# Long-Term Firm Transmission Rights in Organized Electricity Markets > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A06-6494 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** August 1, 2006 - **Citation:** 71 FR 43564 ## Text DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 42 [Docket No. RM06-8-000; Order No. 681] Long-Term Firm Transmission Rights in Organized Electricity Markets Issued July 20, 2006. AGENCY: Federal Energy Regulatory Commission. ACTION: Final rule. SUMMARY: The Federal Energy Regulatory Commission is amending its regulations under the Federal Power Act to require transmission organizations that are public utilities with organized electricity markets to make available long-term firm transmission rights that satisfy certain guidelines adopted by the Commission in this Final Rule. The Commission is taking this action pursuant to section 1233(b) of the Energy Policy Act of 2005, [Pub. L. 109-58, § 1233(b), 119 Stat. 594, 960 (2005).] DATES: Effective Date: This Final Rule will become effective August 31, 2006. FOR FURTHER INFORMATION CONTACT: Udi E. Helman (Technical Information), Office of Energy Markets and Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-8080. Roland Wentworth (Technical Information), Office of Energy Markets and Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-8262. Wilbur C. Earley (Technical Information), Office of Energy Markets and Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-8087. Harry Singh (Technical Information), Office of Enforcement, Division of Energy Market Oversight, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-6341. Jeffery S. Dennis (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-6027. SUPPLEMENTARY INFORMATION: Table of Contents Paragraph Nos. I. Background 3. A. The Development of ISOs and RTOs 3. B. Interest in Long-Term Firm Transmission Rights 6. C. Staff Paper on Long-Term Transmission Rights 11. D. Energy Policy Act of 2005 14. E. Notice of Proposed Rulemaking 15. II. Discussion 16. A. Overview 16. B. Definitions 24. 1. Organized Electricity Market 24. 2. Load Serving Entity and Service Obligation 34. 3. Long-Term Power Supply Arrangement 55. 4. Transmission Organization 63. C. Commission Interpretation of EPAct 2005 Requirements 70. D. Commission's Approach, Regional Flexibility, and Regional Seams Issues 84. E. Guidelines for the Design and Administration of Long-Term Firm Transmission Rights in Organized Electricity Markets 108. Guideline (1)—Specify Source, Sink and Quantity 108. Guideline (2)—Long-Term Hedge That Cannot Be Modified 122. Guideline (3)—Rights Made Available by Expansions Go to Parties That Pay for the Upgrade 185. Guideline (4)—Term of Rights Must be Sufficient to Hedge Long-Term Power Supply Arrangements 217. Guideline (5)—Load Serving Entities with Long-Term Power Supply Arrangements Have Priority to the Existing System 273. Guideline (6)—Rights are Reassignable to Follow Load 331. Guideline (7)—Auction Not Required 361. Guideline (8)—Balance Adverse Economic Impacts 394. F. Transmission Planning and Expansion 429. G. Alternative Designs for Long-Term Firm Transmission Rights 458. H. Miscellaneous Comments 477. I. Implementation of the Final Rule and Compliance Issues 479. III. Information Collection Statement 496. IV. Environmental Analysis 500. V. Regulatory Flexibility Act Certification 501. VI. Document Availability 502. VII. Effective Date and Congressional Notification 505. Before Commissioners: Joseph T. Kelliher, Chairman; Nora Mead Brownell, and Suedeen G. Kelly; Order No. 681; Final Rule 1. In this Final Rule, the Commission is amending its regulations to require each transmission organization that is a public utility with one or more organized electricity markets to make available long-term firm transmission rights that satisfy each of the guidelines established by the Commission in this Final Rule. We take this action pursuant to section 1233 of the Energy Policy Act of 2005 (EPAct 2005), which added new section 217 to the Federal Power Act (FPA). 1 This Final Rule will require each transmission organization subject to its requirements to file with the Commission, no later than January 29, 2007, either (1) tariff sheets and rate schedules that make available long-term firm transmission rights that satisfy each of the guidelines set forth in the final regulations, or (2) an explanation of how its current tariff and rate schedules already provide for long-term firm transmission rights that satisfy each of the guidelines. A transmission organization approved by the Commission for operation after January 29, 2007 will be required to satisfy the requirements of this Final Rule. 1 Pub. L. 109-58, § 1233, 119 Stat. 594, 957 (2005). 2. The guidelines adopted in this Final Rule will give transmission organizations the flexibility to propose designs for long-term firm transmission rights that reflect regional preferences and accommodate their regional market designs, while also ensuring that the objectives of Congress expressed in new section 217(b)(4) of the FPA are met. As described in more detail below, the Commission will allow regional flexibility in setting the terms of the rights, but long-term firm transmission rights must be made available with terms (and/or rights to renewal) that are sufficient to meet the reasonable needs of load serving entities to support long-term power supply arrangements used to satisfy their service obligations. I. Background A. The Development of ISOs and RTOs 3. In Order No. 888, the Commission found that undue discrimination and anticompetitive practices existed in the provision of electric transmission service in interstate commerce. 2 Accordingly, the Commission required all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to file open access transmission tariffs (OATTs) containing certain non-price terms and conditions and to “functionally unbundle” wholesale power services from transmission services. 3 In addition, the Commission found in Order No. 888 that Independent System Operators (ISOs) had the potential to aid in remedying undue discrimination and accomplishing comparable access 4 and set out 11 principles for assessing ISO proposals submitted to the Commission. 5 Following Order No. 888, several voluntary ISOs were established and approved by the Commission. 2 Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities , Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 at 31,682 (1996), order on reh'g , Order No. 888-A, 62 FR 12274 (March 14, 1997), FERC Stats & Regs. ¶ 31,048 (1997), order on reh'g , Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g , Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Policy Study Group v. FERC , 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC , 535 U.S. 1 (2002). 3 Under functional unbundling, the public utility is required to: (1) Take wholesale transmission services under the same tariff of general applicability as it offers its customers; (2) state separate rates for wholesale generation, transmission and ancillary services; and (3) rely on the same electronic information network that its transmission customers rely on to obtain information about the utility's transmission system. Id . at 31,654. 4 Order No. 888 at 31,655; Order No. 888-A at 30,184. 5 Order No. 888 at 31,730. 4. In light of the creation of these ISOs and other changes in the electric industry, the Commission issued Order No. 2000. 6 In that order, the Commission concluded that traditional management of the transmission grid by vertically integrated electric utilities was inadequate to support the efficient and reliable operation of transmission facilities necessary for continued development of competitive electricity markets 7 and that opportunities for undue discrimination continued to exist. 8 As a result, the Commission adopted rules to facilitate the voluntary development of Regional Transmission Organizations (RTOs). The Commission concluded that RTOs would provide several benefits, including regional transmission pricing, improved congestion management, and more effective management of parallel path flows. 9 In Order No. 2000, the Commission established the minimum characteristics and functions that an RTO must satisfy to gain Commission approval. 10 Under Order No. 2000, the Commission has approved the voluntary formation of a number of RTOs. 6 Regional Transmission Organizations , Order No. 2000, FERC Stats. & Regs. ¶ 31,089 (1999), order on reh'g , Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 (2000), aff'd sub nom. Public Utility District No. 1 of Snohomish County, Washington v. FERC , 272 F.3d 607 (D.C. Cir. 2001). 7 Order No. 2000 at 30,992-93 and 31,014-15. 8 Id . at 31,015-17. 9 Id . at 31,024. 10 Id . at 31,106 et seq. 5. Most of the RTOs and ISOs operate organized markets for energy and/or ancillary services in addition to providing transmission service under a single transmission tariff. Most of these markets utilize a congestion management system based on Locational Marginal Pricing (LMP). Congestion is defined as the inability to inject and withdraw additional energy at particular locations in the network due to the fact that the injections and withdrawals would cause power flows over a specific transmission facility to violate the reliability limits for that facility. The market operator manages congestion by scheduling and dispatching generators that can meet load in the presence of congestion. Financially, in LMP markets the price of congestion is measured as the difference in the cost of energy in the spot market at two different locations in the network. When such price differences occur, a congestion charge is assessed to transmission users based on their nodal injections and withdrawals. These price differences can be variable and difficult to predict. In order to manage the risk associated with the variability in prices due to transmission congestion, these markets use various forms of financial transmission rights (FTRs) 11 to allow market participants who hold the rights to protect against such price risks. In most cases, these FTRs have terms of one year or less. In general, load serving entities receive FTRs through either direct allocation or through a two-step process in which the load serving entity is first allocated auction revenue rights (ARRs) and then either uses those rights to purchase FTRs, or has the ability under the transmission organization tariff to convert them to FTRs. 12 11 While “FTR” is sometimes used to refer to “firm transmission rights,” in this Final Rule we use this acronym to refer to the various forms of financial transmission rights that exist in organized electricity markets. In some markets, these are referred to as congestion revenue rights or transmission congestion contracts. 12 For a more detailed discussion, see Long-Term Firm Transmission Rights in Organized Electricity Markets , Notice of Proposed Rulemaking, 71 FR 6693 (Feb. 9, 2006), FERC Stats. & Regs. ¶ 32,598 at P 27 (2006) (NOPR). As we noted in the NOPR, ARRs confer the right to collect revenues from the subsequent FTR auction. B. Interest in Long-Term Firm Transmission Rights 6. In recent years, interest in long-term firm transmission rights in organized electricity markets has increased, stemming in large part from a desire of some market participants to obtain rights that replicate the transmission service that was available to them prior to the formation of the organized electricity markets and remains available today in regions without organized electricity markets. The principal concern of these market participants is the inability to obtain a fixed, long-term level of service under pricing arrangements that hedge the congestion cost risk that they face in the organized electricity markets. 7. There are several important differences between transmission service under the Order No. 888 pro forma Open Access Transmission Tariff (OATT) and transmission rights in organized electricity markets that use LMP and FTRs. 13 However, the differences that are most relevant for purposes of this Final Rule concern the management of congestion, the recovery of congestion costs and the availability of long-term service arrangements. 13 A detailed discussion of transmission rights in traditional and organized markets was presented in the NOPR at P 15-33. 8. Under the OATT, the transmission provider in the first instance manages congestion by redispatching its own or its customers’ network resources as needed to accommodate a transmission constraint; the OATT provides no mechanism by which firm point-to-point transmission customers can participate directly in congestion management. 14 However, in the organized electricity markets that use LMP, the transmission organization manages congestion through the use of locational prices that are determined by bids and offers by markets participants at given locations. This means that all available resources under an LMP system can participate in redispatch for congestion management because they all receive the congestion price signal. As a result, a transmission organization in a region with an organized electricity market is less likely to have to invoke transmission loading relief procedures and service curtailments than a transmission provider under the OATT. 14 The transmission provider may also need to curtail service to certain customers. 9. The recovery of congestion costs also differs greatly between regions with and without organized electricity markets. In regions where transmission service is provided under the OATT, a transmission customer that takes network service or firm point-to-point transmission service is not charged directly for the costs of the redispatch that may be required to accommodate its use of the transmission system. For example, a firm point-to-point transmission customer is allowed to take service up to its contractual entitlement while paying only a fixed demand charge. Also, although a network customer must pay a share of any redispatch costs that the transmission provider and other network customers incur, its cost responsibility is determined after the fact as a load ratio share of the total redispatch costs that are incurred on behalf of all users of the system over a given time period. While this type of pricing may not present the customer with a price signal that accurately reflects all of the costs occasioned by the customer's use of the system, it does provide price certainty. In addition, both network service and firm point-to-point transmission service can be obtained under long-term contracts. These attributes of OATT transmission service result in a less volatile price for transmission service over the long-term, which in turn can help facilitate the planning and financing of large generation facilities and other long-term power supply arrangements. 