EPA-AA-SDSB-82-07
Technical Report
The H-Coal and SRC-II Processes
by
Daniel Heiser
February 1982
NOTICE
Technical Reports do not necessarily represent final EPA decisions
or positions. They are intended to present technical analysis of
issues using data which are currently available. The purpose in
the release of such reports is to facilitate the exchange of
technical information and to inform the public of technical
developments which may form the basis for a final EPA decision,
position or regulatory action.
Standards Development and Suporrt Branch
Emission Control Technology Division
Office of Mobile Source Air Pollution Control
Office of Air, Noise and Radiation
U. S. Environmental Protection Agency
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Table of Contents
Page
I. Introduction 1
II. Financial Input Factors 1
III. Process Description and Economic Analysis of 6
the H-Coal and SRC-II Processes
A. The H-Coal Process 7
B. The SRC-II Process , 25
IV. Summary 47
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I. Introduction
As the nation investigates several alternatives for producing
synthetic fuels from our coal reserves, the major question arising
is what is the most efficient way to utilize our coal resources.
The answer involves determining what kind of synthetic fuels to
produce and what method should be used to produce these fuels.
Much attention is being directed towards development of synthetic
petroleum products. This report will attempt to identify the
products and costs associated with two processes which produce
synthetic crude oil from coal, the H-Coal process and the SRC-II
process.
The first step in this attempt will be the identification of
a set of financial and technical parameters upon which to base the
comparison of costs from various studies originally using differ-
ent bases. Such parameters include plant size, capital charge
rates, etc. This identification will be presented in Section II.
The second step will start with a survey of the economic studies
of the H-Coal and SRC-II processes. These studies will be
compared technically and economically to determine which repre-
sents the best product and cost estimates for each process. Once
the best study (or studies) has been selected in each case, its
financial parameters will be adjusted to those determined in the
previous section. The final product cost of each process will
then be estimated in terms of dollars per million BTU (mBTU).
A summary of the cost estimates will be included at the end
of this report.
II. Financial Input Factors
Differences in costs developed from recent studies on coal
liquefaction can result because of two major factors. One, the
costs may differ because of differences in the financial
parameters specified (such as interest rates, debt/equity ratio,
capital charge rate, etc.). Two, the costs may differ because
hardware costs for each phase of the process itself were estimated
using different cost estimation techniques or were based on
different process requirements. The objective of this section is
to develop a common set of financial and economic parameters for
all studies to eliminate the first cause of these differences.
Hardware or process costs involve intimate knowledge of the speci-
fic coal liquefaction processes and the detailed evaluation of
each study's procedures in these areas is beyond the scope of this
report. However, some evaluation of each study's technical/
economic accuracy will be made based on the overall level of
detail of the engineering design and the source and data of the
process parameters.
To determine a reasonable range of the financial parameters
applicable to such studies, a survey of recent studies on coal
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liquefaction processes was taken.[1,2,3,4,5,6] Two financial
scenarios representing two somewhat extreme cases were found and
are shown in Table 1.
The first scenario represents a situation where utility-type
financing or loan guarantees are available and was taken from a
report by ESCOE.[3] Debt financing is assumed to be 40 percent of
total financing. The overall capital charge rate for this
scenario is 11.5 percent. The second scenario was taken from a
Chevron study[l] and assumes total reliance on equity financing.
The overall capital charge rate of this scenario is 30 percent.
To mention one aspect of the parameters of Table 1, capital
costs are often estimated in terms of "instantaneous" investment
(i.e., as if the costs would occur all at once). In reality, this
does not take place as plants are designed and constructed over a
period of time. Each of the two financial scenarios has a differ-
ent capital investment schedule to account for this. These
investment schedules, along with the cost of interest during
construction are used to adjust the instantaneous capital cost
estimates to full-life capital cost investment. The interest rate
during construction used here will be 6 percent per year and was
taken from a report by ICF.[2] Since all operations are performed
in constant $1981, this 6 percent per annum opportunity cost does
not include the effects of inflation.
For the purposes of this report, the products of each process
will be measured in terms of fuel oil equivalent barrels (FOEB),
each FOEB containing 5.9 million Btu. This is a common unit for
measuring the equivalent energy output of a fuel. To eliminate
cost differences due to economies of scale, all plants will be
normalized to an output of 50,000 FOEB per calender day (FOEB/D).
Because capital costs are usually not in direct proportion to
their plant sizes, a scaling factor is needed. This scaling
factor is an exponent which is applied to the ratio of plant sizes
to determine the effect on capital costs. The capital scaling
factor used in this study will be 0.75, which is an average of
factors found from various studies.[2,5,7,8]
Operating costs need to be adjusted differently than capital
costs. To adjust labor and supervision costs to the common 50,000
BFOE/D plant size, a scaling factor of 0.2 will be used.[3,7]
Maintenance costs, taxes and insurance, and general services,
etc., will be assumed to be the same percentage of plant invest-
ment as specified by individual studies. The use of coal,
catalysts, chemicals, utilities, fuel, and natural gas will also
be assumed to vary in proportion to plant size. Electricity costs
will be normalized to 3.5 cents per kilowatt hour. Also included
in the total annual operating cost will be a 6 percent real
interest charge on working capital.[2]
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Table 1
Common Financial Parameters*
Financial Parameters
Discounted Cash Flow
Rate of Return on In-
vestment, Percent
Project Life, Yrs.
Construction Period, Yrs.
Investment Schedule,
%/Yr.
Plant Start Up Ratios
Nominal Debt Interest
Rate, Percent
Investment Tax Credit, %
Tax Life, Yrs.
Debt/Equity Ratio
Resulting Capital Charge
Rate, Percent
Low Cost Case[l]
Not Available
20
4
9/25/36/30
50, 90, 100...
10
9
15
40/60
11.5
High Cost Case[2]
15
20
4
10/15/25/50
50/100
10
13
0/100
30
* All calculations assume constant first quarter 1981 dollars.
The interest rates shown do not include the effects of inflation.
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A common contingency factor will also be used to increase the
comparability of the various studies. Historical evidence has
shown that a variety of technical problems emerge whenever a plant
is constructed from conceptual stage to the commercial stage.
This usually results in an increase in cost due to the need for
more expensive materials of construction, more complex equipment
specifications and sometimes the need for additional processing
equipment. The contingency factor to be used in this analysis
will be 15 percent, based on a survey of several studies.[2,3,9,
10,11,12]
Costs for feedstock and by-product credits will also be
normalized. The cost of bituminous coal (in 1981 dollars) will be
assumed to be $27.50 per ton. The cost of subbituminous coal and
lignite will be assumed to be $17 per ton and $10 per ton,
respectively. By-product credits for sulfur, ammonia, and phenol
will be normalized to $50 per ton, $180 per ton, and $113 per
barrel, respectively.
The inflation rate for adjusting the cost of studies to 1981
dollars will be based on the chemical engineering plant cost
index. For 1976, 1977, 1978, 1979, and 1980, the resulting infla-
tion rates were 5 percent, 6 percent, 7 percent, 9 percent, and 9
percent, respectively. The only real cost increases projected in
this study were for fuel oil and natural gas used to operate the
plant. These were estimated to be 2 percent per year. These
common technical/economic factors are summarized in Table 2.
While all these adjustments will increase the comparability
of overall product costs, they do not address the differences in
the products produced by the various synfuel processes. It is
generally appropriate to attempt to allocate the costs of process-
ing in accordance to the expected market values of the various
products. To do otherwise would be to mislead oneself that the
premium products of a process were relatively inexpensive (while
the low quality products would also be misleadingly expensive).
Thus, some relationship between the values of the various fuels is
needed in order to determine representative and comparable costs
for each fuel.
A product value approach will be utilized to estimate costs
for individual products. This technique assumes that future
energy prices for particular products will maintain a fixed ratio
to each other. All prices are normalized relative to a reference
product, which here is chosen to be gasoline. A relationship
between various fuels similar to that reported in the ICF report
will be used and is as follows:
1. If the cost of unleaded regular gasoline is $G/mBtu,
2. The cost of No. 2 fuel oil is (0.82)($G)/mBtu, and
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Table 2
Process Cost Inputs and Other
Factors Common to All Studies
Cost Inputs and Other Factors
Product Yield
Coal - Bituminous
- Subbituminous
- Lignite
Operating Cost
a) Utilities
b) Interest on Working Capital
c) Fuel Cost
Scaling Factors
a) Capital Costs
b) Labor Costs
c) Maintenance, Taxes,
Insurance, General
Services, etc.
d) Coal, Catalysts and
Chemicals, Utilities,
Fuel, Natural Gas
By-Product Credit
a) Sulfur
b) Ammonia
c) Phenol
Contingency Factor
Inflation Rate
a) 1976
b) 1977
c) 1978
d) 1979
e) 1980
Real Cost Increases (%/year)
a) Fuel Oil
b) Natural Gas
Value
50,000 BPCD
$27.50/wet ton
$17.00/wet ton
$10.00/wet ton
$0.035/kw-HR
6% of working
capital per year.
$35/bbl
0.75
0.20
Same percentage
of plant invest-
ment as specified
by each individ-
ual study.
