A CBO STUDY The Clean Air Act,

the Electric Utilities,

and the Coal Market

April 1982

On Congress of the United States

U Congressional Budget Office

THE CLEAN AIR ACT,

THE ELECTRIC UTILITIES, AND THE COAL MARKET

Congress of the United States

Congressional Budget Office

For sale by the Superintendent of Documents, U.S. Government Printing Office Washington, D.C. 20402
NOTES

Except where noted, all dollar figures are expressed in 1980 dollars.

All dates are expressed in calendar years.

The projection period analysed begins in 1980 and ends in the year

2000. The most recent year for which most actual data are available is 1979.

ii
PREFACE

In 1981, the Congress began to consider amending the Clean Air Act;

that process is still underway. Among the critical areas being examined are

the federal standards that regulate air pollutant emissions from new electric

power plants using coal. Whether the regulations now in force can control

pollutant emissions effectively without imposing undue cost burdens on the

utilities and without affecting the distribution of U. S. coal production are

critical questions in the Congressional debate.

The Congressional Budget Office has prepared this analysis of these

interrelated issues, focusing both on the current standards and four alternative policies that would contribute to abating pollutant emissions from new

coal-fired power plants. The study was undertaken at the request of Senator

Robert T. Stafford, Chairman of the Senate Committee on Environment and

Public Works. In keeping with the CBO's mandate to provide objective

analysis, this paper offers no recommendations.

John Thornasian of CBO's Natural Resources and Commerce Division

prepared the study, under the supervision of David L. Bodde and Everett M.

Ehrlich. The author wishes to express special thanks to Hoff Stauffer of

ICF, Incorporated for his assistance in preparing the coal-market analysis,

to Johanna Zacharias for assistance in drafting the paper, and to Angela Z.

McCollough for typing the manuscript and preparing it for publication.

Valuable contributions also were made by Emily W. Fox and Paul Ginsburg of

CBO, Richard L. Gordon of Pennsylvania State University, and J. Steven

Herod of the U. S. Department of Energy.

Alice M. Rivlin

Director

April 1982

111

CONTENTS

PREFACE Hi

SUMMARY xiii

CHAPTER I. INTRODUCTION 3

Coal and Pollutant Emissions 3

Regulatory Mechanisms 4

Issues Before the Congress 5

Plan of the Paper 6

CHAPTER H. STANDARDS AFFECTING THE ELECTRIC

UTIUTY INDUSTRY—THEIR EFFECTS ON

EMISSIONS AND COSTS 7

Clean Air Act Requirements Affecting

Electric Utilities 7

Effects on Pollutant Emissions . . . . . 13

Nationwide Pollution Control Costs to

Utilities and to Electricity Consumers .. . 15

CHAPTER m. POLLUTION CONTROL AND THE

ELECTRIC UTILITIES' FINANCIAL

CONDITION 19

CHAPTER IV.

Financial Condition of the Industry and

Regulation by Public Utility Commissions .

Contribution of Air Pollution Control Costs

to Industry Capital Expenses ... .

The Effect of Air Pollution Control Costs

on the Electric Utilities' Financial Position

PROMOTING RELIANCE ON COAL AND

THE EFFECTS OF THE CLEAN AIR ACT .

Prevailing Regulations for Coal Conversions .

Cost Analysis—The Potential Benefits of

Reconversion or Replacement Compared to

Continuation of Oil or Gas Use ... .

Inhibiting Factors

The Immediate Prospects for Conversion .

19

22

23

29

30

31

34

35

CONTENTS (Continued)

Page

CHAPTER V. THE U. S. COAL MARKET AND

THE CLEAN AIR ACT . . 37

The Nature of the U. S. Coal Market ... . 37

The 1971 New Source Performance Standards

and U. S. Coal Consumption ..... . 42

The Revised NSPS and Projections for

U. S. Coal'Markets ....... . 46

CHAPTER VL CHOICES FOR NEW SOURCE

PERFORMANCE STANDARDS 53

Alternative Emissions Standards 53

Comparison of Alternative Emissions Standards . 58

Conclusions from the Analysis 69

APPENDIX A. EFFECTS OF THE PSD PROGRAM ... . 77

APPENDIX B. ANALYTICAL ASSUMPTIONS AND

METHODOLOGY .......... . 83

APPENDIX C. FINANCIAL EFFECTS OF DIFFERENT

ACCOUNTING METHODS FOR CONSTRUCTION

WORK IN PROGRESS ; 95

vii

TABLES

Page

TABLE 1.

TABLE 2.

TABLE 3.

TABLE 4.

TABLE 5.

TABLE 6.

TABLE 7.

TABLE 8.

TABLE 9.

TABLE 10.

TABLE 11.

TABLE 12.

NEW SOURCE PERFORMANCE STANDARDS

FOR COAL-FIRED ELECTRIC UTILITIES . . <

NATIONAL AMBIENT AIR QUALITY STANDARDS

AND ALLOWABLE INCREMENTS UNDER

PREVENTION OF SIGNIFICANT DETERIORATION

PROVISIONS

BOND RATING DISTRIBUTION OF 100 RATED

ELECTRIC UTILITIES AND SAMPLE SUBGROUPS

WITH INVESTMENTS IN ENVIRONMENTAL

CONTROL ,

CAPITAL AND GENERATING COSTS FOR A

500-MEGAWATT OIL-FIRED, RECONVERTED

OIL, AND NEW COAL-FIRED POWER PLANT .

PROJECTED REGIONAL GROWTH IN COALFIRED ELECTRICITY, TO YEAR 2000 . . .

REGIONAL COAL PRODUCTION FOR 1979

AND PROJECTED TO THE YEAR 2000 . . .

SUMMARY OF CURRENT AND ALTERNATIVE

EMISSIONS STANDARDS

TOTAL PROJECTED SULFUR DIOXIDE

EMISSIONS AND COMPARISON OF COST

EFFECTIVENESS UNDER CURRENT LAW

AND ALTERNATIVE STANDARDS . . . .

PROJECTED COST EFFECTS ON THE UTILITY

INDUSTRY OF ALTERNATIVE EMISSIONS

STANDARDS

UTILITY COAL CONSUMPTION IN 1979 AND

PROJECTED FOR THE YEAR 2000, BY REGION

REGIONAL COAL PRODUCTION FOR THE

YEAR 2000 UNDER EACH ALTERNATIVE . .

ESTIMATED LOW SULFUR COAL PRODUCTION

IN 2000, BY REGION

ix

12

25

32

49

50

54

60

62

66

70

72

93-281 0-82- 2

FIGURES

Page

FIGURE 1. ACTUAL AND PROJECTED POLLUTANT

EMISSIONS FROM ELECTRIC UTILITY

PLANTS—TOTAL AMOUNTS AND AVERAGE

RATES 14

FIGURE 2. FINANCIAL TRENDS IN INVESTOR OWNED

ELECTRIC UTILnTES ACCORDING TO TWO

MEASURES: 1970-1980 Zl

FIGURE 3. U. S. COAL FIELDS AND PRODUCING REGIONS . 39

FIGURE 4. TOTAL U. S. COAL PRODUCTION BY REGION

AND MINING METHODS: 1979 39

FIGURE 5. MONTHLY DELIVERIES OF COAL TO U. S.

ELECTRIC UTILITIES, BY SULFUR CONTENT:

1974-1980 43

FIGURE 6. U. S. COAL SUPPLY REGIONS 45

FIGURE 7. U. S. COAL DEMAND REGIONS 45

FIGURE 8. U. S. COAL PRICES, BY SULFUR CONTENT:

1974-1980 47

xi

SUMMARY

As the Congress considers revising portions of the Clean Air Act, it

confronts the sometimes difficult balance between two federal objectives:

o Achievement and maintenance of environmental quality, and

o Assurance of a reliable and low-cost supply of electricity derived

from coal, the nation's most abundant domestic energy source.

At present, coal combustion in utilities furnishes roughly half of the nation's

electricity-*-at the same time emitting nearly two-thirds of all the sulfur

dioxide, a gaseous pollutant, released into the United States' atmosphere.

UNDERLYING ISSUES

The Clean Air Act's new source performance standards (NSPS), by

regulating pollutant emissions from new power plants, will ultimately bring

about a generation of coal-fired facilities that will be markedly cleaner than

those supplying most electricity today. By the turn of the next century, the

amount of pollution utilities release relative to the volume of fuel consumed

will be reduced well below current levels, though/the actual quantity of each

pollutant, except particulate matter, will continue to grow through the year

2000. Sometime after that date, a measurable reduction in total utility

emissions of pollutants should begin to materialize. But because of the very

nature of the NSPS, which set standards for new or modified facilities only,

much of the emissions control benefit of the regulations lie far ahead*

The Role of the Electric Utilities

The nearer term will largely be a period of investment in cleaner

power plants; these will not outnumber their more polluting predecessors for

another two or even three decades. The electric utility industry will carry a

large share of that air pollution control investment. In complying with the

NSPS, utilities burning coal will dedicate some 20 percent of all their

capital investment to air pollution control in the next two decades. More

than half of this investment will involve meeting the current standards

regulating emissions of sulfur dioxide.

xiii
The Coal Market's Role

The U.S. coal industry will also play a part, though a more passive one,

in pursuing the two federal goals of clean air and energy self-sufficiency.

The industry will benefit significantly from the utilities' expanded use of

coal. Coal consumption in power plants, the nation's largest coal user, has

already risen by 65 percent from 1970 to 1979; over the coming two

decades, it will more than double. Not all coal producers will share equally

in this boom, however. Western producers stand to achieve a greater gain

than their counterparts in the Midwest and East. The Congress has already

linked concerns of the coal market to provisions of the Clean Air Act. In

the 1982 debate on the act, similar issues will almost certainly recur: What

effects will the current or alternative NSPS—particularly sulfur dioxide

standards—have on U.S. coal development?

COAL, SULFUR DIOXIDE EMISSIONS, AND NEW SOURCE

PERFORMANCE STANDARDS

An intrinsic chemical property of coal—specifically, its sulfur content—directly affects the amount of sulfur dioxide that results from coal

combustion. When burnt in a 500-megawatt power plant without emissions

control, a high-sulfur coal could generate roughly 91,980 tons of sulfur

dioxide a year. Conversely, combustion of a low-sulfur coal in the same

power plant could yield roughly 7,665 tons of sulfur dioxide a year. Though

coal is produced in all three subdivisions of the country—the East, the

Midwest, and the West—sulfur content varies markedly. Eastern deposits

contain both low- and high-sulfur coal; midwestern coal ranges from

moderate to high in sulfur content; western coal is generally low in sulfur.

The NSPS of 1971

The act's original provisions regulating new source pollutant emissions—eliciting the utility NSPS of 1971, which applied to all new fossilfuel-fired generators—did not take these differences into account. The

1971 NSPS mandated that the utilities meet a mass sulfur dioxide emissions

limit of 1.2 pounds per million British thermal units (BTUs) of coal burnt, as

well as placing limits on nitrogen oxides and participate matter. Utilities

could comply by whatever means was most economical, and most elected to

burn low-sulfur coal. One result was a slowing of sulfur dioxide emissions

growth; a significant reduction in participate pollution occurred; but there

was little success in curbing nitrogen oxide emissions.

xiv
Another result, perceived by high-sulfur coal producers and in turn, by

the Congress, was that imposition of the NSPS would change the distribution

of U.S. coal production—specifically, that the 1971 NSPS could encourage

the production and use of abundant low-sulfur western coal over its highsulfur counterpart in the Midwest. This perception, together with the desire

to promote the use of control technology, led to the revisions in the utility

NSPS that became effective in 1978.

The NSPS of 1978

Revisions implemented in 1978 were conceived, in part, to counter the

relocation of U.S. coal production. The 1978 standards, which remain in

effect and govern all power plants now being planned, were purposefully

designed to make high-sulfur coal as economically attractive to utilities as

low-sulfur coal. To accomplish this, the revisions stipulated not only that

the old mass emissions limit (a "ceiling") must be met, but also that a fixed

percentage of all sulfur dioxide be removed from all power plants burning

coal. In recognition of the sulfur-content variations in coal, the revised

NSPS permitted a sliding scale for emissions removal, to range between 70

and 90 percent, depending essentially on the sulfur content of coal used.

The effect of the provisions under the 1978 NSPS, which are quite

rigid compared to the older standards, is to make the use of flue gas

desulfurization technology—called "scrubbers"—mandatory. To date, scrubbers are the primary control technique that is commercially available to

help utilities meet the NSPS in conventional boilers. No matter what coal is

to be used, all new plants subject to the 1978 standards must be equipped

with scrubbers or some other suitable control method. The costs of

desulfurization will be the single most important element in the utilities'

future costs for air pollution control.

THE COSTS OF EMISSIONS CONTROL

The utilities have already invested sizable sums of money to curb

pollutant emissions, and they are likely to continue to do so. In each year

since 1973, the industry devoted from 5 to 7 percent of all capital

expenditures to emissions control hardware. Over the coming two decades

(the base period for the Congressional Budget Office's projections), investment in air pollution control equipment is projected to involve 20 percent,

or $33.4 billion (in 1980 dollars) of the roughly $167 billion needed to

construct new coal-fired generating capacity (not including transmission and

distribution).

xv
The utilities1

 annual air pollution control costs, including operation of

scrubbers, fixed capital charges, and premiums on low-sulfur fuel, are

expected to rise from $5.35 billion in 1980 to $14.1 billion in the year 2000.

By that year, these costs translate to a nationwide average of 3.43 mills per

kilowatts-hour, representing roughly 6 percent of the average electricity

charge to residential consumers in 1980. Pollution control at new units—by

definition, subject to the 1978 NSPS—is expected to cost approximately 6

mills per kilowatt-hour for western power plants, which can use locally

mined low-sulfur coal and lower-cost scrubbing methods, and 10 mills per

kilowatt-hour for eastern facilities, which typically will use local high-sulfur

coal and expensive scrubbing methods, or will ship low-sulfur coal from

other regions to lower scrubbing costs.

Effects on The Utilities* Financial Condition

Because of the high capital costs of air pollution control, it is

reasonable to question whether the Clean Air Act is placing an unmanageable burden on the electric utilities. Would the industry's finances be

stronger if there were no need to invest in pollution control measures? The

findings of the CBO analysis indicate that, though controlling emissions is

indeed costly, it has not played a major role in impairing the utilities'

financial position, and is hot likely to do so in the future. A comparison of

the bond ratings of two sample groups of firms with appreciable investments

in pollution control against the industry as a whole suggests that utilities

with commitments to pollution control tend to fare no better and no worse

than all electric utilities in general. Special tax provisions and other

mitigating factors directed at easing the investment costs of pollution

control may account in part for why the costs of emissions control are not

especially detrimental. Overall, most utilities, regardless of investment in

emissions control, have experienced some financial decline (indicated by

downgraded bond ratings), but this pattern may be more properly ascribed to

other causes.

Stated-Mandated Accounting Methods. Accounting methods required by

the states' regulatory public utility commissions often tend to make capital

investments in new facilities burdensome. In most states, an electric utility

cannot incorporate the costs of a new power plant in its rate bases until the

facility becomes operational; hence, the utility cannot receive a return on

its investment for roughly eight to 12 years, the usual construction period

for power plants. On the other hand, rising fuel costs often may be

recovered immediately from consumers, with the result that continued

operation of older power plants burning oil or gas, though coxnmonly more

expensive, is the preferred alternative to investing in scrubber-equipped new

facilities entailing high capital expenses.

xvi
EFFECTS ON U.S. COAL MARKETS

The westward shift in coal production seen over the past decade

cannot be directly linked to the Clean Air Act, although such a shift is

certainly clear. In I960, the producing states in the East accounted for 95

percent of total production. By 1970, the Eastfs share had declined to 85

percent and, by 1979, to roughly 75 percent. By the year 2000, the West is

projected to hold a full 66 percent share of the nation's total coal

production. Regarding western coal shipments east, sulfur dioxide limitations of the NSPS have influenced this only partly, and despite the intent of

the revised NSPS to counter this trend, western producers are projected to

capture a still greater share of the total midwestern and eastern coal

markets in the future. In 1979, western producers shipped some 22 million

tons of coal east to utilities; by the year 2000, some 127 million tons of

western coal, or 7 percent of the total 1.9 billion tons produced in that year,

are expected to be shipped east.

The current NSPS appear to have little influence to bolster midwestern and eastern coal production against such growth in the West.

Western coal production is rising for several intrinsic reasons. First, lowercost mining methods predominate there. Second, with this initial cost

advantage, western coal can be shipped long distances, and even in the face

of high and rising rail shipment costs, it can often compete favorably with

indigenous midwestern coal. Third, the West is slated for a sizable

expansion of its coal-fired electrical capacity, which will raise local demand

for western coal. Thus, the prospects for the current NSPS to reverse the

coal market's westward shift in production appear slight.

ALTERNATIVE APPROACHES TO THE CURRENT NEW SOURCE

PERFORMANCE STANDARDS FOR ELECTRIC UTILITIES

All four of the policy choices the CBO has examined would affect the

act's current NSPS as they pertain to sulfur dioxide emissions. Three of the

alternatives would follow the general approach of existing standards, in that

they would apply only to new coal-fired power plants. The fourth would

depart from established approaches in allowing old as well as new sources to

participate in the control of emissions under the standards. After a brief

description of the options (also displayed in the Summary Table), the

following analysis focuses on three potential effects:

xvu

93-281 0-82- 3
SUMMARY TABLE. ALTERNATIVE SULFUR DIOXIDE EMISSIONS

STANDARDS (Projected to year 2000; emissions limits

in pounds per million BTUs of fuel consumed)

Options and

Descriptions

Effects on

Emissions

Current NSPS

Sets a ceiling of 1,2 pounds

and a floor of 0.6 pounds;

90 percent scrubbing required

for emissions above

floor, and 70 percent

for those below floor a/

Total emissions growth

limited to annual 21

million tons; new plant

emissions total 1.6

million tons a year

Option I

Sets a ceiling of 1.2 pounds

Option H

Sets a ceiling of 1.2 pounds

and a floor of 0.8 pounds;

70 percent scrubbing

required for emissions

above floor a/

Option IE

Sets a ceiling of 1.2 pounds

and a floor of 0.6 pounds;

90 percent scrubbing

required for emissions

above floor a/

Option IV

Requires same total emissions

control as under current NSPS;

allows emissions trading

between old and new sources

to meet overall limit

Total emissions growth

limited to annual 22.8

million tons; new plant

emissions total 4

million tons a year

Total emissions growth

limited to annual 22.1

million tons; new plant

emissions total 2.8 million

tons a year

Total emissions growth

limited to annual 21.9

million tons; new plant

emissions total 2 million

tons a year

Total emissions growth

limited to annual 21

million tons; new plant

emissions total 2.5 million

tons a year

a/ Applies to new electricity sources only. (continued)
SUMMARY TABLE. (Continued)

Cost

Effectiveness

Relative to

1971 NSPS

Capital and Operating

Cost Effects

Coal Market

Changes

$2,411 per ton of

sulfur dioxide removed

Total capital outlays

of $33.4 billion; annual

operating costs $14.1

billion in year 2000

High midwestern and

lower western production; 127 million

tons western coal

shipped east

Basis of Comparison Total capital outlays

of $14 billion; annual

operating costs $9.8

billion in year 2000

High western and low

midwestern coal production; 151 million

tons western coal

shipped east

$1,929 per ton of

sulfur dioxide removed

Total capital outlays

of $14.6 billion; annual

operating costs $11.1

billion in year 2000

High western and low

midwestern coal production; 164 million

tons western coal

shipped east

$3,400 per ton of

sulfur dioxide removed

Total capital outlays

of $17.1 billion; annual

operating costs $12.8

billion in year 2000

High western and midwestern coal production; 145 million

tons western coal

shipped east

$550 per ton of

sulfur dioxide removed

Total capital outlays

of $14.7 billion; annual

operating costs $10.8

billion in year 2000

High western and

moderate midwestern

coal production; 149

million tons western

coal shipped east

SOURCE: Congressional Budget Office
o Emissions,

o The electric utilities' costs to meet the standards and the options'

cost effectiveness, and

o Effects on U.S. coal markets.

In the analysis, no attempt is made to weigh costs against benefits. Though

the costs of such governmental regulations as pollution control are reasonably amenable to being quantified and compared, the benefits are not. No

generally acceptable measures exist for gauging health improvements,

preservation of natural and structural assets, or other societal gains that

may result from federal emissions limits. Thus, the CBO has not assessed

measurable costs of abatement against important but intangible benefits*

Option I. Revert to the NSPS of 1971

Reenactment of the original NSPS would effectively rescind the

present requirement that all new power plants be equipped with scrubbers.

The only standard would be a mass emissions limit of 1.2 pounds of sulfur

dioxide per million BTUs of fuel consumed; no fixed percentage of that

pollutant would have to be removed. Thus, combustion of low-sulfur coal

would offer an acceptable means of compliance.

Option n. Achieve 70 Percent Control of Sulfur Dioxide Emissions and Set a

0.8 Pound Floor

Following the general structure of the current NSPS, this option would

require scrubbing for some plants but not all, depending on the coal used.

Sulfur dioxide emissions, between a maximum permissible ceiling of l.Z

pounds and a floor of 0.8 pounds per million BTUs of fuel, would have to also

be reduced by 70 percent. For emissions below the floor, no specific

percentage reduction levels would be mandated. Thus, low-sulfur coal could

be burnt with little or no scrubbing; high-sulfur coal would have to be

scrubbed to remove at least 70 percent of sulfur dioxide emissions.

Option ffl. Achieve 90 Percent Control of Sulfur Dioxide Emissions and Set

a 0.6 Pound Floor

A variant of Option n and the current standards, this alternative would

stipulate the same sulfur dioxide emissions ceiling (1.2 pounds per million

xx
BTUs) but would establish an emissions floor of 0.6 pounds. The percentage

removal for emissions between the ceiling and floor would be 90 percent,

while no control requirements would be specified for emissions below the

floor. This option would thus retain the current scrubbing requirement for

high-sulfur coal, reduce the amount necessary for low-sulfur coals, and

eliminate it entirely for very low-sulfur coals.

Option IV. Constrain Total Emissions Growth by Balancing Sulfur Dioxide

Emissions from Old and New Sources

This option, a fundamental departure from other approaches, would

allow old as well as new sources to be involved in meeting emissions

standards. While still directed at new sources, the standards would permit a

new facility to trade emissions with other existing power plants to achieve

the same quantity of emissions control as required under the present NSPS.

