INITIAL ECONOMIC IMPACT ANALYSIS
OF WATER POLLUTION CONTROL COSTS
UPON THE COAL MINING INDUSTRY
report to
ENVIRONMENTAL PROTECTION AGENCY
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PART I
TABLE OF CONTENTS
Page No,
EXECUTIVE SUMMARY
A. INTRODUCTION 1
B. FINDINGS 2
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PART II
TABLE OF CONTENTS
Page No,
Preface
A. FORMAT i
I. Industry Segments i
II. Price Effects ±
III. Financial Profiles i
IV. Pollution Control Requirements ii
V. Impact Analysis ii
B. APPROACH iv
I. INDUSTRY SEGMENTS 1-1
A. SEGMENTS 1-1
B. PERSPECTIVE ON WATER POLLUTION 1-6
II. PRICE EFFECTS II-1
III. FINANCIAL PROFILES III-l
IV. POLLUTION CONTROL REQUIREMENTS IV-1
A, GUIDELINES IV-1
B. POLLUTION CONTROL TECHNOLOGY iv-2
C. LIME NEUTRALIZATION COSTS IV-5
D. RESERVATIONS IV-14
V. IMPACT ANALYSIS V-l
A. ADL SAMPLE V-l
B. FINANCIAL EFFECTS V-8
C. PRODUCTION EFFECTS V-13
D. EMPLOYMENT AND COMMUNITY EFFECTS v-14
E. BALANCE OF PAYMENTS EFFECTS V-19
VI. LIMITS OF THE ANALYSIS VI-1
A. GENERAL VI-1
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PART II
List of Tables
Page No,
I - 1 Production of coal by the large producers for 1954 and 1967. 1-5
1-2 Percentage distribution of the number of sources and 1-8
proportion of acid mine drainage by type of mine, active
and inactive.
1-3 Breakdown of Pennsylvania mines by type of drainage 1-10
III - 1 Measures of financial performance of coal industry segments III-4
based on 1967 Bureau of Census data
III - 2 Selected financial data for the coal mining industry III-8
based on U. S. Income Tax data
IV - 1 Mine drainage classification IV-1
IV - 2 Estimated cost of lime neutralization of acid mine drainage IV-10
IV - 3 Cost data supplied by EPA for coal mining IV-11
V - 1 Geographical, size and drainage profiles of surveyed coal mines V-2
V - 2 Estimated water treatment costs for surveyed mines. V-4
V - 3 Production, Value of shipments and water treatment costs for V-7
the surveyed mines
V-4 Capital spending by mine segments V-10
V - 5 Acid mine drainage sensitivity of Bituminous coal counties of V-15,
Appalachia and North Central United States V-16, V-17,V-18
V - 6 Areas and communities with maximum sensitivity to water V-20
pollution control costs.
V-7 Number, Production, and Productivity of Coal Mines in V-21
Bituminous Coal States (1970)
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PART II
List of Figures
Page No.
I - 1 Changes in the number of coal mines in three size 1-3
categories since 1960
1-2 Changes in coal production for three sizes of mines since 1960. 1-4
1-3 Areas affected by the acid mine drainage problem in Appalachia 1-7
IV _ i Flowsheet for lime neutralization IV-8
IV - 2 Estimated cost of lime neutralization of acid mine drainage IV-9
IV - 3 Capital costs of lime neutralization of acid mine drainage IV-12
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INITIAL ECONOMIC IMPACT ANALYSIS OF WATER
POLLUTION CONTROL COSTS UPON THE COAL
MINING INDUSTRY
PART I - SUMMARY
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A. INTRODUCTION
The Environmental Protection Agency (EPA) is interested in assessing
the economic impact on the coal industry of proposed legislation affecting
quality of effluent water from coal mining operations. Because of budget and
time constraints and the non-availability of necessary data, the entire coal
mining industry could not be examined; instead, selected operations in several
industry segments were studied.
Four regions account for virtually all the bituminous coal production
of the U.S. - Appalachia, Central U.S., Northern Great Plains and the Mountain
and Pacific states. We believe the problems associated with water pollution and
acid mine drainage are most severe in the Appalachian and Central regions and
therefore have devoted our analysis to these regions.
The coal mining effluent limitation guidelines furnished by the EPA
dated July 29, 1972 were assumed as a standard to be achieved for all effluent
waters. The EPA was to provide all pollution control information including
effluent flow, volumes, pollutant concentration and pollution control costs in
order for us to provide a meaningful impact analysis. However, it proved ex-
tremely difficult for EPA to obtain such data and we were asked to use data
available from other sources in making our analysis. The only data generally
available are from the Bureau of Census and deal only with regional and national
totals for the industry rather than individual mines, thus making it less useful
for a microeconomic impact analysis. We therefore confined our analysis to a
sampling of individual mines that could be made within the time constraints
imposed.
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For the purposes of this study, we adopted, with slight modification,
water treatment capital costs furnished by the EPA. We found these to be con-
sistent with the estimates given to us by industry personnel and available in
standard sources such as the 1969 Appalachian Regional Commission report on
Acid Mine Drainage. Operating costs were similarly obtained from standard
sources coupled with our best judgment of probable costs in those mines where
standard data were not applicable.
In addition to estimating the impact on the coal mine sample that was
studied, we studied qualitatively, the remaining segments of the Appalachian
and North-Central coal regions to determine the probable sensitivity of these
mining areas to the water pollution regulations and the possible impacts that
could be incurred.
B. FINDINGS
We find that there are major differences between the small and large
coal mine operations. The small mines are low profit marginal operations and
in the past few years the number of small mines has been decreasing. This has
been caused by a number of different pressures, but mainly because of their
inability to control price ceilings (which are established by the large pro-
ducers in each region) and therefore to pass on increased costs. Our analysis
indicates that most of the small mines have little or no profits and are quite
susceptible to closures in response to potential cost increases.
The large mine operations are in a relatively better position because
of their ability to increase prices to reflect higher costs even though some-
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times Governmental action delays such increases, and interfuel competition
puts additional constraints on the degree of total pass-on on increased
operating costs. However, with the increasing amount of legislation on the
coal miners from the environmental as well as the coal mine health and safety
programs, costs may increase beyond what can be passed on and the decision
makers of some of the large operations may find it necessary to shut down
because of a number of complex factors.
We find that it is possible to isolate the regions that will be
severely affected be new water pollution regulations on the basis that these
are the areas already affected by acid mine drainage problems and are areas
where coal mines are a major employer. Thus the mines in Northern Appalachia,
particularly Pennsylvania and West Virginia, producing less than 50,000 tons
of coal per year represent a segment of the industry that would be particularly
sensitive to the water effluent regulation and would therefore have the high-
est probability of discontinuing operations. If we assume the worst set of
pollution control costs and this entire segment of the industry shuts down,
this would mean the loss of less than 15% of the coal production from this
region. We believe this to be a minimal impact from the viewpoint of industry-
wide production and growth. However, the community impact would be quite
severe and the following counties could be severely affected: West Virginia -
Boone, Barbour, Logan, Marion, Marshall, McDowell, Monongalia, and Wyoming
Counties, and in Pennsylvania - Greene County. In addition, Gallatin County,
Illinois; Pike County, Indiana; Floyd, Knott, Letcher, and Pike Counties in
Kentucky; and Buchanan, Dickenson and Wise Counties in Virginia would ex-
perience adverse employment and community impacts. Coal mines in these
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counties employ about 53,000 persons, out of which about 6,000 persons are
employed in the small mine segment.
We do not expect possible increases in coal production costs due to
enforcement of mine effluent quality standards to exert any noticeable effect
on the United States balance-of-payment position.
In general, we find that acid mine drainage control costs at active
mines always reflect seepages from abandoned mines. Therefore, mine closures,
per se, do not solve the problem of acid mine drainage. Thus, employment
and community impacts will be severe in certain regions, especially Appalachia.
With the impact of several differing types of legislation and their associated
regulations, the net result on the coal industry is an increase in operating
costs. Shutdowns will occur, especially amongst the small mine operations.
However, when an industry faces the prospects of increasing operating costs
from several sources, mine shutdowns result from the cumulative effect of
these increased costs. One cannot predict individual mine closings on the
basis of examination of one of these factors nor is it safe to assume that
the operators' margins (the difference between price and costs) is available
to absorb the impact from any single course of incremental costs.
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INITIAL ECONOMIC IMPACT ANALYSIS OF WATER POLLUTION
CONTROL COSTS UPON SELECTED SEGMENTS OF
THE COAL MINING INDUSTRY
PART II - INITIAL ECONOMIC IMPACT ANALYSIS
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PREFACE
A. FORMAT
In compliance with EPA's recommendations, we have organized this
report in keeping with the following format provided by the EPA. In so
doing, we recognize the limitations of this format and have endeavored
to minimize its possible effects on the thrust of the conclusions. Where
necessary, reference is made to the Appendix which is issued as a separate
volume and provides general background on the coal mining industry.
I. Industry Segments
A. What different types of plants in the industry might be
affected differently by pollution control requirements.
B. How many of each type of plant are there?
II. Price Effects
A. How are prices determined in the industry?
B. What price changes can be expected as a result of
pollution control requirements?
III. Financial Profiles
A. For plants in each sensitive segment, what is the
1. Annual profit before taxes
2. Annual cash flow
3. Market (salvage) value of assets
4. Cost structure
a. Fixed costs
b. Variable costs
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B. For each of the above, what is the
1. Median
2. Range
3. Distribution
C. What are the constraints on financing additional capital
assets for plants in each segment?
IV. Pollution Control Requirements
What assumptions about pollution control technology, investments,
and costs were used in this study?
V. Impact Analysis
For plants in each segment, what will be the impact of pollution
control costs in terms of:
A. Financial Effects
1. Profitability
2., Capital availability
B. Production Effects
1. Production curtailments
2. Plant shut downs
3. Industry growth
C. Employment Effects
1. From production curtailments
2. From plant shut downs
3. From changes in industry growth
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D. Community Effects
1. Where are plants likely to shut down or reduce employment?
2. Are new plants likely to be built in the same areas
due to the location of the market, raw materials, or
skilled labor?
3. Are laid off employees likely to be absorbed by other
plants in the same areas?
4. Will additional, secondary unemployment result in the
communities because of multiplier effects?
5. How many communities are likely to be seriously impacted?
Where?
E. Balance of Payments Effects
F. Effects Upon the Industry's Suppliers and Consumers
VI. Limits of the Analysis
A. How accurate can the analysis be considered?
B. What is the possible range of error of the estimates?
C. What were the critical assumptions?
D. What questions remain unanswered?
E. Under what circumstances might the major conclusions of
the analysis be altered?
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B. APPROACH
Our efforts were concentrated on Appalachia and North Central
regions, since they currently have an acid mine drainage problem and would
therefore suffer adverse economic effects due to water pollution regulations.
The industry in these areas was analyzed on a "best-efforts" basis, taking
into account regional combinations and within the imposed budgetary and
time cons traints.
We had expected the EPA to furnish us detailed information on
individual mine effluent quality and quantity and detailed information
on pollution control costs. Because effluent data were not made available,
we had to collect data on individual mines as available and our sample of
25 mines is less than 0.5% of the number of mines in the industry. The
EPA cost data were received late and subsequent to the time when we had
compiled a consistent data base for cost estimation.
This project was carried out in conjunction with Apt, Bramer, Conrad
and Associates, Inc., of Pittsburgh, Pa. In addition to compiling effluent
data on mines and calculating the estimated treatment costs, we analyzed
data on mine segments provided by the Bureau of Census and the Internal
Revenue Service. Our analysis of the mine segments was verified by several
discussions with people knowledgeable about the coal industry. These dis-
cussions were also helpful in assessing the coal industry's attitudes regarding
the sources of future incremental operating costs and its effects on the
industry.
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I. INDUSTRY SEGMENTS
A. SEGMENTS
Four regions account for virtually all the bituminous coal
produced in the United States,—Appalachia, Central U. S., Northern
Great Plains and the Mountain and Pacific states. It is our opinion
that the problems associated with water pollution and acid mine
drainage are most preponderant in the Appalachian and Central regions,
and on this basis our study excluded consideration of the other re-
gions .
For purposes of this analysis we have classified coal producers
into three size categories:
• small mines producing 49,999 tons per year or less including
"family establishments" producing less than 10,000 tons per year
• medium-sized mines whose production ranges from 50,000 to 499,999
tons per year
• large mines producing 500,000 tons per year and over.
Of the 4,000 active mines falling into the small category in 1970,
3726 were located in the Appalachian region and 227 in the Central
region. 1288 medium-sized mines were operating nationwide, with 1119
located in Appalachia and 141 in the Central region. The breakdown
for large mines was 187 and 101 for Appalachia and the Central region
respectively.
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Figures 1-1 and 1-2 show the historical trends in the numbers
and production tonnages, respectively, of these segments of the indus-
try nationwide. It should be noted that the number of medium and large
mines has steadily increased at the expense of small mines which have
experienced a steep numerical decline since 1963. Figure 1-2, on the
other hand, shows that the tonnage production from the large mines has
increased sharply while small mines have hardly registered any gains.
This is further highlighted by Table 1-1 which shows the coal produc-
tions and percentages generated by the four and eight largest coal
producers in 1954 and 1967. In this interim, the four largest pro-
ducers boosted their share of total production from 15.8% to 29.2%.
For the top eight producers, the figures are 23.6 and 39.7% respectively.
Thus, while the degree of concentration has increased, the coal indus-
try is not a particularly concentrated industry when compared with the
primary ferrous and non-ferrous industries.
The trend in Figure 1-1 indicates that the smaller producers
are a marginal segment of the industry. Most of the small and medium
producers are involved in exploitation of small deposits that are
generally unattractive to the larger producers since the small de-
posits are not amenable to extraction by large scale operation and to
some extent the larger producers are burdened by higher overheads and
usually by union labor costs. In a given geographical region, the
large producers control the prices and the small producers are gener-
ally unable to exert any significant pressures to control the price
of their product. Because of this, the smaller producers are tradi-
tionally sensitive to those factors that tend to increase operating
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7000
6000
5000
CD
C
o
k.
CD
"I
D
4000
3000
2000
1000
Small
Medium
Large
1960
1962
1964
1966
1968
1970
Year
Note:
Small: 50,000 Tons Per Year and Under
Medium: 50,000 - 500,000 Tons Per Year
Large: 500,000 Tons Per Year and Over
Source: Minerals Yearbook, 1960—1970
FIGURE 1-1 CHANGES IN THE NUMBER OF COAL MINES IN
THREE SIZE CATEGORIES SINCE 1960
1-3
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400
350
300
250
o
c
o
200
150
100
50
Large
Medium
Small
1960
1962
1964
1966
1968
1970
Year
Note: Small: 50,000 Tons Per Year and Under
Medium: 50,000 - 500,000 Tons Per Year
Large: 500,000 Tons Per Year and Over
Source: Minerals Yearbook, 1960—1970
FIGURE 1-2 CHANGES IN COAL PRODUCTION FOR THREE
SIZES OF MINES SINCE 1960
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TABLE 1-1
PRODUCTION OF COAL BY THE LARGE PRODUCERS FOR 1954 AND 1967
Production
(Millions
of Tons)
Percent
of
Total
1954
1. Pittsburgh Consolidation Group
2. United States Steel
3. Sinclair Southern
4. Eastern Gas & Fuel
5. Island Creek-Pond Creek
6. Bethlehem Steel
7. Truax-Traer
8. Peabody
Top 4
Top 8
Total, all companies
22.9
22.7
8.3
8.1
62.0
8.1
8.1
7.2
7.0
92.4
392.0
15.8
23.6
100.0
1967
1.
2.
3.
4.
5.
6.
7.
8.
Peabody (Kennecott)
Consolidation (Continental Oil)
Island Creek (Occidental Petroleum)
Pittston
Top 4
United States Steel
United Electric and Freeman
(General Dynamics)
Bethlehem Mines (Bethlehem Steel)
Eastern Associated (Eastern Gas & Fuel)
Top 8
Total, all companies
59.4
56.5
25.9
19.7
161.5
19.0
14.1
12.6
12.3
219.5
552.6
29.2
39.7
100.0
NOTE: The parent company, if any, is indicated in parentheses,
The figures have been rounded.
SOURCE: FTC Report, Docket 8765
1-5
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costs in the short term and their high "mortality rate" is well docu-
mented. In the long run it can be argued that because of their mode
of operation (i.e., selection of small "easy to mine" deposits) they
would tend to avoid those deposits that are susceptible to water
pollution problems and thus suffer no impact of stringent water pollu-
tion standards. The latter, however, would involve a loss of mineable
reserves.
B. PERSPECTIVE ON WATER POLLUTION
The water pollution resulting from coal mining over the past
century has caused a major impact in certain regions of Appalachia.
Figure 1-3 delineates the areas affected by mine drainage in this re-
gion. It is estimated that acid mine drainage pollutes 5,700 miles of
streams in this region, with 75% of the affected streams located in
the Susquehana, Allegheny, Monongahela, Potomac, and Delaware River
Basins of Pennsylvania, West Virginia, and Maryland.
Table 1-2 shows the percentage distribution of the number of
sources of acid mine drainage in Northern Appalachia, along with the
proportion of drainage by mine type and operating status. It is evi-
dent that nearly 80% of acid pollution comes from abandoned or inac-
tive mines and 71% originates in underground mines. It is expected
that these proportions will probably not change in the near future
unless serious remedial measures are undertaken.
The data of Table 1-2 indicates that stopping operations at a mine
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Applachian Region
Boundary
Area Underlain by
Coal Deposits
Sub-Area Boundary
Areas Affected by
Acid Mine Drainage
SUB-AREAS OF APPALACHIA DESCRIBED IN
MINE DRAINAGE REPORT
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
Anthracite Region
Tioga River Basin
West Branch Susquehanna River Basin
Juniata River Basin
North Branch Potomac River Basin
Allegheny River Basin
Monongahela River Basin
Beaver River Basin
Muskingum River Basin
Hocking River Basin
Little Kanawha River Basin
Kanawha River Basin
Scioto River Basin
Guyandotte River Basin
Big Sandy River Basin
Ohio River Minor Tributary Basins
Kentucky River Basin
Cumberland River Basin
Tennessee River Basin
Source: Appalachian Regional Commission; Arthur D. Little, Inc., estimates.
FIGURE 1-3 AREAS AFFECTED BY THE ACID MINE DRAINAGE PROBLEM IN APPALACHIA
1-7
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TABLE 1-2; PERCENTAGE DISTRIBUTION OF THE NUMBER OF SOURCES AND
PROPORTION OF ACID MINE DRAINAGE BY TYPE OF MINE, ACTIVE
AND INACTIVE
TOTALS
TYPE OF MINES
Number of Sources
ACTIVE MINES
INACTIVE MINES
Underground
5.0
53.0
Surface
1.4
27.0
Combination
0.4
8.4
Other
Sources
0.5
4.3
Sub-
Totals
7.3
92.7
58.0
28.4
8.8
4.8
100.0
Amount of Acid Drainage
ACTIVE MINES
INACTIVE MINES
TOTALS
18.8
52.5
0.9
11.1
1.9
7.3
0.4
7.1
22.0
78.0
71.3
12.0
9.2
7.5
100.0
1. Combination mines include both surface and underground mines on the same site
SOURCE: APPALACHIA REGIONAL COMMISSION, Report on "Acid Mine Drainage in
Appalachia" (1969).
1-8
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does not solve the associated water pollution problems since a high
proportion of the current pollution arises from abandoned mines. As
a corollary, it can be concluded that enforcement of water quality
standards at presently operating coal mines will solve only a fraction
of the pollution problem and the cost of treating active mine waters
in Appalachia will always be affected by seepage from adjoining aban-
doned mines. To forestall future pollution when currently active
mines cease operations, we understand that the state of Pennsylvania
has passed a regulation effectively making an operator of a newly
auaudoned mine liable for future acid mine drainage treatment costs
arising from that operator's mine.
It can be observed from Figure 1-3 that mine drainage prob-
lems are more prevalent in Pennsylvania than in any other state. In
fact, about 60% of the total Appalachian drainage problem occurs in
Pennsylvania,and Pennsylvania has been a leader in documenting the
quality and quantity of acid mine drainage; its impacts and control
costs as well as the regulation of operations to prevent future acid
drainage.
