The Federal Energy Regulatory Commission (“FERC”) Shakes Up Regional Markets

On July 31, 2002,the Federal Energy Regulatory Commission ("FERC" or "the Commission") issued a Notice of Proposed Rulemaking on Standard Market Design ("SMD" or the "GigaNOPR" or the "NOPR"). The rulemaking marks a sharp departure from Order No. 888 and Order No. 2000, by imposing more federal influence in the development of regional competitive markets. FERC notes that SMD is intended to remedy some of the continuing problems that have persisted despite Order No. 888 and 2000, such as the exercise of transmission market power by vertically integrated utilities; the fact that 60% of load (bundled retail load) is not served under the FERC pro forma tariff, but rather under various state rules, leading to seams problems; and inefficiency in the marketplace.

Fundamental elements of the SMD include active monitoring and mitigation to prevent market abuses, a well-organized central spot-power market that complements a decentralized contract-based market for long-term power supplies, and price discovery and market transparency. SMD calls for a major overhaul of the current pro forma transmission tariff such that there will no longer be separate service for network and point-to-point transmission. Instead, features of both will be combined into a new service: Network Access Service. In addition, public utilities that own, control, or operate interstate transmission facilities must either become Independent Transmission Providers ("ITPs"), turn their transmission facilities over to an Independent Transmission Provider, or contract with an ITP to operate their facilities. The ITP will be any public utility that owns, controls, or operates facilities used to transmit electric energy in interstate commerce and must also administer day-ahead and real-time energy and ancillary services markets in connection with its provision of transmission service pursuant to the SMD tariff. It must also be completely independent of any market participant in the region in which it provides transmission service. In addition, Locational Marginal Pricing ("LMP") will be used for transmission congestion management and also will provide tradable financial rights, known as congestion revenue rights.

Although the tariff filing and market-operating requirements only apply to public utilities, there are a number of references throughout the NOPR to "load serving" entities, which include cooperatives and municipals and others with contractual obligations to supply capacity, energy and/or ancillary services to retail customers. In particular, load serving entities are required to be included in the regional resource adequacy requirement, and would be subject to enforcement actions for violation of such requirements.

The 600-page NOPR encompasses many different topics and this summary provides the highlights of significant provisions. It necessarily will not provide advice to the reader, but will call attention to various areas for which FERC has requested comments. Features of the NOPR include plans of the Commission to: (1) place transmission service bundled retail customers under the same terms and conditions of service as wholesale transmission service; (2) revise the existing pro forma tariff to remove provisions that grant preferential treatment to transmission service for bundled retail customers (the "interim tariff "); (3) require all public utilities that own, control or operate interstate transmission to file interim tariffs no later than July 31, 2003 (to become effective September 30, 2003); (4) require all ITPs to file the new SMD Tariff by December 1, 2003,to become effective by September 30, 2004; (5) require that only ITPs would operate Commission-jurisdictional facilities, no later than September 30, 2004, or such date as the Commission may establish; ITPs must be totally independent of any market participant in the region; (6) network Access Service is required to begin no later than September 30, 2004; (7) require ITPs to operate a day-ahead and real-time market for energy; (8) require customers to be given Capacity Revenue Rights ("CRR") for their historical uses that protect against congestion costs when specific receipt and delivery points are used, in order to provide customers with a mechanism for achieving price certainty; (9) require a regional transmission planning and expansion process, within six (6) months from the effective date of the Final Rule, to provide a backstop process for ensuring that needed transmission construction is undertaken; (10) require the ITP to operate market power mitigation measures for the spot markets; (11) permit small entities to seek a waiver of the Final Rule requirements; and (12) require the Wholesale Electric Quadrant of the North American Energy Standards Board, working closely with ITPs, to produce business practice and electronic communication standards.

The Commission is holding a series of public meetings to discuss the SMD NOPR. Written comments on the SMD NOPR are due November 15, 2002, with reply comments due December 20, 2002. There are numerous places throughout the NOPR where the Commission seeks specific comments.

The Commission proposes that all public utilities that own, control, or operate facilities used for the transmission of electric energy in interstate commerce to meet the definition of an ITP, turn over the operation of its transmission facilities to a Regional Transmission Organization ("RTO") that meets the definition of an ITP, or contract with an entity that meets the definition of an ITP to operate its transmission facilities.

All public utilities that own, control or operate interstate transmission are required to file interim tariffs no later than July 31, 2003 (or may request waiver if public utility is already member of an approved RTO or ISO that meets definition of ITP). As noted above, an ITP is 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).

An ITP must file the SMD Tariff to provide transmission services, including ancillary services, and to administer the day-ahead and real-time energy and ancillary services markets; perform market monitoring and market power mitigation, long-term resource adequacy and transmission planning and expansion on a regional basis; file any changes to transmission rates necessary to implement Standard Market Design.

The Commission proposes that six stakeholder classes be represented in the ITPs’ Boards of Directors: (1) generators and marketers; (2) transmission owners, including vertically integrated utilities; (3) transmission-dependent utilities (those utilities that must take transmission service from public utilities to provide retail service to their customers); (4) public interest groups, including consumer advocates, environmental groups and citizens’ groups); (5) alternative energy providers, including distributed generation, demand response technologies, and renewable energy; and (6) end-users and retail energy providers, including load-serving entities that do not own transmission or distribution assets. A separate Regional State Advisory Committee would advise the board. A market participant, and all of its affiliates, would be permitted to have a representative in only one stakeholder sector.

The Board of Directors should have collective experience in the following areas: risk management; generation planning and operation; technology and innovation; senior corporate leadership of a major publicly traded company; professional disciplines of finance, accounting or law; electrical engineering; regulation of utilities; transmission system operation or planning; trading or risk management; information technology; and generation planning or operation.

Regarding selection for Boards of Directors, the Commission proposes that a nationally recognized search firm be retained by the nominating committee to identify at least two qualified candidates for each available board seat. A nominating committee composed of two members from each stakeholder class would review the list of candidates and each committee member would have the right to cast votes equal to the number of open board seats, but not more than one vote for any one candidate could be cast. Board seats would be filled by a simple majority, and board members would then vote to designate one member as Chairman of the Board. The Commission proposes that board members have staggered terms, with half of the first board having initial terms of four years and the rest with terms of three years. The same process used to fill the initial board would be used to fill empty seats. No board member would be permitted to serve longer than two consecutive terms. Board members may not have any financial interests in market participants; stocks or bonds owned by newly elected board members must be divested within six months of election to the board.

