Mitigation generally focuses upon the reduction of emissions of acid precursors. However, because of the magnitude of the projected costs of achieving such reductions and uncertainties about their effectiveness, the issue is highly polarized. Some recommend delaying control measures until more evidence is available; others believe immediate action is necessary.

The problem is primarily existing electric utility plants burning high-sulfur coal. New units must meet New Source Performance Standards (NSPS) mandated by the Clean Air Act. Under that Act, existing units are not subject to NSPS. Their emissions are treated in State Implementation Plans, under which, Reasonable Control Technology is all that is required.

The only options currently available for further reductions in sulfur dioxide emissions are switching to lower sulfur coals, physical cleaning, scrubbing, and environmental dispatching.

It

is,

Fuel switching is in some cases the most economical
approach.
however, not without costs.
Low-sulfur coals currently bring a significant price
premium and that could increase if fuel switching
becomes widespread. Also, plants will usually require
equipment modifications before they can accept
alternative coals; and some plants may be unable to
switch to low-sulfur coal because of design con-
straints. Fuel switching would also have significant
socioeconomic impacts as a result of the displacement
of high-sulfur coal production in the Midwest and
Northern Appalachia.

Cleaning methods presently available can only remove
part of the sulfur, but they are quite effective with
some coals. Such cleaning adds between $4 and $9 per
ton to the price of coal, but there are significant
benefits in addition to a reduction in SO2 emissions.
Transportation costs are lowered because ash and
moisture content are reduced, wear and tear on
coal-handling equipment is decreased, and boiler
performance is improved. If additional coal washing
was undertaken, sulfur oxide emissions might be reduced
by as much 1.5 million tons per year.

Scrubbing involves removing sulfur oxides from the
combustion gases prior to their release to the
atmosphere. In wet scrubbing, the most widely used
method, the gas is treated with aqueous solutions of
chemicals, which capture S02. Such processes can
remove 90 percent or more of the SO2. They are,
however, expensive. Capital costs for scrubbers

constitute about 20 percent of the total cost of a new
plant. The capital costs for retrofitting older units
are highly site specific, but they are typically about
25-30 percent greater than for new units. In some
cases retrofitting an older unit may be physically
impossible or economically impractical.

Environmental dispatching involves calling on
generation from units in order of increased emissions.
Utilities presently employ least-cost dispatching,
which is based on using the lowest cost generating
units first and moving to higher cost production as
demand dictates.

2. Greenhouse Effect. phenomenon that plays an temperature of the Earth.

The greenhouse effect is a natural important role in regulating the "Greenhouse gases" present in the

atmosphere transmit incoming radiation from the sun, but absorb the longer wavelength radiation emitted from the Earth's surface. The major greenhouse gases are carbon dioxide (CO2) and water (H2O).

The concentration of CO2 in the atmosphere has varied over the ages, but prior to the Industrial Revolution it appears to have been 260-280 ppm. 1 Currently it is about 340 ppm and is increasing at a rate of about 0.4 percent per year. The increase is the result of combustion of fossil fuels and changes in land use such as deforestation. Combustion of fossil fuels appears to be the major man-made source of CO2 at present.

The build up of CO2 and other greenhouse gases in the atmosphere is expected to increase the mean temperature of the Earth which in turn will modify the climate and raise the levels of the oceans. A doubling of the concentration of CO2 above pre-industrial levels could result in an increase in the mean global temperature of about 50 F; and in the polar regions the increase might be 2-3 times greater. A global change of this magnitude would make the Earth warmer than it has been in hundreds of thousand of years, resulting in regional changes in temperature, rainfall, storm activity, evaporation and soil moisture. Most studies project a mean temperature increase of 50 F sometime in the latter half of the next century--perhaps as early as 2050. The appropriate level of response is a matter of controversy, but there is general agreement that Draconian

measures to restrict the use of fossil fuels now or in the near future are neither feasible nor justified.

B. TRANSPORTATION. Coal's major advantage as a fuel is its relatively low cost, and that cost is strongly influenced by the cost of transportation. The relative importance of the various modes of transportation is shown in Figure ES-3.

1

Parts per million. (One ppm is equivalent to 0.0001 percent).

1. Railroads. About 60 percent of the coal shipped to consumers in the U.S. is transported by rail and nearly 85 percent of this has no alternative mode of transportation. The average cost of rail transport represents over 30 percent of the delivered cost, but for some Western coals in some markets it may be as high as 70 percent.

The major problem is escalating rail rates which have resulted from the current interpretation of the Staggers Rail Act of 1980 by the Interstate Commerce Commission (ICC). That Act expanded deregulation, which began in 1976, and led to the establishment of the principle of "revenue adequacy." Until a carrier achieves "revenue adequacy," it is free under current rules to adjust its rates on captive coal traffic by an amount not to exceed 15 percent in a single year (after inflation).

2. Coal Slurry Pipelines. Such pipelines can transport coal economically over long distances. The coal is transported as a suspension of pulverized coal in a liquid--usually water.