Within a given area—in this example, a state—a planned plant would be

allowed to find a trading partner among existing sources. If the old source

could meet standards sufficiently below its applicable regulations, its new

source trading partner could exceed the limit by an equal amount, so long as

the old source continued to operate. This approach is termed new source

"bubbling", since it allows control to be balanced between all emissions

within a given atmospheric area, so long as the total quantity leaving the

bubble remains constant. Acceptable methods of compliance would involve

both scrubbing and low-sulfur fuels at both old and new power plants.

Effects of the Alternatives on Future Emissions

In contrast to the current NSPS, which would hold the growth of sulfur

dioxide emissions from electric utilities to a total of 20 percent over the

coming two decades, Option I would allow emissions to rise by 30 percent.

This translates into 21 million tons under current law and 22.8 million tons

under Option I. These figures represent the upper and lower bounds of

emissions control achievable under all the options. Inasmuch as old sources

are projected to account for some 80 percent of all sulfur dioxide emissions

through the year 2000, there is little room for improvement to be achieved

over the projection period by regulations governing new sources only.

Similarly, Option IV, while reducing the costs of emissions control and

spreading the burden between new and old sources, cannot be expected to

bring about any radical change in overall emissions levels, since the control

levels are based on current NSPS. New power plants constructed subject to

Option I would emit roughly twice the amount of sulfur dioxide as those

constructed under the current standards. These differences in total

xxi
emissions would become measurable only when the older generation of

dirtier facilities retire, sometime around the year 2010.

Cost Effect on Utilities

Although the CBO analysis suggests that capital costs for air pollution

control may not be detrimental to the utilities' financial condition, the high

capital expense of scrubbing does appear to raise overall costs for the

utilities and the consumers* The current NSPS would require the greatest

capital outlay ($33.4 billion) and would result in the highest annual cost

($14.1 billion by the year 2000). In contrast, Option I (the previous NSPS),

which would allow widespread use of low-sulfui- coal, would require only $14

billion in capital and $9.8 billion in annual costs by the year 2000. The other

options, by promoting different mixes of scrubbing and low-sulfur coal

combustion, fall somewhere in between, although the capital requirements

of each of these options appear not to be nearly so high as the current

standards. ' ' - • •"" • -.-

 f '' ". — .-. ' .-• . ---;••--. . - , 5,

Cost Effectiveness^ A true measure of the cost differences between

each option can only be made when differences in emissions are also taken

into account. A rough gauge of cost effectiveness may be derived by

measuring the costs of reducing sulfur dioxide emissions below the highest

levels projected--in this case, the 22.8 million tons per year projected under

Option I. The current NSPS would cost $2,411 for each ton of sulfur dioxide

removed below that level. Option n would cost $1,929, and Option m—the

most costly in these terms—$3,400 per ton removed. Option IV, in contrast,

offers the prospect of lowering sulfur dioxide levels at a cost of only $550

per ton removed for as long as existing old sources remain in operation; the

reason for this potential economy is the ability to adhiev^ low-cost

emissions reductions at existing facilities by relying on lower-sulfur fuels.

For example, converting a 500-megawatt plant from high- to low-sulfur coal

would cost $431 for each ton of sulfur dioxide removed from previous

emissions levels; such reductions might be used in a trade. Costs for a new

plant, in contrast, might total some $1,230 per ton to achieve similar levels

of reduction below the 1.2 pounds sulfur dioxide emissions limit of Option I.

Coal Market Effects

From the standpoint of the U.S. coal market, any emissions standards

that would place heavy emphasis on the use of scrubbers should discourage

the purchase of nonlocal coal to meet emissions standards. Conversely, deemphasizing control technology in favor of mass emissions limits should

xxii
increase the demand for and value of low-sulfur coal. These effects are

partly borne out in projections of the coal market under each alternative.

Thus, implementing Options I or IV would tend to perpetuate the trend

observed during the 1970s, during which low-sulfur coal production grew and

western coal sales expanded eastward. Option n, because of its low

scrubbing requirement and high emissions floor, also would promote the use

of low-sulfur coal. Only continuing the current NSPS or adopting Option ffl,

both of which would entail sizable amounts of scrubbing, would tend to

counter that trend, fostering greater use of high-sulfur coal from the East

and the Midwest. /

Neither the current NSPS or any of the alternatives examined appears

to have great potential to stem the growth of western coal production or the

penetration of western low-sulfur coal into markets to the east. Even the

current NSPS, with their universal requirement of scrubbing, can only slow

the rate of shipments of western coal to utilities in the Midwest and the

East. Options I and IV would offer no provisions that would counter this

trend, and Options n and ffl, with some scrubbing requirements but less than

the current NSPS, would have almost as little effect. As has ibeen observed

since the early 1970s, inherent factors in western and coal production are

expected to continue to overwhelm any influence on coal markets arising

from pollutant emissions standards. Circumstances that could significantly

alter this projected pattern include higher-than-anticipated rail shipment

rates and significantly lower costs for control technology.

CONCLUDING REMARKS

Which of the federal government's goals receives higher Congressional

priority would determine which of the options analyzed offers the better

prospects. The Clean Air Act's current NSPS are best suited to holding

down emissions and safeguarding midwestern coal production, but at sizable

costs to the utility industry. The utilities would be better served by Options

II or m, but at some sacrifice in pollution abatement. Under Options I or IV,

the act's pollution control goals would be advanced to different degrees at

minimal costs, but the coal producers of the Midwest would pay a price in

markets lost to western suppliers. In short, the analysis suggests that the

several objectives of constraining sulfur dioxide emissions, easing the

electric utilities' financial burden, and protecting midwestern coal producers

cannot all be pursued with equal emphasis.

xxin

THE CLEAN AIR ACT,

THE ELECTRIC UTILITIES, AND THE COAL MARKET

93-281 0-82- 4

CHAPTER L INTRODUCTION

Federal policies that would protect the nation's air quality and others

that would ensure a reliable, low-cost supply of electricity can sometimes

interact in difficult ways. This study examines the question of whether

clean air and energy policies as they affect the electric utilities are in fact

on a collision course. The mechanisms by which the air quality goal is

sought are embodied in the Clean Air Act, administered by the Environmental Protection Agency (EPA) and last amended in 1977. I/ The establishment of a secure and inexpensive power supply rests on encouraging

greater use of the United States' most abundant energy source: coal.

Since 1970, coal combustion has supplied roughly half of all yearly

electrical production and promises to furnish an even greater share in the

coming decades. Though plentiful and not vulnerable to foreign supply

interruptions—and inexpensive in comparison with oil and gas—coal is also a

major source of air pollution. The burning of coal by utility plants, which

account for more than four-fifths of the nation's total coal consumption,

accounts for approximately 60 percent of all sulfur dioxide emissions in the

United States, 25 percent of all nitrogen oxide emissions, and 15 percent of

all particulate emissions. 2/ The control of these pollutants—especially

sulfur dioxide—is expensive, complicating the interaction between clean air

policy and the desire to promote coal use in electricity production.

COAL AND POLLUTANT EMISSIONS

Chemical characteristics unique to coal have had a direct bearing on

the shaping of federal emissions control regulations and their effects both

1. First enacted in 1968 as Public Law 88-206, the Clean Air Act has

undergone several major legislative revisions since that date. The

structure of the act that prevails today, underlying the analysis in this

paper, was adopted under the Clean Air Act Amendments of 1977

(Public Law 95-95).

2. These data, supplied by the EPA, reflect estimated pollutant levels for

1979, the most recent year for which data are available.
on utility companies and on the coal industry itself. When coal is burnt, it

generates noxious gases (sulfur dioxide and nitrogen oxides) and participate

matter (unburnt material and ash). In particular, the generation of sulfur

dioxide has the greatest bearing on how emissions regulations can affect the

utility and coal industries. The amount of sulfur dioxide produced during

coal combustion is a direct function of the sulfur content of the raw fuel.

Coal's sulfur content varies from source to source, ranging between less

than 1 to greater than 4 percent by weight. Mines in the West generally

produce coal low in sulfur content; medium- and high-sulfur coals predominate in the Midwest; eastern mines produce coals with a full range of sulfur

contents. The higher coal's sulfur content, the higher its emissions of sulfur

dioxide. The evolution of emissions regulations for utility plaints under the

Clean Air Act, and the debate surrounding such regulations, reflect these

particular properties of coal.

REGULATORY MECHANISMS

In its present form, the act is designed to protect air quality through

several chief mechanisms. 3/ The primary objective of the act is to ensure

that all areas of the country achieve air quality equal to or better than

national ambient air quality standards (NAAQS), which are established by

the EPA. These standards reflect the maximum acceptable pollutant

concentrations that offer a safe environment for the public's health and

welfare. Two important programs are designed around the NAAQS. A

"nonattainment program" requires states to develop plans providing for

attainment of all NAAQS in areas not currently meeting them; the prevention of significant deterioration (PSD) program directs the EPA and the

states to limit the increase of pollution in areas with air better than the

NAAQS. Finally, as an aid in limiting pollution growth and maintaining the

NAAQS, the act directs the EPA to establish uniform nationwide emissions

limits for most major new facilities. These standards, termed new source

performance standards (NSPS), apply to specific categories of new and

modified air pollution sources nationwide, and they reflect the minimum

acceptable levels of control for these facilities. The effects of these NSPS

on the utility and coal industries are a major focus of this study.

Since the act's passage, the EPA has twice established NSPS for the

electric utility industry. These regulations affect all new and modified

3. For further information on the Clean Air Act, see National Commission on Air Quality, To Breathe Clean Air, Final Report (March 1981).
facilities built after the effective date of the particular standard and limit

the emissions of most gaseous and solid pollutants. In general, these

standards have met with little controversy; however, the emissions control

requirements for sulfur dioxide have remained a subject of intense debate.

The first set of NSPS was established in 1971 and was designed to

allow the utilities to meet sulfur dioxide emissions standards using either

low-sulfur coal alone or high-sulfur coal with special equipment developed

to reduce sulfur dioxide emissions. The equipment used to reduce such

emissions is flue gas desulfurization technology, commonly referred to as

"scrubbers." Though available at the time of the first NSPS, scrubbers were

expensive, and since they were not mandatory, utility managers generally

avoided installing them in new units. Instead, low-sulfur coal was typically

employed as an emissions control strategy. As a result, controversy arose

over the 1971 regulations with respect to their possible effects on the

nation's coal market, focusing on whether they would encourage the

production of low-sulfur coal (primarily a western product) at the expense of

medium- and high-sulfur coal produced in the Midwest and East.

In amending the Clean Air Act in 1977, the Congress changed the

criteria on which the EPA bases emissions standards for facilities using

fossil fuels. Two factors underlay the change: concern over the apparent

regional inequities in the coal market fostered by the old regulations, and

intent to encourage use of pollution control technology. The new emissions

regulations the EPA adopted—the NSPS of 1978, which are still in effect—require that all newly built power plants curb sulfur dioxide emissions

from any coal they burn. In effect, these NSPS dictate that scrubbers be

installed in all new utility units, since no other commercially available

technology can meet the EPA standards. As a result, since scrubbers

became virtually mandatory, utility managers now have little motivation to

use low-sulfur coal except where it is most readily available--that is, where

it is locally produced. Implement ion of these regulations, it was believed,

would minimize new emissions everywhere and would correct regional

inequities in coal production.

ISSUES BEFORE THE CONGRESS

Two controversies now surround the NSPS for sulfur dioxide emissions:

o Whether the high capital costs of scrubbers overburden the

utility industry in proportion to the control they achieve; and

o Whether the costs of scrubbers jeopardize the economic advantage of coal relative to costlier fuels, namely oil and gas.
With these issues in mind, the Congress has already begun to consider

further revisions to the Clean Air Act. For a third time, legislators will

likely reassess the provisions by which the act requires the utilities to

control emissions.

To assist in clarifying the issues under Congressional debate, this study

explores four critical questions:

o What is the likely future effect of the current NSPS on sulfur

dioxide and other pollutant emissions?

o What are likely to be the costs of reducing pollutant emissions at

coal-fired power plants, and what financial burden do these costs

put on electric utilities?

o How might emissions standards influence the patterns of coal

production and use in the United States?

o What other forms might emissions control standards take, and

what might their effects be on the utility and coal industries?

As before, questions of economic efficiency will probably arise again

in the course of the debate. Will the societal benefits of pollution

abatement warrant their considerable economic costs? Only so long as the

benefits outweigh the costs can those costs be justified. In considering this

question, the Congress will want to identify emissions regulations that will

achieve an economically correct level of abatement. Because the damage

that environmental deterioration may cause—to public health, agriculture,

structures, and other national assets—is difficult to quantify, the benefits

to be gained from clean air policy are equally difficult to gauge. Though

critically important in Congressional decisionmaking, these issues are

beyond the scope of this paper.

PLAN OF THE PAPER

Chapter n of this paper describes the costs of the Clean Air Act to the

electric utility industry. Chapter HI reviews the present financial condition

of utilities and examines the costs to them of pollution control. Chapter IV

analyses the effects of the Clean Air Act on the prospects for conversion

and replacement of oil- and gas-fired generating capacity with coal. The

focus of Chapter V is on the Clean Air Act's implications for the U.S. coal

market. The closing portion of the paper, Chapter VI, outlines four

alternative emissions standards for the utilities, exploring the potential of

those choices on sulfur dioxide emissions, on utilities' capital and operating

costs, and on the U.S. coal market.
CHAPTER n. STANDARDS AFFECTING THE ELECTRIC UTILITY

INDUSTRY—THEIR EFFECTS ON EMISSIONS AND COSTS

The current air pollution control regulations required by the Clean Air

Act will bring about a generation of power-producing facilities that will be

significantly cleaner than their predecessors, but at considerable expense to

the electric utility industry. Meeting the act's emissions control requirements will require significant capital investment for the industry during the

coming two decades. According td the Congressional Budget Office's

analysis, the total electric capacity of U.S. utilities between 1980 and the

year 2000 will increase by some 44 percent, from 588 gigawatts to 844

gigawatts. \J The cumulative capital requirements for new nuclear and

coal plants alone (not including transmission and distribution facilities) are

projected to be $320 billion over this period; of that sum, roughly $176

billion will be attributable to an anticipated 168 gigawatts of new coal-fired

capacity. Efforts to meet the federal new source performance standards

(NSPS) for utility plants and/ to a lesser extent, local air pollution control

regulations, will account for roughly one-fifth ($33.4 billion) of that $176

billion. This chapter presents an analysis of how the NSPS and other key

provisions of the Clean Air Act influence both the quantity of pollutant

emissions nationwide and the costs of generating electricity.

GLEAN AIR ACT REQUIREMENTS AFFECTING ELECTRIC UTILITIES

To help meet and maintain national ambient air quality standards (that

is, the act?s NAAQS) several key provisions of the act serve to regulate

pollutant emissions from electric utility plants. For plants built before the

first federal emissions regulations for utilities in 1971, the states are

required to develop plans, including emissions limits for individual plants, to

achieve and maintain the NAAQS. These plans are called state implementation plans. The act also requires the EPA to limit the amount of air

pollution that a new or modified facility may emit. These regulations are

the NSPS) and they are established (and reviewed every four years) by the

1. A gigawatt is a unit of power equal to one billion watts. A commercial

generator of 500 megawatts (0.5 gigawatts) operating at a 70 percent

capacity factor can produce approximately 3.1 billion kilowatt-hours of

electricity a year, the amount consumed by roughly 371,000 households.
EPA for many categories of pollution sources, including utilities. Finally, to

ensure that areas already meeting NAAQS preserve their good air quality,

the EPA, together with the states, operate the prevention of significant

deterioration (PSD) program. This program establishes an elaborate review

and permit procedure for new facilities and allows states and the EPA to

adopt control measures even tighter than the NSPS, (The PSD provisions are

discussed in greater detail below; their effects on utility emissions limits

and administrative costs are discussed in Appendix A.)

The main focus of this study is on the NSPS (particularly the sulfur

dioxide limits) for electric, utilities; to a lesser extent, the study alsp

considers the PSD provisions. The majority of future electric generating

capacity will be built in areas already meeting the NAAQS, and the majority

of future costs for air pollution control will be attributable to the NSPS,

although a small portion of these expenses will result from the tighter state

and local standards, implemented in most cases under the PSD provisions of

the act.

The New Source Performance Standards of 1971 and 1978

Because of the great variation in sulfur content of coal across the

country, coal-fired power plants could emit sulfur dioxide in widely differing

amounts if such emissions were not controlled. For example, an uncontrolled 500-megawatt power plant could emit sulfur dioxide at rates ranging

from less than 0.5 to more than 6 pounds of that gas per one million British

thermal units (BTUs) tff fuel consumed. In the course df a year, this range

would translate into less than 7,665 and more than 91,980 tons of sulfur

dioxide. The ,NSPS introduced in 1971 tinder the Clean Air Act focused

directly on this problem, setting a uniform nationwide limit of 1.2 pounds of

sulfur dioxide emissions per million BTUs for all new or modified power

plants burning coal. 2/ Similar limits were established under the NSPS for

nitrogen oxides and particulate emissions. The 1971 NSPS were set with

considerations of economic effects, energy costs, and environmental and

public health concerns taken into account.

In 1978, these standards were revised, with much stricter sulfur dioxide and other emissions limits set for the electric utilities. The revisions in

Regulations under both the NSPS,apply also to gas- and oil-fired plants.

The limit set for new oil-burning plants was 0.8 pounds of sulfur dioxide

emissions per million BTUs of fuel consumed*
1978 reflected a fundamental change in the act's NSPS provisions, changes

that were designed, in part, to encourage the use of control technology and

to foster the use of local coal regardless of its sulfur content. Table 1

contrasts the provisions of the two sets of new source performance

standards*

TABLE 1. NEW SOURCE PERFORMANCE STANDARDS

FOR COAL-FIRED ELECTRIC UTILITIES

Pollutant

1971 Maximum

Allowable Emissions

1978 Maximum

Allowable Emissions

Sulfur Dioxide

Nitrogen Oxide

Participate

Emissions

1.2 pounds per million

BTUs of any coal

consumed

0.7 pounds per million

BTUs of all anthracite,

bituminous, and subbituminous coals consumed; 0.6 pounds

for lignite

0.1 pounds per million

BTUs of fuel consumed

No more than 1.2

pounds per million

BTUs of fuel consumed plus 90 percent

emissions reduction,

no more than 0.6

pounds per million

BTUs of fuel consumed

plus 70 percent emissions reduction

0.6 pounds per million

BTUs of anthracite,

bituminous, and lignite

coal consumed

0.03 pounds per million

BTUs of fuel consumed

SOURCE: U.S. Environmental Protection Agency.

NOTE: Table does not show emissions limits applying to either oil-or

gas-fired utility plants. See 36 Federal Register 15703 (December 23, 1971) and 44 Federal Register 33580 (June 11, 1979).

93-281 0-82- 5
The 1978 revisions did not supersede the older NSPS. Plants licensed

to operate under the 1971 NSPS remained (and still are) subject to them.

Rather, the new standards added stringent requirements for those new

plants to which they would apply. Besides limiting emissions to 1.2 pounds

of sulfur dioxide per million BTUs generated from coal, new or modified

plants burning coal (or any fossil fuel) must now also remove a finite

percentage of that pollutant from emissions. 3/ The level of mandatory

pollutant removal is not uniform, however, requiring that between 70 and 90

percent of all sulfur dioxide emissions be eliminated. The determinant of

what percentage sulfur dioxide removal a plant must achieve, based on its

final emissions rate, is whether the plant will burn high- or low-sulfur coal.

Methods of Compliance and Effects. A typical method for a utility

plant's meeting the 1971 NSPS was to use fuel with inherently low emissions

characteristics—that is, low-sulfur coal or oil. Under the new NSPS,

however, sulfur dioxide emissions must be reduced from any variety of coal

being burnt. At present, the only commercially available device that can

achieve the required reductions in conventional power plants is a scrubber;

thus, in effect, the 1978 NSPS mandates the use of scrubbers in all new

coal-fired power plants. Though no new or modified coal-fired utility

generators planning to use scrubbers under the 1978 regulations are yet in

full Commercial operation, the effect of scrubbing will be to cut

emissions by more than a half from levels allowed under the old NSPS. 4/

The 70-90 percent sliding scale for sulfur dioxide emissions removal

effectively gives utilities an economic choice between using "wet" and

 ndryn

scrubbers, depending on the sulfur content of the coal they plan to burn. 5/

3. The regulation chiefly affects new coal plants, since the Power Plant

and Industrial Fuel Use Act of 1978 prohibits the burning of oil or gas in

major new power plants.

4. In view of the time lag that intervenes between a firm's decision to

build a new plant and the time that plant is actually generating power,

the effects of the 1978 NSPS cannot be expected to materialize before

well into the 1990s.

5. Wet scrubbers remove sulfur dioxide by passing exhaust gases through

an aqueous chemical spray that absorbs the sulfur dioxide, leaving the

exhaust gas with a lower sulfur dioxide concentration. (Particulates are

10
Wet scrubbers, which can remove 90 percent or more of the sulfur dioxide a

power plant emits, are by far the costlier choice; installation of a wet

scrubber can add as much as 20 percent of the initial capital costs of a new

plant. They do, however, permit combustion of medium- and even highsulfur-content coal. Dry scrubbers, capable of 70 percent sulfur dioxide

removal and considerably cheaper—accounting for perhaps 10 percent of

initial capital outlays for a new plant—are suitable only for low-sulfur coal

combustion under the present regulations* Commercial experience with dry

scrubber systems on utility plants is lacking, because the technology is

relatively new; however, it is a fairly well proven technology, and many

utility systems have dry scrubbers on order for their new plants.

Prevention of Significant Deterioration

For areas now attaining the NAAQS, the Clean Air Act mandates that,

if possible, air quality be prevented from deteriorating to the level of the

NAAQS because of new air pollution. The act's provisions applying to such

regions are encompassed in the PSD program, and as the term implies, they

cover regions where the air quality is relatively good at the time a utility

firm or other industry contemplates locating a new plant there. The PSD

provisions are designed to preserve air quality while at the same time

avoiding hindrance of industrial growth. The amount of pollution-caused

degradation allowed in an area (possibly up to but not exceeding the NAAQS)

is denoted by specified increments or classes, shown in Table 2. The Clean

Air Act Amendments of 1977 classified certain areas, such as national

parks, as mandatory Class I. Other public use areas, such as national

recreation areas, were originally classified as Class n and may not be

changed to Class m. All other areas were originally classified as Class n

and may be redesignated by the state with the governor's approval.

