thefederalregister.com

Daily Rules, Proposed Rules, and Notices of the Federal Government

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket Nos. RM06-8-000 and AD05-7-000]

Long-Term Firm Transmission Rights in Organized Electricity Markets; Long-Term Transmission Rights in Markets Operated by Regional Transmission Organizations and Independent System Operators

AGENCY: Federal Energy Regulatory Commission.
ACTION: Notice of Proposed Rulemaking.
SUMMARY: The Federal Energy Regulatory Commission is proposing to amend its regulations to require transmission organizations that are public utilities with organized electricity markets to make available long-term firm transmission rights that satisfy certain guidelines established in this proceeding. The Commission is taking this action pursuant to section 1233(b) of the Energy Policy Act of 2005, Public Law No. 109-58, section 1233(b), 119 Stat. 594, 960 (2005).
DATES: Comments are due March 13, 2006. Reply comments are due March 27, 2006.
February 2, 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 Market Oversight and Investigations,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: I. Introduction

1. On August 8, 2005, the Energy Policy Act of 2005 (EPAct 2005)1 became law. Pursuant to the requirement in section 1233 of EPAct 2005,2 which added a new section 217 to the Federal Power Act (FPA), the Commission is proposing 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-termfirm transmission rights that satisfy guidelines established by the Commission in this rulemaking. The Commission proposes to require each such transmission organization to file, no later than [INSERT DATE 180 DAYS AFTER PUBLICATION OF FINAL RULE IN THEFederal Register], either: (1) Tariff sheets and rate schedules that make available long-term firm transmission rights that are consistent with the guidelines set forth in the Final Rule; or (2) an explanation of how its current tariff and rate schedules already provide long-term firm transmission rights that are consistent with the guidelines set forth in the Final Rule. Transmission organizations that are approved by the Commission after [INSERT DATE 180 DAYS AFTER PUBLICATION OF FINAL RULE IN THEFederal Register], must meet the requirements of the proposed rule before commencing operation.

1Pub. L. 109-58, 119 Stat. 594 (2005).

2Pub. L. 109-58, § 1233(b), 119 Stat. 594, 960.

2. New section 217(b)(4) of the FPA provides:

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.3

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.4

3Pub. L. 109-58, section 1233, 119 Stat. 594, 958.

4 Id.at 960.

3. In this Notice of Proposed Rulemaking (NOPR), we propose guidelines for the design and administration of long-term firm transmission rights that transmission organizations with organized electricity markets5 would make available to all transmission customers. 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 needs of load-serving entities to hedge long-term power supply arrangements made or planned to satisfy a service obligation. While we propose that long-term firm transmission rights be made available to all transmission customers, in the event that a transmission organization cannot accommodate all requests for long-term firm transmission rights over existing transmission capacity, we propose to require that a preference be given to load-serving entities with long-term power supply arrangements used to meet service obligations. The other properties we believe long-term firm transmission rights must have are discussed in the proposed guidelines below. These guidelines will give transmission organizations, in consultation with market participants, the flexibility to propose alternative designs that reflect regional preferences and accommodate the regional market design, while also ensuring that the objectives of Congress expressed in new section 217(b)(4) of the FPA are met.

5 See“Definitions” below.

4. In proposing this 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. We understand that specifying and allocating long-term firm transmission rights supported by existing transfer capability will raise difficult issues that must be addressed in this rulemaking and in its implementation over time. We note, however, that long-term rights are available to market participants in a direct manner, namely by supporting an expansion or upgrade of grid transfer capability. As described in more detail below, 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. Such a long-term transmission right must be for a term equal to the life of the new facilities, or for a lesser term if requested by the funding entity. The transmission organization tariffs must clearly and specifically provide for this arrangement, if they do not already.

II. Definitions

5. The Commission proposes several definitions in this NOPR. We set forth those proposed definitions in this section, since these defined terms are used extensively in the background discussion and proposed guidelines that follow. The Commission seeks comment on whether these definitions are appropriate.

A. Transmission Organization

6. The Commission proposes a definition for “transmission organization” that is similar to the definition provided in EPAct 2005.6 Specifically, we propose to include the word “independent” in the last clause of the EPAct 2005 definition, such that transmission organization would mean “a Regional Transmission Organization, Independent System Operator, independent transmission provider, or otherindependenttransmission organization finally approved by the Commission for the operation of transmission facilities.”7 We make this clarification to the definition in EPAct 2005 because we interpret section 1233(b) of the legislation to require that long-term firm transmission rights be made available in the currently existing independent entities approved to operate transmission facilities that have organized electricity markets (as defined below), and any such independent entities that are created in the future.8 We seek comments on whether this definition appropriately captures the intent of section 1233(b) of EPAct 2005.