Amount varies
proportionally
to plant size
$50/ton
$180/ton
$113/bbl
15%
5%
6%
7%
9%
9%
2%
2%
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3. The cost of LPG Is (0.77)($G)/mBtu.[2]
Since unleaded premium gasoline is produced in some cases a rela-
tionship between this fuel and regular gasoline is also needed.
Since a history of the relationship between these two fuels was
not readily available, a history of the cost ratio of leaded
premium to leaded regular gasoline was used. This relationship
indicated a cost ratio of 1.075.[13] This product cost relation-
ship was then applied to premium and regular unleaded gasoline.
A price relationship between SNG and the reference was also
needed. This may be determined by assuming that SNG will have the
same relationship to gasoline as natural gas. However, the well-
head price of natural gas is just in the process of being deregu-
lated; therefore, it is incorrect to use the current gasoline/
natural gas price relationship. Instead, a method used by Mobil,
and a method which relates the natural gas price to that of No. 2
fuel oil will be utilized. These two methods are described
below.
In a study examining the production of gasoline from coal one
of the scenarios examined by Mobil was the co-production of SNG
and gasoline.[14] To obtain a realistic value for the SNG
produced, Mobil estimated the cost of SNG from a coal-gasification
plant producing essentially 100 percent SNG. Using this cost for
SNG, they then allocated the remaining cost to the gasoline. The
result was that the SNG cost 77 percent as much as the gasoline on
an energy basis (i.e., it was cheaper on an energy basis to
produce SNG solely than to co-produce SNG and gasoline).
Another technique to obtain a representative SNG/gasoline
cost relationship is to assume that SNG has the same value as No.
2 fuel oil. This is reasonable since both have at least one large
common market in industrial and domestic heating. Using this
method, the cost ratio of SNG to gasoline would be the same as
that above for No. 2 fuel oil, 0.82.
Since the two techniques yielded very similar results, it was
decided to average the two cost ratios. Therefore, the SNG/un-
leaded gasoline cost ratio used will be 0.80.
These relative product values will not actually be used in
this report, since the refining of the H-Coal and SRC-II syncrudes
into usable products is beyond the scope of this report. A later
study will address the refining of syncrudes and will use these
product values to allocate costs appropriately.
III. Process Description and Economic Analysis of the H-Coal and
SRC-II Processes'
Two general processes have been historically studied to
convert coal into liquid fuels. One is indirect liquefaction,
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which is essentially coal gasification followed by catalytic
reaction of the produced synthesis gas. The second is direct
liquefaction which involves direct hydrogenation of coal to form
liquids.
Looking at direct liquefaction processes, there are three
processes receiving the most consideration today. Two of these
are the Solvent Refined Coal II (SRC-II) and the Exxon Donor
Solvent (EDS). Both are considered solvent extraction processes
which use coal-derived liquids containing hydroaromatic compounds
to transfer hydrogen to the coal, thereby producing liquid
hydrocarbons. Unconverted coal, after separation from the
extract, may be used to generate the necessary hydrogen. Hydrogen
may also be obtained from gases produced during processing, from
additional coal, or heavy petroleum products. The third direct
liquefaction process is the H-Coal process, which is a catalytic
liquefaction technique whereby hydrogen is added to the coal with
the aid of a catalyst. This reaction occurs in the liquid phase
with particulate catalysts dispersed or present in a fixed bed.[15]
The cost estimates of the products derived from two of these
processes will be discussed in detail below. First, a cost anal-
ysis of the H-Coal process will be presented, followed by a
similar analysis for SRC-II process. A product cost for each of
these processes (in terms of dollar per million BTU of product)
will be determined from a critique of the studies examining each
of these processes. Those product costs best representing 'each
process will then be adjusted according to the common set of
economic and financial parameters determined above. Analysis of
the EDS process will be performed in a separate report.
A. The H-Coal Process
The H-Coal process liquifies coal to either boiler fuel or
synthetic crude in the presence of an added particulate catalyst.
To produce synthetic crude instead of boiler fuel, more hydrogen
is added to the slurry and reactor residence times are increased.
It was developed by Hydrocarbon Research, Inc. (HRI) and was
selected by the Department of Energy for further development on a
pilot-plant scale with the participation of Ashland Oil, Mobil
Oil, Standard Oil of Indiana, Continental Coal Development
Company, the Commonwealth of Kentucky, and Electric Power Research
Institute (EPRI). Operation of the pilot plant began in June 1980
with a design capacity of 600 tons per day (TPD) feed coal at
Cattlesburg, Kentucky.[10,15]
There are five major studies which analyze the cost of the
H-Coal liquefaction process.[2,3,9,10,11] These five studies were
performed by Fluor[9], ICF[2], the Engineering Societies Commis-
sion on Energy, Inc. (ESCOE)[3], and Ashland Oil (two stud-
ies). [10,11] Each study estimates capital costs, operating and
maintenance costs, feedstock rate, product mix, and by-product
credits.
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Each study will be examined in the order described above.
After each study has been initially critiqued, the studies will be
comparatively critiqued to determine the best single cost esti-
mate. This best cost estimate will then be normalized for size,
inflation and economics according to the discussion in Section II
above.
1. Fluor[9]
This study was prepared by Fluor Engineers and Constructors,
Inc. for the Electric Power Research Institute (EPRI). Fluor
obtained field data from Hydrocarbon Research for the technical
and economic evaluation of the H-Coal process. Fluor's scope-of-
work included development of the overall plant configuration for
large commercial facilities to produce hydrocarbon liquids from
14,448 TPD of two different coals, Illinois No. 6 (bituminous) and
Wyodak (subbituminous). Actual production from these feed rates
were estimated by Fluor to be 43,000 barrels per day (BPD) from
the Illinois No. 6 coal, and 35,000 BPD from the Wyodak. The
plants were operated in the syncrude mode and employed the latest
yield data generated by HRI's process development unit at Trenton,
New Jersey at the time the report was written (Dec. 1979).
Fluor prepared detailed material and energy balances for each
of the two cases. Each case was designed to be self-sufficient
with respect to its internal requirements of hydrogen, fuel, elec-
tric power, steam, and other utilities. Hydrogen was produced via
the gasification of vacuum bottoms using Texaco technology, while
electric power was produced from combined-cycle gas turbines fired
by process-derived fuel gas.
In each case, Fluor's work showed that the major products
produced included naphtha, turbine oil and distillate fuel oil,
while the Illinois case also produced a substantial amount of
LPG. The breakdown of products for each case are shown in Table
3. Overall thermal efficiencies (using higher heating values
(HHV)) of 68.4 and 60.9 percent were determined by Fluor for the
Illinois and Wyodak cases, respectively.
Fluor stated that researchers have generally observed that
the Wyodak coal is not as favorable to use in the liquefaction
process as is the Illinois coal. Although this phenomenon is
some- what less observed in the catalytic H-Coal process, use of
the Wyodak coal is still considered economically inferior to use
of the Illinois No. 6 coal. Fluor stated that this may be related
to the higher oxygen content of the coal that reacts to form
water, resulting in increased hydrogen consumption. However,
although economic considerations for Wyodak coal are not favorable
at present, Fluor believed that future commercial developments may
occur if conditions are found that favor oxygen removal in the
form of carbon monoxide. For purposes of this analysis, then, the
Wyodak case will still be presented, though it should be remem-
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Table 3
Product Slate of the H-Coal Liquefaction Process
(Barrels Per Day of Fuel Oil Equivalent*)
Product
Feed Rate
(Tons/Day)
Naptha
Turbine Oil
Distillate
Fuel Oil
Butane
Propane
LSR Gasoline
Reformate
Total
By-Products
Sulfur (TPD)
Phenols (TPD)
Ammonia (TPD)
Fluor[9] ICF[2] ESCOE[3]
Illinois Wyodak Illinois Wyodak Illinois
No. 6 Coal Coal No. 6 Coal Coal No. 6 Coal
14,448 14,448 16,370 20,548 25,000
13,392 15,952 15,173 22,700 31,900
16,235 12,366 18,395 17,600
8,761 6,842 9,926 9,700 24,300
3,350 — 3,796
2,392 — 2,710
—
— — — — —
44,130 35,160 50,000 50,000 56,200
493
40
165
Ashland [10, 11]
Illinois
No. 6 Coal
18,000
26,300
4,300
6,500
3,750
11,500
52,350
535
100
200
Pipeline Gas
(MMSCFD)
Ethane (MMSCFD)
56.3
32
One fuel oil equivalent barrel contains 5.9 million Btu.
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bered that it assumes that a number of technological breakthroughs
will occur.
The capital cost estimates made by Fluor for an Illinois No.
6 and a Wyodak coal liquefaction plant were determined in
mid-1979 dollars. The capital costs for the Illinois coal plant
was based on an Illinois location on a clear and level site,
receiving coal by railway. The capital cost for the Wyodak coal
plant assumed that coal would be received via conveyer from a
nearby surface mine. The total capital requirement estimated by
Fluor included total plant investment, prepaid royalties,
preproduction costs, working capital, initial chemical and
catalyst charge, allowance for funds during constructions, and
land. The total plant investment included process plant
investment and general (or offsite) facility costs (excluding
contingency). The process plant investment included the total
constructed costs of all onsite processing and generating units,
including all direct and indirect construction costs and all
engineering and home office fees. Taxes (5 percent of total
material) were also included.