Board members or their immediate families should not have current or recent ties (within the last 2 years) as a director, officer or employee of a market participant, or its affiliates, in the region. Board members, their immediate families and senior management will be required to fill out annual financial disclosure statements.

In the event of mergers of ITPs, the new Board of Directors would be composed of equal representation from each former organization plus an equal number of new board members. The new members would be selected using the same process described above, but the nominating committee would be composed of two board members from each of the merging companies and the Chairs of two committees representing market operations, reliability and/or management.

The Commission proposed that to eliminate undue discrimination, the transmission component of bundled retail service must be taken under an open access transmission tariff. Under the current pro forma tariff, a utility is supposed to designate the resources it uses to serve bundled retail customers in the same manner as wholesale customers are required to designate network resources under network service. SMD would create a new, universal form of transmission service. The new transmission service tariff combines elements of the existing network and point-to-point services available under Order No. 888, and allows all wholesale power sellers to use the grid as much as transmission owners do. Point-to-point service would be eliminated as a stand-alone service. All transmission users will be able to schedule power deliveries using multiple receipt and delivery points, providing the same operational flexibility enjoyed by transmission owners.

Designations of network resources would be used to convert service used to meet retail obligations, while the existing level of service would be provided pursuant to the new Network Access Service. The load serving entity or the retail customer would receive either CRR or the auction revenues for these rights for the currently designated resources.

Until the new tariff is in place, the Commission proposes to require bundled retail load to be placed under the existing pro forma tariff. However, a number of sections 1 of the existing pro forma tariff must be modified to implement these changes. Public utilities will be required to file revisions to their tariffs and execute service agreements to take network service on behalf of their bundled retail load no later than July 31, 2003. Further changes, as clarified in several previous Commission orders, would require a customer to submit a request to roll over its contract no later than 60 days prior to the date the current service agreement expires; would require that the public utility may only deny a customer its right to roll over a contract due to future load growth if the public utility includes in the original service agreement a specific, reasonably forecasted need for the transfer capability to serve load growth for the network customers at the end of the term of the service agreement; and would require that long-term firm customers who request to use alternate point(s) of receipt or delivery would retain the right of first refusal for service at the original point(s) of receipt and delivery at the time the current service agreement expires.

The new transmission tariff will combine features of both network and point-to-point services. It will be grounded in the flexibility of network service but will add a measure of reassignability similar to that available under firm point-to-point. In addition, it will give all customers the opportunity to have tradable CRR. These rights entitle the holder to receive specified congestion revenues in the day-ahead market.

Under SMD, network access service will be available to all eligible customers, and allow load-serving entities to choose to serve load with any available resource on the system (or access any interface to import power from a neighboring system). It would allow a customer to have the ITP integrate, dispatch and regulate the customer’s current and planned resources to serve its load as is currently done under the pro forma tariff. Customers can also use service for through-and-out service, to aggregate resources for resale, and to perform hub-to-hub transactions similar to point-to-point. Customers would be permitted to trade (reassign) CRR. In addition, the customer would be allowed to access points, which, under the current pro forma tariff, are secondary points that may be fully subscribed, by paying all applicable congestion charges. The customer would have the right to transmit power between any number of combinations of receipt and delivery points, and would be able to substitute receipt points on a daily or hourly basis through the day-ahead and real-time scheduling processes. Only those customers taking power off the grid would pay the access charge. All customers would pay congestion costs and losses associated with their particular transaction.

With Network Access Service, all customers who want physically feasible service will be able to receive service; however, uncertainty can arise as to the rate paid to receive the service. In addition to the access charge, the customer would be subject to the cost of congestion between its chosen receipt and delivery points. To achieve certainty with respect to price and avoid congestion costs, the customer would have to acquire the CRR associated with its specific receipt point-delivery point combinations(s).

Conditions for receiving service would be largely unchanged from those under the existing pro forma tariff. Additionally, the customer must agree to pay any congestion charges and transmission losses associated with its request, and any customer serving load located within the ITP’s system must agree to pay the applicable access charge.

Under the new tariff, CRR can be acquired through direct allocation that is based on some measure of current or historical rights to the system, periodic auctions, or some combination of these methods. Transmission service will be schedule through the day-ahead market with deviations accounted for in the real-time market. This is comparable to the existing pro forma tariff. The Network Access customer must indicate the location of its receipt and delivery points when its schedules service in the day-ahead or real-time markets. If a customer holds CRR between a set of receipt and delivery points in the day-ahead market, but later decides to take transmission service between a different set of points, the customer could incur different congestion costs. To the extent that a customer’s real-time transactions differ from its day-ahead schedule, the customer would be liable for any redispatch costs that occur in real time that are necessary to accommodate its real-time transactions.

Under the proposed SMD, the reservation of capacity for service is no longer required. There is no longer a need for a customer to designate network resources to get transmission service. A customer will now request receipt and delivery points through the day-ahead scheduling process and real-time transactions.

Under the existing pro forma tariff, choosing alternate resources to meet load required placing a request in the queue for new service. With Network Access Service, this process is no longer necessary. A Network Access Service customer can access any point simply by requesting it through the day-ahead scheduling process or real-time transaction (and be willing to pay congestion costs and losses). To the extent the customer wanted to avoid the cost of congestion for the transaction, it could retain its existing CRR and acquire additional CRR for its new receipt and delivery points through an auction or secondary market. Alternatively, the customer could request a "reconfiguration" of the CRR it holds, i.e., the customer could turn in the CRR for the old receipt and/or delivery points and request CRR from the new receipt point or to the new delivery point.

Most service requests will be resolved through the day-ahead security-constrained dispatch. Nevertheless, the ITC will conduct system impact and/or facilities studies for service involving the interconnection of a new load or generator, and routinely perform simultaneous feasibility studies to determine the configurations of CRR that can be accommodated. Sections of the existing pro forma tariff addressing various studies will remain largely unchanged except to add references to the simultaneous feasibility studies.

Under the existing pro forma tariff, load shedding and curtailment procedures were developed for inclusion in individual network operating agreements. These will be included in the SMD Tariff. When system conditions require curtailment (in real time) that cannot be resolved through the congestion management system, the ITP should curtail the customers whose transactions contribute to the constraint on a pro rata basis. To the extent the ITP is unable to schedule all requests for service made through the day-ahead scheduling process, those customers with CRR for their requested receipt point-delivery point combinations should be scheduled first.

The ITP can assess a penalty for failure to curtail if a transmission customer fails to curtail after reasonable notice. The proposed penalty is the locational marginal price plus $1000 per MWh. The Commission has approved a minimum notice period of ten minutes if the curtailment is for reliability purposes.