6Pub. L. No. 109-58, section 1233, 119 Stat. 594, 985.

7 See id.at 942, 985.

8The transmission organizations that currently have an organized electricity market are ISO New England, Inc. (ISO-NE), New York Independent System Operator, Inc. (New York ISO), PJM Interconnection, Inc. (PJM), California Independent System Operator, Inc. (CAISO), and Midwest Independent Transmission System Operator, Inc. (Midwest ISO). Southwest Power Pool is currently developing its market.

B. Load-Serving Entity and Service Obligation

7. The Commission proposes to define the terms “load-serving entity” and “service obligation,” for purposes of the proposed rule, exactly as they are defined in section 217 of the FPA. Specifically, we propose to define load-serving entity to mean “a distribution utility or electric utility that has a service obligation.”9 We propose to define service obligation to mean “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.”10 We seek comment on whether it is necessary toexpand or clarify these definitions in the Final Rule.

9 See id.at 957. In section 1291 of EPAct 2005, “electric utility” is defined as “a person or Federal or State agency (including an entity described in section 201(f) [of the FPA]) that sells electric energy.”Id.at 984.

10 See id.at 958.

C. Organized Electricity Market

8. EPAct 2005 and section 217 of the FPA do not define “organized electricity market.” The Commission proposes 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.” We intend for the Final Rule we develop in this proceeding to apply to any transmission organization with a day-ahead and/or real-time (or “spot”) bid-based energy market that is the transmission provider in its region.11 These markets could either be administered by the transmission organization itself or by another entity. The definition we propose here is intended to ensure that the Final Rule covers all such transmission organizations, either existing or developed in the future. We seek comment on whether the scope of this definition is appropriate or whether it should be revised.

11As noted above, the transmission organizations that currently have an organized electricity market are ISO-NE, New York ISO, PJM, CAISO, and Midwest ISO. Southwest Power Pool is currently developing its market.

D. Long-Term Power Supply Arrangement

9. Section 217(b)(4) of the FPA requires the Commission to exercise its authority to enable load-serving entities to obtain firm transmission rights on a long-term basis “forlong-term power supply arrangementsmade * * * or planned” to meet service obligations.12 While “long-term power supply arrangements” is not defined in the legislation, section 217(b)(1)(A) of the FPA suggests that a load-serving entity has a long-term power supply arrangement if it “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.” For purposes of this proposed rule, we propose to use similar language to define “long-term power supply arrangements.” Specifically, we propose to define “long-term power supply arrangements” to mean “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.”13

12Pub. L. No. 109-58, section 1233, 119 Stat. 594, 958 (emphasis added).

13While we consider long-term as “more than one year” in the context of defining a long-term power supply arrangement, later in this NOPR we note that we consider “long-term” in the context of the appropriate terms for long-term firm transmission rights to be terms and/or renewal rights that cover the multiple years necessary to support a long-term power supply arrangement.See infraat P 55.

III. Background A. The Development of ISOs and RTOs

10. In Order No. 888, the Commission found that undue discrimination and anticompetitive practices existed in the provision of electric transmission service in interstate commerce, and determined that non-discriminatory open access transmission service was one of the most critical components of a successful transition to competitive wholesale electricity markets.14 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.15

14 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 Groupv.FERC,225 F.3d 667 (D.C. Cir. 2000),aff'd sub nom. New Yorkv.FERC,535 U.S. 1 (2002).

15Under 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.

11. 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.16 To guide the voluntary development of ISOs, Order No. 888 set forth 11 principles for assessing ISO proposals submitted to the Commission.17 Following Order No. 888, several voluntary ISOs were established and approved by the Commission.

16Order No. 888 at 31,655; Order No. 888-A at 30,184.

17Order No. 888 at 31,730.

12. In light of the creation of these ISOs and other changes in the electric industry, the Commission issued Order No. 2000.18 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 that is necessary for continued development of competitive electricity markets.19 The Commission also found that even after functional unbundling of electric utilities under Order No. 888, opportunities for undue discrimination continued to exist.20 As a result, the Commission adopted rules intended 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.21

18 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, Washingtonv.FERC,272 F.3d 607 (D.C. Cir. 2001).

19Order No. 2000 at 30,992-93 and 31,014-15.

