-------
60-70% from Central Appalachia, 25-30% from Northern Appalachia and 1-5%
from Southern Appalachia. The rtviaininri 3-4".' of low productivity under-
ground coal came from the Rockies and the Hestern N'orthern Great Plains.
Underground mines in the Midwest produced a significant amount of
coal at productivities between 10-16 tons per shift and at productivities
between 20-30 tons per shift.
The relative share of production from mines in the Rockies and the
Western Northern Great Plains increases to about 10-15% for productivities
of between 16 and 50 tons per manshift.
Mines in Southern Appalachia had productivities of at the most 30
tons per manshift. The percentage of total production from Northern
Appalachia mines is relatively small for productivities of more than 16
tons per manshift compared with the relatively large percentage of total
production from mines in that region with productivities of less than 16
tons per manshift.
The relative percentage of total underground production from Central
Appalachia at productivities of over 16 tons per manshift is at least 80%.
For strip mines producing bituminous and lignite coal the percentage
distributions of coal production and of workers employed in different
(2)
regions are shown in Figure 111-23. v '
In the range of up to 10 tons per manshift r.ore than 80% of pro-
duction came from the Appalachian regions. The percentage share of the
production from Appalachian areas for productivities larger than 50 tons
per manshift is only about 10%.
' 'Since percentage production and percentage of mine workers employed
were found to be approximately the same, Figure III.23 also shows the
regional distribution of mine workers employed.
IIJ-33
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Practically all production from mines with productivities of more
than 100 tons per manshift caine from the Eastern rind Western Northern
Great Plains.
Figure 111-24 shows that about 48', of all auger mines were smaller
than 50,000 tons per year. These smaller mines employed 55% of the mine
workers used in auger mining and produced less than 8" of all bituminous
coal from auger mines.
As shown in Figure 111-25 about 40'.- of all auger mines have pro-
ductivities of less than 4 tons per manshift, illustrating the relatively
small size of most of these operations.
As can be seen in Figure 111-25 average productivities of smaller
auger mines were comparable with average productivities of strip mines
of the same size. However, average productivities of the largest auger
mines were up to three times as high as the average productivities of
strip mines of similar size.
Only 10 culm bank operations had production in 1976. The produced
a total of one million tons of bituminous and lignite coal while employ-
ing 167 mine workers (see Table III-2). The size and productivity of
these operations varied considerably as can be seen in Figure 111-25,
where the production and productivities for the individual operations
r-
are shown. One operation had no ore :han 1,000 tons of production at
an average productivity of one ton per manshift; the largest operation
had half a million tons of production with a,'i average productivity of
38 tons per manshift. Half of the culm banks each produced less than
25,000 tons in 1976. Also about half of the culm bank operations had
productivities smaller than the average strip mine productivity as shown
in Figure 111-26.
111-35
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111-38
-------
As shown in Table III-3of all producing auger mines 8?% were
active during the whole year, 9?5 closed temporarily and another 9". closed
permanently. For culm banks the percentage of mines closing temporarily
or permanently was much higher, 20:^ each. However, the small sample size
(10 culm banks) renders these percentages somewhat unreliable for definite
conclusions.
d. Distribution of Anthracite Mine Sizes and Productivities
Anthracite production in 1976 took place only in northern App?'''un'?.
The 204 mines produced 6.4 million tons while employing 2,439 mine workers.
Production was by three types of mines: underground, strip and culm b?.tik
mines.
Forty-six percent of all mines producing anthracite in 1976 were
strip mines, which produced 61% of all anthracite and employed 84'J of all
mine workers. Twenty-nine percent of all anthracite mines were underground
mines, producing 15'- of all anthracite while employing ?.% of the work
force. Twenty-five percent; of the anthracite :'r;rines" wore culm bcnks,
which accounted for 24^ of total anthracite produced while employing 10-
of all anthracite mine workers.
As shown in Figure 111-27 about 80/j of all underground anthracite
mines produced less than 20,000 tons in 1976. Those mines employed 25%
of underground anthracite mine workers and produced 15% of underground
anthracite coal.
As shown in Figure 111-28 the average productivity of underground
anthracite mines with more than 10,000 tons production in 1976 was generally
comparable with that of underground mines of the same size producing bi-
tuminous and lignite coal. Mines with less than 10,000 tons of 1976 pro-
duction experienced productivities higher than the average productivity
of bituminous and lignite underground mines of the same size.
Cumulative distributions of the number of mines, the number of mine
workers and anthracite produced by strip mines are shown in Figure Hl-29.
111-39
-------
TABLE 111-3
NUMBER OF AUGER MINES AND CULM BANKS IN CENTRAL APPALACHIA,
NORTHERN APPALACHIA AND THE MIDWEST, WHICH WERE REPORTED
ACTIVE. HAVING TEMPORARILY CLOSED OR HAVING PERMANENTLY CLOSED DURING 1976
Northern Appalachia:
Mines
Central Appalachia:
Mines
AUGER MINES
TEMPO-
RARILY
ACTIVE CLOSED CLOSED TOTAL
CULM BANKS
TEMPO-
RARILY
ACTIVE CLOSED CLOSED TOTAL
56 6 3 65 4 1 27
86.1 9.3 4.6 100.0 57.1 14.3 28.6 100.0
127
80.4
13
8.3
18
11.4
158
100.0
Midwest:
Total
Mines
%
2
66.6
1
33.4
0 3
0.0 100.0
Mines 183 19 21 223 6 2 2 10
% 82.0 9.0 9.0 100.0 60.0 20.0 20.0 100.0
SOURCE: MESA
111-40
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111-43
-------
Fifty percent of the work force in those mines was employed by 12% of all
strip mines, which individually produced at least 50,000 tons in 1976,
arid as a group accounted for 58" of all production. Shown in Figure 111-30
average productivity for those strip mines was generally lower than the
average productivity of strip mines producing bituminous and lignite coal
in 1976, vjhile thr.t of the culn banks greatly exceeded average produc-
tivities for bituminous and lignite strip mines.
As shown in Figure 111-31 50* of all worker employed by culm
bank operations worked in operations with more than 25,000 tons of anthra-
cite production in 1976. In total these mines produced more than 85fj of
all anthracite from culm banks.
Table 111-4 shows, for anthracite mines and for bituminous and
lignite mines, the percentages of active mines, mines which closed tem-
porarily and mines which closed permanently in 1976 in Northern Appala-
chia.
A larger percentage of underground anthracite mines closed per-
manently than was found to have been the case for underground lignite
and bituminous mines; possibly indicating an older mine population. The
percentage of temporary closures for underground anthracite mines was
significantly smaller than that for underground bituminous mines.
Anthracite strip mines experienced significantly higher percentages
of closures than did bituminous and lignite mines.
A comparison of anthracite culm banks with bituminous and lignite
culm banks is not really possible because of the small number (i.e. 7) of
culm banks in Northern Appalachia producing bituminous coal. However,
compared with strip mines, anthracite culm banks had a significantly
higher percentage of temporary closures and u significantly smaller per-
centage of permanent closures.
111-44
-------
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111-46
-------
TABLE III-4
NUMBER OF MINES IN NORTHERN APPALACHIA, PRODUCING BITUMINOUS & LIGNITE
COAL AND ANTHRACITE RESPECTIVELY, WHICH WERE REPORTED ACTIVE,
OR TO HAVE TEMPORARILY OR PER11ANENTLY CLOSED,
TYPE OF MINES
Underground: Mines
Strip:
Mines
Culm Bank: Mines
BITUMINOUS & LIGNITE
TEMPO-
RARILY
ACTIVE CLOSED CLOSED TOTAL
ANTHRACITE
TEMPO-
RARILY
ACTIVE CLOSED CLOSED TOTAL
147
84.0
795
86.0
4
57.1
16
9.0
64
7.0
1
14.3
13
7.0
64
7.0
2
28.6
176
100.0
923
100.0
7
100.0
44
84.6
66
66.0
44
78.6
2
3.8
15
15.0
9
16.1
6
11.6
19
19.0
3
5.3
52
100.0
100
100.0
56
100.0
Source: MESA
111-47
-------
IV. COAL MINE PRODUCTION COSTS
IV.1 INTRODUCTION
Coal mine production costs depend on the following factors:
t Mining conditions (i.e., geology and topography of
the coal seam);
Mix of management, labor and technology used;
External constraints such as environmental regula-
tions;
Cost of money;
Taxes.
The first five sections of this chapter discuss the historical
trend in mine labor productivity (Section IV.2), labor and equipment
costs (Section IV.3), the estimated costs of various regulatory con-
straints imposed on coal mining (Section IV.4), the cost of money for
coal mining firms (Section IV.5) and taxes (Section IV.6).
Section IV.7 discusses the method used to obtain production
cost distributions for underground and surface mines in different
regions.
IV-1
-------
IV.2 HISTORICAL TRENDS IN MINE LABOR PRODUCTIVITY
Historical trends in the underground and surface mine product-
ivity index are shown in Figure IV.1 for the period from 1950 through
1976.
Underground mine productivity, i.e., average tons produced per
man-shift, increased steadily until 1966 at an average rate of 4% per
year with the introduction of new mining methods and the maturing of
the labor force; it remained stable for the following two years, then
began a precipitous decline in 1969 which continued until 1976. This
steep decline in mine worker productivity, reducing average output
per man-shift by as much as 40%, is generally ascribed to the enforce-
ment of safety regulations incorporated in the Mine Health and Safety
Act of 1969.
The surface mine productivity index shown in Figure iv.l also
shows a gradual increase until 1966 at an average rate of 6% per year,
leveling out in 1974. Between 1974 and 1976 average surface mine
productivities fell by 40%, most probably because of increased enforce-
ment of State reclamation standards.
IV-2
-------
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IV-3
-------
IV.3 HISTORICAL TRENDS IN MINE LABOR AND EQUIPMENT COSTS
As shown 1n Figure IV.2 the index of average hourly earnings
1n bituminous mines in constant dollar terms (i.e., deflated by the
GNP deflator) Increased at an average rate of about 4.0% per year
from 1950 until 1957; it remained relatively flat through 1968 and
increased again at an average rate of 4.0% per year until 1976.
The constant dollar wholesale price index for mining machinery
and equipment followed the same general pattern as the labor cost index
during the period from 1950 through 1968; it increased at an average
rate of 5% per year until 1958, remained relatively stable through
1968. However, between 1968 and 1974 the index declined at an average
rate of 2% per year. It surged at an average rate of 10% per year
between 1974 and 1976; the sudden increase in demand for coal as a
fuel, caused by the fourfold increase in the price for imported oil,
resulted in an unforeseen increased demand for mining equipment which
led to the equipment price increases indicated by the steep rise in
price index.
IV-4
-------
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IV-5
-------
IV.4 COSTS OF REGULATORY REQUIREMENTS
The impact of regulatory constraints on coal production costs
has been significant. The most important regulatory constraints
imposed on the coal mining industry have been the following:
The Federal Coal Mine Health and Safety Act of 1969
and the Mine Health and Safety Act Amendments of
1977, which concentrate on the improvement of safety
in the operation of coal mines, especially under-
ground mines.
The Federal Black Lung Benefits Act of 1972 which
was intended to assist miners affected by the black
lung disease; partly as a result of the Act, coal
companies now carry a black lung insurance program,
the costs of which may represent up to 25% of direct
labor costs in the East and 5-10% of direct labor
costs in the West.
The Federal Surface Mining Control and Reclamation
Act of 1977 which is intended to control the issu-
ance of surface mining permits and to minimize the
environmental impacts by surface mining or by
surface operations of underground mines.
The Federal Water Pollution Control Act Amendments
of 1972, which charged the Environmental Protection
Agency with establishing effluent limitations for
discharge point sources.
The impact of these four Acts on coal production is hard to
estimate for individual mines. However, the historical time series
of the production indices, discussed in the previous section, allow
some idea of how large the cost impact of the regulations has been.
IV-6
-------
As shown in Figure IV. 1 , average productivity in underground mines
decreased by about 45% between 1967 and 1969. Depending on the inter-
pretation given to this index it can be inferred that underground
mine production costs increased from 30-50%.' '
On average the costs of the Black Lung Insurance program is
estimated to be 25% of direct labor costs for Eastern underground mines.
This implies that for underground mines the average production costs
are increased by 10% for Black Lung Insurance premium payments. For
surface mines the same type of payments are estimated to be 3-5% of
average production costs.
An estimate about the average impact of regulations.governing
surface mining operations and the reclamation of lands disturbed by
surface mining operations can be obtained when considering the decline
in the surface mine productivity index, which in Figure IV.1, is
shown to have declined by about 30% between 1973 and 1976.
The impact of this productivity decline can be estimated to
have resulted in a production cost increase of 10-20%, depending on
whether this decline in productivity resulted in an increase in labor
costs alone or in an increase in all productivity-related costs.
Generally, the cost impact is estimated to have been lower for surface
mining operations in the West, Southwest and Midwest than for surface
mining operations in the East.
The Federal Surface Mining Control Act of 1977 instituted an
Abandoned Mine Reclamation Fund requiring payment by coal producers
of a fee of $0.35 per ton for surface mining, $0.15 per ton of coal
produced in underground mines and-$0.10 per ton or lignite produced.
^ 'Assuming that direct labor costs make up about 40% of total under-
ground production costs, a 45% reduction in labor productivity
implies an increase of at least 30% total production costs; if other
costs (e.g., mining equipment, power and supplies) were similarly
affected by the decline in productivity, then production costs for
underground mines would have increased an estimated 50% (Table IV-1),
IV-7
-------
TABLE IV.1
ESTIMATED TOTAL INCREASE IN THE ESTIMATED AVERAGE
1968 PRODUCTION COST FOR EASTERN UNDERGROUND
AND STRIP MINES RESULTING FROM REGULATIONS
(In 1977 Dollars)
Estimate of Average
Production Cost in 1968
(1)
Underground
Mines
($/Ton)
9.00
Strip
Mines
TfTroh)
6.40
Estimated Cost Increase
Caused by:
The Coal Mine Health and
Safety Act
2.70 to 4.50
0.0
The Black Lung Benefits Act
0.90
0.20 to 0.30
State Surface Mining
Regulations
0.65 to 1.30
Federal Surface Mining Control
and Reclamation Act
0.10
0.35 to 2.35
EPA Water Pollution
Control Standards
Total Estimated Cost Increase
0.20 to 0.75
3.90 to 6.25
0.20 to 0.75
1.40 to 4.70
* 'Estimate based on Bureau of Mines data on average price of
coal sold or consumed in 1968.
IV-8
-------
Depending on the nature and degree of enforcement of existing State
regulations, the Federal Surface Mining Act is expected to delay new
mine openings. The Act will also increase production costs, by any-
where from a minimum of $0.35 per ton for surface mines and $0.15 per
ton for underground mines (consisting of payment of the above-mentioned
reclamation fee) to an estimated high of $2.00 per ton in states where
existing laws are not very stringent and where restoration of surface
land disturbed by mining operations will be difficult (e.g., steep
slopes and thin coal seams).
The estimated cost impact of the guidelines for water point
source performance standards for 1977 which the EPA issued for the coal
mining industry and for coal preparation plants varied from a low of
$0.01 to $0.07 per ton for underground and surface mines in the West
to a high of $0.20-$0.75 for respectively surface and underground
mines in the East. '
In addition to the direct cost impacts from the regulations
discussed above, it can be expected that the requirement for strip
mining permits, which generally require an environmental impact state-
ment, will have some cost implications and may cause delay in the dates
when actual mining operations can start.
Economic Impact of Effluent Guidelines, Coal Mining, Report to
U.S. Environmental Protection Agency, by Arthur D, Little, Inc.
IV-9
-------
IV.5 COST OF CAPITAL
n/^5.1 Defining the Cost of Capital
Most firms have a target rate of return for evaluating the rela-
tive attractiveness of different investment opportunities. This rate
is used to discount projected cash flows to determine the net present
value of a particular investment opportunity.
The target rates of return for companies which are actually
used in investment decisions are not easily obtained since that type
of information is regarded as proprietary. However, capital market
research has resulted in a method which can be used to calculate
nominal rates of return representing minimum rates of return which a
firm should be earning in order to stay in business.
This nominal rate of return is the weighted cost of capital/ '
which accounts for the respective costs of the mix of different sources
of financing present in a firm's capital structure, which can be made
up of funds obtained externally through bank loans, or by issuing
long-term debt and preferred or common stock.
The formula used to calculate the weighted average cost of
capital has the following general format:
WACC = (Ke VE/VF) + (Kd VD/VF) (1-t),
where:
WACC = a firm's weighted average cost of capital,
VE = the market value of a firm's stock,
VD = the market value of a firm's debt,
VF = VE + VD = the firm's value in capital markets,
Ke = the average cost of the firm's equity capital,
* 'Cost of money and cost of capital, as used in this section, are
synonymous.