The Commission has required transmission providers to incorporate the Transmission Loading Relief Procedures developed by NERC as a single generic amendment to the pro forma tariff. Under Network Access Service, procedures for addressing non-discriminatory curtailment of parallel flows will continue to be needed under emergency conditions when the use of the proposed regional congestion management procedure does not completely relieve a constraint. Language has been added to the SMD Tariff to reflect this.

A feature of the new tariff is the provision of CRRs, and the ability to trade or reassign them. CRRs may be acquired directly from the ITP, through a formal auction, or through secondary markets. A customer may sell them at any time to another entity, whether or not that entity intends to transmit power, and the sale could be for all or a portion of the amount or duration of the rights. All resales of rights must be reported on and conducted through the OASIS, and must be traded at the price at which purchasers value the rights.

Ancillary services provided as part of the existing pro forma tariff will largely remain the same. But certain ancillary services will be provided through organized markets with appropriate market power mitigation.

Additional changes must be made to the pro forma tariff in the areas of capacity benefit margin, regional and independent calculation of available transfer capability and performance of facilities studies and OASIS, the regional planning process, modular software design, transmission facilities that must be under the control of an ITP.

The Commission proposes to standardize the treatment of Capacity Benefit Margin ("CBM") to ensure that only customers benefiting from it pay for it, and transfer capability needed to access resources on a neighboring system is treated consistently with all other portions of the transmission grid. An ITP itself would not be permitted to set aside transfer capability for generation reliability reasons. A load-serving entity wanting access to resources on a neighboring transmission system to meet its resource adequacy requirement should instead acquire CRR from the interface to its load to ensure that access. The prohibition does not apply to an ITP’s responsibility to set aside transfer capability to ensure transmission reliability, i.e., Transmission Reliability Margin.

Under SMD, calculations of transmission capability and the performance of facilities studies for transmission expansions must be performed by an independent entity to reduce the opportunity for preferential treatment by the transmission provider. Transmission capabilities must be calculated regionally. All transmission providers that are not part of a Commission-approved RTO must contract with an independent entity to perform transmission capability calculations on a regional basis. The Commission also proposes a common OASIS for the region.

Regional planning processes should be instituted within six (6) months of the effective date of the Final Rule and designed to identify beneficial transmission needed for both reliability and economic reasons to support regional markets and reduce the effects of generation concentration. All public utilities that own, control, or operate transmission facilities must participate in a regional planning process for the planning areas listed below. The first regional transmission plan should be completed within twelve (12) months after the effective date of the Final Rule.

Multi-State Entities will preserve the states’ role in siting decisions. They will be an important component of the regional planning process. The Proposed Regional Planning Areas include: the area covered by the Western Electricity Coordinating Council; the area covered by PJM, MISO, and SPP; the area covered by New York ISO and ISO-New England; and the areas covered by the Southeastern Electric Reliability Council and the Florida Reliability Coordinating Council. The regional planning process will change as ITPs play a greater role. They must provide a review of all proposed projects to assess whether the project would create loop flow issues that must be resolved on a regional basis. No private investment sponsor for some projects that would benefit the region would be permitted. Private investment decisions in response to prices may not result in adequate expansions, and private parties may not be eligible to ask the state to exercise its eminent domain rights. Some needed and beneficial expansions may not create enough identifiable financial benefits to compensate private investors adequately. Therefore, parties will need to evaluate the benefits of alternative proposals and provide an independent assessment of which projects are the most cost-effective and/or have the least environmental impact.

The ITP will establish a mechanism for regional transmission planning and expansion guided by the following principles. (1) The planning process should identify all expansion needs on the system, including both reliability and economic needs. (2) The planning process should be open to all industry segments. (3) All entities could propose projects and would be free to complete the project as long as they are willing to assume any market or regulatory risk. (4) To the extent the entity sought to roll-in the costs of the facilities, the rate treatment should be reviewed through the planning process. (5) The ITP should have the responsibility to issue requests for proposals when the planning process determines that additional resources are needed to serve the regional market. (6) The ITP would approve transmission expansions that would be paid for by all customers only when planned private investments are judged to be inadequate to meet the reliability and market needs of the region. (7) If the bidding process fails and the ITP determines that additional facilities are needed, the affected transmission owner(s) would be required to expand or upgrade the transmission system. (8) The ITP would act as a clearing-house for the proposed projects. (9) The ITP would identify separate projects that could be constructed at a lower cost if the projects were combined. (10) The ITP would evaluate advantages of alternative projects.

The SMD software should have the following characteristics: transparency – the ability to understand what the software does; testability – the ability to understand and compare performance; modularity – the ability to change software modules without changing other software; and that input and output data systems and other Electronic Data Interchange be standardized in a common data model including a data dictionary and common network description.

The Commission proposes that its seven factor test (which identifies local (retail) distribution facilities) is the appropriate starting point for determining which facilities belong under the control of an ITP. Thus, if a facility is classified as transmission under the proposed test, then it belongs under the control of the ITP.

Customers currently taking transmission service under an OATT would continue to do so, but now would be served under the new Network Access Service under a revised OATT. Bundled retail customers would continue to receive service from their existing load-serving entity. But the load-serving entity would be required to take service under the new Network Access Service pro forma tariff in order to serve those retail customers. The proposed rule would allow certain regional flexibility in the implementation process to the SMD Tariff, including flexibility in converting the rights of existing customers to CRR or auction revenues under the new tariff, and flexibility in establishing the rate design for the new ITPs.

The Commission proposed the following process for the allocation of Congestion Revenue Rights. The ITP compiles a catalogue of all the existing long-term firm obligations for its transmission system that would still be in effect when Standard Market Design is implemented. This includes firm point-to-point service, firm transmission under pre-Order No. 888 contracts, designated resources for network transmission service pursuant to an OATT, and bundled retail load. For firm point-to-point, the existing rights would be those specified in existing service agreements. For network service and bundled retail transmission service, the existing rights would be limited to the designated resources in effect at the time, up to an amount equal to the customer’s current peak load since this would replicate the service the customer is currently receiving. CRR would go to the entity taking service under the ITP’s tariff. Customers would not be granted an initial allocation based on additional for future load growth, but would have to secure those rights. The catalogue of firm obligations would be subject to a simultaneous feasibility test. If all needs cannot be met simultaneously, then not all customers can have annual CRR equal to their peak usage, then the initial allocation would be limited to the amount that is simultaneous feasible. CRR could be allocated between customers on a pro rata basis or customers could be given the opportunity to change receipt points to achieve a simultaneously feasible result, or the CRR could be restricted to certain periods.

