Wyoming and Montana

are cracking Midwest coal markets,

despite local protectionism.

As pressures build steadily toward deregulation and increased competition between electric power generators, Western low-sulfur coal is emerging as the most economical fuel option for an increasing number of companies. The low cost of delivered fuel and avoidance of capital outlays offer attractive savings. But more than that, Western coal can also provide a competitive edge.

Today, Wyoming has assumed the title of the nation's leading coal-producing state, having displaced West Virginia from second place in 1984, and Kentucky as the leader in 1988. Since the late 1980s, Wyoming and its neighbor, Montana (em which together form the Powder River Basin (PRB) region (em have come to challenge the Appalachian states for the title of "King Coal." Of the nation's 91 billion tons of low-sulfur coal reserves, 86 percent lie in the West. Given current consumption of low-sulfur coal (em about 300 million tons a year (em Wyoming and Montana could supply all the nation's requirements for 200 years. In fact, by year-end 1994, PRB coal generated approximately 20 percent of the coal-fired, steam-generated electricity in the United States.

This shift of coal production from East to West carries both short- and long-term implications for coal producers, coal transporters, and electric utilities (em in both the economics and the politics of competition.

Clean Air Strategies

The production increases seen in Western coal production gained momentum from the 1990 Clean Air Act Amendments (CAAA), which require utilities to reduce their sulfur dioxide (SO2) emissions. to 2.5 lbs/MMBtu by January 1, 1995, and to 1.2 lbs/MMBtu by January 1, 2000. PRB coal carries between one-half and one-sixth the sulfur content of most Interior or Appalachian coals. Additional pluses for PRB coal come from abundant reserves, infrastructure development, and low-cost

production and distribution economics.

The CAAA moved away from the concept of command and control for SO2 emissions. It allowed utilities to exercise freedom of choice to pursue the most efficient compliance option. Nevertheless, political concerns have prevailed periodically over economic factors, often at ratepayer expense,

clouding the economics of the various clean air options:

Scrubbers. Although investment in scrubbing has not lived up to expectations, some utilities have chosen this route to CAAA compliance. Unfortunately, scrubbers almost never provide the right economic answer. Not only do they average $100 million to purchase and install, they increase a utility's cost of generation.

U.S. average scrubber retrofit costs run to $244,000 per megawatt, according to the Utility Data Institute. For a 500-megawatt (Mw) plant, a scrubber's capital cost would reach $122 million. Amortizing this capital addition over 20 years at 10-percent interest works out to $14 million annually (em approximately $5 per megawatt-hour (Mwh) for a plant operating at a 65-percent capacity factor. The national average operation and maintenance cost for a scrubber is $1.42/Mwh. Thus, using a scrubber can increase the cost of power generation by 20 to 25 percent. These costs inevitably lead to higher prices or heightened risk for ratepayers, or unnecessary costs for shareholders, as well as making it more difficult 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.

Transport Techniques

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 advantage of spot electricity markets. Today, a creative coal-hauling contract gives MP the flexibility of Western low-sulfur coal deliveries to avoid purchasing offsystem power during certain periods. Looking forward, the parties contemplate a new agreement to allow the incremental coal transportation price to swing to capture spot electricity sales.

Overcoming Political Barriers

Despite the powerful economics of PRB coal, some states have erected artificial political barriers to "protect" the local coal industry from the rigors of free-market competition. Inevitably, however, local-subsidy schemes force ratepayers to pay more for electricity. In the days of stringent regulation, higher prices could readily be imposed on customers with little access to other sources of electricity; under deregulation, industrial and residential utility customers will presumably avail themselves of alternate competing sources of electricity at better rates.

Like subsidies, state laws protecting local coal represent another common tactic to resist the growth of Western coal. Some states have offered tax incentives favoring high-sulfur coal and, in some cases, have forced the utilities to install expensive scrubbers to reduce sulfur emissions. Taxpayers and ratepayers obviously lose out. But more importantly, such measures lead to higher overall electricity prices, threatening local economies by deterring startups or expansion of manufacturing plants.