Fluor's estimates for the total capital costs for both the
Illinois and Wyodak coal liquefaction plants are shown in Table
4. The total instantaneous capital cost were estimated to be
$1194 million and $1262 million (without a contingency factor) for
Illinois and Wyodak coal, respectively. The operating costs as
estimated by Fluor were divided into fixed and variable costs, to
be estimated on a first year basis. The fixed operating costs
included operating labor, maintenance, and overhead charges. The
average labor rate was estimated at $12.50 per hour (in mid-1979
dollars). Annual maintenance costs were estimated as a percentage
of the installed capital cost of the facilities. Overhead charges
included administrative and support labor, and general and admini-
strative expenses. The variable operating costs included the cost
of raw water, consumable catalysts and chemicals, and ash dis-
posal. By-product credits included the value of ammonia and raw
phenols.
The fixed and variable operating costs for both types of
plants are shown in Table 5. The fixed operating costs were
estimated to be $66 million and $70 million per year, while the
variable operating costs, excluding feedstock, were estimated to
be $15 million and $14 million per year, for Illinois and Wyodak
coal, respectively.
2. ICF[2]
An investigation of the ICF study found that all process cost
estimates were taken directly from the Fluor study above. These
process costs were then adjusted by ICF to a production of 50,000
barrels per day. ICF used an average scaling factor of 0.830 to
adjust capital costs. ICF also adjusted all product costs accord-
ing to their own financial inputs and assumptions. ICF did not
perform any additional research into the process itself.
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Table 4
Capital Costs - H-Coal (As Estimated by Fluor[9])
(Mid-1979 Dollars)
Illinois #6 Coal Wyodak Coal
(million dollars) (million dollars)
Total Plant Investment 904.7 943.3
Prepaid Royalites 3.3 3.6
Preproduction Costs 32.5 34.7 .
Inventory Capital 42.7 40.3
(Working Capital)
Initial Catalysts 6.9 7.3
and Chemicals
Allowance for Funds 201.9 231.7
During Construction
Land 1.8 1.8
Total Capital Requirement $1194 $1262
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Table 5
Fixed and Variable Operating Costs
(As Estimated by Fluor)[9]
(Mid-1979 Dollars)
Fixed Operating Costs,
^Million/Year Illinois #6 Coal Wyodak Coal
Operating Labor 9.0 9.0
Maintenance Labor 14.3 15.5
Maintenance Materials 21.4 23.2
Administrative and Support Labor 7.0 7.3
General and Administrative Expense 13.9 14.7
Total Fixed Operating and
Maintenance, First Year 65.6 69.7
Variable Operating Costs
Excluding Feedstock (First
Year), ^Million/Year
Water 1.0 0.9
Catalysts 11.9 12.1
Ash Disposal 2.3 1.4
Total Variable (excluding feedstock) 15.2 14.4
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ICF's product slate is shown in Table 3. It is the same as
Fluor's product slate, scaled up to a production of 50,000 barrels
per day. ICF's capital costs (without contingency) are shown in
Table 6. Note that, unlike Fluor, ICF does not include prepro-
duction costs, inventory capital, initial catalyst and chemical
costs, allowance for funds during construction and land costs.
ICF did not explain the elimination of these costs.
The fixed and variable operating costs are shown in Table 7.
All costs are in mid-1980 dollars. According to ICF, the capital
costs of an H-Coal plant were estimated to be $1101 million and
$1520 million for Illinois and Wyodak coal, respectively. Total
operating costs were estimated to be $86.2 million and $91.4
million for Illinois #6 and Wyodak coal, respectively.
3. ESCOE[3]
Similar to ICF, ESCOE also used the Fluor study as a refer-
ence for their process cost estimates. In addition, ESCOE derived
many of their cost estimates from a 1976 Bureau of Mines
report. [16] ESCOE scaled their cost estimates to a feed rate of
25,000 tons of coal per day, which leads to a. production of 31,900
FOEB/D naphtha, 24,300 FOEB/D fuel oil, and 56.3 million standard
cubic feet per day (mSCF/D) natural gas as shown in Table 3.
ESCOE also adjusted costs according to their own financial param-
eters and according to their specified product values with gaso-
line as a reference price. ESCOE did not specify what type of
coal was used as feed.
ESCOE estimated the capital costs to be $1134 million in 1978
dollars. ESCOE only broke down these capital costs by process
unit. Fixed and variable operating costs were estimated to be
$103 million and $178 million, respectively. ESCOE did not
include other operating costs such as water and ash disposal.
ESCOE's cost estimates are shown in Table 8.
4. Ashland Oil[10,11]
Ashland Oil recently released two studies on the commercial
H-Coal liquefaction plant which is planned to be built in Breckin-
ridge County, Kentucky (and hence is called the Breckenridge
Project). The first study was an in-depth analysis of the tech-
nology, economics, and environmental impact of the H-Coal plant
(released in March, 1981).[10] The second study was an updated
version of the first study, and was presented at an American
Petroleum Institute meeting in Chicago on May 13, 1981.[11]
According to the Ashland reports, the Breckinridge Project
facilities will be owned by the Breckinridge Energy Company (BEG),
a partnership which currently includes Ashland Oil, Inc., through
its subsidiary, Ashland Synthetic Fuels, Inc. (ASFI); and Airco
Inc., through its subsidiary, Airco Energy Company, Inc. The
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Table 6
Capital Costs - H-Coal (As Estimated by ICF)[2]
(Mid-1980 Dollars. Millions of Dollars)
Plant Selection
Coal Preparation
Liquefaction
Light Ends Processing
Hydrogen Plant
Oxygen Plant
Emission Control System
Effluent Control System
Storage
Utilities
Offsites
Prepaid Royalties
Total*
Illinois
No. 6 Coal
45
345
41 .
206
100
21
40
48
156
94
5
1101
Wyodak
Coal
96
464
15
304
119
17
34
25
188
250
8
1520
* Does not include contingency.
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Table /
Fixed and Variable Operating Costs for H-Coal
(As Estimated by ICF) (Mid-1980 Dollars)[2]
Fixed Operating Costs,
^Million/Year
Operating Labor
Overhead
Maintenance
Total, First Year
Variable
Water
Power
Catalysts and Chemicals
Ash Disposal
Total (excluding feedstock)
Illinois #6 Coal
8.2
22.6
38.6
69.4
1.2
0
14.7
0.9
16.8
Wyodak Coal
8.2
24.0
41.9
74.1
1.3
0
17.3
0
17.3
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Table 8
Fixed and Variable Operating Costs for H-Coal
(As estimated by ESCOE) (Mid-1978 Dollars)[3]
Capital Cost
Plant Capital Requirements
Coal Preparation
H2 or Gasification
02 Plant
Gas Shift
Acid Gas and Sulfur Plants
Reactor Section
Gas Plant
Pollution Control
Total
Other
Total Capital Cost
Fixed Operating Costs
($ Millions/Year)
Labor
Maintenance
Local Tax and Insurance
Total, First Year
Variable
Catalyst and Chemicals
Total
Illinois No. 6
484
158
87
35
57
210
25
40
696
438
1134
12.2
34.3
57.0
103.5
7.0
7.0
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venture will eventually be expanded to at least five partners.
Under the partnership agreement, and consistent with the policy
followed during the initial effort, ASFI will be the operator with
responsibility for managing detailed engineering, procurement,
construction, and operations.
The plant is to be located on the Ohio River near Addison, in
western Kentucky. Work that is currently underway at the location
includes soil survey work, baseline environmental data collection,
and socioeconomic studies. According to Ashland, preliminary
studies indicate that no serious environmental or socio-economic
problems exist. Ashland stated that discussions with local and
state officials make it clear that support from these groups is
strong. Construction of the commercial plant was projected by
Ashland to begin in 1983. Ashland estimated that by 1988
construction should be completed followed by efforts for plant
startup. The plant was projected to be operating at full capacity
in 1991.
In its base case configuration Ashland designed the plant to
operate on 18,000 TPD of washed Illinois no. 6 coal and other
various Illinois Basin coals. The product slate is shown in Table
3. The LSR gasoline and reformate are already refined products,
while the rest of the product slate must undergo further refin-
ing. The production of by-products include 100 TPD of phenols,
200 TPD of ammonia, 535 TPD of sulfur, 32 mSCF/D of pipeline gas,
and 8 mSCF/D of ethane. Alternative product slates presently
being evaluated by Ashland would provide for the additional
production of benzene, toluene, and xylene. The thermal effi-
ciency of the process was estimated to be 63.1 percent.[17]
In their first study, Ashland's design efforts included
extensive use of computer simulations based upon experimental data
and has produced what they believe to be the most accurate
information on the Breckenridge project presently available.
Ashland presented costs based on estimates completed in 1980,
which were then adjusted to 1981 dollars according the Gross
National Product (GNP) deflator. In their second study, Ashland
determined costs directly in 1981 dollars based on more recent
process data. Because the costs in the second study represent
more recent estimates and are based on the most recent data, these
costs will be presented below instead of those from the first
study.
Total instantaneous plant capital cost was estimated by
Ashland to be $3.3 billion. Ashland included in this cost a
contingency for construction costs overruns of approximately 15
percent plus a provision for working capital. A summary of the
project capital cost is shown in Table 9.
