I. Market Power Mitigation and Monitoring In Markets Operated By

The Independent Transmission Provider

1. Principles and Objectives

1. In a structurally competitive market, one with many buyers and sellers who cannot influence price, the market can assure an overall efficient outcome where prices indicate the value of additional supplies and conservation. The development of structurally competitive markets is the Commission's long-term goal. However, at this stage of the industry's evolution, wholesale electric markets are not yet structurally competitive in all respects. The two significant structural flaws are the lack of price-responsive demand and generation concentration in transmission-constrained load pockets. Given these structural defects, the Commission cannot rely on the interaction of supply and demand in all instances to ensure that prices are competitive and thus just and reasonable.

2. Cost-of-service regulation is not effective for spot market pricing of commodities such as electricity. In the past, customers were served by a monopoly supplier under cost-of-service rates, in which the fixed and variable costs of a company’s generation portfolio were allocated over the expected hours of service to determine a cost per kWh. But today, the power needs of load-serving entities are met through a mix of sources, including the companies' generation portfolios, and long-term and spot market purchases from a variety of sellers, including independent producers and marketers. These do not match the long-term arrangements needed for cost-of-service regulation. In this competitive context, cost-of-service regulation designed for long-term cost recovery is not well suited for determining appropriate spot market prices. When applied to spot markets, cost-of-service regulation blunts price signals and leads to inefficient investment and consumption decisions which over the long run increase costs for all customers.

3. When markets do not produce competitive outcomes, the Commission must use new regulatory tools to produce just and reasonable results. We propose new market power mitigation measures to deal with the consequences of major structural defects in wholesale electric markets, by approximating the outcomes that a competitive market would produce. These measures should function in markets that are not workably competitive, but not inhibit market operation in more competitive markets. Effective market monitoring and market power mitigation are critical elements of the Commission's plan to create and sustain competitive regional bulk power markets. Therefore, the Commission proposes rules for the spot markets to be operated by the Independent Transmission Provider to mitigate market power.

4. Market power is the ability to raise price above the competitive level.¹⁹5 This can be accomplished if the generator can withhold physical power (physical withholding) or cause physical power to be withheld through inflated bids (economic withholding).¹⁹6 Competitive prices over the long run should recover both the fixed and variable costs of efficient generating units. The challenge for market power mitigation on the supply side is to assure that it allows long-term competitive prices, which allows the opportunity to recover the fixed costs of the investment as well as the short-term variable costs of producing electricity. If some degree of scarcity pricing is not allowed, and generation only recovers short-term marginal costs, then some generators needed for reliability could fail to recover their full costs and may be retired. Worse yet, prices could be held so low that investors decline to invest in needed generation, transmission and demand-side projects because they do not see a reasonable expectation of recovering their costs.

5. The market power mitigation measures proposed here are designed to address the major structural defects in wholesale electric markets. The major structural defect on the demand side is the lack of price-responsive demand; when customers cannot respond to high prices by lowering their consumption, they cannot discipline price increases from suppliers. Absent demand response, market prices will reflect suppliers’ bids alone, so we cannot rely on market prices to ration scarce supplies in all situations. Therefore, the market power mitigation needs to compensate for the lack of price-responsive demand in the market.

6. On the supply-side, structural problems tend to be more location-specific and time-dependent. For example, binding and sometimes unpredictable transmission constraints may restrict competitive alternatives and create opportunities for some sellers to increase prices above a competitive level, at least for any seller that knows some of its output will be required to meet load reliably. This problem is often described as a load pocket problem. In some load pockets, a specific generator may be identified as needed for reliability, which gives it a local monopoly.¹⁹7 In other situations without severe constraints, the geographic market may be broader but if little generation divestiture or entry by non-affiliated generators has occurred, concentration of ownership may remain high. Market power mitigation needs to mitigate local market power, whether it arises because of a load pocket, transmission constraints, or ownership concentration.

7. To be effective, market power mitigation measures must be applied before the fact, since remedies after the withholding has occurred are disruptive to the market and increase regulatory risk to its participants, which increases costs to customers.

