Detailed Summary of FERC'S Standard Market Design NOPR
On July 31, the Federal Energy Regulatory Commission (FERC), issued a notice of proposed rulemaking (NOPR) in Docket No. RM01-12-000 containing its long-awaited standard market design (SMD) program designed "to remedy remaining undue discrimination in the provision of interstate transmission services and in other industry practices, and to assure just and reasonable rates within and among regional power markets." Regulations implementing SMD would be contained in a new Subpart G to be added to 18 CFR Part 35.
The SMD NOPR proposes significant modifications to FERC's previous Order No. 888, issued in 1996 to require all FERC-jurisdictional public utilities to provide open access transmission as a remedy for undue discrimination, and Order No. 2000, issued in 1999 to cause all transmission owners to place their transmission facilities under the control of regional transmission organizations (RTOs). FERC's objective is to implement SMD fully by September 30, 2004.
Comments on the SMD NOPR originally were due by October 15, 2002. However, in response to requests for additional time and for the opportunity to file reply comments, FERC issued a notice on September 10, 2002, revising the comment schedule. As revised, the schedule calls for comments to be filed by November 15, 2002, and reply comments to be filed by December 20, 2002. The notice also schedules a series of technical conferences on discrete issues addressed in the NOPR.
On October 2, FERC issued a notice announcing a series of additional meetings to discuss specific areas of concern arising from its July 31 Notice of Proposed Rulemaking (NOPR) to implement Standard Market Design (SMD). The SMD NOPR constitutes FERC's newest proposals for restructuring interstate electric transmission and wholesale power markets. The October 2 notice also establishes a new deadline of January 19, 2003 for initial comments on certain specific SMD issues:
- Market design for the Western Interconnection;
- Transmission planning and pricing, including participant funding;
- State concerns and regulatory participation in Regional State Advisory Committees (RSACs);
- Resource adequacy; and
- Transition issues and Congestion Revenue Rights (CRRs).
The current November 15, 2002 deadline for initial comments on other issues was retained. The deadline for all reply comments has been rescheduled to February 17, 2003. FERC has taken these additional outreach actions in response to adverse reactions among the states and certain stakeholders to these identified aspects of the SMD proposal.
Interim Single Transmission Tariff
FERC proposes to initiate SMD by requiring the use of a single, non-discriminatory open access transmission tariff that would be applicable to transmission service for all users of the interstate grid, including wholesale customers and both bundled and unbundled retail transmission customers. FERC asserts that this action is necessary to eliminate undue preferences for native load customers and for the transmission owner's use of its own system. Appendix A to the NOPR contains revisions, referred to as the Interim Tariff, to the Order No. 888 pro forma tariff for this purpose. FERC's assertion of jurisdiction over the transmission component of bundled retail service is based on the Supreme Court's recent decision in New York v. FERC, but can be expected to provoke widespread adverse reaction from state regulators. The NOPR proposes that all entities that own, control or operate interstate transmission facilities be required to file these Interim Tariff revisions by July 31, 2003, to be effective by September 30, 2003. FERC left open the question when unified transmission rates should replace separate rates for wholesale and bundled retail service.
Standard Market Design
SMD will be implemented by a new Standard Market Design Pro Forma Open Access Transmission Tariff (SMD Tariff) contained in Appendix B to the NOPR. Appendix D provides an outline for conversion of the existing pro forma tariff to the SMD Tariff. FERC proposes that an SMD Tariff become effective for each jurisdictional public utility by September 30, 2004. The SMD Tariff will continue the reciprocity provisions used in ISO and RTO tariffs since Order No. 888 and will grandfather existing safe harbors.
Independent Transmission Providers
SMD continues FERC's efforts in Order Nos. 888 and 2000 to develop an effective mechanism for assuring that transmission service is offered by an independent entity. Under SMD, this mechanism is called the Independent Transmission Provider (ITP). An ITP is defined as "any public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce, that administers the day-ahead and real-time energy and ancillary services markets in connection with its provision of transmission services pursuant to the SMD Tariff, and that is independent (i.e., has no financial interest, either directly or through an affiliate, in any market participant in the region in which it provides transmission services or in neighboring regions)." The ITP also will perform market monitoring and market power mitigation, long-term resource adequacy and transmission planning and expansion functions.
Under SMD each public utility must achieve ITP status in one of three ways. The public utility can (1) meet the definition itself, (2) turn over operations of its transmission facilities to an RTO that meets the definition or (3) contract with an ITP to operate its transmission facilities. Each public utility would be required to file an SMD Implementation Plan by July 31, 2003 identifying the ITP that will operate the public utility's transmission facilities; however, a public utility that is a member of an approved RTO or ISO that meets the ITP definition may seek waiver of this notification requirement. The ITP concept is not intended to displace the continued implementation of FERC's RTO program on its current schedule. The SMD NOPR states that an FERC-approved RTO would meet the requirements of an ITP.
