FERC-913(516) Final Rule (Docket No.RM06-8-000) July 20, 2006
Supporting Statement for
FERC-913, Long-Term Firm Transmission Rights in Organized Electricity Markets
(FERC-516 Electric Rate Schedule Filings, see below)
As Proposed in Docket No. RM06-08-000
(Final Rule issued July 20, 2006)
The Federal Energy Regulatory Commission (Commission/FERC) requests Office of Management and Budget (OMB) review and approval of FERC-913, Long-Term Transmission Rights in Organized Electricity Markets as proposed in the Commission's Final Rule issued July 21, 2006, in Docket No. RM 06-8-000. (After issuance of the final rule and submission to OMB, the hours associated with the requirements contained in this final rule will be merged with FERC-516 Electric Rate Schedule Filings, OMB Control No.1902-0096, an existing data requirement. FERC-516 is currently approved by OMB through July 31, 2008.
The subject data collection will be affected by the amended regulations because they amend the filing requirements under 18 CFR Part 35. However for the requirements pertaining to long-term transmission rights, the Commission has created a new section of its regulations, Part 42. Specifically, the final rule requires transmission organizations that are public utilities with one or more organized electricity markets to either file tariff sheets making long-term firm transmission rights available that are consistent with each of the guidelines established by the Commission, or to make a filing explaining how their existing tariffs already provide long-term firm transmission rights that are consistent with the guidelines. Such filings will be made under Part 42 as opposed to Part 35 of FERC’s regulations but be covered by the same OMB control number. This Final Rule requires each transmission organization subject to its requirements to file with the Commission, no later than 180 days after publication of the Final Rule in the Federal Register, 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 180 days after publication of the Final Rule in the Federal Register will be required to satisfy the requirements of this Final Rule.
All of the proposed changes in the subject Final Rule are provided for under section 217 of the FPA as added by section 1233 of the Energy Policy Act 2005.1 We estimate that the annual reporting burden under FERC-913 (to be merged with FERC-516) will be increased by 7,080 hours with the revisions identified in the subject Final Rule are implemented.
Background
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.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 To guide the voluntary development of ISOs, Order No. 888 set forth 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.
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 that is necessary for continued development of competitive electricity markets.7 The Commission also found that even after functional unbundling of electric utilities under Order No. 888, opportunities for undue discrimination continued to exist.8 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.9
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.10 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.11 Under Order No. 2000, the Commission has approved the voluntary formation of a number of RTOs.
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 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) (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.
Currently Available Transmission Rights
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. The following sections describe the transmission rights that are available in regions without and with organized electricity markets, and concludes with a comparison of the two types of rights.
Transmission Rights in Regions without Organized Electricity Markets
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.12
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.13
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.
As a condition of receiving network service, a network customer agrees to redispatch its network resources as requested by the transmission provider.14 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.
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.
Transmission Rights in Organized Electricity Markets
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.15 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.
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.16 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.
To reduce the uncertainty due to congestion, transmission organizations that use locational marginal pricing make FTRs available to their market participants.17 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.
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.”18
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.19
If a load-serving entity holds an FTR that matches its injections and withdrawals exactly, it pays no net congestion cost.20 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.
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.21 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.
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.
NOPR (Docket No. RM06-8-000)
On February 2, 2006, the Commission issued a NOPR in Docket No. RM06-8-000, regarding Long-Term Firm Transmission Rights in Organized Electricity Markets. The purpose of the proposed rulemaking was 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 Commission’s policy is that market participants that request and support an expansion or an 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.
As noted above, on August 8, 2005, the Energy Policy Act of 2005 (EPAct 2005)22 became law. Pursuant to the requirement in section 1233 of EPAct 2005,23 which added a new section 217 to the Federal Power Act (FPA), the Commission 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 in this rulemaking. The Commission proposed to require each transmission organization file no later than 180 days after publication of the final rule in the Federal 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 after180 days after publication of the Final Rule in the Federal Register must meet the requirements of the proposed rule before commencing operation.
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.24
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.25
In the Notice of Proposed Rulemaking (NOPR), FERC proposed guidelines for the design and administration of long-term firm transmission rights that transmission organizations with organized electricity markets would make available to all transmission customers. 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 FERC proposed 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, FERC proposed 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 the Commission believes long-term firm transmission rights must have were discussed in the proposed guidelines. 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.
Subject Final Rule (Docket No. RM06-8-000)
On July 20, 2006, the Commission issued a Final Rule in Docket No. RM06-8-000, regarding Long-Term Firm Transmission Rights in Organized Electricity Markets. In adopting the 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 adopted in the Final Rule are designed and intended primarily to ensure that the long-term firm transmission rights that are made available by transmission organizations and 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.
Many of the comments received by the Commission expressed 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 the 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.26 The Commission’s 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.27 Offering such rights should not force transmission organizations to provide rights to the existing system to one party that are infeasible. The Commission expects 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.