Under the PSD program, a utility considering construction of a new

power plant undergoes a rigid preliminary review process, of which two

components are especially influential both to costs and to air quality. First,

the planners of a new facility must demonstrate to the state and regional

5. (Continued)

removed prior to scrubbing.) The product of the scrubber is a

precipitate of high water content, which typically is filtered and

chemically stabilized before disposal. A dry scrubber involves much

less water and combines both participate and sulfur dioxide removal in

the final step, leaving a dry product for disposal.

11
TABLE 2. NATIONAL AMBIENT AIR QUALITY STANDARDS AND

ALLOWABLE INCREMENTS UNDER PREVENTION OF

SIGNIFICANT DETERIORATON PROVISIONS

(In micrograms per cubic meter)

Increments Under PSD

Pollutants NAAQS Class I a/ Class H b/ Class m c/

Sulfur Dioxide

Annual average

24-hour average d/

Three-hour average d/

Total Suspended

Particulate Matter

Annual average

24-hour average d/

80

365

1,300

75

150

2

5

25

5

10

20

91

512

19

37

40

182

700

37

75

SOURCE: U.S. Environmental Protection Agency.

a/ Designed to protect pristine areas such as National Parks.

b/ Areas meeting NAAQS but not originally designated Class I in 1977.

£/ Certain Class n areas may be redesignated to Class in to allow greater

development; none have been redesignated to date.

d/ Not to be exceeded more than once a year.

environmental protection authorities that emissions from the plant contemplated, combined with emissions already present from other sources in

the same locale, will not exceed certain maximum limits established by PSD

increments (see Table 2). Background pollution levels, plus the specified

PSD increment, are combined to establish the upper bound of allowed

pollution in the area, provided such totals would not jeopardize the NAAQS.

Emissions from any new facility in the area must not cause a violation of

this maximum allowable limit.

12
A second critical feature in the PSD review process entails the use of

the "best available control technology" (BACT) in a new generating facility.

Determinations of what the best available control technology actually is, in

light of specific costs, environmental effects, energy costs, and other considerations, are made on a case-by-case basis by the reviewing agencies,

including both federal and state environmental officials.

In theory, best available control technology should be strict enough to

allow further growth in the area and preserve PSD air pollution limits, while

never exceeding the applicable NSPS—and often surpassing it in stringency.

In practice, however, the reviewing agencies commonly establish BACT at

levels commensurate with the applicable NSPS, unless siting choices and the

characteristics of the area would cause emissions at NSPS levels to violate

the applicable PSD increment. In the case of power plants locating in PSD

areas, BACT limits have been set tighter than NSPS only in certain

instances; this has occurred more often under the NSPS of 1971 than under

the NSPS of 1978. Since adoption of the 1978 NSPS, most BACT designations for new power plants require no more than NSPS-mandated levels,

except in some western states. For the purpose of this analysis, the NSPS

are considered the dominant influence on future utility emissions, except for

assumptions regarding some western states' emissions limits (see Appendix A

and assumptions outlined in Appendix B).

EFFECTS ON POLLUTANT EMISSIONS

The NSPS promulgated in 1971 have had mixed effects on national

utility emissions of the three pollutants discussed in this study. As of 1979,

the most marked improvement—attributed in part to the federal NSPS and

in part to stricter state regulations—was in participate emissions. These

declined by a full 62 percent from 1970 levels, despite major increases in

the utilities1 use of coal (which rose by 50 percent). 6/ Effects on gaseous

emissions, however, were inconsistent. The clearer improvement was in

emissions of sulfur dioxide, which increased only slightly, primarily because

of utilities' efforts to use more low-emissions fuels—mostly oil and lowsulfur coal. Success in controlling nitrogen oxide emissions was minimal,

however; these increased by 50 percent. This apparent failure is ascribed

largely to the lack of available control methods for this pollutant.

6. See Environmental Protection Agency, National Air Pollution Emission

Estimates 1970-1979 (March 1981).

13
In spite of the sharp tightening of the NSPS enacted in 1978,

projections of the national utility emissions trends over the coming two

decades show no dramatic reversals in overall emissions, although the

average emissions rates of the industry should fall as cleaner facilities are

added to existing total capacity (see Figure 1). Particulate emissions from

utility combustion are likely to continue declining by as much as 6 percent

(from the 1,7 million tons of 1979 to 1.6 million tons by the year 2000).

Emissions of sulfur dioxide are likely to rise somewhat more steeply than in

the 1970s, increasing by 17 percent (from 18 million to 21 million tons). The

problem of nitrogen oxide emissions is expected to worsen, with emissions

increasing by 29 percent (from 8.3 million tons to 10.7 tons). The cause

underlying the continued high emissions levels will be the utilities' continuing use of older-generation (pre-NSPS) power generators. By far the

bulk of anticipated emissions of each pollutant—as much as 80 percent—will be attributable to these older sources, at least through the year

2000 and perhaps until 2010.

After the turn of the next century, however, the prospects should

brighten as antiquated generators are phased out and newer ones capable of

emitting far less pollution take their place. Sometime around the year 2010,

a trend in significantly lower emissions can reasonably be expected. The

remainder of this chapter examines the costs of attaining that improvement

through the coming two decades.

Figure 1.

Actual and Projected Pollutant Emissions from Electric

Utility Plants-Total Amounts and Average Rates

Total Amounts Average Rates

22

18

14

10

Sulfur Dioxide

Nitrogen Oxides ^.»——«

I I I I I I I I

1970

J_

1973 1976 1979 2000 1970 1973 1976 1979 2000

Years Years

SOURCES: Actual data derived from U.S. Environmental Protection Agency, National Air Pollution Emission

Estimates (March 1981), and U.S. Department of Energy, The 1980Annual Report to Congress

(April 1981). Projections based on CBO/ICF analysis (see Appendix B).

NOTES: Shows only those pollutant emissions regulated under Clean Air Act new source performance

standards. Projection period starts at 1979, the last year of actual data.

14
NATIONWIDE POLLUTION CONTROL COSTS TO UTILITIES

AND TO ELECTRICITY CONSUMERS

To meet federal and state air pollution control requirements established over the last decade, the utility industry has already made sizable

capital investments. Between 1973 and 1980, the utilities1 expenditures for

pollution control rose at an average annual rate of 10.7 percent, while total

capital expenditures rose at the slower rate of 8.9 percent. 7/ During this

period, investments in pollution control equipment ranged between 5 and 7

percent of the industry's total yearly expenditures. In 1980, the industry's

total capital commitments reached $29*2 billion, of which $1.8 billion (6 percent) went for pollution control.

The trend of high capital investment for pollution control is expected

to continue over the next two decades. The principal cause underlying the

persistence of high utility capital investment commited to pollution control

is the rigid standards established in 1978. Between 1980 and the year 2000,

the utility industry will invest more than $176 billion in new coal-fired

power plants alone, with roughly $33.4 billion (19 percent) dedicated to air

pollution control. Because of the requirements of meeting the 1978 NSPS,

the utilities' air pollution control investment costs will be higher by $19.4

billion that they would be if only the older NSPS were in force.

Aggregate data on the capital costs exacted by controlling air

pollutant emissions give only a partial picture; other essential components

include the charges for operating pollution control equipment (scrubbers and

particulate control devices) in plants burning high-sulfur coal and the

incremental costs of using low-sulfur fuels as a means to control emissions

in place of less expensive, higher-sulfur fuels. In 1980, these two factors

combined entailed an annual expense totaling $5.4 billion, with control

equipment accounting for $4.2 billion and low-sulfur fuel premiums accounting for $1.2 billion. By the year 2000, costs of these two components are

expected nearly to triple, reaching an annual total of $14.1 billion.

Expressed in terms of average generating charges per kilowatt-hour

for all forms of electricity generation, this $5.4 billion in 1980 breaks down

7. Gary Rutledge and others, "Capital Expenditures by Business for

Pollution Abatement," Survey of Current Business, U.S. Department of

Commerce (June 1978 and June 1980).

15
into an average of 2.34 mills per kilowatt-hour* The average charge in 1980

to residential consumers of electricity was 53.6 mills per kilowatt-hour. 8/

Thus, from the ratepayers1 standpoint, the cost of air pollution control in

1980 accounted for 4.4 percent of an average residential electricity bill. By

the year 2000, however, ratepayers are likely to see an increase of 44

percent, bringing the cost for pollution control to 3.43 mills per kilowatthour purchased—just 1.09 mills more than in 1980 or 6 percent of that year's

electricity rate. Although this reflects a potentially sharp increase in

operating costs for control air pollution, the average nationwide contribution of this expense to total future generating costs should remain quite

small. Regional costs will differ markedly, however.

Regional Differences in Air Pollution Control Costs

Aggregate and average national data, though useful for policy analysis,

mask regional differences that have very explicit cost consequences for both

utility companies and consumers in different areas of the country. (Figures

6 and 7 in Chapter V display the coal-producing and coal-demand regions of

the United States.) Three principal factors influence the regional variations

in pollution control costs: what fuel is burnt, what state and local emissions

standards apply, and the vintage of most of the electricity generators in use.

In an area where a low-emissions fuel predominates^-the Gulf states,

where indigenous natural gas is the primary energy source, are an

example—air pollution control costs are negligible. The New England

states, in contrast, typify a different situation; there, though low-emissions

fuels (mainly oil) furnish most utility generation, pollution control costs are

higher because of the premiums paid to meet rigid local emissions standards

with low-sulfur fuels. The costs of air pollution control ranges between 3.7

and 6.2 mills per kilowatt-hour generated in that area.

A utility plant's age also influences regional differences in pollution

control costs, particularly with regard to coal-fired plants. In an area where

the majority of electricity comes from coal-burning facilities that predate

the first NSPS of 1971, pollution costs may be high but only modestly so,

8. Average residential consumers of electricity use between 500 and 1,000

kilowatt-hours per month in the course of a year; thus, average

electricity bills in 1980 ranged from $27 to $54 per month, of which 4.4

percent could be attributed to air pollution control.

16
precisely because of the relative lenience of the governing standards. The

Ohio River Valley, where many existing coal-fired generators are not

subject to either NSPS, air pollution control costs average 3.9 mills per

kilowatt-hour for these facilities, which is near the low end of the oil-fired

power plant costs in New England.

Since the mid-1970s, most new major capacity that has been constructed is coal-fired. Newer plants built under the 1971 NSPS incur control

costs ranging from a high of roughly 8.6 mills per kilowatt-hour in the East

and North Central areas to less than 3.2 mills per kilowatt-hour in the

western Mountain region. In some cases, strict local standards in several

areas of the West result in costs at the higher end of this range.

The highest-cost electricity plants in terms of air pollution control

will be those coal-fired generators that are being built subject to 1978

NSPS, which implicitly require use of scrubbers. Here again, though, wide

variations will occur, with emissions control costs ranging from 5.7 mills to

10.1 mills per kilowatt-hour. Costs in the eastern Central states should fall

at the upper end of the range, around 10 mills per kilowatt-hour, because

medium- and high-sulfur coals predominate there, necessitating use of

expensive wet scrubbers. In the Pacific and Mountain regions, low-sulfur

coal is readily available, permitting utilities to meet the rigid federal

standards with cheaper dry scrubbers, bringing pollution control costs nearer

to the 5.7 mills per kilowatt-hour rate.

17

93-281 0 - 82 -

CHAPTER m. POLLUTION CONTROL AND THE ELECTRIC UTILITIES1

FINANCIAL CONDITION

The financial condition of the electric utility industry has undergone a

steady deterioration over the past two decades. Years of inadequate

revenues in the face of escalating real costs for equipment, fuel, and

financing have combined to weaken the utilities' economic position. Few of

these factors, particularly equipment and interest costs, show signs of

improving soon, and although only moderate electrical capacity growth is

expected throughout the remainder of this century, the high cost of

construction already is expected to strain the financial capacities of the

industry at least through this decade. With respect to the Clean Air Act,

two interrelated questions arise in this context:

o To what extent are emissions control standards mandated under

the act responsible for the utilities' declining financial state?

And conversely,

o What implications do the utility industry's poor financial prospects have for the federal government's future pursuit of clean

air policy? In other words, will a financially weakened power

industry provide an adequate instrument for carrying out the

nation's clean air policy?

Emissions control standards, because of their attendant high capital

costs to electric utilities, have often been cited as contributors to the

financial pressures the utilities are feeling. Available evidence suggests,

however, that, though capital investment in air pollution control probably

does not enhance a utility's financial performance, it probably cannot be

blamed for impairing it either. Instead, the most influential determinants of

a utility's financial condition appear to be the regulations imposed on the

industry by state public utility commission's (PUCs)--the rate-setting bodies

within each state—and management decisions made by a particular firm (a

factor that is difficult to gauge). This chapter attempts to assess the

relative influence of emissions regulations on the utilities' financial performance, measured here as credit worthiness; in so doing, it explores reasons

why PUC rate-making decisions can overwhelm other influences.

FINANCIAL CONDITION OF THE INDUSTRY AND REGULATION

BY PUBLIC UTILITY COMMISSIONS

Among several factors, the continued slow erosion of adequate revenues and the increased costs and difficulty of obtaining capital are strong

19
contributors to a general deterioration of the power industry's financial

health. Although the situation differs markedly among individual companies, actual rates of return are generally below allowed rates and even

farther below the actual costs of equity. In 1980, actual returns on equity

were about 11.5 percent, while allowed returns were in the 14 percent range

and the cost of capital above 16 percent. Investors have responded to these

trends. An average share of common stock for the 100 largest privately

owned utilities sold at about 75 percent of book value by the end of 1980.

As a result, utility managements are reluctant to enter equity markets to

seek new capital, since every share sold dilutes the value of the shares of

present stockholders. Debt markets are similarly constrained, since requirements for interest coverage bar many companies from this source of capital.

(Utilities' interest coverage, which is the rates of total earnings to total

interest charges, as a general rule is prohibited from falling below two). To

a large extent, the PUCs' rate-making decisions have exacerbated these

problems.

Treatment of Capital and Fuel Costs

Accounting procedures unique to the industry and imposed by PUCs

have contributed to the financial difficulties of utilities, chiefly through

regulations that increase the costs and risks of capital investment. Typically, a utility may include in its rate base only the costs of those facilities

that the PUCs define as "used and useful", meaning that the costs for a new

power plant—once requiring from five to eight years of construction and

now requiring from eight to 12 years—cannot be recouped until the plant

begins operation.

To offset the costs of building a new plant, an electric utility firm

usually is granted an "allowance for funds used during construction"

(AFUDC) account. This account represents a return—generally equal to the

company's approximate cost of capital—on all "construction work in progress" (CWIP). Each year, the AFUDC account is treated as part of the

firm's net income, though it does not represent real cash flow. Only when

the plant is completed, and the AFUDC account is added to the plant's total

rate base, can the utility realize a return on its investment. Before plant

operation begins, however, the costs of construction must be borne solely by

the company.

Since an AFUDC account represents noncash income, it can lower the

quality of actual earnings. Furthermore, it can degrade the market value of

the firm's stock, putting upward pressure on the costs of capital. Figure 2

shows trends in both the amount of AFUDC representing income and the

ratio of market price to book value in stocks of the investor-owned

20
Figure 2.

Financial Trends in Investor Owned Electric Utilities

According to Two Measures: 1970-1980

Allowance for Funds Used During

Construction as a Percent of Net Income

Ratio of Stock Market Price

to Book Value (Moody's)

50

40

30

20

> I I I I I I J I

140

120

100 *i

'- 80

60

40-

V I I I I I I

1970 1972 1974 1976

Years

1978 1980 1970 1972 1974 1976

Years

1978 1980

SOURCE: Adapted by CBO from H. L. Culbreath, "An Overview of the Financial Difficulties of the Electric

Utility Industry," Statement by Edison Electric Institute before the House Committee on Energy

and Commerce, Subcommittee on Energy, Conservation and Power (6 April 1981).

utilities—that is, the majority of utilities. In 1980, AFUDC accounted for

46 percent of reported after-tax income; three years earlier, the comparable figure was 30 percent. I/

Unlike capital expenditures, escalating fuel costs may be quickly

recovered tinder most PUC regulations. More than half of the nation's PUCs

provide an automatic fuel adjustment clause to utilities within their

jurisdictions. 2/ Under the fuel adjustment provisions, all or at least a

major part of the cost increases of fuels may be reflected immediately in

higher rates to consumers, with no need for a hearing or other administrative procedure. These provisions effectively protect utilities against the

risks of reduced revenue from higher fuel costs.

1. See Statement of H.L. Culbreath, for the Edison Electric Institute, "An

Overview of the Financial Difficulties of the Utility Industry and the

Impact on the Funding of Necessary Future Construction," given April

6, 1981, before the U.S. House of Representatives Committee on

Energy and Commerce, Subcommittee on Energy, Conservation, and

Power.

See National Association of Regulatory Utility Commissioners, "1979

Annual Report on Utility and Carrier Regulation" (October 1980).

21
The combined effect of detrimental regulatory treatment of capital

investments and advantageous fuel adjustment clauses is to discourage

replacement of expensive oil- and gas-fired capacity and older coal-burning

facilities9 typically meeting standards more relaxed than the current NSPS

(see Chapter n). The short-term result is that construction of capitalintensive new plants, which are cleaner burning and more efficient, is

delayed or postponed indefinitely. These twin outcomes do little to further

the federal objectives of establishing a reliable future electricity supply and

increasing the use of coal.

CONTRIBUTION OF AIR POLLUTION CONTROL COSTS TO INDUSTRY

CAPITAL EXPENSES

In part because of increased demand for electricity, delays in construction, and steep rises in inflation, the utilities' expenditures for power

plant construction have risen sharply over the last decade, exacerbating the

capital-intensive nature of the industry. Though the total capacity growth

of approximately 291 gigawatts in new coal-fired and nuclear capacity

expected over the next 20 years is only moderate, the high cost of power

plant construction will severely strain the industry. 3/ In 1970, electric

utilities spent roughly $11 billion (in nominal dollars) for new equipment; by

1980, annual expenditures for new equipment had exceeded $29 billion. This

160 percent increase in annual capital investment, however, augmented

total capacity by only 40 percent, and this trend is expected to continue. By

the year 2000, expanding electrical capacity is expected to entail capital

investments of more than triple the 1980 level (in nominal dollars), though

capacity is anticipated to increase by only 44 percent overall.

Air pollution control costs are partially responsible for these escalations. In 1971, coal-fired power plants (equipped only with controls for

participate emissions) cost an average of $210 per kilowatt (in nominal

dollars). In 1980, capital costs had risen to approximately $1,100 per

kilowatt for a facility using wet scrubbing and to approximately $1,000 per

kilowatt for a facility using dry scrubbing (in nominal dollars). (Chapter II

describes these processes.) This represents a real cost increase of between

150 to 180 percent. Of this total, air pollution control requirements are

responsible for approximately 25 percent, and cost escalations in basic

materials and construction account for the remaining 75 percent.

3. The breakdown of this projected total new capacity is 168 gigawatts of

coal-fired generation and 123 gigawatts of nuclear power.

22
The Congressional Budget Office has estimated that deferring investments that would be made to meet the NSPS of 1978 would save the industry

some $19.4 billion between 1980 and the year 2000. This savings would

represent only about 6 percent of the estimated $320 billion needed for new

coal-fired and nuclear capacity over the period and 11 percent of those

expenditures needed solely for new coal-fired capacity ($176 billion). 4/

THE EFFECT OF AIR POLLUTION CONTROL COSTS ON THE ELECTRIC

UTILITIES' FINANCIAL POSITION

The aggregate costs of air pollution, though high, appear not to be

generally responsible for the utilities' worsening finances or for their

difficulties in raising capital. The CBO's analysis of this issue, using bond

ratings as a measure of creditworthiness, leads to the conclusion that the

market perceives utilities that have invested in pollution control to have

much the same financial soundness as the general population of electric

utilities.

In an attempt to quantify the effects of pollution control investment

on financial integrity, the CBO compared bond ratings of the 100 utilities

listed by the investment firm Salomon Brothers against two subgroups (see

Table 3). &/ The first of the subgroups is a sample of 29 utilities that had

15 percent or more (that is, a high proportion) of their construetion-work-inprogress accounts dedicated to environmental control equipment in 1979*

The other subgroup, representing utilities with significant investment in flue

gas desulfurization technology, consists of 21 companies, each with at least

one scrubber system in operation.

Both of the subgroups in CBOfs analysis—that is, those utilities with

substantial financial commitments to pollution control—ranked generally

better in terms of bond ratings than did the general population of 100

utilities. In fact, the scrubber group ranked best, with 62 percent of ratings

at or above the straight "A" rating (shown in the table as A/A). Next in

4. These data do not reflect costs of transmission and distribution.

5. The Salomon Brothers rating designations represent a compilation of

bond ratings set by other investment firms, specifically Moody's and

Standard and Poor's; hence the dual appearance of the Salomon Brothers

listings. A Salomon Brothers "AAA/Aaa" listing reflects Standard and

Poor's AAA bond rating and Moody's Aaa rating.

23
order was the group with 15 percent of construction-work-in-progress

investments devoted to environmental commitments. The general population had the lowest distribution rated above A, with only 38 percent of

ratings higher than the straight A rating. In both cases, the deviation of the

subgroups' distributions from that of the general population are significant,

suggesting that pollution control investments are more readily undertaken

by financially sounder utilities. Using a second analytical approach,

however, based on a random sample of utilities from the general population

of 100 firms, the CBO found no statistical correlation between bond ratings

and the ratio of total investment for construction-work-in-progress to the

portion devoted specifically to environmental control.

To assess whether environmental control costs had affected the status

of bond ratings over time, rather than only measure the ratings as of a

specific date, the CBO also conducted a check of bond ratings between 1978

and 1980. In an examination of the same three groups displayed in Table 3,

no significant pattern of rating changes emerged. The only group that had

no upgradings during that period was the scrubber group, in which three

firms with bond ratings below the A level were downgraded by one point or

more. This same group, however, also contained some of the highest rated

electric utilities.

The above results suggest that factors other than pollution control

investment may more strongly influence the utilities' financial health as

measured by bond ratings. Regulations enacted by public utility commissions appear to be a strong influence. According to various investigations

(including another CBO study 6/), unfavorable regulations—those that prohibit or delay adequate return on capital investment—can be major factors

in determining lower bond ratings, leading in turn to higher financing costs.