Table 1-3 indicates the distribution of drainage sources by
counties in the Pennsylvania bituminous coal belt. This table illus-
trates several points that have to be kept in mind when studying the
water pollution aspects of the coal industry; viz. although acid mine
drainage can be localized geographically as in Figure 1-3, there is a
wide variability from mine to mine within a county and frequently
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adjoining mines can have acid and alkaline discharges or widely varying
volumes of discharge. In agreement with the general Appalachia drain-
age picture, the table shows that there are more inactive than active
sources.
1-11
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II. PRICE EFFECTS
As discussed in detail in the Appendix, the marketing of coal
involves steam coal (washed and unwashed) and metallurgical coal for
domestic and foreign consumers. Metallurgical coal is a higher value
product and the demand is essentially price inelastic in the short
term. Two price structures prevail in the steam coal market,—long
term contract price and spot-market price. The large and some medium-
size producers can obtain long-term contracts for steam coal and this
contract price determines the price in that region. The spot-market
price is responsive to short-term supply-demand imbalances and these
sales are dominated by small producers who market their coal through
brokers. In the spot market, the producer is practically unable to
control the price of his product or to pass on any increases in operat-
ing costs. For the large producers, steam coal marketing to the elec-
trical utilities is a highly sophisticated process involving proper
estimation of mining costs over the life of a property, imaginative
auu persistent attention to securing the lowest possible transportation
co^ts, and the capacity to make sales proposals for large-volume, long-
term contracts in intensive competition with other coal producers and
suppliers of alternative fuels. The long-term contracts contain clauses
that determine the extent of automatic cost pass-on in the event that
operating costs increase.
The inability of the small and medium-sized operators to influ-
ence the price received for coal makes them susceptible to any impact of
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increased costs.
We believe that the nature of the long-term sales contract
makes it possible for a large producer to pass on a major portion of
his increased costs including costs of direct compliance with new
government regulations. There are several reasons why the full cost
of compliance could not be passed on automatically but would require
renegotiation of contracts. These relate to government regulations
that might prevent a full pass on of costs and more important, to the
fact that many of the steps necessary for compliance result in a loss
of reserves and a decrease in mine life and the loss of future income
cannot be passed on.
In the case of the smaller producers, we believe that the
added costs can be fully passed on only if
• the larger mines incur identical higher costs which they are able
to pass-on in full
• no government regulations prohibit full pass-on to the consumer.
Partial pass-on would occur if the small and medium-size mines incur
additional costs that are higher than those incurred by the large pro-
ducers. This, in fact, is expected to be more likely since smaller
units do not characteristically have economies of scale. Thus the
most probable occurrence would be an increase in price equal the amount
passed on by the large producers.
II-2
Arthur D Little, Inc
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III. FINANCIAL PROFILES
We have utilized the most recent data on the coal industry, as
developed in the 1967 Census of Mineral Industries (and published
December, 1970) for an assessment of the financial profiles of the
different size segments of the coal industry. Data for the 1972
Census is not expected to be available until late 1974. We made some
tests based on the 1963 Census data and our own information on the
coal mining industry and feel that the 1967 data can be usefully em-
ployed in this study to indicate parameters useful in microeconomic
analyses, as a function of the size of the coal mining operation.
The 1967 Census data provides the following financial infor-
mation on ten employee size segments of the industry.
• Value of shipments (VS) and receipts includes the net selling value
f.o.b. mine after discounts and receipts for contract work done by
others.
• Cost of Supplies, Etc., and Purchased Machinery - This includes:
a. the total delivered cost of all supplies used, minerals re-
ceived for preparation, and purchased machinery installed;
b. the amount paid for electric energy purchased;
c. the amount paid for all purchased fuels used for heat, power,
or the generation of electricity;
d. the cost of work done by others on a contract, fee, or other
basis for the account of the establishments (contract work);
III-l
Arthur D Little, Inc
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e. the cost of products bought and resold without further pro-
cessing.
The total excludes the cost of other services used, such as adver-
tising, insurance, telephone, etc., and research and consulting
services of other establishments. It also excludes overhead costs,
such as depreciation charges, rent, interest, royalties, etc. It
includes supplies, machinery, and equipment used in development and
exploration of mineral properties and in capitalized repairs.
• Capital Expenditures - This covers expenditures made during the
year for development and exploration of mineral properties, for new
construction, and for machinery purchased at their operations that
were chargeable to fixed-assets accounts of the mining establish-
ments and were of a type for which depreciation, depletion, or
Office of Minerals Exploration accounts are ordinarily maintained.
• Mining Employees Payrolls - This total includes the gross earn-
ings paid in the calendar year 1967 to all employees on the pay-
roll of reported establishments. It follows the definition of pay-
rolls used for calculating the Federal withholding tax. It in-
cludes all forms of compensation such as salaries, wages, commis-
sions, dismissal pay, all bonuses, vacation and sick leave pay, and
compensation in kind. It should be noted that this definition does
not include employers' Social Security contributions or other non-
payroll labor costs such as Employees' pension plans, group insur-
ance premiums, and workmen's compensation.
• Value Added in Mining (VA) - This measure is computed by subtract-
Ill -2 Arthur D Little, Inc
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ing the cost of supplies, etc., and purchased machinery from the
value of shipments and receipts plus capital expenditures.
These data can be utilized to derive the following informa-
tion about each size segment as shown in Table III-l.
• Value Added (VA)/Value of Shipments (VS)
Since the value of shipments is a measure of tonnage produced by
each segment, this is equivalent to value added per ton.
• (VA - payroll (incl. suppl. expenses))/VS
If local taxes, insurance and interest charges are subtracted from
this column, we obtain an estimate of pretax cash flow per ton.
• Capital expenditures (CI)/VS
This is an estimate of the average rate of capital investment per
ton of production.
• Variable out-of-pocket costs (CV)/VS
The out-of-pocket costs are obtained by first adjusting the capital
expenditures to remove exploration labor costs which were capital-
ized. When this quantity is subtracted from cost of supplies and
purchased machinery etc; the cost of supplies is obtained. This
cost of supplies plus payroll (including supplemental expenses such
as welfare and social security contributions) gives the out-of-
pocket variable costs per ton.
One striking finding is that the sum of reported out of pocket
operating costs per unit value of shipments (or per ton of coal at
III-3
Arthur D Little, Inc
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III-4
Arthur D Little, Inc
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constant price) is virtually independent of mine size. A rough cross
check of this is obtained with estimates derived from the Statistics
of Income from corporation tax returns reported by IRS for the coal
mining industry for Income Years 1966 and 1967 (covering accounting
periods ending between July 1966-June 1967 and July 1967-June 1968,
respectively).
• Fixed costs, profits and cashflows—Use of IRS data
Because the set of Census Data do not indicate profit or cash flow
from mining, and because of a fair cross check on the unit payroll
and other operating cost data from the IRS sample, we used the IRS
data to develop unit estimates of fixed costs, profit, and "cash
flow" as a function of mine size.
The income tax data comprise a stratified sample of returns with
estimates of sampling variability; all returns with corporate assets
$10 million and above are sampled at 100%. The IRS data are broken
down into two groups—"Returns With Net Income" and "Returns With and
Without Net Income," the latter giving the algebraic sum of returns
showing net income and those showing deficits, etc. Some indication of
the variability of relationships over time can be obtained by examining
the last several years of statistics. However, analysis must proceed
with caution because of the sampling variability, differences in cor-
porate classification over time, differences due to foreign versus do-
mestic earnings mix, and changes in tax laws and regulations over the
last several years.
While we have attempted to reconcile IRS and census data to the
XI1-5 Arthur D Little, Inc
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extent practicable, the IRS data are given on a different basis than
Census (i.e. asset size of reporting corporation rather than average
number of employees per mining establishment), and hence there is only
a rough correspondence between the two sets of data, in addition to
their other limitations.
For the purposes of this analysis, we have defined fixed
charges per unit value of shipments to be equivalent to the sum of rent
paid on business property, interest, depreciation and amortization, de-
pletion and taxes other than Federal Income Tax, all divided by the
value of business receipts—assumed equivalent to the value of ship-
ments. To approximate as closely as possible the data in the 1967
Census, we averaged IRS Income Years 1966 and 1967, covering returns
for corporate accounting periods ending July 1966-June 1967 and July
1967-June 1968. The results shown in Table III-l indicate that fixed
charges tend to increase with the size of coal mining operations.
This may be explained in part by the greater use of long term debt
financing among the large coal companies resulting in higher interest
charges per unit value of shipments.
III-6
Arthur D Little, Inc
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Table III-2 presents estimates of net income after tax,
cash flow (cash flow is defined here as simply net income after tax
plus depreciation and depletion deductions), assets, value of business
receipts, and cash flow per unit value of shipments as a function of
the asset size ranges of corporations reporting to IRS (covering over
2,300 returns). We feel that cash flow as obtained from these data is
a more meaningful measure of financial performance than IRS reported
net income, due to the computational effects of statutory depreciation
and depletion allowances.
Except for the three smallest categories of coal mining
operations, i.e., those with assets under $250,000 and fewer than
20 employees approximately, we find cash flow to be relatively stable
as a percentage of the business receipts (value of shipments). As
indicated in Table III-2 the range is -1.6% to 14.4% for the industry
as a whole with a median of 10.0%. Excluding the three smallest groups,
however, the range is 9.6% to 14.4% with a median of 10.9%.
"7 Arthur D Little, Inc
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TABLE III-2: SELECTED FINANCIAL DATA FOR THE COAL MINING INDUSTRY
BASED ON UNITED STATES INCOME TAX DATA
Corporation
Asset Class
($000)
0-50
50-100
100-250
250-500
500-1,000
1,000-5,000
5,000-10,000
10,000-25,000
25,000-50,000
50,000-100,000
100,000-250,000
250,000 or more
Total
Assets
16.5
27.3
58.1
58.6
131.0
302.0
123.9
325.2
374.1
145.4
360.9
761.8
Reported
Business Net Income "Cash Flow" r
Receipts After Taxes from
(VS) (NI) (NI + De + Dp) L
86.5
72.2
143.7
109.1
185.0
403.8
268.4
270.1
258.9
109.8
349.2
762.1
-Millions of
-4.3
-2.4
-1.6
2.4
4.2
4.5
9.0
-0.7
7.7
5.7
-2.3
16.3
-1.6
0.6
6.4
10.3
22.0
39.1
39.9
32.1
36.1
15.7
28.6
76.5
"Cash Flow"
per Dollar
of Bus .
Receipts
NI + De + Dpi
VS J
%
-1.6
0.9
1.4
9.9
11.9
9.6
10.9
11.9
14.0
14.4
8.7
10.1
Notes: Data from United States Internal Revenue Service, Source Book of
Statistics of Income, Minor Industry 1100 - Coal Mining, Average
of Periods July 1966-June 1967 and July 1967-June 1968, by Arthur
D. Little, Inc.
NI - Net income after taxes
De - Depletion
Dp - Depreciation
VS - Business receipts, assumed equivalent to value of shipments
III-8
Arthur D Little, Inc
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• Salvage Value of Coal Mining Assets
There is little information available yet which could be directly
and meaningfully applied to the question of salvage values of coal
mines in the context of shutdown merely to avoid incremental pol-
lution abatement investment and operating costs. As a first ap-
proximation one may assume that mobile equipment is salvageable.
In a new underground mine cost of mobile equipment would amount to
40-50% of the total capital investment. The share is higher for
strip mines. However, further investigation is necessary to devel-
op and test a methodology for meaningfully estimating salvage val-
ues of this equipment since the actual prices obtainable are sen-
sitive to location and local economic climate.
Some perspective on the maximum possible salvage value of plant
and equipment per ton of production capacity may be obtained from the
1967 census of mineral industries. It indicates gross book value of
machinery and equipment employed by the industry of $2.2 billion, cov-
ering 3921 establishments producing 545 million tons of coal. Pur-
chased machinery installed in 1967 was valued at $259 million; for
1963, when production was 459 million tons, the value of purchased
machinery installed was $191 million (not adjusted for inflation to
1967 dollars).
The salvage value of a mine or plant may be approximated by
III-9
Arthur D Little, Inc
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the sum of the value of net (depreciated) plant and equipment plus the
net working capital associated with the operations. Actually, adjustment
from "book values" will probably have to be made, not only as a result of
differences in accounting treatment and rates of depreciation assumed from
one firm to the next, but also to reflect current market conditions.
Using IRS data, indications are that small coal mining companies typically show
negative or very small positive year-end net working capital positions. Although
varying widely, the large coal mine operations show net working capital
positions on the order of 35% of their net plant and equipment.
Of course, shut-down of a plant or mine does not imply that an
entire corporation goes into liquidation, and the IRS data are not necessarily
amenable to meaningful proration or allocation to a specific mine or plant.
• Constraints on Financing Additional Capital Assets
The constraints on financing additional capital assets fall into
several different categories: managerial, financial, competitive, and
regulatory.
a. Managerial
It is management's task to choose from among investment alternatives
and decide on the optimum utilization of the corporation's resources and
borrowing power and to formulate and implement plans accordingly. Most large
coal companies seek long term contracts with utilities (and vice versa) and
these activities typically require a commitment of capital for development
of a new mining property.
111-10
Arthur D Little, Inc
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The funds available to the corporation include, of course, its
total cash generation plus its borrowing power.
Large amounts of both long-term and short-term external capital
funds have been made available to the large coal companies, and long term
contracts to supply an electric utility facilitate financing of new invest-
ments. The realistic constraints here are the costs of capital vis-a-vis
the expected rates of return on its investment. IRS data indicated all but
the smallest mines carry significant long term as opposed to short term
debt. The small mines typically sell in the "spot" market and carry a
large trade credit.
Mining ventures are typically expected to have relatively high rates
of return and frequently involve some relatively high risks. Uncertainty
over future pollution control requirements is a factor increasing perceived
risk and probably also the cost of capital.
b. Financial
A corporation's earnings and cash flow are generally programmed to
meet dividend, reinvestment, and debt service requirements. When external
financing is required, there are many considerations dictating the type and
amount.
In general, financial institutions and investment firms employ
tests of financial performance and standards or guidelines for debt-to-equity
ratios and coverage of fixed charges in a given industry to assess the
III-ll
Arthur D Little, Inc
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"creditworthiness" of a corporate issuer of securities. The capital
markets together with corporate management, determine how much capital
will be made available, and under what terms, to the borrowing corporation.
Existing commitments carry with them an obligation to make certain
expenditures, meet debt service schedules, etc. Loan agreements may
restrict the extent to which the corporation can diminish working capital,
retained earnings, or issue further debt.
c_. Competitive
A process breakthrough which significantly lowers production cost
may dictate that capital investments be made — by the innovative firm, on
the offensive, and defensively by its competitors. On the other hand, if
pollution control costs are so onerous and if competitive market conditions
do not permit such incremental costs to be passed on to customers or tax-
payers, a firm may elect not to spend the money, assuming it could achieve
a greater return on its investment elsewhere.
d. Regulatory
The financing of certain additional capital assets may be influenced
by regulatory considerations. Tax laws and ownership limitations are the
most important considerations, e.g., in regard to the effect of depletion
allowances, or industrial pollution control revenue bond financing.
111-12
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IV. POLLUTION CONTROL REQUIREMENTS
A. GUIDELINES
We were required to consider the guidelines presented in Appendix B
for water pollution control standards that have to be achieved by each
coal mine. We understand that each coal permit application for water dis-
charge will be evaluated on the basis of these guidelines.
IV'1 Arthur D Little inc
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B. POLLUTION CONTROL TECHNOLOGY
The use of alkalis to neutralize acidic salts and acids from
acid mine drainage (AMD), is the most widely used treatment of such
discharges in use today. The principle involves the use of alkaline
chemicals, mainly hydrated lime and limestone, and is generally com-
bined with an aeration or oxidation process since mine drainages are
often characterized by the presence of ferrous ion.
The objective of neutralization of AMD is to remove acidity
and iron from the discharged water. Iron removal is a necessary
consequence, since ferric ions are only slightly soluble at pH val-
ues over 3.0, and the solubility decreases as the pH increases.
When ferrous sulfate solutions are oxidized at pH values over
3.0, ferric oxides or hydrated oxides are formed, together with an
equivalent amount of sulfuric acid. This acid potential must also
be neutralized by the alkali used.
Water drainage from coal mines may contain varying amounts of
acidity in the form of sulfuric acid and iron salts, principally
ferrous sulfate. Other materials may be present, usually in lesser
amounts, principally calcium, magnesium and aluminum salts. The qual-
ity of mine drainage depends on many factors and is truly the result of
a dynamic series of chemical and physical factors. These factors have
been well defined, in terms of the present state of knowledge. The
quality and classification of mine drainage waters are summarized in
Table IV-1.
jv _ 2 Arthur D Little, Inc
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Those classifications in which the pH is generally below 7.0,
where measurable acidity and iron compounds are present can be treated
by neutralization with alkalis, such as hydrated lime, limestone,
caustic, soda ash, and the like. Such treatment results in the removal
of acidity and the reduction of soluble iron concentration. The
efficiency of removal of these materials depends on the alkali used.
The use of calcium alkalis, lime, hydrated lime and limestone
will remove sulfate ions when present above the saturation solubility of
calcium sulfate, and if accompanied by aeration or other form of oxidation,
will also remove soluble iron salts as insoluble iron oxides. Thus, effluent
solutions from such neutralization processes generally have no acidity or
slight alkalinity, contain low concentrations of soluble iron and reduced
sulfate concentrations if the original sulfate exceeded about 2000 ppm as
calcium sulfate. Soluble aluminum salts are also removed from solution.
Neutralization treatments historically have been applied to mine
drainage classes 1 and 2, since classes 3 and 4 generally have no acidity
and lower iron concentrations. Unslaked lime and hydrated lime are the most
common. More recently limestone has been more widely used, primarily because
of its low cost.
The effluent solutions, after treatment with calcium alkalis,
contain higher than original hardness concentration, may contain up
to about 2000 ppm sulfate, and may contain significant amounts of
IV-4
Arthur D Little, Inc
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suspended solids depending on solids separation techniques. To the
extent that acidity and iron compounds are removed, neutralization
with calcium-based alkalis is successful.
While lowest cost alkalis have been most widely used, it is
obvious that this may not be the determining or limiting factor. In
fact, while some alkalis would not produce a desired effluent for
addition to other surface waters because of high solids content, there
may be other considerations for investigation .
The use of sodium based alkalis such as soda ash or caustic
will effect a removal of acidity and iron. These alkalis are substan-
tially more expensive to use however, but there is one other major
technical difference. Since sodium sulfate is a highly soluble salt,
there is no reduction in sulfate content. The insoluble materials
would be iron and aluminum oxides, and the quantity of insolubles
separated would be less, since no sulfates would be removed. Sludge
disposal is a serious consideration, since it represents a pollu-
tional waste. Disposal methods now in use include lagooning and dis-
posal in abandoned dry mines. Accurate sludge handling and disposal
costs have not been detailed well in the literature, although Corsaro
et al,* provide information and also point out the many factors
which must be considered.
C. LIME NEUTRALIZATION COSTS
Neutralization and oxidation, via the use of lime or lime-
* Second Symposium on AMD, BCR ine (1968)
Arthur D Little, Inc
IV-5
-------
stone with aeration, while not widely practiced on acid mine drainage
taken as a whole, nevertheless are by far the most widely used of all
mine drainage treatment methods.
Engineering Cost Factors
1. Plant treatment capacity: Lime neutralization costs are
less dependent on the volume of water treated than on the acidity and
iron content of the water, although lower volumes of water treated
tend to increase both the operating and capital costs per unit volume
of water.
2. Lime Consumption: Hydrated lime is normally used. Al-
though it reacts quickly and completely, it suffers the disadvantage
of producing a poorly settleable sludge. The theoretical lime re-
quirements can be easily determined by assuming a stoichiometric
balance between the contained acidity and the lime addition. In
practice, this quantity is escalated by about 25% to compensate for
reaction kinetic effects and to ensure iron precipitation. A good
rule of thumb is to add one pound of hydrated lime per 100 ppm acid
per 1,000 gallons of drainage.
3. Mixing and Aeration: These are important operations in
the use of lime, since the chemical reactions involve the formation
of slightly soluble gypsum and the oxidation of ferrous iron. It is
most important that suitable mixing and agitating/aeration facilities
be provided or else incomplete reactions would give an unstable sludge
in effluent water. Oxidation of ferrous ions accelerates as the pH
IV'6 ArthurDLittle,Inc
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is raised.