Supporters claim coal pipelines are needed to provide competition that will restrain continued escalation of rail rates following deregulation under the Staggers Rail Act. Opponents counter that because long-term (30 years or more) take-or-pay contracts will almost certainly be necessary for pipelines, the competition may prove more illusory than real.

The major constraints to the construction of coal pipelines are the difficulty of obtaining necessary rights-of-way

and obtaining the rights to the large quantities of water that are needed to slurry the coal (about one ton of water per ton of coal).

3. Inland Waterways. The network of inland waterways provides an efficient and economical way of moving coal in certain areas of the country. In recent years, congestion at a number of locks has increased to the point where there is some concern about the ability of the system to handle projected growth in tonnages of coal unless improvements are made relatively soon. In many instances this is because the poor condition of locks and dams, over half of which are at least 40 years old.

Historically, the federal government has provided locks and dams, channel improvements and maintenance of the inland waterways system. The first change in that tradition occurred in 1978 when a fuel tax was imposed on vessels engaged in commerical waterway transportation. Some recent legislation calls for users to make a greater contribution to the operation and maintenance of the system through user fees.

4. Deep-Draft Ports. Deep-draft ports need to be developed if U.S. coal is to remain competitive in the future. By the year 2000 it is estimated that 50 percent of the world coal trade will in super ships (100,000 150,000 dwt). At the present time, most U.S. ports cannot handle ships larger than 60,000 dwt.

move

C.

COAL LEASING. The federal government owns 60 percent of the coal reserves in the West and indirectly controls another 20 percent because of ownership patterns, representing about

40 percent of total U.S. coal reserves.

Since 1920, the Department of the Interior (DOI) has administered the leasing of federal coal to private developers under authority of the Mineral Leasing Act. However, extensive leasing of federal coal did not occur until about 1960, at which time activity increased quite sharply. In November of 1970, the Bureau of Land Management released a major study of federal coal leasing which concluded that "existing policies and procedures with respect to development of federally managed coal resources are inadequate to encourage development.' On the basis of that study, an informal moratorium on coal leasing was called in May, 1971, to allow time for policy revisions. The moratorium, which was formalized in February, 1973, lasted until January, 1981.

A comprehensive new federal leasing policy was developed and formally promulgated in regulations in July, 1979, as the Federal Coal Management Program, and the first lease sales under this new program took place in January, 1981. Shortly thereafter, DOI undertook significant and controversial revisions in the Federal Coal Management Program which it hoped would facilitate coal leasing. Controversy heightened with 1982 lease sales in the Powder River Basin in which 1.6 billion tons of federal coal were leased for $67 million--about four cents per ton. There was widespread criticism that the government--by design or by incompetence--had sold these leases at far less than market value.

In light of such actions, Congress voted to halt further coal leasing until leasing policy could be reviewed. One review, conducted by the Linowes Commission, examined the question of how the federal government could lease coal to realize fair market value, while also achieving other goals that often are in

apparent conflict. The other was a review of the environmental acceptability of federal coal leasing policy carried out by the Office of Technology Assessment (OTA).

The Department of the Interior is currently developing a revised leasing policy in light of the recommendations of the Linowes Commision and OTA. DOI estimates that the program could

be ready in time to resume leasing by July, 1985.

Ꭰ. SEVERANCE TAXES. Another factor that can add to the delivered cost of coal is state severance taxes. Many coal producing states levy severance taxes--typically at rates les s than 5 percent of the value of the coal. However, Montana and Wyoming tax coal at 30 and 17 percent respectively. This is of particular concern because those two states possess 40 percent of total U.S. demonstrated coal reserves and more than half of the reserves of low-sulfur coal.

There is general agreement that states should be able to levy taxes to recover costs of providing the additional public services associated with coal production. The taxes imposed by Montana and Wyoming, however, far exceed such costs and are well above those charged by other coal-producing states.

CHAPTER IV. COAL TECHNOLOGIES

Because consumption of coal will continue to be dominated by electric utilities at least for the remainder of this century, coal-fired technologies for generating electricity are the major focus of this chapter.

A. NEED FOR ADDITIONS TO CAPACITY. How much new generating capacity will be needed between now and the year 2000 is unclear. The utility industry has moved into a new and uncertain era marked by uncertain demand growth, large capacity reserves, high capital costs, high interest rates, and long lead times for capacity additions. In these circumstances, the emphasis is on deferring new additions to capacity by:

better utilizing existing capacity by more
effective load management and extending the life of
existing units,

reducing demand by more aggressive and extensive
energy conservation measures, and

purchasing power from third-parties (cogenerators
and small producers).

Widely divergent opinions on the need for additional new generating capacity were presented before Congressman Ottinger's Subcommittee on Energy Conservation and Power in a February, 1984, hearing. Estimates of required additions to capacity between 1982 and the year 2000 ranged from 202 to 457 gigawatts (GW). If allowance is made for capacity under construction at the time of these forecasts, the capacity needed but not yet started ranges from 86 to 341 GW. The wide variation arises