IV-10
-------
Kd = the average cost of the firm's debt capital,
t = the corporate income tax rate (= 0.48).
The cost of equity is the minimum rate of return which a
company must earn on the equity-financed portion of its investments
in order to keep the market price of its stock constant. In general,
if the company's earnings fall short of a shareholders' expectations,
they will sell the firm's stock, with a depressing effect on the market
price of that stock.
The estimation of this required rate of return of a firm's
stock traded in a stock market has received much attention in the liter-
ature dealing with capital market theory and practice. One of the
outcomes of this research is a very practical method which allows one
to calculate the required rate of return for a stock from, in the
first place, the variability of the stock's market price over time
relative to the variability over time in the average price of all
stocks in the market and, secondly, the correlation of the stock's
price changes over time with changes of the average market price.
Stockholders can safeguard themselves against lower-than-aver-
age returns from a particular stock at any one time by investment in a
large enough number of stocks which are independent of each other;
over any given period a lower-than-average return of one stock will
be offset by a higher-than-average return of another stock. It has
been shown by capital market theory that a rational investor with a
consistent set of risk preferences would require a stock to have a
higher return than the average return of the market if the stock's
earning patterns have more variability over time than the average
earning patterns of the stock market and if the stock's earning pat-
terns show a higher correlation with the market's earning patterns.
It has been demonstrated that this risk premium, inherent in a firm's
cost of equity capital, is captured by the following relationship:^ '
* 'For a more elaborate treatise on the subject see: Richard A. Brealey's
An Introduction to Risk and Return From Common Stocks, MIT Press;
Studies in a Theory of Capital Markets, Michael Jensen, editor,
Praeger Pub! ishers.
IV-11
-------
Ke = rf + (rm - rf) B
where
Ke = (P (T) - p (T-!))/P (T-l), the change 1n the
price of stock (i.e., Its return on earnings)
between time (r-1) and (T);
rf » the risk-free rate of return which can be obtained
by investment in issues with guaranteed rates
of return (e.g., Treasury Bonds);
rm = the average annual return (i.e., average annual
relative price changes) of all stocks in the
market between (r-1) and (T);
B * cc (sdi/sdm), the measure of stock's riskiness
where:
cc = the correlation coefficient between stock's
earning changes over time and the average
market earning changes over time-,
sdi « the standard deviation of stock's earning
changes over time (i.e., a measure of the
variability in the stock's earnings);
sdm = the standard deviation of the market's
earning changes over time.
This rate of return required by stockholders represents the
minimum cost of equity (Ke) to the firm.
This relationship was used to estimate the cost of equity for a
selected number of coal companies in 1976. For the risk free rate,
rf, the yield of 4.98% from short-term Treasury Bills for the last
IV-12
-------
quarter of 1976 was used. The average return of all stocks in the
stock market, rm, was calculated to have been 17.85% in 1976 based on
Standard 4 Poor's Index. The data values for B, the measure of the
perceived riskiness of the stock of each of the individual firms, was
obtained from the Value Line Investment Survey's publications.
The cost of a firm's debt is essentially the interest which it
has to pay on its bonds. Bond markets reflect changes in interest
rates of outstanding issues through market value changes. For example,
outstanding issues will have higher market values which will reduce
the effective interest rates of these issues to present-day interest
levels.
Since market values of issues outstanding with the different
companies in the sample are very difficult to obtain, we used the
book or nominal value of these issues and a representative interest
rate on present-day bond issues in our cost-of-capital calculations.
Recent bond issues for firms with A to AAA ratings have yields ranging
from 8.38-8.75%; we used an average yield of 8.56£. This will have
resulted in an underestimate of the cost of capital for firms with
lower bond ratings; however this amounted to an error of not more
than 0.5% in the estimated cost of capital which generally was calcu-
lated to be around 15%.
IV.5.2 The Cost of Cajn'tal for Selected Companies Grouped by Major Activity
Using the methods discussed in the previous section, the cost
of capital was calculated for a sample of coal-producing companies
which were grouped by major activity (i.e., coal, oil, steel, utilities
and miscellaneous; see Section VII. 3 for a list of these companies).
Table IV.2 shows the average and standard deviation for each of the
groups of companies of, respectively, the "riskiness" measure B as
obtained from "Value Line", the ratio of equity capital over total
capital (VE/VF), the calculated cost of equity (Ke), the ratio of debt
capital over total capital (VD/VF), the calculated after tax cost of
debt (Kd), and the weighted average cost of capital (WACC).
IV-13
-------
TABLE IV.2
COST OF EQUITY, COST OF DEBT AND COST OF CAPITAL FOR SELECTED COMPANIES
WITH COAL PRODUCTION GROUPED BY MAJOR ACTIVITY OF OtJNER COMPANY
"RISKINESS"
1.
2.
i
4.
5.
OWNERSHIP GROUP
Coal: Mean)!!!
S.D. UJ
Oil & Gas:
Mean
S.D.
Utilities:
Mean
S.D.
Steel: Me an
S.D.
Miscellaneous:
Mean
S.D.
(B)
1.11
0.07
1.05
0.13
0.72
0.11
1.05
0.13
1.14
0.15
(1976)
Ratio of
Equity
Capital Cost of
VE Equity
VF
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
90
10
66
17
41
06
63
04
66
22
(Ke)
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
19
01
19
02
143
015
185
017
196
020
Ratio of
Debt
Capital
VD
VF
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
After
Tax ,, . Number of
Cost of Cost of Companies
Debt Capital In Sample
(Kd).(l-t) (Kf)
10
10
34
17
59
06
37
04
34
22
0.045 0.
0.
0.045 0.
0.
0.045 0.
0.
0.045 0.
0.
0.045 0.
0.
177
016
141
031
085
008
133
010
146
036
Group
5
8
9
5
9
(1
Cost of Capital, Kf=
income tax rate.
. Ke + . Kd . (1-t) where t=0.48, the corporate
Mean and Standard Deviation for the group of companies.
Source: "Value Line Investment Survey"; Annual reports and 10-K reports.
IV-14
-------
It appears in Table iv.3that the average riskiness of the
companies in the coal group, as perceived by investors in the stock
market, is not significantly different from the riskiness of other
companies in other groups, except for utilities for which the riski-
ness is viewed by investors to be significantly smaller: a B value of
0.72 versus 1.05 to 1.10 for all other groups.
The average ratio of equity capital, at market value, over total
capital for coal companies in 1976 was significantly higher at 0.9
than for any of the other companies; all the other companies had ratios
of around 0.65 except utilities, which were much more leveraged as
shown by an average equity over total capital ratio of 0.41.
The average cost of equity of companies in the coal group was
not significantly different from the average cost of equity found for
all the other groups (about 0.19) except again for the utilities group
(0.14). This can be expected, given the low perceived riskiness of
utilities, stocks and the relatively small amount of equity in their
capital structure.
The after-tax cost of debt for all groups was calculated to be
0.045, reflecting the average interest rate paid on bonds with A and
AAA ratings issued at the end of 1976.
As shown in Table IV.3 the calculated cost of capital turned out
to cluster in three groups of companies: the coal group companies with
a mean cost of capital at 0.177, utility companies at 0.085, and the
three other groups of companies combined at 0.144.
We calculated the t-statistics for the mean costs of capital of
the three groups, assuming that the cost of capital calculated for indi-
vidual firms were distributed normally. As shown, the mean cost of
capital for the coal group at .177 was found to be significantly dif-
ferent, i.e., at the 0.98 confidence level, from the mean cost of
capital for the combined oil and gas, steel and miscellaneous groups;
this last group's mean cost of capital of 0.144 was found to be signi-
ficantly different, i.e., at the 0.995 confidence level, from the mean
cost of capital of 0.085 found for the utility group.
IV-15
-------
TABLE IV.3
TEST ON THE SIGNIFICANCE OF THE INFLUENCE
BETWEEN THE MEAN COST OF CAPITAL AS
CALCULATED FOR THREE GROUPS OF OWNER COMPANIES
-COST OF CAPITAL IN 1976-
STANDARD NUMBER OF
OWNER COMPANIES MEAN DEVIATION COMPANIES t-STATISTIC
1. Coal 0.177 0.016 5
2.22
2. Oil & Gas,
Steel,
Miscellaneous 0.144 0.031 22
3. Utilities 0.085 0.008 9
5.52(3)
* t-Statistic calculated to test the significance of the
difference between the mean cost of capital calculated
for the three different groups shown.
Indicating a significance in the difference between the
mean cost of capital of group 1 and 2 at the 0.98
conf idence leve1.
Indicating a significance in the difference between the
mean cost of capital of group 2 and 3 at the 0.995 con-
fidence level.
IV-16
-------
The main reason for the difference 1n the cost of capital between
the coal group and the combined oil and gas, steel and miscellaneous
group was the lower debt/equity ratio 1n the capital structure of com-
panies 1n the coal group. It appears that coal companies could reduce
their cost of capital by an Increase of their 1976 debt/equity ratio to
a level comparable with that of the other groups studied.
The much lower cost of capital of 0.085 of the utility group 1s
explained by first, the much lower perceived riskiness by the stock
market of utilities and second, the much higher debt portion of total
capital which utilities, as a closely regulated Industry, can afford
to carry.
IV-17
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IV.6 TAXES AND ROYALTIES
The different taxes to which the coal mining industry is subject-
ed are shown in Table iv.4 An operator, in exchange for the right to
mine coal on another party's land, will pay, in addition to the initial
annual lease rentals, a royalty based on the mine's gross production.
Royalties are negotiable and can vary considerably depending on the
supply/demand expectations for the particular mineral concerned and
the finding record for that mineral on nearby properties at the time of
negotiation between the landowner and the prospective operator.
In the Appalachian coalfields, royalties are generally around
7% of the coal sales value for surface mines and around 5% for under-
ground mines. Royalties for mines on land owned by the Federal Govern-
ment (a frequent occurence in the West) are 12.5% of sales; lignite
mine operators in Texas generally pay royalties of 5% of sales.
The State and/or local governments usually levy a production
tax or sales tax, as a percentage of the sales value, and a severance
tax on depletion of non-replaceable resources, which is commonly
specified in terms of dollars per unit produced. Table iv.5 shows the
current rates of these taxes in different coal-producing states.
The Federal government taxes the net income from the mining
operation, which is calculated according to the formula specified in
Table IV.6 The depreciation allowance specified in Table IV.6 is
based on the book value of buildings and equipment; the allowance
consists of an annual write-off of a portion of this book value over
the life of the particular item; the method of calculation for the por-
tion which can be written off and the life of the particular item is
specified in the Federal tax code.^ ' The depletion allowance allows
the company to exempt a percentage of its production from taxation.
Currently, the depletion allowance rate is 10% of net production; net
production means sales minus royalty and severance and/or production
taxes.
* 'Linear depreciation or double declining balance depreciation are
allowed for coal mining operations.
IV-18
-------
TABLE IV.4
DIFFERENT TYPES OF TAXES
PAID BY THE COAL MINING INDUSTRY
RECIPIENT OF TAX
TYPE OF TAX
Landowner
Royalty
State and/or local
Government
Production Tax
Severance Tax
Federal Government
Income Tax
IV-19
-------
TABLE IV.5
STATE
A1 abama
Alaska
Arizona
Arkansas
Colorado
Illinois
Indiana
Iowa
Kansas
Kentucky
Maryland
Missouri
Montana
New Mexico
North Dakota
COAL SEVERANCE TAXES -
TAX
13.5$/ton
No Current Tax
No Current Tax
2*/ton
60
-------
TABLE IV.6
FEDERAL INCOME TAX CALCULATION FORMULA
FIT = (GAP x (1 - ry - st) x PRICE - AOC - DEPR - DEPL) x t, where
FIT = Federal Income Tax
GAP = Gross Annual Production
ry = Royalty Rate
st = Severance and/or Production Tax Rate
PRICE = Unit Price
AOC = Annual Operating Costs
DEPR = Depreciation Allowance for capital items
DEPL = Depletion Allowance
t = Federal Tax Rate
IV-21
-------
IV.7 PRODUCTION COSTS
JV.7.1 Overview^
Given the high variation in mine labor productivity discussed
1n Section m.4> coal mine production costs can also be expected to
vary quite significantly. However, given a lack of appropriate data
1t Is very difficult to determine by how much. Coal production cost
data for individual mines are not available because coal-producing
firms consider public knowledge of this data as a potential threat to
their competitive position.
Changes in production costs as a function of changing labor
productivity can, to an extent, be derived through analysis of model
mine costs. Assuming specific mining conditions it is possible to
cost a mine out and it can be determined how investment and production
costs will change with different geologic conditions. However, geo-
logy and topography represent only one set of factors impacting on
mining costs. Other factors are: the mining technology used, the
quality of labor and management and labor/management relations, and
the impact of so-called external constraints. In absence of consis-
tent analyses of how these other factors affect production costs,
one has to apply judgement when deciding how to derive production cost
distributions from the productivity distributions for existing mines
discussed in Section 111.4.
There 1s a wealth of data available on prices paid for coal
sold under various types of contracts and in the spot market, Infor-
mation which utilities have to file with the FPC on their fuel pur-
chases.(1)
It 1s generally assumed that supply conditions in the utility
steam coal market are sufficiently competitive to force producers to
sell at prices which reflect investment and production costs plus an
"'FPC Form 423, Monthly Report of Cost and Quality of Fuels for
Electric Plants.
IV-2 2
-------
adequate rate of return. Therefore, prices paid for coal sold under
recent user contracts can be assumed to be a good first approximation
of mine production costs including a rate of return on investment.
A close match was found between the range of estimated break-
even production costs, derived by model mine production cost analysis,
(i.e., including a capital charge) for mines producing in 1976 and new
1976 contract prices FOB the mine, as derived from the FPC data base.
Based on this test it was concluded that actual distributions of mine
production costs can be adequately approximated by this method.
IV.7.2 Model Mine Cost Analysis
As shown in Table IV.7. factors which impact on mine production
costs can be organized into the following major groups:
The geological and topographical conditions (e.g.,
seam characteristics, seam depth, landscape contour);
The mining technology (e.g., type of mining equip-
ment, overburden excavation methods);
The quality of labor and management;
External constraints (e.g., environmental regulations).
Model mine analyses use costs of current technology best suited
to the particular mining situation given by a specific set of geological
and topographical conditions.
Analyses which show how production costs change as a function
of changes in the quality of the technology used, do not seem to be
available. This makes it impossible to find out how much of the varia-
tion in the distribution of labor productivity of existing mines can
be expected to result from utilization of different types of techno-
logy; in general, the older the mine the older the mining technology.
IV-2 3
-------
TABLE IV ..7
GROUPS OF FACTORS WHICH IMPACT
MINE PRODUCTION COSTS
GROUPS OF MINE FACTORS:
Quality of Labor External
Mine Life Stages: Geology/Topography Technology and Management Constraints
Access to Mine Site
Mine Development
Mine Production
Mine Termination
X
X
X
X
X
X X
XXX
X X
IV-2 4
-------
Similarly, no studies have been found correlating production costs
and quality of management and labor (or of management/labor relations).
Therefore, model mine cost analysis only allows one to find out more
about production cost changes as a function of changing geological and
topographical conditions. Figure IV.3 shows the numerous factors which
need to be considered when costing out the surface mine.
As schematically shown in Figure IV.4, surface mining conditions
and consequently surface mining methods in the East (i.e., the
Appalachian region), the Midwest and the West differ significantly;
production costs for these three different regions are quite different.
Underground mine production costs also depend on a number of
geological factors as shuv/n in Table IV.8 where the typical ranges
of values for these factors are qiven. One approach to underground
mine costing is shown in Figure IV.5.
The relative values of investment and operating costs for typi-
cal new surface and underground mines in the different areas are
shown in Table IV.9. The relative contribution to a calculated
breakeven or minimum required price (MRP) of the investment costs and
operating costs, is also shown in Table IV.9. This breakeven price
was calculated using the formula shown in Figure IV.6.
The breakeven prices shown in Table iv.9 can be considered to
represent typical 1977 values for the particular regions; somewhat
high for the underground mine shown and somewhat low for the strip
mines in the East and the Midwest since the productivity used to
calculate the mining equipment and operating costs for these mines
was respectively lower than average for the underground mine and higher
than average for the surface mines. The higher MRP calculated for the
Montana strip mine compared with the MRP calculated for the NGP
strip mine reflects the higher State severance tax operators have to
pay in Montana than in the other Northern Great Plains states.
