Amicus Brief — Ruckelshaus v. Natural Resources Defense Council, Inc.

Office-Supreme Court, U.S.

rILED

NO. 82-1591 AUG 31 1983

ALEXANDER L. STEVAS,

IN THE CLERK

Supreme Court of the United States

October Term, 1983

Administrator, Environmental Protection Agency,

Petitioner,

v.

Natural Resources Defense Council, Inc., et al. ,

Respondents.

On Writ of Certiorari to the U.S. Court of Appeals

for the District of Columbia Circuit

MOTION FOR LEAVE TO FILE

BRIEF AMICUS CURIAE

AND

BRIEF AMICUS CURIAE

OF THE AMERICAN GAS ASSOCIATION

JouHN A. MYLER*

American Gas Association

1515 Wilson Boulevard

Arlington, Virginia 22209

(703) 841-8460

Attomey for Amicus Curiae

*Counsel of Record

NO. 82-1591

IN THE

Supreme Court of the United States

October Term, 1983

Administrator, Environmental Protection Agency,

Petitioner,

v.

Natural Resources Defense Council, Inc., et al. ,

Respondents.

On Writ of Certiorari to the U.S. Court of Appeals

for the District of Columbia Circuit

MOTION FOR LEAVE TO FILE

BRIEF AMICUS CURIAE

Pursuant to Rule 36 of the Supreme Court Revised Rules,

the American Gas Association (A.G.A.) hereby respectfully

requests permission to file its brief amicus curiae in support of

the Petitioner, the Administrator of the Environmental Protec-

tion Agency (EPA), in the above-captioned case. A.G.A.’s

motion is required because consent to the filing of the brief

amicus curiae has been withheld by a single party, Chevron

USA Inc. (which is also the petitioner in No. 82-1005).

A.G.A. is a national trade representative for approximately

300 member companies active in either the local distribution

or pipeline transmission of natural gas. Serving approximately

160 million consumers, member companies provide 85 percent

of the nation’s natural gas utility sales.

This case involves the interpretation of language included

in the 1977 Amendments of the Clean Air Act which can have

an impact on the fuel consumption decisions of certain indus-

trial plants. Approximately 53 percent of the sales of natural

gas by A.G.A. member companies are made to industrial users,

to

including electric utilities which use the gas in the generation

of electricity. Consequently, this case is of immediate and

substantial interest to our member companies.

Under Part D of the Clean Air Act as amended, states

which had not, by 1977, met national air quality standards

established by the EPA were directed, among other things, to

require permits for the construction of “‘new or modified

major stationary sources” of air pollution in ‘“‘non-attainment

areas’. In October, 1981, the EPA adopted a regulation for

Part D which permitted states for purposes of reviewing “new

or modified major stationary sources” to utilize a ““plantwide”’

definition of “stationary sources” that treats an industrial

plant as a single source. Such a definition is an example of the

application of a “‘bubble’’ concept. As demonstrated below,

the bubble concept can also be applied to existing source

situations with the same beneficial results as result from use of

the plantwide definition for new source review. The EPA’s

regulation allows involved industrial concerns to burn con-

currently natural gas and less environmentally benign fuels in

order to derive the maximum benefits of the clean-burning

characteristics of natural gas (i.e. the “select use” of natural

gas). The application of the select use concept to existing

sources may be extremely simple, involving no more than the

switching, for example, for low sulphur to high sulphur oil in

one unit, while offsetting this conversion with a change from

low sulphur oil to gas in the nearby unit. Thirty-one states or

jurisdictions have to date utilized the plantwide source defi-

nition and have sought to modify their state implementation

plans required under the Act to incorporate that approach.

A.G.A. submits that EPA correctly concluded that states

should have discretion to define “stationary source” on a

plantwide basis providing their state implementation plans

meet the basic requirements of the statute. One practical

impact of the EPA’s decision, an impact not dealt with below

by the parties, is to afford the nation the variety of benefits

flowing from the ‘“‘select use” of natural gas, bene/its entirely

consistent with the basic purposes of the 1977 Amendments to

the Clean Air Act clearly articulated by Congress. A.G.A.’s

purpose in submitting its brief is to provide concrete examples

of how the “bubble” policy provides a wider array of economic

choices with the capability of environmental, economic, and

national security gains, consistent with Congressional intent.

