Daily Rules, Proposed Rules, and Notices of the Federal Government
1. On August 8, 2005, the Energy Policy Act of 2005 (EPAct 2005)
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.
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.
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 markets
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.
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.
6. The Commission proposes a definition for “transmission organization” that is similar to the definition provided in EPAct 2005.
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.”
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.
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 “for
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.
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.
12. In light of the creation of these ISOs and other changes in the electric industry, the Commission issued Order No. 2000.
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.
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 on
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.
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.
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.
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.
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.
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.
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.
23. To reduce the uncertainty due to congestion, transmission organizations that use locational marginal pricing make FTRs available to their market participants.
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.”
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.
26. If a load-serving entity holds an FTR that matches its injections and withdrawals exactly, it pays no net congestion cost.
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.
28. Since the state of the transmission system and market prices change from year to year, the annual allocation allows market participants to re-
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.
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.
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 in
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.
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.
38. Finally, some respondents felt that long-term rights should not be introduced at this time.
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.
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 markets
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 that
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.
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. Section 217(b)(4) recognizes that there may be alternative designs for long-term firm transmission rights.
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.
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 the
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.