In Order No. 888, FERC established a 7-part test for determining the local distribution component of unbundled retail sale by identifying facilities that are not distribution. SMD will presume facilities are transmission and under ITP control, subject to ITP request for exemption if the transmission owner or ITP think they should not be under ITP control. FERC also is considering a bright-line voltage test (e.g., 69 kV), in addition to or independent of the 7-part test, to determine which facilities are to be controlled by ITP and how non-ITP facilities are to be treated as to open access and rates.
All ITPs will be required to file their SMD Tariffs by December 1, 2003 and to fully implement SMD by September 30, 2004.
The key to ITP status is independence. In addition to the requirement of no direct or indirect interest in any market participant in the ITP's region or adjacent region, SMD also requires that all ITPs meet certain specific governance requirements addressing selection, responsibilities and succession of boards of directors; stakeholder participation and mergers.
Regional State Advisory Committees
The NOPR recognizes that states have an important role in creating and sustaining an efficient competitive wholesale market for energy and proposes to create a formal process for state representatives to participate on an ongoing basis in the decision-making process of ITPs. Each ITP would have a Regional State Advisory Committee (RSAC), which should be formed, and have direct contact with the ITP governing board, in a manner that recognizes its public interest responsibilities and be designed to provide the board, as well as market participants and FERC, with a consensus view from states in the area. The specifics of how each RSAC should be formed and operate would be decided on a regional basis. FERC believes that RSACs will provide "coordinated oversight" that ensures "fulfillment of federal public interest responsibilities in a manner that includes the views of the states throughout the region." Canadian provinces are also encouraged to participate in the RSAC process. FERC states that RSACs "may work with the [ITP] to seek regional solutions to issues that may fall under federal, state, or shared jurisdiction," including resource adequacy standards, transmission planning and expansion, rate design and revenue requirements, market power and market monitoring, demand response and load management, distributed generation and load management, energy efficiency and environmental issues and RTO management and budget review.
North American Energy Standards Board
The North American Energy Standards Board (NAESB) is an industry-wide organization formed in 2002 to set voluntary commercial standards, model business practices and electronic transmission protocols for market participants in the electric and natural gas industries in the United States, Canada and Mexico and has been approved by FERC to serve in this capacity. NAESB is organized into four quadrants Â– wholesale electric, wholesale gas, retail electric and retail gas. The SMD NOPR notes that the NAESB wholesale electric quadrant, working with ITPs, will produce business practice and electronic communication standards necessary to implement SMD, which FERC would incorporate by reference through the rulemaking process, resolving any issues that lack consensus). The NOPR also contemplates that NAESB will or may be involved in other areas, including standardized data transfer between modules, minimum standards for resources to meet RAR (including contract content for resources to be developed), and minimum system security standards.
Network Access Service
The SMD Tariff will also utilize the single tariff approach but will be based on a proposed single transmission service, Network Access Service (NAS), which would replace the two services, Network Integration Service (NIS) and Point-to-Point (PTP) service, established in Order No. 888. NAS combines aspects of Network Integration Service and Point-To-Point Service, but the current first-come/first-served and firm/non-firm limitations on service will be replaced.
Under NAS, all customers will be assured feasible service from and to any point on the system, but the usage charge will be uncertain, except to the extent the customer chooses to hedge its congestion costs through several available mechanisms. Thus, capacity will be rationed by flexible pricing, and not by service limitations or pro-rata curtailments. Scheduling will be similar to current pro forma tariff, with the NAS customer specifying receipt and delivery points at the time it schedules in the day-ahead and real-time energy spot markets, as discussed below.
Customers with pre-Order No. 888 wholesale power or transmission contracts will be able to convert them, consistent with their contract terms, to NAS upon implementation of SMD. However, if customers choose not to convert to the new service, the transmission owner would be required to take and pay for service from the ITP under the new SMD Tariff in order to meet its contractual obligations to serve the pre-Order No. 888 contract customers. FERC anticipates that the transmission owner would receive an initial allocation, as described below, of sufficient CRRs to provide protection against congestion costs for these existing contracts. The transmission owner would have the right to make a filing under FPA Section 205 to demonstrate that its revenue requirement should be adjusted to recover additional costs resulting from its transition to the new SAS.
Pricing of Transmission Service Access Charges
FERC's existing pro forma tariff permits transmission providers to assess an access charge to recover the embedded costs of the transmission grid. A NIS customer pays a monthly demand charge based on its load ratio share (the customer's hourly load coincident with the provider's monthly transmission system peak) of the provider's monthly transmission revenue requirement. A firm PTP customer pays a monthly demand charge for each unit of capacity it has reserved.
For a single transmission provider, these charges usually take the form of a "postage stamp" rate (the same charge for all customers' use of the grid, regardless of the location of the generator or the load) or "license plate" rate (a different charge for use of the entire system based on the revenue requirement for the transmission owner's facilities, or "zone," on which the load is located.) PJM and New York ISO use license plate rates. Currently, a transmission user that transmits power from one provider to another would pay two transmission access chargesÂ–one for use of the system where the generator is located and one for use of the system where the load is located. If the movement required the use of the facilities of an intervening provider, the user would pay three access charges.