WHEREFORE, the American Gas Association respect-

fully moves that this Court grant permission to file its brief

amicus curiae, attached hereto, in support of the positions of

the Petitioner.

Respectfully submitted,

Joun A. MYLER

Attorney for the

American Gas Association

NO. 82-1591

IN THE

Supreme Court of the United States

October Term, 1983

Administrator, Environmental Protection Agency,

Petitioner,

v.

Natural Resources Defense Council, Inc., et al.,

Respondents.

On Writ of Certiorari to the U.S. Court of Appeals

for the District of Columbia Circuit

BRIEF AMICUS CURIAE OF THE

AMERICAN GAS ASSOCIATION

JOHN A. MYLER*

American Gas Association

1515 Wilson Boulevard

Arlington, Virginia 22209

(703) 841-8460

Attomey for Amicus Curiae

*Counsel of Record

TABLE OF CONTENTS

Interest of Amicus Curiae..................

Argument

A. Superior Environmental Characteristics

of Methane Gas Combustion ..........

B. Potential Benefits of Select Use

“Bubbling” — A Hypothetical

Industrial Plant Example .............

C. Potential Benefits of Select Use

“Bubbling” — A Hypothetical

Powerplant Example ................

D. Additional Benefits, ...4.......00 cheb.

meeematy OF Armee ioc cs cc cccvcuins

ENE ic a dE Sic Sd wercca dees be ckecccvlnd

TABLE OF AUTHORITIES

Train v. Natural Resources Defense Council, Inc.

S20 US. 6 cciskcia eee era eae eee

STATUTES

Clean Air Act of 1970 as amended (Part D), Pub. L.

No. 95-95, 91 Stat. 685, 42 U.S.C. (Supp. IV)

Fael CF ONB. Sia cas A rn es feet rte ge

REGULATIONS

40 C.F.R. 51.18G)(1 Gi); 40 C.F.R. 52.24(1(2) «0 wae,

MISCELLANEOUS

H.R. Report No. 95-294, 95th Congress, Ist Sess.

CUDTTD inc peo 0-0 bs ea len anee ana aon wee

46 Fed. Reg. (1981):

OP ai sc ecawg ns have Veaneeee eee

DNS es cc ae nge hab nee bee eee es eee

NO. 82-1591

IN THE

Supreme Court of the United States

October Term, 1983

Administrator, Environmental Protection Agency,

Petitioner,

We

Natural Resources Defense Council, Inc., ef a/.,

Respondents.

On Writ of Certiorari to the U.S. Court of Appeals

for the District of Columbia Circuit

BRIEF AMICUS CURIAE OF THE

AMERICAN GAS ASSOCIATION

8 Interest of the Amicus Curiae

The American Gas Association (A.G.A.) is a national trade

association representing approximately 300 member companies

active in the local distribution or pipeline transmission of

natural gas. A.G.A.’s member companies provide approximately

85 percent of the nation’s natural gas utility sales, approxi-

mately one-half of which ($3%) are sales to industrial users,

including electric utilities which use the gas in generating elec-

tricity. A.G.A. member companies have a direct interest in the

issues before the Court in this proceeding since the practical

effect of the judgement of the U.S. Court of Appeals for the

District of Columbia Circuit is to discourage certain uses of

natural gas in non-attainment areas — a policy determination

unintended by Congress and in direct conflict with the basic

purposes of the Clean Air Act, as amended.' The approach

authorized by the EPA and voided by the Court of Appeals

'The Court of Appeals’ decision is reported at 685 F.2d 718.

to

produces cleaner air and also provides additional benefits of

cost savings sgmtinproved national energy independence.

