EPA-23D/l-75-058b
MAY 1976
ECONOMIC IMPACT
OF
INTERIM FINAL AND PROPOSED
EFFLUENT GUIDELINES
COAL MINING
QUANTITY
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Planning and Evaluation
Washington, D.C. 20460
^*0 ^
$
PHO"*4-
°T
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This document is available for inspection through the
U.S. Environmental Protection Agency. Public Information
Reference Unit, Koum 2404, Waterside Mall, 401 M Street,
S.W., Washington, D.C. 20460.
Persons wishing to obtain this document may write
the Environmental Protection Agency, Economic Analysis
Division, Waterside Mall, 401 M Street, S.W , Washington,
l).C. 20460. Attention: Distribution Officer PM-220.
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ECONOMIC IMPACT
OF
INTERIM FINAL AND PROPOSED
EFFLUENT GUIDELINES
COAL MINING
Report to
U.S. ENVIRONMENTAL PROTECTION AGENCY
EPA-230/l-75-058b
MAY 1976
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PREFACE
The attached document is a contractor's study prepared for the Office
of Planning and Evaluation of the Environmental Protection Agency ("EPA").
The purpose of the study is to analyze the economic impact which could
result from the application of alternative effluent limitations guidelines
and standards of performance to be established under sections 304(b) and
306 of the Federal Water Pollution Control Act, as amended.
The study supplements the technical study ("EPA Development Document")
supporting the issuance of interim final regulations under sections 304(b)
and 306. The Development Document surveys existing and potential waste
treatment control methods and technology within particular industrial source
categories and supports the proposal based upon an analysis of the feasi-
bility of these guidelines and standards in accordance with the require-
ments of sections 304(b) and 306 of the Act. Presented in the Development
Document are the investment and operating costs associated with various
alternative control and treatment technologies. The attached document
supplements this analysis by estimating the broader economic effects which
might result from the required applications of various control methods and
technologies. This study investigates the effect of alternative approaches
in terms of product price increases, effects upon employment and the con-
tinued viability of affected plants, effects upon foreign trade and other
competitive effects.
The study has been prepared with the supervision and review of the
Office of Planning and Evaluation of the Environmental Protection Agency.
This report, was submitted in partial fulfillment of Contract No. BOA
68-01-1541, Task Order No. 25, by Arthur D. Little, Inc., Cambridge,
Massachusetts. Work was completed as of May 1976.
This report is being released and circulated at approximately the
same time as publication in the Federal Register of a notice of proposed
and interim final rule making under sections 304(b) and 306 of the Act for
the subject point source category. The study is not an official EPA publi-
cation. It will be considered along with the information contained in the
Development Document and any comments received by EPA on either document
before or during rule making proceedings necessary to establish final
regulations. Prior to final promulgation of regulations, the accompanying
study shall have standing in any EPA proceeding or court proceeding only to
the extent that it represents the views of the contractor who studied the
subject industry. It cannot be cited, referenced, or represented in any
respect in any such proceeding as a statement of EPA's views regarding the
subject industry.
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TABLE OF CONTENTS
Page
List of Tables vi
Mat: of Figures xii
EXECUTIVE SUMMARY 1
I. INDUSTRY STRUCTURE 1-1
A. INTRODUCTION 1-1
B. COAL MINING AND PREPARATION TECHNOLOGY 1-2
1. "Soft" Coal Segment (Bituminous, Sub-bituminous
and Lignite 1-2
2. Anthracite ("Hard" Coal) Mining 1-3
3. Coal Cleaning and Preparation 1-5
C. COAL PRODUCING FIRMS 1-5
1. Bitiminous Coal and Lignite 1-5
2. Anthracite 1-8
D. SEGMENTATION OF MINES AND PREPARATION PLANTS 1-12
1. Soft Coal Mines 1-12
2. Hard Coal Mines 1-18
3. Coal Preparation 1-18
II. FINANCIAL PROFILE OF THE COAL INDUSTRY II-l
A. COAL PRODUCTION COSTS II-l
B. SALVAGE VALUE OF COAL MINING ASSETS II-6
C. INDUSTRY PROFITABILITY II-6
D. CONSTRAINTS ON FINANCING ADDITIONAL CAPITAL ASSETS 11-21
E. OTHER CONSTRAINTS TO GROWTH IN THE COAL INDUSTRY 11-23
III. COAL—SUPPLY, DEMAND, AND PRICE III-l
A. SUPPLY III-l
1. Coal Resources III-l
2. Coal Production I1I-5
iii
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TABLE OP CONTENTS cont'd
l5£e
B. COAL CONSUMPTION 111-16
1. Domestic Soft Coal 111-16
2. Exports [11-19
3. "Hard"" Coal III-19
C. COAL PRICING TRENDS 111-19
D. FUTURE COAL DEMAND AND PRICES 111-27
1. Stean Coal (BltwalriauB a-ad Lignite) 111-27
2. Metallurgical Coal 111-42
3. Anthracite 111-4(3
it. CobX Preparation 111-4 3
IV. ECONOMIC IMPACT ANALYSIS METHODOLOGY IV-1
A. INTRODUCTION IV-1
B. PRICE AND PRODUCTION EFFECTS XV-1
C. FINANCIAL EFFECTS: IMPACT ON CAPITAL AVAILABILITY IV-4
0. INDUSTRY GROWTH
E. CLOSURE ANALYSIS
F. EMPLOYMENT AND COMMUNITY EFFECTS
G. SALANCE OF PAYMENTS EFFECTS
V, EFFLUENT STANDARDS AND TilE COST UF COMPLIANCE
A. SOURCES AND CHARACTERIS2'ICS" OF EFFLUENT
B. EFFLUENT GUIDELINES
C. COSTS OF COMPLIANCE
VI. IMPACT ANALYSIS
1. Price Effects
2. Financial Effects
1. Production Effects
4. Industry Growth
5. Metallurgical Coal - Mining and Preparation
iv
IV-4
IV-4
IV-4
rv-5
V-i
V-l
V-2
V-6
VI-1
Tfl-2
VI-7
VI-23
VI-25
VI-25
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TABLE OF CONTENTS cont'd
Page
6. Employment Effects VI-29
7. Community Impacts VI-29
8. Balance of Payment Effects VI-29
9. Sensitivity Analysis VI-29
VII. LIMITS TO THE ANALYSIS VII-1
A. MODELS VII-1
B. COMPLIANCE COSTS VIX-2
C. MARKET PROJECTIONS VIX-2
D. OTHER REGULATIONS VXI-2
E. REMAINING QUESTIONS VII-2
v
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Table
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
LIST OF TABLES
Page
Concentration Ratios in Coal Mining 1-6
Top 15 Coal-Producing Groups in 1973 1-7
Share of Production of U.S. Coal in 1973 1-9
Top 20 Producers of Anthracite in 1973 1-10
Share of Production of Anthracite by Company and/or
Affiliates in 1972 1-11
Production of Bituminous Coal by Size of Mine Output 1-14
Distribution of "Soft" Coal Mines by Size of Production
and Type of Mine in 1973 1-15
Distribution of "Soft" Coal Production by Mine Size
and Type in 1973 1-16
Distribution of Employment in "Soft" Coal Mines by
Size and Type of Mine in 1973 1-17
Number of Mines, Production and Employment as
Percentages of the Soft Coal Segment of the U.S.
Industry in 1973 1-19
Anthracite Production by Mine Type 1-20
Characterization of Anthracite Industry by Mine
Size and Mining Method in 1973 1-21
Number of Mines, Production and Employment as
Percentages of the Hard Coal Segment of the U.S.
Industry in 1973 1-22
Trends in Cleaning at Soft Coal Mines 1-23
Regional Characterization of "Soft" Coal Cleaning
Plants in 1973 1-25
Distribution of Mechanical Coal Cleaning Plants by
States in 1973 1-26
Pennsylvania Anthracite Preparation Plants in 1973 1-27
vi
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LIST OF TABLES eoat'd
Table
No, Page
18 Estimates of La^gs Underground Co&l Kine Investment
and Operating Costs II-2
19 Estimates of Small Imderground Kine Investment end
Operating Coats IX-3
20 Estimates of Large Surface Mine InvestcaenC aad
Operating Coets II-4
21 Estimate of Small Surfsee Mine Invastcsent and
Operating Coeta 11-5
22 Estimates of Costs for Underground Mlmee iia the
Central Region II-7
23 Estimates of Costa for Underground Mines In the
Intermountsia Rsgion II-8
24 Estimate of Coats for Strip Mines in the InfcermountslTi
Region I1-9
25 Estimates of Investment and Operating Coats for a
Metallurgical Mine In Appalachia 11-10
26 Coal Preparation Costs 11-11
27 Salient Statistics on Bituminous Coal and Lignite
Mining 11-13
28 Salient Statistics on Anthracite Mining 11-14
29 Statistics by Employment Size of Establishment
Bituminous Coal and Lignite Mining (1972) 11-15
30 Statistics by Employment Size of Establishment
Anthracite Mining (1972) 11-16
31 Salient Statistics for M^jor Coal Companies 11-1?
32 Demonstrated Coal Reserva Base of the United States
by Method of Mining as of January ls 19 74 III-3
33 Distribution of U.S. Demonstrated Coal Reserves by
Segments and Potential Mining Methods 111-4
vii
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ble
o.
34
35
36
37
38
39
AO
41
42
43
44
45
46
47
48
49
LIST OF TABLES cont'd
Production of Bituminous Coal and Lignite, by
Type of Mine
Bituminous Coal and Lignite Production by States,
Coal Regions, and Mining Methods in 1973
Distribution of "Soft" Coal Production by Mine
Size and Type in 1973
Factors to get 1973 Production to 1974 and Capacity
from Existing Mines in 1985
Distribution of Metallurgical Coal Production
by Mine Type in 1973
Pennsylvania Anthracite Production by Extraction
Method in 1973
Consumption of Bituminous Coal and Lignite in
the United States
Trend in U.S. Coal Exports
Trends in Domestic Consumption of Pennsylvania
Anthracite by Consumer Categories
F.O.B. Mine Weighted Value for Coal in 1973
F.O.B. Mine Weighted Value for Coal for 1974
Prices and Quantities of Steam Coal
U.S. Total Gross Consumption of Energy Resources
in Standard Physical Units by Major Sources and
Consuming Sectors in 1980
U.S. Total Gross Consumption of Energy Resources by
Major Sources and Consuming Sectors in 1980
U.S. Total Cross Consumption of Energy Resources in
Standard Physical Units by Major Sources and
Consuming Sectors in 1980
U.S. Total Gross Consumption of Energy Resources by
Major Sources and Consuming Sectors in 1980
viii
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able
No.
50
51
52
53
54
55
56
57
58
59
60
61.
62
63
64
LIST OF TABLES cont'd
Prices and Quantities of Steam Coal by Region in
1985
Prices and Quantities of Steam Coal by Region in
1985
Coal Consumption under Various Scenarios in 1985
with Imported Oil Priced at $13/Barrel
U.S. Total Gross Consumption of Energy Resources
in Standard Physical Unite by Major Sources and
Consuming Sectors in 1985
U.S. Total Gross Consumption of Energy Resources by
Major Sources and Consuming Sectors in 1985
U.S. Total Grose Consumption of Energy Resources in
Standard Physical Units by Major Sources and
Consuming Sectors ia 1986
U.S. Total Gross GonnuEptlon of Energy Resourced
by Major Sources and Consuming Sectcro in 1985
Effluent Levels Achievable Through Application of
the Best Practicable Control Technology Currently
Available
Effluent Levels Attainable Through Application of
the Best Aveilable Technology Economically Achievable
New Source Performance Standards
Costs of Compliance with Effluent Guidelines:
Northern Appalachia
Costs of Compliance with Effluent Guidelines:
Southern Appalachla
CoBts of Complisn.ce with Effluent Guidelines:
Central Region
Coats of Compliance with Effluent Guidelines:
Intermounf.ain Region
Costs of Compliance with SffluessS Guidelines:
Great Plains Magics
is
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LIST OF TABLES cont'd
Table
No.
Page
65 Costs of Compliance with Effluent Guidelines: West
Region V-12
66 Compliance Costs Associated with Water Circuit
Closure for Coal Preparation Plants V-13
67 Coal Prices F.O.B. Mine for Run of Mine Coal VI-4
68 Price Increases Assuming Full Coat Pass Through for
Bituminous Coal Mining and Preparation Segment VI-5
69 Effect of New Source Performance Standards (NSPS)
on Coal Prices, 1980 and 1985 VI-6
70 Effect of BPT Compliance Costs on the Cash Flow
of Model Deep Mines VI-8
71 Effect of BPT Compliance Costs on the Cash Flow
of Model Surface Mines VI-9
72 Effect of BPT Compliance Costs on the Profitability
of Model Deep Mines VI-10
73 Effect of BPT Compliance Costs on the Profitability
of Model Strip Mines VI-11
74 Effect of BPT Compliance Costs on the Cash Flow of
Model Preparation Plants VI-12
75 Capital Requirements to Meet Effluent Guidelines VI-13
76 Effect of Compliance with Effluent Guidelines
Compared to After-Tax Cash Flows for Deep Mines in
Northern Appalachia VI-14
77 Effect of Compliance with Effluent Guidelines
Compared to After-Tax Cash Flows for Strip Mines in
Northern Appalachia VI-15
78 Capital Requirements for Compliance with Effluent
Guidelines Compared to After-Tax Cash Flows for
Preparation Plants VI-16
79 Aggregate BPT Compliance Requirements to Meet
Effluent Guidelines for Existing Mines VI-18
x
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LIST OF TABLES cont'd
Table
No.
80 Aggregate BAT Compliance Capital Requirements
(above BPT) for Existing Establishments VI-19
81 Capacity Needed from New Mines by 1985 ¥1-20
82 Capital Requirements to Meet NSPS up to 1985 VI-21
83 Summary of Estimated Aggregate Capital Requirements
of the Industry up to 1985 to Meet Effluent Guidelines
Standards VI-22
84 Comparison of Average Variable Cost Inclusive of
Deferred Capital Charge and Compliance Costze far
Existing Marginal Sstablishxnent VI-24
85 Coal Consumption VI-26
86 Effect of NSPS on Steam Coal Prices and Demand
Quantities, 1980 VI-27
87 Effect of NSPS on Steam Coal Prices and Demand
Quantities, 1985 VI-28
88 States with Lowest Value F.O.3. Mine by Regions (1974) VI-31
89 Comparison of Average Variable Cost Inclusive of
Deferred Capital Charge and Compliance Costs for
Existing Marginal Mine and Price of Coal VI-32
:;i
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LIST OF FIGURES
Figure
No. Page
1 Mining Methods Used in United States Bituminous
Coal Production 1-4
2 Characterization Scheme for U.S. Coal Industry 1-13
3 Coal Fields of the United States III-2
4 Productivity at Bituminous Coal Mines III-7
5 Trends in Coal Cleaning 111-15
6 Coal Consumption by Market Categories 111-18
7 Average Trend in Value of all coal Mined in the
United States (1965-1973) 111-25
8 Bituminous Coal Wholesale Price Index - 1968-1975
(1967 - 100) 111-26
xii
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EXECUTIVE SUMMARY
PURPOSE AND SCOPE
Under the Federal Water Pollution Act .^jmendment of 1972, the United
States Environmental Protection Agency (EPA) is chmr^ed with establishing
effluent limitations which must b^ achieved by point source? of discharge
into the navigable waters of Che United States.
The objective of this study is to provide the EPA with an analysis of
the economic impact of the costa of compliance with affluent guidelines on
the U.S. coal mining industry represented by the following industry cate-
gories :
SIC Major Group 12 - Bituminous Coal and Lignite Mining, arid
SIC Major Group 11 - Anthracite Miniag.
The EPA's effluent guidelines establish the degree of affluent limita-
tion attainable by 1977 through the application of the beet practicable con-
trol technology currently available (BPCTCA), and by 1963 through the appli-
cation of the best available technology economically achievable (3ATEA).
The new source performance standards (N3PS) establish the degree of effluent
reduction for new sources, which Is achievable through the application of
best available demonstrated control technology, process operating methods,
or other alternatives.
The information on water pollution control technology and costs of com-
pliance to achieve thes^ standards cited in this report were provided by
the EPA.
B. COAL INDUSTRY OVERVIEW
The United StateB is one of the world's leading producers of bituminous
coal and lignite, along with the U.S.S.R. and China. Ir. 1973„ the United
States produced about 18% of the world's output of bituminous coal and lig-
nite and 3.6% of its output of anthracite. In 1973, the U.S. coal mining
industry was comprised of about 5,000 active mines and around 400 prepara-
tion plants, operated by approximately 4,200 firms, which produced 591.7
million tons* of bituminous coal and 6.8 million tons of anthracite. The
Industry employed more than 145t000 people in 1973-
The U.S- coal Industry is dominated by the large firms in terms of
production and employment. Of the 4r000 companies producing bituminous coalB
the top 4 accounted for 27.9% of the production, while 600 companies accounted
for about 97/o of the output. Of the 181 companies producing anthracite in
1973, the top 20 accounted for about 75% of the output„
ftTons in this report refers to short or net tonaP (2,000 lbs).
A
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Approximately one-half of U.S. "soft" coal production (bituminous coal
and lignite) is cleaned prior to shipment. All non-dredge anthracite is
cleaned prior to shipment.
The principal consumers of bituminous coal are the nation's electric
utilities and the basic steel industries. In 1973, they accounted for about
70 and 17 percent, respectively, of the domestic consumption of 556 million
tons. The other consuming sectors are general industry and retail deliveries.
The estimated consumption of anthracite in the United States in 1973 was 5.6
million tons, 51% of which was used for space heating, 25% by the electric
utilities, 13% by the iron and steel industry, and the remaining 11% by cement
plants, collieries, and others. About 52.9 million tons of coal were exported
in 1973.
Since coals vary in quality, their attributes—for example, heat content,
ash, sulfur, volatile matter content, and caking characteristics—have to be
evaluated to determine their suitability for a specific use. Electric util-
ities pay for the coal on its effective heat value, with some credit or penalty
for departures from the norm of ash, sulfur, and moisture content. Emission
limitation requirements on S0X associated with clean air standards have made
sulfur content increasingly important. Steel companies judge coal for its
coking strength, expansion, ash sulfur, phosphorous, carbon content and blend-
ing characteristics. Generally, three commodities can be recognized: low-
and high-suflur steam coal and metallurgical coal.
Coal is sold through long-term contracts or on the spot market. Presently,
around 80% of all coal is sold on a long-term contract basis. Until the mid-
1960 ' s, coal contracts were generally fixed-price or long-term, particularly
for steam coal, in a market where consumption was declining. However, with
increasing demand for coal and escalating costs, recent contracts have tended
to be short-term and include provision for "pass through" of full costs. His-
torically, coal price levels were based on production costs and varied greatly
by type of mining and geography. Prices on the spot market are much more vol-
atile and respond quickly to supply/demand imbalances. Since the oil embargo
and lifting of price controls in the spring of 1974, the spot price for coal
has risen substantially, peaking in December 197A and January 1975 and then
falling throughout 1975. The average price for all coal was $18.75 per ton
In 1975 compared to $15.75 per ton in 1974 and $8.53 per ton in 1973.
C. EFFLUENT GUIDELINES
In developing effluent guidelines, the EPA has divided the industry
into the following subcategories:
• Bituminous, lignite, and anthracite mining - acid or ferruginous
mine drainage;
• Bituminous, lignite and anthracite mining - alkaline mine drainage;
• Coal preparation plant - process water; and
• Coal storage, refuse storage, and coal preparation plant ancillary
effluent.
2
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The.pollutant parameters to ba controlled by these guidelinen Include:
|)H, total iron, dissolved iron- total wwis;anase and total suopended solids.
The BATEA standards are the sane as tha. BPCTCA standards, except for a more
stringent total iron and total suspended solids limitation. The NSPS stand-
ard Is the same as the BATEA standard,, except for total suspended solids
which is the same as the BPCTCA standard. The BPCTCA and BATEA standards for
coal preparation plant process water requires no discharge of pollutants.
D. ECONOMIC IMPACT ON COAL INDUSTRY
Because of the large number of establishments in the coal industry,
and because preparation plants heve separate effluent standards, we seLected
a modelling approach. We first segmented the industry into bituminous coaJ
and lignite mines, anthracite miness and coal-preparation plants. We then
further segmented the mines by geographic regions, mine type, and mine size.
An overriding influence on the nature of the impact of guidelines on
the coal industry is its prospective growth during the next decade. The
Project Independence Evaluation System (PIES)„ administered by the Federal
Energy Administrations, is a detailed U.S. energy system model that provides
forecasts for selected years, including 1980 and 1985. The PIES forecast,
as revised in 1976, was selected because we found that it provided forecasts
of the coal market on a regional basis. The PIES reference (business as
usual) scenarios, with imported oil priced at $13 and $8 a barrel, were
chosen to represent optimistic and pessimistic demand scenarios. The $13
a barrel scenario translates to a demand for coal in 1985 of 1,040 million
tons and the $8 a barrel scenario translates to a demand for coal of 894
million tons. In 1973, domestic consumption and exports amounted to 609
million tons.
The costs of production for model mines and preparation plants were de-
rLved in order to establish a baseline for impact assessment. The costs of
compliance with effluent guidelines for the model mines and preparation plants
were provided by the EPA. It was assumed that all mines in the region have
¦i water problem similar to that of the representative model mine and that
there is no treatment alresdy in place. The impact of effluent guidelines
costs was assessed utilizing the price for coal in short run, as represented
by average 1975 prices, and PIES forecast of prices was used for the long
run. In this analysis all prices are measured in terms of 1975 dollars
purchasing power.
The compliance cost data supplied by the EPA indicated that for anthra-
cite mines no additional expenditure was needed to comply with effluent
guidelines. Consequentlyt further analysis was limited to bituminous coal
and Lignite mining and coal-preparation plants. The West region was not
analyzed as financial data were lacking, as there are very few mines in thin
region and the compliance costs for large surface mines (predominant in this
region) are suia.ll.
3
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1. Price Effects
t£ ateted earlier, coal ie aold through long-term and aedim»~Cer*i caii-
tracte aB well as o-ft the a-p-at wac«.et_» *.t. 7ct%eat exvUrx. 3-i of ill chI ie
-sold through contracts. In the past, contracts were fixed-price whereas
recent contracts penult for escalation based on increased cost of production.
The coet of compliance with BPT atauotardff will not influence the price
of spot market coal and -will have an effect on the price of contract coal
only to the extent Chat current contracta have automatic provisions for
escalation, ba9ed oti the increased cost of production. In the longer run,
as contracts are renegotiated, coate of compliance will be "passed through"
to the consumer. In either caee, the coat of B?T compliance will affect
coal prices only to the extent that current contracts include escalation
clauses or as such clauses are negotiated. The maximum increase 1t» price,
assuming full compliance coat "pass- through,11 would be 2.IS of ehe average
?racc-w^li£n-e price, (ucprepered coal) for the nine segment and 3- 5£ far the
preparation charge coal-preparation plant?.
The coat of compliance with EAT standards, aa with BPT standards, will
effect coal prices only to the extent that coal sold wo contract terms in-
cludes escalation clacsea for production coat increases and the spot laarket
reflects the general level of compliance by the industry. The siaximum in-
crease in price, assuming full compliance cost "pass through," vould be 1.3%
of the average pre compliance price (unprepared coal) Ear the Bine segment.
Cctl preparation plar.ta htve no adiirlar.al ccets for 3AT since PAT standards
are the aeme as EFT for preparation plants.
It should be stressed that price increases for compliance with BPT and
BAT atatidarda wiLl be lower to the extent that contracta do net have esca-
lation clauses.
The more important effect of compliance costs on coal prices, in the
long run, will be the rise occasioned by the HSPS compliance coats. New
mines will be developed only if they can recover their full costs, including
NSPS coats, and make a reasonable profit- The maximum increase in price
tflll be 1.8K of the precoepllance price in 19S0, 1.6% in 1985 for mines,
and 3.5% Ear preparation plants.
2. Financial Effects
a. Profitability
Ttie coet of compliance vicb BFT standards tor existing mines «ill result
fn lowered profits. The extent of the profit decrease will depend on whether
coal ie sold (1) cm the spat market, (2) through a contract without an esca-
lation clause in which cane t-Vva impact f-rafinability would be a maximum,
or (3) tliroti&h a contract i/lcTi en escalation clauae in which caae there
wojAti be no effect on profit. The maximum decrease in cash flow would he
10Bs than 6% of the preconpliance cash flow and reduction in profitability
would be less than 8.5% of the pre-tar. profit, prior to compliance tor mines
and preparation plants.
ii
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in the long run, we would expect that rooat contracts would have been
renegotiated before BAT compliance wae required, with coat "pass through"
provisions resulting In no effect: on the profit of existing nines di.v5 to com-
pliance with BAT standards.
NSPS compliance costs are net likely to affect profit ae new mines will
be developed only to the extent that th<=.y can meet all costs, inclusive of
compliance costs, and make a reasonable profit.
b. Capital Requirements and Availability
The highest capital requirements will be for the deep mines in northern
Appciachia—$0.36-0.45 per annual ton (per ton of annual production) for
BP L', and $0.24-0.69 per annual ton for incremental BAT, and for cosl-
preparation plants—$0.41 per annual ton. From a cash flow analysis of the
models, it seems that pollution control capital could be generated from re-
tained earnings, and capital availability then would not be a probletD. It
should be stressed that small producers tend to sell on the spot market,
which is subject to major fluctuations, and hence their cash flow situation
would likely be different from that predicted by the model. Such producers
might experience difficulties raising pollution control capital.
In the calculation of aggregate capital requirements, it was assumed,
as stated earlier, that all mines have a water problem and there is no in-
place treatment facility. This assumption would tend to overetate
impacts.
Aggregate BPT capital requirements amount to $132.1 million - $79.6
million for mines and $52.5 for preparation plants. In addition, $66.5
million are needed to meet BAT standards, resulting in $198.6 million for
existing mines and preparation plants. The annualized operating coats
amount to $115.6 million and operating and maintenance costs are $87.9
million.
NSPS capital requirements for mir.es were estimated at $106 and $126
'riillion for the $8 and $13 a barrel scenarios, respectively. The corre-
sponding requirements for preparation plants were estimated at $20-35
million.
Thus, the total capital requirements to meet effluent guidelines* were
estimated at $325-360 million to be spent by the coal industry. This
amounts to 3-4% of the capital requirements for expansion of the industry
to meet 1985 demand.
5
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3. Production Effects
a. Production Curtailments
The waste loads in coal mining are unrelated, or only indirectly related,
to production quantities. Hence, curtailing production dotfs not reduce the
pollutant load or the cost of water treatment. Production curtailment as a
result of effluent guidelines seems unlikely. The cost of compliance for
preparation plants is $0.07 a ton, that is somewhat output-dependent. It
is believed that this will not have a significant effect on the demand for
coal cleaning.
b. Closure Analysis
The criterion utilized in analyzing closures is that a mine would re-
main open if the price received for coal were sufficient to cover variable
costs, inclusive of an annualized deferred capital charge and an annualized
cofit of compliance, i.e., all costs exclusive of profits and sunk costs; if
not, it would close. The prices for coal, in the short run, were taken to
be the average 1975 price for the region and, in the long run, they were
taken to be those forecast by the PIES model.
No closures are predicted either in the short run or the long run under
the $8 and $13 a barrel imported oil demand scenarios for any of the model
mines and preparation plants.
The small segment in northern Appalachia has among the highest operating
costs associated with meeting effluent guidelines. Those in this segment
are subject to economic pressures, because they have to sell on the spot mar-
ket, which is subject to rapid and major fluctuations. It is therefore pos-
sible that some marginal operations may have to close.
A. Industry Growth
In our analysis, we used the PIES demand forecast for growth of the coal
industry in ]980 and 1985 as a baseline. Our main assumption was that the
long-run price of coal in each region would equal the minimum acceptable
price for the marginal (highest cost) new mine. This minimum acceptable
price would be increased by the cost of NSPS compliance. The compliance
costs would be fully "passed through" and quantities would be pared by the
long-run coefficient of price elasticity, taken to be -0.5 from the PIES
study. Price increases would range from 0.2 to 1.6%, while quantities
would be reduced by one-half these percentages. This translates to a maxi-
mum decrease in total quantity demanded of about 0.3% or 2.6 million tons
Ln 1980 and 2.8 million tons in 1985. Thus, there will still be significant
growth in the industry between now and 1985.
6
-------
5. Employment Effects
Since the analysis does not Indicate closure or production curtailments,
Ve have identified no adverse employment effects.
6. Community Impacta
Since the analysis does not Indicate cloaurea, production curtailments,
or employment reductions, we expect no adverse community impacts.
7. Balance-of-Payment Effects
Considering that about 85X of U.S. coal expoTta are metallurgical coal,
which ia more valuable than steam coal, that the remainder of coal exports
are alnv&Bt entirely shipped to Canada* that demand for coal exports is on
the whole inelastic, and that there are no ma^or imports of coal, we. antici-
pate no adverse Impacts on the balance of payments due to the effluent
guidelines.
8. Sensitivity Analysis
As stated earlier, electric utilities buy coal principally for the heat
value with credits or penalties for departures from the normal in ash con-
tent, ash fusion temperature, and sulfur and moisture content. The penal-
ties and credits have evolved over a period of time. Far example, the
importance of sulfur content has been highlighted by the requirements of
the Clean Air Act, since the early 1970'a. Hence, the price that a utility
will offer for a coal will depend on the above-mentioned coal quality attri-
butes and the cost of transportation from the mine to the utility, besides
other supply/demand consideration#.
It is reasonable to assume that a new mine producing low-quality coal
would not be developed, unless coal production costs are low enough to pro-
duce an adequate return on capital. Por existing i&inea, the quality of coal
would have been an Important consideration at the time the investment decision
was made. To the extent that the premiums or penalties associated with a
coal attribute have changed since the time the investment decision was srade,
such mines are likely to be at a disadvantage in trying to achieve compli-
ance with effluent guidelines, in that their competitive posture vis-a-vis
other mines in the region deteriorates.
In the case of sulfur content, its importance has Increased since the
early 1970's, and for such mines the effect of sulfur content on value is
likely to have been considered. For older mines, it is to be noted that coBts
and prices of all coal have risen significantly in the 1969-75 period. It
is possible, however, that there are a few mines producing a lower value coal
and having a large water pollution problem that are likely ta be affected
adversely and might cloBe because their already unfavorable competitive posi-
tion further deteriorates because of high effluent guideline compliance costs.
