Acid rain control and United States energy policy

.Energv Vol. 9, No. I I-I.?, Printed in the U.S.A.

pp. 1049-1063,

03&l-SW/84 13.00 + .oo Pergamon Press Ltd.

1984

ACID RAIN CONTROL ENERGY

AND UNITED POLICY

STATES

DAVID G. STREETS Energy and Environmental Systems Division, Argonne National Laboratory, 9700 South Cass Avenue, Argonne, IL 60439, U.S.A. (Received 18 July 1984) Abstract-The U.S. Congress is currently considering whether to legislate a control program to reduce the perceived effects of acid rain. The effects of such a program would be costly, wideranging and would have important implications for the development of U.S. energy policy over the next several decades. The proposals call for reductions of between 30 and 50% in emissionsof SO* in the eastern U.S. Costs of achieving these reductions are es$mated to be in the range of $4I2 billion annually over the next 20 yr or so. In addition to the obvious economic impacts, there will be major energy implications, arising from shifts in the patterns of U.S. coal production and consumption; coal resource, transportation and employment effects; electricity price increases; changes in electric utility system mix; effects on manufacturing industries; and penetration of innovative energy technology. The anticipated effects of acid rain control programs in these areas are discussed, together with creative new ways to address the acid rain issue, including targeted control strategies, emissions bubbling and early retirement.

INTRODUCTION

Proposals being considered by the U.S. Congress to control acid rain represent some of the most significant pieces of environmental legislation ever initiated. The effects of a control program would be costly and wide-ranging and would have important implications for the development of U.S. energy policy over the next several decades. It is the purpose of this paper to highlight the energy issues embodied in the acid rain debate. The problems facing Congress in regard to acid rain are rooted in scientific uncertainty and the absence of clear culpability. Although we have some feeling for the nature of the acid rain problem, we simply do not have enough scientific evidence to state clearly the causes of the damage that has been observed, the mechanisms of damage, the extent of damage, or the risks to sensitive ecosystems now and in the future. This uncertainty is primarily caused by the fact that observed effects are the result of low levels of exposure over long time periods in the presence of other confounding influences. Reliable, longterm monitoring data are inadequate, and theoretical modeling techniques are rudimentary. For these reasons, Congress established’ an Acid Precipitation Task Force and a IO-year research program “to identify the causes and effects of acid precipitation”. A second and equal objective of the program is to “identify actions to limit or ameliorate the harmful effects of acid precipitation”. This leads to the second major problem: lack of clear culpability. We know that emissions of sulfur dioxide and nitrogen oxides from major stationary sources are largely responsible for the acidity of rain in the eastern U.S., but we are uncertain about the roles of other pollutants (oxidants, primarily) and of other sources (transportation, natural sources, etc.). Table 1 shows the magnitude of sulfur dioxide and nitrogen oxides emissions from the major source categories in the eastern and western United States. However, unlike the situation with local air pollution and most other environmental problems, we cannot identify specific sources as being responsible for observed damage. Source-specific tracer experiments are infeasible at present, and no theoretical model is sufficiently accurate (nor can be in the face of meteorological variability) to determine a general source/receptor relationship. We are left, therefore, with a regional-scale problem, in which each of many different sources contributes to acidic deposition at a particular site. This fact causes unprecedented difficulties for Congress to design a control program within the framework of the Clean Air Act, a piece of legislation aimed at identifying 1049

DAVID G. STREETS

1050

Table I. Summary of 1980 emissions of the two major acid rain precursors by source category and region. Source: “Development of the NAPAP Emission Inventory for the 1980 Base Year”, Engineering-Science report for U.S. EPA (June 1984). so emissions (183 tone/yr)

NO Emissions (Ia3 tone/yr)

source Category

Electric

utilities

Non-utility combustion Non-ferrous

Easta

West

Tocal

Easta

West

Total

16,070

1,260

17,320

5.870

2,250

8,120

3,760

820

4,580

2,420

2,770

5,190

1,110

1,220

110

0

0

0

amelrers 550

Transportation Other

sources

Tocal

Total8 may aEaatern

not

31-stare

add due to

region

320

870

1,820

1,290

3,110

22,310

6,800

27,110

independent

6,100 670 15,060

3,000 590 8,610

9,100 1,270 23,670

rounding.

and the Dfsmict

of

Columbia.

and controlling specific sources responsible for local air pollution problems. Twenty-three bills have been introduced (as of 1 November 1984) into the 98th Congress in attempts to wrestle with this complex issue. These are listed in Table 2. The majority of the bills take a broad approach to reducing SO2 emissions, defining an acceptable emission rate (usually 1.2 lb/lo6 Btu) for a source (usually a power plant) and allocating emission reductions to states in proportion to current emissions in excess of the acceptable emission rate. States are then given the responsibility for determining which sources within the state should control emissions further. The overall reduction amount (shown in Table 2) is usually determined somewhat arbitrarily, but often with the general goal of reducing emissions by 5075.t Because of the high costs of achieving these large reductions in emissions, several bills have called for the establishment of an acid rain control fund, in which revenues would be collected through fees on electricity generation or emissions and partial payment for control systems would be made from the fund. Several Congressmen from midwestem or coal-producing states have introduced bills calling not for immediate emission reductions but for an accelerated research program and grants to states for local mitigation measures such as liming of damaged lakes. With this background on the acid rain legislative scene, we can now proceed to examine the projected direct costs$ of these measures, to identify the major implications for energy policy and energy systems, and to discuss recent work by Argonne National Laboratory on the design of alternative strategies. Direct costs of control programs Several estimates309 of the total costs of the major bills have been made, and they are summarized in Table 3. These costs are associated with retrofitting existing coalfired units with flue-gas desulfurization (FGD) control systems, modifying boilers to bum t This objective is derived from a statement by the National Academy of Sciences’ that “it is desirable to have precipitation with pH values no lower than 4.6 to 4.7 throughout such [sensitive freshwater] areas. In the most seriously affected areas . . . this would mean a reduction of 50 percent in deposited hydrogen ions.” $ Our knowledge of the costs of control measures is considerably in advance of our knowledge of the benefits to be accrued from implementing those controls. In major part this is due to uncertainty in estimating the physical improvements to the many receptor systems that would occur as a result of emission reductions; in small part it is due to inherent difficulties in translating the physical changes into economic terms. The national program is working towards improving our ability to perform benefits estimates.

