New York's Capacity Market "Demand Curve" Dr. Thomas Paynter CPUC-CEOB-CAISO Installed Capacity Conference San Francisco, CA October 4-5, 2004

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1 New York's Capacity Market "Demand Curve" Dr. Thomas Paynter CPUC-CEOB-CAISO Installed Capacity Conference San Francisco, CA October 4-5, 2004 The New York Independent System Operator (NYISO), like other ISOs in the northeast, supplements its electric energy market with a separate market for installed capacity 1 (ICAP). In order to ensure reliable service, all load-serving entities (LSEs, including utility affiliates) are required to procure enough ICAP to serve their peak loads, including a reserve margin to cover generator outages. The ICAP market was expected to provide a more predictable revenue stream than the volatile energy market, and to better signal long-term investment needs. Unfortunately, ICAP prices proved as volatile as energy prices, and failed to encourage needed investments; moreover, the ICAP market appeared to be highly susceptible to market power abuse. After reviewing the performance of the ICAP market for over two years, the staff of the New York State Public Service Commission (NYPSC) determined that changes to the ICAP market were needed to ensure reasonable prices and adequate capacity. 2 In May 2002 the staff of the NYPSC proposed an ICAP "Demand Curve," under which ICAP prices would be explicitly linked to the supply of ICAP, with ICAP prices gradually falling as the supply of ICAP increased. The ICAP Demand Curve was designed to make the ICAP market operate as originally intended. PSC staff worked closely with all parties and staff of the NYISO to refine Principal Economist, New York State Department of Public Service (staff of the New York State Public Service Commission). Mark Reeder, Steve Keller and Harvey Arnett of the Department made invaluable contributions, but any mistakes are solely the responsibility of the author. The views expressed are those of the author and do not necessarily reflect those of the New York Commission or other staff. 1 Installed capacity is the maximum reliable output of a generator, measured in kilowatts (kw) or Megawatts (MW); 1 MW equals 1,000 kw. To encourage reliable operation, since November 2001 ICAP has been adjusted for historic outages to produce UCAP (Unforced Capacity), the measure used to determine payments. However, in this paper all UCAP prices have been converted to ICAP values for ease of comparison. 2 The NYPSC is charged with the responsibility to ensure that retail rates to consumers are just and reasonable and that service is safe and adequate. New York State Public Service Law 65(1)

2 the proposal, which was approved by market participants and the NYISO Board in early 2003 and by the Federal Energy Regulatory Commission (FERC) on May 20, The new design appears to be working as intended, yielding more stable and predictable ICAP prices that should provide better signals for long-term investment decisions; moreover, the new market design is much less susceptible to market power abuse. Despite its apparent success, the ICAP Demand Curve has been controversial. 3 Many commentators argue that, instead of repairing the ICAP market, we should get rid of it. 4 They claim that ICAP increases the cost of electricity without providing any benefits. They conclude that customers should pay only for energy, at an hourly price, and the market will take care of the rest. Other commentators want to retain the existing ICAP market, believing that market participants can work around its problems via long-term contracts. In this article we consider the economic rationale for the ICAP requirement and explore its impact on the wholesale energy markets. We review the treatment of capacity costs under regulation. Next we discuss the ICAP market established at the start of the NYISO, when New York's utilities divested their generation. The problems inherent in that design lead into the development of the ICAP Demand Curve. Finally, we speculate on future developments. Why Does the NYISO Require ICAP? The short answer is that the NYISO needs enough generating capacity to meet peak load. Electricity cannot be cheaply stored, so it is generated as needed to serve current load. Without enough installed capacity ("iron in the ground") to serve the peak load, some customers will face curtailments (e.g. rotating blackouts). Moreover, since generators sometimes break down, a reserve margin is needed to ensure reliability. However, there are many products that face capacity limits but get by without government-mandated capacity requirements. New Orleans hotel rooms are in short supply 3 See Bruce Radford, "New York Throws a Curve," in Public Utilities Fortnightly, May 15, 2003, pp ; see also my reply in Public Utilities Fortnightly, July 15, 2003, p In its Notice of Proposed Rulemaking on Standard Market Design, the Federal Energy Regulatory Commission listed a variety of objections parties had made to the entire concept of installed capacity. See Remedying Undue Discrimination Through Open Access Transmission Service and Standard Electric Market Design, 100 FERC 61,138 (2002) (SMD NOPR)