8. In sum, the challenge in developing an effective market power mitigation plan is to design a plan that allows markets to function where they are competitive and, where they are not, uses market mechanisms to facilitate the transition to competitive markets. Market mechanisms can be used to approximate the outcomes that a competitive market would produce to provide the price signals for efficient investment and demand response. Because of the characteristics of electricity (it can be stored only in limited instances – pumped storage, compressed air, batteries) and the electric grid (flows follow the path of least resistance), even in regions where markets are generally competitive, transmission constraints may create non-competitive conditions during certain hours. In addition, when market power exists, the market power mitigation plan should be calibrated so that it does not inefficiently suppress prices, or mask scarcity prices, providing the wrong economic signals for efficient investment or demand response.

2. Overview of the Market Power Mitigation Measures

9. 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.

10. The first measure addresses the local market power problem and is similar in concept to the reliability must run agreements that exist in the ISOs today. The market monitor will identify 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.¹⁹8 The conditions when their power must be supplied to the grid (a must-offer obligation) and the bid cap to apply would be specified in their participating generator agreement with the Independent Transmission Provider.

11. The second component, a safety-net bid cap such as the $1000 per megawatt-hour cap currently used in Northeast markets and Texas, addresses the lack of price-responsive demand. Sellers could freely offer any amount of energy to the spot markets constrained only by the safety-net bid cap. The safety-net bid cap should allow markets to produce prices that reflect some (and perhaps a significant) amount of scarcity when shortages of reserves or power exist. But absent demand response, it sets an outer bound on suppliers’ ability to exercise economic withholding.

12. The third component of the market power mitigation plan is the resource adequacy requirement discussed in Section J. The resource adequacy requirement does not directly prevent withholding, but by expanding the resource alternatives it diminishes the incentive and the ability of suppliers to practice and profit from either physical or economic withholding.

13. While it is clear that the first three measures must be part of the Standard Market Design market power mitigation plan, there may 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. Exercise of this mitigation could be triggered by predetermined conditions or triggers (such as a sustained period of prices significantly above competitive levels), or by significant infrastructure problems in the market (e.g., sustained tight reserve conditions, as might be due to drought). This mechanism is like the Automatic Mitigation Procedure (AMP) used by the New York ISO, and adopted recently for the California ISO. This mechanism would not be required for every region but may be adopted if the market monitor's analysis determines this measure is needed.

14. The implementation of the market power mitigation plan summarized above and described in more detail below will rely on the results of an initial competitive market analysis by the Independent Transmission Provider's market monitor in each region. This will identify at the outset the persistent load pockets or other conditions that create local market power. This analysis will be filed with the Commission as part of the implementation process for Standard Market Design and subject to comment from all interested parties. After Commission review, it will form the basis for the mitigation measures that are applied by the Independent Transmission Provider. It then will be updated annually to review the continuing effectiveness of the market power mitigation.

15. The market power mitigation measures proposed rely principally on mitigating market power in spot markets. Mitigation would only apply to products traded in the spot markets operated by the Independent Transmission Provider, not to products traded under bilateral contracts outside the Independent Transmission Provider’s spot markets. This is the least intrusive framework for market power mitigation but at the same time provides very effective protection against market power.

16. Although power and operating reserves purchased in the organized spot market are only a small percentage of total purchases, mitigating the organized spot market is an effective way of mitigating market power generally.¹⁹9 Bilateral contracts generally reflect buyer and seller expectations of prices in spot markets. Therefore, market power mitigation in the organized spot market will effectively discipline market power in bilateral markets as well.²⁰0 However, if spot market prices are over-mitigated, it may weaken incentives for buyers to contract in bilateral markets and expose spot market prices to greater price volatility. Regular reassessment of the market power mitigation practices can prevent this outcome, and, as discussed infra, the market monitor will be required to annually reassess the effectiveness of the market power mitigation.

3. Market Power Mitigation For Local Market Power

17. 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. Local market power can arise from both persistent and foreseeable congestion, or from sporadic transmission congestion. Although local market power can arise from these different conditions, the mitigation method proposed here can be effective at mitigating the local market power regardless of how it arises.

18. In the existing ISOs in California and the Northeast, participating generator agreements are used to set out the operating terms, conditions and obligations concerning the dispatch of a generating unit, serving principally a reliability purpose. Under the Standard Market Design pro forma tariff all generators dispatched by the Independent Transmission Provider would enter into a participating generator agreement.²⁰1 Standard Market Design will require these participating generator agreements to include provisions to mitigate local market power.

19. The 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. The requirement would apply when the generator's power is needed to maintain the reliable operation of the grid, and also when there are insufficient competitive alternatives. The participating generator agreement 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.²⁰2 The capped bid could also set the market clearing price.

