BACKGROUND PAPER 

Replacing Oil and Natural 

Gas with Coal: 

Prospects in the 

Manufacturing Industries 

August 1978 

O Congress of the United States 

Congressional Budget Office 

REPLACING OIL AND NATURAL GAS WITH COAL: 

PROSPECTS IN THE MANUFACTURING INDUSTRIES 

The Congress of the United States 

Congressional Budget Office 

For sale by the Superintendent of Documents, U.S. Government Printing Office 

Washington, D.C. 2Q4()Z, 

PREFACE 

Because of the United States! growing dependence on foreign oil and 

the predictions of an energy IIcrisis,1I alternative energy strategies are 

constantly being evaluated by the Congress. One of the most often 

discussed alternatives is to increase U.S. reliance on the nationls vast coal 

reserves. This report addresses one component of this potential strategy. 

Specifically, it analyzes alternative policies that could be adopted to 

encourage the manufacturing sector to substitute solid coal for oil and gas 

consumption. Because of technical or cost restraints in other consuming 

sectors, the manufacturing industries are the most likely candidates for 

expanded direct use of solid coal. 

This report has been written at the request of the Senate Budget 

Committee by Craig Roach of the Natural Resources and Commerce 

Division; Porter Wheeler wrote the appendix on coal transportation. 

Richard D. Morgenstern and Raymond C. Scheppach supervised the study. 

Phyllis Nations typed the various drafts of the manuscript. Research 

assistance was provided by Sarah Beth Lambert. The paper was edited by 

Robert L. Faherty. In keeping with CBOls mandate to provide objective 

analysis, this report contains no recom mendations. 

August 1978 

iii 

Alice M. Rivlin 

Director 

CONTENTS 

PREFACE. 

SUMMARY. 

CHAPTER I. INTRODUCTION • 

CHAPTER II. THE POTENTIAL FOR SOLID COAL 

SUBSTITUTION IN INDUSTRY • 

Energy Use in Manufacturing. • 

Targets for Substitution • • • • 

Summary . • • . • . • . . 

CHAPTER III. THE ECONOMICS OF ALTERNATIVE 

iii 

xiii 

1 

3 

4 

7 

10 

BOILER FUELS •.•.•.••• 11 

The Economics of Boiler Fuel Choice • 11 

Critical Assumptions • • • • . • . . 15 

CHAPTER IV. ENVIRONMENTAL REGULATIONS AFFECTING 

INDUSTRIAL ENERGY USE • • • • • • 21 

Air Pollution and Energy Consumption. • • • • 21 

Assumed Air Pollution Regulations • • • • • • 24 

Pollution Control Equipment for Representative 

Boiler Systems • • • • • • • • • • • • • 25 

CHAPTER V. THE POTENTIAL FOR NONBOILER SOLID 

COAL SUBSTITUTION ••••.•••• 

CHAPTER VI. BOILER COAL CONSUMPTION UNDER 

CURRENT POLICY. • • • . . • • . • • 

Estimates of Boiler Coal Consumption under 

Current Policy • • • • • • • • • . . 

The Sensitivity of Boiler Fuel Choice to 

Alternative Assumptions. . . • . • • • • 

v 

33 

39 

39 

41 
CONTENTS (Continued) 

CHAPTER VII. POLICY OPTIONS TO REPLACE OIL AND GAS 

WITH COAL • • • • • . • • • • • • . 43 

Replacing Oil and Gas in Boilers • • • • . • • 43 

Replacing Oil and Gas in Nonboiler Uses • • • • 53 

APPENDIX A. POSSIBLE TRANSPORTATION CONSTRAINTS 

TO INCREASED COAL CONSUMPTION . • • • 57 

APPENDIX B. METHODS AND DATA FOR THE ANALYSIS 

OF INDUSTRIAL BOILER FUEL DEMAND. 69 

APPENDIX C. BUDGETARY EFFECTS OF BOILER TAX 

PROGRAMS • • • • • • • • • • • • • • 83 

vi 
TABLES 

TABLE 1. 

TABLE 2. 

TABLE 3. 

TABLE 4. 

TABLE 5. 

TABLE 6. 

TABLE 7. 

TABLE 8. 

TABLE 9. 

TABLE 10. 

NET ENERGY CONSUMPTION IN THE 

MANUF ACTURING SECTOR. • • • • 

OIL AND GAS CONSUMPTION BY INDUSTRY 

AND TYPE OF PROCESS IN THE 

MANUFACTURING SECTOR •••••••.. 

BOILER EQUIPMENT COSTS BY FUEL TYPE 

AND BOILER SIZE • . • • • • • • . • • . • 

DETAILED EQUIPMENT COSTS FOR A COAL 

BOILER PRODUCING 200 MPPH USING 

HIGH-SULPHUR MIDWESTERN COAL • 

UNCONTROLLED S02 EMISSION RATES 

BY FUEL TYPE • • • • • • • • • • • 

UNCONTROLLED PARTICULATE (TSP) 

EMISSION RATES BY FUEL TYPE . • • 

REPRESENTATIVE AIR POLLUTION CONTROL 

EQUIPMENT COSTS BY FUEL TYPE ••••• 

REPRESENTATIVE OPERATION AND 

MAINTENANCE COSTS FOR AIR POLLUTION 

CONTROL BY FUEL TYPE • • • • • • 

TECHNICAL FEASIBILITY OF COAL USE 

IN NONBOILER APPLICATIONS • • .• 

ENERGY AND BUDGETARY EFFECTS OF 

CURRENT POLICY AND FIVE ALTERNATIVE 

BOILER TAX POLICIES . . • • • • . • • . • 

vii 

5 

6 

14 

16 

26 

27 

29 

31 

35 

45 

APPENDIX TABLES 

Page 

TABLE A-I. REVENUE CARLOADINGS OF COAL 0 • 0 • • 59 , 

TABLE A-2o COAL TRAFFIC AS A PERCENTAGE OF 

TOTAL TRAFFIC FOR CLASS 1 RAILROADS 0 59 

TABLE A-3o RAIL EQUIPMENT NEEDS FOR 

COAL TRAFFIC • 0 0 • • • 0 • • 62 

TABLE B-1. CAPITAL CHARGE RATES • • • 72 

TABLE B-2. FUEL DEMAND FOR NEW, LARGE BOILERS 

BY FEDERAL REGION • • • • • • • 74 

TABLE B-3. LARGE BOILER FUEL CONSUMPTION .. 0 0 75 

TABLE B-4. BOILER UTILIZATION RATE DISTRIBUTION 

IN 1974 BY SIZE OF BOILER: DISTRIBUTION 

BY PERCENT OF FUEL CONSUMPTION 76 

TABLE B-5. DELIVERED COAL PRICES PER 

MILLION BTUs. . • • • • • • • 0 • • 79 

TABLE B-6. DELIVERED RESIDUAL OIL PRICES PER 

MILLION BTUs. • • • • 0 • 0 • 0 • • 80 

TABLE B-7. NATURAL GAS PRICES PER MILLION BTUs. • 81 

TABLE C-1. BUDGETARY IMPACTS OF HOUSE AND 

SENATE BOILER TAX PROGRAMS •••• 0 • 83 

ix 

FIGURES 

FIGURE 1. BOILER COSTS BY FUEL AND UTILIZATION 

RATE FOR REGION X AND BOILER SIZE Y • • 13 

FIGURE I-B. BOILER COSTS BY FUEL AND UTILIZATION 

RATE FOR REGION X AND BOILER SIZE Y • • 69 

xi 

SUMMARY 

When the United States evaluates both short- and long-run policies to 

reduce its dependence on foreign oil, major consideration is always given to 

increasing the nation's reliance on coal. Not only are the known U.S. coal 

reserves immense compared with the domestic reserves of oil and natural 

gas, but the dramatic increase in the world price of oil in 1973 made coal an 

economically attractive substitute for some selected uses. 

Policies encouraging the substitution of coal for oil and natural gas 

were an important part of the Administration's National Energy Plan 

submitted to the Congress in April 1977. By 1985, the Administration 

planned to reduce oil imports by 4.5 million barrels a day-from 11.5 to 7 

million. Of that 4.5 million barrels a day of savings, 2.3 million was to be 

attained by replacing oil and natural gas with coal in the manufacturing 

sector; some additional import savings were also credited to coal substitution in existing electric utilities. Although the House and the Senate have, 

in large part, rewritten the proposed legislation, substituting coal for oil and 

gas remains a cornerstone. Substitution is to be encouraged primarily by 

excise taxes on certain uses of oil and natural gas and by tax rebates and tax 

credits for those buying coal-burning equipment; regulatory programs that 

simply prohibit the use of oil and gas in specific cases are also proposed. 

OPPORTUNITIES FOR COAL SUBSTITUTION 

While processing coal into a liquid or gaseous form may prove 

advantageous in the future, engineering, economic, or institutional barriers 

appear to hinder widespread adoption in the near term. Hence, current 

legislative proposals (and this report) focus primarily on the potential 

substitution of solid coal for oil and gas. 

The manufacturing sector is the most likely target for solid coal 

substitution, since new electric utilities are already turning to coal or 

nuclear power and there appear to be few opportunities for solid coal 

substitution in the transportation, residential, and commercial sectors. 

Within manufacturing, the primary opportunity for shifting to coal lies in 

fueling boilers, since coal-fired boilers are commercially available. At 

present, 25 to 30 percent of U.S. oil and natural gas consumption is 

attributable to the manufacturing sector, and 30 to 40 percent of that (or 8 

xiii 
to 12 percent of total consumption) goes for boiler uses. Since solid coal 

cannot be burned in existing boilers designed to use oil or gas, coal 

substitution must depend largely on the choice of coal by firms purchasing 

new boilers. 

Nonboiler uses of oil and natural gas in manufacturing include a large 

number of heterogeneous processes such as use as a feedstock for the 

petrochemical industry and as a fuel for cement kilns. Coal-burning 

equipment is not commercially available for most nonboiler processes; the 

primary exception is equipment for the production of cement and lime. 

BOILER USES 

By comparing the total costs of new boilers by fuel type, it is possible 

to estimate the effects on fuel substitution and on the federal budget of 

several tax policy incentives designed to decrease the cost of coal-fired 

boilers relative to that of boiler systems using natural gas and oil. Total 

costs include equipment, operation, and maintenance costs as well as fuel 

costs. In addition to relative cost, boiler fuel choice also depends upon 

noncost factors such as a firm's perceptions of fuel supply availability, 

equipment reliability, adequacy of land area, and noncost environmental 

problems. Because of the difficulty in quantifying these noncost factors, all 

estimates must be viewed with a moderate degree of uncertainty. 

Estimates of the effects of five alternative tax policies on the use of 

solid coal in boilers are presented in the Summary Table. While some of the 

policy options induce coal use for a large share of new boiler fuel demand, 

none could reduce oil imports in 1985 by more than 8 percent (assuming 11.5 

million barrels a day of imports). The import reduction is modest both 

because the total boiler fuel market is a relatively small percentage of total 

U.S. energy demand and because the replacement of existing oil and gas 

boilers with new coal boilers will occur slowly. 

Current Policy 

If no specific new federal policies are undertaken to encourage coal 

use, solid coal is likely to be chosen for only 6 percent of new boiler fuel 

requirements in the 1981-1985 period. By 1985, total boiler coal use would 

be about 58 million tons, up from 45 million tons in 1974. This current 

policy estimate is based on and is sensitive to several key assumptions, 

including the following: 

xiv 
SUMMARY TABLE. ENERGY AND BUDGETARY EFFECTS OF CURRENT POLlCY AND FIVE 

ALTERNATIVE BOILER TAX POLICIES 

Current Policy 

A $3.00-a-barrel tax on 

oil and a tax on gas 

sufficient to increase 

its price to that of 

distillate oil (including 

the $3.00 tax) 

A $6.00-a-barrel tax on 

oil and a tax on gas 

sufficient to increase 

its price to that of 

distillate oil (including 

the $6.00 tax) 

40 percent tax credit 

New boilers 

Accelerated retirements 

Senate bill incentives 

House bill incentives 

New boilers 

Accelerated retirements 

1985 

total 

coal use (millions of tons 

per year) 

58 

88 

116 

95 

114 

140 

SOURCE: Congressional Budget Office 

Energy Effects 

Percent of 

1981-1985 

new boiler 

fuel demand 

captured by coal ~! 

6 

36 

63 

38 

61 

72 

1985 

oil and gas 

replacement 

(barrels per 

day equivalent) 

321,000 

621,000 

403,000 

353,000 

50,000 

600,000 

883,000 

717,000 

166,000 

!!:.! Reflects a 6 percent annual rate of inflation starting in fiscal year 1978. 

Budgetary Effects, 

Fiscal Years 1979-1985 

(millions of 

current dollars) al 

Cumulative Cumulative 

tax tax revenues expenditures 

3,091 

3,074 

3,361 

1,683 1,950 

(13,547)!l.1 (-1,756) !l.! 

~/ About 2.2 quadrillion BTUs of fossil fuels will be consumedin all new boilers purchased to meet expansion and 

replacement demand for the 1981-1985 period; these are the boiler investment decisions affected by 

federal policies enacted in 1979. The numbers in this column represent the portion of that new fuel 

demand satisfied by coal. 

All of the revenue is rebated. The negative tax expenditure estimate reflects the net impact of the 

two provisions: the extra 10 percent tax credit and the denial of the existing tax credit for new oil 

and gas boilers and new coal boilers financed with rebates. 

XV 
o By 1985, all crude oil will be sold at the world oil price, which is 

assumed to increase at the rate of U.S. inflation throughout the 

life of the boiler system. 

o A strict interpretation of the 1977 amendments to the Clean Air 

Act will prevail for both coal and oil starting in 1979. 

o Natural gas will be available for new boilers and prices for new gas 

will be deregulated in 1985. 

o Coal prices will increase only because of inflation and depletion of 

low-cost mines. 

o Unlike electric utilities, industries will not be able to sign longterm contracts or use low-rate unit trains for delivery. 

Senate Bill 

The Senate bill proposes a $6.00-per-barrel oil tax and a tax on natural 

gas sufficient to raise its price to that of distillate oil including the oil tax. 

The taxes are on fuel used in new boilers that have a capacity to consume 

100 million BTUs of fuel per hour or more and on fuel used in new smaller 

boilers if they are one of several new units at a Single site with aggregate 

boiler capacity over 250 million BTUs per hour. In addition to the taxes, an 

extra 15 percent refundable tax credit is offered to firms investing in coalfired boilers. The increased coal use resulting from this plan is equivalent 

to 600,000 barrels a day of oil consumption in 1985. The cumulative tax 

revenue by fiscal year 1985 is $1.7 billion, and the cumUlative tax 

expenditure is $2.0 billion. 

House Bill 

Oil and gas user taxes in the House version are imposed on oil and gas 

used in both new and existing boilers and in boilers of all sizes. The oil tax 

gradually increases to $3.00 per barrel in 1985. The gas tax gradually raises 

gas prices to the equivalent price of distillate oil not including the oil tax. 

Both new boilers and existing boilers converted to coal are eligible for tax 

rebates, and the existing 10 percent investment tax credit is denied to 

investors choosing oil- and gas-fired systems. By 1985, the resulting 

increase in coal use is equivalent to 883,000 barrels a day of oil consumpxvi 
tion; 19 percent of the replacement involves the early retirement of existing 

boilers. Cumulative tax revenue would be $13.5 billion, although the total 

revenue is assumed to be rebated, thus providing a major incentive to use 

coal. Denying the existing 10 percent investment tax credit to new oil and 

gas boilers and to new coal boilers financed with the rebate results in a 

cumulative budget savings of $1.8 billion. 

Alternative Tax Options 

Coal's market share could be raised to 36 percent by imposing a $3.00-

per-barrel tax on oil and a tax on natural gas sufficient to increase its price 

to that of distillate oil including the oil tax; coal would be substituted for 

the equivalent of 321,000 barrels of oil a day. By doubling the tax, coal 

substitution would increase to 621,000 barrels a day. Both sets of taxes are 

imposed only on oil and gas used in new boilers. An additional 40 percent 

tax credit for coal boilers would induce coal substitution for the equivalent 

of 403,000 barrels a day; 12 percent of that substitution is achieved by 

inducing the early retirement of existing oil and gas units. The first two 

taxes would generate approximately $3 billion in revenue, while the tax 

credit would decrease revenue by $3.4 billion. 

NONBOILER USES 

The original National Energy Plan included taxes on most oil and gas 

used in the manufacturing industries, but the House and Senate versions of 

the tax program are primarily boiler fuel taxes. 1/ Most nonboiler uses 

were exempted because of the lack of proven equipment and processes 

employing solid coal. The limited engineering analysis available does, in 

fact, conclude that solid coal-burning technologies are not commercially 

available for most nonboiler oil and gas uses. 

]j The House version exempts all fuel used as a raw material and other 

nonboiler (l'processtl) uses in which coal use is not feasible for 

technical, economic, or environmental reasons. And coal use is not 

technically feasible for most nonboiler applications. If nonboiler uses 

do qualify, they are taxed at a lower rate under the House bill. The 

Senate exempts all raw material and process uses. 

xvii 

32-498 0 • 78 • 2 
Taxes on nonboiler oil and gas consumption could serve as an incentive 

for solid coal substitution by inducing businesses to undertake the required 

research and development of new equipment or processes. Alternatively, 

the federal government could finance the research and development. Both 

of these strategies might be misguided, however, since processed coal may 

be a more likely substitute for nonboiler oil and gas consumption. 

ADDITIONAL CONSIDERATIONS 

As presented above tax incentives could be adopted to induce manufacturing firms to use solid coal for a substantial portion of their n~w boiler 

fuel requirements. The need and exact nature of such legislation could, 

however, be questioned on several grounds: (1) oil prices may rise faster 

than projected, leading to more rapid sUbstitution of coal even in the 

absence of tax incentives; (2) air pollution regulations might restrict or 

encourage coal use; and (3) in the longer term processed coal could be made 

a serious competitor to oil and gas for certain selected uses. 

Impact of Foreign Oil Prices 

The need for coal substitution legislation is t:ncertain since it depends 

to a large extent on the future oil-pricing strategy of the Organization of 

Petroleum Exporting Countries (OPEC). If it is assumed, as the Administration has at times argued, that large oil price increases by OPEC are 

inevitable starting in the mid-1980s and, further, that coal prices will not 

increase in tandem, then there is no need for any additional tax legislation 

promoting a shift to coal. The expectation of high oil prices will drive the 

private sector to coal for at least the boiler component of total oil and gas 

use. Specifically, annual oil price increases of 4 percent or more above the 

U.S. rate of inflation, with no similar price increase for coal, would make 

solid coal the lowest-cost fuel for most new boilers. 