IV-2 5
-------
FIGURE IV-3
EXAMPLE OF SURFACE MINE COSTING MODEL
INVARIABLE
OVERBURDEN CHARACTERISTICS
TOPOGRAPHIC CHARACTERISTICS
THICKNESS VARIABILITY
NECESSITY OF SHOOTING AND
RESULTING FRAGMENTATION
STRATIGRAPHIC ARRANGEMENT
STABILITY AND STACKING QUALITIES
PRESENCE OF ACQUIFERS
COAL CHARACTERISTICS
QUANTITY OF RESERVES
QUALITY OF RESERVES
PRESENCE OF MULTIPLE SEAMS
ATTITUDE OF SEAMIS)
THICKNESS OF SEAM(S)
NECESSITY OF SHOOTING
OTHER FACTORS
CUSTOMER QUALITY AND PRODUCTION
REQUIREMENTS
WEATHER CONDITIONS
RECLAMATION AND ENVIRONMENTAL
REQUIREMENTS
MANUFACTURER'S EQUIPMENT SPECI-
FICATION AND LOAD TIMES
EQUIPMENT AND SUPPLIES COST DATA
WAGE AND SALARY SCHEDULES
SAFETY REGULATIONS
VARIABLE
SELECTION OF MINING METHOD
LOCATION AND ORIENTATION OF ANNUAL CUTS
DETERMINATION OF AVERAGE AND MAXIMUM STRIP RATIOS
SELECTION OF PRIMARY STRIP EQUIPMENT
CALCULATION OF INDIVIDUAL PIT
DIMENSIONS
SELECTION OF AUXILIARY EQUIPMENT
CALCULATION OF SUPPLIES REQUIRED
ORGANIZATION AND MANPOWER SCHEDULING
CALCULATION OF MINE CAPITAL AND OPERATING COSTS
IV-26
-------
FIGURE IV-4
ILLUSTRATIONS OF SURFACE MINING CONDITIONS IN THREE MAJOR REGIONS
ROCKY MOUNTAIN REGION
OPEN PIT MINING
AREA MINING
MIDWEST REGION
AREA MINING
APPALACHIAN REGION
CONTOUR MINING,
HILLTOP REMOVAL
IV-2 7
-------
TABLE IV-8
MINE PRODUCTION VARIABLES DEPENDENT ON
GEOLOGIC AND TOPOGRAPHIC CONDITIONS
Seam Characteristics
Seam thickness
Depth of cover
Roof conditions
Floor conditions
Gas emissions
Seam Gradient
Mine Type
Drift
Shaft
Slope
Mining System
Continuous
Conventional
Long wall
Haulage System
Track coal haulage
Belt coal haulage
Mine Characteristics
Mine size (any)
Mine life (any)
(dictated by mine location)
(3 ft., 5 ft., 7 ft.)
(500 ft., 1000 ft., 1500 ft.)
(good, poor)
(hard, rutted, rutted-wet)
(low, moderate, high)
(0°, 6°)
(dictated by topography and depth of cover)
(dictated by seam characteristics)
(dictated by seam characteristics)
IV-2 8
-------
FIGURE IV-5
EXAMPLE OF AN UNDERGROUND MODEL MINE COSTING MODEL
INPUTS TO MODFL
MINE TYPE (DRIFT, SLOPE. SHAFT)
MINING SYSTEM FMPLOYFD
YEARLY DESIGN CAPACITY
MINE LIFE
SEAM CHARACTERISTICS
WORKING SCHhDULE (SHIFTS DAY. DAYS/YEAR)
DESIRED RATE OF RETURN
PRODUCTION
SIZING
"' EQUIPMENT
AND
CONSTRUCTION
MANPOWER
IV SUPPLIES
AND
MATERIALS
POWER
VI.
PREPRODUCTION
DEVELOPMENT
v" MINE COST
AND
INTEREST
VIII.
Dl I'Rl.C IATION.
DEFERRED
CAPITAL
IX.
ANNUAL
OPLRAT1NG COST.
WORKING CAPITAL
X.
PRODUCTION
COST/TON
IV-2 9
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IV-30
-------
FIGURE IV-6
FORMULA USED TO CALCULATE THE
MINIMUM REQUIRED PRICE (MRP) FOR COAL FOB THE MINE
MRP = [ PV (I.(l-cr) - DEPR t) + PV OC (1-t)]/ PV (PROD) FACTOR, where
MRP = the minimum required price (in $/ton)
PV = the present value operator on annual expenditures over the
life of the mine (including the preproduction construction period)
I = the annual investment made in mine and equipment during the
life of the mine
DEPR = the annual depreciation of mine and equipment investment
OC = the annual operating costs incurred during the operating
life of the mine
PROD = the annual production (assumed to be constant over the life
of the mine)
FACTOR = (1 - ry - st) (1 - t + t da)
cr = the investment credit rate applicable to the specific investment
category
t = the federal tax rate
ry = the royalty rate
st = the severance tax rate
da = the depletion allowance rate
-31
-------
Using a computer program to calculate the MRP's for the same
model mine assuming different labor productivities caused by differ-
ences in geological and topographical conditions allows one to derive
a functional relationship between these two variables. The results
of this analysis for large underground mines and large surface mines
in the East are respectively shown in Figures IV-7 and IV-8.
The sensitivity of the MRP changes as a function of changes
in productivity shown in Figure IV-7 and IV-8 is largely dependent
on how sensitive one assumes mining equipment costs and operating
costs to be to changes in labor productivity. Figure IV-9 illustrates
this sensitivity assuming a simple functional relationship between
cost and productivity.
The degree of sensitivity is reflected in the value of the
F-factor:* a value of F of close to one reflects a strong dependence
of the cost on productivity; an F-value close to zero reflects a weak
dependence. In the calculations of MRP as a function of productivity
shown in Figure IV-7 and IV-8, an F-factor value of 0.9 was used for
all costs directly related with labor productitivy, i.e., mining
equipment, wages, power and supplies.
Using the 1976 productivity distributions from MESA data for
existing large (i.e., with more than 100,000 tons production in 1976)
underground and surface mines in the Appalachian and the Midwest shown
in Figures IV.10 and IV.11, MRP's were derived for the lowest and highest
points on these distributions delineating the 90%, 80% and 70% confi-
dence intervals.
The lowest and highest productivities"delineating the three
confidence intervals on the productivity distributions are shown in
*F-factor is defined in terms of the relationship: Operating Cost
a (Productivity)'*7.
IV-32
-------
FIGURE IV-7
MINIMUM REQUIRED PRICE AS A FUNCTION OF PRODUCTIVITY
LARGE UNDERGROUND VINES IN THE EAST AND MIDWEST
50
-------
IV-34
-------
FIGURE IV-9
PRODUCTION COSTS (= OC) AS A FUNCTION OF MINE
PRODUCTIVITY WITH DIFFERENT F-FACTORS (1)
(1) Definition of F-Factor: OC/OC* = (PRTY*/PRTY)'
Where OC = Operating Costs
PRTY = Productivity and
PRTY*, OC* = Model Mine Productivity, Costs
PRTY*/PRTY
0.5
0.75
1.0
1.5
2.0
= 1
0.5
0.75
1.0
1.5
2.0
0.8
0.57
0.79
1.0
1.38
1.74
F = 0.6
0.66
0.84
1.0
1.28
1.52
0.4
0.76
0.89
1.0
1.18
1.32
F = 0.2
0.87
0.94
1.0
1.08
1.15
IV-35
-------
o
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IV-36
-------
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Table IV-10. The MRP's corresponding with these low and high product-
ivities are shown in Table IV-11, both in terms of dollars per ton and
in cents per million Btu's (1977 dollars).
The largest range in productivities was found to exist for
underground mines. Depending on the percentile interval, the highest
productivity was found to be 2.5 times (for the 70 percent interval) to
4 times (for the 90 percent interval) the lowest productivity (see
Table IV-10). The corresponding ranges for surface mine productivities
were found to be 2.0 (for the 70 percent interval ) to 3.0 (for the 90
percent interval ). The ranges between the low and high MRP's derived
from these productivities were found to have narrowed by ten to fifteen
percent.
In order to obtain an idea of how well the MRP's shown in
Table IV-11 approximate actual prices paid for steam coal, FOB mine
mouth prices were derived from the FPC data base for utility coal
delivered under new contracts in 1976. The source and destination
information for coal deliveries allowed to make an approximate correc-
tion for transportation costs. New contract prices for 1976 were thought
to best reflect the investment and production cost conditions for exist-
ing and new mines in 1976.
Table IV-12 shows the results of the FPC price analysis. New
contract steam coal prices paid by utilities in 1976 ranged from a low
57 cents per MMBtu to a high 135 cents per MMBtu for Appalachian coal
and from a low 54 cents per MMBtu to a high 138 cents per MMBtu for
Midwestern coal. As shown in Table IV-13 these ranges for actual
prices correspond closely with the ranges of model mine breakeven
prices when app]ied to productivities of existing mines in the corres-
ponding regions. From the results it can be tentatively concluded
that highly productive surface mines in the two regions analyzed proba-
bly have significantly higher-than-average returns. The results clearly
support the hypothesis that new steam coal contract prices correlate
closely with mine production costs, because market conditions force
IV-38
-------
TABLE IV-10
HIGH AND LOW PRODUCTIVITIES FOR EXISTING UNDERGROUND
AND SURFACE MINES IN THE EAST AND THE MIDWEST
UNDERGROUND MINES, EAST AND MIDWEST
Confidence Levels' '
90%
80%
70%
Confidence Levels
90%
80%
70%
Confidence Levels
90%
80%
70%
High
25.0
21.0
17.5
SURFACE MINES
High
35
31
29
SURFACE MINES,
High
42
39-
36
Low
6.0
7.0
7.5
, EAST
Low
12
14
15
MIDWEST
Low
15
17
19
High 4 Low
4.0
3.0
2.5
High + Low
3.0
2.2
2.0
High * Low
2.8
2.3
1.9
^ 'The percent of mines contained by, respectively, the high and
low productivity.
IV-39
-------
TABLE IV-11
CALCULATED MINIMUM REQUIRED PRICES FOR EXISTING
UNDERGROUND AND SURFACE MINES IN_..THE EAST AND THE MIDWEST
UNDERGROUND MINES, EAST AND MIDWEST
Minimum Required Price ($/Ton)
Percent of Mines
Contained by High
and Low Productivity
90%
80%
70%
Percent of Mines
90%
80%
70%
Percent of Mines
90%
80%
70%
Low
10
11
12.5
SURFACE MINES
Low
7.5
8.0
8.5
SURFACE MINES,
Low
6.5
7.0
7.5
High High + Low
30 3.0
26 2.4
25 2.0
, EAST
High High + Low
18 2.4
16.5 2.1
15.5 1.8
MIDWEST
High High * Low
15.5 2.4
13.5 1.9
13.0 1.7
IV-40
-------
TABLE IV-12
NEW COAL CONTRACT PRICES
FOR UTILITIES IN 1976 ^
PA
WVAS
KYE
TENN
ALA
APPAL
ILL
KYW
MID-
WEST
CIF
FOB est.
CIF
FOB est.
CIF
FOB est.
CIF
CIF
FOB est.
FOB est.
CIF
FOB est.
CIF
FOB est
CIF
FOB est.
FOB est.
if /M
70 80 90 100
78 84 95
53 59 70
97
77
68 75
57 64
57 RANGE
in 1976
73 80 92
56 63 75
85 94
63 72
77
54
89 95
65 71
54 RAN
in 1
UOJ. # Trans-
nBtu Trans- Dis- port
115 130 150 175 actions tance Cost
$/MMBtu
105 119 17 600 25.
80 94
146 1 100 11.
135
109 122 143 155 17 500 23.
86 99 120 132
106 5 300 20.
86
2 100 11.
1 5C CO
103 8 175 17.
86
101 140 7 350 22.
79 118
108 116 5 430 23.
85 93
100 162 9 520 24.
76 -1 38
G E 138 29
976
H/L
1.77
1.53
2.37
1.54
1.87
1.72
2.12
2.56
(1) Source: FPC Form 423
IV-41
-------
TABLE IV-13
RANGE OF NEW STEAM COAL CONTRACT PRICES^ IN 1976 COMPARED WITH RANGE OF
MINIMUM REQUIRED PRICES CALCULATED FOR EXISTING MINES
New Coal Contract Price Range
Confidence Level s:
90%
80%
70%
Confidence Levels:
90%
80%
70%
Prices in
-------
operators to sell at prices which allow them to recover pocket
expenses, investment 1n mine and equipment and a return on that invest-
ment.
IV-43
-------
V. COAL TRANSPORTATION ECONOMICS
V.I INTRODUCTiO.J
Coal must be moved from the mine to the user and the cost of transportation
can be a significant portion of the delivered cost of coal. Table V-1 shows the
average share of total delivered cost of bituminous coal accounted for by the
"at mine" FOB cost and the transportation cost. It must be noted that these
averages are the result of many widely varying transport costs for individual
shipments. The basic determinants of transport cost are the mode of transport
used and the distance shipped. It is interesting to note that the share of
transport cost in total delivered cost has been declining since the early 1960's.
Between 1972 and 1975 the delivered coal prices to utilities have risen 213%
while the at-mine price of coal has risen by 251%.
The method used to ship coal depends on the distance to be moved and the
availability of specific means of transport between the origin and destination.
Short haul transport for gathering or distributing coal may economically use
rail, truck, conveyor belts, or pneumatic pipelines. Long distance (over 100
miles) coal movements are limited to four economically viable modes: rail, water,
slurry pipeline, and mine mouth location of the generating plant (shipping
electricity rather than coal). Some 54% moves to users by rail, 21% moves by
water, 14% moves by truck and 11% of coal is burned at mine mouth generating
stations (see Figure V-l). There is also one coal slurry pipeline in operation
at present which accounts for less than 0.1% of national coal movements.
Over long distances water is the lowest cost means of moving coal, but
it can be used only where waterways are available. Unit trains provide the
next most economical mode of transport, although coal slurry pipelines appear
to offer some cost advantages over rail for very large tonnages for shipments
V-l
-------
TABLE V-1
Share of Delivered
Accounted for
"At-Mine"
Total Cost
per Ton
($)
5.26
7.93
7.74
8.09
7.98
7.80
7.60
7.56
7.57
7.55
7.62
7.68
8.09
9.67
10.77
11.20
Interstate Commerce
Bituminous Coal
by Transport and
Coal Costs
% for
Coal at
Mine
58.2
61.0
58.1
58.0
57.4
57.4
57.8
58.9
58.7
60.1
60.6
60.8
61.7
64.7
65.6
67.2
Cost
% for
Transport
Costs
41.8
39.0
41.9
42.0
42.6
42.6
42.2
41.1
41.3
39.9
39.4
39.2
38.3
35.3
34.3
32.8
Commission/ Investigation of Rail
road Freiqht Rate Structure - Coal ,
ExParte No. 270
Year
1945
1950
1955
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
Source:
(sub.-No.4) Decided December 3, 1974, Washington D.D.
V-2
-------
to
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V-3
-------
1,500 miles. (The costs of large scale slurry pipelines are quite
speculative, while rail costs can be based on some conservative assumptions
on the proportion of rail capital cost borne by coal movements.) For low
Btu coal and moderate transport distances, it may be more cost effective to
locate a generating plant at the mine and ship electricity. The actual means
chosen between a given origin and destination will depend on many specifics
such as the modes available, terrain, Btu content of the coal to be shipped,
system improvements required to handle expected volumes, etc.
Short distance gathering or distribution systems are subject to greater
cost variations. Site-specific factors will have a large impact on the mode
to be used. In the large scale national coal allocation problem dealt with
in this study the costs of these short haul transport systems do not have a
significant impact. They are discussed here simply to provide a perspective
of their role in the transport of coal.
V.2 RAII TRANSPORT (IF MAI
Rail is the most important transport mode for coal. The share of total
coal shipments moved by rail have increased slightly over the 1960-1977 period.
Rail and water dominate the long distance (over 100 miles) movement of coal
and much of the nation's coal resource is in areas where water transport is
not available at all or is available only for a portion of the route. As these
new resources are developed, particularly in the West, rail can be expected
to increase its share of coal transportation.
The cost of rail transport of coal is a complex issue. Railroads are
capable of moving many commodities including coal over the same rails and road-
bed. The question of what portion of these capital costs should be charged
to coal as opposed to other movements is subject to debate. Whatever common
V-4
-------
cost apportioning is used, there are several cost elements whose magnitude
determine the economics of rail coal transportation.