Under SMD the access charges would be assessed primarily on load serving entities (LSEs) that take power off the system, based on their load ratio share, and not on generators. LSEs include large retail customers that purchase power from suppliers other than their incumbent utility. This is proposed as an effort to remove the distorting effects that FERC considers access charges to have on economic choices of market participants. FERC believes economic choices of loads (such as where to locate) are less likely to be affected by access charges than are the choices of generators. FERC also proposes to remove all rate "pancaking" Â– the practice of charging separate embedded cost charges for moving power over components of the grid Â– both within the ITP's service area and between service areas. This would be done by allowing only one access charge to be paid for power to reach load, which would be the access charge for the system where power is ultimately delivered to the LSE.
Thus, under SMD a transaction originating at a location ("source") and terminating at a location ("sink") in the service area of ITP A would pay the access charge (whether a license plate or postage stamp rate) imposed by ITP A for transactions terminating at the sink. However, a transaction originating at a source on the system of ITP A and terminating at a sink on the system of ITP B would pay only the access charge imposed by ITP B for transactions terminating at the sink on its system. In both cases, the access charge would be imposed on the LSE, which would be indifferent to the location of the source. The effect is to eliminate the charge for through and out service. FERC proposes to use one of two mechanisms to avoid the cost shifting that this otherwise would produce. One would be, using the second example above, to have a portion of ITP A's revenue requirement allocated to ITP B and recovered as an uplift in the scheduling charge paid by all of ITP B's customers in whose service area the power sinks. This approach would require projections of inter-regional transfers and to re-allocate costs, as well as deciding how narrowly to focus the cost allocation (e.g., ITP to ITP, export zone to import zone). The other would be a revenue crediting approach under which the inter-regional transfers would be netted across ITPs. The LSEs in the net importing ITP will pay through an uplift in the scheduling charge a load ratio share of the through and out costs of the net exporting ITP and LSEs in the next exporting ITP would receive these revenues.
Market-Based Pricing of Transmission Usage, Energy and Ancillary Services
In addition to access charges, transmission customers under SMD will pay usage charges to recover the cost of congestion, which will be determined, along with prices for energy and ancillary services derived in bid-based markets.
Locational Marginal Pricing
Congestion will be managed by a combination of Locational Marginal Pricing (LMP) and Congestion Revenue Rights (CRRs). LMP, which is used in PJM and New York ISO and proposed for ISO-New England and the California ISO, determines the market-clearing marginal cost of energy at each point (node) on the grid based on bids of sellers and buyers in the market. Congestion prevents the cheapest energy from reaching all nodes where buyers want delivery, meaning there will be many different prices across the system. LMP relies on economic redispatch to manage congestion. Redispatch reduces the amount of energy needed, and therefore the price, on the source side of each constraint (because there more sellers are trying to sell across the constraint than can be accommodated) and increasing the amount of energy needed, and therefore the price, at nodes on the sink side of the constraint (because there local generation must be increased to make up for the power not available due to the constraint). Using this mechanism, LMP determines separate energy prices at each node that reflect the costs of congestion between nodes. The congestion cost for transmission from any source, or receipt point, to any sink, or receipt point, is calculated as the difference between the LMP prices at the source and sink nodes.
Day-Ahead and Real Time Markets
Under SMD, all ITPs will operate day-ahead and real-time markets for energy and certain ancillary services in conjunction with scheduling of transmission service day ahead and in real time.
Scheduling Under NAS
Each day the ITP would accept requests to schedule transmission service to support bilateral energy transactions or customer-owned generation for each hour of the following day. For each requested movement, the request would indicate the receipt point and the delivery point, the amount of power (MW) to be transferred and the time period. The customer can indicate the maximum $/MW usage charge (congestion cost plus marginal line losses) or congestion cost the customer is willing to pay for the service or request service regardless of the usage charge. The customer also may submit multi-block bids, requesting service for a block of consecutive hours and indicating the maximum price for the entire multi-hour period.
The Day-Ahead Market
ITPs also will be required to conduct security-constrained, bid-based day-ahead and real-time energy markets, which will be available, but not mandatory, for all market participants. Each day sellers will submit bids into the day-ahead market that indicate the quantities of power they will offer for sale in each hour of the next day at each node and the bid price, expressed in $/MW, which may include minimum prices that will be accepted as well as self-schedule bids that offer power at a node at the market-clearing price. Bid prices may be multi-part, separately specifying bid-prices for start-up, no-load and energy and technical characteristics such as ramp rates, minimum run times and minimum down times. Buyers will submit bids indicating the amounts of power to be bought, the delivery point, the time period and prices, which also may specify time and price constraints or may be self scheduled bid to purchase at the market-clearing price. Bidders also could submit non-binding financial bids, as now allowed in PJM and the NY ISO. FERC proposes scheduling options to address special conditions facing energy-limited resources such as hydroelectric and environmentally restrained thermal resources and intermittent resources such as wind. Demand reduction resources also would be permitted to bid as suppliers in the market.