Impact of Air Pollution Regulations 

The federal government significantly affects the relative cost of coal, 

oil, and natural gas boilers through environmental policy as well as through 

energy tax programs. Most air pollution regulations add to the equipment, 

operation, or fuel costs of both coal and oil boilers. Consequently, in 

promulgating air pollution emission standards, it is critical to determine the 

differential impacts on the total cost of operating boilers of different fuel 

xviii 
types. It is possible to impose air pollution regulations that would be strict, 

but nonetheless would favor the use of coal; that is, regulations that add 

more to the cost of using oil than coal and thereby encourage expanded coal 

use. Therefore, air pollution policy is a critical component of any coal 

substitution program and can be used in place of, or in addition to, tax 

incentives. 

Solid Coal Versus Processed Coal 

If a coal SUbstitution strategy is to be adopted, the nation must ask in 

what form the coal should be used--in its natural, solid state or processed 

into a gas or a liquid. Such a focus is essential if the federal government is 

to guide a transition from oil and gas to coal, and yet it is noticeably lacking 

in the current energy debate. Each form should be considered since each 

could meet the needs of a particular energy user or a particular geographic 

area. Solid coal might, for example, have a relative cost advantage for 

certain large boilers. Technical constraints, however, preclude its use for 

many other processes. Furthermore, in certain regions, known and suspected environmental problems might be more manageable if coal is 

processed into a liquid or gaseous fuel at a small number of large, remotely 

sited plants rather than being consumed at hundreds of individual factories. 

Thus, the issue of whether the nation adopts a solid coal, processed coal, or 

combination strategy is a critical energy policy decision. If processed coal 

is to play a role, however, the federal government must do more than 

provide cost incentives. Specifically, regulatory decisions with respect to 

pricing and environmental policy are needed. 

xix 

CHAPTER 1. INTRODUCTION 

The Administration's National Energy Plan, which was submitted to 

the Congress in April 1977, proposed as a key objective replacing oil and 

natural gas with coal. It was argued that the nation should use its abundant 

coal resources instead of depending on unreliable and expensive oil imports 

or on domestic oil and natural gas reserves that soon could be depleted. 

Indeed, the majority of the oil import savings credited by the Administration 

to its plan were to be achieved through coal substitution. Although the 

National Energy Plan has been largely rewritten by the House and the 

Senate, replacing oil and gas with coal continues to be a fundamental 

ingredient. Replacement is to be promoted primarily by offering tax 

rebates and tax credits to those buying coal-burning equipment and by 

imposing excise taxes on those consuming oil and gas; also, the use of oil and 

gas will be prohibited in specific cases through regulatory programs. 

This report discusses the likely impact of alternative federal policies 

aimed at encouraging the replacement of oil and natural gas with solid coal 

in the manufacturing industries. It focuses on the industrial sector because 

that is the most likely candidate for increased use of solid coal over the 

next 10 to 15 years. Few opportunities appear to be available in the 

residential, commercial, or transportation sectors, and the electric utility 

industry has already begun the transition to coal and nuclear power. Within 

the manufacturing sector, oil and gas consumption is most often classified 

according to boiler or nonboiler use, with the latter including a large number 

of heterogeneous uses. The present study follows this two-category division. 

For new boilers--for which solid coal-burning equipment is commercially 

available--the report analyzes the conditions under which coal would be the 

cheapest fuel. Firms purchasing new boilers will compare the cost of buying 

and operating coal, oil, and gas units, and they will choose the lowest-cost 

fuel if other criteria, such as reliability of fuel supply and availability of 

space, are satisfied. For nonboiler oil and gas uses, the analysis is more 

restricted. Some industries (primarily cement and lime producers) already 

use oil and gas as well as solid coal in their nonboiler equipment and have 

voluntarily begun coal substitution. For most nonboiler oil and gas uses, 

however, it appears that technologies for burning solid coal are not readily 

available; this report identifies specific processes that offer the opportunity 

for commercial development in the near term. 

1 
Coal can be converted into a gas or a liquid and can then be 

considered as a boiler or nonboiler fuel; this analysis, however, provides 

information only on the impact of federal policies aimed at increasing the 

burning of solid coal in the industrial sector. Nevertheless, a review of the 

costs and timing of a transition to solid coal provides insight into whether or 

not emphasis should be given to indirect transitions involving gasification 

and liquefaction or coal converted to electricity. 

Chapter II offers an overview of the oil and natural gas consumption 

in the industrial sector. Particular attention is paid to the type of industrial 

process and the industry of origin because these characteristics are important in determining the potential for coal substitution. Chapter III analyzes 

the cost factors that enter into the selection of new boiler equipment and 

fuel. Since meeting air pollution regulations is a critical cost associated 

with the consumption of fossil fuel, the assumptions concerning future 

environmental regulations and cost data for air pollution control equipment 

are discussed in Chapter IV. The technical feasibility for coal substitution 

in nonboiler uses is discussed in Chapter V. Chapter VI presents estimates 

of industrial demand for coal for boilers if current policy were continued 

and specifies the sensitivity of such estimates to changes in key assumptions. Finally, the effects of alternative coal substitution policies on energy 

use and on the federal budget are discussed in Chapter VII. The report also 

contains three appendixes: the first considers the possibility that increased 

coal demand would be constrained by inadequate rail transportation, the 

second provides the theory and data for the model of boiler fuel choice used 

throughout the report, and the third displays impacts on the federal budget 

by fiscal year. 

2 
CHAPTER II. THE POTENTIAL FOR SOLID COAL SUBSTITUTION IN 

INDUSTRY 

The manufacturing sector of the U.S. economy is the most promising 

target for solid coal substitution. In all other sectors, either major 

technical barriers to the sUbstitution are present, or the potential for oil and 

gas savings is slight, or the transition to coal or nuclear fuel is already welladvanced. 

Specifically, coal use in the household and transportation 

sectors--which represent approximately 24 and 16 percent of total U.S. 

energy consumption--would depend upon solid coal being converted into a 

liquid or a gas or into electricity. The electric utility industry, which 

accounts for approximately 16 percent of energy consumption, has already 

turned from oil and gas to coal or nuclear power because of the relative cost 

advantage of the latter two fuels. The agriculture, mining, and construction 

industries combined represent less than 8 percent of total energy consumption; thus, the potential savings from converting these sectors to direct coal 

use would be minimal. Moreover, there are technical barriers to coal use in 

these sectors. 1/ Finally, in the commercial sector, which represents 8 

percent of total energy use, there is some potential for coal substitution, 

particularly for steam boiler use. Most of these boilers, however, are small 

and have relatively low utilization rates; thus, large financial incentives 

would be needed to stimulate coal substitution. 

The major potential to replace oil and gas with solid coal is in the 

manufacturing sector, which represents about 29 percent of total energy 

demand. Even within this sector, however, the potential for solid coal use 

varies significantly, depending upon the specific processes involved and the 

capability of existing equipment to burn coal. This chapter provides an 

1/ In agriculture, most of the fuel is used to power farm vehicles such as 

tractors or irrigation pumps. In construction, the greatest use of oil is 

for asphalt to pave roads, and fuel used to power vehicles accounts for 

much of the remaining consumption. In mining, the data are limited, 

but it appears that the greatest use of energy is for extracting oil and 

natural gas; in this case, solid coal would have to compete with readily 

available and perhaps unmarketable supplies of oil and gas. 

3 
overview of energy consumption in the manufacturing sector, with reference 

to specific processes and equipment capabilities. 

ENERGY USE IN MANUFACTURING 

The manufacturing sector consumed 20 quadrillion British Thermal 

Units (quads) of energy in 1974. Natural gas was by far the most popular 

fuel, accounting for 36 percent of the total; the market shares for oil 

(including refinery gas) and coal were 27 percent and 18 percent, respectively. Electricity and other fuels--for example, wood processing 

waste--represented the remaining 19 percent (see Table 1). 

In order to define the potential for substituting solid coal for oil and 

gas, it is critically important to specify the process in which the fuel is 

used. In the manufacturing sector, four broad categories of processes can 

be distinguished according to use: 

o Production of steam in industrial boilers; 

o Generation of direct heat (rather than indirect heat in the form of 

steam) for nonboiler equipment such as furnaces, ovens, and kilns; 

o Use as a raw material; and 

o Use for other purposes such as machine drive. 

A recent detailed study of energy use by Energy and Environmental 

Analysis, Inc., found that, of the 3.6 quads of coal used in 1974 in the 

manufacturing sector, 65 percent was used to produce coke for the iron and 

steel industry (that is, as a raw material), 21 percent was used in boilers, 7 

percent was used for non boiler equipment, and the remaining 7 percent 

could not be traced to specific purposes. About 31 percent of the oil and 

natural gas consumed by manufacturers in 1974 could be traced to boilers; 

the remainder waS used primarily in nonboiler equipment such as furnaces or 

as a raw material in the chemical industry (see Table 2). '1:./ 

Tracing fuel use to specific purposes within manufacturing is a 

difficult task that requires many engineering judgments. Only a few studies 

2/ Energy and Environmental Analysis, Inc., Technical Potential for Coal 

Use in Industrial Equipment other than Boilers, prepared for the 

Congressional Budget Office (April 6, 1978). 

4 
TABLE 1. NET ENERGY CONSUMPTION IN THE MANUF ACTURING SECTOR 

Fuel 1015 BTUs Percent 

Coal 3.6 18 

Oil !};./ 4.4 22 

Natural Gas 7.1 36 

Refinery Gas £/ 1.0 5 

Electricity ~/ 2.1 10 

Other ~/ 1.8 9 

Total 20.0 100 

SOURCE: Department of Energy, Energy Consumption Data 

Base, 1974. 

~/ 

~/ 

9./ 

Fuel oil, liquid petroleum gas, and miscellaneous petroleum products. 

A by-product gas generated as crude oil is processed in 

refineries; it is used to generate process heat and steam. 

Purchased electricity; these are the BTUs in delivered 

electriCity and exclude conversion losses. 

Includes two large items: wood processing wastes burned 

as fuel in the paper industry (about 800 trillion BTUs) and 

fuels used at small manufacturing plants, suspected to be 

primarily natural gas (about 1 quadrillion BTUs). 

5 
TABLE 2. OIL AND GAS CONSUMPTION BY INDUSTRY AND TYPE OF PROCESS IN THE 

MANUFACTURING SECTOR, 1974: IN QUADRILLION BTUs 

Boiler Nonboiler Raw 

Industry (SIC Code) Equipment ~/ Equipment ~/ Material Other ~/ Total 

Food (SIC 20) 0.40 0.10 0.10 0.60 

Paper (SIC 26) 0.70 0.15 0.13 0.98 

Chemicals (SIC 28) 1.10 0.50 2.30 0.30 4.20 

Petroleum (SIC 29) 0.63 2.20 0.05 2.88 

Stone, Clay, Glass (SIC 32) 0.02 0.80 0.82 

Primary Metals (SIC 33) 0.30 1.10 0.10 0.20 1. 70 

Other Manufacturing 0.70 0.70 1.40 

Total 3.85 5.55 2.40 0.78 12.58 

SOURCE: Energy and Environmental Analysis, Inc., Technical Potential for Coal Use in Industrial Equipment 

Other than Boilers, prepared for the Congressional Budget Office (April 6, 1978). 

~/ Includes fuel used for process steam and for on-site production of electricity. 

~/ Includes fuel for direct heat. 

c/ Includes fuels used for purposes such as machine drive. 
on this subject are available, and each has its own approach and set of 

definitions; nevertheless, the conclusions of other studies are in general 

agreement with the data in Table 2. In 1975, Dow Chemical Company 

conducted a survey of large industrial energy consumers and found that 47 

percent of the oil and gas used could be traced to boilers; the percentage is 

higher than that implied in Table 2 because the total excludes oil and gas 

used as a raw material and the definition of oil and gas appears to exclude 

refinery gas. 3/ If only boiler and nonboiler equipment was considered in the 

table, 41 percent of the total would be attributed to boilers. A recent 

report prepared at Drexel University found that 43 percent of all fossil fuel 

used in boiler and nonboiler equipment in manufacturing could be traced to 

boilers; this figure also excludes raw material uses of fuel and includes coal 

as well as oil and gas. 4/ Battelle Laboratories published a similar estimate, 

although it is especially difficult to compare this study with the other three. 

Battelle found that about 33 percent of the fuel used in boiler and nonboiler 

equipment could be attributed to boilers. §./ 

TARGETS FOR SUBSTITUTION 

The potential for oil and gas savings through coal substitution 

depends not only on the purpose of the fuel use but also on the capability of 

the existing equipment to utilize coal. Unfortunately, coal cannot be used 

effectively in equipment that was not designed to burn coal. This simple 

engineering fact implies that policies aimed at replacing oil and gas 

consumption with coal consumption must necessarily induce firms to replace 

oil and gas equipment with coal-fired equipment. This replacement of 

equipment can be achieved in three ways: 

3/ 

§/ 

o Reconverting existing equipment that was originally designed to 

burn coal but now uses oil and gas; 

Dow Chemical Company, Evaluation of New Ener Sources for Process 

Heat, prepared for the National Science Foundation September 1975 , 

p. 115. 

Harry Brown and Bernard Hamel, Industrial Application Study, vol. II, 

prepared for the U.S. Energy Research and Development Administration 

(December 1976), p. 26. 

Battelle Laboratories, Survey of Applications of Solar Thermal Energy 

Systems to Industrial Process Heat, vol. 2, prepared for the U.S. Energy 

Research and Development Administration (January 1977), p. 11. 

7 
o Accelerating the retirement of oil and gas equipment; 

o Purchasing new coal-fired equipment to meet expanded energy 

needs and replacement demand. 

Conversion and Accelerated Retirement of Existing Equipment 

A federal regulatory program aimed at replacing oil and gas with coal 

in the industrial sector already exists. The Energy Supply and Environmental Coordination Act (ESECA) of 1974 authorized the Administration to 

prohibit existing "major fuel-burning installations" (MFBI) from burning oil 

or natural gas and to order new equipment to be designed to be capable of 

burning coal. 

The 'experience of ESECA prohibition orders suggests that the realistic potential for oil and gas replacement in existing units is quite small. 

Under ESECA, an existing unit could be prohibited from using oil or gas if, 

among other things, the unit had originally been designed to burn coal. A 

survey of MFBI conducted by the Federal Energy Administration in 1975 

revealed 780 "coal-capable" units, or 12 percent of the 6,200 units covered 

by the survey. ~/ 

On May 9, 1977, the Administration took the first legal actions to 

order the prohibitions: "Notices of Intent to Issue Prohibition Orders" were 

issued to 24 sites containing 58 units. In June 1977, 28 of the original 58 

units were issued actual prohibition orders. The 28 units were expected to 

use 2.6 million tons of coal each year in lieu of 7 million barrels of oil and 

13 billion cubic feet of natural gas; the other 30 units were already using 

waste fuels. 

The Department of Energy is now preparing a second round of orders. 

They first selected 305 coal-capable units that were installed after 1950 and 

thus might have sufficient useful life remaining to justify reconversion. 7/0f 

this total, 100 units located in cities that were not in violation of air 

pollution standards were targeted for further action. When the firms that 

7/ 

Federal Energy Administration, Major Fuel Burning Installation Coal 

Conversion Report (1975). 

The MFBI data contain 651 coal-capable boilers that reported oil or gas 

as a primary fuel; 252 were installed after 1950, and only 75 were 

installed after 1960. 

8 
operated the 100 units were approached, it was found that 35 of the units 

had already been converted to coal and others were burning coal part of the 

time. 

It thus appears that the potential oil and gas savings from a policy 

aimed at converting existing coal-capable units are small. First, this 

category contains few units; second, many of the units will be switched to 

coal voluntarily in the absence of any federal legislation. The 100 targeted 

units in the Department of Energy's second round of prohibition orders could 

potentially consume about 7 million tons of coal a year. Adding this to the 

2.6 million tons for units that have already received prohibition orders yields . an optimistic estimate of 9.6 million tons of coal that will be consumed by 

existing units that convert to coal without additional government incentives. 

Accelerated retirements of oil and gas units are possible; in view of 

the high equipment costs for coal, however, they are unlikely without a 

strong financial incentive. For a firm to decide to scrap an oil or gas uni t 

with remaining useful life, it would have to be cheaper to pay the annualized 

costs of equipment, fuel, operation, and maintenance for a new coal-fired 

unit than to pay simply the costs of fuel, operation, and maintenance for the 

existing oil or gas unit. In aGldition, an accelerated retirement would be an 

unscheduled investment and might be precluded by a shortage of investment 

funds in particular firms. This topic is considered further in Chapter VII. 

New Eguipment 

New boilers are the most promising target for policies promoting coal 

substitution. Coal boilers are commercially available, and the federal 

government can, through pricing policies, make coal the economically 

attractive fuel. But coal is not the only substitute for oil and gas in boilers. 

Boilers can burn many nonconventional fuels. For example, the most 

popular boiler fuel in the paper industry is a wood processing waste called 

"black liquor"; other industries use wood chips, old tires, wastepaper, and 

the like. Indeed, in the last five years, more large industrial boilers have 

been designed to burn nonconventional fuels than have been designed to burn 

coal. Oil and natural gas may be replaced as a boiler fuel, but it is likely 

that coal and nonconventional fuels will share the task. 

Coal is not used widely for nonboiler energy consumption, and coalfired equipment is not commercially available for many processes; the 

cement and lime industries are the main exceptions. Coal technologies 

would have to be demonstrated on a commercial scale before coal could 

penetrate this market. 

9 
SUMMARY 

The near-term potential for replacing oil and natural gas with solid 

coal is restricted largely to the manufacturing sector. Within this sector, 

the most promising target for coal substitution is oil and gas used in boilers. 

This target can be set in perspective by noting that, of all U.S. oil and 

natural gas use, about 25 to 30 percent can be traced to manufacturing, and 

30 to 40 percent of that can be traced to boiler uses. Thus, the prime target 

for coal substitution amounts to 8 to 12 percent of U.S. oil and gas 

consumption. Finally, since solid coal cannot be burned in existing boilers 

designed to burn only oil and gas, coal sUbstitution must depend largely on 

firms purchasing new boilers. The equivalent of 1.1 million barrels a day of 

fossil fuels is projected to be consumed in all new boilers purchased to meet 

the demands of expansion and replacement for the 1981-1985 period. 

10 
CHAPTER III. THE ECONOMICS OF ALTERNATIVE BOILER FUELS 

A firm will usually choose the type of fuel and boiler that produces 

steam at the lowest total cost to the firm. That total cost must include the 

annualized costs of equipment, fuel, operations, and maintenance. The 

least-cost criterion is, however, subject to at least two critical constraints--adequate space and availability of fuel supply. Coal requires far 

more land area than oil or gas because coal-fired equipment is large and 

because coal storage piles can cover acres of land. In older industrialized 

areas, the land needed for coal simply might not be available. At times, 

firms might not choose the least-cost operation because they believe that an 

alternative represents less risk of a supply interruption. Users of all major 

fuels have experienced short-term supply interruptions in the last few years 

because of coal strikes, oil embargoes, and natural gas curtailments; the 

possibility of such interruptions, however, varies substantially by region. 