7
-------
From the available data it was not possible to separate the effects of
coal quality and transportation, nor to isolate the effect of any individual
coal quality attribute on the value of coal in a given region. The data on
prices, on a delivered basis, paid by utilities from the Federal Power Com-
mission statistics do not allow for the separation and effect of coal quality
and transportation aspects on the price of coal. The other main source of
data is the Bureau of Mines' value f.o.b. mines.
The effect of variation in value f.o.b. mine by states in a region and
by type of mining on the closure decision was examined. No closures were
Indicated in any of the regions.
E. LIMITS TO THE ANALYSIS
The analysis presented in the report has the following limitations:
• The analysis is based on a modelling approach, which is necessary
because of the large number of establishments in the segment.
Site specific factors could result in higher coal production
costs—variation in topography, seam thickness, overburden depth,
etc., and/or compliance cost—high flow rates, pollutant loads
leading to slightly more or less severe impacts than that predicted
by an analysis of the model.
• The analysis evaluates the impact of effluent guidelines alone.
A number of other regulations, such as additional federal strip
mine regulations and clean air requirements, could influence
the cost of producing coal.
9 Coal demand and prices in the future on a regional basis were ob-
tained and modified from the Project Independence Evaluation System
(PIES) study. This analysis is subject to all the limitations of
the PIES study.
8
-------
I. INDUSTRY STRUCTURE
A. INTRODUCTION
Coal is known to be a complex mixture of plant substances which have
been altered in varying degrees by physical and chemical processes. The
first stage is the conversion of plant material into a brown fibrous deposit
called peat; in the course of time the peat, subject to the necessary envi-
ronment, becomes modified to brown coal, lignite and progressively through
sub-bituminous and bituminous to anthracite. The degree of metarao.rphism in
the coal series from lignite to anthracite is referred to as the rar.k of the
coal.
Lignite is usually brown in color and has woody texture. It has a high
moisture content (35 to 45%), relatively low heat value (6 to 8 thousand Btu
per lb), and disintegrates to a granular powder when exposed to the weather
for long periods of time. Sub-bituminous coal varies from a very dark brown
to black color, has half as much moisture as lignite (15 to 30%), slightly
higher heat value (8 to 10 thousand Btu per lb), and the same weathering
characteristics. Both lignite and sub-bituminous coal are primarily used
an steam boiler fuel for the generation of electricity.
Bituminous coal is the most abundant and widespread rank of coal used
in' the United States. It is used for electrical utility and industrial
power generation, production of metallurgical coke and for space heating
purposes. Bituminous coal may be either coking or non-coking, I.e., whether
or not it produces a suitable coke when processed in a coke oven. Most coals
mined in the Appalachian region have coking or caking characteristics to a
degree. The heat value of bituminous coal is considerably higher (10 to 1A
thousand Btu per lb), fixed carbon varies from 69-86%, and volatile matter,
14-31%. Lignite, sub-bituminous, and bituminous coals are referred to as
soft coal.
Anthracite, referred to as hard coal5 is black,, bard„ brittle and haB
a high luster. It burns with a short bluish flame and little eraoke. An-
thracite has a higher percentage of fixed carbon (36-98%) and e. .lowsr percent-
age of volatile matter (2-14%) than lower rank coala.
Coal consists of combustible and non-combustible material, The combust-
ible material contains carbon, hydrogen, and sulfur and the non-combustible
material, nitrogen, water, and mineral matter referred to as ash.
Coals vary in quality and it Is necessary to know the chemical analysie
in order to evaluate it for a specific use. The quality of coal determines
Its value. Not only do various coal beds have different properties, but
even a given seam can vary from area to area. Sometimes even within a given
mine, there can be variations in the ash, sulfur or even volatile matter con-
tent of coal.
Electrical utilities pay for the coal on its effective heat value, pri-
marily with some credit or penalty as to departure from the norm of ash,
1-1
-------
sulfur, and moisture contents. Emission limitation requirements on S0X
associated with the clean air standards have made sulfur content increasingly
impor tant.
Steel companies Judge coal as to its coking strength, expansion, ash,
sulfur, phosphorus, carbon content and how it blends with other coals to
make good coke.
B. COAL MINING AND PREPARATION TECHNOLOGY
The U.S. coal mining industry, from a technological standpoint, may be
considered to comprise raining—dealing with the removal of coal from the
ground, and coal preparation—and processing of mined coal to remove waste
materials, such as slate and rock, to give a better value product. On ac-
count of variations in the mining methods of hard and soft coal, these have
been considered separately.
1. "Soft" Coal Segment (Bituminous, Sub-bituminous and Lignite)
Three methods are used to extract "soft" coal in the United States:
o Underground (or deep) mining,
e Strip (or surface) mining, and
• Auger mining.
The particular method adopted in a specific mine is determined by seam
topography and physical characteristics such as thickness and depth below
the surface. These factors also influence the economics of coal extraction.
Seams may vary in thickness from less than one foot to as much as 100 feet,
although for economic reasons only those thicker than 30 inches are commer-
cially exploitable at present. Current technology of coal extraction limits
the maximum depth of exploitable reserves to about 3,000 feet below the sur-
face .
Underground mining Ln the United States can be categorized as room-
nnd-pillnv mining and longwall mining. In room-and-pillar mining, entries
into the coal body serve as haulage ways and fan out into the coal bed with
side or cross entries from which coal is removed to form rooms. As much
as 50% of the conl is left to support the roof. In the longwall method,
a continuous mining face Is maintained in the coal seam. After mining, the
roof is permitted to settle, 30-50 feet from the working face. A signif-
icant machine development has been the "continuous miner" that breaks the
coal mechanically and loads it for transport, and is provided with roof
supports. Another development is a short-belt conveyor system to move
coal from continuous mining machines to the main haulage system without the
use of shuttle cars.
1-2
-------
Surface raining involves the removal of overburden to expose the coal
Htam for extraction and loading. Surface mining can be divided into two
broad classes: contour mining and area mining. Contour mining is employed
in hilly areas. The coal pits are usually developed in the form of long,
narrow strips, each of which follows a certain contour interval around a
hill. Area mining is uBed in flat or slightly rolling areas where the coal
seams are relatively flat. The pits are developed in a series of long,
narrow strips. As the mining progresses, the overburden from each strip is
cast back into an open pit from the previous strip. Typical surface mining
equipment includes the shovel, dragline, and wheel to remove overburden from
the coal seam. Draglines are the most popular surface mining equipment for
the recovery of moderate depth coal seams.
When the economic limit is reached in normal surface mining, the coal
seam remians exposed at the bottom of the last highwall. One of the methods
of recovering the coal is by auger mining. Auger mining derives its name be-
cause a large auger is employed as a cutting head. The auger is similar to
an auger used to bore holes in a piece of wood; it penetrates deeper into
the coal and discharges coal along the spiral of the auger. Additional
n'iger lengths are added as the cutting head of the auger penetrates further
under the highwall into the coal. Augers often can recover coal that is
physically or economically impossible to recover by any other means.
The trends in bituminous coal mining methods for the period 1940-1973
are .shown in Figure 1.
2. Anthracite ("Hard" Coal) Mining
The anthracite district of northeastern Pennyslvania is generally cha-
racterized by steeply dipping, folded, and faulted sedimentation. Anthra-
cite seams vary in thickness from district to district and can range from
partings of one foot to major seams averaging 36 feet.
Four methods are currently employed in mining anthracite: deep
mining, strip mining, culm bank reprocessing, and dredging. Deep and strip
mining have been discussed in reference to "soft" coal.
Lower recovery costs have made old culm and silt banks dumped in the
early days of anthracite mining an important source of fine sized coal.
The culm material, formerly regarded as waste, is currently trucked to
preparation plants for reprocessing.
Dredging operations are found on the Susquehanna and Schuylkill Rivers.
Fine coals which have accumulated from erosion of mine waste and culm and
silt banks are recovered by means of suction devices and then processed,
washed, and sized on board the dredge.
1-3
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100
90
VI
70
60
50
30
20
to
0
1
10 1942 law 1946 1S4B 1960 1962 1954 1956 1958 1960 5962 1964 1966 196B 1970 1972 1373
ree: U.S. Bureau of Mines
FIGURE 1 MINING METHODS USED IN UNITED STATES BITUMINOUS COAL PRODUCTION
-------
3. Coal Cleaning and Preparation
The objective of coal cleaning is to r&;oove foreign matter,aueh as cock
and slate, from coal. The advantages thus derived are a reduction in «sh
and sulfur content, contra2 of e.sh iuaibility, increase in calorific valuet
and improvement of coking properties. The need to clean c^al prior to ship-
ment has resulted from factors such rb the adoption of mechanized mining
that does not differentiate between coal and impurities and the imposition
of stringent quality specifications by consumers. Mechanical cleaning of
coal la possible because of the difference in Bpaciflc gravity bissvsen the
free impurity (1.7-4.9) and coal (1.3). Generally, clean-tug processes are
classified a6 gravity-based stratification or non-gravity processes„ In-
cluded in the former category are wet processes such as launder washersc
jigs, classifiers, and tables; the non-gravity category includes the heavy
media methods (in air or water) na well s.3 froth flotation.
C. COAL-PRODUCING FIRMS
A fina (company) ia defined as «. business organization selling coal aa
Its product, as distinguished fross a pi*vnt or establishment which could be
a mine, preparation plant,, or rdne and pr«pfi,r«£ion plant which produces or
prepares the coal. Thus, a firro wight ovm sevfiral mines'preparation plants.
In 1973„ the coal mining Industry in the United States comprised about
5,000 active mines and 400 preparation plants operated by approximately
4,2QO firms. Thia industry, ever, though not. displaying high «-tJ.c?.nt»:atioti>
1b indaed dominated by a small number of. firms „ 7he concentration ratios,
defined as the percentage of the production of the four largest companies to
the total U.S. production. are shown in Tab Is 1. This rar.io has been In
the range of 26-32 percent in. rfecso.t. years. Of the 4,,000 companies producing
bituminoua coal and lignite in 1973. the top four accounted for 27.9 percent
of the production; the top 15 PAstw w®re responsible fox 49.5 percent; the
top 50 produced 66,4 percent of thp production, and about 600 corjpaniee ac-
counted for about 97% of the output,. 0£ the ISI ccupanies involved in pro-
ducing anthracite in 197 the top 4 firms accounted for 31.5 percent of
the output and the top 20 about 75% cf the output-
1. Bitumlaoua Coal and Lignite
About 4,000 companies produce bituminous coal and lignite. These com-
panies operate mines and preparation pianos. A coal preparation plant ia
usually apaoci-ated with a lar.ge mine and generally cleans the coal from
thar mine. The output from a nuaibei of snail ex mineB might be handled by
a preparation plant, either £or a fee or by buying the coal. It ie to be
noted that some of the coal i.e aclc. without cleaning.
The top 15 firms are listed in Table 2, along with date on their owner-
ahipa, coal production in 1972 and 1.973. sad relative rankings, in terms
of coal output since 1965. Tv?c. companies,, Peabody Coal Company end
-------
AnthracIte
TABLE 1
CONCENTRATION RATIOS IN COAL MINING
Bituminous
Coal & Lignite
1970
1971
1972
1973
1974
Production of
Top Four Companies
Million Tons*
174.0
148.1
171.7
164.9
153.4
U.S. Production
Million Tons*
602.9
552.2
595.4
591.7
590.0
Concentration
Ratio Percent
28.9
26.8
28.8
27.9
26.0
1973
2.15
6.83
31.5
*Tons in subsequent tables refers to short tons.
Source: U.S. Bureau of Mines, Keystone Coal Industry Manual,
Pennsylvania Department of Environmental Resources.
1-6
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TABLE 2
TOP 15 COAL-PRODUCING GROUPS IN 1973
Company
Ownership
Coal Production
Relative Standing
(million
tons)
1973
1972
1973
1972
1971
1970
1965
Psabody Coal Co.
Kennecott*
69.92
71.6
1
1
1
1
1
Consolidation Coal Co.
Continental Oil
60.5
64.9
2
2
2
2
2
Island Creek Coal Co.
Occidental
22.9
22.6
3
3
3
3
3
Plttston Co.
Public
18.8
20.6
4
4
4
4
5
Assax Group
iimax
16. 7
16.4
5
5
5
5
4
U.S. Steel Corp.
Public
16.2
16.3
6
6
6
8
9
Beth.lehea Mines Corp,
Bethlehem Steal
14,1
13,3
7
7
7
6
7
llorth American Coal Corp.
Public
12.5
12,0
8
9
11
12
12
Old Ben Coal Corp.
Sohio
10.8
11.2
9
10
10
10
11
Eastern Assoc. Coal Corp.
Eastern Gas 6 Fuel
10,6
12,5
10
8
8
7
8
Wastmoreland Coal Co.
Public
8.8
9.1
11
12
12
11
13
General Dynamics Corp.
Public
8.7
10,0
12
11
9
9
6
Pittsburg & Midway
Gulf Oil
8,1
7,5
13
13
13
13
10
Utah International, Inc.
Public
7,4
6o 9
14
14
14
14
31
American Electric Power
Public
6,6
6.3
15
15
15
17
20
Total
292,6
301.2
*Currenfcly under U.S. Supreme Court order to divest itself of Peabody Coal Company.
Source: 1974 Keystone Coal Industry Manual
-------
Consolidation Coal Company, with their subsidiaries, accounted for 22% of
the bituminous coal production in 1973. The top 15 firms were responsible
for 49.5%, while the top 50 accounted for 66.4%. A more detailed breakdown
of bituminous coal production by the approximately 4,000 companies for 1973
is shown in Table 3.
Firms producing a million tons or more in 1973 were responsible for
nearly 75% of total output. Of this group, about 26% was controlled by
the coal industry itself. The oil Industry controlled about 14%, steel and
utilities about 12% each, and decreasing percentages by other industries.
The large-scale acquisition of coal companies by "outside" industries
was a phenomenon of the late 1960's and early 1970'a. The coal industry
characteristically had experienced poor profits and its management was re-
garded as largely outdated. Operators thus were not averse to selling out
at an acceptable price. The buyers, frequently large (petroleum) energy
groups, saw the acquisition of a coal producer as a means of diversification
into another energy source, or of obtaining coal reserves in anticipation
of substantial growth in coal-utilizing industries. The utilities, chemi-
cals, and metals firms generally acquired coal companies as a means of
guaranteeing themselves adequate raw material supplies at economical and
controllable prices.
Besides the large producers, the bulk of the coal mining firms are
small independent operators or family-owned mines. These companies, though
numerous, account for a far smaller proportion of the total coal production
than the large firms. Over the last several years, these smaller firms
have been forced to yield to economic pressures, such as the necessity to
sell in spot markets which tend to be volatile, and the trend toward
greater concentration in the industry is expected to continue.
2. Anthracite
Data from the Pennsylvania Department of Environmental Resources indi-
cate that in 1973 there were about 181 companies involved in anthracite
production. These companies operated one or more of the following types
of facilities: deep mines, strip mines, culm bank mines, cleaning plants,
or breaker preparation plants. All non-dredge anthracite is prepared prior
to shipment. Of these companies, only the 20 listed in Table 4 produced
in excess of 50,000 tons of shippable anthracite. Their cumulative produc-
tion amounted to about 5.1 million tons, equivalent to about 75% of the
total output of anthracite. A more detailed breakdown of anthracite produc-
tion for 1972 is shown in Table 5. The balance of the producers are typi-
cally single-facility operations that serve specific local customers. In-
dications are that, with time, these small operators may succumb to the
economic and market pressures afflicting the anthracite industry, reeulting
in a general consolidation and concentration of the Industry in the hands
of a few relatively large firms.
1-8
-------
TABLE 3
SHARS 0? PRODUCTION OF U.S. COAL IN 1973
(by company and/or group)*
Annual Production
(cons J
3,000,000 and over
2,000,000 to 2,999,999
1,000,000 to 1,999,399
700,000 to 999,559
500,000 to 699,999
400,000 to 499,999
5CO,000 co 399,599
200,000 to 299,999
100,000 to 199,999
Less than 100,000
Nuafcer Busbar
of Groups emulative ol Cqgaa&les
31 31
\9 50 27
30 60 43
20 100 25
33 133 34
32 165 34
64 229 44
88 317 38
212 529 213
3f39S
Firceic of
Total Production
Cumulative By Coiaaiea CtuAatWe
7k .61.42 61.42
101 7.SO 69.22
144 6.40 76.02
169 2.86 73.38
203 3.30 32.IS
237 2.38 34.56
301 3.70 SA.lt
389 3.60 91.36
602 5.OA 96-90
4,000 3.10 1&0.0Q
*Group refers to on affiliation of producing coeponles.
Source: Keystone Coal Industry Manual, 1973.
-------
'i !\x Li- 4
SOP a& PS'i&BCEte ftg AKTMKACITE IR 19?3
Itar-sl
Og&rator tTtti-c.C-vi.ap.
Readier Aarftrscic-e £t>. 157,75-9
Jeddo-Higlii&tid Coal to. 572^8(39
fclue Eoal C&Tfloretlon 459,969
Stctp?i3g Corporation Vt
Ko^tier Coal Co., Ins., Ivesn. £- 326,266
Le.fitg/i Valley Aiithta-C-lt-es.. Inc. 324,390
Manbeck Dredging Co,, lac. 2fS,8QO
CiicerEOT! fwl it.
Hecla rfetiiiaecy 4 Equipmeot Ct». Z* S 2 £
Uaitij^ See lapr-ovKhent CoTf Jitliw. 2£-4,935
3-l>
Sfejrris i ifelirVet, Ir.c. tfj ,6S£
Etictsai Eassrp-rlass, lac, A75.7&?
G-Lea^San, Inc. 164,153
S-cvsli-.l CsttraiUnS 1^7,129
Tye«i«F.ftC XLnLvg. Co., ;3C. 97,393
Spilt Vein C?al Co., la;- 6
-------
TABLE 5
SMSE OF PRODUCTION OF ANTHRACITE BY COMPANY MID/OR AiTILIATZS Hi 1972
% of Total
Annual Production Huebsr Cijt'.LlatIte Nuzbsr Ci*Bul2ti^e .1972 Cifaailailve ProduC.ioi Cimilati-TS
(siiort tcsa) of Croups Tiital of. Cogoaaies Total Tcsiiage Total b? Claaa Total
500,0G0 to 999,999 2 2 3 3 1,759,C,9B 1,759,038 27.iO 27.20
7' 200,000 to 499,999 9 11 9 12 2,512,fJ68 4,271,96(5 39.00 66.TO
i_ 1
M 100,000 to 199,999 5 IS 5 17 303,022 5,079,983 12.54 7S.34
Lass than 100,000* 193 215 1,353,236 6,443,224 21.16 1G0.C1
aAll flgurss for ihis category are astiaatea.
Source: Ho«ll£leri frca Keystone Coal Industrial Xnn-jal.
-------
D. SEGMENTATION OF MINES AND PREPARATION PLANTS
The U.S. coal industry has been sagmented into coal mining and prepara-
tion segments from a technological standpoint. In addition, as there were
differences in mining methods for anthracite (culm bank recovery, dredging),
and as this sector has been showing a declining anthracite output (hard coal),
mining was considered as a separate segment. Soft coal mining was further
categorized by geographic region, type of mining, and size of mining opera-
tion. Figure 2 presents the characterization scheme adopted for the U.S.
coal industry.
1. Soft Coal Mines
Table 6 shows the distribution of active bituminous coal and lignite
mines as a function of mine size for the period 1960-73. The total number
of mines declined from 7,875 in 1960 to 4,744 in 1973. Virtually all of
this decline occurred in the less than 10,000 net ton category, decreasing
from 4,645 in 1960 to 1,093 in 1973. All other categories remained rela-
tively stable or increased in number.
In terms of the proportionate share of coal production, all except the
largest have lost ground since 1960. The over-50.000 tons per year category
has increased its share of total production from 49% in 1960 to 58% in 1973.
On the other hand, the combined shares of Lhe two smallest categories have
slipped from 15.5% to 9.8%.
Tables 7 and 8 represent the number cf mines and production derived
from 1973 statistics from the U.S. Bureau of Mines—by mine size, mine type,
and region.
Nearly 60% of the nation's coal mines were located in northern Appalachia
and accounted for about 46% of the total production. Auger mines accounted
for 11% of the mines in the region and 2% of the production in this region.
Southern Appalachia had the following distribution for its 1,586 mines—41%
underground, 34% strip and 25% auger.
The Central region had 226 mines (4.8% of the national total), but
accounted for a far higher proportion of "soft" coal output in 1973—i.e.,
26%. In this region there were three times as many strip mines as under-
ground mines, and strip mines accounted for almost two-thirds of the region's
coal production.
Only 1% of the nation's coal mines was located in the Intermountain
region, but these accounted for 4% of the "soft" coal production. In the
Great Plains and West regions, strip mine? dominate coal production.
Table 9 shows the distribution of employment, based on 1973 statistics
from the U.S. Bureau of Mines. Northern Aopalachian mines accounted for
nearly 86,000 workers, of whom 55,000 were employed in underground mines
producing over 200,000 tons per year. Small mines with coal outputs of
1-12
-------
FIGURE 2 CHARACTER]ZATKEQ SCK3MI FOB til COAL KWSTRt
-------
TABLE 6
PRODUCTION OF BITUMINOUS COAL BY SIZE OF MINE OUTPUT
Over
200,000-
100,000-
50,000-
10,000-
Less than
500,000
500,000
200,000
100,000
50,000
10,000
Year
Tons
Tons
Tons
Tons
Tons
Tons
Total
NUMBER
OF MINES
1960
202
258
262
396
2,102
4,645
7,865
1961
195
225
242
420
2,183
4,383
7,648
1962
204
240
255
414
2,201
4,426
7,740
1963
224
242
262
499
2,250
4,463
7,940
1964
238
220
270
553
2,299
4,050
7,630
1965
259
224
279
555
2,367
3,544
7,228
1966
274
221
327
589
2,386
2,952
6,749
1967
281
244
267
542
2,079
2,360
5,873
1968
275
260
249
533
1,951
1,959
5,327
1969
295
263
352
524
1,898
1,786
5,118
1970
30/
266
405
617
2,104
1,902
5,601
1971
256
313
408
671
1,888
i ¦> 611
5,149
1972
280
417
617
1,945
1,310
4,879
1973
280
30a
384
600
25C79
1,093
£>744
PRODUCTION (THOUSANDS OF
TONS)
1960
204,999
81,013
37,204
27,894
44,238
20,164
415,512
1961
202,923
73,118
33,694
30,325
45,682
17,235
402,977
1962
213,772
76,458
35,878
28,831
48,463
18,748
422,149
1963
242,548
77,411
36,001
33,745
49,821
19,403
458,928
1964
267,363
73,893
37,540
37,985
52,695
17,523
486,998
1965
292,707
71,897
39,498
38,390
54,311
15,285
512,088
1966
308.868
70,177
45,220
41,335
55,212
13,068
533,881
1967
326,578
77,011
51,787
37,695
49,398
10,159
552,626
1968
318,938
84,118
48,822
27,890
46,576
8,898
545,245
1969
337,683
83,370
48,770
37,108
45,649
7,925
560,505
1970
359,516
84,297
55,729
43,310
50,849
9,227
602,932
1971
294,171
97,661
58,096
46,920
47,576
7,772
552,192
1972
336,604
100,313
58,523
44,072
48,708
7,165
595,386
1973
344,380
95,074
52,629
41,707
52,391
5,553
591,738
Source: U.S. Bureau of Mines
1-14
-------
TABLE 7
DISTRIBUTION OF "SOFT" COAL MINES BY SIZE OF PRODUCTION AND TYPE OF MINE IN 1973
Region Number of Mines in Category:
>200,000
Tons/Yr/Mine
^200,000
Tons/Yr/Mine
Underground
Strip
Auger
Underground
Strip
Auger
Northern Appalachia
249
59
737
1484
308
Southern Appalachia
65
53
1
586
493
388
Central
41
73
14
98
Intermountain
17
7
21
7
1
Great Plains
1
20
5
12
West
2
1
TOTAL
373
214
1
1364
2095
697
Source: U.S. Bureau of Mines
-------
TAELE 3
^ISTSESZTIG^ 0
? ''SCFT' CCai. P&O^JECTKF.
v; AtSfz
alii «a> TYTE
K 1972
55Ei«J
Cxssli.-
1
tva "t-s.1
Ten 5j'v >ja»5
la
— —
>ZOO,000 Toas^fr/lOua
S2QO.OOC
To&s/Vr/Hirae
ISortftero JippaVacVLa :
Cm tie rgrauncf
147,fifiO
Scrip
29,986
Auger
L'cd&rqround
33,5J2
Strip Ayger
56,^15 5,52?f
Southern Appalachia
31,686
19,055
26?
16,121
20,276 9,905,
'
Central
55,181
93,511
—
1,019
3,5 jo —• ;
Inee^mountain
8,097
13,794
1,497
623 ^31
Great Flaius
315
31,739
Ill
353
—
3*940
—,
TOTAL
2&5.159
25?
5^,335
Slf3:5 15,*71
Sc-urca: U.S. Bureau of Jttives
-------
TABLE 9
DISTRIBUTION OF EMPLOYMENT IN "SOFT" COAL MINES BY SIZE AND TYPE OF MINE IN 1973
Region
Total Number of Employees In Category
>200,000 Tons/Yr/Mine
<200,000 Tons/Yr/Mine
Underground
Strip
Auger
Underground
Strip
Auger
Northern Appalachia
55,294
4,750
12,972
11,611
1,264
Southern Appalachia
13,997
3,228
45
7,524
3,515
1,653
Central
12,043
9,795
202
757
Intermountain
2,462
784
457
40
9
Great Plains
126
1,380
49
15
West
375
Sub-Totals
83,922
20,312
45
21,220
15,939
2,926
Source: Derived from U.S. Bureau of Mines' manpower productivity data.
-------
lesa than 200,000 tons per year accounted for 25,847 employees, about 30%
of l:he total.
Table 10 summarizes the relationship of each segment to the soft coal
mining segment of the industry in terms of the number of mines, production,
and employment.
2. Hard Coal Mines
Table 11 shows the production from anthracite mines by type of mining
for the period 1960-73. The total anthracite production declined from
18.8 million tons in 1960 to 6.8 million tons in 1973. The production from
the deep-mine category declined from 7.7 million tons in 1960 to 0.7 million
ton in 1973 and the production from strip mines from 7.1 million tons in
1960 to 3.3 million tons. The production from culm bank processing declined
from 3.3 million tons to 2.4 million tons and from dredging operations from
0.7 to 0.4 million ton.
Table 12 shows the distribution of the number of mines, production, and
employment for anthracite, based on data from the Pennsylvania Department on
Environmental Resources.
Strip mining was the dominant mining method, accounting for 45% of the
mines, 48% of anthracite production, and 60% of employment.
The trend for both strip and underground mines has been one of declin-
ing output. In 1963, strip mines accounted for 7.5 million tons of anthra-
cite compared with 2.5 million tons in 1973. This is due to the scarcity
of economically strippable reserves. The decline in underground anthracite
output may be related to the fact that it is becoming increasingly more
expensive to extract anthracite by underground methods from steeply dipping
seams at greater depths. Culm and silt bank recovery is currently a signif-
icant source of anthracite „ but Its proportionate share is likely tc decrease
as the quantity available from this source is limited.
Table 13 summarizes the relationship of each segment to the hard coal
mining segment of the industry in terms of the number of mines, production,
and employment.
3. Coal Preparation
Table 1.4 presents the trends in soft coal cleaning for the period
1960-1973. The number of preparation plants have declined, but the amount
cleaned has increased, reflecting the larger sizes of newer plants. The
percentage of total production cleaned declined from 66 to 49 percent, prob-
ably reflecting the increasing tonnage of coal from the west that does not
require cleaning. The trends reflect the result of the Federal Coal Mine
Health and Safety Act of 1969 and the Clean Air Act. Most of the hard coal
produced has generally been prepared.
I-IB
-------
TAJBLE 10
gptasa :»j Fjacuciuoa «>i» c-runrc-^.T as
FZSCEKTAGES OF TV1E SOFT COAL SEGMENT CF THt iS.,5, INDUSTRY IN 19/3
H. Appalachia
No- of Mines
Production
Employment
Beep
Large
5.3
25.0
38.3
Small
15.5
5.7
9.0
StrlP
Larfie
1.2
5.0
3.3
Small
31.3
9.6
&.1
Auger
Large
x
x
X
Small
6.5
1.0
0.9
Subtotals
59.8
46.2
59.5
5. Appale-Chia
Ho. nf Hines
?taduttW3
EnployafiBi
l.U
5,7
S.}
12.3
3.1
5.2
1.1
2 .2
10.4
1-5
2,5
0-j
x
8.2
1.7
1.2
33.4
17^2
20.&
i
a—
v?
Central
No. of Mines
Production
Employment
Iptetf&cmptain
So. of Mines
Ptoiuccic-t
Employment
0 .9
9.3
8.3
OA
I A
1.7
0.3
0.2
0.1
Q.S
0.2
0.4
1.5
16.1
5.6
0.2
2.3
0.5
2,1
e.6
0.5
0.1
OJ
T.
X
X
X
4.8
26.3
15.6
1.1
4.1
2.6
Great Plains
Ho. o£ Mines
Production
Employment
x
0.1
0.1
0.1
x
x
0.4
5.4
1.0
0.2
0.1
x
O.S
5.4
1-1
\iest
No. af Nines
Production
Enployn-ett
x
x
x
x
0.7
0.3
x
E
X
D.l
0.7
13.3
Note: % ~
-------
TABLE 11
ANTHRACITE PRODUCTION BY MINE TYPE
(THOUSANDS OF TONS)
YEAR MINE TYPE TOTAL
Deep
Strip
Culm Bank
Dredge
1960
7696
7112
3297
712
18,817
1961
6785
7247
2669
746
17,447
1962
6673
6822
2671
727
16,894
1963
6715
7468
3393
692
18,267
1964
5889
7177
3413
705
17,184
1965
5297
5939
2930
700
14,866
1966
4088
5253
2938
662
12,979
1967
3258
4740
3627
632
12,256
1968
2450
4696
3709
606
11,461
1969
2106
4579
3253
535
10,473
1970
1742
4541
3036
409
9,728
1971
1287
4478
2573
390
8,728
1972
944
3483
2202
477
7,106
1973
726
3279
2384
441
6,830
Source: U.S. Bureau of Mines Minerals Yearbook
1-20
-------
TABLE 12
CHARACTERIZATION OF ANTHRACITE INDUSTRY
BY MINE SIZE AND MINING METHOD IN 1973
UNDERGROUND
STRIP
CULM BANKS
Number of Mines
1973 Production (10^ tons)
Mine Employment
>50,000 <50,000
Tons/Mine Tons/Mine
2 70
243 483
286 430
>50,000 <50*000
Tons/Mine Tone/Mine
17
2,336
814
99
943
819
>50,000 <50,000
Tone/Mine Tone/Mine
12
1,393
104
50
991
223
Source: 1973 Annual Report of the Pennsylvania Department of Environmental Resources
-------
TABLE 13
NUMBER OF MINES. PRODUCTION AND EMPLOYMENT AS
PERCENTAGES OF THE HARD COAL SEGMENT OF THE U.S. INDUSTRY IN 1973
Deep Strip Subtotals
Large
Small
Large
Small
No. of Mines
0.8
28.0
6.8
39.6
75.2
Production
3.8
7.5
36.6
14.8
62.7
Employment
10.7
16.1
30.4
30.6
87.8
Source: U.S. Bureau of Mines.