3 during Mardi Gras, yet New Orleans does not require the building of extra hotels to ensure that everyone gets a room. Airlines have limited numbers of planes, and on peak days some potential customers will get left on the ground, but the federal government does not demand extra planes to ensure reliability. Instead, the shortage is managed by raising prices. For example, consider the market for hotels in New Orleans. Hotel rooms are prevalent during off-peak periods, but fill up during peak periods such as Mardi Gras. During a peak period, hotel prices rise to ration the scarce supply. In effect, the only way to get a hotel room is to outbid other customers. The market price reflects the value of the room to the marginal customer, i.e. the customer who decided it was just too expensive. The high "scarcity prices" during periods of capacity shortage ensure that the rooms go to those who most value them, and the ample revenues at such times help pay the fixed costs of the existing hotels and encourage construction of new hotels. Absent an ICAP requirement, the electricity market might work much as the New Orleans hotel market, relying on scarcity pricing during periods of curtailments to help cover the fixed costs of existing generation and encourage construction of new generation. However, there are differences between the electricity and hotel markets that make reliance on scarcity pricing of electricity problematic. In most markets, a shortage of capacity is relatively predictable and can be rationed efficiently through high retail prices. New Orleans hotels charge more during Mardi Gras, and customers know this when they book the room, so they can decide whether they would prefer to visit another time. Airlines charge more on peak days; and if they overbook a flight, they can offer incentives to passengers to give up their seats, so the passengers who can most afford to postpone their flights will give up their seats voluntarily. In contrast, curtailment of electricity (absent real-time pricing) tends to be a blunt instrument, often consisting of blackouts with little warning and no opportunity for customers to choose when or how much to be cut. Shortages of electricity are typically caused by poorly predictable heat waves and unpredictable outages of large generators or transmission lines. Retail prices set months in advance cannot precisely signal these short-term shortages. Moreover, even if customers had time to respond by voluntarily curtailing load, they have little incentive to do so under current pricing arrangements. Most electric meters do not record the time of use, so LSEs cannot charge more for usage during periods of shortage. Because - 3 -

4 LSEs generally cannot use retail prices to ration supply, customers are stuck with involuntary curtailments (e.g. rolling blackouts) that turn off refrigerators, crash computers and leave them in the dark. The cost to customers, measured as the value of lost load, 5 is estimated to be very high, on the order of thousands of dollars per Megawatt-hour (MWh). 6 The high cost of curtailment also gives rise to market power concerns. When capacity is barely adequate, competitive wholesale prices reflect the operating costs of the most expensive generators, which are typically only a few hundred dollars per MWh. However, an actual shortage could lead to market prices ten times higher, reflecting the value of lost load. The potentially huge spike in prices might tempt large suppliers to withhold output in order to create an artificial scarcity. 7 Involuntary curtailments of electricity are so costly and inefficient that the industry developed reliability standards to minimize them, e.g. requiring enough reserves so that load curtailment (due to inadequate generation) should not occur more than one day in ten years. To implement these standards, in New York all LSEs were required to provide generating capacity equal to their forecast peak load plus a specified reserve margin, and demonstrate that these generators could actually produce their stated capacities. In addition, LSEs serving load in New York City and Long Island were required to purchase a large portion (but not all) of this capacity from local generation, in case transmission outages blocked imports from lower-cost regions. The Cost of Capacity The ICAP requirement can be thought of as a government-mandated thumb on the scale that increases capacity reserve margins. The extra capacity is typically provided by "peakers," i.e. units that can serve peak loads (or other infrequent use) to avoid shortages and load curtailment. These "peakers" have relatively high fuel costs, making them unsuited for 5 The value of lost load is the amount a customer would be willing to pay to avoid the curtailment. 6 A typical residential customer with air conditioning uses about one MWh per month. 7 Paradoxically, wholesale price caps that limit scarcity prices may reduce this temptation, potentially improving reliability. However, some level of scarcity pricing is needed to encourage the development of new peaking units and price-responsive load. New York has implemented a wholesale energy price cap of $1000 per MWh, which balances these and other concerns

