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Did Power Plant Buyers Pay Too Much?

Fortnightly Magazine - November 1 1999

per megawatt-hour. The unit cost components included in this analysis are presented in table 3.

As discussed, these results are dependent on Edison Mission's ability to levelize the debt service and other capital-related costs for its acquisition of Homer City. Not levelized, Homer City's average capital-related costs for the first two years are more than $225 million as compared to the 20-year levelized $218 million. Achieving this level of revenue requires that Homer City sell power at an average price of $31.18 per megawatt-hour.

Table 4 illustrates the cost components of replacement capacity in PJM, assuming the same financing costs and an 84 percent capacity factor. Delivered natural gas prices in the Homer City location in Western PJM are assumed to be the strip price of $2.57 per million British thermal units reported as of this writing in Natural Gas Week, plus our PJM basis differential off of Henry Hub of $0.25 per million British thermal units. The installed cost of a new combined-cycle station is assumed to be $525 per kilowatt in PJM. Assumed new combined-cycle heat rate is 6,900 Btu per kilowatt-hour, resulting in a fuel cost of $19.46 per megawatt-hour. That indicates that prices in PJM will trend toward the all-in price for a combined-cycle generating station, estimated to be $31.43 per megawatt-hour. That amount is close to the required revenues for Homer City to recover its assumed ROE.

Homer City's unit cost range of roughly $29 to $31 per megawatt-hour may be fully recoverable in the two energy markets to which it has full access. With any additional value by virtue of ancillary services, trading, retail revenues or site considerations, Homer City appears likely to recover its acquisition costs and likely will be a winner for Edison Mission.

Central Maine Portfolio. FPL's purchase is a little more complicated to analyze because the CMP assets make up a diverse portfolio of five distinct pieces: hydroelectric assets, the Cape Gas Turbine, the Mason Steam plant, the W.F. Wyman steam plant and the Aroostook Valley biomass generating plant. The hydropower portion of the portfolio consists of several small plants on the Kennebec, Androscoggin and Saco rivers. EIA data indicates a total capacity of 368 MW.

The average capacity factor during the last several years is approximately 50 percent for the hydropower portion of the CMP portfolio. Average non-fuel variable O&M was $0.75 per megawatt-hour from 1988 to 1997. Fixed O&M averaged $12.65 per kilowatt. The contribution of these plants, because they are energy-limited hydroelectric assets, will be limited by the flows of their respective rivers. They will be limited to a 50 percent capacity factor in this analysis, in spite of their low operating costs.

The Cape Gas Turbine facility, on the other hand, will not contribute to the fixed costs of FPL's portfolio unless trading and ancillary services values are applied. The heat rate on this plant is well in excess of 15,000 Btu per kilowatt-hour. Its highest capacity factor was 1.9 percent in 1988, and has not surpassed 0.1 percent since 1989. EIA's "Inventory of Power Plants" indicates that

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