Order No. 888 identifies six ancillary services as being the responsibility of the transmission customer. SMD proposes that three (Scheduling, System Control and Dispatch Services; Reactive Supply and Voltage Control; and Energy Imbalance) must be obtained from the ITP, while the remaining three (Regulation and Frequency Response; Operating Reserve-Spinning and Operating Reserve-Supplemental) must be offered by the ITP, but the customer also may provide them from self-supply or by contract from a third party. Under SMD, the ITP would be required to operate day-ahead and real-time bid based markets to obtain these last three from the lowest cost suppliers. Imbalance energy would be provided through the day-ahead and real time markets as described below, and would no longer be treated as an ancillary service.
Each day, the ITP would determine the total amount of each ancillary service that will be required for each hour of the following day. Customers wishing to meet their ancillary service requirement through self-supply or third parties would provide the ITP with the necessary information and identify the sources. To procure the remaining ancillary services, the ITP would accept bids from sellers for each hour of the following day. The bids would include the various components that would be submitted to provide energy into the energy market and an availability bid indicating the minimum $/MW price required to provide the ancillary service. By providing one ancillary service, a bidder may forego profits from sales in other markets, which foregone profits represent an opportunity cost of providing ancillary services and could be included in the bid. The price for regulation and operating reserves would thus equal the sum of the opportunity cost plus the availability bid.
The ITP would consider the transmission scheduling requests in conjunction with bids submitted in its day-ahead energy and ancillary service spot markets. Based on these, the ITP would develop a day-ahead schedule that maximizes the economic value for all market participants. Using LMP, the ITP would determine a single market-clearing price for energy at each node for each hour of the next day based on the bids. The bid of the last unit of supply needed to satisfy the demand Â– the highest bid selected -- at that node during that hour will be paid to all suppliers, and received by all buyers, of power at that location during that hour. The ITP would establish transmission usage prices for each hour of the next day that are equal to the implicit transmission usage price included in the set of LMP-derived energy prices (the difference in the price of energy at the receipt point and at the delivery point) and would schedule all requests for transmission service that have agreed to pay any applicable congestion charges and those where the usage charge is no higher than the amount the customer indicated it was willing to pay.
As discussed below, transmission customers holding CRRs would receive congestion revenues that help offset any congestion charges paid as part of the transmission usage charge. Based on the accepted bids included in the day-ahead schedule, the ITP would establish day-ahead prices for each of the ancillary services procured in the bid-based markets for each hour, equal to the highest accepted total bid cost. The results of the day-ahead market would be financially binding on market participants. The ITP would post prices and other market information and settle the markets promptly to provide market participants with reliable information regarding their market transactions.
Adjustments to the Day-Ahead Schedule
After the ITP has established the day-ahead schedule and associated prices for energy, transmission service and ancillary services, it would make its own forecast of load within its service area for each hour of the next day. To the extent its forecasted load exceeds the amount of energy scheduled to be delivered in the day-ahead schedule, the ITP may need to procure additional "replacement reserves" to make up the difference by accepting bids from generators who submitted for the day-ahead market. Generators selected for this purpose would be included in the real-time energy bid stack and paid the applicable real-time energy price for what they produce, plus an "uplift" payment to cover any shortfall between their bid price and the real-time price. The total of such uplift payments would be recovered pro rata from all loads that buy energy in real time that have not been scheduled in the day-ahead market. New requests for transmission service, and changes in service that had been scheduled, received after the day-ahead schedule has been established would be accommodated if made to the ITP within specific time deadlines before the real-time market begins.
The Real-Time Market
The ITP would accept bids to buy and sell energy in the real-time market. In general, bids would indicate an offer to depart in real time from one or more components of the bidder's day-ahead schedule to purchase or buy energy. The ITP would make adjustments to energy production and/or load at various locations to balance generation and load and manage congestion by calling on real-time bidders, as well as participants that have been selected to provide spinning, supplemental and replacement reserves. Applying LMP to the bids, the ITP would determine energy prices in the real-time market for each node for each 5-minute period (or other sub-hourly period where a 5-minute period is not technically feasible). Rather than using an ex ante approach that would set real time prices based on the ITP's announced estimate of the real-time market-clearing prices for each 5-minute period, FERC proposes to use an ex post rule that would base the real time price on the price of the actual marginal (highest-cost) resource clearing the market in real time, but not higher than the announced ex ante price, which would be advisory. FERC believes its proposed ex post pricing rule may encourage bidders to respond in real-time in a way consistent with their bids. To the extent market participants fail to produce or take energy according to their schedules in real-time, such imbalances would be settled at the applicable real-time energy price.
The ITP also would operate a real-time market for ancillary services to accommodate adjustments in the supply of ancillary services from the day-ahead schedule and to provide an opportunity for more-efficient substitutions of services in real time. The bids would contain the same types of information as the day-ahead bids, except that availability bids would not be allowed for spinning reserves in real time, on the theory that no incremental costs are associated with providing these services in real time. The ITP would select the bids that minimize overall cost of the procuring ancillary services in real time and establish real-time prices for each hour that reflect the marginal cost of each service.