While it is difficult to generalize, given the flexibility afforded in the Final Rule, the Commission expects 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. The Final Rule also allows the transmission organization to place reasonable limits on the total amount of capacity it will offer as long-term rights. Therefore, the 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, the Final Rule requires that they be fully funded over their entire term.
As the Commission noted in the NOPR and reaffirmed in the 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.
Moreover, the Final Rule also requires 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.
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.28
The Commission understands 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 the Final Rule. The Commission believes that the approach it adopts in the 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. The Commission clarifies that while each guideline permits flexibility in its implementation, transmission organizations with organized electricity markets must satisfy each of the guidelines in the Final Rule. The 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:
Guideline (3) (Rights Made Available by Expansion Go to Parties That Pay for the Upgrade): The Commission has 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, the Commission defers to transmission organizations to develop terms based on existing market rules and stakeholder needs. The Commission encourages 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): The Commission has 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. The Commission’s 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): The Commission has revised this guideline in two respects. First, the Commission has 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. The Commission believes 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 the Commission does 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.
The Commission has 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. The Commission has 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 the 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): The Commission has 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 the Commission has 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 the Commission’s definition of long-term power supply arrangements under guideline (4).
Transmission Planning and Expansion: The 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. The Commission also requires 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.
A. Justification
1. Section 205(c) of the FPA requires that every public utility have all of its jurisdictional rates and tariffs on file with the Commission and make them available for public inspection, within such time and in such form as the Commission may designate. Section 205(d) of the FPA requires that every public utility must provide notice to FERC and the public of any changes to its jurisdictional rates and tariffs, file such changes with FERC, and make them available for public inspection, in such manner as directed by the Commission. In addition, FPA section 206 requires FERC, upon complaint or its own motion, to modify existing rates or services that are found to be unjust, unreasonable, unduly discriminatory pr preferential. FPA section 207 further requires the Commission upon complaint by a state commission and a finding of insufficient interstate service, to order the rendering of adequate interstate service by public utilities, the rates for which would be filed in accordance with FPA sections 205 and 206.
In developing these requirements, the Commission is satisfying the requirements of section 1233(b) of EPAct 2005, and addressing the concerns expressed by market participants (see item #8 of this submission), by establishing a set of guidelines for the design and administration of long-term firm transmission rights in organized electricity markets. The Commission is amending its regulations to require each transmission organization that is a public utility with one or more organized electricity markets29 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 Commission recognizes that there may be many possible approaches to fulfilling this requirement of EPAct 2005. The Commission believes that establishing 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. FERC agrees with many of those commenters 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.
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 the Commission believes are fundamental to meeting the objectives of section 217(b)(4) of the FPA. For example, FERC proposes 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, FERC proposes 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, 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, FERC proposes 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.
While FERC believes these guidelines are critical to the successful implementation of long-term rights, FERC intends 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.
Although FERC proposes to allow regional flexibility in the development of long-term firm transmission rights, the Commission recognizes that allowing transmission organizations with organized electricity markets to implement different rules for these rights could lead to regional seams issues.
2. The data filed in FERC-913/516 enables the Commission to exercise its wholesale electric rate and electric power transmission oversight and enforcement responsibilities in accordance with the Federal Power Act, the Department of Energy Organization Act (DOE Act)2930and EPAct 2005.
Section 217(b) (4) of the FPA requires that long-term firm transmission rights be available to support long-term power supply arrangements. Hence, the Commission proposed 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.31 To address this concern, the Commission proposes that transmission organizations ensure that long-term transmission rights offered by the organization provide a hedge against congestion costs for the entire terms of the right, and for the entire quantity of the right. In proposing that the financial coverage offered by long-term rights, once awarded, not be modified, the Commission seeks 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. The Commission interprets the intent of section 217(b)(4) of the FPA to be that the Commission ensures the availability in organized electricity markets of long-term transmission rights that provide price stability to load-serving entities with long-term power supply arrangements used to satisfy their service obligations.
The information enables FERC staff and other parties to examine and evaluate the cost elements that comprise rates and in particular to examine and evaluate financial elements comprising a utility’s rates (including as appropriate, plant investment, expenses, tax computations and development of the rate of return on investment) to determine whether and how much of these elements should be included in the utility’s rates. With regard to rate of return, staff analyzes the financial data to determine the appropriate rate of return that a utility will be permitted to earn on the facilities used to provide the service at issue. Examples of the financial data include book and market values of common stock, earning per share, dividends per share and historical growth rates in dividends.
Through this data collection process, FERC is able to regulate public utilities and licensees by exercising oversight and review of their reported rate schedules and tariffs. Without this information, FERC would be unable to discharge its responsibility to approve or modify utility electric rate schedule and tariff filings. Further, without incorporating the guidelines set out in the subject Final Rule, the Commission would not be meeting its statutory obligations under the Federal Power Act in particular to advance the Congressional mandate to facilitate the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities to secure firm transmission rights to meet their service obligations.