Two methods could ensure that current customers receive the value of their current contracts: direct assignment and auction with a revenue assignment of CRRs. Under the direct assignment option, for point-to- point customers, CRR would be for length of its contract. For network contracts and implicit contracts, customers would likely continue service for the foreseeable future (without a contract termination date). Under the auction option, the terms of CRR would vary. Initially, a set percentage would be auctioned on a monthly basis, another set percentage would be auctioned for six months and another for one year. Regions would be given flexibility in setting the initial terms sold in auctions. The Commission has expressed a preference for the auction of CRRs with some provisions. After a transition period, all ITPs would be required to auction CRRs. For an initial transition period of 4 years, regional flexibility is permitted.

The Commission will continue its approach to reciprocity and grandfather all reciprocity tariffs that the Commission previously found met the comparability standards of Order No. 888. Similar to Order No. 888, the Commission proposes to retain its reciprocity requirement. Under reciprocity, a non-public utility with transmission must offer comparable service to public utilities from whom it requires service.

The Commission recognizes that there may be a need to include liability provisions in the Commission’s pro forma tariff in circumstances in which there are no liability provisions available in a state tariff; however, at this time, it is not prepared to propose a specific provision. The Commission has included the current indemnification and liability provisions from the existing pro forma tariff in the SMD Tariff pending review of the comments.

The Commission proposes the following changes to transmission service pricing and pricing of transmission expansions: recover embedded transmission owners’ costs through an access charge assessed to load-serving entities based on their respective shares of the system’s peak load; eliminate all rate pancaking both within and between service areas; distribute CRRs to customers paying access charges, but only to long-term firm customers; assign a share of embedded costs to new load-serving entities that attract load from other suppliers; allow CRRs to follow the load; i.e., reallocate Congestion Revenue Rights to new load-serving entities which attract load from other suppliers; permit the use of license plate rates such as those that are currently in effect within ISOs;2 create a mechanism that recognizes the import/export quantities in establishing the revenue requirement to be recovered through the access charge.

FERC expressed a preference for participant funding for transmission facility expansion that benefits a remote region, where the beneficiaries of the project pay for it. In the absence of independence, a default pricing policy under which costs are rolled-in on a region-wide basis all high voltage network upgrades of 138 kV and above will be applied. Costs of network facilities below 138 kV should be allocated on a sub-region level. Regional State Advisory Committees to facilitate the siting of regional expansions will be formed, to enable states to work together to identify beneficiaries of expansion projects, and make recommendations on pricing proposals.

As part of the standard market design, FERC is proposing rules with regard to long term resource adequacy. The resource adequacy requirement will provide for timely development of supply and demand response resources to ensure regional resource adequacy, and will apply to load serving entities, as discussed above, and not be limited just to FERC jurisdictional utilities. FERC determined that a transmission operator must be able to balance generation and load at all times, and this requires having an adequate electric generating, transmission and demand response infrastructure. FERC therefore determined that a well designed resource adequacy requirement will support competitive markets if it allows suppliers to compete to provide infrastructure and buyers to choose the infrastructure with the best combination of features such as cost, reliability, environmental effects and service life.

The ITP will conduct the demand forecast. FERC notes that the demand forecasting has long been used in the utility industry to determine the need for future resources. The ITP should take a bottom up method of demand forecasting by adding up the demand forecast of its component areas through a collaborative process with all stakeholders.

Once the area’s demand is forecast, the ITP will assess whether the collective resource plans of load serving entities in the area are adequate to meet the projected peak need with allowance for adequate reserves. FERC noted that under Open Wholesale Transmission Access, regional patterns of energy flow can change quickly, making single utility transmission planning difficult. Generators sited in the utility service if not under contract may export power to another region. A regional assessment of regional power adequacy by one or more independent entities in the region will help overcome these difficulties. FERC therefore will require the ITP to provide assistance to a regional state advisory committee to establish the appropriate level of resource adequacy for the region.

Concerned about inadequate resources which could lead to poor market liquidity and shortages and with sustained high wholesale power prices, FERC proposes to adopt a 12% reserve margin requirement. A resource adequacy requirement can be satisfied by a combination of generation, transmission and demand response infrastructure. With regard to generation and transmission, the supply requirement could be satisfied by traditional generation, local distributed generation or firm bilateral contracts for power that are backed by specific generating units or portfolio of designated generation units. The firm bilateral contract could be either a forward contract for the purchase of power or an option to purchase energy under specified shortage or price conditions as long as the firm contract is backed by specified generating units. In all cases the generator must be committed to supply power to the load serving entity at least under certain conditions.

Besides generation and transmission assets, a better demand response infrastructure will also help satisfy this requirement. Demand responses must help ensure reliability, prevent a shortage that can produce a curtailment, act as a check against market power and provide a yardstick for the value that buyers place on supply. The ITP will determine if each load serving entity’s planned resources meet certain standards. The resources must meet the standards to count to satisfying the entity’s share of the regional resource requirement.

Grandfathered Contracts

Wholesale customers with pre-Order No. 888 contracts would be given the opportunity to convert to the new transmission service under a revised OATT; if they choose not to do so, the transmission owner that provides service under the pre-888 contract would be required to take service under the new Network Access Service pro forma tariff in order to meet its contractual obligations to service those customers.

If pre-Order No. 888 contracts remain in effect, the contracting transmission owner would be required to take service from the ITP. The ITP would assess the transmission owner for all charges and payments for providing the transmission service. The transmission owner would receive the allocation of initial CRR. If the ultimate transmission customer wanted directed allocation of the CRR, it could convert the contract (subject to any contractual limitations), so that the customer directly receives service through a service agreement under the SMD Tariff and would take service directly from the ITP.

During times of transmission congestion, all Independent Transmission Providers will allocate scarce transmission capability using a system of LMP and Congestion Revenue Rights.