Many observers believe that firms will be reluctant to use coal, even if it is 

the lowest-cost fuel, for reasons other than the two critical constraints. 

For example, coal is more difficult to handle, and it requires more laborers. 

In short, the use of coal gives rise to a greater number of potential problems 

than oil or gas. All of this points to the fact that fuel choice is affected by 

factors other than costs. The Administration's energy plan, however, does 

not attempt to--and probably cannot--remove many of the noncost factors 

impeding increased coal use. 

This chapter treats only the cost factors that enter into a firm's 

decisions about which boiler equipment and fuel to choose. First, the 

economic model that has been used in this analysis to approximate those 

economic decisions is presented, noting particularly the relative cost 

information on which the model is based. Then, the critical assumptions 

that underlie the data used in the model are explained. Appendix B contains 

a more detailed presentation of the model, and all of the data and methods 

are documented fully in the cited reports. 

THE ECONOMICS OF BOILER FUEL CHOICE 

Industrial firms need boiler equipment to produce steam, which is 

used for a variety of purposes. For example, steam is used in papermiUs to 

cook a mixture of wood and a chemical that reduces wood to fiber, 

producing pulp. Steam drives a turbine to produce electricity in cases where 

11 
on-site electricity needs are large. In the chemical industry and in 

petroleum refining, steam is mixed with intermediate products to cause 

chemical reactions. Regardless of how the steam is used, however, a firm 

seeks to produce it at the lowest possible cost. 'The model used in this study 

to simulate the economic decisions of a firm is based on this simple concept: 

a firm will select the least-cost system. In other words, a firm will choose a 

coal boiler system to produce steam when the total annual cost of coal is 

less than the total annual cost of oil or gas. 

The data collected for this study show that boiler equipment for coal 

is always more expensive than an oil or gas unit of comparable size. Coal 

boilers are bigger, coal delivery and handling equipment is more extensive, 

and coal generally requires more pollution control equipment. Operation 

and maintenance costs are also higher for coal. In contrast" the fuel prices 

for coal are lower than those for oil or gas in some regions of the country. 

A firm will prefer coal if the relative fuel cost advantage of coal overcomes 

its relative equipment, operation, and maintenance cost disadvantage. The 

larger the boiler and the higher the utilization rate (the percentage of time 

the boiler is in operation), the greater are the chances that coal will be 

chosen over oil or gas. 

Before a firm can decide which boiler to purchase, it must know the 

boiler size required, the delivered cost of alternative fuels, and the 

expected utilization rate. There is a direct correlation between each of 

these factors and cost: equipment costs vary significantly by boiler size; 

the price for fuels varies significantly by region of the country, largely 

because of transportation costs; and total fuel bills vary with utilization 

rates. The model developed here performs separate cost comparisons for 5 

boiler sizes in 10 regions of the country. The model estimates the 

utilization rate at which coal starts to be the cheapest fuel for a particular 

size boiler in a particular region; that is, the utilization rate at which the 

annual fuel bill advantage of coal starts to outweigh its initial equipment 

cost disadvantage. Any firm choosing a fuel for that size boiler in that 

region will choose coal if the expected utilization rate is high enough. 

The conceptual framework of the model of boiler fuel choice can be 

illustrated using Figure 1. Costs of producing steam for a boiler of a certain 

size are represented on the vertical axis; utilization rates are shown on the 

horizontal axis. A coal-fired boiler costs more than an oil-fired boiler, 

which in turn costs more than a boiler designed for natural gas; thus, points 

3, 2, and 1 represent different costs at a zero utilization rate. As the 

utilization rate increases, total cost increases because the costs of fuel, 

operation, and maintenance are added. 

12 
Figure 1. 

Boiler Costs By Fuel and Utilization Rate For 

Region X and Boiler Size Y 

Total Cost 

3 

2 

Coal L...-------------

o B 

Utilization Rate 

A 100 

In Figure 1, coal becomes cheaper than both oil and gas at utilization 

rate A; that is, coal will be used in region X for new boilers of size Y that 

are expected to be used A percent of the time or more. Oil becomes 

cheaper than gas at utilization rate B; thus, oil will be used for new boilers 

with expected utilization rates between Band A. Gas will be used in all 

other new boilers. A computer program was developed to calculate these 

t'breakpointtt utilization rates. y 

Y The model compares average annual costs (annuities). The initial 

investment is annualized by applying a capital charge rate to equipment 

costs; that rate is similar to a mortgage rate which translates a home 

loan into required annual payments the homeowner must make. Annual 

fuel costs are represented as annuities. An 8 percent after-tax, real 

rate of return is assumed for discounting. 

13 

32-498 0 .. 78 ~ 3 
In order to make the type of cost comparison illustrated by Figure 1, 

one needs to know the cost of the boiler equipment, the annual cost of 

operation and maintenance, and the annual cost of fuel. For this analysis, 

equipment cost data were collected from equipment manufacturers and 

were then compared with similar data presented in published technical 

reports (see Table 3). According to these data, coal equipment is generally 

three times as expensive as equipment for low-sulfur oil and four or five 

times as expensive as equipment for natural gas. The equipment cost 

disadvantage of coal relative to low-sulfur oil ranges from $3.2 million to 

$16.7 million. This disadvantage must be offset by a fuel bill advantage 

over the life of the boiler if coal is to be chosen. 

TABLE 3. 

Fuel Type 

Coal 

BOILER EQUIPMENT COSTS BY FUEL TYPE AND BOILER 

SIZE: IN THOUSANDS OF 1977 DOLLARS ~I 

Boiler Size (MPPH) bl 

50 100 200 300 400 

Northern Appalachian 4,855 8,105 14,238 19,508 24,421 

Central Appalachian 4,696 7,827 13,796 18,912 23,676 

Midwestern 

Western 

Oil 

High-sulfur 

Low-sulfur 

Natural Gas 

SOURCE: 

4,862 8,120 14,296 19,592 24,523 

4,834 8,073 14,218 19,484 24,400 

2,530 4,164 6,966 9,665 12,126 

1,655 2,668 4,421 6,179 7,780 

1,233 1,882 2,942 4,020 4,964 

The data were collected from equipment manufacturers and 

technical publications and are documented completely in ICF, 

Inc., Economic Considerations in Industrial Boiler Fuel Choice, 

submitted to the Congressional Budget Office (June 1978). 

~I Includes costs of equipment, planning and design, and installation for a 

complete boiler system--from fuel handling through waste disposal. 

Q/ Thousands of pounds of steam per hour. 

14 
The equipment costs presented in Table 3 are for a complete boiler 

system, from fuel delivery through waste disposal. The detailed costs for a 

boiler that produces 200,000 pounds of steam per hour (MPPH) using highsulfur Midwestern coal can serve as an example of the relative importance 

of the various equipment components (see Table 4). The boiler itself 

represents 38 percent of the initial direct investment. Air pollution 

equipment equals 33 percent of the direct costs. Fuel handling facilities, 

which are required for rail delivery, and coal storage represent 8 percent of 

direct equipment costs. The expense of constructing the boiler (indirect 

costs) is also substantial. In this example, total indirect costs are $3.7 

million and direct costs are $10.5 million. 

The annual operation and maintenance costs employed in this analysis 

were estimated using standard engineering methods. Those estimates, 

however, were based on several ll.Ssumptions that are detailed in the ICF 

report. 2/ Fuel costs were projected using two models: coal prices from 

ICF's Coal and Electric Utilities Model, and oil prices from a model 

developed by Sobotka and Company. ~/ 

CRITICAL ASSUMPTIONS 

A number of assumptions are made throughout this analysis, but the 

final results are most sensitive to two sets of assumptions: those regarding 

the relative prices of the three major fuels--oil, natural gas, and coal; and 

those regarding the requirements for air pollution control equipment. These 

assumptions are discussed below. 

Coal Prices. The most significant and obvious difference between 

prices for coal and prices for oil or gas is that coal prices are not regulated 

by the federal government. Coal prices are determined directly by the 

forces of supply and demand. Also the price of coal to electric utilities can 

differ significantly from the price to industries. First, coal is generally sold 

to utilities, which are the largest coal customers, on long-term contracts 

that specify the price per ton to be paid throughout the contract period. It 

~/ 

ICF, Inc., Economic Considerations in Industrial Boiler Fuel Choice, 

submitted to the Congressional Budget Office (June 1978). 

Ibid.; and Sobotka and Co., Refinery Gate Product Price Differential 

Forecasts for 1985, submitted to the Department of Energy (1978). 

15 
TABLE 4. DETAILED EQUIPMENT COSTS FOR A COAL BOILER 

PRODUCING 200 MPPH USING HIGH-SULPHUR 

MIDWESTERN COAL: IN THOUSANDS OF 1977 DOLLARS 

Air Pollution 

Equipment Components Steam Plant Control 

Land and Permits 135 8 

Yard Work 460 35 

Fuel Handling and Storage 825 

Boiler House 695 

Boiler Equipment 4,000 

Ash Handling Equipment 550 

SO Control Equipment 2,755 

Pafliculate Control Equipment 685 

Electric Power 395 

Total, Direct Costs 7,060 3,483 

Construction Management 

and Facilities 706 348 

Engineering and Design 353 174 

Contingency 1,218 401 

Working Capital 97 131 

Fuel Stockpile 325 

Total, Indirect Costs 2,699 1,054 

Total, Capital Costs 9,759 4,537 

SOURCE: ICF, Inc., Economic Considerations in Industrial Boiler Fuel 

Choice. 

16 
is not clear whether long-term contracts of this type would be offered to 

industrial users or would be desired by them. In this analysis it is assumed 

that industrial users will not enter into long contracts, but will buy coal 

annually on the "spot market" or on short-term contracts. Spot market 

prices will generally be higher over the years than prices for coal on longterm contracts. Although long-term contracts would offer a price advantage, they would carry the disadvantage of a long-term financial commitment. Second, utilities often take advantage of the low railroad rates 

offered for "unit trains"--lOO-car trains that shuttle between the coal mine 

and the utility--whereas industries are not expected to require enough coal 

to use unit trains. Unit train rates are about one-half those for single-car 

deliveries. 

Spot market coal prices are expected to rise over time for two 

reasons. First, general inflation will drive labor and equipment costs 

upward. Second, as more coal is used, mining companies will have to open 

mines in locations where coal is more difficult to extract and therefore 

more costly to mine. In states such as Colorado and Utah, for example, coal 

prices for new mines are expected to rise about 1 percent a year (in real 

terms) because coal will be increasingly more expensive to mine. ~/ 

Coal prices could, of course, increase at a faster pace than assumed. 

Wage demands, rising state severance taxes, and higher rail rates are 

frequently cited as possible reasons for projecting more rapid escalation of 

coal prices. For example, the 1978 United Mine Workers' settlement could 

result in a 1 to 2 percent increase in real coal prices at the minesite in each 

Spot prices are assumed to equal the first-year cost of opening a new 

mine or enlarging an existing mine; that is, spot prices are assumed to 

equal the marginal cost of producing coal in each region. Spot prices 

could be higher than contract rates for several reasons. First, the 

utility signing the contract absorbs the downside risk of opening a mine; 

that is, the utility will pay for the coal whether it is needed or not. 

Second, the costs of operating a mine for the spot market can be higher 

because of variable output; start-up costs are incurred more frequently 

and problems with cash flow result in a greater number of loans. Third, 

mine owners might demand a greater rate of return for a spot mine 

because of the risks involved. Finally, a contract can be viewed as a 

show of the market strength of the buyer; in a monopsony situation, one 

buyer can control the market and force producers to accept lower 

prices (that is, producer surplus can be denied). 

17 
of the next three years. It is uncertain whether future wage settlements 

will be comparable and, more important, whether labor productivity will 

resume its upward trend and offset any wage pressure on prices. Labor 

productivity has fallen dramatically since 1969, in part because of federal 

legislation regarding health and safety in mines and new union work rules. 

The estimates used in this analysis for current policy implicitly assume that 

real wage increases are offset by increased productivity; the effect of this 

assumption is illustrated in Chapter VI. 

Oil Prices. The principal petroleum product used in boilers is residual 

oil, which is made from crude oil at petroleum refineries. Since crude oil 

accounts for more than 90 percent of the value of residual oil, the price of 

residual oil is largely determined by the price of crude oil. 

The average price of crude oil to U.S. refineries is affected by the 

relative amounts of imported and domestic crude they use and the prices of 

each. Imported crude, which currently accounts for about 45 percent of 

U.S. supply, sells at the going world rate. The price of domestic crude, 

however, is held below the world price by federal regulation. Those 

regulations are scheduled to expire by 1981, but it is assumed in this analysis 

that they would be extended and that the average domestic price will be 

allowed to rise by 10 percent each year until the world price is reached. 

A key assumption underlying the estimates of residual oil prices used 

in this paper is that the world price of crude oil--the price set by the 

Organization of Petroleum Exporting Countries (OPEC)--will increase only 

at the general rate of U.S. inflation. If inflation persists at about 5 or 6 

percent, the price for domestic crude under current policy will equal the 

world price in 1985. 5/ It is assumed that all crude will be sold at the world 

price from that poinf on. 

There is little analytical basis for projecting the policies of OPEC 

since the cartel members will face conflicting political and economic 

pressures when they decide future price policy. The uncertainty is something with which both business and federal policymakers must contend. 

Chapter VI demonstrates the sensitivity of coal demand to alternative 

assumptions about oil prices. 

§/ The alternative of equaling world prices sooner would not significantly 

affect investment decisions. This is because the investor views fuel 

bills over a 30-year period, and slightly lower prices in the first few 

years is inconsequentiaL 

18 
Natural Gas Prices. Currently, natural gas is sold in two distinct 

markets: the interstate market, in which prices are controlled by the 

Federal Energy Regulatory Commission; and the intrastate market, in which 

prices are not regulated. The price for natural gas used in this report for 

current policy is based on the assumption that the dual market is allowed to 

continue. 

Under current regulations, distributors of interstate gas pay different 

prices for gas from different sources. Higher prices are generally allowed 

for newly discovered gas, gas imports, and synthetic gas. Industrial users 

face an average of these prices. That average increases over time as more 

and more gas becomes eligible for higher price levels. In the intrastate 

market, demand and supply determine how prices will change. 

Under current policy, it is assumed that natural gas will be available 

for new boilers at prices that will be allowed to rise only to the equivalent 

price of distillate oil, the closest competitor to gas. The point at which gas 

prices reach the Tldistillate equivalent!! price varies by region, but in general 

it occurs around 1990. Prices are assumed to be constant in real terms 

thereafter. 

When alternative tax policies for boilers are analyzed in Chapter VII, 

it will be assumed that prices for new natural gas will be deregulated 

according to a recent agreement between House and Senate conferees. 

Under that agreement, prices for new gas are allowed to increase gradually 

each year until 1985. Under incremental pricing provisions, industries bear 

the burden of new, high-cost gas if they are served by interstate pipelines. 

After 1985, gas prices are assumed to rise beyond world oil prices; this 

"bonus" reflects the lower costs for equipment, operation, and maintenance 

associated with gas used in both boiler and nonboiler industrial uses, as well 

as in nonindustrial uses. The bonus is assumed to average $0.50 per million 

BTUs (MMBTU). §/ 

Air Pollution Control Requirements. Many assumptions underlie the 

estimates of relative equipment costs, and they are discussed thoroughly in 

this report and its supporting documents. The most important of these 

assumptions, however, are those regarding air pollution control regulations, 

which are explained in detail in Chapter IV. The assumed requirements 

§/ That is, the financial average (the annuity) of natural gas is assumed to 

be $0.50 above that for distillate oil. 

19 
reflect a strict interpretation of the 1977 amendments to the Clean Air Act; 

requirements must be assumed because actual regulations for industry have 

not yet been promulgated. Of particular importance is the implicit 

assumption that the standards will be equally strict on coal and oil. As will 

be demonstrated later, it is the relative strictness that determines the 

impact of air pollution regulations on fuel choice. 'Jj 

'J../ Other important assumptions are as follows: (1) Equipment costs rise at 

the general rate of inflation throughout the years covered by the 

analysis. (2) In line with general industry practice, all coal boilers are 

erected at the factory site, whereas all oil and gas boilers are built and 

then shipped to the site (so-called tlpackagedll boilers). Erection at the 

site increases the cost of coal relative to other fuels because site 

construction costs are usually high. (3) Most boiler equipment has a 30-

year life. Pollution control equipment, however, and all packaged 

boilers were assumed to have only a 15-year life. This assumption was 

made after consultation with equipment manufacturers. 

20 
CHAPTER IV. ENVIRONMENTAL REGULATIONS AFFECTING 

INDUSTRIAL ENERGY USE 

The production and use of coal cause numerous environmental problems. Strip mining scars acres of land, underground mining poses serious 

threats to the health and safety of workers, drainage from strip and 

underground mines pollutes rivers and streams, and burning of coal by 

utilities and industries emits tons of air pollutants and solid waste. Any 

attempt to control the environmental effects of coal production and use 

increases the cost of using coal. For example, the land reclamation that is 

required for strip mines can add from $0.50 to $5 to the price of a ton of 

coal, depending on the geographic region. This chapter examines the 

regulations designed to control the air pollution and solid waste associated 

with coal burning; it then presents estimates of the investment required to 

control air pollution and solid waste associated with turning the industrial 

sector to coal. 

The chapter focuses only on the current generation of environmental 

regulations. New, stricter regulations may be set in future years as 

scientists learn more about the causes and effects of pollution. For 

example, additional sulfur controls could be required because some scientists believe that the real problem with the sulfur in fuels is not the sulfur 

dioxide (SO ) that it helps to generate, but other forms of sulfur such as 

sulfates an~ sulfites. The expectation of more stringent environmental 

regulations could be a disincentive to increased coal use. Unless a firm 

knows which regulations will apply, it does not know the true cost of coal 

use and therefore cannot determine if coal is the economically attractive 

fuel. 

AIR POLLUTION AND ENERGY CONSUMPTION 

Under the Clean Air Act of 1970, the Environmental Protection 

Agency (EPA) established ambient air quality standards for six air pollutants. The combustion of coal, oil, and other fuels is a significant source of 

three of these emissions--sulfur dioxides (S02)' nitrogen oxides (NO ), and 

particulates (ash, soot, and so forth). The act instructed each st\te to 

develop a State Implementation Plan, showing how the standards would be 

met. Primary standards--those needed to protect human health--were to 

21 
be met by 1975 or, if extensions were granted, by 1977. These deadlines 

were not met in many areas. More stringent secondary standards--those 

relating to nonhealth effects such as crop losses--were to be met later, but 

within a "reasonable time," 

The primary standards impose limits on the emission of S02' NO , and particulates from stationary sources such as electric utilitIes arfd 

factories; these limits are in addition to those imposed on mobile sources 

such as cars and on "fugitive" sources such as unpaved roads. 1/ Annual, 

daily, or hourly emission limits are set for both new and existmg sources. 

