EPA-460/3-74-009-C
June 1974
FEASIBILITY STUDY
OF ALTERNATIVE FUELS
FOR AUTOMOTIVE
TRANSPORTATION
VOLUME III - APPENDICES
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Mobile Source Air Pollution Control
Alternative Automotive Power Systems Division
Ann Arbor, Michigan 48105
-------
EPA-460/3-74-009-C
FEASIBILITY STUDY OF ALTERNATIVE
FUELS FOR AUTOMOTIVE
TRANSPORTATION
VOLUME III - APPENDICES
Prepared by
F. H. Kant, R. P. Cahn, A. R. Cunningham,
M. H. Farmer, W. Herbst, andE. H. Manny
Exxon Research and Engineering Co.
P.O. Box 45
Linden, New Jersey 07036
Contract No. 68-01-2112
EPA Project Officer:
C. E. Pax
Prepared for:
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Mobile Source Air Pollution Control
Alternative Automotive Power Systems Division
Ann Arbor, Michigan 48105
June 1974
-------
This report is issued by the Environmental Protection Agency to report technical
data of interest to a limited number of readers. Copies are available free of charge
to Federal employees, current contractors and grantees, and nonprofit organizations
as supplies permit - from the Air Pollution Technical Information Center, Environ-
mental Protection Agency, Research Triangle Park, North Carolina 27711; or may be
obtained, for a fee, from the National Technical Information Service, 5285 Port
Royal Road, Springfield, Virginia 22151.
This report was furnished to the U S . Environmental Protection Agency by Exxon
Research and Engineering Co. in fulfillment of Contract No. 68-01-2112 and has
been reviewed and approved for publication by the Environmental Protection
Agency. Approval does not signify that the contents necessarily reflect the views
and policies of the Agency. The material presented in this report may be based
on an extrapolation of the "State-of-the-art." Each assumption must be carefully
analyzed by the reader to assure that it is acceptable for his purpose. Results
and conclusions should be viewed correspondingly. Mention of trade names or
commercial products does not constitute endorsement or recommendation for use.
Publication No. EPA-460/3-74-009~c
11
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FOREWORD
For convenience, the material covered in this report is divided
into three volumes. Volume I is an executive summary comprising the re-
port summary, highlights of the various sections and a list of conclusions.
Volume II is the technical section, which is a complete description of the
work carried out under this contract. It includes the sections bound sep-
arately in Volume I. Volume III includes the appendices, which deal with
supplementary material for some of the topics discussed in Volume II.
-------
APPENDICES
TABLE OF CONTENTS
Number Title Page
1 BACKGROUND CONSIDERATIONS 1
2 TRANSPORTATION FUEL DEMAND 10
3 RESOURCE BASE INFORMATION 35
4 POSSIBLE APPROACH OF OTHER COUNTRIES TO ALTERNATIVE
TRANSPORTATION FUELS 62
5 BUILD-UP OF SYNTHETIC FUELS MANUFACTURING CAPACITY - 63
6 SIGNIFICANCE OF FUEL PROPERTIES 91
7 BASES FOR CAPITAL RECOVERY 97
8 REFINING OF SHALE AND COAL SYNCRUDE 102
9 COAL MINING COSTS AND INVESTMENTS 119
10 COST OF OPERATING AN AUTOMOBILE 126
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APPENDIX 1
BACKGROUND CONSIDERATIONS
The material in this appendix supports and elaborates parts of
the summary of background considerations in Section 3 of Volume 2. Other
parts of this summary are supported by Appendices 2, 3, and 5.
Project Independence
The concept of "Project Independence" is that domestic resources
should be developed quickly thereby making oil imports unnecessary.
However, in view of the 36% level of dependency on foreign petroleum in
1973, "independence" will not come quickly. Moreover, as pointed out by
Dr. Dixy Lee Ray and others, "independence" has not been precisely defined.
It does not necessarily mean no imports at all and, in the view of some,
including officials of the Federal Energy Administration, it could mean a
continuation of significant importation of petroleum from Western Hemisphere
countries such as Canada, Venezuela, Trinidad, and Ecuador. Nevertheless,
the common objectives are to develop indigenous resources more fully, to
use them more efficiently, and to do these things in environmentally
acceptable ways.
Although analysis of petroleum imports is outside the scope of
the alternative automotive fuels study, such imports are of critical
importance in the determination of how synthetic fuels industries will
develop in the U.S., i.e., what needs these industries will be designed to
meet. For example, the first coal gasification plants will not ..make any
automotive fuels, but rather substitute natural gas (SNG). Additional
gasification plants may produce methanol, but the product may be used as
an industrial, rather than as an automotive, fuel. Analogously, it is not
certain that the initial synthetic liquids plants will produce automotive
fuels since low sulfur fuel oils are a plausible alternative.
Thus, "Project Independence" is the "forcing function" or
"controlling externality" for the present study*. However, additional
work (e.g., in the intended impact study) will be needed to establish
quantitative relationships between alternative automotive fuels and the
concept of "energy independence".
The Administration has begun work on "Project Blueprint", which
will be the action plan for achieving self-sufficiency in energy.
Quoting from the RFP of March 1973 which led to the present
study: "... the forcing function ... is the anticipated scarcity
of domestic petroleum and the economic penalties and energy-security
problems associated with greatly increased petroleum importation ..."
- 1 -
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Projections of Automotive Fuel Demand
It is helpful to have order of magnitude projections of the
future demand for automotive fuels so as to provide a semiquantitative
context for consideration of the rate at which synthetic fuel capacity
may be required.
Early in 1974, and.constrained by the Arab oil embargo, U.S.
automotive fuel consumption approximated 6 MMB/D. This level may be taken
as an approximate lower bound of future automotive fuel consumption.
Evaluation of the factors that could limit future consumption to this level
are beyond the scope of the present study. However, simple arithmetic
shows what future consumption would be at different hypothetical growth rates
from a base of 6 MMB/D:
Average Daily Consumption, MMB/D
Annual Growth Rate 1% 2% 3% 4%
6.8
7.1
7.5
7.8
7.6
8.4
9.3
10.2
8.6
9.9
11.5
13.3
9.6
11.7
14.2
17.3
The above figures are not predictions of future automotive fuel
demand. Their purpose is to provide a numerical "grid" for the discussion
that follows:
The usual approach to forecasting future fuel demand is first to
project the future vehicle population. One such projection is given in
Table 1. The next step is to apply assumptions concerning miles driven
and fuel economy for the various segments of the vehicle population. This
leads to the projection of fuel demand shown in Table 2. These projections
may be characterized as the probable minimum consumption that would have
occurred i£ previous trends* had continued. Although "minimum" in this
specific sense, the projections may also be regarded as giving room for
economies and efficiencies If such are the Nation's will. In this sense,
the projections may be viewed as the maximum consumption of automotive
fuels likely to occur if reasonable efforts are made in support of
"Project Independence." In this context, the projections set an approxi-
mate upper bound on the future need for alternative automotive fuels.
Prior to the Arab oil embargo and general recognition
that the United States is in the middle of an energy problem.
- 2 -
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APPENDIX 1
TABLE 1
PROJECTION OF U.S. VEHICLE POPULATION
Vehicles at End of Year (Millions)
Gasoline
Year
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1982
1984
1985
1986
1988
1990
1995
2000
2010
Passenger
Cars (1)
.3
,1
89.
92,
94.6
97.0
99.5
102.0
104,
106.
108.
110.
112.8
116.9
121.0
123.
125.
129.
132.6
140.2
149.8
164.4
.4
.6
.7
,7
.1
.1
.1
Trucks &
Buses (2)
16,
17.
17.6
18.1
18.6
19.2
19.8
20.5
21.0
21.5
22,
23,
,1
,1
24.0
24.5
25.0
26.2
27.4
29.
31,
.5
.5
34.4
Distillate
Trucks &
Buses (2).(3)
.784
.883
.939
1.00
1.05
1.11
1.17
1.24
1.30
1.38
1.44
1.61
1.79
1.89
1.98
2.19
2.44
3.20
4.09
7.07
Gasoline & Distillate
Vehicle
Subtotal
106.8
110.1
113.1
116.1
119.7
122j.3
125.4
128.3
131.0
133.6
136.3
141.6
146.8
.5
,1
.5
149.
152.
157.
162.4
172.9
185.4
205.9
Total
C4]
108
112
115
118
121
124
127
130
133
136
138
144
149
152
154
160
165
175
188
209
(1) 1970-2000 from Figure 7 in Reference (1).
(2) Total trucks and buses extrapolated from historical data 1960-1972,
Reference (2).
(3) Diesel trucks and buses calculated from highway diesel fuel consumption
assuming the annual fuel consumption per vehicle = 8,000 gals.
(4) Subtotal corrected to allow for public vehicles excluded from other
categories.
(5) Projections assume no radically new engines, e.g. the projections for
distillate fuel actually refer to diesel fuel.
EPA-460/3-74-009
- 3 -
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APPENDIX 1
PROJECTIONS OF FUEL CONSUMPTION
BY U.S. VEHICLE POPULATION
Billions of Gallons During Year
Year
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1982
1984
1985
1986
1988
1990
1995
2000
2010
Gasoline
Passenger
Cars (1)
65.5
68.3
70.7
73.1
75.6
79.0
81.4
84.0
86.1
89.2
91.4
96.1
101.5
103.8
106.1
109.8
113.2
121.9
132.5
148.8
Trucks &
Buses (2)
21.0
21.8
22.8
23.6
24.1
24.4
24.7
25.1
25.6
26.0
26.7
26.9
27.6
27.9
28.1
28.6
28.7
29.5
29.8
23.5
Distillate
Trucks &
Buses
6.27
7.05
7.50
8.00
8.41
8.85
9.33
9.90
10.4
11.0
11.5
12.9
14.3
15.1
15.9
17.5
19.5
25.5
32.7
56.5
Gasoline &
Vehicle
Subtotal
92.8
97.2
101.0
104.7
108.1
112.3
115.4
119.0
122.1
126.2
129.6
135.9
143.4
146.8
150.1
156.9
161.4
176.9
195.0
229.8
Distillate
Total
(3)
94
98
102
106
109
113
117
120
123
127
131
137
145
148
152
158
163
179
197
232
(1) Calculated from Tables XV (total miles driven) and XVII (minimum
fuel consumption) of the Mitre Corporation's Report No. MTR-6391,
April 1973 (Reference 1).
(2) Calculated by difference from trend projection of total automotive
fuel used by trucks and buses and a forecast of automotive diesel
fuel demand based on API's "Petroleum Facts and Figures."
(3) Subtotal corrected to allow for public vehicles excluded from
other categories.
EPA-460/3-74-009
- 4 -
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The figures in Table 2 are summarized below in different units.
The implicit growth rates in demand in the-lower half of this table may
be compared with those in the "grid" above. A possible implication is
that any projections of automotive fuel consumption above about 9.5 MMB/D
in 1985 or 12.5 MMB/D in the year 2000 would be inconsistent with
"Project Independence". These figures are a guide to the size of the
effort required first to supplement and later to replace conventional
automotive fuels with alternative fuels.
Total Highway Fuel Consumption
Billion Approx. % Billion
Year Gallons Distillate Barrels MMB/D 1015 BTU
1970 94 7 2.24 6.1 12.0
1975 113 8 2.69 7.3 14.2
1980 131 9 3.12 8.6 16.8
1985 148 10 3.52 9.6 18.8
1990 163 12 3.89 10.6 20.8
1995 179 14 4.27 11.7 22.8
2000 197 17 4.69 12.8 25.0
A D.O.T. projection discussed in Appendix 2 is 160
billion gallons for highway use. The close agreement
of the numbers is not surprising since both projections
were made by trend extrapolations.
Implicit growth rates: % per year
1970/1975 4.0
1975/1980 2.9
1980/1985 2.6
1985/1990 2.0
1990/1995 2.0
1995/2000 2.0
Cost Trends for Petroleum-derived Fuels
Despite the familiarity of the words, few subjects are more
difficult to deal with than future "costs" and "prices". An elementary
concept is that "price" should be equal to "cost" plus a reasonable
profit to whomever will provide the article that is sold. Some of the
practical difficulties with this concept are that:
(a) There is no way of determining what a "reasonable profit"
should be.
(b) Even if "reasonable profit" could be quantified, it is not
evident how the appropriate profit margin could be fixed (i.e., no more
and no less) in a competitive economy.
- 5 -
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(c) It is generally accepted that some undertakings merit (the
opportunity of) higher profit margins to compensate them for high risks in
their particular line of business. This "risk/reward" concept is important
in exploration for petroleum. However, there is no quantitative agreement
on what risk/reward ratios should be in one line of business relative to
another, e.g., automobile manufacture versus petroleum exploration versus
coal production.
(d) In the real world, profit margins vary greatly such that
some enterprises are able to expand while others go into bankruptcy. This
is an essential part of the competitive system.
(e) All of the above considerations are complicated further in an
inflating economy because most investments "pay off" over a period of years
long after the pertinent investment has been made. With inflation, the
real value of the return in later years must be discounted relative to the
value of the money when it is invested. However, investments must be made
without precise knowledge of what future inflation will be.
An entirely different set of difficulties relates to the variation
in price for a given material depending on what type of sale is made, e.g.:
(a) Whether the sale is "spot" or is made as part of a long-term
contract.
(b) The quantity sold, e.g., 100,000 barrels or 10 gallons.
Clearly, the marketing cost depends on the amount of effort required to
sell a unit of production. This, of course, is why retail prices are
usually much higher than wholesale prices.
(c) Price variations in different parts of the country that tend
to reflect different logistics and, now in the case of petroleum, different
underlying costs for domestic and imported oil.
This brief account of difficulties is needed as background for
explanation of ways in which costs are treated in this study. The approach
is similar to that used by the National Petroleum Council.
NPC deals with domestic "prices" in terms of "the average unit
revenues required to support assumed ranges of activity levels, given an
assumed range of investment returns". NPC's "price" projections to 1985,
in terms of 1970 dollars and relative to average prices in 1970 were:
- oil at the wellhead: up 60-125%
- gas at the wellhead: up 80-250%
- coal at the mine: up about 30%
at the mine: up about 30%
Regarding foreign oil, the NPC said "there is no assurance that
foreign energy will cost less in the future than domestic supplies".
- 6 -
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For uniformity in this study, all of the economic calculations
for alternative fuels derived from coal or oil shale were based on cost-
plus-10% DCF return. This approach gives an indication of a future price
level, assuming a high degree of competition in the synthetic fuels
industry of the future. The underlying consideration is that the new
industry will not attract capital for investment if the opportunity for
profit is substantially less than that obtainable for alternative invest-
ments. A parallel consideration is that if, at some point, the new
industry is significantly more profitable than alternative investments,
then additional capital will flow into investments in synthetic fuels
thereby increasing competition and lowering the profitability to the aver-
age experienced in comparable types of industrial activity.
It is important to recognize that there is no chance of a "dry
hole" with either coal or oil shale. The exact extent of a particular coal
deposit may not be known when it is leased, but there will be an absolute
certainty that the resource exists. This is not the case in wildcatting
for petroleum. All that will be known is that a favorable geological
structure exists; it will not be known whether the structure contains any
petroleum until after expensive drilling has been carried out.
It is also important to recognize that, historically, much of the
exploration for petroleum in the U.S. has been by"independents" (as
distinct from major companies with "integrated operations", i.e., refining
and marketing as well as exploration and production). It is questionable
whether a 10% DCF return is sufficient to attract a high degree of explor-
ation activity by independents. All that is possible in this study is to
illustrate the effect on the required price for domestic crude oil of
making different assumptions concerning DCF return. Additionally, and
solely for the purpose of illustrating an effect, it is possible to show
how elimination of percentage depletion would affect the price of domestic
crude oil at a given DCF return. The following estimates were developed
from NPC's Case 1*, and are indicative of costs projected up to 1985:
Average Wellhead "Price"*
of Domestic Crude Oil
With 22% Depletion Allowance
10% DCF return $6.00 per bbl. (approx.)
15% " " $8.00 " " "
Without Percentage Depletion
10% DCF return $6.60 per bbl. (approx.)
15% " " $8.80 " " "
* "Price" = cost plus DCF return (1973 $)
* High drilling rate combined with high finding rate.
- 7 -
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The search for domestic crude oil is moving into more hostile
and higher cost environments:
- in the Arctic
- farther offshore and in deeper water
- greater drilling depths onshore and offshore.
In general, it is anticipated that the "easier" or lower cost prospects
will be explored before the more difficult ones. The consequence of this
assumption is that there will be a secular or long-term trend to higher
costs. Thus, by 1990 or the year 2000, the cost of domestic petroleum,
particularly of new oil, may be significantly higher than the estimates
given above for the period up to 1985. This leads to an important impli-
cation: namely, that the cost of fuels made from resources such as coal
and oil shale may decline (on a constant dollar basis) as pertinent new
technology is developed whereas the cost of conventional petroleum will
increase.
It is not suggested that the cost of domestic petroleum will
follow a smooth upward curve. Indeed, under a competitive system,
variations in cost and price are to be expected as Alaskan and offshore
resources are exploited to a much greater extent than at present. What
may be inferred from the expected secular uptrend in petroleum costs are
that:
(a) Other materials or forms of energy will be developed to
replace petroleum in many of its current uses.
(b) The way in which petroleum is used will shift progressively
to applications in which, despite higher absolute cost, petroleum is still
the lowest cost alternative.
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APPENDIX 1
REFERENCES
(1) "Energy/Environmental Factors in Transportation 1975/1990", Report MTR-
6391, Mitre Corp., April 1973.
(2) Automotive Industries/Statistical Issues, March 1970 and April 1973.
- 9 -
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APPENDIX 2
TRANSPORTATION FUEL DEMAND
This appendix discusses parts of three recent reports by (a)
the Department of the Interior, (b) the Department of Transportation,
and (c) Oak Ridge National Laboratory. In the case of (a), the purpose
is to tie the present automotive fuels study to a widely used forecast
of energy supply/demand. For (b) and (c) the prupose is to focus atten-
tion on areas of controversy and uncertainty. In doing this, it is
realized, firstly, that the material discussed is separated from its
context in the respective D.O.T. and ORNL reports and, secondly, that
the discussion given here is not a balanced critique of the individual
reports. It is hoped that the authors of the D.O.T. and ORNL studies
will be understanding of the special use to which their studies have
been put.
Some of the specific issues covered in this appendix are:
• the approach taken to petroleum imports and domestic based
synthetic fuels
• problems associated with extrapolation of past trends into
the distant future
• projection of future aviation fuel demand and its implica-
tions for automotive fuels
• consideration of the possible changes in definition of a
family or "standard" car and the implications for automotive
fuels
• concepts regarding the relationship between economic param-
eters, such as GNP and the transportation sector
• apparently significant errors in published information or
in its interpretation.
The overall conclusions are:
(1) the D.O.I.'s energy forecast of December 1972 is a useful
quantitative context for the present study.
(2) post-1985, synthetic fuels from domestic resources wil]
have to substitute for much of the nation's energy supply
projected by the D.O.I, to be provided by imported
foreign petroleum.
- 10 -
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(3) a number of questions, discussed but not resolved here,
appear important to alternative automotive fuels and,
hence, require additional study.
Department of Interior Energy Forecast
In December 1972, the Department of the Interior published a
report titled "United States Energy through the year 2000" (1). The
information in this report may be modified to provide an overall energy
context for the present study. The D.O.I, forecast had been appraised
in a report to the Engineering Analysis Branch of the EPA (2). A few
points from this appraisal that are particularly pertinent to the present
study are recapped below:
• The D.O.I, forecast of total U.S. energy demand falls in
between the National Petroleum Council's (NPC) low and
intermediate projections (3). For the present purpose,
this makes it convenient to turn to the massive NPC study
for cost and financial data while using D.O.I.'s easier-to-
understand forecasts of supply and demand.
• It is necessary to consider the possibility that only some
lower level of supply will be available. Such a shortfall,
relative to the D.O.I, forecast, could occur for a variety
of reasons. Here, it is useful to distinguish among:
(a) Shortfall in supply sectors such as petroleum and
nuclear power, which would place an additional supply
burden on coal and shale.
(b) Shortfall in coal, which would shift the supply burden
to petroleum and nuclear energy.
(c) Shortfall in all primary energy sources, which would
limit consumption.
• The magnitude of the difficulties on the supply side com-
pels the conclusion that a comparable effort will have to
be made to improve the efficiency of energy use and dis-
courage wasteful and unnecessary consumption.
As the above considerations apply to the present study, it may
be noted that:
• The main purpose is to investigate the feasibility of syn-
thetic or "new" automotive fuels.
• For the time-frame of greatest interest, 1985-2000, and
later, it is reasonable to assume that any deficit in
petroleum fuels may have to be corrected by alternative
fuels derived from other domestic resources (coal, shale,
nuclear energy).
- 11 -
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Thus, implicit in the study is the concept that conventional petroleum
fuels may not be able to supply all of the future transportation needs
of the nation. This makes it possible to distinguish between domestic
and imported petroleum, and to argue that the former will be used to
satisfy transportation and other needs to the extent of its availability.
In concept, synthetic and "new" automotive fuels from domestic resources
may be substituted for what the D.O.I, has projected to be supplied via
petroleum imports. An assumption of no petroleum imports after 1985 is
actually a contingency case in which the excess of trend-projected
demand over domestic supply (with conventional petroleum fuels) would
have to be satisfied by some combination of:
• Efficiencies in the automotive sector, i.e., a demand
lower than that obtained by trend-projection.
• Synthetic and "new" fuels from domestic resources.
This assumption is not a prediction of zero petroleum imports after 1985;
rather it provides the basis for scoping the dimensions of the problem
that would occur without such imports. To the extent that imports are
possible, the volumes of synthetic fuels needed would be reduced but the
nature of the steps required would not be changed. It is quite clear
that greater efficiencies alone will not achieve a supply/demand balance
without either synthetic fuels or imports.
The way in which the D.O.I, forecast is structured lends itself
to the above approach. This is because the forecast deals in terms of
"supplemental supplies," that "may be from imports, shale oil, coal
liquefaction, etc." Thus, all that is needed is to redefine "supplemen-
tal supplies" to exclude imports and to throw the whole burden on "shale
oil, coal liquefaction, etc." for the purposes of this study.
Two pages from D.O.I.'s forecast are reproduced here as
Tables 1 and 2*. The text on the first page .is straightforward. How-
ever, the present study and other work sponsored by the EPA and Depart-
ment of Transportation shows that definition of research needs and
actual research is in progress. This means that the D.O.I, forecast
provides a base case and departure points for the present study.
Table 2 (i.e., D.O.I.'s Table 14) lists two items that will be
excluded from this study. The first, natural gas, refers primarily to
the gas consumed by pipelines for the transportation of the gas itself.
This, of course, is not a component of automotive fuel demand. The
second item, utility electricity, refers to the electricity consumed by
rapid transit systems which, in the trend-projected base case, is at a
negligible level. However, the present study does consider the elec-
tricity that may be required to produce "new" fuels such as hydrogen.
Also identified as Table 14, which is its number in D.O.I.'s report.
- 12 -
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APPENDIX 2
TABLE 1
THE TRANSPORTATION SECTOR FORECAST
The forecast for the tr;msportation sector is shown in table 14,
Demand for energy inputs to the transportation sector; 1971 actual,
and projections to the year 2000. As shown, total sector energy inputs
are expected to increase from 16,989 trillion Btu in 1971 to 42,660
trillion Btu in 2000 for an average annual growth rate of 3. 2 percent
over the entire period.
Little significant shift in energy inputs is expected. Petroleum's
share of this market will show a slight decline from 95 percent in
1971 to 93. 8 percent in 2000 while natural gas will increase its share
from 4. 9 percent to 6. 1 percent. Utility electricity is expected to
retain approximately . 1 percent of the market over the entire period.
The major implication of this forecast is that energy consumption
in the transportation sector is expected to continue much as it has in
the past. This is particularly true through 1985, for we are locked
into our present systems of transportation within that time period.
The long lead time required to phase in new transportation equipment
precludes any radical shifts in transportation systems.
While, major changes can occur after 1985 there is little evidence-
to indicate that the research to accomplish these major changes is
being underta.keri. For this time period it is necessary to consider
not only the time lag associated with phasing in new equipment but
also the time lag associated \vith the research and development of the
new equipment. This does not mean that changes cannot occur. It
only means that, barring a major national effort, the changes will be
only evolutionary and will not have significant effects in the present
century.
In preparing the forecast considerable attention was given to the
problem of additional energy consumption due to environmental
regulations. For automobiles little doubt exists that the regulations
will reduce efficiency of utilization. Offsetting this loss of efficiency
will be the movement toward a larger percent of our automobiles
being in the compact category. Other factors limiting the rate of
growth of energy demand in the automotive section of the sector is
the growing saturation rate for automobiles and the declining growth
rate of population. For these reasons the environmentally stimulated
increase in energy inputs would be partially or wholly offset.
- 13 - EPA-460/3-74-009
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APPENDIX 2
TABLE 2
Table 14. Demand for energy inputs to the Transportation Sector, 1971,
Actual and projections to the year 2000
1971 I/ 1975
1980
Total Energy Inputs
Trillions of Btu3/
16,989
19,090
22,870
1985
27,130
2000
Fossil Fuels
Petroleum
Millions of barrels
Trillions of Btu
Percent of total 2_/
Natural Gas
Billions of Cubic feet
Trillions of Btu
Percent of total 2/
Total Fossil Fuels
Trillions of Btu—'
Percent: of total 2J
Utility Electricity
Billions of Kwhrs
Trillions of Btu
Percent ot total 2/
3,004.9
16,139
95.0
800
825
4.9
16,971
99.9
5.34
18
.1
3,360
18,050
94.6
989
1,020
5.3
19,070
99.9
6
20
.1
3,992
21,440
93.8
1,358
1,400
6.1
22,840
99.9
9
30
.1
4,739
25,450
93.8
1,591
1,640
6.1
27,090
99.9
11
40
.1
7,450
40,010
93.8
2,522
2,600
6.1
42,61.0
99.9
15
50
.1
42,660
!_/ Actual, data
2_/ Refers to percentage of total energy inputs to sector.
3/ Includes coal: 7 trillion Btu.
Consideration was given to the shifting nature of our transportation
system. Evidence indicates a shift from the less energy intensive
modes (i.e. railroads and barges) to the more energy intensive modes
(such as airlines). This was factored into the forecast.
EPA-460/3-74-009
- 14 -
-------
The footnote to Table 2 raises a question of considerable
importance, namely the extent to which shifts in the transportation
section will be in the direction of greater energy-intensity.
D.O.T. Report on Improved Transportation Energy Usage
In the Department of Transportation's report, the base case
involves "U.S. demand for oil in the period 1970-2020 as extrapolated
from present trends without any adjustment for greater efficiency of
utilization of transportation and fuel." For example, the projections
for the year 1990 are that transportation will continue to require 25%
of total energy demand, and that the transportation sector will require
246 billion gallons in that year. This figure is identical with
D.O.I.'s projections. This is not surprising since both sets of pro-
jections were obtained by trend extrapolation from the same data base.
However, the linkage between the D.O.T. base case and the D.O.I, fore-
cast is helpful in that it places the former in a broad energy context.
For 1990, the base case (i.e., projection of continuing trends) gave the
following breakdown of fuel demand by transportation mode:
% 109 Gallons MM B/D
Highway 65 160 10.4
Aviation 26 64 4.2
Marine 5-6 13.5 0.85
Other (Pipeline, etc.) 3-4 8.5 0.55
100 246 16.0
Of the above, only the highway transportation mode is directly
pertinent to the present automotive fuels study. However, the other
modes, particularly aviation, are indirectly pertinent because they com-
pete for the same resources. Also, if it is conceptualized that conven-
tional supplies may become limited it also becomes important to consider
whether "new" fuels will enter highway use, or aviation, or both, and
what the relative timing of such events may be.
The D.O.T. study finds that "technological improvements and
changes have the potential to significantly reduce the projected energy
demand of the Nation's transportation system on petroleum within the
next 15 years, and to permit the use of non-petroleum-based energy
sources by the end of the century." This establishes the D.O.T. panel's
time-frame for "new" fuels. Additional thoughts of this kind are:
• "Battery technology is currently inadequate...15 to 20
years are estimated as necessary before electric propulsion
could reach the stage of large scale implementation."
• "...benefits of fuel technology could be realized
gradually, but not fully, before 1985."