4. Settling and/or Thickening: These are to be weighed as
importantly as mixing and aeration, since the sludges formed are
typically slow in settling from solution. In this respect lime treat-
ment is at a disadvantage in comparison with limestone treatment,
which produces a lower volume, more rapidly settleable sludge. The
sludge volume typically produced from a lime treatment plant is a high
percentage of influent volume and contains from 1 to 10% solids on
the average. This volume of solids increases with time. Convention-
ally, the treated water and sludge are sent to a settling lagoon or
impoundment basin from where the supernatant may be removed by pump-
ing.
5. Sludge Disposal: The cost of sludge disposal varies as a
function of the drainage acidity and flow rate, as well as the disposal
method. The above factors have been taken into consideration in the
flowsheet of Figure IV-1 which represents a currently practical process
for lime neutralization of acid mine drainage. The estimated treatment
costs have been plotted in Figure IV-2 as a function of the mine drain-
age rate and acidity. A breakdown is given in Table IV-2 of the sev-
eral cost elements. Capital cost estimates in each case were based on
information furnished by the EPA. The EPA information is summarized in
Table IV-3. We consider the EPA estimates realistic and they appear to be con-
sistent with the estimates given to us by industry personnel and avail-
able in standard sources such as the 1969 Appalachia Regional Commis-
sion Report on Acid Mine Drainage. Capital costs are plotted in Fig-
ure IV-3 as a function of drainage acidity and flow rate. Care must
iv-7 Arthur D Little, Inc
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Raw Drainage
\
1
Holding Lagoon
Sludge for Disposal
Lime
Mixer
Neutralization Tank
Aeration
Tank
Air
Coagulant Aid
Settling
Basin
Treated Effluent
FIGURE IV-1 FLOWSHEET FOR LIME NEUTRALIZATION OF ACID MINE DRAINAGE
IV-8
Arthur D Little, Inc
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4.0
2.0
.10
0.10
,Strong Solution pH-1.0 to 3.0
Average Solution pH-3.0 to 5.0
Weak Solution pH > 5.0
I I
J L I I ill
1.0
Mine Drainage Flow Rate, MGD
10.0
FIGURE IV-2 ESTIMATED COST OF LIME NEUTRALIZATION OF ACID MINE DRAINAGE
IV-9
Arthur DLittleJnc
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IV-10
Arthur D Little, Inc
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TABLE IV-3: COST DATA SUPPLIED BY EPA FOR COAL MINING
A. BASIS
1. Plant capacities: 0.1 - 1.0 - 7.0 million gallons/day
2. Definition of treatment technologies
a. sedimentation
b. neutralization and sedimentation
c. two stage neutralization and sedimentation
d. same as "c" with addition of coagulant aids and aeration
e. same as "d" with addition of deep bed or mixed media filtration
COSTS
1. Plant size of 0.1 million gal/day
Treatment Technology
a. Medium Solution (pH 3.0-5.0)
Investment
Opr & Maint (c/1000 gal)
b. Strong Solution (pH 1.0-3,0)
Investment
Opr & Maint
c. Weak Solution (pH 5.0-7.0)
Investment
Opr & Maint
$ 38,000
19c
$ 65,000
68c
Use 154% of cost shown above
Use 144% of cost shown above
Use 75% of cost shown above
Use 58% of cost shown above
C*
$ 104,000
1.36C
$ 138,000
1.92C
$ 172,000
2.10C
2. Plant size of 1.0 million gallons/day
a. Medium Solution (pH 3.0-5.0)
Investment
Opr & Maint (c/1000 gal)
b. Strong Solution (pH 1.0-3.0)
Investment
Opr & Maint
c. Weak Solution (pH 5.0-7.0)
Investment
Opr & Maint
125,000
3.3c
210,000
46c
Use 162% of cost shown above
Use 171% of cost shown above
Use 46% of cost shown above
Use 30% of cost shown above
340,000
92C
460,000
1.34C
730,000
1.40c
3. Plant size of 7.0 million gallons/day
a. Medium Solution (pH 3.0-5.0)
Investment
Opr 6, Maint (c/1000 gal)
b. Strong Solution ( pH 1.0-3.0)
Investment
Opr & Maint
c. Weak Solution (pH 5.0-9.0)
Investment
Opr & Maint
540,000
1.5C
880,000
43C
Use 191% of cost shown above
Use 179% of cost shown above
Use 35% of cost shown above
Use 22% of cost shown above
1,400,000
86C
2,000,000
1.20C
2,600,000
1.23C
* Note - For this analysis it can be assumed that level "C" will satisfy RAPP guidelines.
IV-11
Arthur D Little, Inc
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10 p
1.0 I
CD
o
0.1
0.01
0.01
0.1 1.0
Drainage Flow Rate, MGD
10
FIGURE IV-3 CAPITAL COST OF LIME NEUTR. OF AMD
IV-12
Arthur D Little, Inc
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be exercised in extrapolating these curves to very low drainage flow
rates since we believe that capital costs become less sensitive to flow
rates at flow rates less than about 10,000 gallons per day. In fact,
we estimate that a small treatment system (containing only the neces-
sary components such as lime feeders and pumps) for a low capacity
operation would cost a minimum of $20,000 to $40,000. This amount of
capital investment (for non-income producing equipment) would have a
significant impact on the smallest mine. The capital cost per 1000
gallons of drainage treated was calculated on the assumption that the
investment is amortized over a ten-year period. Obviously, this
would not apply in the case of a mine with 5 years of remaining life—
a situation applicable to many smaller producers. Other elements of
cost represent our best judgement of unit costs for each item, and are
generally consistent with the operating cost data utilized in the 1969
Appalachian Regional Commission report of the economics of mine drain-
age control. We have also included the cost of waste sludge disposal
which we consider essential for optimum and economic facility opera-
tion.
As shown in Figure IV-2 and Table IV-2, the total treatment
cost for the assumed ranges of flow rate and acidity ranges from a low
of 12 cents to a high of $1.39 per 1000 gallons of effluent treated.
It is noted that at low flow rates, capital and lime costs are the
largest contributors to the overall treatment cost, whereas at high
flows, lime costs alone tend to dominate, especially at high drainage
acidities.
IV- 13
Arthur D Little, Inc
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D. RESERVATIONS
We have the following reservations regarding the applicability
of the cost data presented earlier to specific situations in the coal
mining industry.
• The applicability of the capital cost estimates to small scale
operations. This problem was discussed in section C.
• It appears that the sampling schedule proposed by EPA in Appendix B
is rigorous and would impose a considerable cost penalty on the small
mines.
• Since lime sludge settles to a low solids density, sludge ponds will fill
up rapidly and the sludge has to be removed and disposed. Depending
on location and terrain, lagoon and sludge disposal costs can vary
widely.
• The limitation of 30 mg/1 on suspended solids can have a potentially
great impact. This is because in many cases, the waters received
can contain greater concentrations of suspended solids than this and
non-availability of land in many areas would require the use of more
expensive techniques such as flocculation and/or filtration.
IV-14
Arthur D Little, Inc
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V. IMPACT ANALYSIS
A. ADL SAMPLE
For the purpose of analyzing the potential impact of water pollution
control on the coal mining industry, we had expected the EPA to furnish
us data relating to the water consumption, treatment, and discharge
characteristics of a representative cross-section of coal mines in the
United States. Since the EPA was unable to supply such data, we have relied
on our sampling of those mines in the Appalachian and Central regions who
were willing to disclose their coal production and water-treatment data.
Our sample has been limited to Illinois, Ohio, Pennsylvania, and West
Virginia because this sector accounts for 57% of the annual bituminous
coal production, and most of the acid mine drainage problems in the coal
industry occur in this region.
The production and mine drainage profiles of the mines covered in
our survey are listed in Table V-l. It should be emphasized that due to
time and other constraints, our sample is necessarily neither significant
in relation to the total number of mines in the United States (over 5000)
nor representative of each sector. For instance, although it is our belief
that the small mines with less than about 50,000 tons per year production
are liable to be most adversely impacted by water pollution regulations, they
are not adequately represented in Table V-l.
V-l
Arthur D Little, Inc
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TABLE V-l: GEOGRAPHICAL, SIZE. AMD DRAINAGE PROFILES OF SURVEYED COAL MINES
Mine Code Location Coal Type
No.
01 W. Virginia Steam
03 Pennsylvania "
04 " Met.
05 W. Virginia Steam
06 " "
07 Pennsylvania "
08 W. Virginia "
09 Pennsylvania Met.
10 " Steam
11 " Met.
12 " "
13 W. Virginia Steam
14 Pennsylvania "
15 " Met.
16 " Steam
17
18 " "
19
STRIP
20 Pennsylvania Steam
21 W. Virginia "
22 Ohio
23 Illinois
24 " "
* Not Available
Kev: Plant Size - S = Small Capacity - Less than 50,000
Plant Drainage Profile
Size Flow rate pH Acidity Iron
M S M L M
M M M L L
L L L L M
L M H H H
L S L L N.A.*
M L M M N.A.
L M M M N.A.
L M H H H
L L H H H
L S L L I,
L M M M "
L L L H M
S M H M M
L L H H
L M L L I,
L L L L L
L M L L L
L L L L L
M M H M M
S S L L L
L M H M M
L L L N.A. N.A.
L ' L L N.A. N.A.
tons/yr
M = Medium Capacity - 50,000 - 500,000 tons/yr
L = Large Capacity - Over 500,000 tons/yr
Flow Rate - L = I ow Flow - Less than 150,000 gals.
/day
M = Medium Flow - 150,000 - 750,000 gals. /day
H = High Flow - Over 750,000 gals. /day
£H - L = Low 5.0 - 7.0
M = Average 3.0 - 5.0
H = Severe <3.0
Acidity - L = Low Acidity 0 - 100 ppm
M = Average Acidity 100 - 999 ppm
H = High Acidity 71000 ppm
Iron - L = Low<-25 ppm
M = Average 25-250 ppm
H = High "7250 ppm
V-2
Arthur D Little, In
-------
For the following reasons, our sampling has been limited to mines
and includes no washeries:
o we are informed by reliable industry sources that about 80% of coal
washeries recycle their process water, and thus washeries do not pose
significant water pollution problems. Any problems arising from
washeries are usually related to acid water seepage from gob piles, a
problem which is peculiar to those areas where acid mine drainage is
a problem.
We have not used the water discharge data in the 1967 Census of
Mineral Industries - "Water Use in Mining" because:
• these data do not include establishments consuming less than 20 million
gallons per year. We believe a substantial fraction of small coal mines falls
within this category and thus their water discharge data are not
included in the Census figures.
• it is difficult to relate the Census data to individual mines. It is
only on this basis that reliable conclusions can be drawn in a micro-
economic study concerning the possible impact of water pollution control on
specific mines or mine segments.
Shown in Table V-2 are additional data regarding the ownership and
water treatment practices (where available) of the surveyed mines, as well
as our estimates of costs where treatment facilities are currently in
operation, or estimates of potential costs where no facilities have been
installed. Accordingly, treatment costs for mines 11, 20, 21, 22, 23, and
24 represent our judgment of the requisite treatment system and the incurred
costs of water treatment.
v'3 Arthur D Little, Inc
-------
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Arthur D Little, Inc
-------
Capital cost estimates were derived partly from Figure IV-3
representing the costs furnished by the EPA. We adopted these figures
since we have determined them to be quite consistent with actual capital
costs incurred by industry sources willing to disclose their capital cost
data to us. In several cases, however, we have modified the EPA data to
reflect the peculiarities of a specific treatment system. For instance,
the EPA figures reflected in Figure IV-3 apply to a system incorporating
mine neutralization, aeration, and sedimentation. Where necessary, these
have been adjusted to account for the fact that some operations can ful-
fill the EPA's effluent limitation guidelines by simple lagooning or by
aeration and lagooning only.
The operating costs have been adapted from the cost estimates
given by Holland, Corsaro, and Ladish at the Second Symposium on Coal
Mine Drainage Research in Pittsburgh, 1968. These are shown in Table IV-2.
Their figures are generally accepted to be realistic and were largely
adopted in the analysis of "Engineering Economic Study of Mine Drainage
Control Techniques" by Cyrus William Rice and Company for the Appalachian
Regional Commission. Where necessary, these costs have been modified by
us to reflect the conditions within particular treatment facilities. It
should be noted that our estimates include the cost of sludge disposal
where necessary. We believe that it would be impractical to use a
sedimentation basin for sludge storage since this practice would call for
construction of a new basin every few months.
V-5
Arthur D Little, Inc
-------
It will be observed from Table V-2 that total treatment costs
can range from 0.06 to $1.25 per thousand gallons of drainage treated,
depending on the complexity of the treatment system and the volume flow
rate, acidity, and iron content of the drainage. The variability stems
primarily from the capital cost contribution which indicates that some
treatment facilities can be installed for as low as $5,000 where a low
flow rate is coupled with a drainage that already meets the effluent limit-
ation guidelines.
Table V-3 presents the ratio of the water treatment cost to the
value of shipments of the mines surveyed. Clearly, mine 14 with a water
treatment cost in excess of its value of shipment cannot be expected to
continue in operation. It is our understanding that this mine will be
closing, partly as a result of inability to comply with water pollution
regulations.
The ratio of treatment cost to value of shipments must not, however,
be used as a standard for assessing the impact of water pollution regulations
on particular mines. While this may be meaningful for small independent
mines, the same cannot be said for large captive facilities where the cost
impact of water treatment can be internalized within the organization in
such a manner as not to result in mine shut-down. All that can be said with
regard to the probability of a mine shut-down is that each facility must be
evaluated separately, taking into account, among other factors, its
peculiar organizational structure, production capacity, and water treatment
requirements.
V-6
Arthur D Little, Inc
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V-7
Arthur DLittleJnc
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B. FINANCIAL EFFECTS
1. Profitability and Shutdown Considerations
In the long term, any increase in operating costs that results in
negation of profits would lead to a plant shut down. In the short term,
one could argue that the pressure point vis-a-vis plant shutdown occurs
when revenues just barely exceed projected out-of-pocket costs plus
incremental capital and operating charges for continued operations with
pollution control.
This may be expressed in notational form as follows by defining a
quantity, ($ , the net present value of the future cash flows from
projected operations.
Thus L [Revenues - Out of Pocket - incremental annual Pollution]
(VS) Costs (CV) Control Capital & Operating
Costs (CPC)
(1 + r)n
n=0
Where L is the estimated useful life of the mine
n is years
r is the discount rate which management chooses for present
value/rate of return analysis
We may rewrite the numerator in brackets as follows:
O VS
^-n ^ 77? fVS - cv - cpC]
V-8
Arthur D Little, Inc
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vs [i - cv _ CPC
L VS VS J
For coal mining CV/VS ^ 0.71 (See Table III-l)
VS [1 - 0.71 -
CPC
VS~ is the Unit COSt of a11 incremental pollution control, mine
health and safety, etc.
or d^ # .29 VS - CPC
The pressure point is reached when 6 falls to a critically low value.
The decision to shut down a plant, of course, must not only
weigh the salvage value in comparison with v , the present value cal-
culated above, but also the realistic economic alternatives, and even
non-economic factors.
Our belief is that the realizable salvage values would be some.
fraction of the book value of plant and equipment plus the working
capital associated with a plant, mine, or mines in question (See Chap-
ter III), adding up to a maximum of about 10% of VS. It appears that,
for typical discount rates and mine lives, the pressure point will not
be affected so much by realizable salvage as by management's estimate
of the incremental annual cost of pollution control.
For the smaller mines, the cost of compliance with other re-
cent regulations is significant. For example, we find that the small
V-9
Arthur D Little, Inc
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operator will pay consultants who ensure compliance with the Coal
Mine Health & Safety regulations at a flat rate proportional to the
tons produced. This consultant fee above amounts to about 2-5% of
VS.
2. Capital Spending versus Availability
We believe that the very small coal companies may have diffi-
culty meeting capital requirements for water quality control. For
purposes of this analysis, we have examined companies with fewer than
50 employees, and have assumed a $40,000 minimum requirement for es-
tablishments with acid mine drainage problems to meet the water qual-
ity standards considered for this study.
Based on the 1967 Census, these establishments show the following
pattern of capital expenditure.
V-9a
Arthur D Little, Inc
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Table V-4: Capital Spending Pattern by Mine Segment
with Less than 50 Employees
Average Annual
Value of Shipments Capital Expenditure Average Annual
Employee No. of and Receipts per Dollar Capital Exp.
Range Establishments per Establishment of Shipments per Establishment
0-4
5-9
10-19
20-49
1673
582
636
526
$38,500
$146,000
$264,000
$666,000
0.186
0.183
0.122
0.128
$ 7,160
$26,600
$32,300
$85,400
SOURCE; 1967 U. S. Census of Mineral Industries
Arthur D Little, Inc
v-io
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From the IRS Statistics of Income on Coal Mining, the first
group above may be estimated to have assets of under $50,000, The
second and third groups are estimated to be firms having assets of
from $50,000 to $250,000, and the fourth group, from $250,000 up to
$1 million. Typically, the very small operations report marginal
profitability, or show losses, especially for tax purposes. However,
even adjusting for depreciation and depletion allowances, they are not
considered very profitable. All but the smallest coal mining estab-
lishments appear to utilize a significant amount of long term debt and
the small firms carry a relatively high percentage of short term and
trade credit. On the average, these small firms show little net work-
ing capital.
It seems obvious that the very small coal mining establishments
which are marginal to begin with, will have difficulty financing an
"unproductive" $40,000 investment that raises operating costs. The
credit picture and financial performance of establishments with 50 or
more employees (and perhaps some of the 20 to 49 employee category),
typically with assets of $1 million or more, is such that they are not
likely to be affected as adversely from the capital availability view-
point.
V-ll
Arthur D Little, Inc
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In summary, it may be concluded that:
• while the ratio of water treatment cost to value of shipments
(Table V-3) may be a meaningful indicator of the economic impact
of water pollution control (especially on small independent mines),
it must be evaluated in the context of a specific mine's organi-
zation and ownership, since these factors can influence the extent
to which apparently excessive costs can be internalized, thus
resulting in continued operation of a mine;
• in view of the other "non-productive" demands made on the coal
industry (e.g. Mine Health and Safety Regulations), we believe
that additional water pollution control costs should not exceed
about 10% of the value of shipments, if a mine is to successfully
absorb the economic impact of these added costs;
• we anticipate that the very small mines will experience diffi-
culties in financing water treatment costs. It is in this segment
that we expect a severe impact as a result of water pollution
control.
V-12
Arthur D Little, Inc
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C. PRODUCTION EFFECTS
Irrespective of who absorbs any added effluent water treatment
costs, it is important to view any probable cost effects due to water
treatment costs alone in conjunction with other factors that exert an
impact on coal mining costs. For instance, some of the proposed strip
mining regulations are liable to affect the industry's costs to a
greater extent than would the costs of meeting water quality guidelines
considered for this study. Restrictions on mineable reserves and mine
life, limitations on sulfur content of steam coal, and the more strin-
gent enforcement of mine health and safety laws and future OSHA stan-
dards are expected to have a significant impact on coal production costs.
The impacts of all these costs are generally additive and the decision
to shut down any establishment is made on the basis of all these factors
although any single factor can be "the straw that broke the camel's back."
We believe that those mines in Northern Appalachia (particu-
larly Pennsylvania and West Virginia) producing less than 50,000 tons
of coal per year represent a segment of the industry that would be
particularly sensitive to water effluent regulations and would there-
fore have the highest probability of discontinuing operations. If,
in the absence of a mine-by-mine analysis, it is assumed that this
entire industry segment is forced to close down for one of any variety
of reasons, these would represent less than 157o of the coal production
from these states. The impact of this production loss on the industry
coal output and growth is considered negligible in the long run.
V-13
Arthur D Little, Inc
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D. EMPLOYMENT AND COMMUNITY EFFECTS
To assess the potential adverse impacts on employment, we have
made a county-by-county evaluation of the acid mine drainage conditions
in the bituminous coal regions of Appalachia and North Central U. S.
This was based on Figure 1-3 and other related data. Concurrently, we
determined the total mine employment as a percentage of the population
of each county.
Table V-5 provides a perspective on the areas that are suscep-
tible to acid mine drainage costs and those communities that would
suffer a high impact because a large portion of the population is de-
pendent on coal mining. We assume that a county is heavily dependent
on mining if 4% or more of the county population were involved di-
rectly in coal mining. Thus the combination of high mine drainage
problem areas and high mine employment isolates the areas that have
the maximum sensitivity to the impact of water pollution control
costs. Accordingly, Greene County in Pennsylvania with
a total mine employment of 3,545 is highly sensitive
while the other coal producing counties have a medium sensi-
tivity. In West Virginia, Boone, Barbour, Logan, Marion, Marshall,
McDowell, Monongalia, and Wyoming counties with a cumulative coal
mining employment of 27,797 (59% of survey total), would have a high
probability of being adversely affected.