20. In addition to the bid caps specified in the participating generator agreements, local market power also will be limited through bilateral contracts between load-serving entities and the generators. Under the resource adequacy requirement, load-serving entities must have enough resources to meet their demand to ensure the reliability of the grid. It can be expected that some of those resource requirements will need to be fulfilled with contracts with generators within their load pocket to ensure that the resource is deliverable during peak or congested periods. Bilateral contracts are an effective way for a buyer to mitigate the market power of a seller.²⁰3 The load-serving entities can be expected to include provisions in these contracts specifying when a generator must run to meet any reliability needs in that location and the price to be paid. Whenever a generator is scheduled to run under a bilateral contract, this will fulfill its must-offer obligation in the participating generator agreement with the Independent Transmission Provider.

1. Under the participating generator agreements, when conditions are not competitive, that is, when there are insufficient alternatives available to meet load in that location, a generator must run to provide all its available capacity to the grid, either by scheduling a bilateral transaction or bidding into the spot market. 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.²⁰4

1. The Commission invites comment on how to structure the local market power mitigation, particularly on how to define the noncompetitive conditions which should trigger the mitigation, and on how bid caps should be structured for generators operating under a participating generator agreement.

2. There are some options for dealing with the risk of a forced outage inside a load pocket. One is for a portion of available day-ahead capacity to be exempt from the bid-in requirement to reflect forced outage risk in real time. Another possibility is 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. A third option would vary depending on whether the generator receives a reserve capacity payment. 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. The Commission requests comment on the penalty that would be appropriate to deter unjustified forced outages.

4. The Safety-Net Bid Cap

3. If bid-in capacity is generally insufficient to meet both operating reserve requirements and load, capacity rights associated with the resource adequacy requirement may be exercised by load-serving entities that have secured sufficient capacity so that they will not be interrupted. However, in this situation, lack of demand response can result in dramatic increases in market-clearing prices, even with comprehensive mitigation on the supply-side, if imports can bid in at unrestrained levels. In this case, imported power from adjacent markets could set a market-clearing price above the marginal cost of the highest cost unit dispatched within the market.²⁰5

Current markets in the Northeast and Texas rely on a $1000 per megawatt-hour bid cap, regardless of market conditions, as a safety-net that may be binding in this situation. The Commission proposes to adopt a safety-net bid cap as part of the market power mitigation plan here. 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. In California, for example, imports are not allowed to set the market clearing price. However, in the market power mitigation framework proposed here 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 Resource Adequacy section. A safety-net bid cap, such as the $1000 per megawatt-hour cap in the Northeast and Texas, can serve as a proxy scarcity price under Standard Market Design. The Commission requests comment 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.

4. Comment is requested on how to determine an appropriate value for such a cap. It is important to examine the implicit trade-off between bilateral capacity payments, the safety-net bid cap and local market power mitigation. That is, a bid cap that constrains scarcity prices would be expected to translate into higher bilateral capacity payments under a contract to fulfill the long-term resource adequacy requirement. With a higher safety-net bid cap, perhaps one based on the value of lost load, smaller bilateral capacity payments would be required to maintain the same level of resource adequacy in the absence of price.

5. Mitigation Triggered by Market Conditions

5. 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. For example, extreme supply or demand conditions to which the market cannot quickly adapt, such as the loss of significant hydropower capacity because of drought, or force majeure events such as a major transmission line outage. These kinds of events, which are not transitory, can provide opportunities to exercise market power even in a market that is normally workably competitive. It may be appropriate for other conditions to trigger this mechanism. We seek comment on what these triggers should be. Although market- clearing prices would be expected to rise in these situations, and perhaps sharply and significantly, it may be important for the market to have the assurance that the price increases are attributable to the extreme circumstances and not to the exercise of market power. An AMP mechanism such as those approved by the Commission in New York ISO and California could provide this kind of assurance.²⁰6

6. This kind of mechanism may not be necessary in every region. If a market monitor proposes such a mechanism, the proposal must include the specific triggers that would be used to initiate this form of market power mitigation along with the details of the mitigation method. Since this form of market power mitigation is for temporary market conditions, it will be equally important for the market monitor to indicate the criteria to determine when the market has returned to normal competitive conditions and this market power mitigation method will be suspended.