Congestion Revenue Rights
Under LMP, transmission usage prices will vary based on the price of relieving transmission congestion and losses. Rather than using the current system of physical reservations, a system of financial rights, called Congestion Revenue Rights, or CRRs, will be used to give customers the ability to protect themselves against congestion costs. CRRs entitle the holder to receive specified congestion revenues in the day-ahead market. To the extent that a customer's real-time schedule coincides with its day-ahead schedule and its CRRs, these rights offer complete protection against uncertain congestion charges. Thus, to achieve certainty with respect to price and avoid congestion costs, the customer would have to acquire the CRRs associated with its specific receipt point-delivery point combination(s). These CRRs provide the holder with the revenues associated with congestion between those points, so any congestion costs it pays are fully offset by these revenues. The customer would be provided with certainty as to delivery and price, comparable to firm service under the existing pro forma tariff. To the extent the holder of CRRs opts not to schedule transmission service at those points, it would still receive the congestion revenues.
Customers paying transmission access charges would receive CRRs or, alternatively, revenues from the auction of CRRs. Thus, in exchange for paying the fixed costs of the transmission system, those paying access charges would receive the financial benefits Â– the stream of congestion revenues Â– resulting from usage of the system. The aggregate amount of CRRs issued by the ITP would be the amount simultaneously feasible based on Available Transfer Capability under normal operating conditions. Under such conditions, the ITP would collect enough congestion charge revenue in the day-ahead market to fully pay the revenues owed to holders of CRRs, and may collect a surplus. However, when less service can be provided because a significant amount of transmission facilities are out of service, the ITP may collect less congestion charge revenue from transmission users than the amounts owed to CRR holders. FERC proposes to assign the revenue shortfall to the owners of the out-of-service facilities, except for force majeure events, and also to allocate surpluses to transmission owners.
The NOPR identifies three types of CRRs.
- A receipt point-to-delivery point right entitles the holder to the day-ahead congestion revenues associated with transmission service for a specified MW of power from the receipt point to the delivery point. The right is direction-specific Â– the holder is not entitled to the congestion revenues from the receipt point to the delivery point, not from the delivery point to the receipt point. In addition to the congestion revenues, during any period when the demand for transmission service cannot be met with Available Transfer Capacity (because there are too many customers who have scheduled the service at any price), holders of receipt point-to-delivery point rights would receive scheduling priority over other market participants between the points designated in the rights.
- Receipt point-to-delivery point rights can take the form of obligations or options. When congestion occurs in the opposite direction of the right, congestion revenues in the direction of the right are negative. The holder of an obligation would be required to pay the negative congestion cost, while the holder of an option would not. Existing firm PTP transmission contracts do not require contract holders to transmit energy and, thus, are similar to CRRs that are options.
- A flowgate right entitles the holder to the day-ahead congestion revenues associated with the specified power flows over a particular transmission facility or group of facilities, or flowgate, in the specified direction. A flowgate right would never require the holder to make congestion payments. The congestion revenue associated with a flowgate in a specified direction would equal the additional net economic value to market participants that would result by incrementally increasing the flowgate's capacity in the specified direction. That additional economic value may be positive (when the flowgate is congested) or zero (when the flowgate is not congested) but it never would be negative. Flowgate rights may offer flexibility to customers meeting their loads' needs with a portfolio of generators scattered around a regional electricity market. Since there are fewer congested flowgates than possible under receipt point-to-delivery point rights, transmission customers can focus on their rights on the key congested flowgates. However, flowgate rights may not provide complete protection against congestion charges for a receipt point-to-delivery point transaction because the congestion revenues may differ from the congestion charges.
At the start of NAS, the ITP would be required to offer receipt point-to-delivery point obligations and may offer other types as requested by market participants and when technically feasible. CRRs could be offered for various terms, such as weekly, monthly, yearly, etc.
Transmission customers under existing contracts will receive CRRs that match their current use of the system. The ITP would compile a catalogue of all the existing long-term firm obligations for its transmission system that would still be in effect when SMD is implemented (short term contracts would expire before the implementation of SMD and would not be included in the catalogue). This would include firm PTP service under an OATT, firm transmission under pre-Order No. 888 contracts, designated resources for NIS pursuant to an OATT, and bundled retail load (which is served under an implicit contract with the transmission owner). For firm PTP service, the existing rights would be those specified in those existing agreements. For NIS, and bundled retail service, the existing rights would be limited to the designated resources in effect at the time, up to the customer's current peak load (to replicate the service the customer is currently receiving). The CRRs would go to the entity taking service under the ITP's tariff. An entity paying to construct participant-funded new generation or transmission facilities that add transfer capability would receive CRRs associated with the new capability.
Market participants would be allowed to resell any CRRs for the full term or for any part of the term. Resales could be transacted bilaterally, with the sales reported on and conducted through the ITP's OASIS. ITPs would be required to conduct public auctions of CRRs. The auctions would provide price transparency, provide the ability to reconfigure CRRs into different receipt and delivery points or into different types of rights and allow CRRs associated with other transmission capacity that becomes available, such as through expiration of previously issued rights, to be sold. The ITP would select the combination of bids that maximizes the economic value of the transactions for the participants, within the simultaneous feasibility of all CRRs, and establish market-clearing prices for each CRR bought or sold. The term of CRRs auctioned would be at least one month. ITPs also would be permitted to include in such auctions pre-day-ahead auctions for energy and ancillary services at specific locations on a forward basis, which would allocate transmission capacity among competing demands for CRRs, forward energy and forward ancillary services so as to maximize the economic value of the winning bids.