Arthur D Little, Inc
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TABLE V-5
ACID MINE DRAINAGE SENSITIVITY OF BITUMINOUS COAL
State and County
ALABAMA:
Bibb
Blount
Jackson
Jefferson
Marion
Shelby
Tuscaloosa
Walker
Wins Con
Others
Totals
ILLINOIS:
Chris tian
Douglas
Franklin
Fulton
Gallatin
Jackson
Jefferson
Kankakee
Knox
Maconpin
Mercer
Montgomery
Peoria
Perry
Pope
Randolph
St. Clair
Saline
Stark
Vermillion
Williamson
Totals
INDIANA:
Clay
Fountain
Gibson
Greene
Parke
Pike
Spencer
Sullivan
Vermillion
Vigo
Warwick
Others
Totals
COUNTIES OF APPALACHIA AND NORTH-CENTRAL AMERICA
1970 Total
Coal Production
(000 Tons)
1,046
270
967
9,963
650
568
2,169
4,237
474
219
20,563
4,900
1,140
8,324
5,635
2,898
134
6,395
976
1,528
262
42
2,651
2,875
8,086
12
3,594
7,375
3,457
622
250
3,961
65,117
1,237
W
W
2,748
8
4,285
W
4,569
953
W
7,514
975
Overall
Sensitivity
M
L
L
M
L
M
M
L
L
L
L
L
L
L
H
M
L
L
L
L
L
L
L
L
M
L
L
M
L
L
M
L
L
L
L
L
H
L
L
L
L
L
-
Volume of Acid
Drainage 1000 Gal/Day Employment
N.A. 157
65
105
2,982
154
297
236
1,006
71
"
5,073
N.A. 798
153
1,100
590
700
18
1,226
153
127
102
15
566
292
501
" 11
408
693
845
86
115
758
9,257
N.A. 133
8
163
240
4
517
22
560
48
19
561
it _
Mine Employ as
% of County
Population
1.00%
0.20
0.30
0.30
0.80
1.00
0.20
2.00
0.50
-
2.00%
0.80
3.00
1.20
9.20
0.04
3.79
0.20
0.20
0.20
0.10
1.60
0.15
2.60
0.20
1.30
0.30
3.20
1.00
0.10
1.50
0.70%
0.04
0.50
1.00
0.30
4.00
0.10
2.60
0.20
0.02
0.40
-
Sensitivity
to
Acid MD
H
L
L
H
L
H
H
L
L
-
L
L
L
L
H
H
L
L
L
L
L
L
L
L
H
L
L
H
L
L
H
L
L
L
L
L
H
L
L
L
H
L
L
Total
Number
of
Mines
9
4
3
45
13
6
13
28
5
-
126
1
]
4
A
3
2
3
1
1
]
o
2
3
3
2
3
6
7
1
3
6
59
6
1
1
4
1
9
1
5
1
1
8
-
22,289
2,275
38
V-15
Arthur D Little, Inc.
-------
TABLE V-5 (CONTINUED)
ACID MINE DRAINAGE SENSITIVITY OF BITUMINOUS COAL
COUNTIES OF APPALACHIA AND NORTH-CENTRAL AMERICA
1970 Total
Coal Production Overall Volume of Acid
State and County
KENTUCKY (EAST):
Bell
Boyd
Breathitt
Carter
Clay
Clinton
Floyd
Harlan
Jackson
Johnson
Knott
Knox
Laurel
Lawrence
Lee
Leslie
Let cher
McCreary
Magof fin
Martin
Morgan
Perry
Pike
Pulaski
Rockcastle
Wayne
Whitley
Wolfe
Sub-Totals
KENTUCKY (WEST) :
Butler
Chris t ian
Daviess
Henderson
Hopkins
McLean
Muhlenberg
Ohio
Union
Webs ter
Others
Sub-Totals
Grand Totals
MARYLAND:
Allegany
Garrett
Totals
(000 Tons)
2,803
40
3,356
27
520
168
5,349
9,422
11
2,196
3,718
795
176
286
27
2,322
8,119
479
714
1,612
21
8,175
21,299
84
14
53
704
10
75,500
228
170
804
93
12,533
94
25,903
7,269
4,620
1,089
2,379
55,182
127,682
412
1,203
1,615
Sensitivity Drainage 1000 Gal/Day
L N.A.
M "
M "
M
L
L
H
M
L "
M "
H "
L
L
L "
L "
M "
H
L "
M "
M
M
M "
H "
L "
L "
L
L
M "
-
L N.A.
L "
L "
L
M "
L
M
L
L "
L "
"
L N.A.
L "
Employment
755
20
329
19
210
51
1,994
2,626
9
389
1,113
347
85
55
26
1,054
2,406
223
97
380
14
1,798
5,914
63
8
11
462
6
20,464
55
39
91
68
2,014
28
2,112
636
61
135
N.A.
5,239
25,703
123
234
357
Mine Employ as
% of County
Population
2.10%
0.04
2.10
0.10
1.00
0.60
4.80
5.10
0.08
1.90
6.40
1.40
0.30
0.50
0.30
9.70
8.00
1.80
0.90
3.70
0.10
5.10
17.00
0.20
0.10
0.10
1.80
0.10
0.60%
0.07
0.10
0.20
5.20
0.30
7.60
3.60
0.40
1.00
N.A.
0.15%
1.10
Sensitivity
to
Acid MD
L
H
H
H
L
L
H
L
L
H
H
L
L
L
L
L
H
'-
H
H
H
L
H
L
L
L
L
H
L
L
L
L
L
L
L
L
L
L
-
L
L
Total
Xuiiber
of
'lines
60
5
2°
4
37
5
176
141
2
51
97
48
14
10
2
56
1S9
8
6
15
5
12 '
496
9
3
3
43
1
1 ,623
6
4
1
3
35
3
27
14
4
1
_^L
98
1,721
20
-M
50
V-16
Arthur D Little, Inc.
-------
State and County
OHIO:
Athens
Belmont
Carroll
Columbiana
Coshocton
Callia
Guernsey
Harrison
Hocking
Holmes
Jackson
Jefferson
Lawrence
Mahoning
Meigs
Monroe
Morgan
Muskingum
Noble
Perrv
Stark
Tuscaranas
Vinton
Washings ton
Wayne
Others
Totals
PENNSYLVANIA:
Allegheny
Armstrong
Beaver
Bedford
Butler
Cambria
Centre
Clarion
Clearfield
Clinton
Ilk
Favette
Greene
Indiana
Jefferson
Lawrence
Lycoming
Mercer
Somerset
Tioga
Venango
Washington
Westmoreland
Others
Totals
TABLE V-5 (CONTINUED)
ACID MINE DRAINAGE SENSITIVITY OF BITUMINOUS COAL
COUNTIES OF APPALACHIA AND NORTH-CENTRAL AMERICA
1970 Total
Coal Production
(000 Tons)
56
14,572
503
1,239
2,865
218
48
12,575
165
372
968
5,122
325
448
13
W
4,437
743
2,533
3,731
339
2,167
605
_
40
1,267
55,351
4,642
7,795
219
19
1,984
6,559
1,342
4,383
5,879
451
402
1,825
11,586
8,389
1,663
883
99
226
3,743
885
477
14,464
2,610
245
80,770
Overall
Sensitivity
M
M
L
M
L
M
L
H
L
L
L
M
L
L
M
M
M
L
M
L
L
L
L
M
L
_
M
M
M
M
M
M
M
M
M
M
M
M
H
H
M
M
M
M
M
M
M
M
M
-
Volume of Acid
Drainage 1000 Gal /Day
N.A.
"
"
"
"
"
ir
rr
"
11
"
II
n
II
"
"
11
"
II
"
"
"
"
n
"
II
106,445
35,094
_
1,670
7,877
69,199
6,336
1,930
24,192
432
1,404
2,880
338
115,080
4,514
144
288
_
10,440
288
-
27,330
33,916
1,087
450,884
Employment
14
2,461
80
347
293
41
14
2,585
31
61
186
831
58
81
12
296
393
147
152
536
67
460
83
27
4
-
9,260
1,337
1,783
70
13
477
3,088
286
494
1,378
71
69
864
3,545
2,506
329
163
10
18
1,047
114
69
5,053
764
N.A.
23,548
Mine Employ as
% of County
Pqpula t 1 on
0.01%
3.00
0.30
0.30
1.00
0.20
0.03
14.50
0.20
0.30
0.06
0.10
0.10
0.03
0.05
2.00
3.00
0.20
1.50
2.00
0.02
0.60
I. 00
0.50
0.005
-
0.80%
2.20
0.03
0.03
0.40
1.50
0.40
1.30
1.70
0.20
0.20
0.50
9.00
3.30
0.70
0.10
0.01
0.01
1.35
0.31
0.10
2.30
0.20
-
Sensitivity
to
Acid MD
H
H
L
H
L
H
L
H
L
L
L
h
L
L
H
H
H
L
H
I
L
L
L
H
L
-
H
H
H
H
H
H
a
H
H
H
H
H
h
H
H
H
H
H
H
H
H
H
H
-
lotal
Number
of
Nines
5
36
-4
38
11
7
-
23
7
j
19
35
5
9
3
1
2
12
b
JJ
y
3b
8
0
1
-
307
23
73
7
6
36
51
22
63
101
6
18
35
26
74
70
23
3
3
89
8
10
31
29
-
807
V-17
Arthur DLittleJnc
-------
TABLE V-5 (CONTINUED)
ACID MINE DRAINAGE SENSITIVITY OF BITUMINOUS COAL
State and County
TENNESSEE:
Anderson
Campbell
Claiborne
Cumberland
Fentress
Grundy
Hamilton
Marlon
Morgan
Putnam
Scott
Sequatchie
Van Buren
Others
Totals
VIRGINIA:
Buchanan
Dickenson
Lee
Montgomery
Russell
Scott
Tazewell
Wise
Others
Totals
WEST VIRGINIA:
Barbour
Boone
Brooke
Clay
Fayette
Cllmer
Grant
Greenbrier
Hancock
Harrison
Kanawha
Lewis
Logan
Marion
Marshall
Mason
McDowell
Mercer
Mineral
Mingo
Monongalia
Nicholas
Ohio
Pocahontas
Preston
Raleigh
Randolph
Summers
Taylor
Tucker
Upshur
Wayne
Webster
Wyoming
Others
Totals
1970 Total
Coal Production
(000 Tons)
1,813
1,591
1,922
5
43
134
17
745
434
80
605
298
400
137
8,224
14,825
7,147
1,127
w
2,333
W
1,115
8,466
13
35,026
3,612
12,212
995
W
4,700
93
2,422
478
W
7,190
11,724
333
12,682
9,294
5,162
646
17,146
1,159
363
2,225
12,827
7,277
W
40
3,019
10,426
649
21
225
300
870
105
254
12,969
2,700
144,118
COUNTIES OF
Overall
Sensitivity
M
M
M
M
M
L
L
L
M
L
M
L
L
-
H
H
M
L
M
L
M
H
-
H
H
M
L
L
L
M
L
L
M
M
L
H
H
H
L
H
L
L
M
H
M
M
L
M
M
L
L
M
L
L
M
L
H
-
APPALACHIA AND NORTH-CENTRAL AMERICA
Volume of Acid
Drainage 1000 Gal/Day Employment
N.A. 429
317
461
7
32
29
" 11
" 236
78
28
171
116
74
"
1,989
5,222
1,875
303
5
784
9
352
" 2,070
"
10,620
N.A. 922
3,665
" 267
205
" 1,692
53
573
241
13
1,588
3,183
59
3,779
2,697
1,642
434
7,101
529
81
943
2,870
3,012
794
11 26
" 393
4,017
" 288
10
74
64
292
143
183
" 5,121
"
46,954
Mine Employ as
% of County
Population
0.70%
1.10
2.40
0.04
0.20
0.20
0.005
0.90
0.05
0.10
1.10
2.00
2.00
-
14.20%
9.30
1.20
0.01
3.00
0.03
0.78
4.74
-
6.00%
12.80
1.00
1.80
2.70
0.70
6.90
0.70
0.03
2.00
1.30
0.03
6.20
4.20
4.30
1.80
10.00
0.80
0.40
2.40
5.20
11.90
1.20
0.20
1.50
5.20
1.00
0.07
0.50
0.80
1.60%
0.30
1.30
14.70
-
Total
Sensitivity Xutiber
to ot
Acid MD Mines
N.A. = Not Available
W = Withheld by USBM
L = Low "1
M = Medium I- Sensitivity
H = High J
46
42
15
3
3
1
3
2 7
18
1
485
87
133
803
H
H
H
L
L
L
L
L
L
H
H
L
H
H
H
L
H
L
L
H
H
L
H
L
H
L
L
L
H
L
L
H
L
H
53
104
12
3
59
5
11
19
11
59
82
12
85
14
5
3
196
17
13
58
38
90
2
3
69
100
18
2
9
4
20
5
16
132
1,329
SOURCE: 1970 Minerals Yearbook
ADL Estimates
Pennsylvania Department of Health
City and County Yearbook
¥18
Arthur D Little, Ir
-------
Overall, the counties shown in Table V-6 in the bituminous coal pro-
ducing states are susceptible to a major adverse employment and community im-
pact. In the absence of a detailed breakdown relating sensitivity to mine
size, we show in Table V-7 the number and 1970 coal production of the small
mines which we believe constitute the most sensitive sector of the industry,
as well as the industry productivity in the various states.
It is unfortunate that many of these counties which are susceptible
to mine shut down are the same counties which have in the past been effected
by high unemployment and declining economy. Many attempts have been made
by both the Federal and various state governments to either attract other in-
dustry into the area or relocate more people to other areas, but to no avail.
It seems that the problems still exist and may even get aggravated further.
E. BALANCE OF PAYMENTS EFFECTS
We do not expect possible increases in coal production costs due to
enforcement of mine effluent quality standard to exert any noticeable effect
on the United States balance-of payments position. A high proportion of the
exported coal tonnage consists of low-sulfur metallurgical coal consumed by
steel producers in Canada, Japan, South America and Western Europe. Because
of its high quality and competitive price, we conclude that this market would
be unaffected in the short term. The major impact on metallurgical coal
consumption in the long term (and therefore on export markets) will be from
the development of substitutes — either from non-coking coals or other
fossil fuels.
If metallurgical coal sources in Appalachia are adversely
affected by these standards, any export production curtailment would probably
be made up by increased production from the Western mines. As a matter
of fact, this trend in favor of the Western mines is already noticeable.
The other reason for our conclusion is that metallurgical ccal
enjoys a higher value than steam coal and is, therefore, bf;Cter suited to
V-19
Arthur D Little, Inc
-------
TABLE V-6: AREAS AND COMMUNITIES WITH MAXIMUM SENSITIVITY TO WATER
POLLUTION
STATE
Illinois
Indiana
Kentucky
Pennsylvania
West Virginia
Virginia
CONTROL COSTS.
COUNTY
Gallatin
Pike
Floyd
Knott
Letcher
Pike
Greene
Barbour
Boone
Logan
Marion
Marshall
McDowell
Monongalia
Wyoming
Buchanan
Dickenson
Wise
COAL MINE EMPLOYMENT
700
517
1,994
1,113
2,406
5,914
3,545
922
3,665
3,779
2,697
1,642
7,101
2,870
5,121
5,222
1,875
2,070
Total
53,153
V-20
Arthur D Little, Inc
-------
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V-21
Arthur D Little, Inc
-------
absorb any additional costs due to waste water treatment. It should be
noted that because of the inelasticity of demand, one should expect an
increase in foreign exchange earnings when the price increases as a
result of a full pass on. This is a second order effect and cannot be
quantified within the limits of this analysis.
V-22
Arthur D Little, Inc
-------
VI. LIMITS OF THE ANALYSIS
A. GENERAL
In undertaking an analysis of the impact of pending pollution
regulations on natural resource-based industries, one must face
immediately the problem of lack of similarity of operations. No two
mines are alike, even if they produce the same mineral commodity. Unlike
manufacturing facilities, it is difficult to identify a norm or the
typical mine, and from there determine the deviations that can occur.
Modeling of this sort could quickly lead to erroneous conclusions.
A proper analysis of impact of regulations should be done on a
mine-by-mine basis. However, time and money constraints do not allow
this type of analysis to be made. On the other hand, an analysis of
an industry sector, such as several mines with obvious common charac-
teristics, could tend to allow the investigator to determine the areas
where extreme sensitivity to regulation may occur, and in turn potential
areas of high impact.
This is the approach that was taken in this study. We believe
the analysis to be accurate for the mines or operations that were
analyzed individually. Extrapolation to other mines would have a lower
degree of confidence. Our sample of the coal industry was quite narrow
(less than 0.5% of the total number of mines), because EPA was unable to
furnish information on effluent quality and volumes from individual mines
and because of budget and time constraints.
Arthur D Little, Inc
-------
Of this limited sample, we find that one mine will be seriously affected
with eventual termination of operations.
Turning to EPA's effluent guidelines and associated costs supplied to
us by the EPA, we find that there is a serious question regarding the
effluent guidelines viz. can the guidelines for suspended solids
be met without filtration in some cases. If filtration is necessary,
higher costs might be incurred than assumed for this study, and result
in a greater impact on the coal industry. This is an area that must be
analyzed further. Another example of variability is the fact that for
a general cost analysis, we assumed a 10-year life for water pollution
control equipment. In specific instances involving the small operators,
mine life is much shorter than this and all of the pollution control
equipment is not salvagable. We also believe that the suggested EPA
sampling schedule will have an adverse impact on the small operator.
In making our analysis, we were required to assume that the coal
mining industry is subject to impact by pending water pollution legislation
only. However, we do recognize the additional (or concurrent) impact of
the coal mine health and safety program and its more rigorous enforcement
in the future, black lung benefits, future OSHA standards, the air
pollution legislation and other regulations that affect the value of coal,
and how these contribute to the decision-makers' problems in determining
whether or not a mine stays open or closes. For example, recent estimates
of incremental cost resulting from the coal mine health and safety act alone
vary from $0.91 to $2.15 per ton (Mining Engineering, Oct. 1972).
VI-2
Arthur D Little, Inc
-------
Another problem which arises deals with the enforceability of the
legislation. It is known that the degree of enforcement varies widely,
from region to region. Since many coal mining operations are family
enterprises, the degree of enforcement will vary widely. Thus, the
probable impact could be questionable. An analysis of enforceability
may be a very important input to the overall impact study of this
industry.
If adequate data on effluent volumes from mines, both underground
and strip, were available, an overall impact of the pending water control
legislation could have been evaluated and the impact translated to the
U. S. economy and the energy situation that presently exists. Further,
such a study would focus on the most sensitive regional situations and the
effect on these localities.
VI-3
Arthur D Little, Inc
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APPENDIX A
DESCRIPTION OF THE COAL MINING INDUSTRY
Arthur D Little, Inc
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PREFACE
In accordance with our scope of work, we provide here a
description of the industry to provide the background information
necessary for understanding the main body of the report. Because of
its requirements, EPA requested that this background information be
provided in the following standardized format to the extent possible.
A. Demand
1. Product(s) and substitute product(s)
2. Size, location and relative importance of markets
(including international markets).
3. Distribution system.
4. Recent market trends (i.e., price and volume by,
product).
5. Government influence on market (e.g., Federal
Government is major customer).
B. Supply
1. Industry structure
a. Outline of production process
b. Type and location of raw materials
c. Number and location of firms, plants
d. Type of firms
—large/small
--integrated/non-Integrated
—multiplant/single plant
—multiproduct/single product
—diversified/non-diversified
—stage in production process
e. Types of plants
—large/ small
—new/old
—high technology/low technology
—efficient/inefficient
—stage in production process
f. Number of employees and skill levels
Arthur D Little, b
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g. Significant recent trends
2. Financial structure and trends
a. Prices
b. Sales
c. Costs - fixed, variable
d. Profits
3. Current industry capacity and capacity utilization
and recent trends.
4. Current degree of competition and competitive
practices (including impact of foreign competition)
and recent trends.
5. Current government influence on supply (e.g., quotas,
subsidies) and recent trends.