7. The details of this market power mitigation method, including the triggers, would be set out in the Independent Transmission Provider's tariff. If market conditions developed that satisfied the pre-determined triggers for the mechanism, it would be the market monitor's responsibility to give notice to the public and the Commission that the tariff mechanism had been triggered. The mechanism would then automatically take effect until the conditions developed that satisfied the pre-determined triggers for the suspension of this market power mitigation mechanism. If a market monitor proposes to use this form of market power mitigation, the details of the mechanism and the triggers would be subject to comment by all interested parties, and review by the Commission.

6. Establishing Bid Caps or Competitive Reference Bids

8. The mitigation for local market power, through the participating generator agreements, relies on must-offer obligations to mitigate physical withholding and bid caps to mitigate economic withholding. Mitigating economic withholding entails determining appropriate bid caps for all bid-in parameters.²⁰7 The unit-specific bid caps in the participating generator agreements serve as proxy competitive bids for energy, regulation service, and operating reserves, and for other unit-specific operating parameters such as minimum run times and high and low operating levels. Bid caps should reflect the marginal cost – including opportunity cost – of offering all capacity, including power that may be supplied only under limited conditions. Other bid-in parameters should reasonably reflect operating conditions consistent with good engineering practice under competition.

9. 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. Nevertheless, this mitigation plan would require that each generator, including hydropower and energy-limited units, that may have local market power would need to have an agreement establishing bid caps for all bid-in parameters if its power is needed for the grid or local market power mitigation is necessary.

10. The Commission has approved several options for setting default energy bids that in some circumstances serve as energy bid caps. They include: (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; and (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, similar to PJM's approach for mitigating reliability must run units.²⁰8 Although fossil-fired units may have opportunity costs not fully reflected by operating costs, an adder, such as that used by PJM, is one way to allow flexibility to respond to these uncertain costs. The Commission requests comment on whether the level of the adder should be reviewed on a region-by-region basis or if the Commission should establish a uniform adder, and if so, at what level.

11. 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. The Commission requests comments on whether this approach or other adjustments to bid caps for peaking units might usefully substitute for demand response in the near term.

12. 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. Comment is requested on these and other approaches to establishing reasonable caps for energy bids.

13. Another alternative for hydropower, and other energy-limited resources, would be for the unit operator to submit a seasonal or monthly schedule for when the unit would not be expected to operate. This would enable, for example, hydropower units to specify the periods when they would expect to need to preserve water or flow water to satisfy environmental conditions. While these units have many legitimate competing needs for the water flow, it is still possible for a hydropower generator to engage in physical or economic withholding. In the existing ISOs, generators must submit a schedule for planned outages, which is coordinated by the ISO to ensure that outages occur when they are the least disruptive to the markets. The Independent Transmission Provider is expected to continue to perform this outage coordination function under Standard Market Design. Scheduling outages in advance, coupled with auditing by the market monitor, would provide a way to evaluate whether failures to run were from withholding or legitimate limitations. For hydropower units, for which the marginal costs are primarily opportunity costs, this method may be a sufficient check against withholding so that it might be unnecessary to have a bid cap for these units. The Commission requests comment on these alternatives.

14. Any parameters that a generator may include in its bid may require a cap or other restraint. For example, PJM caps regulation service at $100 per megawatt-hour, and New England uses energy prices to cap prices for spinning reserves. Standard Market Design would also allow availability bids for these products. The participating generator agreements should also contain bid caps for these operating reserves when they are needed for the operation of the transmission system and non-competitive conditions exist. However, the Commission requests comment on how to identify the options for determining competitive bid caps for regulation service and operating reserves, including availability bids, that should be established for day-ahead and real-time markets.

15. In the New York and PJM day-ahead markets, the unit-specific energy bid cap applies to the day-ahead market where separate bids for start-up and no-load costs are also available and would also be available under Standard Market Design. Market power mitigation should also establish caps for these bids and a variety of bid-in operating parameters, such as low and high operating levels and minimum run times, if non-competitive circumstances would permit sellers to manipulate these parameters to get unjustified higher up-lift payments. PJM, for example, does not mitigate the start-up and no-load bids or certain operating parameters, but it only allows units to change these values once every six months. New York permits greater flexibility and uses various screens to assess whether a seller is behaving non-competitively and should be mitigated.