Appendix F to the NOPR contains a detailed description of how CRRs would be allocated and auctioned, depending on the specific type of existing contract and market participant involved.
Other Market Operations Issues
FERC would continue to authorize ITPs, as currently provided in the pro forma tariff, to curtail transmission service and take any other preventative action necessary to preserve system reliability, but SMD also would require ITPs to propose and implement programs to determine and advise participants of the pricing implications of these reliability actions. FERC further proposes to allow generators whose output is adjustable on an hourly basis, but only in increments greater than 1 MW, to be eligible to set the energy price in the real-time market if (1) in the absence of the generator's output, the load either could not be fully met or a more expensive generator would be needed to meet the load and (2) the reason the generator is operating must not be a minimum run time constraint. FERC also is considering whether market participants should face additional charges or penalties for producing or taking, without permission or direction from the ITP, a different amount of energy in real time than was scheduled. ITPs also would be authorized to establish trading hubs.
The ITP would calculate available transfer capability (ATC) for the region. Capacity benefit margin (CBM) constitutes the set-aside of transfer capability by a transmission provider to ensure the ability to import external sources to meet generation reliability requirements. FERC wants to ensure that only customers benefiting from CBM pay for it and that transfer capability needed to access resources on a neighboring system is treated consistently with all other portions of the transmission grid. Accordingly, an ITP will not be permitted to set aside transfer capability for generation reliability reasons. Instead, LSEs wanting access to resources on a neighboring system to meet its RAR should acquire CRRs from the interface to its load. This restriction does not affect an ITP's transmission reliability margin (set-aside of transfer capability to ensure transmission reliability).
Transmission Planning and Expansion
FERC proposes to move transmission planning and expansion to a regional process that would allow market forces to select the best solutions to construction of needed projects. The NOPR proposes to require each public utility to begin to participate in a regional planning process within 6 months after the effective date, with the first regional plan completed within another 12 months, after the effective date of the final rule. Regional planning need not be limited to RTO boundaries or even to the United States. FERC proposes that the Western Electric Coordinating Council serve as the planning region for the West; that the East be split between one region made up of PJM, Midwest ISO and Southwestern Power Pool and another region consisting of the New York ISO and ISO-New England; and that the Southeast would be covered by a single planning region made up of Southeastern Reliability Council plus the Florida Reliability Coordinating Council. The process, for which the ITP would serve as the clearinghouse, should: identify all expansion needs in the region, including reliability and economic needs; give the ITP the responsibility to issue RFPs to meet identified needs; and assign responsibility to transmission owners if no satisfactory bids are received.
FERC has preferred rolled-in pricing for network upgrades, whether for reliability or economic reasons, while participant funding (those who benefit from particular project pay for it) has been required for interconnection facilities. However, FERC has moved to the view, expressed in FERC's recent Generator Interconnection proposed rule, that participant funding may be acceptable where an independent entity determines (1) the cost and responsibility of needed upgrades; (2) congestion price signals to which the customer responds (along with CRRs); and (the assumptions underlying the power flow analysis). Because these functions will be performed by an ITP under SMD, FERC proposes to consider using participant funding for proposed transmission facilities that are included within a regional planning process conducted by an ITP. Otherwise, FERC proposes to apply a default policy that would recognize the regional benefits of transmission expansions by rolling in on a region-wide basis all high voltage network upgrades of 138 kV and above, with the cost of lower voltage network facilities being allocated to a sub-region (e.g. single transmission owner or license plate "zone") where the expansion facilities will be located. FERC states that RSACs would facilitate the planning and siting of regional facilities and that, if there is agreement within the RSAC, FERC would look with favor on a pricing proposal by the RSAC that is consistent with the FPA.
Long-Term Resource Adequacy
FERC is concerned that the spot market alone will not signal the need to bring development of new supply resources in time to avert a shortage and that spot market prices that are subject to mitigation measures, as discussed below, may not produce an adequate level of investment when a shortage occurs. In addition, FERC believes that LSEs will underinvest in resources needed for reliability if they can depend on the resource development investments of others. These concerns have led FERC to propose a long-term resource adequacy requirement, which would be applicable to all regions and replaced installed capacity (ICAP) requirements previously approved for RTOs.
Each ITP will be required to do an annual forecast of the future demand of its area for the time period needed to add new supply and demand response initiatives, called the planning horizon. FERC believes the traditional single-utility method of forecasting may be difficult in today's competitive wholesale markets. Accordingly, the ITP may use a collaborative, "bottom up" method of forecasting by adding up all of the demand forecasts of its component areas, where they are reliable, and must coordinate generation planning with transmission planning. Once future level of supply and demand resources is determined, an appropriate level of resources reserves must be determined. FERC proposes that this resources adequacy requirement (RAR) be set by the RSAC for the ITP's region, but proposes a minimum, safety-net level for all regions equal to 12 % reserve margin (ratio of the reserves to the forecast peak, expressed as a percentage) for all regions.