Gregg Ml tchell Coleman Byrd Rahall Randolph Stafford Stafford St Germain D' Amours Sikorski Donnelly Durenberger D’ Amours Aspin Glenn Rinaldo Wsxman Udall Stafford Green gckart Vent0

Sponsor

5-3-84 6-6-84 6-28-84

5-3-8bi

l-3-83 l-26-83 2-l-83 2-3-83 2-10-83 3-l O-83 3-10-83 3-10-83 4-27-83 6-8-83 6-23-83 9-l 5-83 10-25-83 11-16-83 11-18-83 l-26-84 2-2 2-84 3-30-84 4-4-84

Propoaal Date

X

Xh

X

Entire

CM

8 log log 11 10 log log log

Xf

10 128

8 12 10 Xf log

10 10

X X

X X X X X X

X

Acid Rain: Control Fund

6 Anount of SO2 emission reduction is shown in millions of tons per year. Reintroduction of H.R.4829 (Hoffett) from 97th Congress. i Reintroduction of 5.1706 (Mitchell) from 97th Congress, with minor changes. These bills are essentially the same. i A reintroductfon of S.3041 (Stafford/Committee) from 97th Congress. Reduction amount not specified. g Plus an additional reduction of 4 million tons per year of nitrogen oxides. i Consists of sections on acid deposition and hazardous air pollutants only. Date reported by Stafford/Committee, with major amendments.

H.~.4683 S.2215 H.R.4906 H.R.5314 H.R. 5370 S.768 Ii. R. 5590 H.R.5794 Il. R. 5970

H.R.4404

H.R.132b s.145= H.R.1 33 S.454 I H.R.lbOSd S. 766 S.768’ S.769 H.R.2794’ H.R.3251 H.R.3400 H.R.3904 s.2001

Bill

Acid Rain: Emission Reductions’

X

X

X

X

X X X X

Acid Rain: Accelerated Research, Mitigation

Bill

I November 1984).

Coverage of the

Table 2. Summary of acid rain bills in the 98th Congress (to

X

X

X

TransBoundary Air Pollution

Q

z=:

b

C

5 a

a

3

8

5’

7

2 _. p.

DAVID G. STREETS

1052

Table 3. Estimates of costs of the major acid rain control bills.

Bill

SO2 Emission Re uction (10 % tons/y)

Capital costa ($ lo91

Levelised Total cos a 4 (S 10 /Y)

Source

8.6

3.6

EM3

768

8

S. 760

a

3.1

ICF4

S. 768

a

4.2

ML5

S. 769

12

12.9

ANL5

B.R.

3400

10

3.7-4.4

OTA’

H.R. 3400

10

21.3

4.2

ANL7

H.R. 3400

10

18.4

5.1

EE18

R.R.

3400

10

3.7

ICF9

H.R. 4404

12

6.3

ANL7

S.

‘In 1980 dollars. Other-year dollars converted using an equipment coat index (Chemical Engineering, June 13, 1983).

low-sulfur coal, fuel premiums arising from a switch to lower-sulfur coal and additional 0 & M costs. For emission reductions in the range of 8-12 million tons of sulfur dioxide annually, estimated total levelized costs are generally in the range of $3-12 billion per year over a time period of 20 years or so. At the upper end of the emission range, the cost curve rises steeply due to rapidly increasing marginal cost of pollutant removal. The brunt of these costs would be borne by midwestem states where SO* emissions are currently the highest. For example, the Sikorski-Waxman bill (H.R. 3400) would require the following levelized expenditures (in millions of 1980 dollars per year) in selected midwestem states’: Ohio, 700; Indiana, 480; Pennsylvania, 350; Illinois, 270; etc. Total capital expenditures for this bill would be about $20 billion. It is clear that the national costs of such a program are high, and that the impacts on midwestem states are likely to be especially high. What effect will this have on the electric utility industry’s financial health? It is generally accepted that the crisis situation faced by the industry in the 1970s has been alleviated in the 1980s as a result of favorable rate decisions made by the public utility commissions. Capital requirements for the installation of pollution control equipment to meet the acid rain bill emission limitations represent between 2 and 10% of the total utility capital requirements for new plant and equipment over the next lo-15 years (between $300 and $400 billion”). It is likely that utilities will continue to rely heavily on external sources of capital from domestic capital markets to finance this new construction. The ability of the industry to raise this capital will depend largely on the future rate of inflation and its effect on interest rates. The demand for electrical power in the next decade will also be a determinant. It is possible, particularly in states where the projected capital expenditure on pollution control represents a large share of total capital needs, that the incremental capital requirements of the bills would place an inordinate strain on the electric utility industry. This could act as a further deterrent to new plant construction, leading to lifetime extension of older, dirtier plants and possibly increased imports of Canadian power. For this reason, several legislators have proposed the establishment of an acid rain control fund” to partially subsidize these expenditures and minimize the adverse impact