10. In contrast, a transmission organization in a region with an organized electricity market recovers congestion costs measured as differences in the locational price of energy. Because locational prices include a congestion cost component (which can be positive, negative or zero), a participant in an organized electricity market faces the prospect of paying a congestion charge for many of its transactions. Locational pricing and price-based congestion management provide the market participant with much of the information it needs to make cost effective decisions regarding energy consumption and use of the transmission system (as well as investment in new generation and transmission upgrades). However, the FTRs that transmission organizations currently provide to hedge congestion charges for using existing transmission capacity (as opposed to incremental transmission expansions) are generally available for terms of only one year or less. This can create uncertainty for the market participant who wants to procure supplies on a long-term basis because it will not know from year to year with any degree of certainty whether its award of FTRs will be sufficient to meet its needs. Some market participants have expressed concern that this uncertainty makes it more difficult to finance long-term power supply arrangements. C. Staff Paper on Long-Term Transmission Rights 11. In May 2005, the Commission released a Staff Paper that provided background and solicited comments on whether long-term transmission rights were needed in the ISO and RTO markets, and if so, how to implement them. 15 A number of commenters on the Staff Paper argued that the failure of transmission organizations to offer transmission rights with terms greater than one year is a key deficiency in the markets that produces increased financial risk due to congestion price uncertainty, the failure of forward energy markets to form, and barriers to investment in new generation capacity. Most of the parties in this group stressed that not all transmission capacity should be given over to long-term rights, but that there should be an amount sufficient to cover at least base-load generation resources and perhaps renewable energy generators. 15 Notice Inviting Comments On Establishing Long-Term Transmission Rights in Markets With Locational Pricing and Staff Paper, Long-Term Transmission Rights Assessment, Docket No. AD05-7-000 (May 11, 2005) (Staff Paper). 12. A second group of commenters on the Staff Paper largely agreed with the first that long-term rights should be introduced, but argued that this should take place within the framework of existing FTR market designs and follow a cautious, incremental approach. They also supported limiting the quantity of system capability given over to long-term FTRs for at least an initial period. 13. Finally, some respondents felt that long-term rights should not be introduced at this time. These parties were concerned that the introduction of multi-year rights could introduce inequity and inefficiency into the organized electricity markets because such rights will reduce the availability of FTRs with terms of one year or less that can be used to hedge shorter-term transactions. They also assert that introducing long-term rights could cause cost shifts if holders of long-term rights are given congestion risk coverage greater than that accorded to other parties. D. Energy Policy Act of 2005 14. On August 8, 2005, EPAct 2005 16 became law. As noted above, section 1233 of EPAct 2005 added a new section 217 to the FPA, which provides: 16 Pub. L. 109-58, 119 Stat. 594 The Commission shall exercise the authority of the Commission under this Act in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities to satisfy the service obligations of the load-serving entities, and enables load-serving entities to secure firm transmission rights (or equivalent tradable or financial rights) on a long-term basis for long-term power supply arrangements made, or planned, to meet such needs. 17 17 Pub. L. 109-58, § 1233, 119 Stat. 594, 958. Section 1233(b) of EPAct 2005 requires: Within 1 year after the date of enactment of this section and after notice and an opportunity for comment, the Commission shall by rule or order, implement section 217(b)(4) of the Federal Power Act in Transmission Organizations, as defined by that Act with organized electricity markets. 18 18 Id . at 960. Transmission organization is defined in EPAct 2005 as “a Regional Transmission Organization, Independent System Operator, independent transmission provider, or other transmission organization finally approved by the Commission for the operation of transmission facilities.” Pub. L. 109-58, § 1291, 119 Stat. 594, 985. Below, we adopt this definition with a minor modification for purposes of this Final Rule. E. Notice of Proposed Rulemaking 15. On February 2, 2006, the Commission issued a NOPR that proposed to amend its regulations to require each transmission organization that is a public utility with one or more organized electricity markets to make available long-term firm transmission rights that satisfy guidelines established by the Commission. 19 As discussed in more detail below, the NOPR proposed eight guidelines, and sought comments on various issues raised by the introduction of long-term firm transmission rights in the organized electricity markets. 19 See supra note 12. II. Discussion A. Overview 16. In adopting this Final Rule, the Commission seeks to provide increased certainty regarding the congestion cost risks of long-term transmission service in organized electricity markets that will help load serving entities and other market participants make new investments and other long-term power supply arrangements. The guidelines we adopt in this Final Rule are designed and intended primarily to ensure that the long-term firm transmission rights that are made available by transmission organizations that are subject to the rule have characteristics that will support a long-term power supply arrangement. These guidelines provide a framework within which transmission organizations and their market participants can design and implement long-term firm transmission rights in the organized electricity markets that are compatible with the design of those markets, in particular retaining the advantages of price-based congestion management, and meet the reasonable needs of market participants. 17. Many of the comments received by the Commission express concern that the provision of long-term firm transmission rights will result in a drastic redistribution of transmission rights, with transmission organizations required to provide long-term rights to load serving entities regardless of feasibility or impact on other market participants. This concern is unfounded. While this Final Rule unequivocally requires transmission organizations to offer long-term firm transmission rights with characteristics that will support long-term power supply arrangements, in most cases, offering such rights should not require major changes in allocations or allocation procedures. 20 Our intent with regard to the existing transmission system is that load serving entities be able to request and obtain transmission rights up to a reasonable amount on a long-term firm basis, instead of being limited to obtaining exclusively annual rights. 21 Offering such rights should not force transmission organizations to provide rights to the existing system to one party that are infeasible. We expect that transmission organizations will be able to integrate long-term firm transmission rights into their existing procedures for assessing the feasibility of requests for transmission service. 20 As we discuss in more detail below, while we do not believe major changes to existing allocation procedures will be necessary, Congress did not intend to protect existing or future allocation methodologies from the implementation of section 217(b)(4) of the FPA. See new section 217(c) of the FPA, Pub. L. 109-58, § 1233, 119 Stat. 594, 958-59. 21 Capacity available would be limited to that which is generally available and excludes capacity that is the exclusive right of a participant, e.g. , a participant that paid for such capacity and obtained FTRs for that payment. 18. While it is difficult to generalize, given the flexibility afforded in this Final Rule, we expect that in most transmission organizations with organized electricity markets the process for obtaining a long-term firm transmission right will not be substantially different from the current procedures. Most transmission organizations will be able to use their current allocation/auction systems to allow load serving entities to nominate source-to-sink transmission rights on a longer-term basis than is currently available. Transmission organizations will then assess those requests for feasibility and award a feasible set of transmission rights, as they do today. This Final Rule also allows the transmission organization to place reasonable limits on the total amount of capacity it will offer as long-term rights. Thus, this Final Rule does not necessarily guarantee that a load serving entity will be able to obtain long-term firm transmission rights to hedge its entire resource portfolio or be able to obtain all the long-term firm transmission rights it requests. Once long-term rights are awarded to a load serving entity, however, this Final Rule requires that they be fully funded over their entire term, as discussed in guideline (2) below. 19. As we noted in the NOPR and reaffirm in this Final Rule, transmission organizations must provide the opportunity for market participants to obtain long-term firm transmission rights that are not currently available by supporting an expansion or upgrade of grid transfer capability. The Commission's policy is that market participants that request and support an expansion or upgrade in accordance with their transmission organization's prevailing rules for cost responsibility and allocation must be awarded a long-term firm transmission right for the incremental transfer capability created by the expansion or upgrade. The transmission organization tariffs must clearly and specifically provide for this arrangement, if they do not already. Guideline (3) addresses this requirement. This will enable load serving entities to obtain long-term rights that they may have requested but not received due to infeasibility. 20. Moreover, in this Final Rule we also require transmission organizations with organized electricity markets to explain how their transmission system planning and expansion policies will ensure that long-term firm transmission rights, once allocated, remain feasible over their entire term. 21. Together, these provisions will ensure that transmission systems are expanded where necessary to ensure the continued feasibility of allocated long-term firm transmission rights, while also giving market participants an explicit right to obtain new incremental transmission rights on a long-term basis, in accordance with the prevailing cost allocation methodology in the region. 22 22 We are not requiring any “obligation to build” that does not already exist under Order No. 888. 22. We understand that specifying and allocating long-term firm transmission rights supported by existing transfer capability will raise difficult issues that must be addressed by transmission organizations and their stakeholders as proposals are developed to comply with this Final Rule. As we discuss in more detail, we believe that the approach we adopt in this Final Rule will give transmission organizations and their stakeholders sufficient flexibility to design long-term firm transmission rights that fit their prevailing market design while also ensuring that the rights have certain fundamental properties necessary to achieve Congress's objectives in section 217(b)(4) of the FPA. We also clarify below that while each guideline permits flexibility in its implementation, transmission organizations with organized electricity markets must satisfy each of the guidelines in this Final Rule. 23. This Final Rule largely adopts the overall approach as well as the specific guidelines and definitions proposed in the NOPR. In response to the comments received, however, the Commission has made the following changes to the proposal, as discussed in this preamble: • Guideline (3) (Rights Made Available by Expansion Go to Parties That Pay for the Upgrade): We have removed the requirement that the term of long-term rights from expansion be equal to life of facility or a lesser term requested by the party paying for the upgrade. Based on the comments on the difficulty of defining life of facility, we will defer to transmission organizations to develop terms based on existing market rules and stakeholder needs. We encourage transmission organizations to harmonize the terms for long-term rights awarded for new capacity with the terms of long-term rights to existing transmission capacity as much as possible. • Guideline (4) (Term of Rights Must Be Sufficient To Hedge Long-Term Power Supply Arrangements): We have added a provision that transmission organizations and stakeholders may determine the length of terms and use of renewal rights to provide long-term transmission rights, but must offer coverage for at least a 10-year sequence. Our objective is to balance regional flexibility in defining terms of rights with the need to ensure that those terms are sufficient to allow load serving entities to hedge their long-term power supply arrangements. • Guideline (5) (Load Serving Entities With Long-Term Power Supply Arrangements Have Priority to the Existing System): We have revised this guideline in two respects. First, we have eliminated the preference for load serving entities with long-term power supply arrangements and replaced it with a broader preference for load serving entities in general vis-à-vis non-load serving entities. This broader preference is fully supported by the statute and better meets the needs of organized electricity markets. We believe that Congress's intent in enacting section 217 was to provide long-term firm transmission service to load serving entities and that load serving entities in general should be “first in line” for long-term transmission rights when existing capacity is limited. As originally proposed, guideline (5) could have disadvantaged load serving entities who do not engage in long-term power supply arrangements, a result that we do not believe Congress intended. Proposed guideline (5) could have also presented difficult administrative burdens for transmission organizations, including the burden of evaluating power supply contracts to determine if they qualify for the preference. In addition to addressing these