Under the SMD proposal, the cost of redispatch is the basis for the congestion charges under LMP. Under LMP, the price to transmit energy between any receipt point and delivery point reflects the marginal cost (including the marginal opportunity cost) of such transmission service, and the price of energy at each location reflects the marginal cost (as reflected in participants’ bids) of producing energy and delivering it to that location. To implement LMP, the ITP must operate an energy market to determine the marginal cost of redispatch. The Commission proposes to require that the ITP operate both a day-ahead and a real-time energy market to manage congestion (See discussion of Day-Ahead and Real-Time Market Services). The ITP will establish separate energy prices at each node on the transmission grid and separate prices to transmit energy between any two nodes (receipt and delivery points) on the grid. All bidders will be paid a single market clearing price (and not what they bid). Specifically, the market clearing price is the bid of the last unit of supply needed to satisfy the demand, i.e., the highest bid that is accepted. The market clearing price at a location is paid to all suppliers at that location that are selected in the auction and is paid by all buyers at that location that purchase through the auction. The Commission’s LMP system will use a financial instrument called a Congestion Revenue Right to provide customers with price certainty for transmission service. Congestion Revenue Rights will ensure that the holder of that right will be protected against congestion costs for the transmission service covered by that right in the day-ahead. Once the day-ahead market closes, all customers pay for the service requested and, if they hold Congestion Revenue Rights, are paid congestion costs associated with those rights. Thus, the customer has bought and paid for a quantity of transmission at a specified price. Any changes a customer wants to make to the transmission service it has scheduled in the day-ahead market must be accomplished in the real-time market at real-time prices, which may be different from the day-ahead prices. All Customers will have to pay for transmission losses.

The ITP would be required to offer Congestion Revenue Rights for all of the transmission transfer capability on the grid, but it would not be allowed to sell more rights than can be accommodated. Customers under existing contracts will receive Congestion Revenue Rights that match their current use of the system, which will ease and simplify the conversion process from the existing tariff to the new Standard Market Design Tariff. The Conversion process will be done through compliance filings that allow for different treatment within each region. (The initial allocation process for Congestion Revenue Rights will occur before Standard Market Design is implemented, and is discussed in the Discussion of Transition to Single Transmission Tariff section). Once Standard Market Design is implemented, Congestion Revenue Rights would be available over a variety of terms, such as weekly, monthly, yearly and perhaps for longer terms. Once Standard Market Design is implemented, if an entity pays to construct new generation or transmission facilities that add transfer capability, and the costs of the upgrade are not rolled in, the entity would receive the Congestion Revenue Rights associated with the new transfer capability.

The Commission proposes that Congestion Revenue Rights be made available first in the form of receipt point-to-delivery point obligation rights. Receipt point-to-delivery point rights entitle the holder to the day-ahead congestion revenues associated with transmission service from the receipt point to the delivery point. In addition, during any period when the demand for transmission service cannot be met with Available Transfer Capability (i.e., because there are too many customers who have indicated that they want transmission service at any price), holders of receipt point-to-delivery point rights would receive priority over other market participants in scheduling transmission service between the receipt point and delivery points designated in their rights. Effectively, holders of receipt point-to- delivery point rights have a complete hedge against congestion between the designated receipt and delivery points. Later, the Commission proposes that Congestion Revenue Rights be made available in the form of receipt point-to- delivery point option rights and flowgate rights.

Receipt Point-To-Delivery Point Options – The difference between receipt point-to-delivery point obligations and options is important when congestion occurs in the opposite direction from the right, that is, when there is congestion from the delivery point to the receipt point. In this case, congestion revenues in the direction of the right are negative. Under a receipt point-to-delivery point obligation, the Congestion Revenue Rights holder in that case would be required to pay the negative congestion revenues to the ITP. Under a receipt point-to-delivery point option, the Congestion Revenue Rights holder would not be required to pay the negative congestion revenues to the ITP.

Flowgate Rights – A flowgate right specifies a portion of the transmission capacity over that flowgate in a specified direction. A flowgate right entitles the holder to the day-ahead congestion revenues associated with the specified power flows over the flowgate in the specified direction. Unlike a receipt point-to-delivery point obligation, 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 net economic value may be either positive (i.e., when the flowgate is congested) or zero (i.e., when the flowgate is not congested), but it would never be negative. The major market advantage of the flowgate right is that since there are fewer congested flowgates than possible under receipt-point-to-delivery-point rights, transmission customers can focus their rights on the key congested flowgates. However, because all of the power flowing between two points does not necessarily use the same flowgate, flowgate rights do not necessarily provide a complete hedge against congestion charges for a receipt point-to-delivery point energy transaction, since the congestion revenues may differ from the congestion charges.

Because there is no experience with offering point-to-delivery point options and flowgate rights, the Commission proposes not to require the ITP to offer them initially. However, upon the request of market participants, the ITP would be required to offer receipt point-to-delivery point options and flowgate rights as soon as technically feasible.

The aggregate amount of Congestion Revenue Rights issued by the ITP would be the amount simultaneously feasible based on Available Transfer Capability under normal operating conditions. However, this may lead to situations of over and under revenue collection. When a significant amount of transmission facilities are out of service, so that less transmission service can be provided, the ITP may collect less congestion charge revenue from transmission users than the amounts owed to Congestion Revenue Rights holders. In this circumstance, the Commission proposes that the customer that has a Congestion Revenue Right would receive full protection against congestion costs and the revenue shortfall would be assigned to the transmission owner whose transmission facilities are out of service. There would be an exception for outages due to force majeure events. When surplus revenues, if any, are collected the Commission proposes they be paid to the transmission owners. The Commission seeks comments on the potential of this policy to discourage transmission expansions and if alternative mechanisms should be used to distribute the revenue surplus.

Market participants would be allowed to resell any Congestion Revenue Rights that they have been awarded for the full term of the rights or for a part of the term. Resales could be transacted bilaterally between willing buyers and sellers.

ITP would be required to conduct periodic auctions of Congestion Revenue Rights. The auctions would provide the ability to reconfigure Congestion Revenue Rights into different receipt and delivery points, or into different types of rights in the auctions. Buyers and sellers would submit bids that specify the type of Congestion Revenue Rights desired to be bought or sold, the location, term and price. The ITP would select the combination of bids that maximizes the economic value of the transactions for the participants.

ITP would be permitted, but not required, to conduct pre-day-ahead auctions for energy and ancillary services, i.e., futures markets.

Participation in these pre-day ahead markets, as in all markets, would be on a voluntary basis.

By December 1, 2003 all Independent Transmission Providers will be required to file the SMD Tariff, including language that explains the Independent Transmission Provider’s proposals for market monitoring, market power mitigation, long-term resource adequacy, transmission planning and expansion, transmission pricing and any changes to the SMD Tariff necessary to accommodate regional needs. The filing must also indicate the date, which must be no later than September 30, 2004, or such date as the Commission may establish, when the ITP will be able to fully implement Standard Market Design. As a result of the changes required by the Final Rule, the ITP or transmission owners may believe that other changes are needed in their transmission rates for jurisdictional service. Transmission owners and Independent Transmission Providers should file these types of changes under the FPA at least 60 days prior to the date on which they propose to implement Standard Market Design. The Commission intends the implementation process to be a collaborative one. The Commission directs public utilities to meet with stakeholders and state commissions on a regular basis to discuss the changes that are necessary to comply with the Final Rule.