5 routine use, but compensate by having relatively low fixed (non-fuel) costs. Examples of peakers include older, inefficient units that would otherwise be retired and new gas-fired combustion turbines. 8 The extra capacity reserves increase the cost of electricity, but only modestly. For example, if the annual fixed cost of peakers averaged $60 per kw, requiring an extra 10% reserves would add about $6 per kw of peak load. For New York State load, this would correspond to about $1.30 per MWh of usage, or about 2.6% of the total wholesale cost of electricity. 9 New York regulators believe the extra cost of an ICAP requirement is justified by the benefit of reducing involuntary curtailments, with their high value of lost load. 10 While the cost of an ICAP requirement is likely to be modest, its impact on wholesale market prices is profound. In the absence of a capacity requirement, all fixed costs would have to be recovered from scarcity prices in the energy market. The most inefficient peakers, that only operate a few hours per year, would have to receive enough revenues from the energy market during those few hours to cover their fixed costs. For example, if a peaker had annual fixed costs of $60 per kilowatt and operated just ten hours per year, it would require scarcity prices of $6 per kwh, or $6,000 per MWh, to cover its fixed costs. The problems associated with this level of scarcity pricing were discussed in the last section. With an ICAP requirement to reduce the chances of curtailments, scarcity pricing in the energy market is dramatically reduced. The peakers still must recover their annual fixed costs, but they no longer must rely entirely on scarcity pricing in the energy market. Instead, much of their fixed costs will be recovered through ICAP payments. The higher the ICAP price, the less scarcity pricing will be required by peakers. The extra revenue stream from ICAP payments 8 New combustion turbines are more energy-efficient than many older units, earning energy revenues that offset some of their fixed costs. Only their remaining fixed costs (after offsets for energy and ancillary services) should be counted as reflecting the cost of capacity. 9 New York State's summer peak load is about 32 million kw, and its annual electricity usage (excluding losses) is about 150 million MWh. Thus the average cost per MWh would be about $1.28 per MWh ($6 per kw * 32 million kw / 150 million MWh). This is about 2.6% of the statewide average wholesale price for electricity (about $50 per MWh in 2002). 10 If a competitive LSE were permitted to choose its level of capacity, it would have a strong incentive to procure too little capacity because of the free rider problem: while it pays the full cost of any extra capacity, the benefits of a more reliable system are shared with its competitors

6 enables the market to entice more capacity than would otherwise occur, thereby achieving the goal of enhanced reliability. 11 The same trade-off between scarcity prices and ICAP payments also applies to more efficient generation such as "base-load" plants (which operate around the clock to serve "base" load). Base-load plants provide the same capacity value as peakers in reducing curtailments and avoiding scarcity prices, so they should receive the same ICAP payments. Their ICAP payments will cover the portion of their fixed costs that otherwise would have been covered by scarcity pricing in the energy market. 12 As this discussion shows, most of the apparent cost of an ICAP requirement is simply a shift of fixed cost recovery from scarcity pricing in the energy market to the ICAP market. The net cost to customers is just the increased amount of capacity caused by the requirement. The cost of this is just a few percent of the wholesale cost of electricity, and must be evaluated against the reduction in costs of curtailments, which are not shown on electric bills, and which customers (and even LSEs) cannot avoid through their individual actions. Paying for Peakers: Cost Recovery under Regulation New York's ICAP requirement was developed decades ago, when generation was built and owned by regulated utilities. The minimum ICAP requirement ensured that each utility procured sufficient capacity to meet the one-day-in-ten-years reliability standard, without "leaning on" neighboring utilities. Utilities typically met their requirements by deferring retirements of older, inefficient units. The fixed costs of these old peakers (including most labor and other operating and maintenance expenses as well as taxes and insurance) were recovered through regulated rates. The (prudently incurred) construction costs of new units were included 11 For a discussion of the relationship between capacity reserve requirements, energy market prices, and generation capacity payments, see Eric Hirst and Stan Hadley, Maintaining Generation Adequacy in a Restructuring U.S. Electric Industry, ORNL/CON-472, Oak Ridge National Laboratory, October 1999, available at 12 Base-load plants typically have higher fixed costs than peakers, but they also have lower fuel costs. In a competitive market, base-load plants will receive the same market price for energy as peakers, and thus will earn a margin over their fuel costs during non-peak periods. This margin should be enough to compensate the base-load plants for their higher fixed costs. Thus base-load plants should not require any higher ICAP payments than peakers