This mandate addresses an identified need for transmission organizations with organized electricity markets to provide longer-term transmission rights that can aid load serving entities in financing long-term power supply arrangements to meet their service obligations. Making long-term firm transmission rights available will also provide increased certainty regarding the long-term costs of transmission service in organized electricity markets. As a result, long-term firm transmission rights will allow load serving entities to more effectively plan their power supply portfolios, and encourage load serving entities and other participants in organized electricity markets to make long-term investments in power supply arrangements.
In addition, the Commission would fail to further its own initiatives to advance additional transmission capacity as evidenced by the issuance of a proposed policy statement to promote the efficient operation and expansion of the transmission grid.32
3. There is an ongoing effort to determine the potential and value of improved information technology to reduce the burden. Specifically, in order to increase the efficiency with which it carries out its program responsibilities, the Commission has been implementing measures to use information technology to reduce the amount of paperwork required in its proceedings.
In Order No. 614 (RM99-12-000), the Commission stated that it was initiating a process "necessary to accommodate the movement toward an integrated energy industry and to facilitate the development of common standards for the electronic filing of all electric, gas, and oil rate schedule sheets. Order No. 614 required public utilities to take responsibility for the designation of their tariffs, rate schedules and service agreements, and pagination of their tariff sheets along the lines of the natural gas pipeline program. Order No. 614 also stated that the Commission intended to move to a common standard for the filing of all electric, gas and oil rate schedule sheets.
In addition, in RM01-5-000 FERC proposed that future tariff filings be made over the Internet with software developed (and distributed to public utilities for their use at no cost) software to be downloaded at the users' sites) to enter data manually (for small data sets and to edit corrections) and/or to download spreadsheet data, or other properly formatted system output, directly into the application. In addition, the software will perform edit checks at the utility site to ensure a complete filing and a successful upload at the Commission. The proposed tariffs will change from a tariff-sheet format to a section-based forma that is better suited for electronic filing. The software has undergone testing and refinements to reflect industry comments that were given in several technical conferences held in the summer of 2005 and during testing periods. Integration of eTariff with FERC’s internal business process software is proceeding with a target date of the third calendar quarter 2006.
4. Filing requirements are periodically reviewed as OMB review dates arise or as the Commission may deem necessary in carrying out its regulatory responsibilities under the Act in an effort to alleviate duplication. All Commission information collections are subject to analysis by Commission staff and are examined for redundancy. There is no other source of this information.
The Final Rule as noted above is being issued to implement a Congressional mandate to encourage construction of transmission infrastructure and encourage investment. Making long-term firm transmission rights available will provide increased certainty regarding the long-term costs of transmission service in organized electricity markets. As a result, long-term firm transmission rights will allow load-serving entities to more effectively plan their power supply portfolios, and encourage load-serving entities and other participants in organized electricity markets to make long-term investments in power supply arrangements. The information will be unique to each respondent as they identify what guidelines they have undertaken to implement these initiatives. FERC believes these reporting requirements will provide better and more accessible information to the public and the Commission.
5. The Final rule applies only to transmission organizations with organized electricity markets. In the NOPR, the Commission proposed a definition for “transmission organization” that is similar to the definition provided in EPAct 2005.33 Specifically, the Commission proposed 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 other independent transmission organization finally approved by the Commission for the operation of transmission facilities.”34 The Commission is making this clarification to the definition in EPAct 2005 because it interprets 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, and any such independent entities that are created in the future.35. These entities would not be considered small entities within the meaning of the Regulatory Flexibility Act. However, the Commission will consider granting waivers in appropriate circumstances.
6. If the collection were conducted less frequently, the Commission would be unable to perform its mandated oversight and review responsibilities with respect to electric rates. Furthermore, Section 205 of the FPA mandates that the information be filed every time a licensee or public utility proposes to change its rates. In the Final Rule, FERC amends its regulations to direct each public utility that is a transmission organization with an organized electricity market, within 180 days of the publication of a Final Rule in the Federal Register, to either: (1) file with the Commission tariff sheets and rate schedules that make available long-term firm transmission rights that are consistent with the guidelines set forth in section (d) of the Final Rule; or (2) file with the Commission an explanation of how its current tariff and rate schedules already provide for long-term firm transmission rights that are consistent with the guidelines set forth in paragraph (d) of the Final Rule. The Commission intends that during this 180-day time period, that transmission organizations will work with their stakeholders to develop a long-term firm transmission right that will harmonize the prevailing market design with the guidelines set forth in the Final Rule. The Commission is not proposing any specific stakeholder process, and intends that the transmission organization will use its usual process for receiving stakeholder input and filing tariff changes with the Commission. For any transmission organization that is approved by the Commission after the 180-day time period, the Commission is directing that the transmission organization satisfy the requirements set forth in the Final rule before commencing operation.