- 15 -
-------
• "...for new engines and new fuels, the full realization of
benefits could not be reached before 1990 to 2000."
The long lead-times required for significant changes to occur
suggest that a likely scenario for 1990 could approximate the trend-
projections cited above. However, the D.O.T. study also extends the
trend-projections another thirty years to 2020. The validity of such
extrapolation is questionable, even to produce a "base case", since
there are many reasons for believing that changes will occur during the
next 45-50 years and no reason to believe that current trends will re-
main unchanged during this time period. Nevertheless, the D.O.T. panel's
"simple projections" for the year 2020 are that:
(a) Highway vehicles will account for most of the energy
used by surface transportation.
(b) Aviation will use as much energy as automobiles.
A corollary is that transportation by water, railroad and pipe-
line will be relatively insignificant. However, the economic implica-
tions of this corollary were not examined. For example, what part of the
economy is generating the production that can support the consumption
implied by the highway/aviation demand? What is the transportation
demand associated with the production and distribution of goods, and is
it possible for this component of total demand to be insignificant in
relation to personal transportation? Moreover, much of the present
demand for automotive fuels is attributable to local trips and commuting
by automobile. It hardly seems possible that these components of demand
would shift to an aviation mode.
There is another problem with the extrapolative assumptions.
Economic growth (in terms of GNP, Disposable Personal Income, etc.)
cannot occur independently of its energy base. It is incorrect to assume
that energy consumption will increase because GNP and DPI will increase.
It is better to reason that increases in GNP and DPI will depend on the
way in which the Nation deals with energy supply and consumption.
The point may be put in another way. Past trends in energy
supply and demand are responsible for increasing difficulties. Hence, a
projection that the trends in supply/demand will continue is also a pro-
jection that the associated difficulties will continue to increase. As
the difficulties are already at a serious level, it is not possible for
the trends to continue much longer without difficulty turning into
crisis. At this point, corrective action would become essential. Thus,
it is apparent that past trends are unstable and that long-term extrapo-
lation of these trends is not a reasonable projection of the future.
The transportation industry's share of national income is
reported in Table 3. This share remained approximately constant, at
3.1% of GNP, during the 1968/72 period. This segment of national income
is accounted for by commercial transportation (airlines, railroads,
- 16 -
-------
APPENDIX 2
(A)
Gross National Product, $ Billion
Personal Consumptions Expo, $
PCE as % of GNP
PCE By Type
Autos and Parts, $ Billion
Gasoline and Oil, $ Billion
Subtotal, $ Billion
Percentage of GNP
Autos and Parts, %
Gasoline and Oil, %
Subtotal, %
TABLE 3
I AND THE NATIONAL
1968
Lon 865.0
Jillion 535.8
61.9
37.2
19.0
56.2
4.30
2.20
6.50
.11 ion 27.1
: GNP 3.13
9.63
ECONOMY
1969
931.4
577.5
62.0
40.3
21.1
61.4
4.33
2.27
6.60
29.2
3.14
9.74
1971
1050.4
644.9
63.3
46.7
23.5
70.2
4.45
2.24
6.69
32.5
3.09
9.78
1972
1151.8
721.0
62.6
52.8
25.2
78.0
4.58
2.19
6.77
35.8
3.11
9.88
National Income by Industry
Division - Transportation, $ Billion
(B) Division - Transportation, 70 of GNP
(A) + (B), % of GNP
Source: "Survey of Current Business," U.S. Dept. of Commerce; various Issues,
EPA-460/3-74-009
-------
buses, barges, etc.)- Implicitly, it includes the cost of equipment and
fuels through the prices charged for transportation services. When added
to personal automobile expenditures (including parts, fuels and lubes),
the total of close to 10% of GNP will approximate the transportation
sector's total contribution to GNP. This figure appears to be greatly
at variance with the 20% figure cited in the D.O.T. study.
A small part of the discrepancy may be due to the contribution
to GNP made by transportation exports (excluded from Table 3), particu-
larly of commercial and military aircraft. In 1972, exports of U.S.
transportation equipment accounted for 0.7% of GNP including about 0.3%
for aircraft. Additionally, in the unlikely event that all automotive
equipment imports were to be supplanted by domestic equipment, there
would be an increment to the transportation segment of GNP of about 0.8%.
However, the major part of the discrepancy must have another explanation.
The above discussion may be rephrased in terms of several
hypotheses:
(a) GNP cannot continue to grow at recent trend rates without
correction of the balance between consumption and produc-
tion expenditures (investments).
(b) Unless a correction occurs, the trend rate in GNP growth
will decline. This will affect all factors, e.g.,
transportation fuel demand, that are correlated with GNP
and projected from forecasts of GNP.
(c) It is questionable whether "total U.S. transportation
expenditures will continue at 20% of GNP", as postulated
by D.O.T. (or are at this level now).
If a higher % of GNP is to be applied to production investments,
then a lower % will be available for consumption expenditures. Hence,
discretionary transportation expenditures might fall as a % of GNP.
Alternatively, as in (b), the transportation % might remain constant but
the secular trend in GNP growth would fall. In either case, transporta-
tion fuel demand would follow a slower growth pattern than that obtained
by extrapolation of recent trends.
The second paragraph on page 21 of D.O.T.'s study says:
"while the transport efficiency of the family car is about half that of
the transit but, the small car has a transport efficiency which is nearly
comparable." This is an exceedingly important point because there is
undoubtedly a preference for travel by car. If fuel consumption is
effectively the same, the choice is overpowering. The question is
whether D.O.T.'s "small car" is, or can become, a "family car" in the
U.S.
- 18 -
-------
The need for change is perceived by the D.O.T. study; indeed,
"improved usage" is its goal. Implicitly, the concept of "improved
usage" extends beyond fuel usage per se to the Nation's energy and capi-
tal resources in total. This leads to a major recommendation:
"The Transportation Energy Panel recommends that sub-
stantial emphasis be given to making transportation
synthetic fuels with properties close to petroleum
derivatives to permit undisturbed, continued use of the
presently planned, petroleum-dependent transportation
vehicle industry."
This means that, at any given time, the needs of the existing vehicle
population must be met. Hence, to the extent that this vehicle popula-
tion requires conventional-type fuels, such must be produced, regardless
of the resources used to produce them.
Summarized, D.O.T.'s projections of transportation energy
demand for petroleum or petroleum-type fuels were:
% of Transportation Energy Demand
1969 1977 1985 2000 2020
Automobiles A7 46 40 38 36
Aircraft 14 .24 J35 _37 35_
61 70 75 75 71
Truck 23 22 18 17 16
Bus, rail, ship 11 8 7 8 11
95 100 100 100 98
Total usage, 1015 BTU 14.91 21.54 29.97 38.48 48.36
It is not clear why the percentages for 1969 do not add to 100.
Corresponding D.O.I, statistics for 1969 show 15.13 x 1015 BTU for
petroleum*. Overall, the discrepancy is minor. However, other informa-
tion tends to confirm the percentages for aircraft, trucks, and bus/
rail/ships, and to suggest that automobiles accounted for half of the
transportation sector's total petroleum demand in 1969.
Of much greater concern is the projection that aircraft demand
may grow so rapidly as to approximately equal automobile demand by about
1990. Considering the long life of commercial aircraft and the impor-
tance of common international fuel specifications for aviation fuels,
there would seem to be no opportunity for diverting any significant seg-
ment of aviation fuel demand away from currently used types of fuel by
1990.** In effect, this places aircraft demand in competition for
* And also 0.68 x 10 BTU for natural gas, coal, and purchased utility
electricity. Most of the natural gas was consumed by gas pipelines.
** This does not preclude the possibility that current types of aviation
fuel may be producible from shale oil or other non-petroleum sources.
- 19 -
-------
essentially the same distillate fraction of the "petroleum barrel" used
not only by buses, trucks, etc., but also under consideration for use
by "new" automotive power plants. Lightweight diesels, automotive gas
turbines, and Rankine cycle or Sterling engines could all operate on
distillate fuel. The use of other fuels is possible, but may be neither
the most economic choice nor the fuel used for the engine development.
The growth of aviation fuel demand projected on page 72 of
D.O.T.'s study is seen as a possibly serious constraint to:
(a) achieving overall adequacy of automotive fuel supplies.
(b) following the most economical path to the development
of more efficient ground vehicles.
On the other hand, there are reasons for believing that the
projections of aircraft demand are seriously in error. This will be
considered further during discussion of the ORNL report.
Note may also be taken of an overall conclusion reached in
D.O.T.'s study:
"Finally all of the fuel diversification measures
discussed are of necessity long-term solutions. The
technology developments needed, the useful life of
most heavy duty vehicles, and the historical cycles
for introduction of new vehicles all point to the
continued need for conventional kerosene-type fuels
through the year 2000, at least. Thus, if reduced
dependence on petroleum is deemed desirable, then
production of synthetic crude oil from shale or coal
is essential."
It is not necessary that synthetic crude oil should be pro-
duced. However, it does appear necessary to develop the capability of
producing petroleum-type liquids that can augment conventional petroleum
supplies in such a way that the overall supply of conventional-type
automotive fuels may be significantly increased. This goal might be
achieved by:
(a) Having the synthetic fuels substitute for petroleum in
non-automotive applications, thereby making a higher %
of the petroleum barrel available for automotive use.
(b) Making synthetic fuels directly for automotive use.
(c) Some combination of (a) and (b), Including the blending
of "synthetics" with conventional petroleum fuels.
The above does not mean that there will not be a need for, or
advantage in, entirely "new" types of fuel. Conceptually, however, such
- 20 -
-------
fuels could be developed in parallel with what will be required by a
growing population of vehicles that demand conventional fuels.
Oak Ridge Study of
Energy Consumption for Transportation
The ORNL study (5) considers two cases:
(a) current trends persist
(b) shift towards more energy-efficient transportation modes.
The latter case excludes consideration of technological
changes. This is unsatisfactory for projections made to the year 2000.
The effect of technological change is implicit, but not explicit, in
the trend-projection of (a) — unless it is assumed that no technologi-
cal changes have occurred in the transportation sector. Both cases
assume the same passenger-miles and freight ton-miles.
The demand projections in the Oak Ridge study are based on
Bureau of Mines studies published in 1968 and 1971. These studies are
antecedents of D.O.I.'s forecast of December 1972 (1). A comparison of
the two sets of transportation energy demand projections is given in
Table 4. The following explanation is necessary for an understanding
of the statistics presented:
- There is a large difference between the total primary
energy input and the total of the energy inputs to the
final consuming sectors (Industrial, Transportation,
Residential/Commercial).
- The main reasons for the difference are the conversion and
transmission losses associated with electricity generation
and distribution. In round figures, the primary energy
input to the electricity sector (which is not a "final
consuming sector") is three times as great as the BTU
value of the electricity input to the three final consuming
sectors.*
- The Bureau of Mines (D.O.I.) keeps separate track of (a)
the primary energy (fossil fuel, hydro and nuclear, but
not electricity) input to each sector and (b) the total
energy (including electricity) input to each of the three
final consuming sectors.
Currently, for every 100 BTU's of primary energy input to electricity,
about 67.2 are consumed in generation losses and a further 2.9 are
consumed in transmission, so that the useful electrical energy
delivered is about 29.9 BTU's. Thus, the current ratio is 3.33 to 1.
- 21 -
-------
APPENDIX 2
TABLE 4
COMPARISON OF D.O.I. AND OAK RIDGE PROJECTIONS
Dept. of Interior
Year
Total Primary
Energy Input, 1015 BTU
Primary Energy Input
of Transport. Sector, 10*5 BTU
Transportation
1970
1980
2000
67.44
96.02
191.90
16.34
22.84
42.61
24.2
23.8
22.2
1970
1980
2000
Total Energy Input
to Final Consuming
Sectors. 1015 BTU
55.99
76.12
140.07
Total Energy Input
to Transportation
Sector, 1015 BTU
16.36
22.87
42.66
7
to
Transportation
29.2
30.0
30.5
Oak Ridge
1970
1980
2000
Total Primary
Energy Input. 10 BTU
68.81
88.08
168.60
Total Energy Input to
Transp. Sector, 1015 BTU
16.50
21.56
42.88
7
10
Transportation
24.0
24.5
25.4
Sources;
(1) "United States Energy through the Year 2000", Dept. of the Interior, Dec. 1972,
page 7 and Appendix B Tables 1 and 11.
(2) "Energy Consumption for Transportation in the U.S.", Oak Ridge National Lab.,
March 1972, page 3, Table I, based on Bureau of Mines' projections published
in 1968 and 1971.
EPA-460/3 -74-009
- 22 -
-------
- The transportation sector currently obtains 99.9% of its
energy in primary form and only 0.1% as purchased elec-
tricity. In consequence, the primary energy and total
energy inputs of the transportation sector are essentially
the same.
- When the energy demand of the transportation sector is ex-
pressed as a percentage of total energy demand, there is a
significant difference between (a) the % related to total
primary energy input and (b) the % related to total energy
input to the final consuming sectors.
- These points are of considerable importance in any projec-
tions of future demand that apply percentages to total
demand.
The top segment of Table 4 reports the statistics on a primary
energy input basis. Here, it will be seen that the D.O.I, is projecting
that transportation will account for a declining percentage of primary
energy input. The middle segment of Table 4 reports the statistics on
a final consuming sector basis. Here, it will be seen that transporta-
tion is projected to account for an increasing percentage of total energy
input to final consuming sectors. It is important to understand that
the apparent divergence of trend (declining % versus increasing %) in
the transportation sector is due to what is projected to happen in the
two other final consuming sectors (industrial, residential/commercial)
and not to what is projected for the transportation sector itself. It
is the projected increase in electricity use (and, hence, generation
and transmission losses) in the industrial/residential/commercial
sectors that is causing the superficial anomaly in the transportation
sector's percentage figures.
The third segment of Table 4 reports the statistics cited in
the ORNL study. Here, the statistics are scrambled such that the total
energy input to transportation (a final consuming sector) is related to
the primary energy input to the economy.
The absolute quantities of BTU's projected in ORNL and D.O.I.
studies are essentially the same, but the associated total primary
energy input projections are significantly different. What this means
is that when the D.O.I, made its forecast in 1972 it revised the total
energy requirements upwards but left the transportation sector unchanged,
i.e., all of the increase was in the other two final consuming sectors.
Obviously, this had the effect of decreasing the transportation sector's
percentage of total energy demand relative to what had been projected
in 1971.
The upward revision of total energy demand has important
implications. Quantitatively, the projections for the year 2000 were
increased from 168.6 x 1015 BTU to 191.9 x 10^5 BTU. This increase of
23.3 x 1015 BTU is large in relation to the total demand of the
- 23 -
-------
transportation sector projected for the year 2000, namely, 42.7 x
BTU. Over a period of two to three decades, there will be opportunities
for fuel shifts (from one type of fuel/energy to another) to occur, par-
ticularly in the industrial sector. Hence, a swing in total demand of
23 x 101* BTU's could have a major impact on the availability of (con-
ventional) fuels for the transportation sector.
In its forecast of December 1972, the D.O.I, paid special
attention to synthetic fuels. From a statistical viewpoint, there is
an analogy with electricity. This is due to the large difference be-
tween primary energy input and the energy delivered in useful form.
For example, conversion losses are expected to absorb about 30-35% of
the primary energy input when coal is converted to synthetic fuels.
This is of great practical and statistical importance to studies that
involve consideration of the production of synthetic fuels on a large
scale. For the same amount of energy deliverable in useful form, there
will be a significant difference in the associated primary energy input
depending on the extent to which it is supplied: (a) by petroleum im-
ports and (b) by synthetic fuels. For a given amount of useful product,
the primary energy input will be higher in case (b) . However, the
demand of the transportation sector as a percentage of total demand
would be lower in case (b).
The factors just discussed are even more important in cases
that consider that significant amounts of transportation energy will be
supplied as, or derived from electricity. Here, the output energy at
best will be about one-third of the primary energy input and could be
considerably less if the electricity generated is used in chemical
transformations so as to produce a liquid or gaseous transportation
fuel. Clearly, for a given quantity of electrically-derived transporta-
tion fuel, there would be an increase to total primary energy input.
Statistically, this would reduce the percentage of energy input to the
transportation sector in relation to total primary energy input.
Reverting to the matter of fuel/energy shifts in the economy,
it may be noted that there is a growing possibility of employing nuclear
heat in the industrial sector without prior conversion to electricity.
This would substantially reduce the primary energy input required,
since electricity generation losses would be avoided. From the stand-
point of overall efficiency of energy use, one implication is that
nuclear energy should be applied in the industrial sector before it is
applied to transportation. The underlying concept is that many years
will be needed to develop nuclear capability to the point where incre-
mental capability is available on a large scale for purposes other than
keeping up with conventional electricity demand.* An elaboration of
this thesis is that nuclear process heat may be applicable to synthetic
fuels production:
* This is discussed further in Appendix 3.
- 24 -
-------
to substitute nuclear for fossil fuel energy in the
conversion processes
to generate hydrogen needed in synthetic fuels processing
(for desulfurization, denitrogenation, and correction of
C:H ratio) .
The "all nuclear" economy now visualized for the 21st century
has been elaborated to include a "Hydrogen-Energy system" (6) for trans-
portation and other purposes.
Six different ways of using hydrogen are foreseen:
(a) in the petrochemical and metallurgical industries
(b) for the production of synthetic fuels
(c) by electric utilities for peak-shaving
(d) as a replacement for natural gas used by industry
as a fuel
(e) as a replacement for natural gas used domestically
(f) as a transportation fuel.
The above applications fit different time-frames. The first
is happening now. The second will occur soon. The third is in the
planning stage by electric utilities, and may occur soon. The other
three items are more distant prospects. The first three items promise
to be important in the 1985-2000 time frame and may contribute both to
augmentation of energy supplies and to more efficient energy usage. No
further comment will be made here concerning the second three items,
except that they depend commercially on greatly increased nuclear capa-
bility.
The substantial digression from ORNL's study has been necessary
to show the relationships of transportation energy forecasts to projec-
tions of total energy demand and also the importance of understanding
the statistical basis of such projections. Some specifics of the study
may be discussed now that major statistical difficulties have been ex-
plained.
The ORNL study projects trends in inter-city freight traffic
by transportation mode. The figures in parentheses are for "shift to
greater energy-efficiency", in contrast with continuation of current
trends:
- 25 -
-------
Percent of Ton-Miles
R.R. Trucks Waterways Pipelines Airways
1970 40.1 21.4 15.9 22.4 0.18
1980 37 (41) 21 (18) 16 (16) 25 (25) 0.4 (0.2)
1990 35 (42) 21 (14) 15 (16) 28 (28) 0.7 (0.1)
2000 34 (44) 21 (11) 15 (16) 29 (29) 1.0 (0.1)
Energy consumption by pipelines should be separated from
other components of transportation energy demand when long range projec-
tions are made. Conceptually, the transportation of fossil fuel energy
by pipeline is analogous to the transmission of electrical energy by
cable. It is preferable to separate the transportation of energy from
other types of transportation.
ORNL also provides projections of inter-city passenger
traffic. It is reported that air travel accounted for 2% of such
traffic in 1950 and grew to 9.7% in 1970. With "current trends", it is
projected that a level of 17% would be reached in the year 2000, but
that with a shift to "greater efficiency", the fraction would drop back
to 2%. Similar projections are made for urban travel. With inter-city
and urban travel combined, air travel in the year 2000 would account for
9.4% and 1.1% of total passenger miles in the two cases examined.
Projections for automobile passenger-miles are that urban
trips will account for 49.1% in the year 2000 if current trends continue.
With greater efficiency, the figure would be 45.7%. The difference be-
tween these cases is small, and it might be inferred that urban driving
will account for almost half of the automobile passenger-miles whether
efficiency improves or not. However, this need not be the case if mass
transportation systems are developed.
The report says, "mass transit typically accounts for about
5% of total urban passenger traffic...we consider only automobiles and
buses, since other forms of mass transit account for a very small frac-
tion of total urban passenger traffic". This is true now, and the
physical situation cannot change quickly. Nevertheless, changes in
attitude may be occurring with respect to the uses to which the Highway
Trust Fund may be put, especially after the interstate highway system
is completed. Thus, the situation towards the end of the 1985-2000
time-frame could be appreciably different from what it is today.
Some of the statistics quoted in the ORNL study are at
variance with those reported elsewhere. Hence, pertinent statistics
from Department of Commerce publications will be reviewed. The top
part of Table 5 is concerned with passenger-miles by different trans-
portation modes. The lower half summarizes similar data for cargo
ton-miles.
- 26 -
-------
APPEHDIX 2
TABLE 5
TRANSPORTATION STATISTICS
Passer.ger-Miles or Revenue-Miles (Public Carriers) x 10''
Scheduled Airlines
Railroads
Bus
Automobiles
Total
7. Air
. .... Air Load-Factor
Cargo Ton-Miles x 1
Scheduled Airlines
Railroads
^i Inland Waterways
i Motor Freight
Sub-Total
% Air
Pipelines
Total (Incl. Pipelines)
7. Pipelines
Growth Rate, 7./Yr.
1963
38.5
18.5
21.9
765.9
844.8
4.6
1.0
622
234
336
1193
0.08
253
1446
17.5
1967
98.7
15.2
24.9
889.8
1028.6
9.6
3.4
719
274
388
1384
0.25
361
1745
20.7
1969
125.4
12.2
24.9
977.0
1139.5
11.0
50.0
4.7
774
303
404
1486
0.32
411
1897
21.7
1970
131.7
10.9
25.3
1026.0
1193.9
11. 0
5.0
771
318
412'
1506
0.33
431
1937
22.3
1971
135.6
8.9
26.0
1056.0
1226.5
11.1
48.5
5.1"
746
307
430
1488
0.34
444
1932
23.0
1972
152.4.
8.8
27.0
1087.0
1275.2
12.0
53.0
5.5
763
316
450
1535
0.36
462
1997
23.1
1980E
275.2
10.3
35.0
1294.0
1614.5
17.0
11.1"
967 •
401
537
1916
0.58
614
2530
24.3
63/69
22
Neg.
2.2
4.1
5.1
29
3.7
4.4
3.1
3.7
8.4
4.6
69/72
6.7
Neg.
2.7
3.6
3.8
5.4
Neg.
1.4
3.7
1.1
4.0
1.8
72/80
7.7
2.0
3.3
2.2
3.0
9.1
3.0
3.0
2.2
. 2.8-
3.6
3.0
• Constant $ GNP
551.0
725.6
789.5
4.7
2.9
Sources:
"Survey of Current Business", pages S-23/24, Bureau of Economic Analysis, Dept. of Commerce
"U.S. Industrial Outlook with Projections to 1980", 1971-2-3 Editions, Bureau of Competitive Assessment
and Business Policy, Dept. of Commerce.
EPA-460/3-74-009
-------
The years chosen permit a comparison between trends that
occurred: (a) in a period of rapid economic expansion from 1963 to
1969, and (b) during the recesion of 1969 to 1972. While many other
factors may have been involved, there are qualitative correlations be-
tween constant dollar GNP, total passenger-miles, and cargo ton-miles:
Growth Rate. %/Year
1963/69 1969/72 1963/72
Constant dollar GNP 4.7 2.9 4.1
Passenger-miles 5.1 3.8 4.7
Cargo ton-miles, excluding pipelines 3.7 1.1 2.8
Cargo ton-miles, including pipelines 4.6 1.8 3.7
Passenger-miles plus cargo ton-miles 4.8 2.5 4.0
There is no "scientific" or rigorous basis for adding passen-
ger and cargo miles. Yet, when this is done, the hybrid statistic
closely tracked constant dollar GNP.
Notable in Table 5 is the pronounced decline in growth rate
for both passenger-miles and cargo ton-miles by air during 1969/72
relative to 1963/69. This makes trend-extrapolation extremely difficult.
The problem, as it relates to fuel demand, is mainly with projection of
air travel, since air cargo is at a low absolute level and as a percent-
age of other cargo transportation modes. Air travel itself may be
divided into business and recreational components. As a hypothesis, it
is suggested that advanced telecommunications systems may eventually
reduce the need for business travel. This would have a major impact on
the airlines, because business travel tends to smooth the seasonal and
holiday peaks of recreational travel, and price charged for the latter
would have to increase significantly. Current trends may once again be
in the direction projected by the Department of Commerce for 1980 (7),
but the long range prospects are hard to gauge. The aggregate effects
of recent problems with air travel suggest:
(a) a lower increase in passenger-miles than was predicted
in 1969
(b) emphasis on how to increase load factors
(c) de-emphasis of further Increases in air speed
(d) more moderate increases in total fuel consumption as a
result of (a), (b), and (c).
In the past, the fuel consumed by military aircraft has been
a large fraction of total aviation fuel consumption in the U.S. (8):
- 28 -
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Aviation Fuel Consumption in 1968
Million Barrels _%
Civil aviation 217.79 57.3
Military 162.36 42.7
In 1960, military consumption of aviation fuels accounted for
68.7% of total domestic consumption. By 1970, the fraction had fallen
to 33.5%. The way in which military consumption has been factored into
trend extrapolations of future aviation fuel demand is not clear in the
forecasts reviewed. Certainly, military consumption is included in the
historical statistics reported by the Bureau of Mines and the transpor-
tation totals projected by the D.O.I.
The impact of military procurement is primarily on aviation
fuels (9):
Military Procurement in 1969*
Million Bbls. %
Aviation fuels 268.4 60.8
Motor gasoline
Diesel, distillate, kerosene
Fuel oils and other products
441.1 100
In total, it is judged that the future civil and military
requirements for aviation fuels may be much lower than projected in the
studies reviewed—and will not approach a level of demand equal to that
created by automobiles. The plausibility of this judgment may be
examined quantitatively using figures quoted for the years 1969 and
1985 on page 72 of D.O.T.'s study:
1969 1985
Total transportation energy, 10 BTU 14.91 29.97
Aircraft, % of total 14 35
Aircraft, 1015 BTU 2.087 10.49
In 1969, military aviation accounted for 35.9% of domestic
consumption. A simple projection of the declining percentage of mili-
tary demand from the 1960/1970 statistics results in zero military
usage by 1980. This projection is implausible, and a figure of 10%
will be used for illustrative purposes:
The statistics include fuels procured outside the U.S. for overseas
operations.
- 29 -
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1969 1985
Total aviation demand, 1015 BTU 2.087 10.49
Military demand, % 35.9 . 10
Military demand, 1015 BTU 0.749 1.05
Civil demand, 1015 BTU 1.338 9.44
Annual growth rates, %/yr.
Military demand 2.1
Civil demand 13
A principal source of statistics for aviation fuel demand is
the "Annual Petroleum Statement" published by the Bureau of Mines. It
should be noted that the reporting basis has changed over the years,
and that it may lead to difficulties or errors in extrapolation of
future demand from the reported historical data.*
The calculated growth rates in the above table are implausible
both for military demand (which peaked on a volume basis in 1968, i.e.,
is now declining on a volumetric basis) and for civil aviation demand
that, prior to the Arab oil embargo, was growing at an annual rate of
about 7%.
A further calculation may be made to investigate the effect
on growth of civil aviation fuel demand of a different assumption con-
cerning total aviation fuel demand. The assumption that military demand
will be 10% of total demand is retained.
Total demand assumed to grow at 5%/yr. from 1969 to 1985
Total demand in 1985, 1015 BTU 4.56
Military demand in 1985, 1015 BTU 0.46
Civil demand in 1985, 1015 BTU 4.10
Military demand, annual growth, %/yr. -3.1
Civil demand, annual growth, %/yr. 7.3
The result is plausible. Military demand has been declining
by more than 10%/yr. since 1968, although this decline rate may taper
off appreciably. A demand for civil aviation fuel with annual increases
compounded at 7.3% implies a sustained growth of air travel at rates
just above those experienced recently. If anything, this projection
appears to be on the high side.
For example, "kerosene" included commercial jet fuel beginning in
1960. Starting in 1965, "kerosene" includes kerosene-type jet fuel.
However, "jet fuel" included military jet fuel beginning in 1960.
From 1965, this inclusion was restricted to naphtha-type jet fuel.
Prior to 1964, "motor gasoline" included aviation gasoline. The
latter has been reported separately since 1964.
- 30 -
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The aviation fuel demand projection of 4.56 x 10 BTU above
amounts to 15% of the total transportation fuel demand projected for
1985 in the D.O.I, study. However, if total demand is adjusted down-
wardly for lower aviation fuel demand*, the latter would represent 19%
of the adjusted total. This compares with the value of 35% projected
in D.O.T.'s study. The difference is large, of major consequence to
the future availability of automotive fuels, and requires further
s tudy.
