The future of natural gas supplies in the United States looks promising due to rising projections of recoverable resources, including unconventional production. A strong supply outlook bodes well...
Fossil Fuels and Energy Policy: Understanding the New Natural Gas Economy
kilowatt), have an even lower electric efficiency of 30 percent, or a heatrate of 12,600 Btu per kilowatt-hour. Cogeneration can only partially offset these disadvantages compared to the installed cost of simple turbine generators ($300 to $400 per kilowatt) and of combined-cycle generators ($450 to $500 per kilowatt), and their heatrates (which run from 9,500 to 10,000 Btu per kilowatt-hour, and from 6,300 to 6,700 Btu per kilowatt-hour, respectively). Of course, these larger modular generation options also may require additional investments in electric grid capacity, unlike the smaller distributed generation technologies.
Scenario I: Gas Turbines as Peaking Plants
Let us do a "thought experiment" on how many hours per year a simple-cycle combustion turbine "peaker" costing $350 per kilowatt would have to operate to be profitable at a capital cost recovery factor of 15 percent per year and at power prices of $100, $250, $500, and $1,000 per megawatt-hour. Let us also assume a reasonably conservative levelized natural gas price of $4 per million Btu, a heatrate of 10,000 Btu per kilowatt-hour (38 percent efficiency, lower heating value basis), and 0.5 cents per kilowatt-hour ($5 per megawatt-hour) non-fuel operating and maintenance costs. Thus, we have fuel costs of $40 per megawatt-hour, annual capital recovery costs of $52,500 per megawatt of capacity, and O&M costs of $5 per megawatt-hour.
For example, if the peaker operated for 1,000 hours per year, or at an operating factor of 11.4 percent, generating 1,000 MWh per megawatt of capacity, the capital recovery cost would be $52.50 per megawatt-hour. Adding in fuel costs of $40 per megawatt-hour and O&M costs of $5 per megawatt-hour would yield a total of $97.50 per megawatt-hour in fixed and variable costs. In this scenario, a power price of $100 per megawatt-hour would be quite consistent with past practice of expecting about a 10 percent to15 percent annual load factor for peakers (operating during 10 percent to 15 percent of the 8,760 hours of nominal annual availability).
But consider a now-not-so-unusual, firm on-peak price index of $1,000 per megawatt-hour occurring during short periods in the summer in some of the market hubs. In this case, the required operating time to make such a peaker investment profitable shrinks to 55 hours per year as shown below.
$1000.00/MWh Less $ 45.00/MWh fuel and O&M costs $ 955.00/MWh available for capital recovery $52,500/MW-year = 55 hours/year $955/MWh
What is a reasonable strategy in this market environment for gas combustion turbines?
On one hand, it is doubtful whether any anyone would invest in peaking capacity to satisfy demand at some of the astronomical prices (up to $9,999 per megawatt-hour) experienced briefly in some markets. On the other hand, capacity designed to meet the current price caps of $250 to $500 per megawatt-hour could be profitable in areas where such fly-ups become endemic in the summer for just a few hundred hours of annual operation, as shown in Table 2. Thus, it might be justifiable to install gas-fired peakers in such areas, assuming that the needed gas supplies will available. However, while higher gas prices-say, up to $5