This capital cost included the cost of a reformer to refine
light naphtha to reformate. This cost has not been included in
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-18-
Table 9
Total Project Costs
(As estimated by Ashland) (January, 1981 Dollars)[11]
Direct Costs:
Liquefaction Plant
Oxygen and Hydrogen Plants
Other Refinery Units
Tankage, Interconnecting Piping
Coal Handling, Boilers
Wastewater/Solids Treating
Other Offsites
Total
Field Indirects
Miscellaneous Field Costs
Engineering and Fee
Contingency
Total Installed Cost
Working Capital
Total Project Cost
^Million
690
320
125
120
360
200
185
2000
400
80
280
400
3160
140
3300
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-19-
the other previous studies (Fluor, IGF, and ESCOE). (A later
report will consider the cost of refining syncrudes and will
consider the degree to which the various synthetic petroleum frac-
tions have been refined at the liquefaction plant.) A breakdown
of the cost of the general processing units is also shown in Table
9.
Total annual operating costs were estimated to be $126
million and are summarized in Table 10. Excluded by Ashland from
the annual operating costs are the coal feedstock costs and the
capital recovery charges.
5. Adjustment and Comparison of Each Study
The costs presented in each of the four H-Coal analyses will
be adjusted in this section to the common plant size and financial
parameters as discussed in section II above. For convenience,
capital costs will be left as instantaneous costs until the most
representative study is selected. Coal costs and by-product
credits will also not be included until later.
Once each of the above four analyses have been adjusted, the
most representative study will be determined. This selected best
study will then be adjusted for lifetime capital costs and
calendar day operations, with feedstock costs and by-product
credits also included. A product cost will then be determined for
this selected study. The capital and operating costs, as origin-
ally estimated by each study, are summarized for convenience in
Table 11.
The adjusted product slates and costs for each study are
shown in Table 12 and 13, respectively. With respect to the Fluor
study, instantaneous capital costs were adjusted with a scaling
factor of 0.75 and a 15 percent contingency. Labor costs were
adjusted with a scaling factor of 0.2. Water, catalyst, and ash
disposal costs were adjusted proportionally to plant size. Work-
ing capital was estimated at 6 percent of operating and main-
tenance costs. Remaining costs were assumed to be the same
percentage of plant investment for each plant size. All costs
were inflated from 1979 to 1981 dollars.
Since the costs estimated by ICF already presumed a producton
of 50,000 BFOE/D, their costs did not have to be adjusted for
plant size. Only a 15 percent contingency was incorporated along
with inflation from 1980 to 1981 dollars. Also, in determining
maintenance labor costs it was assumed that maintenance labor was
40 percent of total maintenance costs, the same percentage used in
the Fluor study.
ESCOE's cost estimates had to be scaled down from a produc-
tion of 56,200 FOEB/D to the desired production of 50,000 FOEB/D.
The scaling factors described in Section II were used
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Table 10
Annual Operating Costs[11]
(January, 1981 Dollars)
Power Annual Catalyst and Chemicals $ 4,623,500
Direct Labor and Supervision 10,697,800
Plant Maintenance (Includes Labor, 43,935,400
Supervision, Materials and Contractor
Maintenance)
Payroll Overhead and Operating Supplies 12,515,100
Indirects, G&A 7,016,700
Local Taxes and Insurance 47,511,500
Total* 126,300,000
Includes a 15 percent contingency.
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Table 11
Summary of H-Coal Capital and Operating Costs,
As Estimated by Each Study
Flour
Coal Type
Year
Thermal
Efficiency
Total Production
(BPD/FOE)
Capital Cost
(^Million)
Plant
Other
Operating Costs
($Million/Yr)*
Fixed
Variable
Illinois
No. 6 Coal
Mid-1979
68.4%
44,130
905
289
65.6
15.2
Wyodak
Coal
Mid-1979
60.9%
35,160
943
319
69.7
14.4
ICF
Illinois
No. 6 Coal
Mid-1980
68.4%
50,000
846
255
69.4
16.8
Wyodak
Coal
Mid-1980
60.9%
50,000
1074
446
74.1
17.3
ESCOE
Illinois
No. 6 Coal
Mid-1978
NA
56,200
696
438
103.5
7.0
Ashland
Illinois
No. 6 Coal
1st Q 1981
63.1%
52,350
2000
1300
121.7
4.6
Excludes feedstock costs.
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Table 12
Adjusted H-Coal Product Slates
Based on 50,000 BPD/FOE Commerical Plant Size
Product
BPD/FOE
Naptha
Turbine Oil
Distillate
Fuel Oil
Butane
Propane
LSR Gasoline
Ref ormate
Total
By-Products
Sulfur
Phenols
Ammonia
Pipeline Gas
Flour
Illinois Wyodak
No. 6 Coal Coal
15,173 22,685
18,395 17,585
9,926 9,730
3,796
2,710
—
— —
50,000 50,000
(TPD)
559 58
45 23
187 166
— —
ICF
Illinois Wyodak
No. 6 Coal Coal
15,173 22,700
18,395 17,600
9,926 9,700
3,796
2,710
—
— • —
50,000 50,000
559 58
45 23
187 166
— —
, Ashland
Illinois
ESCOE No. 6 Coal
28,380
—
21,620 26,300
4,300
6,500
3,750
11,500
50,000 50,000
N/A 535
N/A 100
N/A 200
56 32
(MMSCFD)
Ethane (MMSCFD)
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Table 13
Adjusted H-Coal Cost Estimates
Based on 50,000 BPD/FOE Commerical Plant Size
Flour
Illinois
No. 6 Coal
Capital Costs
(^Millions of
1981 Dollars)
Plant Investments 1,180
Other 382
Contingency 234
Total 1,796
Operating Costs
(^Millions of
1981 Dollars)
Fixed
Operating
Labor & Main-
tenance Labor 30.4
Other 55.2
Variable
Water,
Catalyst, etc. 20.5
Working
Capital 6.4
Total 112.5
Coal Feed Rate 16,370
ICF
Wyodak Illinois Wyodak
Coal No. 6 Coal Coal
1,459 922 1,171
494 288 486
293 180 248
2,246 1,380 1,906
31.2 25.8 27.2
69.9 49.9 53.6
20.5 18.3 18.9
7.3 5.6 6.0
128.9 99.6 105.7
20,550 16,370 20,550
Ashland
Illinois
ESCOE No. 6 Coal
811 1,740
510 1,130
198 430
1,519 3,300
32.2 28.3
82.4 93.4
7.9 4.6
7.4 7.6
129.9 133.9
22,242 18,000
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with a 15 percent contingency on capital costs. Maintenance labor
was also estimated at 40 percent of total maintenance cost.
The total production in the Ashland studies is very close to
the desired production rate of 50,000 FOEB/D and, for purposes of
this study, will not be modified. Also, all of Ashland's costs
were already in 1981 dollars and included a 15 percent contin-
gency, so they required no further adjustment.
Of the above four sets of studies, ICF and ESCOE did not
perform their own engineering cost estimates. ICF based all their
process cost estimates on the Fluor estimates, while ESCOE incor-
porated some of Fluor's work along with a Bureau of Mines study
into their overall cost estimate. Thus, the ICF and ESCOE studies
will not be assessed at this point until the firsthand studies of
Fluor and Ashland are further analyzed.
Both Fluor's and Ashland's estimates will be briefly reviewed
here. In the Fluor study, two types of coal feeds were
considered, Illinois No. 6 coal and Wyodak coal, while Ashland
only considered costs for Illinois No. 6 coal as feed. Of the two
sets of studies, the Ashland analyses should represent the most
accurate process costs of H-Coal liquefaction, primarily because
the Ashland studies are more recent (1981). Although the Fluor
study is fairly recent (1979), the projected technology and costs
have changed dramatically even within two years (i.e., from
1979-1981). Costs associated with the updated technological and
process developments have escalated much more rapidly than infla-
tion as indicated by the differences in the costs shown in Tables
4 and 9. The Ashland estimates will be selected as the more
representative of the two.
The ICF and ESCOE studies should also be eliminated from
further consideration for the same reason. The ICF study was
based on the Fluor estimates which are now out of date. ESCOE's
cost estimates were based on Fluor's estimates and an even older
1976 Bureau of Mines report with costs simply inflated to the year
of ESCOE's study, or 1978.
Because the Fluor estimates for the Illinois coal case were
eliminated above due to outdated cost information, their estimates
for the Wyodak coal case should also be eliminated for the same
reason. However since Ashland has not examined Wyodak coal as a
feed, there would appear to be no up-to-date estimate of H-coal
process costs for Wyodak coal. The only thing that can be said at
this time is that it is likely that the processing of Wyodak coal
would be more expensive and less efficient than Illinois coal,
based on the Fluor results.
An overall product cost will now be estimated for the H-Coal
process based on the Ashland estimates. The instantaneous capital
cost and operating costs have already been determined in Table
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13. To obtain the annual capital charge, the interest during
construction and the capital charge rate must be applied to the
instantaneous capital cost. The result of this for each financial
scenario is shown in Table 14, along with the previously deter-
mined operating costs.
The feedstock rate has already been determined to be 18,000
TPD, which amounts to 5,940,000 tons per year, based on 365 day
per year operation. At a coal price of $27.50 per ton, the total
annual feedstock cost would be $181 million per year. The annual
by-product credit is based on a value of $50 per ton for sulfur,
$180 per ton for ammonia, and $113 per barrel of phenol. Based on
the rates of production presented above (see Table 12), total
annual by-product credit is $13 million per year. Pipeline gas
(SNG) and ethane will be considered products and will be included
in the total energy output of the plant.