16. Several approaches could be used for establishing bid caps for these particular parameters. One possibility would be to rely on engineering data, such as from the manufacturer about the specific type of unit, to establish caps for start-up and no-load bids and certain operating parameters, and give generators the flexibility to bid within those ranges without mitigation. These ranges would also be included in the generators' participating generator agreements. Just as with energy bids, a bid above the range could be mitigated if the bid raised market-clearing prices or uplift payments above a competitive benchmark level by a significant amount. Because factors that might cause generators to modify start-up and no-load bids and parameters such as minimum run times generally are thought to be less variable than factors that may influence energy bids, caps for these variables may be quite tight.²⁰9 In fact, PJM's approach to permit changes to these parameters once every six months may be a simpler alternative that does not unduly restrict competitive generator behavior. Comment is requested on this approach and on other ways to prevent sellers from manipulating these bids and operating parameters to increase market-clearing prices and uplift payments.

17. In the implementation filing, the market monitor would propose tariff language that sets forth the process for setting the bid caps for individual units or any formulas that might be used for this purpose. The market monitor would be responsible for collecting and verifying data from these units to establish appropriate caps for energy bid values consistent with the procedures in the Independent Transmission Provider's tariff. This could be controversial, especially for generators in load pockets that may effectively face "mitigation" in most situations. The Commission requests comment whether the Commission should establish a formula for determining the bid caps or whether the Commission should review the proposals developed in each region.

7. Exemptions

18. 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. Sellers with little capacity would have little incentive to exercise market power since a non-competitive bid could eliminate their only unit from the dispatch. However, the Commission requests comment whether any other sellers should be exempt from the mitigation because they have insufficient incentives to withhold.

8. Monitoring

19. 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 Independent Transmission Provider, to permit easy access to the market data and operations personnel, or it may be physically located elsewhere.

20. The market monitor will be expected to report directly to the Commission, and the independent governing board of the Independent Transmission Provider. This will include reporting at regular intervals on the general performance of the markets in its region and reporting, on a timely basis, observed attempts at market manipulation or factors that impair the efficiency of the market. 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 Independent Transmission Provider and the Regional State Advisory Committee. This will enable the committee to carry out its advisory functions in an informed manner.

21. The market monitor must focus both on the functioning of the markets run by the Independent Transmission Provider as well as the conduct of individual market participants. The market monitor should focus on identifying factors that might contribute to economic inefficiency. Such factors include market design flaws, inefficient market rules, entry barriers to new generation, including distributed generation, barriers to demand-side resources, transmission constraints and market power. In monitoring for exercises of market power, the market monitor should focus principally on detecting economic and physical withholding (as distinct from the normal operation of supply, demand, and true scarcity). For entities that own both transmission and generation assets, withholding behavior could include both generator and transmission outages. For example, instead of directly withholding a generator's power, a market participant with transmission assets could effect the same end by derating a transmission line needed to deliver the generator's power to the market. Monitoring should be designed to detect this kind of behavior.

22. The Commission requests comment on whether the market monitor should also be responsible for monitoring the Independent Transmission Provider's operations, in addition to the markets and the market participants. Specifically, should the market monitor evaluate whether the Independent Transmission Provider treats market participants neutrally, without undue discrimination?

23. To meet its responsibilities, the market monitor must have the ability to collect and evaluate necessary data provided by the Independent Transmission Provider and market participants. The market monitor would have the responsibility to propose to the Commission, and the Independent Transmission Provider's board changes to market rules, if they provide inefficient incentives to market participants, and to promptly identify circumstances that may require additional market power mitigation so that remedies can be put in place prospectively.²¹0 The market monitor would also be required 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. In addition, the market monitor must also annually assess the effectiveness of any mitigation actions taken and review the terms, conditions, and bid caps in the participating generator agreements. Finally, the market monitor must engage in surveillance to insure that market participants comply with the rules in the Independent Transmission Provider's tariff.

24. The work and findings of the market monitor must be integrated into the regional planning process. The market monitor's analysis of the markets will identify load pockets and can help provide direction for needed investment in generation, including distributed generation, demand response capability, and transmission infrastructure to improve the competitive structure of the markets.

