Nuclear fuel cost projections typically consist of current reported costs that are escalated at the rate of inflation. These projections usually consist of a single estimate in each year. In the...
Nuclear and Coal: Rebirth on the Horizon?
increase in debt cost from 8.25 to 9.25 percent.
In essence, this study assumes that new generation will continue to be overwhelmingly gas-fired, with progressive improvements in CT technology. We are examining the financial competitiveness of a small population of new nuclear and coal-fired generators introduced into this "world of gas." In most respects, this should maximize their competitiveness.
Two alternative power market structures were examined for impact on the competitiveness of new coal and nuclear plants. The market model used in Scenarios 1 and 3 assumes that there is an explicit ICAP market in addition to the energy market. In essence, this ICAP market becomes the vehicle for enforcing reliability requirements. It is assumed that energy market competitiveness maintains energy market prices at or near prevailing variable costs. In this study, a minimum profit of $3 per megawatt-hour is added to variable cost to obtain generator bid prices during on-peak hours. This minimum profit before sale was scaled back to $1 per megawatt-hour during mid-peak hours, and to zero during off-peak hours. The ICAP market is then relied upon to provide the revenues necessary for new gas-fired combined cycle and/or simple cycle CTs to meet the specified market average target IRR values when new capacity is needed for reliability. This market model anticipates very low ICAP values in early years when reserve-sharing pools have excess capacity. This value was taken to be $10 per kilowatt-year in today's dollars.
In the market model used in Scenario 2, it is assumed that there is a minimal ICAP market, limiting its revenues to $10 per kilowatt-year in today's dollars. The energy market is now called upon to provide the necessary revenues to allow new gas-fired projects to meet target IRRs when they are needed to meet reliability. This was done by increasing only the on-peak minimum profit before sale on a region-wise basis, but applying it to all generators within each region. In this market model, this energy market bidding strategy was allowed to persist during the early years of excess capacity. This produces much higher IRR values than the market model used in Scenario 1 for merchant plants introduced prior to the need for new capacity to maintain reliability, typically in the 2004 to 2008 time frame.
The study horizon was 2020. For new merchant plants installed in 2006, a target IRR of 16 percent in 2020 was assumed. For new merchant plants installed in 2011, the target IRR was assumed to be 12.5 percent in 2020. Capacity prices and energy market minimum profits were adjusted to have gas-fired merchant plants close to these targets. Capital costs for nuclear and coal units were then adjusted to have their IRR values match those of contemporary gas-fired combined cycle units.
1 , May 30, 2001. Article entitled "Nuclear Power Enthusiasts Grapple With Wall Street Skepticism", page 17.
2 Betsy S. Vaninetti, "The Race for New Coal-fired Generation". Article in , July/August 2001.
3 Energy Information Administration Report: Annual Energy Outlook 2001, DOE/EIA-0383 (2001); December 2000. Also, companion documents presenting assumptions and bases.
4 , July