The Commission proposes that the ITP operate day-ahead and real-time markets for energy and certain ancillary services in conjunction with its scheduling of transmission service day ahead and in real time. These markets would allocate transmission and generation capacity among competing uses in different markets through LMP pricing.

Markets exist in the Northeast, Midwest and California. These markets have been established within the working ISOs/RTOs. Markets are not standardized. Transmission providers remaining outside the context of an RTO are not required to establish and maintain energy markets.

To implement LMP, the ITP must operate an energy market to determine the marginal cost of redispatch. Poorly designed market rules, or market rules with unforeseen or unintended consequences, can have a debilitating effect on markets, market pricing and overall confidence in the markets of the market participants. Only standardization of electricity market design will solve these problems. In the parts of the country in which markets are most mature, including the Northeast, Midwest and California, there is broad consensus on the principal elements of market design and business practices. A standard market design rule will help advance this process and extend it to other regions. The Standard Market Design rulemaking is intended to address and remedy many of the market design flaws identified to date and to raise the quality of all electric markets simultaneously.

The real-time price of energy is to be determined through a security-constrained, bid-based energy market. The Commission also proposes that the ITP operate a security-constrained, financially binding day-ahead energy market that is operated together with a day-ahead scheduling process for transmission service. The ITP will also establish hourly prices for certain ancillary services, which may differ by location to the extent that ancillary service requirements differ by location. Under the Commission’s proposal, buyers are not required to procure energy through the day-ahead energy market. A load-serving entity may procure all of its power through bilateral transactions, in the transmission provider’s spot markets, or by generating its own power. The Commission proposes to require Independent Transmission Providers to allow buyers and sellers to submit purely financial bids, a feature that currently exists in the day-ahead markets run by PJM and New York ISO. The day-ahead market would be financially binding. This means that a seller that is selected in the day-ahead market is obligated to actually provide the power in real time or in real time it will be charged the cost of procuring the shortfall through the real-time market. The day-ahead market is also financially binding on buyers.

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. A customer desiring transmission service would be required to submit a scheduling request in a standardized form specified by the ITP. To facilitate the ability of demand to respond to price signals, transmission customers will be given several ways of indicating their willingness to change their consumption based on congestion costs and marginal losses: (1) customers (whether or not they hold Congestion Revenue Rights) will be allowed to specify in their scheduling requests the maximum transmission usage charge at which the customer desires service; (2) customers will be allowed to specify the maximum congestion charge component of the transmission usage charge at which they desire transmission service, or above which they are unwilling to pay any congestion costs; and (3) customers (whether or not they hold Congestion Revenue Rights) could submit a bid that states a desire for transmission service to be scheduled regardless of the transmission usage charge. Customers will also be able to submit multi-hour block bids (specifying maximum aggregate charges not to be exceeded for the entire block, etc.).

The Commission proposes to treat transmission service across borders in the same way as internal transactions, i.e., scheduling of service consistent with internal transactions under Network Access Service (scheduling of transmission and financial bidding). The Commission also suggests a prescheduling option – up to eighteen (18) months in advance – so that the customer has certainty prior to the day-ahead market that it could transmit power across a border.

Transmission customers will be allowed to pay for their assigned losses either in cash or in kind. The Commission seeks comment on whether transmission customers should have the choice of paying for losses in kind, or whether all customers should be required to pay for losses in cash.

The ITP will be required to run a voluntary, bid-based, security-constrained day-ahead energy market. Each day, the ITP would accept bids to sell and buy energy for each hour of the following day. Participants desiring to sell or buy energy would submit a bid in a standardized form. Demand would also be permitted to bid in response to prices.

Based on the accepted bids included in the day-ahead schedule, the ITP would establish day-ahead locational energy prices for each hour. The hourly energy price at each location would reflect the marginal cost (as reflected in bids) of producing and delivering energy to that location in that hour. Energy prices would be consistent with the transmission usage charges, so the difference in energy prices between two locations in an hour would reflect the cost of transmitting energy from one location to the other. The ITP would establish a single market-clearing energy price for each hour for each node on its transmission system. The results of the day-ahead market would be financially binding on buyers and sellers. In certain instances, a generator may alleviate a voltage or stability constraint by producing real power and/or reactive power at its location. By alleviating the constraint, the transfer capability of the grid may be increased, thereby allowing a greater amount of lower-cost energy to be transmitted to an area with higher energy prices.

The four ancillary services that must be offered by, but need not be obtained from the ITP, include: regulation and frequency response, energy imbalance, spinning operating reserve, and supplemental operating reserve. These four ancillary services are in addition to two other ancillary services included in the Order No. 888 pro forma tariff, (1) Scheduling, System Control and Dispatch Services and (2) Reactive Supply and Voltage Control. Pursuant to the requirements of Order No. 888, transmission customers are assigned the responsibility for these ancillary services. Customers may meet their responsibility through self-supply, by procuring these ancillary services from a third party, or by acquiring them from the ITP. Imbalance energy would be provided through the day-ahead and real-time energy markets. For the remaining three ancillary services (regulation and both operating reserves), FERC proposes to require that the Independent Transmission Providers operate bid-based markets open to all potential suppliers so that Independent Transmission Providers can procure these ancillary services from the lowest cost suppliers.

Each day, the ITP would determine the total amount of each of the ancillary services that will be required for each hour of the following day. Customers that wish to meet their ancillary service requirement through self-supply or procurement through a third party would be required to provide the ITP with the necessary information about the generation capacity or demand-side resource that would be providing the ancillary services (as is currently required under the existing pro forma tariff).

To procure the remaining amount of ancillary services, the ITP would accept bids for regulation and the types of operating reserves for each hour of the following day. A participant desiring to sell regulation or operating reserves would submit a bid in a standardized form specified by the ITP. Bids could be offered to provide ancillary services from generation capacity or any demand-side resource that meets the technical requirements of the ancillary service. 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. To promote an efficient market, the price for regulation and operating reserves services would equal the marginal cost of each service, which would equal the highest accepted total bid cost expressed in dollars per MW. The hourly price for one of these ancillary services in a given location would thus equal the sum of the opportunity cost and the availability bid in dollars per MW of the most expensive unit accepted to provide that type of ancillary service in that hour to that location. Although suppliers bid to provide these ancillary services in the day-ahead market, customers pay for them based on real-time load.