25. The Commission proposes here the basic elements of a market monitoring plan to be used by each market monitor. The Commission staff will convene a conference in the Fall to discuss and further develop the essential elements that should be required in a standard market monitoring plan. After getting additional public input at the conference, Staff may propose additional detail for the market monitoring plan, which the Commission may adopt, after an opportunity for public comment.

a. Framework for analyzing market structure and market conduct

26. 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. Examining this core set of issues using techniques reflecting "best practices" would be an essential part of the monitor's responsibilities that allows inter-regional comparisons. However, specifying these core requirements here should not prohibit or discourage monitors from expanding their analyses where regional differences or unanticipated events warrant it. In fact, because markets and monitoring are in a formative stage, the Commission would need to continue to facilitate communication between market monitors to share insights and develop common approaches.

27. An important focus of market monitoring will be structural market conditions since the Commission's ultimate goal is to foster structurally competitive regional bulk power markets. Academic analysts and market monitors have examined the competitiveness of current spot markets using various approaches and data. Some have focused on developing a simulated competitive benchmark that can serve as a reasonable measure of the market's overall efficiency.²¹1 Others have examined whether specific generator bidding behavior has been consistent with profit maximization under competitive conditions.²¹2

28. Some monitors have estimated whether average generator profitability would cover costs of a gas-fired peaking unit and provide sufficient inducement for entry.²¹3 Most monitors also track bidding patterns so that sudden, inexplicable changes can be investigated promptly to evaluate whether market power is a cause of the change.²¹4 Monitors also track changes in concentration, unplanned generator and transmission outages, and changes in various operating parameters that may signify market power problems.²¹5 Although the reports have been very useful in enhancing our understanding of a wide range of issues, the approaches have been varied, key questions have been framed differently and, importantly, the markets have not had the same design. As a consequence, results have not been comparable across markets. With the widely varying market designs of the past, greater comparability across regions was not feasible. However, these analyses have served as a useful starting point for developing a standard analytical framework.

29. 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. This analysis would be performed prior to the implementation of the Standard Market Design, in order to implement the market power mitigation. It also would be performed annually to reassess and adjust the market power mitigation, and to evaluate the conditions of the market.²¹6

30. In addition, the Commission proposes to require an annual assessment of the performance of the markets operated by the Independent Transmission Provider. This assessment would use a competitive benchmark to assess market performance as an additional means of assessing the effectiveness of the market power mitigation.

31. Comment is requested on how the monitor should address these and other topics, to develop useful measures that permit inter-regional comparisons. For example, concentration measures stratified by generator type might better identify competitive alternatives under various demand conditions. Estimates of generator profitability, such as PJM and ISO-New England have used in the past, might be a useful measure of incentives for generator entry. These estimate the degree to which a hypothetical unit operating in all profitable hours would have recovered its costs. Although it is not a definitive profit estimate for any particular generator, it may be a useful measure for comparing incentives for generator entry across market or regions.

32. A core set of questions and analytical techniques must also be developed for monitors to use to evaluate conduct of market participants in the transmission and spot markets operated by the Independent Transmission Provider. Analysis of generation and transmission outages is central because these can be forms of withholding. Because some owners of generation also own transmission, monitors must review any planned transmission outages, for example, to make sure that scheduling outages could not be used to enhance or create opportunities to exercise generator market power. Analysis of generator conduct might also include a review of bidding behavior in the spot markets operated by the Independent Transmission Provider to identify any auction design flaws that may give market participants an unanticipated incentive and ability to manipulate market-clearing prices or up-lift payments. The monitor should also evaluate the effectiveness of the participating generator agreements in mitigating market power where market structure is not sufficiently competitive.

33. Finally, 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. The monitor must also assess whether those who collect congestion revenues are in a position to influence transmission expansion plans that can affect congestion revenues and report on the incentive structure of those arrangements.

34. Any flaws in the market rules that may be identified by the monitor and any market participant conduct that indicates the ability to exercise market power under the market rules in effect would be remedied prospectively after Commission authorization of changes to the market rules. However, if the conduct violates existing rules, the market monitor must have the necessary tools to investigate the conduct and to penalize it. These will be discussed in the sections below.

35. 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 Independent Transmission Provider to include in its tariff certain minimum behavioral rules, which will be monitored by the market monitor. These will include, at a minimum, the following rules:

(1) Physical Withholding: Entities may not physically withhold the output of an Electric Facility (Generating unit or Transmission Facility) by (a) falsely declaring that an Electric Facility has been forced out of service or otherwise become unavailable, or (b) failing to comply with the must-offer conditions of a participating generator agreement.

(2) Economic Withholding: Entities may not economically withhold by submitting high bids that are not consistent with the caps specified in the tariff or the participating generator agreements.