20 Id.at 31,015-17.

21 Id.at 31,024.

13. In Order No. 2000, the Commission established the minimum characteristics and functions that an RTO must satisfy to gain Commission approval. Minimum characteristics of an RTO include independence from market participants and operational authority over transmission facilities under its control.22 Minimum functions of an RTO include ensuring the development and operation of market mechanisms to manage transmission congestion, development and implementation of procedures to address parallel path flow issues, and market monitoring.23 Under Order No. 2000, the Commission has approved the voluntary formation of a number of RTOs.

22 Id.at 31,046et seq.

23 Id.at 31,106et seq.

14. 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. As described in more detail below, most of these markets utilize a congestion management system based onLocational 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.24 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) (described in more detail below) 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. The use of FTRs and their terms is also discussed in more detail below.25

24 See infraat P 21-22.

25 See infraat P 23-28.

B. Currently Available Transmission Rights

15. In recent years, interest in long-term 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. This section describes the transmission rights that are available in regions with and without organized electricity markets, and concludes with a comparison of the two types of rights.

1. Transmission Rights in Regions Without Organized Electricity Markets

16. In general, in regions without organized electricity markets, transmission service is provided to customers under the terms of the Order No. 888 OATT, or under terms of contracts that predate the OATT. The OATT offers two types of transmission service: Network integration transmission service (network service), which is a long-term firm transmission service, and point-to-point transmission service, which is available on a firm or non-firm basis and on a long-term (one year or longer) or short-term basis. Long-term firm transmission customers taking service under the OATT have the right to continue to take transmission service from the transmission provider when their contract expires (rollover right). Transmission providers are required to expand facilities to satisfy network and point-to-point customer needs.26

26 SeeOrder No. 888pro formaOATT at sections 13.5, 15.4 and 28.2.

17. Firm point-to-point transmission service provides for the transmission of energy between designated points of receipt and designated points of delivery. A customer taking firm point-to-point transmission service generally pays a monthly demand charge based on its reserved capacity, and it may resell the service to another customer.27

27Under the Commission's transmission pricing policy, the demand charge may reflect the higher of the transmission provider's embedded costs or incremental expansion costs. Also, if the transmission system is constrained, the demand charge may reflect the higher of embedded costs or “opportunity” costs, with the latter capped at incremental expansion costs.See Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided by Public Utilities Under the Federal Power Act, Policy Statement, 69 FERC ¶ 61,086 (1994). In practice, the demand charge is almost always determined on basis of the transmission provider's embedded costs.

18. Network service provides the customer with flexibility to utilize its current and planned generation resources to serve its network load in a manner comparable to that in which the transmission provider utilizes its generation resources to serve its native load customers. A network customer must designate network resources, including all generation owned, purchased or leased by the network customer to serve its designated load. A network customer also must designate the individual network loads on whose behalf the transmission provider will provide network service. The network customer pays a monthly charge for basic service based on its load ratio share of the transmission provider's transmission revenue requirement.

19. As a condition of receiving network service, a network customer agrees to redispatch its network resources as requested by the transmission provider.28 The transmission provider must plan, construct, operate and maintain its transmission system in order to provide the network customer with network service over the transmission provider's system, and must designate its own resources and loads in the same manner as a network customer. If the transmission provider needs to redispatch the system due to congestion to accommodate a network customer's schedule, the costs of redispatch are passed through to the transmission provider's network customers, including its own native load, on a load-ratio basis. If a curtailment on the transmission provider's system is required to maintain reliable operation of the system, curtailments are made on a non-discriminatory basis to the extent practicable and consistent with good utility practice, with firm service having the highest priority and non-firm generally having the lowest priority.

28Redispatch means that, due to congestion, the utility changes the output of generators to maintain the energy balance. The output of some generators may be increased while the output of others may decrease.

20. The price that a transmission customer pays for OATT transmission service is usually predictable and relatively stable over the long-term. For example, a load-serving entity that has a generating facility at one location that it wishes to use to serve load at a second location can contract for long-term point-to-point transmission service from the generator to the load. For this service, the load-serving entity pays only a demand charge that is known in advance. Although the load-serving entity must pay the demand charge whether or not it uses its full reservation, it does not have to pay additional costs associated with transmission congestion for point-to-point transmission service even when the transmission provider must redispatch its generators to honor the firm service commitment. If the load-serving entity has generators and loads at multiple locations, it can request network service and dispatch of its generators to serve its loads in a least cost manner. The load-serving entity must pay a load ratio share of the transmission provider's Commission-approved transmission revenue requirement but, again, is not directly assigned any congestion costs. If either the transmission provider's or the load-serving entity's generators have to be redispatched to relieve congestion, then the cost of redispatch is shared by the transmission provider and all network customers on a load ratio basis. Thus, whether it takes firm point-to-point transmission service or network service, the load-serving entity faces transmission costs that are relatively stable and predictable over the term of its service agreement.