7 in the utility's rate base and recovered over 40 years. Utilities often carried capacity in excess of their minimum requirements. Regulators accepted a reasonable level of excess capacity as insurance against higher-than-expected load growth or other unforeseen events. 13 Divestiture and the Deficiency Charge In the late 1990s, New York utilities divested most of their generation (selling to unaffiliated companies) as part of a restructuring of the New York electricity system. Owners of divested generation were no longer guaranteed recovery of costs. Instead of regulated rates, generators received market prices for energy, capacity, and ancillary services. Retail competition was also encouraged, with LSEs able to compete for customers throughout the state. While the energy market reflected the voluntary bids of buyers (LSEs) and sellers, the market for capacity was different. ICAP was a "public good" that provided benefits to the entire electric system, rather than to specific LSEs. The customers of competitive LSEs were so intermingled that the NYISO had no way to limit reliable service to those who had met their ICAP requirements. As a result, individual LSEs had no desire to voluntarily purchase ICAP, preferring to be free riders on the system. To overcome the free rider problem, the NYISO imposed a "deficiency charge," a severe financial penalty on LSEs that failed to procure their minimum ICAP requirement. The deficiency charge was set at three times the annual cost of a new gas turbine, to ensure that LSEs would find it cheaper to meet the ICAP requirement than to go deficient and lean on the system. ICAP Prices under the Deficiency Charge The graph below shows the NYISO's auction prices 14 for ICAP in upstate New York from November 2000 to April 2003, the period covered by the deficiency charge. Most auction purchases were via the 6-month voluntary strip auctions, covering the NYISO's summer (May- 13 For example, utilities might retain older oil- or coal-fired capacity as peakers. Besides providing extra supply for peak periods, such units provided fuel diversity in case of shortages of gas or other fuels. 14 Most LSE purchases were outside these auctions, via longer-term bilaterals, often established at divestiture. These generally reflected costs of capacity under regulation, at rates generally higher than the strip prices shown

8 October) and winter (November-April) periods. 15 LSEs could also purchase in the voluntary monthly auctions. If LSEs failed to procure their required ICAP for the coming month, they were required to purchase the deficient amounts in the deficiency auction, at a price capped by the deficiency charge. New York State ICAP Prices under Deficiency Charge $10.00 $9.00 $8.00 $7.00 $/kw-month $6.00 $5.00 $4.00 Strip Monthly Deficiency $3.00 $2.00 $1.00 $0.00 Nov-00 Jan-01 Mar-01 May-01 Jul-01 Sep-01 Nov-01 Jan-02 Mar-02 May-02 Jul-02 Sep-02 Nov-02 Jan-03 Mar-03 Month The graph illustrates some of the deficiencies of this market design. First, strip prices were surprisingly low: Prices in winter fell to $0.68 per kw-month, far below most estimates of the cost of capacity. 16 Second, monthly ICAP prices showed extraordinary volatility, ranging from a high of $6.50 to a low of $0.01 per kw-month, even though total supply of capacity had changed only a few percent. 15 New York's ICAP supply tends to be larger in winter months, because air-cooled turbines have greater capacity in cold weather. This tends to depress New York's winter ICAP prices. 16 The cost of new capacity was estimated in the neighborhood of $60 per kw-year or $5 per kw-month. Even old peakers often had fixed costs in the neighborhood of $1 per kw-month