One analysis, for example, reported that 90 percent of the utilities with low

bond ratings—between A and BBB as set by Standard and Poor's—are

outside of jurisdictions described as having "very favorable" regulatory

climates. 7/ At the same time, only 13 percent of those utilities with

strong bond ratings, as high as A A or A AA, were found to be within the

jurisdictions with PUCs thought to have "unfavorable" regulations, as assessed by five investment firms.

6. See forthcoming CBO paper on regulatory reform.

7. See Peter Navarro, "Electric Utility Regulation and National Energy

Policy," Regulation, American Enterprise Institute Journal on Government and Society (January/February 1981).

24
TABLE 3. BOND RATING DISTRIBUTION OF 100 RATED ELECTRIC

UTILITIES AND SAMPLE SUBGROUPS WITH INVESTMENTS IN

ENVIRONMENTAL CONTROL (Percent distribution)

Bond

Ratings a/

(Salomon All 100 Electric

Brothers Utilities with Bond

Compilations) Ratings

Top 29 Utilities

with Minimum of

15 Percent of CWIP b/

Funds Dedicated to

Pollution Control

21 Utilities

with Scrubbers

in Operation

Aaa/AAA

Aaa/AA or

Aa/AAA

Aa/AA

Aa/A or

A/AA

A/A

A/BBB or

Baa/A

Baa/BBB

Baa/BBB

or Lower

1

1

26

10

32

8

19

3

None

3.4

31

10.3

31

3.4

20.7

None

4.8

4.8

38.1

14.3

28.6

None

9.5

None

SOURCES: Salomon Brothers, Industry Analysis, "Electric Utility Common

Stock Market Data" (March 2, 1981); U.S. Department of Energy,

Statistics of Privately Owned Utilities in the United States

(October 1980); Environmental Protection Agency, EPA Utility

FGD Survey; October-December 1980 (February 1981).

a. Double listings represent a range.

b. Funding for construction work in progress.

25

93-281 0-82- 7
Mitigating Factors—Federal and State Provisions

If the conclusion derived from the foregoing analysis is correct—that

investments in pollution control do not adversely affect the financial

performance of utility companies—then it is reasonable to ask why not.

What factors can mitigate the high costs of efforts to meet emission

standards? The CBO has explored two areas in which mitigating factors can

be found: federal tax provisions, and certain aspects of federal and state

regulations on ratemaking that specifically make allowances for environmental control costs.

Several federal tax programs that apply to the utilities work to ease

the burden of pollution control costs. These include accelerated depreciation allowances (also called rapid amortization allowances), an investment

tax credit, the availability of industrial development bonds (IDBs) to finance

pollution control hardware, 8/ and the routine tax treatment of expenditures for working hardware as tax-deductible business expenses.

Under the accelerated depreciation provisions, which effectively constitute a tax subsidy, a power company with a generating plant that has been

in operation since before 1976 may claim depreciated value for any pollution

control improvement applied to that plant over a 60-month period, even

though the actual useful life of the improvement may be considerably

longer. Coupled with this provision, an investment tax credit of 10 percent,

granted under the Tax Reform Act of 1978, can be used with the rapid

amortization provisions, unless IDBs (discussed in more detail below) are

used to finance expenditures, in which case only a 5 percent tax credit can

be applied. These special provisions, helping older utilities to finance

pollution control efforts, can enhance short-term revenues and offset

overall financing costs.

Another avenue offering considerable tax advantages to new utilities

investing in pollution control is available through the use of IDBs. Issued for

a public purpose either by state or municipal governments or by local

industrial development authorities, IDBs for pollution abatement can furnish

long-term financing on which the interest to buyers is tax-free. This last

feature allows a project financed with an IDB to cost the bond issuer less in

interest than if a taxable form of financing were used. When the proceeds

from a bond issue go toward a pollution control system, the owning firm

pays all principal and interest to the bondholders, often through lease

agreements. In effect, no municipal money is involved in such a transaction.

8. These are sometimes called pollution abatement revenue bonds.

26
If the municipality does guarantee payment to the bondholders, the IDBs are

considered general obligation bonds of the municipality, whereas no such

guarantee classifies the bonds as revenue issues that depend upon the funds

generated by the benefiting firm.

Utilities appear to have relied more heavily on these IDBs than have

any other industries; between 1971 and 1978, some 52 percent of all

pollution abatement revenue bond monies went to utilities. The average

cost of IDBs for pollution control hardware issued for the benefit of these

same utilities was 5.97 percent, while the average cost of long-term debt to

utilities for the years 1971 through 1978 was 7.98. Thus, the cost of capital

from this form of financing was lowered by Z.01 percentage points.

Altogether, the use of these special tax allowances and IDBs (or other

similar revenue bonds) can reduce utilities' pollution control costs significantly. A recent study that examined pollution control costs for electric

utilities in a portion of the Ohio River Valley showed that air pollution

control expenditures could be reduced by as much as 18 percent through full

exploitation of these various allowances. 97

Other provisions, notably certain federal and state rate-making rules

on pollution control investments, can also be credited with a role in easing

the burden on utilities of investing in pollution control hardware. Both the

Federal Energy Regulatory Commission—which regulates interstate electricity rates—and more than half of all its state counterparts (the public

utility commissions, which regulate intrastate rates) allow utilities to

collect a return on part of or all investments for environmental construction-work-in-progress. 10/ (This allowance is distinct from the PUCs1

 typical

prohibition against recovery of general construction costs, which utilities

cannot incorporate in their rate bases until after the plant begins operation.)

The advantage of this allowance is that it yields actual cash earnings for

utilities on assets being constructed; it also obviates the crediting against

income of a noncash allowance for funds used during construction—an

accounting method that can erode earnings and hence stock and credit

ratings. In general, the charging of construction-work-in-progress in the

rate base can result in lower capital costs to the utility and lower lifetime

9. See JACA Corporation, "The Economic Impact of Regulating Air

Pollution in the Ohio River Valley,11 draft report prepared for the

National Commission on Air Quality (December 1980).

10. See National Association of Regulatory Utility Commissioners, "1979

Annual Report."

27
electricity costs to the consumer, ll/ (This subject is discussed in greater

detail in Appendix C.)

11. This discussion is confined to allowances already in existence before

enactment of the Economic Recovery Tax Act of 1981 (P.L. 97-34).

The potential benefits of the new law, which includes more liberalized

depreciation allowances, on utility finances and cash flow have not been

included in this analysis. For a discussion of potential benefits, see

Donald W. Kiefer, "The Impact of the Economic Recovery Tax Act of

1981 on the Public Utility Industry," Congressional Research Service

(January 15, 1982).

28
CHAPTER IV. PROMOTING RELIANCE ON COAL AND THE EFFECTS

OF THE CLEAN AIR ACT

A major goal of U.S. energy policy to foster the nation's independence

from foreign oil suppliers is to promote the burning of coal in electric power

generators instead of oil or gas. Although the United States holds a full 31

percent of the world's recoverable reserves of coal, combustion of that fuel

furnishes only about one-half of the nation's electricity, with oil and gas

providing some 26 percent. (Nuclear and hydroelectric power account for

the balance.) Thus, although exploitation of the coal resource has already

risen appreciably, opportunities to replace far greater quantities of oil and

gas still exist.

Both the Energy Supply and Environmental Coordination Act (ESECA)

of 1974 and its successor, the Power Plant and Industrial Fuel Use Act

(PIFUA) of 1978, were specifically designed to reduce oil and gas consumption in both new power plants and older facilities already capable of burning

coal. Under the latter legislation, the PIFUA, the federal government can

order that utilities operating generators that had at one time been converted from coal to oil reconvert those generators back to coal. In addition,

utilities are effectively prohibited from burning oil or gas in new major

power plants. Thus, a major goal of federal energy policy is also to

encourage the accelerated replacement of gas- and oil-fired capacity with

coal-burning plants.

Air pollution control policy, articulated by the federal government in

the Clean Air Act and by state and local authorities in their own regulations

(state implementation plans), can strongly influence the economics underlying the utilities' choices between reconversion of a power plant or its

replacement, and continuing to rely on gas or oil. Replacement—involving

major capital investment in new plants, which are subject to the act's 1978

NSPS is demonstrably expensive, as indicated by the analysis in the

preceding two chapters. Desulfurizing flue gases by means of scrubbers,

just one of the cost components entailed in meeting the 1978 NSPS, is an

expensive but requisite technique. Reconversion is usually cheaper, since it

rarely entails scrubbers. Reconversion has its own significant costs,

however, including the possible need to upgrade the boilers and burners to

use the particular coal involved, upgrade coal-handling equipment, and

modify or replace participate control devices.

This chapter examines the influence of the Clean Air Act and other

factors on the economic choices for utilities between reconversion, replacement, or maintenance of existing oil- or gas-fired capacity. Results of the

29
Congressional Budget Office's analysis suggest that the costs of reconversion can be substantially less than continuing to burn gas or oil in coalcapable boilers; they also conclude that economic benefits associated with

coal use are possible even with full replacement. At the same time,

however, they point to oil prices as a strongly influential factor in the cost

effectiveness of turning to coal to generate electricity. So long as the

growth rate of world oil prices remains depressed, full replacement of oiland gas-fired capacity may have difficulty proving its economic benefit. If

PREVAILING REGULATIONS FOR COAL CONVERSIONS

Distinct from new plants, which are uniformly subject to the federal

NSPS of 1978, old plants that are candidates for reconversion can fall

subject to a complex mix of federal and state regulations, including

exemptions. Two types of reconversion projects are exempt from both NSPS

and new source review under the act's "prevention of significant deterioration" program (see Chapter n and Appendix A): power plants ordered to

convert to coal under the PIFUA of 1978, and voluntary reconversion of

plants that were capable of burning coal before January 1, 1976. Most

major utility reconversion candidates fall into these two categories. Both of

these types of reconversions must meet the state emissions control requirements for coal-fired power plants of their same vintage, or they must

comply with alternate regulations negotiated with the states and approved

by the federal government (that is, the EPA). All other reconversions, while

generally exempt from the 1978 NSPS, must undergo the PSD new source

review process. Few if any reconversion candidates would fall under this

latter category.

1. Since early 1981, a strong downward pressure in world oil prices has

occurred in response to excess production. Though residual oil prices

have fallen in the spot markets, some by $7 per barrel from their peak

price (approximately $34 per barrel), long-term contract prices remain

high (approximately $33 per barrel). Analysts anticipate that revived

economic growth in the United States and other countries will, by the

mid- to late-1980s, spur a resumption of rising rates in world oil prices

similar to those observed in the late 1970s. However, how long it will

take for oil prices to regain their peak levels (in real terms) is unknown.

30
COST ANALYSIS—THE POTENTIAL BENEFITS OF RECONVERSION OR

REPLACEMENT COMPARED TO CONTINUATION OF OIL OR GAS USE

To quantify and compare the economic effects of Clean Air Act

regulations on power plant conversions, the CBO calculated the annual

capital and maintenance costs of two possible reconversion cases and one

replacement case. The lower-cost reconversion case, requiring no scrubber

but using low-sulfur coal, would be completed at a capital cost of $150 per

kilowatt. The higher-cost example, requiring a wet scrubber to meet

assumed stricter state standards and burning high-sulfur coal, would be

completed at a capital cost of $600 per kilowatt. 2/ The replacement

example would require a capital cost of $1,160 per kilowatt. (All cases

examined here were assumed to meet the applicable environmental standards. The two reconversion examples are assumed to meet all state and

local regulations; the one replacement case is assumed to comply with the

federal 1978 NSPS.)

The assumptions used in the analysis reflect upper-bound costs for

both reconversion and replacement. In all cases, a 10 percent real rate of

interest for capital investments was assumed, using a 15-year period for

reconversion and a 20-year period for replacement (accounting for the

possibly shorter operating life of a reconverted facility). The price of coal

in all cases was assumed to rise at a real annual rate of 2.7 percent.

To allow comparison with the costs of using oil, the CBO also

computed the operating costs of oil-fired capacity under two different

assumptions regarding oil prices. (The maintenance of oil-fired capacity

was assumed to entail no capital expenditures.) One assumption used was no

real rise in oil prices; the other applied a constant 2 percent real rise over a

20-year period. The result yields not only a general comparison of

electricity costs as determined by fuel, but also an illustration of the

sensitivity of economic benefits from conversion and replacement to differing behavior of oil prices. This five-part comparison and an explanation of

all underlying assumptions are displayed in Table 4.

2. The range of reconversion costs were obtained from plant-by-plant

reconversion estimates prepared by the Edison Electric Institute for use

by ICF, Incorporated. See ICF, Incorporated,

 MA Preliminary Economic

Analysis of Reconversion of Coal Capable Utility Boilers," prepared for

the Edison Electric Institute (April 25, 1980).

31
TABLE 4. CAPITAL AND GENERATING COSTS FOR A 500-MEGAWATT

OIL-FIRED, RECONVERTED OIL, AND NEW COAL-FIRED

POWER PLANT

In mills per kilowatt-hour

Capital Annual

(In dollars Fixed Annual Total

Case per kilowatt) Capital Operating Fuel Generating

A. Low Cost

Conversion 150

B. High Cost

Conversion 600

C. Replacement 1,160

3.2 7.5 26.6 37.3

12.9 12.6 19.2 44.7

22.2 10.1 19.2 51.5

D.

E.

Oil Plant with

No Real Fuel

Price Increase None

Oil Plant with

2 Percent Fuel

Price Increase None

None 2.0 48.4 50.4

None 2.0 60.0 62.0

With either low- or high-cost plant reconversion, the generating costs

of 37.3 and 44.7 mills per kilowatt-hour, respectively, are lower than

current oil-plant generating costs of 50.4 mills per kilowatt-hour, even

assuming no real rise in oil prices. 3/ In comparison, the replacement case

of a new coal-fired power plant equipped with a scrubber (having a

generating cost of 51.5 mills per kilowatt-hour) is cost effective only if oil

prices rise by 2 percent in real terms over the next 20 years, resulting in an

oil-plant generating cost of 62.0 mills per kilowatt-hour. The generating

3. These reflect generating costs only and do not include the costs of

transmission and distribution.

32
TABLE 4. (NOTES ON ANALYTICAL ASSUMPTIONS)

A. No scrubber; low-sulfur coal burnt; average fuel cost over 20 years,

starting at $38 per ton delivered price, rising at an annual real rate of

2.7 percent; 10 percent real financing costs for reconversion and

participate emissions control upgrading.

B. Wet scrubber; high-sulfur coal burnt; average fuel cost over 20 years,

starting at $33 per ton delivered price, rising at an annual real rate of

2.7 percent; 10 percent read financing costs for reconversion, particulate emissions control upgrading, and scrubber retrofit.

C. New coal-fired plant with wet scrubber, high-sulfur coal burnt; fuel and

financing costs same as Case B.

D. No capital outlays; fuel costs constant $31.50 per barrel for 20 years.

E. No capital outlays; average fuel cost over 20 years, starting at $31.50

per barrel, rising at an annual rate of 2 percent.

SOURCE: Congressional Budget Office.

cost of a new coal plant burning low-sulfur fuel also was calculated,

assuming a construction cost of $975 per kilowatt. Interestingly enough, the

resulting generating cost of 50.3 mills per kilowatt-hour (not shown in Table

4) is quite close to the replacement example of 51.5 mills per kilowatt-hour,

which includes a scrubber.

Although full power plant replacement under these assumptions may

not be economic unless oil prices begin to rise at some real rate from their

1980 levels of approximately $31.50 per barrel, it does become economic

even assuming constant real oil prices if a 6 percent real interest rate,

rather than a 10 percent rate, is applied. For analytical purposes, a 10

percent real rate of interest is often used in assessing effects of regulations

and was used in these estimates both to allow comparison with other

33

93-281 0-82- 8
analyses and to demonstrate upper-bound costs. In practice, however, real

rates of 6 percent or less more accurately represent true interest charges on

capital for the electric utilities*

INHIBITING FACTORS

Although the Clean Air Act appears not to be a decisive factor in the

economic advantages of reconversion, other factors do impede the rate at

which reconversions can occur. These result from a combination of federal

and nonf ederal regulations.

Economic Constraints at the State Level

Underlying all other factors that may tend to discourage reconversion

or replacement of oil- and gas-fired power plants are the financial condition

of the individual utility and rate-making regulations imposed by the public

utility commissions (see Chapter HI). Many of the large oil-consuming

utilities are in poorer financial condition than the general utility population

and would face difficulty raising the necessary capital. Examination of a

list of conversion candidates prepared by the Edison Electric Institute shows

that only four (22.3 percent) of the 18 rated utilities on the list have higher

than "A" ratings as reported by both Moody's and Standard and Poor's. 4/ In

comparison, the general population of 100 rated utilities shown in Table 3 in

Chapter ffl have 38 percent listed at ratings above A.

Compounding these difficulties are PUCs1 decisions that discourage

reconversion and replacement by delaying a return on investment for

construction projects but providing, through fuel adjustment clauses, immediate relief from higher fuel costs (see Chapter HI). These factors tend to

perpetuate dependence on oil and gas. The net result of such constraints is

a systematic bias against capital investment. A utility company that would

experience a severe cash-flow problem while pursuing a conversion project

may defer any such undertaking indefinitely. Nonetheless, some others,

encouraged by the eventual prospect of savings from burning coal (even a

high-cost reconversion plant of 500 megawatts can save roughly $1.4 million

per month) have tolerated the short-term financial risks and proceeded with

conversion plans.

4. See Salomon Brothers, "Electric Utility Stock Market Data," Industry

Analysis (March 2, 1981).

34
Administrative Impediments in the Clean Air Act

Many of the problems arising from the Clean Air Act can be characterized as administrative. Most reconversion projects fall under individual

state emissions regulations, some of which are extremely strict as a result

of encouraging oil consumption in place of coal in the 1960s and early 1970s

for environmental reasons. Utility companies may seek to relax these stateimposed emissions limits in order to curb reconversion costs, often leading

to long periods of negotiation between the utility, the state, and in some

cases the EPA, which also has authority to enforce state plans. To arrive at

a mutually acceptable emissions standard, the utility firm must submit a

detailed description of the effects of the planned reconversion project on

ambient air quality, including what measures will be taken to control

emissions. The submission and review process is time-consuming and

requires considerable technical expertise. Overall, both voluntary conversions and those mandated by federal regulations can involve two years or

more of administrative effort before the start of conversion activities.

Because of inflation and deferral of cheaper energy-producing capacity, a utility planning conversion of a 500-megawatt generator costing $600

per kilowatt can lose $3.4 million a month (in nominal dollars) to such

administrative delays. This may be compared to the monthly savings of $1.4

million (in nominal dollars) obtainable by that same conversion. Thus,

though conversion to coal remains economically advantageous, some streamlining of the administrative requirements to speed implementation of

conversion plans would enhance that advantage.

Technical Problems During Work in Progress

Once construction begins on a conversion project, technical problems

can slow its progress. Late delivery of equipment and labor shortages can

cost a firm some $3.5 million a month (in nominal dollars), assuming 30

percent completion of the project at the start of delay (again, assuming a

500-megawatt plant reconverted at $600 per kilowatt). The prospects of

such delay once funds have been committed—postponing the anticipated

savings of $1.4 million a month—can be particularly discouraging to firms in

light of PUC regulations that generally prohibit recovery of capital investments for projects under construction.

THE IMMEDIATE PROSPECTS FOR CONVERSION

Despite these hindrances, many conversion projects are under way or

planned. In a review of 14 utilities, the General Accounting Office reported

35
that six firms were planning 25 reconversions, and two other companies had

notified the Department of Energy that they plan to reconvert five

additional units. 5/ Conversion of all 30 units would displace the use of

some 190,000 barrels of oil per day. Potential for even greater oil

displacement is projected by the Department of Energy, which estimates

that as many as 520,000 fewer barrels per day of oil or gas equivalent might

be consumed through conversions. 6/

5. See General Accounting Office, "Financial and Regulatory Aspects of

Converting Oil-Fired Units to Coal,11 report to the Chairman, Senate

Committee on Energy and Natural Resources (November 21, 1980).

6. See Department of Energy, "Fuels Conversion Program Power Plant

Profiles" (January 1981).

36
CHAPTER V. THE U.S. COAL MARKET AND THE CLEAN AIR ACT

To whatever extent the Clean Air Act influences the utility industry's

use of coal, it may also indirectly affect the U.S. coal market. The analysis

in this chapter assesses that indirect but important relationship, both as it

appears to have operated thus far and as it may in the near future. As the

facet of the Clean Air Act most influential to utilities, and in turn to the

coal industry, the evolving new source performance standards (see Chapter

n) governing gaseous and participate pollutant emissions are a focal point of

this analysis.

As background for evaluating the act's effects on coal markets, this

chapter gives an overview of the nature of the coal resource and the factors

that influence its purchase by electric utilities. The chapter then reviews

the effects seen to date of the first NSPS of 1971. It then projects how the

more rigid NSPS of 1978 are likely to influence the supply and distribution

of coal through the year 2000.

THE NATURE OF THE U.S. COAL MARKET

The electric utility industry is the nation's largest user of coal, today

accounting for some four-fifths of all domestic consumption. Roughly half

of all U.S. electricity is now derived from coal. In 1979, some 550 million

tons of coal went to utilities; by the end of this century, if current emissions

standards remain in force, that figure should more than double, reaching an

annual total of 1.2 billion tons. V To meet this demand, coal production in

nearly all regions is expected to rise. The actual distribution of this

increase will probably not be uniform, however, and the Clean Air Act will

have a role in altering the patterns of growth.

Despite the fairly uniform regional distribution of the nation's coal

deposits—all but a few major geographic areas have at least some coal

1. While the use of coal by electric utilities has been rising, demand in

other sectors of the economy has been falling. Between 1970 and 1979,

coal use by electric utilities rose some 65 percent but fell in all other

industries, including steel making, by a combined 30 percent. Residential and commercial users account for only 1 percent of all coal purchases.

37
deposits—the market value of coal varies between and within regions. Two

main characteristics affect the value of the delivered price of all coal:

o How it is mined—whether by deep-mining, which is typically the

costlier method, or by surface techniques; and

o What distances it must travel from where it is produced to where

it is used.

A third factor—sulfur content—is also influential, though of lesser importance, inasmuch as the demand for low-sulfur coal may be enhanced by

emissions limits on sulfur dioxide. Energy content, another fuel-related

value, has less influence on the price of coal at the mine than on the delivered price, since more volume of a low-energy-content coal must be

shipped than of a high-energy-content coal. Aside from these factors, which

can influence delivered price, the fuel value of different coals is essentially

unvaried, since most new power plants can be designed to handle any particular coal chosen for long-term consumption.