2. Transmission Rights in Organized Electricity Markets

21. Each of the transmission organizations that exist today has implemented or is planning to implement an organized electricity market that uses locational pricing for electric energy. In most cases, the locational pricing system that is used is LMP. Under LMP, the price at each location in the grid at any given time reflects the cost of making available an additional unit of energy for purchase at that location and time. In the absence of transmission congestion, all locational prices at a given time are the same.29 However, when congestion is present, locational prices typically will not be the same, and the difference between any two locational prices represents the cost of congestion between those locations.

29The inclusion of marginal losses can cause locational prices to differ across locations even in the absence of congestion. For purposes of this discussion, we will consider only the congestion component of locational price differences.

22. Because locational spot prices can vary significantly over time, a market participant potentially faces some degree of price uncertainty. Consider a load-serving entity that has a generator at one location and load at another. If there is no congestion, the generator and the load will see the same locational prices just as if they were at the same location. However, when congestion arises, locational prices will differ, and the price that the load-serving entity's generator receives typically will not be the same as the price that its load must pay.30 This difference in prices is the congestion cost, and the load-serving entity must pay this cost to the transmission organization whenever power is injected and withdrawn at different locations in the transmission system under constrained conditions.

30It is important to note that, depending on the relative magnitude of the prices at the generator's location and the load's location, congestion costs can be positive or negative.

23. To reduce the uncertainty due to congestion, transmission organizations that use locational marginal pricing make FTRs available to their market participants.31 An FTR is a right to receive the congestion costs paid by grid users and collected by the transmission organization for one megawatt of electricity delivered from a specified point of receipt to a specified point of delivery. The holder of an FTR receives in each hour a payment that is calculated by subtracting the price at the point of receipt from the price at the point of delivery, and multiplying the difference by the megawatt quantity.

31We use the term FTR in this NOPR to refer generally to the financial transmission instruments used in the various organized electricity markets that currently exist. In some markets, these financial instruments are called transmission congestion contracts or congestion revenue rights.

24. In an LMP system, all spot power is purchased and sold at locational prices and all scheduled injections and withdrawals are subject to congestion charges. When there is no congestion, the prices are the same and the payments to FTR holders are zero. However, when congestion is present, prices will differ; prices for withdrawals are generally higher than prices for injections, creating a source of funds to pay the FTR holders. To ensure that the excess revenue is sufficient to meet its FTR payment obligations under normal operating conditions, the transmission organization generally subjects any award of FTRs to a simultaneous feasibility test. The simultaneous feasibility test requires that, before specific FTRs can be awarded, the transmission organization must demonstrate that the transmission system is capable of physically delivering the power flows represented by the FTRs simultaneously with the power flows represented by all concurrently or previously awarded FTRs. Although FTRs do not convey a physical right (or obligation) to use the transmission system, the transmission organization will be at risk of not receiving sufficient revenues to meet all of its FTR payment obligations under normal operating conditions if any awarded FTRs do not meet the simultaneous feasibility test. Any time that revenues are not sufficient, the transmission organization is said to be “revenue inadequate.”32

32It should be noted that, even when all awarded FTRs meet the simultaneous feasibility test, the Transmission Organization may at times be revenue inadequate as a result of unexpected events, such as a line outage or transmission system disruption that reduces transfer capability.

25. The most common type of FTR, which is known as an FTR “obligation,” provides for a payment to the holder when congestion cost is positive, but also requires the holder to make a payment to the transmission organization whenever the cost is negative. Because of this feature, some transmission organizations also offer FTR “options,” which do not place a payment obligation on the rights holder. However, because FTR options require more transmission capacity than FTR obligations to meet the simultaneous feasibility test, their availability is limited.33 Therefore, for purposes of the discussion in this section, we will assume that FTRs are limited to FTR obligations.34

33The need for more capacity is due to the fact that the Transmission Organization cannot assume that the FTR options will provide any “counterflows” when it conducts the simultaneous feasibility test.