Federal regulations dictate emission limits for all new facilities, so that 

limits for new pollutors are generally uniform nationwide. In contrast, 

limits on existing sources are set by states, and they vary by region 

according to the severity of the air quality problem; the more severe the 

problem is, the stricter the limits are. 

In all cases, the emission limits imply the use of some type of 

pollution control equipment or some change in the operation of the facility. 

For S02 control, a costly and controversial item called a "scrubber" (a 

device to remove sulfur from flue gas) can be used, 2/ Alternatively, lowsulfur coal or oil can be burned. Two other methods, which are no longer 

allowed under the 1977 amendments to the Clean Air Act, are to curtail 

production on poor air quality days or to use tall stacks to disperse 

pollutants and thereby reduce their concentration at ground level. For NO , 

the primary control procedure is to regulate combustion temperatur€s 

properly and to alter boiler design; further control would require NO 

scrubbers. Particulate control can involve three alternative pieces 01 

1/ According to a preliminary EPA estimate, fuel combustion at stationary 

sources accounted for 37, 80, and 51 percent of particulate, S02' and 

NO emissions nationwide in 1975. Industrial processes are the other 

larle source of particulates, accounting for 48 percent (fugitive sources 

are not included). Transportation accounts for another 44 percent of 

NO emissions. See Federal Energy Administration, Air Pollution 

1m ~cts of the Oil and Gas Re lacement Program in the utility and 

Industrial Sectors June 20, 1977 . 

2/ Scrubbers spray a liquid into the exhaust gases that flow up the smoke 

stack after coal or oil is burned. That liquid reacts with the sulfur in 

the Ilflue gas" and prevents their emission into the air. The by-products 

of this scrubbing process, often a mucky substance called sludge, 

present a major solid waste disposal problem. 

22 
equipment--electrostatic precipitators (ESP), baghouses, or mechanical dust 

collectors. 'll 

All these controls, whether in the form of equipment or procedures, 

represent an environmental constraint to increased coal consumption only in 

the sense that they increase the cost of using coal. This "direct!! cost effect 

of environmental regulations is relatively easy to assess. But the costs of 

using fossil fuels can be increased indirectly through another environmental 

policy--EPA's emission offset regulations. 

The Emissions Offset Policy 

Following passage of the 1970 act, a controversy arose over the 

apparent conflict between the environmental standard of the act and the 

need for new factories and power plants in "dirty air" areas. Under 

regulations generated by the act, states could not give their preconstruction 

review approval to a new or modified air pollution source if that source 

would "interfere with" the attainment or maintenance of air quality 

standards. It was dramatically argued by opponents that this policy would 

limit economic growth in some of the nation's most populated (and most 

polluted) areas. 

In response to these concerns about growth, EPA developed its 

emissions offset policy, which states that a major new source of air 

pollution can locate in an area that does not meet the air quality standards 

(a nonattainment area) only if its emissions will be controlled to the 

greatest degree possible and, more significantly, only if "more than equivalent offsetting emission reductions (emission offsets) will be obtained from 

existing sources. 1I Emission offsets must be of the same type; that is, S02 

can only be traded for S02' NO for NOx' particulate for particulate. 

Furthermore, credit can only be gi~n !!for emission reductions from existing 

sources which would not otherwise be accomplished as a result of the Clean 

Air Act." In other words, acceptable emission offsets from an existing 

source are possible only after that source complies with the State Implementation Plan. Trade-off emissions are thus very difficult to find. The 

Congress has now endorsed this policy with the Clean Air Act Amendments 

of 1977. 

'll An electrostatic precipitator imparts an electrical charge to particles 

in the flue gas which allows them to be gathered mechanically. A 

baghouse traps particulates by filtering flue gas through large fabric 

bags. 

23 
The emissions offset policy also increases the cost of using certain 

fuels. The costs will be those incurred by the new source as it "buys" 

emission offsets from existing plants; generally, this will entail the costs of 

pollution control equipment such as scrubbers for existing sources for which 

that equipment would not be required. If emissions are scarce, however, 

their "price" will be bid upward and will therefore include a bonus for the 

seller. 

ASSUMED AIR POLLUTION REGULATIONS 

Determining the implications of the array of federal environmental 

laws for an individual industrial installation is not an easy· task. It is 

important to analyze those implications, however, because the impact of 

policies promoting the use of coal cannot be determined until the cost of 

using coal relative to that of using other fuels is known, and that cost must 

include pollution control equipment. 

The pollution control equipment required for new boiler systems will 

be determined through an analysis of the interaction of three federal 

environmental policies--New Source Performance Standards (NSPS), regulations to prevent significant deterioration, and nonattainment policies. 

Current NSPS set emission limits for "major facilities"--that is, for 

new boilers that have a capacity to consume at least 250 million BTUs of 

fuel per hour. The EPA may lower this threshold to whatever level it deems 

necessary. The Clean Air Act Amendments of 1977 require that new NSPS 

be set so as to require the "best system of continuous emission reduction." 

The new NSPS, which have not yet been established for industry, will not 

only set emission limits but will also require a certain percentage reduction 

in emissions. This percentage reduction can be accomplished by cleaning 

fuels before, during, or after combustion; the reduction cannot be accomplished merely by using untreated low-sulfur fuel, although low-sulfur oil, 

some of which occurs naturally, will probably be allowed. 

In areas of the country where ambient air quality standards have been 

met, the goal of environmental regulations is to "prevent significant 

deterioration" (PSD) of air quality. In these PSD areas, new major facilities 

are required to use the "best available control technology,1f which will be 

determined on a case-by-case basis. For these areas, major facilities are 

defined as those with a capacity of more than 250 million BTUs per hour and 

those with a smaller capacity than this but with the potential to emit 250 

24 
tons of a pollutant annually. 4/ As with the NSPS, naturally occurring lowsulfur fuel does not satisfy the control requirements. 

In areas that have not attained ambient air quality standards, new 

major sources are required to achieve the "lowest achievable emission rate" 

in addition to finding emissions offsets. Major sources in nonattainment 

areas are those with the potential to emit 100 tons of a pollutant annually. 

Until regulations are set and interpreted by the courts, any statements on air pollution control requirements are speculative; in this analysis, 

strict requirements are assumed. The first important assumption is that all 

three federal policies will ultimately imply the same emission limits. The 

following specific emission limits are assumed for major facilities: 

o For coal boilers, the standard will allow no more than 1.2 pounds 

of S02 to be emitted per million STUs burned. For oil boilers, the 

limit will be 0.8 pounds. These limits are the same as the current 

NSPS. In addition, an 80 percent reduction in emissions will be 

required as long as emissions are above 0.4 pounds per million 

STUs. That is, no matter what the beginning emissions, they must 

be reduced by 80 percent until the 0.4 pound floor is reached. 

o For both coal and oil, standards will allow no more than 0.03 

pounds of particulates to be emitted per million STUs burned. 

This standard is less than one-third of the cur,rent NSPS of 0.1 

pounds. 

These standards will imply different pollution control equipment for 

different fuels in different size boilers. In the preceeding chapter, the costs 

of lIrepresentative" coal, oil, and gas boilers systems were compared. Those 

costs included the expense of pollution control equipment. The remaining 

section of this chapter presents the detailed costs to meet the assumed 

standards described above. 

POLLUTION CONTROL EQUIPMENT FOR REPRESENTATIVE SOlLER 

SYSTEMS 

Two factors are key to determining what pollution control equipment 

is required for new boiler systems: the size of the boiler and the sulfur and 

!/ The definition is actually more complex. Twenty-eight specific types 

of factories emitting only 100 tons are also considered major. For 

other factories, the standard is 250 tons a year. Many of the new 

boilers will be in one of the 28 types of factories and could therefore 

have to abide by the 100-ton threshold. 

25 
ash content of fuels. If a boiler is large enough to consume at least 250 

million BTUs per hour, it must meet the assumed NSPS. In this analysis it is 

assumed that for coal boilers a scrubber will be used to meet the S02 limit 

and a baghouse will be used to meet the particulate limit. For oil, there are 

two alternatives to satisfy the S02 standard--using a very high-sulfur oil 

plus a scrubber or using an oil thal: is desulfurized at the refinery. The 

scrubber used with high-sulfur oil is assumed to achieve the moderate 

particulate removal required for oil, but particulate control equipment is 

required with low-sulfur oil. 

For boilers smaller than 250 million BTUs per hour, the method of 

estimating equipment requirements is more complex since equipment needs 

vary by chemical composition of the fuel. Tables 5 and 6 display the sulfur 

TABLE 5. UNCONTROLLED S02 EMISSION RATES BY FUEL TYPE 

Sulfur Pounds S02 

Content BTU (per million 

Fuel Type (percent) Content BTUs) 

Coal 

Northern Appalachian 2.5 12,000/lb. 4.17 

Central Appalachian 0.7 12,000/lb. 1.17 

Midwestern 

Western 

Residual Oil 

High-sulfur 

Low-sulfur 

Natural Gas 

SOURCE: 

3.3 11,000/lb. 6.00 

0.5 8, 500/lb. 1.18 

3.0 150, 560/gal. 3.14 

0.3 146,430/gal. 0.31 

1,027/cu.ft. 0.0006 

ICF, Inc., Economic Considerations in Industrial Bu~~~r Fuel 

Choice, submitted to the Congressional Budget Office (June 

1978). 

26 
TABLE 6. UNCONTROLLED PARTICULATE (TSP) EMISSION RATES BY 

FUEL TYPE 

Ash TSP Pounds 

BTU Content Emission TSP (per 

Fuel Type Content (percent) Rate million BTUs) 

Coal 

Northern Appalachian 12,000/lb. 14.0 13 lb/ton/% ash 7.58 

Central Appalachian 12,OOO/lb. 12.0 13 lb/ton/% ash 6.50 

Midwestern 1l,OOO/lb. 11.0 13 lb/ton/% ash 6.50 

Western 8,500/lb. 9.0 13 lb/ton/% ash 6.88 

Residual Oil 

High-sulfur 150,560/gal. 8 Ib/10; gal. 0.053 

Low-sulfur 146,430/gal. 81b/10 gal. 0.055 

Natural Gas 1,027/cu.ft. 5-15Ib/106 0.005-0.015 

SOURCE: ICF., Inc., Economic Considerations in Industrial Boiler Fuel 

Choice. 

and ash contents of the seven fuels used in this analysis and an estimate of 

the amount (pounds) of pollutant that would be emitted by each million 

BTUs of fuel burned if no control equipment was used. For example, 4.17 

pounds of S02 would be emitted for each million BTUs of Northern 

Appalachian coal burned without pollution control equipment. Using such 

factors, it can be determined whether a particular size boiler, using a 

particular fuel, would be forced to abide by the PSD policy because it could 

emit 250 tons of pollutant annually, or would have to abide by nonattainment policies because it could potentially emit 100 tons a year. 

It is clear from these tables that, with respect to both S02 and 

particulates, all the representative coal-fired boilers qualify as major 

facilities under at least one of the federal policies. Even a boiler as small 

as 50 million BTUs per hour using low-sulfur Western coal could emit more 

27 
than 250 tons of both sulfur dioxIde and particulates annually. 5/ To meet 

the emission limits listed above, it is assumed that a scrubber using a 

water/limestone spray will be used to control 802 and that baghouses will be 

used to control particulate emissions. 2./ 

It is also clear that systems using high-sUlfur oil would be required to 

use scrubbers, and that systems using low-sulfur oil and natural gas would 

not. The policy implications are not as clear, however, for particulate 

control with oil. As specified by the assumed New Source Performance 

Standards, oil-fired boilers larger than 250 million BTUs per hour will have 

to meet the assumed limit of 0.03 pounds per million BTUs and would 

therefore have to use some control equipment. But smaUer boilers do not 

have the potential to emit 250 tons (or even 100 tons) of particulates and 

therefore would not be considered major facilities. The implication is that 

no particulate control would be required by federal regulations for oil 

boilers smaller than 250 million BTUs per hour. This would result in a 

loophole, however. 8mall coal-fired boilers would be reducing particulate 

emissions to 0.03 pounds per million BTUs, while small oil-fired boilers 

would be allowed to leave their emissions uncontrolled at 0.055 pounds per 

million BTUs. It is assumed that this loophole would not be allowed to 

persist and that small oil-fired boilers would be asked to reduce particulate 

emissions by about 50 percent. 

(Because they have the potential to emit over 100 tons of S02' all 

coal-fired boilers and most oil-fired units would, in addition to controlling 

their own emissions, have to find emission offsets from existing sources if 

located in a nonattainment area for 802' Coal-fired systems would also 

have to seek particulate offsets. This report, however, does not predict the 

number of units that will have to abide by the offset policy.) 

Examples of the equipment cost of the required pollution control 

effort for each representative boiler system are presented in Table 7. A 

complete set of these estimates is used in the analysis of boiler economics 

in Chapters VI and VII. For the larger boiler shown in Table 7, pollution 

Y The calculation for S0'L!S as follows: 50 MMBTU/HR x 24 HRS x 365 

days x 1.18 lbs. 802 per"MMBTU = 258 tons of S02 per year. 

6/ One exception should be noted. Boilers using Central Appalachian or 

Western coal will only have to reduce their emissions by 60 percent 

since this will bring them to the floor of 0.4 pounds. For this reason, 

these boilers can use smaller scrubbers, and the costs of the equipment 

will therefore be lower. 

28 
control equipment costs up to $6.3 million and would increase the cost of 

that size coal boiler system by up to 48 percent. For the smaller boiler, 

control equipment costs can reach $2.6 million and would increase coal 

system costs by up to 46 percent. 

TABLE 7. 

Fuel Type 

Coal 

REPRESENTATIVE AIR POLLUTION CONTROL EQUIPMENT COSTS BY FUEL TYPE: IN THOUSANDS OF 1977 

DOLLARS '3;.1 

Boiler Size bl 

100 MPPH 300 MP·PH 

Northern Appalachian 2,568 6,314 

Central Appalachian 2,245 5,539 

Midwestern 2,575 6,333 

Western 2,246 5,541 

Residual Oil 

High-sulfur 1,794 4,302 

Low-sulfur 238 637 

Natural Gas 

~ Equipment, planning and design, and installation costs are included. 

~I MPPH = thousands of pounds of steam per hour. 

For high-sulfur oil, equipment costs can be increased by up to 80 

percent and, for low-sulfur oil, by up to 12 percent. But equipment 

requirements are not the only way low-sulfur oil system costs are increased. 

Low-sulfur oil costs about $3.00 per barrel more than high-sulfur oil; this 

premium reflects the additional desulfurization costs at the refinery or the 

price premium attributed to naturally occurring low-sulfur crude oil. 

29 

32.498 0 • 78 • 4 
Air pollution regulations also increase operation and maintenance costs 

(see Table 8). For the high-sulfur coal costs, variable operation and 

maintenance costs can be increased by up to 13 times, and fixed costs can 

be increased by up to 45 percent. For high-sulfur oil, variable costs are 

increased up to 13 times, and fixed costs increased by up to 40 percent. 

The strict environmental regulations described here are assumed to be 

imposed on new boilers starting construction in 1979 or thereafter; these 

boilers will be coming on line beginning in 1981. This. timing coincides with 

the assumed enactment of the oil and gas user taxes detailed in Chapter VII. 

Before then, existing regulations are assumed to prevail. These regulations 

are assumed to require the use of low-sulfur coal (Western or Central 

Appalachian) plus a baghouse in all boilers larger than 250 million BTUs per 

hour; oil boilers of this size are assumed to use 0.7 percent sulfur oil. No 

control is assumed for smaller industrial boilers. 

In summary, strict regulations are assumed to be imposed as a 

result of the Clean Air Act Amendments of 1977. The actual requirements 

for industry have not yet been set, and different legal interpretations could 

result in the same or in different equipment needs. The most likely point 

for differences is in regulations for small boilers. Both Chapter VI and 

Chapter VII discuss the impact of alternative regulations on coal demand. 

30 
TABLE 8. REPRESENTATIVE OPERATION AND MAINTENANCE COSTS 

FOR AIR POLLUTION CONTROL BY FUEL TYPE: IN 

THOUSANDS OF 1977 DOLLARS 

Boiler Size a/ 

100 MPPH 300 MPPH 

Fuel Type Fixed Variable b/ Fixed Variable £/ 

Coal 

Northern Appalachian 132 458 303 1,314 

Central Appalachian 111 293 247 826 

Midwestern 137 522 314 1,500 

Western 111 302 248 851 

Residual Oil 

High-sulfur 84 255 193 750 

Low-sulfur 8 28 18 74 

Natural Gas 

~/ MPPH = Thousands of pounds of steam per hour. 

£/ Assumes a 100 percent utilization. 

31 

CHAPTER V. THE POTENTIAL FOR NONBOILER SOLID COAL 

SUBSTITUTION 

Large amounts of oil and gas are used in industrial equipment other 

than boilers and as raw material in the petrochemical industry. Indeed, 

these uses of oil and gas provide the largest target for coal substitution 

policies--about eight quads of oil and gas were consumed in nonboiler uses 

in 1974 as compared with four quads consumed in boilers. Since coal is not 

widely used in the United States for nonboiler purposes, however, the 

technical feasibility of using solid coal has not generally been demonstrated. 

This chapter identifies some industrial nonboiler processes in which solid 

coal might be used once coal-firing equipment is adequately demonstrated 

on a com mercial scale. Unfortunately, since coal equipment is not 

marketed for most nonboiler needs, no reasonable cost data are available for 

cost comparisons. 

More than 80 percent of the oil and gas consumed in nonboiler 

applications in the manufacturing sector can be traced to four industries: 

chemicals, petroleum refining, primary metals, and stone, clay, and glass. 

The decision about whether the use of solid coal is technically feasible in a 

specific industry is a matter of engineering judgment. Few scientists 

focused on this topic in the 1960s, and thus only a handful of stUdies are 

available. In 1974, a select group of industry representatives were urgently 

called together to formulate the blueprint for Project Independence; they 

were asked about the potential for substituting coal for oil. 1/ The panel 

cited the significant potential of using coal in boilers, but they were 

pessimistic about other potential uses. More importantly, the panel stated: 

tiThe obstinate environmental, logistic, lead-time, and economic demands 

associated with coal as a solid fuel are· a strong inducement for a 

commitment, instead, to a liquid or gaseous derivative." They recommended 

support of a national coal gasification and liquefaction program. 

The Institute of Gas Technology (lGT) recently analyzed industrial 

candidates for solid coal use in nonboiler equipment. '!:../ After screening a 

Science Communication, Inc., Intra Industry Capability to Substitute 

Coal, prepared for Federal Energy Administration (October 1974). 