After the ITP has established a day-ahead schedule and associated prices for energy, transmission service and ancillary services, it would make its own forecast of load within its market area for each hour of the following day. To the extent that its forecasted load exceeds the amount of energy scheduled to be delivered to load in the day-ahead schedule, the ITP may need to procure additional reserves (called "replacement" reserves) from generators to make up the difference, but only to the extent necessary to ensure that sufficient generation will be available to meet load. To procure replacement reserves, the ITP would accept bids from generators submitted for the day-ahead market.

Under Standard Market Design, the ITP would be required to operate bid-based, security-constrained real-time markets for transmission service, energy, and certain ancillary services (i.e., regulation, operating reserve -spinning and operating reserve - supplemental).

Under the Standard Market Design, the ITP would accept bids to buy and sell energy in each hour in the real-time energy market. The bids would be in the standardized form specified by the ITP. In general, bids would indicate an offer to depart in real time from the bidder’s day-ahead schedule to purchase or sell energy (including a day-ahead schedule to purchase or sell 0 MWhs of energy). Real-time bids would be accepted from any market participant, including generators, load-serving entities, eligible retail buyers, marketers and other agents. Bids would indicate the increase or decrease (in MWhs) from the day-ahead schedule in the amount of energy to be sold or purchased in real time, and the location and the hour of the changed purchase or sale.

The ITP would determine energy prices in the real-time energy market for each node for each 5-minute period or other subhourly period where a 5-minute determination is not technically achievable. To promote efficient participant decisions regarding real-time transactions, the Commission proposes that all departures in real time from the day-ahead schedule be settled through the real-time market at the applicable price (as is done today in many markets).

Under Standard Market Design, energy imbalance service would be provided through the transmission provider’s real-time energy market. The remaining three ancillary services would be provided in a real-time market administered by the ITP in which it would accept bids for each ancillary service. The real-time bids would contain the same types of information as those submitted into the day-ahead ancillary service markets, with one exception – availability bids for spinning reserves and supplemental reserves in real time would be excluded. The Commission reasoned that the types of costs reflected in the availability bid to ensure that the supplier will be available to provide these reserves are incurred in the day-ahead time frame, not in real time. There do not appear to be any incremental costs associated with providing these ancillary services in real time, other than the opportunity costs of forgoing sales in another market operated by the ITP, and these opportunity costs would be reflected in the way that ancillary service prices are determined. Transmission customers that have not self-supplied or procured through third parties their full assigned ancillary service requirement would be assessed a pro rata share of the costs incurred by the ITP for procuring ancillary services in real time.

The existing Order No. 888 pro forma tariff gives transmission providers the authority to curtail transmission service and take any other preventive action necessary to preserve system reliability. The SMD Tariff would continue to grant the ITP this same authority. However, the actions taken to ensure system reliability can affect prices in the energy and ancillary service markets. Market participants should be aware of how these actions will affect pricing in the markets operated by the ITP. To that end, the SMD Tariff requires Independent Transmission Providers to file proposals with the Commission regarding the implications for market pricing of each reliability procedure.

The Commission proposes a market power mitigation plan composed of three mandatory components that are specifically tailored to the structural flaws in the wholesale electric markets and a voluntary fourth measure that could apply in unusual market conditions to assure that the high prices are not the result of market power. The components include market power mitigation for local market power, the safety net bid cap, and a resource adequacy requirement (discussed earlier).

Market Power Mitigation for Local Market Power – Identifying certain conditions in which certain generators are in concentrated geographic markets created by transmission congestion or reliability needs of the grid. These would include units needed to run to support the reliable operation of the grid or a set of units owned by a small number of companies. At those times, those units will have localized market power so that when they are required to provide their energy or ancillary services to the grid their bids into the market should be capped.

The Safety Net Bid Cap – A safety-net bid cap such as the $1000 per megawatt-hour cap currently used in Northeast markets and Texas.

Besides, these three components, the Commission stated that there might be market conditions in which a fourth measure is needed. The fourth mitigation measure would deal with situations when non-competitive conditions may exist, by examining and possibly limiting bids from individual suppliers into the day-ahead and real-time spot markets if those bids are high due to withholding rather than scarcity. Mitigation would only apply to products traded in the spot markets operated by the ITP, not to products traded under bilateral contracts outside the Independent Transmission Provider’s spot markets.

Participating generator agreements, which would be filed with the Commission, would identify the non-competitive conditions when the generator with local market power would be required to offer its energy either by scheduling a bilateral transaction or by offering all available energy to the spot markets. This would be a must-offer requirement. Participating generator agreements would specify the conditions that would give rise to a generator’s must-offer requirement, and would also specify bid caps that would apply when the generator was required to bid into the day-ahead and real-time markets. In non-competitive conditions, the generator’s bids could not exceed the capped values. Although the participating generator agreement may restrict a generator’s energy and operating reserves bids, the generator would still receive a market-clearing price and additional revenue to cover start-up and no-load costs. With regard to the risk of forced outages inside a load pocket, the Commission outlined several options, including: (1) for a portion of available day-ahead capacity to be exempt from the bid-in requirement to reflect forced outage risk in real time; (2) to allow generators to provide all available capacity in real time at a capped bid in lieu of bidding in the day-ahead market to accommodate generators that have significant risk or opportunity costs; (3) if the generator receives a capacity payment, that payment compensates for the outage risk so the generator should be obligated to deliver energy or to pay for substitute supply from some other source. If the generator does not receive a capacity payment, then it should not have to bear the risk for a legitimate outage. Units declaring a forced outage would be subject to audit by the market monitor. If the outage is found to be unjustified, then the generator should be subject to a penalty.

A per megawatt-hour bid cap would be established, regardless of market conditions, as a safety-net that may be binding in this situation. Under this proposal, no bid to supply can exceed this level, regardless of cost or risk or location, even if the market is confronted with a genuine operating reserve shortage. However, if the monitor establishes that some units may provide power at a cost that exceeds the safety-net, a higher price for those units would be justified. Imports would be allowed to set the market clearing price in order to get a proxy for a scarcity price, up to a capped value. If requirements cannot be satisfied with bid-in imports that would be subject to the safety-net bid cap, then load that has not met its resource adequacy requirement should be penalized as described in the discussion of Resource Adequacy. The Commission requests comment on what the safety-net cap should be and whether the safety-net bid cap should be uniform across an interconnection, so that there would be one cap applicable in the East and another applicable in the West.

The Commission proposes a fourth voluntary market power mitigation measure which may be recommended by the market monitor during the Standard Market Design implementation process, or any time thereafter. This measure, if needed, would apply to unanticipated and sustained market conditions that would give the ability and the incentive to exercise market power. This measure would be put in place on the occurrence of certain conditions or triggers.