7. This proposed program meets all of OMB's section 1320.5 requirements with the exception of part "d" thereof. Section 1320.5(d) limits the collection of data to an original and two copies of any document. The data provided under FERC-913/516 includes tariff sheets and rate schedules that make available long-term firm transmission rights that are consistent with the guidelines or an explanation of how the current tariff sheets and rate schedules are consistent with the guidelines established in the Final Rule and would be filed by the respondents to comply with the provisions as indicated in Item A (1.). Currently an original and five copies are required to be submitted to the Commission. This is the minimum necessary to permit processing within the statutory time frame for Commission action. The original is routed to eLibrary for public viewing over the Commission's web site. One copy is distributed to the Public Reference and Files Maintenance Branch for public inspection in the Commission's Public Reference Room. An additional copy is distributed to the Office of General Counsel for legal review. Three copies are distributed to the Office of Energy Markets and Reliability for technical review by analysts in rate filings, rate investigations and financial analysis.
However, if the eTariff NOPR is adopted and electronic filing is put into place, this will eliminate the need for paper copies entirely for service agreements and transactional reports. During this transitional period, however, the traditional number of hard copies will still be needed for efficient processing of the data.
8. The Commission's procedures require that the rulemaking notice be published in the Federal Register, thereby allowing all public utilities, natural gas and oil pipeline companies, state commissions, federal agencies, and other interested parties an opportunity to submit comments, or suggestions concerning the proposal. The rulemaking procedures also allow for public conferences to be held as required.
The NOPR was issued on February 2, 2006 along with a request for comments and is scheduled to be published in the Federal Register on February 9, 2006. Comments were due on by March 13, 2006 and reply comments were due by March 27, 2006.
Public Reporting Burden Estimates
In the NOPR, comments were solicited on the Commission’s need for this information, whether the information will have practical utility, the accuracy of provided burden estimates, ways to enhance the quality, utility, and clarity of the information to be collected, and any suggested methods for minimizing the respondent’s burden, including the use of automated information techniques. No comments were received on these issues. Therefore, the Commission is retaining in the Final Rule, the estimates provided in the NOPR.
In the NOPR, the Commission proposed to direct each public utility that is a transmission organization with an organized electricity market, within 180 days of the publication of a Final Rule in the Federal Register, to either: (1) file with the Commission tariff sheets and rate schedules that make available long-term firm transmission rights that are consistent with the guidelines set forth in section (d) of the Final Rule; or (2) file with the Commission an explanation of how its current tariff and rate schedules already provide for long-term firm transmission rights that are consistent with the guidelines set forth in paragraph (d) of the Final Rule. The Commission stated its intent that during this 180-day period, transmission organizations subject to the rule will work with their stakeholders (through their usual stakeholder process) to develop a long-term firm transmission right that will harmonize prevailing market design with the guidelines set forth in the Final Rule. For any transmission organization that is approved by the Commission after the 180-day time period, the Commission proposed that the transmission organization be required to satisfy the requirements of the Final Rule prior to commencing operation.
Comments
APPA, New England Public Systems, and Vermont DPS all supported the Commission’s proposed implementation procedures. New England Public Systems stated that if any transmission organization determines that it will not be able to meet the 180-day timetable, the Commission should require that it submit a detailed explanation of the cause of the delay and a detailed schedule for completing and submitting its compliance filing. PG&E supports the compliance filing timeline, and suggested that those deadlines be expanded to address due dates that would follow the future adoption of market-based congestion management programs by a transmission organization. PG&E also recommended that a parallel rule be adopted for long-term firm transmission rights in markets that do not use market-based congestion management systems.
SMUD argued that the Commission’s proposed compliance procedures contain an insufficient directive to ensure timely compliance, particularly because it would allow transmission organizations to submit proposed tariffs with no proposed effective dates. Accordingly, SMUD states that the Commission should issue a Final Rule by August 8, 2006, and clarify that compliance tariffs and rate schedules must be effective 60 days after their filing, to ensure that long-term firm transmission rights are available within about a year.
Several commenters, including AF&PA, IPL, ISO-NE, NEPOOL and OMS, argued that the 180-day deadline proposed in the NOPR for transmission organizations to make filings in compliance with the Final Rule is “unrealistic” given the complexity of the issues involved and the transmission organizations’ other ongoing projects. IPL suggests that the Commission lengthen the time for stakeholder procedures and compliance filings to 365 days, followed by an additional 365-day period during which the transmission organizations will implement their long-term rights mechanism. IPL also suggests that the Commission allow transmission organizations to phase in long-term rights over time. OMS requests that the Commission permit transmission organizations to report on the status of their stakeholder procedures in 180 days, and then set a specific filing date for tariff changes based on that status report.