Regional Characteristics of Coal

In general, U.S. coal production can be divided into three

regions: the area east of the Ohio and Mississippi rivers (particularly the

Appalachian region); the Midwest (from the Mississippi to the western borders

of Minnesota, Nebraska, Kansas, Oklahoma, and Texas); and the West. (See

Figure 3.) Within all three regions, both deep- and surface-mining methods

are used, though to different extents. In the East, the choice of mining

method is roughly equally split between surface- (40 percent) and deepmining (60 percent). In the Midwest and the West, however, far more

surface- than deep-mining is done (see Figure 4). Because surface-mining is

typically more productive, coal recovered by this method usually has a

sizable cost advantage over coal from deep mines. 2/

2. The location of the coal resource generally determines the recovery

method used. Much Appalachian coal is buried in seams deep within

mountains or hills; deep-mining is the only method available to recover

much of this coal. For more superficial coal, large machines can

remove the overlying soil (overburden), exposing the coal. This method,

also called strip mining, tends to be more productive. In addition,

because of the terrain involved and depth of overburden, many western

surface mines are more productive than eastern surface mines, though

other factors, such as the age of the mines, also can influence

• productivity.

38
Figure 3.

U.S. Coal Fields and Producing Regions

SOURCE: Adapted by CBO from The President's Commission on Coal, "Coal Data Book" (February, 1980).

Figure 4.

Total U.S. Coal Production by Region and Mining Methods: 1979

500,000

400,000

300,000

200,000

100,000

Surface Mining

Deep Mining

EAST MIDWEST WEST

SOURCE: Adapted by CBO from U.S. Department of Energy, Coal Production-1979 (April 30, 1981).

39
The regional pattern of coal's sulfur content also varies from region to

region, and within particular regions. The East contains coals with sulfur

contents ranging from below 1 percent to above 3 percent by weight. The

Midwest offers little low-sulfur coal; most coal in that region is characterized by moderate- or high-sulfur contents, generally above 3 percent.

The West has sizable reserves of low-sulfur coal; more than three-fourths of

all western coal has a sulfur content below 1 percent. In contrast, the

energy content of eastern and midwestern coal reserves is generally higher

than in the West.

Coal production in the United States has been shifting slowly westward. In I960, the producing states of the East accounted for 95 percent of

total U.S. production. By 1970, the East's share of the market had declined

to 85 percent and by 1979, to approximately 75 percent. 3/ The reasons

for this trend are the high productivity of western surface mines, the growth

in western energy consumption, and to some extent, the increased nationwide demand for low-sulfur coal to meet both state and federal environmental regulations. In the future, the revised federal emissions standards—the NSPS of 1978, with their implicit requirement of scrubbers on all

new utility generators—may somewhat slow this westward trend in coal

production, inasmuch as the current regulations provide little if any

economic advantage to users of low-sulfur coal that is not locally produced.

Factors That Influence Choices of Coal Supply and Delivered Price

Although coal is produced in all three regions of the country, much

coal, particularly western coal, is shipped to other geographic regions. Although under ideal conditions utilities would elect to burn local coal only,

several factors often combine to influence them to do otherwise. Local

mining costs, sulfur content, and the availability of a secure long-term

supply often prompt utilities to buy coal produced in other areas, so long as

they obtain the lowest delivered price for the fuel desired. The chief factor

affecting utilities' coal purchasing decisions is the fuel's so-called free-onboard (FOB) price. The FOB price, coal's counterpart to oil's wellhead price,

is its cost at the place of production, including mining and processing costs

and producers' profit, but no transport cost.

3. See Martin B. Zimmerman, The U.S. Coal Industry; The Economics of

Policy Choice, the MIT Press (1981). The 1979 figure is based on the

CBO analysis.

40
Mining method is the most significant factor affecting FOB costs. In

general, surface mines are from two to three times more productive than

underground mines, and coal from surface mines often sells for about onehalf the price of coal from deep mines. In 1979, the average FOB value per

ton of deep-mined coal was $32.76, while that of surface-mined coal was

$17.58. 4/ To determine the delivered price of a particular coal, however,

transporta-tion rates and distances hauled must be added to FOB costs.

Most coal moves by train. Rail haulage rates generally range from 10

to 30 mills per ton for each mile transported (termed a "ton-mile"). Higher

rail rates predominate in the East, although in several western areas, rail

rates have risen steeply over the last few years. At a cost of 15 mills per

ton-mile, a haul of 300 miles can increase the FOB coal price by $4.50 per

ton. For 1,000-mile hauls, $10 to $20 can be added to the price of each ton

of coal. Though unusual in the East, where coal hauls average 300 miles,

1,000-mile hauls are not uncommon in the West.

Within a region, coal's delivered price is largely a function of the

region's predominant mining method, since the value of local coal establishes the upper value for coal shipped from other areas. Delivered coal

prices are highest in the East—where approximately half the coal is mined

underground—ranging from $37 to $44 per ton. Delivered coal prices in the

midwest are lower, ranging from $18 to $33 per ton, corresponding to the

greater use of surface-mining methods in this area. Prices for coal delivered to western users, where surface-mining also predominates, are

lowest, ranging from $14 to $18 per ton. 5/

Low mining costs, together with regulations encouraging the use of

low-sulfur coal (such as stricter state standards on some older power plants

and the 1971 NSPS on newer units) encourage the shipment of much western

coal eastward. Most coal from western deposits happens to be low in sulfur

content and because it is mostly surface-mined, tends to have lower FOB

prices than eastern, deep-mined low-sulfur coal. As a result, western surface-mined low-sulfur coal is an attractive alternative to some buyers in the

East and the Midwest in particular.

4. See U.S. Department of Energy, "Energy Data Report," Coal Production-1979 (April 30, 1981).

5. See U.S. Department of Energy, Cost and Quality of Fuels for Electric

Utility Plants—December 1980, Monthly Report (April 7, 1981).

41
Several factors limit the demand for western coal in the East and

Midwest, however. For one, the East (notably Appalachia) holds large quantities of low-sulfur coals. Although much of this supply is mined (by either

method) at a higher cost than western surface-mined coal, it is closer to

many eastern purchasers and transportation costs thus can be lower. For

eastern users, the costs of shipping western coal can often raise its delivered price above that for comparable low-sulfur eastern coal. Another major

factor is the status of many sulfur dioxide regulations for old power plants.

In many areas of the Midwest, the absence of strict sulfur dioxide regulations for many older power plants, allowing them to use indigenous surfacemined higher-sulfur coal, obviates the need to purchase low-sulfur coal from

another region. Finally, through the imposition of a strict scrubbing requirement on all coal used in new power plants, the current NSPS provide

little stimulus for increasing the import of low-sulfur coal.

THE 1971 NEW SOURCE PERFORMANCE STANDARDS

AND U.S. COAL CONSUMPTION

Concerns about distortions in U.S. coal markets shaped the Congress1

revisions in 1977 of the Clean Air Act's new source performance standards.

Under the old NSPS of 1971, utility companies could—and did—rely heavily

on low-sulfur coal to meet mandatory mass pollutant emissions limits. (As

stated in Chapter n, the maximum allowable amount of sulfur dioxide gas

emitted from a steam boilerfs stack was 1.2 pounds for every one million

BTUs of fuel burnt.) Required only to meet this mass emissions limit by

whatever method was economical, many utility managers elected to burn

low-sulfur coal rather than install costly and still optional scrubbers;

scrubbers were chosen rarely, usually in instances in which low-sulfur coal

was not available within a reasonable distance.

From this apparent preference for low-sulfur coal under regulations

promulgated in response to the Clean Air Act, the Congress concluded that

two related distortions in need of correction existed: that demand for lowsulfur coal was gaining an edge over higher-sulfur coal; and that, accordingly, western coal could flood the market, displacing demand for eastern

and more importantly, midwestern coal.

Data on the trend in demands for high- and low-sulfur coal tend to

bear out these suppositions, but only partly (see Figure 5). The relative

demand for low-sulfur coal did indeed grow during the late 1970s, coincident

with the utilities' implementation of plans to meet the mass emissions limits

42
Figure 5.

Monthly Deliveries of Coal to U.S. Electric Utilities,

by Sulfur Content: 1974-1980

High-Sulfur Coal

(more than 3.01 percent sulfur)

Low-Sulfur Coal

(0.51 to 1.0 percent sulfur)

1974 1975 1976 1977 1978

Year

SOURCE: Adapted by CBO from data provided by Data Resources, Inc.

a

 Drop coincident with mine workers' strike.

1979 1980

promulgated in 1971. 6/ At the same time, the rate of high-sulfur coal

deliveries slackened. Though possibly related to one another and reflecting

some displacement of high- by low-sulfur coal, these two trends cannot be

construed as conclusive evidence of the Clean Air Act's effects. Other

factors also have to be taken into account.

6. By no means should the divergence of high- and low-sulfur coal demand

in the late 1970s be taken as any indication of the effects of the revised

NSPS of 1978. Because utilities1 efforts at compliance with the revised

NSPS are still very much on the planning or initial construction stages,

the 1978 NSPS are unlikely to yield any measurable effects on fuel

markets for another decade or more. Far more reasonable, though still

tenuous owing to an insufficiency of data, is a possible correlation

between the older NSPS and shifts in the coal market in the late 1970s

and early 1980s. Even so, much of the perceived shifts may be attributable to tighter state regulations under the act limiting the emissions

of some older power plants not covered by federal emissions standards.

43
Much of the increase in overall low-sulfur coal demand observed in the

1970s stemmed from the large increase in low-sulfur western coal consumption also observed during this period, an increase not necessarily in response

to sulfur dioxide regulations and not necessarily resulting from regional

shifts in the coal market. Though consumption of western coal rose by 145

percent between 1974 and 1979, the rise can be ascribed more to increased

local consumption than to the attractiveness of western coal's low-sulfur

characteristics to distant buyers. During those years, annual coal consumption in the West South Central, Mountain, and Pacific areas alone increased

by 73 million tons; the nationwide increase for all coals during those years

was 94 million tons. (Figures 6 and 7 outline the specific U.S. regions of

coal supply and demand, which are also used in the coal market projections

described in Appendix B.) At the same time, however, western coal shipments to mid western consumers in Ohio, Illinois, and Indiana (the largest

users of western coal east of the Mississippi) rose by only 10 million tons. 7/

For the most part, coal-burning utilities in those states continued to rely on

local fuel, and of the total increase in national coal consumption between

1974 and 1979, less than 11 percent involved increased shipments of western

coal to the three midwestern states. As stated above, mines in the East,

notably in Appalachia, also yield significant amounts of low-sulfur coal.

Thus, eastern suppliers too may have shared in the increased use of lowsulfur coal.

For the portion of low-sulfur western coal that was shipped east during

the 1970s, mining costs may have been as strong an element as emissions

regulations in stimulating its demand. As stated above, much low-sulfur

coal, by virtue of being located in the West where surface-mining methods

predominate, tends to incur relatively low recovery costs. Furthermore,

western surface mines are more productive than many midwestern surface

mines. In 1979, the average FOB price of surface-mined coal from Montana

and Colorado ranged from $9*76 to $13.13 per ton, while that from Illinois,

Indiana, and Ohio ranged from $19.21 to $21.13 per ton. 8/ Thus, this

factor too may have contributed to the increased use of low-sulfur coal

during the late 1970s.

7. See U.S. Department of Energy, Bituminous Coal and Lignite Distribution, Calendar Year 1978 (April 1979); see also, U.S. Department of

Energy, Bituminous Coal and Lignite Distribution, Calendar Year 1979

(April 1980).

8. See U.S. Department of Energy, Coal Production-1979.

44
Figure 6.

U.S. Coal Supply Regions

Region Boundaries

Coal Producing Areas

SOURCE: Adapted by CBO from ICF, Incorporated.

Figure 7.

U.S. Coal Demand Regions

r\

East'\ South

South \ Atlantic

Central

SOURCE: Adapted by CBO from ICF, Incorporated.

45
Though the nationwide demand for low-sulfur coal did rise during the

1970s, the characteristic of low-sulfur content does not appear to have

caused that fuelfs delivered price to be significantly higher than the delivered price for high-sulfur coals. Throughout the 1970s, the price of both highand low-sulfur coal proceeded along roughly parallel upward paths (see

Figure 8), with low-sulfur coal priced only slightly higher. The only anomaly

in the pattern, also evident in the illustration of deliveries (Figure 5),

occurred in 1978, coincident with a strike of mine workers against coal

producers; though pronounced and causing a brief, inexplicable gain for highsulfur coal over low-sulfur coal, this episode represents only a temporary

disturbance on the otherwise quite regular course of both low- and highsulfur coal prices. The fact of no significant difference between the delivered price of both coals suggests that buyers, at least in the 1970s, were

willing to pay only a slight premium for low-sulfur content over the cost of

locally available coals.

In conclusion, though increased demand for low-sulfur coal in the

1970s has occurred roughly simultaneous with implementation of utilities'

plans to meet the 1971 NSPS, no firm correlation can be established,

perhaps because the standards have not been in effect long enough. Nevertheless, the perceived potential for future distortions in the coal market

prompted the Congress to take preventive measures in amending the Clean

Air Act in 1977.

THE REVISED NSPS AND PROJECTIONS FOR U.S. COAL MARKETS

By requiring the installation of scrubbers in all new coal-burning generating plants, the revised NSPS of 1978 were designed to remove the

attractiveness to utilities of using non-local low-sulfur coal. The requirement to remove a fixed percentage of sulfur dioxide when burning any type

coal under the 1978 NSPS was designed to encourage the use of the cheapest

coal available, usually a locally produced coal. In devising the new regulations, the EPA formulated projections through 1995 on the basis of a computer model simulation. 9/ The simulation indicated that, as a result of the

proposed new standards, total pollutant emissions would be reduced through9. See ICF, Incorporated, "The Final Set of Analyses of Alternative New

Source Performance Standards for New Coal-Fired Power Plants," prepared for the U.S. Environmental Protection Agency and Department of

Energy (June 1979).

46
Figure 8.

U.S. Coal Prices, by Sulfur Content: 1974-1980

1.60

1.40

£1.20

£

B

11.00

iO.80

•5

0.60

0.40£

Low-Sulfur Coal

(0.51 to 1.0 percent sulfur)

A

High-Sulfur Coal

(more than 3.01 percent sulfur)

1974 1975 1976 1977

Year

1978 1979 1980

SOURCE: Adapted by CBO from data provided by Data Resources, Inc.

a

 Divergence coincident with mine workers' strike.

out the projection period, and that reliance on local coal would increase

appreciably.

As part of a reexamination of the NSPS of 1978, the analysis in the

remainder of this chapter attempts to assess what effects, if any, the revised NSPS will have on U.S. coal markets through the year 2000. Since the

new standards were enacted, knowledge about scrubber costs, electricity

growth, and coal supply has increased. To take account of this information

in its analysis, the CBO requested ICF, Incorporated, a consulting firm

specializing in coal-market information, to examine the effects of the 1978

NSPS on the basis of new assumptions developed by the CBO. ICF was

chosen to conduct the modeling because it operates one of the most detailed

coal and utility emissions models available, and because that model continues to be used by the EPA and other researchers to determine the effect

of alternative standards on the utility and coal industries.

The purpose of the modeling was to establish a baseline of reasonable

expectations for current policy with regard to three sets of issues: What

quantity of air pollutant emissions can be expected from the utility sector

through the year 2000? What are likely to be the annual and cumulative

47
costs of the standards limiting these emissions? And what consumption and

regional production levels of different coal types may be anticipated? (This

same model is used in the analysis in Chapter VI that compares alternative

emissions standards for sulfur dioxide—the most influential emissions limit—against this baseline and against each other.) The remainder of this

chapter focuses on two aspects of the third issue: What type of coal is

likely to be used within each consuming region, and where will that coal

originate? The analysis is based on the assumption that the current NSPS

will remain in force. (Appendix B details the assumptions and the

methodology used.)

In the year 2000, the majority of projected new coal-fired capacity—that is, plants subject to the current NSPS—will be in the West South

Central area and Atlantic seaboard states. Almost 100 gigawatts (60

percent) of the 168 gigawatts of new coal-fired electric capacity anticipated will be located in these areas (see Table 5). The area seen to

experience one of the lowest growth rates in new coal-fired capacity is the

southern Midwest (encompassing the East South Central area); the sizable

commitment to new nuclear power in that region will tend to lower the

Midwest's growth in coal-fired capacity, though recent nuclear plant cancellations may result in greater projected coal-fired capacity.

With regard to the sulfur content of coal burnt by new plants subject

to the current NSPS, the pattern of overall consumption established late in

the 1970s is expected to continue. Low-sulfur coal (generating less than 1.2

pounds of sulfur dioxide per million BTUs) is projected to meet roughly 60

percent of all new coal-fired utility demand by the year 2000. Much of that

consumption is seen to occur in the Mountain and West South Central

regions (36 percent), where low-sulfur coal naturally predominates; and the

South Atlantic region (24 percent), where low-sulfur coal is available from

Central Appalachia. Hence, the low-sulfur coal consumed in these regions

will come largely from local supplies. In the East, North, and South Central

areas of the Midwest, however, where low-sulfur coal is not mined, lowsulfur coal will supply approximately 60 percent of the regional demand in

the year 2000 in power plants covered by the NSPS. Most of this supply will

probably come from the West, indicating an accelerated trend toward

western coal supplies. The growth in midwestern coal production (see Table

6), however, also indicates that many new power plants will choose to burn

the locally produced high-sulfur coal under the NSPS.

Three western areas are projected to experience significant increases

in total coal production. In the Rocky Mountain states, production is seen to

rise by 578 percent; in the Southwest, it should rise by 468 percent; and in

the Western Northern Great Plains, by 268 percent. These sizable growth

rates are attributed partly to consumption by users in the West and West

48
TABLE 5. PROJECTED REGIONAL GROWTH IN COAL-FIRED

ELECTRICITY, TO YEAR 2000

Region

Total 20-Year

Growth in CoalFired Capacity

(In gigawatts)

Total Projected

Annual Coal Consumption (In

millions of tons)

Percent

Increase in

Consumption

from 1979

East (New England

and Middle and

South Atlantic) 44.2 290 110

East North Central 25.5 241 50

East South Central 3.6 88 23

West North Central 11.8 134 82

West South Central 54.2 275 535

West (Mountain

and Pacific) 25.0 146 134

Total 164.3 1,174 114

SOURCE: CBO/ICF analysis.

South Central regions, and partly to increasing demand in the Midwest and

East. In the year 2000, western coal will supply approximately 21 percent of

all coal burnt by both new and old utilities east of the Mississippi. The

majority of coal used in these areas, however, will still be supplied by midwestern and eastern (primarily Appalachian) producers.

These data indicate some important trends in coal markets. Most

important, coal production is seen to rise in all U.S. regions, most notably in

the western areas. The exception is Southern Appalachia; a slowing of production in Appalachia is to be expected, since these eastern reserves have

been mined for longer periods and are declining in productivity.

Also important is the increasing amount of western coal shipped east

by the year 2000. In 1979, eastward shipments of western coal are esti49
TABLE 6. REGIONAL COAL PRODUCTION FOR 1979 AND PROJECTED

TO THE YEAR 2000 (In millions of tons per year)

Region

Northern Appalachia

Central Appalachia

Southern Appalachia

Midwest

Central West

Gulf

Eastern Northern

Great Plains

Western Northern

Great Plains

Rocky Mountains

Southwest

Northwest/ Alaska

Total

Total Western Coal

Shipped to Eastern

Utilities

SOURCE: CBO/ICF

Base Year

Production

(1979)

187

213

24

131

14

26

14

104

27

25

5

770

22a/

analysis.

a/ Estimate obtained from data in

and Subbituminous Coal and

Total Projected

Annual Production

331

342

21

252

17

119

44

383

183

142

33

1,867

127

Percent

Increase

77

61

-13

92

21

358

214

268

578

468

560

142

477

U.S. Department of Energy, Bituminous

Lignite Distribution, Calendar Year

1979.

50
mated to have been some 23 million tons; by the year 2000, these are projected to be 127 million tons—an increase of more than 450 percent. (Most

western coal shipped east comes from Powder River Basin in Montana and

Wyoming and goes to Ohio, Indiana, and Illinois.) This increase can be compared to growth in overall coal production, which is estimated to rise by 142

percent over approximately the same period. Thus, even under the current

NSPS, with their intent to promote reliance on local resources, western coal

penetration of the midwestern and eastern markets is seen to increase substantially throughout the remainder of this century.

To a large extent, the increase of western coal sales in midwestern

markets is projected because inexpensively mined—hence low-priced—western coal can be shipped long distances and still retain a competitive edge

over local coal supplies. For example, it is estimated that in the year 2000,

a Wyoming Powder River coal shipped 1,000 miles to Indiana at 20 mills per

ton-mile—achieving a delivered cost of $1.64 per million BTUs—will still

underprice a locally produced Indiana coal shipped 100 miles at a delivered

cost of $1.68 per million BTUs. 10/ However, this slight competitive edge

is highly sensitive to transportation rates, which, if they rise higher than

projected, can result in much higher delivered prices for Western coals

shipped long distances.

The different control requirements for high- and low-sulfur coal also

are expected to have some influence, though a small one, on U.S. coal

markets. The lower control requirement of 70 percent for low-sulfur coal

(instead of 90 percent) was originally established in recognition of the higher

marginal cost of reducing sulfur dioxide from coals already low in sulfur

content. This lower control requirement, however, is expected to provide a

small cost advantage to some users of non-local low-sulfur coal. For

example, the total cost differential of scrubbing a high-sulfur midwestern

coal versus that of scrubbing a low-sulfur western coal is roughly 4.5 mills

per kilowatt-hour, or approximately $8.70 more per ton than using the lowsulfur western coal. (This estimate is based on a 500-megawatt power plant

burning western coal with a heat content of 10,000 BTUs per pound.) This

differential would favor the purchase of low-sulfur coal over an equivalentcost high-sulfur coal within an approximate radius of 500 miles. Such differentials are not large enough, though, to cause large-scale distortions in

the U.S. coal market.

10. Because Wyoming Powder River coal and Indiana Interior Basin coal

have different energy contents, their delivered price reflects the total

cost of buying and shipping the equivalent amount of fuel energy,

expressed as one million BTUs.

51
Mining costs and transportation rates remain the major determinants

of coal selection under the current standards, while low sulfur content is

only a small influence. In this respect, the current standards should eliminate only a portion of the perceived encouragement to use non-local coal

supplies. In the next chapter, the effects of alternate standards are examined and compared to the current standards to determine what effect, if any,

different sulfur dioxide emissions limits may have on total emissions, on the

costs of compliance, and on the production and distribution of coal.