34 See infraat P 72-79 for a more complete discussion of the properties of FTR obligations and FTR options.

26. If a load-serving entity holds an FTR that matches its injections and withdrawals exactly, it pays no net congestion cost.35 A load-serving entity may also reduce its congestion cost risk by holding an FTR that provides a partial hedge. Typically, the FTRs that load-serving entities hold do not exactly match their use of the transmission system in each hour, but the “over” and “under” financial coverage provided by the FTRs evens out over time to provide a sufficient hedge.

35This net result is reached because congestion charges billed to the load-serving entity (or any other party that holds FTRs) are exactly offset by FTR payments.

27. In general, transmission organizations provide FTRs on an annual basis to load-serving entities and others that pay access charges or fixed transmission rates. Load-serving entities receive FTRs either through direct allocation or through a two-step process in which the load-serving entity first is allocated auction revenue rights (ARRs) and then purchases FTRs in an auction.36 The revenues from the auction flow back to the load-serving entity and other ARR holders and thus defray the cost of purchasing the FTRs in the auction. Transmission organizations currently offer ARRs and FTRs with terms of one year or less. Although details vary by transmission organization, the allocation is based largely on historical uses of the system as measured by peak loads, but also allows market participants some flexibility to choose among transmission paths. Most transmission organizations also allocate long-term ARRs and FTRs to any party that invests in transmission upgrades that increase transmission capability. FTRs can be traded in annual and monthly transmission organization auctions or bilaterally outside the auction.

36ARRs confer the right to collect revenues from the subsequent FTR auction. For example, the holder of an ARR between location A and location B knows that it will collect revenues equal to the market clearing price of an FTR between location A and location B. An ARR can, but does not need to, exactly match an FTR. In some Organized Electricity Markets, a market participant must submit a bid for FTRs in the auction to convert its ARRs to FTRs, while in other Organized Electricity Markets a market participant can convert its ARRs to FTRs directly and is not required to bid in the auction.

28. Since the state of the transmission system and market prices change from year to year, the annual allocation allows market participants to re-configure their transmission rights requests each year to reflect such changes. The annual reconfiguration also helps the transmission organization to manage exposure to situations where payments to FTR holders can exceed congestion revenues. Revenue shortfalls can occur due to changes in the transmission grid or in the availability of generators that have a major impact on power flows. If such changes are expected to be long-lasting, the transmission organization is able to adjust the quantity and configuration of rights made available in the next annual cycle. However, a load-serving entity may receive fewer FTRs or ARRs than it requests due to factors outside of its control, such as changes in the network, the network flow assumptions or the FTR nominations of other participants. As a result, load-serving entities are uncertain from year to year whether they will obtain the FTRs needed to support long-term power supply arrangements, including investment in generation resources.

3. Comparison of Transmission Rights in Regions With and Without Organized Electricity Markets

29. There are several important differences between transmission service under the OATT and transmission rights in organized electricity markets that use LMP and FTRs. However, the differences that are most relevant for purposes of this NOPR concern the management of congestion, the recovery of congestion costs and the availability of long-term service arrangements.

30. Under the OATT, the transmission provider 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. However, in organized electricity markets, the transmission organization manages congestion through the use of locational prices. 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 (TLR) procedures and service curtailments than a transmission provider under the OATT.

31. 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 lowers the transmission customer's price uncertainty. 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 a long-term, which in turn can help facilitate the planning and financing of large generation facilities and other long-term power supply arrangements.

32. In contrast, a transmission organization in a region with an organized electricity market recovers congestion costs through the locational pricing 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. For example, as explained above, a load-serving entity that has generation at one location and load at another, but does not hold FTRs, is at risk of incurring congestion costs, which may not be predictable. Also, although that load-serving entity can avoid congestion costs by holding FTRs, it still faces a congestion price risk if its spot sales and purchases or scheduled injections and withdrawals do not correspond exactly to its allocated (or purchased) FTRs. Clearly, 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 because, in any given year, its award of FTRs may not 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.

33. The Commission believes that some of the problems of uncertainty in organized electricity markets can be overcome and the objectives of section 217(b)(4) of the FPA can be met through the introduction of long-term firm transmission rights. However, for a variety of reasons that are discussed below, transmission rights in organized electricity markets cannot always be designed in a way that captures all of the features of the transmission rights that have long been available under the OATT. Consequently, the Commission's objective in issuing this NOPR is to present 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.

C. Staff Paper on Long-Term Transmission Rights

34. Prior to the enactment of EPAct 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.37 This section provides an overview of the comments to the notice.

37Notice 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). While we are issuing this NOPR in both Docket No. RM06-8-000 and Docket No. AD05-7-000, we expect to issue our Final Rule in only Docket No. RM06-8-000. Comments in response to this NOPR should be filed in Docket No. RM06-8-000.