The major capital requirements for rail transport are the right-of-way,
roadbed, rails, ties, etc.; and locomotives and rail cars. The major operating
costs are for fuel and labor. A study of unit train costs done for the Bureau
of Mines estimates cost elements for a rail line of 750 miles carrying various
annual coal volumes at various speeds. For a 25 million ton per year movement
over the 750 mile route it is estimated that the total annual cost would be
$127.8 million, of which $64.1 million (50.4%) would be the annual charge on
capital. More significant to the economics of rail transport is the variation
of these costs as the annual volume of coal shipped varies, table V-2 shows the
index of the major cost elements over the 750 mile movement for various annual
volumes. As the volume of coal increases the amount of capital must also be
increased; more cars and more locomotives are required; the rail line must be
upgraded as more sidings or even sections of double track are required to
permit returning empty trains to pass. The table shows that an 80% reduction
in annual volume results in a 12% reduction in capital requirements. On the
other hand, operating costs (fuel, labor, etc.) vary virtually directly as the
volume of coal moved. The net result is a substantial reduction in the per
ton costs as the volume increases.
These costs are for unit train shipments which provide the lowest costs
for large movements. When volumes fall to below train load requirements, then
there is a sharp jump in the costs of rail handling due to the need to switch
cars from train to train in yards.
* 'Michael Rieber and Shao Lee Soo: Comparative Coal Transport Costs; Volume 2
Unit Trains. Bureau of Mines - 146-(2)-77, Washington, D.C. 1977 (NTIS PB
274 380)
V-5
-------
TABLE V-2
VARIATION OF RAIL COSTS WITH ANNUAL VOLUME
(Costs for 25 MMTPY Indexed at TOO)
5 MMTPY 10 MMTPY 25 MMTPY 70 MMTPY
Cost Volume
Annual Capital Charges
Operating Costs
Total Costs
Cost Per Ton
20.0
82.1
19.5
50.9
254.4
40.0
86.1
39.1
62.7
156.8
100.0
100.0
100.0
100.0
100.0
280.0
139.0
278.2
208.4
74.4
Source: Michael Rieber and Shao Lee Soo; Comparative Coal Transportation Costs:
An Economic and Engineering Analysis of Truck, Belt, Rail, Barae and
Coal Slurry and Pneumatic Pipelines. Volume 2. Unit Trains. Tables on
pages 2-56, 2-68, 2-80, and 2-92. Bureau of Mines OFR 146(2)-77. NTIS
PB 274 380.
V-6
-------
These various cost factors have been taken into account and the railroads
have developed a series of different rate classes applicable to coal. The
rate classes are basically four: single car, multiple car, train load, and
unit train. Within these rate classes there are variations for minimum ship-
ments or annual guaranteed volumes. These rate classes and variations repre-
sent the recognition by the railroads of the economies of scale in bulk commodity
movements and the use of those economies for competition with alternatives in
the movement of coal. '
V.2.2 Multiple Car Rates
Single car rates apply to movement of coal in a single car from origin
to destination. This rate is generally the highest as the costs of this
service are highest. The main economy which has been introduced is that of
a larger capacity car so that the costs of handling the car can be prorated
over a larger volume. Single car rates have also been adjusted to so called
concentration rates where a group of cars can be brought together and moved
for part of their journey as a block of cars.
V.2.1 Single Car Rates
A coal shipment large enough to require two or more cars can move at a
multiple car rate, reflecting the economies of handling a block of cars. Mul-
tiple car rates are an extension of s ;gle car concentration rates.
The establishment of multiple car rates was specifically prohibited by
the Interstate Commerce Commission virtually from the time the agency was
established. It was not until 1939 that the Commission decided it was permis-
sible for the railroads to compete with other modes of transport by offering
shippers the savings associated with larger volume movements. (Molasses from
New Orleans to Peoria and Pekin, Illinois 235ICC485).
Interstate Commerce Commission Investigation of Railroad Freightrate Structure
Coal. Ex Parte No. 270 (Sub-No. 4) decided December 3, 1974 page 313.
V-7
-------
v 2.3 Trainload Rates
The logical extension of the multiple car rate is the train load rate.
Trainload service requires a volume sufficient to require a full train,
specified as a minimum shipment volume, which moves from a single origin to
a single destination. These volumes have been large enough to make consider-
able technical development practical in loading and unloading coal. Coal
can be^loaded by gravity from silos into a slowly moving train. For unload-
ing, rotary dumpers can be used, and special car couplings have been developed
which eliminates the need to uncouple cars. Special hopper cars have been
developed with doors in the bottom of the car which allow a 10,000 ton train
to be unloaded in 20 minutes, instead of 4 hours by means of a rotary dumper.
These cost-saving terminal facilities are considered in rail rates by speci-
fication of train free time at the origin and destination. The volume require-
ment of train!oad shipments means that the service is used for large volumes
of coal going to electric utility stations and for some large movement of
metallurgical coal to steel plants.
V.2.4 Unit Train Rates
Unit train service is an extension of the concept of trainload service.
A unit train is a specific set of equipment, moving on a set schedule between
single origin and destination. The characteristic which distinguishes unit
train from a trainload service is the fixed schedule of train operation. The
fixed schedule allows the railroad to realize cost savings. Unit train rates
generally specify an annual movement volume, train schedule, train car type,
and number of cars. Unit train service is largely restricted to movements to
electric utilities, specifically to contract coal purchases since regularity
of service and large volumes are required to generate the economies of unit
train service.
V-8
-------
,.2.5 Comparative Rail Rates
A large set of actual rates charged by railroads for coal shipments
was compiled by the staff of the Interstate Commerce Commission as part of
an ex parte proceeding on rail rates. By converting these rates into ton-mile
costs the average costs of coal transport under the several classes of service
can be analyzed.
These average ton-mile rates are shown in Table V-3 for six different
classes. Trainload rates with an annual minimum shipment (which would cover
unit train service) have significantly lower rates than all other classes of
service. The table also shows that the cost per ton-mile drops substantially
with distance as fixed costs are prorated over longer distances. It can be
seen that single car rates are substantially more expensive than unit train
rates, while multiple car rates with no annual minimum are close to carload
rates. Multi-carload rates with an annual minimum appear to be close to unit
train rates. Trainload rates without an annual minimum shipment requirement
are very close to carload rates for distances of under 250 miles, but signifi-
cantly lower for longer distances. Many multiple car rates specify shipments
which would require 10 to 15 cars. These differences in rates by class of
service mean that large contract coal volumes can be moved at substantially
lower costs than small shipments, and that spot market transactions are likely
to face higher transport costs than contract transactions since the substantial
savings in coal rail transport are available mainly for trainload shipments
with annual volume requirements. These annual volume requirements range from
60 thousand to 11 million tons per year.
These rates collected by the ICC provide a-good indication of the relative
differentials of costs between various classes of service, but they are now
several years old and costs have escalated. Arthur D. Little, Inc. gathered
V-9
-------
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r set of trainload/unit train rates for various areasa* yaui rsreu
of 1978. The emphasis was placed on trainload/unit train shipments because
that is expected to be the class of service which will increase most rapidly
and which will have the greatest bearing on the economic potentials of western
coal reserves. These rates were then analyzed statistically in an effort to
construct a model of rail costs.
A total of 191 rates for specific coal movements were collected from the
railroads. Of the 191 rates, 125 of these were eastern and midwestern origin
rates, while 66 were for coal originating in the west. Each movement covered
included information as to the cost, distance, minimum trainload size, minimum
annual volume, origin, destination, and whether the cars were railroad-owned.
Some of the eastern rates were for consolidation of smaller shipments to train-
load volumes, which was also noted.
Regression analysis was used to determine the functional relations of
various shipment parameters and the rate charged for the movement. Interest-
ingly two parameters which were not related to rates were the trainload volume
and the minimum annual volume. Conversation with one eastern railroad indicated
that they had done away with minimum annual volume specifications in their
contracts because volume "took care of itself".
Where different rates for different annual volumes for the same movement
were published, those rates universally showed lower costs with increasing
volumes, but the cost differentials were not systematically related to the
actual volume required.
After some experimentation it appeared appropriate to divide the rates
into two subsets; the eastern rates, for shipments originating in the Appala-
chian coal fields and the midwest, and the western rates for shipments origina-
ting west of the Mississippi. These two subsets proved to have significantly
different relationships between rates and other parameters.
V-ll
-------
Eastern rates proved to be the most straightforward, The rate charged
was a function of the distance traveled and whether or not the railroad owned
the cars used. The equation was:
TC = 3.288 + 13.568D - 1.534 OWN
(0.579) (.353)
with R2 = .9544
where TC is the total cost in dollars per ton
D is the distance in 1,000's of miles
OWN is a dummy variable set to 1 if the cars were
not owned by the railroad, and to zero if
they were.
The overall fit is excellent, over 95% of the total variation in rates
was explained by the two variables. Both variables are strongly significant
as indicated by their standard errors (in parentheses under the coefficients).
The coefficients are of the expected signs and magnitudes. There is a charge
of 1.36 cents per ton-mile and a fixed charge of $3.29 per ton for shipments
using railroad-owned cars. If the shipper owned the cars a reduction of $1.53
per ton would be made to the fixed charges.
The relationship between cost and other parameters for western origin
shipments proved to be more complex. The function is as follows:
TC * 0.096 + 9.044D - 1.091 OWN + 0.450 LCH + 3.556 RI
(0.435) (0.304) (0.226) (0.317)
with R2 = .9450
where the variables are defined as above with the addition of
LCH, the number of linechanges required on the route, and
RI a dummy variable which was set equal to 1, for rates
which were negotiated after the oil embargo in 1973-74
and equal to zero before.
The overall fit is excellent with just under 95% of the total variation
in costs explained by the independent variables. The variables are all si.gni-
V-12
-------
ficant as indicated by their standard errors. The coefficients are all of
the expected signs. The distance coefficient for western rates is significantly
different from that for eastern rates, thus the appropriateness of treating
the two subsets of rates separately.
The western rates proved to be significantly related to the line changes
required for the shipment. A $0.45 per ton charge appears to be assessed on
the average for each line charge required. The variable RI was specified after
conversations with the railroads indicated rates had increased significantly
over and above built-in inflation escalation clauses during and after the oil
embargo. The information as to when the rate was negotiated proved to be
statistically significant and of the expected sign.
These rail rate functions show the basic characteristic of declining ton-
mile costs with increased distances which are expected due to the fixed costs
of loading and unloading.
V-3 WATER TRANSPORT OF COAL
A substantial portion of the nation's coal resource is located close to
the waterway system and a substantial portion of coal use points are also close
to the waterway system, thus much coal is moved by water.
The waterway system used for coal transport can be divided into two
components: the inland waterway system (composed of the river system of Middle
America plus the Gulf Intracoastal waterway) and the Great Lakes waterways.
These are the two waterway systems which are significant to the movement of
domestically used coal, although a small amount of coal is moved on the Atlantic
Intracoastal waterways. Figure V-2 shows a map.of the waterway system.
The inland waterway system is composed of many rivers which rise in Northern
and Central Appalachia and flow west into the Mississippi. Coal can move along
these waterways to major demand centers such as Pittsburgh, the cities of Ohio
Valley, St. Louis, and then up- or down-stream on the Mississippi.
V-13
-------
FIGURE V-2
MAP OF THE INLAND WATERWAY SYSTEM
t**** . .r^-Ti^f^
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Table V-4 shows the coal loadings on various rivers by state of origin.
The Green, Monongahela, and Ohio Rivers account for the bulk of coal shipped
on the internal river system. Kentucky is the state which contributes the
greatest proportion of water-shipped coal.
The Great Lakes are also used for waterborne shipment of coal. Coal is
moved to the Lakes usually by train and then transshipped to Laker carrier for
movement to various demand centers along the lake shores. A large proportion
of export coal from the U.S. to Canada motes over the Great Lakes. Table V ~5
shows coal shipments from U.S. Lakes ports to U.S. and Canadian destinations.
The dominant loading port is Toledo with Conneaut the second.
Coal movements on the Great Lakes have been fluctuating around the mid-
30-million ton level in the 1970's, but the long-term trend is declining. Unit
train and trainload shipment economies have made Lake shipment less attractive
especially as it requires a mode transfer. Another disadvantage of the Lakes
is that they may not be used for several months in the winter. For example,
the share of coal moving by rail into Michigan has increased from 53% in 1970
to 60% in 1976.
There are some economies of scale in waterborne transport of coal. Econo-
mies of scale in equipment size are limited by the physical size of navigation
improvements on the inland waterway system, such as lock size, the radius of
curves in the channel, and depth of the channel. Costs are specific to the
river system and to the direction since the number of locks to be moved through
and the current conditions determine costs. Different sections of the waterway
system have different carrying capabilities and navigation seasons, factors
also determining costs.
The costs of water transport of coal are divided among a number of components.
A major distinction is between the waterway costs (dams, locks, channel construc-
tion, lock operation, dredging, etc.) and the costs of barge and towboat con-
struction and operation. The first set of costs are subject to various allocation
V-15
-------
TABLE V-4
Coal Loadings on the Internal River System
(1974)
Loadings
River
Allegheny
Arkansas
Big Sandy
Black Warrior
Green
Illinois
Kanawha
Monongahela
Ohio
Rough
Tennessee
State of
Loading
Pennsylvania
Arkansas
Oklahoma
Kentucky
Al a bama
Kentucky
Illinois
West Virginia
Maryland
Pennsylvania
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
By State
(OOP Tons)
620
Percent of
By River River
(OOP Tons) Tonnage
620
.9
164
178
204
3,058 3
13,052 13
26
3,740 3
81
15,323
1,956
3,453
7,380
6,024
122
3,393 .
22
22
342
204
,058
,052
26
,740
,540
,228
.5
.3
4.5
19.3
*
5.5
33.3
32.8
Kentucky
Al a bama
Tennessee
513
852
586
513
1,438
.8
2.1
67,754
67,754
100.0
*Less than 0.05
Source: U.S. Senate, Committee on Energy and Natural Resources, National
Energy Transportation, Volume I Current Shipments and Movements,
May 1977, Pub. No. 95-15.
V-16
-------
TABLE V-5
Coal Shipments From Great Lakes Ports
Port
Ashtabula
Conn ea lit
Lorain
Sandusky
To! edo
Total --
Source: National
1975
(000 Tons)
To Canada
3,853
6,819
--
2,836
3,432
16,940
Coal Association
To U.S.
732
1,514
1,265
1,502
11,223
16,236
Coal Traffic
Total
4,585
8,333
1,265
4,338
14,655
33,175
Annual - V
Edition, Washington, D.C., page 38
V-17
-------
:chemes depending on the proportion of total waterway movements accounted for
by coal. The costs for towboats and barges are borne directly by the commodity
being transported by them.
Rate information has proved very difficult to obtain for water transport.
Most coal on the waterways is moved by private carriers who are not regulated
and publish no rates. However, the Rieber-Soo Bureau of Mines study has made
estimates of waterway transport costs for coal based on engineering estimates
of cost components and the volumes of coal that can be moved by various equip-
ment combinations over various waterways^ . Their waterborne costs range
between 0.2 and 0.9 cents per ton-mile in 1976 prices, substantially below the
(2\
ton-mile costs for unit train rail estimated by the studyv . Rieber and Soo
estimated that water transport costs would be substantially higher if waterway
improvement and operation costs were fully borne by waterway users. (Presently
most of these costs are covered from federal general funds). Tablev.6 shows a
set of the specific estimated costs for waterborne movement of coal along various
waterway systems both as total cost per ton and ton-mile cost. These costs
do not include any of the costs of waterway construction and maintenance. Costs
are substantially lower on the Lower Mississippi because there are no locks to
slow the tow and channel conditions permit tows about twice the size of those
on the Upper Mississippi, Ohio Illinois, etc. The highest costs are estimated
for the Missouri River where many locks are required and channel conditions
limit two sizes to about 1/3 those useable on the Ohio, Upper Mississippi, etc.
V.4 TRUCK TRANSPORT OF COAL
Only 14% of the total tonnage moved in the first six months of 1977 moved
by truck and those movements are restricted to relatively short distances.
Truck transport is often used to bring coal to a river loading dock or to a
user which is only a short distance from the mine. Trucks which use public
(l)Rieber & Soo, op cit Volume 4
(2)Rieber & Soo, op cit Volume 1, Figure 1.2 page 1-44.
V-18
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highways are subject to regulations on their size and weight-, this limits their
potential economies of scale. However some truck links do not move over public
roads, and trucks capable of carrying 150 or more tons of coal have been
developed.
The most important factors in trucking costs are high variable costs and
low fixed costs. A simple shovel or drag line can load a truck and it has
its own unloading mechanism (dumping). The Rieber-Soo study^ estimates truck
costs at 3.4 cents per ton-mile with no additional loading or unloading charges.