A footnote on page 4 of the ORNL study says, "Rice's energy-
efficiency estimates for aircraft are apparently^-too low by 30-50%.
His values are adjusted upward in Tables 3 and 5 so that the total air-
craft energy consumption agrees with the FAA data given in ref. 16"
(10,11). Much of the ORNL study is based on direct use of Rice's data.
Hence, the resolution of 30-50% discrepancies would seem important.
There is a tabulation in the ORNL report that compares the
study's computations of transportation energy requirements, if trends
continue, with the historical statistics and projections published by
the Bureau of Mines:
Year ORNL. 1015 BTU B. of M.. 1Q15 BTU % Difference
1950 4.83 8.72 44.6
1960 7.50 10.88 31.1
1970 12.31 16.50 25.4
1980 17.96 21.56 16.7
2000 30.02 42.88 30.0
Several reasons are given for ORNL estimates being lower than
the Bureau of Mines statistics. Elements excluded from ORNL's estimates
were:
- urban freight traffic
- personal, agricultural, and service use of trucks
- non-bus urban passenger traffic (excluding private cars)
- private boating and passenger traffic carried by boats
- general (i.e., private) aviation
* Correction is (10.49-4.56) x 1015 BTU •= 5.93 x 1015 BTU
Adjustment to total: (29.97-5.93) x 1015 BTU - 24.04 x 1015 BTU
Adjusted aviation fuel demand .= 4.56 x 10 BTU (A)
Adjusted transportation fuel demand = 24.04 x 10 BTU (B)
(A) as % of (B) = 19.
- 31 -
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It has been suggested (12) that aggregation across sectors
may be responsible for the lack of visible, systematic, linear varia-
tions between the ORNL and B. of M. statistics, and that it may be Im-
portant to dig below the surface to uncover the factors responsible for
the fluctuating differences between the two sets of transportation energy
statistics.
The ORNL study also discusses the total energy consumption
attributable to automobiles in terms of the energy equivalents of:
- gasoline consumption
- petroleum refining (to produce the gasoline)
- automobile manufacturing
- retail sales of automobiles
- repairs, maintenance, insurance, replacement parts,
accessories, parking, tolls, taxes, etc.
The table implies that the efficiency of automobile usage
improved slightly between 1960 and 1970, while efficiency of gasoline
usage declined:
1960 1970
Total energy required (BTU/mile) 19,270 18,600
Gasoline energy required (BTU/mile) 9,524 9,933
The imputed energy requirements were estimated to have been:
BTU/mile
1960 1970
Petroleum refining
Automobile manufacture
Retail sales
Repairs, etc.
9.746
The estimated increase in energy consumption due to petroleum
refining is inconsistent with the fact that refinery fuel consumption
relative to the energy content of the petroleum processed decreased
from 12.3% in 1960 to 11.5% in 1970.
The energy used to manufacture automobiles will have been
affected by car imports (which require no expenditure of manufacturing
energy in the U.S.). However, this would not account for a 40% reduc-
tion, i.e., (1327-788) x 100 -r 1327. There is no obvious reason why
retail sales of automobiles should have become 30% more energy-efficient.
- 32 -
-------
The final item for repairs, etc. is seriously in error. It
was estimated from BTU per dollar of GNF and the percentage of GNP
represented by automobile maintenance, etc. The latter is primarily a
service activity of low energy-intensity. The error is significant
because, in ORNL's estimates, it accounts for 20% of the "total energy
required" for automobiles in 1970.
Thus, for 1970, the energy demand imputed to petroleum refin-
ing and auto repairs, etc. has been overestimated, while the imputed
demand for automobile manufacturing and retailing may have been under-
estimated. The first two factors outweigh the others quantitatively.
ORNL estimated fuel consumption and the imputed energy demands to have
approximately equal weight. However, it is judged that a more probable
ratio is about 2:1. The difference is important because gasoline con-
sumption is affected by the efficiency of the vehicle that uses it
while the other factors are not.
- 33 -
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APPENDIX 2
REFERENCES
(1) Dupree, W. 0. and Vest, J. A., "U.S. Energy through the Year 2000,"
U.S. Dept. of Interior (1972).
(2) "Energy Scenarios - Supply Considerations," Submitted by Esso Res.'
and Eng. Co. to Tech. Analysis and Evaluation Section, Engin.
Analysis Branch, Control Systems Laboratory, EPA, Research
Triangle Park, N. Car. (1973).
(3) "U.S. Energy Outlook," National Petroleum Council, Washington,
D.C. (1972).
(4) "Research and Development Opportunities for Improved Transportation
Energy Usage," summary technical report of the Transportation
Energy R&D Goals Panel, Report No. DOT-TSC-OST-73-14, September,
1972.
(5) "Energy Consumption for Transportation in the U.S.," Eric Hirst,
Oak Ridge National Laboratory, Report No. ORNL-NSF-EP-15, March
1972.
(6) "A Hydrogen-Energy System," study by Institute of Gas Technology
for the American Gas Association, August 1972.
(7) "U.S. Industrial Outlook with Projections to 1980," 1971-2-3
editions, Bureau of Competitive Assessment and Business Policy,
Dept. of Commerce.
(8) 1971 Edition of A.P.I.'s "Petroleum Facts and Figures," page 427.
(9) ibid, page 436.
(10) "System Energy as a Factor in Considering Future Transportation,"
R. A. Rice, A.S.T.M., December 1970.
(11) "Statistical Handbook of Aviation," F.A.A., 1970.
(12) Private communication of 5/28/74 from G. Hinkle, Environmental
Protection Agency.
- 34 -
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APPENDIX 3
RESOURCE BASE INFORMATION
This appendix is divided into two sections.
the terminology applied to "resources" and
"reserves",
Part 1 explains
The definitions
are quite complicated and are not uniform for different types of resources.
These differences are discussed as a prelude to a quantitative interpre-
tation of the principal domestic energy resources in Part 2.
Part 1
U.S.G.S. Definitions - General Principles
Estimates compiled by specialists of the U.S. Geological Survey
are generally based on projections of favorable rocks and on anticipated
frequency of the energy resource in the favorable rocks. According to
the U.S.G.S. (1), the accuracy of the estimates "probably ranges from 20
to 50 percent for identified-recoverable resources to about an order of
magnitude for undiscovered-submarginal resources". Additional points from
U.S.G.S. Circular 650 state that:
(1) "Resources...include all rocks and minerals (including their
contained heat for geothermal sources) potentially usable by man, including
currently known and recoverable reserves, undiscovered resources which are
estimated geologically or mathematically and which would be recoverable if
found, and energy sources (identified and undiscovered) whose exploitation
will require more favorable economic or technologic conditions than those
of the present".
diagram:
(2) Mineral resources may be represented by the conceptual
able
inal
inal
Identified
Known and -• . /
' • x X ' /
Recoverable Reserves -'
s / / / / '
Undiscovered
i
(C)
- 35 -
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The feasibility of economic recovery increases in the direction of (A) to
(B), while the degree of certainty concerning the existence of the
resource increases from (A) to (C).
(3) The above diagram is due to McKelvey (2) who defined para-
marginal resources as "recoverable at prices as much as 1.5 times those
prevailing now".
Recent changes in energy prices must have converted some para-
marginal resources into recoverable reserves. However, there has not yet
been time for this economic effect to be recognized in published estimates
of reserves. Although the concept of distinguishing among recoverable,
paramarginal, and submarginal resources is very useful for reviewing the
current situation at any given time, it presents difficulties when applied
to long range projections. The problem arises because we do not know what
price will prevail in the future, hence, we do not know where to draw the
line between recoverable reserves and paramarginal resources. In many
cases, legal barriers to resource utilization add another dimension to the
difficulty of estimating how much of a resource is, or will be, recoverable.
The resource base and the definition of terms that relate to it
are discussed in "Energy Research and Development - Problems and Prospects"
(3). It is pointed out that "different terms have been used to classify
the various kinds of resources for each of the fuels so that it has been
difficult to make comparisons among them", and also that the Geological
Survey definitions eliminate much of the difficulty. The definition of
identified recoverable resources has a number of important qualifications:
"Identified recoverable resources are the amounts of the resource that
can be extracted commercially at current prices and with current
technology. Enough detailed geologic information must be available so
the quantity of the fuel and its geologic setting are sufficiently
well known so that there is a high degree of certainty that it will
meet the general parameters that are used to class a given fuel in
this resource category. The amount of detailed geologic information
that permits different fuels to be classed in the identified recover-
able category varies for each fuel, and to use the reported values
intelligently requires a thorough understanding of the limitations
imposed by the definitions*. The amount of any resource in a given
category changes over time. As prices rise, as more efficient tech-
nology for extraction is developed, or other factors change...."
Put more bluntly: anyone can add numbers together, but it
takes more than arithmetic to know what the numbers mean and
whether they should have been added in the first place.
- 36 -
-------
U.S.G.S. Definition of Coal Resources
(1) Identified coal resources include coal beds that have been
mapped, with tonnage estimates made on the basis of thickness and general
quality. Recoverable coal within this category is defined in terms of
seam thickness as;
(a) at least 3-1/2 feet for bituminous coal and anthracite
(b) at least 10 feet for sub-bituminous coal and lignite
(c) 28 inches to 3-1/2 feet for bituminous coal and
anthracite
(d) 5 feet to 10 feet for sub-bituminous coal and lignite.
At a recovery factor of 50%, the U.S.G.S. estimates the identified,
recoverable coal reserves within 1000 ft. of the surface to be:
(a) + (b) = 200 billion ST
(c) + (d) - 190 billion ST
(2) Identified submarginal coal resources include "the thicker
coal left in the ground on first mining and thinner coal beds to a cutoff
at 14 inches for bituminous coal and anthracite and 30 inches for sub-
bituminous coal and lignite...to a depth of 6000 ft.". These submarginal
resources have been estimated at 1.2 trillion tons. No estimated recovery
factor has been assigned to these resources.
(3) "Undiscovered coal resources include deposits that have
not been mapped or sampled within the known coal fields. The estimates
are based on expected volumes of favorable rocks and expected coal
frequency within these rocks in unmapped or unexplored areas and in basin-
ward projections from the outcrop". To a depth of 3000 ft., and without
applying a recovery factor, the U.S.G.S. places the undiscovered coal
resources at 1.3 trillion tons, with a further 340 billion tons at depths
between 3000 ft. and 6000 ft.
U.S.G.S. Estimates of Petroleum Resources
S. P. Schweinfurth of the Geological Survey has compiled a number
of McKelvey charts that provide estimates of the petroleum liquids (crude
oil plus natural gas liquids) and natural gas resources of the U.S. as of
12/31/70 (1). The resources are quoted in billions of barrels and
trillions of cubic feet, respectively. The estimates may be summarized:
- 37 -
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Petroleum Liquids (10^ bbls)
Identified Undiscovered
(a) Conterminous U.S. plus
Alaska, including conti-
nental margin to 2,500 m.
(b) Alaska and related cont.
margin (incl. in (a))
(c) Conterminous U.S. plus
Alaska, offshore to depth
of 2,500 m.
(d) Conterminous U.S. (excl.
Alaska, onshore)
Natural Gas (TCF)
(a) Total
(as above)
(b) Alaska
(as above)
(c) Offshore Total
(as above)
(d) Onshore (excl. Alaska)
(as above)
Recoverable
Submarginal
Recoverable
Submarginal
Recoverable
Submarginal*
Submarginal**
Recoverable
Submarginal
Recoverable
Submarginal
Recoverable
Submarginal
Recoverable
Sub. 0-200 m.
Sub. 200/2,500 m.
Recoverable
Submarginal
52
290
11
20
6
17
36
220
290
170
31
8
40
14
220
150
450
2100
100
450;
200
550
700
230
800
2100
4000
480
860
850
900
1600
1000
1500
* Continental shelf, 0-200 m. water depth (0-656 ft.)
** Continental slope, 200-2,500 m. water depth (656-8,200 ft.)
The Geological Survey observes "part of the quantities reported
of identified Submarginal liquids and gas could become recoverable with
an increase in wellhead price or equivalent advances in technology and,
therefore, could now be called paramarginal. The data to make such a
breakdown meaningful, however are not available".
Reconciliation of Information Reported by U.S.G.S. and Others
The following definitions are used by the American Petroleum
Institute (API) and American Gas Association (AGA):
(a) Proved reserves of crude oil are the quantities estimated
with reasonable certainty to be recoverable from known reservoirs under
existing economic and operating conditions. Proved reserves include what
can be produced by fluid injection and other (secondary) recovery
- 38 -
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techniques. Also included are quantities of crude oil that may be produced
when secondary recovery techniques are applied to reservoirs expected to
respond to such techniques.
(b) Original oil-in-place is the estimated number of barrels of
crude oil prior to any production. In known reservoirs, it includes past
production and nonrecoverable oil as well as what may be recovered in the
future.
(c) Proved reserves of NGL and natural gas are similarly defined.
The Geological Survey's approach to undiscovered petroleum
resources differs from that used by API and AGA (whose approach will be
described later). In outline, the U.S.G.S. approach is;
(a) To extrapolate the results of past drilling to the remain-
ing unexplored but geologically favorable rocks in the U.S.
(b) To limit the estimates to a drilling depth of 20,000 ft.
and to an offshore water depth of 2,500 meters (approx. 8,250 ft.).
(c) To estimate natural gas by application of a gas/oil ratio
to the estimates of total petroleum resources.
(d) To estimate NGL by application of an NGL/gas ratio to the
quantities of gas estimated in (c).
(e) To assume that five-eighths of the resource in the ground
will (eventually) be discovered.
The U.S.G.S. also attempts to reconcile its own estimates with
API's. The latter recognizes total original oil-in-place (crude oil
only), from which may be deducted cumulative production, proved reserves,
and indicated additional reserves at the end of a given year. The differ-
ence is equivalent to McKelvey's known paramarginal and submarginal
resources of crude oil.
The API reports proved reserves of NGL, but does not report
cumulative production or total original NGL-in-place. The category
"indicated additional reserves of NGL" is not applicable because of the
general inapplicability of secondary recovery to natural gas reservoirs.
The AGA reports known quantities of gas reserves at the end of
a given year as proved reserves. Cumulative past production is reported,
but is a somewhat inexact estimate since natural gas produced in con-
junction with crude oil was flared for many years, and there are no
accurate records of the extent of this flaring. The AGA does not report
total original gas-in-place, and does not consider indicated additional
reserves because of the general inapplicability of secondary recovery to
gas reservoirs. Primary recovery of gas approximates 80%, whereas
primary recovery of crude oil now averages just over 30%.
- 39 -
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The Potential Gas Committee (Colorado School of Mines) separates
this potential into probable, possible, and speculative "reserves" of
natural gas. The NPC has made use of PGC's estimates, but has tended to
reduce them to two categories: probable/possible and speculative.
Geologic and mathematical methods are both used for estimating
petroleum resources. However, different authors or groups use different
variants of these methods. For example, the U.S.G.S. considers a larger
area of favorable rocks than the PGC. However, the latter includes poten-
tial rocks to drilling depths of 30,000 ft. whereas the U.S.G.S. stops at
20,000 ft. On the other hand, the U.S.G.S. considers offshore water depths
to 8,250 ft. while the PGC stops at 1,500 ft.*
Referring to an NPC report published in 1970, the U.S.G.S.
observes that:
(a) 'VlPC used a recovery factor of (only) 30% to estimate proved
reserves, even though substantially higher recoveries are likely over the
lifetime of production of the reserves. "
(b) "Some oil in the probable/possible category can be considered
to have been already discovered but not cited as proved reserve at the time
the NPC report was prepared. This is oil in undeveloped parts of fields
and pools that have been discovered but not drilled out. . .roughly it might
be assumed to be an amount equal to the proved reserves reported by the
API."
areas..."
(c) "The NPC report does not cover all potentially favorable
In self-appraisal of its own approach the Geological Survey says:
"This is, therefore, the only geology-based estimating method that is entirely
consistent. This method is not necessarily good, however, in estimating
potential resources because not all regions are alike in their geology and
petroleum potential. On the other hand, if the method is applied to large
enough areas, it is felt that errors will average out, and at least a
valuable first approximation will be obtained." Others disagree, as is
discussed below.
* It may be noted that a number of offshore drilling rigs are now
capable of operation in water depths up to 3,000 ft., and a few
rigs now under construction will have even a greater capability.
- 40 -
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H. R. Warman's* Views on Future Availability of Oil (4)
Mr. Warman observes "there seems to be such confusion and con-
flict in public utterances on the nature and significance of oil reserves
..." that it is necessary to explain the bases used for compiling the
statistics. He says "the only oil with which we need concern ourselves is
that which can be produced and used in commerce within the time under review.
This is the meaning applied to the term recoverable reserve...it is appalling
how little heed is often given to the relevance of time and cost in the
understanding of the concept of recoverable reserves". Additional points
are reproduced here since they may add greatly to an understanding of pub-
lished estimates of oil resources and of why such estimates may differ very
appreciably.
(1) The only oil ever likely to be produced is that which has
accumulated in the pore spaces of porous and permeable sedimentary rocks.
The effective pore space varies between 57, and 35% of total rock volume.
The oil content of the pore space of a reservoir capable of producing oil
varies between 35% and 90%, and below 6070 of oil saturation in the reservoir
will produce mainly water. The remainder of the pore space is filled with
water and gas.
(2) After discovery of an oil field and drilling of a few wells
it is possible to make approximate estimates of the total volume of the
reservoir and of the oil-in-place. From the collective experience of pro-
ducing many thousands of oil fields over more than 100 years, it is possible
to estimate how much oil will be recoverable.
(3) Sources of error in estimating reserves include:
(a) Ignorance of reservoir behavior. This can be important
for an individual reservoir, but not for global estimates.
drilled up.
(b) Misunderstanding and misreporting.
(c) Inability to define the size of fields until they are
(d) The "North American factor": "Firstly, companies'
declarations of reserves are governed by regulations of the S.E.C. (to
safeguard investors) and the IRS (vis-a-vis depreciation allowances). In
brief, these regulations stipulate that reserves can only be declared that
can be produced by 'existing facilities'. Thus, when a discovery well is
drilled into a new field the official 'declared' reserves have historically
been limited to what one well can produce or what can be produced from some
prescribed area around that well. Thus, as a field has been drilled up
* Chief Geologist, British Petroleum Co., Ltd., and an
acknowledged authority in the field.
- 41 -
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and as various extra facilities have been installed, including extra
recovery systems, the recoverable reserves figures have been increased.
In addition, the competitive lease system in America has often put a
premium on underquoting new discoveries. Patterns are changing, however,
as for example the published figures for the reserves of the Prudhoe field
in Alaska where the figures published are those of estimated total yield
of recoverable reserves".
(e) A tendency to use minimum figures when estimating the
return to be obtained from large capital investment to put a field on
production.
(4) It is not possible to produce more than about 50% of the
total recoverable oil in a reservoir in less than about 10 years. After
this, production will decline exponentially at a rate of about 10% annually.
Secondary and tertiary recovery methods may be used to arrest the initial
rate of decline but an even sharper decline rate may ensue later. The
effective life of an oil field will generally be in the range of 20-30
years.
Mr. Warman's discussion is concerned with world-wide oil
resources, and not exclusively with those of the U.S. However, from item
(3-d), it may be inferred that U.S. reserves have been conservatively stated
in relation to foreign petroleum reserves in general. However, Mr. Warman
also discusses the high cost of producing oil in a hostile environment or
from under deep water. He argues that only exceptionally large fields with
very good reservoir conditions will be economically producible and that
this will limit the amount of recoverable reserves from such areas:
"Thus, a very large part of the reserves of the U.S. would not under any
conceivable climate within the next two or three decades constitute a
recoverable reserve in the deeper offshore environment. On these grounds
the resource base concept so beloved of some U.S. authors, particularly in
the U.S.G.S., who quote reserves per unit volume of sediment from a
statistical estimate based on the history of American onshore areas needs
very critical analysis..."*
In relation to item (4), an offshore oil field discovered this
year might be placed in production in 1977 and might still be producing
past the turn of the century. However, only about 3% of U.S. offshore
acreage has yet been leased. Hence, the leasing of such acreage may con-
tinue for another two decades or longer depending, or course, on the rate
at which the leasing occurs. Therefore, petroleum production from this
segment of the domestic resource base may continue until the year 2025 or
* Nevertheless, if prevailing price levels continue, there would
seem to be good prospects for moving significant quantities
of resources into the category of recoverable reserves.
- 42 -
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later. The Department of the Interior has been considering an accelerated
offshore leasing schedule* such that the present average of two sales per
year would be increased to three sales annually through 1978. However,
President Nixon's January 23 energy message to Congress recommended a
faster schedule.
Part 2
U.S. Coal Resources
Chapter 5 of NPC's "U.S. Energy Outlook" is the basis for the
discussion that follows. In general, the statistical information has been
taken without significant modification other than rearrangement. However,
the interpretation of the data is specifically for the alternative auto-
motive fuels study (which, of course, was not NPC's purpose). Although
differing in detail, the statistics are broadly compatible with those of
the U.S. Geological Survey estimates. Indeed, the statistical resource
base used by the NPC and the U.S.G.S. is essentially the same.
(1) NPC reports the domestic resource base to include 150
billion tons of coal in formations of comparable thickness and depth to
those being mined in 1971-72. Of this total, 45 billion tons would be
recoverable by surface mining and 105 billion tons by underground mining.
However, NPC also observes, "Further mapping and exploration...should
result in substantial additions to reserves that can be mined with present-
day technology...especially...in the western states where large areas of
coal-bearing formations have been only partially explored".
(2) NPC quotes the following U.S.G.S. estimates of the coal
resource base that is "unmapped and unexplored":
* The time between the "call for nominations" and the actual lease
sale is about one year if the intermediate steps are not delayed.
These steps are; (a) "nominations due" (about 2 months after the
original call for nominations), (b) "announcement of tracts" (about
2 months later), (c) "draft environmental statement" (2 months
later), (d) "public hearing" (1 month later), (e) "final environ-
mental statement" (2 months later), (f) "notice of sale" (1 month later)
and, finally, the bonus sale itself in the following month.
- 43 -
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Estimate of Unmapped
State % Unmapped Resources, 1()9 Tons
W. Virginia Nil Nil
Pennsylvania 13 10
Ohio 5 2
Indiana 39 22
Illinois 42 100
Wyoming 73 325
N. Dakota . 34 . 180
Montana 41 157
Colorado 64 146
Utah 60 48
New Mexico 31 27
(3) It is important to recognize that a high percentage of the
unmapped coal resources in all of the western states except Utah may be
recoverable by surface mining. Thus, the potentially strippable coal
resources (which appear crucial to the production of synthetic fuels) are
much larger than implied by the statistics in items (1) and (4). Also of
significance is that most of the unmapped resources are under Federal
jurisdiction. In addition, it should be pointed out that the recovery
factor with strippable coal is above 80% whereas the NPC and others assume
an average recovery factor of only 50% for deep mining (by current tech-
nology).
(4) NPC gives the regional breakdown of coal reserves recover-
able by surface mining as:
States 10^ Tons %
Ky., W. Va., Va., Tenn. 4.2 9
Pa. 0.8 2
Iowa, 111., Ind., Ohio 5.6 12
Okla., Kans., Mo. 1.6 4
Colo., Mont., N.M., Wyo. 23.8 53
N.D. 2.1 5
Other States 6.9 5
Total 45.0 100
The above are recoverable reserves that have already been identified and
mapped.
(5) The comparable breakdown for reserves recoverable by under-
ground mining are:
- 44 -
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States
Pa., W. Va. (excl. 3 counties)
W. Va. (Mercer, McDowell, Wyoming counties)
Ky., Tenn., Va.
Ala.
111., Ind., Ohio
Utah, Colo.
Other States
Total
109 Tons %
33.5
4.6
12.2
0.3
29.7
6.7
17.6
104.6
•^P^BBB
32
4
12
<1
28
6
17
100
(6) NPC believes that most synthetic fuels plants will be built
in the western states, rather than in the Midwest or Appalachia. After
deducting significant quantities of western coals expected to be reserved
for direct use by electric utilities, the net (already identified) recover-
able reserves in certain western states were estimated to be:
State
N.M.
Colo.
Wyo.
Mont.
Mont.
N.D.
Tex., Ark.
Rank of Coal 10^ Tons
Bituminous 1.7
(23 MM BTU/ST) 0.5
Sub-bituminous 13.0
(17 MM BTU/ST) 2.9
Lignite 3.0
(13.5 MM BTU/ST) 1.3
1.0
Approx. Number of
Syn. Fuels Plants
Supportable*
10
3
56
13
10
5
3
}
}
13
69
100
The quantity of "committed reserves" required for each plant would be:
Billion Tons
Bituminous
Sub-b i tuminous
Lignite
Syn. Gas
0.16
0.22
0.27
Syn. Liquids
0.18
0.24
0.30
50:50 Mix**
0.17
0.23
0.29
* Syngas: 250 MMCF/D, 67% conversion efficiency, 90% operating factor;
coal reserves adequate for 30 years operation at full capacity.
Syn. liquids: 50 MB/D, 72% conversion efficiency, 90% operating fac-
tor; coal reserves adequate for 30 years operation at full capacity.
** Used to calculate the number of plants supportable, based on the
arbitrary assumption of equal numbers of each type of plant.
- 45 -
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(7) The geographical focus of the 100-odd plants estimated to
be supportable with identified and recoverable western coal may be
summarized:
Number of Plants*
Wyoming 56
Montana 23
New Mexico 10
N. Dakota 5
Colorado 3
Texas/Arkansas 3
Considering the unmapped resources estimated in item (2) many additional
plants may be supportable in all of the above states with the exception of
Texas/Arkansas. Although the ultimate potential in New Mexico is not as
great as in the other western states, its strippable coal of relatively
high rank gives it a compensating advantage. Wyoming appears to have the
greatest ultimate potential. However, this state's coal resources may
greatly exceed its capability for producing synthetic fuels. Water avail-
ability, plant sites, and many other factors are likely to be more limiting
than Wyoming's coal resource base.
(8) NPC states that sulfur content data for the coal reserves
referred to in item (1) are not available. However, quoting the Bureau of
Mines, NPC says that 46% of known coal reserves to a depth of 3000 ft. con-
tain 0.7% or less sulfur, and that 93% of this coal is in states west of
the Mississippi River. Other information (4) may be summarized to give a
general picture of the average sulfur content of U.S. coal on a state-by-
state basis:
State Av. Wt. % S
Pennsylvania 2.3
W. Virginia 1.5
Virginia 0.9
Illinois 3.5
Indiana 2.8
Ohio 3.4
Kentucky 2.4
Missouri 3.9
Kansas 3.4
Alabama 1.5
Texas 2.3
N. Dakota 0.4
Montana 0.7
Wyoming 0.8
Colorado 0.4
New Mexico 0.7
Utah 1.3
* Based on the arbitrary assumption of equal numbers of
250 MM CF/D syngas and 50 MB/D syn. liquids plants.
- 46 -
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(9) Processes used to produce synthetic fuels, whether gases
or liquids, will eliminate or substantially reduce sulfur. The disadvantage
of high sulfur content may be relatively less in gasification than in
liquefaction processes because of the greater ease of sulfur removal from
gas streams.
(10) NPC reports that only 11% of the coal reserves east of the
Mississippi River have sulfur contents of 0.7% or less. Much of this coal
is low volatile or medium volatile, and commands a premium price for
metallurgical purposes. In fact, most of this type of coal is produced
captively by, or dedicated to, the U.S. and foreign steel industries. Thus,
it is questionable whether any synthetic fuels will be produced from low S
eastern coals.
U.S. Oil Shale Resources
In 1972, the Geological Survey reported (1) that: "Resources
of oil shale are considered submarginal, although the best grade and most
accessible deposits would yield oil at a moderate increase in price of oil
into the range $4 to $5 per barrel...". Since crude oil prices have risen
above this level, it would seem that "submarginal" is no longer applicable
to the richer deposits of oil shale.