Il. Argument

Pursuant to Part D of the Clean Air Act as amended, states

which had not, by 1977, met national air quality standards

established by the EPA were directed to require permits for the

construction of ‘“‘new or modified major stationary sources” of

air pollution in non-attainment areas. In October, 1981, the

EPA adopted a regulation for Part D which permitted states for

purposes of reviewing “new or modified major stationary

sources” to utilize a “plant-wide”’ definition of “stationary

source” that treats an industrial plant as a single source, an

example of what is the so-called “bubble” concept.? The Court

of Appeals has invalidated that regulation, finding the use of

the bubble concept inappropriate in programs enacted to

improve the quality of ambient air. A.G.A. submits that the

application of a “‘plant-wide”’ definition to “stationary source”

for purposes of new source review under Part D is legally per-

missible and socially desirable. Use of the bubble concept

affords firms the flexibility to meet air quality standards in

the most efficient and cost-effective fashion. There is no identi-

fiable inconsistency between the bubble approach and the basic

Congressional goal of bringing all national air quality regions

into compliance with the requirements of the Clean Air Act

pursuant to Part D thereof, 42 U.S.C. § 7501 ef seq.

Congress stated quite clearly that the 1977 amendment to

the Clean Air Act aimed at the so-called non-attainment areas

(Part D) has

“two main purposes: (1) to allow reasonable eco-

nomic growth in [a non-attainment] area while mak-

ing reasonable further progress to assure attainment

of the standards by a fixed date; and (2) to allow

States greater flexibility for the former purposes

than EPA’s present interpretive regulations afford.”

H.R. Rep. No. 95-294 at 211.

2C.F.R. 51.18(jX1 Mii); 40 C.F.R. 52.24(f(2).

The bubble concept provides direct support to achieving

both Congressional purposes. Indeed, the EPA relied, in the

process of establishing the bubble approach, on indications

that to define ‘‘stationary source” otherwise tended to frus-

trate legislative intent.

EPA noted expressed concerns that its prior definition

of “source” as both an industrial plant and the individual

pieces of process equipment within the plant provided disin-

centives to new investment and modernization by discourag-

ing modifications to existing facilities and could retard en-

hanced air pollution control by discouraging replacement of

dirtier equipment with cleaner. 46 Fed. Reg. 16280, 16281

(March 12, 1981); 46 Fed. Reg. at 50768.

The discussion below provides concrete examples of how

the bubble policy provides a wider array of economic choices

and the potential for environmental, economic, and national

security gains, consistent with legislative intent.

A. Superior Environmental Characteristics of Natural

Gas Combustion

Natural gas is the cleanest burning fossil fuel. It emits

virtually no sulfur dioxide (a component of “acid rain”) or

particulate matter when combusted. Emissions of carbon diox-

ide, carbon monoxide, nitrogen oxide and non-methane hydro-

carbons are all significantly less with natural gas combustion

than with the combustion of other fuel sources (e.g., coal or

oil). As an example, a large electric utility or industrial boiler

operating on natural gas emits only .0006 pounds of sulfur

dioxide (SO,) per million Btus (MMBtu) of fuel consumed.?

In contrast, typical grades of fuel oil and coal burned under

similarly sized boilers would release 1.6 and 3.4 pounds of

SO, per MMBtu, respectively.*

Employing the bubble concept with natural gas permits

the fuel mix at a plant to be altered to meet varying sulfur

3Compilation of Air Pollutant Emission Factors, Pub. No. AP-42,

U.S. Environmental Protection Agency at 1.4-2 (3rd Ed., August, 1977).

41d. at 1.1-3 (coal), at 1.3-2 (oil). Fuel oil would thus emit 2667

times the amount of SO> as natural gas, coal 5667 times.

dioxide emission limits. The tables attached as Appendices |

and 2 show how this concept operates. For example, « plant-

wide emission limit of 1.4 pounds of sulfur dioxide per MMBtu

could be achieved by operating the plant on a mix of 33 percent

gas and 67 percent fuel oil (2 percent sulfur content) (See Ap-

pendix 2). Tighter standards could be met by burning a mix

with a higher quality oil, or by increasing the proportion of

gas consumed.

B. Potential Benefits of Select Use ‘Bubbling’ — A

Hypothetical Industrial Plant Example

A simple illustration of the select use approach is provided

by the recently approved “multiple-source”’ bubble for the Nar-

ragansett Electric Company in Rhode Island which was operat-

ing two generating stations less than one mile apart, both on |

percent sulfur oil. The EPA approved a plan allowing one of

the units to operate on 2.2 percent sulfur oil, while the other

unit burns gas. As a result, anticipated savings were $24 million

per year, SO, emissions will be reduced by 1,388 tons per year,

and oil imports will be reduced by 600,000 barrels per year.