The development of bid caps, especially for generators with significant opportunity costs such as hydropower and energy-limited units, is difficult and can be controversial. The Commission has approved several options for setting default energy bids that in some circumstances serve as energy bid caps, including: (1) default bids based on various averages of previously selected in-merit bids; (2) default bids based on various cost measures, usually a measure of operating cost adjusted for fuel costs; (3) default bids agreed through contract or negotiation.

For many fossil-fired units, an estimate of operating costs plus a margin, such as ten percent, could provide a reasonable bid cap for a unit’s energy bid when competitive forces cannot be relied on. For peaking units that are likely to set market clearing prices when they are dispatched, the must-offer requirement coupled with mitigation that sets bid caps at marginal cost could result in revenues that fail to recover fixed costs over a reasonable period of time. Although such units may recover additional revenue in capacity and reserves markets, bid caps for these units could also reflect a "scarcity" premium or adder to compensate for the lack of price-responsive demand that would otherwise set the price when these units were dispatched. The average cost of a new peaking unit at a given location operated over a given number of hours could form the basis for setting such a premium. This kind of adjustment to bid caps for peaking units could help support reliability until demand-side measures for responding to price were more fully incorporated in markets.

For hydropower and other energy-limited resources much of the difficulty in determining an appropriate energy bid cap for these units comes from the difficulty of assigning a value to their temporal opportunity costs. However, the times when it would be necessary for the transmission provider to call on power from these sources are likely to be times when prices are high and these units would want to be scheduled in any event. At all other times, hydropower units, in particular, should be offering all available capacity as operating reserves since their marginal operating costs are close to zero, but they may have high temporal opportunity costs. In other words, there appears to be no economic reason why such units should not always be fully committed either to the bilateral market or spot markets for operating reserves. Consequently, it appears unnecessary to cap energy bids from such resources below the safety-net bid cap as long as their bids to provide operating reserves were always in-merit. Alternatively, other energy-limited resources might be allowed to submit a bid that states a total megawatt-hour availability over the day and allow the market operator to schedule the power from the unit in the hours when the price is highest.

It is appropriate to exempt certain sellers from the market power mitigation. Specifically, sellers who control a small amount of capacity in the market, for example no more than fifty megawatts, would be exempt from mitigation.

Market monitoring should be conducted on an on-going basis by a market monitoring unit that is autonomous of the Independent Transmission Provider’s management and market participants. The market monitoring unit may be located within the offices of the ITP, to permit easy access to the market data and operations personnel, or it may be physically located elsewhere. Although the market monitor will be accountable only to the Commission and the governing board, it should share its analyses and reports with the management of the ITP and the Regional State Advisory Committee. This will enable the committee to carry out its advisory functions in an informed manner. The market monitor must have the ability to collect and evaluate necessary data provided by the ITP and market participants. The market monitor would have various responsibilities, including: (1) to propose changes to market rules to the Commission and the Independent Transmission Provider’s board; (2) to provide a comprehensive analysis and report of market structure and individual generator conduct in the spot markets, at least annually, to evaluate the overall efficiency of spot market operations, the market for Congestion Revenue Rights, and how the balance between resources and demand in the region affects the market’s ability to efficiently serve load at least cost; (3) to annually assess the effectiveness of any mitigation actions taken and review the terms, conditions, and bid caps in the participating generator agreements; and (4) to engage in surveillance to insure that market participants comply with the rules in the Independent Transmission Provider’s tariff.

The Commission intends to require the use of a core set of questions and analytical techniques to be used by each market monitor to assess market structure, participant behavior, market design, and market power mitigation. This will facilitate inter-regional comparisons. The Commission proposes to require each monitor to perform a structural analysis of the region that would include: (1) market concentration including by type of generation; (2) conditions for entry of new supply; (3) demand response; and (4) transmission constraints and load pockets that give sellers the ability and incentive to exercise market power. In addition, the Commission proposes to require an annual assessment of the performance of the markets operated by the ITP. This assessment would use a competitive benchmark to assess market performance as an additional means of assessing the effectiveness of the market power mitigation. The monitor must analyze the operation of the congestion management system and the market for the resale of Congestion Revenue Rights for evidence of market power or manipulation. An important adjunct to the market power mitigation and monitoring plan will be a clear set of rules governing market participant conduct with the penalties for violations clearly spelled out. The Commission proposes to require the ITP to include in its tariff certain minimum behavioral rules, which will be monitored by the market monitor, including rules regarding: physical withholding, economic withholding, availability reporting, factual accuracy, information obligation, cooperation, and physical feasibility.

Data collection should be targeted to providing monitors with information necessary to answer the required questions covering critical issues regarding market structure, participant behavior, and market design. These data would be acquired from various public sources and in the normal course of operating the markets, and would include: (1) market statistics and indices, such as market-clearing prices and system-wide congestion costs; (2) data on system conditions, such as transfer capability and planned and forced outages; (3) information on other prices, such as fuel prices and prices in adjacent markets; (4) information on load served from the spot market; (5) data relating to generator bidding patterns; and (6) information on Congestion Revenue Rights. In addition, monitors must have the ability to obtain data on generator production and opportunity costs and information on the operating status of transmission and generation facilities that relate to claimed outages or deratings. Generator-specific data on all relevant costs and operating parameters – e.g., start-up, no-load, environmental, fuel, maintenance, ramp rates, low and high operating levels, and heat rates - may also be relevant to establishing appropriate bid caps for participating generator agreements. As a condition for participating in the spot markets, and using the transmission grid, market participants must agree to provide the market monitor with any information requested.

At a minimum, the monitor would be required to submit an annual report to the Commission and the Independent Transmission Provider’s governing board, and share that report with the Regional State Advisory Committee. The report 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 following guidelines described above; (3) an evaluation of the effectiveness of mitigation measures taken; (4) an overall assessment of market efficiency perhaps using a simulated competitive benchmark as some have developed; (5) an evaluation of barriers to entry for generating, demand-side, and transmission resources; and (6) any recommended changes to market design or market power mitigation measures to improve market performance.

The market monitor must play an important role in the enforcement of the market rules contained in the Independent Transmission Provider’s tariff. In this role the market monitor will need to coordinate closely with the Commission’s investigative and enforcement staff. As a condition of participating in the markets operated by the ITP and using the transmission grid operated by the ITP, the Commission proposes to require market participants and transmission customers to agree to predetermined penalties that would apply to violations of the tariff rules. It may be appropriate to build into the tariff standards for mitigating the penalty. Some standards that could be used are: the impact on the operation of the grid, the financial impact on the violator, and any good faith efforts to maintain compliance.

© 2002 Paul, Hastings, Janofsky & Walker LLP