Acid rain control and U.S. energy policy

1053

the hardest-hit states.? This is analogous to the Superfund concept for hazardous waste cleanup. Funds collected would then be disbursed to utilities to partially subsidize the purchase, installation and operation of control systems. Various subsidy schemes have been proposed. Representatives Sikorski and Waxman (H.R. 3400), who first introduced the concept, would subsidize 90% of the capital costs for continuous emission control technology, but none of the 0 & M costs. Senator Glenn (S. 2215) would subsidize 90% of the capital costs and 50% of the annual operating costs of control technology. Senator Durenberger (S. 2001) would subsidize 70% of the capital and 30% of 0 & M costs. The effect of these subsidies would be to level out the costs among states; those states that are major consumers of electricity tending to subsidize those that are major emitters of pollution. This is a policy clearly resented by Atlantic Coast, New England and western states. The Durenberger bill may have little effect because it raises its fees preferentially from states that have the largest current emissions, which are the same states preferentially using the subsidy. Subsidies that fund capital costs but not 0 & M costs are likely to lead to overdesign of equipment. Subsidies that fund too high a percentage of either capital or 0 & M costs are likely to lead to cost inefficiencies on the part of utility operators. The 70%/30% split suggested by Senator Durenberger may be a reasonable compromise. There have been doubts expressed over the ability of certain of the fee systems to accrue sufficient interest or capital to cover the necessary outlays.” There appears to be a definite timing mismatch for the Sikorski-Waxman bill (H.R. 3400). Fees are to be collected over the 1985- 1995 period, but compliance is required by 1990, which necessitates the start of construction several years earlier. It is unlikely that the fund would have accumulated sufficient capital to support the rapid outlays that would be required. This means that utilities would have to borrow capital and be reimbursed from the fund at a later date, raising the question of whether interest payments can be covered by the subsidy. Inflation-linked fees have also been considered. on

Electricity prices The inevitable consequence of the costs of a control program will be an increase in electricity prices. EIA3 estimates an average real price increase of 2.7 mill/kWh (about 5%) in 1995 electricity prices as a result of implementation of S. 768. ICF9 projects an average price increase of 1.2 mill/kWh as a result of H.R. 3400. In contrast, EEI* projects much larger price increases, ranging as high as 12 mill/kWh in Indiana and Missouri. In an earlier paper,” we illustrated the kind of state-by-state variation that can accompany a moderate average rate increase. Figure 1 shows that Midwest regional-average electricity prices are projected to rise by approximately 5.3% between 1985 and 1995, in the absence of an acid rain control program (without CP2). With the imposition of a control program consisting of a 2 lb/IO6 Btu ceiling on SO2 emission rates (with CP2), average prices increase by approximately 6.6%. While these price increases may be acceptable on average, Figure 1 shows that increases in specific states can vary widely from the average. On one hand, electricity prices in Ohio could increase by approximately 16.8% without CP2 and by 21.4% with CP2. On the other hand, a state such as Florida would be minimally affected by this control program. Electricity prices will increase in the future without further environmental measures; the effect of an acid rain control program is to add to these increases preferentially in those states required to reduce emissions the most. EIA3 showed that prices are quite sensitive to the demand for electricity. In a high demand scenario, the price increase was 3.7 mill/kWh, as opposed to 2.7 mill/kWh under a base projection. t H.R. 3400 would impose a I mill/kWh tax on nonnuclear electricity generation in the 48 contiguous states. H.R. 4404 raised this to I .5 mill/kWh and also exempted hydrogenerated electricity. Senator Glenn, in S. 2215, called for a 1 mill/kWh tax in 1985. a 2 mill/kWh tax in 1986, rising to 3 mill/kWh in 1987-1999. This tax is to be levied on existing major emitters in the eastern U.S. Senator Durenberger, in S. 2001, required the tax to be levied on the basis of emissions of SO* and NO, throughout the U.S. This is the only bill to propose an emissions tax.

1054

DAVID

G. STREETS m

Without CP2

a

With CP2

Regional Average With CP2

ReQiOnd

AVW,QO

Without CP2

-5

Fig. 1. Typical changes in electricity prices in selected states in the eastern U.S. over the period 1985-1995, with and without a 2 lb/lo6 Btu acid rain control measure (CP2).

Several bills include provisions to ensure that subsidies are used to offset cost increases that would otherwise be passed on to the customer in the form of increased electricity rates. Senator Glenn requires that “(A)ny payment . . . be made only if the owner or operator passes on such payment to its current customers in the form of a rebate or rate reduction” [S. 2215, Section 189(a)(5)(C)]. The Sikorski-Waxman bill includes a similar provision.