1-22
-------
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
TABLE 14
TRENDS IN CLEANING AT SOFT COAL MINES
Number of
Cleaning Plants
Cleaned Coal
(106 Tons)
Total Coal
Production
(106 Tons)
Percentage of
Coal Production
Cleaned
535
273.2
415.5
65.7
503
264.7
403.0
65.7
508
271.6
422.1
64.3
499
289.5
458.9
63.1
495
310.2
487.0
63.7
497
332.3
512.1
64.9
486
340.6
553.9
63.8
471
349.4
552.6
63.2
454
340.9
545.2
62.5
435
334.8
560.5
59.7
415
323.4
602.9
53.6
411
271.4
552.2
49.2
408
292.8
595.4
49.2
382
288.9
591.7
48.8
1-23
-------
a. "Soft" Coal
Table 15 Indicates that only about half of U.S. "soft" coal production
In 1973 had been cleaned prior to shipment to the consumers. Ninety-five
percent of the active cleaning plants were located In Northern and Southern
Appalachia and In the Central Region.
It should be pointed out that over 96% of the cleaned coal shipments
In 1973 involved "wet" processes which had the potential of generating
liquid effluents.
A more detailed breakdown of the cleaning plants by states is given in
Table 16. It Is worth indicating that the metallurgical coal-producing
states (Alabama, Eastern Kentucky, Pennsylvania, Utah, and West Virginia)
In 1973 accounted for a combined total of about 250 of the 382 cleaning
plants, producing 159 million tons of cleaned coal (55% of the total), in
addition, the high-sulfur coal states of Ohio, Western Kentucky, Illinois,
and Indiana contributed 81 plants and more than 102 million tons of coal.
Coal cleaning is not generally practiced in the sub-bituminous and lignitic
coal regions of the Great Plains and the West.
Table 16 also suggests that jigs, heavy media separation, and water
tables are, in that order, the most popular mechanical cleaning techniques.
Their percentage contributions to the total cleaned coal output in 1973
were, respectively, 46%, 31%, and 12%.
b. "Hard" Coal
To remove shale, slate, and other contaminants recovered along with the
coal during mining, and to meet the quality specifications set by the con-
suming markets, it is necessary to clean all non-dredge Pennsylvania anthra-
cite prior to shipment.
Table 17 is a listing of the major cleaning plants operating in 1973.
Estimated daily cleaned coal capacity is about 36,600 tons, equivalent to
an annual value of 9.2 million tons on the basis of 250 operating days
per year at full capacity. Actual preparation plant output in 1973
(excluding dredge production) was 6.A million tons, suggesting an apparent
capacity utilization in that year of about 70%.
It may be noted from Table 17 that the heavy-media, washing, and water
table techniques are the preferred methods of anthracite preparation.
1-24
-------
TABLE 15
REGIONAL CHARACTERIZATION OF
"SOFT" COAL CLEANING PLANTS IN 1973
Numbax of Cleaning Cleaned Coal Percent of Total
Region Plants Production Coal Production
(103 Tons)
Northern Appalachia 241 153,687 56.6
Southern Appalachla 54 35,114 34.6
Central 67 88,107 61.7
Intermountain 10 5,237 ^21.8
Great Plains W.A. W.A. N.A.
West 3 3,312 63,6
Other States* _7 3,460 5.7
Total 382 288,918 48.8
"Includes Arizona, Arkansas, Towa, Kansas, Maryland, Missouri,
Montana, New Mexico, "North Dakota, Texas, end Wyoming.
Source: U.S. Bureau oE tfines
1-25
-------
TABLE 16
DISTRIBUTION OF MECHANICAL COAL CLEAMIHG PLANTS BY STATES IN 1973
No. of
Total Cleaned
Ho.
of Plants
i Employing. Clearing
Methods*
Cleaning
Coal Production,
Air
Heavy-
Water
State
Plants
(1Q3 tons)
Ji»s
Tables
Flotation
Media
Tables
Hasher
Alabama
19
11,705
12
__
3
7
12
3
Alaska
1
50
-Not Available:
Colorado
3
1,662
—
—
1
3
—
—
Illinois
36
46,091
14
2
4
12
4
10
Indiana
10
19,699
5
—
—
—
1
5
Kentucky:
Eastern
33
22,264
20
3
11
31
21
15
Western
18
20,005
Ohio
17
14,588
83
2
—
5
1
6
Alt 1 nh Amn
1
11 7
.-.Writ- 1 iKI r-i— -
uK_ia noma
J
sji. &
—not
Pennsylvania
(Bituminous)
68
45,731
13
25
13
29
15
6
Tennessee
2
1,145
1
1
—
2
1
—
Utah
7
3,575
2
—
1
1
1
1
Virginia
32
17,696
16
8
10
17
12
6
Washington
. 2
3,262
1
—
—
—
—
—
West Virginia
124
75,672
42
18
47
97
57
15
Other States
5
3,460
2
3
1
1
2
TOTAL
382
288,918
136
62
91
205
125
69
Glean coal production by each method
(10^ tons):
132,655
10,505
14,201
88,203
34,935
8,418
*A plant may employ more than one cleaning method.
Source: U.S. Bureau of Mines; 1973 Mineral Industry Surveys; 1974 Keystone Coal Industry Manual.
-------
TABLE 17
PENNSYLVANIA ANTHRACITE PREPARATION PLANTS IN 1973
Cleaned Coal
Capacity Cleaning
Company/Location Plant Name (tone/day) Method(s)*
Blaschak Coal Co., Inc., Nicholas
Blaschak
1,050
W
Blue Coal Corp., Ashley
Huber
7,500#
HM-W
Taylor
Taylor
HM
Buckley Coal Co., Eckley
Eckley
800
HM-W
Cass Contr. Co., Marlin
Marlin
450
HM-W
Gilberton Coal Co., Gilberton
Gilberton
1,000
HM-W
Glen Burn Colliery, Shamokln
Glen Burn
1,800
HM
Gowen Coal Co., Fern Glen
Gowen
600
HM-WT
Greenwood Min. Co., Tamaqua
Greenwood
6,000
HM-F-W
Honey Brook Mines, Inc., Audenreid
Audenreid
2,000
HM
Jeddo-Highland Coal Co., Jeddo
Jeddo #7
3,500**
HM-F
Lehigh Valley Anthr. Inc., Swoyerville
Harry E
HM-W
Hazleton
Hazleton Shaft
1,625**
HM-W
Shenandoah
Mammoth
HM-W
Manbeck Dredging Co., Tremont
Westwood
400
WT
Pine Creek Coal Co., Spring Glen
Pine Creek
400
WT-W
Reading Anthracite Co., Pottsvllle
New St. Nicholas
HM-W
St. Nicholas
St. Nicholas
3,795**
W
Trevorton
Trevorton
HM-W
Reidinger Coal Service, Paxinos
Reidinger
350
HM
Rosini Coal Co., Shamokln
Carbon Run
1,000
J-WT-W
Thos. W. Schenck Coal Co., Pine Grove
Breaker
NA
HM
Sun Coal Co., Inc., Atlas
Diamond
2,000
HM
Swatara Coal Co., Minersville
Breaker
800
HM-WT
Underkoffler Coal Service, Lykens
Underkoffler
500
HM
* J ¦ jigs, jig washers
F - flotation, froth flotation
HM ~ heavy media
WT - water tables
W - washery
**ADL estimate
Source; 1974 Keystone Coal Industry Manual, and ADL estimates.
1-27
-------
II. FINANCIAL PROFILE OF THE COAL INDUSTRY
A. COAL PRODUCTION COSTS
Numerous factors, often interacting complexly, affect the cost of coal
production. These factors very between mining regions, between mines in the
same region, and even within a given mine. Of the physical factors, seam
thickness and depth below the surface dominate since they largely determine
the system used for mining thra deposit. Some of the other factors influenc-
ing coal production costs are mining technology, mine size, operating con-
ditions, and labor productivity„
Since conditions vary from one mine/region to the other, no single pro-
duction model will be applicable to all coal mines. We have derived model
mining costs by type of mining—underground or strip, by mine size, and for
various regions of the country. The actual costs experienced by a mine will
approach those synthesized in the model only to the extent that its operat-
ing conditions approximate those assumed in the derivation.
Tables 18 through 21 present a summary of our estimates of mining costs
for underground and surface mines. The cost derivations are based on U.S.
Bureau of Mines estimates with suitable revisions and escalations to bring
costs to December 1974.
The capital Investment consists of an initial expenditure required to
put a mine into operation, including such items as the costs of land acqui-
sition, exploration and development, initial Installed equipment, and a
deferred capital requirement which must be expended over the life of the
mine in order to sustain a given production rate and replace depreciated
equipment.
We have hypothesized that small mines operate under a different set of
coal placement, availability, and market conditions. They are likely to
lower their costs by employing used and/or rebuilt equipment and operate in
coal seams relatively near tc the point of entry, such as in the high wall
of former strip operations„ In such mines, one would probably not have
extensive entries and elevators. A similar philosophy is extended to the
calculation of operating costs. The nature of these operations is reasoned
to be such that they could not survive (except in unusual spot market con-
ditions) , unless their costs are less than (or at most equal to) those exper-
ienced by the large mines. A profitable operation would hinge on the use
of minimal equipment, the ingenuity of the operator in devising practical
mining shortcuts, the ability of personnel to perform a wide variety of jobs,
and the existence of very favorable geologic and topographic mining condi-
tions amenable to the utilization of minimum equipment and personnel. We
have also assumed lower wage rates for non-union labor. The cost of truck
haulage of the coal to a loading point has been included for small under-
ground and surface mines.
II-l
-------
TABLE 18
ESTIMATES
OF LARGE UNDERGROUND
COAL MINE
INVESTMENT AND OPERATING
COSTS
(December 1974)
Mine Size (10 tons/year)
0.5
1.0
2.0
3.0
Mine Type
Drift
Drift
Drift
Drift
Seam Thickness
5'6"
5'6"
5'6"
5*6"
Productivity (tons/mari-day)
11.5
11.9
12.2
12.5
Manpower Requirements:
Union
165
320
630
933
Salaried
30
53
95
127
Total
195
373
725
1060
Investment ($/annual ton)
Mine
19.5
16.4
14.2
13.4
Rail Loading
1.4
1.2
0.7
0.6
Working Capital
2.5
2.4
2.4
2.3
Initial Investment
23.4
20.0
17.3
16.3
Deferred Capital
22.7
20.3
17.8
16.9
Operating Cost ($/ton)
Labor (Operating & Maintenance)
Union1
3.92
3.80
3.75
3.70
Salaried2
0.97
0.85
0.76
0.68
Operating Supplies
1.85
1.85
1.85
1.85
Power (1.25c/kWh)
0.27
0.26
0.25
0.25
Royalty
0.50
0.50
0.50
0.50
Welfare Fund
1.05
1.05
1.05
1.05
Payroll Overhead3
1.71
1.63
1.58
0.53
Black Lung Insurance 4
1.22
1.16
1.13
1.10
Indirect Costs 5
1.01
0.98
0.95
0.93
Variable Costs
12.50
12.08
11.82
11.59
Insurance and Taxes6
0.47
0.40
0.35
0.33
Depreciation7
2.30
2.00
1.75
1.66
:al Costs
15.27
14.48
13.92
13.58
'Union labor at $11,890 per man-year.
2Supervisory labor at $16,100 per man-year.
325% of payroll.
^37% of payroll.
515% of labor and supplies.
62% of initial investment.
720-year straight-line depreciation of mine investment.
II-2
-------
TABLE 19
ESTIMATES OP SMALL UNDERGROUND
MINE INVESTMENT AND OPERATING COSTS
(December 1974)
3
Mine Size (10 tons/year) 100
Seam Thickness 4*
Mine Location Appalachla
Productivity (tons/man-day) 11.0
Manpower Requirements:
Hourly 34
Salaried 10
Total 44
Investment ($/annual ton)
Mine 10.2
Loading Facility 1.0
Working Capital 1.1
Initial Investment 12.3
Deferred Capital1 8.6
Operating Costs ($/ton)
Labor (Operating and Maintenance)
Hourly2 3.23
Salaried3 1.28
Operating Supplies 1.85
Fuel 0.35
Royalty 0.50
Payroll Overhead 14 1.35
Black Lung Insurance5 1.13
Truck Haulage 1.50
Indirect Costs6 0.95
Variable Costs 12.14
Insurance and Taxes (2% Investment)7 0.25
Depreciation6 2.09
Total Costs 14.48
*70% of initial investment over 10-year mine life.
2Hourly labor at $9,500 per man-year.
3SalaTied at $12,825 per man-year.
430% payroll.
s25% payroll.
615% of labor and supplies
72% of initial mine investment.
010-year straight-line depreciation of mine investment.
II-3
-------
TABLE 20
ESTIMATES OF LARGE SURFACE MINE INVESTMENT AND OPERATING COSTS
(December
1974)
Mine Size (10^ tons/year)
0.5
1.0
3.0
1.0
3.0
6.0
Location
... Appalachia ...
Central
Great
Plain
Type of Mine
Contour
• • • •
• • • • •
Area .
Overburden to Coal Ratio
. 20:1 ..
OO
:1 ..
3:1
Productivity (tons/man-day)
25
25
50
45
60
105
Manpower Requirements:
Hourly
82
164
254
93
210
244
Salaried
15
26
35
16
34
36
Total
97
188
289
109
244
280
Investment ($/annual ton)
Mine
26.2
21.3
16.2
22.9
14.3
4.4
Rail Loading
1.7
1.4
0.7
1.4
0.7
0.5
Working Capital
1.4
1.3
0.9
1.4
0.9
0.6
Initial Investment
29.3
24.0
17.8
25.7
15.9
5.5
Deferred Capital
9.2
7.2
3.6
4.9
2.6
2.0
Operating Costs ($/ton)
Labor (Operating & Maintenance)
Hourly1
1.59
1.59
0.82
0.90
0.68
0.39
Salaried2
0.40
0.34
0.15
0.21
0.15
0.08
Operating Supplies
1.67
1.40
0.83
1.04
0.85
0.91
Power
0.72
0.69
0.65
0.40
0.37
0.13
Payroll Overhead3
0.70
0.68
0.34
0.39
0.29
0.16
Royalty
0.50
0.50
0.50
0.50
0.50
0.50
Welfare Fund
1.05
1.05
1.05
1.05
1.05
1.05
Black Lung Insurance14
0.20
0.19
0.10
0.10
0.08
0.05
Indirect Costs5
0.55
0.50
0.27
0.32
0.25
0.21
Reclamation Costs
0.30
0.30
0.30
0.15
0.15
0.05
Road Construction
0.20
0.13
0.10
0.07
0.05
0.03
Variable Costs
7.88
7.37
5.01
5.13
4.42
3.53
Insurance and Taxes6
0.59
0.48
0.36
0.51
0.32
0.11
Depreciation7
1.93
1.56
1.07
1.53
0.93
0.37
Total Costs
10.40
9.41
6.44
7.17
5.67
4.01
*Labor cost of $9,700 a year.
2Average salary of $13,200 a year.
335% payroll.
410% payroll.
515% of labor and supplies.
62% of Initial investment.
720—year straight-line depreciation of mine investment.
II-4
-------
TABLE 21
ESTIMATE OF SMALL SURFACE MINE
INVESTMENT AND OPERATING COSTS
(December 1974)
Mine Size (10"^ tons/year) 100
Mine Location Appalachia
Productivity (tons/man-day) 25
Manpower Requirements:
Hourly 18
Salaried _5
Total 23
Investment ($/annual ton)
Mine 6.6
Loading Facility 0.9
Working Capital 2.1
Initial Investment 9.6
Deferred Capital1 1«4
Operating Costs ($/ton)
Labor (Operating and Maintenance)
Hourly2 1.46
Salaried3 0.55
Operating Supplies 2.05
Fuel 0.90
Royalty 0.50
Payroll Overhead4 0.70
Black Lung Insurance5 0.20
Reclamation 0.30
Truck Haulage 1.50
Indirect Costs6 0»61
Variable Costs 8.77
Insurance and Taxes7 0.19
Depreciation® 1•10
Total Costs 10.06
115% of initial investment.
2Hourly rate at $8,100 per man-year.
3Salaried rate at $11,000 per man-year.
**30% payroll.
510% payroll.
615% of labor and supplies.
72% of initial mine investment.
®10-year straight-line depreciation of mine investment.
II-5
-------
Tables 22 and 23 present our estimates for production costs for deep
mines in the Central and Intermountain regions based on the deep-mine models
modified for the increased productivity of mines in this region compared to
the Appalachian region and adjustments in capital investment. Table 24
presents similar estimates for strip mines in the Intermountain region de-
rived from strip mining costs in the Central region adjusted for productivity
changes.
Metallurgical coal carries a premium value, in relation to steam coal.
Consequently, it is worthwhile to operate a metallurgical coal mine at higher
production costs than would be justified for a steam coal mine. Most of the
metallurgical coal production in the United States is from deep mines in
Appalachia. Table 25 presents a summary of Investment and operating costs
for a million-ton-per-year deep mine producing metallurgical coal in
Appalachia.
Table 26 presents our estimates of investment: and operating costs for
preparation plants for various size plants cleaning steam coal. The prep-
aration of coal results in yield losses of the order of 15-20 percent, i.e.,
one ton of raw coal processed by a preparation plant produces 0.8-0.85 ton
of clean coal and 0.15-0.2 ton of refuse. Consequently, mining and prepa-
ration costs are not directly additive; the yield loss in preparation has
to be factored in. We have assumed that these costs are applicable to all
coal cleaned in preparation circuits similar to those for steam coal cleaning.
B. SALVAGE VALUE OF COAL MINING ASSETS
There is little information available on the question of salvage value
of coal mines, especially in the content of shutdown to avoid incremental
pollution abatement Investment and operating costs. As a first approximation,
one could assume that the mobile equipment is salvageable. In a new under-
ground mine the cost of mobile equipment would amount to 40-50% of the total
capital investment. This share is higher for strip mines. The actual prices
obtainable for equipment depend on the local demand for such equipment.
The salvage value of coal mining assets are variable and small enough
that no significant influence on investment decisions results.
C. INDUSTRY PROFITABILITY
No reliable figures have been published on the profitability of the coal
industry. The Internal Revenue Service publishes a composite balance sheet
and profit and loss statements, but thelatest figures are several years old.
There are clear indications that the industry has not, on the average over
the past 10 years, been very profitable. In 1970 and 1974, returns have been
substantial for many companies, but for those companies locked into low
escalation rate contracts they have been inadequate.
Data on the coal industry, based on the 1972 Census of mineral industries,
are used to present certain salient features of the soft and hard coal segments
II-6
-------
TABLE 22
ESTIMATES OF COSTS FOR UNDERGROUND
MINES IN THE CENTRAL REGION
Mine Size (10^ tons/year)
0.5
1.0
2.0
3.0
Productivity (tons/man-day)
20.0
20.4
20.7
21,0
Investment ($/annual ton)
Initial Investment
Deferred Capital
17.6
17.0
15.0
15.2
12.9
13.4
12.2
12 o 1
Model Productivity (Appalachia)
11.5
11.9
12,2
12.5
Labor-Related Costs ($/ton)
8.56
8.14
7.89
7.67
Decrease in Labor-Related Coets
($/ton)
Decrease in Power and Supplies Cost
($/ton)
3.64
0.60
3.39
0.60
3.24
0.60
3.10
0.60
Decrease in Variable Costs ($/ton)
4.24
3.99
3.84
3.70
Decrease in Fixed Costs ($/tem)
0o69
0.59
Q„53
0.50
Decrease in Total Costs ($/ton)
4.93
4.53
4.37
4.20
Variable Costs ($/ton)
8.26
8.09
7.93
7.39
Total Costs ($/ton)
10.34
9.90
9.55
9.33
II-7
-------
TABLE 23
ESTIMATES OF COSTS FOR UNDERGROUND
MINES IN THE INTERMOUNTAIN REGION
Mine Size (10^ tons/year)
0.5
1.0
2.0
3.0
Productivity (tons/man-day)
18.0
18.5
18.9
19.3
Investment ($/annual ton)
Initial Investment
Deferred Capital
16.4
15.9
14.0
14.2
12.1
12.5
11.4
11.8
Model Productivity (tons/man-day)
11.5
11.9
12.2
12.5
Labor-Related Costs ($/ton)
8.56
8.14
7.89
7.67
Decrease in Labor-Related Costs
($/ton)
Decrease in Power and Supplies
Costs ($/ton)
3.09
0.70
2.90
0.70
2.80
0.70
2.70
0.70
Decrease in Variable Costs ($/ton)
3.79
3.60
3.50
3.40
Decrease in Fixed Costs ($/ton)
0.83
0.71
0.63
0.60
Decrease in Total Costs ($/ton)
4.62
4.31
4.13
4.00
Variable Costs ($/ton)
8.71
8.48
8.32
8.19
Total Costs ($/ton)
10.65
10.17
9.79
9.58
II-8
-------
TABLE 24
ESTIMATE OF COSTS FOR STRIP
MINES IN THE INTERMOUNTAIN REGION
Mine Size (10^ tons/year) 1*0 3.0
Overburden to Coal Ratio 9:1 9:1
Investment ($/annual ton)
Initial Investment 16.5 9.5
Deferred Capital 3.0 1.6
Productivity (tons/man-day) 80 96
Model Productivity (tons/man-day) 45 60
Labor-Related Costs 1.78 1.33
Decrease in Labor Costs ($/ton) 0.78 0.50
Decrease in Fixed Costs ($/ton) 0.74 0.51
Decrease in Total Costs ($/ton) 1.52 1.01
Variable Costs ($/ton) 4.35 3.92
Total Costs ($/ton) 5.65 4.66
II-9
-------
TABLE 25
ESTIMATES OF INVESTMENT AND OPERATING COSTS
FOR A METALLURGICAL MINE IN APPALACHIA
Mine Size (10^ tons/year) 1.0
Type of Mine Deep
Investment ($/annual ton)
Mine 23.5
Preparation Plant and Loading Facility 8.3
Working Capital 3.8
Initial Investment 35.6
Deferred Capital 34.7
Operating Cost ($/annual ton)
Labor 5.79
Operating Supplies 3.15
Power 0.40
Payroll Overhead1 2.32
Welfare Fund 1.05
Black Lung Insurance2 1.16
Royalty 1.50
Indirect Costs3 1-34
Variable Costs 16.71
Taxes and Insurance** 0.71
Depreciation5 3.52
Total Costs 20.94
*40% payroll.
225% payroll.
315% labor and supplies.
**2% of initial mine investment.
520-year straight line-depreciation of mine investment.
II-10
-------
TABLE 26
COAL PREPARATION COSTS
Plant Size
(10^ tons/year raw coal)
0.5
1.0
2.0
3.0
(approx. tons/hour raw coal)1
170
330
670
1000
Manpower Requirements:
Hourly
6
8
14
22
Salaried
2
_2
_2
_2
Total
8
10
16
24
Investment ($/annual ton)
7.5
6.7
4.2
3.4
Operating Cost ($/ton)
Labor:
Hourly2
0.12
0.08
0.07
0.07
Salaried3
0.05
0.03
0.01
0.01
Operating Supplies
0.25
0.25
0.25
0.25
Power
0.05
0.05
0.05
0.05
Payroll Overhead14
0.06
0.04
0.03
0.03
Black Lung Insurance5
0.02
0.01
0.01
0.01
Indirect Costs6
0.06
0.05
0.05
0.05
Variable
0.61
0.51
0.47
0.42
Insurance and Taxes7
0.15
0.12
0.08
0.07
Depreciation®
0.38
0.34
0.21
0.17
Total Co&ts
1.14
0.97
0.76
0.71
*230 days a year, 2 shifts a day, 13 hours a day.
2Hourly at $9,700 a year.
3Salaried at $13,200 a year.
435% payroll.
510% payroll.
&15% labor and supplies.
72% of initial mine investment.
820-year straight-line depreciation on investment.
11-11
-------
of the U.S. coal industry. This information has been summarized in Tables
27 through 30. Tables 27 and 28 present trends in the industry from
1954-1972, and Tables 29 and 30 present statistics by employment size of
establishment in 1972.
Table 31 puts together salient statistics for the major coal companies
for the last five years from company annual reports, 10K. reportB, and
Arthur D. Little, Inc. estimates including coal sales, earnings, and produc-
tion for the 16 major coal producers.
The larger companies tend to be subsidiaries of major corporations,
mostly in the oil and mining industries. There is a considerable gap in
tonnage between the second and the third largest producers, but the coal
revenues of the top four are more tightly bunched. The coal revenues of
Peabody and Consolidated Coal are both reduced by production payments (por-
tions of coal revenue dedicated to repaying an obligation incurred by the
parent company at the time of acquiring the coal company). The revenues
of Island Creek and Pittston are enhanced by larger shares of metallurgical
coal and exports. The average price per ton obtained by Westmoreland,
Pittston end Island Creek was well above average due to the relative share
of exports of the companies—exports accounted for 58% of Pittston's tonnage,
48% of Westmoreland's, 30% of Eastern Associates and 20% of Island Creek's
in 1971.
The major producers generally sell coal under long-term contracts
at specific prices, but generally subject to price escalation clauses
which permit the producers to recover certain cost increases from their
customers.
Most coal producers recognize that competent air quality standards may
have a substantial indirect impact through its effect on public utility
consumers. The degree of this impact will depend on the sulfur content of
reserves—companies like Amax and Peabody could experience adverse effects
on sales. Surface mining, subject to regulations that prescribe land recla-
mation standards, is likely to suffer increased costs; it is, however, gen-
erally recoverable under price-escalation clauses of long-term contracts.
Among the important independent companies are Pittatac., Jkicth Acacican
Ccal, and Westmoreland. Meet of Plttaton's CDal production comes from deep
cities (B7£ In 197-43. Metallurgical coal £.ccounted far 7h% of the coal pro-
duction of 17.4 million tons, the remainder being steam coal. Exports ac-
counted for 33* of the metallurgical coal production.
North American Coal has substantial reserves of lignite in North
Dakota. It derives more than 90 percent of its sales from long-term contract
sales. Westmoreland produces low, medium, and high volatile coals, both
steam and metallurgical, all under 1 percent sulfur. Utah International
produced 71 million tons of steam coal in 1972 from its Navajo, New Mexico,
strip mine, all of which were sold to the Four Corners Power Plant of the
Arizona Public Service Company under a long-term contract.
11-12
-------
T&EUS 2?
SALIEHT STATE5T1C5 M 3ITUHXK0US CCfrL Aj1> ^ISKITS KIKTBG
<195^-1972)
JO
Tc?C«l
Valq£ of
S«L
leceiptg iectipw cr£ CO£i
crWjtflar
'tftWlrm
ltaJ«-T Ci ijuji 12. (d.ts3cd£,M€ Cemi rumd Lifplire jttwjjg
1«?J
a* 34a
lill7
W,«
1B 7*9*3
132.3
JM.5
l.W.T
2.MV.9
2**65.6
56?, J
1-567 1
4J>S1
1.0S6
124.*
joa,9
m.*
??«.»
2S1309.1
i.ztt.-e
2,S&*.6
1,«} .8
551,7"
3MJ
I?fr3
it3o;
m.9
7*2^
HB.fi
m,s
VS\.3
1,00ft. i
444.fi
na.3
ISJ5S
6,94£
¦1.J75
1BE.0
s-is.i
m/.
7ii.i
i^bi5.?
1*003.7
£,U0.»
iiDftg.5
HIJ
Cj SM6i
l.W
&7?.4
200.0
m.s
747.7
1,424.2
770,7
1,074.S
331-S
no. t
Hocai SsC4 prtsr tci- i?54 •jrpeax to fctuoe I, 1P-S5 Gestae ftf •tLosrid Isutcs-trlea b 1*bU 1 af tfe« cfeipter delated to tJte3< ittdaitr^.
l£ept«re»t3 tSe ^e4 the «4ee -ejt^blSBSaeBt fer ps*iresr or b&j\.
^lo 1^72 Altai iW]„ -iita VjC *st.=j?j[Ktuta^itJ* prii 2*1*1.07*53 %rt e^Kiude<£ £*o« tb« c%sjeaa, tu 1965* tfetre J storsiita wijbwt psJ.:*
E3^ji.iiye*a ia B-ittfalticwi Coat sn4 Citftlfce iftjuatry, Jtxd i *»raiCUHWe^Sui Us eh* ^Itai&StwKui Caji. aai Wfcni-tS: t&3£a& 5t£*lctt* VJtf* try J , t*uil
&*rcc.^st't-L tci Jj&s?. tfuut 1 fercent cf r«iu* *^sJe^ f^sr th«®E iirfsatrles-
fajrce: 1972 Cqjuub cC Si%ecil IcQjatrlpa, Seal aati LJjatte- ^tnii>
-------
TABLE 28
SALIENT STATISTICS ON ANTHRACITE MINING
(1954-1972)
Operating
companies
Edebtahmcnts
Ail employ***
Production, development,
and exploiapon workers
Value
added
Cod of
wppl«&.
etc .
purdused
machffwv
irmjfted
Value ol
Aipmtfds
nd
rtctipts
Vahte ol
net
sh*>menti
and
recasts
Net
production
of
anthracite'
Capital
expendi-
ture!