52
CHAPTER VI. CHOICES FOR NEW SOURCE PERFORMANCE STANDARDS

The Congress is now considering possible changes to the Clean Air

Act, and the debate will almost certainly include a reexamination of the

new source performance standards. This chapter outlines various possible

courses of action with respect to the NSPS, altering only the way they

restrict emissions of sulfur dioxide. The analysis focuses primarily on three

aspects of the alternative approaches:

o Total projected emissions of sulfur dioxide under each option;

o The costs of each alternative to the electric utility industry

and to consumers; and

o The production and distribution of U.S. coal.

ALTERNATIVE EMISSIONS STANDARDS

To provide a framework for Congressional consideration of the Clean

Air Act, the CBO has projected the possible outcomes of four alternative

standards for the NSPS that became effective in 1978. Being current law,

though subject to change through EPA review at intervals of four years or

less, the 1978 NSPS are treated as one basis against which the alternatives

are measured; comparison of each alternative against the others is equally

important, however, and is a critical part of the analysis. The four

alternatives to current law that the CBO has analyzed include one option

that would be a reversion to the NSPS of 1971, a second and third that would

alter the imposition of percentage reductions for sulfur dioxide that are

stipulated in current law, and a fourth that would allow a balance of sulfur

dioxide emissions control between old and new sources to achieve the same

level of control as would the current NSPS. Descriptive details of these

four options are given on the following pages; the essential characteristics

are summarized in Table 7. I/

1. The model used to project the effects of the options is described in

Appendix B.

53
TABLE 7. SUMMARY OF CURRENT AND ALTERNATIVE

EMISSIONS STANDARDS

Current Law

and Options

Mass Emissions Limits

(In pounds of sulfur dioxide per million

BTUs of fuel consumed)

Current Law—New Source

Performance Standard of 1978 a/

1.2 pound ceiling

0.6 pound floor

Option I—Revert to 1971 New 1.2 pounds

Source Performance Standard a/

Option n— Achieve 70 Percent

Emissions Control and Set an

0.8 Pound Floor for Sulfur

Dioxide Emissions a/

Option m—Achieve 90 Percent

Emissions Control and Set a

0.6 Pound Floor for Sulfur

Dioxide Emissions a/

Option IV-—Constrain Total

Emissions Growth by Balancing

Sulfur Dioxide Emissions

Control Between Old and New

Sources

1.2 pound ceiling

0.8 pound floor

1.2 pound ceiling

0.6 pound floor

New plant must meet current

NSPS emissions level if no

tradeoff used; if emissions are

reduced at an existing plant

new plant may increase its

emissions beyond current NSPS

level by same amount

a/ Applies to new or modified sources only.

Option I. Revert to the New Source Performance Standards of 1971

Reenactment of the 1971 NSPS, as described in Chapter H, would

require coal-fired utility plants to limit emissions of sulfur dioxide gas to

1.2 pounds for every one million BTUs of fuel burnt. (For brevity, the

54
TABLE 7. (Continued)

Required Percentage

Reduction Level Comments

90 percent for emissions

between floor and ceiling; 70

percent or more if emissions

are below floor

None

70 percent for emissions

between floor and ceiling; none

required if emissions are

below floor

90 percent for emissions

between floor and ceiling; none

required if emissions are

below floor

Same as current law if no

emissions trading used; none

or variable when trading

used, depending on reduction

needed to meet constraints

Requires all coal to be scrubbed

regardless of sulfur content

Allows low-sulfur eastern and

western coal to be used without

scrubbing

Allows much western and some

eastern coals very low in sulfur

content to be used without

scrubbing

Eliminates scrubbing for some

low-sulfur western coals; reduces

scrubbing for most western

and some eastern coals

Limits projected emissions to

those calculated under current

law; allows new and old facilities

within a state to decide individual

control levels so long as the limit

on total emissions is not violated

SOURCE: Congressional Budget Office

following text expresses such a standard as 1.2 pounds SO- per million

BTUs.) An electric utility subject to this standard could comply either by

using low-sulfur coal without sulfur dioxide emissions controls (a scrubber),

or by using a scrubber and burning a cheaper higher-sulfur coal. The

primary distinctions of this standard over its successor are that it leaves

55
scrubbers optional and that it does not require a set percentage reduction of

potential sulfur dioxide emissions.

Option IL Achieve 70 Percent Emissions Control and Set a 0.8 Pound Floor

for Sulfur Dioxide Emissions

This alternative would scale down the current standards' requirement

that utilities control sulfur dioxide emissions by 90 percent when burning

high-sulfur coal; it would also eliminate the current requirement to use

scrubbers in plants burning very low-sulfur coal. It would call for scrubbing

(or another technique that can desulfurize flue gases) only if emissions were

above a maximum control level, or "floor", set at 0.8 pounds SO- per million

BTUs. No control requirement would be specified for emissions below this

floor. Above the floor, sulfur dioxide emissions would have to be reduced by

at least 70 percent, and in no case could emissions exceed the 1971 NSPS

ceiling of 1.2 pounds SO- per million BTUs. Under this option, much

western coal and some eastern (notably Appalachian) coal could be burnt

without scrubbers.

Option HI. Achieve 90 Percent Emissions Control and Set a 0.6 Pound Floor

for Sulfur Dioxide Emissions

Though retaining the current NSPS requirement of 90 percent sulfur

dioxide emissions control for utilities using high-sulfur coal, this option

would lower the current control requirement for some low-sulfur coals and

eliminate it entirely for others. The alternative would stipulate that sulfur

dioxide emissions be reduced by at least 90 percent if they are between 0.6

and 1.2 pounds per million BTUs of fuel consumed, a requirement similar to

the current standard. Unlike the current standards, however, no control

requirements would be specified for emissions below 0.6 pounds SO- per

million BTUs. Under this alternative, only some western coals could be

burnt without scrubbers, although the control requirement for the remaining

low-sulfur western and eastern coals would be significantly relaxed.

Option IV. Constrain Total Emissions Growth by Balancing Sulfur Dioxide

Emissions Between Old and New Sources

Two features are unique to this option: first, it would operate on a

state-by-state basis within a general, nationwide framework; and second, it

could affect old sources as well as new ones. Total future sulfur dioxide

emissions within each state would be limited to levels projected under the

56
current NSPS, allowing operators of new and old utility plants within each

state to meet the overall emissions limit by using any combination of

measures. Thus, the alternative would allow new plants to increase their

emissions above NSPS permitted levels, so long as commensurate emissions

reductions occurred at existing sources within the same state. This is

commonly termed "emissions trading," or "new source bubbling." 2/ For

purposes of the CBO analysis, because western states contain few old coalfired facilities, emissions trading was treated as permissible only in the 31

states east of the Mississippi River. All other new power plants were

assumed to be required to meet current state or federal NSPS requirements,

whichever was lower. (Limiting the analysis to the 31-state region reduced

computation time and costs but not accuracy.)

Under such a plan, a utility planning a new plant would first determine

the quantity of new emissions the contemplated plant would contribute to

the area's atmosphere after complying with the current NSPS; this would

establish a baseline for trading. That plant could then increase its sulfur

dioxide emissions by a measured amount above the baseline, so long as

emissions from one or more already existing sources were reduced by an

equal amount. In this procedure, overall incremental emissions would be

held to current NSPS levels, but the burden of control could be distributed

between utilities operating new and old sources. For purposes of analysis,

emissions trading was treated as being limited to intrastate areas, assuming

that such a plan would not allow negotiation over state boundaries; this

assumption tended to produce results showing higher costs than plans

allowing emissions trading between states. 3/ It was also assumed that this

option would allow new sources to trade emissions allowances with an

existing source only so long as the latter continued to operate. 4/

2. "Bubbling" is a calculating procedure that envisions each state as

having an enclosing overhead bubble within which the utility emissions

of that state are contained; additions and subtractions of pollutant

emissions are treated as occuring within the confines of that bubble.

3. Administration of this option would probably be complex and perhaps

somewhat costly in terms of both money and time. Because the

administrative mechanics of implementing this plan are purely conjectural, this analysis disregards any potential such costs the option might

entail.

4. Should the existing facility be retired, the new source would have either

to apply the tradeoff to another existing facility in the region or reduce

its own emissions by the amount originally slated for trading.

57
COMPARISON OF ALTERNATIVE EMISSIONS STANDARDS

For a continuation of current law and each of the alternative

emissions standards outlined, the CBO projected sulfur dioxide emissions,

costs, and coal use.

Effects on Emissions and Control Costs

The highest growth in sulfur dioxide emissions from new

coal-fired power plants would be allowed under Option I, increasing total

utility emissions from an annual 17.6 million tons in 1979 to 22.8 million in

the year 2000. 5/ Both the current standards and Option IV would limit

total emissions to 21 million tons by the year 2000, the lowest increase of

all the alternatives. Total emissions under the other choices—Options n and

m—would tend to fall between these upper and lower bounds. Table 8 shows

total projected emissions of all the alternatives examined, including the

current standards. 6/

5. As stated in Chapter n, these increased emissions would accompany the

addition of 168 gigawatts of new coal-fired electrical capacity anticipated.

6. Four cautions must be noted, however, when comparing the costs and

projected emissions. First, the current NSPS and Option IV could yield

the lowest level of future sulfur dioxide emissions. This does not give a

measure of the health effects or costs of allowing pollutant levels to

rise beyond the current standards; whether any analyis could assess

these effects from such small differences in projected emissions is

doubtful. Second, if new sources using emissions tradeoffs from

existing plants were allowed to retain the higher emissions limits after

the existing plants were retired, the bubbling approach could leave a

dirtier generation of new plants than would be allowed under the

current NSPS; however, this analysis assumes that regulations under

Option IV would not permit this. Third, the long operating life of most

electric plants—usually about 50 years—suggests that most existing

sources that could be useful for emissions offsets (as under Option IV)

would continue to operate through the year 2010, after which a sharp

drop in utility emissions could be expected because of the surviving

generation of cleaner plants. Since the surviving plants would be

required to lower emissions to reach the original standards, then the

predicted cost effectiveness over the life of the plants could drop (that

58
Power plants subject to neither of the Clean Air Act's NSPS can emit

twice to six times the volume of sulfur dioxide than do plants that are

regulated under the standards. Therefore, emissions from facilities not

subject to either standard dominate the projections shown in Table 8. New

plants under the most stringent national standards—the current NSPS—will

contribute only 1.6 million of a total projected 21 million tons of sulfur

dioxide emissions in the year ZOOO. Similarly, even under the most lenient

standards—Option I—new plants will contribute only 4 million of a total

22.8 million tons of sulfur dioxide in the year 2000. The difference between

the emissions projected for new units under current law and Option I is only

2.4 million tons. In both cases, roughly eight-tenths of all sulfur dioxide

emissions would arise from units in existence during the early 1970s—that

is, those facilities subject to neither NSPS. This disparity is attributable

primarily to the higher emissions rates associated with older sources. For

example, the average emissions rate in the year 2000 from a power plant

that is subject to neither of the act's emissions standards is estimated to be

2.6 pounds SO- per million BTUs, compared to an average emissions rate of

0.4 pounds SO^ per million BTUs for plants operating under the stringent

1978 NSPS.

Judgments about cost effectiveness can be made from comparing the

costs incurred by reducing sulfur dioxide emissions from the highest

projected levels—in this case, 22.8 million tons by the year 2000 under

Option I. Under the current NSPS, sulfur dioxide removal is projected to

cost $2,411 a ton. Removal costs under Option n would be $1,929 a ton.

Option IE—by far the most expensive choice according to this measure—would incur a removal cost of $3,400 a ton. Option IV, in sharp

contrast, would permit sulfur dioxide removal at only $550 a ton at the end

of the projection period.

Option IV would offer the utilities the greatest economic efficiency,

because it would permit fuel-switching as a substitute for scrubbers;

6. (continued)

is, become more expensive per ton of sulfur dioxide removed), depending on the cost of the new control technique chosen. Finally, the

mandatory installation of scrubbers under the current NSPS provides a

form of insurance against increased levels of sulfur dioxide emissions

that could result from the burning of high-sulfur coal, under possible

emergency situations. For these reasons, only partial conclusions about

the full benefits of each alternative relative to cost can be drawn in

this study.

59
TABLE 8. TOTAL PROJECTED SULFUR DIOXIDE EMISSIONS AND

COMPARISON OF COST EFFECTIVENESS UNDER CURRENT

LAW AND ALTERNATIVE STANDARDS

Emissions Under

Current Law and

Alternative

Total Nationwide

Sulfur Dioxide Emissions

(In millions of

tons per year)

Incremental Cost of

Sulfur Dioxide Reductions

Below 1971 NSPS

(In 1980 dollars

per ton reduction)

Standards

Current Law

Total

New Sources

Option I a/

Total

New Sources

Option H

Total

New Sources

Option m

Total

New Sources

Option IV

Total

New Sources

1979

17.6

None

17.6

None

17.6

None

17.6

None

17.6

None

1990

20.7

0.4

21.1

0.8

21.0

0.6

21.1

0.4

20.7

0.4

2000

21.0

1.6

22.8

4.0

22.1

2.8

21.9

2.0

21.0

2.5

1990 2000

1,800 2,411

N/A b/ N/A b/

None 1,929

None c/ 3,400

900 550

SOURCE: CBO/ICF analysis.

a. Incremental cost of sulfur dioxide emissions reduction represents cost

of control beyond these standards.

b. Not applicable.

c. No significant emissions reduction is achieved beyond Option I, although

annual costs are increased by $360 million.

60
switching to a lower-sulfur coal at existing power plants to reduce the

control requirements for new plants would lower annual costs while achieving the same emissions reductions as the current NSPS. For example,

switching an existing 500-megawatt plant from a high-sulfur coal at 3.33

pounds SO- per million BTUs to a medium-sulfur coal at 1.66 pounds SO^ per

million BTOs could reduce emissions at a rate of $431 per ton removed. By

contrast, a new plant of comparable size but equipped with a scrubber may

incur costs of $1,230 for each ton of sulfur dioxide removed beyond the level

that would be required under Option I.

Measures of cost effectiveness can only be taken as rough gauges of

economic efficiency, however. For example, although the current NSPS

cost less per ton of sulfur dioxide removed than would Option HE, they are

actually more expensive in terms of capital and annual charges (the next

section examines these costs). They remove more sulfur dioxide, however,

and hence are less costly per ton removed. Thus, consideration of these

options should include total costs as well as costs per ton.

Cost Effects on the Utility Industry

Annual costs of air pollution regulations to the utility industry are a

function of two factors: the capital and operating costs of pollution control

equipment and the increased premiums associated with purchasing and

shipping low-sulfur coal.

Capital Costs. In general, the capital requirements of each alternative are roughly proportional to the amount of scrubber control needed. The

current NSPS are projected to involve the greatest capital outlay, approximately $33 billion between 1980 and 2000 (see Table 9); that large capital

expense is attributable for the most part to the need to install scrubbers to

meet the standards.

At the other end of the spectrum, capital outlays for the moderate

amount of optional scrubbing entailed in meeting the NSPS of 1971 (Option

I) are projected to total only $14 billion over the 1980-2000 period.

The two choices that stipulate emissions floors (Options n and ffl)

would reduce the overall costs of scrubbing by eliminating mandatory

desulfurization for very low-sulfur coals and by allowing many coals to meet

the emissions floor with only moderate reduction levels (70 percent and

less). High-sulfur coals in both of these options would still need to be

scrubbed by either 70 percent (Option n) or 90 percent (Option HI), affecting

primarily the midwestern and Atlantic seaboard states; in both cases, the

61
TABLE 9. PROJECTED COST EFFECTS ON THE UTILITY INDUSTRY OF

ALTERNATIVE EMISSIONS STANDARDS

Current

Standards Option I Option n Option IH Option IV

Cumulative Capital Requirements

(In billions of 1980 dollars)

1990 8.30 3.90 4.50 4.10 6.60

2000 33.40 14.00 14.60 17.10 14.70

Projected National Scrubber-Equipped Capacity

(In gigawatts)

1980 45.70 45.70 45.70 45.70 45.70

1990 81.60 55.80 59.00 55.30 73.00

2000 213.50 73.30 77.40 87.30 123.40

Approximate Annual Costs

(In billions of 1980 dollars)

1980 5.35 5.35 5.35 5.35 5.35

1990 8.10 7.38 7.38 7.74 7.74

2000 14.10 9.76 11.11 12.82 10.75

Nationwide Average Generating Costs of Air Pollution Control

(In 1980 mills per kilowatt-hours)

1980

1990

2000

2.34

2.57

3.43

2.34

2.34

2.37

2.34

2.34

2.70

2.34

2.46

3.12

2.34

2.46

2.62

SOURCE: CBO/ICF analysis.

use of an emissions floor requiring no further control would tend to reduce

significantly the amount of scrubbing needed in the western states. The

capital costs for Option n and HI are estimated to total between $14 and $17

billion for the 1980-2000 period.

62
Option IV would require scrubbing only in instances in which a new

source could not find an old one to serve as a trading partner with which to

balance emissions allowances. Because of the high degree of emissions

control mandated in this latter option, more scrubbing is envisioned than for

Option I (at roughly the same capital expense) although much less than for

the current standards.

Generating Costs. The current NSPS would result in the highest

expected annual cost ($14 billion in the year 2000), while Option I would

result in the lowest ($10 billion). Option IV would entail lower annual costs

after 1990 ($11 billion per year by the year 2000) once significant coal-fired

capacity growth had begun in the East, where the most existing capacity is

available for cost-effective emissions trading purposes (see Table 9).

The current NSPS would have the highest generating cost associated

with pollution control primarily because of the current fixed and variable

charges of using scrubbers. The 3.43 mills per kilowatt-hour charge in 2000

(shown in Table 9) under the current standards would translate into

approximately $1.72 for a monthly electricity use of 500 kilowatt-hours.

This represents approximately 6 percent of the average residential electricity charge recorded in 1980. 7/

Option I would exact the lowest average generating costs for emissions

control—2.37 mills per kilowatt-hour. This cost is not projected to change

appreciably through the year 2000, largely because the proportion of present

scrubber-equipped capacity compared to total capacity would not change

significantly. In addition, though the standards under Option I would

encourage use of low-sulfur coal, and thus could slightly raise annual

operating costs, that increase would be insignificant when averaged over

total electricity production. Overall, the utilities1 operating costs for air

pollution control would rise by less than 5 percent.

The two alternatives that set emissions floors, Options n and HI, would

involve average generating costs higher than under Option I but lower than

under the current standards. This cost would occur because both scrubber

and low-sulfur coal use under both options would fall somewhere between

that under Option I and the current standards. The price of and demand for

low-sulfur coal would be lower than under Option I but higher than under

7. See U.S. Department of Energy, 1980 Annual Report to Congress (April

1981).

63
current NSPS; conversely, the scrubbing costs of both Options n and IE

would be lower than under the current NSPS but higher than under Option L

Aside from Option I, Option IV would result in the lowest generating

cost for pollution control—2.62 mills per kilowatt-hour in 2000. At the

same time, Option IV would also achieve the lowest projected emissions

levels. The combination of low cost and high emissions control would occur

because many old sources would switch to low- or medium-sulfur coal as an

economical method for curbing emissions and reducing the burden of

emissions control at newer sources (through emissions trading). When the

older units used for emissions trading retired, however, the annual generating costs of Option IV might rise. Assuming normal plant retirement

rates, however, this rise would not likely occur until after the year 2010.

Other Cost Factors. The sensitivity of electricity costs to other

factors besides pollution control—notably fuel transport—is important. To

test this sensitivity, the CBO also examined the influence of continued real

increases in rail rates (in addition to the generic assumptions outlined in

Appendix B). In assessing Option I, the CBO assumed high rail rates; the

results showed that if rail rates rose an additional 15 to 25 percent in real

terms during the 1985-1990 period, the incremental (that is, real) cost to

electricity users in the year 2000 would be 5.34 mills per kilowatt-hour—up

128 percent over the present rate of 2.34 mills per kilowatt-hour and higher

than the rate resulting from either the current standards or from any other

option. Interestingly, the higher transportation costs could stimulate an

increase in the numbers of scrubbers built for new plants under Option I,

since high-sulfur coal use with scrubbing would become more economical in

many cases than shipping low-sulfur western coal to the Midwest.

Coal Consumption and Production

Because of the long lead time that precedes a new coal-fired power

plant's becoming operational, effects associated with any emissions control

strategy initiated today would not be observable until the mid- to late1990s. Accordingly, coal-market effects in the year 2000 would best

indicate the influence of standards enacted now as alternatives to the

current law 1978 NSPS.

Coal Consumption. Coal consumption by electric utilities generally

determines the production patterns of all U.S. coals. Under each of the

options analyzed here, as well as under current law, total coal consumption

by the utilities is seen to be divided roughly between the western and

eastern halves of the country in the year 2000. The West South Central

64
region (see Figure 7 in Chapter V) would experience the highest growth in

total consumption, from 43 million tons per year in 1979 to between 254

million tons under Option I to 275 million tons under current law (see Table

10). These figures delineate the upper and lower bounds of growth projected

for that region. This pattern is consistent with the region's expected high

growth in coal-fired capacity (see also Table 5 in Chapter V). The

interregional differences in total coal consumption primarily reflect small

variations in capacity use and "energy penalties" associated with scrubbing;

thus, the current NSPS, in requiring scrubbers on all new coal-fired plants,

show the highest forecast of total coal consumption. 8/

Although overall coal consumption is not significantly influenced: by

standards, the quantity of low-sulfur coal used is affected. For example,

because Option I would have a more lenient control standard than the other

options and would not mandate scrubbers, most utilities subject to this

standard would choose to burn low-sulfur coal; in the year 2000, more than

half of all coal consumed by utilities would be low-sulfur coal (see Table

10). 9/ At the opposite extreme, the current NSPS, by requiring scrubbers,

would discourage consumption of low-sulfur coal where it was not locally

producedc In the year 2000 under the current NSPS, only 40 percent of the

coal consumed by utilities would have a low sulfur content, reflecting less

eastern and midwestern consumption of low-sulfur coal than would occur

under Option I. Options IE and m, by permitting compliance with emissions

floors, would also spur the consumption of low-sulfur coal, though to a lesser

extent than Option I. Similarly, Option IV, by promoting emissions trading,

would increase low-sulfur coal consumption, since that fuel could be used in

both new and old facilities to achieve relatively inexpensive emissions

reductions.