ISO-NE also requested that the Commission lengthen the 180-day time period for developing and filing a proposal to comply with the Final Rule, stating that a strict requirement to formulate a long-term firm transmission right design within that time frame could present insurmountable challenges since it is also in the process of developing other important market reforms as part of its Wholesale Market Plan.
NYISO states that it will likely be able to meet the proposed 180-day deadline, provided the Commission’s Final Rule clarifies that only limited changes to the current market design need to be considered. It explains that it may need additional time, however, if the Final Rule requires more modifications of existing systems. New York Transmission Owners suggest that if changes to the NYISO market are required, the Commission should allow it to develop a procedure to phase in such changes to avoid market disruptions that could affect the availability of short-term and intermediate transmission rights.
CAISO noted in its initial comments that it faces unique challenges in implementing long-term firm transmission rights because it is in the process of implementing a complete market redesign, which includes a transition to LMP.36 To implement this redesign by November 2007, CAISO states that it will be difficult, if not impossible, to expand the scope of the initial market design. According to CAISO, to adopt long-term transmission rights before the start of the new market it would be necessary to develop a “hybrid” instrument that could be used in both the current market and new market. Developing this instrument, it states, would divert resources from its effort to implement the new market. Accordingly, CAISO asks that it not be required to implement, prior to the start of its redesigned market, any “hybrid” long-term transmission rights product.
Furthermore, given its current process and timeline for implementing the market redesign, CAISO states that it most likely would not be able to fulfill the requirements of the Final Rule under the proposed compliance schedule. Accordingly, it states that the Commission should not require it to have long-term FTRs in place until at least one year after the start of its new markets. CAISO notes that its market participants lack experience with short-term financial rights. As a result, it contends that it could not have a meaningful stakeholder debate on the design and implementation of long-term rights, and urges the Commission to allow it the same opportunity to gain experience with LMP that other transmission organizations have had. Furthermore, it argues that it is important that market participants have a sufficient demonstration of the financial rights they will be able to receive under the market redesign before long-term rights are implemented.37 As a result, CAISO seeks sufficient time for stakeholder discussions on alternate designs, and asks that it not be required to implement long-term financial rights before having at least one year of experience with LMP markets.
SoCal Edison, noting the same concerns regarding the timing of CAISO’s market redesign, argued that the Commission should revise its proposed compliance procedures to require a transmission organization that has filed a complete redesign of its organized electricity market to make a proposal for implementing long-term firm transmission rights after the revised market becomes effective, instead of within 180 days of the final rule. CPUC and SDG&E also express concerns with regard to the timing of CAISO’s implementation of long-term firm transmission rights. CPUC agrees with CAISO that it should be given a period of time to gain experience with LMP before implementing long-term rights, while SDG&E states that the Commission should, in the Final Rule, require CAISO to include long-term rights in its planned second release of the market redesign.
Conversely, CMUA, APPA and NCPA all suggest that accommodating long-term rights should be more easily accomplished in CAISO because it is not an established LMP market, and that it would be easier and less expensive to incorporate long-term rights into the market design rather than retrofit the market later. Nevertheless, CMUA opposes blanket application of the 180-day timeline to CAISO, and (along with TANC) urges the Commission to address CAISO’s implementation schedule for long-term firm transmission rights as part of its consideration of CAISO’s market redesign filing in Docket No. ER06-615-000.38.
Several commenters, including PG&E, SMUD, and Transmission Agency of Northern California, oppose CAISO’s request for deferral and argue that the Final Rule should apply to California upon its implementation of LMP as part of its market redesign. PG&E argued that CAISO’s reasoning that delaying deferral because it has not relied on short-term rights for as long as other transmission organizations “stands . . . EPAct on its head” and perpetuates the problem driving Congress to enact section 217(b)(4) of the FPA and section 1233(b) of EPAct 2005.39 SMUD (and others) note that CAISO was directed by the Commission to develop a long-term firm transmission service more than eight years ago, and has not yet proposed such an option (including in its recent market redesign filing).40 To avoid further delay, SMUD states that if a transmission organization cannot provide a long-term financial transmission right product within 180 days, it should be required to offer physical path arrangements until it can develop a financial product that meets the requirements of section 217(b)(4) and the Commission’s guidelines.41 SMUD also asserts that CAISO wrongly assumes both that implementing long-term rights will cause a delay in the start of its redesigned markets, and that there is urgency in implementing the market redesign.
Commission Conclusion
The Commission will adopt the implementation timetable proposed in the NOPR. The Commission clarifies that it expects transmission organizations subject to this Final Rule to file compliance proposals within 180 days of its effective date. Specifically, they must file proposed tariff sheets and rate schedules that would make available long-term firm transmission rights that satisfy each of the guidelines in the Final Rule. The Commission recognizes that the implementation of long-term firm transmission rights presents difficult issues, and that significant effort will be required to file compliance proposals within 180 days. Congress directed the Commission to act quickly, however, requiring in section 1233(b) of EPAct 2005 that the Commission issue this Final Rule within one year of the legislation’s passage. The Commission believes that this directive shows Congress’s intent that long-term firm transmission rights be made available as soon as possible.