Such a plan is exceedingly simple, yet provides substantial

benefits, as illustrated by the hypothetical example set out in

Appendix 3. Consider “an industrial facility with two large

boilers, each with a capacity of 250 MMBtu/hr operating on

low sulfur (0.5 percent) oil at a cost of $35.36/bbl. (June,

1983 N.Y. harbor price of $30.75/bbl, increased by a factor of

15 percent to account for delivery to the New York/New Jersey

area.) An SO, emission limit of 0.52 Ibs/MMBtu is not uncom-

mon in the Middle Atlantic region. Assuming a capacity utiliza-

tion factor of 65 percent, the annual fuel cost for these two

boilers would be approximately $16.2 million. The annual

maintenance expense for the two boilers, based on a charge of

30 cents/MMBtu, would be $850,000. Total annual fuel con-

sumption would be 460,000 barrels of oil (2,848 Trillion Btu),

and the SO, emission rate would be 0.52 lbs/MMBtu.

The same emission rate, 0.52 Ibs/MMBtu, could be achieved

by operating on slightly higher sulphur oil (one percent) in one

of the units and gas in the second unit. This allows significant

\

reductions in both fuel and maintenance expenses, even if the

price of gas increases to the price of low sulfur oil ($5.70/

MMBtu, equivalent to oil priced at $35.36/bbl). Economic

savings can still be realized, even under this pessimistic gas

pricing assumption, since the substitution of gas in the second

unit allows lower quality oil to be burned in the first unit — 1

percent sulfur at $29.44/bbl delivered (June, 1983 N.Y. harbor

price of $25.60/bbl increased by 15 percent).

As a result of this select use bubbling approach, the annual

plant fuel bill is reduced by over $1 million, from $16.2 million

to $14.9 million. Again, the cost of fueling the second boiler

(with gas) is not assumed to change; the reduction stems en-

tirely from a switch to lower quality oil in the first unit. Boiler

maintenance cost is also reduced in the select se case. A reduc-

tion of roughly $85,000 results from a charge of 24 cents/

MMBtu for gas boiler maintenance versus the 30 cents/MMBtu

for oil boiler maintenance. Although the overall energy con-

sumption in each case is the same, 2,848 Trillion Btu, the sub-

stitution of domestic gas for oil — much of which is imported —

results in an oil savings of 230,000 barrels per year. There is

no technological impediment to this select use bubbling option,

and the results in terms of environmental impact, reduced fuel

costs, maintenance costs and oil consumption are substantial.

C. Potential Benefits of Select Use “Bubbling” — A

Hypothetical Powerplant Example

In addition to select use bubbling as a means to reduce fuel

and operating costs and oil imports, while maintaining or

improving air quality ambiance, by switching from oil-only

operations (with emissions monitored on a boiler-by-boiler

basis) to a gas/oil fuel mix with emissions monitored on a plant-

wide basis, similar results exist for a switch from coal-only to

gas/coal. In addition, gas/coal “‘bubbling’’ may preclude the

need for coal-fired facilities to purchase and operate expensive

pollution control equipment.

In 1981 the American Gas Association examined three

operating scenarios for 12 New England electric powerplants

which are under consideration by the Department of Energy

for conversion from oil to coal. The purpose of the analysis was

to compare two conversion options for the 12 plants versus

their continued dependence on oil for a generating fuel in all

units:

1) Continued dependence on oil in their non-coal-

capable units, and conversion from oil to coal in

coal-capable units with the addition of adequate

pollution control equipment to meet state environ-

mental standards; and,

2) Conversion from oil to coal in coal-capable units

and some combination of oi/ and gas in non-coal-

capable units which would satisfy relevant emission

limitations without the addition of SO, scrubbers.

For comparison purposes, all cost and energy consumption

data were based on plant totals rather than on coal-capable

boilers alone. For example, in the scrubbed coal scenario, the

20 coal-capable boilers would operate exclusively on coal. How-

ever, the analysis also included the energy consumption and

costs associated with those boiler units which would not con-

vert (roughly 50 percent of the total generating capacity at the

12 powerplants). For purposes of this analysis, the prices of oil

and gas to powerplants were assumed to be equal. A summary

of the updated analysis results is provided in Appendix 4 and

summarized below.