Efects on manufacturing industries Manufacturing industries are likely to be affected in two distinct ways by an acid rain control program: first, by the indirect effect of increased electricity prices; and, second, by a direct requirement to reduce emissions as embodied in legislation or in state plans to achieve legislated emission reductions. EEI projects that electricity rates to industrial customers will increase more than to commercial or residential customers8 These increases can be expected to adversely affect the already depressed industrial Midwest. It is a vicious circle: industries suffering recession include the primary metals industries and related manufacturing industries which themselves emit large quantities of sulfur dioxide or are using electricity supplied by heavilyemitting utility power plants; states supporting such industries are therefore required to clean up under the bills on the basis of their current emissions; costs are high in these states, thereby increasing electricity bills the most and further affecting the ailing industries. Missouri, Indiana and Ohio are the three states projected to have the highest increases in electricity rates for industrial customers under H.R. 3400.* At least one bill, introduced by Representative D’Amours (H.R. 4404), would specifically require SO2 emission reductions from industrial emitters: one million tons annually from fuel combustion and one million tons annually from process emissions. We estimate’ that these reductions would cost about $0.9 billion per year and $1.2 billion per year, respectively. However, current analyses cannot capture all the real-world effects that might accompany this requirement, in terms of plant closings, reduced productivity, effect on foreign trade balance, etc. This bill does not limit reductions to the eastern U.S., with the result that reductions from western smelters make up the majority of the process reduction component ( 18% from Arizona alone). The benefit of such reductions for acidic deposition are likely to be small due to their large distances from sensitive receptor areas. It should also be remembered that, whereas allocations of state emission reductions are determined on the basis of utility emissions, the bills generally give authority to the states to determine which sources should actually clean up to achieve the mandated state total reduction. It is expected that non-utility sources will indeed be called upon by the states to reduce emissions, especially in those states where non-utility emissions represent a significant portion of current emissions and for those bills requiring the largest emission reductions. Note that ICF4 projects that by the year 2000, industrial reductions of about

Acid rain control and U.S. energy policy

I

Ernlr*,on (tbS0,/106

1055

Llmltr

Btu)

Year

On-Line

Fig. 2. 1980 sulfur dioxide emissions from coal-fired power plants by age distribution applicable emission limit.

and

700,000 tons of SO2 annually (about 8% of the total reduction) would be projected under S. 768, assuming a least-cost strategy were selected by the states. Industrial SO* emissions are generally expected to increase significantly in the future (from 2.9 to 5.3 million tons per year between 1980 and 2010) while utility emissions are expected to increase only slightly? (from 17.4 to 18.0 million tons per year over the same time period).4 Many bills require such new growth to be offset by equal emission reductions at existing sources. There is much uncertainty about what the effect of acid rain legislation will be on manufacturing industries. It would seem advisable not to specifically include industry in man&ted reductions under federal legislation, but to defer to the states for inclusion of such sources in a state-devised program, if they deem it desirable after weighing the local costs and benefits. Electric utility system eflects There is a common misconception that acid rain is caused by older power plants that will probably retire before the end of the century leading to an alleviation of the problem. In fact, the greatest emissions emanate from large power plants constructed relatively recently. Figure 2 shows that the bulk of current SO2 emissions (over 8 million tons) comes from plants constructed in the IO-yr period from 1965 to 1975. Despite the passage of stringent New Source Performance Standards in 197 1, most of these plants commenced construction before 197 1, thereby gaining exemptions from NSPS. In the absence of acid rain legislation, many of these plants will likely continue operating well into the next century. Utilities are finding it an increasingly attractive option to extend the lifetime of units through refurbishment and good maintenance practices, rather than to retire units and incur the high costs of new plant and emission control equipment. Lifetimes as long as 60 yr are considered possible. Therefore, we may well see the emissions problem persisting until 2030 or so. Representatives Broyhill and Madigan proposed an approach (not a bill) in September 1983 of phased-in retirement of existing plants exceeding an emission rate of 1.2 lb/lo6 Btu. This is interpreted as a clean-up-or-retire program. We have analyzed this interesting strategy.’ Figure 3 shows emission projections for the time period 1980-2030 on the assumptions of 60-yr and 40-yr retirement ages for plants. It is clear that significantly lower emissions can be realized in the early part of the next century, if plants can be induced to retire early. Figure 4 shows the relative costs of these two options, assuming replacement new capacity (at about $1200/kW) for the 40-yr retirement case, and refurbishment costs for the 60-yr retirement case. The costs of a 1.2 lb/ 1O6 Btu ceiling 7 Utility emissions of SOI will increase only slightly because the emission increases due to new coal-fired plants (large capacity, but low emissions due to stringent new source performance standards) are partially offset by emission decreases due to retirement of old coal-fired units (smaller capacity, but much higher emissions).

DAVID G. STREETS

1056

p “0

11-L 12-

c g? IO.P 1 5 0 0

86

6 b-

*-

5 5

*-

l/7

a

40 Yr Retirement 60 ---_ Yr Retirement -_-

1980

r

f990

I

2010

2000

2020

1

2030

Year Fig. 3. Projections of future emissions of sulfur dioxide from coal-fired power plants, assuming 40yr and 60-yr retirement ages.