The following estimates were reported by the Geological Survey
(billion barrels):
Undiscovered Resources
Identified Extension of Undiscovered and
Resources Known Resources Unappraised
Recoverable Nil Nil Nil "
Paramarginal 160-600 850 500
Submarginal 1600 2500 20,000
The above figures do not apply directly to the present study
because none of the resource is classified as "recoverable", i.e.,
economically recoverable at the time the estimates were made. However,
price increases for conventional crude oil may have converted much of the
identified paramarginal resources into the "recoverable" category. The
matter may be examined further by review of NPC's findings:
(1) Most of the nation's oil shale resources are underlain by
the Green River Formation that extends through parts of Colorado, Utah,
and Wyoming. The richest deposits are in the Piceance Basin of Colorado
and the Uinta Basin of Utah. Somewhat thinner and generally lower grade
deposits are in the Green River Basin and Washakie Basin of Wyoming.
(2) NPC classifies oil shale deposits as follows:
- 47 -
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Class Thickness Richness (galIons/ton)
1 at least 30 feet " averaging 35
2 at least 30 feet averaging 30
3 (a) less well-defined averaging 30
(b) less well located
4 poorly defined 15-30
(3) Estimates of resources, based on the above classification,
are (billion barrels):
Piceance Basin . Uinta Basin
Class Colorado Utah, Colo. Wyoming Total
1 34
2 83 12
3 167 15 4
4 916 294 256
1781
(4) The shale oil resources in Class 1, and perhaps Class 2 as
well, may be regarded as economically recoverable. However, it is question-
able whether these resources can be considered as reserves. Only a fraction
of the oil shale will be recoverable by current mining methods, and some
loss of yield will be experienced in the process that converts the oil that
is bound in the shale rock to a synthetic (shale oil) crude. NPC estimates
that 54 billion barrels of syn. crude would be recoverable from the Class 1
and 2 deposits in the Piceance and Uinta Basins.
(5) The estimate in item (4) is conservative in some respects
but not in others. For example, it is likely that improvements in mining
and processing technology will increase the ultimate yield of syn. crude
obtainable from the Piceance/Uinta deposits. On the other hand, "reserves"
carry the connotation of availability. Approximately 8070 of the oil shale
deposits are on Federal lands and, hence, are not "available" until leased.
For environmental and other reasons*, this is not a limitation that can be
changed by a "stroke of the pen". The leasing question is substantially
different from that of western coal lands. The richest oil shale deposits,
in the Mahogany Zone of the Piceance Basis, are concentrated within an area
of about 30 miles by 35 miles. At present there are no reliable estimates
of the maximum density of mining and processing that will be tolerable in
this small area. Federal leasing, on a large scale, most probably will not
take place until the results of a prototype leasing program are known,
i.e., not before 1980.
* e.g., disputed mineral rights to much of the acreage.
- 48 -
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(6) It appears that, for many years, shale oil will be a
resource that is not limited by the oil shale resources but by other
resources such as water availability. Thus, it seems impossible to assign
any (billion barrel) number to shale oil reserves that will not be mis-
leading if separated from very important qualifications. Shale oil reserves
are different in character from petroleum reserves, but measuring both in
billions of barrels implies a similarity that invites wrong conclusions to
be drawn. One approach to this problem would be to say that the oil shale
resource base is enormous but that recoverable reserves of shale oil are
currently indeterminate. The size of the reserves that will be recoverable
over the next 50 years will depend on the availability of other natural
resources and on the technology that is developed to enhance the use of
these resources. For example, in situ recovery of shale oil, if feasible,
could greatly increase the effective reserves of oil shale by:
(a) Making it economically feasible to produce oil from
leaner and deeper deposits.
(b) Extending the area in which shale oil could be produced
economically, thereby alleviating the density problem in the Mahogany Zone.
(c) Reducing the amount of water required per barrel of
shale oil produced and, by virtue of (b), expanding the area from which
water may be drawn (see Section 5.1).
(d) Avoiding or minimizing the environmental problems
associated with the disposal of (retorted) spent shale.
U.S. Petroleum Resources
(1) By API definitions, proved reserves of domestic crude oil
approximated 35 billion barrels on 1/1/74, including 10 billion barrels
estimated for Alaska's North Slope. With the addition of indicated
reserves of crude oil and estimated reserves of NGL, the estimated total
recoverable reserves of petroleum liquids would approximate 47 billion
barrels. This figure is compatible with the 52 billion barrels of
identified-recoverable reserves reported by the U.S.G.S. for 12/31/70.
(2) The NPC projections to be cited refer to crude oil, i.e.,
they exclude NGL. Hence, the estimates of discoverable crude oil should
be related to the sum of proved-plus-indicated reserves of about 40 billion
barrels on 1/1/74. However, the NPC estimates have a reference date of
1/1/71. At this time, proved-plus-indicated reserves of domestic crude
oil totaled about 44 billion barrels.
(3) As of 1/1/71, NPC estimated that about half of the original
oil-in-place was yet to be discovered. Thus, the U.S. would have access
to its proved and indicated reserves plus whatever could be discovered and
converted into recoverable reserves. The estimates that follow refer only
to the remaining discoverable oil-in-place. These figures will be sig-
nificantly greater than the quantitites of oil that can actually be
recovered from what may be discovered.
- 49 -
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Remaining Discoverable OIF
Billion % of Original
Area Barrels Oil-in-Place
Lower 48 states - onshore 177 32
11 " " - offshore 89 87
South Alaska, incl. offshore 23 89
North Slope - onshore 48 67
" " - offshore 48 100
Total 385 48
Onshore subtotal (approx.) 237 37
Offshore " " 148 90
(4) The above estimates show that while more oil may remain to
be discovered onshore, it is the offshore areas that are relatively unex-
plored and, hence, offer the better prospects for discovery of large oil
fields. Stated another way, two-thirds of the onshore oil has already been
discovered whereas only one-tenth of the offshore oil has been found.
(5) Strictly for illustrative purposes (i.e., not a quantitative
prediction or projection), it may be assumed that during the next few
decades it would be possible to find about half of the 385 billion barrels
still discoverable on 1/1/71 and also that about half of the oil found
could be recovered (this assumes significant advances in the technology
and application of secondary/tertiary recovery techniques). On this basis,
some 96 billion barrels of potentially discoverable oil would become
recoverable. This figure may be compared with 44 billion barrels of crude
oil reserves as of 1/1/71. Adjusting to 1/1/74, the figures would become
92 and 40 billion barrels, respectively, for a hypothetical total of 132
billion barrels. Including an estimate for NGL would raise the total for
conventional petroleum liquids to about 150 billion barrels. If the
quantity were to be produced over a span of 50 years, the average annual
production rate would be about 3 billion barrels, or 8.2 MMB/D.
(6) Even if oil discovery were to take place as hypothesized in
item (5), annual production would not have a flat profile, i.e., 8.2 MMB/D
for 50 years. Within the next few years, the current downtrend (from
today's level of close to 11 MMB/D of domestic petroleum liquids) would be
reversed. Production might peak before the end of the century and would
probably be in a steep decline trend a decade later.
The NPC analyzed six cases of domestic crude oil supply. The
four cases most commonly referred to are based on the following assumptions:
Case 1 Case 2 Case 3 Case 4
Finding rate High High Low Low
Drilling rate High growth Medium growth Medium growth Current downtrend
- 50 -
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Parenthetically, it may be observed that the "current downtrend"
of Case 4 has been partially reversed sinc.e publication of NPC's study. A
medium growth condition exists now, although constrained by shortages of
drill-pipe and other oil field equipment. The finding rate in 1973 was
higher than in 1972, but the quantity of oil found per "discovery" was less.
The current drilling rate is 40% higher than a year ago. Whether "medium
growth" will turn into "high growth" would seem to depend on the vector of
the large amount of energy legislation now under consideration.
Using the above assumptions, the NPC projected the following
wellhead production rates for petroleum liquids from the continental U.S.
and Alaska. For Case 4, it was assumed that the Alaska pipeline would not
be in operation until 1981. Current production approximates 11 MMB/D
(including natural gas liquids) and is declining.
Case 1 Case 2 Case 3 Case 4
1980 MMB/D 13.6 12.9 11.6 8.9
1985 " 15.5 13.9 11.8 & 10.4
If the Administration's energy policies are put into effect, the
most likely condition in 1985 is intermediate between Cases 1 and 2.
Several inferences may be drawn for automotive fuels:
(1) Conventional petroleum from domestic resources would be
adequate to supply the transportation sector with fuels (and the petro-
chemical industry with feedstocks) for many years if it were possible to
shift the demand for all other uses to other energy sources.
(2) The early 1974 level of automotive fuel consumption of
approximately 6 MMB/D corresponds to slightly more than half the volume
of domestic production of petroleum liquids.
(3) Vigorous efforts to economize in the use of automotive
fuels are now in effect*. If corresponding efforts are made to expand
petroleum supplies the ratio of automotive fuel demand to domestic petroleum
supply may remain at about the current level.
(4) It is not feasible to replace all nontransportation fuel uses
of petroleum with other sources of energy, but it should be possible to move
in this direction.
(5) Synthetic fuels have the theoretical potential for substi-
tuting for petroleum in both transportation and nontransportation uses.
* This was true during the first quarter of 1974.
- 51 -
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(6) The national interest may be served best if overall energy
usage is optimized*, as distinct from trying to force-fit a given form of
energy into a limited number of uses.
(7) Conventional petroleum supplies are likely to be available
from domestic resources through the first quarter of the 21st century and,
hence, will be potentially available for automotive use during most of
this period.
(8) The existing vehicle population requires petroleum (or
petroleum-type) fuels. The prospects for supplying it are good provided
that the conditions of item (3) are satisfied.
U.S. Natural Gas Resources
On 1/1/71 proved reserves of natural gas totalled 291 trillion
cubic feet (TCP), with the North Slope contributing 26 TCP to this total.
The estimates that follow refer to the remaining discoverable gas converted
to the quantities that would be recoverable.
Remaining Discoverable Gas
Area TCF % of Original Gas
Lower 48 states - onshore (N) 550 57
" " " - offshore (N) 214 82
Alaska (N) 272 98
(N) = Nonassociated Gas 1036 6£
Gas associated with or
dissolved in crude
oil. 142 40
Total, (N) + assoc./
dissolved 1178 63
The importance of Alaskan and offshore resources of natural gas is very
apparent. The Potential Gas Committee (PGC)** estimates that 62% of the
above 1178 TCF is in operationally difficult or frontier areas:
(a) 14% is below 15,000 ft. onshore
(b) 20% is offshore
(c) 28% is in Alaska
* In the sense of allowing competition and the
marketplace to decide the issue.
** The PGC's estimates are a function of The Potential Gas Agency
of The Colorado School of Mines Foundation, Inc.
- 52 -
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The estimated total of 1178 TCF is approximately equivalent to 200 billion
barrels of crude oil. However, the PGC has already eliminated the recovery
factor that has to be applied to crude oil. If the same discovery assump-
tions were applied to natural gas, then the oil equivalent of the recover-
able gas would be 100 billion barrels. Thus, the quantities of domestic
crude oil and natural gas that may be recoverable in the future are
approximately equal in terms of heat content. The same is true on the
basis of currently proved reserves. Which quantity is the larger depends
on the way that NGL is treated. Geologically, the gas liquids "belong"
to the gas. Statistically, NGL are combined with crude oil to give total
petroleum liquids. The approximate parity on the basis of heat content
also applies to current production:
Crude oil plus NGL 11 MMB/D oil equivalent
Dry natural gas 10 " " "
The current level of domestic natural gas production is 22 TCF/yr. and has
been declining. However, the more optimistic cases considered by NPC
envisage an upturn before 1980:
Case 1 Case 2 Case 3 Case 4
1980 TCF 26.1 24.4 20.5 17.3
1985 " 31.9 27.3 21.2 15.0
1980 MMB/D O.E. 12.2 11.4 9.5 8.1
1985 " " 14.9 12.7 9.9 7.0
NPC's study also notes that nuclear-explosive stimulation of
natural gas reservoirs "is regarded as appropriate only in those areas
where conventional well completion techniques do not permit commercial
operation. Therefore, this technology...could be thought of as increasing
the reserve potential". This possible increase has not been considered in
the above tabulation.
Natural gas is pertinent to the alternate automotive fuels for
three reasons;
(1) Natural gas can substitute for petroleum liquids in most
stationary uses of fuel and, hence, impacts on the quantity of liquids
available as transportation fuels.
(2) Natural gas is the source of NGL* including natural gasoline.
* By convention, natural gas liquids are included with
resources of petroleum liquids (i.e., crude oil plus NGL),
- 53 -
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(3) If nuclear energy were to displace natural gas from its
electric utility and largest industrial markets, then significant quanti-
ties of gas might be available for conversion to methanol (as a potential
automotive fuel) or for direct use as automotive LNG.
The time-frame in which item (3) may occur is uncertain, except
that it will probably be after 1985.
U.S. Nuclear Energy Resources
Nuclear energy has been utilized commercially almost entirely in
the form of electricity. However, ways of using nuclear heat are already
under development (5). Nuclear energy itself is not a primary resource
since it is obtained from certain fissionable elements that, in turn, are
derived from mineral resources. The mining methods and all of the subsequent
steps combine to greatly affect the amount of useful energy produced for a
given quantity of the original mineral resource. The future availability
of nuclear energy is of crucial importance to the corresponding avail-
ability of transportation fuels because of its potential for releasing
fossil fuels from stationary uses.
It is customary to begin a discussion of the long range avail-
ability of nuclear energy with a review of uranium resources. An AEC study
cited by NPC estimated the following position as of 1/1/72:
1000 Tons of U3Q8 (Cumulative)
Reasonably Assured Estimated Additional
Cost of Production, $lb. (Proved Reserves) (Potential Reserves
$8 or less 273 460
$10 " " 423 650
$15 " " 625 1000
There are many problems with translating such figures into nuclear
capability. The first concerns mining practice. NPC says "...existing
underground mining operations are not recovering low-grade ores which have
been adjudged to be capable of yielding U308 at costs in the range of $8
to $15 per pound. Once these ores have been by-passed during the initial
mining operation, the likelihood of recovering the remaining 11303 for $15
per pound or less, in many mines, is very small". Thus, the apparent
increment in 11303 availability between $8/lb. and $15/lb. of 625,000-
273,000 = 352,000 tons may be illusory.
There is far more uncertainty about how the uranium will be used,
how much will be needed, and when other potentially utilizable materials
such as thorium will enter the picture. AEC's estimates of thorium
resources, at two price levels, are:
- 54 -
-------
(Resources, 1000 Tons)
Cost of Production Identified Potential
$10/lb. or less 65 325
$30/lb. " " 200 400
Current, light-water reactors (LWR) are either "pressurized
water" (PWR) or "boiling water" (BWR). Each of these reactor types
achieves about a 1.5% utilization of the uranium "burned". A significant
improvement in fuel efficiency is possible with the high temperature gas-
cooled reactor (HTGR). However, the efficiency of utilization could jump
to 70% or higher with the light metal fast breeder reactor (LMFBR). Both
the HTGR and LMFBR can make use of thorium as well as uranium. In the
very distant future, nuclear fusion, if proved to be feasible, holds the
potential of energy supplies that would not be limited by uranium-type
natural resources. NPC provides additional information about these
resources:
"Uranium as it is found in nature contains about 0.7% of the isotope
U235 with the remainder being the isotope U238«••.enrichment...in
the AEC's gaseous diffusion plants...(increases the percentage of
U235) to 2 to 3 percent which is required for the LWR's. The isotope
U238» which comprises 97-98% of the enriched uranium fuel, can con-
tribute significantly to power production only after it is trans-
formed into a fissionable isotope of plutonium (Pu) within the
reactor... .Fissile fuels such as U233, U235> an(* ^U239 are those
which undergo fission; fertile fuels such as thorium and U238 absorb
neutrons to produce a fissile fuel (U233 atu^ ^U239 respectively)...
HTGR's use highly enriched uranium (approx. 937. U235) as the fissile
fuel and thorium as the fertile fuel".
NPC's projections of nuclear electricity capacity are summarized
below (1000 MWe, i.e., GWe*):
Case 1 Case 2 Case 3 Case 4
1972 22 22 22 11
1975 64 64 64 28
1980 188 188 150 107
1985 450 375 300 240
In addition, NPC projected the four cases to the year 2000 to
"establish the requirements for exploration and the development of forward
reserves of natural uranium through 1985 and to analyze the trends in
demand for and supply of nuclear energy to the end of the century". The
post-1985 projections involve fast breeder reactors as well as current
reactor types (PWR, BWR, and HTGR). The first section of the table shows
* Megawatts electric and Gigawatts electric.
- 55 -
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the projected totals of electricity generating capacity in terms of 1000
MWe. The lower section shows the percentage of this capacity projected to
be in breeder reactors;
Nuclear Capacity, 1000 MWe
Case 1
10
25
39
Case 2
10
25
39
Case 3
10
25
39
Case 4
1
18
37
Case 1 Case 2 Case 3 Case 4
1990 750 625 500 400
1995 1065 890 710 568
2000 1470 1225 980 785
% of Total Capacity in Fast Breeder Reactors
1990
1995
2000
NPC characterizes Case 3 as being "an orderly growth of nuclear
power... a 'medium1 nuclear energy demand case...closely approximates the
AEC's 'most likely case'...current (i.e., 1972) licensing and legal prob-
lems are expected to be largely resolved during the next 2 or 3 years.
The lead time required from order to plant operation drops to 6 or 7 years
...". Case 2 is similar to Case 3 but also assumes that there will be a
marked preference for nuclear plants over fossil-fueled plants because of
increasingly stringent air pollution regulations and limited availability
of clean fossil fuels. Case 1 assumes that both government and industry
join in a maximum effort to increase U.S. nuclear power capacity. Case 4
assumes that "environmental constraints, manufacturing and technical
problems of more than a routine nature, and regulatory difficulties all
continue to cause planning and construction delays such that only those
plants already ordered by 1971 will go into operation by 1980...plant
completions pick up after 1980, but the installed capacity by 1985 falls
20% short of Case 3".
A study (6) by the Staff of the Joint Commission on Atomic
Energy (JCAE) has observed that "recent indications suggest that our actual
nuclear power production will be 15% or so less than what is shown here*
..." and also: "...it will be noticed how our slippage in nuclear power in
the year 1980 alone will require well over one-half million barrels per day
of oil equivalent**".
* Reference is to NPC's "Initial Appraisal".
** Oil equivalent is a quantity of energy. For crude oil of average
quality, 1 B.O.E. approximates 5.8 MM BTU. However, there is no
implication that the energy has to be supplied in the form of oil.
In round figures 500 MB/D O.E. are equivalent to 45 million short
tons of coal per year.
- 56 -
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It should be explained that NPC's "Initial Appraisal", the
Case 3 referred to in the previous section, and projections made by the
AEC in 1968, all estimate the same levels of nuclear capacity for 1975,
1980, and 1985. However, the AEC made further estimates in 1972, and it
is to these later estimates that the JCAE refers as being "15% or so
less..." Quantitatively, the various projections are:
Nuclear Capacity, (1000
AEC (1968) AEC (1972) NFC Case 3
1980 150 132 150
1985 300 280 300
1990 500 508 500
2000 1000 1200 980
The staff study implies that the recent trajectory has been
intermediate between NPC's Case 3 and Case 4, that this slowdown relative
to previously estimated "most likely" cases will exert an impact through
1980 but, eventually, an acceleration will occur such that nuclear capacity
in the year 2000 will be higher than previously projected. Clearly, AEC's
1968 estimates and NPC's Case 3 are equivalent. However, the differences
between the two AEC projections are important. On a percentage basis they
are:
% Difference
AEC (1972) - (1968)
1980 -12
1985 - 7
1990 + 2
2000 +20
The staff study also cited an information report made to the
JCAE on 3/7/73 by the Atomic Industrial Forum. AIF's estimates, shown
below, were developed as "the maximum which would be feasible providing
the limitations presently imposed by specific factors such as licensing,
development of additional uranium supplies, technical and construction
manpower limitations, and so forth are significantly diminished, and a
massive national effort is made to develop the nuclear systems". NPC's
Cases 1 and 2 are reproduced for comparison:
Nuclear Capacity, (1000 MWe)
AIF (1973) Case 1 Case 2
1980 146 188 188
1985 365 450 375
1990 700 750 625
2000 — 1470 1225
- 57 -
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Here, it must be observed that delays have continued since 1972
such that what may have been attainable in 1980, under "maximum" conditions,
from a starting point two years ago is no longer attainable now. With
more than a year's slippage, neither NPC's Case 2 nor AIF's estimate for
1985 seems feasible now and, clearly, NPC's Case 1 is not.
A simple way of constructing a new "maximum" case from today's
vantage point is to assume that AIF's trajectory is possible but that a
slippage of one year will not be recoverable. In this way, a modified AIF
projection (indicative of maximum possible nuclear capacity) may be compared
with AEC's 1972 projections (indicative of what is more likely assuming
that national energy policy is soon able to reduce lead-times and overcome
other problems). The difference between these two sets of numbers may be
used for various purposes. One application is to calculate the maximum
amount of nuclear capacity that might be applicable to synthetic fuels
production _if a maximum nuclear effort is begun almost immediately. Such
a maximum effort is extremely unlikely, hence the implication is that the
nuclear capacity available for synthetic fuel production will be at some
lower level.
Nuclear Capacity (1000 MWe)
Modified AIF AEC (1972) Differential
1980 120 132 -12
1985 300 280 20
1990 608 508 100
2000 1450«* 1200 250
-------
(a) A saving of about 2 MM B/D of oil or other fossil fuels
that would otherwise be required for process heat*, thereby "releasing"
such fossil fuels for other purposes including, in part, automotive uses.
(b) Direct application of the nuclear capacity to the production
of synthetic fuels. Using current best technology for producing hydrogen
by electrolysis, the hydrogen producible with 680 x 10^ KWH would be
equivalent to 0.6 MM B/D of oil.
(c) Application of the electrical capabilityto ground trans-
portion systems (mass transit and/or electrically powered private vehicles).
By the end of the century, any or all of these possibilities
could be operational at a significant level. Nevertheless, this level
would be much below the total energy requirements of ground transportation.
For example, the 250 GWe "differential" in the above tabulation is regarded
as a maximum that is unlikely to be realized. It is even more unlikely
that all of this "differential" would be applied to automotive fuels.
However, J^f this were to be done and jJE the entire product were automotive
hydrogen, then the quantity would approximate 1.5 MM B/D of "crude oil
equivalent" or a slightly higher volume of "gasoline equivalent" (say 1.7
MM B/D).
Long range, domestic resources of uranium and thorium appear
adequate for conceivable levels of energy demand. However, a squeeze
could occur by 1985 or shortly thereafter if several events occur in con-
junction:
(a) Construction of new capacity to separate uranium (by
diffusion or centrifugation) is delayed.
. (b) Development of the breeder is delayed, thereby forcing con-
tinued reliance on reactors that do not utilize uranium efficiently.
(c) There are further delays, for some time, in bringing exist-
ing nuclear plants and those under construction fully on line--but this
condition is followed by a rapid acceleration of getting nuclear capability
on line, with an accompanying acceleration in the demand for nuclear fuel.
The potential problems are due to long lead-times in the various
elements of an industry of high capital intensity that is growing rapidly
but unevenly.
* Uses of nuclear heat, other than for generating electricity, are already
under development and could double the effective energy output of a
nuclear plant. The application of nuclear heat to the manufacture of
synthetic fuels, chemicals, and steel is under active consideration (5).
- 59 -
-------
The possibility of a squeeze in uranium supplies around 1985
will be reviewed in the light of the capacity projections discussed above.
By 1985 nuclear capacity could approximate NPC's Case 3 projection of 300
GWe. However, the cumulative consumption of uranium concentrate would be
somewhat below that projected for Case 3 because of a lower level of nuclear
electricity generation during the earlier years of this time period.
Case 3 projects a cumulative requirement of 500,000 short tons
(ST) of U308 through 1985. However, the cumulative requirement would be
about 440,000 ST if the Case 4 annual usage were to be approximated until
1980 and Case 3 usage from 1980 to 1985. These quantities may be com-
pared with the estimated domestic reserves of 11303 available at $8/lb.:
Proved Potential Total
1000 ST of U30s 273 460 733
Thus, adequacy of supplies seems likely through 1985. However, the require-
ments in 1985 would be at an annual level of 70,000 tons and would be
increasing at an annual rate of about 117o. Hence, the remaining reserves
of "$8" 11303 would be exhausted before 1990 if this rate of consumption
were to continue. This is an unrealistic scenario. One possibility, if
it becomes apparent that the fast breeder will be seriously delayed, is
a slowing down in the ordering of LWRs. Another possibility is the utiliz-
ation of higher cost uranium resources. A further alternative is the
procurement of foreign 11303, and several U.S. electric utilities are
exploring this possibility. However, the availability and cost of petroleum
in W. Europe and Japan is having a predictable effect on acceleration of
the development of nuclear energy. Hence, there is no assurance that the
U.S. will have access to all of the foreign ^03 that it might wish to
purchase post-1985. Imports from Canada seem feasible*, yet some Canadian
production has alreadybeen contracted to W. Germany. Fuller analysis of
these questions is beyond the scope of the contract, but it is judged that:
(a) Any serious delay to the development and subsequent rapid
commercialization of the fast breeder reactor may constrain the rate at
which new orders are placed for nuclear capacity. This could occur before
1985.
(b) Scenarios that involve a build-up of nuclear capacity that
is significantly more rapid than NPC's Case 3 or AEC's 1972 projections
should also resolve item (a).
(c) An "all nuclear" scenario, not involving the use of fossil
fuels, is unrealistic until well into the 21st century (i.e., is infeasible
by the year 2000).
* When permitted by U.S. law.
- 60 -
-------
APPENDIX 3
REFERENCES
(1) "Energy Resources of the United States," Geological Survey Circular
650, P. K. Theobald, S. P. Schweinfurth, and D. C. Duncan, 1972.
(2) "Mineral Resource Estimates and Public Policy," V. E. McKelvey,
American Scientist, Vol. 60, No. 1, 1972.
(3) Prepared by Resources for the Future, Inc., at the request of Senator
Henry M. Jackson, Chairman of the Senate Committee on Interior and
Insular Affairs; Committee Print Serial No. 93-21, 1973; Chapter 5.
(4) Reported in Appendix 3, Table 13 of "Long Range Sulfur Supply and
Demand Model" (prepared under EPA Contract No. EHSD 71-13), and
based on data from "The Economy, Energy, and the Environment,"
Environmental Policy Division, Legislative Reference Service, Library
of Congress, September 1970.
(5) Proceedings of Meeting on Nuclear Process Heat by Commission of the
European Communities, Brussels, 1973.
(6) "Certain Background Information for Consideration when Evaluating
the National Energy Dilemma," staff study prepared at the request of
the Chairman of the Joint Committee on Atomic Energy, Joint Committee
print, May 1973.
- 61 -
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APPENDIX 4
POSSIBLE APPROACH OF OTHER COUNTRIES
TO ALTERNATIVE TRANSPORTATION FUELS
Although no supporting statistical evidence will be presented
here, it is expected that a shortage of petroleum fuels for transportation
will occur in W. Europe and Japan long before it need occur in the U.S.*
Prospects for synthetic fuels (other than hydrogen derivable from nuclear
energy) are limited or negligible in W. Europe and Japan. Hence, it is
anticipated that these countries will be forced to solve the "alternative
fuels" problem before the U.S. is forced to do so, and also that the for-
eign solution to this problem will affect what subsequently occurs in the
U.S.
Hydrogen from nuclear energy is a technical, but not a practical,
solution for W. Europe and Japan except in the very long range future. This
is because a high priority will have to be assigned to the development of
nuclear capability fast enough to provide industrial energy to maintain
economic development. Therefore, the solution of the problem in W. Europe
and Japan is likely to be heavily weighted towards effective ground trans-
portation systems powered by nuclear electricity. Initially, and already
in progress, is the development of effective mass transit systems. Even-
tually, by the time that sufficient nuclear capability is available, elec-
trically powered private vehicles seem likely (on a far larger scale than
exists today). At this stage, there would be a theoretical choice between
using the incremental nuclear capacity (a) to make hydrogen for automotive
purposes or (b) to power electric vehicles. The latter is expected to be
the choice because it would be a development that could occur incrementally
from a base that already exists.
Once sufficient nuclear capability has been developed in W. Europe
and Japan, petroleum is likely to be conserved for applications for which
electricity is not suitable. Hydrogen as a fuel will not be feasible until
nuclear capability can satisfy essentially all stationary uses of energy as
well as an effective ground transportation system. And, when this condition
occurs, there would not seem to be any need for fuel hydrogen despite its
technical feasibility.