Coal Production. Where coal is produced and how production is

affected by different emissions standards are other important questions.

Regardless of which of the options examined here were chosen, the western

states would experience the highest growth in coal production over the next

two decades. The major reason for this is not so much the amount of

8. The use of scrubbers requires power, which must be supplied by the

utility. Thus, the greater amount of scrubbing employed, the more coal

consumed to meet overall electricity demand. (See Appendix B on

scrubber assumptions.)

9- For the purposes of this discussion, low-sulfur coal is assumed to

produce less than 1.2 pounds sulfur dioxide per million BTUs.

65
TABLE 10. UTILITY COAL CONSUMPTION IN 1979 AND PROJECTED FOR

THE YEAR 2000, BY REGION (In millions of tons per year)

Region

Baseline

Consumption

(1979) a/

Current Standards

Total Percent

Con- Lowsumption sulfur

Option I

Total Percent

Con- Lowsumption sulfur

East 208

East North Central 160

East South Central 72

West North Central 74

West South Central 43

West (Mountain

290

241

88

134

275

41

21

21

33

49

291

243

90

128

254

48

35

28

46

79

and Pacific)

Total

62

619

146

1,174

47

40

146

1,152

67

51

(continued)

NOTE: Boundaries of regions displayed in Figure 7.

a/ Percent of total 1979 low-sulfur coal consumption is not available.

eastern and midwestern demand for western coal arising from each option,

as it is the expected high growth in western coal-burning capacity. Beyond

the West's high projected use of local coal supplies, the choice of emissions

standards can, however, influence the West's share of the eastern markets.

The Midwest, with its deposits of high- and moderate-sulfur-content coal, is

the area most vulnerable to standards that encourage consumption of lowsulfur coal.

Continuation of the current standards, which, by design, should mitigate

the economic advantage of low-sulfur coal as a means to control emissions,

would result in relatively high production forecasts for the Midwest (a 92

percent growth in production by the year 2000) and the lowest projected

eastward shipment of western coal (127 million tons). In contrast, Option I

66
TABLE 10. (Continued)

Option

Total Percent

Con- Lowsumption sulfur

Option

Total Percent

Con- Lowsumption sulfur

Option IV

Total Percent

Con- Lowsumption sulfur

290

242

89

130

260

48

34

28

47

76

292

242

88

128

263

37

31

18

39

74

290

242

89

132

268

46

20

24

36

57

149

1,160

65

50

146

1,159

59

44

149

1,146

55

42

SOURCE: Baseline 1979 consumption from U.S. Department of Energy,

Bituminous and Subbituminous Coal and Lignite Distribution,

Calendar Year 1979 (April 21, 1980).

would encourage the use of low-sulfur coal; this choice would reduce the

expected growth rate in midwestern coal production to 76 percent and raise

the quantity of low-sulfur western coal shipped east to an annual 151 million

tons by the year 2000 (see Table 11). (This amount would be higher were it

not for the large quantity of low-sulfur coal available from Northern and

Central Appalachian mines—see Table 12.)

Both western production and eastward shipment would rise as a result

of policies that put a premium on coal with a sulfur content below 1.2

pounds sulfur dioxide per million BTUs—coal that, despite Central Appalachian reserves, is not abundant in the East. Thus, Option n would foster the

eastward movement of large quantities (164 million tons in 2000) of western

coal; such transported coal would help users to meet this option's floor of

67
0.8 pounds sulfur dioxide per million BTUs without scrubbing (see Table 10).

As a result of lowering the floor to 0.6 pounds sulfur dioxide per million

BTUs, as in Option m, however, the supply of coal usable without scrubbing

would become limited primarily to that mined in the Rocky Mountain and

Western Northern Great Plains regions. This would restrict the total

eastward import of western coal to an annual 145 million tons in the year

2000. Furthermore, the limited availability of western coal that can meet

the standard of Option HI without scrubbing, plus the costs of transport, and

the emissions floor requiring no further control would all tend to encourage

the use of local high-sulfur coal in the Midwest. The result would lead to

production levels in the Midwest similar to those encouraged by the current

standards (see Table 11). 10/

Compared to the current standards, Option IV would increase western

coal production but would not give rise to so high a demand for low-sulfur

coal as the other alternatives (see Table 12), since medium-sulfur coal would

often supplant high-sulfur coal. High-sulfur coal production in the Midwest

would be lower than under the current standards but somewhat higher than

under Option I. This small increase could be expected to result from greater

use of existing plants with scrubbers and from emissions trading in some

areas that allow a few plants to burn high-sulfur coal without scrubbers.

(This latter situation might not be desirable, and an emissions ceiling for

new sources could be used to prevent it; such a ceiling was not included in

these estimates.)

Substitution of medium- for high-sulfur coal (not shown in the tables)

also would be high under Option IV, since this approach would allow utilities

to meet acceptable emissions limits at nominal expense; burning mediumsulfur fuel would remain appreciably cheaper than resorting to scrubbers.

Use of low-sulfur coal, however, would remain the chief strategy to reduce

emissions under Option IV, and demand for western coal for eastern utilities

10. Because most midwestern coal is surface-mined and hence cheaper than

most Appalachian coal, which is deep mined, some Appalachian coal

production would be displaced by midwestern coal. This would allow

midwestern coal production levels in Option in to remain as high as

under current standards, even though more western coal actually would

be shipped eastward. Without the very low emissions floor of Option HI,

however, the cost to eastern users of purchasing and scrubbing a

midwestern coal would be higher than buying a low-sulfur coal from

nearby Appalachia (coal that must be scrubbed even to meet very low

emissions floor), and midwestern coal production levels would fall.

68
would rise to 149 million tons per year—higher than under the current

standards but lower than all others except Option m.

Sensitivity to Flue Gas Desulfurization and Other Cost Assumptions,

To whatever extent that the costs of flue gas desulfurization technology

drop, the demand for low-sulfur coal would also fall. This effect would be

particularly pronounced under any alternative standards that emphasize

scrubbers or any similar sulfur dioxide control method. On the other hand,

if the cost of using low-sulfur coal increased, scrubber capacity also would

rise. For example, the amount of low-sulfur coal shipped east is affected by

rail costs; if rail rates are assumed to rise 15 to 25 percent between 1985

and 1990 (as stated earlier, under modified assumptions for Option I), only

94.3 million tons of western coal would be shipped east in the year 2000.

This is a reduction of almost 57 million tons from that originally predicted

for the same alternative. The high rail rates would force eastern and

midwestern coal users to turn to the higher-priced but nearer low-sulfur

Appalachian coal and to use scrubbers, so that cheap local high- and

medium-sulfur coals could be burnt while meeting a standard of 1.2 pounds

sulfur dioxide per million BTUs. In this respect, increased rail costs alone

would be responsible for greater shifts in coal production and distribution

than would be the expected changes resulting from any of the emissions

control alternatives considered.

CONCLUSIONS FROM THE ANALYSIS

The CBO projections suggest that alternative emissions standards for

new electricity sources can yield nominally different levels of sulfur dioxide

emissions at widely divergent costs. Adopting Option I—that is, reverting

to the NSPS of 1971—would be the least effective in controlling new emissions, resulting in 22.8 million tons of sulfur dioxide from utilities by the

year 2000. In comparison, the current NSPS are projected to achieve sulfur

dioxide emissions levels 8 percent lower, but at an average cost of $2,411

for each ton of sulfur dioxide eliminated. The two alternatives with

emissions floors, Options n and ID, each would entail significantly lower

capital costs than the current NSPS, but neither would be highly cost

effective in reducing emissions. Option H would lower emissions by 3

percent from the previous NSPS at a cost of $1,929 per ton of sulfur dioxide

removed, while Option in would lower emissions by 4 percent, but at a cost

of $3,400 per ton. Finally, Option IV, with its emissions trading feature,

would achieve the same quite high degree of emissions control as the

current 1978 standards do, but at an average cost of only $550 for each ton

of sulfur dioxide reduced beyond the levels forecast for Option I.

69
TABLE 11. REGIONAL COAL PRODUCTION FOR THE YEAR 2000

UNDER EACH ALTERNATIVE (In millions of tons per yea*

and percent increase over base year)

Base Year Current Standards

Production Pro- Percent

Region (1979) duction Increase

Northern Appalachia

Central Appalachia

Southern Appalachia

Midwest

Central West

Gulf

Eastern Northern

Great Plains

Western Northern

Great Plains

Rocky Mountains

Southwest

Northwest

and Alaska

Total

187

213

24

131

13

26

14

104

27

25

5

769 1

Total Western Coal Consumed

by Eastern Utilities 22 a/

331

342

21

252

17

119

44

383

183

142

33

,866

127

77

61

-13

92

31

358

214

268

578

468

560

143

477

Option I

Production

316

359

21

231

19

82

44

409

199

131

32

1,843

151

Percent

Increase

69

69

-13

76

46

215

214

293

637

424

540

140

586

(continued)

a/ See U.S. Department of Energy, Bituminous Coal and Lignite

tion, Calendar Years 1978 and 1979 (December 21, 1979 and

DistribuApril 21,

1980).

70
TABLE 11. (Continued)

Option

Production

312

350

20

234

16

94

45

401

216

132

32

1,852

164

n

Percent

Increase

67

64

-17

79

23

262

221

286

700

428

560

141

645

Option m

Production

302

356

20

254

15

87

45

385

231

126

32

1,853

145

Percent

Increase

61

67

-17

94

15

235

221

270

756

404

540

141

559

Option IV

Production

314

354

20

239

16

112

45

402

180

148

33

1,862

149

Percent

Increase

68

66

-17

82

23

331

221

287

567

492

560

142

577

SOURCE: CBO/ICF analysis.

71
TABLE 12. ESTIMATED LOW SULFUR COAL PRODUCTION IN 2000,

BY REGION (In millions of tons per year)

Region

Northern Appalachia

Central Appalachia

Southern Appalachia

Midwest

Central West

Gulf

Eastern Northern

Great Plains

Western Northern

Great Plains

Rocky Mountains

Southwest

Northwest/ Alaska

Total

Current

NSPS

20.8

203.7

3.4

0.5

5.1

None

1.4

214.0

122.7

79.7

21.4

672.7

Option I

24.1

224.9

3.4

0.4

6.1

None

1.4

268.0

138.7

84.3

21.4

771.3

Option H

37.1

207.9

2.9

0.5

4.7

None

1.4

265.4

161.2

85.3

21.4

787.8

Option HI

31.8

217.7

2.9

0

4.4

None

1.8

247.0

180.4

77.5

21.4

784.9

Option IV

29.2

206.7

3.4

0.5

5.0

None

1.4

245.3

124.7

82.4

21.4

720.0

SOURCE: CBO/ICF analysis.

NOTE: Figures on base year production not available.

The low cost per ton of Option IV highlights two important points:

o Emissions from older sources not covered by any emissions

standards will dominate national emissions through the year 2000

and beyond—hence the rather narrow margin within which

emissions abatement projections fall; and

72
o The least costly control measures now available are those that

involve substituting lower-sulfur coals at existing sources now

using high-sulfur coals.

With regard to effects on the utilities' financial requirements, the

results indicate that the current NSPS are the most capital-intensive choice;

they also entail the highest annual costs because of fixed and variable

charges associated with scrubbers. Options n and in, with their greater

reliance on low-sulfur coal as a means to achieve emissions control, would

result in lower capital requirements; they also involve generally lower

annual costs, although utilities would remain vulnerable to fuel and transport cost escalations. Control levels equivalent to the current NSPS could

be achieved by Option IV, and at a significantly lower cost; the burden of

control would be more evenly distributed among new and older facilities.

In light of the current costs of control technology and the abundance

of low-sulfur western coal, emissions standards for new sources can alter

traditional patterns of coal supply and demand. In particular, limiting sulfur

dioxide emissions without requiring scrubbers for all coal types, as under

Option I, would tend to increase the market share that low-sulfur coal holds.

That, in turn, could raise the volume of shipments of western coal to the

Midwest and East, as eastern low-sulfur coal costs rise and supplies in

certain instances shrink. Nothing short of a mandatory scrubbing, as under

current standards, could slow—and only slow—this eastward penetration.

Both Options n and HI, by eliminating scrubbing for only some coals (those

found mostly in the West), would also raise the amount of western coal

shipped East* No matter what emissions standard are in force, midwestern

and some eastern coal production would remain vulnerable to the lower cost

and rapidly growing production of western coal. Mitigating circumstances

that would help encourage coal production in the East, and in particular, the

Midwest, are higher-than-expected rail rates over the next two decades and

significantly lower costs than anticipated for flue gas desulfurization

technology. The latter would entail technological breakthroughs or improvements now being studied but not yet foreseen.

Finally, the analysis points to some difficult choices for the Congress

in assigning priorities, since minimizing sulfur dioxide emissions, utility

costs, and losses in midwestern coal production cannot all be done simultaneously. To hold emissions to their lowest levels and protect midwestern

coal production, the current standards are the best choice. If, however,

reducing the capital burden on utilities is given equally high priority, then

Option HI—which lowers capital needs by roughly half, raises emissions only

slightly, and yields relatively high midwestern production forecasts—

becomes a more preferable choice. If both emissions control and cost are

73
high priorities, but safeguards for midwestern coal production are not, then

the best alternative is Option IV. Finally, if cost is the chief concern, then

Options I and n, which would promote the use of low-sulfur coal though

allowing greater emissions growth than the current standards, are the most

suitable policy choices*

74
APPENDIXES

APPENDIX A. EFFECTS OF THE PSD PROGRAM

The CBO analysis of the Clean Air Act's potential influence on the

electric utilities includes assumptions about the effects of "prevention of

significant deterioration" (PSD) provisions. Though probably smaller than

the effects of the new source performance standards, and difficult to

quantify separately from them, the effects of the PSD provisions are still of

interest. The following analysis reviews the estimated influence of the PSD

program on emissions, power plant siting, and construction schedules. Only

the effects of the PSD program on emission limits were included in the

projections (see Appendix B), since other costs, such as administrative

requirements, are believed to be insignificant.

EFFECT ON EMISSIONS LIMITS

In a recent study, the National Commission on Air Quality has

concluded that the case-by-case "best available control technology" review

process under the PSD program has often resulted in emission limitations

stricter than would have been required by NSPS or state implementation

plans. \J According to the commission, all PSD permits issued between

April 1978 and November 1979 showed that nine out of 16 permits issued for

power plants during that period contained control requirements significantly

more stringent than the NSPS. These tighter requirements will lead to ZO

percent reductions in sulfur dioxide emissions and 25 percent reductions in

participate emissions beyond levels allowed under the NSPS. (The means of

compliance for these facilities is unknown, but it probably will often involve

additional scrubbing or lower-sulfur fuel.) Because these control levels were

established before 1979, however, much of their cost to the industry should

be captured in the analyses in Chapter II.

Because the current NSPS require such a high degree of control,

situations in which the PSD regulations result in significant additional

emissions control should be rare. The exceptions concern possible requirements of up to 90 percent control on sulfur dioxide emissions for plants

burning low-sulfur coal, rather than the requisite 70 percent. This situation

1. See National Commission on Air Quality, To Breathe Clean Air, Final

Report (March 1981).

77
could occur in areas desiring to limit emissions further and protect air

quality; examples may be Wyoming and New Mexico, which already require

more than 70 percent control on some power plants firing low-sulfur coal.

No evidence suggests, however, that BACT levels stricter than NSPS will be

established with any frequency in the future for most regions.

EFFECTS ON POWER PLANT SITING

An important concern is whether the Clean Air Act imposes noneconomic, institutional constraints on the construction of new generating

capacity. Compliance with both PSD regulations and national ambient air

quality standards can pose operational limitations on a power plant at a

particular site. Such limitations can restrict how much capacity can be

built in certain areas.

The EPA reports that both the 1971 and revised 1978 NSPS for utilities

allow a 1,000-megawatt coal-fired boiler to operate in a Class n PSD area,

assuming no appreciable background concentrations or other sources nearby,

and relatively flat terrain. 2/ Under these conditions, one large plant

complying with the 1971 NSPS would leave little if any 24-hour PSD

increment (see Table 2 in Chapter n), while the same plant complying with

the 1978 revised NSPS would consume approximately half of the 24-hour

increment, usually the most limiting standard. Compliance with either

emissions standard would not allow a facility of this size to be located either

in or near a Class I area. Thus, in certain circumstances, such as where the

terrain is mountainous, contains Class I areas, and other nearby sources,

compliance with NSPS might not be sufficient to protect the Class n

increments, and further emissions control or moving to another site might

be necessary. If emissions control proved too costly, or if an alternate site

were not available, the new plant would not be built.

Both the national commission and the National Academy of Sciences

report that the major constraints on power plant siting from PSD regulations

involve the presence of "complex11 (mountainous) terrain and Class I areas

near or surrounding the potential site. 3/ In the West, Class I areas

2. Terrain that is not flat tends to confine and thus concentrate pollutant

emissions.

3. See National Commission on Air Quality, To Breathe Clean Air, and

National Academy of Siences, On Prevention of Significant Deterioration of Air Quality, National Academy Press (1981).

78
(National Parks and certain national monuments) represent the greatest

potential constraint, at times perhaps limiting development within a 100-

kilometer radius. In the East, Class n areas and the presence of other

sources of pollutants pose the greatest potential for siting constraints. Both

the commission and national academy also conclude that such constraints

are specific to certain sites and are difficult to quantify generically;

moreover, they point out that other legislation besides the Clean Air Act

severely restricts development in many Class I areas, thus making it

difficult to assign growth limitations in Class I areas to the Clean Air Act

alone. Finally, alternative sites are usually available, thus allowing a plant

to be built somewhere. Much less certain is the incremental cost of

relocating a power plant early in its planning process.

Only two applications for PSD permits have been denied, both involving permits for coal-fired power plants near Class I areas. After

submission of additional information, one was approved with minor modification. The other power plant eventually received a permit after adopting

more stringent controls to reduce total sulfur dioxide emissions by 95

percent. The actual incremental cost of achieving this additional control is

unknown.

EFFECTS ON CONSTRUCTION SCHEDULES AND RESULTING COSTS

Between 1970 and 1980, average power plant construction times

increased from four to seven years. The reasons most often cited involve

the numerous operating licenses and permits required by various laws

enacted over the last decade. The Clean Air Act is responsible for one of

the more complex permit processes, and thus it is a suspected contributor to

protracted construction schedules.

The PSD regulations entail certain explicit and implicit time-consuming tasks. Strictly interpreted, the regulations can require one-year's air

quality monitoring data for the permit application. Time is also taken up in

developing permit submissions, probably six months. In addition, the

reviewing agency is then allowed one year either to approve or reject the

permit application. Thus, assuming the permit is approved, up to 30 months

can elapse before construction begins.

In practice, the time necessary to obtain a PSD permit varies widely,

but it is usually less than 30 months. Table A-l shows the time spent in the

various stages of obtaining a permit, based on a survey of PSD permits

issued according to the requirements of the Clean Air Act's 1977 amendments. Before embarking on the early stages of the permit process, a utility

79
TABLE A.I PROCESSING TIME SPENT FOR NEW SOURCES

BEFORE AND DURING PSD REVIEW

Median Number 90th 95th

Process Sequence of Days Percentile a/ Percentile a/

Initial Contact

to Initial Submission

Initial to Final

Submission

Final Submission

to Permit Issue

Initial Submission

to Permit Issue

Initial Contact

to Permit Issue

42

57

157

271

333

440

298

323

463

612

487

319

328

528

634

SOURCE: See Dames and Moore, "An Investigation of Prevention of

Significant Deterioration (PSD) and Emission Offset Permitting

Processes," prepared for National Commission on Air Quality

(Revised December 1980).

a/ Upper quartiles; 90 percent and 95 percent of permits were processed in

these numbers of days or fewer.

applicant typically contacts the agency to determine whether monitoring is

required, and if so, how much and what control requirements may be

imposed. If the critical permit stages, including monitoring, are assumed to

occur between initial contact and permit issuance, then it is clear that total

processing time is usually completed within a year, although delays of up to

two years can occur in rare instances.

The reasons for the relatively shortened time needed to obtain a

permit compared to what theoretically can elapse probably involve the short

median time an agency spends on reviewing a final permit and determining

how much monitoring to require. The short processing time for final

permits is evidenced in Table A-l as usually consuming less than six months.

80
With regard to monitoring, the same study responsible for the data in the

table found that reviewing agencies required actual on-site monitoring data

for particulate matter and sulfur dioxide in only 17 and 15 percent of all

cases, respectively. In the other instances/ either monitoring was not

required, or existing state and local data collected by public agencies were

available and accepted.

With regard to the costs associated with increased lead times for

construction, it is important to distinguish between time requirements that

can be incorporated into the overall planning process and those that fall

outside of this schedule, thus resulting in delay. Table A-1 indicates that

the overall time required to obtain a PSD permit can cover one to two years

but more commonly involves one. If the one year usually required to obtain

a permit can be partially or totally absorbed within other planning requirements, such as selection of final design and equipment specifications prior

to construction, then delay is reduced to less than one year.

Table A-Z presents estimates of project cost increases for a six month,

12-month, 18-month, and 24-month delay in construction start-up. These

estimates include the costs associated with inflation as well as those

associated with extended use of obsolete capacity (identified in the table as

energy replacement), in this case, a 500-megawatt oil-fired plant.

TABLE A-2. ESTIMATED COSTS OF DELAYS IN CONSTRUCTION

START-UP OF A NEW 500-MEGAWATT COAL-FIRED

POWER PLANT (In millions of dollars)

Six-Month

Delay

Energy Replacement 4.3

Inflation 25 «0

Total 29 o 3

12-Month 18-Month 24-Month

Delay Delay Delay

8.6 13.0 17.4

50.0 78.0 104.0

58.6 91.0 121.4

SOURCE: Congressional Budget Office.

81
The average increase in normal project lead-time associated with the

Clean Air Act is estimated to be six months, which translates into some

$29*3 million for the example given in Table A-2. This estimate assumes

that approximately one year of permit preparation and review is necessary,

of which half falls outside the normal planning schedule necessary for

project start-up. Adding the costs of a full monitoring network for sulfur

dioxide, nitrogen oxide, and particulate emissions, and necessary air quality

analysis costs for developing a permit (a total cost of approximately

$140,000) results in a possible total cost increase of $29.4 million for the

example given. For comparison, CBO estimated that a change in the

interest rate or weighted cost of capital from 10 to 11 percent could result

in a total project cost increase of $101 million.