strategy are on the order of $2 billion per year.’ Thus, it is clear that early retirement is significantly more expensive than the other options, and clean-up-or-retire translates to clean-up in all likelihood. Several analysts have suggested that, because growth in electricity demand is projected to be slow in the future and because current reserve margins are high, there may be potential for retirement of some existing units without incurring expensive replacement costs. Data indicate that as much as 26 GW of additional capacity could be obtained by raising 1980 capacity utilization to a floor of 60%. This would lead to an estimated increase in annual SOz emissions of 2.1 million tons, because the existing plants have higher SOZ emission rates than the replacement capacity would have. This is of environmental concern because many bills do not make it clear that increased emissions due to increased utilization of existing plants must be offset by reductions elsewhere. In the absence of such provisions, replacement would be discouraged. However, Keelin and Oatman” have refuted this notion and demonstrated that increased demand (whether through economic growth or replacement of aging capacity) would require construction of new capacity to ensure reliable service. Although certain individual utility companies may have excess capacity it does not appear to be a widespread phenomenon. Other analysts have warned that under strict control programs, such as the SikorskiWaxman requirement to retrofit FGDs on the 50 largest emitters, utility companies may well choose to shut down plants rather than control them. This is good from the perspective of emission reductions, but potentially bad from the perspective of the coal industry and plant employment. The Illinois coal industry, for example, may be hard hit if Illinois utilities choose to close the Kincaid and Baldwin plants in response to H.R. 3400 and take up the generating slack with nuclear power, as has been suggested.14 These two plants alone consume 7.6 million tons of Illinois coal annually.

Fig. 4. Incremental costs to coal-fired power plants of replacement capacity and refurbishment foi the 40-yr and 60-yr retirement cases.

Acid

rain control and U.S. energy policy

1057

The actual response of utility operators to requirements for reduced emissions is hard to predict. In some instances, we may well see early retirement of inefficient, dirty units and replacement either with new coal capacity, nuclear capacity, or increased utilization of existing units. Acid rain legislation would certainly force utilities to reevaluate their among new coal plants, nuclear or other mix of plants for system optimization, nonpolluting plants, refurbished plants, old coal plants with and without FGD, etc. Their choices are hard to predict, and, therefore, future levels of emissions are also hard to predict. Coal resources When a utility power plant is forced to cut its emission rate, the first option to be considered is a switch to a coal of lower sulfur content. This is invariably the most costeffective strategy. In general, retrofitting FGD equipment will only be considered if mandated by law, if the emission reduction is large enough that FGD is the only technical option, or if the plant is locked into a long-term coal contract. Therefore, strategies that require the states to achieve emission reductions but do not mandate continuous emission reduction technology result in large-scale fuel switching away from high-sulfur midwestem and Northern Appalachian coals, and towards low-sulfur western or Central Appalachian coals. The Stafford Bill, S. 768, is a good example of a bill requiring a large reduction in SO2 emissions (8 million, tons annually) with no constraints on the method of achieving that reduction. As a result, EIA3 forecasts large shifts in the patterns of coal production, despite a small total increase in production of 20 million tons/year. The major regional production changes are projected to be: Northern Appalachia, - 16%; Midwest, -44%; Central Appalachia, +27%; West, +12%. ICF4 projects similar changes: -27, -50, +I8 and +16%, respectively. These shifts result from the utility companies responding to the need to reduce emissions by switching to coals of lower sulfur content. State-level effects are clearly significant. Figure 5 shows the kinds of coal shifts that can occur in midwestem states. I2 There are uncertainties associated with these projections. It is hard to compare costs resulting from differences in fuel prices with costs resulting from technology purchase

Coal Types

q q Ixi

70

1

q

OH

Northern

Appalachian

Central

Appalachian

interior

Eastern

Southern

IN

Appalachian

PA

n Central Western q Southern Wyoming q Powder River q Interior Western

MO

IL

FL

Fig. 5. Typical changes in the patterns of utility coal consumption for selected states under an acid rain control program that permits fuel switching (first bar is 1995 base: second bar is a 2 lb/lo6 Btu emission ceiling).