Commenters (particularly ISO-NE) express concern that implementing long-term firm transmission rights on the proposed compliance timetable could negatively impact the ability of transmission organizations to complete work on other initiatives. The Commission encourages transmission organizations to explore ways to reorder their priorities to ensure that this important Congressional directive is fulfilled. The Commission will not rule out at this time the possibility that transmission organizations may seek permission from the Commission to reorder its schedule for market design changes, tariff changes or other projects that were directed by the Commission.
Some commenters suggested that the Commission permit transmission organizations to phase in tariff and market rule changes to introduce long-term firm transmission rights. The Commission cannot decide here whether any particular proposal to phase-in long-term firm transmission would be just and reasonable. The Commission reminds transmission organizations again, however, that Congress intended the implementation of long-term firm transmission rights to occur as soon as possible. Any proposal to phase-in long-term firm transmission rights will be considered in light of this statutory directive.
The Commission notes that the final regulations require transmission organizations to file tariff sheets and rate schedules that make available long-term firm transmission rights that satisfy each of the guidelines within the 180-day timeframe. While SMUD asked the Commission to specify that such tariff sheets and rate schedules be effective 60 days after filing, the Commission does not believe it would be appropriate to prescribe effective dates now. Transmission organizations may need to synchronize the availability of long-term firm transmission rights with their existing allocation schedules. They may also need to take additional steps, such as making necessary software or procedural changes, to implement the rights after the Commission acts on their compliance proposals. As a result, the Commission will consider effective dates on a case-by-case basis, again in light of Congress’s intent that long-term firm transmission be implemented as soon as possible.
Additionally, the Commission clarifies that for transmission organizations with organized electricity markets that are formed after the effective date of this Final Rule; the Commission intends that such organizations will provide long-term firm transmission rights satisfying the guidelines in the regulations. The Commission has made revisions to the proposed regulatory text to clarify that transmission organizations approved by the Commission in the future will be required to satisfy this Final Rule.
The Commission will require that all existing transmission organizations, including CAISO, make proposals to comply with the Final Rule on the same timetable. While the Commission understands CAISO’s concerns regarding its pending market redesign efforts, it cannot address in this rulemaking of general applicability any possible plans for the phase-in or delayed implementation of long-term firm transmission rights. Even if the Commission could, CAISO has not provided any timetable in its comments for implementing long-term firm transmission rights as required by section 217(b)(4) of the FPA and section 1233(b) of EPAct 2005. Therefore, CAISO must work with its stakeholders to develop and submit a compliance filing within the timetable proscribed in this Final Rule, and the Commission will consider any issues specific to CAISO or any proposals offered in its compliance filing for implementing long-term firm transmission rights in CAISO. Once again, the Commission reminds transmission organizations and their stakeholders, including CAISO, that Congress intends that the introduction of such rights occur as soon as possible.
Several entities submitted comments generally addressing the Commission’s 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
Long-Term Transmission Rights from Existing Capacity
Some commenters, particularly Cinergy, Coral Power and NYISO, argued 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 asserted 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.
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 expansions 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
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.42 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.”43 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.
In response to these arguments, APPA argued 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, stated 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
Some entities, including IPL, Midwest ISO and NYISO, argued 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, asserted 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 asserted 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.”44 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 noted that section 217(c) preserved existing FTR allocation methodologies, and argued that Congress sought to complement rather than replace current transmission rights allocation methods.
NYAPP, in reply comments, objected 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.
Midwest TDUs noted in its reply comments that Midwest ISO is subject to a specific directive to consider the preservation of existing transmission rights. Specifically, 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
As noted above, many of the specific interpretations of section 217(b)(4) of the FPA made by the Commission are discussed with regard to the guidelines adopted in the Final Rule. However, here the Commission addresses more general comments regarding its interpretation in the NOPR of the requirement of section 217(b)(4) and section 1233(b) of EPAct 2005.
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. The Commission concludes that this interpretation of the statute is the most reasonable.45 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 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.
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.46 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.
The Commission disagrees 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. The Commission emphasizes, however, that transmission organizations must provide long-term firm transmission rights that satisfy each of the guidelines in the Final Rule even if doing so requires changes to existing systems.
Additionally, the Commission disagrees with suggestions that transmission organizations already provide long-term firm transmission rights, and that creation of long-term financial transmission rights in the Final Rule 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. The Commission agrees 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, the Commission disagrees 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, the Commission agrees 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. The Commission reads this language as requiring it 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.
Finally, the Commission disagrees 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. The Commission believes 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.
