FERC

GAS PIPELINES. Noting a move toward shorter-term contracts since Order 636, the FERC on July 29 issued an "integrated package" of reform proposals for the natural gas pipeline...

portfolio costs reflect the underlying assets. Table 6 shows the portfolio capital cost assumptions. Except for the capacity factors, these assumptions are identical to those for Homer City to facilitate comparison of results.

Table 7 shows the results of the analysis for the CMP portfolio. Revenue requirements of $54.85 per megawatt-hour for the 20 percent Wyman case and over $49 per megawatt-hour for the 40 percent Wyman case are the result of high capital costs associated with the acquisition. The variable operating costs of the 20 percent Wyman case - $14.24 per megawatt-hour ($12.11 + $2.13) - are quite low, reflective of the low operating costs of the hydropower assets and the Aroostook plant. However, the low capacity factor of 33 percent for the entire portfolio does not provide enough hours of operation over which to spread the acquisition costs, resulting in a unit cost of $35.53 per megawatt-hour for capital recovery and taxes. The energy-limited nature of hydroelectric assets is one of the causes of this apparent inconsistency between low operating costs and low capacity factor. Even assuming the higher 40 percent capacity factor for the Wyman station, its high variable operating costs partially offset the additional megawatt-hours over which FPL may recover the capacity costs.

At this basic level of analysis, the CMP portfolio revenue requirements do not bode well for FPL's ability to recover its acquisition costs. Even in the absence of a likely supply glut in the NEPOOL market, baseload market prices should be capped by the all-in costs of incremental combined-cycle capacity.

Table 8 shows the unit cost components for replacement capacity - both baseload combined-cycle and peaking combustion turbine technologies. Incremental capacity unit costs are calculated for both assumed CMP portfolio capacity factors, 33 percent and 45 percent, and the 84 percent capacity factor used in the Homer City analysis. That is done to determine the least-cost alternative between new combined cycle and new combustion turbine capacity for incremental capacity additions. With these input assumptions, the combined-cycle stations have the lowest all-in costs, and therefore are assumed to provide a price cap on NEPOOL market prices across all three capacity factors.

Natural gas price assumptions in northern NEPOOL are taken from the Natural Gas Week 12-month strip for Henry Hub of $2.57 per million British thermal units plus our firm's northern NEPOOL basis differential of $0.38 per million British thermal units. The same combined-cycle heat rate as was used in the Homer City analysis, 6,900 Btu per kilowatt-hour, is used here. The combustion turbine peaker heat rate is assumed to be 9,700 Btu per kilowatt-hour. The resulting fuel costs are $20.36 and $28.62 per megawatt-hour for combined cycles and combustion turbines respectively.

Due to higher observed installed costs for new capacity in NEPOOL, combined-cycle installation is assumed to be 10 percent higher in the CMP analysis than in PJM for the Homer City analysis. Thus, combined-cycle stations are installed at $578 per kilowatt instead of the $525 per kilowatt cost assumed for PJM. Combustion turbine peakers cost $325 per kilowatt. All financing cost assumptions are identical