35. With respect to the need for and design of long-term transmission rights, the views of the respondents tended to fall into three general groups. The first group consisted of advocates of long-term transmission rights with terms inthe range of 5-30 years.38 These parties argue 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. The core problem expressed by these parties is that annual allocations of rights may not provide sufficient rights year-to-year to adequately cover potentially volatile congestion cost exposure. In turn, the inability to secure a known quantity of transmission rights for multiple years introduces an unacceptable degree of uncertainty into resource planning, investment and contracting.

38 See, e.g., Comments on Staff Paper of the American Public Power Association (APPA) at 1, 8, 19; Comments on Staff Paper of the Transmission Access Policy Study Group (TAPS) at 19-21; Comments on Staff Paper of the National Rural Electric Cooperative Association (NRECA) at 17-19; Comments on Staff Paper of the Electricity Consumers Resource Council (ELCON) at 9-10.

36. Most of the parties in this first 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.39 These commenters argue that long-term rights should be FTR obligations only under certain conditions that limit financial exposure of the rights holder. Several proposed that the long-term rights should be FTR options. Otherwise, the rights could be physical rights40 or modified FTRs (e.g.financial rights with physical characteristics, such as “use-or-lose” rights) designed to alter the financial settlement properties of traditional FTRs so as to reduce congestion risk.41

39 SeeComments on Staff Paper of APPA at 31; Comments on Staff Paper of TAPS at 17-19. However, other parties supportive of long-term transmission rights argued that their allocation should not be tied to particular classes of generator.See, e.g., Comments on Staff Paper of ELCON at 8-9.

40 SeeComments on Staff Paper of Sacramento Municipal Utility District (SMUD) at 12-16; Comments on Staff Paper of City of Santa Clara, California, Silicon Valley Power (SVP) at 14-18.

41For example, a right that only provides a financial hedge when the holder submits a physical schedule (a type of “use or lose” right).See, e.g., Comments on Staff Paper of the Transmission Access Policy Study Group (TAPS) at 21-25; Comments on Staff Paper of the Electricity Consumers Resource Council (ELCON) at 12-13. Note also that several commenters argued that ISOs with LMP and financial rights should not revert to physical rights to provide long-term transmission service, nor should they allow such ISOs to offer combinations of physical and financial rights (with the exception of already awarded grandfathered rights).See, e.g., Comments on Staff Paper of ABATE at 10-11; Comments on Staff Paper of American Electric Power (AEP) at 3; Comments on Staff Paper of Cinergy at 13-14; Comments on Staff Paper of Edison Electric Institute (EEI) at 3; Comments on Staff Paper of Electric Power Supply Association (EPSA) at 6-8; Comments on Staff Paper of FirstEnergy Solutions at 8; Comments on Staff Paper of ISO/RTO Council at 2-3.

37. A second group of commenters 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. These parties, which included most of the ISOs and RTOs that submitted comments as well as many stakeholders, argued that rights of greater than one year duration would indeed find a role in the markets, but that care was needed in the design of the rights.42 Most of these parties were supportive of straightforward extensions of the current FTR market design to include FTR obligations of longer terms, although perhaps with modified creditworthiness requirements and other rule changes to reflect the different risks embodied in such rights. In general, they proposed terms for such FTRs of between 2 to 5 years. They also supported limiting the quantity of system capability given over to long-term FTRs for at least an initial period.

42 See generallyComments on Staff Paper of California ISO; Comments on Staff Paper of ISO New England; Comments on Staff Paper of New York ISO; Comments on Staff Paper of PJM; Comments on Staff Paper of ISO/RTO Council.See also generallyComments on Staff Paper of New York Public Service Commission (NY PSC) and the Organization of Midwest States (OMS). On appropriate term lengths,seeComments on Staff Paper of Cinergy at 10; Comments on Staff Paper of Coral Power at 3, 6; Comments on Staff Paper of DC Energy at 4-5; Comments on Staff Paper of Edison Electric Institute (EEI) at 10; Comments on Staff Paper of Electric Power Supply Association (EPSA) at 11; Comments on Staff Paper of Midwest Transmission Owners at 11; Comments on Staff Paper of Morgan Stanley at 7; Comments on Staff Paper of National Grid at 15; Comments on Staff Paper of Pacific Gas Electric (PGE) at 5.