9 Many market participants both buyers and sellers complained that they could not make rational business decisions in the face of such unpredictable market prices. For example, the spike in ICAP prices in May 2001 was so large and sudden that it drove some LSEs out of the market. 17 Yet prices spiked not because of a true shortage of ICAP, but only because out-ofstate sellers, discouraged by previously low ICAP prices, did not bother to bid into the market. Conversely, prices in winter were so low that some ICAP suppliers considered shutting down. This collapse in prices occurred despite the fact that supplies were only a few percent above the minimum requirement and the NYISO proclaimed a need for thousands of Megawatts of new capacity to meet forecast load growth. Vertical Demand Unfortunately, the extreme volatility of New York's ICAP market was inherent in its design. The deficiency charge created a fixed demand for ICAP equal to the minimum ICAP requirement. This could be characterized as a "vertical demand," as illustrated in the graph below (solid line). LSEs only wanted to buy the minimum required amount of ICAP (vertical line at 100%), and were willing to pay anything up to the deficiency charge ($9.58 in this case). Meanwhile, the supply of ICAP was nearly fixed (at least in the short run) by the available capacity, leading to a near-vertical supply curve. The combination of a vertical demand and a nearly vertical supply curve led inevitably to extremely volatile prices. When the market was in short supply, deficient LSEs had to pay the very high deficiency charge. If suppliers expected a shortage, they had no incentive to offer capacity at less than the deficiency charge. As a result, the entire capacity market tended to clear at a price equal to the deficiency charge, as illustrated on the graph below. Conversely, when the supply of ICAP was even moderately above the minimum level, competition among existing suppliers drove capacity prices down precipitously. This is illustrated on the same graph, where an "adequate supply" only 4% above the "short supply" causes the price to drop 80%, to $2. Suppliers often talked about the minimum ICAP requirement as a cliff, and used the term falling off the cliff to represent what happens to price when supply exceeded the minimum requirement. Although an ICAP supply a few percent 17 The deficiency in May 2001 resulted in over 1,300 MW clearing at the deficiency charge (then at $9.58 per kw-month)

10 above the minimum does not seem excessive, it nevertheless drove the market-clearing price down dramatically and placed no value on the benefit of the additional capacity (which went unsold, effectively receiving a zero price). Deficiency Charge (Vertical Demand) $/kw-month Demand (Deficiency Charge) Short Supply Adequate Supply ICAP Quantity (% of Minimum Requirement) In most markets, buyers would respond to low prices by increasing purchases. However, the ICAP market was distorted by the free-rider effect. LSEs had no interest in purchasing additional capacity because the benefits were socialized: LSEs who purchased more than the minimum would provide added reliability not only for themselves, but also for their competitors. Because of this free-rider problem, LSEs purchased only their minimum requirements; any additional supply went unsold, effectively receiving a price of $0. The lack of demand for any additional supply explains the extraordinarily low ICAP prices in the monthly and deficiency auctions: there were simply no buyers for any supply above minimum requirements. This contrasts sharply with the conditions under regulation, where additional supply was valued as a hedge against the vagaries of load growth, generator outages, fuel shortages, and other risks

11 The vertical demand signaled that the market should supply exactly the minimum capacity required, not a MW more or less. Any excess MW went unsold and tended to drive down the price for all capacity. The low prices would signal supply to shrink, until it was barely above the minimum requirement. Inevitably, some random event such as unexpected load growth or a forced retirement would create a deficiency and create a huge spike in capacity prices, yielding short-term bonanzas for generators and nightmares for consumers. Such a pattern of extreme volatility in prices and reliability in the capacity market harmed both producers and consumers. From the producer s perspective, it was difficult to make efficient investment or maintenance decisions based on extremely volatile and unpredictable capacity prices. This was especially problematic for higher-cost peaking units, which only operate during a few peak hours and therefore have limited, and unpredictable, earnings from energy sales. Moreover, this extreme volatility was likely to increase costs of capital, since suppliers could not demonstrate predictable revenue streams. These effects tended to increase the cost of supplying capacity, and ultimately the higher costs would flow through to consumers. Additionally, volatile prices made it difficult for consumers to budget for this essential product. The vertical demand also raised serious concerns about market power. Sellers exercise market power by withholding supply. 18 Withholding can drive the market price up enough to make it profitable for the withholding generator. This strategy is successful if the extra revenue a generator receives from the higher price for its remaining supply exceeds the lost profits associated with the supply that is withheld from the market. When existing supplies are only slightly above the minimum requirements, the vertical demand provided an enormous temptation for large suppliers to withhold some of their capacity from the market, in order to create a deficiency and drive the market price up toward the deficiency charge. For example, suppose the market had just "adequate supply," as shown in the graph above. If one supplier owned capacity equal to 8% of the minimum requirement, and sold it all, the ICAP price would be $2. However, if the supplier withheld half of its capacity, the market would be in "short supply" and the ICAP price would reach the deficiency charge of almost $ Withholding is accomplished either via a reduction in the amount of capacity that participates in the market (physical withholding) or via the pricing of a portion of one s capacity so high as to price it out of the market (economic withholding)