Y«
Total
20
inptoyen
or mat
Hunter
Payroll
Number
fcUn-
hoon
WJ90
(nomber)
(number)
(nunber)
11.000)
(miftoa
dotLan)
(1,000)
(millions)
(mdlton
do Oars)
(millon
dollars)
(mitten
doftan)
Urell«o
tfoflan)
(suUion
doflari)
(1.000
tons)
(million
dollars)
GHUUP
11. AN t HKACITE
MIMING
1Q72
(|U)
230
SI
4.5
35.3
3.8
7.7
29.8
68.4
' 68.1
129.7
95.0
7,133.6
6.7
1967
(HA )
403
69
7.2
41 .1
6.2
11.6
35 .O
82.1
80.3
155 .9
111 .7
11 ,844 .8
6.4
1,025
1,157
1,296
1 ,069
1,248
102
11 .8
58.8
10.3
19.5
49 .9
120.5
131.1
236.5
172.1
18,388.0
15.1
159
22.8
93.4
20.0
30.9
79 .4
164.5
177.2
325.1
234.0
22,258.0
16.6
1 ,43G
245
37.5
135 .9
33.0
*8.3
113.9
196.8
222.1
408.4
291 .4
29,255.0
10.5
i
»-•
.c-
Note: Data prior to 1954 appear in Volume I, 1963 Census of Mineral Industries, in Table 1 of the
chapter devoted to those industries.
Represents the clean coal equivalent of all coal mined, including coal produced and used at the same
establishment for power or heat.
NA = Not available.
Source: 1972 Census of Mineral Industries, Anthracite Mining.
-------
TABLE 29
STATISTICS BY EMPLOYMENT SIZE OF ESTABLISHMENT
Bituminous Coal and Lignite Mining (1972)
E4*
fahmtnu
All wptaym
Production, ilawtapmarn.
md npkrttba mvtari
Vitas added
si omning
Cod of sup-
plies, etc..
and puxdusd
machncry
in staffed
Vthm of
duprasnti
and racsipU
•xponddurn
ran
cods
ton
Nonpar
PtyroO
Han-howi
**"
(ntnte)
(fJBOQ
(mrffion
doGsn}
(1JB0Q
IswflinoO
UaiKoa
do fin)
(bbQmm
doJtsrd
(mHHon
do Bars)
(mOioo
tfoJbrt)
(mfflioo
dcSan)
1211
BITUMINOUS COAL AKD LIGHTS
3,190
151.9
1,711.3
17.6
129.6
256.0
1,410.4
3,621.2
2,372.3
5,306.7
686.8
Establishments with an average of-
... .E5
1,160
1.9
1.8
3.1
14.8
70.8
40.8
84.5
27.2
R2
457
3.1
*7.7
2.8
5.0
22.6
71.9
67.1
126.5
12.4
498
6.9
64.7
5.9
11.3
52.3
192.8
141.4
299.3
34.8
450
14.2
145.7
11.9
23.8
116.1
393.3
270.1
582.3
81.1
210
14.5
161.4
11.7
23.6
125.3
363.8
358.3
628.4
93.8
247
39.7
469.3
33.6
67.9
388.2
996.1
719.5
1,514.0
201.6
132
47.0
547.1
40.7
80.4
459.4
1,064.2
526.9
1,413.5
177.6
35
24.6
277.9
21.0
40.9
231.7
468.7
248.0
65*.S
58.3
1
(D)
(D)
(D)
)
7rol 1 and Mies dftts for mall establishments (generally siocle-oslt coiptnles with less than 5 employees) tere obtained (rtw
utaiDlotratlve records of other govenaeot agencies Instead of from a Census report fore. These data were then used In conjunction vltb Industry
averages to estlsate the balance of the ltess shown in the table for these aaall establishments. This technique was also used for a nail number of
other establishments whose reports were not received at the time the data cere tabulated. The following syabols are shown for those size classes
where administrative records data were used and account for 10 percent or sore of the figures shown:
El—10 to 19 percent £3—30 to 39 percent ES—SO to 59 percent E7—70 to 79 percent E9—90 to 99 percent
E2—30 to 29 percent E4 40 to 49 percent E6—60 to 69 percent 88—00 to 89 percent ED—100 percent
(D) Withheld to avoid disclosing fignres for ladlvlAjal companies. Data for this ltea are included In the underscored figures above.
1Report forms were not generally sailed to companies with less than 5 employees that operated only 1 establishment. Payroll and sales for 1972
tot® obtained from administrative records supplied to other agencies of the 7ederml >i¦ t These payroll amd sales data mere then used la
conjunction with Industry averages to estimate the balance of tho items shown la the table. Data are also Included in the respective slse classes
shown for this Industry.
Source: 1972 Census of Mineral Industries, Bituminous Coal and Lignite Mining.
-------
TABLE 30
STATISTICS BY EMPLOYMENT SIZE OF ESTABLISHMENT
Anthracite Mining (1972)
an
cvdt
men
tflab
Ldftraeffii
All cmoloyetf
ftodociwft, Jevetacwwf,
and •¦ptofiion mortm
V*lu* added
in niintnq
(nulbon
ifellMi)
Cost ol sup
plei.m..
and pwctu*d
mtcfincry
intuited
{¦iill ion
AlCfcartf
V»hm ol
tftipnwitli
rtctipH
(rnullcn
donaisj-
Cap
• Kpendftiati
Imiti am
doitytJ
Nunitr
(1J0Q]
Payrcfl
Inulhcn
dolivil
I1JB001
Man-hours
UcdberaJ
Waj»
laanipr-
dollar ij
llll
AMTKftAC 1TE
B»tabl 1 ahmcnta , total...«
213
4.0
31.9
3.4
€.*
S3-9
65.7
122.7
5.R
E3tsbllstsacnta aith an average of-
0 to 4 cmpl £4
97
.3
1.2
. 1
.2
. 9
3.«
2. 1
5.5
.4
i to 9 «plnf«ea Kl
36
.2
1.7
.2
.4
1.5
4.0
4.7
R.3
.4
10 to 19 aaplojeea
39
.5
4.2
.4
.8
3.5
>2.B
7.9
19.5
1.2
SO to 49 omplofees............................
22
,7
5.7
-6
1. 1
4 ,B
15.6
16.0
29.5
2.2
SO to 99 anplnyccs..
9
.6
4.5
.3
.7
2.6
4.9
7.ft
12. 2
.4
100 to 249 ispkoyeca
9
1.4
14.7
1.6
3.5
J3.5
2i. B
27. J
47.7
1 .2
250 to 499 '
r D
1
R« tabl i s-taci is- c^vi-rerf tJJ aetain. rceorta 1,
40
t7.)
.3
(z)
, 1
. 3
. A
.5
1 , 1
. 1
Hot*: The payroll *rw5 sales data For small establishments ( gem-ra 11 j nc^e-unl t companies «|ih les> than 5 rvplon'i^ 1 mti- s>b!atni>ct Ira
adstsfcsirat I ve records of other government agencies Instead of i ro« = Census report for*. These ri.ilr. •iti- then u$«tl in con ] unc t Ion »im inclusirj
averages to estimate the balance at the itf« shoo-rt in clie table for thesr siulj establishments. This irrbi>|q«*. »as also us«j fvr a mj|] number
ol oUwr rstablk Jhmcnla whose report s- «ere not received al the time the data tow tabulated, The foljotlnit -rmbojs art ,iha*n far those size classes
ttacrt adm) nlMrsllvp neaiD* ditt «fcrt ua«4 tnd account for 10 percent or mare of the d^ures shown-
El— 10 to 19 percent E3—30 to 39 percent E5-W to 55# percent E7—70 to 79 percent to 99 percent
E2--20 to 29 percent £4—iO to 49 percent E6—60 to 69 percent E8—SO to «9 percent CO—100 percent
(0 ] "Withheld to avoid disclosing figures for Individual companies. Da.ta for this L tern are Included in the underscored figures above.
-2) Lei-a tKa.n half of the unit o-f measurement sho*n (under SO iboue-and dol lart or maa-fiours; under eepioyec* !.
'Report foraa *er« not generally mailed to companies «lth leas than 5 employees ibat operated oclj one establishment. Payroll and vale* for
19T2 vere Obtained from administrative records supplied by other agencies of the Federal Government. These pa/roll end sales data «er« then used in
conjunction aith Industry averages to estimate the balance of the Items shown In the table. Data are also Included in the respective sice clashes
afekooti fctr ttila laduttrj.
Source: 1972 Census of Mineral Industries, Anthracite Mining.
-------
TABLE 31
SALIENT STATISTICS FOR MAJOR COAL COMPANIES
Coal
Coal
%
Markets
Coal
Sales
Earnings1
Production
Surface
%
%
Reserves
Company
Ownership
Year
<$106)
C$io6)
(106 tons)
Mined
Steam
Export
(106 tons)
Peabody Coal
Kennecott
1974
504
PT
29.3
68.1
66
90
9,000
Co.
1973
381
PT
7.1
68.8
1972
344
PT
15.7
70.0
1971
269
PT
8.5
56.2
84
81
8,457
1970
283
PT
21.7
66.4
Consolidation
Continental Oil
1974
747
XX
43.8
47.1
34
89
13,900
Coal Co.
1973
474
XX
(12.8)
54.4
10,600
1972
421
XX
16.6
58.5
1971
321
XX
7.6
49.0
28
86
6,270
1970
312
XX
21.3
57.4
Island Creek
Occidental
1974
562
PT
136.9*
20.8
49
18
3,400
Coal Co. Div.
Petroleum
1973
301
PT
16.52
22.9
20
65
1972
255
PT
9.5
22.6
1971
247
PT
18.9
22.8
0
69
20
3,400
1970
262
PT
63.0
29.7
73
Pittston Co.
Public
1974
573
XX
100.0
17.4
13
26
57
1973
300
XX
16.0
18.8
23
50
1,550
1972
288
XX
15.1
20.6
1971
256
XX
24.2
20.1
17
31
58
1,400
1970
221
XX
26.8
20.5
30
55
Amax Coal Co.
AMAX, Inc.
1974
140
PT
45.0
19.9
96
100
4,900
(ex. Ayrshire)
1973
154
PT
22.0
16.7
1972
137
PT
23.0
16.3
1971
118
13.3
95
100
4,000
1970
88
5.7
14.3
2,900
TT PT = Pretax and interest;
XX = After tax, before interest and corporate charges.
2. XX, 1S73 earnings from Island Creek were $10.6' million and $101.5 million in 1974.
-------
TABLE 31
Coal
Sales Earnings1
Company
Ownership
Year
($105)
($106)
U.S. Steel
Public
1974
Corp.
1973
1972
1971
1970
Bethlehem
Bethlehem
1974
Mines Corp.
Steel
1973
1972
1971
1970
North American
Public
1974
161
XX
4.9
Coal Corp.
1973
125
XX
4.0
1972
100
XX
2.8
1971
64
XX
1.2
1970
56
XX
1.9
Old Ben Coal
Sohio
1974
115
PT
31.5
Co.
1973
85
PT
12.4
1972
78
PT
11.5
1971
66
PT
12.2
1970
65
PT
10.6
A.T. Massey
St. Joe
1974
332.8
XX
43.5
Coal Co.,Inc.3
Minerals
1973
144.8
XX
6.4
Corp.
1972
116.2
XX
1.8
1971
118.4
1970
152.7
1. PT = Pretax and interest;
XX = After tax, before interest and corporate charges
2. Exact amount not given.
3. Includes sale of purchased coal.
(Continued)
Coal % Markets Coal
Production Surface % % Reserves
(106 tons) Mined Steam Export (106 tons)
16.4 3,000
16.3
16.5
16.6 5 -v-5 3,000
19.6
^12.02
14.1
13.2
12.0 21 ^5 1,800
14.6
11.3 94 5,400
12.4
12.0
8.8 11 100 2,500
9.7
9.5
11.5 825
11.2
10.5 27 ^90 850
11.7
7.8 65
6.7
4.7
4.3
4.2
-------
TABLE 31 (Continued)
Coal Coal % Markets Coal
Sales Earnings1 Production Surface I I Reserves
Company
Ownership
Year
($106)
($106)
(106 tons)
Mined
Steam
Export
(106 tons)
Eastern
Eastern Gas
1974
262
PT
34.4
7.7
40
34
2,600
Associated
& Fuel
1973
145
PT
(2.4)
10.6
Coal Corp.
1972
157
PT
5.3
12.5
1971
150
PT
10.2
11.7
0
33
40
1,400
1970
175
PT
22.7
14.5
Westmoreland
Public
1974
n.a.
n.a.
n.a.
Coal Co.
1973
173
PT
4.32
8.8
17
37
29
1972
160
PT
5.1
9.1
1971
145
PT
4.9
8.4
0
23
48
1,900
1970
165
PT
11.3
11.5
Freeman United
General
1974
n.a.
Coal Mining
Dynamics
1973
8.7
Co.
Corp.
1972
10.0
1971
11.5
36
^90
3,000
1970
14.1
Pittsburg &
Gulf Oil
1974
7.5
4,800
Midway Coal
1973
8.0
Mining Co.
1972
7.5
1971
7.1
76
100
2,600
1970
7.8
Utah Inter-
Public
1974
7.1
100
100
1,100
national, Inc.
1973
7.4
1972
7.5
1971
7.1
100
100
0
1,100
1970
7.8
(in U.S.
)
1. PT = Pretax and interest;
XX = After tax, before interest and corporate charges.
2. Tax recovery of .37 would boost this to $4.7 million.
-------
TABLE 31
(Continued)
Coal
Company
Ownership
Coal
Year ($10°)
($io6)
Markets
Sales Earnings1 Production Surface %
%
(10 tons) Mined Steam Export (106 tons)
Coal
Reserves
6
Central Ohio
et al.
American
Electric
1974
1973
1972
1971
1970
6.5
6.6
6.3
5.4
5.5
80
100
1,500
(
N3
O
1. PT = Pretax and interest;
XX = After tax, before interest and corporate charges.
-------
The major steel companies have produced much of their own metallurgical
coal for many years. U.S. Steel and Bethlehem are the largest producers.
Republic Steel and Jones and Laughlin Steel Corporation also produce coal
for their own use. U.S. Steel produced 16.4 million tons in 1974 from
mines in six states and has sizable reserves of metallurgical coal.
Bethlehem's production has been around 12 million tons over the years. Some
utilities, such as American Electric Power and Montana Power Companies, also
own captive mines.
The Federal Energy Administration sampled a number of medium-sized coal
producers and estimated the 1974 rate of return on net worth of
30.2%, more than double the return for any of the previous 10 years. The
next best year was 1970, with a return on net worth of 14.5%.
Financial data on the small mine segment are lacking. This segment is
likely to be owned by independents who are likely to sell their output on
the spot market or cater to local demand. This segment Is generally caught
in an economic squeeze. The survival of such operations (except in unusual
spot market conditions) hinges on the use of minimal equipment, the ingenu-
ity of the operator in devising practical mining shortcuts, the ability of
personnel to perform a wide variety of Jobs, and the existence of very
favorable geologic and topographic mining conditions amenable to the utili-
zation of minimal equipment and personnel.
D. CONSTRAINTS ON FINANCING ADDITIONAL CAPITAL ASSETS*
Traditionally the coal industry has financed its development programs
with capital derived from retained earnings, along with interim bank loans
and, to some extent, from private placements of long-term debt. Sales
of equity and debt securities to the public have been so nominal as to be
insignificant. Cash flow, Including capital recovery accounts, was the
principal source for the modest development work in the post-war years
through the early 1960's. During this period, the industry experienced a
bottoming out of its own recession, followed by an upturn as increasing
volumes of coal were sold to electric utilities. There was some use of bank
credit during this period, principally for working capital and to finance
acquisition of undeveloped coal reserves.
The latter half of the decade of the 1960's was the period during which
production payment financing was employed by the coal industry, in part to
maximize the benefits of percentage depletion and as an important ingredient
in financing the acquisition of several major coal producers by their present
parent companies.
In recent years, the earnings for the coal industry have been poor
except for 1970, 1974, and 1975. For coal producers, 1970 was a very good
*Thls section is,to a large extent, based on W. W. Wilson's "Capital for Coal
Mine Development," Coal Mining and Processing, January 1976, pp. 68-78.
11-21
-------
year, followed by sharply reduced earnings in the 1971-1973 period attributed
in part to Increased costs arising out of compliance with the Mine, Health,
and Safety Act. Also, for most coal producers 1974 was a very good year with
spot coal prices going to new highs as a result of the energy crunch and
the metallurgical coal market being in excellent shape. In 1975, spot coal
prices fell and financial performance seemed modest, at least in comparison
to 1974. For marginal producers who did well in 1974, 1975 was very bad.
The up-and-down trend (more downs than ups) in earnings has been a dif-
ficult handicap because it tended to shut out independent coal producers from
public money markets for the sale of equity or debt securities. This implied
continued heavy reliance upon the traditional sources of medium- and long-
term financing, viz., commercial banks and sophisticated private Investors.
Of course, some small and medium sized coal companies, especially the pro-
ducers of metallurgical coal, have used recent good earnings to retire recent
debts and build up short-term investments in anticipation of future capital
needs. For the most part, however, the capital needs of coal companies which
are subsidiaries of companies in other capital-intensive areas of the economy
are provided by bank loans. These coal subsidiaries compete for capital
funds at the same time (and from many of the same sources) as their parent
companies. The coal subsidiaries will have to augment advances from parent
companies with more direct financing of their expansion program. To the
extent that the parent companies cannot provide equity funds in such arrange-
ments, they may provide non-cash support of financing through working capital
agreements, guarantees of specific performance, and similar measures.
Conventional bank credit analysis techniques are designed to evaluate
risks and include scrutiny of historical earnings patterns, debt-equity
ratios, and other balance sheet criteria. While these factors are not abso-
lute in evaluating specific credits, there is no question that many coal
companies would not score highly under these analysis procedures.
The difficulties in obtaining funds for expansion have stimulated the
development of new and innovative financing arrangements, referred to gen-
erally as project financing. These arrangements involve greater reliance
upon the security and cash-generating capacity of a specific project, such
as a new coal mine, rather than the general credit of the customer. A more
rigorous technical and economic evaluation of the credit worthiness of the
project being financed is required than otherwise would be the case and
must be supported by specific agreements and obligations with respect to
completion and operation of the project. In most instances the availability
of long-term sales contracts, with appropriate provisions for cost escala-
tions to assure operating margins, are important Ingredients in project
financing for coal mine development. Project financing has become increas-
ingly popular in recent years for mineral resource development and related
operations. Another point of Importance, is the non-recourse nature of
these loans which are usually made to nominally capitalized third or fourth
parties not directly or financially related to the operating company.
Production payment transactions probably are the best known of all
forms of project financing. Their use originated in the oil industry, first,
11-22
-------
in connection with mineral leasing, wherein the lessor shared part of the
risk of the venture by agreeing to tafca part of hie, Lea&e borwia out of oil
as and If produced. Whan the agreed upon amount was fully recouped,
the pr&duction payment automatically terminated. Ae Buch, they qualified
as economic interests subject to depletion which made them useful in a num-
ber of tax-oriented transactions designed to raise or conserve capital.
The&e tax-related arrangements were legislated out of existence by the 196?
Tax Reform Act. The sale of carve-out production payments, since 1969,
has become one of the favored methods for structuring project financing.
In a typical coal financing transaction, the mining company contracts to
aell, to a designated unrelated third party, a series of installments in a
production payment of a stated total amount, payable out of one or more
mines, usually Including the mine Co be developed* during eji agreed-jpcr.
'-aV-eic^Tk aatitvci to match ite cash needs.
Some interest has? been expressed in establishing "cost" or captive
coal companies to provide coal to several co-owners auch aa large Industrial
companies who need independent sources of energy fuel. The concept of a
captive mine, wholly-owned subsidiary of a steel company which takee the
total output is well established In the coal industry. Direct participation
in the financing of new coal development by electrical utilities ia likely,
lu the future, unless there is further deterioration in their financial
position. An example of a consumer-guaranteed loan ie the one aigned be-
tween U.S. Steel, the coal producer, and Ontario Hydro. U.S. Steel ie to
provide 11.5% of the capital investment needed, Ontario Hydro around 31.1%,
and the remainder le to be provided by tvo consortia of banks—this amount to
be guaranteed by Ontario Hydro. U.S. Steel ie guaranteed a minimum profit
of $1.70 per ton (in constant dollars) above the production cost.
Another variation is a take-or-pay coal purchase contract front a con-
sume! to assure a market for the output of a mine that would serve aa col-
lateral to secure developmental financing under a conventional loan agree-
ment. In mast jurisdictions, electrical utilities nruat obtain approval of
such contracts from appropriate regulatory authorities.
Recently, the profitability of the. Industry ie showing signs of improve-
ment , partly because of constraints imposed by the price and availability of
alternate fuel sources in recent years. Eiowever, impedimenta still remain
in the fern of uncertainties arising out a£ the status of the Clean Air Act,
IsrpciwiiTig federal strip mine legislation, and the eeeming lack of direction
in the federel energy galley.
E. OIEBK CONSTRAINTS TO GROWTH IS THE COAL XHMJSTBY
This growth in the coal industry will be influenced by the ability of
the coal transportation Industry to develop adequate capacity tc deliver
the coal from the minea to the consuming sectors.
Ia 1973* 52£ of all coal was moved by rail; nearly 19!£ was moved
wholly or partly by barge; 12% by truck and leaser araunts aa the Grea-
Lakes, tidewatert cxnveyor aelta, ana pipelines. Rail freight rate varied
between 7 and 20 mile per ton-mile, depending on location and distance.
11-23
-------
Another factor influencing the growth of the coal industry is govern-
mental regulation.
Spurred by public concern, government activity has focussed on
1. preserving or restoring the environmental quality of mined land, and
2. ensuring the health and safety of the mine workers.
Although President Ford recently vetoed Bill HR 25, other state and federal
laws regulate strip mining.
State Strip Mine Laws. About 33 states have laws relating to strip
mining, with most of the current legislation enacted since 1965. All
of the state laws provide for an administrative agency to oversee regula-
tory programs. The assigned responsibilities consist of approving permits,
supervising mines, collecting bonds, and approving reclamation work. Three
states, Pennsylvania, Washington, and Tennessee, require an additional per-
mit from the state water pollution control agency. Although Btate laws on
strip mining are fairly extensive, they are generally regarded as sensible
by the industry. Enforcement, which has been weak and spotty, is becoming
more effective.
Leasing of Federal Lands for Coal Mining. The Bureau of Land Manage-
ment under the Department of the Interior is charged with the leasing of
federal lands for coal mining. It has proposed new regulations that will
impose rigorous land reclamation requirements on federal lands leased for
coal mining.
Federal Air-Quality Standards. While compliance with primary standards
for the sulfur dioxide concentration of ambient air was set for July 1,
1975, compliance with secondary standards was set for October 1, 1977. In-
dividual air quality control regions have already submitted implementation
plans, had them approved by the EPA, and set them into effect locally.
Nevertheless, when these regulations will be enforced is unclear. A second
uncertainty is how to achieve acceptable sulfur dioxide levels in the stack-
gas when high sulfur coals are used. Since this uncertainty is enough to
curtail the use of high sulfur coals severely, amendments have been proposed
to extend the compliance schedules of the Clean Air Act and permit the use
of intermittent control systems under certain circumstances.
The Federal Coal Mine Health and Safety Act of 1969. This Act was
passed to reduce the hazards of underground coal mining. It seeks to ensure
adequate underground ventilation at the coal face, ensure proper cleaning
and rock dusting practices, provide adequate roof support, limit the rate
of advance of continuous miners in order to keep the operator under bolted
roof, and regulate the specifications of underground coal mining equipment.
11-24
-------
III. COAL—SUPPLY, DEMAND, AND PRICE
A. SUPPLY
1. Coal Resources
Studies by the U.S. Geological Survey and the U.S. Bureau of Mines
indicate that the demonstrated coal reserve base* of the United States on
January 1, 1974, was about 434 billion tons. As shown In Figure 3, these
reserves are widely distributed, with 47% in states east of the Mississippi
River. Eighty-three percent of the bituminous reserves and virtually all
of the anthracite occurs East of the Mississippi River. All of the sub-
bituminous coal and most of the lignite occurs in the West where some of
the largest coal deposits in the country are located, especially in
Montana, Wyoming, North Dakota, and South Dakota.
Table 32 shows the distribution of the nation's demonstrated coal re-
serves by states and potential mining methods. About 54% is bituminous,
38% sub-bituminous, 6% lignite, and 2% anthracite. Bituminous coal, which
is fairly hard, has an energy content of about 10,000 to 14,000 Btu/lb.
Sub-bituminous coal, which is not so good quality, has an energy content of
8,000 to 10,000 Btu/lb. Lignite, the lowest rank of coal, contains 6,000
to 8,000 Btu/lb. Anthracite and semi-anthracite, which are found almost
exclusively in eastern Pennsylvania, are the highest rank of coal having
between 13,000 and 14,500 Btu/lb.
Nearly a third of the demonstrated reserve base (137 billion tons)
occurs in beds so close to the surface that underground mining is virtually
impractical. Of this quantity, about 75% is located in states West of the
Mississippi River.
If the states In which demonstrated reserves occur are grouped into
six major geographical segments, on the basis of similarity of coal rank
and seam topography, the distribution of these reserves would be as shown
in Table 33. The Creat Plains and Central regions account for about 40%
and 25%, respectively, of the demonstrated reserves. Interestingly these
regions also represent the greatest potential for additional reserve dis-
covery. The Appalachian regions have been well explored.
*"Demonstrated reserve base" is a collective term for the sum of measured
and indicated reserves calculated under specified depth and thickness cri-
teria, i.e., seam thicknesses of 28 inches or more for bituminous coal and
anthracite, and 60 Inches or more for sub-bituminous and lignite. Maxi-
mum depth for al] ranks except lignite is 1000 ft. Only the lignite beds
that can be mined by surface methods are included—generally those beds
that occur at depths no greater than 120 feet.
III-l
-------
Source: U. S Geological Survey Circular 793,Coal Resources of the United States.
FIGURE 3 COAL FIELDS OF THE UNITED STATES
-------
TABLE 32
DEMONSTRATED COAL RESERVE BASE* OF THE UNITED STATES
BY METHOD OF MINING AS OF JANUARY 1, 1974
(Million tons)
State
Alabama
Alaska
Arizona
Arkansas
Colorado
Georgia
Illinois
Indiana
Iowa
Kansas
Kentucky, East
Kentucky, West
Maryland
Michigan
Missouri
Montana
New Mexico
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
Washington
West Virginia
Wyoming
Total
Potential Mining Method
Underground Surface
1,798
4,246
420
14,000
1
53,442
8,949
2,885
9,467
8,720
902
118
6,074
65,165
2,136
31
17,423
860
1
29,819
667
3,780
2,971
1,446
34,378
27,554
297,235
1,184
7,399
350
263
870
12,223
1,674
1,388
3,450
3,904
146
1
3,414
42,562
2,258
s
16,003
3,654
434
V
1,181
428
320
3,272
262
679
508
5,212
23,674
136,713
Total
2,982
11*645
350
665
14,870
1
65,665
10.623
2,885
1,388
12,917
12.624
1,048
119
9,^88
107,727
4 s394
31
16,003
21,077
1,294
1
31,000
428
987
3,272
4,042
3,650
1,954
39,590
51,228
433,948
Source: U.S. Bureau of Mines.
1 Includes measured and indicated categories as deEined by the USBM and USGS
and represents 100X of the coal in place.
2Less than 1 million tons.
I1I-3
-------
TABLE 33
DISTRIBUTION OF U.S. DEMONSTRATED COAL RESERVES
BY SEGMENTS AND POTENTIAL MINING METHODS
(Million tons)
Segment
Northern
Appalachia
Southern
Appalachia
Central
Intermountain
Great Plains
West
Component States
Md., Pa., Ohio, Va.,
W. Va.
Ala., Ca., East Ky.,
N.C., Tenn.
Ark., 111., Ind., Iowa,
Kan., West Ky., Mich.,
Missouri, Okla., Texas
Ari., Colo., N. Mex. ,
Utah
Mont., N. Dak., S. Dak.
Wyo.
Alaska, Ore., Wash.
Potential Mining Method
Underground Surface
85,493
11,964
81,468
19,916
92,719
5,693
10,872
4,954
26,573
3,740
82,667
7,907
Total
96,365
16,918
108,041
23,656
175,386
13,600
Total
297,235
136,713 433,948
Source: U.S. Bureau of Mines
III-4
-------
2. Coal Production
a. Bituminous Coal and Lignite
In 1973, the United States produced 591.7 million tons of bituminous
coal and lignite, accounting for 18% of the world's total output of 3.2
bilLion tons. In 1974, U.S. coal production was 603.4 million tons, about
19% of the world's output of 3.2 billion tons.
Table 34 shows the trends in the methods of coal mining since 1940.
In 1973, underground milling accounted for 50.6% of bituminous coal and lig-
nite production, strip mining 46.8% and auger mining the balance. It should
be observed that domestic coal production has shown relatively little in-
crease since 1969 despite an apparent increase in demand. This is believed
to be due to the steady decline in labor productivity brought on largely by
the enforcement of the 1969 Federal Coal Mine Health and Safety Act and
several state strip mine laws. The trend in labor productivity since 1950
is shown in Figure 4. The decline has been most severe for underground mines
where productivity has dropped from 15.6 tons per man-day In 1969 to only
11.2 per man-day in 1973. Strip mine productivity declined only slightly
from 35.7 to 34.6 tons per man-day in this period. It ought to be noted
that despite the decline in U.S. coal mine productivity in recent years, it
is considerably higher than most other coal-producing countries. In this
regard it is recognized that productivity is not based solely on mining
practice, but is also a function of such other variables as seam thickness
and geology, overburden ratios, and similar considerations.
Table 35 shows the distribution of 1973 bituminous coal and lignite
production by states, coal regions and mining methods. The Appalachian and
Central regions dominated coal production, accounting for about 90% of the
total output. Among individual states the IcndJng producers were, in order,
Kentucky (21.6% of total), W. Virginia (19.5%), Pennsylvania (12.9%), and
Illinois (10.4%).
Table 36 presents 1973 soft coal production by mine size and type for
various regions of the country based on data from the Bureau of Mines and
the Keystone manual.
We have derived apparent depletion rates of existing mines from a study
by the Federal Energy Administration,1 in order to estimate production from
existing mines in the future. These depletion rates are summarized In Table 37.