38. Finally, some respondents felt that long-term rights should not be introduced at this time.43 These parties argued that the current procedures for annual allocations of FTRs with terms of one year or less were well-established and that transmission rights markets were efficient and maturing around this design. They were concerned that the introduction of multi-year rights could introduce inequity and inefficiency into the organized electricity markets, because they believe 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. Some respondents that supported this position were from retail choice states, reflecting concerns that long-term rights could adversely affect their ability to acquire and trade transmission rights used to hedge shorter-term contracts.

43 See, e.g., Comments on Staff Paper of Cinergy at 3; Comments on Staff Paper of Coral Power at 7. However, many of these respondents did articulate views on how long-term rights should be specified in the event that the Commission required them.

39. In general, those responding to the Staff Paper did not favor a uniform, “one size fits all” approach to long-term rights. Instead, they stressed that the development of long-term transmission rights should take place in a regional context, which would allow stakeholders to balance the different needs of transmission users and reflect the characteristics of the regional grid and generation resources. Also, those responding provided suggestions on many other aspects of long-term transmission right design and implementation. We will refer to those suggestions where relevant in some of the discussion that follows.

IV. Proposed Guidelines for Design and Administration of Long-Term Firm Transmission Rights in Organized Electricity Markets A. The Commission's Proposed Approach

40. To satisfy the requirements of section 1233(b) of EPAct 2005, and to address the concerns expressed by market participants, the Commission proposes to establish a set of guidelines for the design and administration of long-term firm transmission rights in organized electricity markets. The Commission proposes to require each transmission organization that is a public utility with one or more organized electricity markets44 to file with the Commission, within 180 days, either proposed tariff sheets that make available long-term firm transmission rights that are consistent with the guidelines, or an explanation of how the transmission organization already makes such rights available. The proposed compliance procedures are discussed in more detail below.

44As noted elsewhere, this proposed rule would apply whether the Organized Electricity Markets are administered by the Transmission Organization itself, or whether the Organized Electricity Markets are administered by another entity.

41. The Commission recognizes that there may be many possible approaches to fulfilling this requirement of EPAct 2005. Parties commenting on the Staff Paper suggested a number of possible approaches to designing and implementing long-term transmission rights. The Commission believes thatestablishing guidelines for the design and administration of long-term firm transmission rights in this rulemaking, followed by development of specific long-term firm transmission right designs within the stakeholder process of each Transmission Organization with an organized electricity market, is the most appropriate course for complying with the directive of section 1233(b) of EPAct 2005. We agree with many of those commenting on the Staff Paper that a “one size fits all” long-term firm transmission right design is not appropriate, and that long-term transmission rights should be developed through regional stakeholder discussion.45

45 See, e.g., Comments on Staff Paper of APPA at 23-24; Comments on Staff Paper of Association of Businesses Advocating Tariff Equity (ABATE) and Coalition of Midwest Transmission Customers at 11-12; Comments on Staff Paper of New York ISO at 3-4; Comments on Staff Paper of New York Transmission Organizations at 3-4.

42. This flexible regional development of long-term firm transmission rights must, however, occur within certain guidelines. Accordingly, the Commission proposes guidelines for the design and administration of long-term firm transmission rights that ensure that those rights have certain properties that we believe are fundamental to meeting the objectives of section 217(b)(4) of the FPA. For example, we propose below that long-term firm transmission rights be made available with terms (and/or rights to renewal) that are sufficient to meet the needs of load-serving entities to hedge long-term power supply arrangements made or planned to satisfy a service obligation. Additionally, as described in more detail in the guidelines that follow, we propose that transmission organizations be required to award long-term firm transmission rights to market participants that request and support an expansion or upgrade to the transmission system in accordance with the transmission organization's prevailing rules for cost allocation. Such long-term firm transmission rights must be for a term equal to the life of the new facilities, or for a lesser term if requested by the funding entity. Also, as described in more detail below, while long-term firm transmission rights should be made available to all transmission customers, in the event that a transmission organization cannot accommodate all requests for long-term firm transmission rights over existing transmission capacity, we propose that the approach most consistent with section 217(b)(4) of the FPA is to require that a preference be given to load-serving entities with long-term power supply arrangements used to meet service obligations.

43. While we believe these and the other properties outlined in the guidelines below are critical to the successful implementation of long-term rights, we intend for the guidelines to form only a framework for further, more specific development of long-term firm transmission rights by each transmission organization. Accordingly, the guidelines should provide enough flexibility to allow each region to develop, through its usual stakeholder process, a specific long-term firm transmission right design that fits the prevailing market design and best meets the needs of market participants in that region.