These comments relate to the ways in which the future uses and
availability of synthetic fuels and conventional fuels are conceptualized.
It is important to place the automotive fuels question in a broad context
of energy supply and demand and in relation to what may occur in other
countries. What happens abroad may influence what occurs in the U.S.
* Excluding the shortage induced by the Arab oil embargo,
- 62 -
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APPENDIX 5
BUILD-UP OF SYNTHETIC FUELS MANUFACTURING CAPACITY
The delivered cost of imported petroleum is already at, or above,
the cost-plus-return-on-investment level estimated for synthetic fuels
from domestic resources. Whether this situation will continue will
depend primarily on events outside the U.S., and the outcome is a matter
for political rather than technical analysis. However, an assumption
that the situation will continue leads immediately to two questions:
(a) how soon can synthetic fuels become available?
(b) what quantities can be available at what times in the future?
Tentative answers are given in this Appendix, together with
an explanation of the basis on which the schedule of capacity build-up
was constructed. Additionally, it is explained why much of the answer
has to be found outside of published projections of synthetic fuel
availability. The Appendix is prefaced by an overview that places syn-
thetic fuels in a broader energy context and summarizes the quantitative
estimates made subsequently. The Appendix ends with a review of a study
sponsored by the Senate Committee on Interior and Insular Affairs.
Overview of Synthetic Fuels Capacity
The quantitative potential for manufacturing synthetic fuels
depends not only on the resource base but also on the rate at which the
resources can be brought into production. This section considers the
quantitative extent to which synthetic fuels from coal and oil shale may
contribute to the nation's total energy supply. No attempt is made here
to predict the extent to which the synthetic fuels will be used for auto-
motive purposes. However, the projections may be taken as an indication of
what the upper limit of such use may be.
. A summary of the projections for the different synthetic fuels
is given in Table 1. On the basis of product BTU'S, the projections im-
ply the following growth rates for production of synthetic fuels in aggre-
gate:
Period Growth. %/Year
1980 - 1985 43
1985 - 1990 19
1990 - 1995 12
1995 - 2000 10
The projected schedules for the different types of synthetic
fuels:
- 63 -
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APPENDIX 5
TABLE 1
PLAUSIBLE SCHEDULE FOR PRODUCTION OF
SHALE OIL. COAL LIQUIDS AND COAL SYNGAS
Shale Oil Coal Liquids Coal Syngas Total
Year MB/D 10 BTU MB/D 10 BTU TCF 10 BTU 10 BTU Million ST*
1978
9
1980
1
2
3
4
5
1990
1995
_
50
100
150
200
250
300
400
900
1600
_
0.11
0.22
0.33
0.45
0.55
0.66
0.9
2.0
3.6
_
-
-
50
100
200
300
400
900
1600
-
-
-
0.11
0.22
0.45
0.66
0.9
2.0
3.6
0.08
0.2
0.4
0.6
0.8
1.1
1.5
1.9
4.7
8.3
0.08
0.2
0.4
0.6
0.8
1.1
1.5
1.9
4.7
8.3
0.08
0.3
0.6
1.0
.1.5
2.1
2.8
3.7
8.7
15.5
5
12
24
43
60
87
127
163
343
692
2000 3200 7.2 2700 6.0 11.6 11.6 24.8 1024
* In terms of bituminous coal (11,500 BTU/lb.).
Notes: (1) The above projections are for average production during
the year.
(2) The BTU values refer to the heat content of the total
annual production.
(3) Arbitrarily, the heat content of 1 barrel of shale oil or
of coal liquids is taken as 6 MM BTUs. Actually, the coal
liquids may have a slightly higher heat content.
(4) Coal syngas includes both Hi-BTU and Lo-BTU gas. Volumes
are corrected to 1000 BTU/CF.
EPA-460/3-74-009
- 64 -
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(1) are believed to be realistic in terms of when first commercial
production may be expected (in the absence of national priority such as was
given to the Manhattan Project).
(2) have been kept comparable in growth rate since insufficient
evidence is available for biasing the schedules towards or away from any
given synthetic.
(3) in aggregate, are believed to be feaeible with respect to
construction capabilities, i.e., more emphasis on any one synthetic might
force reduced emphasis elsewhere.
Item (3) applies primarily to the first part of the next decade.
Beyond 1985, it may be that construction capability could be increased
substantially. For this to happen will require the groundwork to be laid
quite soon. The impact of construction requirements in the electric utility
industry must also be kept in mind.
The total capital investment, in mining and primary conversion
facilities, required for the projected 1985 production levels would be
about $17 billion*. However, the actual amount of capital invested would
be higher than this figure due to investments in additional plants not
yet on stream. The total investment would exceed $20 billion and, by
1985, would be at the annual rate of approximately $3.5 billion. These
figures may be compared with those for total energy investments in
Table 2:
(a) The cumulative capital requirements are shown for the period
1971-1985 for NPC's Cases (1) and (2), with electricity generation and
transmission separated from other energy investments.
(b) The estimates in (a) are converted from 1970 to 1973 dollars.
(c) An intermediate case is constructed that is one-third of the
way from Case (2) towards Case (1).
(d) An estimate of capital invested from 1971 to 1973 is deducted
from the total in (c), and the approximate annual rate of investment in
1985 is estimated.
The comparison suggests that about 4% of total energy investments
may go into synthetic fuels between now and 1985, and that synthetics may
account for about 5% of the annual total in 1985. These percentages would
be about doubled if electricity generation and transmission were to be
excluded from the total energy estimates. However, it must be pointed out
that the estimates are only rough approximations because:
In 1973 dollars, converted from NFC estimates (for various types of
facilities) in 1970 dollars. Costs have escalated more rapidly than
general inflation since the NFC study, hence the numbers derived from
the NFC study should be considered low.
- 65 -
-------
APPENDIX 5
TABLE 2
NPC PROJECTIONS OF CAPITAL
REQUIREMENTS FOR ENERGY INDUSTRIES
Included
Excluded
Resource development
Processing
Primary distribution
Power plant construction
Transmission
Water resources
(A) 1971-1985 Capital Requirements
Electricity generation and
transmission
All other
Total
(B) 1971-1985 Capital Requirements
Electricity generation and
transmission
All other
Total
(C) 1971-1985 Capital Requirements
Electricity generation and
transmission
All other
Total
Petroleum marketing
Gas distribution
Electricity distribution
Development of overseas resources
Billion 1970 $
NPC Case (1)
235.0
312.4
547.4
NPC Case (2)
235.0
272.2
507.2
Billion 1973 $
Case (1)
263
350
613
Case (2)
263
305
_ 568
Intermediate Case*
263
320
583
* 1/3 of the way from Case (2) towards Case (1).
(D) 1974-1985 Capital Requirements
Total
Approx. annual rate in 1985
Billion 1973 $
532
72
Based on NPC's "U. S. Energy Outlook," Chapter 14 and Table 180.
EPA-460/3-74-009
- 66 -
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(1) The NCP estimates relate to levels of consumption that
are no longer likely to occur.
(2) On a unit basis (i.e., investment required to produce a
given amount of energy), the NPC estimates are too low because:
(a) Petroleum imports are expected to be lower than pro-
jected by NPC (thereby leading to higher levels of domestic investment).
(b) Synthetic fuels and nuclear power investments are
more capital intensive than investments associated with conventional
petroleum particularly if much of the latter is assumed to be imported*.
(3) Costs have escalated since the NPC study was made.
While it is not known whether the total investments in Table 2
are overstated or understated, the percentage of total energy investments
projected for synthetic fuels is probably understated. Whatever scenario
is preferred for synthetic fuels, high investments are expected in the
aggregate of:
(1) Exploration for domestic petroleum (crude oil and natural
gas ) .
(2) "Conventional" petroleum refining.
(3) Coal mines for the satisfaction of domestic and export
requirements for solid coal (i.e., coal other than that used to make
synthetic fuels).
(4) Electric utilities.
(5) Nuclear energy.
Published Forecasts of Synthetic Fuels Production
Although there are numerous forecasts that refer to synthetic
fuels, few are independent. For example, a recent study (1) projects
the following:
MMB/D of Oil Equivalent
Shale oil
Coal SNG
1975
0.2
1980
0.5
1985
0.1
0.7
* The investments associated with the production of foreign oil are
excluded from Table 2.
- 67 -
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However, it turns out that the above numbers were taken from
a report (2) by the staff of the Joint Committee on Atomic Energy. The
first page of this study notes:
"The staff has developed an energy display system...The data
displayed are based on past history for the years of 1960 and 1970, and
projections for 1980 and 1985 , all of which were published approximately
two years ago by the Lawrence Livermore Laboratory (3) based primarily
on information released by both the Department of the Interior and the
National Petroleum Council."
Tracing back further, it is found that the original references
cited are:
"America's Energy Needs and Resources," remarks by the Hon. Hollis M.
Dole, Asst. Secretary for Mineral Resources, at Palo Alto on 1/12/71.
- "U.S. Energy Outlook. An Initial Appraisal 1971-1985." National
Petroleum Council, 7/15/71.
Subsequently, both the D.O.I, and the NPC have superseded
their 1971 studies. In December 1972 the D.O.I, published "United
States Energy through the Year 2000," while the NPC published its final
report on the "U.S. Energy Outlook" at the same time. While it must be
expected that both of these reports will be superseded*, they are the
most useful comprehensive energy supply studies presently available.
Pertinent elements of both will be reviewed next. Some information dis-
cussed in other sections of the report will be repeated. This is un-
avoidable in the interest of making this Appendix as complete as possible
in itself so as to relieve the reader from having to refer to other parts
of the report.
The D.O.I, makes separate projections for (a) synthetic gas,
(b) synthetic liquids, and (c) a catch-all category called "supplemental
supplies." The explanation of the latter is worth quoting in full:
"Between now and 1980, these supplemental supplies must come
either in the form of imported oil from foreign sources or incremental
production from conventional domestic resources, both onshore and off-
shore, to the extent that it may be made available through increased
discoveries of new reserves. The proportion which each of these sources
will contribute is dependent primarily upon governmental policies,
environmental restraints, and economic conditions during this period.
Beyond 1980, supplemental supplies will come not only from these sources
but also from such nonconventional sources as shale oil, tar sands, and
coal liquefaction. Development of new technologies will also be a con-
tributing factor to the extent to which these new energy forms are made
available."
Probably by up-dating studies by both the D.O.I, and NPC, and also
new material from the Federal Energy Administration.
- 68 -
-------
The quantitative D.O.I, projections are reproduced in Table 3.
Immediately apparent is that the projected quantities of "synthetic gas"
and "synthetic liquids" are small in relation to "supplemental supplies.'
On an input BTU basis (which makes allowance for consumption of primary
energy in synthetic fuels processes), the combination of "synthetic gas"
and "synthetic liquids" amounts to 8.5% of "supplemental supplies" in
1980, with the percentage rising to 13.6 in 1985 and 19.3 in the year
2000.
The scenario for the alternative automotive fuels contract is
compatible with the Administration's "Project Independence," i.e., much
of the "supplemental supplies" will have to be in the form of synthetic
fuels rather than imported petroleum. However, the level of "supple-
mental supplies" projected by D.O.I, is probably unattainable. Indeed,
"independence" requires energy conservation far beyond what is projected
by D.O.I. Hence, it is not legitimate to use D.O.I.'s projections of
"supplemental supplies" as a forecast of synthetic fuels production.
At the same time, the level of synthetics production specifically fore-
cast by D.O.I, is clearly inadequate for "independence".
Four different cases of supply were examined in NPC's final
report. As noted in Table 4, NPC considered Case (1) hard to attain
because of its dependence on rapid removal of a number of constraints—
most of which are still in effect a full year after the report was
issued. Case (4) assumed that the constraints on development of domes-
tic energy resources would be maintained. There is reason to believe
that this situation has begun to change and, hence, that Case (4) is too
pessimistic. Cases (2) and (3), which are intermediate between (1) and
(4), seem probable for the medium term. However, after a significant
near-term time-lag, the conditions for Case (1) may still be achievable
and, in the long run, surpassed. It should be noted that NPC's detailed
projections extended only to 1985 and, thus, deal with only the very
early stages of the synthetic fuels industry.
The D.O.I, and NPC projections are compared in Table 5. When
considered on the same basis, the D.O.I, projections fall between NPC's
Cases (1) and (2) but are closer to (1) than to (2). The data in Table
5 are for synthetic products (not the primary energy input needed to
make these products) and hence, their BTU content may be related to the
projected demand of the final consuming sectors (i.e., excluding the
energy consumed in conversion processes ahead of the final consuming
sectors). On this basis, the synthetics in NPC's Case (1) would supply
5.9% of the total energy demand of the final consuming sectors. All of
the other cases would contribute a smaller percentage of final demand.
From the standpoint of synthetic fuels, NPC's Case (1) for 1985 may be
characterized as follows:
(1) About equal volumes of syncrude from shale and coal.
(2) About 50% more BTUs from coal syngas than from either
coal or shale syncrude.
- 69 -
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APPENDIX 5
TABLE 3
D.O.I. PROJECTIONS*
Synthetic Gas
(Based on Table 12 of D.O.I. Study)
1980 1985 2000
Coal - Million Tons 19 86 308
- Trillion BTUs 430 2000 7140
Petroleum - Million Barrels 84 128 105
- Trillion BTUs 440 670 550
Total Inputs - Trillion BTUs 870 2670 7690
Total Output (Gas Produced)
- Trillion CF 0.7 2.0 5.5
- Trillion BTUs 700 2000 5500
Synthetic Liquids (Based on Table 16)
- Million Barrels — 180 365
- Trillion BTUs — 1000 2010
Supplemental Supplies
(Based on Table 16)
- Million Barrels 3875^ 4885^ 9125^
- Trillion BTUs 18,420 27,100 50,160
= all imports
= new (conventional) domestic supplies, imports, shale oil,
coal liquids, etc.
* "United States Energy through the Year 2000," Walter G. Dupree, Jr.,
and James A. West, Department of the Interior, December 1972.
EPA-460/3-74-009
- 70 -
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1980
Shale Syncrude
Coal "
Coal Syngas
1985
Shale Syncrude
Coal "
Coal Syngas
MM B/D
ii
TCF
MM B/D
TCF
APPENDIX 5
TABLE 4
NPC PROJECTIONS*
Case 1
0.15
0.08
0.6
0.75
0.68
2.5
1980
Shale Syncrude
Coal "
Coal Syngas
Trillion BTU
it
296
175
512
983
Case 2
0.10
0.4
0.40
0.08
1.3
197
329
526
Case 3
0.10
0.4
0.40
0.08
1.3
197
329
526
Case 4
0.2
0.10
0.5
165
165
1985
1478
1489
2269
5236
788
175
1208
2171
788
175
1208
2171
197
—
494
691
Shale Syncrude
Coal "
Coal Syngas
Notes: Above statistics do not include the primary energy consumed in
the conversion processes.
Case 1 is considered difficult to attain because it requires
early resolution of environmental issues, ready availability
of government land for energy resource development, adequate
economic incentives, etc. Case 4 makes pessimistic assumptions
about these factors. Cases 2 and 3 are intermediate, and make
relatively optimistic assumptions about the finding rate for
conventional petroleum and for the development of nuclear
generating capability.
* "U.S. Energy Outlook," National Petroleum Council, December 1972.
EPA -460/3-74-009
- 71 -
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APPENDIX 5
COMPARISON OF D.O.I
TABLE 5
. AND NPC PROJECTIONS FOR 1985
NFC Case
Shale Syncrude - MM B/D
12
- 10 BTU
Coal Syncrude - MM B/D
- 1012 BTU
Coal Syngas - TCP
- 1012 BTU
Total Synthetics - 1012 BTU
ditto excl. shale oil
D.O.I.
N.S.
0.5
1000
2.0
2000
3000
3000
(1)
0.75
1478
0.68
1489
2.5
2269
5236
3758
0.40
788
0.08
175
1.3
1208
2171
1383
(3)
0.40
788
0.08
175
1.3
1208
2171
1383
0.10
197
0.5
494
691
494
For 1985, D.O.I, estimated a primary energy demand of 116.6 x 10 BTU
and a net energy demand in final consuming sectors of 89.7 x 10-^ BTU.
Total Synthetics as % of:
- Total Primary Energy
- Consuming Sector Demand
2.6
3.4
4.5
5.9
1.9
2.4
1.9
2.4
0.6
0.8
Note: D.O.I, projections exclude shale oil and other synthetics that
are buried in the "supplemental supplies" category.
EPA-460/3-74-009
- 72 -
-------
(3) A significant, but still minor, percentage of total
energy demand supplied by synthetics.
(4) An implication that synfuel production could be in a
rapid uptrend by 1985, i.e., production in subsequent
years could be much higher than the volumes projected
for 1985.
Recent Information
Important events since publication of the D.O.I, and NPC fore-
casts in December 1972 have included the President's energy message of
April 1973, the Arab oil embargo, the»creation of a Federal Energy
Agency, the expansion and more centralized control of government and
government-sponsored research on energy, some changes in the controls on
energy prices, and a number of Congressional bills whose fate is not yet
determined. In total, many changes have occurred while many others are
in prospect, although it is not clear what they will be. A plausible
scenario is that delays will continue until several controversial issues
are settled, that these issues will be substantially settled before the
end of 1974, and that an accelerating rate of development will occur
subsequently. However, it is already apparent that construction capa-
bility and manpower will be rate-limiting factors even if all other
obstacles can be overcome.
While the shortages may be temporary, oil field supplies
(e.g., steel pipe and drilling rigs) are already limiting drilling
activities. Backlogs of work by engineering contractors are increasing.
Although construction labor is not tight yet, there are widespread pre-
dictions that this will occur, particularly when construction of the
Alaska pipeline begins to siphon off manpower from the "lower 48" states.
The need to plan the sequential construction of Athabaska tar sands
projects in Canada has been recognized. A shortage of roof bolts is
delaying the construction of coal mines. A persistent shortage of rail-
road hopper-cars is restricting the movement of coal and other commodi-
ties, and may lead to direct intervention by the Interstate Commerce
Commission. The items cited are just a sampling, and are intended to
support the conclusion that it will be extremely difficult, or even
impossible, to advance the dates at which the first commercial-sized
synthetic fuels plants can be on stream even though the earliest possible
operation appears to be clearly in the national interest.
Schedules for the production of different types of synthetic
fuels will first be discussed separately, and then considered on an
aggregate basis.
Shale Oil
In testimony to the House Interior Mining Subcommittee in
December 1973, John Hutchins, the manager of the Colony Development oil
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shale plant, placed the maximum production of shale oil at 500 MB/D in
1985, "given the best possible conditions." For practical purposes,
this estimate corresponds to NPC's Case (2) projection, since something
less than "best possible" can be expected.
Announcing that the first lease sale of government shale
lands would take place on January 8, 1974, Secretary of the Interior
Rogers Morton said that the leasing program "will encourage oil shale
development and allow us to learn whether our 600 billion barrel shale
oil reserves can be developed at acceptable economic and environmental
costs." This suggests that the first six shale oil producing facilities
could be in operation by the end of 1981, and would have a combined
capacity of about 250 MB/D. Allowing for some slippage in timing and
for sustained production somewhat below the nominal capacity, this
figure is compatible with Mr. Hutchins1 estimate of a maximum of 500
MB/D in 1985. The D.O.I, schedule is about one year more optimistic
than the Lawrence Livermore estimates (5) reported below:
Projected Start-Up Dates
of First Synthetic Fuels Plants
Type Year
Shale Oil 1979
Lo-BTU Coal Gasification 1979
Solvent Refined Coal 1981
Hi-BTU Coal Gasification 1981
Coal Liquefaction 1982
The environmental impact statement (8) by EPA/DOI that preceded
the announcement of the oil shale lease sale projected significant pro-
duction of shale oil from properties already in private hands:
By end of Leased Lands Production, MB/D
1981 Private 400
1985 Private and Government 650
The EIS looked at the impact of shale oil production up to a
level of 1 MMB/D, but without estimating when this level might be
achieved. The EIS appears to be:
(1) conservative, in the sense that it considers the environ-
mental impact of larger volumes of production than are
likely until after 1985.
(2) optimistic, in terms of the level of production that is
likely by 1985.
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The difficulty in developing a schedule for shale oil produc-
tion, for use in the alternate automotive fuels study, is that a judg-
ment has to be made about the vector of a number of conflicting
variables:
Favoring High Level of Production
(1) Extensive resource base
(2) Domestic resource
(3) Cost estimated to be moderate relative to alternatives
(4) Similarity of product to petroleum
Constraints to Production
(1) Environmental (disposal of spent shale, water
availability, population/ecological pressures)
(2) Availability of leases
(3) High capital cost
(4) Construction time
(5) In situ technology not proven
Some of the above points have been highlighted as follows (9):
"The leasings announced last week will allow...the Department
of the Interior to take stock of the environmental damage that
results. After three or four years, the companies should be
able to decide whether oil shale development is commercially
attractive, and the Federal government will be able to decide
whether the environmental costs justify throwing the whole
area open to development."
"...production of 1 million barrels of shale oil a day will
require the mining, processing, and dumping of 2 million tons
of rock, and that would require a mining operation equivalent
in size to the entire United States domestic coal industry."
"If it can be perfected, in situ production would have the
advantage that little or no rock would have to be brought to
the surface and eventually disposed of, so many of the
environmental problems would not arise, and it would also
use less water."
Similarly, the EIS stated: "It is obvious that considerable
further improvements in in situ recovery are still required before
industrial scale in situ recovery could become a reality."
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Secretary Morton's reference to "600 billion barrel shale oil
reserves"* may be used to illustrate problem quantitatively. If produc-
tion in 1985 were to be 0.4 MMB/D, and were to grow thereafter at an
annual rate of 20%, a production rate of 33 MMB/D or 12 billion barrels
annually would be reached in nearly 25 years (i.e., around the year
2010). At that time, about one quarter of the 600 billion barrels would
have been produced. If the rate stabilized at 33 MMB/D in the year
2010, production at that level might be continued for another 25 years
such that in the year 2035 about three-quarters of the reserves would
have been consumed. By this time, a decline in production might be
assumed so that, after another 25 years (i.e., the year 2060), the
entire deposit would be exhausted.
The above example is entirely hypothetical since it is not
known whether it will ever be feasible to produce shale oil at the rate
of 33 MMB/D. Nor is it known whether a growth rate of 20%/yr. could be
sustained for more than two decades. From today's vantage point, both
conditions seem most unlikely. The purpose of the example is to argue
that:
(1) The existence of a large resource base does not imply
that substantial production can be developed quickly.
(2) Factors other than the size of the resource base may
set a ceiling on production rate.
(3) Strictly from the standpoint of resources, shale oil
production may be feasible throughout the 21st century
at production levels set by (2).
The NPC estimates the total of shale oil resources in the Green River
formation to be 1,781 billion barrels:
Class Characteris tics Billion Barrels
1 Most favorably located; at least 35 gals./ton 34
2 II II It I* II OQ II II QC
3 Less " " " " 30 " " 186
4 Poorly defined deposits; " " 15 " " 1466
Secretary Morton's figure includes all of the Class 1-3 resources and
part of Class 4 deposits. The cut-off point in Class 4 is believed
to be at 25 gals./ton. Secretary Morton's figure corresponds to the
upper end of the range of "paramarginal" shale oil resources as pre-
viously defined by the U.S.G.S. and cited in Appendix 2.
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A more moderate growth rate of 15%/yr. would lead to the
following approximate schedule:
Year Av. Production During Year, MMB/D
1979 0.1
1985 0.4
1990 0.9
1995 1.6
2000 3.2
The above schedule is a middle course. On the one hand, it is
recognized that much larger volumes could be utilized much sooner. On
the other hand, experience drawn from the petrochemical industry sug-
gests that sustained growth rates of 15%/yr. are possible but uncommon
for tonnage petrochemicals. A schedule compatible with the above pro-
duction rates is given in Table 6. It is assumed that commercial pro-
duction of shale oil by in situ methods will occur in the 1985-1990 time-
frame. If suitable technology (to overcome environmental problems and
water limitations) is not developed by this time, then it seems improb-
able that shale oil production could approach 3 MMB/D in the year 2000.
Indeed, there is much speculation that the upper level may be about
1 MMB/D.
Coal Gasification
The schedule for coal gasification is pertinent to the
alternative automotive fuels study for three reasons:
(1) The possibility that methanol may be made from syngas
(CO and H_, not from synthetic CH,).
(2) Engineering and construction effort that is applied to
coal gasification will tend to restrict the effort that
is available for other syn fuel developments.
(3) Coal used for gasification must be subtracted from the
coal potentially available for other purposes and, hence,
gasification and liquefaction may be seen as being in
competition for the same resource.
The D.O.I, and NFC projections for coal syngas have already
been compared in Table 5. The D.O.I, forecast is substantially equiva-
lent to NFC's Case (1). However, there has been some slippage in the
schedule such that the 1985 "target" for coal syngas no longer appears
achievable.
A report (6) by the National Gas Survey task force of the
Federal Power Commission believes that five 250 MM CFD Hi-BTU coal
gasification plants could be in operation by the end of 1980 and that
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APPENDIX 5
TABLE 6
PLAUSIBLE SCHEDULE FOR BUILD-UP OF
SHALE OIL CAPACITY AND PRODUCTION
Nominal Capacity, MB/D Average Production, MB/D
Year at Year-End During Year
1979 100 50
1980 150 100
1981 200 150
1982 300 200
1983 350 250
1984 450 300
1985 500 400
1986 600 500
1987 700 600
1988 800 700
1989 900 800
1990 1000 900
1991 1100 1000
19?2 1250 1100
1993 1400 1200
1994 1600 1400
1995 1800 1600
2000 3500 3200
Notes: For above schedule to be achieved, it is assumed
that engineering and purchasing would begin 3-1/2 -
4 years before the start-up of each plant, and that
construction would begin at least 3 years before
plant start-up. For example, if an average of 50
MB/D of shale oil is to be produced from the first
plant during 1979 then this plant would have to
start up early in 1979. In turn, the construction
would have to begin by mid-1975, while engineering
and purchasing for the plant would have to start
before the end of 1974.
EPA-460/3-74-009
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16 such plants could be operating by the end of 1985. Nominally, each
plant would have the capacity to produce 250 x 365 MM CF per year. How-
ever, the NPC considers that an operating factor of 90% should be
applied. In this case, the annual production of each plant would be
0.082 TCP. Thus, using the FPC projection for numbers of plants, the
level of Hi-BTU syngas production would be slightly less than 0.4 TCF in
1980 and slightly less than 1.3 TCF in 1985*. Each plant would require
the following raw material input, with the volume depending on whether
bituminous, sub-bituminous, or lignite coal was used:
Million ST/yr.
bituminous coal 5.0
(or) sub-bituminous coal 7.2
(or) lignite 9.1
To the above should be added the prospects for considerable
quantities of Lo-BTU gas that could be used directly by electric utili-
ties, by certain industries, or for conversion to methanol. Whereas
the Hi-BTU gas would have a nominal heat content of 1000 BTU/CF, the
Lo-BTU projects may produce gas of various heat contents. Hence, it is
convenient to consider the Lo-BTU gas projects on a Hi-BTU equivalency
basis, i.e., to express their output as if it were gas of 1000 BTU/CF.
A plausible schedule of the build-up of coal syngas production
is given in Table 7. It must be pointed out that the split between
Hi-BTU and Lo-BTU gas is a matter of judgment, and that no attempt has
yet been made to specify how much Lo-BTU gas may be converted to
methanol**. The immediate purpose is to derive the coal production
implications of the schedule. The current level of coal production,
mostly bituminous coal, and inclusive of metallurgical coal for domestic
use and export markets, is approximately 600 million ST annually. Hence,
one implication of the projections in Table 7 is that, within the next
25 years, the syngas industry may require an increment in coal produc-
tion equal to today's level of production. For the period 1982-2000,
the growth rates projected for shale oil (Table 6) and for coal used to
make syngas (Table 7) are comparable. As projected, Lo-BTU gas has a
slightly higher growth rate than shale oil which, in turn, has a nomi-
nally higher growth rate than Hi-BTU gas. However, the rates calculated
* Actual production would be less than year-end capability since some
plants would be brought on stream during the year.
** Interrelationships between syngas and methanol are discussed in
Section 5.3. Capacity to produce 1 x 10^5 BTU/yr. of syngas is
approximately equivalent to 900 MB/D of methanol.