Each LSE must satisfy a portion of the regional RAR. The term LSE here means any entity that uses transmission in interstate commerce to provide power to load and includes a traditional distribution utility, an energy service supplier that aggregates load under a retail choice program or a large retail industrial or commercial customer that has retail access rights and buys power directly from suppliers. FERC is considering whether each LSE's share of the RAR should be based on each load's forecasted demand, on each load's most recently documented load ratio share or left to regional determination.
Once each LSE's share of the RAR is determined, the ITP must require each LSE to report and document how it plans to meet its adequacy requirement. The requirement can be met by self-owned generation or by firm bilateral contracts for power backed by real and specific generation units (or a portfolio of designated units) committed at least during certain conditions such as operating reserve shortage. The firm contract must be for a forward-looking period that would at least cover the planning horizon. In order to encourage the development of new resources, FERC contemplates that generation under contract for development within the planning horizon should satisfy the requirement and is considering whether the content of such contracts should be specified or perhaps the content should be referred to NAESB for determination. The LSE also must demonstrate that the future use of the specific resource at the designated locations is physically feasible, including that transmission is or will be available to deliver the power from the resource to the load. A CRR for the appropriate time period is one way to satisfy this requirement, as would be of demonstration that planned transmission with full siting approval and completion expected in the time frame. An LSE that does not want to pay for generating reserves may substitute a proven demand response alternative to meet its RAR, such as biddable remand reduction, interruptible load or other dependable load reduction program.
The planning horizon for each region is the number of years ahead for which the ITP must forecast annually its area's load, as well as the number of years ahead for which LSEs must show that they have adequate resources. Historically, the planning horizon for a state-regulated electric utility was 10-20 years. FERC proposes to make the planning horizon a matter for regional choice and to have the planning horizon for each region determined by the RSAC, with information and support from the ITP.
FERC's proposed mechanism for enforcing RAR obligations has two components, a penalty rate and first curtailment of load. Each of these components would occur at the end of the planning horizon (e.g, if the planning horizon is three years, any LSE that fails to submit in 2004 an adequate resource plan for 2007 would be subject to the penalty rate and load curtailment in 2007 if a shortage occurred in that year). During a shortage for spot market energy purchases in a year for which the LSE fails to meet its RAR, the ITP will add a per-megawatt penalty price to the price of energy taken from the spot market by the LSE during that year. The penalty rate would increase in stages, as the shortage becomes more severe. If the operating reserve level drops to the point that some load must be curtailed, the spot market energy purchases of that LSE would be reduced by the amount of its resource deficiency and consequently some of its customers would be curtailed before the loads of other LSEs. FERC also proposes to charge the deficient LSE a further penalty rate of $1000/MWh plus the applicable LMP for all unauthorized energy taken following an instruction from the ITP to implement curtailment. In support of its proposed RAR enforcement mechanism, FERC would require the ITP to inform the LSE's state regulatory authority if an LSE fails to submit a satisfactory plan for adequate future resources, with the expectation that the state regulator would require the LSE to meet its RAR as a condition of doing business.
Market Power Monitoring and Mitigation
FERC finds that cost-of-service regulation is not effective for spot markets of commodities such as electricity because it blunts price signals and leads to inefficient investment and consumption decisions that increase long run costs for consumers. However, FERC finds that wholesale electric markets are not yet structurally competitive in all respects. Specifically, FERC identifies the lack of price-responsive demand and generation concentration in transmission-constrained load pockets as two structural flaws in these markets, which create the potential for participants to exercise market power, defined as the ability to raise price above the competitive level. FERC proposes new market power mitigation measures to deal with the consequences of these defects by approximating the outcomes that a competitive market would produce. These measures will be implemented by the Market Monitoring Unit (MMU), an entity that will report directly to the FERC and to the independent governing board of the ITP the results and recommendations derived from its study of the markets operated by the ITP. FERC also proposes that sellers who control no more than 50 MW of capacity in a region would be exempt from market power mitigation requirements.
The first measure addresses local market power and is similar in concept to the reliability must-run agreements that exist in RTOs today. Local market power principally arises either from the concentration of generator ownership within a load pocket or the need for local units to operate to assure system reliability and stability within the load pocket. Under the SMD Tariff, each generator dispatched by the ITP will enter into a participating generator agreement. Under these agreements, when there are not sufficient alternatives available to meet load in that location, a generator must run to provide all its available energy to the grid, either by scheduling a bilateral transaction or by bidding into the spot market. The agreement would specify the conditions that would give rise to this must-offer requirement and also would specify bid caps for that generator. The need for the generator to be producing could be identified either in the day-ahead market based on projected system conditions or in real time. In the day-ahead market, all available capacity would include all capacity not sold bilaterally and scheduled or on an outage. In the real-time market, all available capacity would include all non-producing capacity (not delivered to the market), i.e. capacity not on a planned or forced outage. FERC is considering options for dealing with the risk of a forced outage inside a load pocket.