82
APPENDIX B. ANALYTICAL ASSUMPTIONS AND METHODOLOGY

To arrive at forecasts of pollutant emissions, changes in capital and

annual costs, and coal market effects, the CBO used a detailed linear

programming model developed by ICF, Incorporated. The key assumptions,

including scrubber costs, were supplied by CBO for use in the simulations. A

review of the assumptions and methodology used follows.

DESCRIPTION OF ASSUMPTIONS

Table B.7, at the end of this appendix, defines the major assumptions

used in the modeling effort. Tables B.I through B.4 present the estimated

costs used in the analysis of scrubbers for different coal types. These costs

are based on a recent Tennessee Valley Authority study, Technical Review

of Dry FGD Systems and Economic Evaluation of Spray Dryer FGD Systems

(EPA-600/7-81-014) and the information contained in EPA Utility FGD

Survey; October-December 1980, (EPA-600/7-81-021a). The costs of the

basic units include all equipment and materials needed to transfer the flue

gas from the boiler to the stack, as well as collection and disposal of sludge

and fly ash residues. The estimates in the tables also reflect a small

expected increase in the real costs of equipment and operation between

1980 and 1985, the starting point used for the simulations. Table B.5

displays estimated costs of upgrading participate control equipment necessary when switching from high-sulfur to low-sulfur coal, as simulated for

computation for Option IV.

The costs presented in these tables give rough approximations of the

cost-penalty involved; only a case-by-case analysis of actual fuel-switching

situations could provide an accurate estimate. Such information was not

available for this report.

METHODOLOGY

The effects of the assumptions and alternative standards were estimated using the ICF Coal and Electric Utilities Model flCF/CEUM). The

model simulated key attributes of the coal and electric utility industries by

year and by region. For the coal industry, forecasts were made of coal

consumption by sector, production by mining method, supply prices, coal

83
TABLE B.I. CURRENT NSPS

Item

Annual Sulfur

Dioxide Limit

Design Control

Efficiency

Actual Control

Efficiency

Scrubber Type

Variable

(Coal Type in Pounds SO- Per Million BTUs Consumed)

Raw Coal

Delivered Coal

Coal to Scrubber

0.8

0.8

0.76

1.2

1.2

1.14

1.76

1.67

1.59

3.92

3.33

3.16

6.67

5.0

4.75

8.89

6.67

6.33

0.24 0.36 0.5 0.5 0.67

(Percent Pollutant Control)

70

68

Dry

70

68

Dry

70

69

Dry

90

84

Wet

90

86

Wet

0.89

90

86

Wet

Total Costs for SO- and

Particulate Control 144

Operation and

Maintenance Costs—

Fixed and Variable 2.15

(Dollars per Kilowatt)

145 146 228 231

(Mills per Kilowatt-Hour)

2.39 2.68 3.9 4.37

235

4.8

(Percent)

Capacity Penalty

Energy Penalty

1.52

2.36

1.54

2.38

1.58

2.42

2.23

3.47

2.45

3.85

2.61

4.01

SOURCE: Congressional Budget Office

NOTES: All costs based on a 500-megawatt power plant generating 5,500

hours per year. Amortized capital costs not included; all O&M

costs are first-year costs. Costs expressed in mid-1980 dollars.

84
TABLE B.2. OPTION I—EMISSIONS CAP OF 1.2 POUNDS OF SULFUR

DIOXIDE PER MILLION BTUs OF FUEL CONSUMED

Item

Annual Sulfur

Dioxide Limit

Design Control

Efficiency

Actual Control

Efficiency

Scrubber Type

Variable

(Coal Type in Pounds SO- Per Million BTUs Consumed)

Raw Coal

Delivered Coal

Coal to Scrubber

0.8

0.8

0.76

1.2

1.2

1.14

1.76

1.67

1.59

3.92

3.33

3.16

6.67

5.0

4.75

8.89

6.67

6.33

0.76 1.14 0.8 1.0 1.0

(Percent Pollutant Control)

0

0

NA

0 Part a/

0

NA

50

Dry

70

68

Dry

80

79

Wet

1.0

90

84

Wet

Total Costs for SO- and

Particulate Control 71

Operation and

Maintenance Costs—

Fixed and Variable 0.1

(Dollars per Kilowatt)

71 123 148 , 207

(Mills per Kilowatt-Hour)

0.1 1.77 3.64 4.2

235

4.8

(Percent)

Capacity Penalty

Energy Penalty

0

0

0

0

1.12

1.71

1.8 2.24

2.81 3.48

2.61

4.01

SOURCE: Congressional Budget Office

NOTES: All costs based on a 500-megawatt power plant generating 5,500

hours per year. Amortized capital costs not included; all O&M

costs are first-year costs. Costs expressed in mid-1980 dollars.

a/ "Part" indicates 70 percent control of portion of flue gas.

85
TABLE B*3* OPTION E-ACHIEVE 70 PERCENT EMISSIONS CONTROL

AND SET A 0.8 POUND FLOOR

Item

Annual Sulfur

Dioxide Limit

Design Control

Efficiency

Actual Control

Efficiency

Scrubber Type

Variable

(Coal Type in Pounds SO. Per Million BTUs Consumed)

Raw Coal

Delivered Coal

Coal to Scrubber

0.8

0.8

0.76

1.2

1.2

1.14

1.76

1.67

1.59

3.92

3.33

3.16

6.67

5.0

4.75

8.89

6.67

6.33

0.76 0.62 0.64 1.0 1.0

(Percent Pollutant Control)

Part a/ Part a/

0

NA

50

Dry

60

Dry

70

68

Dry

90

80

Wet

1.0

90

84

Wet

Total Costs for SO- and

Particulate Controf 71

Operation and

Maintenance Costs—

Fixed and Variable 0.1

(Dollars per Kilowatt)

119 134 148 231 235

(Mills per Kilowatt-Hour)

1.32 2.15 3.64 4.22 4.8

(Percent)

Capacity Penalty

Energy Penalty

0

0

1.04

1.61

1.37

2.1

1.81

2.81

2.45

3.58

2.61

4.01

SOURCE: Congressional Budget Office

NOTES: All costs based on a 500-megawatt power plant generating 5,500

hours per year. Amortized capital costs not included; all O&M

costs are first-year costs. Costs expressed in mid-1980 dollars.

a/ "Part" indicates 70 percent control of portion of flue gas.

86
TABLE B.4. OPTION m— ACHIEVE 90 PERCENT EMISSIONS CONTROL

AND SET A 0.6 POUND FLOOR

Item

Annual Sulfur

Dioxide Limit

Design Control

Efficiency

Actual Control

Efficiency

Scrubber Type

Variable

Raw Coal

Delivered Coal

Coal to Scrubber

(Coal Type in Pounds SO~ Per Million BTUs Consumed)

0.6 1.2 1.76 3.92 6.67 8.89

0.6 1.2 1.67 3.33 5.0 6.67

0.57 1.14 1.59 3.16 4.75 6.33

0.54 0.50 0.50 0.50 0.67

(Percent Pollutant Control)

0

NA

70

58

Dry

70

70

Dry

90

85

Wet

90

86

Wet

0.89

90

86

Wet

Total Costs for SO- and

Particulate Control 71

Operation and

Maintenance Costs—

Fixed and Variable 0.10

(Dollars per Kilowatt)

145 146 228 231 235

(Mills per Kilowatt-Hour)

2.22 2.69 3.9 4.37 4.8

Capacity Penalty

Energy Penalty

0 1.54

0 2.22

(Percent)

1.58 2.23

2.43 3.50

2.45

3.85

2.61

4.01

SOURCE: Congressional Budget Office

NOTES: All costs based on a 500-megawatt power plant generating 5,500

hours per year. Amortized capital costs not included; all O&M

costs are first-year costs. Costs expressed in mid-1980 dollars.

87
TABLE B.5. ESTIMATED COST PENALTIES IN OPTION IV ASSOCIATED

WITH FUEL SWITCHING (Per kilowatt of capacity)

Initial Coal

by Pounds S

Per Million

BTUs 0.8 1.2 1.76 3.92 6.67 8.89

by Pounds SO~ New Coal Types by Pounds SO- Per Million BTUs Consumed

Per Million

0.8

1.2

1.76

3.92

6.67

8.89

X

20

30

60

60

60

X

X

20

30

60

60

X

X

X

20

30

60

X

X

X

X

20

30

X

X

X

X

X

20

X

X

X

X

X

X

SOURCE: Congressional Budget Office.

NOTE: No scrubbers are assumed to figure in this estimate.

distribution, and transportation costs by mode. For the electric utility

industry, forecasts were made of generation, changes in emissions, fuel use

(including coal by type), and changes in costs for capital, fuel, operation and

maintenance, and pollution control for alternative standards.

The model generates a least-cost equilibrium solution using a standard

linear programming formulation, which simultaneously balances supply and

demand requirements for each region of the United States. This equilibrium

solution reflects a wide variety of conditions affecting both the coal and

electric utility industries, including both governmental policies and nongovernmental factors. The results are summarized regionally in terms of

production, consumption, and prices for coal for utilities. These provide the

basis for estimating other impacts, such as capital requirements and

environmental effects.

The CEUM links the coal and electric utilities industries. The electric

utility sector in the model is structured in such a way as to minimize total

88
generation and distribution costs. The model forecasts economic capacity

expansion and dispatch. The model can operate existing capacity of various

plant types and/or build new capacity. Further, it can operate capacity in

any of four local categories—base, cycling, seasonal peaking, and daily

peaking. It is designed to build and operate capacity of various plant types

in the various load categories such that the total of fuel, capital, and

operations costs is minimized.

Different pollution control regulations (for sulfur dioxide and other

pollutants) that apply to specific types of plants in different jurisdictions

are explicitly modeled. For older sources, actual state emission limitations

are used. For sources subject to NSPS, either the federal standards or

assumed PSD or state limit is used, whichever is lower (see Table B.6).

Hence, consumption of any one coal type depends on its price relative to

other coal types and other compliance alternatives. Rather than merely

minimizing delivered coal costs, the model minimizes the total costs of

generating and distributing electricity.

The current NSPS and all alternatives were simulated as follows. All

existing sources were assumed subject to the applicable state and local

standards contained in the State Implementation Plan (or PSD determination, if lower), and all new sources were subject to the alternative federal

emissions standards being examined, except when those would be superseded

by more stringent state regulations in effect as of 1980. Option IV was

modeled similarly, except that new sources were permitted to increase

emissions above current NSPS levels if equivalent reductions of sulfur

dioxide (beyond levels regulated by the SIP) were obtained at one or more

existing sources. In all cases, the least-cost solution for electricity

production was simulated.

Table B.7 outlines the assumptions used in the model simulation

analysis.

89
TABLE B.6. PREVENTION OF SIGNIFICANT DETERIORATION

ASSUMPTIONS FOR SPECIFIED STATES (In pounds of

sulfur dioxide per million BTUs consumed)

Montana

Wyoming

Colorado

New Mexico

Utah

Arizona

Nevada

North California

South California

State New Source

Emissions

Standards

1.20

0.20

0.40

0.34

0.12/1.20

0.80

1.20

0.13

0.13

Assumed Federal

PSD Emissions

Limit

1.20

0.20

0.20 a/

0.34

0.20 a/

0.20 a/

0.20 a/

0.13

0.13

SOURCE: Congressional Budget Office.

a/ Denotes states where assumed PSD limit is more stringent than

state standards.

90
TABLE B.7 MAJOR ASSUMPTIONS USED IN CBO/ICF ANALYSIS

Parameter Base Case Comment

Energy and Economic

Conditions

GNP (Percent per year

real growth

1980 - 1985 = 2.9

1985 - 2000 = 3.0

Modified from recent CBO economic forecasts.

World Oil Prices

(1980 dollars)

Natural Gas Prices

and Availability

Electric Utility

Energy Demand

Electricity Growth Rate

(Percent per year)

Nuclear Capacity

Substitution of Coal

for Oil and Gas

1985 = 37.29

1990 =41.17

1995 = 45.46

2000 = 50.19

As estimated by ICF

Gas Models

1979 - 1985 = 3.2

1985 - 1990 = 2.7

1990 - 1995 = 2.7

1995 - 2000 = 2.7

1985 = 78

1990 = 121

1995 = 141

2000 = 175

Reconversions assumed

and accelerated replacement allowed but deterred

by capital cost penalty

and state limits.

Higher oil prices encourage the substitution of coal

for oil by electric utilities, within assumed financial

and institutional constraints. Estimates of future

oil prices assume a 2 percent per year real escalation

in price, which is based on recent CBO forecasts.

Growth rates for electricity are expected to remain

well below pre-1980 historical averages. This is consistent

with Wharton Economic Forecasting Assumptions

(WEFA) and ICF analysis of the electricity markets

Since coal is a substitute for nuclear power in generating

electric power, variation in nuclear capacity levels

leads to variations in national coal production forecasts.

The estimates are based on a unit-by-unit review.

Current and projected oil and gas prices indicate

it is economic to substitute coal for oil and gas in

substantial proportions, but institutional and

financial constraints make this unlikely to occur.

In the base case, about 18 gigawatts of conversions are

assumed. The accelerated replacements of oil and

gas units with new coal units are inhibited by adding

capital cost penalty to the cost of a new coal unit

and by limiting the amount of new coal capacity in

key states—California, Texas, Louisiana, and Florida.

(continued)
TABLE B.7 (Continued)

Parameter Base Case Comment

Power plant and

Industrial Fuel Use Act

Utility Capital Costs

per kilowatt

(1980 dollars)

Non-Utility Coal Demand

Industrial Coal Use

(Per million tons)

Steam Coal Exports

(Per million tons)

Metallurgical Coal Use

(Millions of tons)

Export

Domestic

Coal = About 850

Nuclear = 1,020-1,254

Turbine = 223-235

1985 = 80

1990 = 117

1995 = 171

2000 = 225

1985 = 40

1990 = 84

1995 = 120

2000 = 196

1985 = 51

1990 = 56

1995 = 58

2000 = 60

1985 = 73

1990 =67

1995 = 66

The off-gas provision is not in effect, but the baseyear gas use rule remains in 1985 only with the

base year quantity defined as the maximum use

during 1970s. Oil and gas-fired combined cycle are

prohibited for new power plants.

Capital costs for new power plants are based on

the most recent (1979) technical data developed

by EPRI. They include a total real escalation of

12 percent between 1978 and 1985, as modified by CBO.

Based on recent ICF analysis.

Long-term estimates of export demands for steam

coal are based on recent ICF in-depth analysis of

the export markets.

Export demand for metallurgical coal is assumed to

decline from abnormally high levels in 1980, and then

increase only slightly. Metallurgical exports are

assumed to be primarily low-sulfur, high-Btu coals.

Domestic use of metallurgical coal is expected to

decline due to the sluggish growth of the U.S. steel

industry and continued process changes that reduce

the use of coke per ton of product.

(continued)
TABLE B.7 (Continued)

Parameter Base Case

Synfuels (Coal input in

millions of tons)

1985 = 7

1990 = 24

1995 =82

2000 = 139

Residential and Commercial

Coal Use

Financial Parameters

Inflation Rate

(Percent per year)

Discount Rates

(Percent per year)

1985 = 8

1990 = 9

1995 = 10

2000 = 11

1980 - 2000 = 8.0

Coal Mine = 14.48%

Utility = 12.61%

Coal Transport Rates—

Rail, Barge, and Truck

(Percent total real

escalation)

Mining Costs (Dollars

total real escalation)

Other

Federal Leasing Policy

1979 - 1985:

East = 25.0%

West = 25.0%

1980 - 2000:

Capital = 0.0%

Labor = 0.0%

Materials = 0.0%

Enough

Air Pollution Regulations Most recent federal

and state rules.

Comment

Estimated demand for coal-derived synfuels in 1985

has been reduced from earlier forecasts to reflect a

reduced government role in promoting commercial

synfuels production and a project-by-project assessment of announced plans.

Residential and commercial coal use is expected to

increase slowly. Residential and commercial demand is

assumed to be limited to low- and medium-sulfur coals.

The annual inflation rate is assumed to be 8 percent

per year, consistent with recent C.BO forecasts.

These nominal rates are based on a 6.0 percent

real rate for mining and a 4.27 percent real rate

for utilities.

Transportation rates are estimated to increase in real

terms through 1985 as allowed under the Staggers

Rail Act.

Capital, labor, and materials are assumed to remain

constant in real terms. Productivity increases are

assumed to offset any real cost escalation.

It is assumed that enough coal will be leased by 1985

and later to avoid artificially driving up market prices.

Controls on utility emissions of SO~, NO , and TSP are

subject where applicable to federal NSPsf revised NSPS

and PSD rules; or to state SIP rules if more stringent.

APPENDIX C. FINANCIAL EFFECTS OF DIFFERENT ACCOUNTING

METHODS FOR CONSTRUCTION WORK IN PROGRESS

Particular accounting methods used by the electric utilities can

influence the financial condition of the industry and the costs of producing

power. They can also affect the industry's costs to meet the Clean Air Act's

NSPS.

The most significant regulation pertaining to utility finances is the

state public utility commissions' treatment of "construction work in progress." In most instances! utilities may not earn returns on CWIP investments before their new facilities are fully operational. To account for the

lost revenue a firm incurs while a facility is being built, the state PUC

usually allows a utility to establish an "allowance for funds used during

construction" account. This account essentially represents the value of

total CWIP capitalized each year at a rate of return set by the commission.

The capitalized annual CWIP appears as income for accounting purposes, but

it is not realized as cash until the facility is service. When the facility does

begin operation, the capitalized AFUDC is added to the total investment,

forming the rate base. The rate base is then depreciated over the operating

life of the facility, with the utility earning an annual return on the

undepreciated portion. Although the utility is ultimately allowed to earn a

fair return on its construction costs, it must borrow or otherwise maintain

its cash flow in the interim.

Table C.I compares the finances of a new 500-megawatt plant under

three different accounting and pollution control hardware assumptions.

Each facility is assumed to have begun construction in 1980 with expected

start-up in 1987. The first facility includes a scrubber as part of the total

plant, and its rate base is calculated to include AFUDC. The second facility

also has a scrubber, but the utility is allowed to earn a return on its CWIP

investment before plant start-up. The third facility has no scrubber, and

similar to the first facility, its rate base includes AFUDC. The calculations

assume either all or none of the facility is subject to CWIP or AFUDC,

depending on the case.

Figure C.I shows the electricity cost curves for each plant over its

lifetime. Both plants using AFUDC in the rate base do not start charging

for electricity until the first year of operation. The plant using CWIP, on

the other hand, begins adding a small charge to existing electricity costs

during the years of construction. This added charge from passthrough of

95
TABLE C.I. FINANCIAL COMPARISON OF A NEW 500-MEGAWATT

POWER PLANT UNDER DIFFERENT ACCOUNTING AND

POLLUTION CONTROL HARDWARE ASSUMPTIONS

(In millions of dollars)

Plant and Plant with

Scrubber with Plant and Scrubber No Scrubber,

AFUDC withCWIP AFUDC

(In Rate Base) (In Rate Base) (In Rate Base) c/

Total Plant in

Rate Base Start-up

(nominal dollars) a/ 1,195 892 933

Total Interest

During Construction

(nominal dollars) a/ 303 124 229

Cost to Consumers

Over Life of Plant

(1980 dollars) b/ 86,542 64,394 68,020

SOURCE: Congressional Budget Office.

a/ Interest rate, AFUDC, and return on rate base calculated at 13.74

percent.

b/ Discount rate used was 10 percent over 25 years.

£/ Life cycle costs of this facility also include higher fuel cost for lowsulfur coal.

CWIP to existing electricity costs would result in high electricity rates

during the years preceeding plant start-up. As Table C.I shows, however,

both plants using AFUDC as an accounting procedure have larger rate bases,

higher interest costs, and greater electricity costs over the life of the plant

than the facility obtaining a return on CWIP, which is assumed to offset a

portion Q£ its annual investment during construction.

96
Figure 'Ct.

Projected Electricity Rates Under Different Accounting

Assumptions: 1980-2010

79

60

Rate for plant with scrubber with

allowance for funds used during construction

incorporated in rate base

Rate for

plant without scrubber

with allowance for funds

used during construction

incorporated in rate bast

Rate for plant

with scrubber

with costs of

construction

work in progress

- incorporated in

rate base

1980 1985 1990 2000 2005 2010

Years

SOURCE: Congressional Budget Office.

NOTE: Transmission and distribution rates not included.

It is important to note that the cost of AFUpC to a plant with a

scrubber is approximately equal to the cost of the scrubber itself. The

present v^lue difference in total investment (with interest) of the first two

plants shown in Table C.I is equivalent to $184 per kilowatt-hour. This cost

is approximately equal to a wet limestone scrubber without particulate

controls.

The reason AFUDC is employed as an accounting procedure primarily

involves the reluctance of state PUCs to force present consumers to

subsidize the rates of future consumers. Though over the long term,

utilities and ratepayers enjoy lower costs when CWIP is incorporated in the

rate bases, the prospect of yearly rises in electricity rates before a plant's

start-up remains an unattractive option to most PUCs.

A recent survey reveals that many states allow some CWIP in the rate

base, but such treatment is not uniform, and the average amount allowed is

only approximately 20 percent. \J In the survey, 44 state PUCs, accounting

I/ General Accounting Office, "Construction Work in Progress Issue

Needs Improved Regulatory Response for Utilities and Consumers"

(June 23, 1980).

97
for $38 billion out of the $42.5 billion of total CWIP in 1978, provided

information on their treatment of CWIP. In these 44 states, 23.4 percent of

CWIP was allowed in the rate bases. The range of CWIP allowed in rate

bases nationwide was between 21 and 23 percent in 1978. This 21 to 23

percent figure may be misleading, since state PUCs often employ an

"AFUDC-offset" when CWIP is allowed in the rate base. This offset

essentially subtracts part of the real income generated by CWIP and

replaces it with AFUDC accounting income.

Although AFUDC represents only one accounting procedure that can

adversely affects the financial condition of a utility, it is perhaps the most

important one. As AFUDC increases as a percent of total revenues, the

quality of a utility's earnings diminishes. This reduction in the quality of

earnings is perceived negatively by the investment community, which, in

turn, becomes reluctant to continue lending, resulting in increased cost of

capital for utilities. A 1 percent rise in interest rates can add $25.6 million

to the total cost of a new 500-megawatt facility. Such potential costs and

those actually associated with financing a utility subject to AFUDC largely

overshadow the cost of most air pollution controls.

o '

98