concerns, broadening the preference also makes it possible for transmission organizations to apply the same basic principles for allocating long-term firm transmission rights that they currently use for the initial allocation of short-term firm transmission rights, or auction revenue rights. As a result of this change in the guideline, load serving entities will not be required to provide evidence of a long-term power supply arrangement. We have also revised guideline (5) to allow transmission organizations to place reasonable limits on the amount of existing transmission capacity made available for long-term firm transmission rights. We have done so in recognition of the expected reluctance of transmission organizations to commit all of their existing grid capacity to long-term firm transmission rights due to uncertainty regarding load growth, changes in power flows and the full funding requirement of this Final Rule. This will also help to accommodate load serving entities that prefer short-term rights. In addition, commenters claim that the principal need for long-term firm transmission rights is to support long-term power supply arrangements for base load generation, not peaking or intermediate generation. • Guideline (8) (Balance Adverse Economic Impacts): We have elected not to adopt this guideline in the Final Rule. This guideline is not needed as it requires, in effect, nothing more than adherence to the FPA requirement that public utility tariffs must be just and reasonable and not unduly discriminatory. Moreover, it could have been misinterpreted to require long-term firm transmission right proposals to meet a different or higher standard, something the Commission did not intend or believe that Congress intended. • Definition of “Long-Term Power Supply Arrangement”: Because we have deleted the reference to “long-term power supply arrangements” from guideline (5), that term is only used in guideline (4), relating to the term of long-term firm transmission rights. The Final Rule removes the specific definition of long-term power supply arrangements proposed in the NOPR, and addresses issues related to our definition of long-term power supply arrangements under guideline (4). • Transmission Planning and Expansion: This Final Rule requires that each transmission organization with an organized electricity market implement transmission system planning and expansion procedures to accommodate long-term firm transmission rights that are allocated or awarded to ensure that they remain feasible over their entire term. We also require each such transmission organization to make its planning and expansion practices and procedures publicly available, including both the actual plans and any underlying information used to develop the plans. B. Definitions 1. Organized Electricity Market 24. In the NOPR, the Commission proposed to define “organized electricity market” as “an auction-based market where a single entity receives offers to sell and bids to buy electric energy and/or ancillary services from multiple sellers and buyers and determines which sales and purchases are completed and at what prices, based on formal rules contained in Commission-approved tariffs, and where the prices are used by a transmission organization for establishing transmission usage charges.” 23 The Commission stated that it proposed this definition to ensure that the Final Rule in this proceeding applies to any transmission organization that is the transmission provider in its region and has a day-ahead and/or real-time bid-based energy market, administered by the transmission organization itself or by another entity. We sought comment on the scope of this proposed definition. 23 NOPR at P 8. Comments 25. AMPA 24 and Public Power Council both argue that the proposed definition is too narrow and should be expanded to include “Day 1” RTO/ISO markets, non-RTO/ISO markets, and other forms of “organized markets” (which can include bilateral markets that use a form contract). 25 Public Power Council argues that the proposed definition could lock the Commission into adopting the types of markets described in the definition to the exclusion of other types of markets, and that section 217 of the FPA does not support the Commission's narrow reading. 24 A list of commenters on the NOPR and the acronyms used to refer to them in this preamble is attached as Appendix A. 25 NRECA, while not recommending any change to the proposed definition, notes that the issues raised over the availability of long-term firm transmission rights also arise in transmission organizations without Day 2 markets and on the systems of non-independent entities. 26. Other commenters argue that the definition should be narrowed. TAPS, for example, asserts that the Final Rule should not apply in regions where the OATT provides for long-term physical transmission rights, particularly the Southwest Power Pool. According to TAPS, the last clause of the definition of organized electricity markets (“where the prices are used by a transmission organization for establishing transmission usage charges”) excludes SPP because the prices produced by its imbalance market will not establish transmission usage charges. TAPS requests that the Commission clarify that as currently designed SPP will not be subject to the Final Rule. 27. PG&E, EPSA and TAPS all state that because the proposed rule primarily addresses markets that use locational market-based congestion management mechanisms like LMP and have FTRs, the Final Rule should clearly state that it only applies to those markets, and only addresses long-term financial transmission instruments. PG&E recommends that the Commission issue a parallel rule providing for long-term transmission rights in markets that do not use a market-based congestion management mechanism. 28. In reply comments, NRECA opposes proposals to narrow the definition of organized electricity market, arguing that the need for long-term firm transmission rights and the language of the statute are not limited to transmission organizations with locational pricing structures. 29. APPA states that it supports the proposed definition of organized electricity market, but suggests that it be revised to replace “auction-based market” with “a centralized market” because use of “auction-based” implies that buyers and sellers in RTO markets have more choice and autonomy than they do in practice. Commission Conclusion 30. We will adopt the definition of organized electricity market proposed in the NOPR with one modification. Specifically, we modify the first clause of the definition to state that organized electricity market “means an auction-based day ahead and real time wholesale market * * *.” We make this modification to clarify the application of this Final Rule and ensure that the definition captures the transmission organizations with organized electricity markets using LMP and FTRs to which Congress directed the Commission to apply this Final Rule to in section 1233(b) of EPAct 2005. Today, those electricity markets do not offer financial transmission instruments supported by existing capacity with terms longer than one year, and thus entities are not able to obtain a “firm” transmission right on a long-term basis in those markets as section 217(b)(4) of the FPA directs. As a result, they are appropriately the focus of this Final Rule. 31. The Commission will not expand the definition to include other RTO/ISO regions (sometimes called “Day 1” markets), non-RTO/ISO transmission providers, or any other electricity market structure. Applying the Final Rule to non-RTO/ISO markets would not be appropriate because EPAct 2005 requires us to implement section 217(b)(4) in this rulemaking in “transmission organizations with organized electricity markets,” and non-RTO/ISO transmission providers by definition are not transmission organizations. 26 And while Public Power Council is correct that there may be other electricity market structures, the definition we adopt here is only for the purposes of this Final Rule and is crafted to ensure that the appropriate entities are subject to the Final Rule. Additionally, as we noted in the NOPR, non-RTO/ISO transmission providers and other RTO/ISOs offer long-term physical transmission service under the Order No. 888 OATT without rates that vary with congestion costs. 27 The Commission recently issued a NOPR in Docket Nos. RM05-25-000 and RM05-17-000 that would institute reforms to the OATT. It is more appropriate to consider in that rulemaking any issues related to the application of section 217(b)(4) of the FPA to the other markets identified by commenters, particularly issues related to coordinated, open and transparent transmission system planning. 26 This is not to say that there might not in the future be types of transmission organizations other than ISOs and RTOs approved by the Commission that operate transmission facilities and provide transmission service. The new FPA definition of transmission organization leaves open this possibility. At the current time, however, RTOs and ISOs are the only such organizations approved by the Commission. 27 While transmission organizations with organized electricity markets are also expected to have OATTs that meet the requirements of Order No. 888, the total cost of transmission service in those transmission organizations varies with the cost of congestion, and such transmission organizations only offer FTRs to hedge congestion costs with short-terms. 32. In response to TAPS, we clarify that SPP is not subject to this Final Rule because its current market design does not fit within the definition of organized electricity market that we adopt for purposes of this rule. 33. Finally, we decline to revise the “auction-based” language as APPA requests. This language simply recognizes that the organized electricity markets Congress intended to be subject to this Final Rule are those that utilize auction mechanisms for the buying and selling of electric energy. We note that we are adopting this definition for the purposes of this Final Rule only, and do not intend that it will necessarily apply in other contexts. 2. Load Serving Entity and Service Obligation 34. We proposed to define “load serving entity” and “service obligation,” for purposes of the proposed rule, exactly as Congress defined those terms in new section 217 of the FPA. Specifically, we proposed to define load serving entity as “a distribution utility or electric utility that has a service obligation.” 28 We proposed to define service obligation as “a requirement applicable to, or the exercise of authority granted to, an electric utility under federal, State or local law or under long-term contracts to provide electric service to end-users or to a distribution utility.” 29 28 NOPR at P 7, citing Pub. L. 109-58, § 1233, 119 Stat. 594, 957. EPAct 2005 defines electric utility as “a person or Federal or State agency (including an entity described in section 210(f)) that sells electric energy.” Pub. L. 109-58, § 1291, 119 Stat. 594, 984. 29 NOPR at P 7, citing Pub. L. 109-58, § 1233, 119 Stat. 594, 958. Comments 35. APPA, E.ON, NRECA, PG&E and Public Power Council all express support for the proposed definitions. 36. Several commenters (including Industrial Consumers, CAISO, NARUC, National Grid and SDG&E) argue that the proposed definitions in the NOPR would exclude several entities that should be eligible for long-term firm transmission rights because they are not a “distribution utility” or “electric utility.” These entities include industrial customers who serve their own load pursuant to state law, several types of retail service providers, community aggregators, and various non-public utilities. The comments generally seek clarification that all of these various entities are “load serving entities” for purposes of this rule. 37. More specifically, Industrial Consumers and Alcoa explain that while many large industrial customers are permitted under state law to self-supply their own load, usually by registering as a retail provider, not all of these states use the term “load serving entity.” Industrial Consumers argue that entities who have qualified as retail electric providers under state law meet the definition of “electric utility” under EPAct 2005, and request that the Commission unambiguously state that entities who are qualified to serve retail load under state law, including those self-supplying, are load serving entities for purposes of the Final Rule and thus qualify for long-term firm transmission rights. 38. Regarding retail service providers, several commenters (including CAISO, EEI, NARUC and National Grid) seek clarifications regarding whether various types of service providers in retail access states are load serving entities under the proposed definition. NARUC notes that states with retail choice programs either may have multiple sellers of electricity to end users, or may use an auction process whereby the distribution utility takes delivery of the power supply and bills the cost to customers, making it the only seller. 30 To protect and accommodate these choices made by the states, and to be consistent with Congress’ intent that the protections in section 217 of the FPA be available to all customers, it asks the Commission to clarify that all of these entities are “electric utilities” and/or “distribution utilities,” thereby making them load serving entities and eligible to obtain long-term firm transmission rights. 31 OMS, noting specifically that Illinois utilities will soon be required to use an auction process to procure supply and that auction winners under this format would not meet either definition, asks the Commission to revise the definition of load serving entity to replace “a distribution utility or electric utility” with “an entity,” and revise the definition of service obligation to replace “electric utility” with “entity.” EEI and National Grid both note that under certain retail access structures service obligations (including the default service obligation) may be reassigned for terms that are less than the term of long-term firm transmission rights. EEI asserts that the proposed definition of load serving entity should be clarified to be simply the distribution utility, unless its service obligation has been reassigned, while National Grid suggests that the load serving entity should be the electric utility when it holds the service obligation, and the distribution utility in the first instance. National Grid also asserts that the Commission should clarify that the term “electric utility” is defined in section 3(22) of the FPA (any “person or Federal or State agency * * * that sells electric energy”), which would encompass both municipal utilities and merchant suppliers not normally subject to state regulation. 