1) Conversion of all 12 coal-capable New England

powerplants to coal with select gas use would be

$225 million per year (15 percent) less costly than

continuing to operate these plants exclusively on oil.

The annualized cost of select gas use, including the

capital costs of coal conversion, and operation and

maintenance and fuel expenses over 15 years, would

be 4.2 cents/kwh as compared with 5.0 cents/kwh

for the fuel and operation and maintenance costs

associated with a continued dependence on oil (1982

dollars).

~ The total annual cost of converting and operating

all 12 plants on coal with select use of gas would

average an estimated $1,325 million versus an

3)

4)

D.

average of $1,550 million required annually for

continued oil operation (annualized life-cycle

cost basis).

At the same time, coal conversion of these 12 plants

with select gas use would save 100,000 barrels of oil

per day, roughly 15 percent of New England’s total

oil consumption. This oil savings, some 36 million

barrels per year (worth $1.2 billion at current prices),

would require 67 billion cubic feet of natural gas per

year, about one-third of one percent of current

annual domestic gas consumption.

By comparison, converting to coal with the use of

scrubbers would cost New England electric con-

sumers approximately 10 percent more than convert-

ing with select use of gas (4.6 cents/kwh versus 4.2

cents/kwh).

Initial capital costs for converting coal-capable

units at the 12 plants for select gas use operation

would total an estimated $955 million, roughly

50 percent less than the scrubbed coal capital

cost of $1,815 million or an annual average cost

of $125 million versus $240 million.

~ Average annual operation and maintenance

expenses associated with the select gas case

would be an estimated $55 million per year,

approximately one half the $115 million for the

scrubbed coal case.

Oil offset by the scrubbed coal case would be 69,000

barrels per day, 31 percent less than the volume

potentially offset by the select use gas case.

Additi~nal Benefits

In addition to the fuel cost, oil import and maintenance

savings offered by select use bubbling in the industrial and

powerplant examples presented above, as well as the elimination

of large capital expenditures in the powerplant example which

would be required absent select use bubbling, this strategy may

also offer additional benefits. For example, the multiple oil

supply disruptions of the 1970's, coupled with coal miner

strikes and freezing coal piles, indicate that the fuel diversity

which select use bubbling presents is indeed worthwhile.

Finally, select use bubbling enhances the opportunity

for plants in some areas to burn higher sulfur local coal rather

than importing lower sulfur coal from distant sources. This

option can be exercised while meeting applicable state imple-

mentation plan emission limits; thus, movement toward the

attainment of national ambiant air quality standards need not

be hindered.

III. Summary of Argument

The utilization of natural gas with less clean energy sources

in a bubble mode (referred to as the “select use”’ of gas) offers

a variety of benefits, to the fuel consumer and to the nation.

From a national perspective, select use can: maintain or

improve air quality; reduce our dependence on imported

oil; and increase reliance on domestic coal (and gas). For the

energy consumer, select use can: reduce overall fuel costs;

reduce susceptibility to fuel supply disruptions, such as a coal

or rail strike or an oil embargo; and preclude the need to

purchase expensive pollution control equipment.

The EPA regulations at issue in this case were the product

of a reasoned decisionmaking process which provided the

opportunity for compliance with important legislative goals

in a manner offering the benefits described above, benefits

consistent with the controlling statutory language and legis-

lative history. As such, they reflect an exercise of agency

discretion clearly supportable by precedent of this Court.‘

STrain v. Natural Resources Defense Council, Inc., 421 U.S. 60,

87.

IV. Conclusion

The judgement of the Court of Appeals should be

reversed.

Respectfully submitted,

Joun A. MYLER

Attorney for the

American Gas Association

Al

APPENDIX 1!

PERCENTAGE OF FUEL MIX REQUIRED TO BE GAS

FOR VARIOUS GRADES OF COAL AND SO,

EMISSION LEVELS

Sulfur Content of Sulfur Content of

Eastern Coal? Western Coal?