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APPENDIX 5
TABLE 7
PLAUSIBLE SCHEDULE FOR BUILD-UP
OF COAL SYNGAS PRODUCTION
Annual Production, TCF
Year
1978
1981
1982
1983
1984
1985
1986
1990
1995
2000
Hi-BTU
0.08
0.4
0.55
0.7
0.9
1.1
1.3
2.4
4.1
5.6
Lo-BTU (1)
—
0.2
0.25
0.4
0.6
0.8
1.1
2.3
4.2
6.0
Total
0.08
0.6
0.8
1.1
1.5
1.9
2.4
4.7
8.3
11.6
Coal
Required
Million ST(2)
37
48
62
91
115
195
235
500
700
(1) Lo-BTU gas reported in terms of Hi-BTU gas equivalency,
i.e., corrected to a heat content of 1000 BTU/CF.
(2) In terms of bituminous coal. Corresponding tonnages of
sub-bituminous coal or lignite would be higher because
of the lower BTU contents of these lower rank coals.
Tonnages may be overstated because of the lower amount
of process energy required to make Lo-BTU gas, i.e., by
not having to use energy for the methanation step re-
quired in the production of Hi-BTU gas. On the other
hand, the conversion of Lo-BTU gas to methanol does have
an energy requirement and, to the extent that the end
product is methanol rather than Lo-BTU gas, the coal
requirement on the basis of product BTU content would
approach that of Hi-BTU gas production.
EPA-460/3-74-009
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depend on the base year chosen. In general, the approach has been to
estimate the initial year of commercial production and then assume that
subsequent development would be about equally rapid for each synthetic*.
On a product heat content basis, the projections are:
1015 BTU
Year Shale Oil Coal Syngas
1985 0.9 1.9
2000 7.2 11.6
Coal Liquefaction
The technical feasibility of making petroleum-type liquids
from coal has been known for many years. However, it is only recently
that the economic feasibility of coal liquefaction in the U.S. has
begun to appear assured. The change has occurred because of very large
increases in the cost if imported petroleum followed by relatively
smaller, but still significant, increases in the average cost of domes-
tic petroleum.
Previously, many forecasts had assumed that crude oil prices
would rise, but that the rise would be gradual and, hence, the level at
which coal liquids could compete would not be reached until about 1980.
Thus, until recently, coal conversion research was concentrated more on
gasification than on liquefaction. The present situation requires con-
sideration of three factors:
(1) the marginal barrel of foreign crude oil is being
delivered to the U.S. at a price comparable to that
estimated to be required for coal liquids in order
to provide a reasonable return on investment.
(2) "Project Independence" requires the development of
adequate supplies of liquid fuels from domestic
resources.
(3) Shale oil is expected to make an important, but
insufficient**, contribution to (2), hence, coal
liquids will be required also.
* Since there is no compelling reason for any other assumption.
** Because of the absolute rate at which this resource can be
developed.
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Thus, the present situation ±a giving a higher priority to
coal liquefaction. On the other hand, the lead-time for liquefaction*
is greater than for gasification. Doubtless, major efforts will be made
to improve on the start-up date (1982) for the first coal liquids plant
predicted by Livermore. However, it seems unlikely that more than two
years could be shaved from the schedule of the first plant of commercial
size. Of course, a number of large pilot plants will be in operation
long before 1980, and it is the data from these plants that will be used
in the design of the first plants of commercial size. The inference is
that the first large coal liquids plant cannot come on stream before
1980 or 1981, but that the subsequent build-up of capacity could be
quite rapid. This reasoning leads to the schedule proposed in Table 8.
Problems and Prospects
A recent study (7) by Resources for the Future, Inc., contains
information about possible construction rates for synthetic fuels
plants. The information was obtained as follows:
"Interviews were conducted with 19 individuals or
groups representing a wide range of interests in
energy R&D. The research arms of energy trade
associations, university professors, research
directors in coal, oil, gas, and utility industries,
private consultants, and Government personnel
engaged in R&D activities were all asked the same
questions..."
Direct citations or condensations of salient points in the RFF
study are itemized below:
Assumptions
(1) "It was assumed that environmental delays would not occur...that
the Government would provide the necessary incentives...that the
plants would be standardized so that vendors could gear up to mass
produce parts...."
(2) Two conditions were assumed:
(a) "forced draft": with priorities given to equipment for
synthetic fuel plants (and other construction delayed, if
necessary)
(b) "rolling in": along with other plant construction (oil
refineries, petrochemical plants, etc.)
* Except for "solvent refined coal" (which will not be suitable as a
source of automotive fuels, and is not intended for this purpose).
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APPENDIX 5
TABLE 8
PLAUSIBLE SCHEDULE FOR BUILD-UP OF
COAL LIQUIDS PRODUCTION
Coal
Nominal Capacity, MB/D Average Production, MB/D Required
Year at Year-End During Year Million ST*
1980 50
1981 100 50 6
1982 200 100 12
1983 300 200 24
1984 400 300 36
1985 500 400 48
1990 1000 900 108
1995 1800 1600 192
2000 3000 2700 324
* In terms of bituminous coal. Corresponding tonnages
of sub-bituminous coal or lignite would be higher because
of the lower BTU contents of these lower rank coals.
EPA-460/3-74-Q09
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(3) The plants are assumed to be:
(a) coal gasification (Lurgi): 250 MM CF/D (capital cost $350-400
million)
(b) shale oil: 100 MB/D (capital cost $500 million). At 90%
operating factors, the energy output of these plants would be:
(a) coal gasification: 82 x 1012 BTU/yr.
(b) shale oil: 198 " "
i.e., the effective output of each shale oil plant would be 2.4
times the energy output of each high-BTU gas plant. (50 MB/D
shale oil plants were also referred to in the questionnaires
used for the interviews but, apparently, are translated into
100 MB/D units in the overall statistics reported)
Size of Engineering Design Industry
(4) "In 1971 design firms in the U.S. had billings of nearly $20 billion
(including foreign work). The 51 largest contractors had billings
of over $17 billion...14 had business of more than $400 million.
Therefore, there appear to be about 14 firms able to act as prime
contractors".
Manpower Limitations
(5) One firm thought: "The major constraint to the number of plants that
could be started immediately, as well as the limitation to the rate
of acceleration, was the large number of engineers needed to design
the initial plants and the very limited number of engineers available
with any skills in these new technologies".
(6) The same firm estimated that 300-400 engineers working for two years
would be needed to design each type of synthetic fuel plant (i.e.,
500,000-700,000 man-hours per plant).
(7) The same firm also thought that "construction crafts and labor
(particularly in remote locations such as where the rich oil shale
deposits are found) might also place a limitation on possible rates
of construction" both initially and subsequently. A limitation of
seven 100 MB/D shale oil plants was seen, with such plants being in
operation 6-8 years hence.
Construction Rate
(8) Lastly, the same company could undertake one $400-500 million project
now (either coal synthetic gas or shale oil) and could begin another
about 1-1/2 years later. From this the study inferred that:
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(a) if 14 contractors worked at this rate, there could be 70 plants
in 1985
(b) if all of these plants were to make (shale) liquids, their total
capacity would be 7 MM B/D.
(9) "The majority of the estimates for either high-BTU gas or oil shale
were in the range of 12 to 15 plants in operation by 1985. Some
doubt was raised that if both types of plants were to be constructed
simultaneously as many as 24 to 30 would be possible."
(10) Other companies variously estimated the 1985 plant capability as:
(a) 40 plants
(b) 35-54 plants
(c) 24-36 plants
(11) With no assignment of engineering manpower to the design of oil
refineries, petrochemical plants, LNG facilities, etc., about 29
synthetic fuel plants could be designed simultaneously.
(12) "With a level of construction of 6 plants per year to start and with
a new generation of starts being made every 1-1/2 years thereafter,
36 synthetic fuels plants could be in operation by 1985." Apparently,
the schedule would be:
Number of Plants Start On Stream
6 mid-1973 mid-1977
6 Jan. 1975 Jan. 1979
6 mid-1976 mid-1980
6 Jan. 1978 Jan. 1982
6 mid-1979 mid-1983
_6 Jan. 1981 Jan. 1985
36
(13) Based on an analogy with the construction of electric power plants,
35 synthetic fuel plants could be in operation by 1985. Another
estimate was 36 plants.
Other Limitations
(14) Each coal gasification plant requires a 6000 T/D oxygen plant:
"The entire U.S. capacity per year for constructing oxygen plants
is of about the same order."
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(15) "Synthetic fuel plants require a very large number of compressors.
There are only 3 or 4 large compressor manufacturers in the U.S. and
they are now, or soon will be, at full capacity. Apparently, they
have no plans to expand since, if they do, there is not the foundry
and forging capacity that could supply them."
Discussion of RFF Study
The assumptions that underlie long range projections are of
critical importance. Different assumptions may be made for different
purposes. The purpose here* is to assess the reasonableness of the
synthetic fuel capacity estimates cited above. Item (1) is the tip-off.
No reasonable person should assume that environmental delays will not
occur**. Next, the "forced draft" condition in item (2a) is conceptually
unsound, since there will be a need for oil refineries, petrochemical
plants, etc., as well as for synthetic fuel facilities. The plant size
assumptions in item (3) are questionable also. The first commercial shale
oil plants will have a nameplate capacity of 50 MB/D. The first coal
liquefaction plants are also likely to have capacities of 50 MB/D or
perhaps less. Hence, the assumption in item (3) that all shale oil plants
(and, by extension or implication, all synthetic liquids plants) will have
capacities of 100 MB/D is incorrect. Nor can it be considered that the
design and construction effort required for two 50 MB/D plants will be
the same as for one plant of twice this size.
Item (4) contemplates that all of the 14 largest engineering
design companies would be uniformly engaged in the design of synthetic
fuel plants. This level of concentration is unlikely with synthetic fuels,
but some specialization*** by the engineering companies is likely while
some may not enter the field at all (perhaps concentrating on oil refining
or petrochemicals and on foreign business). A high degree of standard-
ization is improbable in the early stages of the industry. In fact,
full-scale evaluation of alternative processes may be encouraged by the
Government. Moreover, most of the companies for whom the plants are
built will want a variety of special features incorporated into their own
plants.
* RTF's purpose was quite different. Hence, the discussion here is not
a criticism of RFF's study but, rather, a reinterpretation of the
study's findings based on a critical review of the assumptions.
** Such an assumption is tantamount to assuming either that
environmental problems do not exist or that such problems can
be ignored.
*** e.g., some concentrating more on coal gasification than on oil
shale processing, etc.
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Manpower limitations are discussed in items (5)-(7). The last
of these items also refers to a maximum shale oil capacity of 700 MB/D.
The explanation is:
"...rich oil shale resources that are found in a limited geographic
area will be limited for physical reasons relating to difficulty of
plant location, potential environmental pollution problems, and
water availability to a possible maximum of seven 100,000 barrels
per day plants. Thus the constraint on oil shale will be in total
production until these limitations are somehow removed."
Item (8) indulges in the fantasy that 7 MM B/D of synthetic fuel
capacity could be in operation in 1985. This "estimate" was picked up by
the press, and may have aroused unrealistic expectations in the minds of
the public as well as unnecessary apprehension by environmentalists.
Items (9) and (10) are straightforward. Item (11) involves a
concept that has been objected to while discussing item (2). Many of the
companies who may wish to build synthetic fuel plants are involved with
oil refining, petrochemicals, etc. Hence, it is unrealistic to suppose
that these companies would abandon all construction except that of synthetic
fuel plants.
Regarding item (12), it is apparent that construction of 6
synthetic fuel plants did not start in mid-1973 or even in mid-1974.
Hence, there has already been a slippage of over a year in item (12)'s
schedule. However, work on 2 coal gasification plants has begun. Hence,
the schedule could be revised to a maximum 32 plants in 1985. However,
a number of the synthetic liquids plants will be smaller than the 100
MB/D unit considered in the study. Thus, as a first approximation, the
8 "small" plants listed below may be taken as equivalent to 4 x 100 MB/D
synthetic liquids plants, such that the 36 actual plants would be roughly
equivalent to 32 units as estimated in the study. On this basis, a break-
down of the 1985 capacity might be:
Type
Hi-BTU coal syn.
Lo-BTU coal syn.
Coal liquids
Coal liquids
Shale oil
Shale oil
gas
gas
Number of
Plants
13
10
2
2
6
JJ
36 (32)
Unit
Capacity
250 MMCF/D
250 MMCF/D*
50 MB/D
100 MB/D
50 MB/D
100 MB/D
Total Capacity
3.25 billion CF/D
2.50 billion CF/D*
100 MB/D
200 MB/D
300 MB/D
300 MB/D
* In terms of Hi-BTU gas, equivalent to 1000 BTU/CF.
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From the above it is possible to estimate the volume of
synthetic fuels that might be produced in -1985. This calculation requires
several manipulations:
(a) application of an operating factor in order to convert
from nameplate capacity to a daily average production rate
(NPC suggests a factor of 90%).
(b) consideration that some of the plants would probably be
starting up in 1985 and, hence, would not be operating
for the full year of 1985.
(c) conversion of all of the estimated production to a common
basis (for illustrative purposes taken as 6 MM BTU/bbl.).
Type
Coal syn. gas
Coal syn. gas(b)
Coal liquids
Coal liquids(b)
Shale oil
Shale oil(b)
No. of
Plants
19
4
3
1
8
_J^
36
1985 Production
1985 Avg. Production
Converted to MB/D
19 x 250 x 365 x 0.9 MMCF
4 x 250 x 365 x 0.45 MMCF
4 x 50 x 365 x 0.9 MB
1 x 100 x 365 x 0.45 MB
10 x 50 x 365 x 0.9 MB
1 x 100 x 365 x 0.45 MB
1505
Thus, on the above basis, aggregate synthetic fuel production
in 1985 would average 1.5 MM B/D O.E. If all of the plants denoted (b)
in the above tabulation were fully operational throughout 1985, instead
of some being assumed to come on stream during 1985, aggregate production
would increase to 1.65 MM B/D O.K.*. If one year could be cut from the
plant construction schedules between now and 1985, total production in
that year could be about 30% higher, i.e., in the range of 2.0 - 2.1
MM B/D O.E. This level may be regarded as a maximum.
Item (13) is consistent with the estimates given above, i.e.,
a reasonable chance of producing an average of 1.5 - 1.6 MM B/D O.E. in
1985 and a slight possibility of reaching 2.0 - 2.1 MM B/D O.E. These
levels, however, depend on assumptions that environmental and institutional
barriers to synthetic fuels production are progressively removed. This is
not the same as assuming that no environmental delays will occur, but
rather that the delays will be reduced and no absolute roadblocks will be
experienced. Without a generally favorable climate, maintained without
interruption during the next decade, synthetic fuel production in 1985
will be substantially less than an aggregate of 1.5 MM B/D O.E.
* This figure exactly matches the projected total of synthetic fuels
production given earlier in Table 1, although the "mix" of the
various synthetic fuel plants is slightly different.
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Finally, items (14) and (15) are noted as examples of obstacles
that still have to be overcome. Doubtless-, these difficulties will be
surmounted if the business climate is favorable and remains so. Without
this condition, it is clear that equipment as well as manpower could
bottleneck the build-up of synthetic fuel capacity. A favorable business
climate will also be essential to attract enough capital into a new
industry that is extremely capital-intensive as well as being "high
risk." The potential reward may be enough for the initial investments,
but there will have to be a reasonable level of actual reward if the
investment momentum is to be sustained.
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APPENDIX 5
REFERENCES
(1) "The Challenge of Resolving the Energy Shortage," K. M. Elliott,
Mobil Research and Development Corporation; presented at the Oil
Daily Forum on 9/25/73.
(2) "Certain Background Information for Consideration when Evaluating
the National Energy Dilemma," by staff of JCAE, 5/4/73.
(3) "Energy: Uses, Sources, and Issues," Lawrence Livermore Laboratory,
UCRL-51221, 5/30/72.
(4) Private communication of 10/16/73 from H. R. Warman to L. G. Cook
(Exxon Research and Engineering Co.) transmitting published paper on
the future avilability of oil. See also Geophysical Journal, Vol.
138, Part 3, 1972, pp. 287-297.
(5) Lawrence Livermore Laboratory estimates cited in Business Week,
12/1/73.
(6) Cited by Electrical World, 11/15/73, page 47.
(7) "Energy Research and Development - Problems and Prospects," prepared
at the request of Senator Henry Jackson (Chairman, Senate Committee
on Interior and Insular Affairs) as a contracted study by Resources
for the Future under the direction of Harry Perry; published as
Senate Document No. 93-21.
(8) "Final Environmental Impact Statement for the Prototype Oil Shale
Leasing Program," Vol. 1, U.S. Dept. of Interior, 1973.
(9) Nature, Vol. 246, 12/7/73, pp. 323-324.
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APPENDIX 6
SIGNIFICANCE OF FUEL PROPERTIES
Volatility
Datermines the ease with which a fuel can be vaporized. In car-
buretted engines, it controls ease of starting, warm-up, and
acceleration. A final boiling point above about 400°F. may result
in excessive crackcase dilution and/or engine deposits. Exces-
sively high volatility can give rise to vapor lock problems and/or
carburetor icing.
In fuel-injected engines (e.g., diesel, gas turbine) appreciably
lower volatility (i.e., higher boiling point) can be tolerated.
However, final boiling points above about 650°F. may not burn
cleanly, particularly in high speed reciprocating piston engines
where burning time is short. The time available for burning is a
function of engine speed in reciprocating piston engines and of
combustor size and air rate in engines using steady state combus-
tion (e.g., gas turbine).
Vapor Pressure
Another measure of fuel volatility. With carburetted engines, in-
creasing vapor pressure improves ease of starting, but enhances
dangers of vapor lock and carburetor icing.
Heat of Vaporization
A measure of the energy required to convert a unit weight of fuel
from a liquid to a vapor.
In carburetted engines, the higher the heat of vaporization, the
lower will be the temperature of the fuel-air mixture in the in-
take manifold, the greater weight of fuel (and air) inducted into
the combustion chamber, resulting in more power per cycle. How-
ever, if the fuel-air mixture temperature becomes too low, a
heterogeneous fuel-air mixture may result, causing poor engine
operation. In this case, heat must be added to the intake mani-
fold to vaporize the fuel.
In the case of cryogenic liquids, it also represents the amount
of heat that must be added to fuel storage to provide fuel vapor
for the engine.
Heat of Combustion (Net)
The amount of heat produced by burning a unit amount of fuel in
air under stoichiometric conditions to gaseous products. The
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lower the heat of combustion, the more fuel that must be carried
aboard a vehicle to provide a given level of energy storage.
BTU/ft
The amount of heat that will be generated by burning 1 cubic foot
of a stoichiometric mixture of air and fuel. Everything else
being equal, the higher this figure, the more power will be gen-
erated by a carburetted reciprocating engine of given displacement.
Octane Number
Measures the resistance of the fuel to detonation in an Otto cycle
engina. As octane number of a fuel is increased, the allowable
engine compression ratio increases. Thus, high octane fuels are
capable of increased miles/gal., since engine thermal efficiency
increases with an increase in compression ratio.
Research octane number measures knock resistance under less severe
conditions than the Motor Octane Number. Heretofore, the road
anti-knock performance of a gasoline could be correlated best with
an average of the Research and Motor Octane Numbers. 1973 model
U.S. cars now correlate best with Motor Octane Number.
Octane Number has no significance with regard to fuel performance
in an engine using steady-state combustion (e.g., gas turbine).
There is a rough inverse relationship between Octane Number and
Cetane Number, which makes high octane fuels miserable fuels for
compression ignition engines.
Cetane Number
The higher the Cetane Number, the less the ignition delay in a
compression ignition engine. Currently, #2 diesel fuels in the
U.S. average 48 Cetane Number. A minimum Cetane Number of 40 is
allowed by some diesel engine manufacturers. Lower Cetane Numbers
may be used in heavy, slow-speed engines, particularly if auxiliary
means of ignition is employed (e.g., spark or glow plug, or pilot
fuel injection). It will be noted that spontaneous ignition tem-
perature tends to decrease as Cetane Number increases.
Cetane Number has no significance regarding fuel performance in a
continuous combustion engine.
Flame Speed
Current engines have been optimized to operate best with a hydro-
carbon fuel (flame speed 1.1 ft/sec). Wide variations in flame
speed from this level would probably require that engine operation
be modified for best results. For example, the high flame speed
of hydrogen and the slow speed of ammonia suggest that expedients
- 92 -
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must probably be used with these fuels for best operation in
reciprocating engines. In continuous combustion engines, combus-
tor residence time (e.g., combustor size) for the fuel air mixture
must be increased as flame speed decreases to ensure complete com-
bustion.
Flammability Limits
Represent the range in fuel-air mixtures that will support a flame.
In general, wide limits are an advantage in engine operation, since
the probability of misfire due to engine variability and hetero-
geneity of the fuel-air mixture is reduced. It will also allow
greater flexibility in design of continuous combustors.
Kinematic Viscosity @ 77°F
This property is primarily of concern where fuel injection and
atomization is used to introduce the fuel into the combustion
space. For pressure injection, the degree of atomization becomes
poorer as viscosity increases. It is of particular concern in
diesel engines where the degree of spray penetration is important.
Kinematic Viscosity at 0°F
This property is important in giving guidance as to low temperature
handling properties. Pumping difficulties increase as viscosity
increases.
Density
The density of the liquid is of concern with regard to the size of
storage vessels and lines in terminals, service stations, and
vehicles. In general, the less dense fuel will require a greater
storage volume for a given energy supply, unless the heat content
(BTU/lb) compensates for the density difference.
Density is also of importance in fuel systems where the fuel is
metered by volume (e.g., in diesel fuel injectors). In such a
system, the more dense fuel will be supplied at a higher mass
rate, which will influence fuel/air ratios, and power at a given
injector setting.
Freezing Point (Pour Point)
Represents the temperature below which the fuel becomes solid and
cannot be pumped. This limits the minimum temperature at which
the oil can be handled either at the terminal or aboard a vehicle.
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Flash Point
The temperature at which the bulk liquid can be ignited by an open
flame. Fire hazard increases as flash point decreases.
Solubility in Water
All current petroleum fuels are exposed to contact with consider-
able water in storage and handling, unless special, expensive pre-
cautions are taken. Fuel losses to the water phase are thus
possible if fuel solubility in water is appreciable.
Solubility for Water
In view of the fact that it is difficult to avoid contact of fuel
with water in the normal commercial storage and handling system,
commercial fuels have ample opportunity to pick up water. The
water can be precipitated when the fuel is cooled. Thus, water
can be deposited in sensitive areas of the fuel system (filters,
nozzles, controls). This problem would be expected to become more
severe as the solubility of water in the fuel increases.
Emulsion Tendency
This is the tendency for a fuel to form an emulsion when agitated
with water. The greater this tendency, the greater the probability
that emulsified water picked up in the fuel transportation and
storage system will be carried from the storage tanks, through the
fuel system, and, eventually, to the engine where it can cause
engine malfunction by interfering with the smooth flow of fuel to
the engine. The trouble in the engine may be caused by the poor
flow characteristics of the emulsion itself, by deposit of water
when the emulsion breaks, by corrosive salts dissolved in the
water (e.g., sea water) or by dirt and rust suspended in the emul-
sion. Thus, a fuel with low tendency to emulsify or in which the
emulsion breaks and settles rapidly is much easier to deliver clean
to the engine than a fuel that emulsifies easily.
Storage Stability
In the present fuel distribution system it is possible that six
months or more may elapse between the time a fuel is produced at a
refinery until it is burned in an engine. Thus, it is important
that a fuel have the ability to retain its desirable characteristics
and not degrade in storage over this period. Storage instability
may take a number of forms, e.g., loss of volatile fuel components,
formation of gum or sediment, change in color, etc.
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Static Charge
A static electric charge can be accumulated on a liquid of low
electric conductivity (e.g., a petroleum fuel) when it is moved at
high velocity through pipes, filters, etc. Under proper conditions
the electric charge will discharge to a conductor of lower poten-
tial (e.g., a grounded tank wall) in the form of a spark capable of
igniting a combustible mixture of fuel vapor and air. Thus the
tendency to develop a static charge (which is roughly an inverse
function of its electrical conductivity) is of interest as one
source of fire hazard in the handling of fuels.
Toxicity
the toxicity of a fuel is of great concern and determines the pre-
cautions that must be taken in its safe handling and use. Three
main types of toxicity are of interest: vapor inhalation, inges-
tion and skin contact. Vapor toxicity determines the care that
must be taken to avoid breathing the fumes. Ingestion indicates
the hazard in case of accidental swallowing of the vapor or liquid.
Skin toxicity represents the hazard connected with fuel coming in
contact with skin.
Lubricity
Lubricity is the ability of a fuel to lubricate the equipment
through which it flows. It is proportional to viscosity. The
lubricity of the fuel can have an important effect on the type of
pump used in handling. With some pumps a fuel of poor lubricity
can cause excessive wear (e.g., using a diesel fuel having an un-
desirably low viscosity). Accordingly, care must be used in cor-
rectly matching fu'el and pump. In some cases, poor lubricity may
be corrected by means of a fuel additive.
Corrosivity
A reaction (chemical, dissolution, etc.) between a fuel and the
materials of the fuel system in which it is used is, of course,
undesirable. It may cause engine malfunction due to formation of
fuel leaks, distortion of fuel system components, development of
undesirable deposits in sensitive areas, staining and coating of
finely finished surfaces in controls, pumps, etc. Thus it is im-
portant that a fuel be compatible with the fuel system in which it
is used. The degree of compatibility must be high since the ex-
pected service life is long (10+ yrs.) and relative small changes
in sensitive parts (e.g., in; metering devices) can be very trouble-
some .
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Effect on Plastics
In most engine fuel systems, plastic parts may be found perhaps as
lines, diaphrams, gaskets, control parts, etc. It is important
that the fuel be compatible with such materials and not cause them
to lose strength, swell or otherwise deteriorate.
- 96 -
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APPENDIX 7
BASES FOR CAPITAL RECOVERY
20 year project life
16 year depreciation
Investment Schedule
Year-2 15%
Year-1 45%
Year 0 30%
Year 1 10%
Working capital - 45 days product inventory, 30 days raw materials
Startup expense 5% on investment
Working capital expensed in year 0 and recovered in year 20
Startup expense as follows: 2% in year -1, 90% in year 0, 8% in year 1
Production Schedule
Year 1 50%
Year 2 87.5%
Years 3-20 100%
Income tax rate - 50%
Definition of Investors Rate
of Return (Discounted Cash Flow Return)
Investors rate of return is the maximum interest rate which
can be paid on money borrowed to finance a project when the project is
the only source of income to the investor.
- 97 -
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VD
00
APPENDIX 7
TABLE 1
SAMPLE DCF CALCULATION(l) - 100 MM$ INVESTMENT, 10% NET RETURN.
Year
End
-2
-1
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Totals
(A)
Revenue
Minus Cost
(100) (2)
(4,500) (2)
10,350 (2)
18,800
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
21,500
(B)
Depreciation
„
-
-
11,800
11,000
10,300
9,600
8,800
8,100
7,400
6,600
5,900
5,100
4,400
3,700
2,900
2,200
1,500
700
0
0
0
0
100,000
(C)
Taxable
Income
(A)-(B)
(100)
(4,500)
(1,450)
7,800
11,200
11,900
12,700
13,400
14,100
14,900
15,600
16,400
17,100
17,800
18,600
19,300
20,000
20,800
21,500
21,500
21,500
21,500
(D) (E) (F)
Net A/T
Income Working
(A)-50%(C) Investment Capital
15,000
(50) 45,000
(2,250) 30,000 7,400
11,100 10,000
14,900
15,900
15,500
15,100
14,800
14,500
14,100
13,700
13,300
12,900
12,600
12,200
11,800
11,500
11,100
10,800
10,700
10,800
10,700 (7,400)
100,000 0
(G)
Cash Flow
(D)- (E)-(F)
(15,000)
(45,000)
(39,600)
1,100
14,900
15,900
15,500
15,100
14,800
14,500
14,100
13,700
13,300
12,900
12,600
12,200
11,800
11,500
11,100
10,800
10, 700
10,800
18,100
(H)
Discount
Factor
1.21
1.10
1.0
0.909
0.826
0.751
0.683
0.621
0.564
0.513
0.467
0.424
0.386
0.350
0.319
0.290
0.263
0.239
0.218
0.198
O.'ISO
0.164
0.149
(D
Discounted
Cash Flow
(G)x(H)
(18,150)
(49,500)
(39,600)
1,000
12,300
11,900
10,600
9,400
8,300
7,440
6,600
5,810
5,130 v
4.520 '
4,020
3,540
3,100
2,750'
2,420
2,140
1,930
1,776
2,700
120
Notes:
(1) Units - thousand dollars/year.