30 National Grid notes that pursuant to state law, its distribution utilities have at various times been required to contract with wholesale suppliers to meet their load obligations (including congestion cost exposure), while in other retail choice programs those responsibilities have been directly assigned to retail suppliers. 31 In its reply comments, NARUC reiterates its request, further stating that the Commission should clarify that vertically-integrated utilities, municipal utilities and cooperatives in traditionally regulated states, power suppliers in retail states, and distribution utilities or auction winners in other states are all “electric utilities” and/or “distribution utilities,” and thus eligible to obtain long-term firm transmission rights. 39. Santa Clara asserts that the definition of load serving entity should include non-public utilities (as defined in section 201(f) of the FPA), subsidiary agencies of non-public utilities, and entities in which non-public utilities hold an interest (such as joint action agencies), since each either serve load under statutory obligations to serve or facilitate such service. Similarly, California DWR and MWD argue that the Commission should revise the definition of load serving entities to include water pumping entities. 32 They assert that in new section 217(g) of the FPA, Congress recognized a need to expand the definition of load serving entity to include such entities. 33 To comply with section 217(g), California DWR and MWD contend that the Commission should revise the proposed definition to define load serving entity to mean “a distribution utility, or an electric utility that has a service obligation, or other wholesale transmission user that owns generation facilities, markets the output of federal generation facilities, or holds rights under one or more wholesale contracts to purchase electric energy, for the purpose of meeting a service obligation.” 34 32 MWD notes that its water pumping operations require large amounts of power (roughly 2-3 percent of California's total energy requirement), and that these operations require long-term transmission rights to achieve reliable water delivery. 33 Specifically, section 217(g) provides that “[t]he Commission shall ensure that any entity described in section 201(f) that owns transmission facilities used predominately to support its own water pumping facilities shall have, with respect to the facilities, protections for transmission service comparable to those provided to load serving entities pursuant to this section.” See Pub. L. 109-58, § 1233, 119 Stat. 594, 959. 34 Reply Comments of California DWR at 9. 40. MSATs seek clarification that as stand-alone transmission companies that do not own generation or distribution facilities, buy or sell energy, serve loads or act as transmission customers or market participants, they are not considered load serving entities under the Commission's proposed regulations. 41. Ameren asks the Commission to clarify that the definition of service obligation includes future obligations, and not just obligations existing at the effective date of the Final Rule, which it states will provide certainty and reassure load serving entities that long-term firm transmission rights will continue to be made available in the future. 42. Commenters (including CAISO, PG&E and NU) also raise issues and seek clarification specifically with regard to the application of the service obligation definition in retail access frameworks, and particularly seek clarification as to whether a default service obligation is a “service obligation.” According to CAISO, these clarifications are important because they will impact the eligibility rules for long-term firm transmission rights and the rules for transferring those rights as end-users switch providers. Commenters such as PG&E assert that entities holding the default service obligation, even though they may not be serving the load now, must be able to plan to meet that load should they be required to serve it in the future. Coral Power states that the definition of service obligation should be expanded because as proposed by the Commission, it only applies to distribution companies or entities that provide electric service to end-users under contracts. It argues that the definition should include wholesale power suppliers that provide hedging services to competitive retail suppliers or that have assumed load obligations under default service or retail access programs. 43. Commenters (including NU and PG&E) also raise issues with the “long-term contracts” language in the definition, arguing that it has the potential to discriminate against load serving entities in retail access jurisdictions, since such entities do not typically enter into long-term power supply contracts. NU argues that in New England, the definition would favor municipal utilities (whose customers are not included in retail access programs) and utilities from outside the region that serve load through New England resources. 35 Accordingly, it asks that the Commission narrow the definitions to limit eligibility for long-term firm transmission rights to entities that serve customers within the same region. 35 Comments of NU at 3-4. Commission Conclusion 44. In the Final Rule, the Commission is adopting the definitions of load serving entity and service obligation provided by Congress in EPAct 2005 and proposed in the NOPR. We believe using these definitions as Congress provided them will most closely effectuate the intent of Congress in section 217(b)(4) of the FPA. We will, however, offer several clarifications. 45. At the outset, we note that the definition of load serving entity is important in this Final Rule only in that it establishes a priority in the allocation of long-term firm transmission rights when necessary under guideline (5). It does not determine eligibility for long-term firm transmission rights, as some commenters suggest. All market participants are eligible for long-term firm transmission rights. 46. In response to National Grid, we clarify that the term “electric utility,” as used in the definition of load serving entity, is defined in section 3(2) of the FPA as “a person or Federal or State agency (including an entity described in section 201(f)) that sells electric energy.” 36 This expansive definition will cover many of the entities for which commenters seek clarification as to their status as load serving entities. 36 16 U.S.C. 796(22) (2000), as amended by EPAct 2005, Pub. L. 109-58, § 1291(b)(1), 119 Stat. 594, 984. 47. With regard to large industrial customers who self-supply their own load, while some of these entities may not technically “sell * * * electric energy,” we construe them to be load serving entities for purposes of this Final Rule, to ensure that Congress's objectives in section 217 of the FPA are fulfilled. Thus, transmission organizations should treat them as such when complying with this rule. 48. With regard to non-public utilities, the Commission notes that the definition of electric utility discussed above, as amended by EPAct 2005, includes “an entity described in section 201(f)” of the FPA, i.e. non-public utilities. As a result, they are within the definition of load serving entity, provided, of course, that they have a service obligation. Additionally, in response to California DWR and MWD, we note that the definition of load serving entity provided by Congress appears to already capture water pumping entities, which are non-public utilities. New section 217(g) of the FPA provides that “[t]he Commission shall ensure that any entity described in section 201(f) that owns transmission facilities used predominately to support its own water pumping facilities shall have, with respect to the facilities, protections for transmission service comparable to those provided to load serving entities pursuant to this section.” 37 In light of this Congressional directive, we clarify, to the extent necessary, that water pumping entities with the characteristics described in section 217(g) are load serving entities for purposes of this Final Rule. 37 Pub. L. 109-58, § 1291(b)(1), 119 Stat. 594, 984. 49. MSATs request that we clarify that stand-alone transmission companies are not load serving entities for purposes of this rule. We clarify that as described by MSATs, stand-alone transmission companies that do not own generation or distribution facilities, buy or sell energy, serve loads or act as transmission customers are not load serving entities for purposes of this Final Rule. We emphasize, however, that this clarification should not be read broadly to suggest that other types of stand-alone transmission companies (either existing or that might be developed) with different characteristics from those described by MSATs will not be load serving entities under this Final Rule. The Commission will consider these issues on a case-by-case basis, as necessary. 50. In response to those seeking clarifications regarding various types of retail service providers, we note that many retail service providers will be a “person * * * that sells electric energy,” thus making it an electric utility and, consequently, they can be a load serving entity provided they have a service obligation. The Commission cannot decide here, however, whether each possible entity operating in state retail electric markets will meet the definition of load serving entity. We agree with NARUC, however, that Congress intended to broadly protect the ability of load serving entities with service obligations to obtain transmission service. Thus, transmission organizations should ensure that different types of retail service providers that have service obligations are accommodated when implementing the Final Rule. 51. As noted above, commenters raising issues regarding the application of the service obligation definition in retail access frameworks focus primarily on the default service obligation, which generally (with variation from state-to-state) requires the entity subject to that obligation to provide electric service to customers who do not have another supplier (either because they did not choose one or because their supplier left the market). Under the definition provided by Congress, a default service obligation only becomes a service obligation for purposes of this rule when the entity holding the default obligation is actually required to serve the load, i.e. when the competitive supplier either stops serving the load or the load switches to the default supplier. A default service obligation only becomes “a requirement applicable to, or the exercise of authority granted to” the default supplier when it must actually serve the load. We understand the concerns expressed by PG&E and others that a utility holding the default service obligation must plan to serve that load should it be required to do so in the future. Transmission organization rules currently provide that auction revenue rights (ARRs) or FTRs will generally “follow the load” in instances where load switches suppliers; guideline (6), discussed below, also requires that long-term firm transmission rights allocated to load serving entities be reassignable. As a result, when default suppliers assume the service obligation, they will receive transmission rights that they can use to serve the default load. While we are aware that those transmission rights may not match the resources that the default supplier will use to serve the load, this is a problem that already exists today, and is not a result of our adoption of Congress's definition of service obligation. Transmission organizations may consider whether any rules are necessary (such as allowing or requiring holders of long-term transmission rights to turn back those rights for reallocation) to deal with this problem. 52. We decline to revise the definitions of load serving entity and service obligation to replace “distribution utility or electric utility” and “electric utility” with “an entity,” as requested by OMS. Congress chose to use these terms to limit these definitions, and we are not persuaded to change them here, and do not believe such a change is necessary to address OMS's concern. While OMS may be correct that auction winners under Illinois’ procurement mechanism may not meet these definitions, the Illinois utilities that procure electric energy under this mechanism and resell it to their customers (under their service obligation) presumably meet the definitions of load serving entity and service obligation, and thus should be able to obtain long-term firm transmission rights to deliver that energy to load. Similarly, we decline to define load serving entity to be only the distribution utility, unless its service obligation has been reassigned, as requested by EEI, or to be the distribution utility in the first instance, as requested by National Grid. This would limit the definition provided by Congress, which chose to include electric utilities (other than distribution utilities) that have service obligations in the definition, and we are unsure how these revisions would address EEI and National Grid's concerns. As we note above, when load serving obligations are reassigned, the new entity serving that load will be a load serving entity and have a service obligation under the definitions in this Final Rule, and associated transmission rights will “follow” that load. Any problems associated with transmission rights whose term is longer than the transferred service obligation may be addressed in proposals to implement this rule; revising these definitions do not appear to resolve such concerns. 53. In response to Ameren, we clarify that the definition of service obligation, as written by Congress and adopted by the Commission in this Final Rule, includes future service obligations and not simply those existing on the effective date of this rule. Nothing in that definition, or in section 217(b)(4)'s charge that the Commission exercise its FPA authority in a manner that facilitates the planning and expansion of transmission facilities and enables load serving entities to obtain long-term firm transmission rights, suggests that service obligations should be limited to those existing as of the effective date of this rule. 54. Finally, we will not revise the definition in response to the concerns raised by NU and PG&E regarding the “long-term contracts” language in the definition of service obligation. The definition provides that a service obligation is either “a requirement applicable to, or the exercise of authority granted to, an electric utility under Federal, State, or local law or under long-term contracts * * *.” (emphasis added). Thus, having a long-term contract to serve load is not necessary to have a service obligation under this definition. Load serving entities in retail access jurisdictions will be interpreted to have a service obligation under this rule if they are either required, or have been given authority, under state law to provide electric service. Thus, we do not believe the definition results in any discrimination against load serving entities in those jurisdictions or gives any favor to municipal utilities not included in retail access programs. 