9. There are no payments or gifts to respondents in the proposed rule.
10 and 11. The Commission generally does not consider the data filed in rate filings to be confidential. There are no confidentiality or questions of a sensitive nature associated with the data requirements proposed in the subject Final Rule. Specific requests for confidential treatment to the extent permitted by law will be entertained pursuant to 18 C.F.R. Section 388.110. Section 205(c) of the FPA requires that every public utility have all of its jurisdictional rates and tariffs on file with the Commission and make them available for public inspection, within such time and in such form as the Commission may designate. Section 205(d) of the FPA requires that every public utility must provide notice to the Commission and the public of any changes to its jurisdictional rates and tariffs, file such changes with the Commission, and make them available for public inspection, in such manner as directed by the Commission.4247
12. The Commission estimates there will be an increase of 7,080 hours for information requirements/collections under FERC-913/516, as proposed in the subject Final Rule. This is based on the Commission's recent experience with tariff filings. The Final Rule will consist of the tariff filing as described in item no. 6 above.
Data Collection |
Number of Respondents |
Number of Responses |
Hours Per Response |
Total Annual Hours |
FERC-913/516 |
|
|||
Transmission Organizations with Organized Electricity Markets* |
6 |
1 |
1180 |
7,080 |
Totals |
6 |
1 |
1180 |
7,080 |
See footnote #34 above.
The Commission’s experience has found that on average it takes 183 hours for public utilities to prepare and submit a tariff filing. However, as several entities already have FTR programs in place and would only be required to modify existing tariff filings, we estimate that it will only take 100 hours to prepare the tariff filing. Further, to implement the guidelines, staff has reviewed the program that is currently in operation at PJM. The transmission organizations identified above are funded by their memberships and rely on the stakeholders to make determinations for all operating programs. In implementing the guidelines, the Commission estimates that it will take 10 stakeholder meetings at 6 hours each with about 50 stakeholders and transmission organization staff in attendance. To this figure must be added the hours for the transmission organization’s staff which we estimate to be 500 hours for developing examples, business rules, documentation and doing simulations of results.
Current OMB Proposed Proposed New OMB
Inventory in the NOPR in Final Rule Inventory
Number of respondents: 0 6 6 6
Number of Responses: 0 6 6 6
Hours per Response: 0 1,180 1,180 1,180
Total Annual Hours: 0 7,080 7,080 7,080
Difference: +7,080
Program Change: +7,080
Current OMB New OMB
Inventory (FERC-516) Inventory
Number of respondents: 1,238 1,238
Number of Responses: 4,234# 3,348
Hours Per Response: 117.84 119.74
Annual Hours: 393,841 400,921
Difference:
# In taking credit for the 215,180 hours for rescinding the initiative to implement Standard Market Rate Design (RM01-12-000) the Commission did not account for the number of responses that would be eliminated by not implementing this rule (-892).
Program Change: (As implemented in the final rule)
+ 7,080 hours for a total of 400,921.
13. The estimated annualized filing cost to respondents as related only to the data collection requirements as contain in the Final Rule is as follows:
The Commission projected the average annualized cost to be: Total hours 7,080 x $150 per hour or $1,062,000. (The hourly rate was determined by taking the median annual salary projections for legal and technical support using the Bureau of Labor Statistics, Department of Labor Occupational Handbook as a reference.
14. The estimated annualized cost to the Federal Government related only to the data collection requirements as proposed in the Final Rule is as follows:
Data Analysis FERC Total Cost
Requirement of Data Estimated Per One Years
Number (FTEs) x Salary = Operation
FERC-516 4.0 $117,321 $469,284
(Estimated 2006 data)
15. There is a program increase to the reporting requirements contained in FERC-913/516. As noted above, FERC is amending its regulations in the Final Rule to direct each public utility that is a transmission organization with an organized electricity market, within 180 days of the publication of the Final Rule in the Federal Register, to either: (1) file with the Commission tariff sheets and rate schedules that make available long-term firm transmission rights that are consistent with the guidelines set forth in section (d) of the Final Rule; or (2) file with the Commission an explanation of how its current tariff and rate schedules already provide for long-term firm transmission rights that are consistent with the guidelines set forth in paragraph (d) of the Final Rule. The Commission intends that during this 180-day time period, that transmission organizations will work with their stakeholders to develop a long-term firm transmission right that will harmonize the prevailing market design with the guidelines set forth in the Final Rule.
16. The results of this information collection will be posted on the Commission’s Internet web site in eLibrary. These documents are normally posted two days after they are received.
Schedule for Data Collection and Analysis
As noted above, 180 days after publication in the Federal Register of the Final Rule, transmission organizations are to file tariff sheets and rate schedules show consistency with the proposed guidelines or an explanation of how current tariff sheets and rate schedules already meet the guidelines. Respondents seeking to have the Commission approve their FTR guidelines will file a revised tariff incorporating the guidelines or a revised tariff explaining their current program and its compliance with the guidelines.