Table 38 presents estimates of 1973 metallurgical coal production, based
on Mutschler' and estimates of coke consumption by coke oven operators and
exports.
l"National Energy Outlook," Federal Energy Administration, Washington, D.C.,
February 1976.
''Mutschler, P.H., "Impact of Changing Technology on the Demand for Metal-
lurgical Coal and Coke Produced in the United States to 1985," (IC 8677),
U.S. Bureau of Mines, 1975.
III-5
-------
TABLE 34
PRODUCTION OF BITUMINOUS COAL AND LIGNITE, BY TYPE OF MINE
(10"* tons)
Strip
Auger
Underground
Total
Year
Mining
Mining
Mining
Production
1940
43,167
417,604
460,772
1941
55,071
459,078
415,149
1942
67,203
515,490
582,693
1943
79,685
510,492
590,177
1944
100,898
518,678
619,576
1945
109,987
467,630
577,617
1946
112,964
420,958
533,922
1947
139,395
491,229
630,624
1948
139,506
460,012
599,518
1949
106,045
331,823
437,868
1950
123,467
392,844
516,311
1951
117,618
205
415,842
533,665
1952
108,910
1,506
345,425
466,841
1953
105,448
2,291
349,551
457,290
1954
98,134
4,460
289,112
391,706
1955
115,093
6,075
343,465
464,633
1956
127,055
8,045
365,774
500,874
1957
124,109
7,946
360,649
492,704
1958
116,242
7,320
286,884
410,446
1959
120,953
7,641
283,434
412#028
1960
122,630
7,994
284,888
415,512
1961
121,979
8,232
272,766
402,977
1962
130,300
10,583
281,266
422,149
1963
144,141
12,531
302,256
458,928
1964
151,859
13,331
321.808
486,998
1965
165,241
14,186
332,661
512,088
1966
180,058
15,299
338,524
533,881
1967
187,134
16,360
349,133
552,626
1968
185,836
15,267
344,142
545,245
1969
197,023
16,350
347,132
560,505
1970
244,117
20,207
338,788
602,932
1971
258,972
17,332
275,888
552,192
1972
275,730
15,554
304,103
595,386
1973
276,647
15,740
299,354
591,739
Source: Bituminous Coal Data, National Coal Association
III-6
-------
Soufce: Bmimmous Coal Data, Waiiona) Coal Association
FfiJUfiE J> PROCUCTlV'TV AT QITUMW0US COAL MINES
-------
TABLE 3 5
BITUMINOUS COAL AST) LIGNITE PRODUCTION BY STATES,
COAL REGIONS, AM? MINING METHODS IS 1973
(10^ tons)
Region State Bituminous Coal and Lignite
Underground
Strip
Auger
Total
Northern kppalachia
Maryland
66
1,643
79
1,789
Pennsylvania
46,207
29,829
366
76,403
Ohio
16,225
28,527
1,031
45,783
Virginia
23,437
8,700
1,824
33,961
West Virginia
95,516
17,704
2,228
115,448
Sub Total
181,451
36,403
5,528
273,384
Southern Appalacbis.
Alabama
7,618
11,529
84
19,230
Eastern Kentucky
40,553
23,671
9,742
73,966
Tennessee
3,636
4,236
34S
6,219
Sub Total
51,807
39,436
10,174
101,415
Central
Arkansas
3
432
___
434
Illinois
32,570
29,002
61,572
Indiana
789
24,465
25,253
Iowa
356
245
601
Kansas
1,086
1,086
Western Kentucky
22,342
31,337
53,679
Missouri
•
4,658
4,658
Oklahoma
2,183
2,183
Texas (lignite)
6,944
6,944
Sub Total
56,060
100,352
156,410
-------
TABLE 35 continued
BITUMINOUS COAL AND LIGNITE PRODUCTION BY STATES,
COAL REGIONS, AND MIMING METHODS IN 1973
Region
State
Bituminous Coal
and Lignite
Underground
Strip
Auger
Total
IntermountaiTi
Arizona
Colorado
Hev Mexico
"Utah
3,361
733
5,500
3,247
2,834
3,336
38
3,247
6,233
9,069
5,500
Sub Total
9,594
14,417
38
24,049
Great Plains
Hontana - Bituminous
- Lignite
N. Dakota - Lignite
Wyoming
1
425
10,410
314
6,906
14,461
10,411
314
6,906
14,886
Sub Total
426
32,091
32,517
West
Alaska
Washingtoo
16
694
3,254
694
3,270
Sub Total
16
3,948
3,964
TOTAL
299,354
276,647
15,740
591,739
Source: U.S. Bureau
of Mines
-------
I
o
TABLE 36
DISTRIBUTION OF "SOFT1' COAL PRODUCTION BY MINE SIZE AND TYPE IN 1973
(10^ tons)
Region Deep Mines Strip & Auger TOTAL
>2000 1000-2000 500-1000 200-500 <200 >1000 500-1000 200-500 <200
Northern
Appalachia 25,092 48,599 30,285 43,904 33,572 12,262 2,978 14,746 61,942 273,380
Southern
Appalachia ~ 11,864 9,474 12,348 18,121 3,767 4,111 11,448 30,282 101,415
Central 22,783 19,798 10,683 1,917 1,019 71,317 18,807 5,387 3,530 155,241
Inter-
mountain ~ 1,008 3,328 3,761 1,497 11,712 1,268 814 661 24,049
Great
Plains — — -- 315 111 18,860 11,187 1,692 353 32,518
West — — — — 16 3,229 711 ~ 8 3,964
TOTAL 590,567
-------
TABLE 37
FACTORS TO GET 1973 PRODUCTION TO 1974*
AND CAPACITY FROM EXISTING MINES IN 1985
1974 Capacity 1985 Capacity Depletion Rates
Region 1973 Capacity 1974 Capacity %/Year
N. Appalachia
1.014
0.592
3.7
S. Appalachia
1.036
0.577
3.8
Central
1.00
0.647
3.2
G. Plains
1.208
0.952
0.4
Intermountain
1.295
0.966
0.3
West
1.205
1.00
0.0
*1974 Capacity if there were no UMW strike.
Source; PIES, Federal Energy Administration.
III-ll
-------
TABLE 38
DISTRIBUTION OF METALLURGICAL COAL
PRODUCTION BY MINE TYPE IN 1973
(10^ tons)
Region Deep Mines Strip & Aup.er
Northern Appalachia 80,437 8,938
Southern Appalachia 27,806 3,089
Central 4,214 468
Intermountain 4,682
Great Plains
West
117,139 12,495
111-12
-------
Indications are that the production from strip mining will increase
steadily to about 55% some time in the mid-1980's, underground mining will
probably decline to 44%, and auger mining to IX. The future trends in both
total coal output and the method of coal production will depend on national
energy policies and promulgated environmental (especially strip mining)
legislation. On the assumption that very restrictive strip mining legislation
is not adopted, western coals may account for as much as one-third of U.S.
production by 1985. It was expected that 1973 would see the bottoming-out
of the productivity slump and a return to around 14-15 tons per man-day by
1985. Such an expectation seems less likely by the provisions of the 1974
labor agreements between coal operators and the United Mine Workers. This
agreement provides for additional personnel in underground mines, and that
is expected to result in lower productivity; future federal strip mine legis-
lation may have a similar adverse effect on productivity.
b. Anthracite
Domestic anthracite production has declined from 18.8 million tons in
1960 to 6.8 million tons in 1973. The U.S. anthracite production in 1973
was about 3.6% of the world's anthracite output. Table 39 provides U.S.
anthracite production levels by the extraction method in 1973.
c. Coal Preparation
Figure 5 shows the trends in bituminous coal preparation from 1940-73.
At one time, practically all the coal was placed on the market as run of
mine, i.e., without preparation. In 1940, about a fifth of the coal produc-
tion was cleaned. It increased to about two-thirda in the 1960'a and has
since declined to about a half in 1973.
Coal preparation practices are directly related to mining methods. The
use of continuous mining in underground mining leads to Increased mining
rates. However, a continuous miner does not discriminate between coal, slate,
or roof and bottom materials leading to the removal of significant quantities
of waste materials along with the coal. These waste materials are brought
to the surface with the coal and must be prepared. The increase in prepa-
ration of deep-mine coal during the 1950's and 1960's corresponds to the
increasing production by continuous mining during that time.
As regards the methods of mechanical coal cleaning during the past 30
yearB, Jigs maintained their principal role as the most common, accounting
for nearly one-half the total production of cleaned coal. Dense medium
separation and concentrating tables represent the second and third most
used methods. Relatively little coal is cleaned by pneumatic methods or
by wet classifiers and launders.
111-13
-------
TABLE 39
PENNSYLVANIA ANTHRACITE PRODUCTION
BY EXTRACTION METHOD IN 1973
Extraction Method
Underground
Strip Pits
Culm Banks
River Dredging
Total
Production (000 tons)
726
3,279
2,384
441
6,830
Source: U.S. Bureau of Mines
111-14
-------
ma
1950
I960
Sou»cb: U.S. Suctst?
-------
B. COAL CONSUMPTION
1- Domestic Soft Coal
The trends in domestic consumption for coal in its major markets since
196? are shown in Table 40. These coaL consumption figures show only
dOTr.eatic consumption and da not include the rapidly growing demand for
exported coa] needed to support steel operations throughout the Western
World and to supply power, mostly in Canada- Exports are discussed In the
next Bection.
It can be seen from the trend curveB of Figure 6 that the principal
coal consuming sectors are the electric utility and coking coal. The
former is by far the largest and fastest growing market, accounting in
1973 for nearly 702 o£ the domestic consumption. While utility coal demand
should remain strong fox the next decade or so, the continued utilization
oE coal as a boiler fuel will depend on present and future air quality
standards. In the recent past, it was not uncommon for low-sulfur oil,
most of it imported* to displace coal in & wide and increasing segment of the
utility market, largely because economically viable pollution control tech-
nologies are not yet available for coal-fired boilers. Among the develop-
ments that could cotnbat this trend and permit the utilization of higher
sulfur coal in the future are conversion
-------
TABLE 40
CONSUMPTION OF BITUMINOUS COAL
AND LIGNITE IN THE UNITED STATES
(10^ short cons)
Manufacturing
and Mining Industries
Year
Electric
Utilities
Bunker,
Lake
Vessel 4
Foreign
Beehive
Coke
Plants
Oven
Coke
Plants
Steel &
Rolling
Mills
Other
Manufacturing
and Mining
Industries
Retail
Deliveries
to Other
Consumers
Total of
Classes
Shown
1967
271,784
467
1,372
90,900
6,330
92,464
17,099
480,416
1968
294,739
417
1,268
89,497
5,657
92,028
15,224
498,830
1969
308,461
313
1,158
91,743
5,560
85,374
14,666
507,275
1970
318,921
298
1,428
94,581
5,410
82,909
12,072
515,619
1971
326,280
207
1,278
81,531
5,560
68,655
11,351
494,862
1972
348,612
163
1,059
86,213
4,850
67,131
8,748
516,776
1973
386,879
116
1,310
92,324
6,356
60,837
8,200
556,022
Source: U.S. Bureau of Mines
-------
Ill-IE-
-------
2. Exports
Following World War II, bituminous coal exports became an important
item of U.S. foreign trade, contributing positively and significantly to the
international balance of payments. Table 41 shows the trend in coal exports
for a selection of years between 1940 and 1973. Exports fluctuated prior
to 1961 because of various emergencies abroad; the lack of any major fuel
crises since then up to 1970 has enabled exports to increase steadily. In
1970, the United States exported 70.9 million tons of coal, stemming from
an unprecedented rise in world steel production, a depletion of large coal
stockpiles and a reduction in coal mines capacity abroad. Similarly, the
reduction in 1972 exports resulted generally from diminished steel demand
abroad, improved world coking coal supply, and sufficient coal stocks
abroad. Accordingly, coal buying became selective and the adequate world
coal supplies and lower demand resulted in a sharp focusing on prices.
There was a further decline to 52.9 million tons in 1973, stemming primarily
from reduced demands in Canada and Western Europe. But despite the lower
export volumes, the value of coal exports rose slightly over the prior year
to about $1 billion.
In 1973, Japan retained its premier position as an Importer of U.S.
coal, receiving about 36% of the total foreign shipments. Shipments to
Canada, Europe, and South America accounted for 30.7%, 26.9%, and 5%, re-
spectively. U.S. exports accounted for less than 10% of production.
Compared to 1972, less coal was exported from the Appalachian and Cen-
tral coal regions in 1973. Shipments from the former were 18 million tons
less than in 1972, while shipments from Western Kentucky, Illinois, and
Indiana were approximately 2 million tons below those of 1972. Shipments
from the western states Increased by almost 14 million tons in 1973.
3. "Hard" Coal
Anthracite consumptions by domestic user categories are similarly shown
in Table 42. Apparent consumption in the United States in 1973 (calculated
as production minus exports, Including purchases by the federal government
to supplement the fuel needs of the U.S. Armed Forces in West Germany),
totaled about 5.6 million tons, 51% of which was used for space heating,
25% by electric utilities, 13% by the iron and steel industry, with the
remaining 11% distributed among cement plants and for colliery fuels and
other uses.
C. COAL PRICING TRENDS
In considering coal markets, we have to look at three commodities—
metallurgical coal and low- and high-sulfur steam coal and whether coal is
sold through long-term contracts or on the spot market at specified prices.
Until the mid-1960's, coal contracts were generally fixed price and
long term, particularly for steam coal. In a market where consumption was
111-19
-------
TABLE 41
TREND IN U.S. COAL EXPORTS
Year Total Exports*
(000 tons)
1940 16,466
1945 27,956
1950 25,468
1955 51,277
1960 36,541
1965 50,181
1970 70,944
1971 56,633
1972 55,960
1973 52,903
*Excludes fuel or bunker coal loaded in vessels engaged in foreign
trade and shipments to U.S. military forces.
Source: U.S. Bureau of Mines
111-20
-------
TABLE 42
Trends In Domestic Consumption of Pennsylvania
Anthracite by Consumer Categories
3
(10 short tons)
Residential Iron and Steel Industry
& Commercial Colliery Electric Cement Sintering & Other
Year
Heating
Fuel
Utilities
Plants
Coke Making
Palletizing
Uses
1969
4,209
17
1,849
213
543
623
1,355
1970
4,042
16
1,897
W*
472
464
1,357
1971
3,850
15
1,646
W
451
339
1,037
1972
2,960
11
1,584
W
474
283
603
1973
2,917
11
1,442
W
467
231
603
*W - withheld to avoid disclosing individual company confidential data; included
in "other uses."
Source: U.S. Bureau of Mines, Mineral Industry Surveys.
111-21
-------
declinlTE., such c:n:r3cts uEre acceptabls to b:th tbe producer and the con-
eureer. Rowever} with increasing dessnd Er,r ;cal aaA escalating. ccEts, Euch
contracts have become unacceptable to the producer. Recent contracts are of
ahort-er term and generally include provision for pass-through of full costB
on an annual basia. Presently 80/S of all coal la sold under Long-term con-
tracts .
Historically,, coal price levels have been baaed on production coate,
vfhlch vary greatly by type of mining and geography- The average price f.a.b.
cnlne for alL coal was $15.75 per ton in 1974 compared to a value of $3.53
per ton in 1973. The average value for underground coal was §19-.B6 Per 1:0,1
In 1974 compared to $10.34 per ton in 1973; for atrlp-ained coal, It wae $11.11
per ton It* 1^74 compared to 56.1L in L973 audi for auger coal It was $16.99
per ton in 1974 compared to $7.39 per ton in 1973. The average f.o.b* mine
value varied from a high of $24.94 per ton In Virginia to a low of $3.90 per
ton in Montana. These average values include coal sold under long-term con-
tracts and in spot tcarfceta.
Tables 43 and 44 give the average value f. o.b. mine on a regional basis
derived from Bureau of Mines statistics. Figure 7 gives the trend In value
f.o.b. mine for the period 1965-73.
Spot prices change in response to short term supply/demand imbalances.
When demand exceeds supply, spot prices tend to rise quite quickly in re-
sponse. Contract prices, on the other hand, are not so quickly influenced by
such influences as imbalance. Should premium prices prevail In the spot
¦market over a period of time, producers can renew long-term agreements from
a position of considerable strength.
Since the oil embargo end the lifting of price controls in the spring
of 1974j the spot price for coal rose substantially, due to shortages, higher
price levels for competing fuels, the anticipation o£ the strike in
November, the stepped~up buying by steel producers in Japan, and the Federal
Energy Administration's effort to have eastern utilities switch to coal from
oil. Prices have since been falling up to November 1975, when prices were
still above average 1974 levels. Around March 1975, pricee for icrw-eul£ut:
utility ccal \jere around $20-25 per ten compared to a high of S35-5G pet ton
in 1974.
During 19 74 spot price quotations advanced 1495; far metallurgical in
the low- to medi^a-volatile grades, and 156^ in the high-volatile grades.
Ir. 1975, the prices of metallurgical grades declined.
The trends in the wholesale price index are shovr in Figure 8.
111-22
-------
TABLE 43
F.O.B. "MIME WEIGHTED VALUE FOfi COAL Iff 1973
($/ton)
on
R. Appalachia
S, Appalachia
Central
IntermoimtalTi
G. Plains
West
U.S.
Underground
11.33
11.21
7.09
10.66
7.09
17.74
10.84
Strip + Auger
7.76
7. 38
5.64
3.32
3.19
6.50
6.34
Average
10.13
9.34
6.31
6.71
3.24
6.56
8.53
Source: derived from U.S. Bureau of Mines -data.
111-23
-------
TABLE 44
F.O.B. MINE WEIGHTED VALUE FOR COAL IN 1974
($/ton)
Region Underground Strip + Auger Average
N. Appalachia 21.85 17.30 20.08
S. Appalachia 24.82 19.16 21.70
Central 10.81 8.32 9.25
Intermountain 12.83 5.33 10.69
G. Plains 10.19 4.88 5.02
West 28.70 W* W
U.S. 19.86 12.25 15.72
*W = withheld to avoid disclosing individual company confidential data.
Source: Derived from U.S. Bureau of Mines data.
111-24
-------
Year
Source: U.S. Bureau of Mines
FIGURE 7 AVERAGE TREND IN VALUE OF ALL COAL MINED
IN THE UNITED STATES (1965-1973)
111-25
-------
ises ?sss law is?'. isn i3f3 i37s
FtGUS£ 3 rrrrtj^mOUSCCAS. W^Gu^UILS fflfCE i?-ll'iX -1383-1375 CSSGT-'tWVt
-------
D. FUTURE COAL DEMAND AND PRICES
1 . Steam Coal (Bituminous and Lignite)
a. Short-Run Demand
For strictly 8hort-run purposes, demand and prices were regarded as
the production quantities and the average prices prevailing during 1975.
It is possible that mine operators may consider 1976 or 1977 as the year in
which to m/jke ;m investment decision, but prospective demand growth should,
if anything, impart optimism. The short-run price elasticity of demand for
coal is extremely low in that energy users, such as electricity-generating
plants, are in the short term committed, in most instances, to a particular
fuel.; thus, changes in the price of coal will not, in the near term, occasion
significant change in the quantity demanded. The prospective pattern is a
tendency for demand to rise—the demand curve to shift to the right—with
the inelasticity of the function forcing prices upward and thus encouraging
production within the industry.
The Federal Energy Administration has made a short-term estimate* that
the coal demand is likely to grow over the 1976-78 period at a rate of about
5.1 percent. The forecast is based on the following assumptions: (1) rate
of growth of electricity generation at about 5.5% based on utilities adding
new capacity as Indicated by the National Electricity Rehabilitation Council;
(2) coal conversion program will increase annual consumption by 5, 10, and
15 million tons in 1976, 1977, and 1978, respectively; and (3) EPA will con-
tinue its Clean Fuels Policy of encouraging states to relax sulfur emission
standards that are more stringent than required to protect public health
and/or granting compliance delays of those coal burners unable to comply
with sulfur emissions limitations due to the lack of adequate supplies of
low sulfur coal and/or stack scrubbers.
b. Long-Run Demand
The Project Independence Evaluation System (PIES), administered by the
Federal Energy Administration, is a detailed U.S. energy system model that
provides forecasts for selected years, including 1980 and 1985. PIES was
fully elaborated as an econometric exercise in 1975 and early 1976 with the
results published1 in a number of forecast cases and scenarios incorporating
the supply and demand by consuming sectors. The results of the exercise
are tabulated as quantities and prices (in 1975 dollars) for each raw mate-
rial and energy product.
^'National Energy Outlook," Federal Energy Administration, Washington, D.C.,
February 1976.
111-27
-------
The PLUS forecast was selected because Co our knowledge, it was the one
that provided forecast of coal markets, on a regional basis, by producing the
supply and demand of various energy sources, a range that embraces several levels
of coal production and consumption projected by other studies on future U.S.
energy needs and sources.1'2"3 The model considers the long-run demand for
coal as a function of the demand for energy as a whole and supplies of
alternative energy sources.
In the generation of electricity by utilities, the predominant coal-
consuming sector, 3team coal, competes with oil and in some regions natural
gas and nuclear sources. The readiness to select coal-fired generating sys-
tems will he, over the long term, dependent upon the prospective price of
each of the alternative sources. Although coal and other sources are com-
pared in terms of Btu content, it is recognized that long-run relative
prices, one energy source to another, are not to be explained by Btu content
and the costs of extracting such content. Coal and other sources are not
substitutable, to that extent, even as boiler fuels. Coal traditionally
carries prices that are below what would be warranted by strict coat of
Btu extraction criteria and these established patterns ere not presumed to
change. These patterns indicate that relative prices tend over the long-
run to be preserved and therefore it is appropriate to regard that the
price of coal and other energy sources bear eignifican.t relationship to the
price of imported oil.
It is expected that over the long-run the price of coal will be cost-
determined, i.e., price will be at a level sufficient to cover total costs
of production (including any compliance costs) of marginal mines, inclusive
of an adequate rate of return on invested capital needed to attract the
requisite equity and debt funds for the industry. As suggested by this
pricing principle, no economic rent will be attached to marginal coal
deposits other than that associated with alternative site uses. Such an
approach to long-run coal prices is warranted by (a) the immense coal re-
serves of the United States and (b) the large number of enterprises owning
and mining coal deposits such that competitive relationships preclude
pricing at a level that would enable sellers to enjoy a "monopoly" profit.
The PIES model treats the long run supply of coal as cost determined
and demand as a function of the aggregate demand for energy and the supplies
of alternative fuels. PIES segments the United States into 12 producing
regions. The total demand for coal by the nation and for exports is traced
from final consumers 1 sector and consuming region back to each of the pro-
ducing regions.
^Juprce, W.C., Jr., and J.A. West, "United States Energy through the Year
2000," U.S. Department of the Interior, December 1972.
2"A National Plan for Energy Research, Development, and Demonstration:
Creating Energy Choices for the Future," Energy Research and Development
Administration, 1975.
^Ballanger, "A Time to Choose," "Ford Foundation Energy Folicy Project,
Cambridge, 1974.
-------
Thus, with provi8ison8 for the cleaning of all coals, except sub-bituminous
and lignite, annual quantities and average f.o.b. mine prices for raw coal
are forecasted.* The market clearing prices and quantities are a function
of (a) demand considerations, including all that have been mentioned; and
(b) supply considerations, in the form of minimum acceptable price—equal to
full cost inclusive of an adequate equity return—of the marginal new mine
in the region, i.e., the highest cost of all the mines in the region needed
to supply the quantity demanded.
It should be stressed that this approach determines for all mines pro-
ducing a specified quality of coal a single average price which, in a now-
growing industry like coal, is well above the variable and annualized
deferred capital costs that are the minimum acceptable prices for existing
mines.
In recognition of the crucial role of the price (and quantity) of im-
ported petroleum, cases are built using three such per barrel prices: $8,
$13, and $16. The make-up of the scenarios is drawn from a number of altern-
ative sets of policies respecting such key attributes as price controls,
the price of electrification, the growth of nuclear power, and the develop-
ment of synthetic fuels, all imposed for purposes of conservation, abate-
ment of air pollution, and the like.
The 12 PIES regions and all the data attached to them have been aggre-
gated or averaged to arrive at the dimensions of the six producing regions
used in the present study.
Demand as it is forecasted for 1980 on the assumption of imported oil
at $13 a barrel and at $8 is shown in Tables 45 through 49. It is presumed
that production will match the quantities demanded at market clearing price,
these being equal to the full cost inclusive of profit at 8% for the mar-
ginal (highest cost) mine to be developed by 1980 in each of the producing
regions. Tables 46 through 49 also show demands for other energy sources,
in standard physical units and in terms of trillions of Btu. The average
annual growth rate for coal demand under the assumption of $13 a barrel
imported oil is 5.1% and the 1980 quantity demanded is 797 million; if the
price of imported oil dropped to $8, the demand for coal would rise only
4.7Z, reaching 784 million tons by 1980.
Tables 50 and 51 provide a quantitative description of prices and quan-
tities under two alternative assumptions regarding the price of imported
oil, by geographic regions and consuming sectors. Tables 52 through 56
indicate the quantities of other energy sources by standard physical units
and trillions of Btu that will be used in the stipulated scenarios.
The market clearing demand quantity in 1985, if imported oil is priced
at $8 a barrel, is 894 million tons, well below the range (910-1,260 million
tons) of the eight PIES scenarios constructed on the assumption of $13 as
the price of imported oil. Under the reference scenario with imported oil
priced at $13 a barrel, the market clearing demand for raw steam coal is
*In all consideration of forecasts in this report, prices are expressed in
dollars of average 1975 purchasing power.
111-29
-------
TABLE 45
PRICES AND QUANTITIES OF STEAM COAL BY REGION IN 1980
Case: Imported Oil Priced @ $13
Prices: 1975 $ per ton raw coal f.o.b. mine
Quantities: millions of tons
Region
-ow Sulfur
High Sulfur
Combined
Price Quantity Price Quan t ity Price Quantity
Northern Appalachia
24.16
73.4
10.85
148.5
16. 32
221.9
Southern Appalachfa
23.62
83.9
10.87
28.9
22.29
112.8
Central
25.00
9.2
10.00
112.1
11.06
121. 3
Great Plains
5.48
191.9
4.50
5.7
5.48
197.6
Intermountain
9.40
12.8
5.10
2.8
8.62
15.6
West
6.50
1.0
6.00
0.1
6.05
1.1
Total Production
372.2
298.1
670.3
Source: Estimated by Arthur D. Little, Inc., from Frc
-------
TABLE 46
El.S. TOTAL GROSS CON'St^PTIC*' Of E.ViSCV RESOURCES L\
STANDARD PHYSICAL L^'ITS BV MAJOR SOURCES. ASP CQNSUyiVC SECTORS IX I? SO
CA5E
Household (r Cataaercial
Industrial
Trar.sporta cion
Electrical Generation
Exports
Total**
t,oai
Million
Short Tons
?etroleutr:
.Million
Sarrels
1122.54
125?.92
3602.52
&4?2.IS
Sat lira.;
9
Billions
Cubic Feet
3945.54
11933.23
659.43
S'ucl ear
Frw9r
Billion
Kilowatt Hours
22041.00
¦£:. s?
38; .60
Utility Electricity
Distributed pillion
Kilowatt-flours
1366.45
91S.24
U. 32
2239.02
*8efeT&3C£ case vitb imported oil priced at $13/barrel.
¦''Total «£.>• tiat £dd up be:ats£ oi soj n Ji r.^;.
Source: Adapted by Arthur D. Little, Inc. from Project Independence Evaluation System J1976)-
-------
TABLE 47
U.S. TOTAL GROSS CONSUMPTION OF ENERGY RESOURCES BY MAJOR
SOURCES AND CONSUMING SECTORS IK 1980
(Trillions of Btu's)
CASE A*
Gee- Total
Coal
Petroleum
Natural
Gas -
Total
Fossil
Fuel
Sue lear
Power
Hydro-
Solar
Power
Grcss
Energy
Inputs
Household & Commercial
156
6403
6137
12696
12696
Industrial
4044
6769
12315
23129
23129
Transportation
3
19413
681
20096
20096
.Electrical Generation
11486
3017
3614
18117
3876
3704
25696
Total**
15690
35601
22746
74037
3876
3704
81617
^Reference case with imported cil priced at $13/barrel.
**Totals may not add up due to rounding.
Source: Adapted by Arthur D. Little, Inc., from Project Independence Evaluation System (1976).
-------
TABLE 48
U.S. TOTAL GROSS CONSUMPTION OF ENERGY RESOURCES IN
STANDARD PHYSICAL UN'ITS BY MAJOR SOURCES AND CONSUMING SECTORS IN 1980
CASE B*
Xacural Nuclear
Coal
Million
Short Tons
Petroleum
Million
Barrels
Gas
Billions
Cubic 7eet
Power
Billion
Kilovatt-Hours
Utility Electricity
Distributed Billion
Kilowatt-Hours
Household & Commercial
7.07
1337.18
6118.31
1376.23
Industrial
180.35
1349.08
12292.97
930.42
Transportation
. 14
3829-34
713.36
4. 32
Electrical Generation
518.93
776.16
2504.09
366.15
Exports
78.00
Total**
784.49
7291-76
21628.72
366.15
2310.97
^Reference case with imported
oil priced
at $8/barrel.
**Total may not add up due to rounding.
Source: Adapted by Arthur D. Little, Inc., from Project Independence Evaluation System ^1976).
-------
TABLE 49
U.S. TOTAL GROSS CONSUMPTION OF ENERGY RESOURCES BY MAJOR
SOURCES A3D CONSUMING SECTORS IS 1980
(trillions of Bcu's)
CASE E*
Geo- ictal
Coal
Pe-roleum
Natural
Gas
Total
Fossil
Fuel
Suelear
Power
hydro-
Solar
Paver
Gross
Energy
Inputs
Household & Conmercial
156
7602
6314
14072
14072
Industrial
3985
7293
12686
23965
23965
Transportation
3
20629
736
21368
21368
Electrical Generation
11303
4743
2584
18630
3662
3704
25995
Total**
15447
40267
22321
76035
3662
3704
85400
Reference case with imported oil priced at $8/barrel.
**Total may rtot add up due to rounding.
Source: Adapted by Arthur D. Little, Inc., from Project Independence Evaluation System (1976).
