives separate authorization by the Commission.
(a)
(b)
(c)
(d)
(a) In addition to other requirements in subpart A, every public utility that is authorized to sell electric energy at market-based rates pursuant to section 205 of the Federal Power Act must have on file with the Commission a tariff of general applicability. Such tariff must be the market-based rate tariff contained in Order No. __, FERC Stats. & Regs. ¶ 31, __ (Final Rule on Market-Based Rates for Wholesale Sales of Electricity by Public Utilities).
(b) The market-based rate tariff contained in Order No. __, FERC Stats. & Regs. ¶ 31, __ must be filed by Sellers who have been granted market-based rate authority prior to the issuance of Order No. ____, in accordance with Order No. ____, FERC Stats. & Regs. ¶ 31, __ (Final Rule on Electronic Tariff Filing). A market-based rate tariff must be filed by a Seller who is initially seeking market-based rates at the time it applies for market-based rate authorization.
(c) Each corporate family will file a single market-based rate tariff, with all affiliates with market-based rate authority separately identified in the tariff.
(a) As a condition of obtaining and retaining market-based rate authority, a Seller must timely 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. A change in status includes, but is not limited to, the following:
(1) Ownership or control of generation capacity that results in net increases of 100 MW or more, or transmission facilities or inputs to electric power production other than fuel supplies, or
(2) Affiliation with any entity not disclosed in the application for market-based rate authority that owns, operates or controls generation or transmission facilities or inputs to electric power production, or affiliation with any entity that has a franchised service area.
(b) Any change in status subject to paragraph (a) of this section must be filed no later than 30 days after the change in status occurs. Failure to timely file a change in status report constitutes a tariff violation.
1. Availability: Electric energy, capacity and ancillary services are available under this tariff for wholesale sales to purchasers with whom seller has contracted. Not all services may be available from all sellers listed. Seller shall comply with the provisions of 18 CFR Part 35, Subpart H, as applicable, and with any conditions the Commission imposes in its orders concerning seller's market-based rate authority, including orders in which the Commission authorizes seller to engage in affiliate sales under this tariff or otherwise restricts or limits the seller's market-based rate authority. Failure to comply with the applicable provisions of 18 CFR Part 35, Subpart H, and with any orders of the Commission concerning seller's market-based rate authority, will constitute a violation of this tariff.
2. Applicability: This tariff is applicable to all wholesale sales of electric energy, capacity and ancillary services by seller.
3. Rates: All sales shall be made at rates established by agreement between the purchaser and seller.
4. Other Terms and Conditions: All other terms and conditions not listed herein shall be established by agreement between the purchaser and seller.
5. Effective Date: This Rate Schedule is effective on the date of compliance with the final rule on Electronic Tariff Filings, Order No. __, FERC Stats. & Regs. ¶ 31,__.
The following Appendix will not appear in the Code of Federal Regulations.
All Category 2 sellers that own or control generation in the California, Northwest, Southwest, Midwest, SPP, Southeast, PJM, New York, and New England regions during the period specified below (Qualification Period) will file updated market power analyses within the filing period specified in the following schedule. Triennial Reviews
The following Appendix will not appear in the Code of Federal Regulations.