Ml
Arthur D Little Inc
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A. DEMAND
1. Competitive Energy Sources
The economic and industrial growth of the United States has
been largely based on its energy and mineral resources. Of these, coal
constitutes a very basic resource, since it is the principal energy
source for generating the large amounts of low-cost electric power
needed by most industrial activities. The demand for coal is a derived
demand. It is derived from the demand for electricitv, for heat and
for a multitude of other goods and services. The total demand for coal
Is a part of the complex demand for energy of all types with its sub-
stitution effects among coal, gas, oil and nuclear energy plus legisla-
tion on pollution limits, coal quality limits, transportation factors
etc.
Figure A-l depicts the relative proportions of the energy
consumption of the United States supplied by the major sources in 1950
and 1970, as well as the projected supply pattern for 1990. While the
percentage share of the energy market supplied by coal declined from
over 40% in 1950 to just 207, in 1970, projections for 1990 call for coal
to hold its own in the next two decades. The gains predicted for
nuclear energy will be made largely at the expense of natural gas.
The importance of coal as an energ" source takes on added
importance when viewed through the eyes of the power generation
industry. As shown in Figure A-2, coal accounted for nearly two thirds
of this industry's total fuel demand in 1970. While the proportion of
the utility industry's fuel demand supplied by coal might decline after
1990, primarily because of the impact of nuclear power generation, we
believe that coal consumption will steadily increase in absolute terms.
The costs of nuclear power have been higher than predicted, and the
construction program is many years behind schedule as a result of
rising concern about the environmental impact of nuclear power plants.
2. >farkets
A discussion of the markets for coal must recognize a
difference between the market sectors for metallurgical coal and that
for steam coal. The demand for metallurgical coal is characteristically
inelastic in the short run with respect to price and may in fact remain
so in the long run. Substitution of alternate coals or fuels would
occur when mechanically suitable chars can be produced from non-coking
coals and if alternative fuel costs become favorable. Where coal is
A1
Arthur D Little, Inc
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c
0>
a
<0
3
.a
o
80
60
40
20
Share %
74
1950
1970
1990
32
Coal
Gas
16
p r-;,i""v
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./
s '
Oil
1950
1970
1990
465
350
230
c
o
116
Source: Chem. Eng., Oct. 30, 1972
'includes geothermal energy
FIGURE A-1 DISTRIBUTION OF U.S. ENERGY DEMAND BY
SOURCE FOR 1950-1970, AND PROJECTED
1990 PATTERN
A2
Arthur D Little, I
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3000
2500
1970
1975
1980
1985
1990
F.GURE A-2 UN.TED STATES ELECTR.C UT.L.TY FUEL DEMAND, 1970-1990
Source: Arthur D. Little, Inc.
A3
Arthur D Little Inc
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clearly the cheapest available fuel, the demand for steam coal is
similarly inelastic. Generally, however, the demand function is com-
plex and dependent to a high degree on interfuel competition i.e. the
cost of fuel oil or natural gas to a major consumer.
Table A-l is a breakdown of the coal markets for the
principal coal-producing states. Included also are the sulfur contents
of the coals shipped to the various markets, since this parameter
determines in part the most advantageous market for each coal product.
Figure A-3, a graph of bituminous coal production and con-
sumption statistics from 1962 to 1971, includes a breakdown of con-
sumption tonnages by industries or markets. The electrical utility
industry is by far the largest and fastest growing market for coal,
accounting in 1971 for about 58% of the total consumption. The intake
by the steel industry has remained virtually constant with time,
despite large increases in steel tonnage output; this is a consequence
of improvements in blast furnace technology, which have reduced coke
consumption rates. The development of supplementary fuel oil and gas
injection has lowered the coke consumption still further.
Following World War II, bituminous coal exports became an
important item of U.S. foreign trade, contributing significantly to the
international balance of payments. Table A-2 shows the trends in coal
export and import for a selection of years between 1950 and 1970.
Exports fluctuated widely prior to 1961 because of various emergencies
abroad; the lack of any major fuel shortages since then has enabled
exports to increase steadily. Because of its high quality and com-
petitive price relative to locally mined coal, we believe that U.S.
metallurgical coal will continue to enjoy a favorable market, especially
in Canada, Japan, and Western Europe. The recent trend is increasing
export of western metallurgical coals to Japan at the expense of
eastern coals.
In 1970, the United States exported 70.9 million tons of coal,
an increase of 14.7 million tons over the corresponding 1969 figure.
The increased demand for U.S. coal stemmed from an unprecedented rise
in world steel production, a depletion of large coal stockpiles, and a
reduction in coal mining capacity abroad. The total revenue earned from
coal export in 1970 was $91 million, representing 2.3% of the total
national export value.
Nearly 96% of the exported tonnage uent to Canada, Japan, and
Europe, and the bulk of the remainder rent to Brazil and Chile. Ship-
ments to the Iron Curtain countries amounted to 466,000 tons, all
destined for East Oerraany and Romania. Exports to these Eastern T'lor
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FIGURE A-3 1962-1971 PATTERNS OF COAL PRODUCTION AND
CONSUMPTION IN THE UNITED STATES
Arthur D Little, Inc
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TABLE A-2
TRENDS IN U. S. FOREIGN TRADE IN COAL
1950 - 1970
Year
1950
1957
1960
1965
1968
1970
Total Exports'
(106 tons)
25.5
76.5
36.5
50.2
50.6
70.9
Total Imports
(103 tons)
346.7
366.5
260.5
184.4
224.4
36.4
Excludes shipments to U. S. military forces
Source; Bituminous Coal Data, 1971 Edition,
National Coal Association
A8
Arthur D Little, In(
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countries totaled 159,000 tons in 1969. Imports, as shown in Table
A-2, have steadily declined since 1964 and totaled only 36,400 tons in
1970, a mere 0.007% of the yearly domestic consumption.
3. Distribution System
Recent trends in the modes of coal distribution are shoT/n in
Table A-3. It should be pointed out that, except for metallurgical
coal which can, because of its relatively high value, travel long
distances, there is no "national" market for coal. Steam coal is
generally produced and consumed within a specific geographical region.
The average haul is between 290 and 430 miles. An exception has been
the growing tendency for Western low-sulfur coal to be transported to
Mid-Western generating stations. Thus the competitive reach of
Western coals is stretching to Chicago, St. Paul, Oklahoma, and Texas.
Coal transportation is dominated by the railroads, handling
about 73% of all bituminous coal and lignite. In fact, coal provides
the backbone of the operations of the nation's railroads, contributing
25% of railroad tonnage and 10% of the total revenues.
Figure A-4 illustrates the relative costs of transporting
coal by the alternative modes. Railroad rates have been declining
since 1958 and this decline is expected to continue. Contributing in
no small measure to this decline is the development of unit-trains in
the early 1960's, as well as the design and development of storage and
materials handling systems which have resulted in lower car turnaround
times and manpower requirements.
Recent pressures on electrical utility plants to curtail the
level of SOX emissions by using low sulfur fuels has affected the con-
sumption of eastern high sulfur steam coal and has led to a reduction
in coal tonnages delivered by some of the major Eastern railroads which
had dominated coal transportation in the past. Adverse impacts on
profits have been felt by such lines as the Delaware and Hudson, the
Baltimore and Ohio, and the Western Maryland rail-lines. On the other
hand, Mid-Western and Western lines have reaped the benefits of the
increasing tonnages of coal that move eastward from the low-sulfur
reserves of the West. Thus the Southern, the Seaboard Coast Line,
and the Illinois Central Gulf have all shown recent impressive
growths attributable to their rising coal hauls.
Other coal transportation modes have also witnessed important
changes in recent years. Tow boats have increased in size, thereby
increasing the basic tow and reducing overall costs.
Other factors which offer opportunities for more favorable
delivered prices of coal and of coal-generated energy are the adapta-
bility of coal to transmission by coal-slurry pipelines, and the
development of extra-high-voltage transmission of electricity over long
A9
Arthur D Little, Inc
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TABLE A-3
TREND IN MODES OF
COAL SHIPMENT
(million tons)
Load at Mine
For Shipment By
Year
1965
1966
1967
1968
1969
1970
Rail
371.
387.
404.
396.
397.
409.
Water
5
0
5
4
9
1
60
62
67
66
71
81
.3
.1
.0
.9
.0
.3
Trucked to
Final Destination
68
67
62
61
66
74
.3
.0
.0
.8
.0
.0
Used at
Mine
12
17
19
20
25
4
.0
.8
.1
.2
.6
.1
Total
Shipment
512.1
533
552
545
560
602
.9
.6
.2
.5
.9
1
Total shipment includes coal consumed at mine-mouth
generating plants.
Source; Bituminous Coal Data, 1971 Edition,
National Coal Association
A-10
Arthur D Little; I
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18
16
14
12
10
8
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distances from coal-fired power plants in or relatively close to
indigenous coal producing areas.
4. Recent Market Trends
As was shown in Figure A-3, the general trend in coal produc-
tion has been upward, except in 1968, when labor disputes caused it to
drop. This factor again played an important role in the 1971 dip, along
with the general slowdown in the free world economy and the implenenta-
tion of stringent air pollution control and mine safety regulations.
The 1970 and projected 1980 data on consumption are shown in
Table A- according to end use. While the coal demand of the electric
utilities industry is expected to remain strong, the use of high sulfur
eastern steam coal will be limited by EPA regulations, at least in the
short term until SOX control processes are widely adopted at power
plants. Also, the EPA regulations will accelerate the trend towards
substituting imported low or medium sulfur fuel oil for local coal,
which was started many years ago on the East Coast and is now spreading
to the Midwest. The ferrous metallurgical coal requirements should
increase only modestly as coke rates per ton of blast furnace iron
decrease and as supplementary injection of low-sulfur oil becomes more
universally adopted. Industrial demand is expected to remain stable,
while the shrinking residential and commercial market is expected to
remain fixed at about 12 million tons. Overall, however, the cumula-
tive demand for coal should remain strong, and its average price should
slowly rise, reflecting increases in costs of operation and capital
installations. A major new market is represented by coal gasification
and coal liquification processes that are currently being developed
under public and private sponsorship. This new market is not expected
to amount to much before 1980.
5. Government Influence
In addition to the various Federal government programs aimed
at ensuring the future availability of coal at reasonable costs,
developing new uses for coal, expanding exports, and providing funda-
mental information on resources and availabilities, the thrust of
recent government activity has been directed toward preserving or
restoring the environmental quality of mined land and health and safety
in mining. These activities have been spurred on by increasing public
concern over the environmental deterioration due to mining operations,
particularly strip mining.
• As of November 1972, the Federal government had no regulatory role
in the conduct of strip mining. However, one bill, - HR 6482 - was
passed by the House in early October. Among other provisions, it
would prohibit contour mining on all slopes exceeding 20°. It
would also require all coal operators to obtain mining permits of
one-year duration which are renewable after reviex? by state and/or
A12
Arthur D Little, ln(
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TABLE A-4
U. S. COAL CONSUMPTION BY USE
(millions of short tons)
1970 1980
Electric Utilities 320 525
Metallurgical Coal 102 120
Industrial 84 84
Residential and Commercial 12 12
Total 518 741
Sources: Bureau of Mines for 1970 actual; 1971 National
Petroleum Council Energy Forecast, and Arthur D.
Little, Inc. estimates for 1980.
A 13
Arthur D Little, (nc
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federal authority. It also would establish a $100 million federal
fund to assist in reclaiming previously stripped land. A Senate
bill, - S 630, that would cover strip mining of all minerals could
not be passed before the adjournment of the 92nd Congress. The
chances are good that a bill to regulate strip mining will be
reintroduced when the new Congress meets.
• The Federal Coal Mine Health and Safety Act of 1969 was passed to
reduce the hazards of underground coal mining. Among other things,
it seeks to ensure adequate environmental and coal face ventilation
underground, ensure proper cleaning and rock dusting practices, pro-
vide adequate roof support, limit the rate of advance of continuous
miners in order to keep the operator under boltod roof, and regulate
the specifications on underground mining ecmipment. Coal opera-
tors report production cost increases due to this law of about 257,
ranging from an average low of $0.91 for continuous captive nines to
a high of $2.15 for conventional captive nines (rining Engineering,
Oct. 1972)
• The regulatory activities of the Interstate Connerce Conmission,
especially as they apply to railroad freight rate, influence the
market for coal. The delivered price of coal is composed of the
f.o.b. mine price and the cost of transportation from the nine to
the consumer. Transportation costs currentl^ represent about 40%
of the delivered price of coal, and are thus significant in
determining the competitive posture of coal viz-a-viz the other fuel
sources. It is apparent that further escalations in transportation
costs would make fuel substitution much more attractive to present
coal consumers.
• Similarly, the activities of the Federal Power Commission relating
to energy rates and the value of imported foreign energy sources
exert a direct impact on the coal markets. In 1970, fuel imports
added $2.7 billion to the U.S. balance-of-payments deficit and a
figure of in excess of $15 billion is projected for 1980 if current
trends persist. Such deficits are obviously intolerable and efforts
to establish substitute domestic sources, preferably based on coal,
are beginning to gain momentum.
• The Environmental Protection Agency's standards limiting the sulfur
content of utility boiler fuels affect the competitive ability of
eastern coals as well as the domestic development pattern of coal
resources. As sulfur emission standards become more stringent,
there would be a tendency for low-sulfur oil and gas to substitute
for high-sulfur coal in those instances xrfiere the economics and
availability warrant it. Furthermore, exploitation of the low-sulfur
reserves of the Western United States becomes increasingly
attractive.
• There are several other regulatory pressures exerted on the coal
A 14
Arthur D Little In<
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industry by State and Federal Agencies. Examples are regulations
relating to backfilling of top soil and overburden in strip mines,
coal left in place to prevent water seepage from adjoining under-
ground mines, etc. These pressures generally result in increased
operating costs and/or a loss of reserves and decreased mine life.
B. SUPPLY
1. Industry Structure
a. Production Processes
The particular mining technique adopted for a given coal bed
is determined to a large degree by a combination of factors including
the seam topography and physical characteristics (thickness, depth
below the surface), which in turn influence to some degree the economics
of mine production. Seams may vary in thickness from less than a foot
to as much as 100 feet, although for economic reasons, only those seams
thicker than about 30 inches are commercially exploitable at present.
In addition, current technology of coal extraction limits the maximum
depth of exploitable reserves to no more than about 3000 feet below the
surface.
Three primary mining techniques and combinations thereof are
currently practiced: strip mining, underground mining, and auger
mining. These are further described below, and their respective per-
centage contributions to the national bituminous coal output are shown
in Figure A-5.
(a) Strip Mining. Strip mining has increased in popularity
since World War I because it enjoys certain characteristic advantages
such as higher output per man-shift (resulting in lower production cost
per ton of strip coal), lower requirement of generally scarce labor,
and perhaps a faster return on investment. However, stripping is not
universally applicable to all coal seams. To qualify, a seam must be
located relatively close to the surface, with an overburden of no more
than 100 to 125 feet. In practice, the overburden is first removed
using scrapers, bulldozers, or mechanically-operated shovels. The coal
is scooped up by pox^er shovels and loaded into trucks. The productivity
of strip mines has been about 36 tons per man-day over the last three
years. A large strip mine requires an investment of between $4.00 and
$12.00 per annual ton on productive capacity.
(b) Auger Mining. This method derives its name from the fact
that a large auger is employed as a cutting head, along with a tube and
screw for coal transportation. Auger mining is a relatively recent
introduction to the coal industry and is used mostly in the eastern
states where coal is extracted from the rough terrain of the
Appalachian Region. It possesses advantages where the overburden is
too great for strip mining. The mechanism is unitized so that the
A 15
Arthur D Little, fnc
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Arthur D Little Inc
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coal-removing system is extensible as the cutter penetrates the coal
seam. The auger, generally operated from an outcrop location, is
mounted on movable frames and can bore holes over 200 feet deep. The
coal falls from the auger into a conveyor and is elevated into a truck.
Like conventional strip mining, auger mining enjoys a high productivity,
with the average figures for 1969 and 1970 being respectively 39.9 and
34.3 tons per man-day.
(c) Underground Fining. Underground raining may be further
categroized into two broad types which have been employed in the
United States: room-and-pillar mining, and longwall mining. The
roon-and-pillar method is in more common use, accounting for about 90%
of present underground mining; however, the lon^al! technique,
originally developed in Europe, has been registering definite rains in
recent years, primarily because it offers increased nine safety and
productive capacity.
In roon-and-pillar mining, entries into the coal bodv serve as
.haulage ways and fan out into the coal bed vl.th side or cross entries
fron which the coal is removed to forn roons. As nuch as 50% of the
coal is left to support the roof. In the longwall method, a continuous
mining face is maintained in the coal seam. After nininp,, the. roof is
permitted to settle, 30 to 50 feet from the nine working face. Waste
rock is used to support the roof and for maintenance of haulage
roadways.
Perhaps the most significant mechanical accomplishment in
underground mining has been the advent of multi-purpose machines
known as continuous miners. These combine in a single unit the actions
of dislodging the coal from the solid seam and loading it into some unit
of a transportation system. In effect, they combine the separate steps
of cutting, drilling, blasting, and loading.
The rapid rate of coal extraction in continuous mining makes
it imperative that haulage be synchronized with extraction and loading
operations. Among recent innovations aimed at accomplishing this
objective is the development of short belt conveyor systems to move
coal from continuous mining machines to the main haulage system without
the use of shuttle cars.
The capital investment for a large (over one million tons per
year) underground mine in deep overburden ranges from about $3.50 to
$15.00 per annual ton of production, and can vary outside this
range depending on specific conditions.
(d) Cleaning Process. The objective of coal cleaning is to
remove solid foreign matter, such as rock and slate, from the coal prior
to its use. The advantages thus derived are a reduction in ash and
sulfur content, control of ash fusibility, increase in calorific value,
and improvement of coking properties. The need to clean coal prior to
A 17
Arthur D Little, Inc
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shipment has resulted from factors such as the adoption of mechanized
mining, which does not differentiate between coal and impurities, and
the imposition of stringent quality specifications by consumers, who
are increasingly conscious of environmental pollution due to coal
combustion.
The proportion of U.S. coal production subjected to some form of
mechanical cleaning increased rapidly from about 22% in 1940 to a
high of about 67% in 1961. Since 1961, this figure dropped, partlv
because of the increasing production of Western coal, which requires
little if any cleaning. About 54% of all U.S. coal underwent mechani-
cal cleaning in 1970, which amounted to a total of 325.5 million tons.
Of this, 305.6 million tons were treated by wet methods and therefore
involved the consumption of some process water.
Mechanical cleaning of coal is possible because of the
difference in specific gravity between the free impurities (density
between about 1.7 and 4.9) and coal, which has a density of about 1.3.
Generally, cleaning processes can be classified as either gravity-based
stratification or non-gravity processes. Included in the former
category are wet processes such as launder washers, jigs, classifiers,
and tables; the non-gravity category includes the heavy-media methods
(in air or water) as well as froth flotation.
The principles of some of the more important types of cleaning
processes currently in use are briefly reviewed below.
• Jigs - Jigging is one of the oldest ways to wash coal and is still
the most universal method. It is essentially a special form of
hindered settling which stratifies the particles into layers of
different densities. Jigs can handle closely sized feeds as well as
mixed sizes through a wide range of specific gravities. About 46%
of all coals cleaned by wet methods in the United States in 1970
were treated in jigs.
• Launders - The launder washer operates on the principle of flowing
current concentration and hindered settling. The launder consists
of a long, sloping trough with discharge boxes located at intervals
along the trough bottom. Coal and flush water are fed at the high
end, and the heavy-gravity material is withdrawn through the
discharge boxes. Launders are capable of cleaning coal of practi-
cally any size. Their capacity varies with the width of the launder
and size of the coal feed.
• Tables - In 1970, tables accounted for about 14% of the wet-cleaned
coal in the United States. Of the various coal-cleaning processes
that are based on the principle of gravity concentration, the
tabling process is unique in that it is especially adapted to the
treatment of the fine rather than the coarse coal sizes. The only
tables of importance in the coal industry are riffled shaking tables,
A 18
Arthur D Little, Ir
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in which a deck that is inclined slightly from the horizontal is
shaken with an asymmetrical motion in the direction of the long axis.
The coal travels across the deck at right angles, while the refuse
travels essentially parallel to the motion. Wash water flows over
the table at right angles to the direction of the motion.
• Heavy Media Process - In this process, coal is separated from its
associated impurities by a suspension of finely divided solids in
water, aqueous solutions of inorganic salts, and organic liquids.