Institute of Gas Technology, Assessment A plication for Direct Coal 

Combustion, prepared for the National Science Foundation February 

1977). . 

33 
large number of processes, they identified a few targets for immediate 

conversion in two industries--stone, clay, and glass and primary metals. 3/ 

IGT concluded that complete conversion of the existing equipment could 

save 899 trillion BTUs a year using available equipment and technology. 

They noted, however, that problems with equipment damage would have to 

be overcome. 

A more complete engineering study recently submitted to the 

Congressional Budget Office classifies a large number of nonboiler uses 

according to the risk of failure entailed in developing coal-burning technologies and equipment. The four classes are: 

o Proven: Coal is currently used for the industrial process in the 

United States. 

o Low risk: No insurmountable technical obstacles are foreseen, 

but the coal-burning equipment must be built and demonstrated in 

the United States before it can be considered commercially 

available. 

o High risk: Coal-burning equipment may be developed, but there is 

a greater risk of failing to develop reliable and safe systems. 

o Not feasible: Without breakthroughs in material or design, coal 

probably cannot be burned. 

The results of this technical feasibility study are summarized in 

Table 9. The major problems with coal burning are the lack of temperature 

control, potential equipment damage, and possible product contamination. 

The temperature and distribution of heat cannot always be controlled 

because the heat or energy content of the coal being fed to the equipment is 

not constant. Equipment damage is a problem because of the many 

chemicals found in most coal; those 'chemicals can also contaminate the 

product in situations where the product comes into direct contact with the 

coal flame. The problem with replacing oil and gas that are used as raw 

materials is the chemical state of coal. 

Y The processes included: cement and lime calcining where coal is 

already used; glass melting; iron ore benefication; blast furnace and 

open hearth operations; soaking pits; copper smelting; and structural 

clay products. 

34 
TABLE 9. TECHNICAL FEASIBILITY OF COAL USE IN NONBOILER APPLICATIONS 

1974 Coal Feasibility 

Nonboiler (percent of 1974 nonboiler oil 

Oil and Gas and gas consumQtion) 

Consumption Low High Not Not 

Industry (quadrillion BTU s ) Proven risk risk feasible studied 

Petroleum Refining fi/ 1.81 50 29 9 13 

Steel b/ 0.64 18 25 6 51 

Aluminum c/ 0.17 33 47 20 

Stone, Clay, Glass ~/ 0.80 58 33 9 

Ammonia ~/ 0.59 100 

Ethylene y 0.99 100 

All Others 2.92 100 

Total 7.92 7 21 10 16 45 

SOURCE: EEA, Inc., Technical Potential for Coal Use in Industrial EquiQment Other than 

Boilers, prepared for the Congressional Budget Office (April 6, 1978). 

fi/ 

Q/ 

~/ 

~/ 

~/ 

Low-risk processes include atmospheric crude distillation, catalytic reforming, alkylation; 

high-risk processes include hydrocracking, hydrotreating, vacum distillation, hydrorefining, 

and hydrogen manufacture. 

Proven processes include injection of supplemental fuel into blast furnaces and as a fuel in 

open hearth steel making (although it should be noted that open hearth processes are being 

replaced by other steel-making techniques); the reheat furnace is the low-risk process. 

Low-risk processes are melting, holding, and casting; processes classed as not feasible, 

include calcination and fabrication (because of possible product contamination). 

Coal use for cement, lime, and brick production processes is proven; glass industry use is 

high risk (equipment damage and product contamination are the key problems). 

Considered low risk because a process that uses coal for both feedstock and fuel is 

currently used overseas; the process begins with coal gasification. ERDA and W.R. Grace 

and Company are conducting a joint experiment with the process in the United States. 

Process is considered not feasible because precise temperature control is required. 

35 
The varying potential for coal use in non boiler applications is 

revealed by an examination of three industries: stone, clay, and glass; 

petroleum refining; and chemicals. Within the stone, clay, and glass 

industry, coal is already used in the production of cement and lime, and the 

cement industry is rapidly and voluntarily converting to coal. Industry 

representatives estimate that 90 percent of the industry will be capable of 

burning coal as well as oil or gas by 1980; this dual-firing capability will 

enable them to respond quickly to fluctuations in fuel prices. 4/ The 

widespread conversion is attributed to two unusual circumstanceS: little 

additional equipment is required for coal use; and the production process 

itself controls the sulfur pollutant by capturing the pollutant in the cement. 

In glass production, the product comes into direct contact with the coal 

flame, and there is a chance of product contamination. Recent successful 

demonstrations, however, make this a likely target for coal use in the 

future. §/ 

Within the petroleum refining industry, oil and gas are used for 

process heat in tubes till heaters and furnaces. The use of solid coal is 

judged to be technically low risk for new process equipment, which accounts 

for 50 percent of oil and gas process uses, including atmospheric crude 

distillations, catalytic reforming, and alkylation. While new catalytic 

reforming units may be low risk in terms of technical feasibility, industry 

sources indicate that the economic cost of any equipment failure by this 

process is so great that its reliability with coal firing would have to be 

exhaustively demonstrated before any serious consideration of direct coal 

firing. Another 30 percent of current process heat uses are considered high 

risk for new equipment. Retrofit of existing processes is not feasible. 

Furthermore, much of the gas used in nonboiler equipment is "internally 

generated refinery off gas"--gases emitted and recaptured as crude oil is 

processed--and it will be difficult to force refiners to import coal and sell 

these gases elsewhere. 

Within the chemical industry, petrochemical ethylene is a building 

block for many products, including the packaging material polyethylene and 

synthetic fibers. Currently, natural gas liquids are the primary raw material 

4/ Portland Cement Association, "U.S. Cement Industry: Fuel Conversion 

Report," June 1975 • 

. y Proceedings of the Fuel Switching Forum, sponsored by the Department 

of Energy, Pittsburgh, Pennsylvania, June 6-7, 1977. 

36 
for ethylene production; the gases emitted during raw material processing 

are recaptured and used for all the fuel needs. Coal use is termed infeasible 

and this judgment seems to be shared by the industry since, as curtailments 

of natural gas increase, billions of dollars are being spent for facilities that 

use oil as raw material and fuel. 6/ Ammonia produced in the chemical 

industry is a key ingredient for -nitrogen fertilizers. A process now 

employed in Europe and Asia in the production of ammonia uses coal as both 

raw material and fuel; the process actually begins with coal gasification. 

For this reason, the development of a coal-fired process is termed low risk 

for new equipment. 

In sum, processes involving 54 percent of nonboiler uses of oil and gas 

were reviewed; of that 54 percent, only 7 percent could be considered to 

have proven technologies for coal. Another 31 percent, however, were 

judged to have some potential for successful demonstration of coal-based 

technologies. Penetration into this market appears, to be contingent on 

commercial-scale demonstration of new technologies, and very little information is available on this topic to date. 

§j "Petrochemicals: The Prodigious Costs of Facing the Future," Business 

Week, July 18, 1977. 

37 

32.498 0 • 78 • 5 

CHAPTER VI. BOILER COAL CONSUMPTION UNDER CURRENT POLICY 

The purpose of this chapter is to project the demand for boiler coal in 

the industrial sector in 1985 if no specific government incentives are 

adopted--that is, if current policy is maintained; the following chapter will 

project changes in that demand under alternative federal policies. Since any 

estimate depends on several key assumptions, this chapter presents the 

sensitivity of the current policy estimate to four major factors: future 

OPEC oil prices, future coal prices, natural gas availability for new boilers, 

and alternative environmental standards. 

ESTIMATES OF BOILER COAL CONSUMPTION UNDER CURRENT 

POLICY 

The choice of industrial boiler fuel is plagued with uncertainty. 

Corporations deciding which equipment to buy must forecast fuel prices and 

availability for many years into the future. Apart from federal regulations, 

the most important and unpredictable factors affecting fuel choice are the 

expected rates of increase in oil and coal prices and the availability of 

natural gas. The current policy assumptions used here include world oil 

prices increasing at the U.S. rate of inflation and coal prices increasing 

slightly faster, primarily because of decreasing mine productivity. Gas is 

assumed to be available, but at prices that regulators allow to rise only to 

the level of distillate oil prices by the early 1990s. 

With these assumptions, the economic model developed in this 

analysis is used to forecast boiler fuel choice in future years; that is, the 

model is used to approximate individual corporate decisions. Unfortunately, 

historical sales data are of little help in predicting future fuel choice or in 

gauging the accuracy of the model. Before 1970, puchasers did not have to 

consider the implications of nationwide air pollution control requirements or 

predict the impact of comprehensive mine safety legislation on mineworker 

productivity and thus on coal prices. In addition, before 1973, OPEC had not 

demonstrated its pricing power and the federal government had not been 

authorized to order factories to burn coal instead of oil and gas as it was by 

the Energy Supply and Environmental Coordination Act of 1974. 

39 
Even very recent sales data do not reveal a clear trend. Since two to 

three years are required for construction, most of the new industrial boilers 

that have or will come on line between 1975 and 1980 were purchased 

between 1972 and 1977. In the first five years of that period, 10 to 15 

percent of the large, industrial, fossil-fuel boiler capacity sold each year 

was coal-fired. Then, in the first half of 1977, the market share for coalfired boilers increased to 50 percent, although boiler sales were abnormally 

low in those months. From 1972 through the first half of 1977, the coalfired capacity sold to the industrial sector totaled 21,849,000 pounds. This 

new capacity could account for 8 million tons of coal consumption by the 

end of 1980. 1/ 

If current policy is continued, it is projected that coal would 

represent approximately 13 percent of total new boiler fuel demand over the 

period from 1975 to 1980. In 1980, this would total 12 million tons of coal 

consumption. Between 1981 and 1985, when the strict environmental 

regulations discussed in Chapter IV could be imposed, it is projected that 

only 6 percent of the new boiler fuel demand would be coal. By 1985, this 

would represent an additional 6 million tons of coal being consumed as a 

boiler fuel. 

Boiler coal consumption was 45 million tons at the end of 1974. Since 

about 3 percent of these existing boilers will be retired each year, 

consumption in old boilers will fall to 30 million tons by 1985. 2/ As 

explained in Chapter II, 10 million tons is an optimistic estimate of the coal 

consumed by old oil and gas units that will reconvert to coal; this brings 

total coal consumption in old boilers to 40 million tons by 1985. Adding the 

coal consumed by old coal boilers to the coal consumed by the new coal 

boilers installed in the 1975-1985 period yields an estimate of 58 million 

Based on sales data from the American Boiler Manufacturers Association. SIC codes include 00, 20 through 39, and 73. Total MPPH was 

multiplied by 1,300 to convert it to million BTUs. Coal boilers were 

assumed to be operated at 70 percent utilization. Only boilers larger 

than 80 MPPH were included. 

The 45 million tons is taken from the file of major fuel-burning 

installations (MFBI). A 3 percent retirement rate implies that, over the 

1975-1985 period, 30 percent of the existing stock of coal boilers would 

reach 30 years of age and be retired. In fact, more than 50 percent of 

the coal boilers listed in the MFBI file were installed before 1950, and 

another 30 percent were installed between 1951 and 1960. 

40 
tons for 1985 boiler coal consumption, assuming that no additional energy 

legislation is enacted. 

THE SENSITIVITY OF BOILER CONVERSION TO ALTERNATIVE 

ASSUMPTIONS 

Although the current policy estimate presented above is based on a 

set of reasonable assumptions, it is important to stress the fact that a 

considerable amount of uncertainty surrounds the estimate. This is primarily because the corporate decision about which type of boiler to 

purchase is extremely sensitive to future oil and coal prices and to 

environmental standards. To a much lesser extent, the estimate also 

depends upon the availability of natural gas. 

Natural Gas Availability. Coal will be chosen more often as a boiler 

fuel if natural gas is not available. With no gas available for new boilers, 

coal would capture 7 percent of the market in the 1981-1985 period instead 

of 6 percent; 1985 coal consumption would increase to 59 million tons under 

such an availability assumption. 

Future Oil Prices. If, in addition to gas being unavailable, boiler 

purchasers expect OPEC to increase real crude prices, a much larger share 

of the boiler market will turn to coal under current policy. For example, if 

crude oil prices increase fast enough, starting in 1985, to push delivered 

residual oil prices up each year by 2 percent faster than inflation during the 

life of the boiler, then 38 percent of the new industrial boiler market will be 

captured by coal in the 1981-1985 period; 1985 boiler coal consumption 

would be 90 million tons. Clearly, OPEC price increases or widespread 

expectation of OPEC price increases can induce significant replacement of 

oil and gas by coal. 

Future Coal Prices. Coal prices in the future are also uncertain 

because of the difficulties involved in projecting equipment costs, labor 

costs, and productivity changes. For example, the 1978 labor contract will 

increase real coal prices at the mine site by a little over 1 percent each 

year over the next three years, assuming constant labor productivity. It is 

uncertain whether future contracts will include similar wage and benefit 

provisions and, more importantly, whether labor productivity will, after the 

recent dramatic decline, resume its long-term upward trend and offset real 

wage increases. 

A steady increase in coal prices can offset the effect of gas 

unavailability and an expected OPEC price increase. If coal prices at the 

41 
mine site were expected to increase by an additional 2 percent each year 

starting in 1978, the effect of the 2 percent OPEC price hike would be 

completely offset; the market share for coal would return to 6 percent. 

Environmental Policies. Chapter IV explains the air pollution control 

requirements assumed in this report. The assumptions reflect a very strict, 

but plausible, interpretation of the 1977 amendments to the Clean Air Act. 

Since the control requirements result in higher costs for both coal and oil, 

they should be expected to encourage the consumption of natural gas; the 

analysis confirms this point. 

'When analyzing the effect of alternative assumptions on competition 

between coal and oil, one obvious, but frequently overlooked, point is made 

very clear--the impact of air pollution regulations on coal demand depends 

as much on the requirements for oil as it does on those for coal. A factory's 

choice between coal and oil depends on relative costs, and air pollution 

regulations add to the equipment or fuel costs of using both fuels. 

To illustrate the point, "pro-coal" air pollution standards were 

analyzed. First, it was assumed that natural gas is not available for new 

boilers; as noted, this results in coal being used for 7 percent of new boiler 

fuel needs in the 1981-1985 period. Second, the oil standards detailed in 

Chapter IV were changed. Specifically it was assumed that only low-sulfur 

oil (0.3 percent) can be used, with particulate control equipment; the option 

of using high-sulfur oil with a scrubber is eliminated. As a result of this 

tightening of oil standards, the market share for coal increases to 15 

percent. Third, it was assumed that boilers under 300 million BTUs per hour 

are allowed to use low-sulfur coal alone without scrubbers, but particulate 

control is required. Tight oil requirements are maintained so that for these 

smaller boilers the S02 standard for oil is three times as strict as that for 

coal--1.2 pounds per million BTUs of fuel consumed as compared with 0.4 

pounds. With this standard, coal's market share increases to 27 percent. 

Finally, if low-sulfur coal is allowed in all sizes of boilers while maintaining 

the tight oil controls, coal would be used for 39 percent of new boiler fuel 

needs. 

In all the cases considered above, the increase in coal demand must 

be attributed to tight oil standards together with more lenient standards for 

coal. For example, consider the case in which low-sulfur coal is allowed in 

all sizes of boilers, but instead of strict oil standards the current NSPS for 

oil is imposed--that is, 0.8 pounds of sulfur dioxide per million BTUs of oil 

burned with no particulate control. Under these regulations, coal captures 

about 10 to 15 percent of the new boiler market. 

42 
CHAPTER VII. POLICY OPTIONS TO REPLACE OIL AND GAS WITH 

COAL 

This chapter analyzes the impact of alternative federal policies 

aimed at encouraging the replacement of oil and gas with solid coal in the 

industrial sector. Both boiler and non boiler uses are considered, although 

the analysis of the former is based on the detailed economic model and cost 

information presented above, whereas the analysis of the latter is more 

SUbjective. Since the major policy options for boilers are tax incentives, the 

analysis quantifies the potential budgetary effects as well as the extent of 

coal substitution. 

The first section of the chapter discusses five possible federal tax 

options to encourage industry to utilize solid coal in boilers. Each option is 

evaluated in terms of potential oil and gas savings and budgetary effects. 

The budgetary effects can take three forms: (1) user taxes on oil and gas, 

which are reflected as increased revenues; (2) rebates of these revenues for 

those who buy coal equipment; and (3) tax credits on new coal equipment, 

which are reflected as decreased revenues. Special budgetary implications, 

administrative issues, and the interaction of the boiler tax incentives with 

both environmental policy and the coal substitution regulatory program are 

all treated. The second section discusses the federal policy that might be 

adopted to encourage coal use for nonboiler purposes in the industrial 

sector. 

REPLACING OIL AND GAS IN BOILERS 

The demand for coal as an industrial boiler fuel may increase slowly 

over the next decade under current policy. The federal government may, 

however, wish to assure that coal use increases through various tax 

incentives to reduce the price of coal relative to the price of oil and natural 

gas. For example, the original National Energy Plan included taxes on most 

oil and gas used in the industrial sector; that plan also called for rebates of 

those taxes for firms buying coal equipment. Similarly, the coal conversion 

programs passed in 1977 by both the House and the Senate included 

provisions for user taxes on industrial oil and gas and for rebates to firms 

purchasing coal equipment. The key difference between the Administration's original plan and the Congressional programs is the number of oil 

and gas uses exempt from the proposed tax. The House and Senate versions 

43 
tax boiler fuel uses almost exclusively; non boiler uses were exempted . primarily because of the lack of proven coal-using equipment . .!/ 

Federal Policy Options 

Although the number of policies that the federal government could 

potentially adopt to accelerate the rate of coal conversion is quite large, 

only five options are presented in this report. These options should, 

however, provide policymakers with an overview of the magnitude of 

replacement to be accomplished by a relatively wide spectrum of policies. 

Estimates of the potential oil and gas savings and the budgetary effects of 

policies for new boilers are displayed in Table 10. The estimates are all 

based on several key assumptions that were discussed elsewhere in detail; 

chief among these assumptions are the following: 

o By 1985, all crude oil will be sold at the world oil price, which is 

assumed to increase at the rate of U.S. inflation throughout the 

life of the boiler system. 

o Strict environmental regulations will prevail. 

o Natural gas prices will be deregulated in 1985, and they will 

increase to levels that average $0.50 per million BTUs above the 

price of distillate oil. 

o Coal prices will increase only because of inflation and depletion. 

o Industries will buy coal on the spot market and use single-car 

trains for delivery. 

Oil and Gas Taxes Without Rebates. A tax on oil of $6.00 a barrel 

and a tax on gas raising gas prices to oil price levels including the oil tax 

(hereafter referred to as a gas equalization tax) would increase the 

percentage of new boiler fuel demand captured by coal to 63 percen t 

The House version exempts all fuel used as a raw material and other 

nonboiler ("process!!) uses in which coal use is not feasible for technical, 

economic, or environmental reasons. As discussed in Chapter V, coal 

use is not technically feasible for most nonboiler applications. If 

non boiler uses do qualify, they are taxed at a lower rate under the 

House bill. The Senate exempts all raw material and process uses. 