3. Long-Term Power Supply Arrangement 55. We noted in the NOPR that while new section 217(b)(4) of the FPA requires the Commission to exercise its authority to enable load serving entities to obtain long-term firm transmission rights “for long-term power supply arrangements made * * * or planned” to meet service obligations, Congress did not define “long-term power supply arrangements” in the legislation. 38 Based on language in section 217(b)(1) of the FPA, we proposed to define long-term power supply arrangements as “the ownership of generation facilities, rights to market the output of Federal generation facilities with a term of longer than one year, or rights under one or more wholesale contracts to purchase electric energy with a term of longer than one year, for the purpose of meeting a service obligation.” 39 38 NOPR at P 9 citing Pub. L. 109-58, § 1233, 119 Stat. 594, 958. 39 NOPR at P 9. Comments 56. NRECA and PG&E support the proposed definition. Public Power Council also supports the proposed definition with two “editorial suggestions.” First, it suggests removing the phrase “with a term of longer than one year” after “Federal generation facilities” because it is redundant. Second, it suggests replacing the word “rights” where it appears before the phrase “to market the output of Federal generation facilities” with “authority or obligation,” since federal Power Marketing Agencies (like BPA) have a statutory obligation, rather than a “right,” to market the output of their facilities. 40 40 Public Power council notes that the Commission could also interpret rights as a description of these statutory obligations. 57. Commenters taking issue with the proposed definition addressed three primary issues: (1) The “longer than one year” language, (2) whether the definition should include specific criteria, and (3) whether the definition unduly discriminates against load serving entities in retail access states. 58. APPA argues that the Commission should not define “long-term power supply arrangements” as “longer than one year,” and should instead harmonize this definition with minimum term of long-term firm transmission rights discussed in guideline (4). PJM and TAPS also state that this language is unreasonable, and argue that “long-term power supply arrangements” should be defined as those with a minimum term of 10 years. According to TAPS, this change would appropriately limit the availability of long-term rights to those long-term power supply arrangements most poorly served by annual FTRs, particularly baseload and renewable power arrangements with terms longer than 10 years. 59. Some commenters suggest that the Commission revise the definition of “long-term power supply arrangements” to require that they have certain specific characteristics. CAISO and PG&E, for example, suggest that to make more transparent the process of validating requests for long-term rights, “long-term power supply arrangements” should designate specific resources. Others argue that to prevent inefficient allocations of long-term firm transmission rights, the Commission's definition should require “long-term power supply arrangements” to be firm for their entire term, specify specific amounts of energy, and be for both capacity and energy. Wisconsin Electric suggests that the definition exclude peaking facilities. Wisconsin Electric also asks that the Commission clarify that long-term leasing arrangements or other arrangements, in addition to ownership, qualify as “long-term power supply arrangements.” 60. In response to CAISO, CMUA states that while it agrees that contracts with flexible points of delivery are an implementation issue that must be addressed, it is concerned that CAISO's proposed modification is too narrow. According to CMUA, if CAISO's proposed modification would make long-term transmission rights available only for unit contingent contracts, it would create upheaval in the bilateral markets of the West, where power supply contracts with multiple resources are common. 61. NSTAR suggests that the combination of this definition and guideline (5) results in a long-term firm transmission right that is not available to (and thus unduly discriminates against) load serving entities that provide default service in retail access states because such entities do not enter into “long-term power supply arrangements,” as defined in the rule. According to NSTAR, these entities do not generally own generation and do not enter into long-term power supply contracts either because of the variable nature of their service obligation from year to year or because state regulatory requirements limit them to short-term power purchase agreements. According to NSTAR, requiring long-term power supply arrangements (including generation ownership or purchased power contracts) would conflict with section 217's overall purpose to protect the transmission rights of all end users and deal a blow to competitive retail electric markets by benefiting long-term rights holders at the expense of retail access loads holding shorter-term rights. NSTAR suggests that the Commission correct this problem by adding “or other arrangements for the purpose of meeting a service obligation on a long-term basis” to the definition. Commission Conclusion 62. As discussed in more detail below, the Commission is removing from guideline (5) the requirement that, in order to have priority in the allocation of long-term firm transmission rights from existing capacity, a load serving entity must hold long-term power supply arrangements. Therefore, that term is only used in the final regulations in guideline (4), relating to the term of long-term firm transmission rights. Accordingly, we are removing the definition of long-term power supply arrangements from the Final Rule, and will generally discuss issues related to our definition of long-term power supply arrangements under guideline (4), particularly with regard to the length of such arrangements. The discrimination arguments raised by certain parties in response to the proposed definition are discussed under guideline (5). 4. Transmission Organization 63. In the NOPR, we proposed to define “transmission organization” as “a Regional Transmission Organization, Independent System Operator, independent transmission provider, or other independent transmission organization finally approved by the Commission for the operation of transmission facilities.” 41 This proposed definition is similar to the definition of transmission organization provided by Congress in EPAct 2005, except that we added the term “independent.” We explained in the NOPR that we added “independent” because we interpret section 1233(b) of EPAct 2005 to require that long-term firm transmission rights be made available by independent entities that are approved by the Commission (either currently or in the future) to operate transmission facilities and have organized electricity markets. 41 NOPR at P 6. Comments 64. EPSA, PG&E and PJM all support the Commission's proposal to include “independent” in the definition of transmission organization. 65. APPA and AMPA, while supportive of the Commission's addition of the word “independent” to the definition of “transmission organization” provided by Congress, note that this addition raises questions regarding the level of independence required to be considered a “transmission organization.” Both raise the question of whether ICT's are “transmission organizations.” APPA argues that an ICT should not be considered an independent transmission organization because it is employed and paid solely by the transmission-owning utility. APPA adds, however, that it assumes the Commission will apply a “flexible, yet vigilant” standard to determine the independence of transmission organizations. 42 AMPA, for its part, asserts that given the broad intent of EPAct 2005, the Commission should consider applying the NOPR to all organized electricity markets with independent transmission providers, to ensure that all load serving entities will receive protection for their service obligations and long-term price certainty. 42 Comments at APPA at 11. 66. Public Power Council, on the other hand, specifically opposes the addition of the word “independent,” arguing that it unduly restricts the definition adopted by Congress, which intended that any organization finally approved by the Commission for the operation of transmission facilities (whether or not independent) would fall under the statute. According to Public Power Council, Congress instead chose to qualify “other transmission organization” with the phrase “finally approved by the Commission for the operation of transmission facilities,” meaning any such transmission organization falls under the statute whether or not it is independent. Commission Conclusion 67. The Commission will adopt the definition of transmission organization proposed in the NOPR. In section 1233(b) of EPAct 2005, Congress narrowed the Commission's implementation efforts to “Transmission Organizations * * * with organized electricity markets,” even though the overall directive of section 217(b)(4) applies more broadly. We believe that it is reasonable to interpret the more focused directive in section 1233(b) as principally requiring that the Commission implement section 217(b)(4), through rulemaking, in the current independent RTOs and ISOs that operate centralized markets for the purchase of electric energy and/or ancillary services, and any similar transmission organizations that are created in the future. This does not mean, however, that the requirements of section 217(b)(4) will not apply to other transmission providers. The Commission is simply adopting a definition of transmission organization for purposes of this Final Rule that it believes comports with Congress's intent, expressed in section 1233(b) of EPAct 2005, that the Commission act specifically with regard to transmission organizations with organized electricity markets. 68. In response to comments concerning the level of independence required to be a transmission organization, we note that prior to approving transmission organizations (such as RTOs and ISOs) with organized electricity markets, the Commission makes specific findings, based on established standards, that the entity is independent from market participants. We do not believe any further determination or separate standard is required for purposes of this rule. 69. With regard to comments seeking to clarify whether proposed independent coordinators of transmission are transmission organizations under this Final Rule, we note that these proposals are still developing. Moreover, to date none of these proposed entities has proposed to implement an organized electricity market as defined in this Final Rule. As a result, the Commission will not address whether such entities meet the definition of transmission organization unless and until such time as they propose to establish an organized electricity market. C. Commission Interpretation of EPAct 2005 Requirements 70. In addition to the comments below regarding our flexible approach in the NOPR, several entities submitted comments generally addressing our interpretation of the requirements of new section 217(b)(4) of the FPA and section 1233(b) of EPAct 2005 with respect to long-term firm transmission rights in organized electricity markets. Comments regarding specific interpretations of the statutory requirements that we made in connection with the proposed guidelines are addressed elsewhere in this Final Rule. Comments Long-Term Transmission Rights from Existing Capacity 71. Some commenters, particularly Cinergy, Coral Power and NYISO, argue that the Commission misinterprets section 217(b)(4) and section 1233(b) of EPAct 2005 as requiring the long-term firm transmission rights be made available from existing capacity. They assert that those provisions only require the Commission to exercise its authority to facilitate the planning and expansion of transmission facilities in a manner that allows load serving entities to secure long-term transmission rights. Thus, they contend that the Commission inappropriately gives independent effect to the second clause of the statute (“enables load serving entities to secure firm transmission rights * * * on a long-term basis”), when the true thrust of the law is its first clause (“[t]he Commission shall exercise * * * [its] authority * * * in a manner that facilitates the planning and expansion of transmission facilities * * *”). The second clause, they contend, only modifies the first. 72. In reply comments, APPA, New England Public Systems, NRECA, Peabody, and TAPS urge the Commission to reject Cinergy's interpretation of the statute. In general, they state that the Commission correctly reads section 217(b)(4) as providing two directives: (1) Facilitating transmission planning and expansion, and (2) enabling load serving entities to obtain long-term transmission rights for their long-term power supply arrangements. TAPS argues, for example, that nothing in the statute's long-term rights clause restricts such rights to new capacity, as Cinergy and others suggest, and further asserts that such a reading would inappropriately “sell short” and render both the long-term rights and planning provisions a nullity. Similarly, APPA contends that if planning and expansion were all Congress sought to address, it would not have included the second clause of section 217(b)(4). Need To Require Long-Term Financial Rights 73. Cinergy and others note a difference between long-term transmission rights and long-term FTRs. According to Cinergy, load serving entities can already acquire long-term transmission rights, and Congress would have used “and” instead of “or” if it intended to require RTOs to also provide long-term FTRs. 43 IPL similarly argues in its reply comments that the creation of long-term firm transmission rights or long-term financial transmission rights is not statutorily mandated, and as a result must be justified in the record, since it is a “stark departure from past practices.” 44 IPL states that section 217(b)(4) is properly implemented by ensuring that load serving entities can obtain either firm or financial transmission rights on a long-term basis. 43 Comments of Cinegry at 14. 44 Reply comments of IPL at 7. 