SO, SIP

(Ib./MMBtu) 8% 1% 2% 3% 8% 1% 2% 3%

0.6 53% 62% 81% 87% 61% 68% 84% 89%

0.8 37 49 75 83 47 58 79 86

1.0 22 637 68 7 34 47 74 82

1.2 6 24 62 75 21 37 68 79

1.4 - 11 56 71 8 26 63 75

1.6 - -— $50 66 - 16 58 72

1.8 - — 43 62 -. 3 Sa @&

2.0 - «=«— 3F 32 - -— 47 65

2.2 - - 31 54 - — 42 61

2.4 - — 24 49 - — 37 58

2.6 - — 18 4§ - — 32 54

2.8 - -— 12 41 - -—- 26 51

3.0 - = $ 37 - - 21 47

' Select Gas Use for Environmental Purposes, American Gas Associa-

tion 20 (January, 1983).

212,000 Btu/Ib.

310,000 Btu/Ib.

A2

APPENDIX 2!

PERCENTAGE OF FUEL MIX REQUIRED TO BE GAS FOR'

VARIOUS GRADES OF RESIDUAL OIL AND SO,

EMISSION LEVELS

Sulfur Content of Oil

SO, SIP :

(Ib./MMBtu 25% 5% 1% 2% 3%

0.2 23% 62% 81% 90% 94%

0.4 23 62 81 87

0.6 ~ ~ 43 71 81

0.8 - - 24 62 75

1.0 ~ - 5 52 68

1.2 - - ~ 43 62

1.4 - _ - 33 56

1.6 -- - - 24 49

1.8 - - - 14 43

2.0 - - ~ 5 37

2.2 - - - - 30

2.4 ~ - ~ - 24

2.6 - - -- - 17

2.8 - - - -- 1]

3.0 - - -- - 5

! Select Gas Use For Environmental Purposes, American Gas Associ-

ation 21 (January, 1983).

SUMMARY ECONOMIC COMPARISON OF OIL ONLY AND SELECT GAS USE

WITH OIL IN TWO LARGE INDUSTRIAL BOILERS

Oil Only Select Gas Use with Oil

Unit#1 Unit#2 _—‘Total Unit #1 Unit #2 Total

Annual Operating Expense ($000)

Fuel $8,100 $8,100 $16,200 $6,800 $8,100 $14,900

Operating & Maintenance 425 425 850 425 340 765

Total $8,525 $8,525 $17,050 $7,250 $8,440 $15,665

Annual Fuel Consumption

(Billion Btu)

Oil 1,424 1,424 2,848 1,424 0 1,424

Gas ; 0 0 0 0 1,424 1,424

Total 1,424 1,424 2,848 1,424 1,424 2,848

Annual Oil Savings (000 Bbl) 0 0 0 0 230 230

€ XIGNAddV

tV

ECONOMIC COMPARISON OF OIL, SCRUBBED COAL, AND SELECT GAS USE

WITH COAL IN 12 NEW ENGLAND POWERPLANTS

Capital Cost ($1982, Millions)

— Oil to Coal Conversion!

— SO, Scrubber?

— Electrostatic Precipitator?

— Gas Hook-Up?

Total Capital Cost

Total Annualized Capital Cost ($1982, Millions)®

Annualized Operation & Maintenance

Cost ($1982, Millions)*®

=O

— Coal

Scrubber Related

Non-Scrubber Related

Total Coal

— Gas

Coal With

Oil Coal With Select Gas

(Base Case ) Scrubber Use

- $790 $790

- $875 ~

- $150 $150

_ _ $12

- $1,815 $955

— $240 $125

$50 $25 $15

_ $55 -

- $35 $35

- $90 $35

¢ XIGNAddV

pV

ECONOMIC COMPARISON OF OIL, SCRUBBED COAL, AND SELECT GAS USE

WITH COAL IN 12 NEW ENGLAND POWERPLANTS (Cont’d.)

Total Annualized Operation & Maintenance

Annualized Fuel Cost ($1982, Millions)5»®

- Oil

— Coal

— Gas

Total Annualized F::el Cost

Total Annualized Capital, O&M, and Fuel Cost®

Production cost per Kwh (¢1982/Kwh)

Difference per Kwh vs. Oil

Energy Consumption (Trillion Btu/yr)®

— Oil

— Coal

— Gas

Total

Oil Saved (Thousands of Bbls/day)

Oil

(Base Case)