These high costs per unit of distance, about 5 to 10 times that of rail or
water, mean that truck are economical only over short distances or where rail
or water facilities are lacking. Truck costs exceed the highest unit train
costs at about 50 miles so the maximum distance which appears to be economic
for high volumes truck coal shipment is 70 to 100 miles.
Truck offer great flexibility and low capital costs which make them attrac-
tive for gathering and distribution systems, particularly in surface mining
operations. The costs of truck operation are subject to many site-specific
parameters such as terrain, road conditions, etc.
V.5 MINE MOUTH LOCATION OF GENERATING PLANTS
The location of power plants is determined by a large number of cost
elements and physical constraints. One of those cost elements is the trade-
off of locating the generating plant at the mine (or close to it) and trans-
mitting the electricity generated to load centers versus locating the plant
close to the load and moving coal (or other fuel) to the plant. Historically
the costs of transmission of electricity (construction cost and line losses)
were high enough in comparision to coal transport costs to locate most plants
close to load centers. Mine mouth generating plants have generally been
limited to the areas of the country where coal resources are located close to
^ 'Rieber & Soo, o cit, Volume 1, Summary and Conclusions, Figure 1.2, page 1-44.
V-20
-------
.oad centers.
However, several factors have been at work which make locating the
generating plant close to the mine more attractive. Some of these factors,
such as air quality standards, water availability, and land availability, are
completely unrelated to the transportation trade-off.
Basically there are two cost components in electricity transmission:
construction costs for the line and terminal facilities, and line losses.
Line losses represent energy which must be generated but cannot be sold; they
are related mainly to the line voltage and distance plus line loading, insu-
lation and conductor size. The National Coal Model has estimated a transmission
line construction cost for 765 KV lines at about .021 mills per Kwh-mile of
input electrical energy^ '. The input is translated to output energy by taking
the line losses into account. Line losses are a function of distance, given
line voltage. The capital costs are translated to an annual charge per Kwh-mile
by use of a capital recovery factor of 0.20 by the National Coal Model.
In order to construct the trade-off between transmitting electricity or
transporting coal, the costs of each must be translated onto a common base:
cents per million Btu. (In converting Kwh transmission costs to a cents per
million Btu cost, we must account for the fact that it requires about 9500 Btu
of fuel input at the generating station to generate one Kwh.)
The cost of transmission and transport may be compared for a 500-mile link.
The National Coal Model estimates a transmission cost of 2.31 mills per Kwh
(21
delivered^ '. This translates to $0.243 per million Btu of input energy required,
required^ '. That cost of transmitting electricity is to be compared with the
alternative of shipping coal to generate electricity over an equivalent distance.
(1) Federal Energy Administration, The National Coal Model Description and
Documentation, ICF, Inc., Washington, D.C., October 1976, Page III, 105.
National Coal Model Table 111-57, page III 106, (UN-CO-516 miles.)
2.31 mills/Kwh = 2.31 mills/9500 Btu input = $2.31/(9.5 x 106) Btu.
V-21
-------
The cost of coal transport would depend on the specific rail link, but consider
a unit train moving from Appalachia. Costs would be estimated at $7.819 for
each ton of 24 million Btu per ton coal or $0.326 per million Btu^. In this
case it is cheaper to transmit the energy as electricity.
These same calculations using a transmission distance of 1314 miles
(National Coal Model, page III-106 MW-CH) results in an equivalent cost of
$0.682 per million Btu of required input energy. The comparable rail costs
for a 24 million Btu per ton eastern coal is equivalent to $0.683 per million
Btu. For a 20 million Btu per ton coal over that distance the cost using
western rail rates, translates to $0.596 per million Btu and for a 15 million
Btu per ton coal translates to $0.794 per million Btu. In this case, the
attractiveness of transmission of the energy as electricity depends mainly
on the Btu/ton content of the coal.
The economies associated with longer hauls by rail mean that over longer
distances the balance tips toward transporting the coal. The shorter the
distance the more advantageous the transmission of electricity becomes.
The sensitivity of the comparative advantage of transmission relative
to transport of lower Btu coals has meant that many generating facilities in
the west are mine mouth or planned as mine mouth facilities. However, com-
parative cost of transport and transmission is only one of several factors to
be considered. Other factors, such as regulatory requirements, may be more
important than transportation costs at any given site.
V.6 COAL SLURRY PIPELINES
The costs of transporting coal via a water slurry through a pipeline are
subject to considerable speculation. At present there is only one such pipeline
' ' Eastern Rate equation, pageV-12, deflated to 1975 by Price Index for Railroad
Freight* to be comparable with National Coal Model transmission costs in
1975 prices.
* Railroad Freight Index from survey of Current Business approoriate issues
V-22
-------
in operation, between the Black Mesa coal fields and the Mohave Power Plant,
This is a 273-mile, 18-inch diameter line built as an alternative to a new
rail line. Coal 1s pulverized and mixed with an equal weight of water to form
a slurry somewhat like tooth paste. The basic operating cost is energy required
for pumping. Coal slurry pipelines are rather inflexible in operation and
capacity. There is a minimum flow speed in order to keep the particles sus-
pended and prevent plugging. An increase in speed requires increases in power,
pressures, and pipe wear.
Pipeline transport of coal must bear the costs of both forming the slurry
and getting most of the water out of slurry. The end result is a coal which
has a high moisture content and which produces less net energy per ton than
an equivalent dry coal. The slurry also produces coal fines (particles of
less than 40 micrometer in diameter) which cannot be dried sufficiently for
burning and present a disposal problem.
Another issue critical to the economics of coal slurry pipelines is the
cost of the required water. Water costs or availability could even require
that a parallel pipeline be constructed to return water, significantly increas-
ing costs. The Rieber-Soo study estimates coal slurry pipeline costs based
on several assumptions of water cost over various distances. These costs,
summarized in Table V-7, are for a hypothetical pipeline transporting 25 million
tons per year.
Cost is not the only consideration for pipeline transport of coal. Cost
economies require that large volumes, of coal be moved through the pipe, volumes
which are equivalent to the outputs of several of the largest existing mines
and would meet the requirements of several large power stations. The risks
of pipeline failure are substantial if only one line supplies a large portion
of total requirements. A pipeline offers no rerouting or rescheduling possi-
bilities as does rail or barging. The distribution of coal from a pipeline
V-23
-------
TABLE V-7
ESTIMATED COAL SLURRY PIPELINE COSTS
Scale: 25 MMTPY of Coal
(1976 Prices)
DISTANCE
MILE
WATER
COSTS
CAPITAL
RECOVERY
$/TON
OPERATING
COST
$/TON
TOTAL
COST
$/TQN*
TOTAL
COST
$/TON-MILE
195
$1.00/KGal 1.92
$2.50/KGal 1.92
Return Water 2.50
1.25
1.66
1.15
3.17
3.58
3.66
1.63
1.84
1.88
390
$1.00/KGal 2.98
$2.50/KGal 2.98
Return Water 4.17
1.46
1.87
1.51
4.43
4.85
5.68
1.14
1.24
1.46
585
$1.00/KGal 4.04
$2.50/KGal 4.04
Return Water 5.84
1.64
2.06
1.86
5.69
6.10
7.70
0.97
1.04
1.32
780
Sl.OO/KGal 5.11
$2.50/K6al 5.11
Return Water 7.50
1.84
2.25
2.22
6.95
7.36
9.73
0.89
0.94
1.25
1170
$1.00/KGal 7.25
$2.50/KGal 7.25
Return Water 10.84
2.22
2.63
2.94
9.47
9.88
13.77
0.81
0.84
1.18
* May not sum exactly due to rounding
Note: Costs do not include costs of de-watering or penalties incurred
through burning of a wet coal.
Source: Rieber & Soo, Comparative Coal Transportation Costs, Volume 3, Coal
Slurry Pipelines, page 3-37 to 3-48.
V-24
-------
to different users adds to the costs and the slurry velocity limits make
branching of slurry pipelines less flexible.
V.7 OTHER GATHERING SYSTEMS
Conveyor belt systems are used over short distances, their main advantage
is in rough terrain where the belt can reduce the distance required substantially
over truck transport. Conveyor systems are capital intensive. Rieber and Soo
estimate total costs ranging from $3.171 per ton mile for short (3.5 mile)
low-volume (under 100,000 tons per year) movements to $0.044 for long (100 miles),
high-volume (5.5 million ons per year) movements.
Pulverized materials are moved by pneumatic pipeline systems and these
systems could be extended to coal. Rieber and Soo believe that distribution
or gathering systems of up to 100 miles could be built for coal and their ton-
mile costs would be competitive with those of conveyor systems, truck and short-
haul rail.
V-25
-------
VI. COAL UTILIZATION COSTS
VI.1 INTRODUCTION
Since energy can be developed from other fuels, the value of
coal will be limited by the cost of energy derivable from alternative
sources.
The costs of fuel utilization are determined by a number of
factors such as the size of the plant, the difficulties of "burning"
the fuel, the equipment needed to handle the fuel, to move it from
inventory to burner, etc. These factors can be considered as the
direct fuel-to-energy conversion costs. In addition to these costs
are the costs of using the fuel in an environmentally acceptable manner.
It is useful to treat the utilization costs associated with environ-
mental regulations separately from energy conversion costs because the
former are dependent on regulations which have varied over time and
location, and are subject to change.
Cost comparisons of coal with other fuels are complicated
because the composition of coal varies. It comes with different amounts
and compositions of ash, different moisture and sulfur contents, etc.
These variations result in a range of utilization costs for different
coals.
VI. 1.1 Utility Fuel Choice
There are three principal factors in the decision of a utility
as to how best to generate electricity, the capital cost of the required
plant, the nonfuel variable or operating costs of the plant, and the
cost of the fuel. The decision is based on trade-offs of these various
factors. Additional capital will be invested if savings in operating
or fuel costs will result in less expensive power being produced over
the life of the plant. Each of the fuels available to utilities have
VI-1
-------
quite different structures of capital, nonfuel, and fuel operating costs.
Some of the equipment required for generation from coal is not
required for a comparable scale of generation from oil or gas, and other
components can be of smaller scale and lower cost. The economies of
scale associated with each of the six system components to be discussed
below are important in comparing the economics of larger and smaller
plants. Economies of scale can be expressed as the power term X in the
expression:
X
^ "
where C is the total plant or component cost at size A or
size B,
MW is the capacity of the generating plant being considered
at size A or size B, and
X is the economy of scale exponent.
If X is unity then there are no economies of scale; the cost per unit
capacity is the same regardless of size. Where the exponent is less
than unity, the larger the plant, the lower the cost per unit. For
example, if the economy of scale exponent is 0.6, a component twice as
large as the base would cost only 52% more, so the relative cost for
the larger component per unit of capacity would be
1^ = 0.76.
2.0
Coal must be unloaded, stored in piles or silos, and moved to
the burner. These fuel handling systems account for only 3.3% of total
plant costs, and are subject to substantial economies of scale with an
exponent of about 0.6.
VI-2
-------
Large power plants require that coal be pulverized and coals
with high moisture contents are dried to improve combustion efficiency.
A 500 MW plant for example, generally has five pulverizers. For a
single pulverizer there are economies of scale. Since single units
are limited in size, capacity increases are only achieved by combining
units. Therefore, the total pulverizer system exhibits only minor
economies of scale. The pulverizing equipment accounts for about 3.0%
of the total capital cost in a typical 500 MW generating station.
Steam generators are required by all fuels, but those for oil
and gas-fired units are about one-third cheaper than those for coal.
Steam generator component costs are a major portion (about 34%) of coal
generating plants and are subject to an economy-of-scale exponent of
about .8.
About 20% of the total ash content of coal becomes bottom ash,
which must be removed from the fire box/steam generator; the remainder
is in the form of fly ash which must be removed from exhaust gases by
the particulate removal system. Bottom ash removal systems constitute
a relatively small portion of total coal plant costs (about 0.8%) and
are not required at all for gas-fired and oil-fired plants. Bottom
ash removal systems have a scale factor exponent of 0.8. The amount
of fly ash which must be removed from the exhaust stream, for a fairly
general emission standard of 0.1 pounds of particulates per million
Btu, is about 99%, which can be achieved with precipitators. The
precipitator costs are a significant portion of total plant cost (about
8.6%.) The economies of scale associated with precipitators are slight;
the scale factor exponent is estimated at 0.9.
A major cost component (about 51% for coal, 63% for oil and
60% for gas plants) is the steam cycle turbogenerator, the cost of which
is fairly insensitive to the type of fuel used.
VI-3
-------
The total cost for a power plant includes many specific items
such as site preparation, building construction, equipment costs, work-
ing capital, engineering, architect fees, etc. These costs are usually
estimated as a percent of the total component costs discussed above.
In Table VI.1 these other costs have been prorated over the individual
component costs in order to derive the total plant cost for the 500 MW
generating station size considered. Due to the greater capital cost
required to utilize coal, coal must be produced for less per Btu than
oil or gas, in order to produce energy at the same cost.
The nonfuel operating and maintenance costs are also higher
for coal than for oil or gas. There is more equipment to be maintained
and coal generates more solid wastes than does either oil or gas. These
higher nonfuel operating costs increase the necessary differential in
cost per Btu which coal must give to oil or gas if energy is to be
generated at an equal cost. These costs are summarized in Table VI.2
where the capital costs have been converted into a capital charge per
kwh over the life of the plant. The table also includes estimates for
nuclear power. The cost comparison shows, for the hypothetical 500 MW
generating plant, that to produce electricity at an equal cost with
coal, oil could be priced at 58 cents more per million Btu than coal,
and gas could be priced at 63 cents more per million Btu. These
differential costs of utilization have historically determined utility
fuel choice. In the recent past and for the future the costs of
utilization are also altered by the addition of emission standards for
sulfur oxides. These are discussed below.
VI.1.2 Coal-Specific Generation Cost Differentials
Coal varies as to moisture content, ash composition and content,
energy content and sulfur content. All of these characteristics result
in different capital costs for electricity generation. Appalachian
costs have the lowest direct fuel-to-energy direct conversion costs,
and can serve as a base for cost comparison purposes. Table VI.3 shows
VI-4
-------
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VI-5
-------
TABLE VI.2
COMPARISON OF GENERATION COSTS
FOR DIFFERENT FUELS
Capital Charge
Mills/Kwh
NATURAL
COAL OIL GAS NUCLEAR
16.16 11.91
11.57 19.38-27.89
Nonfuel Operating
Mills/Kwh
3.00
2.00
1.90
1.60
Total Nonfuel Costs
Mills/Kwh
19.16 13.91
13.47 20.98-29.49
Fuel Price Premium
Relative To Coal
Mills/Kwh
Cents/MMBtu
(0.00) 5.25 5.69 (-1.82)-(-10.33)
(0.00) 58.00 63.00
Source: Arthur D. Little, Inc. estimates for 500-MW plants, except
nuclear power cost based on 1,000 MW plants from Bechtel
Power Corporation; Coal and Nuclear Generating Costs: EPRI
Special Report (PS-455-SR), April, 1977.
VI-6
-------
TABLE VI.3
VARIATIONS IN COAL DIRECT CONVERSION COSTS
FOR COALS FROM DIFFERENT REGIONS
COAL SUPPLY REGION
Appalachia
Illinois Basin
Texas (Lignite)
Dakota (Lignite)
Wyoming/Montana
Arizona/New Mexico
Rocky Mountain
Washington
UTILIZATION
COST INCREMENT
Mills/Kwh
0.00
0.30
0.90
1.00
0.70
0.50
0.10
0.50
TYPICAL COAL
HEAT CONTENT
(Btu/pound)
11,850
10,820
7,130
6,800
9,850
9,850
10,340
8,100
Source: Arthur D. Little, Inc. estimates based on Bechtel Power
Corporation, Coal-Fired Power Plant Capital Cost Estimates
and Thompson R. D. et al. The Reserve Base of U.S. CoAls
in Sulfur Content; Bureau of Mines Information Circular
IC8680, May, 1975.
VI-7
-------
the direct conversion cost, relative to that of Appalachian coals and
coals of other regions. The costs are stated in mills per kwh, allow-
ing for the variation in Btu's per kwh for different costs. The
difference in direct conversion costs among different coals is not
large. However, as is discussed below, the different sulfur levels
in various coals does have a significant impact on utilization costs
due to environmental constraints.
Plants are designed for specific coals; other coals are more
expensive to use. The chemical composition of ash must be compatible
with the specific boiler design, or the plant will have to be run less
efficiently using another coal. The direct conversion costs outlined
above are for large installations.