12 While the supplier sold half as much, the selling price would be almost five times higher, so ICAP revenues would more than double due to the withholding. If the withheld capacity were peakers, the supplier would not be giving up much energy revenues, so the withholding would be profitable. Moreover, the vertical demand might fail to encourage new generation even if a shortage occurred and prices reached the deficiency charge. If potential investors observed that there was only a moderate shortage, or if a deficiency was the result of withholding, then they might fear that adding new capacity would cause the price to fall off the cliff. As a result, investors might discount potential capacity revenues in deciding whether to finance new generation. This posed a bleak prospect for consumers, who could suffer inadequate reliability and pay extremely high deficiency charges to existing suppliers without effectively encouraging the new entry needed to provide relief. The ICAP Demand Curve Responding to the above concerns, changes to the ICAP market design were proposed by the NYPSC staff, approved by the NYISO's committees, and filed at FERC by the NYISO in March These changes were approved by FERC and successfully implemented in May The minimum purchase requirement and fixed deficiency charge were replaced by a gradually sloped Demand Curve, as illustrated in the graph below. The Demand Curve sets a price buyers pay that varies with the supply of ICAP. As more, or less, ICAP is offered, the price paid per kw gradually decreases, or gradually increases. 19 Under this proposal, LSEs may be obligated to purchase an amount of capacity above the minimum requirement level, but will pay a lower price in that case. The obligation to purchase above the minimum level (if the price is low enough) prevents prices from "falling off the cliff" due to a small excess of supply. The graph below illustrates the sloped ICAP Demand Curve (solid line). In this case, a short supply will cause prices to increase above the average cost of new capacity, but only by about 12% (to about $5.60), instead of spiking to the deficiency charge. On the other hand, a 19 Due to reliability requirements, whenever the auction clears at less than the minimum requirement, the NYISO is required to try to make up the deficiency via supplemental purchases. However, the price of the supplemental purchases is capped at the market price determined by the Demand Curve

13 small excess of capacity ("adequate supply") will cause only a moderate decline in prices (to about $4.20). Sloped Demand Curve $/kw-month 5 4 Demand Curve Short Supply Adequate Supply ICAP Quantity (% of Minimum Requirement) At the minimum requirement level, the Demand Curve sets a "reference" price equal to the estimated annual cost of ICAP (say $5 per kw-month). This is less than one-third of the deficiency charge, 20 thereby protecting customers from severe spikes in ICAP prices. Suppliers are compensated by being able to sell more than the minimum requirement, if they offer at sufficiently low prices. For example, if the supply of ICAP (offered at a low enough price) is 3% above the minimum requirement, LSEs will be obligated to purchase the extra 3% of the minimum requirement. However, the ICAP price will fall by 25%, signaling a "buyers' market." 20 In order to encourage new generation, the capacity market must provide a revenue stream to cover the annual fixed costs of a gas turbine that are not expected to be recovered through the energy and ancillary services markets. For example, assume that the annual (non-fuel) costs of a gas turbine, including return on and of investment, are $80 per kw-year, and that the gas turbine can be expected to achieve energy and ancillary services market net revenues of $15 per kwyear and $5 per kw-year respectively. In such a case, the capacity market need not provide the full $80, but only $60 per kw-year, or $5 per kw-month