The total annual cost is the sum of the annual capital, oper-
ating, and feedstock costs, less the by-product credits. This
amounts to $1402 million per year for the high capital charge rate
case and $732 million per year for the low capital charge rate
case.
The energy value of the product is estimated to be approxi-
mately 122,275,000 million BTU per year, based on a 50,000 FOEB/D
(5.9 million BTU per FOEB) plus the SNG and ethane. The total
product cost is then $11.47 per million BTU for the high capital
charge rate case and $5.99 per million BTU for the low capital
charge rate case.
B. The SRC-II Process
The SRC process is being developed by Pittsburg and Midway
Coal Mining Company, a subsidiary of Gulf Oil Corporation, under
DOE sponsorship. The SRC-II process converts coal to liquid and
gaseous products by dissolving finely-ground coal and mixing it
with recycled process solvent. Hydrogenating and hydrocracking of
the dissolved coal takes place at an elevated temperature and
pressure. Catalytic activity in recycle slurry enhances hydrogen-
ation and hydrocracking. Inorganic matter in the feed coal also
accelerates these reactions.[15,18]
In the process, raw coal is ground to fine particles and is
then mixed with hot-recycle slurry in a mix tank. This mixture of
coal and recycle slurry is pumped together with hydrogen through a
fine preheater to a reactor maintained at about 460°C (860° F) and
2000 psig. Upon exiting the preheater, the pulverized coal is
almost completely dissolved in the solvent portion of the recycle
slurry. Highly exothermic hydrocracking reactions occur in the
reactor, allowing the temperature at the outlet of the preheater
to be considerably lower than the required reactor temperature.
Hydrogen is injected into the reactor for temperature control and
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Table 14
Overall Product Cost of the H-Coal
Process Based on Ashland Estimates ($1981)
Instantaneous Capital
Cost (^Billion)
Annual Capital Charge
(millions per year)
Operating Costs
(millions per year)
Feedstock Cost
(millions per year)
By-Product Credit
(millions per year)
Total Annual Cost
(millions per year)
Average Product Cost
(per mBtu)
Low Cost
Case
3.3
430
134
181
(13)
732
5.99
High Cost
Case
3.3
11(0
134
181
(13)
1402
11.47
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to maintain adequate gas distribution, as well as to promote the
hydrocracking reactions. The reactor effluent flows through a
series of vapor-liquid separators, where it is ultimately separ-
ated into process gas, light hydrocarbon liquids and slurry.
The process gas consists primarily of hydrogen and gaseous
hydrocarbons, together with minor amounts of hydrogen sulfide and
carbon dioxide. It is cooled to about 38° C (100° F) and goes
through an acid gas removal step for removal of hy*. :ogen sulfide
and carbon dioxide. The treated gas passes througf a cryogenic
separation step for removal of the hydrocarbons. The purified
hydrogen is recycled to the process, while the hydrocarbons are
recovered as products.
Any remaining carbon monoxide is converted to methane and is
then sold as pipeline gas (SNG). The other light hydrocarbon
gases are fractionated to produce ethane, propane, and butane
streams. All of the light hydrocarbon liquid collected from the
various condensation steps, plus the overhead stream from the
vacuum tower (below) are sent to the fractionator. In the
fractionator, the total liquid product is separated into naphtha,
middle distillate, and heavy distillate.
The product slurry is split, with one portion being recycled
to the process for slurrying with the feed coal. The other
portion of the product slurry goes to a vacuum tower where the
lighter portion of the distillate is removed overhead and sent to
the fractionator. A heavy distillate product is removed as a
sidestream. Residue from the vacuum tower is converted into
synthesis via gasification gas. A portion of this gas is used to
produce hydrogen for the process. The synthesis gas in excess of
that required for hydrogen production is purified and burned as a
plant fuel.
There are six major studies which specifically analyze the
costs of the SRC-II liquefaction process. These studies include
two by Pittsburg and Midway Coal Mining Co., one by Ralph M.
Parsons Co., an ICF study, an ESCOE study and a recent DOE study.
Each study estimates a final product cost (in terms of dollars per
million BTU) based on capital costs, operating and maintenance
costs, feedstock costs, and by-product credits.
First, the two Pittsburg and Midway Coal studies will be
examined, followed by the Parsons study, the ICF report, the ESCOE
report and the DOE report. After these studies have been
critiqued and partially adjusted for comparison purposes, the
study with the most accurate estimates will be selected. As was
done with the H-Coal process, cost estimates from the selected
study will be adjusted according to all of the input factors
determined in section II. A final product cost will then be esti-
mated.
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1. Pittsburg and Midway Coal Mining Company[12,18]
Two studies of the SRC-II process were recently completed by
Pittsburg and Midway Coal Mining. The first study, performed
under contract with DOE, was a 1979 study which gave a detailed
analysis of the SRC-II Conceptual Commercial Plant.[12] Pittsburg
and Midway stated that the Conceptual Commercial Plant produces a
product slate including SNG, butane LPG, low sulfur fuel oil, an
ethane-propane light hydrocarbon stream and a naphtha stream, as
well as sulfur, ammonia, and tar acid by-products. The ethane-
propane light hydrocarbon stream and the naphtha stream could both
be burned directly as fuel products. However, Pittsburg and
Midway stated that they are both readily capable of being upgraded
to higher valued products by known technology. A detailed econom-
ic analysis was also included in this study by Pittsburg and
Midway, with capital costs and annual operating and maintenance
expenses.
The second study,[18] completed in 1980, was essentially an
updated version of the first study, and although it was not as
detailed, it still addressed the areas of importance for purposes
of this study. The cost estimates of the second study will be
used here except where they are not addressed. In these cases,
the costs from the more detailed first study will be used.
The economic analysis for a commercial-size plant completed
by Pittsburg and Midway mining was based on work prepared for the
6,000 ton per day demonstration plant which to be located near
Morgantown, West Virginia. This commercial-size plant would
process West Virginia area coal (Powhatan Coal, 12,813 BTUs per
pound) at a rate of 33,500 tons per stream day (330 days per
year). Pittsburg and Midway estimated the thermal efficiency of
the process to be 72 percent, producing the product slate shown in
Table 15. On an energy basis, this amounts to a total production
of 100,000 FOEB/D.
The investment and operating costs for the conceptual commer-
cial plant as estimated by Pittsburg and Midway mining were based
on a design developed by assuming that the key process steps will
be successfully demonstrated in the mid-1980's in the 6,000 T/D
demonstration plant, and that the first commercial plants will be
built and operating in the early 1990's. The direct capital cost
estimates were those costs which would normally be incurred for
engineering, procurement, and construction. They included direct
field costs, indirect field costs, and engineering costs. The
indirect capital cost estimates included catalyst and chemicals,
license, owner management costs, land, and working capital.
Indirect field costs included field staff costs, field office
expenses, payroll taxes, insurance, performance bonds, consumable
supplies, temporary facilities, construction equipment rental, and
small tools. No precommissioning or commissioning costs have been
included.
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Table 15
Product Slate of the SRC-II Liquefaction Process
(Barrels Per Day of Fuel Oil Equivalent)
Pittsburg
Product and Midway [13]
Naptha
Fuel Oil
Residual
LPG (Ethane/
Propane)
Butane
Methane
(MMSCFD)
Total
By-Product (TPD)
Sulfur
Ammonia
Phenols
Tar Acids (BPD)
Feed Rate (TPD)
17,000
56,000
—
22,000
3,000
50
100,000
1,200
180
—
240
33,500
Par sons [14]
5,148
11,253
33,680
—
—
—
50,000
N/A
N/A
N/A
N/A
17,232
ESCOE[3] ICF[2] DOE [22]
10,700 8,700 3,050
45,300 36,800 10,030
—
5,500 4,500 3,900
500
10
61,500 50,000 18,000
854 694 215
283 230 30
69 56
43
25,000 20,325 6,000
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Engineering costs were estimated as a percentage of total
field costs (the sum of direct and indirect field costs). The
total estimate included approximately 3,964,000 engineering hours
for the engineering/construction contractor.
The total instantaneous direct capital investment, including
a 20 percent contingency, was $1794 million in 1st quarter 1980
dollars. A breakdown of these costs are shown in Table 16. The
total indirect investment is $190 million.
The total instantaneous capital costs were then $1.98
billion, based on a production of 100,000 barrels of fuel oil
equivalent per day.
The annual operating costs (fixed and variable) were esti-
mated with appropriate contingencies included, in accordance with
DOE guidelines. The operating labor and supplies included an
average operator rate plus adjustment for idle time, fringe bene-
fits, and contingency. Operating supplies were calculated at 10
percent of operating labor. Maintenance labor were also included
in operating costs, based also on an average rate for maintenance
work, plus adjustments for idle time, fringe benefits and contin-
gency. Maintenance materials were assumed to be 2 percent of
total depreciable investment including catalysts and chemicals and
owner management costs but excluding license fees and land.
Contract maintenance was also estimated in this cost at the same
number of workers as the direct-fire plant maintenance work
force. Catalysts chemicals, electricity (at $0.035 per KWH), and
property taxes and insurance (at 1.5 percent of fixed capital
investment) were also included in the operating costs. The total
annual operating costs, without feedstock, was estimated to be
$110 million per year (1980 dollars).
