BOX 4-1

The Cost of Replacing Indian Point: In Theory

The cost of replacing Indian Point is substantial because its two operating nuclear reactors, Units 2 and 3, represent 2,000 megawatts (MW) of baseload capacity with relatively low operating costs. In addition, a large capital investment of these units has already been made. To the extent that a replacement strategy includes conventional generating capacity (e.g., using natural gas as a fuel), the incremental cost of building this new capacity will include the capital costs, and in addition, the operating costs will be higher. Under traditional regulation, all of these incremental costs would be passed on directly to customers in New York State. Although someone has to pay for these higher costs, customers may not see major increases in their monthly bills in the new deregulated market in the state. How is this possible? An explanation follows using a simple example of the magnitudes of the costs involved.

Let us assume that the full operating costs of Indian Point are $20 per megawatt-hour (MWh) and that the units operate for a total of 8,000 hours per year. These operating costs would include the nuclear fuel, labor, and capital costs for operations and maintenance (which might require adding a cooling tower in the future), and payments into a sinking fund to cover decommissioning as well as a charge paid to the federal government to cover the cost of disposing of nuclear waste. Since Indian Point has a capacity of 2,000 MW, the total annual cost of operations is $320 million per year (20 x 2,000 x 8,000).

The average wholesale price of electricity in New York Control Area Zone H was $80 per MWh in 2005 (when the price of natural gas was substantially higher than historical levels). Consequently, the annual revenue, if all power had been sold in the wholesale market, would be $1,280 million per year (80 x 2,000 x 8,000) and the annual earnings for Entergy Corporation (the plant’s owner) would be $960 million per year (1,280 – 320). The situation is more complicated in reality, because Entergy may have long-term contracts to sell some of the power at prices below the current high level in the wholesale market. Nevertheless, these contracts will have to be renewed periodically, and with high prices for natural gas, Indian Point represents a very valuable source of income for Entergy.

To keep the example simple, let us assume that Indian Point is replaced completely by 2,000 MW of combined-cycle capacity using natural gas as a fuel. The operating cost of these units is $60 per MWh, and the annualized capital cost is $120 per kilowatt per year (kW/year). These units will also operate for 8,000 hours per year, and as a result, the capital cost prorated to the annual amount generated corresponds to $15/MWh (120,000/8,000). The total annual cost of generation is $1,200 million per year ([60 + 15] 2,000 x 8,000), and the incremental cost of replacing Indian Point is $880 million per year (1,200 – 320). That is a very large amount of money, but it could be much lower for a number of valid reasons. For example, reducing load by improving the efficiency of appliances is shown in Chapter 2 of this report to be much more cost-effective than building new generating capacity, and the transmission upgrades discussed in Chapter 3 may allow existing units in other locations to generate more power.

Under traditional regulation, all prudent operating costs and capital costs for generation, transmission, and distribution are aggregated to determine the size of the revenue requirement and the corresponding retail rates charged to customers.1 In a competitive market for generation, the most expensive unit needed to meet the load sets the wholesale price paid to all units that are generating in the market (prices actually vary from location to location owing to congestion on the transmission lines, but this is not an important issue for this example). When an expensive peaking unit sets the price on a hot summer day, the wholesale price paid to generators is much higher than the operating costs of most units. This “extra” income can be used to cover the capital cost of generation.

In theory, the wholesale price in a competitive market should cover all of the operating and capital costs of generation, but, as explained in this chapter and in Appendix E, “Paying for Reliability in Deregulated Markets,” a truly competitive market will not cover the capital cost of a peaking unit unless high prices (scarcity prices) are allowed. However, the total cost of the combined-cycle unit in this example ($75/MWh) is covered by the wholesale price ($80/MWh). Although these results are clearly sensitive to the assumptions made, this specific example shows that it is quite possible in a competitive market to add new generating capacity without increasing the wholesale price. In fact, the simulated market prices in some of the scenarios presented in Chapter 5 are lower when new generating capacity is added. The reason is that the new efficient units displace some generation from existing units that are more expensive to operate, and the more efficient units set the market price more frequently.

Who does pay for the incremental cost of replacing Indian Point in this example, if customers still pay the same wholesale price as before? The main loser in this example is Entergy, because the substantial annual earnings from Indian Point have now been eliminated. Given the many complexities of determining costs, such as the effect of increases in the use of natural gas on the future price of natural gas, it is extremely difficult to measure the true cost to customers of replacing Indian Point. The most important complications about determining this cost are discussed in Box 4-2. The main point of the present example is to show that the current wholesale price of electricity in the New York market may cover a large part of the incremental costs of replacing Indian Point. In a competitive market, the financial consequences for customers are likely to be smaller than the consequences would have been under traditional regulation. There is, however, an important qualification that should be made. The example here and the scenarios presented in Chapter 5 assume that new generating capacity will be built in a timely way before Indian Point is retired. If Indian Point experienced an unscheduled failure and had to be taken off-line in an emergency, the wholesale price would increase substantially. Without Indian Point and without new capacity, more-inefficient units with higher costs would have to be used to meet load. These expensive units would set higher wholesale prices.


1In fact, traditional regulation did not apply to Indian Point Unit 3, because it was owned by the New York Power Authority, and its power was sold in part outside the regulated market.

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