14 Since the decline in price is greater than the increase in quantity, total LSE spending on ICAP will decline as supply increases. The Demand Curve for capacity represents a middle road in ICAP pricing between traditional regulation and the deficiency charge. Under the Demand Curve, as under traditional regulation, LSEs may purchase a larger quantity of ICAP than the minimum requirement. However, the Demand Curve price will gradually decline as supply increases, instead of holding constant as would regulated charges or falling precipitously as would prices under the deficiency charge. The reduced volatility of ICAP prices should help suppliers as well as LSEs. New merchant generation entrants and their investment bankers should be able to more easily forecast the future stream of capacity market prices. Existing generation owners should be able to make better investment, maintenance, and retirement decisions. Moreover, reduced volatility is likely to decrease costs of capital, since suppliers can demonstrate more predictable revenue streams. The Demand Curve also protects against abuse of market power. The slope of the Demand Curve determines the extent to which an act of withholding will raise the price. A sufficiently shallow slope can keep any such price rise small enough that even a fairly large supplier will find it unprofitable to withhold. In other words, the small price increase applied to its remaining sales would not compensate for the lost profits from its foregone sales. We can compare this result to the profitability of market power under the vertical demand. Suppose the market has just "adequate supply," as shown on the "Demand Curve" graph above. If one supplier owned capacity equal to 8% of the minimum requirement, and sold it all, the ICAP price would be about $4.20. However, if the supplier withheld half of its capacity, the market would be in "short supply." However, the ICAP price would rise only to about $5.60, instead of spiking to the deficiency charge of almost $10. While the supplier sold half as much, the selling price would increase by a third, so ICAP revenues would fall due to the withholding. 21 This result suggests that the withholding would not be profitable under the Demand Curve, in sharp contrast to the profitability of withholding under the vertical demand (deficiency charge). 21 ICAP revenues would fall by a third due to withholding in this case: If Q is the supplier's total capacity, selling all would yield revenues of $4.20 * Q, while selling half would yield revenues of $5.60 * Q/2 = $2.80 * Q. The reduction in revenues is 33% (-$1.40/$4.20)

15 Some parties objected that the Demand Curve is an administrative intrusion into the market. It is certainly true that the Demand Curve must be set administratively, but the same is true for the ICAP deficiency charge and minimum requirement. As explained above, the ICAP requirements both quantity and price must be imposed administratively because individual LSEs have an incentive to minimize capacity purchases and lean on the system. This market failure applies not just to the purchase of the minimum requirement, but also to the willingness to purchase more than the minimum. As long as customers face the threat of costly involuntary curtailments, administrative measures must be taken to deal with this threat to reliability. Another concern was that the Demand Curve might set ICAP prices that are too high. Much analysis went into estimating the cost of new capacity, which determined the Demand Curve's reference price. However, mistakes in the estimation will be largely corrected by the ICAP market itself. If the reference price are set too high, encouraging too much new generation, the resulting increase in supply will automatically drive down the market price (along the Demand Curve) until the price reflects the true cost of capacity. ICAP Prices under the Demand Curve Since the introduction of the ICAP Demand Curve in May 2003, the NYISO's ICAP spot market prices have become stable and predictable, as expected. Due to the northeast region's current excess supply of capacity, the NYISO received many offers of ICAP at relatively low prices from neighboring ISOs. As a result, the NYISO accepted the maximum quantity of imports allowed for ICAP purposes (2755 MW). The imports, when added to the in-state supply, yielded a total supply of over 106% of the minimum requirement, more than half-way down the ICAP Demand Curve. The result was summer spot market prices equal to less than half of the reference price, averaging $2.09 per kw-month. Winter spot market prices averaged $1.42 per kw-month (lower due to larger winter capacity from combustion turbines). The annual average spot price of about $1.75 per kw-month was higher than the previous year's (May 2002 April 2003) annual average strip price of $1.10 per kw-month, but below the $1.86 average for the prior year (May 2001 April 2002), and well below the average price for summer 2001 (boosted by the deficiency in May 2001)