In summary, the total instantaneous capital cost was esti-
mated to be $1.98 billion and the total operating cost was esti-
mated to be $110 million, without feedstock, in 1980 dollars.
These cost estimates will be compared later to the remaining four
studies below (Parsons, ICF, ESCOE and DOE).
2. Parsons[19]
A study sponsored by EPRI was prepared by The Ralph M.
Parsons Company of Pasadena, California. In this study, two cases
were developed for the SRC-II process: a case to represent normal
operations required to maximize the production of heavy fuel oil
and a case at more severe operating conditions to lower the sulfur
content of the products and increase the yield of liquid fuel
products (i.e., in the syncrude mode). For purposes of this anal-
ysis, only the case where the low sulfur content is produced will
be considered. This case produces a crude more similar to petro-
leum than the first case which can be later refined to a usable
transportation fuel.
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Table 16
Capital Investments for SRC-II (As Estimated by
Pittsburg and Midway Coal Mining Company) [13]
33,500 T/SD
West Virgina Coal
Millions of Dollars
(First Quarter 1980)
Coal and Ash Handling 86
Hydrogenation 707
Hydrogen Production 480
Refining and Gas Recovery 161
Secondary Recovery 94
Utilities and General Facilities 266
Total Direct Investment 1794
Indirect Investment 190
Total $1984
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A factored cost estimate was prepared by Parsons in the EPRI
study. For process units that were under pilot plant development,
major equipment was sized and factored to an installed cost.
Process units that were commercially demonstrated were factored
from previously developed cost estimates. The estimates assumed a
complete, self-sustaining plant which included the generation of
all power required for their operation. The plant capacities were
based on a normal output of 50,000 FOEB/D.
The products in this study were based on an experimentally
achieved 69.9 percent overall thermal efficiency. The products
were 33,680 BPD of residual oil, 11,253 BPD of fuel oil, and 5,148
BPD of naptha. The coal feed rate was 17,232 tons per day. These
are shown in Table 15.
The total capital costs as estimated by Parsons are shown in
Table 17. The total capital costs were defined as the sum of
total plant investment, royalty allowance, preproduction costs,
working capital, construction loan interest, capital cost escala-
tion and land. The total plant investment was the sum of total
constructed cost, home office engineering and overhead, contin-
gency and sales tax. These costs are mid-1976 estimates.
The home office engineering and overheads were estimated at
nominally 15 percent of total constructed costs based on Parsons
experience. This charge covered the cost of management and admin-
istrative, process and project engineering, construction support,
design, drafting, accounting, estimating, scheduling, cost
engineering, procurement, expediting, inspection, stenographic and
clerical expense, printing, reproduction, computer charges,
communications and travel.
Contingency was also included in the capital costs, estimated
to be 15 percent of the sum of total constructed costs and home
office engineering and overhead. Sales tax were estimated at 5
percent of direct material costs. Royalty allowance was arbi-
trarily taken at 0.5 percent of total plant investment. Land
requirements were estimated at two sections (1280 acreas) which
presumably could be purchased for $2,500/acre. The total instan-
taneous capital cost was estimated to be $1.61 billion (1976
dollars).
The annual operating costs were also calculated by Parsons
based on a 90 percent onstream factor, and are shown in Table 18.
The total direct operating costs included washed coal, residue
disposal, raw water, catalyst and chemicals, operating labor
requirements, and maintenance labor and materials. The total
annual direct costs were estimated to be $57 million (1976
dollars) without the cost of feedstock. The indirect costs
include administrative and support labor, general and admini-
strative expenses, and property tax and insurance. The total
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Table 17
SRC-II Capital Cost Estimates
(As Estimated by Parsons)[14] Mid-1976
(^Million)
Total Constructed Cost: 867
Home Office Engineering 130
Contingency 150
Sales Tax 26
Total Plant Investment: 1173
Royalty Allowance 6
Preproduction Costs 76
Working Capital 85
Construction Loan Interest 269
Capital Cost Escalation 0
Land 3_
Total Capital Requirement $1612
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Table 18
SRC-II Annual Operating Cost, Excluding Feedstock
(As Estimated by Parsons)[14]
(Millions of
Direct Costs 1976 Dollars)
Residue Disposal 0.869
Water 1.314
Catalyst and Chemicals 17.500
Operating Labor 18.528
Maintenance Labor and Materials 18.499
Total Direct Costs 56.710
Indirect Costs
Administrative and Support Labor 5.558
General and Administrative Expense 11.116
Property Taxes, and Insurance 29.336
Total Operating Cost 102.72
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-35-
indirect expenses are $46 million. The total annual operating
costs are then $103 million (1976 dollars), without feedstock
costs.
3. ESCOE[3]
ESCOE's cost data was obtained directly from a process devel-
oper. However, ESCOE did not mention who the developer was and
they merely present the data without explanation. ESCOE's costs
were based on a coal feed rate of 25,000 tons of coal per day, and
which resulted in a production of 61,500 FOEB/D. The product mix
is shown in Table 15.
Although ESCOE did not go into great depth about how their
cost estimates were obtained, they did nevertheless present esti-
mates for capital and operating costs (in 1978 dollars). The
instantaneous capital cost was $1.26 billion. Annual operating
costs (except for feedstock) amounted to $6.0 million for
catalysts and chemical, $12.2 million for labor, $38.2 million for
maintenance, and $63 million for local tax and insurance. Total
annual operating costs were $119 million. These costs are shown
in Table 19.
4. ICF[2]
The ICF report based their cost estimates on the ESCOE study
just analyzed above, adjusted to ICF's own financial parameters
and a production volume of 50,000 BPD. ICF used an average
scaling factor of 0.830 to adjust capital costs. They did not
perform any additional research into the actual process. The
product slate of ICF is shown in Table 15 and the capital and
operating costs are shown in Table 20.
5. DOE[20]
DOE has released a very recent cost estimate for the 6,000
TPD demonstration plant located near Morgantown, West Virginia
which was being planned cooperatively with Pittsburg and Midway
Mining. These updated cost estimates were provided to the Senate
Committee on Appropriations, Subcommittee on Interior and Related
Agencies following the March 25, 1981 testimony of Roger W. A. Le
Gassie, DOE's Acting Assistant Secretary for Fossil Energy.
This release by DOE was very brief and did not go into detail
about the SRC-II demonstration plant project. However, much of
the technical analyses and results found in the Pittsburg and
Midway studies should also apply here relative to the plant size
and product slate. Other parameters, such as coal type, should
also be identical in both cases.
The breakdown of capital and operating costs (in Ist-quarter
1981 dollars) is shown in Table 21. Capital costs total $1.99
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-36-
Table 19
Capital and Operating Costs for SRC-II
(As Estimated by ESCOE) (Mid-1978 Dollars)[3]
Cost (Million
Capital Cost Dollars Per Year)
Plant Capital Requirements .
Coal Preparation 63
H2 or Gasification 253
02 Plant 129
Gas Shift
Acid Gas and Sulfur Plants 60
Reactor Section 195
Gas Plant 30
Pollution Control 44
Total 774
Other 488
Total Capital Cost 1262
Fixed Operating Costs
($ Millions/Year)
Labor 12.2
Maintenance 38.2
Local Tax and Insurance 53.0
Total, First Year 113.4
Variable
Catalyst and Chemicals 6.0
Total 6.0
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Table 20
Capital and Operating Costs for SRC-II
(As Estimated by IGF, Mid-1980 Dollars)
Capital Costs Cost
Plant Selection
Coal Preparation 63
Reaction Section 195
Light Ends Processing 30
Hydrogen Plant 254
Oxygen Plant 129
Emission Plus Effluent Control System 104
Storage 36
Total Plant Investment 775
Utilities 369
Offsites 109
Prepaid Royalties 7_
Total 1260
Fixed Operating Costs
(^Million/Year)
Operating Labor 9.7
Overhead 26.6
Maintenance 45.4
Total, First Year 81.7
Variable
Water 1.32
Catalyst and Chemicals 5.78
Ash Disposal 1.20
Total (Excluding Feedstock) 8.3
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Table 21
Cost Estimates for the 6000TPD
SRCII Demonstration Plant
(February, 1981 Dollars)
Million Dollars
Phase I - Design (1980-84) 292
Phase II - Construction (1982-86) 1415
Phase IIIA - Start-Up (1986) 286
Preoperational Subtotal 1993
Phase IIIB - 2 Yrs. Operation 347
(1986-88)
Phase IIIC - 3 Yrs. Operation 495
(1988-91)
Total 842
Annual Average 160
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billion, which includes an estimated 13 percent contingency, but
no working capital. These costs were given for different phases
of the plant development, thus being presented as lifetime costs
rather than instantaneous investments. Mechanical operation was
estimated to begin in early 1986. The annual operating and main-
tenance cost was approximately $165 million per year. This did
not include coal costs or capital recovery.
6. Selection of Best Study
A summary of the capital and operating costs as estimated by
each study are shown in Table 22. Each of these five sets of
estimates will be adjusted to an output of 50,000 FOEB/D and the
financial input factors discussed in section II above. As was
done previously with the H-Coal process, costs at this point will
be left as instantaneous capital costs and stream day operations
for convenience, unless otherwise specified. Feedstock costs and
by-product credits will also be accounted for later. Once selec-
tion of the best study or studies have been determined, final
adjustments will be made, if necessary, for lifetime capital
costs, calendar day operations, feedstock costs, and by-product
credits.