(2) Includes startup costs: Year 1 100 M$
0 4500
+1 400
Total 5000
(3) Assumed to be 7.4% of investment.
EPA-460/3-74-009
-------
APPENDIX 7
TABLE
2
EFFECT OF VARIOUS FACTORS ON CAPITAL RECOVERY
Case
Project Life, Years
Depreciation Period, Years
Depreciation Type*
Working Capital, % on Inv.
Startup Cost, % on Inv.
Production Rate, %
Year 1
Year 2
Year 3 to End
Investment Schedule
% in Year
-2
-1
0
+1
A
16
16
SL
0
0
100
100
100
0
0
100
0
B
16
16
SYD
0
0
100
100
100
0
0
100
0
C
20
16
SYD
0
0
100
100
100
0
0
100
0
D
20
16
SYD
0
0
100
100
100
15
45
30
10
E
20
16
SYD
7.5
0
100
100
100
15
45
30
10
F
20
16
SYD
7.5
5
50
87.5
100
15
45
30
10
Capital Recovery Factor 0.193 0.179 0.164 0.181 0.196 0.215
* Code: SL - Straight Line Depreciation
SYD - Sum of Yearly Digits
SL: Annual Cost
Depreciation Life
SYD: Annual Cost = .• 0 . „ . for Year 1
J.TZTJT ... n
11-1 for Year 2
3+ ... n
t0 1+2+ 3+ ... n f°r Year n
EPA-460/3-74-009
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Investment Buildup
(1) Direct M&L (Materials & Labor)
Onsites
Offsites
(2) Field Labor Overhead and Burden
(3) Engineers and Contractors Fees
(4) Project Contingency - 15% of (1-3) + process contingency when
processing not well defined
(5) Escalation: Cost increase due to inflation: not considered when
economics are calculated on basis of constant dollars
TOTAL INVESTMENT: 1-5
Operating Costs
(1) Capital Charges (see information on Capital Recovery)
(2) Repair Material - 2-5% of investment
(3) Supplies, Taxes, etc. - 4% of investment
(4) Manning @ $ X /men/yr.
(5) Utilities ~\
(6) Fuels
I.
(7) Catalyst ^ other items included in operating costs
i
(8) Chemicals I
(9) Licenses )
TOTAL OPERATING COSTS: 1-9
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Bases for Economic Calculations
for Shale Syncrude
3 Year Construction Period
20 Year Operating Period
10 Year Life on Mining Investment - Initial and Deferred
10 Year Life on Crushing Investment - Initial and Deferred
10 Year Life on Ash Disposal Investment - Initial and Deferred
20 Year Life on Retort Investment - 16 Yr. Depreciation
20 Year Life on Water Investment - 16 Yr. Depreciation
Initial Capital Distribution (percentages)
Yr. -2 -1 0 +1
Mining 20 30 50
Water Supply 50 50
Retorting 10 45 45
Refining 10 45 45
Working 50 50
Preproduction Expense
Start-up 65 35
Mine Development 50 50
Management 33 33 34
2% Salvage Value on Investment
Working Capital Recovered in
20th Year
Royalty on 35 gpt shale 170/ton included in mining operating cost
No tax on preferences included
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APPENDIX 8
REFINING OF SHALE AND COAL SYNCRUDE
A study was carried out on the economics of refining shale and
coal syncrude to give gasoline and distillate products. The properties
of the syncrude are given in the attached Table 1, which recaps informa-
tion given in Sections 5.1 and 5.2. A number of comments should be made
about the properties of these syncrudes, which affect the refining
sequence:
1. Neither syncrude contains any "bottoms" (material boiling
above 850-950°F) so that there is no need to provide for bottoms conver-
sion processes.
2. Both syncrudes are very low in sulfur and nitrogen, which
reduces the requirements for subsequent hydrotreating.
3. Shale syncrude has a higher H/C ratio than coal syncrude.
Therefore, it requires less hydrogen in the refining step. The higher
H/C ratio also is reflected in the lighter yield structure of shale
syncrude.
4. The higher aromatics content of coal vs. shale syncrude
suggest the use of hydrocracking rather than catalytic cracking in the
conversion step.
Study Bases
The following bases were used:
1. 100 MB/SD refinery, located on the U.S. Gulf Coast.
2. Refinery produces automotive gasoline (mogas) and
distillate.
3. Where no other information was available, it was assumed
that the syncrudes can be processed similarly to petro-
leum crudes .
4. Information on coal syncrude refining was based on the
study done by Hydrocarbon Research, Inc. for the office
of Coal Research. (1)(2)
5. Information on shale syncrude refining was based both on
the literature (3) and on the contractor's experience in
petroleum refining.
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6. All other bases were the same as those used throughout
the study, e.g., 10% DCF, 1973 $, etc.
Description of Cases
The processing scheme for refining coal syncrude to gasoline
and distillate is shown on Figure 1 (Case 1). The syncrude is received
via pipeline into crude storage. It is then fractionated in an atmos-
pheric pipestall (APS) and crude light ends unit. The light naphtha is
blended directly into the mogas pool without further treatment. The
heavy naphtha is hydrotreated and fed to the reformer.
The middle distillate sidestream is hydrotreated at severe
conditions. Part of the hydrotreated distillate is taken off as dis-
tillate product. The remaining portion is hydrocracked to naphtha.
This naphtha is then reformed along with the heavy naphtha from the
naphtha hydrotreater and the entire reformate stream is blended into
mogas. The butanes and light naphtha made in the hydrocracking and
reforming processes are blended directly into the mogas pool.
A small stream of bottoms taken off the pipestill is referred
to as furnace oil. For the purposes of this study, this furnace oil is
assumed to be a product. However, it can also be used as refinery fuel,
as can the refinery gases which are made in the processes. Both refinery
gases and furnace oil are assumed as products in order to keep the
refinery fuel basis consistent from case to case. The basis used was
to purchase all the refinery fuel required at the cost of syncrude.
This is dealt with in more detail in the discussion of operating
costs.
The hydrogen for the hydrotreating and hydrocracking is sup-
plied by the reformer and from the steam reforming of naphtha. Both
sulfur and ammonia are recovered as byproducts in this process scheme.
The case for making all mogas from coal syncrude is shown on
Figure 2 (Case 2). In this case, all of the middle distillate is hydro-
cracked to naphtha and reformed. Aside from unit size differences,
there are no basic process differences between Cases 1 and 2.
The processing scheme for the base case for refining shale
syncrude to mogas and distillate is shown on Figure 3 (Case 3). As
in the coal refinery, the syncrude is received via pipeline into crude
storage. It is then fractionated in an APS and light ends unit. The
shale syncrude, unlike the coal syncrude, contains butanes. These are
blended directly into the mogas pool, with the excess being sent to
refinery gases. The amount of butanes in the mogas pool is set by the
Reid Vapor Pressure specification. The light naphtha from the pipestill
- 103 -
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is blended directly into the mogas pool. . The heavy naphtha is hydro-
treated and reformed to increase its octane. The 375/430°F cut is
blended directly into the mogas pool.
The 430/550°F cut taken off the APS is sent directly to
distillate product storage. The 550+°F stream from the pipestill is
hydrocracked to naphtha. The heavy naphtha made in the hydrocracker is
reformed along with the heavy naphtha from the hydrotreater in a cyclic
reformer. The reformate is blended into the mogas pool. The butanes
and light naphtha made in the hydrocracking and reforming steps are sent
to refinery gases and blended into the mogas pool respectively.
The hydrogen for the hydrotreating and hydrocracking is sup-
plied from the reformer. To achieve the necessary hydrogen purity, a
cryogenic hydrogen recovery unit is needed.
The shale case making all mogas is shown on Figure 4 (Case 4).
In this case, all of the 430+°F material is hydrocracked to naphtha
and reformed to make mogas. Since more high octane reformate is being
blended into mogas, a semi-regenerative reformer can be used rather
than a cyclic unit as in Case 3. However, the hydrogen requirements
are not met by the reformer gases, so a hydrogen plant is needed. As
with the coal cases, the hydrogen is produced by the steam reforming of
naphtha.
An alternative to Case 4 replaces the hydrocracker with a
catalytic cracker. This is shown in Figure 5 (Case 5). To meet
octane specs, a cyclic reformer is needed, as well as an alkylation
plant and a polymerization plant. The effects of these changes relative
to the base case are discussed below.
Product Yields and Qualities
The product slates for the four base cases mentioned above
are shown below.
Coal Shale
Case 1 2 _3 _4
Mogas
MB/SO 66.1 101.3 66.9 93.7
RON Clear
RVP, psi
Distillate
MB/SD 33.3 -- 27.5
Cetane Index* 35-38 -- 49
* Cetane Index: calculated from a correlation of "API gravity
and mid-boiling point, based on many petroleum fractions;
correlates well with cetane number as determined in single-
cylinder engines.
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Since the shale syncrude has a lighter yield structure, and includes
butanes, it tends to produce less liquid product per barrel of syncrude
than coal. Therefore, while more gaseous products are made, the lighter
yield structure requires less conversion to make the mogas product. In
addition, since the butanes require no additional processing to be
blended into mogas, the average cost of refining per barrel is lowered.
The gasoline octane and Reid vapor pressure specification were
set at a minimum of 91 RON Clear and a maximum of 10.5 psi, respectively.
Actual performance characteristics of these gasolines would have to be
established to set product quality requirements.
The Cetane Index of the coal distillate is too low for use as
an automotive diesel fuel, whereas the shale distillate has an accept-
able Cetane Index. As discussed in Section 6, there are a number of
options for dealing with this situation (assuming that engine tests on
coal distillates confirm the Cetane Index prediction):
(1) hydrogenation (or hydrocracking) to increase cetane
number: this is fairly expensive (ca. $3/Bbl or $0.50/MMBTU) and
results in a loss of distillate yield. It is the least desirable
alternative.
(2) use of cetane improvers such as amyl nitrate: a question
of economics.
(3) blending of coal distillate with shale or petroleum frac-
tions to achieve higher cetane number: the most desirable alternative.
More generally, the coal distillate is expected to be quite
satisfactory for uses other than diesel fuel.
Investments
As mentioned previously, all investments presented in this
study are for a 1973, U.S. Gulf Coast location. The refineries were
sized for 100 MB/SD of syncrude feed.
The investments for the four base cases are shown as follows:
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MM$ (1973)
Coal Shale
Case: 1 2 3 4
Onsites
APS + Light Ends 11.0 11.1 11.7 11.7
Hydrocracker 32.3 47.0 19.2 33.6
Naphtha Treating & Reforming 22.3 29.2 22.9 22.3
Hydrogen Plant 42.0 52.1 .6.0 22.1
Sulfur + Ammonia Recovery 2.0 2.0
• Onsites Total 109.6 141.4 59.8 89.7
Offsites
Utilities 30.1 37.9 23.5 29.4
Tankage 14.7 15.1 14.7 15.2
Offsites 37.7 41.0 34.5 37.7
• Offsites Total 82.5 94.0 72.7 82.3
• Total Investment 192.1 235.4 132.5 172.0
A complete breakdown of the investments is given in Table 2.
The utilities were based on information from the previously
mentioned reference studies. The unit investments were developed using
historical data and Company experience in this area. Contingencies and
allowances have been added as is usual in estimates of this type for
petroleum refineries. The utilities investments cover steam generation,
power distribution, cooling water system, and the miscellaneous utilities
associated with a refinery.
The offsites facilities were developed based on historical
experience with petroleum refining. The offsites were based on a pipe-
line refinery where the syncrude is fed to the refinery via pipeline
and the products are removed from the refinery via pipeline. Therefore,
no marine or truck facilities are needed for crude or product loading.
Included in the offsites is the site preparation needed based on a flat,
dry site. Difficult sites that require extensive preparation would cost
significantly more. Also, this cost does not include the cost of the
land for the refinery.
The waste treatment facilities are for a refinery located in
a "restrictive area" typical of the U.S., Japan and most of Europe.
Areas with more stringent requirements will also add to the investments
shown. The general offsites include safety facilities, fire protection,
chemicals handling, buildings, and other miscellaneous facilities
typical of a petroleum refinery. The tankage investment includes the
cost of ten days crude tankage, any necessary intermediate tankage, and
thirty-five days product tankage.
- 106 -
-------
Annual Costs
The annual costs for the four base cases are shown below and
are given in detail in Table 3.
MM$/Yr. (1973)
Coal
Shale
Case:
Catalyst + Chemicals
Electric Power
(Fixed costs @ 0.7 C/KWH)
Investment Related
Return on Investment
• Cost of Refining, ex Fuel
MM$/Yr.
$/Bbl Syncrude
Refinery Fuel
Fuel for Electric Power
(@ 104 BTU/KWH elec.)
H2 Plant Feed & Fuel
MM$/Yr.
$/Bbl Syncrude
• Total Cost of Refining
MM$/Yr.
$/Bbl Syncrude
1
4.0
4.1
16.5
41.3
65.9
2.0
20.6
7.8
20.6
49.0
1.5
114.9
3.5
2
6.4
4.8
20.2
50.6
82.0
2.5
30.6
9.0
29.6
69.2
2.1
151.2
4.6
3.7
2.9
6.4
4.1
46.2
1.4
16.4
5.6
68.2
2.1
62.3
1.9
24.0
7.7
10.8
42.5
1.3
104.8
3.2
The catalyst and chemicals costs were estimated from the studies men-
tioned, and adjusted to reflect 1973 costs. The annual cost for pur-
chased electric power was split into fixed costs, at 0.7C/KWH, and fuel
costs, at 10,000 BTU/KWH. The electric loads were estimated from the
studies. Investment related costs, which include supplies, manning,
taxes and repair material, were estimated as 8.67» of investment per
year based on historical experience. Return on investment is based on
a 107» DCF return assuming a project life of 20 years with 16 years sum
of the years' digits depreciation schedule. A 50% combined federal and
state tax rate was also assumed. A sensitivity to rate of return is
discussed in a subsequent section.
Refinery fuel includes fuels for process use as well as that
required for steam generation. The process fuel requirement was deter-
mined from the original studies. Fuel for steam generation was esti-
mated from the steam load using 0.2 FOEB* per thousand pounds of steam
* Fuel oil equivalent barrels: 6.05 MMBTU lower heating value.
- 107 -
-------
generated as the conversion factor. The fuel cost for purchased electric
power was separated from the fixed costs-because electric power is a
major cost, which is extremely sensitive to fuel value. The feed and
fuel for the hydrogen plant is purchased.
The cost of fuel for the above requirements was assumed to be
8$/Bbl for all of the cases. This is the approximate value for coal
syncrude. A sensitivity to fuel value was also developed since fuel is
a major component in the overall refining cost. This sensitivity is
discussed in the following section. In addition, no premium over refinery
fuel was assumed for the cost of the naphtha feed and fuel to the hydro-
gen plant. Any premium would substantially increase the cost of refining
coal syncrude relative to the cost of refining shale syncrude.
For consistency, no fuel credit was taken for refinery gases
or furnace oil produced in any of the cases. All refinery fuel was
purchased and refinery gas and furnace oil considered product. While
these streams might be burned as refinery fuel in actual operation, the
decrease in product volume would have to be compensated for by an in-
crease in syncrude throughput. By tying the refinery fuel cost to syn-
crude cost, this interaction is accounted for without any undue bias
for any one case.
Sensitivities
In order to reflect the possibility of bases different than
those used in this study, sensitivities were developed on critical
items. The first sensitivity reflects the utilization of catalytic
cracking instead of hydrocracking when refining shale syncrude. The
running plan for this process sequence is shown on Figure 5. The
cost of refining for this case is 2.50$/Bbl, which is 0.70$/Bbl less
than the cost of the comparable hydrocracking case making all mogas
(Case 4) .
The primary area of economy of catalytic cracking versus
hydrocracking is in fuel requirements. The refinery fuel requirement
is substantially lower because the catalytic cracker requires little
imported fuel, exports steam from the CO boiler, and requires a smaller
catalytic reformer. In addition, the catalytic cracking case doesn't
require hydrogen. This results in the complete savings of the cost of
purchased naphtha. There is also a slight savings in overall invest-
ment, in part due to the elimination of the hydrogen plant.
One offsetting debit for catalytic cracking is the need to
purchase butanes to meet the RVP specification in the mogas pool.
Another debit, which is not really reflected in an analysis of this
type, is the yield loss associated with catalytic cracking. Although
catalytic cracking does require less "imported" fuel, the heat required
in the cracker is supplied by burning carbon deposited on the catalyst.
This results in less product make as can be seen from Figures 4 and 5.
The absolute delta for catalytic cracking would depend on the product
- 108 -
-------
pricing structure as well as the value of refinery fuel. Since, for
the purposes of this study, the syncrude -feed was held constant, the
effect of the yield differences was not accounted for. It should be
noted, however, that this yield loss could possibly offset the process-
ing cost advantage that is shown for catalytic cracking.
A cat cracking alternative was not developed for coal syncrude
since it seems that the high polyaromatic content would necessitate the
use of hydrocracking as the conversion process.
A second sensitivity was developed to reflect the possible
variation in fuel price. It was assumed that fuel price would be
directly related to syncrude price. This is realistic in that any
product being burned as refinery fuel is in effect being purchased at
syncrude prices. Therefore, to reflect the uncertainty in syncrude
prices, and thus the uncertainty in fuel price, a change in fuel price
of 2$/Bbl was examined. The effect of this change on overall costs
ranges from 20-40 e/Bbl for shale to 40-60 c/Bbl for coal.
The third sensitivity reflects the possible differences in
financial criteria expressed as rate of return on investment. The cost
of refining was developed for 5, 10, and 15% DCF rates of return, with
107o being the base case.
The detailed breakdown of the investments and annual costs
for the base cases and the sensitivities to the base cases can be found
in Tables 2 and 3.
- 109 -
-------
APPENDIX 8
TABLE 1
Whole Crude
Gravity, °API
Sulfur, Wt. 7,
Nitrogen, Wt. %
C/H Ratio, Wt. %
Butanes, LV %
Naphtha, Cut °FVT
Yield, LV 7»
Gravity, "API
Sulfur, Wt. 7o
Nitrogen, Wt. %
Aromatics, LV °L
Naphthenes, LV 7»
Paraffins, LV %
Middle Distillate, Cut °FVT
Yield, LV %
Gravity, °API
Sulfur, Wt. 7»
Nitrogen, Wt. %
Heavy Distillate, Cut °FVT
Yield, LV %
Gravity, "API
Sulfur, Wt. 7o
Nitrogen, Wt. %
Res id, °FVT
Yield, LV °L
Sulfur, Wt. 7»
Nitrogen, Wt. 7,
Coal Syncrude
32.4
0.1
0.1
—7.3-8.5
975+
Shale Syncrude
34
0.005
0.035
'6.2-6.4
9.0
C5/375
40.0
53.0
0.1
0.1
--
--
--
375/650
54.2
23.2
0.1
0.1
650/975
5.8
3.5
0.3
0.1
C5/350
27.5
54.5
<<0.0001
0.0001
18
37
45
350/550
41.0
38.3
0.0008
0.0075
550/850
22.5
33.1
<0.01
0.12
850+
means data not applicable.
Data previously cited in Section 5.1.
EPA-460/3 -74-009
- 110 -
-------
APPENDIX 8
TABLE 2
ALTERNATIVE FUELS STUDY
REFINING SYNCRUDE
INVESTMENT SUMMARY (1973$, BAYTOWN)
• ONSITES
+ APS + Light Ends
+ Hydrocracker (R1+R2)
+ Cat Cracker
Polymerization
Alkylatlon
+ Naphtha Treat + Reforming
+ H2 Manufacture
+ Sulfur + Ammonia Recovery
• ONSITES TOTAL, MM$
• OFFSITES
+ Utilities^'
Steam (10.9 $/Mlb/hr)
Power (204 $/KW)
Cooling Water (54.4 S/GPM)
Other (20* of above)
Total Utilities
+ Tankage
+ General Off sites
- Waste Treatment
- Site Prep
- Blending + Loading
- Gen'l Offaites
• OFFSITES TOTAL, MM$
• TOTAL INVESTMENT, MM$
Coal
Case 1 (Mogas/Dist) Case 2 (All Mogas)
( /SD) MM$
100 MB 11.0
(53 + 28lMB 32.3
-
51 MB^1) 22.3
100 MMSCF(3X5) 42.0
31 LT 2.0
109.6
(640 Mlb/hr) 4.6
( 79 MKW) 16.1
( 80 MGPM) 4.4
5.0
30.1
14.7
11.9
5.8
14.0
6.0
37.7
82.5
192.1
( /SD)
100 MB
61 MB
-
76 MB'1'
144 MMSCF(3X5)
31 LT
(930 Mlb/hr)
( 93 MKW)
(110 MGPM)
MM!
11.1
47.0
-
29.2
52.1
2.0
141.4
6.7
19.0
5.9
6.3
37.9
15.1
12.5
6.4
15.7
6.4
41.0
94.0
235.4
Shale
Caae 3 (Moeas/Dlst) Case 4 (All Mogas) Case 5 - Cat Cracking (All Mogas)
( /SD) MM$
100 MB 11.7
22.5 MB 19.2
-
37 MB(2> 22.9
46 MMSCF<4> 6.0
-
59.8
(555 Mlb/hr) 4.2
( 66 MKW) 13.5
( 37 MGPM) 2.2
3.7
23.5
14.7
11.3
5.2
11.9
6.1
34.5
72.7
132.5
( /SD) MM$
100 MB 11.7
50 MB 33.6
-
59 MB(1> 22.3
53 MMSCFW 22.1
-
89.7
(675 Mlb/hr) 4.9
( 78 MKW) 15.8
( 69 MGPM) 3.8
4.9
29.4
15.2
11.9
5.8
14.0
6.0
37.7
82.3
172.0
( /SD) MMj
100 MB 12.3
-
J50 MB 55.0
19 MB<2) 12.2
-
79.5
(435 Mlb/hr) 3.2
( 82 MKW) 16.7
( 46 MGPM) 2.6
. 4.5
27.0
17.2
12.2
6.2
14.9
6.2
39.5
83.7
163.2
Notes:
(1) Semi-regen Reformer
(2) Cyclic Reformer
(3) Steam Reforming H2 Manufacture
(4) Cryogenic H2 Recovery
(5) Two Trains
-------
TABLE 3
ALTERNATIVE FUELS STUDY
REFINING SYNCRUDE
ANNUAL COST SUMMARY
1973 MM$/Year
Coal
Shale
• Annual Costs. BM$/Year
+ Catalyst + Chemicals
+ Electric Power (0.7 c/KWH
ex Fuel)
+ Investment Related
+ Return on Investment, % DCF
• Cost of Refining (ex Fuel)
IMS/Year
$/Bbl Syncrude
• Refinery Fuel Costs.(1)
MMS/Yr
* + Refinery Fuel<2>
+ Electric Power Fuel
Electric Powe:
(«« S)
+ H2 Flant Feed Fuel
+ Purchased Butanes'3'
• Annual Cost of Fuel
MK$/Yr
$/Bbl Syncrude
• Totsl Cost of Refining
MMS/Yr
$/Bbl Syncrude
Case 1 (Mogas/Dlst)
5
23.4
48.0
1.5
6$/Bbl 8/$B
15.4 20.6
5.9 7.8
15.4 20.6
36.7 49.0
1.1 1.5
84.7 97.0
2.6 2.9
4.0
4.1
16.5
10
41.3
65.9
2.0
6$/B B$/B
15.4 20.6
5.9 7.8
15.4 20.6
36.7 49.0
1.1 1.5
102.6 114.9
3.1 3.5
15
63.7
88.3
2.7
6S/B 8$/B
15.4 20.6
5.9 7.8
15.4 20.6
36.7 49.0
1.1 1.5
125.0 137.3
3.8 4.2
Case 2 (All Mogas)
5
28.7
60.1
1.8
6$/B 8$^
22.7 30.6
6.8 9.0
22.2 29.6
51.7 69.2
1.6 2.1
111.8 129.3
3.4 3.9
6.4
4.8
20.2
10
50.6
82.0
2.5
6$/B 8$/B
22.7 30.6
6.8 9.0
22.2 29.6
51.7 69.2
1.6 2.1
133.7 151.2
4.1 4.6
15
78.1
109.5
3.3
6$/B 6$/B
22.7 30.6
6.8 9.0
22.2 29.6
51.7 69.2
1.6 2.1
161.2 178.7
4.9 5.4
Case 3 (Mocas/Dlst)
(Hvdrocracklng)
5
16.2
34.7
1.1
6$/B 8$/B
12.3 16.4
4.2 5.6
-
16.5 22.0
0.5 0.7
50.4 55.9
1.5 1.7
3.7
3.4
11.4
10
28.5
47.0
1.4
6$/B 8$/B
12.3 16.4
4.2 5.6
-
16.5 22.0
0.5 0.7
62.7 68.2
1.9 2.1
15
44.0
62.5
1.9
6$/B 8$/B
12.3 16.4
4.2 5.6
-
16.5 22.0
0.5 0.7
78.0 84.5
2.4 2.6
Case 4 (All MOROS)
(Hydrocrackinfl)
5
21.0
46.3
1.4
6$/B 8$/B
18.0 . 24.0
5.8 7.7
8.1 10.8
31.9 42.5
l.Q 1.3
78.2 88.8
2.4 2.7
6.4
4.1
14.8
10
37.0
62.3
1.9
6$/B 8?/B
18.0 24.0
5.8 7.7
8.1 10.8
31.9 42.5
1.0 1.3
94.2 104.8
2.9 3.2
15'
57.1
82.4
2.5
6S/B 8$/B
18.0 24.0
5.8 7.7
8.1 10.8
31.9 42.5
1.0 1.3
114.3 124.9
3.5 3.8
Case 5 (All Nonas)
(Catalytic Cracking)
5
19.9
42.3
1.3
6$/B 8$/B
7.9 10.6
6.0 8.0
50 67
18.9 25.3
0.6 0.8
61.2 67.6
1.9 2.0
4.2
4.2
14.0
10
35.1
57.5
1.8
6? /B 8$/B
7.9 10.6
6.0 8.0
18.9 25.3
0.6 0.8
76.4 82.8
2.3 2.5
J5_
54.2
76.6
2.3
6$/B 8S/B
7.9 10.6
6.0 8.0
5.0 6.7
18.9 25.3
0.6 0.8
95.5 101.9
2.9 3.1
(1) As some 9 BBL - FQEB
(2) No credit for refinery gases
(3) Butane at 6/B. . Q$/FOEB and 8/
.
U$/FOEB
EPA-460/3-74-009
-------
APPENDIX 8
FIGURE I
ALTERNATE FUELS STUDY
REFINING SYNCRUDE
COAL - CASE 1 - MOGAS/DIST
C1-C3
Light Naphtha
7.0 MB/SO
Heavy Naphtha
28.0 MB/SD
100 MB/SO
Sync rude
L. Naphtha
7.5 MB
SIT
27.8 MB
SD~
MO
21.8 SD-
28.7 SD"
" 50.5
MB/SD
Semi-Regen
Reformer
1 Distillate
Furnace Oil
Purchased Naphtha
7.8 MFOEB/SD
Feed
4.3 MFOEB/SD
Fuel
H2
Plant
3.5 MFOEB/SD
•100 MMSCF/SD
(95% H2)
(2 Trains @50)
S +NH3
Recovery
Ammonia
12 LT/D
19 LT/D
Refinery Gas 2.7
MFOEB
SD
MOGAS
Butanes
Naphtha
5.9 MB/SD
14.5 MB/SD
Reformate 45.7 MB/SD
Total 66.1 MB/SD
Distillate
33.3 MB/SD
Furnace Oil
2.2 MB/SD
Purchased Fuel
(7.8 MB/SD)
Refinery Fuel
Process: 5
MF(
Steam: 1.9 S
9 MFOEB
DEB"55""
D
EPA-460/3-74-009
-------
APPENDIX 8
FIGURE 2
ALTERNATE FUELS STUDY
REFINING SYNCRUDE
COAL -CASE 2 -ALL MOGAS
Light Naphtha
100 MB/SD
Sync rude
7.0 MB/SD
Heavy Naphtha
APS
+
Light
Ends
28.6 MB/SD
Middle Dist.