1058

DAVID GSTREETS

and operation. The two are influenced by different factors and may behave quite differently in the future. Several utilities (including TVA) suspect that with a long planning horizon the cost advantage of fuel switching may not be so clear cut and FGD could well be the control option of choice. There are several unknowns associated with fuel switching on a large scale, including the costs of boiler modifications, the costs of particulate control system modifications, the ability of the low-sulfur coal industry to meet demand, and the effect of high demand on low-sulfur coal prices. Nevertheless, as a near-term option, fuel switching currently holds a definite edge. What effect would these changes in the patterns of coal production and consumption have? Midwestern and eastern coal-producing states predict grave consequences. The Congressional Research Service” projects that S. 768 could raise unemployment in the coal-mining and related service industries in the coal-producing areas of Illinois, western Kentucky and Ohio by 11-l 8%, and in Indiana by 9-10%. Various coal industry studies show mining employment losses of anywhere from 20,000 to 80,000 jobs in the East. With recession already causing high unemployment in these regions, the political pressure to avoid exacerbating the situation is high. This is one reason why Representatives Sikorski and Waxman preferred to accept the higher costs of a forced-scrubbing strategy, rather than risk jeopardizing the whole control program in the face of a strong coal lobby. Recently, the Alliance for Clean Energy, a coalition of low-sulfur coal producers, has advocated a freedom-of-choice approach on the grounds that total coal production is expected to rise naturally in the future and also as the result of an acid rain control program and that there are sufficient reserves of low-sulfur coal in the East to support a fuel-switching strategy. This strategy downplays the extremely parochial nature of eastern coal mining, where shifts of production and jobs from county to county are resisted, let alone from state to state. From a national energy policy perspective, fuel switching on a large scale may be undesirable. The nation possesses large reserves of high-sulfur coal, which is cheap, serviced by an experienced work force, and capable of being burned in the majority of existing power-plant units. To exploit domestic energy resources fully and avoid future dependence on imported energy, it is important to develop ways to exploit these resources in an environmentally sound manner. It seems counterproductive to switch away from such resources and towards a scarcer resource like low-sulfur coal that would be better reserved for small combustors (where control technology is less cost-effective) and locations where air pollution protection is at a premium. It is certainly important to redouble our efforts to develop cleaner technologies for the combustion of highsulfur coal. Coal conversion policy The opinion has been expressed that stringent emission limitations on the burning of coal will inhibit the nation’s general energy policy goal of encouraging the conversion of existing oil-fired boilers to coal. Although the power-plant capacity expected to convert to coal in the near future is relatively small (8 GW, according to EIA3) and largely mandated under the Powerplant and Industrial Fuel Use Act, significant voluntary conversion by utilities and industry may occur in the future depending on the relative fuel price paths of oil and coal. if vulnerability to disruption of foreign oil supply becomes a resurgent issue, disincentives to conversion would be undesirable. Several of the major acid rain bills provide relief for facilities converting to coal. For example, S. 768 would only include those emissions from converting plants in excess of 1.5 lb S02/106 Btu towards excess emissions that must be offset. This implies that a converting plant can bum a compliance coal of relatively low sulfur content and avoid further constraints under the acid rain program. On the other hand, many of the plants scheduled for conversion to coal under the Powerplant and Industrial Fuel Use Act are located in the Northeast, close to sensitive receptor areas such as the Adirondacks. Increases in emissions from these local sources could have a disproportionate effect on acid deposition in those areas, compared to emissions in more distant locations. In this sense, coal conversion stands as a point of

Acid rain control and U.S. energy policy

1059

conflict between energy policy goals and environmental policy goals. If oil prices should start to rise rapidly in the future, this issue will reassume the prominence it had during the Carter Administration. Innovative energy technology This brings us to the last important energy issue: the role of innovative technology. Acid rain legislation is seen as presenting a potentially large market for new technology, both for advanced environmental control technology and for low-polluting energy technology. As discussed earlier, the large emission reductions required by some of the bills imply retrofitting a substantial portion of the existing coal-fired utility generating stock with emission control technology. Estimates for that capacity range to a maximum of about 80 GW for the major bills, depending on whether fuel switching is allowed as a compliance strategy. Senator Glenn, in proposing his control program,16 recommended that the federal government work with industry to move innovative control technology into the marketplace. Analysis by the Congressional Research Service” seemed to indicate a considerable role for limestone-injection multistage burners (LIMB), sufficient to reduce control costs by 34% to achieve an eight million ton reduction goal. This analysis, however, was based on optimistic forecasts of LIMB costs, as contained in EPA’s program objective specifications (capital costs for LIMB of one-fifth to one-sixth those of lime/limestone FGD per ton of SO* equivalent removed). Thus,. they represent performance and cost goals, rather than demonstrated performance and costs. More realistic estimates, based on the latest LIMB and wet FGD cost and performance estimates, suggest that LIMB is likely to hold only a small advantage over wet FGD, if any at all, as a major technology for the removal of acid rain precursor emissions.‘* t Nevertheless, the idea of providing an incentive for new technologies under acid rain legislation is clearly a good one. In his subsequent bill, S. 2215, Senator Glenn included Section 187, Innovative Control Orders, for operators who would install innovative emission limitation systems (such as LIMB). Exemptions from the major bill requirements would be permitted, provided a final date of compliance is specified (no later than 1 January 1996) and incremental progress towards emission reductions is achieved. In addition [Section 189(d)(l)], innovative control technology would be subsidized out of the control trust fund to the extent of 90% of capital costs and 90% of operating costs, as opposed to 90% of capital and 50% of operating costs for conventional control technology. This would be a significant spur to new technology development. Representative D’Amours took a different approach in his bill H.R. 4404. Part of the control fund was specifically to be used to fund fullscale demonstration of LIMB and to accelerate research on other lowSOr and low-NO, technology (atmospheric fluid&&bed combustion and magnetohydrodynamics are specifically mentioned). The Senate Committee bill (S. 768) [Section 182(c)] requires the national task force to conduct research on advanced flue-gas cleaning and precombustion fuel treatment technologies and inherently low-emission combustion processes (including atmospheric and pressurized fluidized-bed combustion). These measures are likely to be less effective than Senator Glenn’s, because they address only the acceleration of research, but do not provide incentives for introduction of the technologies into the marketplace. Alternative strategiesfor controlling acid rain For several years, Argonne National Laboratory has been analyzing alternative strategies for controlling acid rain that would be either less costly or more effective than the broad emission reduction programs proposed in the congressional bills. t LIMB holds an advantage over wet FGD in that it reduces emissions of NO, as well as SO2. Several bills credit reductions in NO, towards mandated SO2 reductions, on a two-for-one basis (i.e. two units of NO,, by weight, are considered equivalent to one unit of SOJ. Taking this into account, and using the latest cost and performance estimates from LIMB tests, ANL projects LIMB costing S800-1900 per ton of SO2 equivalents removed, compared to $750-1000 per ton removed by wet FGD. LIMB also has a lower maximum SO2 removal rate. Therefore, the window of opportunity for LIMB is rather narrow at present, but potentially larger in the future.