The separating medium is adjusted to achieve a predetermined
gravity of separation, so that clean coal will float in it and
the heavier refuse materials will sink. At present, finely ground
magnetite is used almost exclusively as the medium, because it is
easily recovered and cleaned by magnetic methods. Furthermore,
varying gravities can be obtained merely by mixing with water.
Cleaning coal by a heavy media process involves feeding crushed and
screened coal into a vessel containing a suspension of the magnetite
medium at the desired specific gravity. The coal floats and is
continuously removed, while the refuse particles sink and are also
removed. The popularity of this process is underscored by the fact
that it was used for 35% of all wet-processed coal in the United
States in 1970.
• Froth Floatation - This is a process for separating fine materials
from their associated impurities by having one constituent adhere
to air or oil and rise to the surface. The theory is based on the
fact that an air bubble will become attached to small particles and
carry them with it as it rises to the surface. In coal processing,
the optimum particle size for froth flotation is approximately 48
mesh. The cleaning process involves the agitation of raw fine coal
with a suitable amount of water and a small quantity of reagents.
The reagents selectively form a water-repellent coating on the coal
particles, so that they adhere to the air bubbles and float to the
surface, where they are easily removed. While froth flotation of
coal has experienced a steady growth since 1900 (accounting for
3.5% of all U.S. wet-cleaned coal in 1970), its application has been
limited to production of very high quality metallurgical coals.
However, it also has potential for removing pyritic sulfur from
finely ground coal, and its use for this purpose can be expected to
increase.
We estimate that about 80% of the wet coal cleaning plants
recycle a major portion of their process water and therefore we expect
a minimal impact of new water pollution control regulations on these
plants. These plants produce large quantity of solids wastes and
would be vulnerable to stringent regulations in that area.
b. Reserves
The characteristics of the coal resources in the United States
A 19
Arthur D Little, Inc
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are well known. All types of coal occur in a wide variety of seam
thicknesses, dips, and formations, and it is generally conceded that
there are enough exploitable supplies to meet the nation's needs for
the foreseeable future.
Deposits occur in 35 states, but 23 of these account for most
of the production. The locations of the coal fields are shown in
Figure A-6. The latest reserve estimates are shown in Table A-5, and
brief comments about the deposits in each of the major states follow.
(1) Alabama. Four major coal fields, covering 8000 square
miles - Coosa, Cahaba, Plateau, and Warrior Fields. Present production
mostly from Warrior Field.
• Coosa Field - Coal medium- to high-volatile bituminous,
ash content 4-14%, 13,000-14,500 Btu/lb, sulfur 0.8-4.1%.
Four beds 14 inches-12 feet thick. Some steep dips.
• Cahaba Field - Coal formations horizontal to steep in-
clines, irregular thickness, and folded and faulted. Most
coal high-volatile bituminous, 3-12% ash, sulfur 0.4-2.1%,
13,200-14,150 Btu/lb. More than 16 coal beds, 3-11 feet
thick.
• Plateau Field - Eight coal beds, average thickness about
27 inches. Medium-volatile bituminous, 8-11% ash, sulfur
0.7-3.9%, 12,900-15,000 Btu/lb.
• Warrior Field - Seven productive coal beds, 1-7 feet thick.
Medium- to high-volatile bituminous, ash 2.5-15.9%, 12,300-
14,300 Btu/lb, sulfur 0.7-3.1%. Gentle basin structure with
horizontal to slightly dipping beds.
Also, lignite belt 200 miles long and 30 miles wide. Outcrops up to 12
feet thick; 14% ash and 30% moisture.
(2) Alaska . Four major coal fields:
• Arctic Slope Region - Low-volatile coking coal to sub-
bituminous and lignite.
• Cook Inlet - Sub-bituminous coal up to 40 feet thick,
dipping 10-14°.
• Nenana - Sub-bituminous, producing field.
• Mantannska - High-volatile bituminous, 21 beds, 18-22 feet
thick.
A 20
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(3) Arizona. One principal coal field, at Mesa Verde. High-
volatile bituminous. A number of seams, some up to 9 feet thick. Much
of this can be open-pit mined.
(4) Arkansas. Three coal seams extending from the Oklahoma
Field. Seams to 8-1/2 feet thick of low-volatile bituminous and ranging
into semi-anthracite. 3.8-10.2% ash, 12,000-14,600 Btu/lb, sulfur
0.6-3.2%.
(5) Colorado. Seven principal coal fields, covering over
20,000 square miles. Large reserves of bituminous and semi-bituminous
coals and some anthracite.
• Green River Region - Most coal is high-volatile bituminous
coming from seams ranging from 4-1/2 to 23 feet thick.
Ash 3.7-12.6%, 9,590-12,360 Btu/lb, sulfur 0.4-2.5%.
• Uinta Region - This region actually comprises eight differ-
ent coal fields ranging from sub-bituminous to anthracite.
Seams range from flat lying to completely tilted, folded,
and faulted. Seams 4-1/2 to 22 feet thick. Some good
coking coals.
• San Juan River Region - Mined seams 5-9 feet thick. High-
volatile bituminous rank.
• Dakota Sandstone - Most coals here are thin, discontinuous,
and of poor quality, but thicker volatile bituminous coals
are available in the Nucla-Naturita area. They have about
11.9% ash, 12,000 Btu/lb, sulfur 0.9%.
• Raton Mesa Region - Seams of high-volatile bituminous
2-1/2 to 9 feet thick. In Trinidad Field, some coking
coal.
• Denver Region - Mostly coals of sub-bituminous rank. Mined
at depths of 250-450 feet. Seams mined range from 7 to
10-1/2 feet thick. Ash 4.4-10.1%, 9,060-10,660 Btu/lb,
sulfur 0.3-0.9%.
• Canyon City Field - Seams of high-volatile bituminous
3.5-8 feet thick.
(6) Illinois. About 37,000 square miles of Illinois is
underlain by coal-bearing formations that contain mostly high-volatile
bituminous coals. Calorific value 11,000 to 14,000 Btu/lb, ash 6-14%,
sulfur 0.5-6%, moisture content 6-18%. Some coking coal in southern
area. Coals usually overlain by slate or limestone, commonly two feet
of slate, then thicker limestone. Ten principal seams 18 inches to
25 feet thick. No. 6 seam is uniformly 6-7 feet thick and lies at
A 23
Arthur D Little, Inc
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depths of 650 to 1200 feet in southern Illinois. Gently dipping.
(7) Indiana. Coals are an extension of the large field in
Illinois. The beds and coal seams here dip to the west and southwest
at about 25 feet per mile. Nine major coal beds occur 2.5 to 8 feet
thick. Generally high-volatile bituminous with 6.3-12.2% ash, 10,900-
11,600 Btu/lb, and 1.2-3.3% sulfur. Roof rock generally shale.
(8) Iowa. Coal beds cover 1,300,000 acres in 37 counties of
Iowa. Of possible interest are three groups of coal beds:
• Wabansee Group - One principal bed 14-18 inches thick in
southwest.
• Marniaton Group - One principal bed about 2-1/2 feet thick.
• Cherokee Group - Eleven coal beds of some interest. Often
lenticular with individual lenses 5 feet thick. Other beds
32 to 66 inches thick. Mostly utility coal.
(9) Kansas. Bituminous coal bearing rocks cover 18,500 square
miles in eastern part of the state. There are at least 32 coal beds in
Kansas, of which 12 are of some importance. All coal is high-volatile
bituninous and averages 15,500-13,300 Btu/lb. Seams are 12-60 inches
thick. In northeastern Kansas, coal seam depths range from 660 to 1200
feet. North central Kansas also has a lignite area in a bed 12 to 36
inches thick.
(10) Kentucky. Kentucky has two distinctly separate coal
mining regions, the Western and Eastern Regions. The Eastern Region
is part of the Appalachian Region which includes Pennsylvania, Ohio,
Maryland, Virginia, West Virginia, Tennessee, and Alabama. The
Western Region is part of the Eastern Interior Basin x^hich includes
Illinois and Indiana.
Eastern Kentucky coals are generally high-volatile bituminous,
good for coking coals, with less than 10% ash and 3% sulfur. Eastern
Kentucky has about 12 major coal seams 22-99 inches thick. The
average thickness mined is probably 36-44 inches. Btu values range
from 12,500 to 14,000.
Western Kentucky coals are also high-volatile bituminous but
generally are higher in ash and sulfur content than the Eastern Region
coals. Seven major beds varying from 3 to 8 feet thick are known
in this region.
(11) Maryland. Coal fields in Maryland cover 455 square
miles in the northwest corner of the state. There are five major
fields, with 8 major seams ranging from 3 to 14 inches thick and
bituminous in rank. Ash content is 5.3-15.5%, sulfur 0.6-4.2%, and Btu
A 24
Arthur D Little, Ir
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value ranges from 12,500 to 14,500.
(12) Missouri. Coal beds underlie 23,000 square miles. The
beds dip generally in a northwest direction. Much of the coal in the
area is generally thin. Mining has been confined to near the out-
cropping areas.
The state has been divided into five coal districts, and
some nine major beds have been identified. The mined beds are 22 to 57
inches thick. The coals contain 6-16% ash, 2.2-6.9% sulfur, and heating
values of 10,500-13,000 Btu/lb.
(13) Montana. Montana has large reserves of sub-bituminous
and lignite coals, ranging in thickness from 4 to 80 feet, with
3.9-9.6% ash, 0.5-12% sulfur, and 5600-9500 Btu/lb heating values.
Strip mining is used in the eastern part of the state, but west to Fort
Union most of the coals will require underground mining.
(14) New Mexico. New Mexico has both bituminous and sub-
bituminous coals in beds 2 to 20 feet thick. Coals have 3.0-12.5%
ash, 0.4-1.6% sulfur, and 9500-13,500 Btu/lb. In the principal field
(San Juan Basin) the coal crops out as a narrow belt around the margin
and dips under thick cover toward the center. In the other field
(Raton) the coal beds are horizontal or gently dipping westward, and
are from 3 to 13 feet thick.
(15) North Dakota. The western part of the state contains
about two-thirds of the total U.S. lignite reserve. It covers about
28,000 square miles. Over 100 beds have been identified, ranging
from 4 to 24 feet in thickness. The lignite beds are practically
horizontal and are covered generally with a layer of impervious clay.
Average analyses show 5.6% ash and 0.3% sulfur, 700 Btu/lb, 36.2%
moisture, and 31.2% fixed carbon.
(16) Ohio. Coal beds occur under 12,340 square miles of
eastern Ohio. Some 54 coal beds are known, but only 24 are thick enough
to consider as containing potential reserves. These range from 28 to
60 inches in thickness.
The coals are high-volatile bituminous fuel coals with 6-9%
ash, 1.5-3.7% sulfur, and 12,000-13,000 Btu/lb heating value.
(17) Oklahoma. Some 20,000 square miles of Oklahoma are
underlain by coal-bearing formations. Most coals are bituminous in
rank. There are at least seven important seams, ranging in thickness
from 24 to 72 inches. In one area (Lightning Creek) a 12-15 inch coal
seam is strip mined by removing the limestone above it. A typical
analysis shows 8% ash, 0.9% sulfur, and 13,500 Btu/lb.
(18) Pennsylvania. Coal beds underlie 33% of the state and
A 25
Arthur D Little, Inc
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are part of the Appalachian coal basin. Some 52 coal seams are known
and named in eight fields. Coals range in rank from high-volatile
bituminous to anthracite (in the east). Heating values range from
14,700 to 15,800 Btu/lb. Moisture contents range from 0.5 to 12%,
sulfur 1-3%, and ash 4-15%. Most of these coals of bituminous rank
coke to some degree.
In the main western bituminous areas, the beds dip generally
less than 2° and rarely more than 8°. In general, folding and faulting
are not serious. In one isolated field (Broadtop), dips frequently up
to 30° are encountered. These bituminous seams are 16-72 inches thick.
Anthractie in eastern Pennsylvania consists of four fields.
Much folding and faulting has occurred, and dips of 60° are not un-
common. The seams vary from 3-12 to 21 feet in thickness and commonly
contain partings of several feet.
(19) Tennessee. Tennessee coals are a part of the
Appalachian region and underlie some 5000 square miles in a belt
passing though the central part of the state. The coals are bituminous
in rank and have been divided into nine major districts. Some 11 seams
are of importance, and these vary from 15 to 72 inches in thickness.
Roof rocks are generally shales, sandstones, and slates.
These coals have 2-14% ash, 0.4-5.8% sulfur, and 12,000-
14,300 Btu/lb heating value. In some areas the Sewaull seam produces a
coking-grade coal.
(20) Texas. Texas contains lignite, bituminous, and sub-
bituminous coals over an area of 75,000 square miles. All current
production is from lignites having about 12% ash, 1.0% sulfur, and a
7800 Btu/lb heating value.
(21) Utah. Coal fields cover an area of 15,000 square miles
in Utah, divided into 11 principal fields. The coals are of
bituminous rank, and in one area (Salima and Huntington Canyon) they
contain up to 15% resin. Much of the coal is of coking quality.
Typical analyses show 5.4 to 6.3% ash, 0.5 to 1.2% sulfur, and 10,700
to 13,200 Btu/lb heating value.
Eight major coal seams are known, ranging from 4 to 30 feet
thick. A variety of dips and conditions occur in the seams. For
example, the Sunnyside seams are only slightly dipping, and the roof
consists of shales or sandstones; the Castle Gate seams dip 12° to
the north and have good roof and floor conditions; and the Hiawatha
seam is 8-15 feet thick, dips slightly, and is covered by a massive
sandstone overburden that is 40-150 feet thick.
(22) Virginia. Virginia coal fields are widely scattered and
are commonly grouped in three major divisions. In southwest Virginia,
A 26
Arthur D Little, Ir
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high- and low-volatile bituminous coals occur; these fields are part of
the Appalachian Region. The other areas are known as the Valley Fields
and the Richmond Basin.
Some 27 seams have been described, with thicknesses varying
from 1.3 to 8 feet. The coals have 0.7 to 3.7% sulfur, 3 to 10% ash,
and 13,000 to 15,000 Btu/lb heating values. Most of the beds are gently
dipping.
(23) Washington. Most of the coal reserves in Washington
occur in a discontinuous belt along the western edge of the Cascade
Range. Formations in all areas are folded and faulted, and dips of 90°
are often encountered in the seams. Most of the coals are high-
volatile bituminous with about 11% ash, 0.7% sulfur, and 14,000 Btu/lb
heating value.
In the Roslyn Field in Kittitas County, beds dip up to 40° and
have thicknesses of 15 to 19 feet. In the Centralia area there is a
seam 15 to 20 feet thick with a 15° dip. This seam has the composition
indicated above.
(24) West Virginia. West Virginia is situated in the central
part of the Appalachian Region, and coal occurs in 53 countries in the
state. Some 62 of the known coal seams contain minable reserves. Most
of this coal is high-volatile bituminous, and the seams are 2 to 20 feet
thick. Typical analyses show 0.6 to 4.8% sulfur, 7 to 17% ash, and
12,500 to 15,000 Btu/lb heating value. Beds are commonly horizontal or
slightly dipping.
(25) Wyoming. Vast coal deposits occur over 40,000 square
miles of Wyoming. Coals rank from lignite to high-volatile bituminous.
There are over 40 fields, of which eight are of major interest and
importance. In the Powder River Basin the Roland bed has a maximum
thickness of 106 feet, and in many of the fields beds range from 7 to
118 feet thick. Also in the Powder River Basin near Lake De Smet,
strippable coal beds over 200 feet thick are being developed. In
general, roof rocks are shales, but some sandstones are also encountered.
Analyses of typical coals show 1-9% ash, 0.3-1.4% sulfur, and
7400-13,400 Btu/lb heating value.
The Wyoming coals occur in broad synclinal basins. Around
the edges of these basins the coal-bearing strata may dip steeply as
the result of later uplift of the surrounding mountains, but in the
central basins the seams are virtually flat-lying.
c. Location of Mines
The coal mining industry of the United States may be divided
into three distinct regions - the Appalachian, the Central, and the
A 27
Arthur D Little, Inc
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Mountain and Pacific (or Western consisting of the bituminous and
semi-biturainous coals of the Intermountain Region and the lignites of
the Northern Great Plains). Table A-5 (and Figure A-5) shows the
distribution of bituminous coal and lignite mines by state, size of
output, and type of mining used in each of these regions.
The Appalachian Region comprises the coal fields of Maryland,
Virginia, and West Virginia (grouped into the South Atlantic sub-
district), Kentucky, Tennessee, and Alabama (forming the East-South
Central subdistrict), and the Mid-Atlantic subdistrict consisting of the
Pennsylvania coal deposits.
The Central Coal Region is composed of mines in Ohio,
Illinois, Indiana, Iowa, Kansas, North Dakota, Missouri, Arkansas,
and Oklahoma.
The coal producing states in the Mountain and Pacific Region are
Montana, New Mexico, Wyoming, Arizona, Colorado, Utah, Washington, and
Alaska.
d. Coal ?Iinirig Companies
Table A-7 lists the 40 largest U.S. coal companies and their
respective production tonnages in 1970 and 1971. We have also indicated,
wherever possible, the ownership of a given company and whether or not
it is publicly quoted on the major stock exchanges. Relatively few are
publicly held; most of the large companies have been acquired by multi-
product corporations, while others have actively diversified.
Pittston Company, the fourth largest, is probably typical in this re-
spect, since only about 44% of its revenue comes from coal sales.
The bulk of the coal mining companies are small, independent
operators or family-owned mines, that are only involved in coal
mining. These companies, though numerous, account for a smaller
proportion of the total coal production than the large companies. Over
the last several years, these smaller companies have succumbed to
economic pressures fron a variety of sources, and the trend towards
greater concentration in the industry is expected to continue. Despite
this, the coal mining industry is not particularly concentrated in
comparison with industries such as the primary ferrous and non-ferrous
industries.
e. Types of Mines
Table A-6 showed that 55% of the 5032 mines in the Appalachian
Region are underground operations and account for 66.5% of the total
regional production of 415 million short tons. Over 1700 strip mines
and 513 auger nines in the regionpproduce 29" and 4.5% of its coal
output respectively. Relative to the total U.S. coal production,
Appalachia accounted for about 69%.
Arthur D Little, I
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A 33
Arthur D Little, Inc
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While nearly 85% of the Appalachian mines produce less than
100,000 tons each per year, this group accounts for only 22.5% of the
tonnage output. In fact, 1763 mines, each of which produces less than
10,000 tons per year, contribute only 2% of the annual coal production
of this region. This emphasizes the relatively small size of many of
the coal mines, as well as the dominating effect, in terms of tonnage
output, of the mines that produce over 500,000 tons per year (3.7% of
the total number of mines and 38.4% of the production). In contrast
to the Appalachian Region, a high proportion of the mines in the
Central Region are strip operations: 72% versus 34.5% in Appalachia.
Accordingly, 65.5% of the coal production is accounted for by strip
mines, whereas the corresponding figure in the Appalachian Region is
29%. These comparisons are shown in Table A-8. The Central Region is
the source of 26% of the total U.S. bituminous coal output.
The coals of the Mountain and Pacific Region are of varying
purity, with Colorado and Utah furnishing most of the metallurgical
coals consumed. The entire region accounts for less than 5% of the
total U.S. production of bituminous coal and lignite.
There is no auger mining in the Mountain-Pacific Region;
strip mining is the preferred technique, with 67% of the facilities
employing this method. Over 80% of the coal production comes from 10%
of the mines, each of which produces in excess of 500,000 tons per year.
Twenty-seven percent of the establishments produce less than 10,000 tons
each per year and cumulatively generate only 3.0% of the total regional
coal tonnage.
f. Mine Employment
The latest year for which complete coal industry statistics
are available is 1967. Although the absolute figures on industry employ-
ment may be expected to have changed since that time, we believe the change
has been less than 10% and that the data therefore furnish a reliable
representation of industry patterns and trends in 1971.
Figure A-7 depicts the 1967 distribution of mine sizes in
terms of the number of employees per mine. An overwhelming number of
the operating mines employed less than 100 workers each; in fact,
approximately 2400 of the 5873 active mines employed less than ten
each. This graph also shows the number of employees in each mine size as
a percentage of the total industry employment. Clearly, the operations
that employ less than ten men account for small proportion of the
workers in the industry. On the other hand, the fewer mines with
over 50 men employ a high proportion of the total working force.
