The Cost of Replacing Indian Point: In Practice
Although the cost of building and operating new electric generating capacity to replace some or all of the 2,000 MW at the Indian Point Energy Center would be substantial, it is very difficult to determine what the overall effect would be on the bills paid by customers. The committee’s scenarios, presented in Chapter 5, project the basis for the wholesale market prices in different zones. Generally, these prices are higher than the prices in the base case with Indian Point operating, but in some situations they are lower. The explanation for getting lower wholesale prices is that new efficient capacity displaces some of the old inefficient capacity and sets the market price more often.
The pricing mechanism used in all of the scenarios is based on a uniform-price auction assuming that the market is competitive (i.e., that the offers submitted into the auction by generators are equal to the true production costs, and under this specification, it would be extremely unlikely for the market price ever to be set by the low production cost of Indian Point). Assuming that the market is competitive is a reasonably close representation of how the market is actually performing at this time. Hence, the predicted prices in the scenarios provide a consistent way to determine how wholesale prices would be affected in different situations. Higher wholesale prices would result in higher rates charged to customers unless there was an offsetting reduction in the other costs of generation.
The main complication for determining the total cost of generation in the current market structure is that the wholesale price of electricity is only one of the components of the total cost. It would be necessary to determine how the costs of the other components would change to get a complete accounting of the effects of replacing Indian Point. Some of these costs are set by regulators and are subject to change. Consequently, unlike modeling wholesale prices, there is no consistent structure for modeling the other costs, and it is virtually impossible to predict how they would change in different scenarios.
The best examples of the other costs of generation are (1) payments for availability in the installed capacity (ICAP) market, and (2) payments for reserve capacity. In addition, the discussion of reliability in this chapter explains why the current structure of markets is still not providing sufficient incentives for new merchant projects. The implication is that investors will have to be paid some form of additional premium above the revenue received from the existing markets if new capacity is going to be built. In the long run, customers will have to pay for all of the additional costs of generation as well as for purchases in the wholesale market.
Information on the performance of the wholesale market is readily available, but information about the other costs of generation is much more limited. Patton (2005, pp. 22-25) provides a valuable discussion of the performance of the ICAP and reserve markets; in that report, Section F, and Figure 16 in particular, shows a “net revenue analysis” of the annual net revenue (revenue minus production costs) in 2002-2004 for a combined-cycle turbine and a combustion turbine in different locations. For generators in New York City, the ICAP market is the primary source of net revenue for combustion turbines (roughly $140,000 per year per MW out of a total net revenue of $160,000 per year per MW in 2004) and a major source for com-bined-cycle turbines (roughly $140,000 per year per MW out of a total net revenue of $260,000 per year per MW in 2004). The net revenue from the ancillary service markets (e.g., reserve capacity) is small for both types of turbine (roughly $10,000 per year per MW). The net revenues for generators on Long Island are similar to the levels in New York City, but for upstate generators, the net revenue from the ICAP and reserve markets is very small (roughly $25,000 per year per MW).
The discussion above is relevant for assessing the cost to customers of replacing Indian Point because it shows the importance of the location of capacity on the magnitudes of the “other” costs of generation. In New York City and Long Island, customers will eventually have to pay the relatively high wholesale prices for all of their purchases (the annual average prices in 2005 were $83 per megawatt-hour (MWh) and $98/MWh, respectively, compared to prices ranging from $65/MWh to $72/MWh in Zones A through F upstate) and the high other costs of generation for all generating capacity in New York City and Long Island (Zones J and K). New capacity that is built in zones other than J and K will incur relatively low costs in the ICAP and reserve markets but may require a higher premium to make them financially attractive (i.e., because the net revenue from the existing markets will be low). It is beyond the scope of this study to try to determine the net effect of these offsetting factors.
The current regulatory strategy in the ICAP market is to make all generating capacity in a region eligible for capacity payments. Hence, the relatively high prices for capacity in Zones J and K are paid to all installed capacity that have offers accepted in the ICAP auctions for those zones. Nevertheless, it is probable that additional premiums will have to be paid to get new merchant capacity built.
An alternative regulatory strategy is to direct capacity payments to cover the premium for new capacity, and possibly for existing capacity that operates most of the time at a minimum level but is still essential for reliability. This alternative strategy may be a less expensive way to maintain reliability in the long run, because making capacity payments to all installed capacity in the current ICAP market places no obligation on existing generators to build new capacity. Once again, there is a lot of uncertainty about how regulators will decide to deal with current concerns about reliability and what the additional costs will be above the price in the wholesale market.