74. In response to these arguments, APPA argues that the term “firm transmission rights” was meant to refer to the physical transmission rights that exist in non-transmission organization markets (since the statute covers all regions), and that the inclusion of the phrase “or equivalent tradable or financial rights” was intended to address the FTRs used in transmission organization markets. According to APPA, the network service contract and associated payment toward the fixed cost of the transmission system does not cover transmission congestion costs. Only an FTR covers these costs and “firms up” the total cost of transmission service, APPA contends. Finally, it, along with NRECA and TAPS, state that if Cinergy's assertion that transmission organizations already provide long-term transmission rights in compliance with the statute is correct, then section 217(b)(4) was unnecessary and did nothing. Disruption of Current Market Designs or Allocation Methods 75. Some entities, including IPL, Midwest ISO and NYISO, argue that Congress did not intend for the Commission, when implementing section 217(b)(4), to disrupt current market designs or existing transmission rights allocation methodologies. Of these entities, some argue that nothing in section 217 suggests that the Commission require major changes to the existing auction-based FTR systems, and that it would be consistent with section 217 for the Commission to allow transmission organizations to retain their current systems so long as they offer long-term financial transmission rights. Midwest ISO, for example, asserts that section 1233(c) of EPAct 2005 provides that Congress did not intend for the Commission to disrupt existing market designs that already offer long-term FTRs. Similarly, NYISO asserts that nothing in section 217 requires major changes to auction-based FTR systems, noting that this section expressly recognizes that financial rights can be equivalent to physical rights and expressly protects established FTR allocation systems. According to NYISO, the Commission could, consistent with section 217, allow transmission organizations and their stakeholders to retain their current systems so long as they offer long-term FTRs. IPL states, in part, that Congress was aware of the current transmission rights constructs in the organized markets, and by using the phrase “or equivalent tradable or financial rights,” “at the very least left open the possibility that the Commission might use existing financial rights designs to achieve the statutory objectives.” 45 NYISO also contends that nothing in section 217 requires transmission organizations to offer any rights with longer terms than they already do, noting that section 217 only requires that rights be “long-term” without saying what that means. PJM, while generally supportive of the Commission's NOPR, nevertheless notes that section 217(c) preserved existing FTR allocation methodologies, and argues that Congress sought to complement rather than replace current transmission rights allocation methods. 45 Id. 76. NYAPP, in reply comments, objects to NYISO's contention that nothing in section 217 requires transmission organizations to offer any rights with longer terms than they already do, arguing that this interpretation would render section 217(b)(4) a nullity. 77. Midwest TDUs notes in its reply comments that Midwest ISO is subject to a specific directive to consider the preservation of existing transmission rights. Specifically, Midwest TDUs point out that under section 217(c), which shields the other established transmission organizations from the impact of section 217(b)(1) through (b)(3), Midwest ISO is subject to that section's “provided, however” clause, thus requiring the Commission to take into account existing rights held by a load serving entity as of January 1, 2005 (prior to the commencement of the Midwest ISO organized electricity market). Commission Conclusion 78. As noted above, many of the specific interpretations of section 217(b)(4) of the FPA made by the Commission are discussed below with regard to the guidelines adopted in this Final Rule. However, in this section we address more general comments regarding our interpretation in the NOPR of the requirement of section 217(b)(4) and section 1233(b) of EPAct 2005. 79. First, the Commission believes it correctly interpreted section 217(b)(4) of the FPA as containing two separate directives: (1) To exercise its authority to facilitate planning and expansion of transmission facilities, and (2) to enable load serving entities with long-term power supply arrangements used to meet their service obligations to obtain firm transmission rights on a long-term basis. We conclude that this interpretation of the statute is the most reasonable. 46 Cinergy's interpretation of the relevant statutory language as requiring only that the Commission facilitate planning and expansion of transmission facilities in a manner that that allows load serving entities to secure long-term transmission rights is unreasonable in light of the actual statutory language used by Congress. When it drafted section 217(b)(4), Congress separated the first clause (requiring that the Commission exercise its FPA authority to facilitate the planning and expansion of transmission facilities) and the second clause (“and enables load serving entities to secure firm transmission rights * * * on a long-term basis”) with a comma, indicating two separate requirements. The comma is also followed with the word “and,” further suggesting that Congress intended them as two separate directives. No language in the statute suggests that the two clauses are part of a single directive to the Commission. 46 See e.g., Chevron, U.S.A., Inc. v. NRDC, Inc., 467 U.S. 837, 844-45 (1984) (noting that where Congress has expressly left a gap for an agency to fill, the agency's interpretation of the statute is giving weight unless it is “arbitrary, capricious, or manifestly contrary to the statute”); see also Acosta v. Gonzales, 439 F.3d 550, 552-53 (9th Cir. 2006) (noting that courts defer to agency regulations that are based on a permissible construction of the statute). 80. Moreover, a reading of section 217 in its entirety suggests that Congress intended for the Commission to both facilitate planning and expansion and enable that load serving entities can obtain long-term firm transmission rights. As a whole, section 217 is directed to protecting the ability of load serving entities with native load service obligations to obtain firm transmission service to satisfy those service obligations. 47 Directing transmission organizations with organized electricity markets to provide long-term firm transmission rights from both new and existing capacity is fully consistent with this statutory directive. Furthermore, if Congress only intended to direct the Commission to facilitate planning and expansion of transmission facilities in a manner that enables load serving entities to obtain long-term firm transmission rights, it would not have included the long-term firm transmission rights language in a second, separate clause. Finally, the directive in section 1233(b) of EPAct that the Commission implement this provision within one year in transmission organizations with organized electricity markets (where only annual rights to existing capacity are available) strongly suggests that Congress intended for the Commission to direct such transmission organizations to begin offering long-term rights from existing capacity. A reasonable interpretation is that Congress believed FTRs to capacity at the time of enactment were not sufficiently long, and therefore directed the Commission to make longer-term rights to existing capacity available. 47 Common principles of statutory interpretation support reading section 217 as a whole to ascertain its intent. See. e.g., United States v. Andrews, 441 F.3d 220, 223, (4th Cir. 2006) (noting that statutory phrases are not construed in isolation, and are instead read as a whole). 81. We disagree with comments suggesting that section 217(c) immunizes existing market designs and transmission rights allocation methods from the implementation of section 217(b)(4). The “savings clause” in section 217(c) specifically provides that “[n]othing in subsections (b)(1), (b)(2), and (b)(3)” of section 217 shall affect the existing or future methodologies of certain transmission organizations; that clause expressly omits subsection (b)(4) from its protections. As a result, section 217 permits the Commission to require changes to existing market designs and transmission rights allocation methods if necessary to implement section 217(b)(4). This does not mean that the Commission will require such changes or that section 217(b)(4) requires changes to existing designs and allocations in all cases; if a transmission organization can offer long-term firm transmission rights that satisfy each of the guidelines in this Final Rule while retaining its current systems, it may do so. We emphasize, however, that transmission organizations must provide long-term firm transmission rights that satisfy each of the guidelines in this Final Rule even if doing so requires changes to existing systems. 82. Additionally, we disagree with suggestions that transmission organizations already provide long-term firm transmission rights, and that creation of long-term financial transmission rights in this rulemaking is unnecessary. While transmission organizations may provide firm “physical” transmission rights on a long-term basis, the cost of transmission service in transmission organizations that use LMP to manage congestion is dependent on the cost of that congestion. We agree with APPA that for a transmission right to be “firm,” it must be firm as to both quantity and price. In the LMP context, this means “firm transmission rights” must be firm as to both the “physical” component of the right and the “financial” component of the right. FTRs can hedge congestion costs (when matched to the physical path of the transmission right) and make transmission rights in an LMP system “firm,” but are currently only available for one year. As a result, to comply with the directives of section 217(b)(4) and section 1233(b) of EPAct 2005, transmission organizations with LMP and FTRs will need to offer FTRs with longer terms to truly enable load serving entities to secure firm transmission rights on a long-term basis. Further, we disagree with Cinergy's contention that the “or equivalent tradable or financial rights” language in the statute suggests that transmission organizations can offer either long-term physical rights or long-term financial rights. Rather, we agree with APPA that this language was intended to address the FTRs used in transmission organizations with organized electricity markets and congestion management systems (primarily LMP) that impact the cost of transmission service. We read this language as requiring the Commission to exercise its FPA authority to enable all load serving entities to obtain firm transmission rights on a long-term basis, whether they are located in a region with more traditional “physical” transmission rights or a region that uses LMP and FTRs. 83. Finally, we disagree with NYISO's contention that section 217 does not require transmission organizations to offer transmission rights with longer terms than those they currently offer. While some transmission organizations could in theory have sufficiently long-term transmission rights and thus would not be required to offer longer terms, if the current transmission rights offered by all transmission organizations were sufficient, it is unclear why Congress would have included the second clause of section 217(b)(4) at all. Moreover, it is reasonable to conclude that Congress believed not all transmission organizations were offering sufficient long-term firm transmission rights given that it focused the Commission's attention in section 1233(b) of EPAct 2005 on those entities, and given the fact that long-term firm transmission rights are available today in regions without transmission organizations with organized electricity markets. We believe it is reasonable to conclude that Congress was aware that the current terms for transmission rights offered by transmission organizations were insufficient and drafted section 217(b)(4) of the FPA and section 1233(b) of EPAct 2005 together to require that they offer rights with longer terms. D. Commission's Approach, Regional Flexibility, and Regional Seams Issues 84. In the NOPR, the Commission proposed a flexible regional approach to satisfying the requirements of section 1233(b) of EPAct 2005. Specifically, we proposed to establish a set of guidelines for the design and administration of long-term firm transmission rights in organized electricity markets. Following the establishment of these guidelines in the Final Rule, we proposed to allow each transmission organization subject to the rule to develop specific long-term firm transmission right designs through its usual stakeholder process that would fit the prevailing regional market design. 85. We stated that this flexible approach was appropriate because there is no “one size fits all” long-term firm transmission right design that could be implemented in each of the various transmission organization markets. However, we stated further that flexible regional development must occur within guidelines, to ensure that the specific long-term firm transmission rights ultimately proposed by transmission organizations have certain properties that are fundamental to meeting the objectives of section 217(b)(4) of the FPA. Nonetheless, the NOPR stated our intent that the guidelines form only a framework for further, more specific development of long-term firm transmission right designs through the usual stakeholder process of each transmission organization, and noted that the guidelines should provide enough flexibility to allow transmission organizations and their stakeholders to develop a specific long-term firm transmission right design that fits the prevailing market design and meets the needs of market participants in that region. 86. Finally, we noted the potential that this flexible regional approach could lead to regional seams issues, and sought comments on any features of long-term firm transmission rights that, if not consistent across transmission organizations, could interfere with the effective operation of regional markets. Comments 87. Several commenters, including Industrial Consumers, Kentucky PSC, LADWP, LIPA, Midwest ISO, MSATs, NARUC, National Grid, NYDPS, NYISO, PJM, Public Power Council, SoCal Edison, and Wisconsin Electric all support the Commission's proposal to develop guidelines, as opposed to specific long-term firm transmission rights designs, to allow for regional flexibility. Many of these commenters argue that regional flexibility is essential, given that each transmission organization has developed its own market design to meet the needs of its stakeholders and to accommodate regional differences (including different operating practices). They contend that regional flexibility is also necessary to honor the transitions already agreed to by transmission organization stakeholders. 