The distribution of the 5,873 mines, by mining method and
mine size, is shown in Figure A-8. The near-coincidence of the
underground mint and the total mine curves underscores the dominance of
underground mining in the coal industry in terms of the number of mines.
A34
Arthur D Little, Ir
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TABLE A-8
MINING AND PRODUCTION PATTERNS IN U.S. COAL DISTRICTS
Region
Appalachian
Central
Mountain-
Pacific
% of Total
U.S.
Production
68.9
26.2
4.9
% of Output By
Mining Method
Underground Strip Auger
66.5 29.0 4.5
33.6 65.5 <1%
32.9 67.1 0.0
<1 0,000
tpy
2.1
(35.0)a
0.3
(23.9)
0.3
(27.0)
% of Output
Mine Size
<1 00,000
tpy
22.5
(84.7)
5.6
(64.0)
3.7
(60.0)
By
>500,000
tpy
38.3
(3.7)
84.7
(21.5)
80.9
(19.0)
Percentage of the total number of mines in this size range are enclosed in parentheses.
Source: Table A-6
A 35
Arthur D Little, Inc
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A 36
Arthur D Little I
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X Underground
O Strip
D Auger
• Total
1-19
20-99
Size of Mine (by Employment)
Source: U.S. Department of Commerce, 1967 Census of Mineral Industries
100-Over
FIGURE A-8 DISTRIBUTION OF COAL INDUSTRY EMPLOYMENT
BY MINING METHOD AND MINE SIZE
A37
Arthur D Little, Inc
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The histogram of Figure A-9 shows the historical employment
pattern in the coal industry by mining method. In the 25-year span from
1945 to 1970, employment in the industry dropped from about 383,000 to
about 140,000 due mainly to increased mechanization and the closing
of facilities that were unprofitable of unable to meet more stringent
safety and pollution control. While the number of men in underground
mines has decreased progressively since 1955, the number in strip
mines has held fairly constant, in spite of the fact that the number of
strip mines has increased since then. Employment statistics on auger
mines have been available since 1955; both the number of such mines
and the work force employed by them have shown a slow and steady
increase.
g. Trends in Coal Mining and Washing
Recent trends in coal mining and beneficiation have been
instigated largely by the desire on the part of producers to supply
high-quality coals to consumers at prices that are competitive with
.alternative fuels. These requirements make it imperative that coal
producers engage in careful planning and astute operational management
at all stages of the coal production process.
Table A-9 shows the recent trends in mining methods. It is
apparent that the percentage of the total production from under-
ground mines has been declining, whereas strip and auger mining have
registered corresponding increases. Longwall mining appears to be
firmly established and will be adopted by a growing number of mines.
To further enhance the economics of strip mining, the trend
is toward larger machinery capable of stripping to depths of over
200 feet. In the not very distant future, draglines of up to 300-
cubic-yard capacity could become commonplace at mine sites. Similarly
impressive advances are being made in drilling and blasting practices.
The mechanization of mining, loading, and conveying is
increasing rapidly. The degree of mechanical loading underground,
for example, has risen from 36% of underground production in 1940 to
97% in 1970. Similarly, strip mining has undergone great advances in
mechanization, and this trend is expected to continue.
Another area that stands to receive substantial attention in
the future concerns the application of automatic control of mine
face equipment. The impetus for this trend comes not only from the
improved face performance expected, but also from the need to move
the coal miner back from the face area, where most underground
accidents occur.
In coal preparation, the essential design features of the
major gravity separation units are x:ell established. There is, however,
a continuing effort to modify them to effect better separation
A38
Arthur D Little, Ir
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A 39
Arthur D Little, Inc
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TABLE A-9
BITUMINOUS COAL AND LIGNITE PRODUCTION BY MINING
METHODS IN THE U.S. 1967-71
Millions of Net Tons
Underground Mining
Percentage of Total
Strip Mining
Percentage of Total
Auger Mining
Percentage of Total
1967
187.1
33.9
16.4
3.0
1968
349.1 344.1
63.1 63.1
185.8
34.1
15.3
2.8
1969
16.4
2.9
1970
347.1 338.8
62.0 56.2
20.0
3.3
1971
302.4
54.0
197.0 244.1 238.6
35.1 40.5 42.6
19.6
3.3
Total
552.6 545.2 561.0 602.9 560.0
Estimates
Source; Coal Age, February 1972
A 40
Arthur D Little, Ir
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of coal from sulfurous impurities. Both physical and chemical tech-
niques are being evaluated for achieving this objective. The gravity-
and density-based processes for pyrite removal evaluated thus far
appear promising, but they suffer from the economic handicap that the
clean coal yield decreases with the extent of desulfurization. The
chemical processes for organic sulfur removal, which generally
include a solvent-extraction step, have been tested primarily on a
laboratory scale and are still a long way from commercial use.
Table A-10 shows the historical trend in the number of
cleaning plants in the various coal-producing states. In virtually
every state, the number has been decreasing progressively since 1966.
This does not necessarily imply a de-emphasis of coal cleaning by the
industry; rather, it reflects the decrease in the number of mines and
the consolidation of cleaning plants.
Despite improvements in transportation methods and the
attendant decrease in freight rates, shipping rates for coal are still
high relative to those of competing energy sources. Accordingly,
pipeline transportation of slurried coal is receiving careful con-
sideration from the power-generating industry. Another recent trend
among power generators is to install the power plants at the coal mine
and transmit the energy at extra-high voltages from there to load
centers. Between 1965 and 1971, about 25 coal-fired electric generating
units located at mine sites were brought on-stream, and this trend is
expected to continue.
The output per man-day at a coal mine is not a foolproof
measure of productivity, since it fails to compensate for the physical
characteristics of the coal bed and the degree of mining mechanization,
among other variables; nevertheless, it is a working indicator of
trends within the industry and provides a basis for comparing per-
formance at various locations. To convey the proper perspective,
Table A-10 lists productivities in terms of output per man-day for the
three major mining methods in the United States from 1945 to 1970, and
for underground coal mines in several European countries. The data for
U. S. underground and strip mines are plotted in Figure A-10, along with
our projections of the respective productivities through 1980.
For all mining methods, productivity has been inching generally
upward. Compared with those in European countries, as shown in Table A-ll,
U. S. mines are immensely productive; however, one must interpret the fig-
ures for Europe in the light of the mining conditions there.
2. Financial Structure and Trends
a. Prices
Coal pricing is a complex subject and can be visualized as
A 41
Arthur D Little, Inc
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A 42
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Legend:
A U.S. Average Strip Mines
O U.S. Average - Underground
1945
1950
1955
1960
1965
1970
1975
1980
Source: 1945 - 1970 U.S. Bureau of Mines
1971 - 1980 Arthur D. Little, Inc., estimates.
FIGURE A-10 PRODUCTIVITY OF U.S. BITUMINOUS COAL MINES
A 43
Arthur D Little, Inc
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A 44
Arthur D Little, Inc
-------
involving three major commodities - metallurgical coal, low-sulfur coal,
and high-sulfur coal. Since sulfur is considered an impurity in coal, a
sulfur penalty is levied. At the present time, this is equivalent to
about $0.75 per ton per percentage point of sulfur in excess of about
2.0% in the spot market. This penalty is expected to escalate as sulfur
specifications for steam coal decrease. Another price-determining fac-
tor is whether the coal is washed or unwashed. The price of washed
versus unwashed coal varies by as much as $0.05 per ton for each 100
Btu increase in energy content obtained by washing.
In addition to the above factors, coal pricing is also a func-
tion of the size and organization of the producing firm - large and/or
captive, large and independent, or small and independent.
Contract sales generally involve fixed prices and built in
escalation changes for the large producers, while the independent pro-
ducers sell coal mainly in the open spot market. Thus, the spot market
is dominated by small independent producers who market coal through
brokers who charge a commission rate of 20 to 30 cents per ton.
Typically, the small producer can do no better than to accept the
brokers stipulated price which, in turn, is set in a region by the
large producers and consumers. Figure A-ll depicts the spot price trend
from 1965 to 1972 for metallurgical and steam coals. Spot prices change
continuously in response to short-term supply-demand imbalances which
are affected by factors such as the implementation of new coal-mining
labor contracts and sags in steel demand by such consumers as the auto-
motive and construction industries. Generally, the trend in the spot
price of coal since 1965 has been upward. In contrast to the spot
market, prices in contract sales are less erratic because of the long-
term character of the contracts.
b. Sales
This discussion has been covered in Section A.4.
c. Costs
The principal components of the cost of coal production are
the capital costs and the operating costs. Typical capital costs for
an underground mine are shown in Table A-12. Underground equipment
constitutes the largest cost item, absorbing about 55% of the total
expenditure. Elements of production cost are given in Table A-13,
with production costs amounting to $5.07 per ton (including
amortization).
The estimated production costs for a small Northern Appalachian
strip mine are given in Table A-14, and they range from $4.05 to $5.15
per ton.
Of particular interest to an economic impact study would be a
cost function for mines in different size categories i.e. how
A45 Arthur D Little, Inc
-------
o
Q)
OQ
O
CO
£
o
Q
16.00
15.50
15.00
14.50
14.00
13.50
13.00
12.50
12.00
11.50
11.00
10.50
10.00
9.50
9.00
8.50
8.00
7.50
7.00
6.50
6.00
5.50
5.00
4.50
4.00
DMW Wage Increase
II
I!
II
Metallurgical Low and
Medium Volatile
Metallurgical High Volatile
(Comparable to Lowi
Sulfur Steam Coal) J
Screenings, Industrial Use
(Comparable to High Sulfur
Steam Coal)
I I I
I
16.00
15.50
15.00
14.50
14.00
13.50
13.00
12.50
12.00
11.50-
11.00
10.50
10.00
9.50
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6.50
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LL
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4.00
Jan. Jan. Jan. Jan. Jan. Jan. Jan. Jan. Jan.
1965 1966 1967 1968 1969 1970 1971 1972
Source: U.S. Bureau of Labor Statistics.
FIGURE A-11 SPOT PRICE TRENDS - U.S. BITUMINOUS COAL F.O.B. MINE 1965-1972
A 46
Arthur D Little, Inc
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TABLE A-12
ESTIMATED CAPITAL COSTS FOR A TWO MILLION TON
PER YEAR UNDERGROUND COAL MINE
Estimated Capital Costs
Underground equipment $ 7,000,000
Slope and slope belt 1,118,000
Air shafts 476,000
Man-elevator 110,000
Fan 40,000
Preparation plant 2,250,000
Unit train facilities 5000,000
Engineering 100,000
Prospecting 110,000
$11,704,000
All other surface facilities:
$11,704,000 * 95 minus $11,704,000 = 616,000
$12,320,000
Underground development 400,000
Total Estimated Capital Costs $12,720,000
This is an average cost of $6.36 per annual ton of production
Source: N. Robinson - "Third AGA Pipeline Gas Symposium", 1970
A 47
Arthur D Little; Inc.
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TABLE A-13
ESTIMATED COST OF PRODUCTION FROM AN UNDERGROUND MINE
(1.9 million tons of clean coal/2.4 million tons raw coal per yr)
8,000 Tons clean coal -5- 231 men = 34.6 tons per man
Per Ton
Labor $1.36
Supplies 1.25
Power 0.12
Welfare 0.40*
Royalty 0.15
New mine, health and safety law 1.00
Depreciation 0.50
Taxes 0.03
Gross sales tax 0.06
Insurance 0.03
Operators association dues, miscellaneous 0.02
Administration 0.12
Sales 0.03**
Total estimated cost of production $5.07
*Will be 0.80
**Sold under long-term contract
Source: N. Robinson, "Third AGA Pipeline Gas Symposium", 1970.
A 48
Arthur D Little
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TABLE A-14
TYPICAL AVERAGE COSTS FOR A SMALL STRIP MINE3
IN NORTHERN APPALACHIA
Royalties
9
Overburden removal
@ 12-15c/yd3
Loading
Backfilling
Direct Cost
Brokerage and commissions
Profit
$/Ton
0.30-0.50
(can be as high as 0.80)
2.50-3.00
0.25-0.35
0.50
0.20-0.30
0.30-0.50
non-union mine; typically, costs are much lower at the
beginning of a stripping operation and higher toward the
end.
includes capital charges on mining equipment and cost of
explosives and labor.
Source: ADL estimates.
A 49
Arthur D Little Inc
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operating costs change with varying production.
In an analysis of a specific small strip mine in S. Ohio,
Dreese* was able to derive a theoretically appealing downward sloping
cost function (indicating lower operating costs per ton at higher
production rates) with the curve rising again at very high production
levels. Analysis of Dreese's data indicate that 'low-cost at high
production1 occured when the company was fortuitously operating a
thick shallow seam at a time when the demand was adequate. Thus this
theoretically appealing curve says nothing about whether that mine
could deliberately increase production in the short term and reap
the advantages in decreased operating cost per ton, thus being able
to absorb increased costs resulting from pollution abatement.
Furthermore, after considering a major production increase as a Long-term
option, Dreese states "It is questionable whether the economics of
large scale would offset the higher costs, and whether the additional
competition for customers would be possible in a market with several
large producers with years of experience and large amounts of capital."
We believe that there are a bexd.ldering variety of variables
that contribute to the overall costs of production at each nine and
even knowing the cost function of a mine in one segment contributes
little to knowing the cost function at any other mine in that segment.
d. Profits
Table A-15 lists the coal reserves and production statistics,
as well as recent sales and income data for the major coal-producing
firms.
Table A-16 lists the price-to-earnings ratios for selected
companies as of early April 1972. These values, v/hich range from
11.8 to about 27, may be higher than normal, because the coal strike
in 1971 depressed the earnings of most companies.
3. Industry Capacity and Productivity
In terms of the cumulative energy reserves, coal constitutes
the most plentiful fuel in the United States and accounts for almost
90% of the known reserves, including uranium. It is estimated that
390 billion tons of coal reserves are commercially exploitable under
present economic conditions, and with existing mining technology.
Sizeable as this quanitty is, it is nevertheless a small fraction of
the estimated 1.6 trillion tons of total mapped and explored coal
reserves.
*Dreese & Bryant, "Costs and Effects of a Water Quality Program for a
Small Strip Mining Company" OTIS Springfield, Va. (1971) IUR Report
71-7.
A 50
Arthur D Little, I
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TABLE A-15
COAL AND INCOME STATISTICS FOR MAJOR U.S. COAL-PRODUCING FIRMS
Company
t CM. ftasarvas—-N/-—Coal Production—vgoa| s«l*s Salas Total
Total Low 1971 % Cnanca 1971 1971
(Billion Tons) Sulphur (Million Tons) 1970-72* (Millions) (Millions)
Nat Incoma 5 jr. An.
1971 Matiirn
(Millions) on Equity
Burlington Northern
Union Pacific
Kenneeott Copper
(PeabodyCoal)
Continental Oil
(Consolidation Coal)
Exxon (Monterey Coal)
American Metal Climax
(AmaxCoal)
Occidental Petroleum
(Island Creek Coal)
United States Steel
Gulf Oil
(Pitts, ft Midway Coal)
North American Coal
Reynolds Metals
Bethlehem Steel
Pacific Power* Light
American Electric Pwr.
Eastern fias ft Fuel Assoc.
(Eastern Assoc. Coal)
Kerr-McGee
Norfolk ft Western RR
Utah International
Westmoreland. Coal
Prttston Co.
Montana Power
(Western Energy)
Standard Oil of Ohio
(Old Ben Coal)
Ziegler Coal
General Dynamics
Freeman/United Elec.
Rochester ft Pitts. Coal
Carbon Fuel
Amer. Smelting ft Refin.
(Midland Coal)
11.0
10.0
8.7
8.1
7.0
4.0
3.3
3.0
2.6
2.5
2.1
1.8
1.6
1.5
1.5
1.5
1.4
1.3
1.2
1+
1
.8
.8
.6
.3
.1
.1
100%
50+
27
35
NA
50
28
NA
8
80
95
NA
100
minimal
33
60
99
94
88
100
100
minimal
0
0
0
97
0
none
none
54.8
54.8
1.2
12.5
22.8
16.6
7.0
8.8
none
12
1.7
5.5
11.7
minimal
none
6.81
8.4
20.1
5.1
10.5
4.0
11.5
4.3
2.6
4
none
none
5.7
6.0
12.8
-24.3
NA
3.6
31.8
none
6.3
29.4
27.8
none
none
27.2
-21.7
NA
607.4
NA
-15.5
-24.2
15.2
-1.4
NA
none
none
J268.8
360.3
NA
NA
247.2
NA
33.5
63.6
none
none
none
none
150.0
none
NA
144.8
255.6
NA
66.3
25.3
N.A.
43.4
24.3
NA
$ 1,028.8
977.2
1,053.4
3,051.1
18,700.6
756.9
2,635.2
4,928.0
5,940.0
63.6
1,093.3
2,963.6
178.4
748.2
291.4
603.3
1,054.1
104.4
144.8
581.0
88.2
1,393.8
25.3
1,868.8
43.4
24.3
656.8
$ 38.7
90.7
87.2
140.1
1,516.6
55.4
d48
154.5
561.0
1.3
5.9
139.2
38.6
135.0
16.8
40.7
76.8
34.2
4.4
35.3
20.0
58.8
1.1
20.6
.8
2.8
46.0
2.2%
5.4
11.9
10.8
13.4
13.9
17.3
5.5
12.5
6.6
6.4
7.2
9.7
13.0
13.0
11.9
6.3
20.4
9.0
17.0
17.7
10.9
8.3
6.8
4.3
14.2
13.5
• Comparison of first six months of 1972. d-D«ficit. N.A.-No! available.
Source: Forbes, November 15,1972
A 51
Arthur D Little Inc
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TABLE A-16
PRICE EARNING RATIOS FOR A
SELECTION OF PUBLICLY-QUOTED COAL COMPANY STOCKS
Rank
4
8
11
12
14
26
Company
Pittston Co.
Eastern Gas & Fuel Associates
North American Coal Corp.
Westmoreland Coal Co.
Utah International Inc.
Carbon Fuel Co.
Average
Coal Revenue
as Percent
of Total
44
52
~ 100
~ 100
~ 20
86
Fiscal 1971
Earnings
per Share
2.67
1.65
0.76
1.30
2.50
1.25a
Market
Price
4/4/71
37.5
31
19
27.5
67
14.75
P/E
14
18.7
25
21.2
26.8
11.8
19.5
Initial offering 3/16/72 at $17.50/share for a P/E of 14.
A 52
Arthur D Little, I
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National industry data are shown in Figure A-12, using mine
tonnage output as a criterion of size. The approximately two hundred
mines that produce less than 50,000 tons per year account for a small
proportion of the annual output. Similar data are presented in
Figures A-13 and A-14, specifically for underground mines and strip
mines respectively. The small mines dominate numerically, but their
contribution is relatively modest in terms of coal production.
4. Competition from Other Energy Sources
While coal price and demand can reasonably be expected to
remain strong and competitive for the next decade, it should be
recognized that sharp price increases would force major market segments
to substitute otfier energy sources for coal where the economics so
dictate. Major competitors in the electrical power Industry are
hydroelectric power, nuclear power, natural gas, and oil. Hydroelectric
power should not be a serious contender, since most hydroelectric sites
in the United States have already been developed and very little growth
is projected for this energy segment into the 1990s. Nuclear power
plants are no longer expected to attain the very rapid construction
growth predicted for them until 1980. As for natural gas, a supply
shortage is predicted in the near future. Oil is the only source that
threaten to penetrate the coal market in the electrical industry.
Already it has gained a substantial foothold on the East Coast and is
penetrating the Great Lakes metropolitan areas. While the price of
low-sulfur oil exceeds that of coal in the inland eastern United States,
the pressure of pollution control codes, the unreliability of current
sulfur dioxide control technologies, and the limited availability of
low-sulfur coal are forcing current conversions to low-sulfur oil,
particularly in urban areas.
In the ferrous metallurgical industry, coal's dominant
posture as a fuel source is threatened by the inception of direct-
reduction processes (for converting ore to high-iron pellets suitable
for blast-furnace feeding) based on natural gas, the increasing
importance of scrap or pellet-consuming electric furnaces as steelmaking
units for both carbon and high-alloy steels, and the future development
of nuclear-energy-based blast furnaces for iron smelting. Of some
importance also are the improvements in blast-furnace and coking
practices which make it possible to decrease coke consumption per ton
of iron produced, such as the recent development of processes for pro-
ducing form coke from noncoking coal.