Coal, and each of the other fuels, is subject to scale economies.
A substantial portion of energy coal use is in facilities much smaller
than electric utility generating stations.
VI.1.3 Industrial Energy Source Choice
Industrial energy facilities are much smaller than those used
for utility electricity generation. The choice of fuel for these
smaller energy conversion facilities is affected by the relative scale
economies and the particular equipment required for that conversion.
The characteristics required by industry of energy sources vary
considerably. In some cases a fuel is required which can be burned
directly in the manufacturing process, in which case cleanliness of
the fuel is of overwhelming importance (e.g., glass manufacture.) For
such uses natural gas or electricity are ideal sources. A great deal
of energy in industry is used in the form of steam, which can be created
from a variety of fuels. It is largely in the generation of steam that
coal finds its principal industrial energy use.
VI-8
-------
In the utility sector many disadvantages of coal could be
overcome through the economies of scale associated with very large
plants. In general industrial boilers are much smaller than utility
boilers. An FEA study pursuant to the implementation of the Energy
Supply and Environmental Coordination Act carried out a survey of
major industrial fuel-burning installations. These were defined as
units with design firing rates of at least 100 million Btu per
hour (approximately equivalent to a small utility plant of only 10
megawatt capacity.) The FEA found approximately 6300 such units and
found that 80% of these units were 300 million Btu/hour or less. Units
burning coal accounted for 19% of the total number, natural gas for 47%,
oil for 20% and other fuels for 14%. Coal accounted for 27% of the
fossil fuel consumed by these units, while natural gas and oil accounted
for 52.5% and 20.5%. The relation between share of units and proportion
of fuel burned indicates that coal-fired units were on the average larger
than the other units.
The economics of industrial boiler design are outlined in a paper
2
by Lerner et al. Table VI.4 shows the estimates of Lerner et al. for
a boiler of 250,000 pounds per hour steam capacity. A coal-fired boiler
is substantially more costly than one fired by oil even without the
special environmental costs which are borne by coal. The annualized
cost difference is substantial. Coal must have a substantial price ad-
vantage relative to oil and natural gas to be the economical fuel for
steam generation. To cover the difference of the capital costs alone
coal must be 80 cents per million Btu cheaper than oil. The extra
operating costs associated with coal would mean that coal would need
FEA: Imp!ementating Coal Utilization Provisions of Energy jupply and
Environmental Coordination Act, April 1976.
2
Michael 0. Lerner, Mann, Coleman, Tschupp, and Dandekar; Industrial
Coal Use: Economics and Pollution Control. Fourth Symposium on Coal
Utilization, National Coal Association and Bituminous Coal Research Inc.,
conference proceedings, October 18-20, 1977.
VI-9
-------
TABLE VI.4
INDUSTRIAL BOILER CAPITAL COST COMPARISON
250.000 POUNDS OF STEAM PER HOUR
CAPITAL COSTS COAL OIL
Boilers and Related Equipment $6,300,000 $2,600,000
Fuel Handling 700,000 100,000
Ash Handling 600,000
Nonfuel Related 1,000,000 1,000,000
Particulate Control 750,000
Sulfur Control (FGD) 1.900.000 -
Total Capital With
Environmental Control $11,250,000 $3,700,000
Capital Cost (at 17%/year)
Per 106 Btu at 75% Operating
Rate $1.16 $.38
Source: Michael 0. Lerner, Mann, Coleman, Tschupp and Dandekar;
Industrial Coal Use: Economics and Pollution Control.
Fourth Symposium on Coal Utilization, NCA/BCR Coal
Conference Proceedings. October 18-20, 1977.
VI-10
-------
to be priced between $1.10 to $1.25 per million Btu cheaper than oil.
The fuel choice by industry is also very dependent on the size
and utilization rate of the boiler. Lerner et al. estimate that a
100,000 pounds of steam per hour boiler would cost about 15% more per
unit of capacity than would a 250,000 pound per hour boiler. Oil-fired
boilers are not estimated to show such economies of scale. These factors
indicate that industry's use of coal will be oriented to large boilers
which operate at high load factors.
VI-11
-------
VI.2 ENVIRONMENTAL CONTROL COSTS
In recent years a significant component of fuel utilization
cost has become environmental control cost. Coal is at a considerable
disadvantage in terms of particulate emissions relative to oil and gas
due to much higher ash content. In addition, the formulation of sulfur
emission regulations has substantially increased the costs of environ-
mental control for coal. Some standards can be met by burning a coal
which occurs naturally with a low enough sulfur content, while in
other cases coal can have its sulfur content reduced through cleaning,
or the resulting sulfur dioxide can be removed from the flue gases.
The analysis of the impact on coal utilization costs is compli-
cated by diverse standards under State Implementation Plans (SIP). The
standards which apply under the several SIP's cover a substantial range
in the allowable sulfur concentrations; some standards are stated in
terms of a specific total sulfur emission limit per hour, some in terms
of allowable limits of sulfur emissions per million Btu, others in terms
of allowable sulfur concentrations in the coal itself.
The range in the allowable sulfur dioxide emissions per million
Btu, the most common standard, ranges from a high of six pounds SO^ per
million Btu to 0.34 pounds S02. The standards in terms of percent
sulfur in the coal burned range from 3.5% to 0.2% (see Table VI.5 for
some representative SIP standards.) The range of these standards means
that there are cases where coals may be used without removal of S02 from
flue gases and there are cases where current standards virtually preclude
the use of coal. A substantial quantity of coal is available which
contains 3.0% sulfur or less. However, virtually no coal is available
with 0.6% sulfur or less. While coal can be cleaned to remove a portion
of the sulfur, that portion is generally limited to about one-third for
low-sulfur coals. Thus a standard requiring 0.3% sulfur content or less
precludes the use of coal under the coal cleaning technology available
within the next 10 years.
VI-12
-------
TABLE VI.5
STATE AND REGION
Arizona (State)
Alabama - AQCR 5,7
AQCR 1,2,3,4,6
Widows Creek
Delaware - AQCR 045
Other Areas
Georgia
Florida
Illinois - Chicago-Peoria
Other Areas
New Sources
Iowa
Kentucky - AQCR 78
AQCR 72,77,79
AQCR 101-105
New Sources
Massachusetts (Met Boston)
Other Areas
New Mexico -AQCR 014
New Jersey (Part)
District of
Columbia
REPRESENTATIVE AIR EMISSION STANDARDS
FOR SULFUR DIOXIDE
% SULFUR
POUNDS SOo/MMBTU
~ (-
1.0
1.8
4.0
1.2
1.0
3.0
no emission limit
1.5
1.8
6.0
1.2
6.0
1.2
2.0
3.5
1.2
0.55
1.21
0.34
0.2
0.5
Source: EPA: State Implementation Plan Emission Regulations For
Sulfur Oxides: Fuel Combustion, EPA 450/2-76-002, March,
T976~:
VI-13
-------
The emission standard measured in pounds sulfur or sulfur dioxide
per million Btu must take the Btu content of the fuel into account to
determine the coals which can be used but under such a standard a non-
compliance coal can be brought into compliance through flue gas desul-
furization. Illinois Basin coal at 3.56%S, burned as is, would generate
6.6 pounds SOp per million Btu. Thus with a small amount of sulfur
removed from the coal, it would meet the highest Illinois standard of
6.0 pounds SOp per million Btu. However, 94% of the SOp would have to
be removed from the flue gases for that coal to meet a 0.4 pounds S02
per million Btu standard. The lowest sulfur coal available, the Wash-
ington Subbituminous (0.65%S) at 16,200 million Btu per ton, would
generate 1.6 pounds SOp per million Btu. The most advantageous coal
would be Rocky Mountain Bituminous, which would generate 1.3 pounds SOp
per million Btu. A summary of coals by major region and their sulfur
content and equivalent pounds SOp per million Btu is shown in Table
VI.6.
Under many SIP standards, the simplest and least expensive means
for compliance was to convert a coal plant to oil or natural gas. These
fuels have been available with sulfur contents that have required no
flue gas desulfurization.
The federal government has also set regulations for sulfur
emissions for new sources. New Source Performance Standards have moved
through two iterations. The first, formulated in 1972 (NSPS-I),
require SOp emissions of 1.2 pounds per million Btu or less. The New
Source Performance Standards (NSPS-II) formulated in 1978 specified an
85% sulfur removal, subject to the condition that no emission be greater
than 1.2 pounds SOp per million Btu and that no emission need be less
than 0.60 pounds SOp per million Btu.
NSPS-I resulted in some coals being capable of use without flue
gas desulfurization, with some removal of sulfur from the coal itself.
The NSPS-II appears to require flue gas desulfurization for all coals.
VI-14
-------
TABLE VI.6
COAL SULFUR QUALITY PARAMETERS
COAL
Appalachian Low Sulfur
Appalachian High Sulfur
Illinois Basin
North Dakota (Lignite)
Powder River (Wyoming)
Rocky Mountain Bituminous
San Juan Sub-Bituminous
Texas Lignite
Washington Sub-Bituminous
% SULFUR
0.79
r 2.62
3.56
0.82
0.72
ous 0.67
s 0.88
0.82
ous 0.62
MMBTU/TON
23.70
23.70
21.64
13.60
16.30
20.68
19.70
14.26
16.20
POUNDS S00/MMBTU
1
1.33
4.42
6.58
2.41
1.77
1.30
1.79
2.30
1.53
Source: Thompson, R.D., et at. The Reserve Base of U.S. Coals in Sulfur
Content. Bureau of Mines, Information Circular IC8680, May, 1975.
VI-15
-------
There is virtually no coal available which will meet a 0.6 pounds S0?
per million Btu standard in its natural state, even if 50% of the sulfur
were removed from the coal by preparation.
The costs of flue gas desulfurization (FGD) are dependent upon
the quantity of S02 which must be removed. Figure VI.1 shows capital
cost curves for three sizes of power plant as a function of the S02 to
be removed from the flue gases. For example, an increase of S02 removal
from 72 pounds to 144 pound per million Btu results in an increase of
capital cost from about $58 to $69 per kwh of capacity. There are also
economies of scale for FGD with plant size but with a scale factor
exponent of about 0.90, these are not large.
The process of FGD requires lime or limestone to combine with
the absorbed SO- gas to form slurry which contains the sulfur in a
disposable solid form. The amount of lime or limestone is a direct
function of the amount of S02 to be removed. The total costs for FGD
for several sizes of power plant are shown in Figure VI.2 over a range
of pounds of S02 removed per million Btu. These costs are substantial
ranging from just over 30 cents per million Btu to 70 cents per million
Btu for an 800 MW plant (based on a 65% operating load factor.) The
average Illinois Basin coal would have to have five pounds of SOp per
million Btu removed from flue gases which would cost about 53 cents
per million Btu. Thus this high sulfur coal would face a 53 cents per
million Btu disadvantage relative to other fuels which would not require
flue gas desulfurization. This sulfur disadvantage would be added to
the direct conversion cost of utilization faced by coal generally.
The cost disadvantage due to sulfur depends basically on the
regulation to be met and the sulfur content of the coal per million Btu.
Table VI.7 shows the estimated costs for meeting various standards
through FGD for the various coal and residual fuel oils. (Natural gas
contains almost no sulfur and thus would not require application of
FGD.) These costs are based on a 500 MW plant to be comparable with
VI-16
-------
FIGURE VI.1
CAPITAL COSTS VERSUS SULFUR CONTENT OF THE COAL
FOR LIME FGD SYSTEMS
(90% Removal)
1
i/i
o
Q.
(O
O
Sulfur Content of Coal (Lbs Sulfur/MM Btu Coal)
Pounds S02 Removed Per Million Btu
VI-17
3.5%
S02 Removal
-------
FIGURE VI.2
OPERATING COST FOR LIME FGD SYSTEMS
65%ANNUAL BOILER OPERATING LOAD
o
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.85
.80
.75
.70
.65
.60
.55
.50
.45
.40
.35
.30
.25
.20
.15
200 MW
500 MW
800 MW
200 MW
500 MW
800 MW
Sulfur Content of Coal (Lbs Sulfur/MM Btu Coal)
0.0 0.5
1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0
VI-18
-------
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VI-19
-------
the typical example plants used in Section VI.1.1 of this chapter. The
table shows that to meet the current formulation of New Source Performance
Standards (NSPS-II) costs would range from 35 to 61 cents per million Btu
for these average coals. Note that low sulfur oil (0.5%) would not
require FGD, while high sulfur oil (2.5%) would require FGD costing
40 cents per million Btu (FGD would be required for oils containing
more than 0.6% sulfur.) It is also interesting to note that the cost
of meeting NSPS-II is no more than 5 cents per million Btu greater than
that of meeting NSPS-I. The major cost difference is between the NSPS
standards and a moderately lenient SIP standard of 3.5 pounds S02 per
million Btu, the major cost reduction coming where FGD is not required.
The cost of utilization including sulfur emission control sub-
stantially increases the fuel premium for fuels which can avoid FGD.
Thus natural gas commands a substantial premium relative to coal due to
lower direct conversion costs plus the lack of any requirement for FGD.
Relatively low-sulfur coals face approximately the same FGD costs as a
high (2.5%) sulfur oil. Thus the oil premium vis-a-vis coal is only
that derived from the lower energy conversion costs for oil. Even
moderate-sulfur oils requiring FGD would face a FGD cost of about 30
to 35 cents per million Btu. The main impact of FGD requirements is
to substantially alter the utilization costs among coals.
VI-20
-------
VII.COAL MINING INDUSTRY STRUCTURE
AND FINANCIAL CHARACTERISTICS
VI 1.1. INTRODUCTION
The coal producing Industry 1s highly segmented as discussed
below. The number of business entitles exceeds three thousand. The
large variation 1n this number of coal mining business entitles (which
closely track changes In coal prices) Indicates a relatively easy entry
Into the coal mining Industry. Most of these coal mining business
entities are very small partnerships, proprietorships or corporations,
but most of the coal 1s produced by a small number of large corpora-
tions.
The smaller firms are much more sensitive to market fluctua-
tions; firms in the medium size range seem to have benefited most from
the structural changes in coal markets which took place following the
1973 quadrupling of Imported oil prices.
Profit margins and after-tax cashflows for a selected group
of coal processing firms were generally below total U.S. industry
averages in the years before 1973, Increased significantly between
1973 and 1974; they are probably settling down.at levels close to U.S.
industry averages. Capital expenditures by coal producing firms res-
ponded to these improvements in cash flows and consequently have
Increased significantly. Part of the improved cashflow has been used
to reduce debt; as a result, debt/equity ratios of coal producing firms
in 1976 were smaller than the average for all U.S. manufacturing compan-
ies.
Details to support the above conclusions are presented in the
section below.
VII-l
-------
V11.2 DISTRIBUTION OF COAL BUSINESSES BY TYPE OF OWNERSHIP
Internal Revenue Service (IRS) data on gross revenue and net
Income before taxes by type of ownership are available for businesses
with coal as their main source of income. The three major ownership
types which are discerned in these data are:"'
Corporations
t Partnerships
Proprietorships
As shown in Figure VII-1 the estimated total number'of business
entities included in the coal mining category by the IRS, and which
filed returns with the IRS, was generally around 3,900 from 1971 through
1974, with a low of 2,890 in 1973. Corporations accounted for about
50 percent of this total number of business entities; the remainder of
the coal businesses consisted of partnerships and proprietorships, with
the number of proprietorships generally exceeding the number of partner-
ships.
As shown 1n Figure VI1-2 about 90 percent of all gross revenues
from coal for those business entities shown in Figure VII-1 were genera-
ted by corporations: partnerships and proprietorships had,respectively,
between 6 and 9 percent and between 2 and 3-1/2 percent of all revenues
in the years from 1971 through 1974. Total revenues for these three
categories of coal mining businesses increased from about 4 billion
dollars to 5 billion dollars from 1971 to 1973 and more than doubled
from 1973 to 1974 to 10.2 billion dollars, reflecting the general
increase in coal prices which occurred during that period.
* 'See note at the end of this section for the definition of these
different types of ownerships.
VII-2
-------
FIGURE VII-1
ESTIMATED NUMBER OF CORPORATIONS, PARTNERSHIPS AND PROPRIETORSHIPS IN
THE YEARS 1971 THROUGH 1974 WITH REVENUES MAINLY FROM COAL MINING*
90-
80-
70
60
50
40
30
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1972 VEAR - 1973
1974
VII-3
-------
FIGURE VII-2
100
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80
70
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40
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ESTIMATED REVENUES IN THE YEARS 1971 THROUGH 1974 FOR CORPORATIONS,
PARTNERSHIPS AND PROPRIETORSHIPS WITH REVENUES MAINLY FROM COAL MINING*
board
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1972 YEAR
VII-4
1973
1974
-------
The effect of this general Increase 1n coal price levels men-
tioned above 1s better Illustrated when one allows for the changes 1n
the number of business entitles and calculate the average revenues per
business entity as shown In Table VI1-1. The average revenues from
coal per partnership tripled from 1971 through 1974, while the average
revenues from coal per proprietorship and per corporation doubled.