-------
TABLE 50
PRICES AND QUANTITIES OF STEAM COAL BY REGION IN 1985
Case: Imported Oil Priced Q S13
Prices: 1975 $ per ton raw coal f.o.b. mine
Quantities: millions of tons
Region Low Sulfur High Sulfur Combined
Price
Quantity
Price
Quantity
Price
Quantity
Northern Appalachia
27.18
77.3
13.46
171.5
17.97
248.8
Southern Appalachia
27.21
87.5
13.57
36. 7
25.09
124.2
Central
25. 30
14.2
10.07
171.5
11.24
185. 7
Great Plains
6.06
276.4
4.41
28. 7
5.90
305.1
Intermountain
10.00
20.4
5.10
12.9
8.10
33.3
Pacific
6.50
0.1
4.00
4.0
4.06
4.1
Total Production
475.9
425.3
901.2
Source: Adapted by Arthur D. Little, Inc., from Project Independence Evaluation System
(1975/76).
-------
TABLE 51
PRICES AND QUANTITIES OF STEAM COAL BY REGION IN 1985
Case: Imported Oil Priced Q $8
Prices: 1975 $ per ton raw coal f.o.b. mine
Quantities: millions of tons
Region Low Sulfur High Sulfur Combined
Price
Quantity
Price
Quantity
Price
Quantity
Northern Appalachia
24.70
68.4
11.43
151.7
15.57
220.1
Southern Appalachia
24.20
77.9
11.35
36.4
20.20
114.3
Central
24.40
12.1
9.38
147.3
10.52
159.4
Great Plains
5.75
227.7
4.50
4.9
5.72
232.6
Intermountain
9.80
19.2
5.10
9.4
8.26
28.6
West
6.50
0.1
4.00
1.0
4.23
1.1
Total Production
405-4
350.7
756.1
Source: Adapted by Arthur D. Little, Inc., from Project Independence Evaluation System
(1976) .
-------
TASLE
COAL CONSUMPTION 8KDER VARIOUS SCENARIOS IK 1985
WITH IMPORTED OIL PRICED AT $13/BARR£L
{Millions of Tons)
Scenarios
Regional
Limitation
Accelerated
$7.50
$9.00
Regional
WBAU*
Supply
Supply with
Electri-
Sectors
Reference
Regulation
Regulation
Limitation
Demand
Pessimism
Conservation
fication
Househa Id/Co ana
erclsl 5
5
5
5
5
5
5
5
Industrial
22k
ZU
213
213
219
213
zoa
28-4
Electrical Generation 716
659
679
613
640
555
673
a*i
Synthetics
lb
16
16
16
16
16
53
53
EicpQrts
80
80
ao
so
80
80
SO
Total
1,041
979
998
92 7
960
911
1,013
1,265
*Business as Usual.
Source: Fccject Mepsadetce Evaluation System (1976).
-------
TABLE 53
U.S. TOTAL GROSS CONSUMPTION OF ENERGY RESOURCES IN
STANDARD PHYSICAL UNITS BY MAJOR SOURCES AND CONSUMING SECTORS IN 1985
CASE
A*
Coal
Million
Short Tons
Petroleum
Million
Barrels
Natural
Has
Billions
Cubic Feet
Nuclear
Power
Billion
Kilowatt-Hours
Utility Electricity
Distributed Billion
Kilowatt-Hours
Household & Commercial
5.30
1451.31
6240.62
1885.22
Industrial
223.69
1531.11
13587.08
1132.43
Transportation
-11
4150.47
785.98
4.22
Electrical Generation
716.14
433.87
2955.41
866.51
Synthetics
16.27
-164.10
Exports
78.00
Total**
1039.50
7566.76
23404.99
666.51
3021.88
*Reference case with
**Total may not add up
imported oil priced
due to rounding.
at $13/barrel.
Source: Adapted by Arthur D. Little, Inc.
, from Project
Independence
Evaluation System
(1976).
-------
TABLE 54
i
UJ
ID
Household -4 Commercial
Industrial
Transportation
Electrical Generation
Synthetics
Total**
U.S. TOTAL GROSS CONSUMPTION Of E3JERGY RESOURCES BY MAJOR
SOURCES AND CONSUMING SECTORS IS 1983
(trillions of Btu's)
CASE A*
Geo-
Coal
Petroleum
Natural
Cas
Total
Fossil
Fuel
Nuclear
Power
Hydro
Solar
Power
114
8232
6440
14737
4817
8236
14022
27075
2
22367
811
23181
15381
2696
3050
21126
8665
3940
261
-169
92
20575
41532
24154
86261
8665
3940
Total
Gross
Energy
Inputs
14737
27075
23181
33732
92
98366
*Reference case with imported oil priced at $13/barrel.
**Total may not add up due to rounding.
Source: Adapted by Arthur E. Little, Inc., from Project Independence Evaluation System (1976).
-------
TABLE 55
U.S. TOTAL GROSS CONSUMPTION OF ENERGY RESOURCES IN
STANDARD PHYSICAL UNITS BY MAJOR SOURCES AND CONSUMING SECTORS I.N7 1986
CASE B*
Coal
Petroleum
Natural
Gas
Nuclear
Power
Million
Short Tons
Million
Barrels
Billions
Cubic Feet
Billion
Kilowatt-Hours
Household & Commercial
5.18
1760.02
6390.67
Industrial
215.83
1670.23
13948.03
Transportation
.11
4515.46
830.80
Electrical Generation
578.73
1371.94
536.23
793.57
Synthetics
16.27
-164.10
Exports
78.00
Total**
894.13
9317.65
21541.63
793.57
~Reference case with imported oil priced
**Total may not add up due to rounding.
at $8/barrel.
Source: Adapted by Arthur
D. Little, Inc.
, from Project Independence Evaluation System
Utility Electricity
Distributed Billion
Kilowatt-Hours
1841.27
1108.28
4.22
2953.78
-------
TABLE 56
U.S. TOTAL GROSS CONSUMPTION OF ENERGY RESOURCES BY MAJOR
SOURCES AND CONSUMING SECTORS IN 1985
(trillions of Btu's)
CASE B*
Geo- Total
Coal
Petroleum
Natural
Gas
Total
Fossil
Fuel
Nuclear
Power
Hydro-
Solar
Power
Gross
Energy
Inputs
Household & Commercial
114
9969
6595
16678
16678
Industrial
4751
9027
14394
28173
28173
Transportation
2
24319
857
25178
25178
Electrical Generation
12499
8336
553
21388
7936
3940
33264
Synthetics
Total**
261
-169
92
92
17628
51650
22231
91509
7936
3940
103385
*Reference case with imported oil priced at $8/barrel.
**Total may not add up due to rounding.
Source: Adapted by Arthur D. Little, Inc., from Project Independence Evaluation System (1976).
-------
901 million tons, carrying an average price of $12.29 per ton at the mine;
if the price of Imported oil dropped to $8 per barrel, the result without
any exogenous changes would be a reduction in the demand of steam coal to
756 million tons priced at an average of $11.22 per ton.
The long-run price elasticity for energy as a whole is generally be-
! leved to be low in the neighborhood of -0.1 to -0.2.1,2 For coal (other
than metallurgical coal), the price elasticity in 1985, as calculated by the
I'KA (in the reference case with imported oil at $13/barrel), would be -0.56.3
Thus, a 1. percent LncreaBe in the price of coal relative to the prices of
other fuels as a group could be expected to occasion about a 0.5 percent drop
in the quantity consumed. The long-run relationship in thie report ie pre-
sumed to be relevant for both 1980 and L985.
2. Metallurgical Coal
The demand for metallurgical coal for consumption in the United States
or for export—85% of U.S. coal exports are metallurgical coal—is a func-
tion of the steel production in thig country and abroad. In 1975 about 83
million tons of metallurgical coal were consumed in the United States and
exports of coal totalled 64 million tons.
Both within the short run and the long run, the demand for metallurgical
co.il may be regarded as relatively inelastic with respect to price as there
arc, or are not likely to be, any commercially significant substitutes for
metallurgical coal at least up to 1985.
Price then corresponds in the long run to the full costs, including
rate of return on the marginal new mine, which is the most costly of the
mines that need to be developed to meet consumption requirements. While
there may be some price elasticity attached to overseas demand, there iB
no expectation that the U.S. share will be reduced because of price con-
siderations. The several forces that affect supply and demand of steam
coal are not likely to influence the market for metallurgical coal. The
total quantity in 1985 used in the PIES model is 100 million tons of metal-
lurgical and other coking coal for domestic consumption. Coal exports are
expected to reach 80 million tona. The study of the demand for metallurgi-
cal coal by Paul Mutschler,1" published by the Bureau of Mines, indicated
that domestic demand could be 82 to 109 million tons and export demand could
be 129 to 136 million tons, well above the demand used in the PIES model.
1"Energy Self-SufftcLency: An Economic Evaluation," MIT Policy Study Group,
Technology Review, Volume 76, No. 6, May 1974.
¦^Noill , R.F., D.L. Meadows, and J. Stanley-Miller, "The Transition to Coal,"
Technology Review, October/November 1975.
1 "National Energy Outlook," Federal Energy Administration, Washington, D.C.,
February 1976.
'•Mutschl er, P.M., "Impact of Changing Technology on the Demand for Metallur-
gical Coal and Coke Produced in the U.S. to 1985," U.S. Department of In-
terior, Bureau of Mines, 1975.
111-42
-------
3. Anthracite*
The constraints to the production of anthracite are steep pitches, hard
rock overburden in many areas, water pumping and treatment problems, lack
of mechanization, and fragmented ownership, all of which result in high pro-
duction costs. The transportation situation in the region is not promising—
at least with respect to the railroads.
For anthracite to share the switch by industry and utilities from oil
ami gas to coal (with bituminous coal and lignite) would require a changed
set of circumstances to overcome the constraints; some of them are now
emerging, such as:
.1. Changed world energy supply outlook;
2. Changed economics of coal production, reflected mainly through
world oil price increases; and
3. Clean Air Act of 1970 and corresponding need for low-sulfur fossil
fuels in addition to low-sulfur oil and gas.
The third factor will compel utilities and industries in Pennsylvania, New
York, New Jersey, and southern New England to take a close look at anthra-
cite. According to the U.S. Geological Survey, 97% of the anthracite is
less than IX sulfur with the majority 0.7% or less. The anthracite region
lies within 3.50 miles of one-eighth of the U.S. population. At present, the
downward slide in anthracite production has continued and some kind of gov-
ernmental assistance in the form of guaranteed loans, low-interest loans,
tax advantage or economic stockpile, and the like, may be needed to start
the revitalization process.
It is estimated that anthracite resources may be as much as 17 billion
tons.
4. Coal Preparation
For the immediate future (up to 1985), it is likely that new preparation
plants will be built, based on innovative use of available technology. For
the purpose of this study, we have assumed that the quality of coal produced
from each region and the proportions of coal cleaned are likely to hold around
the percent values for each of the regions—50.3% in Appalachia, 58.5% in the
Central region, 21.8% in the Intermountain, and 83.6% in the West. In some
regions, these percentages may even increase somewhat as a result of clean
air standards witli coal preparation as a means of removing part of the sulfur.
Based on the demand for coal in 1980 and 1985, this translates to an estimate
of the amount of coal cleaned in 1985 of 374.8 million tone under the $13
a barreJ. imported oil scenario compared to 289 million tons requiring an
additional capacity for 86 million tons of clean coal. The estimate of clean
coal in 1985 under the $8 a barrel scenario is 337.3 million tons, requiring
an additional capacity for 48 million tons of clean coal.
*This section is based on N.E. Mutchler, "Can Anthracite Make a Comeback?,"
Coal Mining & Processing, April 1976, pp 60-62.
II1-43
-------
IV. METHODOLOGY FOR ECONOMIC IMPACT ANALYSIS
A. INTRODUCTION
For purposes of analysis, the U.S. coal mining industry was seg-
mented by type of coal (hard coal and soft coal) by geographic regions,
by mine type (deep vs. surface), and mine size. Coal-preparation plants
were considered as a separate segment. Each segment and the whole indus-
try comprising the segments were studied in terms of reaction to the
costs of compliance to discern the following types of Impact.
• Price and production effects;
e Financial effects, including availability of capital;
• Plant closures;
• Employment and community effects;
• Industry growth; and
• Balance-of-payment effects.
The methodology recognized that the fundamental analysis of effects of com-
pliance on prices and production would have to be accomplished first. The
results of that analysis were then to be examined in terms of their impli-
cations for capital requirements and for the availability of funds to
cover the needed outlays. Following the combining of these two analytical
pieces, other types of impacts could be logically inferred and described.
B. PRICE AND PRODUCTION EFFECTS
Price and production effects were studied together because they are
the Joint result of the conjunction of supply and demand forces. The
analytical sequence required the consideration of the supply and demand
schedules. The relevant data included, on the supply side, the 1975
minimum acceptable (supply) prices and quantities for existing mines,
those supply prices being the variable operating costs plus annualized
deferred capital charges, all on a per ton basis; the demand side utilized
1975 consumption data. For the purpose of long-term analysis, the same
kindB of supply data for existing mines, pertinent to 1985, were used;
these data describe existing mines as they are expected to appear in 1985
after provision for closures because of exhaustion. The remainder of
the 1985 supply schedule (disregarding compliance) was constructed from
the quantities to be produced by new (to-be-developed) mines at their
minimum acceptable prices comprising all costs inclusive of minimum
prospective profit. Demand schedules for 1980 and 1985 were also intro-
duced.
IV-1
-------
Price and production analysis, both short- and long-term, involved
modifying supply schedules to include annualized compliance costs per
ton and then, with attention to the relevant demand schedule, observing
the associated changes in prices and quantities.
It may be well to emphasize certain assumptions that were pertinent
to the demand forecasts and that pertained as well to the manner in which
compliance costs were introduced into the analysis;
1. There is a sufficiently large number of coal mining
companies, each perceiving itself as unable to influence
the general level of coal prices, that the industry may
be analyzed as if it conforms, at least on the selling
side, to the economist's model of perfect competition.
2. Similarly, buyers of coal and alternative energy forms
are arrayed such that they may be treated in accordance
with the perfectly competitive model.
3. It follows that each mining company, even though it
negotiates long-term price contracts, sees those prices
as negotiated within a range set by forces beyond its
own power to influence appreciably.
4. The company, as it operates a given facility, chooses an
optimum level of output that maximizes profit (or minimizes
loss), a level that can be expected to be almost independent
of selling price. (It is recognized that mines may produce
as many tons as they believe can be sold at current prices,
a tonnage that may be less than the optimum level; such
behavior does not lessen the usefulness of the competitive
model, however.)
5. The industry's supply curve, seen in annual terms, comprises
the quantities that mines are prepared to produce at or
above minimum acceptable prices, these prices being equal
to all costs that are not "sunk", i.e., equal to variable
costs plus annualized prospective capital outlays, Including
those necessary for compliance. These several assumptions
operate to produce a "stair-step" supply curve.
6. For short-run purposes, relevant to the initial impact
of BPCTCA-level compliance, market prices, demand quantities,
and production quantities are taken to be those that pre-
vailed in 1975. The methodology then allows for the possible
downward modification of production In the event that any
model type of facility closes as compliance costs push the
minimum acceptable price above prevailing market prices.
IV-2
-------
7. For long-run purposes, relevant to all three levela of
compliance (BPCTCA, EATEA, and KSPS), the aupply curve
is extended to include, for each producing region, minea
thtr -£v Is opened to enlarge industry capacity to -meet
expected 1985 demand. ?c^cje Lb ttdu^&d to be coat-
determined with 1960 and 1985 prices then equal to iuLl
coet inclusive of profit for the marginal (moat costly)
^.ire needed to natch demand.
8. The assumption that each mine will tend to operate at
capacity (provided that capacity output can be sold at
going pricea) implies that the addition or compliance
casta will not occasion any modificatiaci in the narkec
behavior of the aine. Thus, apart from provisions in
existing contracts lot the pass through o£ cosapliarLce-
type coatsj. existing tiines will rot be able to exert any
upward pressure on prices except a& any existing mine
closes. If there are closures, the supply quantities
contract relative to demand and prices
-------
BATEA, and NSPS, these same costs were compared with the prospective
market prices that equate demand and the full cost inclusive of profit
and of annualized compliance for the marginal to-be-developed mine.
The methodological steps just outlined were directly pertinent to the
production of steam coal. The analysis of price and quantity impacts
upon metallurgical mines was fundamentally the same but was simplified
because of the near zero price elasticity of the demand for metallurgical
coal.
C. FINANCIAL EFFECTS: IMPACT ON CAPITAL AVAILABILITY
Following the determination of the price and production effects that
would be prompted as model mines pursued policies that would maximize
profits or minLmize losses, attention was given to the magnitude of the
impact upon profits and resultant implications for the availability of
the incremental capital needed to finance compliance. Attention was
directed not only to prospective profitability but also to pre-existing
profits, assets, and the debt-to-equity ratio effecting the credit worthiness
of the enterprise.
D. INDUSTRY GROWTH
The growth of the coal industry over the next decade as it may evolve
in the absence of the costs of compliance for existing and new mines was
considered. The imposition of compliance costs, the financing of those
costs, and the resultant shifts in the prospective supply schedules tend
in themselves to exert a retarding pressure on industry growth. Supply
schedules, adjusted for compliance, were next placed in juxtaposition
with demand. The secular growth of demand for coal, in conjunction with
compliance-modified supply, provided the total impact of compliance upon
the growth of coal as an industry.
E. CLOSURE ANALYSIS
The extent of shutdowns both in the short term and in the long term
was to be inferred by noting any model mine situation in which price, as
analyzed above, was not sufficient to cover variable costs plus annualized
deferred capita] charges plus annualized compliance outlays, or in which
capital needed for compliance appeared not to be available.
F. EMPLOYMENT AND COMMUNITY EFFECTS
Employment and community effects would be endangered by effluent
standards only in the instance of production curtailment or closures.
IV-4
-------
G. BALAJRCE-OF-PAYKENT EFFECTS
EffectB of effluent standards in the coal industry upon U.S. foreign
trade and the balance of payments were analyzed by observing the impact
on export supply of compliance costs in conjunction with the prospective
foreign demand for U.S. coal—demand that is primarily for metallurgical
coal. In the absence of any prospective importation of coal, no analysis
of the imports side of the balance of payments was needed.
IV-5
-------
V. EFFLUENT STANDARDS AND THE COST OF COMPLIANCE
A. SOURCES AND CHARACTERISTICS OF EFFLUEMT
Water handled and discharged in coal mining and preparation may generally
be classified into two broad categories: (1) process water from either coal
preparation by wet methods, or that used for dust and fire protection; and (2)
mine drainage.
Process Water. The coal mining and preparation industry consumes
relatively little process water. The major usage of process water Is
in preparation plants. A majority of wet cleaning plants recycle a major
portion of their process water. Suspended solida consisting of semi-colloidal
particles of coal, shale and clay form one of the principal preparation plant
pollutants. Additionally, some minerals and salts, such as chlorides and sul-
fates of alkalies and alkaline earth metals, dissolve easily in water. In
certain circumstances, these salts significantly change the pK of the water.
Mine Drainage Discharge. Compared with process water discharges, the
handling and disposal of unwanted mine drainage water ie a much larger prob-
lem. The amount and nature of mine discharge is determined largely by the
mining methods and the characteristics of the mine site. Two important mine
characteristics which affect drainage properties are the geologic history
and the chemistry of the coal-bearing strata.
Mine drainage water originates from direct precipitation or from ground-
water. Surface mining areas are directly exposed to precipitation and the
nature of the exposed materials will affect the quality of the surface run-
off. The degree of groundwater discharge depends on the depth of penetra-
tion made by cutting into the groundwater zone of the sub-surface. In
general, the topographically high surface mines will encounter the least
amount of groundwater and will provide smaller quantities of mine drainage,
unless the surface mining intersects a water-filled underground mine.
Water encountered in deep mines may come from different sources. In
mines with light cover and without a firm solid roof, rainwater may seep
directly into mine workings. This may alao be true of deeper mines where
pillar fallB have broken the roof to the surface. In such cases, except
where passing under a year-round stream, the amount of water generated I.h
usually pretty closely related to the precipitation in the region—more-
water during the wet months, less during the dry. The deeper a mine i«,
the longer it is beFore changes in rainfall are reflected In the quantity
of drainage generated. Another source oE water in underground mines, not
connected with seasonal changes. Is "old" water, accumulated over a period
of tLme Ln abandoned workings of the mine, or from flooded adjacent mines.
Here the water Filters through coal and partings, or comes up through cracks
in the floor. Similarly, core holes drilled to prospect the coal property
can be a source of water.
Water muwt be disposed from the mining areas, so that mining can con-
tinue smoothly.
V-l
-------
The interaction between mineral wastes from mining and related opera-
tion and mine waters can produce dissolved or suspended pollutants.
The most difficult type of mine drainage to handle is known as acid
mine drainage. It is formed by the reaction of air and water with pyrite
(iron sulfide) present in or associated with the coal seam, and can be
represented by the reaction
70. + 2H.0 + 2FeS„ -> 2FeS0. + 2HoS0.
2 2 I 4 2 4
The reaction products are water-soluble and, in general, consist of varying
umounts of acid, iron, and sulfates and may contain suspended solids. The
ferrous sulfate can undergo further reaction with air and water to form
ferric hydroxide or "yellowboy." This is the substance that imparts the
characteristic yellow-orange color to streams and rivers polluted by acid
mine drainage.
Mine drainage can also be alkaline. This generally occurs when water
passes through limestone deposits. It can contain a significant amount of
dissolved iron and suspended solids and in arid sections of the western
United States is naturally alkaline in streams, ponds and lakes; thLs
affects mine discharge.
One of the main characteristics of wastes from coal mining operations
is that they are generally unrelated or only indirectly related to produc-
tion quantities.
If mine drainage is acidic, with large amounts of dissolved Iron,
hydrated ]ime (calcium hydroxide) or quicklime (CaO) is added, followed by
aeration which converts the iron to insoluble ferric hydroxide. The water
then passes Into a large lagoon to settle the suspended solids. The treat-
ment of alkaline drainage consists of aeration in a large lagoon.
B. EFFLUENT GUIDELINES
In developing effluent guidelines, tlie U.S. coal mining industry has
been divided into the following groups:
• Bituminous, lignite and anthracite mining - acid or ferrugLnous
mine drainage and alkaline mine drainage;
• Coal preparation plant - process water; and
• Coal storage, refuse storage,and coal preparation plant ancillary
area.
Tables 57, 58 and 59 give the BPCTCA (Best Practical Control Tech-
nology Currently Available), BATF.A (Best Available Technology Economically
Achievable), and NSPS (New Source Performance Standards) guidelines for
the coal mining industry. BATEA requirements are the same as BPCTCA re-
V-2
-------
TABLE 57
EFFLUENT LEVELS ACHIEVABLE THROUGH APPLICATION OF THE
BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY AVAILABLE
Parameter
<
I
U)
Bituminous, Lignite, and Anthracite
Mining Services
Coal
Preparation
Plant
30 Day
Average
Daily
Maximum
Coal Storage,
Refuse Storage
and Coal Prep-
aration Plant
Ancillary Area
30 Day 1
Average
Dally *
Maximum
Bituminous, Lignite, and
Anthracite Mining
Acid or Ferrugi-
nous Mine Drainage
Alkaline Mine
Drainage
30 Day *
Average
Daily *
Maximum
30 Day *
Average
Daily *
Maximum
pH
Iron, Total
Dissolved Iron
Manganese, Total
Total Suspended
Solids
C
<0
o
Q_
Q)
CT>
S-
fo
JC
u
IT,
¦r-
Q
O
c
3
O
Q.
a>
cn
i.
to
JZ
u
l/>
o
o
6-9
3.5
0.30
2.0
35
6-9
7.0
0.60
4.0
70
6-9
3.5
0.30
2.0
35
6-9
7.0
0.60
4.0
70
6-9
3.5
35
6-9
7.0
70
All values except pH in mg/1
Source: Effluent Guidelines Division, EPA
-------
TABLE 53
EFFLUENT LEVELS ATTATVAftl F THftni'EH APP1 T T.AT I OH C.f THF
"•gESTTtTOMTTTcHwoLOsy FcomcAu7achievable
Bituminous, Lignite, and Anthracite
Mining Services
Bituminous, Lignite, and
Anthracite fining
Parameter
Coal Preparation
Fldit
Coal Storage,
Refuse Storage
and Coal Prep-
aration Plant
Aricil lary Area
Acid or Ferrugi-
nous Mine Drainage
Alkaline Mine
Drainage
pH
Iron, Total
Dissolved Iron
Manganese» Total
Total Suspended
Solids
30 Day
Average
IS)
+-*
c
s-
jz:
-j
-o
O
Daily
Maximum
C.
A3
O
CL-
a>
cn
SL
¦P3
JC
u
m
*»-
TJ
O
30 Day *
Average
Daily *
Maximum
30 Day *
Average
Daily *
Maximum
30 Day *
Average
Daily *
Maximum
6-9
6-9
6-9
6-9
6-9
6-9
3.0
3.5
3.0
3.5
3.0
3,5
0.30
0.60
0.30
0.60
2.0
4.0
2.0
4.0
£0
4C
20
40
20
40
ALl values except pR in ngj'l.
Source: Effluent Guidelines Division, EPA
-------
TABLE 59
NEW SOURCE PERFORMANCE STANDARDS
Parameter
<
I
Bituminous, Lignite, and Anthracite
Mining Services
Bituminous, Lignite, ancf
Anthracite Mining
Coal Preparation
Plant
30 Day
Average
Daily
Maximum
P«
VI
¦M
C
to
¦M
C
ra
1 t
ro
» *
Iron, Total
Z3
3
o
O
Dissolved Iron
Q.
CL
4-
O
o
Manganese, Total
OJ
OJ
CFi
¦r
D>
e
Total Suspended
V-
fO
-C
ra
JZ
Solids
o
a
bO
"O
o
o
2
z
Coal Storage,
Refuse Storage
and Coal Prep-
aration Plant
Ancillary Area
Acid or Ferrugi-
nous Mine Drainage
Alkaline Mine
Drainage
30 Day *
Average
All values except pH in rag/1.
Source: Effluent Guidelines Division. EPA
Daily *
Maximum
30 Day * Daily *
Average Maximum
30 Day *
Average
Daily *
Maximum
6-p
6-g
6-9
6-9
6-9
6-9
3.0
3.5
3.0
3.5
3.0
3.5
0.30
0.60
0.30
0.60
2,0
4.0
2.0
4.0
35
70
35
70
35
70
-------
quirements, except for lower total iron and lower suspended solids require-
ment. NSPS standards are the same as BATEA, except for suspended solids,
which is the same as the BPCTCA standard. The BPCTCA, BATEA and NSPS stan-
dards for coal preparation plants require no discharge of pollutants.
C. COSTS OF COMPLIANCE
The Effluent Guidelines Division of the EPA provided estimates of the
cost of compliance for the BPCTCA and BATEA guidelines by regions and
type of mining for the U.S. coal mining industry. These costs were pro-
vided as total BPCTCA costs, i.e., no in-place water treatment.facility
and incremental BATEA, i.e., costs above BPCTCA levels in mid-1974 dollars.
The cost categories included capital requirements, operating and mainte-
nance, and total annualized costs. An interest rate of 8% and expected
useful life of 10 years for equipment and mine life for facilities were
used to amortize pollution control investment in the annualized costs.
"New source performance standards" compliance costs were stated to be the
Bame as total BATEA costs, i.e., BPCTCA plus incremental BATEA costs.
The treatment technology for acid mine drainage is lime neutraliza-
tion, aeration and settling to meet BPCTCA standards and additional sand
filtration to meet BATEA standards. The wastewater treatment for alkaline
drainage consists of settling to meet BPCTCA standards with flocculation
to meet BATEA standards. According to Calspan, the Effluent Guidelines
Division contractor providing the costs, costs represent upper-bound costs.
For surface mines, a new settling pond is built every six months and these
costs are treated as operating costs. The mine drainage treatment costs
are based on one outfall per mine. The cost of compliance for preparation
plants is based on closure of water circuits and treatment of water asso-
ciated with coal and refuse storage incorporating settling in ponds or
basins.
Tables 60 to 65 summarize the BPCTCA and incremental BATEA costs
(above BPCTCA) by regions and type of mining in terms of capital invest-
ment and annualized operating costs associated with compliance with
effluent standards. Table 66 presents the costs associated with compliance
for preparation plants.
V-6
-------
TABLE 60
COSTS OF COMPLIANCE WITH EFFLUENT GUIDELINES: NORTHERN APPALACHIA
(1974 Dollars)
>3
Size:
Annual Tonnage (10"1 ST)
BPT Costs
• Capital Investment
$103
$/Annual Ton
• Operating Costs
S103
$/Ton
BAT Costs (Incremental)
• Capital Investment
$103
$/Annual Ton
• Operating Costs
S103
$/Ton
BAT Costs (Total)
o Capital Investment
$/Annual Ton
• Operating Costs
$/Ton
Large
1016
400-428
243-262
58-62
Deep Mines
Medium
102
37-42
25-28
240-260 60-70
0.24-0.26 0.59-0.69
21-23
0.06-0.06 0.21-0.23
0.63-0.68 0.95-1.10
0.30-0.32 0.46-0.51
Small
51
22-23
0.39-0.42 0.36-0.41 0.43-0.45
11-12
0.24-0.26 0.25-0.28 0.22-0.24
NA
NA
NA
NA
NA
NA
Surface Mines
Large
508
Medium
102
90-105 40-46
0.18-0.21 0.39-0.45
28-30 15-16.5
0.06-0.06 0.15-0.16
0.25-0.29 0.43-0.49
0.18-0.19 0.36-0.40
Small
51
36-38 .4.4-4.5 3.7-3.8
0.07-0.08 0.04-0.04 0.07-0.08
58.5-64.8 21.4-24.9 13.2-15.4
0.12-0.13 0.21-0.24 0.26-0.30
NA
NA
NA
NA
NA
NA
Source: Calspan, Effluent Guidelines Division Contractor; memo, January 29, 1976.