88. While the commenters were virtually unanimous that a “one-size fits all” approach to implementing long-term firm transmission rights would not be appropriate, the comments raise issues regarding the amount of flexibility that the Commission should provide. Some commenters, including Dominion, EEI, ISO-NE, and NSTAR argue for more flexibility, including flexibility within the requirements of each guideline. For example, EEI states that the Commission should issue only “basic principles” that focus on “reasonable outcomes,” and should treat the guidelines as “a general direction for future action” instead of imposing them as prescriptive requirements. 48 EEI also suggests that the Commission alter the general direction under section (d) of the proposed regulations to provide that “[t]ransmission organizations * * * should to the extent they find reasonable given their existing arrangements make available long-term transmission rights that satisfy the following guidelines.” 49 Further, EEI contends that no single guideline can or should be mandatory, and that transmission organizations and their stakeholders should be given the first opportunity to balance the guidelines to best meet market participant needs. ISO-NE argues that section 217(b)(4) permits substantial flexibility, since it does not require several design features (including creating a “perfect hedge” for load serving entities, a particular length of term, or a priority mechanism.) New York Transmission Owners argue that the Commission should clarify that the guidelines are not binding or mandatory obligations, and that they do not predetermine any particular result or design for long-term firm transmission rights. 48 Comments of EEI at 11. 49 Id . at 18. 89. Some commenters in New England and New York, including NU and Coral Power, note that there has not been great demand for long-term firm transmission rights in those regions. Accordingly, NU argues that the Commission should allow regional flexibility in determining the extent to which such rights are needed. 50 In reply, New England Public Systems assert that the clear statutory directive makes arguments regarding the lack of interest in long-term rights or the lack of need for such rights irrelevant. 51 50 NU notes in reply comments that a working group has been formed within NEPOOL to “address whether the development of [long-term transmission rights] in New England can be accomplished.” Reply Comments of NU at 1. 51 Reply Comments of New England Public Systems at 6-7. 90. NSTAR states more generally that imposing a Final Rule on long-term firm transmission rights that is inconsistent with the structure of a transmission organization market, particularly a well-developed market reflecting an extensive history of market operations, would be “disruptive and counter-productive.” 52 Accordingly, NSTAR advocates that the Final Rule allow the greatest latitude possible to stakeholders in established transmission organization markets to develop rules for long-term firm transmission rights. It argues that section 217(c) of the FPA (stating that subsections (b)(1), (b)(2) and (b)(3) do not affect existing or future transmission right allocation methodologies) recognizes the historical practices followed by transmission organizations and permits the Commission to defer to such practices, even if they are deemed to differ from practices embodied in subsections (b)(1) through (b)(3) of section 217. 53 52 Comments of NSTAR at 11. 53 New England Public Systems argues in response to NSTAR that section 217(c) does not provide any basis for the wide flexibility NSTAR advocates, since that section expressly omits reference to section 217(b)(4). 91. Reliant states that the Commission should recognize ongoing stakeholder-driven efforts in several existing transmission organizations to develop long-term firm transmission rights, and provide sufficient leeway for such markets to provide access to long-term rights. 92. BPA states that in general it supports the Commission's flexible approach, and states that the Commission should allow sufficient flexibility so as not to preclude formation of transmission organizations with regionally-developed characteristics, such as the developing proposals in the Northwest. 54 It argues that the Final Rule should address how the guidelines will apply to transmission organizations in the process of forming organized electricity markets. 54 See also Reply Comments of BP Energy at 10 (agreeing). 93. Midwest ISO states that the Commission should consider the detrimental effect some of the proposed guidelines could have on Midwest ISO market participants and should ensure that the terms it ultimately adopts allow sufficient flexibility to ensure that they can work in the Midwest ISO markets. 94. Others, including APPA, New England Public Systems and TAPS, argue that regional flexibility should not be offered too broadly. They assert that the Commission should make clear that the Final Rule gives regions the flexibility to decide how to implement long-term rights, but not the flexibility to decide whether to implement them at all. NRECA also supports some regional flexibility, but states that there must be adequate minimum guidelines to ensure that the objectives of section 217 of the FPA are met. APPA and TAPS both assert that the Commission explicitly require transmission organizations to fully comply with the provisions of the Final Rule, and also suggest that the Commission consider renaming the guidelines “requirements” or “standards” to ensure that there is no implication that the guidelines are only advisory and may be disregarded. Similarly, PG&E, while also supportive of the Commission's approach, recommends that the Commission further require transmission organizations “to fulfill the guidelines of the ultimate rule to the maximum extent compatible with the realities of their market and legal environment.” 55 55 Comments of PG&E at 5. 95. Some commenters, including Midwest TDUs and Industrial Consumers, express concern that the use of stakeholder procedures will not result in the development of long-term firm transmission rights that satisfy the intent of the Commission and Congress. Midwest TDUs express concern that “the stakeholder process will be used to eviscerate long-term rights” given the Midwest ISO's “evident resistance to long-term rights” and the opposition of some Midwest ISO stakeholders. 56 They state further that “[i]mplementation of these Congressionally-mandated rights in a manner that achieves their crucial purpose cannot depend on TDU's ability to overcome Midwest ISO's resistance or out-vote other stakeholders.” 57 Industrial Consumers state that they and other industrial and customer groups have had concerns that some transmission organization stakeholder processes do not have the proper balance to guard against one side of the market gaining an upper hand over the other. Accordingly, Industrial Consumers recommend that the Commission provide guidance to ensure that the stakeholder processes used to develop long-term firm transmission rights will include a balanced composition of stakeholders, and require each compliance filing to include a statement by the transmission organization that the stakeholder process was fair and impartial and did not discriminate against load and load serving entities. 56 Reply Comments of Midwest TDUs at 6-7. 57 Id . at 7. 96. With regard to the potential for the Commission's flexible approach to create regional seams issues, comments address both the potential for seams between transmission organizations and between transmission organization regions and non-transmission organization regions. Some commenters, including APPA and PG&E, note that different term lengths for long-term firm transmission rights and different processes for the allocation of long-term rights (including different timetables) are two areas where seams could arise. TAPS states that the Commission should require transmission organizations to provide a mechanism that allows load serving entities to obtain long-term transmission rights that cross seams and ensure that those rights continue if new or different seams emerge, and should require transmission organizations to coordinate their schedules for allocating long-term rights that cross seams. BPA also notes the possibility that a load serving obligation might be met with a resource outside the transmission organization, and states that in such situations “the transmission organization should continue to provide long-term transmission service for such deliveries under existing and renewed transmission contracts.” 58 58 Comments of BPA at 5. 97. TAPS and Wisconsin Electric express specific concerns regarding the potential for seams to develop between Midwest ISO and PJM. TAPS contends that the Commission should require close coordination between Midwest ISO and PJM with regard to the definition of long-term firm transmission rights and the process for obtaining such rights, arguing that a load serving entity should be able to obtain rights crossing the border on a consistent timeline (ideally through a single process) to support a commitment to baseload resources needed in both transmission organization regions. Wisconsin Electric argues that there must be consistency between the two regions with regard to the allocation of long-term firm transmission rights to ensure that a “financial wall” does not develop, which would inhibit the ability to flow energy under long-term contracts between the regions. 98. MidAmerican states that the Commission should require compliance filings to address resulting seams and how they will be resolved. MidAmerican, as well as NARUC, also note that these issues can and should be addressed in the Joint Operating Agreements and Seams Operating Agreements between transmission organizations. NARUC urges the Commission to clarify that tariff provisions designed to award long-term transmission rights will not adversely impact these seams agreements, and clarify that long-term rights granted within a transmission organization will not confer rights on the holder outside that market. According to NARUC, these clarifications are necessary to ensure that costs for upgrades or expansions are not transferred between transmission organizations or a transmission organization and non-transmission organization utility and to ensure that transmission rights in other regions are not adversely impacted. 99. Comments also generally addressed seams that might arise between transmission organizations and non-transmission organization regions. APPA, for example, notes that non-transmission organization regions use physical rights, and as a result financial and physical rights must coexist to ensure that future power supply and transmission service arrangements are not adversely impacted. CMUA states that because CAISO operates a market based on financial rights, while the rest of the Western Interconnection consists of bilateral markets with physical rights, any regional stakeholder process to develop long-term firm transmission rights in CAISO should include the Western Electricity Coordinating Council (WECC), neighboring control areas and relevant transmission owners in the West. 59 59 In response, CAISO notes that it has not and will not discourage such parties from participating. Commission Conclusion 100. In this Final Rule, the Commission adopts the guidelines approach and the allowance for regional flexibility set forth in the NOPR. This approach will appropriately recognize regional differences in market design, while ensuring that long-term firm transmission rights have certain properties that are fundamental to satisfying the mandate of Congress in section 217(b)(4). 101. In response to comments seeking additional flexibility, we emphasize that we are adopting the guidelines approach to ensure that transmission organizations have the flexibility to design long-term firm transmission rights that fit their prevailing market design. This flexibility is not intended and should not be interpreted to allow transmission organizations the latitude to decide whether long-term firm transmission rights should be implemented at all. Congress has directed in both section 217(b)(4) of the FPA and section 1233(b) of EPAct 2005 that load serving entities have the ability to obtain long-term firm transmission rights to meet their reasonable needs to satisfy their service obligations. Congress also specifically directed that such rights be implemented in the transmission organizations with organized electricity markets, through section 1233(b)'s charge that the Commission implement section 217(b)(4) within one year in those regions. As a result, the implementation of long-term firm transmission rights by transmission organizations with organized electricity markets is mandatory. 102. We reject comments suggesting that the guidelines be treated as merely general directives. As noted above, the guidelines are intended to ensure that long-term firm transmission rights have certain properties we believe are necessary to fulfill Congress' directives. Particularly, the guidelines are designed to ensure that the long-term firm transmission rights are truly “long-term” and “firm,” and that they can be used to deliver the output of long-term power supply arrangements to load serving entities, as section 217(b)(4) requires. As a result, transmission organizations must satisfy each of the guidelines when complying with the Final Rule. We have modified the proposed regulatory text to clarify this requirement. 103. With regard to flexibility within each guideline, the Commission believes that each of the guidelines already provides sufficient flexibility to allow transmission organizations to satisfy them in a manner that fits their individual market design. Each of the guidelines state basic, fundamental properties that long-term firm transmission rights must possess, but are not prescriptive market design mandates. Thus, while proposals to comply with this Final Rule must satisfy each of the guidelines, we believe each of the guidelines may be satisfied in any number of ways, and we do not intend that the guidelines predetermine any particular design. 