(3) Availability Reporting: Entities must comply with all reporting requirements governing the availability and maintenance of a Generating Unit or Transmission Facility, including proper Outage scheduling requirements. Entities must immediately notify the Independent Transmission Provider when capacity changes or resource limitations occur that affect the availability of the unit or facility or the ability to comply with dispatch instructions.

(4) Factual Accuracy: All applications, schedules, reports, or other communications to the Independent Transmission Provider or the Market Monitor must be submitted by a responsible company official who is knowledgeable of the facts submitted. All information submitted must be true to the best knowledge of the person submitting the information.

(5) Information Obligation: Entities must comply with requests for information or data by the Market Monitor or the Independent Transmission Provider that are consistent with the tariff.

(6) Cooperation: Entities must assist and cooperate in investigations or audits conducted by the Market Monitor.

(7) Physical Feasibility: All bids or schedules that designate resources must be physically feasible within the limits of the resource, i.e., the resource is physically capable of supplying the energy, ancillary service, or demand response needed to fulfill a schedule or bid according to the physical limitations of the resource.

36. These rules must be accompanied by predetermined penalties, as discussed below in the Enforcement section.

b. Data Requirements and Data Collection

37. 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. They 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.

38. 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. These data when combined with information acquired in the normal course of business operations and schedules for planned outages should give monitors the information they need to fully analyze the competitiveness of the markets operated by the Independent Transmission Provider.

39. 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. Since the ability of the market monitor to perform his or her monitoring role is dependent upon the ability to acquire the necessary information, the monitor must have the ability to require market participants to provide information. This is an important enforcement tool. The Independent Transmission Provider's tariff should specify the penalties that would apply to market participants who fail to comply with an information request from the market monitor. Market participant objections to market monitor information requests will be resolved by the Commission on an expedited basis because delays in providing information could result in continuing harm to the market. In any such dispute the Commission will give substantial deference to the market monitor's stated need for the information.

40. All information obtained by the monitor that is specific to a market participant would be treated confidentially. Any disputes concerning how the confidential information could be used would be resolved by the Commission, before the data are released to the public. Since the Commission has oversight responsibility for wholesale electric markets, any data collected by the market monitor would be available to the Commission and the confidentiality of the data would be protected by the Commission under its regulations.

c. Reporting Requirements

41. 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 report would also include a discussion and analysis of any region-specific issues that the monitor judges important to achieving a competitive outcome. This could also be particularly useful to the planning process in determining where expanded transmission capacity might reduce market power problems in load pockets. The annual report would be made public, with appropriate protections to maintain confidentiality, if necessary.

42. In addition, the market monitor will be required to report to the Commission, through the Office of Market Oversight and Investigation, any instances of conduct by market participants that appear to be inconsistent with the Independent Transmission Provider's tariff. Early reporting of questionable conduct will permit coordination between the market monitor and the Commission's investigative staff to determine the best methods for developing the facts and addressing conduct that could be harmful to the market.

43. The Commission requests comment whether additional reporting requirements are needed.

d. Enforcement of the Tariff Rules

44. 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. However, to ensure effective enforcement, the market monitor must have adequate authority to investigate market participant conduct and the Independent Transmission Provider must have a set of predetermined penalties to apply to conduct that is in violation of the rules of the Independent Transmission Provider's tariff.

45. As a condition of participating in the markets operated by the Independent Transmission Provider and using the transmission grid operated by the Independent Transmission Provider, the Commission proposes to require market participants and transmission customers to agree to predetermined penalties that would apply to violations of the tariff rules. Since the tariff rules are intended to ensure the fair and efficient operation of the markets, the penalties should be designed to deter conduct that is inconsistent with the fair and efficient operation of the markets. Specifically, the penalties should deter conduct that results in an economic benefit derived from a violation of the rules. The penalties should, at a minimum, require payment of the economic benefit derived by the violator from violating the rules. Where the violation could result in conduct that could be harmful to the reliability of the grid, it would be appropriate for the penalty to be significantly higher to serve as a deterrent for the conduct. The Independent Transmission Provider's tariff must specify the conditions that would apply for each level of penalty.

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. The Commission requests comment on the conditions that would justify mitigation of the penalty.