The Pittsburg and Midway studies will be examined first. Its
adjusted product slate, shown in Table 23, is simply one-half the
amount estimated for a 100,000 FOEB/D product slate. The capital
cost estimates need to be adjusted to a production of 50,000
FOEB/D using the 0.75 scaling factor, inflated to 1981 dollars and
have a 15 percent contingency added. These changes reduce this
cost to $1.23 billion (1981 dollars). Labor costs are similarly
adjusted using a scaling factor of 0.2. The catalyst, chemical,
and electricity costs, originally estimated at $11 million (1980
dollars) for the 100,000 FOEB/D case, would be (with inflation)
$6.0 million (1981 dollars) for a production of 50,000 FOEB/D.
The remaining operating and maintenance costs are assumed to be
the same percentage of plant investment in both the 100,000 FOEB/D
case and the 50,000 FOEB/D case. A summary of Pittsburg and
Midway's adjusted capital and operating and maintenance costs are
shown in Table 24.
The Parsons' study is already based on a 50,000 FOEB/D
production. Thus, its product slate and process costs will not
have to be modified at this point, except for inflation. The
inflated costs are shown in Table 24.
The capital costs and operating costs of the ESCOE study
required adjustment from ESCOE's original production of 61,500
FOEB/D to 50,000 FOEB/D, based on appropriate scaling factors and
inflation to 1981 dollars. ESCOE's adjusted costs are shown in
Table 24.
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Table 22
Summary of SRC-II Capital and Operating Costs,
As Estimated by Each Study
Coal Type
Coal
Thermal
Efficiency (%)
Pittsburg
and Midway [13]
W.V. Coal
72
Parsons [14]
111. #6*
69.9
ESCOE[3] ICF[2] DOE [22]
111. #6* 111. #6 W.V.
N/A N/A 72
Total Production
(FOEB/D)
Capital Cost
($Million/Yr)
Plant
Other
Operating Costs
Fixed
Variable
100,000
1,794
190
99
11
50,000
1,173
439
102.7
18.5
61,500 50,000 18,000
774 775 1,707**
488 485 286
113.4 81.7 130
6.0 8.3 30
* This was assumed for each study where coal types were not stated.
** These are lifetime capital costs.
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Table 23
Adjusted SRC-II Product Slates
Based on 50,000 FOEB/D Commercial Plant Size
Coal Feed Rate
Efficiency (%)
Product
Naptha
Fuel Oil
Residual
LPG (Ethane/
Propane)
Butane (TPD)
Methane
(MMSCFD)
Total
By-Product
Sulfur (TPD)
Ammonia (TPD)
Phenols (TPD)
Tar Acids (BPD)
Pittsburg
and Midway
16,750
72%
8,500
28,000
—
11,000
1,500
25
50,000
600
90
—
120
Parsons
17,232
69.9%
5,148
11,253
33,680
—
—
—
50,000
N/A
N/A
N/A
N/A
ESCOE ICF DOE
20,325 20,325 16,750
70% 70% 72%
8,700 8,700 8,500
36,830 36,800 28,000
4,470 4,500
11,000
1,500
25
50,000 50,000 50,000
694 694 600
230 230 90
56 56
120
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Table 24
Adjusted SRC-II Cost Estimates,
Based on 50,000 BPD/FOE Commercial Plant Size
Pittsburg
and Midway Parsons
Instantaneous
Capital Costs
(Millions of
1981 Dollars)
Plant Investment 969 1,379
Other 103 592
Contingency 161 296
(@ 15%)
Total 1,233 2,267
Operating Costs
(Millions of
1981 Dollars per
Stream Day)
Fixed
Operating Labor 27.0 13.9
and Main-
tenance Labor
Other 46.5 73.0
Variables
Water, 6.0 26.5
Catalyst, etc.
Working Capital * 6.8
Total 79.5** 120.2
ESCOE IGF DOE
787 845 2,870
496 529 100
192 206 430
1,475 1,580 3,400
31.3 30.4 62
87.4 58.7 218
5.8 9.0 47
7.5 5.9 19
132.0 104.0 346
* Included in other costs.
** Calendar day operation.
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Concerning the IGF study, product slates and costs are
already determined for a production of 50,000 FOEB/D. ICF's
costs, however, still must be inflated to 1981 dollars. These
costs are shown in Table 24.
Finally, DOE's estimates for lifetime capital costs and oper-
ating costs will be adjusted using the appropriate scaling
factors. Only a feedrate of 6000 TPD is given by DOE, without the
corresponding production volumes. However, both feedrate and
production volume should be proportional to the Pittsburg and
Midways estimates. Since Pittsburg and Midway estimated a feed
rate of 33,500 TPD for a 100,000 FOEB/D plant, 16,750 TPD of coal
should correspond to a production of 50,000 FOEB/D. Thus, based
on a feedrate of 17,000 TPD and a scaling factor of 0.75, the
lifetime capital costs would be $4.35 billion, which includes a 13
percent contingency but does not include working capital. With a
15 percent contingency and working capital, which is estimated to
be about 4 percent of all other capital costs (based on the
previous studies), the total lifetime cost would be $4.60
billion.
The instantaneous capital cost of the DOE study will now be
estimated so that it can be compared to the instantaneous capital
costs of the other studies. The instantaneous capital cost
depends on the construction interest rate and the building
schedule incorporated into DOE's lifetime capital cost. The
investment schedule is shown in Table 25, and the opportunity
cost, based on DOE's work, is estimated to be 10 percent per
year. The resulting adjustment factor is 1.348. If the lifetime
capital cost of $4.60 billion is divided by the adjustment factor
of 1.348, the resulting instantaneous capital cost is $3.4 billion.
As mentioned earlier, DOE estimated total operating costs to
be $165 million per year. Adjusting this cost to the desired
plant size of 50,000 FOEB/D is difficult since DOE did not give a
complete breakdown of the labor, catalyst, chemical, electricity
and other costs. However, based on the Pittsburg and Midway
studies, the labor costs for the 6000 TPD plant are 30 percent of
total annual operating costs, or $50 million. When adjusted to a
plant size of 50,000 FOEB/D production, the labor cost is about
$62 million, based on a 0.2 scaling factor. Pittsburg and Midway
estimated catalyst, chemical, and electricity costs to be about 10
percent of the annual operating costs, which would be $16.5
million for the 6000 TPD plant. Since these vary in direct
proportion to plant size, these costs would total $47 million for
the 50,000 FOEB/D plant. The remaining operating and maintenance
costs (excluding working capital interest) are 60 percent of total
operating and maintenance costs, or $100 million. These costs are
based on a fixed percentage of capital and, based on a 0.75 scal-
ing factor, would amount to $218 million for the larger plant.
This would bring the total operating and maintenance cost, without
working capital interest, to $315 million per year. With working
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Table 25
Investment Adjustment Factor Calculations
For DOE-SRC-II Study
Year
1980
1981
1982
1983
1984
1985
1986
Fraction of
Investment
Completed
0.029
0.029
0.171
0.171
0.171
0.142
0.286
1.00
Adjustment for During
Desig,: ., Construction,
a id Start-up
(1.10)7
(1.10)6
(1.10)5
(1.10)4
(1.10)3
(1.10)2
(1.10)1
Adjustment
Factors
0.057
0.051
0.275
0.250
0.228
0.172
0.315
1.348
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capital interest at 6 percent of this cost, the total operating
and maintenance costs amount to $346 million per year. As with
the other studies, feedstock costs and by-product credits will not
be estimated until later.
The ESCOE and ICF studies will be evaluated first, primarily
because ICF depends upon ESCOE's study and thus the outcomes of
these two studies should be similar. ESCOE expresses their own
judged accuracy in their cost estimate in what is known as a
"confidence factor." The "confidence factor" for this process
development is described as "pre-commercial successful pilot plant
operation." However, the economic reliability is described as
"screening estimate, very approximate." ESCOE also gives little
detailed support for its estimates. In addition to these low
confidence factors expressed by ESCOE themselves, ESCOE's cost
estimates are outdated relative to Ashland and DOE and simple
inflation to 1981 dollars could still underestimate the process
costs as they actually occur today. As has been discussed for
H-Coal in the previous section, changes in the SRC-II process
itself have increased costs at a much higher rate than inflation.
For all these reasons, ESCOE's study will be rejected from further
consideration in favor of the more recent Ashland and DOE studies
evaluation in determining the study with the most accurate process
cost estimates. As the ICF cost estimates were also derived from
the ESCOE study, their study will also not be analyzed further.
The remaining studies to be analyzed are the Pittsburg and
Midway studies, the DOE study and the Parsons study. Of these
studies, the Pittsburg and Midway and DOE studies should best
represent the process costs of the SRC-II process, based on the
following reasons. First, Pittsburg and Midway is under contract
with DOE to determine the costs of the 6000 TPD plant to be
located near Morgantown, West Virginia and has done all the
process development work on SRC-II. Second, both Pittsburg and
Midway and DOE have used more recent data to estimate process
costs. Parson's was only able to use data available prior to
1978. Third, the Pittsburg and Midway and DOE studies show a more
desirable product output. Naptha, which is the most desirable
product from coal liquefaction, is about 17 percent of the product
output according to the Pittsburg and Midway studies, while in the
Parson's study, the naptha production is about 10 percent of total
output. Thus, based on the above three reasons, the Pittsburg and
Midway and DOE studies will be adjusted separately to all the
conditions determined in section II above as these studies most
accurately represent and estimate the cost of a future SRC-II
commercial plant.