44 
TABLEl10. ENERGY AND BUDGETARY EFFECTS OF CURRENT POLICY AND FIVE ALTERNATIVE 

BOILER TAX POLICIES 

Budgetary Effects, 

Energy Effects Fiscal Year 1979-1985 

1985 Percent of 1985 (millions of 

total 1981-1985 oil and gas current dollars) al 

coal use new boiler replacement Cumulative Cumulative 

(millions of tons fuel demand (barrels per tax tax 

per year) captured by coal ~I day equivalent) revenues expenditures 

Current Policy 58 6 

A $3.00-a-barrel tax on 

oil and a tax on gas 

sufficient to increase 

its price to that of 

distillate oil (including 

the $3.00 tax) 88 36 321,000 3,091 

A $6.00-a-barrel tax on 

oil and a tax on gas 

sufficient to increase 

its price to that of 

distillate oil (including 

the $6.00 tax) 116 63 621,000 3,074 

40 percent tax credit 95 403,000 3,361 

New boilers 38 353,000 

Accelerated retirements 50,000 

Senate bill incentives 114 61 600,000 1,683 1,950 

House bill incentives 140 883,000 (13,547) ~/ H,756) s/ 

New boilers 72 717,000 

Accelerated retirements 166,000 

SOURCE: Congressional Budget Office 

Reflects a 6 percent annual rate of inflation starting in fiscal year 1978. 

About 2.2 qUl;ds of fossil fuels will be consumed in all new boilers purchased to meet expansion and 

replacement demand for the 1981-1985 period; these are the boiler investment decisions affected by 

federal policies enacted in 1979. The numbers in this column represent the portion of that new fuel 

demand satisfied by coal. 

All of the revenue is rebated. The negative tax expenditure estimate reflects the net impact of the 

two provisions: the extra 10 percent tax credit and the denial of the existing tax credit for new oil 

and gas boilers and new coal boilers financed with rebates. 

45 
between 1981 and 1985; total boiler coal consumption would be 116 million 

tons in 1985. These taxes would increase tax revenues by approximately $3 

billion. (current dollars) between 1979 and 1985. An oil tax of $3.00 a barrel 

and the relevant gas equalization tax would increase coal's market share to 

36 percent. Both sets of taxes are imposed on oil and gas used in all new 

boilers. 

Investment Tax Credits. Taxes on oil and gas encourage coal 

consumption by increasing coal's relative price advantage. Investment tax 

credits encourage coal use by lowering its equipment cost disadvantage. If, 

for example, an extra 40 percent refundable investment tax credit was 

allowed for all new coal boilers, the market share for coal would jncl'ease to 

38 percent of the new boiler fuel market in the 1981-1985 period; this large 

tax credit would also induce accelerated retirements. Total boiler coal 

demand would be 95 million tons by 1985 as a result of both the increased 

share of the new boiler fuel market and the accelerated retirements. The 

tax expenditures or revenue reductions associated with this credit would be 

approximately $3.4 billion in current dollars for the period 1979-1985. 

(Without gas deregulation the tax credit would result in a 29 percent coal 

share.) 

Senate Bill Incentives 

The Senate bill proposes a $6.00-a-barrel oil tax and an accompaning 

gas equalization tax on fuel used in new boilers that have a capacity of 100 

million BTUs per hour or more and on fuel used in a new smaller boiler if 

that unit is one of several new units at a single site with aggregate boiler 

capacity over 250 million BTUs per hour; new units are not eligible for 

rebates. Oil and gas burned in an existing coal-capable unit are also taxed, 

and the taxes can be rebated if the unit is converted to coal. In addition to 

the taxes, an extra 15 percent refundable tax credit is offered to firms 

investing in coal-fired boilers. 

This policy is estimated to increase the market share for coal to 61 

percent in the 1981-1985 period; about 8 percent of that can be attributed 

to the tax credit in the bill. The increased coal is the equivalent of 600,000 

barrels a day of oil consumption. This policy would increase tax revenues by 

approximately $1. 7 billion, while the credit would cause revenue reductions 

of approximately $2.0 billion. This would net to a $300 million revenue 

decline in current dollars for the period 1979-1985. Without the provision 

exempting boilers' smaller than 100 million BTUs per hour, coal's market 

share would be 71 percent. 

46 
House Bill Incentives 

In the House bill, user taxes are imposed on oil and gas used in both 

new and existing boilers of all sizes. The oil tax starts at $0.30 a barrel in 

1979 and gradually increases to $3.00 a barrel in 1985. The gas tax 

gradually raises gas prices to the equivalent price of distillate oil not 

including the oil tax. Both new boilers and existing boilers converted to coal 

are eligible for rebates, but a firm must choose between a rebate and an 

extra 10 percent tax credit (added to the existing 10 percent tax credit 

allowed for all business investments). 2/ Finally, the House bill denies the 

existing 10 percent tax credit to investors choosing oil- and gas-fired 

systems. 

Estimates of the oil and gas replacement induced by the House 

incentives depend crucially on what is assumed about deregulated natural 

gas prices after 1985 and about the effect of the tax rebates. In this report, 

gas prices to industry are assumed to rise beyond world oil prices and the 

rebate is assumed to be perfectly effective. 3/ With these assumptions the 

House incentives enable coal to capture 72 percent of the new boiler 

market; the bill would also induce enough accelerated retirements to 

increase coal use by 15 million tons in 1985. 

If gas prices after 1985 did not increase as much as assumed, the 

House incentives would be much less effective. (This is not so for the 

Senate bill since its user tax already pushes gas prices beyond the world oil 

price.) For example, if gas prices did not increase beyond the equivalent 

price of distillate oil, and if gas was still available for new boilers, coal's 

market share would be 52 percent. The tax portion of the bill would result 

~/ 

If a rebate is chosen, a firm cannot take the existing credit on the 

portion of the investment financed with the rebate. The bill also 

exempts from the taxes the equivalent of the first 50,000 barrels of oil 

consumed in each firm, and cuts the gas tax by 10 percent for those 

firms accepting !!interruptable" gas contracts; both exemptions lower 

the pool of funds eligible for rebates and thereby cut the rebate effect. 

The entire tax liability for the 1979-1985 period is assumed to be 

rebated. The user-tax liability (except for 1979 and 1980) cannot be 

carried forward nor can it be transferred, so it is possible that liability 

will not be in the right place at the right time. 

47 
in only an 18 percent market share; tax rebates would supply much of the 

incentive for the remaining share. ~/ 

Total boiler coal consumption would be 140 million tons by 1985 

as a result of both the increased share of the new boiler fuel market and the 

accelerated retirements. The resulting increase in coal use is equivalent to 

883,000 barrels a day of oil consumption. The cumulative tax revenues 

would be $13.5 billion, but the whole amount is assumed to be rebated. 

Denying the existing 10 percent investment tax credit to oil and gas boilers 

and to coal boilers financed with the rebate results in a cumulative budget 

savings of $1.8 billion. 

Budgetary Effects 

Since the policy incentives for accelerated coal sUbstitution are 

primarily tax incentives to change the capital or fuel costs of oil and gas 

relative to coal, these options have budgetary effects. The impacts can be 

on the revenue side in terms of increased revenues from user taxes for oil 

and gas or decreased revenues from tax credits on investment in new coal 

equipment. In addition, the options with tax revenue rebates will be 

reflected in the budget in terms of direct outlays. The budget estimates in 

Table 10 are cumulative for fiscal years 1979-1985, and they are given in 

current dollars with an assumed inflation rate of 6 percent a year; the 

estimates by fiscal year are displayed in Appendix c. . 

The estimates of tax expenditures reflect only the investment tax 

credits on new coal boilers. The Senate bill, for example, actually provides 

the 15 percent credit for a long list of "Alternate Energy Properties,1l and 

the tax expenditure resulting from this broader program would be much 

higher. Indeed, the most frequently cited disadvantage of the tax credit 

approach is that it rewards those who would not use oil and gas even in the 

~/ The effect of rebates is equivalent to the effect of an investment tax 

credit. This can be illustrated by considering a factory paying $10 

million in oil user taxes that is faced with a decision of whether to buy 

a new coal or oil boiler. Since the user tax is a deductible business 

expense, the tax reduces the firm!s after-tax profits by $5 million. If 

the firm decides to buy a coal boiler for $10 million, all of its user 

taxes will be rebated and, therefore, it will increase its after-tax profit 

by $5 million dollars. This effect is identical to that of a 50 percent 

investment tax credit. With a 50 percent credit, a firm would buy the 

coal boiler for $10 million, reduce its income tax liability, and thereby 

increase its after-tax profit by $5 million. 

48 
absence of the policy. In' view of the widespread use of waste fuels in 

industries such as paper and steel, the consequent drain on the federal 

budget could be considerable. With a tax approach, if a factory does not use 

oil or gas, no tax is levied and thus no tax is collected. 

As will be discussed later, the budget estimates are derived from 

optimistic assumptions about the tax programs. For example, with the 

House bill a smooth flow of taxes and rebates is required; actually, since tax 

liability cannot be carried forward, it is possible that millions of tax dollars 

will remain with the U.S. Treasury. Similarly, coal use could be precluded 

by physical constraints such as land availability and, if exemptions are not 

granted, millions of dollars of revenues could accrue to the Treasury. 

Interaction of Environmental and Energy Tax Policy 

For all of the tax policies considered here, it was assumed that a 

strict environmental policy would prevail, as detailed in Chapter IV. 

Alternative environmental policies would affect the impact of any tax 

program on coal demand. As an illustration of this point, consider the case 

in which natural gas is simply not available for new boilers and a $3.00-abarrel oil tax is imposed. With strict controls, coal's market share is 36 

percent. With the "extreme pro coal" environmental policy, coal's share of 

new boiler fuel demand would be 72 percent with this tax. When a 

"moderate pro coal" policy is coupled with the tax, coal's share is 51 

percent. Thus, there is a clear and important interaction between energy 

taxes and environmental regulations. §j 

Administrative Issues 

The estimates of oil and gas replacement in Table 10 should be 

viewed as optimistic; they do not reflect all the ways taxes 'Can be avoided 

and, therefore, all the ways the program can be undermined. Since the 

success of any coal SUbstitution program will depend heavily on how it is 

administered, it is important to identify possible administrative problems 

for the recently proposed House and Senate bills. 

§j The extreme pro coal policy allows low-sulfur coal and baghouses for all 

sizes of coal boilers, but it requires 0.3 percent sulfur oil plus baghouses 

for all oil boilers. The moderate policy has the same coal standards, 

but it imposes a standard of 0.8 lbs of S02 per million BTUs of oil 

burned and does not require particulate control on oil boilers. 

49 
First, both the House and the Senate bills are primarily boiler fuel 

taxes. Exemptions of non boiler fuel uses makes any program harder to 

administer and may undermine its effectiveness. The program will be 

difficult to enforce simply because it is hard to trace fuel to specific 

purposes within a factory. To see how the effectiveness of the program can 

be undermined by this exemption, it should, be remembered that many 

industries currently use by-product fuels. For example, gases emitted while 

crude oil is refined are recaptured and used as fuel at refineries; to avoid 

any boiler fuel tax legally, this by-product fuel could be used exclusively in 

boilers instead of being used in both boiler and non boiler applications. If 

this occurs, the tax is avoided by shuffling types of fuel among boiler and 

non boiler uses rather than being avoided by switching to coal. By-product 

fuels are also'available in other industries such as steel and chemicals. 

Second, the House bill depends heavily on the rebate effect, and for 

such policies the number of exemptions and the number of equipment types 

eligible for rebate are crucial. Exemptions lower the user-tax liability 

available for rebate and thereby lessen the rebate effect. Recently 

proposed tax policies exempt firms for which coal burning is precluded by 

state or federal air pollution regulations. "Preclusion" will have to be 

defined and, if program administrators are liberal with such exemptions, 

they will undermine the program by decreasing the number of boilers 

affected by the tax as well as by lowering the chances for large rebates. 

Additionally, broad eligibility lowers the portion of the user-tax liability 

that will actually be available for coal boilers. In recent legislation, rebates 

are available for equipment using any "alternate substance"; alternate 

substance means any substance other than oil or natural gas, not just coal. 

There is the chance that the effectiveness of the rebate plans would be cut 

because all equipment using substances other than coal, oil, or natural gas 

would receive rebates. Paper mills, petroleum refineries, and other 

facilities have always purchased such units. 

Third, both tax bills include "environmental exemptions." The House 

bill exempts only existing units, but the Senate bill makes both new and 

existing units eligible for exemptions from taxes if the use of coal is 

precluded by state or federal environmental regulations. Actually, no 

environmental law specifically precludes coal burning, so the exemptions are 

a matter for administrative judgment. One popular interpretation of this 

environmental exemption is that purchase of a new boiler will be considered 

"precluded" if the purchaser would have to abide by the emission offset 

policy. Only one study has taken a serious look at the potential for this 

impact. According to that study, if 296 million tons of coal consumption 

would be stimulated by the original economic incentives of the National 

Energy Plan, 29 percent of this economically justified coal use would be 

50 
affected. 6/ A number of conceptual problems cloud the study and hence 

its conclusIon. Most notably, since the study was not able to forecast 

precisely the location of the new fuel use, it is not really possible to 

estimate how much of it would fall in nonattainment areas; also, it must be 

remembered that both oil and coal users could be affected by the offset 

policy. Equally important is the fact that some localities have been 

assisting industry in obtaining the required offsets. For example, officials 

of New Stanton, Pennsylvania, recently interceded with state and county 

officials to get reductions in hydrocarbon emissions from state and county 

roads, thereby clearing the way for Volkswagon's new assembly plant in the 

area. Thus, for all practical purposes, Volkswagon did not incur additional 

expense to locate in a nonattainment area. The effect of the trade-off 

policy has not been, and perhaps cannot be, estimated confidently, and thus 

its effect is not reflected in any of the estimates. 

Fourth, the Senate bill exempts existing boilers and thus encourages 

oil and gas users to extend the life of their units so the tax can be avoided. 

Fifth, both bills delay inflation adjustments for the oil taxes until 

after 1980. If inflation is 6 to 7 percent in 1978 and 1979, the oil tax would 

fall in real terms by more than 14 percent and would thereby cut the 

effectiveness of both programs; this is not reflected in Table 10. The reason 

for such a delay is not at all clear once a program is chosen and the 

appropriate tax level established; the issue does not appear to arise with the 

natural gas taxes. 

Sixth, the tax programs are assumed to be permanent in this analysis. 

A purchaser buys coal-fired equipment to avoid higher oil or gas prices that 

are assumed to prevail throughout the life of the boiler. Any indication that 

the tax could soon be repealed would undermine the program's impact. 

Industrial Coal Conversion Regulatory Program 

Since 1974, the federal government has had the authority to prohibit 

the use of petroleum and natural gas in individual factories (major fuelburning installations). The program typically required a long legal process in 

which the federal government proved that a new or existing MFBI should be 

so prohibited. A recent House/Senate Conference agreement makes a broad 

and basic change in the coal conversion program by establishing a "blanket" 

2../ U.S. Environmental Protection Agency, Potential Siting Problem for 

Increased Coal Use, October 1977. 

51 
prohibition: firms are prohibited from using petroleum or natural gas in new 

boilers unless the federal government grants them a specific exemption. 

The bill has switched the burden of proof; now, the MFBI must show why it 

should not be prohibited from using oil or natural gas. Affected by this 

prohibition are boilers capable of consuming 100 million BTUs of fuel per 

hour or smaller boilers that are one of a group capable of consuming 250 

million BTUs per hour. 

As with the old program, existing MFBI must receive specific 

prohibition orders and the order can only be issued for units originally 

designed to burn coal. The Secretary of Energy is also given authority to 

prohibit petroleum and natural gas use in a few vaguely defined and, perhaps, 

inappropriate nonboiler applications (gas tubines, combined cycle units, or 

internal combustion engines). 

Temporary (5 to 10 years) and permanent exemptions are available 

upon request. An exemption for a new MFBI can be granted: 

o If the cost of using coal "substantially exceeds" the cost of using 

imported oil; 

o If a reliable coal supply is not available; 

o If "site limitations" such as inadequate space exist; 

o If environmental regulations preclude coal use; and 

o If the MFBI plans to use synthetic fuels that are not currently 

available--in this case a 10-year exemption is available. 

The primary targets of the industrial coal conversion program are 

new boilers larger than 100 million BTUs per hour; these units are projected 

to consume the equivalent of 0.9 million barrels a day by 1985. Success for 

the program depends completely on strict and clever enforcement. Projections of the coal sUbstitution induced by the program depends completely on 

one's guess of how well it will be administered. 

The industrial oil and gas user taxes and the regulatory program 

obviously overlap. Two of the ways in which the programs could interact 

are: 

o The regulatory program prohibits oil and gas use in new boilers as 

long as coal is not "substantially" more expensive to use than 

imported oil. Tax programs increase the cost of using oil and, for 

this reason, it is often argued that the tax program makes the 

52 
regulatory program easier to enforce. Another view, however, 

has been noted. The regulatory program, in effect, guarantees a 

market for coal as long as the cost of a coal boiler system is 

within a yet-to-be-prescribed range of oil costs. If a market is 

guaranteed to coal producers and associated industries, a strong 

incentive exists to increase the price of coal, coal transportation, 

and coal-fired equipment, and by adding to oil costs the tax 

program may invite even more price hikes. Competition among 

firms will tend to dampen unwarranted price increases, although 

it is not clear to what extent. 

o The Senate tax bill allows exemptions from taxes when a firm is 

exempt from the regulatory program. The provision complicates 

program administration by requiring cooperation among the 

Internal Revenue Service, which will administer the tax program, 

and the Department of Energy and the Environmental Protection 

Agency, which have prescribed roles in the regulatory program. 

This provision also increases the chance for liberal exemptions. 

REPLACING OIL AND GAS IN NONBOILER USES 

Nonboiler fuel uses are of two general types--oil and gas used in 

equipment such as ovens, kilns, and furnaces and that used as a raw material 

in the production of petrochemicals. Coal will be used as a raw material 

only if it is first processed into a gas or liquid. Solid coal use in nonboiler 

equipment such as industrial furnaces will generally require Research and 

Development of new equipment. A federal Research and Development 

program aimed at developing new, coal-fired industrial equipment and 

processes could be very expensive, difficult to manage, and have a high risk 

of failure. The heterogeneity of nonboiler uses necessitates demonstrations 

at many sites and, therefore, the program would have a high cost and would 

be difficult to manage. The fact that research on new ways to use energy 

cannot be divorced from research on new ways to produce products means 

that such a program might require unprecedented cooperation between 

government and industry scientists; thus, the risk of failure is high. 