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1⁹⁵The Commission's natural gas pipeline cases have used a definition of market power that examines the company’s ability to raise prices significantly above a competitive level for a sustained period. Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines, 74 FERC ¶ 61,076 at p. 61,230 (1996); and cases cited id at n. 52. See also, Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines, 70 FERC ¶ 61,139 at p. 61,403 (1995) (concerning transportation and storage services). These factors recognize that it is difficult to identify market power with precision, both because it is difficult to precisely identify the competitive price (which should recover both fixed and variable costs over the long run) and because it can be difficult to isolate the impact of one entity on the competitive price. These factors also recognize that there is an implicit cost/benefit assessment to decisions to intervene in the exercise of market power. The cost of intervention in transient price increases could be greater than the public benefit gained by the intervention. Commission decisions about when to intervene in an exercise of market power are important, but need to be tailored to the circumstances of the product and the industry. In the electric industry, electricity prices can spike for one hour or a few hours in ways that are less likely for natural gas pipeline transportation and storage rates, and the consequences can be quite different. Since the definition of market power and the decision when to intervene in its exercise are analytically distinct issues, in this rulemaking the Commission incorporates the concept of when to intervene in an exercise of market power into the choice of triggers for the market power mitigation mechanisms, rather than in the definition of what constitutes market power.

1⁹⁶Market power can also be exercised by creating barriers to entry so other suppliers cannot reach the market or by causing other supplier's production costs to increase.

1⁹⁷This is also true for certain types of ancillary services (e.g., reactive power) where specific generators may have the ability to exercise market power because of their location.

1⁹⁸This would include a broader group of units than what are often referred to as reliability must run units.

1⁹⁹Stoft, Steven. Power System Economics. New York, NY: Wiley-IEEE Press, 2002, Section 2-4.5, "How Real-Time Price-Setting Caps the Forward Markets," p. 150.

2⁰⁰Relying on mitigating market power in the spot market has been an effective mitigation method in the New York ISO under its AMP, and the California ISO since May, 2001.

2⁰¹SMD Tariff Section A.9.2.

2⁰²SMD Tariff section F.1.11. The generator's legitimate minimum run times would also be honored under the provisions of SMD Tariff section F.1.5.

2⁰³See Comment of the Staff of the Bureau of Economics and the Office of the General Counsel of the Federal Trade Commission, Docket No. RM01-12-000 (July 23, 2002).

2⁰⁴Under the Standard Market Design tariff, all units scheduled day ahead under a must-offer obligation, but not needed in real time would get paid their start-up and no-load costs.

2⁰⁵Generators outside the region would not have participating generator agreements with the Independent Transmission Provider, with provisions for addressing local market power, and neither would marketers.

2⁰⁶See California Independent System Operator Corp., 100 FERC ¶ 61,060 (2002). See New York Independent System Operator, Inc. et al., 99 FERC ¶ 61,246 (2002). Although AMP was in effect in all of New York, it was only triggered on four occasions, reflecting conditions in eastern New York.

2⁰⁷These same considerations would apply if the Commission adopted an AMP-like mechanism with bid caps or competitive reference bids.

2⁰⁸This method may not work for fossil-fired units that are only permitted to run a limited number of hours due to environmental restrictions. These energy-limited resources are discussed below.

2⁰⁹For example, energy prices could change frequently because of differences in the cost of fuels such as natural gas.

2¹⁰The changes would only go into effect after Commission approval.

2¹¹See, e.g., Borenstein, S., J.B. Bushnell, and F. Wolak (1999). "Diagnosing Market Power in California's Deregulated Wholesale Electricity Market." POWER Working Paper PWP-064, University of California Energy Institute, available in <http://www.ucei.berkeley.edu/ucei/pwrpubs/pwp064.html>.

2¹²Joskow, P.J., and E.P. Kahn (2001). "A Quantitative Analysis of Pricing Behavior in California's Wholesale Electricity Market During Summer 2000." NBER Working Paper No. W8157. National Bureau of Economic Research.

2¹³See, e.g., PJM Interconnection State of the Market Report 2000.

2¹⁴See, e.g., New York Market Advisor Annual Report on The New York Electricity Market for Calendar Year 2000, by David B. Patton, Ph.D., Capital Economics, April, 2001.

2¹⁵See, e.g., Annual Market Report, May 2000-April 2001, ISO New England, August 1, 2000.

2¹⁶The monitor should particularly pay attention to concentration in the regulation and operating reserves markets, and consider the amount of supply relative to demand, and propose specific market power mitigation measures for these markets if necessary.