-------
TABLE 61
COSTS OF COMPLIANCE WITH EFFLUENT GUIDELINES
(1974 Dollars)
Deep Mines
Size:
3
Annual Tonnage (10 ST)
BPT Costs
• Capital Investment
S103
$/Annual Ton
e Operating Costs
S103
$/Ton
BAT Costs (Incremental)
e Capital Investment
$103
$/Annual Ton
• Operating Costs
S103
$/Ton
BAT Costs (Total)
• Capital Investment
$/Annual Ton
e Operating Cost
$/Ton
Large
1,016
31.2
0.03
7.9
0.01
2.9
0.003
82.1
0.08
0.033
0.09
Medium
102
9.9
0.1
3.4
0.03
1.8
0.02
14.2
0.14
0.12
0.17
Small
51
2.9
0.06
1.0
0.02
1.4
0.03
3.3
0.07
0.09
0.09
Source: Calspan, Effluent Guidelines Division Contractor;
SOUTHERN APPALACHIA
Surface Mines
Large Medium Small
508 102 51
56.1-66.4 15.8-22.1 10.5-12.0
0.11-0.13 0.15-0.22 0.21-0.24
1.8 1.4 1.4
0.004 0.01 0.03
6.7-8.8 2.1-3.3 1.7-1.8
0.01-0.02 0.02-0.03 0.03-0.04
0.004 0.01 0.03
0.12-0.15 0.17-0.25 0.24-0.28
, January 29, 1976.
-------
TABLE 62
COSTS OF COMPLIANCE WITH EFFLUENT GUIDELINES: CENTRAL REGION
Size:
Annual Tonnage (103 ST)
BPT Costs
® Capital Investment
S103
$/Annual Ton
« Operating Costs
$103
$/Ton
BAT Costs (Incremental)
• Capital Investment
$103
$/Annual Ton
• Operating Costs
S103
S/Ton
BAT Costs (Total)
• Capital Investment
$/Annual Ton
o Operating Costs
$/Ton
(1974 Dollars)
Deep Mines
Large
1,016
13.8
0.014
5.4
0.005
2.9
0.003
20.2
0.02
0.017
0.03
Medium
152
5.7
0.038
2.7
0.018
1.8
0.012
5.6
0.037
0.05
0.06
Small
51
2.8
0.055
1.0
0.02
1.4
0.03
2.2
0.04
0.085
0.06
Large
1,016
69
0.068
1.8
0.002
8.9
0.009
0.002
Surface Mines
Medium
102
Small
15.7-20.7
0.15-0.20
1.4
0.01
1.9-2.3
0.02-0.023
0.01
51
10.6-15.1
0.21-0.30
1.4
0.03
1.7-2.1
0.03-0.04
0.03
0.08 0.17-0.22 0.24-0.34
Source: Calspan, Effluent Guidelines Division Contractor; memo, January 29, 1976.
-------
TABLE 63
COSTS OF COMPLIANCE WITH EFFLUENT GUIDELINES: INTERMOUNTAIN REGION
<
i
Size:
3
Annual Tonnage (10 ST)
BPT Costs
o Capital Investment
?103
$/Annual Ton
e Operating Costs
$103
$/Ton
BAT Costs (Incremental)
e Capital Investment
$103
$/Annual Ton
e Operating Costs
$103
$/Ton
Large
762
8.2
0.01
2.9
0.01
1.8
0.012
11.0
0.01
(1974 Dollars)
Deep Mines
Medium
Small
Large
3048
38.6
0.01
1.4
0.0005
4.0
Surface Mines
Medium
152
7.1
0.05
1.4
0.009
1.3
0.01
Small
51
6.3
0.12
1.4
0.027
1.3
0.03
BAT Costs (Total)
• Capital Investment
$/Annual Ton
o Operating Costs
$/Ton
0.013
0.02
0.0005
0.01
0.009
0.06
0.027
0.15
Source: Calspan, Effluent Guidelines Division Contractor; memo, January 29, 1976.
-------
TABLE 64
COSTS OF COMPLIANCE WITH EFFLUENT GUIDELINES: GREAT PLAINS REGION
<
i
Size:
3
Annual Tonnage (10 ST)
BPT Costs
e Capital Investment
$103
$/Annual Ton
o Operating Costs
$103
$/Ton
BAT Costs (Incremental)
o Capital Investment
$103
$/Annual Ton
o Operating Costs
$103
$/Ton
BAT Costs (Total)
• Capital Investment
$/Annual Ton
® Operating Costs
$/Ton
Large
762
15.4
0.02
5.5
0.01
2.9
0.004
22.0
0.03
0.024
0.04
(1974 Dollars)
Deep Mines
Medium
152
6.0
0.04
2.7
0.02
1.8
0.012
6.2
0.04
0.052
0.06
Small
51
3.1
0.061
1.0
0.02
1.4
0.03
3.8
0.08
0.091
0.10
Large
5079
38.6
0.01
1.4
0.0003
3.7
0.0003
0.01
Surface Mines
Medium
152
Small
9.8
1.4
0.009
1.4
0.01
0.009
0.07
51
4.8
0.10
1.4
0.03
1.2
0.02
0.03
0.12
Source: Calspan, Effluent Guidelines Division Contractor; memo, January 29, 1976.
-------
TABLE 65
COSTS OF COMPLIANCE WITH EFFLUENT GUIDELINES
(1974 DollarsJ
WEST REGION
Size:
3
Annual Tonnage (10 ST)
BPT Costs
o Capital Investment
S103
$/Annual Ton
9 Operating Costs
S103
$/Tod
EAT Costs (Incremental)
« Capital Investment
$10 3
3/Annual Ton
et Operating Costs
§103
$/Ton
BAT Costs (Total)
a Capital Investment
$/Annual Ton
c Operating Costs
$/Ton
Large
Deep Mines
Me diutn
Small
Large
3251
44-. 8
0.02
1.8
0.0006
k .0
Surface Mines
Medium
71
0.02
5,8
0.08
1.4
0.02
1.3
0.02
0.02
0.10
Snail
Source: Calspan, Effluent Guidelines Division Contractor; memo, January 29, 1976.
-------
TABLE 66
COMPLIANCE COSTS* ASSOCIATED WITH WATER CIRCUIT CLOSURE
FOR COAL PREPARATION PLANTS
(1974 Dollars)
Preparation Plant
Capacity
Annual Capacity
Effluent Flow Rate
Percent Solids in Effluents
Capital Investment
$
($/Annual Ton)
Amortization ($)
Operating and Maintenance ($)
Annual Operating Costs
$
($/Ton Coal Cleaned)
Model C
1000 tons per hour raw coal
3,000,000 tons raw coal
1500 GPM
15
1,234,000
0.41
144,378
76,840
221,218
0.07
H
Includes costs for closure of water circuit for preparation
plant and water treatment with storage of refuse and coal
storage.
Source: Effluent Guidelines Division, I'll'A
V-13
-------
VI. IMPACT ANALYSIS
The U.S. coal industry comprises a large number of establishments,
almost 5,000 mines and 400 preparation plants. The coal industry was seg-
mented into coal mines and coal preparation plants. The coal mine segment
was further subcategorized as "soft" coal mines (bituminous, sub-bituminous,
and lignite), "hard" coal mines (anthracite), and by geographic regions, by
type of mine (deep vs. surface), and by mine size to analyze the Impact of
compliance with the effluent guidelines.
The segmentation involves regional categorization of "soft" coal mines
as follows: N. Appalachia - Maryland, Pennsylvania, Ohio, Virginia, and
West Virginia; S. Appalachia - Alabama, E. Kentucky and Tennessee; Central -
Arkansas, Illinois, Indiana, Kansas, W. Kentucky, Missouri, Oklahoma, Texas
and Iowa; Intermountain - Arizona, Colorado, New Mexico, and Utah; Great
Plains - Montana, N. Dakota, and Wyoming; and West - Alaska, and Washington.
Anthracite is produced in Pennsylvania. Financial infomation was lacking
for the West region as there are very few mines. In addition, as compliance
costs are small for this region, they were excluded from the analysis.
According to the memorandum on compliance costs from the Effluent Guidelines
Division of the EPA, no additional expenditures are necessary to comply
with effluent guidelines for the anthracite mining segment, and hence this
segment has been excluded from further analysis.
The analysis of each type of Impact or effect rails for a separation
by time period and by a relevant set of guidelines [BPCTCA (Best Practical
Control Technology Currently Available) in 1977, BATEA (Best Available
Technology Economically Achievable) in 1983, or NSPS (New Source Performance
Standards)]. These separations can be described briefly before indicating
analytical steps and results.
The effects of BPCTCA need to be considered first in the short run,
which may be thought of as a period too bried for the impact to include re-
sultant changes in the capacity of the industry. A short-run period is not
relevant to BATEA, because presumably requirements will be well-known suf-
ficiently far in advance that capacity plans will be firmed In anticipation
of the 1983 deadline; similarly, a short-run period need not be envisaged
respecting NSPS, because guidelines will be incorporated into the scheduled
investments as new mines are developed.
The long term is then a period sufficiently long that changes in
industry capacity can be made in consequence of the institution of guide-
lines. Thus, BPCTCA, BATEA, and NSPS may each occasion long-run Impacts.
As a working timeframe, the year 1980 may be taken as the time at which
to assess initial indications of the long-run effect of BPCTCA for existing
mines and NSPS for new mines that are developed prior to 1980. The year
1985 serves a a reference point for evaluating BATEA and NSPS as well, in
terms of the new mines being developed during the same period as BATEA be-
comes effective for existing mines.
Vl-l
-------
The overriding influence on the character of impact of guidelines on
the coal industry is prospective growth of the industry during the next dec-
ade as the United States endeavors to reduce its dependence upon imported pe-
troleum. For example, the PIES (Project Independence Evaluation System) ref-
erence scenario with imported oil priced at $13 per barrel shows coal pro-
duction increasing from 639 million tons in 1975 to 1,040 million tons in
1985, an average annual growth rate of 5%. The reference scenario with
imported oil at $8 per barrel shows coal production at 894 million tons, an
average annual increase of 3.4%. These scenarios are considered in this
analysis to represent both optimistic and pessimistic growth rates. The in-
creased demand necessitates additional new mining capacity. The continuing
pull of demand upon supply quantities operates to lift prices to the levels
needed to induce sufficient new mine openings. Thus, the long-run price of
coal tends to be at the level of minimum acceptable price (full cost inclu-
sive of normal profit) for the highest cost (marginal) new mine.
Impact possibilities are shaped also by the competitive market situation
among coal producers. Although producers, and buyers as well, seek to pro-
tect themselves against untoward fluctuations in the spot price of coal by
entering into contracts that include negotiated prices for coal, producers
perceive themselves as having virtually no power to affect the general level
of coal prices, and no power to negotiate contract prices that are at odds
with that general level. This almost perfectly competitive pricing situation
is coupled with a cost situation for any mine that puts the lowest average
cost per ton at an output level approximately the capacity of the mine. A
key corollary of this observation is that increasing costs not directly re-
lated to output, such as those caused by compliance, do not occasion any
changes in the level of output.
Throughout the impact analysis, all prices are measured in dollars of
1975 purchasing power. Production costs are as of December 1974 and take
into account wage increases arising out of the National Bituminous Coal
Wage Agreement of 1974 (effective December 1, 1974) and therefore represen-
tative of the early 1975 period. Compliance costs are in terms of mld-1974
dollars. We have considered compliance costs to be representative of the
1975 period. Thus, the problems of analysis are not aggravated by considera-
tion of inflation and changes in the value of the dollar used for measuring
the magnitudes relevant to guidelines impact. The use of constant 1975 dol-
lars does not eliminate the possibility of changes in relative prices for
coal and the inputs for producing coal. (The relative price of coal may
rise for other reasons as well, such as the inability of productivity in
coal mining to keep pace with rising productivity in the economy as a
whole, but no formal introduction of such relationships into the analysis
has been made.)
1. Price Effects
It is well to emphasize from the outset that coal is sold through long- and
medium-term contracts as well as on the spot market. At present around 80%
of all coal is sold through contracts. Most new contracts permit escalations
VI-2
-------
based on increased coat of production. Short-term contracts are in Fogue,
especially for old utility stations; for example, one-year "evergreen" that
are essentially supply contracts renegotiated snonthly. Producers are seek-
ing contracts which, at the very leaat, guarantee a full pass through of coats,
and it is likely that new contracts will be negotiated with provision for
pasB through for increased production costs, including environmental control
COBtS.
The cost of compliance with BFT standards will not influence the price
of spot market coal in the short run and will have an effect on the price
of "contract" coal only to the extent that current contracts have automatic
provisions for -escalation based or. the increased cost of production. In the
longer run, however, as ~~r.tr acre, are res ego coated, it 13 iiV.-g xtsat ^tie
costs of compliance will be passed through. Hence, the cost of BFT compli-
ance will affect caal prices only to the extent that current contractB include
escalation clauses or as euch clauses are negotiated.
The mote important effect on coal prices during the longer tens, but
before the advent of BAT influences, ie the rise occasioned by the increase
in demand arid the need to open new mines that will have to be reimbursed
with full costs inclusive of profits and inclusive also of the coats of
NSPS. These marginal-mine prices will aet the level for the rest of the
wairket, pulling prices received by existing mines above the levels that would
"be prompted by BPT requirements alot\e.
The cost of compliance with BAT standards wilJL again affect coal prices
to the extent that coal sold on contract tern«s includes escalation clauses
for production cost increases atid the spot market reflects the general level
of compliance by the rest of the industry.
Table 6? presents the prices of coal in 1975, 1980, and 1985 that have
been used iti the analysis. The average 1975 prices were derived from Bureau
of Hinea data on 1974 value f.o.b. mine by states, using a $Z.G0 per ton
preparation charge for prepared steam coal and a §4.00 per ton charge for
prepared metallurgical coal to arrive at a value f.o.b. mine far run of nine
unprepared coal. The preparation charges are as used in FIES, and for
ateam coal seem reasonable in comparison with the costs of preparation of
eteara coal derived in Chapter II. Theae values were adjusted to average
1975 prices by an escalation factor derived from the average value f.o.b^
nine far all coal in 1974 of 515.75 a ton and in 1975 of $18.75 a ton. The
prices in 1930 and 1935 are prices derived from t^e PIES model.
In Table 68, we have presented the price increase as a result of com-
pliance with BPT and BAT standards assuming full cost pass through. The
maximum increase is 2.1% for BPT and 1.3% for BAT for mines and 3.5% for
BPT for preparation plants. It should be stressed that the actual increases
would be less than these to the extent contracts do not have escalation
clauses.
In Table 69, we present the effect of compliance with USPS cm coal
prices. The compliance costs Cor the coBts of compliance) for new sources ate
VI-3
-------
TABLE 67
COAL PRICES F.O.B. MINE FOR RUN OF MINE COAL
(1.975 $/Ton)
Region
1975 Prices
1980 Prices
$13^
1985 Prices
$13z $8-'
N. Appalachla
Deep
Strip
22.48
19.93
17.79
14.03
19.59 17.29
15.45 13.58
S. Appalachla
Deep
Strip
26.42
22.42
25.41
19.62
28.60 23.12
22.08 17.93
Central
Deep
Strip
11.12
8.23
12.89
9.92
13.15 12.35
10.12 9.55
Intermountain
Deep
Strip
11.87
6.35
9.40
5.10
10.00 9.80
5.10 5.10
Great Plains
Strip
4.85
5.48
5.78 5.61
'Derived from U.S.li.M. data.
ZPI1£S - $13 a barrel Imported oil.
3PIES - $8 a barrel imported oil.
VT-4
-------
TABLE 68
MODEL
Mine Segment
PRICE INCREASES ASSUMING FULL COST PASS THROUGH
FOR BITUMINOUS COAL MINING AND PREPARATION SEGMENT
(1975 $/Ton)
BPT
Average
Precompliance
Price (1975)
Maximum Average
Compliance Percent
Cost Increase
Average
1985 Price
$131
$8-
BAT
Maximum
Compliance
Cost
(Incremental)
Average
Percent
Increase
$131 $8:
N. Appalachia
Deep
Strip
22.48
19.93
0.28
0.24
1.2
1.2
19.91
15.64
17.29
13.58
0.23
0.16
1.2
1.0
1.3
1.2
i
Ui
S. Appalachia
Deep
Strip
26.42
22.42
0.03
0.24
0.1
1.1
28.69
22.23
23.12
17.93
0.14
0.04
0.5
0.2
0.6
0.2
Central
Deep
Strip
11.12
8.23
0.02
0.30
0.2
3.6
13.18
10.20
12.35
9.55
0.04
0.04
0.3
0.4
0.3
0.4
Intermountain
Deep
Strip
11.87
6.35
0.01
0.12
0.1
1.9
10.02
5.11
9.82
5.11
0.01
0.03
0.1
0.6
0.1
0.6
G. Plains
Strip
4.85
0.10
2.1
3.79
.62
0.02
0.3 0.4
Preparation Plants 2.00 0.07 3.5
^IES - $13 a barrel imported oil.
2PIES - $8 a barrel imported oil.
-------
TABLE 69
Mine Segment
N. Appalachia
Deep
Strip
S. Appalachia
Deep
Strip
Central
Deep
Strip
Intermountain
Deep
Strip
G. Plains
Strip
Preparation Plants
EFFECT OF NEW SOURCE PERFORMANCE
STANDARDS (NSPS) ON COAL PRICES, 1980 AND 1985
1980 Price
1
1985 Price1
Cost of
NSPS
1975 S/ton
Price
Excluding NSPS
1975 S/ton
Percent
Increase
with NSPS
Price
Excluding NSPS
1975 $/ton
Percent
Increase
with NSPS
.32
.19
17.79
14.03
1.8
1.4
19.59
15.45
1.6
1.2
.09
.15
25.41
19.62
0.4
0.8
28.60
22.08
0.3
0.7
.03
.08
12.89
9.92
0.2
0.8
13.15
10.12
0.2
0.8
.02
.01
9.40
5.10
0.2
0.2
10.00
5.10
0.2
0.2
.01
.07
5.48
2.00
0.2
3.5
5.78
2.00
0.2
3.5
;PIES reference scenario; imported oil priced at $13/barrel.
-------
rep essentia cy EAT (total) coats- The c&splts nee cost& ior the Isrge orltie
model havs been used In feacV. tA tYie regions, the BiaxiwuK increase i*n price
is 1.85 in 1980 and 1.6? In 1965 for CLlc.ee, &"wl Eot jlepaTation plants.
2. Financial Effects
a. profltabllit-i
Hie c^at of compliance with BPT etand-ards will result In & JUswareJ
profitability E-ot existing fliines. The extent of profitability ttecrs^e-e vill
depend m AH:rr r.tm ..vtt.«.ls c:« f-h-a Spot n>ark?t , cc haa t co3<: r j.'t
without escalation cltiuaes—-in which caae Wva eStecX on. profitability will he
a vptf.-*ViXjT-i; or if he h^a a contrac- vith an escalation clause, in vfttch tuae
there will be no effect ot> profitability. the extent of reduction 13' pre-
tax tjish flow and decease In profitability For the model mines xind prepara::l£?c
jslnnte are presented in Tables 70 to 74. Tha tfattiiwuro decrease lr> cash f lotj
is leas th$% 6.™ of pTeccwpLlanca pre-tax c£8h Flew smd reduction In
profCtabillty is less ttuisx €,,<,% -dI i>Te~tajt profits for jnlcea sad preparation plantt
In the longer run, as contracts ate renegotiated, it la likely that the
increased eostg will be passed throu&h via escalation cleuaea, resulting in tio
effect on profitability of existing mines, to the extent that these fflr.ea
have ccotr^cte vitti tio "cc-et pass through" pfcvlaitms^ eV^te oa-a be at irsttt
of BaT ccuvpliauta CLoats =f etiz zlig, mlsee. It is ejected
tlwt most j^s^;ra;tE- waiJd isve "aetn cerje^stla^a^ b^fare BAT conpjllapce is
Ffctf-iirecl vlth cost pte3 through previsions,
Tfaere ie likely tc be no effect of USPS campliance tosta on th£ profit-
ability o£ (vew mines, eince new mines will he att.tac.te4 otvl^ to the extent that
they can meet all costs> inclusive of compliance, arvd obtstn a reasonable
profit-
b. Capital Requirgwec^a stt* Availability
Teklg 75 preaarte- the capital requirements to meet /SF7 axvi BJVE MJlncJcri^
in collars per .annual ton for BfT s^et dallara per annual ton (above BPT)
for BAT. It is seen th£t the highest investments are required for mines l/i
Northern Appslachla mid fur preparation plants.
Tables 7<> to 7ft y£ea«ni comparisons of Jifter-lax cast's Clows to the com-
pliance capital auti the average deferred capital requirements for .^oriherr
Appal&chia atfd preparation p.'anbs for which the investment for Effluent rcr-
trol are the highest. Interest expenses bbbi^hS s debt~tc-i btIo of
J;2.5 and interest rate. It is seen thet foe the model raises acc ptep^
ration planta»tbe sftsr-tax cfleh £1 o*> ie adequate to f.o^t T-Vseea requirements.
We Jtave- usee? .tver&gz st>ot plus contract prices In 1'ieSre Eajtylntimts.
SrfiaLJ Tnlrea are llkrly «ell their output on trie spot market. Spat .""firew
-------
TABLE 70
EFFECT OF BPT COMPLIANCE COSTS
ON THE CASH
FLOW OF MODEL DEEP MINES1
(1975 $/Ton)
Mine Size (106 TPY)
0.1 0.5
1.0
2.0
3.0
N. Appa 1 uchf 11
Average 1975 Price
22.48 22.48
22.48
22.48
22.48
Cost of Production'
12.39 12.97
12.48
12.17
11.92
BPT Compliance Coal
0.28 0.26-0.
28 0.26
0.26
0.26
Cash Plow' I'recompl lance
10.09 9.51
10.00
10.31
10.56
X Change in Cash Flow
as a Result of Compliance
2.8 2.7-2.
9 2.6
2.5
2.5
S. Appalnclila
Average 1975 Price
26.42 26.42
26.42
26.42
26.42
Cost of Production1
12.39 12.97
12.48
12.17
11 .92
BPT Compliance Cost
0.03 0.01-0.
03 0.01
0.01
0.01
Cash Flow^ Precompllunce
14.03 13.45
13.94
14.25
14.50
Z Change In Cash Flow
as a KesulL of Compliance
0.2 0.1-0.
2 0.1
0.1
0.1
Mine Size (106 TPY)
0.5
1.0
2.0
3.0
Central
Average 1975 Price
11.12
11.12
11.12
11.12
Cost of Production'
8.61
8.39
8.23
8.13
BPT Compliance Costs
0.005-0.02
0.005
0.005
0.005
Cash Flow? Precorapllance
2.51
2.73
2.89
2.99
X Change In Cash Flow
as a Result of Compliance
0.2-0.8
0.2
0.2
0.2
Intermountaln
Average 1 9 7 *> Price
11.87
11.87
11 .87
11.87
Cost of Production'
9.03
8. 76
8.56
8.42
BPT Compliance Costs
0.01
0.01
0.01
0.01
Cash Flow*' Precomp 1 lunce
2.84
3.11
3.31
3.45
Z Change In Cash Flow
as a Result of Compliance
0.4
0.3
0.3
0.3
'Fjccludes depreciation, depletion.
2Cnsh Flow - Pre-tax Profit + Depreciation + Depletion.
Vl-C
-------
TABLE 71
EFFECT OF BPT COMPLIANCE COSTS ON
THE CASH FLOW OF MODEL SURFACE MINES1
(1975 $/Ton)
Mine Size (10 TPY)
W. Appalachla
Average 1975 Price
Cost of Production1
BPT Compliance Costs
Cash Flow2 I'rccompl lance
Z Change In Cash Flow'' as
a Result of Compliance
S. Appalachla
Average 1975 Price
Cost of Production1
BPT Compliance Costs
Cash Flow2 Hrecompliance
Z Change in Cash Flow2 as
a Result of Compliance
0.1
19.93
8.96
0.24-0.30
10.97
2.2-2.7
22.42
8.96
0.22-0.24
13.46
1.6-1.8
0.5
19.93
8.47
0.13-0.24
11.46
1.1-2.1
22.42
8.47
0.13-0.22
13.95
0.9-1.6
1.0
19.93
7.85
0.13
12.08
1.1
22.42
7.85
0.13
14.57
0.9
3.0
19.93
5.37
0.13
14.56
0.9
22.42
5.37
0.13
17.05
0.8
Mine Size (10 TPY)
Central
Average 1975 Price
Coot of Production'
BPT Compliance Costs
Cosh Flow2 Precompliance
X Change In Cash Flow2 as
a Result of Compliance
Intennountain
Average 1975 Price
Coat of Production1
BPT Compliance Costs
Cash Flow2 Precompliance
Z Change in Cash Flow2 as
a Result of Compliance
1.0
8.23
5.64
0.07
2.59
2.7
6.35
4.67
0.01
1.68
0.6
3.0
8.23
4.74
0.07
3.49
2.0
6.35
4.10
0.01
2.25
0.4
Mine Size (10 TPY)
Groat Plains
Average 1975 Price
Cost of Production1
BPT Compliance Costs
Cash Flow' Precompliance
Z Change in Cash Flow2 as
e Result of Compliance
6.0
4.85
3.64
0.01
1.21
0.8
'Excludes depreciation, depletion.
2Coeh Flow - Pre-tax Profits + Depreciation + Depletion.
VI-9
-------
TABLE 72
EFFECT OF BPT COMPLIANCE COSTS
ON THE PROFITABILITY OF MODEL DEEP MINES
(1975 $/Ton)
Mine Size (106 TPY)
0.1
0.5
1.0
2.0
3.0
N. Appalachin
Average 1975 Price
22.18
22.48
22.48
22.48
22.48
Coot of Production
16.73
17.52
16.73
16.17
15.83
BPT Compliance Costs
0.24-0.30
0.13-0.24
0. ] 3
0.13
0.13
Pre-tax Profits Precompllance
5.75
4.96
5.75
6.31
6.65
Z Change In Pre-tax Profits
as a Result of Compliance
4.2-5.2
2.6-4.8
2.2
2.1
2.1
S. Appalachia
Average 1975 Price
26.42
26.42
26.42
26.42
26.42
Coat of Production
17.12
17.91
17.12
16.56
16.22
BPT Compliance Costs
0.03
0.01-0.03
0.01
0.01
0.01
Pre-tax Profits Precompllance
9.30
8.51
9.30
9.86
10.20
Z Change in Pre-tax Profits
as a Result of Compliance
0.3
0.1-0.4
0.1
0.1
0.1
Cent rol
Average 1975 Price
—
11.12
11.12
11.12
11.12
Coat of Production
~
10.45
10.2 7
10.13
10.06
BPT Compliance Coats
—
0.005-0.02
0.005
0.005
0.00!
Pre-tax Profits Precompllance
—
0.67
0.85
0.99
1.06
I Change in Pre-tax Profits
as a Result of Compliance
—
0.8-3.0
0.6
0.5
0.5
Mine Size (106 TPY)
0.1
0.5
1.0
2.0
3.0
InterraountaJ n
Average 1975 Price
--
11.87
11.87
11.87
11 .87
Coot of Production
--
11.00
10. B0
10.69
10.55
BPT Compliance CoHta
—
0.01
0.01
0.01
0.01
Pre-tax Profits Precompllance
—
0.87
1.07
1.18
1 .32
Z Change in Pre-tax Profits
as a Result of Compliance
::
1.2
0.9
0.9
0.8
VT-10
-------
TABLE 7 3
EFFECT OF BPT COMPLIANCE COSTS ON THE
PROFITABILITY OF MODEL STRIP MINES
(1975 $/Ton)
Mine Size (10 TI'Y) 0.1 0.5 1.0 3.0
N. n l_)i c Ma
Average 1975 Price 19.93 19.93 19.93 19.'JJ
Cost of I'rodui l I on 12.05 12.39 1 1 .40 8.43
BPT Compliance Costa 0.24-0.30 0.13-0.24 0.13 0.13
l're-tox Profits PrecompI lance 7.88 7.64 8.53 11.48
% Change In Pre-tax Profits
as a Result of Compliance 3.0-3.8 1.7-3.1 1.5 1.1
S. Appq 1 ach I J)
Average 1975 Price 22.42 22.42 22.42 22.42
Cost of Production 12.30 12.64 1 1 .65 8.68
BPT Compllame CohIh 0.22-0.24 0.13-0.22 0.13 0.13
Pre-lax Profits Procump 1 i;ince 10.12 9.78 10.77 13.74
X Change In Pre-Lax Profits
as a Result of Compliance 2.2-2.4 1.3-2.3 1.2 0.9
Central
Average 1975 Price
Cost of Production
BPT Compliance Costs
Pre-tax Profits Precomp1 lance
X Change In Pre-tax Profits
as a Result of Compliance
8.23
7.29
0.07
0.94
7.4
8.23
6.49
0.07
1.74
4.0
Mine Size (10 TPY)
Intcrmoun tain
Average 1975 Price
Cost of Production
BPT Comp1 I unco Cuslh
Pre-tax Profits Precomp I lance
Z Change in Pri—lux I'roflLs
as a Result of Compliance
1.0
6.35
5.73
0.01
0.62
1 .6
3.0
6.35
5.30
0.01
1 .05
1.0
6.0
Crcat Pin inn
Average 19 75 Price
Cost of Production
BPT Compliance Costs
Pre-tax Profits Precomp11ance
X Change in 1're-t.ix Profits
as a Result of Compliance
4.85
4.34
0.01
0.51
2.0
V I - 1 I
-------
TABLE 74
EFFECT OF BPT COMPLIANCE COSTS
ON THE CASH FLOW OF MODEL PREPARATION PLANTS
(1975 $/Ton)
Plant Size
(106 TPY raw coal)
Average Price
Cost of Production
Pre-tax Profit
Pre-tax Cash Flow
0.5
2.00
1.14
0.86
1.24
1.0
2.00
0.97
1.03
1.37
2.0
2.00
0.76
] .24
1.45
3.0
2.00
0.7]
1.29
1.46
fiPT Compliance Cost
0.7
0.07
0.07
0.07
% Change in Pre-tax Profits
as a Result of Compliance
8.1
6.8
5.7
5.4
% Change in Pre-tax Cash
Flow as a Result of
Compliance
5.7
5.1
4.8
4.8
VI-] 2
-------
TABLL5 75
Model
CAPITAL REQUIREMENTS TO
MEET EFFLUENT GUIDELINES
(1975 $)
BPT Compliance
Capital Investment
$/annual ton
BAT (above BPT)
Compliance-
Capital Investment
$/annual ton
N. Appalachia
Deep
Surface
S. Appalachia
Deep
Surface
Central
Deep
Surface
Intermountain
Deep
Surface
G. Plains
Deep
Surface
West
Deep
Surface
0.39-0.45
0.04-0.08
0.03-0.1
0.014-0.055
0.011
0.02-0.06
0.24-0.69
0.18-0.45
0.003-0.03
0.004-0.03
0.003-0.03
0.002-0.03
0.002
0.0005-0.027
0.004-0.03
0.003-0.03
0.0006-0.02
Preparation Plants
0.41
VI-1 3
-------
TABLE 76
EFFECT OF COMPLIANCE WITH EFFLUENT GUIDELINES
COMPARED TO AFTER-TAX CASH FLOWS FOR DEEP MINES IN NORTHERN APPALACHIA
(1975
$/Ton)
Mine Size (106 TPY)
0.