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The most interesting of these options is the targeted control strategy.’ We have linked models of electric utility cost and emission reduction with models of atmospheric transport and deposition. Using optimization routines, strategies can be designed to achieve specific objectives of deposition reduction in selected sensitive receptor areas at minimum cost. We recognize that these models, particularly those of atmospheric transport and deposition, are subject to uncertainty. Better models are under development but will not be available for several years. We advocate the use of currently available models on two grounds: first, we believe they are adequate for discerning relative merit between different policy options (although we recognize that the estimates of deposition for a particular option are subject to uncertainty); and, second, we believe that the use of these models in policy analysis is preferable to not using them, which is how current bills are being formulated. Table 4 summarizes the major findings of this work. A simple cost-optimization of the bills S. 768 and S. 769 can reduce costs by about 50%, to achieve the same reduction in sulfur dioxide emissions. Deposition of sulfur in the Adirondacks, one of the regions of the U.S. most sensitive to acid deposition, is actually reduced more than under the bills. If the atmospheric transport models are then used to optimize emission reductions in those states in upwind proximity to the Adirondacks, costs can be reduced by about 75% compared to the unoptimized bills. Emission reductions are necessarily less, but deposition reduction is the same as the bills. Figure 6 shows how the patterns of emission reductions needed to minimize deposition reduction in the Adirondacks change under a targeted strategy. This particular strategy is targeted towards a single receptor area, the Adirondacks. Nevertheless, it performs almost as well for other sensitive areas in the Northeast (Quebec, Southern Nova Scotia, Vermont, New Hampshire and Pennsylvania). However, it does not lead to such a large reduction in deposition in the Smoky Mountains, for which a second targeted strategy could be designed if the evidence for ecological damage is compelling. The technique can be used and has been used, for designing multipletargeted strategies for many different areas simultaneously and for different kinds of deposition .goals. All strategies show marked superiority over the bills before Congress. We believe this analytical technique can go a long way towards resolving the impasse faced by Congress. The second interesting option is the regional, new-source bubble strategy.‘9*20 Under current regulations, emissions from new sources are controlled stringently under New Source Performance Standards, whereas emissions from existing sources are controlled under State Implementation Plans, which in many cases are quite lax. Our strategy

Table 4. Comparison

Strategy

Senate

Bill

Bill

41 easured

Reduction In Annual SO2 Emisrions (Milliono of Tone)

4.2 1.9 0.9

9.0 9.0 5.0

23 26 23

12.9 6.0 3.0

14.9 15.0 9.8

40 46 40

Reduction Acid Rain Adirondacks

S. 769

Aa Proposed Cost-Optimized Tatge ted ‘Levelized

Annual Coat (Billions of 1980 Dollarsa)

S. 768

As Proposed Cost-Optimized Targeted Senate

of selected control strategies.

1980 dollars. as reduction

in sulfur

deposition.

in n i (X)

Acid rain control and U.S.

energypolicy

Proiscted 6.768

Fig. 6. Sulfur dioxide emission

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Twoatsd S.788

reductions

under S. 768, as

proposedand

when targeted.

reasons that, if acid rain is a regional problem that does not permit identification of culpable sources, then restrictions on individual sources can be relaxed, provided ( 1) local air pollution problems are not worsened and (2) total emissions from a particular region do not increase. This permits more cost-effective solutions to emission control to be selected among the group of sources (old and new) within a given region. Significant cost savings can be achieved by relaxing requirements for new sources slightly and tightening up the requirements for existing sources. Figure 7 shows various least-cost control curves for all existing coal-fired utility plants and those new plants scheduled to come on line in the East between 1980 and 2000. The base-case (current regulations) permits the emission of about 16 million tons of sulfur dioxide annually at a cost of about $54 billion per year. Costs presented here are the sum of pollution control costs and coal costs. The latter are included to capture the effects of fuel switching to achieve emission reductions. This means that differences in cost between different policies then reflect true compliance costs. The various minimum cost curves shown are for ( 1) a regional bubble, (2) a state bubble (limited to state boundaries) and (3) a state bubble utilizing currently-unexploited local reserves of low-to-medium sulfur coal.

,

8.2 x 10” tons *

\

Control Option ----

Regional Bubble State Bubble Local Coal

--

Current

0

6

10

15

20

regulations

25

Annual TotsI Emirslons (lOe tons>

Fig. 7. Potential

emission

reductions

achievable in the eastern U.S. under a regional, new-source bubble policy.

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DAVID G. STREETS

Examination of Fig. 7 reveals that emissions reductions of between 6 and 8 million tons per year (comparable to the bills) are potentially achievable at no cost, relative to the costs of current regulations, under a regional, new-source bubble policy. Such a high degree of cost-effectiveness (relative to other strategies presented here) is achieved only by sacrificing the stringency of emission limitations that currently apply to new sources. The strategy has other drawbacks associated with it. It is hard to implement, and emissions tend to increase over time relative to the nonbubble case. Nevertheless, we believe its potentially high payoff demands attention. The final option to be mentioned is that of a nonregulatory approach through economic incentives. Representative Aspin introduced a bill, H.R. 4483, in November 1983, that was completely different from all the other bills. Representative Aspin, instead of mandating a specific reduction in emissions, would set up a scheme to pay to the operator of a coal-fired facility 50 cents for each pound of sulfur removed prior to emission. A fund would be set up to cover these payments by taxing the amount of sulfur contained in coal sold by the producer. Although there are major problems with Aspin’s bill, which make its adoption unlikely, the concept is of great interest. We are currently analyzing the Aspin bill, and results are expected shortly. CONCLUSIONS