104. In response to comments suggesting that there has been little demand for long-term firm transmission rights in New York and New England, we note that we agree with New England Public Systems that regardless of the level of interest in such rights, Congress has mandated that they be available to meet load serving entities reasonable needs. Thus, while we are adopting a flexible approach, that flexibility does not extend to deciding whether such rights are needed, as NU suggests it should. The fact that only a few stakeholders in a particular region seek long-term firm transmission rights can be a design consideration, however, as we discuss in more detail elsewhere in this Final Rule. 105. BPA asks that the Commission address how the guidelines will apply to transmission organizations with organized electricity markets that are being developed, and asks that we retain sufficient flexibility so that regional efforts to develop a transmission organization in the Northwest are not precluded. As we state above, we conclude that the guidelines approach in the Final Rule provides enough flexibility to ensure that long-term rights can be developed with regional characteristics while still meeting the statutory objectives of section 217(b)(4). Entities in the process of forming transmission organizations should take into account the requirements of this Final Rule and how the market designs they file will satisfy the rule. 106. In response to the comments of Industrial Consumers and Midwest TDUs regarding the use of stakeholder procedures to develop specific long-term firm transmission rights proposals, we do not believe it is necessary to specifically direct that any particular stakeholder procedures be used. Transmission organizations have Commission-approved procedures in place that specify the stakeholder process and conditions and criteria by which they may file proposals with the Commission. Comments suggesting that such procedures are flawed are outside the scope of this proceeding. 107. Regarding the potential for regional seams, the comments indicate that seams are most likely to develop where the terms of long-term rights and the procedures (including timelines) for allocating such rights are not sufficiently coordinated. We agree with commenters that transmission organizations should consider these issues when complying with the Final Rule. Additionally, we agree that revising the already existing seams agreements between transmission organizations, if necessary, could be one vehicle to address seams issues related to long-term rights that arise between transmission organizations. Accordingly, we direct each transmission organization to explain in its compliance filing how its proposal addresses potential seams issues, particularly with regard to the term of the long-term rights offered and the procedures and timelines for obtaining such rights. With regard to potential seams between transmission organizations, each transmission organization should also explain why it has or has not elected to revise its seams agreements. E. Guidelines for the Design and Administration of Long-Term Firm Transmission Rights in Organized Electricity Markets Guideline (1)—Specify Source, Sink and Quantity 108. As proposed in the NOPR, guideline (1) stated that the long-term firm transmission right should be a point-to-point right that specifies a source (injection node or nodes) and sink (withdrawal node or nodes), and a quantity (MW). The discussion of this guideline pointed out that flowgate rights were not precluded from consideration as long as they could hedge a point-to-point transmission schedule. Comments 109. Guideline (1) is generally supported by commenters. Most commenters recognize that current transmission organization market designs for specifying and allocating transmission rights largely adopt the source point and sink point requirements of guideline (1). But there are exceptions. In particular, some commenters note that ISO-NE does not allocate auction revenue rights on a point-to-point basis. Flexibility in Source and Sink Designation 110. Several commenters request that guideline (1) explicitly recognize nodal aggregations, such as zones or hubs, as sources and sinks. 60 ISO-NE notes that spot market purchases by load are priced on a zonal basis in its system and that allocation of zone-to-zone long-term transmission rights would be more desirable than allocation of point-to-point rights. PJM Public Power Coalition, Public Power Council and Strategic Energy request that guideline (1) should not be interpreted to require that long-term rights are tied to specific generation resources, but rather to points or aggregates on the transmission system. Several commenters note that the boundary nodes can serve as sources or sinks. 60 See , e.g. , AEP, Coral Power, IPL, ISO-NE, NEPOOL, Reliant and TAPS. 111. Other source/sink designation issues pertaining to guideline (1) were raised by commenters that are, or will be, transmission customers but that are located outside the transmission organization markets. SMUD stresses that in California, long-term rights must be developed for transmission customers that use through and out service. SMUD argues that the Commission should require that allocation criteria for long-term rights will not be dependent upon where load is located, but rather on whether, by its use of the system, the customer will make substantial contribution to recovery of the transmission system's fixed costs. Consistency of Current Market Rules With Guideline 1 112. Some commenters state that the current rules for allocating ARRs and auctioning FTRs in ISO-NE are not consistent with guideline (1) in combination with guideline (7). New England Public Systems notes that under the ISO-NE market rules, most ARRs are allocated among congestion-paying load serving entities on a zonal load ratio share basis. Each such load serving entity is paid the auction clearing price of an average FTR in the zone times the ratio of its peak load to the zonal peak load. This rule does not offer assurance that the revenues received will be sufficient to enable the load serving entity to acquire a specific point-to-point FTR across a particular congested path. New England Public Systems thus requests that the Commission confirm that in New England, FTRs awarded under the current rules cannot simply be extended in term. Instead, under guidelines (1) and (7), ISO-NE should provide either the allocation of point-to-point long-term transmission rights or point-to-point long-term ARRs that can be converted to long-term transmission rights. Other Issues 113. CMUA, NRECA and SMUD argue that guideline (1) should be modified and clarified so that it does not rule out long-term rights with properties of Order No. 888 network service rights for network transmission customers. In particular, these commenters argue that long-term firm transmission rights should afford the customer the flexibility to change receipt and delivery points without penalty. In contrast, Cinergy argues that long-term rights should not be allowed to have characteristics of Order No. 888 network rights. 114. CMUA and SMUD request that guideline (1) not limit the ability of transmission organizations to consider other types of rights that meet the commercial needs of load serving entities. In particular, they discuss contractual rights that are “bidirectional” in nature to support seasonal power supply arrangements in the West and for which they propose option transmission rights in each direction of the transaction. 115. There were several miscellaneous comments on guideline (1). PJM states that the Final Rule would benefit from clarification that there are no requirements with respect to the nature of the right—i.e., physical versus financial—and explicitly state that this issue will be determined by the regions. We address this issue in Section II.F, “Alternative Designs for Long-Term Firm Transmission Rights.” APPA requests that as part of compliance with guideline (1), each transmission organization should be required to establish rules that prevent gaming of the long-term rights allocation by swapping of generation resources. This issue was raised by several other parties in conjunction with guideline (5) and we address it there. Commission Conclusion 116. We will adopt guideline (1) without modification. The primary objective of guideline (1), consistent with section 217(b)(4), is to allow a load serving entity to obtain a long-term firm transmission right for purposes of hedging congestion charges associated with delivery of power from a long-term power supply arrangement to its load. Moreover, as several commenters noted, guideline (1) is largely consistent with existing designs for FTRs in the organized electricity markets operated by transmission organizations. Flexibility in Source and Sink Designation 117. We clarify that guideline (1) permits specification of long-term firm transmission rights to hedge zonal or hub pricing where, for example, congestion prices are calculated using a weighted average of the locational marginal prices within a zone. Guideline (1) also permits specification of long-term transmission rights from points on the network, such as boundary locations, that are not the locations of specific generators. For customers with through and out service, we would expect that transmission organizations will establish long-term firm transmission rights corresponding to the terms and conditions of existing transmission contracts. However, if quantity limits are established for the allocation of long-term firm transmission rights, then rules may be needed to determine the eligibility of through and out service, based, for example, on historical usage patterns. Consistency of Current Market Rules with Guideline (1) 118. Based on the comments, only ISO-NE has adopted a financial rights model for transmission rights that does not directly allocate rights that are point-to-point to eligible market participants. We will require ISO-NE to adopt rules for allocation of long-term firm transmission rights that are consistent with guidelines (1) and (7). However, as discussed below, we note that ISO-NE does not have to provide the same allocation rules for short-term rights as it does for long-term rights. 119. We understand that in some organized electricity markets, particularly in regions with substantial divestiture of generation capacity and retail choice such as that of ISO-NE, hedging particular generation resources with financial transmission rights is not the prevailing approach; rather, buyers and sellers have adopted portfolio approaches to power supply contracts and hold financial transmission rights based on their expected revenues from congested transmission paths rather than on their ability to hedge specific resources. We do not intend for this Final Rule to obstruct that business model, but note that other entities in these regions are not following such a business model. As a result, they seek transmission rights that hedge congestion charges associated with delivering power from particular generators to their load. Guideline (1) is intended to support the ability of load serving entities to obtain point-to-point long-term transmission rights that will hedge particular long-term power supply arrangements. Guideline (7) is intended to support the ability of load serving entities to obtain such rights without having to purchase the rights in an auction. We will thus require all transmission organizations to offer long-term firm transmission rights that are consistent with these guidelines. This is not to say that transmission organizations like ISO-NE must adopt new allocation rules and apply them for both short-term rights and long-term rights. To the extent that a transmission organization can satisfy requests for long-term firm transmission rights under these guidelines, but stakeholders prefer remaining with existing rules for short-term rights, we will consider proposals that use such a “two-track” approach. At the same time, as we discuss in guideline (2), there might be advantages to harmonizing at least some rules between short-term and long-term rights to ensure that the rules encourage efficient nominations and equitable allocations. Other Issues 120. We will not modify guideline (1) to require allocation of long-term transmission rights with properties of Order No. 888 network service, as requested by NRECA and SMUD. In general, we have not precluded any design that stakeholders could agree on, but we do require that designs support equitable allocation of transmission rights (see discussion in Section II.F, “Alternative Designs for Long-Term Firm Transmission Rights”). The right to change receipt and delivery points without penalty could, under most rules for allocation of financial transmission rights, deprive other load serving entities of their eligible rights. 61 Hence, the rules in organized electricity markets generally require parties that are converting Order 888 network rights to financial rights to select a fixed distribution of source points for their total MW eligibility over their network resources. 61 For example, consider a load serving entity that is eligible for 100 MW of FTRs and that requests that the entire quantity is sourced at each of four network resources that it has historically used, each of which is capable of providing the full amount, thus encumbering up to 400 MW of transmission capacity. 121. We will not modify guideline (1) to explicitly support “bidirectional” transmission rights. CMUA defines such rights as “option” rights in either direction. We discuss the difficulties in allocating option rights equitably in Section II.F, “Alternative Designs for Long-Term Firm Transmission Rights.” There are other solutions. Sufficient granularity of the transmission rights specified as obligation rights would allow the rights to better track the power flows in contractual arrangements. Guideline (1) also does not preclude flowgate rights, which have option properties. All of these approaches, and possibly others, could be used to address situations where power flows change direction on a regular basis. Guideline (2)—Long-Term Hedge That Cannot Be Modified 122. As proposed in the NOPR, guideline (2) stated that the long-term firm transmission right must provide a hedge against locational marginal pricing congestion charges (or other direct assignment of congestion costs) for the period covered and quantity specified. Once allocated, the financial coverage provided by the right should not be modified during its term except in the case of extraordinary circumstances or through voluntary agreement of both the holder of the right and the transmission organization. We refer to the provision that the payments from the rights should not be prorationed (with the exceptions as mentioned) as “full funding.” 123. The NOPR sought comments on how to fully fund the long- [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A06-6494. Public record. Not legal advice.