The decrease 1n the number of business entities in any of the
three categories 1n the period from 1971 through 1973 coincided with
an Increase 1n the average revenues obtained per business entity and
vice versa. Since prices paid for coal during that period were rela-
tively stable, one can conclude that in each of the three categories
the smaller businesses tended to be the marginal business, i.e.,
those which discontinued or started operations during that period.
From 1973 to 1974 an increase in the number of proprietorships
and corporations of, respectively, 55 percent and 30 percent coincided
with the increase in the average revenues per business entity for those
two categories. Apparently, the significant increase in revenues
resulting from Increases in coal prices outweighed the decreasing
effect caused by the lower-than-average revenues of the new entries.
Revenues for the average proprietorship almost doubled compared with
an Increase of not more than 25 percent for the average corporation.
This was probably caused, first, because most coal mined by proprie-
torships is sold in the spot market which experienced a temporary
upsurge In 1974 of about 2 to 3 times higher than that of contract
prices, and second, because the relative size of new entrants in the
case of corporations is much smaller than the average size of already-
existing businesses than in the case of proprietorships. The fact
that cumulative distributions of the number of corporations by asset
size, as shown 1n Figure VII-3 did not change appreciably from 1973
to 1974, supports this last observation. These distributions in Figure
VII-3 show a large percentage of corporations to be relatively small
(e.g., 60 percent with assets less than one-half million dollars).
VII-5
-------
TABLF VII-1
NUMBER AND GROSS BUSINESS RECEIPTS OF DIFFERENT COAL MINING
BUSINESSES BY OWNERSHIP TYPE
1971 1972 1973 1974
Partnerships:
Number 793 596 820 689
Total Revenues* 287 257 304 808
Per Partnership* 0.362 0.431 0.371 1.173
Proprietorships:
Number 1119 1209 751 1076
Total Revenues* 142 141 113 311
Per Proprietorship* 0.127 0.117 0.151 0.289
Corporations:
Number 1766 2161 1319 2143
Total Revenues* 3693 3615 4592 9018
Per Corporation* 2.091 1.673 3.481 4.208
*In millions of current dollars
Source: Internal Revenue Service
VII-6
-------
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VII-7
-------
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VII-8
-------
Since the shape of the distributions remained essentially the same from
1973 to 1974, It follows that most of the new entrants between 1973
and 1974 must have been relatively small companies.
The percentage of corporations with less than 100,000 dollars
1n assets first Increased from 42 percent in 1971 to 50 percent in
1972, then decreased to about 28 percent in 1973 and remained the same
(I.e., 28 percent in 1974see Figure VII-3. Apparently, the large
number of corporations which went out of business between 1972 and
1973, shown 1n Figure VII-1, were r.ainly small firms: the percentage
of firms with less than 1 million dollars in assets decreased from
about 88 percent in 1972 to about 75 percent in 1973; at the same time,
the number of firms with assets of more than 1 million dollars increased
from about 12 percent in 1972 to 25 percent in 1973.
The distributions shown in Figure VII-3 and Figure VII-4 show
that in 1974 70 percent of the small corporations with less than 1
million dollars 1n assets accounted for only about 15 percent of all
revenues by coal mining operations. However, about 5 percent of the
large corporations with more than 10 million dollars in assets accounted
for 65 percent of the revenues.
Note on Ownership Types
The Internal Revenue Service (IRS) assigns businesses to major
Industry groups according to the industrial activity of those
businesses which is the source of the greatest percent of
gross Income. According to this classification, a coal busi-
ness need not derive fifty.or more percent of its gross Income
from coal , but rather, it needs to derive more income from
coal than from any other of Its activities.
In addition, the IRS defines four major types of ownership, all
of which fit a distinct income tax form. A brief description of
each ownership type follows:
VII-9
-------
Corporations (Tax Return Form 1120)to be defined as
a corporation, a business must possess the following
characteristics:
- Intention to conduct a business and distribute
its profits;
- Continuity of life on the death or withdrawal of
a member;
- Centralized management;
- Limited liability; and
- Free transferability of interests in the organiza-
tion.
Small Business Corporations^ '(Tax Return Form 1120s)
in addition to the corporate requirements a small
business corporation must:
- Have no more than ten shareholders;
- Derive less than 80 percent of its gross receipts
from outside the U.S. and no more than 20 percent
from interest, dividends, rents, royalties and
gains from securities transactions; and
- Not be eligible to file a consolidated return
with any corporation.
Under Subchapter 5 of the Internal Revenue Code, a
corporation meeting the above requirements may elect
partnership-type taxation in which corporate income,
loss and tax preferences are taken in the shareholders'
individual tax declaration.
' 'In the analysis, small business corporations are included in the
"Corporations" category.
VII-10
-------
Partnership (Tax Return Form 1065)this ownership
type includes syndicates, pools, joint ventures or
any other organization that carries on a business
or financial operation. Characteristics of a part-
nership are:
- Voluntary association to conduct a business;
- Contribution by each of property or service;
- A community of interest in profits.
Sole Proprietorship (Tax Return Form 1040, Schedule
C)an Individual who is self-employed in a business
or trade is considered a sole proprietor with the
exception of certain services such as those per-
formed by religious organizations and public offices.
VII-ll
-------
3. UNIT PROFIT MARGINS BY OWNERSHIP TYPE
As shown in Figure VII-5 for coal mining operations as a
group, unit profit margin, defined as percentage net income before
taxes per unit of revenues from coal sales, was very low, at levels
around 3 percent, in the years from 1971 through 1973, increasing
sharply to 15.6 percent in 1974. For comparison, the unit profit
margin for all manufacturing industries was slightly above 7-1/2 per-
cent from 1971 through 1974.
The large increase in the coal mining corporation group's
unit profit margin from 1973 to 1974 is explained by the increase in
coal price levels brought about by the quadrupling of crude oil prices
worldwide which occurred at the end of 1973 (also see Figures VII-8
and VII-9.
The unit profit margins for the group of coal mining partner-
ships and for the group of coal mining proprietorships is not
directly comparable with the unit profit margin of corporations. Since
the mines in general are operated by one of the owners (i.e., the
proprietor or one of the partners) who derives his income as a share
1n the profits before taxes, not all operating costs are allowed for
1n calculating net income before taxes for these businesses. This
probably explains part of the generally higher profit margins experi-
enced by these two business entities during the period of the analysis
(see Figure VII-5.}
The unit profit margin for coal mining proprietorships declined
from about 5 percent to about 2-1/2 percent from 1971 to 1973, then
increasing to 25 percent in 1974. As mentioned before, these business
entities must have benefited from a high in the spot market which
started in 1974 and lasted into 1975. For comparison, the unit pro-
fit margin for proprietorships in all industries fluctuated only
slightly at levels between 14 and 15 percent over the same period
VII-12
-------
FIGURE VI1-5
NET INCOME BEFORE TAXES PER UNIT OF SALES FROM1971 THROUGH 1976
FOR COAL MINING CORPORATIONS, PARTNERSHIPS AND PROPRIETORSHIPS*
Net-Income
Unlit of Sales,
-Ta&es
Pe'rceht
Sfttep gait l.oh s:
QlIbYporatTons-tTAH-1'
ibnufacturinc
Department
D Proprio
vir-13
-------
from 1971 through 1974. Since most of the smaller coal producers
trade in the spot market it can be expected that the profit margin
for this group of small producers In the years 1975 and 1976 will
have followed the general decline 1n spot market prices. Therefore,
their profit margin will have probably decreased to 15 percent or less
1n 1976.
Partnerships in 1971 and 1973 fared significantly better than
proprietorships. The unit profit margin for the group of partnerships
in both these years was around 11 percent; higher than the unit profit
margin of all types of partnerships taken as a group, which decreased
from around 9-1/2 percent in 1971 to around 7-1/2 percent in 1973. The
unit profit margin for partnerships in 1972 was as low as for proprie-
torships. The significantly higher unit profit margin for partnerships
in 1971 and 1973 compared with the unit profit margins for proprietor-
ships and corporations is not readily explained. Unit profit margins
for partnerships surged in 1974 for the same reason as discussed in
the previous paragraphs for proprietorships.
As shown 1n Figure VI1-6 unit profit margins for smaller
corporations showed much more variability over time than the unit
profit margins of larger corporations. As shown in Figure VI1-5 unit
profit nargins of all corporations decreased from 1971 to 1972 and
increased from 1972 to 1973, but much more so for the smaller corpora-
tions than for the larger corporations. For corporations with more
than 100 million dollars in assets, the unit profit margins remained
at levels of around 4 percent. The almost step-wise increase in
coal prices in 1974 brought about an across-the-board increase in the
profit margins in corporations of'all sizes. Corporations in the
range between 1 and 100 million dollars in assets clearly benefited
more from the price increases than smaller and larger companies, proba-
bly reflecting the better market position of "these companies which
allowed to benefit more from the short-lived surge in spot market
prices.
VII-14
-------
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VII-15
-------
The higher variability in profitability of the smaller-sized
corporations is also illustrated by the total corporate losses before
taxes reported by each group as a percentage of total profits before
taxes reported by the same group shown in Figure VI1-7 by company asset
size. Total losses as a percent of total profits were generally higher
for the groups of smaller corporations than for the groups of larger
companies indicating that a larger percentage of these smaller companies
were losing money than was the case for larger companies. Also, the
variation from year to year in these percentage losses were much larger
for the groups of smaller companies. For example, in 1972 for groups
of companies with less than one million dollars in assets total losses
reported to the IRS were higher than total reported profits; for groups
of companies with assets of more than 100 million dollars, total dollar
losses reported to the IRS were about one fifth of total profits reported
to the IRS.
These variations from 1971 to 1974 show the same general pattern
as observed in Figure VII-6 for the smaller corporations the percentage
losses in 1972 increased significantly from 1971 to 1972 and they de-
creased from 1972 to 1973; in 1974 only companies with assets of less
than 2 1/2 million dollars experienced any losses.
VII-16
-------
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VII-17
-------
4. ANALYSIS OF FINANCIAL DATA OF SELECTED COAL PRODUCING COMPANIES
a. Overview
Financial data for the period from 1971 to 1976 from annual
reports and 10-K reports were obtained for 37 companies all producing
more than 100,000 tons per year. Table VII-2 lists these companies
grouped by major activity. As shown, companies which were assigned
to the coal mining group had at least 49 percent of their revenues
from coal sales/ ' This percentage of revenues from coal sales was
at the most 25 percent for any of the other companies in the other
groups. For companies in the steel group and in the utilities group
the percentage of revenues from coal sales could not be estimated
because practically all coal production was for internal (i.e., cap-
tive) use.
As shown in Table VII-8 the selected companies comprised,
respectively, 33 percent of total identifiable production by coal
companies; 87 percent of total coal production by oil and gas compan-
ies; 70 percent of coal production by metals and mining companies,
chemical and diversified companies; 100 percent of coal production by
utilities and 70 percent of coal production by steel companies.
As a sample of all companies involved in coal production, the
group of 37 companies was biased towards the largest companies. It
is shown in Table VII-4,that all of the companies in the two highest
production ranges of, respectively, more than 25 million tons per
year and 10 to 25 million tons per year, were represented in the sample.
The percentage of total number of companies represented in the sample
was progressively smaller for the smaller production range classes
(see Table VII-5). None of the 3,500 estimated privately and publicly
* 'Three companies in the coal group had a high percentage (60 percent)
of metallurgical coal sales.
VII-18
-------
TABLE VI1-2
COMPANIES, SELECTED FOR FINANCIAL ANALYSIS,
GROUPED BY MAJOR ACTIVITY
I. COAL MINING GROUP
Name of
Parent Company
Name of Affiliated
Coal Company
Peabody Coal Co.
Pittston Coal Co.
North American Coal
Westmoreland Coal
Eastern Gas and Fuel
Falcon Seaboard Inc.
Falcon Coal Co.
Coal Production,
Million Tons,
in 1976
70.54
17.10
10.68
9.37
7.96
5.19
% Revenues
From Coal
Sales in 1976
100%
53%
100%
100%
49%
84%
120.84*
II. OIL AND GAS GROUP
Continental Oil Co.
Occidental Petroleum
Ashland Oil Co.
Standard Oil of Ohio
Gulf Oil Corp.
MaPco, Inc.
Quaker State Oil
Refining
Exxon Corp.
Consolidation Coal Co.
Island Creek Coal Co.
Arch Mineral Group,et al.15
Old Ben Coal 9
Pittsburg & Midway 7
Martiki Coal, et al.
Valley Camp Coal Co.
Monterey Coal
55.89
17.61
21
52
92
3.92
3.62
2.78
116.47
14%
10%
7%
5%
less than 1%
25%
less than
18%
1%
III. METALS AND MINING GROUP
Amax Coal Co.
23.06
Amax, inc.
Gulf Resources &
Chemicals C & K Coal Co, et al. 5.03
St. Joe Minerals Co. Martin County Coal, et al. 7.85
Jim Walter Corp. Jim Walter Resources, Inc.0.76
36.70
22%
27%
20%
10%
IV. CHEMICALS GROUP
Allied Chemical Corp. Semet-Solvay Div.
Union Carbide Corp.
1.05
Union Carbide, Metals Div.0.85
1.90
8%
less than 1%
* 50.30 million tons without Peabody Coal Co,
VII-19
-------
TABLE VII-2[Cont.)
Name of
Parent Company
V. Diversified
General Dynamics Co.
Lykes Corp.
Alco Standard
Name of Affiliated
Coal Company
Coal Production,
Million Tons,
in 1976
Freeman United Coal 6.13
Lykes Resources et al. 2.21
Barnes & Tucker Co.et al.1.93
10.27
% Revenues
From Coal
Sales in 1976
5%
Captive
3%
VI. UTILITIES GROUP
Pacific Power & Light
American Electric Co.
Montana Power Co.
Montana Dakota
Utilities Co.
Pennsylvania Power
& Light Co.
Duke Power Co.
Public Services Co.
of New Mexico
Iowa Public Service Co
Black Hills Power
& Light Co.
Central Ohio Coal et al
Western Energy
Knife River Mining Co.
Greenwich Collieries
et al.
Eastover Mining
Western Coal Co.
Energy Development Co.
Wyodak Resource
Development Corp.
17.95
.10.69
9.26
4.11
2.90
2.25
1.22
1.13
0.84
50.35
Captive
VII. STEEL GROUP
U. S. Steel
Bethlehem Steel
Armco Steel
Republic Steel
Kaiser Steel
15.98
14.06
2.39
3.23
1.66
37.32
Captive
Captive
Captive
Captive
Captive
* All production is for internal use.
Source: Company Annual Reports
VII-20
-------
TABLE VII-3
PERCENTAGE OF TOTAL 1976 IDENTIFIED PRODUCTION
CONTAINED IN THE SAMPLE OF COMPANIES SELECTED FOR
THE FINANCIAL ANALYSIS AND GROUPED BY MAJOR ACTIVITY
GROUP
PRODUCTION (million tons/yr)
; SAMPLE GROUP 2'.TOTAL IDENTIFIED 1 as a % OF 2
Coal Mining
Oil and Gas
120.8/50.3
116
(2)
356
134
33%/14%
87%
Metals and Mining,
Chemicals and Diver-
sified Companies
54
less than 77
more than 70%
Utilities
50
50
100%
Steel
37
53
70%
(1)
(2)
SOURCE: National Coal Association:"Implications of Investments
in the Coal Industry by Firms from Other Energy Industries".
Including Peabody Co./Excluding Peabody Co.; only 1976 data
are available for Peabody Co.
VII-21
-------
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VII-22
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TABLE VII-5
RELATIVE ANNUAL PROFITS BEFORE TAX FROM 1971 TO 1976 FOR SELECTED COMPANIES
WITH COAL PRODUCTION GROUPED BY MAJOR ACTIVITY OF OWNER COMPANY (1)
OWNERSHIP GROUP
Index of Annual
1971
1.
2.
3.
4.
5.
Coal
Oil & Gas
Electric Utilities
Steel
Miscellaneous (2)
1.
1.
1.
1.
1.
00
00
00
00
00
1972
0.87
1.09
1.11
1.33
1.21
Profits Before Taxes
1973
0.
1.
1.
3.
1.