1
0.5
1.
0
2.0
3.
0
Northern Appalachia
Average 1975 Price
22.
48
22.48
22.
48
22.48
22.
48
Cost of Production
14.
48
15.27
14.
48
13.92
13.
58
Interest Expense1
0.
53
1.11
0.
98
0.84
0.
78
Gross Profit
7.
47
6.10
7.
02
7.72
8.
12
Depletion'1
2.
125
2.25
2.
,25
2.25
2.
25
Taxable Profit
5.
.22
3.85
4.
,77
5.47
5.
,87
Net Profit after Taxes3
2.
.61
1.93
2.
,39
2.74
2.
,94
After-tax Cash Flow*4
6.
,95
6.48
6.
,64
6.74
6.
85
BPT Capital Requirements
0.
.45
0.42
0.
,42
0.42
0.
,42
Average Deferred Capital
0.
,86
1.14
1.
,02
0.89
0.
,85
Average 1985 Price
19.
,91
19.91
19.
,91
19.91
19.
.91
Cost of Production
14.
,48
15.27
14,
,48
13.92
13.
,58
Interest Expense1
0.
,53
1.11
0,
.98
0.84
0.
.78
Gross Profit
4,
.90
3.53
4,
.45
5.15
5,
.55
Depletion2
1.
.99
1.77
1,
.99
1.99
1,
.99
Taxable Profit
2,
.91
1.76
2,
.46
3.16
3
.56
Net Profit after Taxes3
1
.46
0.88
1
.23
1.58
J
.78
After-tax Cash Fl.ow'1
5
.54
4.95
5
.22
5.32
5
.43
BAT (above BPT) Capital
Requirements
0
.69
0.26
0
. 26
0.26
0
. 26
Average Deferred Capital
0
.86
1.14
1
.02
0.89
0
.85
'Debt-to-equity ratio, 1:2.5; 8% interest rate.
^10% of sales up to a maximum of 50% of gross profit.
•'Federal Income Tax, 50% of taxable profit.
''After Tax Cash Flow = Net Profit after Taxes + Depreciation + Depletion.
VI-14
-------
TABLE 77
EFFECT OF COMPLIANCE WITH EFFLUENT GUIDELINES COMPARED
TO AFTER-TAX CASH
FLOWS FOR
STRIP
MINES
IN
N.
APPALACHIA
(1975 $/Ton)
Mine Size (106 TPY)
0
.1
0
.5
1.0
3.
0
Northern Appalachia
Average Price 1975
19
.93
19
.93
19.93
19.
.93
Cost of Production
10
.06
10
.40
9.41
6,
.44
Interest Expenses1
0
.31
0
.94
0.77
0.
.57
Cross Profit
9
.56
8
.59
9.75
12,
.92
Depletion7
1
.99
J
.99
1.99
1 ,
.99
Taxable Profit
7
.57
6
.60
7.76
10.
.9 3
Net Profit after Taxes-*
3
.79
3
.30
3.88
5.
.47
After-tax Cash Flow4
6
.88
7
.22
7.43
8,
.53
BPT Capital Requirements
Average Deferred Capital
0
.14
0
.46
0.36
0,
.18
Average Price 1985
15
.64
15
.64
15.64
15.
.64
Cost of Production
10
.06
10
.40
9.41
6,
.44
Interest Expenses1
0
.31
0
.94
0.77
0,
.57
Gross Profit
5
.27
4
.30
5.46
8,
.63
Depletion2
1
.56
1
.56
1.56
1
.56
Taxable Profit
3
.71
2
.74
3.90
7
.07
Net Profit after Taxes-3
1
.86
1
.37
1.95
3
.54
After-tax Cash Flow4
4
.52
4
.86
5.07
6
.17
BAT (above BPT) Capital Requirements
0
.49
0
.29
0.29
0
.29
Average Deferred Capital
0
.14
0
.46
0.36
0
.18
'Debt-to-equity ratio,1:2.5; 8% interest rate.
210% of sales up to a maximum of 50% of gross profit.
^Federal Income Tax, 50% of taxable profit.
''After-Tax Cash Flow - Net Profit after Taxes + Depreciation + Depletion.
VI-15
-------
TABLE 78
CAPITAL REQUIREMENTS FOR COMPLIANCE WITH
EFFLUENT GUIDELINES COMPARED TO AFTER-TAX
CASH FLOWS FOR PREPARATION PLANTS
(1975 $/Ton)
Plant Size (10 TPY raw coal)
Average Price
Cost of Production
Depreciation
Interest Expense1
Taxable Profit
Net Profit after Taxes2
After-tax Cash FlowJ
BPT Compliance Requirement
0.50
2.00
0.76
0.38
0.24
0.62
0.31
0.69
0.41
1.00
2.00
0.63
0.34
0.21
0.82
0.41
0.75
0.41
2.00
2.00
0.55
0.21
0.13
1.11
0.56
0.77
0.41
3.00
2.00
0.54
0.17
0.11
1.18
0.59
0.76
0.41
'Debt-to-equity ratio,}:2.5; 8% interest rate.
^Federal Income Tax, 50% of taxable profit.
3After-Tax Cash Flow = Net Profit after Taxes + Depreciation.
VI -16
-------
are much more volatile than contract prices. If demand exceeds supply, spot
prices will be depressed. These fluctuations are related to demand-supply
imbalances and are not affected by compliance costs. It is possible that
some mines in these segments may have difficulty in raising capital as their
cash flow position may be different from that of the model mines.
c. Aggregate Compliance Requirements for the Coal Mining Industry
We have summarized the capital requirements annualized costs and ope-
rating and maintenance costs for compliance with BAT and BPT standards for
existing mines in Tables 79 and 80. These costs make no allowance for
treatment in place and also assume that all mines in the region have a water
problem.
Most of the BPT investment in the mines segment, greater than 96% of
the $79.6 million will have to be made in N. Appalachia. Preparation plants
contribute $52.5 million to make up a total BPT investment of $132.1 million.
An additional $66.5 million to meet BAT standards will add up to a total for
existing mines and preparation plants of $198.6 million. The annualized
costs amount to $115.6 million and operating and maintenance costs are
$87.9 million.
Table 81 'summarizes the capacity needed from new mines, by 1985, for
the $8 and $13 a barrel imported oil scenarios. It was obtained based on
the difference between the quantity demanded from each of these regions
in 1985 and the supply in 1985 from mlneB existing in 1974 (see Chapter I,
Table 37).
It was assumed that the new mines would be deep mines in the Appalachian,
Central, and Intermountain regions and surface mines in the Great Plains
region. The capital requirements for water pollution control for a new
mine is represented by the NSPS cost (equal total BATEA) for the large mine
model in the region. Table 82 presents the aggregate capital requirements
to meet new source performance standards. The aggregate requirements are
$106 million for the $8 a barrel scenario and $126 million for the $13 a
barrel scenario.
The estimates for new cleaning capacity were 48 million tons of clean
coal for the $8 a barrel imported oil and 86 million tons of clean coal for
$13 a barrel imported oil scenarios. These are based on the assumption that
the relative proportions of coal cleaned in a region is likely to remain the
same up to 1985 and that current capacity is fully utilized. Also assuming
that 78% are stage II plants and NSPS capital requirements of $0.41 an annual,
ton, the aggregate capital requirements for new preparation plants up to
1985 are of the order of $20-35 million.
Table 83 presents a summary of capital requirements for the coal indus-
try up to 1985 associated with compliance with effluent guidelines. It is
estimated that the Industry will have to spend $325-360 million to meet
effluent guidelines standards between now and 1985.
VI-1.7
-------
TABLE 79
Model
AGGREGATE BPT COMPLIANCE REQUIREMENTS
TO MEET EFFLUENT GUIDELINES FOR EXISTING MINES
Number of
Establishments
In Segments
(1973)
(1975 $)
Segment
Production
(1973)
(10° tons)
BPT
Capital
Requirements
C$ L0C )
Annual
Cos t8
<£ 106)
Operating
and
Maintenance
6 to(l)
MJ_ne Segment:
N. Appalachia
Deep: Large
Small
Surface: Large
Small
249
737
59
1792
147.9
33.6
30.0
61.9
56.0
13.6
2.2
4.5
34.7
8.5
3.5
16.6
25.3
6.7
3.2
16.0
S. Appalachia
Deep: Large
Small
Surface:
Large
Small
65
586
54
881
33.7
18.1
19.3
30.3
0.9
1.7
0.3
0.5
2.3
6.7
0.2
0.3
2.3
6.7
Central
Deep:
Large
Small
Surface: Large
Small
41
14
73
98
55.2
1.0
95.5
3.5
0.7
0.1
0.2
0.0
6.1
I .0
0.2
0.0
6.1
1.0
Intermountaln
Deep: All
Surface: All
38
15
9.6
14.5
0.1
0.1
0.3
0.0
0.3
G. Plains
Surface: All
32
32.1
0.4
0.4
Preparation
Plants
407
295.3
52.5
9.0
1.8
TOTAL
132.1
90.2
72.
lClean coal
VI-1 8
-------
TABLE 80
AGGREGATE BAT COMPLIANCE CAPITAL
REQUIREMENTS (ABOVE BPT) FOR EXISTING ESTABLISHMENTS
(1975 $)
Number of
Establishments
In Segment
(1973)
Segment
Production
(1973)
106 tons
BAT
Capital
Requirements
(above BPT)
$ 10G
BAT
BAT Operating &
Annualized Maintenance
Costs Couts
(above BPT) (above HIJT)
$ lO1" $ l-0fl
M11ie Segment:
N. Appalachia
Deep: Large
Small
Surface: Large
Small
249
737
59
1792
147.9
33.6
30.0
61.9
25.9
15.6
4.3
18.8
6.0
5.2
1.2
6.7
2.3
2.7
0.7
3.8
S. Appalachia
Deep: Large
Small
Surface:
Large
Small
65
586
54
881
33.7
18.1
19.3
30.3
0.1
0.4
0.1
0.9
1.8
1.7
0.3
0.8
1.8
1.7
0.2
0.6
Central
Deep: Large
Small
Surface: Large
Small
41
14
73
98
55.2
1.0
95.5
3.5
0.1
0.0
0.1
0.1
0.8
0.0
0.6
0.1
0.8
0.0
0.6
0.1
Intermountain
Deep: All
Surface: All
38
15
9.6
14.5
0.0
0.0
0.1
0.0
0.0
0.0
G. Plains
Surface: All
32
32.1
0.1
0.1
0.1
PrepnratIon
P Lnnta
407
295.3
TOTAL
66.5
25.4
15.4
'Clean coal
Vl-19
-------
TABLE 81
CAPACITY
NEEDED
FROM NEW MINES
BY 1985
(million tons)
Supply from
Mines
Total Required
Supply
Capacity
from New
Needed
Mines
Region
Existing in
1974
$131
$8^
$131
$82
N. Appalachia
164.4
342.8
314.1
178.4
149.7
S. Appalachia
60.6
156.0
146.1
95.4
85.5
Central
100.7
189.9
163.6
89.2
62.9
Great Plains
27.7
305.1
232.6
277.4
204.9
Intermountain
40.8
41.6
36.9
0.8
West
4.8
4.1
1.1
—
1$13 a barrel imported oil scenario
^$8 a barrel imported oil scenario
V1-20
-------
TABLE 82
CAPITAL REQUIREMENTS TO MEET NSPS UP TO 1985
Aggregate
Region
Capacity
Capital Requirements
for NSPS
Capital Requirements
(million
tons)
($ iob)
3131
$81
$ per annual ton
$13!
$8 2
N. Appalachia
178.4
149.7
0.68
121.3
101.8
S. Appalachia
95.4
85.5
0.033
3.2
2.8
Central
89.2
62.9
0.017
1.5
1.1
Great Plains
277 .4
204.9
0.0003
0.1
0.]
Intermountain
0.8
0.013
126.1 105.8
*$13 a barrel, imported oil scenario.
2$8 a barrel, imported oil scenario.
VI-21
-------
TABLE 83
SUMMARY OF ESTIMATED AGGREGATE CAPITAL
REQUIREMENTS OF THE INDUSTRY
UP TO 1985 TO MEET EFFLUENT GUIDELINES STANDARDS
($ io6)
Existing Mines, BPT $132
Existing Mines, BAT Incremental $67
New Mines, NSPS $106-1261
New Preparation Plants, NSPS $20-351
Total Water Pollution Control
Capital Requirement $326-3601
'Range due to demand scenarios - $8 a barrel imported oil to $13 a
barrel imported oil.
VI -22
-------
In comparison, the capital needed for achieving the expansion by 1985
(coal production and preparation alone) is estimated at $10-13 billion.
These are based on $28 an annual ton for deep mines in the East and $8 an
annual ton for surface mines in Che Great Plains region- The capital needed
for water pollution control is 3-4% of the industry's capital requirements
for expansion of capacity.
3. Production Effects
a. Production Curtailments
The waste loads in coal mining are unrelated or only indirectly related
to production quantities. Hence, curtailing production does not reduce the
pollutant load or the cost of water treatment. Production curtailment as a
result of effluent guidelines seems unlikely. The cost of compliance for
preparation plants is 7 cents a ton, that is somewhat output-dependent. It
is believed that this will not have a significant effect on the demand for
coal cleaning.
b. Closure Analysis
The mine operator is faced with increased costs as a result of compli-
ance with effluent guidelines. The operator's decision as to whether he con-
tinues to operate or closes down depends on the price he getB for coal. If
the price Is sufficient to cover his variable costs, annualized cost of
compliance, i.e., all costs exclusive of profits and sunk coata, he continues
operations; if not, he closes down.
In the short run, the prices obtainable for coal can be judged from
the current trends In the price of coal. Average 1975 prices have been used.
The long-run price of coal is obtained from the PIES energy model. In thiB
model, an aggregate demand for coal is inferred from demand for energy and
translated to a regional demand for coal. The excess of this regional
demand in 1985 over the production from mines in existence in 1974 will have
to come from new mines. This quantity will be supplied by the least costly
it'w mine, and so on, until the demanded quuntity is satisfied. The set of
mines providing the last quantities of coal to fulfill demand are the ones
determining the price of coal. The long-run price of cou] will be such thut
full costs inclusive of compliunce and reasonable profit (8% DCF rate or
return in the PTES) will be; covered.
Table 84 presents a comparison of the variable costs inclusive of a
charge of future outlays for deferred capital and the compliance costs for
the highest cost existing mine and preparation plant in the region and the
price of coal and coal cleaning. For all regions these margins are com-
fortably covered.
Vl-23
-------
Mine Segment:
TABLE 84
COMPARISON OF AVERAGE VARIABLE COST INCLUSIVE OF DEFERRED
CAPITAL CHARGE AND COMPLIANCE COSTS FOR EXISTING MARGINAL ESTABLISHMENT
(1975 $/Ton)
Model
BPT
Average Variable Cost
with Deferred Capital 1975
and Compliance Cost Average
for Marginal Establishment Price
BAT
Average Variable Cost
with Deferred Capital
and Compliance Cost
for Marginal Establishment
1985
Average
Price
$131 $82
N. Appalachia
Deep
Surface
14.55
9.26
22.48
19.93
14.17
9.24
19.59
15.45
16.97
13.39
S. Appalachia
Deep
Surface
14.30
9.20
26.42
22.42
13.83
9.06
28.60
22.08
23.03
17.78
Central
Deep
Surface
9.61
5.81
11.12
8.23
9.19
5.72
13.15
10.12
12.31
9.47
Intermountain
Deep
Surface
9.96
4.70
11.87
6.35
9.54
4.65
10.00
5.10
9.80
5.10
G. Plains
Surface
3.79
4.85
3.75
5.78
5.61
Preparation
Plants
0.68
2.00
l?lES - S13 a barrel imported oil. 2PIES - $8 a barrel imported oil.
-------
Hence, no closures are anticipated from this analysis of model mines
and preparation plants.
A. Industry Growth
The expected pattern of coal industry growth over the next 15
years as (brojected by FEA in the reference scenario that assumes the price
of imported petroleum to be $13 per barrel) is outlined in Table 85. This
table shows total coal consumption and the prospective changing composition
of that consumption over the period. Over the 15-year span the consump-
tion of coal by electric utilities is expected to increase at an average annua]
rate of 5.7% and coal use by Industry at a A.2% rate; other uses will grow
more 9lowly.
The impact upon quantities and prices of raw steam coal in 1980 and in
1985 of compliance with NSPS of the marginal new mine in each producing
region is indicated in Tables 86 and 87. The fundamental assumption here,
of course, is that the underlying long-run price of coal in each region
equals the minimum acceptable price of the marginal (highest cost) new mine.
The minimum acceptable price is increased by the cost of NSPS compliance
expressed as a percentage of the ex-compliance price. The compliance cost
will be fully passed through and quantities will be pared by the long-run
coefficient of price elasticity, here taken to be -0.5.1 Price increases
range from 0.2 to 1.6%,while quantities will be reduced by one-half these per-
centages. This translates to a decrease in the total quantity demanded of 0.3%.
5. Metallurgical Coal - Mining and Preparation
In Chapter II, estimates were presented for the cost of mining metallur-
gical coal for a mine in Appalachia producing 1 million tons per year.
Effluent guidelines compliance cost for the mining segment is independent of
the rank of the coal.^ The highest compliance costs are for treatment of acid
mine drainage in N. Appalachia—(BPT Capital -0.41 $/Annual Ton, Operating Coat
0.28 $/Ton; BAT (total) Capital 1.10 $/Annual Ton, Operating Cost 0.51 $/Ton).
this coal is prepared in Stage III preparation plants (those with froth
flotation as part of the coal cleaning flowsheet), there is no cost of com-
pliance for preparation. The price of metallurgical coal was estimated
conservatively at $30 a ton.
'"National Energy Outlook.," Federal Energy Administration, Washington, D.C.,
February 1976.
^"Development Document for Interim Final Effluent Limitations Guideline and
New Source Performance Standards for the Coal Mining Point Source Category,"
United States Environmental Protection Agency, Washington, D.C., October
1975.
VI-25
-------
TABTJ'. 85
COAL CONSUMPTION*
(millions of tons)
1975 1980 1985
Electric Utilities 406 528 716
Household/Commercial 7 7 5
Industrial 147 184 224
Synthetics - - 16
Exports 64 80 80
Total 624 799 1,041
Period Annual % Growth Rate
1975-1980 5.1
1980-1985 5.4
*Reference scenario; imported oil priced at $13/barrel
Source: Federal Energy Administration, National Energy Outlook, 1976.
VI-26
-------
TABLE 86
EFFECT. OF NSPS ON STEAM COAL
PRICES AND DEMAND QUANTITIES, 1980
Case: Imported Oil Priced @ $13/bbl
Prices: ]975 $ per Ton Raw Coal f.o.b-. Mine
Quantities: Millions of Tons
l're-Compllance
Region
Price
Quantity
Northern Appalachia
16.
.32
221.9
Southern Appalachia
22.
.29
112. 8
Central
11.
.06
121.3
Great Plains
5
GO
197.6
Intermountain
8.
.62
15.6
With NSPS Compliance
% NSPS* Pri'ce .. 'Quantity
1.6
16.58
220.1
0.6
22.42
112.5
0.5
11.12
ri2i ;o
0.2
5.49
197.4
0.2
8.64
15.6
Total Production
2
669.22
666.62
JNSPS aa percent of pre-compJiance price.
^Excludes 1.1 million tona expected production in-West region;
V1-27
-------
TABLE 87
EFFECT OF NSPS ON STEAM COAL
PRICES AND DEMAND QUANTITIES, 1985
Case: Imported Oil Priced @ $13/bbl
Prices: 1975 $ per Ton Raw Coal f.o.b. Mine
Quantities: Millions of Tons
Pre-
Compliance
With
NSPS Compliance
Region
Price
Quantity
% NSPS
1 Price
Quantity
Northern Appalachia
17.97
248.8
1.4
18.22
247.1
Southern Appalachia
25.09
124.2
0.5
25.22
123.9
Central
11.24
185.7
0.5
11.30
185.2
Great Plains
5.90
305.1
0.2
5.91
304.8
Intermountain
7.54
33.3
0.2
7.56
33.3
Total Production2
897.I2
894.32
^SFS as percent of pre-compliance price.
2Excludes 4.1 million tons expected production in West region.
VI-28
-------
As the demand for metallurgical coal is inelastic with no substitutes
at least until 1985 and demand determined by steel demand, we expect that in
the long run compliance costs will be passed on. In the short run, however,
prices will not increase to cover compliance and, consequently, profitability
will decrease—for the model mine by less than 4 percent.
Considering that coal of metallurgical quality can alternatively be
consumed as steam coal, it is possible that a spurt in steam coal prices
(or a temporary drop in the demand for steel, and thus for metallurgical
coal) could in the short run divert some metallurgical coal into the steam
coal market. Any such short-term blurring of the distinction between the
two markets would not, however, operate to aggravate any adverse impact that
compliance would have on the coal industry as a whole.
6. Employment Effects
Since the analysis does not indicate closure or production curtailments,
no adverse employment effects have been identified.
7. Community Impacts
Since the analysis does not indicate closures, production curtailments,
or employment reductions, no adverse community impacts are expected.
8. Balance-of-Payment Effects
Considering that about 85% of U.S. coal exports are metallurgical coal,
which is more valuable than steam coal, that the remainder of coal exports
are almost entirely shipped to Canada, that demand for coal exports is on the
whole inelastic, and that there are no major imports of coal, we do not
anticipate any adverse impacts on the balance of payments due to effluent
guidelines.
9. Sensitivity Analysis
As mentioned in Chapter I, electric utilities buy coal principally for
the heat value with credits or penalties for departures from the normal in
ash content, ash fusion temperature, sulfur, and moisture contents. The
penalties and credits have evolved over a period of time. For example, the
importance of sulfur content has been highlighted by the requirements of
the Clean Air Act, since the early 1970's. Hence, the price that a utility
will offer for a coal will depend on the above-mentioned coal quality attri-
butes and the cost of transportation from the mine to the utility, besides
other supply/demand considerations.
A mine that produces a lower quality coal and receives a lower price
for its coal (as there are others that produce and are willing to supply
VI-29
-------
higher quality coal in the region) can upgrade its coal quality by prepara-
tion, provided that the added cost of preparation is justified by the increase
in value. It is reasonable to assume that a new mine producing low-quality
coal would not be developed unless coal production costs were low enough to
produce an adequate return on capital. For existing mines, the quality of
coal would have been an important consideration at the time the investment
decision was made. To the extent that the premiums or penalties associated
with a coal attribute have changed since the time the investment decision
was made, such mines are likely to be at a disadvantage in trying to achieve
compliance with effluent guidelines in that their competitive posture vis-
a-vis other mines in the region is affected, especially if these costs
are high.
In the case of sulfur content, its importance has increased since the
early 1.9 70's and for such mines the effect of sulfur content on value is likely
to have been considered. For older mines, it is to be noted that costs
and prices of all coal have ri3en significantly in the 1969-75 period. It
is possible, however, that there are a few mines producing a lower value coal
and with a large water pollution problem that are likely to be affected adversely
and might close, because their already unfavorable competitive position fur-
ther deteriorates because of high effluent guidelines compliance costs.
It was not possible from the available data to separate the effects
of coal quality and transportation or to isolate the effect of any individ-
ual coal quality attribute on the value of coal, in a given region. The
data on prices, on a delivered basis, paid by utilities from the Federal
Power Commission statistics do not allow for the separation and effect of
coal quality and transportation aspects on the price of coal. The other
main source of data is the Bureau of Mines' value f.o.b. mines.
Consequently, this section considers the effect of variation in value
f.o.b.
The Bureau of Mines' value f.o.b. mine data on a state-by-state basis
indicate that value varies by type of mining, deep or surface, and by
geography. The variations in value reflect the effects of coal
quality and remoteness from market. The following important coal-producing
states have value f.o.b. mines that are the lowest in the region in
which they belong—Ohio in Northern Appalachia; Tennessee for deep mines
and Alabama for strip mines in S. Appalachia; Western Kentucky in the Cen-
tral region; Utah for deep mines in the Intermountain region and Montana
for strip mines in the Great Plains region, as shown in Table 88.
Table 90 presents a comparison of variable costs inclusive of a charge
of future outlays for deferred capital and compliance costs for the highest
cost existing mine in the region and the 1975 price of coal for the above-
mentioned states in the region. The average 1975 prices were derived from
Bureau of Mines' data for 1974 by states using a $2.00 per ton preparation
charge for steam coal and $4.00 per ton charge for metallurgical coal to
arrive at run of mine coal value. These values were adjusted to average
1975 prices by an escalation factor relating the average value f.o.b. mine
for all coal in 1974 and 1975. For all regions, the price is greater than
the variable; costs inclusive of a deferred capital charge and compliance
cost; consequently, no closures are indicated.
VI-30
-------
TABLE 88
STATES WITH LOWEST VALUE
F.O.B. MINE BY REGIONS (1974)
('$/ton)
Region/State Type of Mining
Deep Surface
N. Appalachia: Average 21.85 17.30
Ohio 13.70 11.68
S. Appalachia: Average 24.82 19.16
Tennessee 13.70
Alabama 17.09
Central: Average 10.81 8.32
W. Kentucky 10.25 7.86
Intermountain: Average 12.83 5.33
Utah 12.24
Colorado 5.33
G. Plains: Average 4.07
Utah 3.90
VI-31
-------
TABLE 89
COMPARISON OF AVERAGE VARIABLE COST
INCLUSIVE OF DEFERRED CAPITAL CHARGE AND
COMPLIANCE COSTS FOR EXISTING MARGINAL MINE AND PRICE OF COAL
(1975 $/Ton)
Model
Average Variable Cost
with Deferred Capital
and Compliance Cost
for Marginal Establishment
1975 Price,
Determined by State
with Lowest Value
f.o.b. Mine in Region
N. Appalachia
Deep
Surface
14.55
9.26
14.85
13.55
S. Appalachia
Deep
Surface
14.30
9.20
15.36
18.87
Central
Deep
Surface
9.61
5.81
11.46
8.35
Intermountain
Deep
Surface
9.91
4.70
12.42
6.35
Great Plains
Surface
3.79
4.64
VT-32
-------
VII. LIMITS TO THE ANALYSIS
This analysis is based on a number of assumptions which describe the
coal industry and its wastewater treatment practices. Financial profiles
were developed, supply and demand projections were made, and effluent
treatment costs provided by the EPA were used. Wherever possible, these
assumptions were made in a manner that would err towards overstating the
economic imparts of the effluent guidelines. Several specific and import-
ant constraint?! are described below.
A. MODELS
The main limits to this analysis arise out of the modelling approach
which was necessitated because of the large number of establishments in
the industry. Coal production costs vary widely and are dictated largely
by the geology of the seam and the age of the mine in view of the rapid
escalation in mine equipment costs. Strip mining costs are influenced by
the stripping ratio of overburden to coal, seam thickness, and topography.
Underground mining costs depend on coal seam thickness, depth, entry access,
conditions of the roof above and the floor below the seam, water table level,
and many other factors.
Trae ideal method of assessing industry impacts arising from effluent
guidelines is en a nine by mine bssia. This method ^jould alLou Far the
specific identification of effluent sources and concentration of polljtant3
so that compliance coats could be estimated for each mine. The cost
structure of the raine prior to compliance could be determined. The above
information, along with selling practicee (contract or spot market, and type
of contract), would allow a detailed evaluation of the impact of effluent
guidelines.
Since evaluating the impact of the regulations on each establishment
was not feasible, a model approach was taken. Model mines and preparation
plants were choBen to represent the major differences in the characteris-
tics of establishments. Production costs were estimated for these models
and were designed to represent all the establishments in a segment (e.g.,
small underground mines in Northern Appalachia). The costs of compliance
with effluent guidelines for each of these models were provided by the EPA.
Very few establishments will have the exact characteristics of the models,
but it is felt that for the purposes of this analysis they are sufficiently
alike to predict the economic impacts of the effluent guidelines. However,
If a mining operation had one or more of the following characteristics, it
couid be more Bonsitive to effluent control costs than the model:
1. High production contn due to topography, seam thickness, over-
burden depth, and the ifke;
2. Large quantities of water interfering with the mining process;
VII-l
-------
3. Coal of low value due to distance from the market, high sulfur
content, high ash content, low Btu content, and the like; and
4. High compliance costs due to large volumes of water to be treated
or very bad raw water quality.
B. COMPLIANCE COSTS
The costs of compliance with the effluent guidelines were provided
by EPA in terras of BPT and incremental BAT compliance costs. It was stated
that the NSPS compliance costs were BPT plus incremental BAT costs. Be-
cause information on existing discharge practices was unavailable, the
analysis assumed that no treatment was in place prior to installation of
BPT. It was also assumed that all mines did have effluent discharges.
These assumptions overstate the total costs of compliance, and for individ-
ual mines with treatment in-place overstate the impact.
C. MARKET PROJECTIONS
Coal demand and prices in the future on a regional basis were obtained
and modified from the Project Independence Evaluation System (PIES) study.
This analysis is subject to all the limitations of the PIES study.
D. OTHER REGULATIONS
This analysis has evaluated the impact of compliance with effluent
guidelines alone on the coal mining industry. A number of other regulations
such as strict federal strip mining laws, safety requirements and strin-
gent clean air requirements will also affect the costs of producing and
cleaning coal; therefore, the impact is likely to be more severe if all the
other factors are also considered. Evaluation of these costs is beyond
the scope of this analysis.
E. REMAINING QUESTIONS
As was pointed out in the section on capital requirements and avail-
ability in Chapter VI, the small mine segment in N. Appalachia has signif-
icant capital and operating costs requirements associated with compliance
Marginal mines could exist in this segment, but as a result of site
specific factors may experience significantly higher production and or
compliance costs than the model. It is also to be noted that these mines
are apt to sell their output on the spot market, which is subject to rapid
and major price fluctuations depending on coal supply/demand imbalances.
When the market is depressed, the additional cost of compliance may trigger
a closure decision.
VII-2
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POSTAGE AND FEES PAID
U S. ENVIRONMENTAL PROTECTION AGENCY (A-107) ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON. D.C. 20460 EPA-335
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