FERC believes that, in addition to the bid caps specified in the participating generator agreements, local market power will be limited through bilateral contracts between LSEs and generators to meet the LSEs' RARs. FERC expects that these contracts would address the LSE's need for generation resources to available during peak or congested period and so would include provisions specifying when the generator must run to meet any reliability needs in that location and the price to be paid.
If bid-in capacity is insufficient to meet both operating reserve requirements and load, imports (generators not dispatched by the ITP, as well as marketers, which do not have participating generator agreements with the ITP) may be able to bid in at unrestrained levels due to a lack of demand response. Under such conditions, the resulting market-clearing price could be set above the marginal cost of the highest cost unit within the market. FERC proposes to adopt a safety-net bid cap, regardless of cost or risk or location, even if the market is confronted with a genuine operating reserve shortage (which would be addressed through the RAR enforcement mechanism discussed above). However, if the MMU establishes that some units may provide power at a cost that exceeds the safety- net, a higher cost may be justified for these units. FERC proposes that the $1,000 per megawatt-hour cap currently in use in the Northeast and Texas can serve as a proxy scarcity price under SMD but is still considering what an appropriate cap would be and whether it should be uniform across an interconnection, so there would be one cap in the East and one in the West.
FERC also proposes that each SMD tariff also may include an additional, voluntary market power mitigation measure to apply to unanticipated and sustained market conditions that would give the ability and the incentive to exercise market power. This kind of mechanism may not be necessary in every region, as recommended by the MMU. If adopted for a region, the specific triggers and mitigation mechanisms would be set out in the SMD Tariff and reviewed by FERC.
Monitoring would be conducted on an ongoing basis by a MMU that is autonomous of the ITP's management and market participants. The MMU will report directly to FERC and the ITP's governing board and share its analyses and reports with the ITP's management and RSAC. The MMU will focus on the functioning of the ITP's markets, the conduct of individual market participants and on identifying factors that might contribute to economic inefficiency. FERC intends to require the use of a core set of questions and analytical techniques to be used by each MMU to assess market structure, participant behavior, market design and market power mitigation, which will facilitate inter-regional comparisons.
At a minimum, the MMU would be required to submit an annual report that would include: (1) a general description of the market operations, supply and demand, and market prices; (2) an analysis of market structure and participant behavior; (3) an evaluation of the effectiveness of mitigation measures taken; (4) and overall assessment of market efficiency perhaps using a simulated competitive benchmark; (5) an evaluation of barriers to entry for generating, demand-side and transmission resources; and (any recommended changes to market design or market power mitigation measures to improve market performance. In addition, the MMU will be required to report to FERC, through the Office of Market Oversight and Investigation, any instances of conduct by market participants that appear to be inconsistent with the SMD Tariff. As set forth in the SMD Tariff, market participants and transmission customers will be required to agree to predetermined penalties that would apply to violations of the tariff rules.
Modular Software Design
FERC proposes to use a standardized, as opposed to open systems, approach to accomplish standardized data transfer between modules and is considering using the NAESB process or forums set up by the Electric Power Research Institute (EPRI), to set standards for data standardization for inputs and outputs to software modules and to encourage the industry to develop benchmark problems to sets various alternative systems.
The Critical Infrastructure Protection Advisory Group of the North American Electric Reliability Council (NERC) recently developed a set of minimum standards for securing information assets that support grid reliability and market operations and the physical environments in which these assets operate. FERC proposes to require all public utilities that have tariffs on file with FERC to self-certify by January 31, 2004 and by each January 31 thereafter, that they are in compliance with these standards. The self-certification form is contained in Appendix G to the NOPR. Additionally, on and after February 1, 2004, as a condition of receiving transmission service provided by a public utility that owns, controls or operates transmission facilities, a customer must demonstrate that it has a basic security program in place. This obligation of the transmission customer can be satisfied by supplying the public utility with an executed self-certification form. When SMD is implemented, FERC intends to impose this same requirement on any customer seeking to buy or sell through the ITP's markets.
Within 30 days after effective date of Final Rule:
All public utilities that own, operate or control transmission facilities must begin discussions with stakeholders and state representatives about how to implement and comply with the Final Rule, including selection of one or more ITPs and RSACs for a region; development of regional transmission planning and expansion program; development of long-term RAR and identification of load pockets where mitigation or appropriate infrastructure will be necessary.
By July 31, 2003:
Interim Tariff to be filed by all transmission entities, to be effective by September 30, 2003.
Rate changes warranted by the InterimTariff, to be effective 60 days after filed.
SMD Implementation Plan, plus status reports quarterly thereafter.
Within 6 months after effective date of Final Rule:
Transmission entities to begin regional transmission planning and expansion process and to complete plan within 12 months after effective date.
By December 1, 2003:
ITPs must file SMD Tariff and state date by which it will be implemented.
Rate changes warranted by the SMD, to be effective 60 days after filed.
By January 1, 2004:
Transmission entities must file NERC self-certifications.
By February 1, 2004:
Anyone desiring transmission service must provide NERC self-certification or alternative basic security plan to transmission provider.
By September 30, 2004:
SMD fully implemented.