44. Although we propose to allow regional flexibility in the development of long-term firm transmission rights, we recognize that allowing transmission organizations with organized electricity markets to implement different rules for these rights could lead to regional seams issues. We seek comments on our proposal to provide regional flexibility. In particular, we ask commenters to identify features of long-term firm transmission rights that, if not consistent across transmission organizations, may interfere with the effective operation of regional markets.

B. Proposed Guidelines

Guideline (1): 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).

45. Section 217(b)(4) of the FPA requires that long-term firm transmission rights be available to support long-term power supply arrangements. Hence, we propose that the transmission rights must be specified such that they can hedge the congestion costs that may be incurred in delivering the output of particular generation resources to particular loads.46 The source nodes can correspond to a single generator or a set of generators (e.g., a zone). Similarly, the sink nodes can specify a single node or set of nodes.47 This guideline is not intended to preclude flowgate rights so long as they are designed with the same hedging properties as an equivalent long-term point-to-point right.

46APPA states that, because ISO-NE offers only general system-wide ARRs, there is no direct relationship between the ARRs that a market participant receives and the FTRs that the market participant may desire, given the location of its resources.SeeComments on Staff Paper of APPA, attached Concept Paper—Long-Term Transmission Rights, at 16, n. 22.

47It is thus possible to define a form of network service that consists of a set of point-to-point rights, each of which specifies a source, a sink and a megawatt quantity. This, however, would differ from network service under the OATT, which does not require the customer to reserve a specific amount of capacity between its network resources and network loads.

46. Section 217(b)(4) recognizes that there may be alternative designs for long-term firm transmission rights.48 For many transmission organizations and their market participants, the most straightforward method to develop long-term firm transmission rights would be to extend the term of the auction revenue rights or FTRs that they currently allocate. These may require additional market rules, such as modified creditworthiness standards. However, we do not preclude alternative designs for long-term rights. Some possible designs are compared in Section IV.C of this NOPR.

48In particular, that provision states that the Commission shall exercise its authority “to enable load-serving entities to secure firm transmission(or equivalent tradable or financial rights)on a long-term basis” (emphasis added).

Guideline (2): 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.

47. In most existing organized electricity markets, LMP is used to manage congestion. The FTRs currently offered in the organized electricity markets provide a hedge against these charges, but are only offered in terms of one year or less. Because of this short term, market participants with long-term power supply arrangements are at risk of having the ARRs or FTRs that they are eligible for to hedge congestion charges associated with delivery of that power prorated during the course of the power supply arrangement. As noted above, one criticism of the current FTR market rules is that the annual FTR allocation may produce different results from year to year in the quantity of FTRs allocated to eligible load-serving entities. APPA, for example, argues that there is a need for a mechanism to keep long-term firm transmission rights feasible in the “out” years.49

49Comments on Staff Paper of APPA at 21.

48. To address this concern, we propose that the transmission organization ensure that the long-term firm transmission rights it offers provide a hedge against congestion costs for the entire term of the right, and for theentire quantity of the right. In proposing that the financial coverage offered by the long-term rights, once awarded, not be modified, we seek to establish rights that provide a high degree of stability in terms of payments from year to year, rather than subject to uncertainty over the possibility of significant pro-rationing in the event of revenue inadequacy. We interpret the intent of section 217(b)(4) of the FPA to be that the Commission ensure the availability in organized electricity markets of long-term firm transmission rights that provide price stability to load-serving entities with long-term power supply arrangements used to satisfy their service obligations.

49. When conditions arise that cause the transmission organization to receive congestion revenues that are not sufficient to meet payment obligations to FTR holders, the transmission organization must have in place a mechanism to fully fund the rights by collecting the needed revenues from a set of market participants. We will not specify here how that funding should be allocated among market participants, which is a subject for stakeholder discussion, but note that ideally the rules for funding of the rights should be designed to create and improve incentives for the maintenance and expansion of the transmission system that is needed to ensure the feasibility of the long-term rights that are allocated. This might be accomplished, for example, by placing the entities that are ultimately responsible for system maintenance and expansion at risk (wholly or partially) for funding revenue shortfalls that are due to inadequate maintenance or expansion practices. The transmission organization might also define rules for transmission upgrades and expansion to support the feasibility of long-term rights.50 The Commission seeks comments on funding revenue shortfalls related to the provision of long-term firm transmission rights, particularly with regard to how any necessary charges should be allocated. Should such charges be allocated to a transmission owner that is responsible for maintaining and expanding the capacity suppo