Taxes on nonboiler oil and gas users can also be used to encourage 

coal use. The taxes would first provide an incentive to undertake the 

required research and development; then, when successful demonstrations 

are completed, they would provide an incentive to purchase coal-fired 

equipment. The House bill imposes user taxes on nonboiler uses when such 

uses are technically, economically, and environmentally feasible. The oil 

tax reaches $1.00 a barrel in 1982 and is constant in real terms thereafter; 

the gas tax gradually raises gas prices to a level $0.30 per million BTUs 

53 

32-488 0 - 78 M 6 
below the equivalent price of distillate oil in 1985. The actual eligibility for 

this tax is a matter of administrative judgment and, for the purposes of this 

report, it is assumed that most n6nboiler uses will be exempt on the grounds 

that solid coal use is not now technically feasible. Oil and gas consumption 

in the remaining uses, primarily for cement and lime production, is not 

estimated, although these energy consumers appear to be turning to coal 

voluntarily under current policy. 

The Administration may have the authority to impose the taxes 

contained in the House bill on many non boiler uses because consumption of 

processed coal may be feasible. It is not likely, however, that these low 

taxes would induce much demand. But this narrow administrative point 

raises another broad and complex energy issue: if coal is to be used to 

replace oil and natural gas, in what form should that coal be employed--in 

its natural, solid form or processed into gases or liquids. , 

If the federal government is to guide a transition to processed coal in 

the near term, it must do more than impose taxes on oil and gas. Many 

questions must be answered before this new energy industry can flourish. 

For example, what prices will be allowed for gasified coal? Will those 

gasification facilities be considered public utilities? How will they be sited, 

and what environmental regulations will be imposed? 

54 
APPENDIXES 

APPENDIX A. POSSIBLE TRANSPORTATION CONSTRAINTS TO 

INCREASED COAL CONSUMPTION 

EXISTING PATTERNS OF COAL TRANSPORTATION 

Railroads are by far the most important transporter of coal, moving 

about two-thirds of all produced. The three major competitors to rail for 

transporting coal are barges, trucks, and mine-mouth generation. Each of 

these competitors handles just over 10 percent of current U.S. coal 

production. The railroads! share has dropped slightly over the past 10 years, 

primarily because of the development of mine-mouth generation plants. 

Hence, the rail share of coal transported--that is, coal actually moving 

away from the mine--has remained fairly steady at just under 75 percent. 

Current movements of coal are not at all evenly balanced on a 

geographical basis. Generally, the coal-producing districts in the East have 

dominated U.S. production, with the Appalachian Region accounting for 

about two-thirds of total production. A large proportion of coal produced is 

destined for use in the East-North Central and South-Atlantic Regions; 

these two census regions account for about two-thirds of coal use. II The 

general dominance of the East shows up clearly in the maps depicting coal 

movements by the various modes that accompanied the 1977 Senate report 

on National Energy Transportation. '!:..I The major exceptions are the Great 

Lakes traffic and the emerging flows of western coal to eastern markets. 

Rail Coal Movements 

Coal is the largest single commodity carried by railroads. Coal 

traffic represented 20 percent of total railroad carloadings in 1976. The 

'!:..I 

Richard J. Barber Associates, Inc. "The Railroads, Coal, and the 

National Energy Plan," September 1977, Figure 5. 

U.S. Senate, Committee on Energy and Natural Resources and Committee on Commerce, Science, and Transportation, National Energy 

Transportation, 95 Congo 1 sess. (May 1977), Volume I, Maps 2-5. 

57 
next most important .. commodity is metallic ores, which account for only 

about one-third as much of total carloadings as coal. 

The slow growth of coal traffic, however, has been a major disappointment for the railroads. Even during the past four years, while the 

energy crisis has become a prominent issue, railroad coal traffic has grown 

very slowly (see Table A-1). Coal carloadings had declined fairly sharply in 

the early 1970s. Since 1973, coal carloadings have increased at a rate of 

only about 1 percent a year. Over the same period, however, total 

carloadings moving by rail have, in fact, decreased by 14 percent. Thus, 

although coal traffic has been relatively flat, it has been stronger than 

overall traffic. 

Focusing on measures of coal traffic other than carloads presents a 

somewhat different numerical picture of the importance of coal to the 

railroads, but it does not change the general magnitude discussed above (see 

Table A-2). Since coal is a relatively dense, heavy commodity, its 

percentage of traffic by weight (tons originated) is somewhat higher than its 

percentage of gross revenues or total carloadings--29 percent for all Class I 

railroads in 1976. On the other hand, coal rates are relatively low per ton 

compared with the rates for other commodities, and they are thus somewhat 

lower than the corresponding ratio for carloadings--coal represents 14 

percent of total Class I revenues. All three measures--tons, revenues, and 

carloadings-- show coal to be increasingly important to railroads. The 

geographic imbalance of coal traffic is also reflected in the traffic carried 

by the individual railroads. Seven railroad systems currently account for 

more than 85 percent of total railroad carloadings of coal. These are mostly 

eastern railroads, especially the Norfolk and Western and the Chessie 

System, which together earn 39 percent of railroad industry coal revenues. 

Other eastern rail lines with important coal traffic are the Family Lines 

System, ConRail, and Southern Railway. Non-eastern railroads with important coal traffic are the Burlington Northern and the Illinois Central Gulf. 

SIGNIFICANCE OF INCREASED COAL TRAFFIC 

The Administration's National Energy Plan projects a substantial 

increase in national coal production by 1985, whether or not new energy 

legislation is passed as recom mended. Even without the plan, production is 

expected to rise by 59 percent over 1976 levels. With implementation of the 

plan, an 89 percent increase is projected by the Administration. The 

increased production would be used by electric utilities and by general 

industry. Although the biggest proportional increases (and the greatest 

impact of the plan) are projected for general industry use, the largest 

58 
TABLE A-1. REVENUE CARLOADINGS OF COAL, 1973 TO 1976: IN 

THOUSANDS OF CARLOADS 

SOURCE: 

Year 

1973 

1974 

1975 

1976 

Carloads 

4,487 

4,544 

4,693 

4,699 

Association of American Railroads, Yearbook of Railroad 

Facts, various editions. 

TABLE A-2. COAL TRAFFIC AS A PERCENTAGE OF TOTAL TRAFFIC 

FOR CLASS I RAILROADS, 1973 AND 1976 

Tons Gross 

Year Originated Revenues Carloadings 

1973 24.3 9.8 16.4 

1976 29.0 14.0 19.9 

SOURCE: Association of American Railroads, Economics and Finance 

Department. 

59 
absolute increase in tonnage is attributed to electric utilities, representing 

56 percent of the projected overall increase. 

The implications for the rail industry--indeed, for all transportation 

modes--depend on the actual increase in coal production, its timing, and the 

percentage of share going to each mode. For purposes of the present 

discussion, an arbitrary increase in production of approximately two-thirds 

(to 1.1 billion tons a year) is assumed. It is further assumed that the 

railroads continue to move their current share of coal production. Coal 

traffic by rail would thus increase in the same proportion as production. 

This would represent an increase in tonnage originated of 288 million tons by 

1985, increasing from 437 million tons now hauled to the assumed total of 

725 million tons. 

If this projected increase were spaced evenly over the eight years 

from 1978 through 1985, coal tonnage by rail would increase about 35 

million tons a year, or about 8 percent annually. The additional coal traffic 

would increase total rail tonnage of all commodities by only about 3 percent . a year. ThUS, although coal is the most important single commodity moved 

by rail, a substantial increase in coal movement taking place over a number 

of years does not translate into a very striking increase in railroad traffic 

overall. It remains to be seen, however, whether railroads would be able to 

transport adequately such an increase in coal traffic. 

If the full growth in coal production envisioned in the National 

Energy Plan is realized, the annual growth in rail tonnage would be about 11 

percent, reaching a total of 837 million tons in 1985; again this assumes that 

rail retains its 66 percent modal share. Other scenarios for coal production 

and use could imply substantially higher rates of increased coal traffic for 

the railroads. For example, a study published by the Electric Power 

Research Institute (EPRI) projected a much larger increase in coal production and consumption by 1985, and further assumed that the railroads might 

indeed handle 100 percent of all coal production, diverting coal movement 

from barge, truck,. and mine-mouth generation. Under this scenario, rail 

carloadings of coal were projected to increase by substantial amounts, and 

the ability of the railroad industry to handle such increases would clearly be 

more questionable than under the above assumptions. 

Key Factors Regarding Rail Capacity 

Several key areas can be identified that will determine the ability of 

the railroads to increase substantially the movement of coal. These factors 

include the railroads' ability to supply needed equipment and to operate the 

equipment effectively. These items, in turn, depend on the volume of other 

60 
noncoal freight movement and the adequacy of the overall rail plant for 

other rail shipments. Finally, there is the question of financing needed 

expansion of either equipment or plant capacity. 

Unit Trains. The amount of equipment required and its effective 

utilization under any scenario regarding coal production will be significantly 

affected by whether the movement can be made by unit trains. A unit train 

represents dedicated equipment that is permanently linked and shuttling 

between fixed production and consumption points on a continuous basis. It 

has proven to be a cost-efficient method of moving coal to large users. Unit 

trains provide dramatic improvements in car utilization relative to normal 

car service: for example, one railroad that converted to unit train service 

from standard carload service now uses 892 cars in unit train service to 

deliver the same amount of coal that formerly required 2,400 hopper cars, a 

dramatic 63 percent reduction in car equipment needed for the service. 2..1 

While coal tonnage increased only slightly over the past decade, tons 

moved in unit trains have almost doubled in the same period. Between 1971 

and 1976, coal tonnage increased only about 15 percent, but the amount 

moving by unit trains increased over 60 percent. 

Of the growth in coal production, the amount that is likely to move 

by unit train will depend on the amount going to electric utilities and the 

intensity of industrial conversion. The National Energy Plan envisions 56 

percent of additional coal production going to electric utilities, which are 

well-suited to unit train service. If industrial conversion is accomplished 

only for large energy users, and for users that are near each other, then unit 

train operations could be applicable. It seems likely, however, that much of 

the projected industrial use will not be of sufficient scale and concentration 

to warrant unit trains, so that the railroads will need to finance greater 

expansion of equipment than would otherwise be the case. 

Eguipment Needs. In order to handle additional coal traffic, railroads 

will need to add coal-moving equipment, primarily open-top hopper cars and 

locomotives to pull them. Existing equipment will also have to be replaced 

in order to maintain current capacity. Based on an assumed two-thirds 

increase in coal traffic and a constant railroad share, two projections of 

equipment needs are presented in Table A-3. The influence of unit trains is 

clear: the number of hopper cars required per year ranges from 9,700 to 

13,400, while the number of locomotives required per year ranges from 485 

to 670. In both cases, actual coal-carrying capacity rises faster than the 

2..1 Association of American Railroads, "Coal and the Railroads--1977." 

61 
TABLE A-3. RAIL EQUIPMENT NEEDS FOR COAL TRAFFIC, 1978-1985 

Option 

High Unit-Train Option 

Hopper cars, new and replace 

Locomotives 

Annual Cost 

Low Unit-Train Option 

Hopper cars, new and replace 

Locomotives 

Annual Cost 

Units per 

Year 

9,700 

485 

13,400 

670 

Millions of 

Dollars per Year 

291.0 

242.5 

533.5 

402.0 

335.0 

737.0 

SOURCE: Association of American Railroads, "Coal and the Railroads--

1977." Assumes two-thirds increase in coal transported. 

62 
rate at which equipment is added, because the new cars are of higher 

capacity than those being replaced. 

These equipment needs compare very well with the current rate of 

equipment purchases. Three things about the recent experience should be 

noted: 

o The level of open-top hoppers installed in 1976 was 18,160, and 

over the past three years both orders and cars delivered have been 

running at an average annual level of about 16,000. 

o These high rates of car installations have not resulted in large 

expansions in fleet available. For example, the total cars in the 

open-top hopper fleet at the end of 1976 was 365,500, just slightly 

above the level of 256,600 available at the end of 1974. 

o The level of new cars ordered has been declining for the past two 

years. The level on order as of the end of 1976 was only about 

7,000 cars, so that recent levels of new car delivery cannot be 

maintained unless new orders accelerate. 

Thus, the actual rate of new cars installed in recent years has been 

greater than the rate projected to be necessary to transport expanded coal 

production. Even the projected need of 13,400 cars under the more likely 

low unit-train option falls well below the recent three-year installation rate 

of 16,000. Replacement needs appear to have been higher in recent years, 

however, than those incorporated in the projections, since the total car fleet 

has not expanded. Further, the disappointing levels of recent coal traffic 

have led to reductions in actual car orders, and new orders seem likely to be 

more closely linked to the level of actual, not projected, coal movements. 

Excess Current Capacity. In the fall of 1977, expectations of a coal 

miners' strike led to increased rail shipments as coal users attempted to 

build up inventories. If the actual number of carloads moved in the six 

weeks ending October 22 were extrapolated for an entire year, it would 

represent an increase of 20 percent over carloads moved in 1976 without any 

additional equipment. 4/ Thus, excess equipment currently in place could 

provide capacity for a substantial amount of the projected increase in coal 

movement. 

i/ Remarks by William H. Dempsey, President, Association of American 

Railroads, before the National Association of Regulatory Utility Commissioners, New Orleans, La., November 15, 1977. 

63 
Another dimension of rail capacity is the adequacy of the rail plant 

to handle coal movements along with other freight. Since World War II, 

railroads have had difficulty maintaining their share of the intercity freight 

market; to some extent, they have had difficulty maintaining their absolute 

level of traffic. While revenue ton-miles in 1976 were slightly higher (7 

percent) than in 1966, originated tonnage, freight car miles, and freight 

train miles were all lower in 1976 than 10 years earlier. Thus, there is a 

considerable historical potential for moving more freight over the existing 

rail plant. In more instances, this could be accomplished by reintroducing 

longer sidings, double track, or centralized traffic control signalling for 

existing track. The more even geographic distribution of future coal 

movements seems likely to favor just those railroads with capacity that 

could be expanded without great difficulty, but a number of specific 

bottlenecks have been identified in various studies. ~I 

The actual, frequent movement of heavy unit trains will not require 

much new rail line; some existing lines will have to be upgraded within a few 

years, and the lines will have to be maintained. The grain-hauling railroads 

of the Midwest and West were constructed with relatively lightweight rail. 

The Coal Transportation Task Force of the U.S. Department of Transportation concluded: II Although this lighter weight rail will be able to handle coal 

traffic for the next several years, 130-pound rail is likely to be needed 

before 1985." §/ 

Financing Expanded Capacity. Equipment financing has generally 

been the least sensitive of all railroad financing to the railroads' problems of 

low earnings and low rate of return. There are several reasons for this. The 

equipment itself is portable and can be transferred from one railroad to 

another in the event of default. Therefore, equipment trusts--that is, loans 

for the purchase of the equipment--have generally been available to most 

railroads, even those in financial difficulties. Further, shippers themselves 

and other third-party groups often purchase cars for lease or dedicated use, 

~I 

§./ 

For example, Manalytics, Inc., "Coal Transportation Capability of the 

Existing Rail and Barge Network, 1985 and Beyond," prepared for the 

Electric Power Research Institute, September 1976. 

U.S. Department of Transportation, Transporting the Nation'S Coal--A 

Preliminary Assessment (January 1978), pp. 11-22. 

64 
reducing the financing needs accruing directly to the railroad in question. 

Thus, the $4 to $6 billion capital investment for equipment needs that is 

implied by the estimates in Table A-3 should pose no special problem. 

The investment in fixed plant is more difficult to finance externally. 

Improvements of fixed plant, especially upgrading to heavier rail, and 

regular maintenance in the face of increased use are the areas of potential 

financing problems. Increased rates on coal traffic and more certainty 

about long-term traffic prospects may be necessary to generate adequate 

private investment. Preliminary estimates in the report of the Coal 

Transportation Task Force suggest a $4 to $5 billion level for upgrading. 

Some of this capital might be provided through Title V of the Railroad 

Revitalization and Regulatory Reform Act of 1976, but the Federal Railroad 

Administration has not yet released its report on the capital needs anticipated in January 1978. This report is supposed to discuss the overall 

capital needs of the railroads and the federal role in meeting them. 

Conclusions of Other Studies. Several studies of the coal movement 

and potential rail capacity have been conducted in recent years. On the 

whole, these studies conclude that projections of coal movement through 

1985 are basically manageable by the railroads with selected capacity 

improvements. Two reports have been less sanguine. First, the Manalytics/Electric Power Research Institute (EPRI) report projected much higher 

coal traffic for railroads and therefore magnified the potential problems of 

capacity. Second, various reports put out by the Slurry Pipeline Association 

generally suggest that the weaker railroads will experience the greatest coal 

traffic increases and will be unable to handle them; they further suggest 

that grain and other midwestern traffic may be displaced by the increased 

coal movement. 

KEY LEGISLATIVE ISSUES 

There are basically two areas in which legislation can influence the 

transportation of expanded coal production. The first is legislation providing financial assistance that influences the competitive situation between 

the various coal-moving modes. The second involves regulatory issues. 

Influences on Competition 

Transportation legislation influences the competition between modes 

in several fashions, the simplest of which involves the legislative promotion 

of specific modes. If the Congress provides promotional assistance for 

competing modes, such as barge operators on federally financed waterways, 

65 
then that mode's privately incurred costs would be lower than they would 

have been in the absence of such federal assistance, and the mode will be 

able to compete on more favorable terms. Although coal traffic by truck 

tends to be mostly intrastate in nature, federal aid for highways in general, 

and for energy-related roads in particular, could work to the advantage of 

truck transport of coal. Assistance to these other modes could expand 

transport capacity in general but undermine the ability of the railroad 

industry to increase the movement of coal if that assistance results in 

reduced rail earnings and an inability to build capital either internally or 

externally. 

Not all legislation that affects competition between modes need 

involve direct financial assistance. For example, the current financial 

assistance for the railroad industry itself is somewhat indirect and inVOlves 

a complex mix of loans and loan guarantees. Furthermore, legislation may 

be nonfinancial in nature, but quite influential nonetheless. For example, 

the issue of whether to grant eminent domain to proposed coal slurry 

pipelines involves little direct financial involvement on the part of the 

government. Nevertheless, Congressional indecision on this issue could have 

a major impact on railroads' willingness and ability to move additional 

amounts of coal. Construction of slurry pipelines would provide additional 

capacity for transporting coal and it reputedly would be less expensive than 

other forms of transportation. Slurry pipeline competition is potentially 

destructive, however, since traffic would be diverted on long-term contract, 

leaving rail unable to compete regardless of the actual cost structure. 

Pipelines could divert sufficient coal traffic to make railroad expansion 

unattractive; this might possibly undermine the railroads' viability as a 

mover of other commodities. 