65
48
28
17
73
1974
3.
2.
1.
5.
2.
29
12
28
97
95
1975
5.
1.
1.
3.
2.
40
84
80
89
51
1976
4.20
1.71
2.33
2.72
2.35
6. Total Nonfinancial
U.S. Companies (3) 1.00 1.23 1.29 1.08 1.35 1.63
SOURCE: Annual Reports, 10-K reports
2
Metals and Mining, Chemicals and Diversified Companies
SOURCE: Department of Commerce:"Survey of Current Business",
March 1977.
VIl-23
-------
held companies with less than 700,000 tons of production in 1976
were represented in the sample. However, the distribution of coal
producers by size is biased toward the large producers. Thus, our
sample of 37 companies contained 56 percent of all production in 1976
and 51 percent of the estimated 134.1 billion tons of coal reserves
estimated to be privately held.
b. Relative Changes in Annual Profits
Table VI1-6 shows how profits before taxes changed for the
different groups of companies included in the sample for which finan-
cial data were obtained.
Between 1971 and 1973 profit levels went down; in 1974 and
1975, they increased sharply to peak in 1975 at an almost ninefold
level relative to 1973, and they then decreased about 22 percent
between 1975 and 1976. Relative to 1971 profit levels, profits before
taxes for the coal group in 1976 increased by a factor of 4.
This marked improvement in profit levels for the coal group
can be explained by significant increases in coal prices,as illustrated
by Figure VII.8, showing the increase in average electric utilities'
steam coal prices for the period starting in 1973 and ending in 1975.
It should be pointed out that the increases in profit levels
for this group of coal companies has likely been greater than for coal
companies in general. About 60 percent of the coal sold by three of
the five companies in the coal group was metallurgical coal sold both
to domestic and export markets, which generally commands a signifi-
cantly higher price than steam coal. Consequently, more than 40 per-
cent of the total coal sales by the coal group were metallurgical
coal; as a comparison total U.S. met coal sales, including exports,
in 1976 were about 22 percent of total coal sales.
VII-24
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TABLE VII-6
PROFIT MARGIN OF SELECTED COAL COMPANIES FOR THE PERIOD
FROM 1971 TO 1976 COMPARED WITH PROFIT MARGIN OF ALL
MANUFACTURING CORPORATIONS
GROUP Profit Margin, Percent of Sales (Pre-tax)
1971 1972 1973 1974 1975 1976
1. Coal (1) 3.4 5.5 5.2 16.3 19.3 15.4
2. Total U.S. Manufacturing
Corporations (2) 7.1 7.5 3.0 8.7 7.5 8.7
: Annual reports and 10-K reports
SOURCE: Federal Trade Commission: "Quarterlv Financial Report",
Fourth Quarter 1971, 1972, 1973, 1974, 1975, 1976.
Vll-25
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VII-26
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All coal producing groups experienced increases in before-tax
levels above those for total U.S. non-financial companies. Except
for the utility-owned group, they experienced a peaking of those pro-
fit levels in 1974; in contrast to a relative low which occurred in
profit levels of all non-financial U.S. companies. Part of this
peaking phenomenon may be attributed to the increase in coal prices
which in itself was caused bv the surge in U.S. oil and gas prices
in 1974 as shown in Figure VII-9, and part is explained by the fact
that unit profits for coal mining operations in 1973 had been general-
ly well below the average unit profit levels of non-financial U.S.
companies as shown in Table VII-7; prior to 1973 the U.S. coal producing
industry was in a depressed state. From 1971 to 1973 these unit profits
(i.e., profits as a percent of sales) for the coal group were only
3 to 5 percent compared with the 7 to 8 percent experienced by all
U.S. manufacturing companies.
c. Relative Changes in Annual After-Tax Cash Flows and Capital Expenditures
Cash flow, defined as net income after taxes plus deprecia-
tion and depletion allowances, is one of the three possible sources
of funds for investment in plant and equipment. Relative changes in
annual cash flows for the different groups of companies are shown
in Table VII-8.
The characteristics of these changes are generally the same
as discussed in the previous section for profits before taxes: cash
flow levels improved between 1971 and 1976 for all groups; they
increased the most for the coal group; except for utility-owned coal
operations, cash flow levels for all groups peaked between 1973 and
1976.
In contrast to profit before taxes, relative changes in after-
tax cash flows between 1971 and 1976 for all groups except coal and
utilities were not significantly different from changes in cash flow
VII-27
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FIGURE VII-9
DOMESTIC AND FOREIGN CRUDE OIL PRICES 1969-1977
13
12
11
10
10
03
i
7 .
o 6
O
2 r
1 .
!
0
Upper Tier (10% Increase)
Lower Tier (5% Increase)
Arabian Light FOB
Contract Price
Annual Average U.S. Wellhead
Pirce (Bureau of Mines) r~~"
/ I
Monthly Average U.S.
Wellhead Price (FEA)
Arabian Light FOB Contract Price
1969 1970 1971 1972
1973
1974
1975 1976
1977
Sources: U.S. Bureau of Mines, Federal Energy Administration, and Arthur D. Little, Inc.
Figure 5. Domestic and Foreign Crude Oil Prices, 1969-1977
VII-28
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TABLE VII-7
RELATIVE ANNUAL AFTER-TAX CASH FLOWS FROM 1971 TO 1976 FOR SELECTED COMPANIES
WITH COAL PRODUCTION GROUPED BY tIAJOR ACTIVITY OF OWNER COMPANY (1)
OWNERSHIP GROUP
Index of Annual After-Tax Cash Flows
1. Coal
2. Oil & Gas
3. Electric Utilities
4. Steel
5. Miscellaneous (2)
6. Total Nonfinancial
U.S. Companies (3)
1971
1.00
1.00
1.00
1.00
1.00
1972
1.13
0.99
1.14
1.13
1.17
1973
1.03
1.44
1.28
1.56
1.37
1974
2.37
1.77
1.36
2.32
1.86
1975
3.55
1.62
1.63
1.88
1.66
1976
3.23
1.72
1.93
1.67
1.81
1.00 1.19 1.40 1.56 1.51
1.78
SOURCE: Annual reports and 10-K reports
Metals and Mining, Chemicals and Diversified Companies
SOURCE: Department of Commerce: "Survey of Current Business",
March 1977.
VII-29
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TABLE VH-8
RELATIVE CAPITAL EXPENDITURES IN PLANT AND EQUIPMENT FROM 1971 TO 1976 FOR SELECTED
COMPANIES MTU COAL PRODUCTION GROUPED BY tIAJOR ACTIVITY OF OWNER COMPANY (1)
OWNERSHIP GROUP
Index of Annual Capital Expenditures
1971 1972 1973 1974 1975
1976
1. Coal
2. Oil & Gas
3. Electric Utilities
4. Steel (2)
5. Miscellaneous (3)
6. Total Nonfinancial
U.S. Companies (4)
1.00 0.84 0.64 0.84 1.06 1.58
1.00 0.86 1.10 1.73 2.14 2.36
1.00 0.98 1.15 1.34 1.24 1.48
1.00 0.81 0.94 1.42 1.71 1.87
1.00 1.00 1.38 2.07 2.95 3.15
1.00 1.09 1.23 1.38 1.39 1.49
SOURCE: Annual reports and 10-K reports
2
Based on data available for two of the five companies in the
selected group.
Metals and Mining, Chemicals and Diversified companies.
SOURCE: Department of Commerce,'"Survey of Current Business"/
March 1977.
VII-30
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levels shown to have occurred for total non-financial U.S. companies.
Most, if not all of, the relative higher increase in profits before
taxes was absorbed through higher tax payments.
Relative changes in capital expenditures in plant and equip-
ment between 1971 and 1976 generally increased significantly more
than for the total non-financial U.S. companies. As shown in Table
VII.F-Sonly the utility-owned group increases in investment levels were
comparable with increases in investment levels which took place for the
total U.S. non-financial companies.
The capital expenditure levels of the coal group did not start
to rise above 1971 levels until 1975. This may partly be explained
by the fact that coal companies applied the larger portion of their
cash flow increases in 1974 and 1975 to debt retirement in order to
improve their debt/equity ratio which, as discussed in the next sec-
tion, had been very high.
The ratio of cash flow to capital expenditures is shown in
Table VII MC;in 1975 the ratio was at least twice as high for the coal
group as for any of the other groups shown. Except for the coal group
and the oil- and gas-owned group capital expenditures in 1976 were
significantly higher relative to cash flows than was the case for total
U.S. non-financial companies.
Electric utilities with their tradition of debt financing had
a consistently lower cash flow to investment ratio than any of the
other groups shown in Table VII F-ll The steel companies and the com-
panies in the miscellaneous group apparently stepped up investment
programs significantly after 1974. The cash flow to investment ratios
decreased from about 130 percent of the ratio shown for total national
U.S. non-financial companies in 1974 to about 75 percent of that ratio
in 1976.
VII-31
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TABLE VI1-9
CASH FLOW AS A FRACTION OF CAPITAL EXPENDITURES IN PLANT
AND EQUIPMENT FROM 1971 TO 1976 FOR SELECTED COTPANIES
WITH COAL PRODUCTION GROUPED BY MAJOR ACTIVITY OF OWNER COMPANY (1)
Cash Flow
OWNERSHIP GROUP
1. Coal
2. Oil & Gas
3. Electric Utilities
4. Steel
5. Miscellaneous (2)
6. Total Nonfinancial
U.S. Companies (3)
Capital Expenditures
1971
0.66
0.88
0.40
1.03
1.28
1972
0.89
0.76
0.46
1.36
1.56
1973
1.06
0.67
0.44
1.59
1.36
1974
1.86
0.86
0.40
1.57
1.25
1975
2.21
1.16
0.52
1.08
0.82
1976
1.34
1.21
0.52
0.86
0.82
1.00 1.09 1.13 1.13 1.09 1.20
""SOURCE: Annual reports and 10-K reports.
"Metals and Mining, Chemicals and Diversified Companies.
SOURCE: Department of Commerce: "Survey of Current Business",
March 1977.
VII-32
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TABLE VII-10
AFTER TAX CASH FLOW PER TON OF COAL PRODUCED FROM 1971 TO 1976 SEPARATELY
FOR A GROUP OF COAL MINING COMPANIES WITH SUBSTANTIAL METALLURGICAL COAL SALES
AND FOR A GROUP OF COAL MINIMS COMPANIES WITH MAINLY STEAM COAL SALES (1)
(in current $/ton produced)
1971 1972 1973 1974 1975 1976
Coal companies with Substantial
Metallurgical Coal Sales 1.24 1.15 1.15 3.49 3.42 3.86
Coal Conpanies with Mainly
Steam Coal Sales 0.46 0.92 1.10 1.78 1.96 2.14
For companies which had significant revenues fron other than coal sales,
the cash flows were adjusted by multiplying total cash flows by the ratio
of revenues from coal sales over total revenues.
VII-33
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d. Annual Cash Flows Compared with New Mine Investment Requirements
Annual cash flow dollars per ton of coal produced can be used
to compare Internally generated funds with typical new mine Investment
requirements. Therefore, cash flow dollars per ton of coal produced
were estimated for companies in the coal group. This was done
separately for the group of coal companies with mainly steam coal sales
and for the group of coal companies with substantial metallurgical
coal sales in order to allow for any effect of significantly higher
metallurgical coal prices.
As shown 1n Table VII-1l,th1s cash flow per ton more than
tripled from 1.15 dollars per ton in 1973 to 3.86 dollars per ton
1n 1976 for the group of companies with substantial metallurgical
coal sales; the cash flow almost doubled from 1.10 dollars per ton
1n 1973 to 2.14 dollars per ton in 1976 for the companies with mainly
steam coal sales. As discussed below, these cash flows per ton are
not adequate to cover estimated investment requirements for new mines.
For the group of companies with metallurgical coal sales, annual
cash flow requirements can be estimated to be about 3.60 dollars per
ton of coal to cover investment costs in new mines in the East which
would allow the same mix of coal as was produced in 1976 (i.e., 60
percent of metallurgical coal and 40 percent of steam coal). Invest-
ment costs used in this calculation were 50.00 dollars per ton for a
new metallurgical coal mine and 40.00 dollars per ton for a medium
sized new Eastern underground or surface steam coal mine/ Assum-
ing that the money would be borrowed for 20 years at an interest rate
of 9 percent per year, and allowing for the fact that those interest
payments would be tax deductible (i.e., the effective interest rate
would be 4.7 percent), the after tax cash flow required for these
^'Practically all of the production of the coal companies in the coal
group came from the East. Therefore, only investment costs in
Eastern surface and underground mines were considered. The invest-
ment cost estimates are Arthur D. Little, Inc., estimates.
VII-34
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TABLE VII-11
RATIO OF LONG TERM DEBT TO STOCKHOLDERS EQUITY PLUS
RETAINED EARNINGS FOR SELECTED COMPANIES 17HH COAL
PRODUCTION GROUPED BY MAJOR ACTIVITY OF OWNER COMPANY (1)
Long Term Debt
OWNERSHIP GROUP Stockholders' Equity & Retained Earnings
1971 1972 1973 1974 1975 1976
1. Coal 0.53 0.66 0.73 0.48 0.30 0.21
2. Oil & Gas 0.20 0.21 0.16 0.16 0.17 0.20
3. Electric Utilities 1.08 1.13 1.13 1.16 1.04 1.10
4. Steel 0.23 0.23 0.21 0.16 0.18 0.21
5. Miscellaneous (2) 0.31 0.29 0.26 0.20 0.24 0.26
6. Total U.S. Manufacturing
Companies (3) 0.34 0.34 0.33 0.32 0.35 0.32
SOURCE: Annual reports and 10-K reports.
2
Metals and Mining, Chemicals and Diversified Companies
SOURCE: Federal Trade Commission: "Quarterly Financial Report",
Fourth Quarter 1971, 1972, 1973, 1974, 1975, 1976.
VII-35
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two investments would, respectively, be 3.92 dollars per ton for
the metallurgical coal mine and 3.14 dollars per ton for the steam
coal mine or about 3.61 dollars per ton for an investment "mix" to
produce 60 percent metallurgical coal and 40 percent steam coal.
The 3.86 dollars per ton cash flow calculated for the metal-
lurgical coal group of companies would be just enough to pay for this
investment if all cash flow dollars could be applied to repayment
of this loan. In reality this is not the case; for example, dividend
payments, which historically for the coal companies in this group,
were about 10 percent of after tax flows, would reduce available cash
flow dollars for loan repayment to 3.50 dollars per ton or less than
the 3.61 dollars per ton estimated to be required. Similarly, the
2.14 dollars per ton of after tax cash flow for the steam coal group
of companies would not be adequate to cover the estimated investment
cost requirements of 3.14 dollars per ton in a medium sized Eastern
steam coal mine.
The reason for these relatively "low" cash flows for the com-
panies in the coal group is most probably the fact that a substantial
amount of the coal is still sold under old contracts at prices which
do not reflect new mine investment costs. Traditional coal companies
with a relatively large number of old contracts can be expected to
have difficulties raising the money required for new mine openings.
Therefore, a large part of the expected growth in coal producing
capacity will have to be financed by new entrants into the business
with large amounts of cash, such as the oil companies.
VII-36
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e. Changes In Debt/Equity Ratio
As mentioned 1n the previous sections, the coal mining group
companies experienced very low profit margins in the years from 1971
to 1974. As a consequence, internal funds were not adequate for
plant and equipment financing and an increasing amount of capital
expenditures had to be financed with funds raised in capital markets.
As shown in Table VII-11 an increasing part of this external
financing was obtained in the form of long term debt.
The debt/equity ratio for firms in the coal group increased
from 0.53 in 1971 to 0.73 in 1973. Between 1973 and 1977 this ratio
decreased to 0.21; the relative increase in unit profits on coal sales
allowed the companies to retire much of their debt and to improve
their capital stock position by increases in retained earnings. As a
result, the debt/equity position for coal companies in 1976 was about
the same as the debt/equity position of companies in the oil and gas
group, steel group and somewhat better than that of companies in the
miscellaneous group; all these groups showed a 1976 debt/equity ratio
smaller than that for total U.S. manufacturing companies.
The debt/equity ratios for the other groups did not differ
much in 1976 when compared with 1971; for all the groups, except for
electric utilities, debt/equity ratios went through a relative low in
1974, coinciding with the relative high in cash flows in that same
year shown in Table VI1-8. The electric utility group, while being
part of a regulated industry, could afford debt/equity ratios about
three times higher than the average for all U.S. manufacturing
companies.
. 5 . GOVERNMENT PRINTING OF F I CE i 1 98 I-3 4 I-08 5/4 6 3 9
VII-37
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