57.9 MB/SD
Light Naphtha
16.6 MB/SD
Naphtha
Hydrotreater
Hydrocracker
(Rl + R2)
48.0
MB/SD
-*T*
28.7 MB/SD
76.7
MB/SD
Semi-Regen
Reformer
C5 +
Furnace Oil
C1'C3
Purchased Fuel
(11.6 MB/SD)
Refinery Gas 4.8
MFOEB
MOGAS
Butanes
Naphtha
8.7 MB/SD
23.6 MB/SD
Reformate 69.0 MB/SD
Total
101.3 MB/SD
Furnace Oil
2.2 MB/SD
Refinery Fuel
process:
SD MFOEB
Steam: 2.8 SD
Feed
Purchased Naphtha
11.2 MFOEB/SD
6.2 *~
Fuel
Plain
5.0
144 MMSCF/SD
*- (95% H2)
(2 Trains @72)
S+NH3
Recovery
^Z. *- 12 LT/D
Ammonia __ 19 LT/D
EPA-460/3-74-009
-------
APPENDIX 8
100 MB/SO
Syncrude
FIGURE 3
ALTERNATE FUELS STUDY
REFINING SYNCRUDE
SHALE - CASE 3 - MOGAS/DISTILLATE
C1-C4
9.0MB/SD
C5/200 12.0 MB/SO
APS
+
Light
Ends
200/375 19.0 MB/SD
375/430 10.0 MB/SD
430/550
550+
2.8 MB/SD
22.5 MB/SD
C5/180
6.0 MB/SD
Hydrocracker
180/350
1779 MB/SD
Ref Gases
Refinery Gases
MB
36.950"
C4(4.4 MFOEB/SD)
Cyclic
Powerformer
1.5 MB/SD
C5+(100RONCL)
Purchased 6.2 MB/SD
46 MMSCF/SD
95% H,
Refinery Gases 6.6
MFOEB
MOGAS
Butanes (6.6 MB/SD)
C5/200 (12.0 MB/SD)
Reformate (32.3 MB/SD)
375/430 (10.0 MB/SD)
C5/180 (6.0 MB/SD)
Total 66.9 MB/SD
Distillate (27.5 MB/SD)
Refinery Fuel
process: 4.6
, ,
Steam: 1.6
MFOEB
EPA-460/3-74-009
-------
APPENDIX 8
MB
100 SD"
Syncrude
FIGURE 4
ALTERNATE FUELS STUDY
REFINING SYNCRUDE
SHALE - CASE 4 - ALL MOGAS
C1-C4
"4 9.0 MB/SD
C5/200 12.0 MB/SD
APS
+
Light
Ends
MB
200/375 19.0SD
Hydro treater
MB
58.7 SD"
375/430 10.0 MB/SD
430 +
6.2 MB/SD
50 MB/SD
C 5/180
Hydrocracker
180/350
3.1 MB/SO
Semi-Regen
Powerformer
RONCL)
13.3 MB/SD
39.7 MB/SD
Feed
Purchased Naphtha
4.1 MFOEB/SD
2.3 MFOEB/SD
Fuel
1 *-
H2
Plant
53 MMSCF/SD
*- (95% H2)
1.8 MFOEB/SD
Refinery Gases
11.9 MFOEB/SD
MOGAS
Butanes (8.9 MB/SD)
MB
C5/200 (12.0~S~D~)
MB
Reformate (49.5 SO)
375/430 (10.0 MB/SD)
C5/180 (13.3 MB/SD)
Total 93.7 MB/SD
Purchased Fuel
9.1 MB/SD
Refinery Fuel
Process: 7.1MF°fB
Steam: 2.0™.
EPA-460/3-74-009
-------
APPENDIX 8
FIGURE 5
ALTERNATE FUELS STUDY
REFINING SVNCRUDE
SHALE - CASE 5 - CAT CRACKING
Purchased C .
100 MB/SO
byncruoe
iC4
4.3 MB/
C4 4.7 MB/SD
SD
1
C5/200 12.0 MB/SD
,
APS
-t-
Light
Ends
}
MB
200/375 19.0'SD" Hydrof
^ Cyclic Po
1.7 MB/SD
1 . i
1.4 MB
SD~
ner 15.2 MB/SD (100 RONCL'
werrormer
375/430 10.0 MB/SD
430
50 MB/SD CatCra
i T 43 MR/<5D * roiymer
i C4
-------
APPENDIX.8
REFERENCES
(1) "Project H-Coal", Hydrocarbon Research, Inc., 1967; Office of Coal
Research Contract #14-01-0001-477.
(2) "Evaluation of Project H-Coal"; American Oil Co., Research and De-
velopment Department; 12/8/67; OCR Contract #14-01-0001-1188
American Oil Project //6120.
(3) Montgomery, D. P., "Refining of Pyrolytic Shale Oil"; IEC Product
Research & Development, Vol. 7, Issue 4, 12/68 (Phillips Petroleum
Co.) .
- 118 -
-------
APPENDIX 9
COAL MINING COSTS AND INVESTMENTS
The principal sources of the information discussed in this
Appendix are:
(a) "Cost Analysis of Model Mines for Strip Mining of Coal
in the United States", Bureau of Mines Information
Circular No. 8535, 1972.
(b) "U.S. Energy Outlook -- Coal Availability", National
Petroleum Council, 1971.
The purposes of this review are to identify the most important
factors that affect coal cost, to illustrate the relative importance of
the different factors, and to permit reasonable estimates of the future
average cost of coal that may be used to produce synthetic fuels. The
cost data have been converted from the numbers actually reported in the
above references to 1973 dollars in order to be consistent with other
cost estimates in this study.
General conclusions for surface mining (unless otherwise
noted) are:
(1) operating costs and initial investments vary widely for
different ranks of coal.
(2) costs vary with seam thickness and overburden and, hence,
with stripping ratio. In general, seam thickness is the more important
variable. Tripling of seam thickness may reduce operating and invest-
ment costs by 50%.
(3) production costs decrease as capacity increases.
(4) mining productivity may increase 20% by 1985*.
It may be noted that the average productivity of underground mines
decreased by 28% from 1969 to 1973 (from 15.61 tons per man-day to
11.20 tons per man-day). Corresponding averages for strip mines
were 35.71 and 34.60 tons per man-day.
- 119 -
-------
(5) in 1973, initial investment in a surface mine will have
averaged about $9 per ton of annual production. For Western strip
mines, the investment will have been lower than the national average,
e.g., $6-7/annual ton for an annual capacity of 1 million tons and
$2.60-5.60/annual ton for a capacity of 5 million tons. Costs for Mid-
west and Appalachian surface mines run about 8570 higher at the same
capacity level.
(6) costs plus 12% DCF return for sub-bituminous coal from
the Great Plains area were estimated by the Bureau of Mines to be:
Scale of
Operation Average Seam Stripping Cost 1973$/Ton
MM tons/yr. Thickness, ft. Ratio F.O.B. Mine, 12% DCF
1 8 7.5 . 3.98
1 25 3 2.16
5 8 8.8 3.15
5 25 3 1.71
(7) comparable estimates made by the NPC were:
Cost 1973 $/Ton
Location Stripping Ratio F.O.B. Mine, 12% DCF
Western 6 3.37
" 7 .3.60
10 4.16
15 5.06
Pennsylvania 6 5.30
" underground mine 9.30
(8) the effect of the DCF return assumed may be illustrated
at a constant stripping ratio of 8:1 for Western coal:
Cost 1973 $/Ton
7, DCF Return F.O.B. Mine, 127. DCF
10 3.20
15 3.60
20 4.00
(9) other factors affecting the production cost of coal in-
clude labor productivity, reclamation costs, and percentage depletion.
The high labor intensity of underground mines makes productivity an
important factor in total production costs. Labor productivity, at the
levels commonly experienced in surface mines, has a relatively smaller
- 120 -
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effect on total costs. Estimates of reclamation costs range from 2
cents to 20 cents per ton depending on seam thickness*. If the deple-
tion allowance (currently 10% for coal) were to be eliminated, the
effective cost of coal would increase by at least $l/ton.
Several tables will now be presented to illustrate the break-
down of costs for a "model" mine. This mine has a nominal production
capacity of 5 million tons/year and is typical of a mine of this size
located in Arizona, Colorado, New Mexico or Utah. Summarized character-
istics of the model mine are:
Production: 5 million tons/year.
Capital investment: $28.7 million .
Life of mine average operating cost**: $12 MM/year or
$2.40/ton.
- Selling price: $3.03/ton*** in 1973 dollars.
The breakdown of estimated capital requirements is given
in Table 1.
i
The depreciation schedule is given ;in Table 2.
Estimated working capital is reported in Table 3.
Annual production costs are estimated in Table A.
Calculation of the coal selling price is shown in Table
5. i
* These estimates were made prior to proposed legislation now under
consideration by Congress. If enacted, certain of the proposals
could increase reclamation costs almost ten-fold from the estimates
above.
** Operating costs increase with time because the thicker seams are
exploited first.
*** Note that this estimate is consistent with the assumed cost of
$3/ton for Western sub-bituminous coal used for the first time-
frame (1982) of the present study.
T All subsequent financial statistics in Appendix 9 are reported
in 1972 dollars, which may be escalated to 1973 dollars by multi-
plying by 1.04.
- 121 -
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APPENDIX 9
TABLE 1
TOTAL ESTIMATED CAPITAL REQUIREMENTS (1972 $)
Exploration, roads, and buildings $ 2,200,000
Unit-train loading facilities 750,000
Mining equipment 18,311,300
Total direct ... 21,261,300
Field indirect • . 425.200
Total construction 21,686,500
Engineering 433,700
Subtotal 22,120,200
Overhead and administration 1,106,OOP
Subtotal . 23,336,200
Contingency 2,322,600
Subtotal 25,548,800
Fee 511,000
Total plant cost (insurance-tax base) 26,059,800
Interest during construction 651,500
Subtotal 26,711,300
Working capital . 1,945,400
Total capital requirements 28,656,700
1973 $ = 1.04 x 1972 $
EPA-460/3-74-009
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APPENDIX 9
TABLE 2
DEPRECIATION SCHEDULE
Straight-line
Items Depreciation, Yrs
Exploration, coal lease 20
Buildings, shops 20
Train loading facilities 20
Dragline, cable handers 20
Powerline, substations 20
Loaders, bulldozers 10
Pumps 10
Trucks 6-10
Engineering, overhead, administration
contingency, fee, and IDC* 20
* Interest-During-Construction
EPA-460/3-74-009
APPENDIX 9
TABLE 3
ESTIMATED WORKING CAPITAL (1972 $)
Direct labor, 3 months $ 306,900
Payroll overhead, 3 months . 107,400
Operating supplies, 3 months 824,500
Indirect cost, 4 months 226,300
Fixed cost, 0.5 percent of insurance base 130,300
Spare parts 300,000
Miscellaneous expense 50,OOP
Total 1,945,400
1973 $ = 1.04 x 1972 $
EPA-460/3-74-009
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APPENDIX 9
TABLE 4
ESTIMATED ANNUAL PRODUCTION COST (1972 $)
Direct Cost:
Production:
Labor
Supervision
Subtotal
Maintenance:
Labor
Supervision
Subtotal
Total direct labor
Operating supplies
Spare parts
Explosives
Lubrication
Diesel Fuel
Tires
Miscellaneous
Total operating supplies
Power
Union Welfare
Royalty
Payroll overhead
Subtotal
Total direct cost
Indirect cost: 15 percent of labor,
maintenance, & supplies
Fixed cost:
Taxes & insurance (27» of plant cost)
Depreciation
Deferred expenses
Total fixed cost
Total annual production cost
Total Annual
Cost
$ 783,900
183,000
966,900
233,700
27,000
260,700
1,227,600
2,000,000
678,000
70,000
125,000
175,000
250,000
3,298,000
800,000
2,000,000
875,000
429,700
4,104,700
Cost Per
Ton
$0.15
.04
.19
.04
.01
.05
.24
.40
.14
.01
.02
.04
.05
.66
.16
.40
.18
.08
.82
8,630,300
678,800
1.72
.14
521,200
1,484,100
716,400
2,721,700
.10
.30
.14
.54
12,030,800
2.40
1973 $ = 1.04 x 1972 $
EPA-460/3-74-009
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APPENDIX 9
TABLE 5
CALCULATION OF COAL-SELLING PRICE
12 percent -- 20 years
R = $28,656,700/7.469 = $3,836,900
less depreciation -1,484,100
$2,352,800 = depletion + net profit
Depletion + net profit = 3/4 gross profit
Gross profit = 1.333 x $2,352,800 = $3,136,300
Sales = production cost + gross profit
= $12,030,800 + $3,136,300 = $15,167,100
Selling price/ton -- $15,167,100/5,000,000 = $3.03 = "cost" of coal, F.O.B. mine
*
Depletion = 50 percent of taxable income
Gross profit $3,136,300
Depletion 1,568,150
Taxable Income 1,568,150
Federal income tax (F.I.T.) 784,100
Net profit 784,050
Annual cash flow = net profit + depreciation + depletion
=$784,100 +$1,484,100 + $1,568,200 = $3,836,400
* Although the depletion allowance applicable to coal is 107o of the
"gross income from property" (i.e., essentially 107o of the annual
F.O.B. mine value of the coal produced and sold), it is also limited
to 50% of the taxable income from the property as computed without
application of the allowance.
EPA-460/3-74-009
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APPENDIX 10
COST OF OPERATING AN AUTOMOBILE
The major components of the cost of operating an automobile
include the following categories: variable or operating costs (which
depend on the miles driven) consisting of fuel, oil, maintenance repairs
and tires; and fixed costs (independent of miles driven) made up of
depreciation, insurance, registration and license fees. In general, the
former are related to the miles driven and the weight of the car, while
the latter are related to its first cost. From published information
(1,2), a breakdown of the various cost categories (in 1973 dollars) has
been estimated for three car sizes:
1. Standard size car, curb weight 4000-4300 Ibs. equipped with
standard accessories and automatic transmission, power steering, power
brakes, radio and air conditioning; estimated retail cost $3900.
2. Intermediate size car, curb weight 3500-3800 Ibs., equipped
with standard accessories and radio, automatic transmission, power steer-
ing and air conditioning; estimated retail price $3400.
3. Compact size car, curb weight 2800-3400 Ibs., equipped with
standard accessories and radio, automatic transmission and air condition-
ing; estimated retail price $3000.
The following assumptions were made:
• average cost of gasoline in the U.S. in early 1973
was 38
-------
The results of these estimates are presented in Table 1 and in Figures
1 and 2.
The next step was to estimate the effect of fuel changes on
vehicle operating costs. This involved estimating separately the fuel-
related changes in car weight and cost. These estimates were made in
terms of incremental weight and cost compared to a 1973 gasoline
powered automobile, weight 3500 lb., range 260 miles, retail price
$3400.
The following factors were considered separately for this
analysis:
• the fuel and fuel storage requirements. In this study, the fuel
storage capacity required was assumed to be that necessary to provide
the same operating range (i.e., about 260 miles) as is currently pos-
sible with 20 gallons of petroleum, gasoline (2.25 x 10^ BTUs used in
an engine of 9.5% thermal efficiency*). The weights were calculated
as follows:
Incremental Wt. « I 134
- 134
where 134 is the wt. of gasoline and fuel tank
for the Otto cycle engine
is the thermal efficiency of other engines
H is the net heating value of other fuels, BTU/lb.
18650 is net heating value of gasoline, BTU/lb.
the engine.
the need for modifications to meet future exhaust emission require-
ments, i.e., to meet U.S. post-1976 emission standards: 0.41, 3.4,
0.4 gms./mile for HC, CO, and NO , respectively (5).
X
the need for modification of the fuel system to handle potentially
toxic or hazardous fuels safely, i.e., to avoid loss of toxic fuel
vapors and/or contact with harmful liquid by spills, tank rupture
or deliberate removal.
Typical of 1973 ICE on Federal Emissions Driving cycle; see Sect. 4,
Vol. II.
- 127 -
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• the change in support members of the vehicle occasioned by the
increase or decrease in weight due to the foregoing factors. By
support members are meant the frame, front suspension, rear suspen-
sion, brakes, wheels and tires. It is assumed that a three pound
increase in the weight of non-load bearing members (e.g., propulsion
system, fuel, tank, etc.) will require an increase of one Ib. in the
load-support members (estimated from data in Ref. 3).
Following is a list of the specific assumptions and approxima-
tions used in the analysis:
• an automotive diesel engine weighs 142 Ibs. more than a conventional
gasoline engine of the same horsepower (116 H.P.). This was esti-
mated from data in (A). The incremental cost is calculated on the
assumption that the incremental diesel weight costs $1.70/lb. The
estimated differentials include the cost of the fuel injector. How-
ever, it is not possible to establish from these generalizations the
specific cost of the injector. This point is not critical to the
relative fuel comparisons.
• a gas turbine engine is assumed to weigh 100 Ibs. less than the Otto
cycle engine of the same performance. Its cost is assumed to be
equal to that of a diesel engine of same performance.
• the distillate fuels derived from coal will be highly aromatic in
nature. They will thus be difficult to burn without smoking. For
this reason, diesel engine burning 100% coal distillate is assumed
to be derated by 10%. Likewise, the gas turbine engine burning the
coal distillate has been derated by 5% to compensate for the expected
high luminosity of the coal distillate flame. These penalties of
course can be avoided by blending the coal fuel with suitable petro-
leum fractions to provide mixtures approximating currently available
distillates in combustion characteristics.
• the future Otto cycle engine will be equipped with a catalytic
exhaust gas treatment device.
• the diesel engine will require modification or devices to meet future
exhaust emission levels including restrictions on exhaust odor and
particulate emissions.
• the low front-end volatility of 100% coal gasoline will require the
use of fuel injection for good engine performance. By blending with
suitable low boiling petroleum fractions, a gasoline suitable for
use in current carburetted engines could be obtained.
• an Otto cycle engine burning methanol will require bigger fuel pump,
lines, filter, manifold heater and carburetor than a gasoline fuel
engine.
- 128 -
-------
a gas turbine burning methanol will require large fuel pump, lines,
filter and controls. However, t;he weight debit associated with these
items is assumed to be compensated by the low luminosity of its flame
which will allow savings in combustor cooling requirements.
the fuel cost for the various cases was calculated as follows:
Fuel Cost - (BFC)
where: BFC is the base fuel cost (gasoline) read from Figure 1
for the appropriate car weight
C-,v - cost of the new fuel, $/10 BTU ex tax
r A
P, - thermal efficiency of the various engines, i.e., 9.5%
for the Otto cycle, 16.5% for the diesel and 10% for
the gas turbine (on the Federal Emissions Driving
Cycle).
3.35 = cost of petroleum gasoline in $/10 net BTU based on
38.1 C/gal.*
• the various fuels will have no unusual effect on vehicle maintenance
requirements. This assumption is required by lack of data on which
to base a sounder estimate.
• while there may be differences in maintenance and lubrication
requirements between engine types, it is felt this will not nullify
the comparison among the fuels in a given engine.
The total fixed costs were read from Figure 2 for the appro-
priate retail price (i.e., total cost) of the automobile.
Tables 3 and 4 present the estimates for the various engine
and future fuel combinations using the following fuel costs:
Since the cost alternate fuels is on an ex tax basis in this study,
the reference gasoline cost has to be on the same basis. Purely
fortuitously, the ex tax cost in early 1974 is about the same as the
cost with tax in early 1973, so that Figure 1 can be used in making
corrections.
- 129 -
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$/106 BTU
ex tax (1973 $)
Petroleum gasoline (1974) @ 38
-------
APPENDIX 10
TABLE I
ESTIMATED LIFE TIME COST
OF OPERATING AN AUTOMOBILE (1973 DATA)
(Car Life 10 years, Total Mileage - 100,000)
Type of Car Standard Intermediate
Curb Wt., Ibs. 4000-4300 3500-3800
Retail Price, $ 3900 3400
Variable or Operating
Lifetime Costs, $*
Gasoline 3180
Oil 168
Maintenance and Repairs
Labor 1430
Materials 720
Total 2150
Tires 620
Total Lifetime Operating
Costs 6118
Fixed Costs**
Depreciation 3900
License & Registration 280
Collision Insurance 715
Property Damage & Liability 1790
Total Fixed Costs 6933
GRAND TOTAL COSTS 13,051
3000
158
1430
635
2065
590
5813
3400
218
630
1790
6284
12,097
Compact
2800-3400
3000
2540
134
1430
540
1970
500
.5144
3000
186
536
1790
5722
10,866
* From Figure 1.
** From Figur^ 2; does not include interest cost on capital required
for the purchase of the car.
EPA-460/3-74-009
- 131 -
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APPENDIX 10
10
N3
TABLE
2
ESTIMATE OF OPERATING COST OF POST 1976 AUTOMOBILES
(10 years, 100,
Fuel Source
Fuel Type
Engine Type
Incremental Wt. (Ibs)*
(Due to Following Factors)
Fuel & Fuel Storage
Engine
Emission Correct.
Toxic ity & Safety
Support Members
Total A Wt., Ibs.
Total Car Weight
Lifetime Operating Cost,
1973 $
Fuel
0,M,R,T**
Total Operating Cost
Fuel Cost c/Mile (ex tax)
Petroleum
Gasol.
Otto
0
0
30
0
10
40
3540
2890
2770
5660
2.9
Distill.
Diesel
-56
142
10
0
32
128
3628
1415
2790
4205
1.4
Distill.
G.T.
-7
-100
0
0
-36
-143
3357
2195
2710
4905
2.2
Gasol.
Otto
0
0
30
0
10
40
3540
2330
2770
5100
2.3
000 miles)
Shale
Distill.
Diesel
-56
142
10
0
32
128
3628
1060
2790
3850
1.1
Distill.
G.T.
-7
-100
0
0
-36
-143
3357
1610
2710
4320
1 1.6
Gasol.
Otto
0
0
30
20
17
67
3567
2900
2780
5680
2.9
Distill.
Diesel
-56
196
10
10
53
213
3713
1390
2810
4200
1.4
Coal
Distill.
G.T.
-7
-80
0
10
-25
-102
3398
2130
2710
4840
2..1
MeOH
Otto
156
30
15
20
68
279
3779
3540
2840
6380
3.5
MeOH
G.T.
154
-100
0
20
16
90
3590
3230
2770
6000
3.2
* Reference vehicle 1973 gasoline, Otto cycle car, 3500 Ibs. curb weight.
** Oil, Maintenance, Repairs and Tires.
EPA-460/3-74-009
-------
APPENDIX 10
LO
10
ESTIMATE
TABLE
OF FIXED COSTS OF
(10 years, 100,
Fuel Source
Fuel Type
Engine Type
Incremental Cost* $ because
of Following Factors
Fuel Storage
Engine
Emission Correct.
Toxic ity & Safety
Support Members
Total A Cost $
Total Purchase Cost $
Total Fixed Costs
Petroleum
Gasol.
Otto
0
0
300
0
8
308
3708
6660
Distill.
Diesel
-10
245
200
0
24
459
3859
6860
Distill.
G.T.
0
245
0
0
-27
218
3618
6550
Gasol.
Otto
0
0
300
0
8
308
3708
6660
3
POST 1976
000 miles)
Shale
Distill.
Diesel
-10
245
200
0
24
459
3859
6860
AUTOMOBILES
Distill.
G.T.
0
245
0
0
-27
218
3618
6550
Gasol.
Otto
0
100
300
60
13
423
3823
6820
Distill.
Diesel
-10
335
200
10
40
575
3975
7050
Coal
Distill.
G.T.
0
345
0
10
-17
338
3738
6720
MeOH
Otto
15
50
100
60
51
276
3676 '
6650
MeOH
G.T.
15
295
0
60
12
382
3782
6790
(10 yrs.)**
* Reference vehicle 1973, gasoline, Otto cycle car, cost $3400.
** From Figure 2.
EPA-460/3-74-009
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APPENDIX '10
TABLE 4
ESTIMATED COSTS OF OWNING AND OPERATING
A POST 1976 AUTOMOBILE*
(Lifetime, 10 yrs., 100,000 miles)
Lifetime Costs $ (1973)
Raw Material
Petroleum
Petroleum
Petroleum
Shale
Shale
Shale
Coal
Coal
Coal
Coal
Coal
Fuel
Gasol.
Distill.
Distill.
Gasol.
Distill.
Distill.
Gasol.
Distill.
Distill.
Methanol
Methanol
Engine
Otto
Diesel
G.T.
Otto
Diesel
G.T.
Otto
Diesel
G.T.
Otto
G.T.
Operating
5660
4205
4905
5100
3850
4320
5680
4200
4840
6380
6000
Fixed
Charges
6660
6860
6550
6660
6860
6550
6820
7050
6720
6650
6790
Total
12,320
11,060
11,460
11,760
10,710
10,870
12,500
11,250
11,560
13,030
12,790
* Intermediate size - reference vehicle, 3500 Ibs., cost $3400:.
EPA-460/3-74-009
- 134 -
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o
o
o
Cfl
H
8
u
9
pa
S
od
2
APPENDIX 10
FIGURE 1
OPERATING COSTS OF AN AUTOMOBILE
(CAR LIFE 10 YRS., 100,000 MILES)'
VARIABLE COSTS - 1973 $
GASOLINE*
OIL
MAINTENANCE
REPAIRS
TIRES
*GASOLINE @ 38.1C/GAL. WITH TAX; 26.9C/GAL. EX TAX
(FIRST HALF - 1973 AVERAGE)
BASED ON: INFORMATION FROM "YOUR DRIVING COSTS"
AMERICAN AUTOMOBILE ASSOC, 1973-1974 EDITION
: STATISTICAL ABSTRACT OF THE U.S.-1973, p. 550,
TABLE 907
, I , J i I
3 4
CURB WEIGHT OF CAR (1000 LBS.)
EPA-460/3-74-009
- 135 -
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APPENDIX 10
FIGURE 2
OPERATING COSTS OF AN AUTOMOBILE
(CAR LIFE., 10 YRS., 100,000 MILES)
FIXED COSTS - 1973 $
O
O
O
H
O
DEPRECIATION
INSURANCE
LICENSE & REGISTRATION
6:
/
BASED ON: INFORMATION FROM "YOUR
DRIVING COSTS" AMERICAN
AUTOMOBILE ASSOC. 1973-1974
EDITION
RETAIL PRICES OF 1973 NEW CARS
RETAIL PRICE OF CAR (1000 $)
EPA-460/3-74-009
- 136 -
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APPENDIX 10
REFERENCES
(1) "Your Driving Costs - 1973-1974 Edition," Pamphlet from American
Automobile Association,
(2) Statistical Abstract of the United States, 1973, page 550,
Table 907.
(3) Hangen, K., et al., "The Chevrolet Corvair," SAE Preprint 1AOC,
January 1960.
(4) Springer, K. J., et al., SAE Preprint 739133, Table 1.
\
(5) Report by the Committee on Motor Vehicle Emissions, February 12,
1973, National Academy of Sciences.
- 137 -
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-460/3-74-009-C
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Feasibility Study of Alternative Fuels for Automotive
Transportation - Volume III, Appendices
5. REPORT DATE
June 1974
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
F. H. Kant, R; P. Cahn, A. R. Cunningham, M. H. Farmer,
W. Herbst, E. H. Manny
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORG \NIZATION NAME AND ADDRESS
Exxon Research and" Engineering Co.
P.O. Box 45
Linden, New Jersey 07036
10. PROGRAM ELEMENT NO.
1A2017
11. CONTRACT/GRANT NO.
68-01-2112
12. SPONSORING AGENCY NAME AND ADDRESS
Environmental Protection Agency
Office of Mobile Source Air Pollution Control
Alternative Automotive Power Systems Division
2929 Plymouth Road, Ann Arbor, Michigan 48105
13. TYPE OF REPORT AND PERIOD COVERED
Final June 1973-June 1974
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This study identifies feasible and practical alternatives to
automotive fuels derived from petroleum for the 1975-2000 time period.
The alternative fuels are liquids derived from domestic coal and oil
shale — specifically, gasolines, distillates, and methanol. While many
uncertainties remain, initial production of the new fuels is likely within
the next five to seven years.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Automotive fuels
Substitutes
Feasibility
Forecasting
Oil-Shale
Methyl alcohol
Gasoline
Automotive fuels
Non-petroleum fuels
Synthetic gasolines
Coal liquids
13 B
18. DISTRIBUTION STATEMENT
Release unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
144
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
- 138 -
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