Estimated Activity Completion Time
Tariff Filed On Occasion
Initial Commission Order 60 Days
17. It is not appropriate to display the expiration date for OMB approval of the information collected. Currently, the information on the tariff filings is not collected on a standard, preprinted form which would avail itself to this display. Rather, public utilities and licensees prepare and submit filings that reflect the unique or specific circumstances related to rates and services involved in the filing. In addition, the information contains a mixture of narrative descriptions and empirical support that varies depending on the nature of the services to be provided.
18. For exceptions to the Certification Statement, see item no. 17 above.
B. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS
This is not a collection of information employing statistical methods.
PROPOSED GUIDELINES
(1) The long-term firm transmission right should specify a source (injection node or nodes) and sink (withdrawal node or nodes), and a quantity (MW).
(2) The long-term firm transmission right must provide a hedge against day-ahead 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 a financial long-term right should not be modified during its term (the “full funding” requirement) except in the case of extraordinary circumstances or through voluntary agreement of both the holder of the right and the transmission organization.
(3) Long-term firm transmission rights made feasible by transmission upgrades or expansions must be available upon request to any party that pays for such upgrades or expansions in accordance with the transmission organization’s prevailing cost allocation methods for upgrades or expansions.
(4) Long-term firm transmission rights must be made available with term lengths (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. The length of term of renewals may be different from the original term. Transmission organizations may propose rules specifying the length of terms and use of renewal rights to provide long-term coverage, but must be able to offer firm coverage for at least a 10 year period.
(5) Load serving entities must have priority over non-load serving entities in the allocation of long-term firm transmission rights that are supported by existing capacity. The transmission organization may propose reasonable limits on the amount of existing capacity used to support long-term firm transmission rights.
(6) A long-term transmission right held by a load serving entity to support a service obligation should be re-assignable to another entity that acquires that service obligation.
(7) The initial allocation of the long-term firm transmission rights shall not require recipients to participate in an auction.
1?/Pub. L. No. 109-58, 119 Stat.594 (2005).
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.
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 31,046 et seq.
11 Id. at 31,106 et seq.
12See Order No. 888 pro forma OATT at sections 13.5, 15.4 and 28.2.
13 Under 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.
14 Redispatch 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.
15 The inclusion of marginal losses can cause locational prices to differ across locations even in the absence of congestion. For purposes of this discussion, the Commission will consider only the congestion component of locational price differences.
16 It 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.
17 FERC used the term FTR in the 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.
18 It 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.
19 The 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.
20 This 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.
21 ARRs 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.
22 Pub. L. No. 109-58, 119 Stat. 594 (2005).
23 Pub. L. No. 109-58, § 1233(b), 119 Stat. 594, 960.
24 Pub. L. No. 109-58, § 1233, 119 Stat. 594, 958.
25 Id. at 960.
26 As the Commission discusses in more detail in the Final Rule, while it does 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. No. 109-58, § 1233, 119 Stat. 594, 958-59.
27 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.
28 The Commission is not requiring any “obligation to build” that does not already exist under Order No. 888.
29 As noted elsewhere, this Final rule applies whether the Organized Electricity Markets are administered by the Transmission Organization itself, or whether the Organized Electricity Markets are administered by another entity.
30?/ 42 U.S.C. 7172.
31 APPA 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.
32 Proposed Pricing Policy for Efficient Operation and Expansion of Transmission Grid, Docket No. PL03-1-000, 10 FERC ¶61,032 (2003).
33 Pub. L. No. 109-58, § 1233, 119 Stat. 594, 985.
34 See id. at 942, 985.
35 The 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.
36 This proposed market redesign was filed on February 9, 2006 in Docket No. ER06-615-000.
37 CAISO noted that it has conducted studies of the financial rights allocation, but that a dry run with market participants under the allocation rules filed with the Commission would be more accurate. It does not expect to complete such a dry run before the first quarter of 2007.
38 APPA stated that it defers to this proposal.
39 Reply Comments of PG&E at 17.
40 See, e.g., Comments of SMUD at 40-41; Reply Comments of CMUA at 3, citing Pacific Gas and Electric Company, et al., 80 FERC ¶ 61,128 at 61,427 (1997).
41 According to SMUD, CAISO can implement physical long-term rights immediately, and in fact has done so for the Western Area Power Administration.
42 Comments of Cinergy at 14.
43 Reply Comments of IPL at 7.
44 Id.
45 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 given 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).
46 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).
47?/See The Power Company of America, L.P. v. FERC, 245 F.3d 839 (D.C. Cir. 2001) (PCA). In PCA, the court found, 245 F.3d at 846, that the Commission may alter its view of what information is required to be on file under section 205(c) of the FPA and 35.15 of the Commission's regulations.
| File Type | application/msword |
| Author | Michael Miller |
| Last Modified By | Michael Miller |
| File Modified | 2006-07-24 |
| File Created | 2006-07-18 |