The final adjustments to the DOE and Pittsburg and Midway
studies include adjustments for feedstock costs, by-products
credits, and annual capital charges. For Pittsburg and Midway,
the feedstock rate for a 50,000 FOEB/D plant would be 16,750 tons
per day, or for a 365 days per year operation, the feedstock rate
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would be 6,113,750 tons per year. At the 1981 estimated coal
price of $27.50 per ton, the total feedstock cost would be $168
million. The annual by-product credits of Pittsburg and Midway
(already in 1981 dollars) for sulfur and ammonia are $11.0 million
per year and $5.9 million per year, respectively. It is assumed
that tar acids will not be sold as a marketable by-product.
Pittsburg and Midway estimated the instantaneous capital cost
to be $1.23 billion. Using the capital charge rates of 11.5
percent and 30 percent for the low and high cases, respectively,
along with the appropriate construction schedules, the annual
capital recovery costs are $161 million per year for the low cost
case and $414 million per year for the high capital charge rate
case.
The total annual cost for Pittsburg and Midway is the sum of
the annual capital recovery, operating, and feedstock costs, and
less that of the by-product credits. This amounts to $645 million
for the high capital charge rate case and $392 million for the low
capital charge rate case. The energy value of the products shown
in Table 23 is 112,570,380 million BTU per year. The total
product cost is then $3.50 per million BTU for the low capital
charge rate case and $5.30 per million BTU for the high capital
charge rate case.
Next, the DOE study will be further analyzed. DOE's feed-
stock cost should be the same as that determined for the Pittsburg
and Midway study, since as was previously mentioned, both feed-
stock rates and coal types are identical. This cost is estimated
to be $168 million. DOE's annual by-product credits are also the
same as determined by Pittsburg and Midway, which amounts to about
$17 million.
DOE's instantaneous capital cost was estimated to be $3.4
billion. Using the adjustment factors mentioned above, the annual
capital recovery costs would be $440 million for the low and $1.14
billion for the high capital charge rate case. DOE's total annual
cost is the sum of annual capital recovery, operating and main-
tenance, and less that of by product credits. This amounts to
$760 million for the low cost case and $1.46 billion for the high
capital charge rate case.
The product energy value in DOE's study is estimated to be
107,673,000 million BTU per year, the same as that estimated by
Pittsburg and Midway. The total product cost is then $7.05 per
million BTU for the low and $13.56 per million BTU for the high
capital charge rate case.
A large discrepancy in product costs exists between the
Pittsburg and Midway studies and the DOE study. The DOE product
estimates are over twice as large as the Pittsburg and Midway
estimates. The primary difference is due to the cost of capital.
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After a more thorough investigation, it was found that the 1980
cost estimates of the Pittsburg and Midway study[18] were merely
adjusted for inflation from their original 1979 estimates.[12]
However, as was discussed in the H-Coal studies earlier, coal
liquefaction process costs have tended to rise significantly
faster than the rate of inflation due to changes in the processes
with time. The Pittsburg and Midway study probably underestimated
the latest costs figures as they were merely inflated from
previous work. On the other hand, the DOE study may overestimate
costs because it was based on a smaller demonstration plant,
though the scaling factor (0.75) should help reduce this effect.
Thus, although there is some chance of overestimation in the DOE
study, it is still likely to be the more realistic. Also, DOE's
capital cost is much nearer that estimated for the H-Coal process,
while Pittsburg and Midway's capital costs are one-third of that
for the H-Coal process and well below that estimated by Parsons'
earlier. Thus, the DOE study, with adjustments, appears to be the
best product cost estimate for the SRC-II process.
IV. Summary
The publicly available studies addressing the costs of both
the H-Coal and SRC-II process were analyzed to determine which
contained the most accurate assessment of costs. Two very recent
reports by Ashland were found to contain the most up-to-date
assessment of the H-Coal process[10,11] and a DOE report was found
to contain the most recent cost estimates for the SRC-II
process.[20]
The costs contained in each of these studies were placed on a
common financial and economic basis, as discussed in section II.
The results were that the instantaneous capital cost of a 50,000
FOEB/D H-Coal plant is approximately $3.3 billion (1st quarter
1981). The average product cost would be $5.99 per million Btu
with an 11.5 percent annual capital charge rate and $11.47 per
million Btu with a 30 percent annual capital charge rate.
The instantaneous capital cost of an SRC-II plant of the same
size is $3.4 billion. The average product cost would be $7.05 per
million Btu with an 11.5 percent annual capital charge rate and
$13.56 per million Btu with a 30 percent annual capital charge
rate.
Cost estimates both for the H-Coal and SRC-II plants are much
greater than estimates of previous years. This is due to the
costs associated with synthetic fuel processes rising much faster
than the general rate of inflation.
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References
1. "Refining and Upgrading of Synfuels From Coal and Oil
Shales by Advanced Catalytic Processes," Sullivan and Frankin,
Third Interim Report, Processing of SRC-II Syncrude, March 1980,
Chevron Research Co., FE-2315-47.
2. "Methanol From Coal: Prospects and Performance as a
Fuel and as a Feedstock," ICF, Inc., for U.S. National Alcohol
Fuels Commission, Washington D.C., 1980.
3. "Coal Conversion Comparisons," Roger, K.A., et al.,
Engineering Societies Commission on Energy, Inc., Washington D.C.,
July 1979, FE-2468-51.
4. "Economic Feasibility Study, Fuel Grade Methanol from
Coal for Office of Commercialization of the Energy Research and
Development Administration," McGeorge, Arthur, DuPont Company, for
U.S. ERDA TID-27606.
5. "Methanol Use Options Study," (Draft) DHR, Inc. for
DOE, December, 1980; Contract No. DE-ACOI-79 PE-70027.
6. "Methanol From Coal, An Adaptation From the Past," E.E.
Bailey, (Davy McKee), Presented at The Sixth Annual International
Conference; Coal Gasfication, Liquefaction and Conversion to Elec-
tricity, University of Pittsburgh, 1979.
7. Plant Design and Economics for Chemical Engineers,
Peters, Max S. and Timmerhaus^ Klaus D. , McGraw-Hill Company,
Second Edition, 1968.
8. "The Potential for Methanol from Coal: Kentucky's
Perspective on Costs and Markets," Kermode, R.I., Nicholson, A.F.,
Holmes, D.F., Jr., and Jones, M.E., Jr., Division of Technology
Assessment, Kentucky Center for Energy Research, Lexington,
Kentucky, March, 1979.
9. "Engineering Evaluation of a Conceptual Coal Conversion
Plant using the H-Coal Liquefaction Process," Prepared by Fluor
Engineers and Constructors, Inc. for EPRI, December, 1979.
10. "The Breckinridge Project," Ashland Synthetic Fuels,
Inc. and Airco Energy Company, Inc., Submitted to United States
Synthetic Fuels Corporation, March, 1981.
11. "The Breckinridge Project: A Commercial H-Coal Plant
Status Report," Hicks, Harold N., Presented at the American Petro-
leum Institute Mid-Year Meeting, Chicago, Illinois, May 13, 1981.
12. "SRC-II Demonstration Project, Phase Zero," Prepared by
Pittsburg and Midway Coal Mining Co. for U.S. Dept. of Energy,
July 31, 1979.
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13. "Monthly Energy Review," U.S. DOE, DOE/EIA-0035
(81/04), April 1981.
14. "Research Guidance Studies to Assess Gasoline from Coal
by Methanol-to-Gasoline and Sasol-Type Fischer-Tropsch Tech-
nologies (Final Report)," Mobil Research and Development Corp.,
for DOE, FE 2447-13, August 1978.
15. Coal Liquefaction Processes, Nowacki, Noyes Data Corp.,
1979.
16. Preliminary Economic Analysis of H-Coal Process Produc-
ing 50,000 Barrels Per Day of_ Liquid Fuels from Two Coal Seams;
Wyodak and Illinois, Prepared for the U.S. Energy Research and
Development Administration ERDA 76-56, Morgantown W.V. Process and
Evaluation Group, U.S. Bureau of Mines, U.S. Department of
Interior, March 1976.
17. "The Breckinridge Project Overall Thermal Efficiency,"
Issued for Phase 0 by Ashland Oil, June 15, 1981.
18. "The SRC-II Process," Schmid, B.K. and D.H. Jackson,
(Pittsburg and Midway Coal Mining) Presented at discussion meeting
on New Coal Chemistry, Organized by the Royal Society, London,
England, May 21-22, 1980.
19. "Process Engineering Evaluations of Alternative" Coal
Liquefaction Concepts," Prepared by The Ralph M. Parsons Company
for EPRI, April, 1978, AF-741.
20. Memorandum and Press Release to James McClure, Chair-
man, Subcommittee on Interior and Related Agencies, from Roger
W.A. LeGassis, Acting Assistant Secretary for Fossil Energy, April
30, 1981.
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