$50

$1,500

$1,500

$1,500

5.0¢

Coal With

Coal With Select Gas

Scrubber Use

$115 $55

$760 $430

$330 $385

— $330

$1,090 $1,145

$1,445 $1,325

4.6¢ 4.2¢

-0.4¢ -0.8¢

155 88

151 151

- 67

306 306

69 100

(‘P.3U0D) & XIGNAddV

SV

gi:

ECONOMIC COMPARISON OF OIL, SCRUBBED COAL,AND SELECT GAS USE

WITH COAL IN 12 NEW ENGLAND POWERPLANTS (Cont’d.) (Footnotes)

' Profiles for Title | Existing Electric Powerplants, (Washington, D.C.; Economic Regulatory Administration, Office

of Fuels Conversion, April 1980). Conversion costs based on estimates of $115/Kw for “low-cost” conversions; $340/Kw

for “high<ost” conversions.

? Particulate and Sulfur Dioxide Emission Control Costs for Large Coal-Fired Boilers, (Cincinnati; PEDCo Environ-

mental Inc. for the Environmental Protection Agency, EPA450/3-78-007, February 1978), pp. 3-12, 4-16. Assumes 3.5%

sulfur coal used in limestone scrubber equipped units. Scrubber costs range from $140 to $314/Kw, depending on unit

capacity, and varying emission limits. Assumes 3.5% sulfur, 14% ash coal used in scrubbed coal case with electrostatic pre-

cipitator. In the select gas use case, 0.8% sulfur coal, 14% ash content assumed. Precipitator costs in both cases range from

$26/Kw to $59/Kw, depending on unit capacity.

3Fuel Distribution, (Argonne; Institute of Gas Technology for Argonne National laboratory, ANL/CESITE 79-8,

July 1979), p. 35. Costs reflect distance to nearest gas transmission line, rather than nearest distribution line. It is likely

that the distance toas distribution lines is less than the distance to transmission lines, and thus the gas hook-up cost is

probably somewhat overstated. No hook-up cost was added to the West Springfield plant, which currently bums some gas.

* Annual O&M expense of 2 mills/Kwh assumed for unscrubbed coal units and 5 mills/Kwh for scrubbed units. See:

A Preliminary Economic Analysis of Reconversion of Coal Capable Utility Boilers (Washington; ICF for Edison Electric

Institute, April 1980), Attachment B. O&M costs for oil and gas units assumed to be 67% and 33% respectively, of un-

scrubbed coal O&M as per: Kaiser Aluminum & Chemical Corp., Economics of New Coal versus New Gas/Oil Boilers,

(January 1978), Exhibit 4 and Table IV.

(PIUOD) & XIGNAddV

9V

ECONOMIC COMPARISON OF OIL, SCRUBBED COAL, AND SELECT GAS USE

WITH COAL IN 12 NEW ENGLAND POWERPLANTS (Cont'd.) (Footnotes)

Fuel price projections for coal and oil from the Spring 1982 TERA Base Case of the American Gas Association:

price of gas assumed to equal the price of oil. Coal for scrubber equipped units assumed to be 3.5% sulfur coal for select

gas use case assumed to be 0.8% sulfur, and 10% more expensive than average utility coal. Price differentials by sulfur con-

tent taken from: Cost and Quality of Fuels for Electric Utility Plants ~ July 1980, (Washington; U.S. Energy Information

Administration, November 1980), pp. 12-13. Price differentials reflect those reported in Ohio, a significant producer and

consumer of both high and low sulfur coals, which is relatively close to the New England market.

® Annualized costs reflect 10 percent per year real time value of money , exclusive of inflation. Ten percent is an esti-

mate of the real pretax rate of retum of US. electric utilities based on: 50-50 debt-equity ratio; 12% return on debt

(weighted average of yields on newly issued utility bonds, Moody's Public Utility Manual, 1980); 27.2 percent return on

equity (derived from price earning ratio of 6.8 and 46% tax rate, Moody's Public Utility Manual, 1980), and, an inflation

rate of 8.8% (implicit GNP deflator as published in the Survey of Current Business of the Department of Commerce).

7Energy consumption based on 35% boiler efficiency and 55% annual capacity utilization. Energy contents of 6

MMBtu/bbI (oil), 24 MMBtu/ton (coal), and | MMBtu/Mcf (gas) were assumed.

(‘puoD) + XIGNAddv

Lv