There is an extensive research program in progress on the
conversion of coal to synthetic pipeline gas, synthetic crude oils,
or heavy oils suitable for burning in utility boilers. The successful
development of this technology is expected to increase the demand for
coal. However, the projected prices for these coal-derived products are
A 53
Arthur D Little, Inc
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Arthur D Little, I
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high, so that the competition between imports and domestic products will
continue.
5. Effects of Federal Government Programs on the Coal Industry
These effects were discussed earlier on Page A-12.
A57
Arthur D Little, Inc
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APPENDIX B
EFFLUENT LIMITATION GUIDELINES PREPARED BY THE EPA OFFICE OF PERMIT PROGRAMS
IN 1972
General
This guidance for the establishment of effluent limitations for discharges
in the Coal Mining Industrial category sets forth numerical
limitations based on the application of 'best practicable control technology
currently available.1 Schedule A values reflect the Agency's best technical
judgment of the effluent levels which can be achieved by the application
of the highest level of control technology which is now considered 'practicable'
and 'currently available' for the.industry. Schedule A values are based on
the totality of experience with the technology, including demonstration projects,
pilot plants, and actual use, which demonstrates that it is technologically and
economically reliable.
In every case of (i) new plants installing pollution abatement equipment and
(ii) existing plants now beginning abatement programs, yea should apply
Schedule A values- In some cases, economic and social factors may affect
the practicability of applying control techniques to achieve these values,
and may require some modification of Schedule A values as to particular
plants. These instances should be kept to an absolute minimum. Guidance on the
economic and social factors which may require that you consider such
modifications, as well as more detailed explanation of the engineering
assumptions underlying the Schedule A values, will be provided at technical
seminars to be conducted concerning each industrial category.
Schedule B values represnt the minimum acceptable effluent levels for the Coal
Mining Industry. No plant should achieve less pollution reduction than
Schedule B values. Schedule B values may be applied where a discharger has,
at the time the permit is issued, commenced and made substantial progress on
an abatement program.
B-l
SOURCE: EPA
Arthur D Little, Inc
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Rationale - Effluent Limitations for the Coal Industry
There are three major categories of effluent associated with the
production of coal: coal preparation waste (coal washers),
.underground coal mining waste (underground mine drainage), and
Surface mining waste (strip mine drainage). Because these three
wastes are somewhat different and require different treatment,
the major problem areas are discussed separately. Also, these
.. wastes are often unrelated, or only indirectly related, to
- production quantities, therefore, in this text, effluent
limitations are expressed in terms of concentration rather *.-•'*•-
than units of production. Due to the wide variation of geological
and hydro!ogical factors in the coal industry a jpound per day
limitation is impractical. The effluent limitations for the
"coal mining industry were based on utilization of the geochemical
approach which encompassed oxidation potential, reaction rates^
and solubility constants, as well as pH control." The term
"underground mine drainage" as used'herein applies not only to
discharges which have a low pH value but also to discharges with
a neutral value but which are high in metallic salts which
can be a problem in an alkaline environment.
It should be noted that this rationale was developed as a guideline
for the coal mining industry only and should not be applied to
hardrock mining.
A. Preparation Plant Wastes
Semi-colloidal particles of coal, shale, and clay in suspension
form one of the principal pollutants ~ suspended solids. Reduction
in the amount of suspended solids reaching the stream can be
achieved by installation of settling and impounding facilities.
Other, methods of control include the use of froth flotation,
floCculation, filtration, and mechanically operated sedimentation
and clarification basins. Organic coagulants, such as polyacrylamide,
used alone or in combination with inorganic coagulants may
demonstrate good settling qualities.
In addition to the problem of suspended solids, the effluent from
coal washing may contain iron and sulphur compounds in suspension.
In high enough concentration.these would cause considerable
loading on the stream and will require chemical treatment before
discharge. The effluent limitations for preparation plant
wastes, shown in Attachment A, reflect the eventual goal of
complete recycling.
SOURCE: EPA
B-2
Arthur D Little,
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B. Underground Mine Drainage
Drainage from coal mines may be acid in character and may contain
sulfuric acid, ferrous and ferric iron, aluminum, and manganese
in significant concentrations. Carbon dioxide, and calcium,
magnesium, and sodium salts, all of which contribute to a
very high degree of hardness, may also be present. Preventive1
measures might include reduction of the amount of infiltration
into the mine, controlled dewatering to reduce contact with
acid-forming materials, removal of acid forming materials and
sealing or flooding of inactive mines, and replacement of
waste rock. Treatment methods which might be used to meet
the effluent requirements, shown in Attachment B, may
include neutralization, and removal of iron and manganese.
Neutralization
Neutralization to a pH of 6.0 to 9.0 can be accomplished by the
use of lime, limestone, oxidation, or varied combinations of
the three, depending on the characteristics of the waste. A
French patent was granted in the nineteen-hundreds for the
treatment of mine drainage water with lime (Fassin). This
process, consisting of lime neutralization and precipitation of
metallic salts, was accomplished by adding more lime as the
effluent was passed through a series of ponds.
A number of neutralization processes using limestone have been
tried. _ The first reported application of limestone in acid
mine treatment was at the Calumet Mine, Westmoreland County,
Pennsylvania, In 1916.
Following this, a patent was granted for a two-step process
which was first used by Mason and Travers. Their treatment was
carried out in tanks, with the addition of powdered limestone to
br.tng the pH to approximately 5. Lime was then added to the
mixture to complete neutralization.
It was found that limestone powder did not react with ferrous
.salts, however, this reaction could be produced by causing
oxidation either by direct aeration or by the use of chlorine or
some other oxidant. A period of 50 minutes was required to
oxidize 640 milligrams per liter by aeration of an acid waste
to which had been added a fourfold excess of limestone. The
ferrous salts are converted to free ferric salts which precipitate
out.
SOURCE: EPA
B-3
Arthur D Little, Inc
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While neutralization with a combination of lime and limestone is
not new (it has been used by the steel industry for treating
pickle liquor for a number of years) its application in the
neutralization of coal mine drainage water is still effective.
The use of a two-step neutralization process, that is, the use
of limestone £6 bring the pH to 5, with the addition of lime,
to completethe neutralization, could result in a considerable
savings both in the cost of chemicals and in sludge handling.
The sludge resulting from the two-stage precipitation method
has better settling qualities and a higher solids concentration
than sludge from using lime alone.
Iron Removal
At present there are two common methods employed for the removal
of iron from mine drainage. Both processes are based on
precipitation reaction. In the first process, precipitation is
carried out through adjusting the pH; this reaction results in
precipitation of iron oxide. The second method, precipitation
by chemical addition, results in the formation of an insoluble
sulfide compound. This method is by far the more costly of the
two.
At present, the Clinchfield Coal Corporation of Clarksburg,
West Virginia operates a treatment facility for neutralization
and removal of iron from mine pumpage wastes. On a daily flow
of 600,000 gallons, and through the use of lime treatment and
sedimentation, the pH is increased from 3.8 to 8.5. This facility
employs a two-pond sludge settling system with the first pond
reducing iron content from 240 mg/1 to 9 mg/1, at the same time,
through oxidation and precipitation, the total iron content is
decreased in the second pond from 9 mg/1 to 0.6 mg/1. In this
process iron is removed at two different pH levels. At the first
level, ferric iron will precipitate at a pH of about 3.2 and, at
£he second level, ferrous iron will precipitate at a pH between
8 and 9. Lime neutralization, with the oxidation of ferrous
iron to ferric iron, is carried out between the two levels, at
a pH of about 7. At a pH of 7 to 9, depending on temperature, an
amorphous ferric oxyhydroxide is formed. This suspension is
light and almost colloidal. To aid in sedimentation a coagulant
or some form of polyelectrolyte could be used to enhance
clarification in existing lagooning systems.
SOURCE: .EPA
B-4
Arthur D Little,
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Manganese Removal
Depending on the compound of manganese to be removed, coagulation
and precipitation can be carried out to varying degrees. A
moderate concentration of manganese can be reduced to 0.6 mg/1
by utilizing the pH adjustment system previously described.
Lime is added to raise the pH from 10 to 11, at which time the
manganese can be removed with some form of aeration to form
flocculent settleable material. The addition of either sodium
or barium sulfide will aid in precipitation of a manganese
sulfide.
C. Surface Mining
In 1965 the total U. S. production of coal from surface mining
operations was 180 million tons or 35% of the total. In 1970,
44% of the coal mined was by surface methods, according to the
National Coal Association. (This includes a 17.5% increase in
the total coal mined in the United States). With this continuing
increase in surface mine operations, even greater control and
implementation of existing technology is needed.
Attachment C contains the effluent limitations for surface
mining (strip mining operations). To meet the effluent limitations,
operators will have to employ one or all of the following methods
presently being used by many companies:
*
1. Keep as much water as possible out of the operating, site;
2. Provide proper drainage removal to a treatment facility;
3. Separate contaminated and non-contaminated water; and
4. Insure that all water receives proper pH control as
well as removal of suspended solids and metallic
materials.
At present, a number of operations are employing lagooning
systems. Evaporation results in a reduction in the suspended
solids as well as the ferric hydroxide and the ferric sulfate.
Precipitation eventually results through the oxidation process.
One source of acid mine water is the refuse pile or "gob pile"
which contains sulfurous refuse from the preparation and cleaning
process. Control of the gob piles could eliminate a source of
acid drainage. The simplest system for control is to cover
these piles with a non-acid producing material such as two feet
of dirt. At a later time, to insure stability, some form of
vegetation should be planted. Sealing or benching of the cut
area so that there are no opportunities for oxidation of the
pyrite material will eliminate a major part of the problem.
SOURCE: EPA
B-5
Arthur D Little, Inc
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CONSIDERATION OF APPLICATION OF LIMITS TO PREPARATION PLANTS,
UNDERGROUND MINE DRAINAGE, AND SURFACE*MINING OPERATIONS
1. It shall be considered a violation of the discharge permit if
the average of the analyses peformed over any thirty-day period
exceeds the limitations (except for pH) as stated in
Attachments A, B, and C.
2. It shall be considered a violation of the discharge permit
if at any instantaneous measurement the pH of the effluent
is less than 6.0 or more than 9.0.
3. It shall also be considered a violation of the permit if any
composite sample exceeds the limitation shown in the
Attachments by more than 50%.
4. It shall be considered a violation of the permit if any
single grab sample exceeds the limitations by 100%.
5. Any single violation may be considered sufficient cause
for revocation of a discharge permit.
NOTE: Four violations in any 12-month period will require an action
memorandum from the Regional Administrator or his designee
to the Assistant Administrator for Enforcement and
. General Counsel detailing an action program to bring-such
violations to an end.
SOURCE: EPA
B-6
Arthur DLittl
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PREPARATION PLANTS
A. Recommended Effluent Limits
1. There shall be no dilution of the effluent stream.
2. Use limits shown in Attachment A, Schedule $ or B, as
appropriate.
B. Monitoring
^* Minimum Frequency
A weekly sampling frequency shall be maintained for the
first twelve weeks with the exception of pH and flow
which will always be continuous measurements. Following
the first 12 weeks, a monthly sampling schedule may be
established.
2. Sampling and Analysis
Analyses shall be performed on composite sairples consisting
of at least five grab samples taken at equally spaced
intervals over the operating period. The maximum
compositing period for any composite sample, shall be
24 hours.
NOTE: The applicability of any of the parameters 3i;sted must be
at the discretion of the Regional Administrator or his
designee.
Monitoring Program is shown in Attachment D.
SOURCE: EPA
JB-7
Arthur D Little, Inc
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MINE DRAINAGE (Underground)
A. Recommended Effluent Limits
1. The velocity of discharge shall be such that scouring of
stream bed shall not occur.
2. Use limits shown in Attachment B, Schedule A or B, as
appropriate.
B. Monitoring
1. Minimum Frequency
A weekly sampling frequency will be maintained during
the first 12 weeks; thereafter, a monthly schedule may
be initiated.
NOTE: Sampling mine discharges is generally much like
sampling a reservoir or a small lake. The
changes in water quality are slow and generally
consistent; modification of the sampling program
should be decided by the Regional Administrator
or his designee.
Dischargers shall maintain daily records of duration and
volume of flow. These records are necessary because
many operations have a varying discharge, which is
• dependent on the season of the year and- the rate -of
production.
NOTE: The flow can be calculated using pumpage rates
and duration, providing controls are installed
to insure continual pump suction.
2. Sampling and Analysis
a. Analyses shall be performed on composite samples consisting
of at least five grab samples taken at equally spaced
intervals over the operating period. The maximum compositing
period for any composite sample, shall be 24 hours.
b. Program is presented in Attachment E.
NOTE: pH should be run on each of the grab samples making up
the composite.
NOTE: Neutralization - Neutralization is generally required for
mines located in the eastern United States. Graph #1
is included to help to aid in estimating chemical requrements
and chemical costs.
SOURCE: EPA
Arthur D Little, I
B-8
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B. Monitoring
^* Minimum Frequency
The monitoring program is shown in Attachment F.
NOTE: Suspended matter in parts per million may in some
instances be estimated by multiplying turbidity in
jackson turbidity units by 2.2.
*
2. Sampling and Analysis
Daily sampling and analysis for turbidity and pH should be
carried out for the first three weeks when a discharge is
occuring. Following the first three week period, a
frequency of twice a week may be initiated for sampling
and analysis.
The additional parameters shall be sampled weekly; analysis
may be performed on grab samples for the first three weeks.
Thereafter, a monthly schedule, sampling annually may be
maintained. The monthly analysis shall be performed on
.composite sample consisting of at least five grab samples
taken at equal intervals over an operating period.
The compositing period shall not exceed 24 hours, for
any one sample.
SOURCE: EPA
B"9 . Arthur D Little, Inc
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o
SOURCE: EPA
B-10
Arthur D Little, In
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SURFACE MINING OPERATIONS
A. Recommended Effluent Limits
1. All treatment facilities shall be of sufficient size to handle
the run-off resulting from a once-in-ten-years1 storm.
(Source-- Kentucky revised statutes relating to strip mining
and reclamation, 1966, Chapter 350, Regulation 11.)
2. The effluent shall not contain suspended matter in excess of
the limits shown in Attachment C, with the exception of during
and four hours after a major precipitation event. The operator
is not at any time to discharge an effluent containing suspended
matter in excess of 1,000 mg/1 from any area of land affected.
NOTE: (1) A major precipitation event: The number in inches
of water greater than the duration of the storm in minutes
divided by 100 plus 0.2. (Source - U.S.D.A. miscellaneous
publication #204, "Rainfall Intensity and Frequency Data,"
1935.)
(2) Graph #2 is an example of the method employed in
determining a major precipitation event. The graph depicts
a major precipitation event according to time.
(3) Since the operator must show the major precipitation
event has occurred, it will require an installation at the
operating site of a recording rain gauge. In addition,
precipitation must be included in the monitoring program.
(4) Area of land affected: (The area of land from which
overburden is to be or has been removed and upon which the
overburden is to be or has been deposited, which shall
include all land affected by the construction of new
roads or the improvement or use of existing roads other
than public roads to gain access and to haul coal.)
3. .Sudden release of large volumes of water from the treatment
facility must be prohibited.
NOTE: Release of large volumes of water, as during a storm must
be prohibited to prevent scouring of the treatment facility.
Therefore, there should be established a level at which the
flow will be diverted from the treatment facility. This
level must be set for each individual operation taking into
consideration the following: (i) average precipitation of
area; (ii) receiving stream water quality standards; and
(iii) the volume of water discharged during a once-in-ten-
years' storm.
4. Use limits shown in Attachment C, Schedule A or B, as appropriate.
SOURCE: EPA
B-ll
Arthur D Little, Inc
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ATTACHMENT A
RECOMMENDED PERMIT CONDITIONS FOR COAL-PREPARATION PLANTS
CRITERIA
RECOMMENDED CONCENTRATION
SCHEDULE
Suspended Solids
PH
Total Iron
Alkalinity
Toxic Materials
Oil and Grease
30 mg/1
6.0 - 9.0
4.0 mg/1
Greater than acidity
B
40 mg/1
6.0"- 9.0
7.0 mg/1
No toxic or hazardous material a
designated under the provisions
Section 12 of the Federal Water
Pollution Control Act or known
to be hazardous or toxic by the
permittee except with the
approval of the Regional
Administrator (EPA) or his
Authorized representative.
Final resolution of this paramet
must await discussions with the
oil industry. After
resolution, it will be applied
to all industry on a
relatively uniform basis. Prese
thinking is that it may be a
single number no more stringent
than 5 mg/1 and no less
stringent than 10 mg/1 as a
final effluent limit. The use
of dilution to achieve this
number will not be allowed.
SOURCE: EPA
B-12
Arthur D Little, I
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ATTACHMENT B
RECOMMENDED PERMIT CONDITIONS FOR MINE-DRAINAGE
CRITERIA
RECOMMENDED CONCENTRATION
SCHEDULE
Suspended Solids
PH
Total Iron
Alkalinity
Toxic Materials
B
30.0 ntg/1 40.0
6.0 - 9.0 6.0 - 9.0
4.0 mg/1 7.0 mg/1
Greater than acidity
No toxic or hazardous material
as designated under the provisions
of Section 12 of the Federal
Water Pollution Control Act or
known to be hazardous or toxic
by the permittee except with the
approval of the Regional
Administrator (EPA) or his
authorized representative.
SOURCE: EPA
B-13
Arthur D Little, Inc
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ATTACHMENT C
RECOMMENDED PERMIT CONDIT FOR SURFACE MINING OPERATIONS
CRITERIA
Suspended Solids
PH
Total Iron
Alkalinity
Toxic Materials
Oil and Grease
RECOMMENDED CONCENTRATION
SCHEDULE
A
30 mg/1
6.0 - 9.0
B
100 mg/1
6.0 - 9.0
4.0 mg/1 7.0 mg/1
Greater than the acidity
No toxic or hazardous material
as designated under the
provisions of Section 12
of the Federal Water Pollution
Control Act or known to be
hazardous or toxic by the
permittee except with the
approval of the Regional
Administrator (EPA) or his
•authorized representative.
Final resolution of this
parameter must await discussion
with the oil industry. After
resolution, it will be applied
to all industry on a
relatively uniform basis. Prese
thinking is that it may be a
single number no more stringen
than 5 mg/1 and no less
stringent than 10 mg/1 as a
final effluent limit. The use
of dilution to achieve this nu
will not be allowed.
SOURCE: EPA
B-14
Arthur D Little, In
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SOURCE: EPA
B-15
Arthur D Littk Inc
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ATTACHMENT D
MONITORING - PREPARATION PLANTS
PARAMETERS
PH
Flow
Suspended Solids
Suspended Volatile Solids3
Total Dissolved Solids3
Iron (total)
Manganese3
Turbidity3
Aluminum3
Alkalinity3
Acidity1
Chemical Oxygen Demand (COD)3
Oil and Grease^
TYPE OF
SAMPLE
Continuous
Continuous
Composite
Composite
Composite
Composite
Composite
Composite
Composite
Composite
Composite
Composite
Composite
iy Determine by hot phenolphthalein method
2/ Report as total hexane soluble
3/ If conditions warrant monitoring these parameters,
use type of sampling specified above.
SOURCE: EPA
B-16
Arthur D Little, I
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ATTACHMENT E
MONITORING - MINE DRAINAGE
PARAMETERS
PH
Flow
Suspended Solids
Total Dissolved Solids*
Total Iron
Manganese*
Aluminum*
Sulfates*
Turbidity '
Conductivity*
Suspended Volatile Solids*
Chemical Oxygen Demand (COD)*
Acidity
Alkalinity
TYPE OF
SAMPLE
Grab
Continuous
Composite
Composite
Composite
Composite
Composite
Composite
Composite
Composite
Composite
Composite
Composite
Composite
*If conditions warrant monitoring these parameters,
use type of sampling specified above.
SOURCE: EPA
B-17
Arthur D Little, Inc
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PARAMETERS
ATTACHMENT F
MONITORING - SURFACE MINING
TYPE OF
SAMPLE
pH Grab
Flow Continuous
Precipitation Continuous
Turbidity Grab
Conductivity* Composite
Suspended Solids Composite
Total Dissolved Solids* Composite
Total Iron Composite
Alumi num* Compos i te
Manganese* Composite
Chemical Oxygen Demand (COD)* Composite
Sulfates* Composite
Alkalinity (total) Composite
Acidity, (total) Composite
Suspended Volatile Solids* Composite
*If conditions warrant monitoring these parameters,
use type of sampling specified above.
SdURCE: EPA
B-18
Arthur D Little, I
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