Such narrow political practices recently received a significant setback last year in Illinois, where the U.S. Court of Appeals for the Seventh Circuit found that protectionist legislation violated the Commerce Clause of the U.S. Constitution: "The Illinois Coal Act is a none-too-subtle attempt to prevent Illinois electric utilities from switching to low-sulfur Western coal as a CAAA compliance option." Moreover, the court discounted arguments that the Illinois law would safeguard citizens from a decline in the local coal industry: "Such concerns do not justify discrimination against out-of-state producers." Alliance for Clean Coal v. Miller, 44 F.3d 591

(7th Cir.1995).

In striking down the Illinois statute, the court confirmed the right to fair access to new markets for Western coal. It also granted utilities genuinely free access to all fuel options in making the best economic decisions for their customers and shareholders.

On March 27, 1995, the U.S. District Court for the Southern District of Indiana reaffirmed these principles when it struck down parts of the Indiana Environmental Compliance Plans Act (ECPA) as unconstitutional. U.S. District Judge John Daniel Tinder called the ECPA "a burden on interstate commerce" and noted:

"It is plainly protectionist to the extent that it requires the Indiana Utility Regulatory Commission to consider the effects a utility's 1990 CAAA compliance plan may have on the Indiana coal industry, and imposes restrictions on approval of the plan based upon the plan's effects on the Indiana coal industry. The ECPA cannot be justified on the grounds that it protects the State of Indiana and its citizens from economic harm which could result from a decline in the state's coal industry as a consequence of compliance with the 1990 CAAA."

Judge Tinder left little doubt as to his view of the state's motivation behind the statute: "The obvious intent of the challenged portions of the ECPA was to limit or eliminate the use of Western coal in Indiana generating plants with an eye toward promoting instead the use of high-sulfur coal, preferably that mined in Indiana. This is exactly the type of statute the dormant Commerce Clause prohibits. Therefore, the challenged portions of the ECPA fail to pass constitutional muster." Alliance for Clean Coal v. Bayh, 888 F.Supp. 924 (S.D.Ind.1995); see also General Motors Corp. v. Indianapolis P&L Co., 654 N.E.2d 750 (Ind.App.1995).

Facing the Future

Utility managements that have not yet decided on Western low-sulfur coal may yet take advantage of certain creative opportunities.

One option would see the utility participate in a "tolling" arrangement with another utility that already relies on PRB coal. This approach would allow a first company to take advantage of PRB coal-generated electricity while still maintaining control over fuel purchases and transportation. Some western coal producers and railroads have indicated they are willing to explore these kinds of arrangements.

Another approach that may prove advantageous involves

conversion of boilers to burn

low-sulfur coal (em a move that is less costly than some might believe. Utilities such as Mississippi Power and Alabama Power have found the conversion economics very attractive. Moreover, a large body of experience built up by utilities and boiler manufacturers can be applied to most boilers in the country. One PRB coal- production company executive recently summed up the future for Western coal this way:

"Electricity customers of those utilities that have a capability to switch to PRB low-sulfur coal are the lucky ones. ... But if their utility tries ... avoiding a switch to low-sulfur coal, our job is to find another way to get the choice of PRB coal-generated electricity to them."

In the future, electric utilities should assume that Western railroads and coal producers will be looking for opportunities to move low-sulfur coal to the maximum number of customers. And as access to the nation's power grid expands, more utility customers will see the value of PRB coal. The calendar favors Western coal. Conversions will grow inevitably over the next decade. Ratepayers, utilities, and shareholders should emerge as winners. t

John Anderson and Jerry Bartlett work for Burlington Northern Santa Fe's Coal, Metals and Minerals Business Unit as executive vice president and director of market and economic analysis, respectively.

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