16 New York State ICAP Prices under Demand Curve $10 $9 $8 $7 $6 $5 $4 $3 $2 $1 $0 Jun-03 Jul-03 Aug-03 Sep-03 Oct-03 Nov-03 Dec-03 Jan-04 Feb-04 Mar-04 Apr-04 May-04 Jun-04 Jul-04 Aug-04 Sep-04 Oct-04 $/kw-month Strip Monthly Spot Month While the ICAP Demand Curve only applies to the monthly spot market, its predictable price now provides a benchmark for forward auctions. Arbitrage between the forward and spot market auctions causes forward prices to reflect the expected spot market prices. During the year, spot prices have tended to drift lower as new supply enters the market. Moreover, New York enjoys greater ICAP supply during the winter period (November April), which depresses winter prices. However, demand increases each May based on that summer's load forecast (which determines the ICAP requirement for the next year), boosting ICAP prices. With the relative stability provided by the ICAP Demand Curve, developers should be able to better predict their ICAP revenues and finance needed new capacity. Future Developments The ICAP Demand Curve appears to have met its immediate objectives of reducing price volatility, reducing market power, and improving the transparency of the ICAP market

17 However, it remains to be seen whether the ICAP Demand Curve will meet its longer term objective of encouraging sufficient capacity to ensure reliability at reasonable cost. 22 The first step in ensuring this long-term objective is to reevaluate the parameters of the ICAP Demand Curve (reference price and length, i.e. point at which the price on the Demand Curve reaches $0). The reference price should provide sufficient ICAP revenues to encourage new capacity (when the system needs new capacity), taking account of revenues from sales of energy and ancillary services. The length of the Demand Curve should be sufficient to discourage withholding of capacity even by the largest suppliers (especially when capacity is close to the minimum requirement). The NYISO is currently reevaluating the parameters of the ICAP Demand Curves for New York State and the two localities (New York City and Long Island). A consulting firm (Levitan & Associates) is preparing an independent study which will inform discussions among the NYISO's market participants and the NYPSC. A NYISO filing to FERC to establish the parameters for 2005 through 2007 is expected by the end of this year. Some observers have questioned whether the financial markets will support merchant generation even if market revenues appear adequate. This has led to calls for LSEs to help shoulder the financial risks (although not to the extent under traditional regulation). In New York City, where capacity is especially tight, Con Ed has signed a ten-year contract to help finance the 500-MW Astoria SCS project. The NYPSC is evaluating its policies towards Providers of Last Resort, which might encourage regulated LSEs to purchase more of their supplies (both energy and capacity) in advance. However, the current surplus of capacity in much of the northeast region (outside New York) naturally depresses the market for new generation. Only time will tell whether merchant generation is viable. Finally, New York's supply of ICAP includes curtailable loads that meet ICAP requirements, designated as Special Case Resources (SCRs). 23 SCRs agree to curtail their load on short notice from the NYISO, during peak loads or emergency conditions, in exchange for ICAP payments. SCRs also are paid for the energy they curtail, provide energy bids and can set 22 See e.g. ESAI Capacity Watch, February 2004, pp SCRs also include distributed generation, such as emergency back-up generators, which are "behind the meter" and treated as load reductions by the NYISO

18 real-time market prices for energy, just like gas turbines. Typically, SCR energy bids are much higher than gas turbine energy bids, reflecting the relatively high cost of curtailing load. While the amount of SCRs is currently small, curtailable load provides a promising alternative to gas turbines for peaking capacity. Most capacity shortages occur in the real-time market, leading to severe price spikes in the real-time energy market. Customers who purchase energy in the day-ahead market and are willing to curtail in real time can effectively sell it back at the high real-time energy price. If some customers are willing to curtail based on high energy prices, they may become the cheapest source of peaking capacity. 24 The development of curtailable load for peaking capacity could transform the electricity markets. Capacity prices could fall (reflecting the lower fixed costs of load curtailment), but energy prices would rise to reflect the high value of curtailed load (which would set real-time energy prices). This would shift energy revenues from the capacity market to the energy market, much like "scarcity pricing" as an alternative to ICAP. However, the shift would be gradual, as customers learn how to adapt to real-time prices. If this vision were fulfilled, the blunt regulatory instrument of ICAP would be gradually replaced by the more efficient market instrument of price-responsive, voluntarily curtailable load. 24 This is similar to the airlines' practice of overbooking flights based on expected no-shows, instead of having many empty seats on most flights. On the rare occasions when all the customers show up, the airline offers large payments to those willing to "curtail" (i.e. delay) their flight. The real-time payments for curtailing customers are apparently cheaper than the cost of supplying extra seating capacity