Big Share of '95 Fuel Mix
For the second year in a row, natural gas fueled an increasing share of U.S. electric generation. When the final numbers are tabulated for 1995,...
for the utility to prosper in an extremely tough business environment.
With these costs and business risks, scrubber investment has fallen below many expectations.
Emission Credits. Few Phase II utilities will be able to rely solely on emission credits to achieve compliance with CAAA targets, since utilities generally must couple a credit strategy with other options to make economic sense.
For example, a 500-Mw plant operating at a 65-percent capacity factor burns just about 1.34 million tons of 3-percent sulfur coal rated at 11,000 Btu. This coal burn produces more than 80,200 tons of SO2 emissions, requiring more than 62,500 allowances. Assuming an allowance price of $150, the utility's annual purchase of credits would approach $9.4 million. Emission credits make economic sense only when a utility burns a lower-sulfur coal and already stands near its compliance goal.
Fuel Switching. Alternative fuels provide another compliance option. However, both oil and natural gas present alternatives that are considerably higher in cost than coal in general (em and PRB coal in particular (em for large-scale, baseload electric generation.
Coal Switching. Most utilities have so far preferred to switch to low-sulfur coal rather than install scrubbers or convert to oil or gas. That trend is highly likely to continue, as deregulation proceeds and competition grows.
Currently, 10 of the 15 lowest-cost steam-electric plants in the country burn PRB coal, including such utilities as Basin Electric Power Co-op, Midwest Power Systems, Nebraska Public Power, San Antonio Public Service Board, and Wisconsin Electric Power. Prices for Western-delivered coal are lower today in absolute terms than Appalachian or Interior coal, and have been declining at an increasing rate since 1986. This price decline contrasts with the alarmist rhetoric from high-sulfur coal producers, who have predicted run-ups in prices for low-sulfur Western coal.
While delivered coal prices have fallen between 10 and 21 percent for all three regions since the mid-1980s (em owing to increased mine capacity, mine productivity, and transportation competition (em the price of Western low-sulfur coal has dropped the most, approximately 21 percent.
The availability of economical and reliable long-distance rail haul service for PRB coal has played a major role in fuel selection.
While 1994 witnessed slower cycle times, as record demand for low-sulfur coal increased faster than available rail capacity, these capacity constraints were quickly addressed by the Western railroads. Approximately 300 million tons of annual rail hauling capacity is planned for the PRB by 1997.
Distance from the mine source has not proved a major problem for most utilities. Some utilities that burn PRB coal operate more than 1,000 miles east of mine, including Detroit Edison, American Electric Power, and Mississippi Power. These utilities lowered their costs with PRB coal after an exhaustive search and test of many U.S. coals.
The case of Minnesota Power (MP), the first Midwestern utility (in 1969) to switch to Western coal, illustrates how utilities can work with coal transporters to tailor solutions to meet company needs. The utility acted when its coal-hauling railroad showed interest in a flexible pricing concept for incremental coal transportation to take