Regulatory Issues 

The Congress sets the framework for regulation and often legislates 

specific regulatory prescriptions. A few selected examples of how legislative poliCY influences regUlatory matters and thereby the potential for 

expanded coal transportation follow: 

o Regulation of railroad rates, and particularly rates for coal 

movement, will substantially influence the willingness of the 

railroad industry to expand coal capacity. Rates on coal traffic 

have increased rather slowly relative to value, and they have 

often lagged well behind increased costs for factor inputs. If 

regulatory policy results in unattractive rates for coal movement, 

railroads will not willingly invest in additional equipment nor be 

attracted to move coal traffic. The Congress recently changed 

66 
the ground rules for rate regulation in the Railroad Rehabilitation 

and Regulatory Reform Act of 1976, generally moving toward 

more rate flexibility for the railroads and therefore rendering 

more likely voluntary expansion of rail capacity. Recent legal 

decisions, however, have held down unit train rates, and this will 

have the opposite influence. 

o A bill recently introduced by Congressman Harley Staggers of 

West Virginia (H.R. 9027) proposes a limitation on the length of a 

freight train. The proposed limit is 4,300 feet, which is the 

equivalent of roughly 75 cars. Enactment of this bill would 

substantially influence the economies of unit train operation since 

most' unit trains consist of 100 to 110 cars. Higher transport 

costs, in turn, might make coal conversion less attractive to 

industry if the costs were passed on or coal movement less 

attractive to the railroads if the rates were held down. 

o The regulatory process restricts common carriers from entering 

into long-term contracts in certain ways. The railroads argue 

that this restriction creates a disadvantage relative to the Slurry 

pipelines, which are likely to offer fixed long-term contracts. At 

present, railroads publish rates for coal movement, but they 

cannot build in automatic escalators for future cost increases. 

o The Congress controls maximum permissible truck weights, at 

least on the Interstate System, via provision of various highway 

acts. The most recent change in these restrictions was introduced 

in the Federal-Aid Highway Amendments of 1974. This can have 

pervasive competitive impact between modes, since it directly 

affects the coal tonnage that a truck can legally carry. The 

change in certain other clauses regarding state weight limitations 

in the 1974 legislation may have made trucks much more competitive for coal business. Furthermore, it is often alleged that coalcarrying trucks are typically and substantially overweight relative 

to both federal and state regulations, thus gaining an illegal 

competitive advantage. 

67 

APPENDIX B. METHODS AND DATA FOR THE ANALYSIS OF 

INDUSTRIAL BOILER FUEL DEMAND 

The concept behind the model of boiler fuel choice developed in this 

report is best expressed with the aid of Figure B-1. Costs of the steam 

output for a given size of boiler are represented on the vertical axis, while 

utilization rates are shown on the horizontal axis. Equipment for a coal 

boiler costs more than equipment for an oil-fired boiler, which in turn costs 

more than equipment designed for natural gas; thus, the points 3, 2, and 1 

represent costs at a zero utilization rate. As the utilization rate increases, 

total cost increases because the costs of fuel, operation, and maintenance 

are added. Coal becomes cheaper than both oil and gas at utilization rate A; 

that is, coal will be used in region X for new boilers of size Y that are 

expected to be used A percent of the time or more. Oil becomes cheaper 

than gas at utilization rate B, so oil will be used for new boilers with 

Figure 1·B. 

Boiler Costs By Fuel and Utilization Rate For 

Region X and Boiler Size Y 

Total Cost 

3 

2 

Coal 1.--------------

o B 

32.498 0 • 73 • 7 

Utilization Rate 

69 

A 100 
expected utilization rates between Band A. Gas will be used in all other 

new boilers. 

A computer program was developed to calculate these "breakpoint" 

utilization rates with all costs expressed as annuities. The equation used for 

the calculation is: 

(1) 

where: 

TOTAL ANNUAL COST = TAC = 

AC + OF + (OV x CF) + (F x CF) 

AC = capital cost annuity, 

OF = fixed operation and maintenance costs, 

CF = utilization rate or capacity factor, 

OV = variable operation and maintenance cost 

(expressed at 100 percent utilization), and 

F = fuel cost (expressed at 100 percent 

utiliza tion). 

Coal will be chosen over oil for a particular size of boiler when the total 

annual cost of coal (TAC c) is less than the total annual cost of oil (T AC 0); 

that is: 

(2) 

The utilization rate at which this begins to be true must be calculated; that 

is, the following equation must be solved for CF: 

(3) 

AC - AC + OF - OF 

c 0 c 0 

CF = OV - OV + F - F 

o c 0 c 

Coal would be chosen over oil for all boilers of a given size if their expected 

utilization rate exceeded CF. 

As noted above, the calculation must be performed for eight fuels for 

five boiler sizes in ten regions. Each term in equation (3) requires a 

separate set of calculations; these calculations are as follows. 

AC. For each boiler system there are two equipment costs--that for 

equipment which lasts 30 years (CAP 30) and that for equipment which lasts 

only 15 years (CAP 15). Each of these capital costs must be multiplied by a 

capital charge rate (CCR) to yield an annuity; to reflect differences in 

70 
regional prices, that annuity must then be multiplied by a regional price 

adjustment factor (RAF). In symbols: 

(4) 

OF. A fixed annual operation and maintenance cost is entered for 

each boiler system; it is then multiplied by a regional price adjustment 

factor. In symbols: 

(5) OF = OF* (RAF) 

F. A fuel price per million BTUs (FP) is entered for each boiler. To 

calculate fuel cost at 100 percent utilization, the fuel price is first 

multiplied by hourly fuel consumption (HFC); the product of that multiplication is then multiplied by 8,760, the number of hours in a year. In 

symbols: 

(6) F = (FP)(HFC)(8,760) 

OV. Variable operation and maintenance costs at 100 percent 

utilization are entered and multiplied by a regional price adjustment factor. 

In symbols: 

(7) OV = OV* (RAF) 

An 8 percent real, after-tax rate of return was used for all 

discounting. Some capital charge rates used in the analysis are displayed in 

Table B-1. 

Boiler Fuel Demand Projections 

Large Boilers. The starting point for the demand projections was 

1974 large industrial boiler fuel consumption by region and by SIC code; the 

data are taken from a federal survey of boilers in that year. 1/ Growth in 

that boiler fuel demand was then projected to 1980 and to 1985. All 

increases in fuel consumption were assumed to involve the purchase of a 

Y The Major Fuel Burning Installation Survey conducted by the Federal 

Energy Administration in 1975. The data were grouped by the 10 

federal regions. 

71 
TABLE B-l. CAPITAL CHARGE RATES !y 

Investment 

Tax Credit 

10 

25 

40 

Equipme,nt Life 

, 30 Years 

0.1693 

0.1410 

0.1128 

15 Years £/ 

0.1873 

0.1502 

0.1130 

SOURCE: Congressional Budget Office 

a/ Assuming an 8 percent real after-tax rate of 

return, straight-line method for book depreciation, sum of the yearsf digits method for tax 

depreciation, a 3 percent property tax, 4 percent state income tax, and general and 

administrative of 1 percent. 

'£/ Equipment lasting 15 years was assumed to be 

replaced in the 16th year at the same real 

equipment price. 

72 
new boiler. The increases were calculated by applying estimated industrial 

growth rates to 1974 BTU consumption. 2/ These growth rates reflect an 

economy that makes steady progress toward full employment in the early 

1980s and has growth sufficient to maintain full employment thereafter; 

real GNP grows, on average, by 4.5 percent each year between 1976 and 

1983 and then by 3.1 percent between 1983 and 1990. 

In addition to this "growth demand," a replacement demand for 

boilers was estimated. It was assumed that 3 percent of the 1974 boilers 

(representing 3 percent of 1974 boiler fuel consumption) would be retiredand therefore would need replacement-each year. The resulting estimates 

of new boiler fuel demand are displayed in Table B-2. 

The survey cited above was also used to distribute the growth and 

replacement boiler fuel demand across five boiler sizes and then, for each 

size group, across seven utilization rates. A change in the size distribution 

over time was not projected because that distribution, according to survey 

data, was remarkably stable over the last 30 years. The seven utilization 

rates are required because fuel choice is very sensitive to small differences 

in annual usage. 

The size and utilization rate distributions are displayed in Tables B-3 

and B-4. Given BTU consumption for a particular size of boiler, the portion 

attributable to a particular utilization rate equals: 

(8) 

U. N. 

1 1 

Lu. N. 1 1 

where 

U = utilization rate, and 

N = number of boilers with a particular 

utilization rate. 

(The reader should be cautioned that the data in the MFBI file has 

many obvious errors, and one must be selective about which entries to 

believe. Unfortunately, the MFBI file is the only source of data on size 

distribution and utilization rates.) 

The industrial growth rates are taken from Data Resources, Inc., U.S. 

Long Term Review: Fall 1977. --

73 
TABLE B-2. FUEL DEMAND FOR NEW, LARGE BOILERS 

BY FEDERAL REGION: IN TRILLION BTUs 

Federal 

Region 1974 Base 1974-1980 1981-1985 

1 103 41 52 

2 234 106 124 

3 464 186 230 

4 600 257 321 

5 854 314 392 

6 1,185 547 604 

7 81 37 37 

8 125 46 58 

9 143 59 56 

10 116 45 55 --

Total 3,905 1,637 1,928 

SOURCE: Congressional Budget Office calculations based on 

MFBI file provided by the Department of Energy. 

74 
TABLE B-3. LARGE BOILER FUEL CONSUMPTION 

IN 1974, BY BOILER SIZE 

Boiler Size 

(in million BTUs 

per hour) 

100 to 199 

200 to 299 

300 to 399 

400 to 499 

over 500 

Percent of Boiler 

Fuel Consumption 

35 

23 

15 

10 

17 

SOURCE: Calculated by Congressional Budget 

Office with data from the MFBI 

file provided by the Department of 

Energy. 

75 
TABLE B-4. BOILER UTILIZATION RATE DISTRIBUTION IN 1974 BY 

SIZE OF BOILER: DISTRIBUTION BY PERCENT OF FUEL 

CONSUMPTION 

Boiler Size (in million BTUs Qer hour) 

Annual 

Utilization 100 to 200 to 300 to 400 to over 

Rates 199 299 399 499 500 

10 to 29 8 5 2 2 3 

30 to 39 12 7 5 3 5 

40 to 49 12 6 8 6 10 

50 to 59 18 18 13 11 13 

60 to 69 14 15 24 17 11 

70 to 79 15 20 16 28 32 

80 to 100 21 29 32 33 26 

SOURCE: Calculated by Congressional Budget Office with data from the 

MFBI file provided by the Department of Energy. 

76 
Small Boilers. No detailed data are available on fuel consumed in 

small industrial boilers-those with a capacity less than 100 million BTUs 

per hour. It was assumed that 1974 BTU consumption was a little over 1 

quad. The MFBI file traces 3.9 quads of fossil fuels to large boilers in 1974; 

two other studies estimate total boiler fossil fuel use at about 4.7 quads. 2./ 

Given this rough estimate, small boiler fuel demand for growth and 

replacement would be about 500 trillion BTUs between 1974 and 1980, and 

between 1981 and 1985. This growth was distributed across regions 

according to the distribution for large boilers displayed in Table B-2. Small 

boilers were given the same utilization rate distribution as boilers in size 

group 100-199 million BTUs per hour. 

The final form of these large and small boiler projections is "cells" of 

new boiler fuel demand characterized by region, by boiler size, and by 

utilization rate. 

By applying industrial growth rates to 1974 fuel demand, it was 

implicitly assumed that boiler energy consumption per unit of output 

would remain constant through 1985. It is almost certain that coal, oil, and gas 

use per unit of output will fall over time for three reasons: 

o Boilers will be designed to produce steam with less energy per 

unit of steam generated. 

o Production processes will be modified to use less steam. 

o Other, nonconventional fuels will replace coal, oil, and gas. 

The third point appears to be by far the most important factor. Industrial 

wastes, for example, are a potentially important alternative fuel for boilers. 

An assumption of falling energy use per unit of output would reduce the 

demand for new boilers and, consequently, reduce the opportunity for coal 

to replace oil or gas as a boiler fuel. Of course, declines in oil and gas use 

per unit of output--that is, energy conservation--also lessen the need for a 

replacement policy; conservation and replacement are alternative means to 

lowering industry's dependence on oil and gas. To reflect conservation, new 

boiler fuel demand was cut by 10 percent. While 10 percent is not presented 

!I See the Energy Consumption Data Base; and Harry Brown and Bernard 

Hamel, Industrial Application Study, vol. II, prepared at Drexel 

University for the U.S. Energy Research and Development Administration (December 1976). 

77 
as a precise estimate, it appears reasonable, but conservative. Energy 

consumption per unit of manufacturing output fell at an annual rate of I 

percent or more even during the 1960s when real energy prices were 

constant or falling. 4/ Most industries have set goals of 10 to 15 percent 

for energy conservatIon by 1980; the goals were set by industries participating in the federal government's voluntary conservation program. The 

estimates should be viewed as presenting fossil fuel consumption in boilers 

at high rates of economic growth and with limited conservation. 

Model Solution 

In each region, breakpoints are calculated for all relevant fuel 

comparisons for each of five sizes (100, 200, 300, 400, and 500 million BTUs 

per hour). These breakpoints are then used to determine which cells of fuel 

demand will use coal, which will use oil, and which will use gas. For 

example, if the breakpoint for coal in region X for boilers of 100 million 

BTUs is 70 percent, two demand cells will be allocated to coal--the cells 

with boiler size 100 to 199 million BTUs and utilization rates 70 to 80 and 80 

to 100 percent. 

Fuel Cost Data 

The assumptions behind the fuel price estimates used in this report 

were discussed in Chapter III. The actual estimates for selected years are 

displayed in Tables B-5 through B-7. All price series were converted to 

annuities using an 8 percent discount rate. 

See Eners:x Consumption In Manufacturing, a report to the Er 

Policy Project of the Ford Foundation, 1974. 

78 
TABLE B-5. 

Federal 

Region 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

DELIVERED COAL PR, <ES PER MILLION 

BTUs:~ IN 1977 DOLLAR. 

1980 1985 1990 

1.57 1.63 1.69 

1.52 1.58 1.64 

1.47 1.53 1.59 

1.35 1.43 1.52 

1.14 1. 22 1.31 

1.74 1. 77 1.80 

1.27 1.35 1.44 

0.91 0.94 0.97 

1. 74 1.84 1.95 

1.82 1.85 1.88 

SOURCE: ICF, Inc., Economic Considerations In Industrial 

Boiler Fuel Choice, submitted to the Congressional 

Budget Office. These are not the fuel cost annuities presented in the ICF report; they are fuel 

prices in particular years. 

f!:./ In this analysis, coal can be delivered from five different 

coal supply regions to any of the 10 federal regions. This 

table only displays the lowest-price coal for each region. 

Regions 1, 2, and 3 use Northern Appalachian coal; 

regions 4, 5, and 7 use Midwestern coal; regions 6, 8, and 

10 use Western coal; and region 9 uses Rockies coal. 

Also in this analysis, boilers smaller than 300 million 

BTUs per hour use specially prepared and more expensive 

"stokerll coal; this table shows prices for "pulverized" 

coal used in large boilers. 

79 
TABLE B-6. 

Federal 

Region 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

DELIVERED RESIDUAL OIL PRICES PER 

MILLION BTUs: a/ IN 1977 DOLLARS 

High-Sulfur Oil ,Low-Sulfur Oil 

1980 1985 1980 1985 

2.07 2.30 2.65 2.91 

2.02 2.24 2.59 2.85 

2.09 2.31 2.66 2.92 

2.10 2.32 2.67 2.93 

2.22 2.45 2.80 3.06 

2.07 2.29 2.64 2.90 

2.10 2.32 2.67 2.93 

2.00 2.22 2.57 2.83 

2.04 2.26 2.61 2.87 

2.04 2.26 2.61 2.87 

SOURCE: ICF, Inc., Economic Considerations In Industrial 

Boiler Fuel Choice and Sobotka and Co., Refinery 

Gate Product Price Differential Forecasts For 

1985, submitted to the Congressional Budget 

Office. These are not the fuel cost annuities 

presented in the ICF report; they are fuel prices in 

particular years. 

!l/ Prices are constant in real terms after 1985 to reflect the 

assumption that world oil prices rise no faster than U.S. 

inflation. High-sulfur oil contains 3 percent sulfur, and 

low-sulfur oil contains 0.3 percent sulfur. 

80 
TABLE B-7. 

Federal 

Region 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

NATURAL GAS PRICES PER MILLION 

BTUs: al IN 1977 DOLLARS 

1980 1985 1992 

2.69 3.02 3.02 

2.12 2.67 2.96 

1. 76 2.55 3.03 

1.43 2.19 3.04 

1.64 2.23 3.17 

1.30 2.13 3.01 

1.60 3.04 3.04 

1.25 2.35 2.94 

1.69 2.56 2.98 

1.59 2.20 2.98 

SOURCE: ICF, Inc., Economic Considerations In Industrial 

Boiler Fuel Choice, submitted to the Congressional 

Budget Office. These are not the fuel cost annuities presented in the IeF report; they are fuel 

prices in particular years. 

fl.1 Prices are shown for 1992 because by this year gas 

prices have reached the distillate equivalent price 

in all regions and remain constant in real terms 

thereafter. 

81 

APPENDIX C. BUDGETARY EFFECTS OF BOILER TAX PROGRAMS 

The budgetary impacts of the House and Senate boiler tax programs 

are displayed in Table C-l. The estimates are in current dollars, assuming a 

6 percent annual rate of inflation. Taxes under the Senate bill begin in 

fiscal year 1982 because only new boilers are taxed and the eligible units 

will begin to come on line in 1982; the tax expenditure starts in 1980 

because "progress payments" will be eligible for the tax credit. The Senate 

tax revenue is assumed not to be rebated; only existing coal-capable units 

are eligible and, as discussed in Chapter II, those units not in nonattainment 

areas are assumed to convert under current policy before 1979. In contrast, 

all of the revenue collected under the House bill is assumed to be rebated 

evenly over the years 1980-1985; under the bill, only 1979 and 1980 tax 

liability can be carried forward. 

TABLE C-l. BUDGETARY IMPACTS OF HOUSE AND SENATE BOILER 

TAX PROGRAMS: BY FISCAL YEAR, IN MILLIONS OF 

CURRENT DOLLARS ~/ 

Policy Description 1979 1980 1981 1982 1983 1984 

Senate Bill 

Taxes 143 330 515 

Tax expenditures 218 307 326 345 366 

House Bill 

Taxes 485 1,515 1,966 2,200 2,398 2,365 

Tax expenditures (227) (320) (339) (289) (282) 

SOURCE: Congressional Budget Office 

IJ:./ Assumes a 6 percent rate of inflation starting in 1978. 

83 

o 

1985 Total 

695 1,683 

388 1,950 

2,618 13,547 

(299) (1,756)