Any control program that seeks to reduce emissions enough to relieve the acid rain problem significantly is bound to be costly. It will also undoubtedly have major repercussions for the coal industry, especially in the East and Midwest. It will cause the utility industry to re-evaluate its thinking on system planning and technology choice. It may lead to turnover in the existing stock of facilities and may open up opportunities for new technologies. Reverberations will be felt in the manufacturing industries and in the pocketbook of the American homeowner. All these impacts, however, may indeed be worth paying to ensure the survival of some of our more fragile ecosystems and valuable materials. The outcome of the cost-benefit equation will not be known for several years. What is important is that we do not jump head first into a perceived solution without carefully comparing the options, utilizing all the analytical tools at our disposal, and evaluating the impacts on all strata of society. Acid rain is not just an environmental policy issue; it is an economic policy issue and an energy policy issue. The search for a balance point must be pursued diligently. Acknowledgments-It gives the author pleasure to acknowledge the analytical assistance and ideas provided by his colleagues [D. Carter (DOE), L. Conley, D. Garvey, D. Hanson, D. Knudson, M. Place& J. Roberts, E. Trexler (DOE), J. Vemet (DOE), T. Veselka, and T. Williams (DOE)] and the funding provided by DOE’s 0th of Policy, Safety and Environment and Office of Fossil Energy. The opinions expressed in this paper should not be construed as representing the policy of Argonne National Laboratory or the U.S.. Department of Energy. REFERENCES 1. Title VII of the Energy Security Act of 1980 (P.L. 96-294). 2. National Research Council, “Atmosphere-Biosphere Interactions: Toward a Better Understanding of the Ecological Consequences of Fossil Fuel Combustion”, National Academy Press, Washington, D.C. 20418 (1981). 3. Energy Information Administration, “Impacts of the Proposed Clean Air Act Amendments of 1982 on the Coal&d Electric Utility Industries”, DGE/EIA-O407, Washington, DC. 20585 (1983). 4. ICF, Inc., “Analysis of a Senate Emission Reduction Bill (S-304 I)“, ICF report for U.S. EPA, 1850 K Street NW, Washington, D.C. 20006 (Feb. 1983). 5. D. G. Streets, D. A. Hanson and L. D. Carter, J. Air Pollut. Control Ass. 34, 1187 (1984). 6. Office of Technoloav Assessment. “An Analysis of the SikorskilWaxman Acid Rain Control Proposal: H.R.3400, ‘The Nat&al Acid Deposition Control Act of l983”‘, Washington, D.C. 205 IO (July l98j). 7. D. G. Streets, D. B. Garvey and T. D. Veselka, Argonne National Laboratory, unpublished information (May 1984). 8. Edison Electric Institute, “Evaluation of H.R.3400, the ‘Sikorski/Waxman’ Bill for Acid Rain Abatement”, prepared for EEI by Temple, Barker & Sloane, Inc., 33 Hayden Avenue, Lexington, MA 02173 (Jan. 1984). 9. ICF, Inc., “Analysis of the Waxman-Sikorski Sulfur Dioxide Emission Reduction Bill (H.R.340)“, ICF report for U.S. EPA, 1850 K Street NW, Washington, D.C. 20006 (April 1984). IO. Electrical World l%(6), 83 (1982). II. L. B. Parker and L. Kumins, “Sharing the Cost of Acid Rain Control: An Analysis of Federal Financing Under H.R.3400”. Congressional Research Service. Library of Congress, Washington, D.C. 20540 (Sept. 1983).

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12. D. G. Streets, D. A. Knudson and J. D. Shannon, Environ. Sci. Technol. 17, 474A (1983). 13. T. W. Keelin and E. N. Oatman, Public UtilitiesFortnightly IlO( 13), 29 (1982). 14. M. F. Ellis, “Acid Rain: Control Strategies and Costs”, Illinois Energy Resources Commission, Springfield, IL 62706 (March 1984). 15. L. B. Parker, “Mitigating Acid Rain: Implications for High-Sulfur Coal Regions”, Congressional Research Service, Library of Congress, Washington, D.C. 20540 (May 1983). 16. Congressional Record, S.4667 (14 April 1983). 17. L. B. Parker, ‘Distributing Acid Rain Mitigation Costs: Analysis of a Three-Mill User Fee on Fossil Fuel Electricity Generation”, Congressional Research Service, Library of Congress, Washington, D.C. 20540 (April 1983). 18. J. L. Gillette, C. D. Livengood, D. A. Hanson and D. G. Streets, Argonne National Laboratory, unpublished information (March 1984). 19. D. G. Streets, P. J. Grogan, D. A. Hanson, and T. D. Veselka, “A Regional, New-Source Bubble Policy for Sulfur Dioxide Emissions in the Eastern United States”, Argonne National Laboratory report ANL/EESTM-239, 9700 South Cass Ave., Argonne, IL 60439 (Oct. 1983). 20. D. G. Streets, D. B. Garvey, P. J. Grogan, D. A. Hanson and L. D. Carter, J. Air Pol/ut. Control Ass. 34, 25 (1984).